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179-080
U,xxonftbil Production Company l= 0. Box 19G6 01 t,. uhotage. Alaska 99519 6)001 010'15615331 Telephone August 4, 2014 R-2014 OUT -157 RECEIVED AUG 0 6 2014 AOGCC SCANNED E i. Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 RE: Final Location Clearance • Point Thomson Unit (PTU) #1 (PTD 176-085) • PTU #2 (PTD 177-064) • PTU #3 (PTD 178-005) • Staines River State #1 • West Staines State #18-9-23 (PTD 169-120) • West Staines State #2 (PTD 175-002) • Alaska State C-1 (PTD 180-046) Dear Commissioner Foerster, ElonMobil Production By letter dated May 18, 2007, the Alaska Oil and Gas Conservation Commission (Commission) advised ExxonMobil that ten wells in the Point Thomson area did not meet the Commission's requirements for plugged and abandoned wells. The Commission further noted that permits to drill cannot be issued to an operator that is in violation of a Commission regulation pertaining to drilling, plugging or abandonment of a well. In addition to the seven wells listed above, the Commission's May 2007 letter addressed Challenge Island #1 (PTD 180-090), Alaska State J-1 (PTD 183-045), and PTU #4 (PTD 179- 080). Challenge Island was operated by another party, and we understand remedial work there has been completed. ExxonMobil has pursued remedial and final abandonment work on the ExxonMobil operated wells identified in the May 2007 letter. Visual inspections of all sites were conducted in 2007 and comprehensive inspections of the nine Exxon MobiI-operated wells were conducted in winter 2008/09. Remedial work was completed on the J-1 and PTU #4 wells in 2009 and 2012, respectively, and final reports were submitted to the Commission. During the winter 2013/14, final remedial or plugging and abandonment work on the seven subject wells was completed. A final report of Well Completion for the Plugging and Abandonment of each well was submitted to your office on May 14, 2014, followed by the summer well site debris clean- up reports submitted July 18, 2014. Cathy Foerster 2 August 4, 2014 All well remedial and abandonment work on the nine ExxonMobil operated wells was conducted in accordance with approved Applications for Sundry Approvals, some of which received modifications as the work progressed. Timely notices were provided to the Commission so inspection of the work could be performed at the Commission's discretion. The PTU #4 well file on the AOGCC website contains a final location clearance. With respect to work to close the reserve pit and conduct contaminated site cleanup work at WSS #18-9-23 and WSS #2 and incorporation of the PTU #3 and C-1 locations into the Point Thomson Project gravel infrastructure, our understanding is that receipt of final location clearance is not required at this time in order to be in compliance with plugging and abandonment requirements. Given the unique history of these nine sites in view of the Commission's May 2007 letter, ExxonMobil respectfully requests the Commission to either approve final location clearance or otherwise confirm to ExxonMobil that it has met AOGCC requirements with respect to the plugging and abandonment of these wells and do not represent an impediment to approval of permits to drill for ExxonMobil. If you have any questions or require additional information, please contact me at (907) 564-3773. Sincerely, Irene T. Garcia SSHE Manager THE STATE of T GOVERNOR SEAN PARI\ELL February 28, 2014 Mr. Dale Pittman Alaska Production Manager ExxonMobil Production Company P.O. Box 196601 Anchorage, AK 99519-6601 Re: Location Clearance Point Thomson Unit #4 PTD 1790800 Dear Mr. Pittman: Al slkz Oil and Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Wiain: 907.279.1433 Fax: 907.276.7542 The Alaska Oil and Gas Conservation Commission (AOGCC) completed a location clearance inspection at Point Thomson Unit #4 (PTD 1790800). This exploration well was drilled by Exxon Corporation from a gravel pad during 1980. Surface plugging and abandonment was completed during March 2013 (not witnessed by AOGCC). Location inspections were performed by AOGCC on August 10 and August 31, 2013. Inspection on August 31, 2013 showed the Point Thomson Unit 44 location to be in compliance with onshore location clearance requirements as stated in 20 AAC 25.170. The AOGCC requires no further work on the subject well and location. However, ExxonMobil remains liable if any problems occur in the future with this well. cc: Mr. Rob Dragnich (email) Sincerely, P at P. oerster Chair SCANNEO • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Surface Abandonment/ Location Clearance/Suspended Well (Title 20 AAC 25.170) FILE INFORMATION: Operator Exxon Corporation Well Name: PTU#4 Address: PTD No.: 1790800 API No. 50- 089-20009-00-00 Surface Location(From Sec. Line): Unit or Lease Name: Point Thompson North/South 2700 ft FSL East/West 2900 ft FEL Field and Pool: Point Thomson Field Section: 32 Township: 10N . Range: 22E Meridian: UM Downhole P&A Date: 12/20/1980 • 20 AAC 25.120-ABANDONMENT MARKER: Insp. Date N/A Surface Monument Approval Date: N/A Post OD: (4"min) " Length: ft. Set on (Wellhead,Csg , In Cmt) Height above final grade(4'min.): ft. Casing stub_ft. below final grade Top of Marker Post Closed?— All openings closed? Inspector: Insp. Date N/A Subsurface Monument I Approval Date: 4/16/13 ' Marker Plate Diameter: 36 " Distance below final grade Level: 10 ft Thickness: " Side Outlets removed or closed: yes• • Marker Plate Attached To Conductor Y (Y/N) Cement to surface(all strings)? yes • Inspector: N/A Exact Information Beadwelded Directly to Marker Post or Blind Marker Plate: Insp. Date N/A I Approval Date: 4/16/13 Point Thomson Unit#4 ExxonMobil Corporation PTD#179-080 SCANNED FEB 2 6 2014 API#50-089-20009-0000 Note: Surface P&A not witnessed by AOGCC;photos provided by Exxon with Report of Sundry Well Operations – (Form 10-404)dated 3/28/13 Inspector: N/A Insp.Date'8/31/13 I 20 AAC 25.170-LOCATION CLEANUP: Approval Date: 8/31/13 Pit's filled in? Yes Liners Removed or Buried? Yes Debris Removed: Yes Notes: General condition of pad/location: Flat (Rough,Smooth,Contoured, Flat, Natural) Notes: Type of area surrounding location: Tundra,coastline. (Wooded,Tundra,Grass,Brush,Dirt,Gravel,Sand) Debris on surrounding area: none Notes: Area has been cleaned up. Access road present? No Type road: (Dirt,Gravel, Ice,Other) Condition: Condition of road: Notes: Cellar filled in? Yes Type of fill: gravel Height above grade: mound 8' Notes: Trench along mound has been filled. Type work needed at this location: 2nd inspection of site(initial inspection 8/10/13) Trench along mound filled;debris on pad and tundra removed;piling removed Inspector: Jeff Jones RECOMMENDED FOR APPROVAL OF ABANDONMEN'Yes X No (If"No"See Reason) Distribution: Reason: This location has now been properly cleaned up. orig-Well file c-Operator Final Inspection performed? Yes X No c-Database c Inspector Final Approval By: jaVt1Q54 j DATE: 10/10/2013 Title: Supevisor, Inspections / Sheet by L.G.8/5/00 2013-0831_Location Clear_PTU-4jj.xlsx 10/10/2013 Location Clearance (Follow-up) Inspection - Pt. Thomson #4 PTD 1790800 Photos by AOGCC Inspector J. Jones 8/31/2013 Refer to Location Clearance Inspection Report for details of observations • Aftri 4 1", • • .` 4 K} yy. M vx s +.�• - ltd f... w.• a .r. , �, 4" '. 7 ■• -r r .? _ r. may =y! " X • •• •.yam2 r♦ M v� -�1 \ l T -4 2013 0831_Location_C ear_P U _photos.docx Page 1 of 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Surface Abandonment / Location Clearance / Suspended Well ( Title 20 AAC 25.170 ) FILE INFORMATION: Operator: Exxon Corporation Well Name: PTU #4 Address: PTD No.: 1790800 API No. 50- 089-20009-00-00 Surface Location (From Sec. Line): Unit or Lease Name: Point Thompson North/South 2700 ft FSL , East/West 2900 ft FEL Field and Pool: Pt. Thomson Field Section: 32 Township: 1 O Range: 22E Meridian: UM Downhole P&A Date: 12/20/21980 20 AAC 25.120 - ABANDONMENT MARKER: Insp. Date N/A Surface Monument Approval Date: Post OD: (4" min) _" Length:_ft. Set on (Wellhead, Csg , In Cmt) Height above final grade (4' min.): _ft. Casing stub_ ft. below final grade Top of Marker Post Closed ? _ All openings closed ? Inspector: Insp. Date N/A Subsurface Monument I Approval Date: 4/16/13 Marker Plate Diameter: 36 Distance below final grade Level: 10 ft Thickness: _" Side Outlets removed or closed: Yes Marker Plate Attached To Conductor Y (Y/N) Cement to surface (all strings)? Yes Inspector: N/A Exact Information Beadwelded Directly to Marker Post or Blind Marker Plate: Insp. Date N/A I Approval Date: 4/16/13 Point Thomson Unit #4 ExxonMobil Corporation PTD #179-080 ,C A9�1i���i API #50-089-20009-0000 Note: Surface P&A not witnessed by AOGCC; photos provided by Exxon with Report of Sundry Well Operations (Form 10-404) dated 3/28/13 Inspector: N/A Insp. Date 8/10/13 20 AAC 25.170 - LOCATION CLEANUP: I Approval Date: none Pit's filled in? Yes Liners Removed or Buried? Yes Debris Removed: No Notes: foam, plastic, wood has spread out around the pad on the tundra and must be removed. General condition of pad/location: Flat ( Rough, Smooth, Contoured, Flat, Natural ) Notes: mound settling caused trench along edge of mound, must be filled to prevent unnatural poncling. Type of area surrounding location: Tundra, coastline. ( Wooded,Tundra, Grass, Brush, Dirt, Gravel, Sand) Debris on surrounding area: foam pieces, plastic, paper, wood, concrete, piling, barrel, bou . Notes: More cleanup needed at this location. Access road present? No Type road: ( Dirt, Gravel, Ice, Other) Condition: Condition of road: Notes: Cellar filled in? Yes Type of fill: gravel Height above grade: 8' Notes: Type work needed at this location: Fill in trench along mound, remove all debris, remove piling. Inspector: Jeff Jones RECOMMENDED FOR APPROVAL OF ABANDONMEN Yes No X ( If "No" See Reason ) Distribution: orig - Well file Reason: This location has not been properly cleaned up and the trench needs to be filled, piling removed. c - Operator Final Inspection performed? Yes No X c - Database c - Inspector Final Approval By: Title: Sheet by L.G. 8/5/00 2013-0810_Location_Clear_PTU-4Jj.xlsx 10/10/2013 Location Clearance Inspection - Pt. Thomson #4 PTD 1790800 Photos by AOGCC Inspector J. Jones 8/10/2013 Refer to Location Clearance Inspection Report for details of observations 2013-0810_Location_Clear_PTU-4_photos.docx Page 1 of 2 - ... , . f- * ��� °� � a ... ^ � fir` r `►� - ..�,-- .. ;.'hi+ • „ � _+v - ' r J �'�"3^ ,,/��ffk�� -.t gf,�'Wi �`"'�S °' '.Y'" "r.'.....ro• .� • Y � ¢y STATE OF ALASKA AIL OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS ��r , s �°. A- 1. Operations Abandon P ( Repair Well❑ Plug Perforations III Perforate❑ Other El Remediation Performed: Alter Casing❑ Pull Tubincj Stimulate - Frac ❑ Waived] Time Extension ❑ Change Approved Program ❑ Operat. Shutdowrfl Stimulate - Other ❑ Re -enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: ExxonMobil Oil Corporation Development❑ Exploratory El 179 - 080 3. Address: PO Box 196601 Stratigraphicfl Service❑ 6. API Number: Anchorage, AK 99519 - 6601 , 50 - 20009 _ 14003 7. Property Designation (Lease Number): 8. Well Name and Number: N. ADL 47563 Point Thomson Unit # 4 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): t N/A Wildcat 11. Present Well Condition Summary: Total Depth measured 15,074 feet Plugs measured 0 - 100 feet true vertical 13,194 feet Junk measured N/A feet Effective Depth measured N/A feet Packer measured N/A feet ' , . ' ''. true vertical N/A feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural 91' 28" x 36" 91' 91' N/A N/A Conductor 2,102' 20" 2,127' 2,127' 3,060 1,500 Surface 3,397' 13 -3/8" 3,422' 3,422' 5,380 2,670 Intermediate 11,862' 9 -5/8" 11,887' 10,222' 8,150 7,100 Production 10,730' 7" 15,049' 13,170' 12,460 / 13,700 1,0760 / 13,010 Liner N/A N/A N/A N/A N/A N/A Perforation depth Measured depth N/A feet APR 1 9 t� True Vertical depth N/A feet Sww��NGY AJ- R 1 9 2013 Tubing (size, grade, measured and true vertical depth) N/A �� N/A N/A NIA Packers and SSSV (type, measured and true vertical depth) N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): None Treatment descriptions including volumes used and final pressure: No treatment 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: N/A N/A N/A 0/0 0 Subsequent to operation: N/A N/A N/A 0/0 0 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Well Photographs Exploratory evelopmen0 Service ❑ Stratigraphic ID Daily Report of Well Operations See Attachment 16. Well Status after work: /A bandoned Oil ❑ Gas ❑ WDSPL❑ 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 - 080 Contact Tom Juranek (713 - 656 -4225) Email tom.a.iuranek(a�exxonmobil.com Printed Name William Hanenberg Title Alaska SSH&E Manager Signature (18 V Phone 907 - 564 -3773 Date 3/28/2013 Form 10 -404 Revised 10/2012 rxiS APR 16 201dM) 7 4 zi•f( 'f 3 Submit Original Only • ExxonMobil Production Coney Joint Interest U.S. P. 0. Box 196601 Anchorage, Alaska 99519 -6601 907 561 5331 Telephone 907 564 3789 Facsimile EkonMobil Production April 9, 2013 Mr. Guy Schwartz Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: Sundry Report of Well Operations ExxonMobil Oil Corporation Point Thomson Unit #4 PTD No. 179 -080 Sundry No. 313 -080 Dear Mr. Schwartz: ExxonMobil hereby submits a Report of Sundry Well Operations for remedial abandonment work conducted on the Point Thomson Unit #4 well. The well is plugged and abandoned. Remedial actions were taken on the well pursuant to earlier communications between ExxonMobil and the Alaska Oil and Gas Conservation Commission. Attached please find: Form 10 -404: Report of Sundry Well Operations Inspection Summary Photographic documentation of the well before and after the work Please contact Tom Juranek at 713 - 656 -4225 or William Hanenberg at 907 - 564 -3773 if you have any questions. Sincerely, VA./ William J. Hanenberg WJH:blc Attachments A Division of Exxon Mobil Corporation • Point Thomson Unit #4 Operations Summary March 27, 2013 Point Thomson Unit #4 is plugged and abandoned. Remedial actions were taken on the well pursuant to earlier communications between ExxonMobil and the Alaska Oil and Gas Conservation Commission. Attached is a summary of work activities and photograph documentation of the work. March 12, 2013 Arrived on location and spotted equipment. Completed snow removal from pad. March 13, 2013 Began excavating of well head. Estimated 60% complete. March 14, 2013 Continued excavation of well head. Located both 3" valves on well head (estimated 10 feet down). Commence digging out bench area (estimated 4 - 6 feet down on east side) to allow excavator to dig hole to estimated 18 feet. March 15, 2013 Continued excavation of well head. Reached 18 feet on the South and East sides. Stair step of East and North side 90% complete. Suspended work due to snow blow. Moved dirt to build barrers on East side to help slow down snow build up from blow. March 16, 2013 Continued excavation of well head. Currently at a depth of 18 - 19 feet, totally around well head. Estimated 85% complete on stair step on East and North side. From the bottom valve, the conductor pipe has external cement fill around it. March 17, 2013 Continued excavation of well head. Completed excavation of bench on North Side for excavator to work from. Received 32 foot extension ladder and carried out a confined space LMRA with employees. Set u all equipment re uired to carry out confined p up q rY space entry. Carried out confined space entry for inspection of Well Head. Picked up all equipment and tools and shut down for day. March 18, 2013 Continued excavation of well head. Completed excavation work on West & South stair steps. Received two jack hammers and air dryer, along with small chipping hammers. Held conference call w /Anchorage & Houston to discuss options and concerns on removal of concrete from around well head. March 19, 2013 Completed excavation of wellhead. Completed chipping of concrete around 36" • conductor pipe by use of air chipper hammer & electrical chipper hammer. Cleared out all chippings from hole. Completed installation and butt welding of 36" drip pan. • • March 20, 2013 Cleared snow from ice road & location. Moved material & equipment around as required. Completed cutting cap off 36 ", 32" & 28" casing. Removed section, chipped off cement around 20" casing. Ready for Wach saw cut. Removed 1 -3" gate valve. Commenced erecting scaffolding around well head, estimated 70% complete. March 21, 2013 Completed scaffolding. Opened up well and found 0 psi with trace of liquid. (Note: Cut & removed all bolts /nuts for top flange, but could not break & remove flange.) Rigged up Wach saw, rigged up tag lines, lift slings, and connected to excavator. Little Red, Halliburton & Peak Vac Truck arrived. Completed Wach saw cut of 20" casing. Removed well head, rigged down Wach saw, picked up tools and shut down for day. March 22, 2013 Carried out gas test, re- erected scaffold to construct work platform, and installed and welded 20" drip pan. Installed and welded stabbing work table. Rigged up 1" elevators and slips onto excavator. Picked up 1" pipe and located onto work platform. Commenced installation of 1" collars. Little Red began heating up diesel for circulation. Ran 1" pipe into 36" conductor, tagged at about 13 ft. Tag felt soft. Pulled out 1" pipe. Ran 1" pipe into 13 -3/8" x 9 -5/8" annulus and tagged at estimated 30 ft. Circulated diesel for about 1 -1/2 hours at 1/2 bbl /min at an average of 100 psi. Recovered 15 bbls. 13 -3/8" x 9 -5/8" tag was solid. Secured 1" pipe in hole. Shut down for day. March 23, 2013 Carried out gas test. Carried out inspection of scaffold and set up tools and equipment to continue running 1" pipe. Pulled out 1" pipe from 13 -3/8" x 9 -5/8" from North side of annulus, ran same 1" pipe into 13 -3/8" x 9 -5/8" annulus on South side and tagged again at 30 ft (hard tag). Hooked up Little Red, circulated hot (90 degrees) diesel for 1 hour (est. 60 bbls) at 120 psi. Tag remained the same. Ran 1" pipe into 13 -3/8 "x 20" annulus to 200 ft. without tagging anything. Circulate hot (90 degrees) diesel at 150 psi. Received about 15 minutes of arctic pack returns. Halliburton commence rigging up cement iron and manifold. Received approval for cement of 32 "x36" annulus, 13 -3/8" x - - ---- G - - -- 9-5/8" annulus & 13 -3/8" x 20" annulus from uy Schwartz with AOGCC. March 24, 2013 Carried out gas test, inspection of scaffold, and safety meeting. Halliburton completed hook -up of cement equipment. Halliburton cemented 28 "x36" conductor annulus 12 2 ._ bbls), 9 -5/8" x 13 -3/8" annulus (3.5 bbls) & 13 -3/8" x 20" annulus (28 bbls), Had good returns on all three annuli. Used 115 bbls of fresh water with cement. Rigged down and released Halliburton, Little Red, 2 Peak vacuum trucks, & water hauler truck. SXP & AIC personnel assisted during cement operation as required. March 25, 2013 Carried out gas test and safety meeting. Cut & removed 20" & 36" drip pans. Made final cut of all casings. Took photos before welding on marker plate. Welded on marker plate and took photos of marker plate after welding. Took photos of final measurement of well cut off distance from tundra elevation. Cut off estimated 10 ft. below tundra. Back filled excavation, using location gravel to establish 7 foot of mound. De -mob of all equipment and materials. Project Complete. • • i Point Thomson Unit #4 As Found z r' r ,,. v+ .,..r ' �n„r" '".. , :. ',� , . Mi le i J— ; .r . y r to • h ,,,,,? v; ?� �, .. 's ,---. - ° b Point Thomson Unit #4 �. Y r < Wellhead Excavated • • � . s 0 y - , max` t 3i `S f +' s ti ii t 4 e -:-.N,,,,, ..-, , , i . - , - 8 , k -NJ : ,,- ' f, , At ' A i 'N ■ %iiiimir ��a. ; r .e ' + s . 4 0 ,. . r _ Installing Drip pan, preparing to cut wellhead . . , ' , , • : Ps, ‘40 # t ililoilikib • F + i Y :;. it `, 6.4, s. d } aft . s V +� \.y' • • r~ s • 1 F ` �r'. Initial cut of wellhead. • • • 1 ,. _ ' ' .�- 1" tubing run in all the annuli. . i tiiiiir 7 7 3.w- -rte --,.' :::1- ';' ' ,' of lre c4 , w e+.y r ,4 -k .57' .. i.; aPir 1 Ai +S 0. A r a�. . - ?- 4,4`x' t i" } �� •: f y - , . `` 4 fi ;, 4 a .. i ' — '''• • ' i t r' '' it A ) -1. All strings cemented, ready to weld on marker plate.' • • Marker plate welded on. ; ° m ' . A . . , 4 i i V 't im yl , • ..:41:4--''''' _ s ^ f- � s " , .,-,,,Id-.. , x r 4 t t,A'f / Q }= t 'V '' may. y. . , �' J • , 1 ,ii il 1.. r.„. 1.1 1 . , fie 4 Tundra Level -- w► ic , 4 • 7 „, - ‘ _....... . ....... ..... . ...;‘,. „._, .- 3 . .,,,,, . . , 0/ _.,.., .,- , .. .2,...,...:,, ,..., „. . 41. , , !e -- -,, , ..-.' , ,:- `. t w //‘""..****'‘ _ 4, :, ' (°"—..‘%1 ,4in , ...., , ,: f .. 7 ,....1 , 7 _ ,, 4.,. 4,,,, .. ii#4 e J a . '�- • a 4 11r".' . "je e :: t v Marker plate i nstalled an estimated 10 below tundra level. • • Point Thomson Unit #4 As Left .. V • oh.,--ii F 3 ws ` a ye .'^' { yy�] �. may ! 'S' r 1 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Saturday, March 23, 2013 2:24 PM To: 'Robert Dragnich' Cc: Gilbert Wong; Dennis Collins; Mirick Cox; Craig Ruminer; Bill Penrose; Tom Juranek; Greene, Timothy L Subject: RE: PTU #4 P&A Status and Variance Request Rob, Thanks for the update. Your request for a variance to 20 AAC 25.112 (d) to place a 15'-30' plug in the outer annulus is approved *(less than required 150' plug) . The casing depth for these conductors is very shallow (90 ft) and a shorter cement plug at surface will be adequate to safely P & A this annulus. Also, your request to place less than a 150' cement plug at surface in the 9 5/8" X 13 3/8" annulus is approved per 20 AAC 25.112 (i). Tagging hard in the annulus at 30' could be remnants of the cement shoe that was pumped. (The 9 5/8" X 13 3/8" annulus has a cemented shoe at the 13 3/8" shoe ... approx. 300' of cement ) . Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office SCANNED C Y '� 20" From: Robert Dragnich [mailto:robC-Orgdragnichllc.com] Sent: Saturday, March 23, 2013 1:28 PM To: Schwartz, Guy L (DOA) Cc: Gilbert Wong; Dennis Collins; Mirick Cox; Craig Ruminer; Bill Penrose; Tom Juranek; Greene, Timothy L Subject: PTU #4 P&A Status and Variance Request Guy, We request approval for a variance from the AOGCC regulations to allow less than a 150 ft surface plug in the 13-3/8" x 9-5/8" annulus of the Point Thomson Unit #4 well (PTD 179-080). We also request your concurrence that a 15 to 30' cement plug in the outer annulus of the insulated/refrigerated conductor will be sufficient. We expect to be able to put at least a 150' cement plug in the 20" x 13-3/8" annulus and the 9-5/8" casing will be filled with cement to the surface. As you may recall, this well has a refrigerated / insulated conductor with 2 annuli (36" x 32" and 32" x 28") and 2 inner well annuli (13-3/8" x 9-5/8" and 20" x 13-3/8"). Following cut-off of the wellheads, the insulated/refrigerated conductor did not contain any apparent refrigeration tubes. The inner annulus (32" x 28") of the conductor was full of cement to the surface. A brief summary of the operations follows: 22 March 2013 36" x 32" • Ran 30' of 1", worked last 5 feet before tagged hard. Used the excavator to pound down the last 3 — 5 feet and no further progress was possible. POOH and found 4" — 6" of "grit" inside the 1" pipe. • Plumb all around and tagged at 13' at each location. 20" x 13-3/8" • No attempt on 22"d 13-3/8" x 9-5/8" • Ran 30' of 1" and tagged hard. Circulated at 80 —100 psi with 90F diesel. Pumped —13 bbls total. Returns taken to vac truck. 9-5/8" Casing • Tagged hard —2 feet below cut. Tagging existing cement plug. 23 March 2013 13-3/8 x 9-5/8 • Ran 3 joints of 1" and tagged hard bottom at 30'. First joint had a 3" mule shoe cut into it. Pumped 1 hour, —60 bbls, of 90F diesel. • Continued to tag hard bottom after circulation. • Moved 1" pipe to different locations around the 9-5/8" casing and continued to hit hard bottom at 30'. 20" x 13-3/8" • Ran 10 joints of 1" to —150 ft. First joint had a 3" mule shoe cut into it. Will run 5 more joints of 1" after lunch. • Expect to be able to achieve at least 150' cement plug in annulus. We would welcome an inspection visit by the AOGCC. ►A Thank you for your consideration and time. I will call your cell phone to discuss. Regards, Rob Dragnich �i1�:�GZ13� • � robkrg,dragnichllc.com r • • Schwartz, Guy L (DOA) From: Robert Dragnich <rob @rgdragnichllc.com> Sent: Saturday, March 23, 2013 1:28 PM To: Schwartz, Guy L (DOA) Cc: Gilbert Wong; Dennis Collins; Mirick Cox; Craig Ruminer; Bill Penrose; Tom Juranek; Greene, Timothy L Subject: PTU #4 P&A Status and Variance Request Pool. PTU No.4 Sundry No.313-080.pdf ts. 2013 -02 -22 AOGCC PT Field.PT o ry P Attachmen D 17 44.° Guy, We request approval for a variance from the AOGCC regulations to allow less than a 150 ft surface plug in the 13 -3/8" x 9 -5/8" annulus of the Point Thomson Unit #4 well (PTD 179 -080). We also request your concurrence that a 15 to 30' cement plug in the outer annulus of the insulated/refrigerated conductor will be sufficient. We expect to be able to put at least a 150' cement plug in the 20" x 13 -3/8" annulus and the 9 -5/8" casing will be filled with cement to the surface. As you may recall, this well has a refrigerated / insulated conductor with 2 annuli (36" x 32" and 32" x 28 ") and 2 inner well annuli (13 -3/8" x 9 -5/8" and 20" x 13- 3/8 "). Following cut -off of the wellheads, the insulated/refrigerated conductor did not contain any apparent refrigeration tubes. The inner annulus (32" x 28 ") of the conductor was full of cement to the surface. A brief summary of the operations follows: 22 March 2013 SCANNED APR 2 5 2013 36" x 32" • Ran 30' of 1", worked last 5 feet before tagged hard. Used the excavator to pound down the last 3 — 5 feet and no further progress was possible. POOH and found 4" — 6" of "grit" inside the 1" pipe. • Plumb all around and tagged at 13' at each location. 20" x 13 -3/8" • No attempt on 22 13 -3/8" x 9 -5/8" • Ran 30' of 1" and tagged hard. Circulated at 80 —100 psi with 90F diesel. Pumped —13 bbls total. Returns taken to vac truck. 1 r • • 9 -5/8" Casing • Tagged hard -2 feet below cut. Tagging existing cement plug. 23 March 2013 13 -3/8 x 9 -5/8 • Ran 3 joints of 1" and tagged hard bottom at 30'. First joint had a 3" mule shoe cut into it. Pumped 1 hour, -60 bbls, of 90F diesel. • Continued to tag hard bottom after circulation. • Moved 1" pipe to different locations around the 9 -5/8" casing and continued to bit hard bottom at 30'. 20" x 13 -3/8" • Ran 10 joints of 1" to -150 ft. First joint had a 3" mule shoe cut into it. Will run 5 more joints of 1" after lunch. • Expect to be able to achieve at least 150' cement plug in annulus. We would welcome an inspection visit by the AOGCC. Thank you for your consideration and time. I will call your cell phone to discuss. Regards, Rob Dragnich 907 - 830 -4796 robic[rgdr gnicI llc.coni 2 • • • OF T� 4:s,. THE STATE Alaska Oil and Gas 0f AL 1 1 a S Commission conservation Cossion GOVERNOR SEAN PARNELL *h 333 West Seventh Avenue p Anchorage, Alaska 99501 -3572 ALAS Main: 907.279.1 433 Fax: 907.276.7542 William J. Hanenberg SSHE Manager pNNE'� MAR 1 1 2013 ExxonMobil Oil Corporation 1 1 P.O. Box 196601 Anchorage, AK 99519 -6601 Re: Point Thomson Field, Point Thomson Pool, Point Thomson Unit #4 Sundry Number: 313 -080 Dear Mr. Hanenberg: 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, r Cathy P. Foerster Chair DATED this GA" day of February, 2013. Encl. 4 • • RECEIVED STATE OF ALASKA -EB 14 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION 0 4 .z APPLICATION FOR SUNDRY APPROVALS ' • GCC 20 AAC 25.280 1. Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspen€1 Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdowl❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Well Remediation 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exxon Mobil Corporation Exploratory ig Development ❑ 179 - 080 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: PO Box 196601, Anchorage, AK 99519 - 6601 50 20009 - 0000 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Point Thomson Unit #4 . Will planned perforations require a spacing exception? Yes ❑ No o ` 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL 47563 ' Point Thomson Unit • 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): 15,074 13,194 . 0 0 Many plugs, see schematic None Casing Length Size MD TVD Surat Conapse Structural Conductor 91' 28" x 32" x 36" 91' 91' N/A N/A Surface 2,127' 20" 2,127' 2,12T 3,060 psi 1,500 psi Intermediate #1 3,422' 13 -3/8" 3,422' 3,422' 5,380 psi 2,670 psi Intermediate #2 11,887' 9 -5/8" 11,887' 10,222' 7,290 psi 7,100 psi 1 Production 10,730' T' 15,049' 13,193' 12,460 psi 10,760 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): N/A N/A N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (It) and TVD (ft): N/A N/A 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch r 1 Exploratory ( ✓] Stratigraphic n Development n Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: March 1 , 2013 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned CI Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Tom Juranek 713 - 656-4225 Email tom.a.juranek @exxonmobil.com Printed Name Willaim J. Hanenberg Title SSHE Manager Signature (,J Phone Date 907 - 564 -3773 COMMISSION USE ONLY Conditions of approval: Notify Commission s t a representative may witness Sundry 3-1--Dr-_) Plug Integrity E BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance Er p Other: /I 04 ' •-,<- a sre. - r Lti :411 -e-SS cc — a - �i$ ®MS .FEB 2 5 2 Gv 6 a- L., - 1, lam. Spacing Exception Required? Yes ❑ No Er Subsequent Form Required: /Q - Yot( � APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date:2, - 2:2_— / 3 2 - Lcr /3 Submit Form and N For 10 (Revised 111 R IGIN/r is valid for 12 months from the date of a prove l � Attachments in Duplicate L t , (' ExxonMobil Production Come • RECEIVED Joint Interest U.S. P. O. Box 196601 Anchorage, Alaska 99519 -6601 1 4 '`'- 907 561 5331 Telephone 907 564 3789 Facsimile A CC E(onMobil Production February 4, 2013 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7 Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Sundry Approval Well Remediation: Point Thomson Unit #4 (PTD No. 179 - 080) Dear Ms. Foerster, ExxonMobil hereby applies for Sundry Approval to perform remedial plugging and abandonment work on the subject well. The work is described in more detail on the attached Summary Procedure. The general procedure will be: 1. Excavate the well cellar and check pressures inside the well casing and all un- cemented annuli to verify there is no internal pressure. 2. Verify the integrity of the surface cement plug in the 9 -5/8" casing. 3. Cut off the wellhead and all casing strings at least 3' below the natural tundra level. 4. Remove the arctic pack from two inner annuli and cement the annuli with permafrost cement to surface. 5. Cement the annuli in the refrigerated /insulated conductor. 6. Top off the 9 -5/8" casing and all annuli with cement. 7. Install a well identification marker cap and backfill the excavation with gravel. / Attached please find the following documents supporting this Application: • Sundry Application Form 10 -403 • Proposed Work Procedure including before and after wellbore diagrams • A Division of Exxon Mobil Corporation • • Ms. Cathy Foerster Alaska Oil and Gas Conservation Commission February 4, 2013 Page Two If you have any questions or require additional information, please contact me at (907) 564- 3773 or Tom Juranek at 713 - 656 -4225. Sincerely, ) William J. Hanenber SSH &E Manager WJH:nlr Attachments • • POINT THOMSON UNIT #4 WELL HISTORY AND ABANDONMENT PROCEDURE Affected Wells and API /APTD Numbers: Point Thomson Unit #4 API # 50- 089 -20009 APTD #: 179 -080 Background: The PTU #4 well was drilled in 1980. The well was subsequently plugged and abandoned on Dec 20, 1980, but requires removal of Arctic Pack and the wellhead to at least three feet below ground level consistent with current AOGCC regulations. The 9 -5/8" casing has a cement plug set from 0' -100'. Arctic Pack is present above TOC in the 9 -5/8" x 13- 3/8 "annulus at —3,000' and the 13 -3/8" x 20" annulus at — 2,000'. The current well schematic is attached to this procedure. The reservoir section of the well is effectively isolated; therefore no pressure at the wellhead is anticipated during wellhead removal and permanent plugging activities, and no pressure was found during a wellhead inspection in 2009. OBJECTIVE: Permanently remove wellhead, removal of up to 200' of Arctic Pack, plug all casing strings 1 to surface with cement, and install marker plate. The proposed abandonment will be supported by on -site equipment and materials such as excavator, camp, fuel, and other essential elements of remote operations. The following well abandonment program is planned: 1. Insure all necessary permits and applications are in place. Notify AOGCC at least 10 days before operations begin. 2. Excavate gravel around wellhead. Erect wellhead shelter and warm wellhead. Install catch pan around 36" well casing to receive returns from all casing annuli. Install pump to transfer fluids from catch pan to appropriate waste tank. 3. Install pressure gauges on casing and both annuli. Record pressures and bleed off pressure, if any. 4. Notify AOGCC of planned operations and confirm steps to be witnessed throughout operation. 5. Remove glycol mixture refrigerant from both annuli of the refrigerated /insulated conductor via compressed air or by vacuum. Pump returns from catch pan to waste tank. Note: the 2009 inspection found the refrigerant in lines to be crystallized. If the refrigerant is immobile, proceed to step 6. 6. Cut -off the 28" x 32" x 36" casing with a torch to allow for the future use of Wachs saw. Point TittntOrtUnit It AbandOnnien> Procedure. , . =k ; -4 .; ;,. r _; • • 7. Remove wellhead cap with 2" ball valve and verify (tag) 9 -5/8" cement plug. 8. Remove two FMC 3 -1/8 ", 5k gate valves. Send gate valves and 2" ball valve to warehouse stock in Anchorage. 9. RU Wachs saw and cut off wellhead. 10. RU false rotary. 11. Run 1" jointed pipe inside the 13 -3/8" x 20" annulus to about 200' and wash out Arctic Pack with warm diesel. Take Arctic Pack/diesel returns to dedicated waste tank. Leave joined pipe in hole for cement job to follow. 12. Run 1" jointed pipe inside the 9 -5/8" x 13 -3/8" annulus to about 200' and wash out Arctic Pack with warm diesel. Take Arctic Pack/diesel returns to dedicated waste tank. Leave joined pipe in hole for cement job to follow. 13. Run 1" jointed pipe inside the 32" x 36" conductor casing as deep as possible. Leave jointed pipe in hole for cementing to follow 14. Run 1" jointed pipe into 28" x 32" conductor annulus as deep as possible. Leave pipe in annulus for cementing to follow. Notes: • If unable to run 1" pipe to 150' or deeper in Steps 11 and 12, run pipes as deep as possible and contact AOGCC to obtain approval for alternative depth. • The configuration of refrigeration tubes and insulation in the conductor is uncertain. The intent is to remove as much of the refrigerant fluid and to run tubing as deep in the conductor annuli as possible in order to fill the annuli with as much cement as possible. 15. Prepare to cement two refrigerated /insulated conductor annuli and both casing annuli. Pump 10.7 ppg Permafrost cement to surface in both conductor annuli. Top off 28" x 32" x 36" refrigerated /insulated conductor casing with cement as required. 16. Pump 10.7 ppg Permafrost cement to surface in both 13 -3/8" x 20" and 9 -5/87" x 13 -3/8" annuli . Ensure good cement returns. With cement to surface in all four annuli and all jointed pipes full of cement, cut -off jointed pipes and leave in hole. Diesel returns from cementing to be pumped from catch pan to appropriate waste tank. 17. RU Wachs saw and make second cut of casing strings flush with conductor. This cut must be a minimum of 3' below tundra level. 18. Top off 9 -5/8" x 13 -3/8" and 13 -3/8" x 20" casings with cement as required. • • 19. Level casing stub using a grinder. Weld marker plate (circular plate w/ 36" OD) with well information across all casing strings. Marker plate to contain the following information bead welded onto it: Point Thomson Unit #4 Exxon Mobil Corporation PTD # 179 -080 API # 50 -089- 20009 -0000 20. Backfill cellar with gravel. Mound the gravel (5 -10') to compensate for summer thawing and settling as per AOGCC guidance. 21. Clean up location. Transport all wastes and site clean -up debris to Deadhorse for disposal at approved waste disposal sites in accordance with ExxonMobil Waste Management Plan. p ... . :hotl .oltn. ando nmentp edure l`�_- _:�': -V ... Y _. .. ib,t.,. _ k. �'S... t� "'`' ?}'.'` • • Current Wellbore Sketch Exxon Mobil Point Thomson Unit #4 API #: 60089200090000 APTD #: 179-080 McEvoy 20 -3/4 ", 3 kpsi A- section & McEvoy 13 -5/8 ", 5 kpsi B- section w/ flange cap & 2" ball valve 50 sx (8.3 bbls) PF cmt plug . + ��% 28" x 32" x 36" insulated/refri cond. at 91' in 95/8° from 0' to 100' t� ti % g ` I i 5 26" hole Arctic pack in 13 -3/8" x 20 & 9-5/8" x 13 -3/8" annuli ;:ii':. : 20 , 133 Ib/ft, K -55 at 2,127' y Cmt'd to surf w/ a total of 9,00 sx TOC in 13-3/8' x 20" at % Cl Brine p � % TOC 2,900± (estimated) ± 2,096', 100 sx (20 bbls), 3 15.0 ppg PF cmt followed '' TOC ± 3,098', BOC ± 3,442' by 350 bbls of arctic pack 100 sx (20 bbls), 15.0 ppg PF cmt followed by 180 bbls arctic pack 17 -1/2" hole ° Cmt retainer at 4100' 13 -3/8 ", 72 lb/ft, N at 3,422' Cmt'd w/ 835 sx permafrost ± 4026' ' f Sqz'd 13 -3/8" shoe 3 times w/ 990 sx of PF Pumped 23.2 bbls cmt below TOC of 4 026' in 95 csg retainer & 5.4 bbls on top 4 ottom f ,417 7" casing cut of at 4,319' 1 -1/4 °h TOC 8,950' cmt from at ± tem ture survey 13.6 ppg mud 9 -5/8 ", 47 Ib/ft, S -95 at 11,887' Cmt'd w/ 2,800 sx, 15.8 ppg, Class G Sgz'd 95/8" shoe w/ 200 sx class G Cmt retainer at 13,395' -@1r TOC 13,375' ? Sgz'd w/ 150 sx class G - p i a ' Baker Model F1 at 13,423' * Perfd 13,475' - 13,477' sgz'd twice w/ 150 & j x r r I 300 sx class G cmt r *r{ • Perfd 13,478' - 13,542', sgz'd w/ 150 sx class G Cmt retainer at 13,555' �i Perfd 13,560' - 13,562', sgz'd w/ 150 sx class G I TOC 13,625' +? 15.6 ppg mud i ` Bridge Plug at 14,707' Perfd 14,802' - 14,812' & 14,822' - 14,882' Sgz'd w/ 200 , later drilled out Perfd 14,807' sx - 14,812' & 14,822' - 14,877' Cmt retainer at 14,920' i Baker model F1 packer at 14,930' *' " }'t Y! r _ Perfd 14,954' - 14,956' sgz'd w/ 150 sx class G Perfd 14,956 - 14,976', sgz'd w/ 100 sx class G 15 007' '012'itirlat 7", 35/32 lb/ft, P -110 at 15,049' Cmt'd w/ 601 sx class G (partial returns at surf.) Total Depth 15,074' (13,194' TVD) Well sehematle drawn June 29 200 by Fairweather E & P Services, Inc. Updated April 13, 2009, July 26, 2009, and September 8, 2009 by EM ; 8 8 A: T? iR .:..:r '. 34Pf^U h .`niT+*S.'�3...� r .; : :� #3. j 4 Rs .-' . • tonMobil Point Thomson Unit #4 Current Wellbore Diagram (Detail) BOC in 9 -5/8" Cement Cap 100' *•"•••••••••"' Arctic y •� _ Arctic Pack in 13 -3/8" x 20" ���_: & 9 -5/8" x 13 -3/8" P 20 ", 133 Ibs /ft, K -55 @ 2,127 TOC in 13 -3/8" x 20" — 2,096' Estimated TOC — 2,900' —II— 10.2 ppg CaCl2 %rq Brine % e - TOC — 3,098' 13 -3/8 ", 72 Ibs /ft, N -80 @ 3,422' TOC in 9 -5/8" Casing — 4,026' BOC @ 4,417' 13.6 ppg TOC @ 8,950' 4 a. :'• Mud 9 -5/8" 47 Ibs /ft, S -95 @ 11,887' A A REV : 07 JAN. 2013 Point Thomson Unit #4 Abandonment Procedure V' l # • Proposed After P&A Wellbore Sketch ExxonMobil Point Thomson Unit #4 API #: APT° #: 179.080 Well marker plate at -3' below tundra 50 sx (8.3 bbls) PF cmt plug , # , \?. ' "" PF cmt inside 28" x 32° x 36" csg to -91' in 9-5/8" from 0' to 100' v'�•i t ` 28" x 32" x 36" insulated/refrig. cond. at 91' PF cmt in 13 -3/8" x20" & 9- �` s 26° hole 5/8" x 13 -3/8" annuli to -200' s 4 t{ 20", 133 lb/ft, K -55 at 2127' Arctic pack in 13 -3/8" x 20" t 10.2 ppg Cmt'd to surf w/ a total of 9,100 sx permafrost & 9-5/8" x 13 -3/8" annuli ■ CaCl Brine TOC ± 2,900' (estimated) TOC in 13 -3/8" x 20" at to r A TOC t 3,098', BOC t 3,442' ± 2,096', 100 sx (20 bbls), 100 sx (20 bbls), 15.0 ppg PF cmt 15.0 ppg PF cmt followed x' followed by 180 bbls arctic pack by 350 bbls of arctic pack 17 -1/2" hole ` 13 -3/8 ", 72 Ita/ft, N -80 at 3,422' Cmt'd w/ 835 sx permafrost ± 4,026' Sqz'd 13 -3/8" shoe 3 times w/ 990 sx of PF Cmt retainer at 4100' Pumped 23.2 bbls cmt below 4 1 1 TOC ± 4,026' in 9 -5/8" csg retainer & 5.4 bbls on top • 7" casing cut of at 4,319' } Bottom of cmt at ± 4,417' 12 -1/4" hole TOC 8,950' from temperature survey 13.6 ppg `.g mud - 1 9 -58 °, 47 lb/ft, S -95 at 11,887' Cmt'd w/ 2,800 sx, 15.8 ppg, Class G Sqz'd 9 -5/8" shoe w/ 200 sx class G TOC 13,375' 7 Cmt retainer at 13,395' Sqz'd w/ 150 sx class G . Baker Model F1 at 13,423' Perfd 13,475' - 13,477' sqz'd twice w/ 150 & 300 sx class G cmt Perfd 13,478' - 13,542', sqz'd w/ 150 sx class G Cmt retainer at 13,555' Perfd 13,560' - 13,562', sqz'd w/ 150 sx class G € TOC 13,625'+ 7 15.6 ppg t. mud �. - ( Bridge Plug at 14,707' Perfd 14,802' - 14,812' & 14,822' - 14,882' Sqz'd w/ 200 sx, later drilled out ' Perfd 14,807' - 14,812' & 14,822' - 14,877' Cmt retainer at 14,920' Baker model F1 packer at 14,930' ) -. Perfd 14,954' - 14,956', sqz'd w/ 150 sx class G Perfd 14,956 - 14,976', sqz'd w/ 100 sx class G 15,007' Si71111.1111 7 °, 35/32 lb/ft, P -110 at 15,049' Cmt'd w/ 601 sx class G (partial returns at surf.) Total Depth 15,074' (13,194' TVD) Well schematic dawn June 2901, 2007 by Fairweather E & P Services. Inc. Updated April 13, 2009, July 26, 2009, and September 8, 2009 by EM ;.11 4,1,414 ,,..:^±.4. i t X1,07.5.." Page 1 of 1 • Schwartz, Guy L (DOA) From: Juranek, Tom A [tom.a.juranek ©exxonmobil.com] Sent: Wednesday, February 20, 2013 1:59 PM To: Schwartz, Guy L (DOA) Cc: Dragnich, Rob /EXT Subject: Re: Sundry Applications for PTU #4 and WSS #18 -9 -23 (PTD 179 -080 & 169 -120) Msg Class:Unclassified No, we had issues getting rigged up on one of the other wells (WSS #2) and ran out of time before actually moving to PTU #4. Thanks, Tom Juranek From: Schwartz, Guy L (DOA) [mailto:guy.schwartz©alaska.gov] Sent: Wednesday, February 20, 2013 04:53 PM To: Juranek, Tom A Cc: Dragnich, Rob /EXT Subject: RE: Sundry Applications for PTU #4 and WSS #18 -9 -23 (PTD 179-080 & 169 -120 ) i, � p Tom, --at It looks like the PTU #4 procedure is mostly a re -issue of the sund #310 -061 was not completed 1 4-12:fr i due to the ice road degrading back in 2010. I didn't see any major change o the procedure... Was any work done back in 2010 that would require a report (10 -404)? Z t ' 1 3 Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Juranek, Tom A [ mailto :tom.a.juranek @exxonmobil.com] Sent: Tuesday, February 19, 2013 12:41 PM To: Schwartz, Guy L (DOA) Cc: Dragnich, Rob /EXT Subject: Sundry Applications for PTU #4 and WSS #18 -9 -23 (PTD 179 -080 & 169 -120) Guy, About 2 weeks ago, we submitted Sundry Applications for Point Thomson Unit #4 (PTD 179 -080) and West Staines State #18 -9 -23 (PTD 169 -120) for well remediation. I was just checking in to see if you needed anything further and the status of the applications. Please let me know if you have any questions or need any follow -up information. Thanks, Tom Juranek Subsurface Engineering Advisor EMPC Global Engineering- Houston Subsurface Engineering & Operations Support CORP- EMB -3039S Phone: 713 - 656 -4225; Fax: 713 - 656 -7353; BB: 832 - 596 -5406 email: tom.a.juranek @exxonmobil.com 2/21/2013 ExxonMobil Development Compao P.O. Box 241449 Anchorage, Alaska 99524-1449 907 564 3617 Telephone 907 743 9809 Facsimile ' :L.1 SEP 2 0 2010 Brien E. F Environments and Regulatory Manager Point Thomson Project fl Development September 15, 2010 eft CNILc oft ER -2010 -OUT -0148 Mr. To aunder? '1Ka Oil 8,Gas Conservation Commission 333 West 7th Avenue, Suite100 Anchorage, Alaska 99501 Re: Plug and Abandonment of PTU Wells Dear Mr. Maunder: > 11o(; -1a-0 As you are aware, efforts to re-enter the West Staines State (WSS) #2 and WSS #18-9-23 wells this past winter season encountered equipment difficulties. After considering the learning gained from this effort, ExxonMobil has developed a plan for moving forward. First we plan to complete the inspection of WSS #18-9-23 well by measuring the well's internal pressures, if any, by May 2011. Thereafter, we plan to remove diesel and/or Arctic Pack from PTU -4, WSS #2, and WSS #18-9-23 wells during the 2012/13 winter season pending the availability of an ice road to move the necessary workover equipment. Regarding the WSS #18-9-23 inspection, we have obtained the Vetco Gray crossovers for this work and hope to commence site operations by March 2011. Installation of new side outlet valve(s), obtaining the pressure measurement and backfilling the excavation around this wellhead will complete the well inspection portion of the remediation program. The next steprofthe remediation work involves removal of Arctic Pack from the upper portion of two annuli of4, installation of cement plugs in these annuli, welding an identification marker plate on the well, and backfilling and mounding the excavation to complete the plugging operations. Additional operations will involve the removal of diesel from WSS #18-9-23 well and diesel and Arctic Pack from WSS #2 well. We will be evaluating the use of coil tubing units, snubbing units, and workover rigs for the well re-entries. Our outlook is to conduct the work on these three wells during the 2012/13 winter season, pending the availability of an ice road. We will update the execution plans and schedule upon completion of our evaluation. Our Alaska Production Manager, Mr. Dale Pittman, met with Commissioner Cathy Foerster on August 25, 2010 and the presentation materials he provided included additional detail on ExxonMobil's inspection / remediation efforts and plans. An ExxonMobil Subsidiary Mr. Tom Maunder • -2- Seomber 14, 2010 If you would like to discuss ExxonMobil's plan further, please contact me at 907-564-3617 or via email (brien.e.reep@exxonmobil.com) or Jack Rickner at 281-217-4350 or via email Oack.a.rickner@exxonmobil.com). We are available to talk about the various aspects and progress towards completing this work program. Sincerely, -0<!f� For and On Behalf of Exxon Mobil Corporation BER:sw:mk Point Thomson Well Inspection and Remediation Work Plans AOGCC - Cathy Foerster Review August 2010 Meeting Objective Provide update of ExxonMobil's inspection and remediation efforts and latest plans Snubbing Unit at West Staines State #2 (March 2010) E.J(onMobil Production 40 0 Status Update February 2009 Plans • Perform well integrity inspection program on 9 ExxonMobil wells during Winter 2008/2009 (Phase 1) + Evaluate condition of gravel, flanges, valves, bull plugs, etc. and inspect wells for seepage or leakage + Check casing and annulus for pressure + Install side outlet gate valves + File Form 10-404 with AOGCC documenting inspections and conditions found • Remediate Alaska State J-1 during Winter 2008/2009 • Remediate PTU 4, WSS 18-9-23 and 2 during Winter 2009/2010 (Phase 2) Activities completed • All well integrity inspection activities completed with the exception of checking the casing and annulus pressure on WSS 18-9-23 (at time of inspection, unable to add a new gate valve since existing valve did not have flanged ends) • Alaska State J-1 remediated as planned • In Winter of 2009/ 2010, completed gravel pad remediation at Bullen Point • Attempted to complete the Phase 2 remediation scope of work in Winter 2009/2010 (i.e. PTU 4, WSS 18-9-23 and 2) but was unsuccessful 2 E*(onMobil Production 0 0 Status Update (continued) Winter 2009/2010 Remediation Activities • Built ice ramp to PTU -4 and ice road spurs off of main ice road to the Point Thomson Unit Central Pad • Surveyed WSS 18-9-23 for gravel contamination • Executed a lump sum contract with contractor to complete all remediation activities for PTU 4, WSS 18-9-23 and 2 • Mobilized camp, snubbing unit, crane and additional equipment and began remediation efforts on WSS 2 • Installed anchors, anchor lines to BOP stack, rigged up hydraulics and tested BOP stack • Effort shutdown due to safety concerns and indications that contractor would be unable to complete work as planned • and scheduled • Key Lessons Learned - snubbing unit not previously used in Arctic service created challenges + Inadequate winterization + Inadequate advanced planning complicated mobilization and rig -up + Extensive required use of crane complicated by North Slope wind conditions + Non -North Slope equipment resulted in delays Current Plans • Winter 2010/2011 - Install gate valves on WSS 18-9-23 to enable annulus and casing pressure testing • Conduct risk assessment and pursue other work -over rig options to ensure a safe and more efficient execution of the remediation scope of work (note: access to pads limited to winter periods) • If snubbing unit still required, may need "winterization" retrofit to ensure work can be performed safely in the winter • months • Will update execution plans and schedule as additional data is gathered, but tentatively targeting Winter 2012/2013 to reschedule remediation activities (scope of work will also includes pad remediation at WSS 18-9-23 and 2) 3 E)XonMobil Production Scope of Well Remediation (WSS 18-9-23 and 2, PTU 4) Remediation Procedure • Remediate WSS 18-9-23 as follows: — Drill out bridge plug at 150' — Verify presence of bridge plug and cement at 2000' — Replace diesel in 9 5/8" down to 200' with CaCl2 — Perforate casing @ 1000', circulate out annulus fluids and cement — Spot cement to surface — Remove wellhead to 3' below ground level — Weld marker cap — Fill excavation with gravel — File Well Completion or Recompletion Report and Log Form with AOGCC documenting P&A • Remediate WSS 2 in similar manner • Remediate PTU 4 — Remove Arctic pack (rather than diesel) in annuli — PTU #4 contains CaCl2 below surface plug Risk Assessment • Removal of diesel below shallow bridge plugs on WSS 18-9-23 & 2 — Potential pressure below bridge plug at 2000' is a risk — Use of a coiled tubing unit has not proven to be a viable option — Going through a risk assessment but snubbing unit may be only option 4 E.,XonMobiI Production 0 0 Ion Elim 117S to • 12-6 i+ Rmaanb s 0 acs .YT -Ulm W -oupc iq C: Pur ems `.rE-c4 A -A tit SS • £ SErms'#6E .3 CC L 56 -MG UE :d ZE3 :.! 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I dm LC 40MB X1:1 4VA xCld ul UD IM V M40ft. LO 0 G � ACCO l 19 jXl _ 0 W m ,`s7d"EI IQ �I�k! ' W24 CnIC IMM ,98 CE U2 }. m dB t -v w cis AS'0' ;R ZLV M 19 X1319 t%YM W .LEC 3t 42.> sa sere 19 MI-17-Zd r -V6'3 to 124,_: is 031 iCl'E-.iP7'i — uwWsryna.a .&'S-6 x ..FwE-U UJILMOD Sri, t:p POI Ac Stc--Sl xwp.rs JURM AS 9 1 t LOW. P7AMA- -',C£ �t C d.tte:•.BtS-bulF id_ ar;__ }v: {al s .r: c'iPW-.3E P424MMic a, DW S'St l4YY .E9 - Ehl!! I dm LC 40MB X1:1 4VA xCld ul UD IM V M40ft. LO • Page 1 of 1 Maunder, Thomas E (DOA) From: Crisp, John H (DOA) t� Sent: Thursday, April 08, 2010 8:20 AM ! \5 —0 Q To: Regg, James B (DOA) c f��\ Cc: Maunder, Thomas E (DOA) \ S — \ �V Subject: CUDD West Staines VAS - d 5� Just a note about the P &A on West Staines. We were attempting to test the Annular preventer, the CH2MHill Rep. had a conference call with Exxon. They pulled the plug on the job & decided to De- Mobe equipment before Ice Road problems. This decision saved a lot of controversy. I'll make a detailed report with photos. Looked like Mardi Gras North Slope style because the CUDD hands were so happy. FEB Ze d 4/9/2010 411 411 Subject RE: Rig Down of WSS #2 Efforts Jack, et al, Sounds like the good, tough call. I am not sure of any other requirements right now. On the other effort up there, was any work able to be accomplished on PTU #4? Regards, Tom Maunder, PE AOGCC Original Message From: jack.a.rickner @exxonmobil.com [ mailto :jack.a.rickner @exxonmobil.com] Sent: Thursday, April 08, 2010 8:56 AM To: Maunder, Thomas E (DOA) Cc: michael .d.murrey @exxonmobil.com; silas.wong @exxonmobil.com; brien.e.reep @exxonmobil.com; rob.g.dragnich @exxonmobil.com Subject: Rig Down of WSS #2 Efforts Tom, perhaps by now you have heard from your field inspectors that we have made a decision to stop further work efforts to complete the defined remediation work on West Staines State #2 well. There are a number of reasons for this decision but probably the foremost reason is the late date in this winter's season. As of yesterday, we had not competed the initial BOP testing, would have had another day or two to complete the RU after completion of a good test, then perhaps 6+ days to complete the necessary well work, and another 14 days to RD and demob approximately 100 loads of snubbing unit and camp equipment /materials. As you might expect, that would almost certainly carry us into the very end of this month or May without weather delays or any mechanical problem with the defined well work. Given the current and forecasted warming conditions which almost certainly will lead to degrading ice road conditions, we decided to not tempt fate any longer and retreat while we can. Since we have not drilled the surface plug and were able to verify that the surface plug is intact and solid, we feel that we can safely RD and button -up the well leaving it in a safe condition. We will meet with CH2MHill and Cudd after the demob has been completed to evaluate this season in preparation for future efforts. We would like to visit with you after that evaluation to share our learnings. Again, I regret having to send you this note. I'll call later today to discuss this decision with you and determine if additional action may be required on our part. Regards, Jack Jack A. Rickner Environmental & Regulatory Group Point Thomson Project 907 -564 -3638 281- 217 -4350 • Original Message From: Maunder, Thomas E (DOA) Sent: Thursday, April 08, 2010 9:28 AM To: 'jack. a. rickner@exxonmobil.com' Cc: brien.e.reep @exxonmobil.com; michael .d.murrey @exxonmobil.com; rob. g. dragnich@exxonmobil.com; silas.wong @exxonmobil.com Subject: RE: Rig Down of WSS #2 Efforts Jack, et al, The decision to accomplish any activity during the remainder of the season on these wells is Exxon's to make. I only asked the question for information purposes since I was aware that the sundry was issued for PTU #4. Best regards, Tom Maunder, PE AOGCC Original Message From: jack.a.rickner @exxonmobil.com [ mailto :jack.a.rickner@exxonmobil.com] Sent: Thursday, April 08, 2010 9:23 AM To: Maunder, Thomas E (DOA) Cc: brien.e.reep @exxonmobil.com; michael .d.murrey @exxonmobil.com; rob.g.dragnich @exxonmobil.com; silas.wong @exxonmobil.com Subject: RE: Rig Down of WSS #2 Efforts Tom, thanks for your quick response. During our conference call yesterday with the field personnel to discuss this decision, I asked if it would be possible to complete the work on PTU - 4. At this point, all our efforts are focused on conducting a safe and orderly demob operations. I have asked our field personnel and contractor to keep completion of PTU - well work as an option. I will revisit this question with our field personnel and CH2MHi11 early next week. We will be evaluating how well our demob is progressing, the current weather conditions and projected forecast, and available personnel. I would like to delay a decision on PTU -4 for perhaps a week and provide an answer at that time. Regards, Jack Jack A. Rickner Environmental & Regulatory Group Point Thomson Project 907 - 564 -3638 281- 217 -4350 "Maunder, Thomas E (DOA) " To <tom.maunder@a jack.a.rickner@exxonmobil.com laska.gov> cc michael. d. murrey@exxonmobil.com, silas.wong @exxonmobil.com, 04/08/2010 brien.e.reep @exxonmobil.com, 08:59 AM rob.g.dragnich @exxonmobil.com • • Subject RE: Rig Down of WSS #2 Efforts Jack, et al, Sounds like the good, tough call. I am not sure of any other requirements right now. On the other effort up there, was any work able to be accomplished on PTU #4? Regards, Tom Maunder, PE AOGCC Original Message From: jack.a.rickner @exxonmobil.com [ mailto :jack.a.rickner @exxonmobil.com] Sent: Thursday, April 08, 2010 8:56 AM To: Maunder, Thomas E (DOA) Cc: michael .d.murrey@exxonmobil.com; silas.wong@exxonmobil.com; brien.e.reep @exxonmobil.com; rob.g.dragnich@exxonmobil.com Subject: Rig Down of WSS #2 Efforts Tom, perhaps by now you have heard from your field inspectors that we have made a decision to stop further work efforts to complete the defined remediation work on West Staines State #2 well. There are a number of reasons for this decision but probably the foremost reason is the late date in this winter's season. As of yesterday, we had not competed the initial BOP testing, would have had another day or two to complete the RU after completion of a good test, then perhaps 6+ days to complete the necessary well work, and another 14 days to RD and demob approximately 100 loads of snubbing unit and camp equipment /materials. As you might expect, that would almost certainly carry us into the very end of this month or May without weather delays or any mechanical problem with the defined well work. Given the current and forecasted warming conditions which almost certainly will lead to degrading ice road conditions, we decided to not tempt fate any longer and retreat while we can. Since we have not drilled the surface plug and were able to verify that the surface plug is intact and solid, we feel that we can safely RD and button -up the well leaving it in a safe condition. We will meet with CH2MHi11 and Cudd after the demob has been completed to evaluate this season in preparation for future efforts. We would like to visit with you after that evaluation to share our learnings. Again, I regret having to send you this note. I'll call later today to discuss this decision with you and determine if additional action may be required on our part. Regards, Jack Jack A. Rickner Environmental & Regulatory Group Point Thomson Project 907 -564 -3638 281- 217 -4350 • ~~Q~C~ OCR a~Q~~(Q /.~.M.~Ew~o~.~ Dale Pittman Alaska Production Manager Exxon Mobil Corporation ~u~, ~, ~ ~_; ,~ P.O. Box 196601 `~~~~~`y ~~~~ ~ ~ Vic`' Anchorage, AK 99519-6601 ~g ~' _/ Re: Point Thomson Field, Point Thomson Unit No. 4 ~ --- Sundry Number: 310-061 ~~ Dear Mr. Pittman: 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 rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Seamount, Jr. Chair DATED this ~ ~ day of March, 2010. Encl. ExxonMobil Production Company. P. O. Box 196601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone 907 564 3677 Facsimile February 22, 2010 Dale Pitt Alaska Production Manager Joint Interest U.S. E~onMobil Production RE~~IVED Mr. Daniel T. Seamount, Jr. Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Sundry Application for Remediation ExxonMobil Point Thomson Unit #4 PTD No. 179-080 Dear Commissioner Seamount: FEB ~ 2010 All~ske 0~ ~ bas cons. Commissiiarl Anchorage Exxon Mobil Corporation hereby submits an Application for Sundry Approval to perform remedial plugging and abandonment work on the subject well. This work was described in ExxonMobil's letter of November 14, 2007 to the AOGCC and has been discussed in corre~p~ndence and meetings between AOGCC and ExxonMobil staff. The work is described in more detail in the attached. The general procedure will be: 1. Excavate the well cellar and check pressures on the 9-5/8" casing, the 9-5/8" x 13-3/8" annulus, and the 13-3/8" x 20" annulus to verify there is no surface pressure. 2. Cut off all casing strings and wellheads at least 3' below the natural tundra level. 3. Verify the integrity of the surface cement plug in the 9-5/8" casing. 4. Remove arctic pack from two annuli and cement annuli with permafrost cement to surface. 5. Cement the 28" x 32" x 36" insulated/refrigerated conductor annuli with permafrost cement from about 91' to surface. (-T -~c-Q2 c~e~t ~,~}-SQEc,~cr~~.~@c'~s~c+~~~~~`,c ~w~~t 6. Remove the diesel in the 9-5/8" casing and fill casing with permafrost cement. 7. Install well identification marker cap, backfill excavation with gravel and mound gravel to allow for settling. Please find enclosed the following information: • Form 10-403 Application for Sundry Approval (Original and 1 copy) • Revised Wellhead Schematic • Current Wellbore Schematic • Proposed Wellbore After Remediation Schematic • Overview of Remediation Procedure If you have any questions or require additional information, please contact Jack Rickner at 564- 3638. Sincerely DDP:eaa Attachments A Division of Exxon Mobil Corporation • • STATE OF ALASKA 3, i 1 ALASKA OIL AND GAS CONSERVATION COMMISSION RECEIVED EEB 2 5 2010 APPLICATION FOR SUNDRY APPROVALS Alaska Oil ~ 6as Cons. Commission Zo AAC 25.280 Anchorage 1. Type of Request: Abandon ^ Plug for Redrill ^ Perforate New Pool ^ Repair Well ^ Change Approved Program ^ Suspend ^ Plug Pertorations ^ Pertorate ^ Pull Tubing ^ Time Extension ^ Operations Shutdown ^ Re-enter Susp. Well ^ Stimulate ^ Alter Casing ^ Other: Well Remediation0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exxon Mobil Corporation Development ^ Exploratory ~ 179.080 3. Address: Stratigraphic ^ Service. ^ 6. API Number: PO Box 196601, Anchorage, AK 99519-6601 50-089-20009-0000 7. If pertorating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: N/A Spacing Exception Required? Yes ^ No ^ Point Thomson Unit No. 4 ' 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 47563 Point Thomson 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): 15,074 13,194 Surtace Surface See Attached None Casing Length Size MD TVD Burst Collapse Structural 91' 30" 91' 91' N/A N/A Conductor 2102' 20" 2127' 2127' 3060 1500 Surtace 3397' 13 3/8" 3422' 3422' 5380 2670 Intermediate 11862' 9 5/8" 11887' 10222' 7290 7100 Production 10730' 7" 15049' 13170' 13700/12460 13010/10760 Liner N/A N/A N/A N/A N/A N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): N/A N/A N/A N!A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A N/A 12. Attachments: Description Summary of Proposal Q 13. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^~ Development ^ Service ^ 14. Estimated Date for 2-Mar-10 15. Well Status after proposed work: Commencing Operations: Oil ^ Gas ^ WDSPL ^ Plugged ^ 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 Jack Rickner 907-564-3638 Printed Name le-Pittn n Title Alaska Production Manager Signature Date ~I~H/~o 0 COMMISSION USE ONLY Conditi f l N tif it d N b 3/D'"C/((// ' C i i th t t ti S ons o approva : y ve may w ness un ry um er: ., o omm ss on so a a represen a Plug Integrity ~ BOP Test ^ Me chanical Integrity Test ^ Location Clearance s c ~ Other: h©~Y~`-~~~-~~tT~C ©T ~ eP~~n~ T~ ~ ~~ ~~T ~~ ~G~~ Subsequent Form Required: ~~ L` ~~ ~~ ~ ~`~ L~~O~ ~r ~ ~O.\\~ r~1~ CG~V G.. i ~ { ~ C). 1~ S C> ` ~L `` ~ C-~c3~-~ ~ , APPROVED BY ~1, COMMISSIONER THE COMMISSION Date: ~ J / ~ I~ A o d b ppr ve y: Ate/ Y ~ . ~ ~` I A L RBDMS MAR 12 2010 ~ .~~ ~• ``~ - ~ Form 10-403 Revised 12/2009 ~ Submit in Duplicate !O • i Pt. Thomson Unit #4 Notes: Marker Post Top Flange Tapped 2" Ball Valve in Flange 13 5/8" 5M - Inside valve McEvoy model C 31/8" 5M Outboard valve Model 120+ 3 1/8" 5M err 20 3/4" 3M 3M-5M Adapter Inside valve McEvoy model C 3 1/8" 3M Outboard valve Model 120+ 3 1/8" 5M McEvoy Split Speedhead System Current Wellbore Sketch Exxon Mobil Point Thomson Unit #4 API #: 60089200090000 APTD #: 179-080 • McEvoy 20-3/4", 3 kpsi A-section & McEvoy 13-5/8", 5 kpsi B-section w/flange cap & 2" ball valve 50 sx (8.3 bbls) PF cmt plug ~ ~ ~ ~t~;... in 9b/8" from 0' to 100' fi ~ ~ ~` ' _ - ~ ~ 28" x 32" x 36" insulated/refrig. cond. at 91' ' 26" hole Arctic pack in 133/8" x 20" & 9-5/8" x 13-3/8" annuli ( 20", 133 Ib/ft, K-55 at 2,127 TOC in 133/8" x 20" at t 2,096', 100 sx (20 bbls), 15.0 ppg PF cmt followed by 350 bbls of arctic pack 17-1 /2" hole Cmt retainer at 4100' Pumped 23.2 bbls cmt below retainer & 5.4 bbls on top 7" casing cut of at 4,319' 10.2 ppg Cmt'd to surf w/ a total of 9,100 sx permafrost CaCIZ Brine ~--TOC 2,900't (estimated) TOC t 3,098', BOC t 3,442' 100 sx (20 bbls), 15.0 ppg PF cmt followed by 180 bbls arctic pack 13-3/8", 72 Ib/ft, N-80 at 3,422' Cmt'd w/ 835 sx permafrost t 4026' ~ Sgz'd 13-3/8" shoe 3 times w/ 990 sx of PF .~ y TOC t 4026' in 9-5/8" csg Bottom of cmt at ± 4,417' 12-1/4" hole TOC 8,950' from temperature survey 13.6 ppg mud 9-5/8", 47 Ib/ft, S-95 at 11,887' Cmt'd w/ 2,800 sx, 15.8 ppg, Class G Sgz'd 9b/8" shoe w/ 200 sx class G Cmt retainer at 13,395' Sgz'd w/ 150 sx class G TOC 13,375' ? Baker Model F1 at 13,423' Perf'd 13,475' -13,477' sgz'd twice w/ 150 & 300 sx class G cmt PerFd 13,478' -13,542', sgz'd w/ 150 sx class G Cmt retainer at 13,555' ~."n~,~ +~ " Perfd 13,560' -13,562', sgz'd w/ 150 sx class G ~,,, TOC 13,625'+? 15.6 ppg mud ``s Bridge Plug at 14,707' Perfd 14,802' -14,812' & 14,822' -14,882' Sgz'd w! 200 sx, later drilled out Perfd 14,807' -14,812' & 14,822' -14,877' Cmt retainer at 14,920' Baker model F1 packer at 14,930' PerFd 14,954' -14,956', sgz'd w/ 150 sx class G Perf'd 14,956 -14,976', sgz'd w/ 100 sx class G 15 007' " 7", 35/32 Ib/ft, P-110 at 15,049' Cmt'd w/ 601 sx class G (partial returns at surt.) Total Depth 15,074' (13,194' TVD) Well schematic drawn June 29'", 2007 by Fairweather E & P Services, Inc. Updated April 13, 2009, July 26, 2009, end September 8, 2009 by EM • Proposed After PS.A Wellbore Sketch ExxonMobil Point Thomson Unit #4 API #: 50089200090000 APTD #: 179-080 50 sx (8.3 bbls) PF cmt plug 5 -' '~F cmt inside 28" x 32" x 36" csg to ~91' ... 7 ~ in 9-5/8" from 0' to 100' s ~ ~. u ' 28" x 32" x 36" insulated/refrig. cond. at 91' P(= ci71t i!n 9 3-3I8" x. 20" ~ 9 ~ 26" hole 5r'S" ,t i'~-318" ~nrst!h tc> ~2G~~` ) 20", 133 Ib/ft, K-55 at 2,127' Arctic pack in 13-3/8" x 20" " " 10 2 ppg Cmt'd to suit w/ a total of 9,100 sx permafrost & 9~/8 x 13-3/8 annuli CaCl2 Brine TOC t 2,900' (estimated) TOC in 13-3/8" x 20" at TOC t 3,098', BOC t 3,442' t 2,096', 100 sx (20 bbls), 100 sx (20 bbls), 15.0 ppg PF cmt 15.0 ppg PF cmt followed followed by 180 bbls arctic pack ~ by 350 bbls of arctic pack ~: 17-1/2" hole 13-3/8", 72 Ib/ft, N-80 at 3,422' Cmt'd w/ 835 sx permafrost Sgz'd 13-3/8" shoe 3 times w! 990 sx of PF Cmt retainer at 4100' ~ ± 4,026' ~ Pumped 23.2 bbls cmt below ~ ~ TOC t 4,026' in 9-518" csg retainer & 5.4 bbls on top ~ _ ~ 7" casing cut of at 4,319' ~ s~ ~ '" ~ ` ~ Bottom of cmt at t 4,417' ~ 12-1/4" hole 13.6 ppg mud TOC 8,950' from temperature survey 9-5/8", 47 Ib/ft, S-95 at 11,887' Cmt'd w/ 2,800 sx, 15.8 ppg, Class G Sgz'd 9-5/8" shoe w/ 200 sx class G r TOC 13,375' ? Cmt retainer at 13,395' Sgz'd w/ 150 sx class G Baker Model F1 at 13,423' Pert'd 13,475' -13,477' sgz'd twice w/ 150 & 300 sx class G cmt Pert'd 13,478' -13,542', sgz'd w/ 150 sx class G Cmt retainer at 13,555' ., ~ Pert'd 13,560' -13,562', sgz'd w/ 150 sx class G ~ TOC 13,625'+ ? 15.6 PP9 mud Bridge Plug at 14,707' Perfd 14,802' -14,812' & 14,822' -14,882' } Sgz'd w/ 200 sx, later drilled out ~' ` PerFd 14,807' - 14,812' & 14,822' -14,877' Cmt retainer at 14,920' ~ '. Baker model F1 packer at 14,930' ~ ` ~ ` Perfd 14,954' - 14,956', sgz'd w/ 150 sx class G > ` ' Pert'd 14,956 - 14,976', sgz'd w/ 100 sx class G ' ` 15,007' 7", 35/32 Ib/ft, P-110 at 15,049' Cmt'd w/ 601 sx class G (partial returns at suit) Total Depth 15,074' (13, 194' TVD) Well schematic drawn June 29`", 2007 by Fairweather E & P Services, Inc. Updated April 13, 2009, Juy 26, 2009, and September 8, 2009 by EM Point Thomson Unit #4 Point Thomson Field Well Remediation Procedure Overview of Remediation Procedure: 1. Ensure all necessary permits and applications are in place. Notify AOGCC: • at least 10 days before operations begin and review procedure • at least 48 hrs prior to cementing and capping the well, due to remote well location • of any procedural changes during operations 2. Mobilize all personnel and equipment to the Point Thomson Unit #4 location via ice road. Record travel routes and well location using GPS. 3. Observe and record any signs of hydrocarbon leaks in the area surrounding the well. Take photographs showing the condition of the surrounding location. A detailed report .documenting any contamination will be prepared. 4. Hold safety meeting. Excavate gravel and any cement from around the wellhead. Note: well has a deep cellar. Take photographs showing the condition of the wellhead as found. Document any areas of concern. 5. Check for HC by using a gas analyzer. Warm up the wellhead using heaters to remove any ice plugs to the extent possible. 6. Check wellhead pressures. If pressure is observed, perform diagnostic testing to determine if the pressure is sustained casing pressure or trapped pressure. Record pressure bleed down and build up. Record the fluid type and volume. Take fluid samples for possible analysis. Note: no wellhead pressures were found when the well was inspected on April 22, 2009. 7. Remove top wellhead flange with 2" ball valve and tag 9-5/8" surface cement plug. Clean out any cement below the 9-5/8" casing hanger slips. 8. Rig up internal mechanical cutter and cut the 9-5/8" casing below the 9-5/8" hanger slips. The 9-5/8" casing should drop deeper into the wellbore after the cut. Remove wellhead B-section. 9. Rig up internal mechanical cutter and cut the 13-3/8" casing just below the slips. The 13-3/8" casing should drop deeper into the well bore after the cut. 10. Attempt to remove any refrigerant from the insulated conductor by circulating warm 10.7 ppg CaCl2 brine. 11. Cut-off the 28" x 32" x 36" insulated/refrigerated casing with a torch as needed to allow access to the 20" casing string with the Wachs Guillotine saw. 12. RU Wachs Guillotine saw around the 20" casing. Cut-off the 20" casing and wellhead, including 13-3/8" and 9-5/8" casing stubs if they didn't drop below the cut point. 13. Weld on a full opening flow nipple with a side outlet (e.g., flow tee) to the 20" casing stub and route a return fluids line to a 55 gallon drum. Page 1 • 14. RU false rotary. Run small diameter jointed tubing inside the 9-5/8" x 13-3/8" annulus to about 200' and wash out Arctic Pack with warm diesel. It may be necessary to remove the Arctic Pack in steps, such as 50', 100', 150', and 200'. Flush diesel with warm 10.7 CaCl2 brine. 15. RU Cement Unit. Mix and spot 15.7 ppg, 0.93 ft3/sk, permafrost cement plug inside the 9- 5/8" x 13-3/8" annulus from about 200' to surface (150' minimum requirement). POH with small tubing. 16. Run small tubing inside the 13-3/8" x 20" annulus to about 200' and wash out Arctic Pack with warm diesel. It may be necessary to remove the Arctic Pack in steps, such as 50', 100', 150', and 200'. Flush diesel with warm 10.7 CaCl2 brine. 17. RU Cement Unit. Mix and spot 15.7 ppg, 0.93 ft3/sk, permafrost cement plug inside the 13-3/8" x 20" annulus from about 200' to surface (150' minimum requirement). POH with small tubing. 18. Cut off the 20"flow nipple. 19. Run small tubing inside the 28" x 32" x 36" conductor casing down to the casing shoe at 91' if possible. Circulate warm 10.7 CaCl2 brine. Mix and spot 10.7 ppg, permafrost light weight cement plugs from about 91' to surface. POH. All casino annuli must contain permafrost cement to surface. Permafrost light weight cement is recommended due to concern of breaking down the shallow set conductor casing shoe. 20. Top-off the 9-5/8" surface plug with 15.7 ppg, 0.93 ft3/sk, permafrost cement as required. 21. Cut and level casing stubs as needed. The well cap must be at least 3' below tundra level, per AOGCC regulations. Weld marker plate with the required AOGCC information on it across all casing strings, including the 28" x 32" x 36" conductor casing. Take photographs showing the condition of the casing stubs and marker plate. 22. Backfill cellar with gravel. Mound the gravel (~5-10') to compensate for summer thawing and settling as per AOGCC guidance. 23. Conduct general location clean-up. Take photographs showing the condition of the location. Final well site restoration will be performed at a later date. 24. Transport all wastes and site clean-up debris to Deadhorse for disposal at approved waste disposal sites in accordance with EM's Waste Management Plan. 25. Prepare final well report and Sundry Report. 26. After the summer thaw, notify AOGCC for visual inspection and site clearance. Page 2 U NOTE TO FILE 175-002 ExxonMobil West Staines State #2 310-060 Exxon has made application to perform remedial plugging and abandonment work on the subject well. This and other work proposals are in fulfillment of Exxon's commitment to perform remedial plugging and abandonment work on legacy wells in the Pt. Thomson Unit following a series of Commission letters beginning in May 2007. I recommend approval of Exxon's proposal. This proposal as well as one for West Staines State #18-9-23 (169-120) is the first new work proposed where Exxon plans to re-enter legacy wellbores. The need to re-enter the wellbores is to remove and replace the diesel in the wellbores through the permafrost interval and prepare the wells for final plug and abandonment including wellhead removal. Similar work was successfully accomplished about 1998 in several other Exxon legacy wellbores at Pt. Thomson. Similar work has also been successfully accomplished by CPAI and BP in their legacy wellbores. The novel proposal for this latest work is employing a hydraulic workover or snubbing unit to allow pipe movement in the well. In order to remove the diesel, it will be necessary to drill out the surface plugs placed in the well long ago. The snubbing unit is one of 3 possible ways to be able to move pipe in the well. The others are a conventional rig or coiled tubing. Coiled tubing was employed in the 1998 Exxon work. The Inspectors have expressed reservations about using this equipment due to it being "stick built" and potentially not adequately shielded from the elements. Both the Inspectors and myself have expressed concerns regarding the nearly exclusive use of hammer union connections. After contacting Exxon, high pressure hoses have been included in the choke and kill lines and an equipment placement drawing and winterization plan provided. It is my assessment that Exxon and their contractor (CH2MHill) have considered the need to keep equipment, fluids, etc from freezing and have made plans to have the necessary equipment available. Regarding fluid lines, the choke and kill lines are easily the most critical. These now will be flanged hoses. All hammer union connections have not been eliminated, but given short time duration (likely less than 1 month) that this equipment will be employed it is my opinion that eliminating all such connections is not practical. The lines will be tested according to the regulations and Exxon will need to make repairs, if necessary, to allow pressure competence to be demonstrated to that satisfaction of the attending Inspector. Employing multiple no-flanged connections should not compromise the ability to control any pressures. To date no pressures associated with hydrocarbon reservoirs have been encountered in the many prior similar re-entries that have been accomplished. The planned work will result in the removal of the surface cement plug, but there is no intent to disturb any deeper plug in the well although the plug at near the base of the permafrost may be tagged. It is uncertain if tagging the plug as proposed will be possible. Shallow • • collapsed casing has been encountered in several of the past re-entries and in particular in wells where prior work had been accomplished more that 15 years ago. Collapsed casing was encountered in the Alaska State A-1 (179-080) during the 1998 work. The collapsed casing has not precluded removing the diesel in those wells. I recommend approval of Exxon's proposal. ~~ ~ Tom Maunder, PE Sr. Petroleum Engineer ExxonMobil Development Company 3301 C Street, Suite 400 Anchorage, Alaska 99503 907 564 3617 Telephone 907 564 3772 Facsimile February 8, 2010 Brien E. Reep Environmental and Regulatory Manager Point Thomson Project E~onMob~l ___ 1~e~ael~~~azent Mr. John Easton ~::.'~~;~~~~?y ~'~~~ ~` ~ ;~~':r' FEE y 0 2010 Alaska Department of Natural Resources ~k/ C O is~ion Division of Oil and Gas 550 West 7th Avenue, Suite 800 ~t1GhAti~ Anchorage, Alaska 99501 p~~~c~~sc~t~ ~~~~~ ~ ~~ Re: Lease/Unit Plan of Operations Applications ` ~ ~ _ ~~~ Point Thomson Area Site Remediation Project ~ ~~, ~ .a Dear Mr. Easton: l~ ~ , ~ Exxon Mobil Corporation requests a royal to conduct site mediation at the West Stain Pp es State #2 (WSS #2) and at the West Staines State #18-09-23 (WSS #18-09-23) exploratory well locations as set forth in the attached Lease/Unit Plan of Operations Applications. We also request approval to perform remediation on these and the Point Thomson Unit #4 (PTU 4) well. This work is being conducted in conjunction with other remediation projects in the Point Thomson area. The overall effort is described in the attached Project Description entitled "2010 Inspection and Remediation Program, Point Thomson Area" and corresponding Coastal Project Questionnaire. These documents were amended on February 5, 2010, to reflect the discussion and agreements reached in January 29, 2010 meeting with ADEC and ADNR. The specific approvals requested from the DOG are: West Staines State #2 Gravel/Reserve Pit Remediation - LO/NS Application Attached Exploration activities at the WSS #2 site were previously authorized by LO/NS 74-24. The WSS #2 site has an open reserve pit that will be closed in accordance with a Corrective Action Plan (CAP) submitted to the Alaska Department of Environmental Conservation for approval on January 13, 2010. The reserve pit contains ice and water that will be removed and transported to the Prudhoe Bay area for disposal. Following sampling and characterization under a Phase II Site Assessment Work Plan, also to be approved by ADEC, gravel from the WSS #2 pad will be placed into the reserve pit as part of the closure process. Gravel will not be removed below the level of the surrounding tundra unless that is necessary to meet clean-up levels. If additional gravel is required to fill and level the reserve pit, gravel will be taken from the nearby WSS #18-09-23 exploratory well gravel pad. Field surveys have indicated sufficient gravel is available at these two sites to fill the reserve pit. Site rehabilitation following gravel removal will be conducted as described in the ADEC approved CAP. An Exx®nMobii Subsidiary Mr. John Easton -2- February 8, 2010 West Staines State #18-09-23 Gravel Remediation - LO/NS Application Attached Exploration activities at the WSS #18-09-23 site were previously authorized by LO/NS 69-017. Following sampling and characterization under a Phase II Site Assessment Plan and CAP, both to be approved by ADEC, it is proposed to remove as much gravel from the WSS #18-09-23 pad as necessary to fill and mound the open reserve pit at the WSS #2 location. Gravel will not be removed below the level of the surrounding tundra unless that is necessary to meet clean-up levels. Site rehabilitation following gravel removal will be conducted as described in the ADEC approved CAP. WSS #2, WSS #18-09-23, PTU #4 Well Remediation - LO/NS 09-007 Concurrence Section 4.2 of the attached Project Description describes the remedial work that will be performed on three exploratory wells (WSS #2, WSS #18-09-23, and Point Thomson Unit #4 (PTU #4)) in the Point Thomson area. The remedial well work is to bring their abandonment condition into conformance with current AOGCC regulations. No other well re-entry or drilling operations will be undertaken at these locations. Approval for investigative work on these wells was provided administratively under LO/NS 09-007 on March 16, 2009. The investigative work was performed during the winter of 2008-09 and there are no changes to the well remedial work as described in the December 2008 Project Description and amended on March 5, 2009. We would appreciate confirmation that LO/NS 09-007 authorizes ExxonMobil to conduct the well remedial work described. The reserve pit closure, site rehabilitation, and well remediation activities will be performed concurrently as a single, overall project and will rely upon some of the same support services and personnel. Accordingly, they are described in a single Project Description and Coastal Project Questionnaire. The Inspection and Remediation Program is a separate project from the Point Thomson drilling activities described in the February 10, 2009, Plan of Operations for Point Thomson Drilling. However, it will be supported by and will use the ice roads, other infrastructure, and permits established for drilling activities. The ice road between Endicott and the Central Pad location will serve as a supply road and the origination point for inspection and remediation activities. Access from the ice road to the individual well sites will be supported by agency-approved off- road vehicle travel or by conventional vehicles travelling on additional spur ice road routes that may be constructed. Previously this type of activity has been found consistent with GCD-49 and A-List #3, #4, and #7. ExxonMobil has reviewed General Concurrence 49, Removal of Uncontaminated Gravel Structures, and has adopted the alternative measures (termed "standard conditions") into our proposed project plans. Attached are the following: • Lease/Unit Plan of Operations Applications for the WSS #2 and WSS #18-09-23, • Project Description (Amended as of February 5, 2010), • Corrective Action Plan for WSS #18-09-23, • Coastal Project Questionnaire and Certification Statement, and • Permit fees of $500 ($250 for each application). Mr. John Easton -2- February 8, 2010 The WSS#2 CAP was submitted to you on January 13, 2010. The WSS#2 and WSS#18-09-23 Phase II Site Assessment Work Plans were submitted to you on January 25, 2010: If you have any questions or need additional information, please contact Rob Dragnich at (907) 564-3711 or via email (rob.g.dragnich@exxonmobil.com) or Janet Sheldon at (907) 564-3650 or via email (janet.sheldon@exxonmobil.com). Sincerely, C~---` BER:eaa Attachments cc: w/ Attachment Nina Brudie ADNR/DCOM Gary Schultz, ADNR/DMLW w/o Attachments Tom Maunder, AOGCC Don Perrin, ADNR/OPM Jack Winters, ADFG €�'voduc46oru cairnrzu-v P. O. Box 196601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone 907 564 3677 Facsimile September 23, 2009 Commissioner Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7'h Avenue, Suite 100 Anchorage, Alaska 99501-3539 I2aEs UDR(tn%an Alaska Production Ivianager Joint Interest U.S. L � {C5').LFN ��'cq)C RE: Request for Verification of Suspended and Shut-in Well Information Dear Commissioner Foerster: k-1 °t - O % ~J Product'ak E, SEP 2 4 2009 By letter dated January 29, 2009, the AOGCC requested verification of information regarding suspended long-term shut-in wells listed as operated by ExxonMobil or predecessor companies. The lists of Suspended and Shut In Wells attached contained a total of eleven wells. We have no revisions to the information for the Kuparuk 28243 1 well which is located within the Kuparuk River Unit operated by ConocoPhillips. As with your records, we understand that the Starichkof St 1 well was operated by Pennzoil, not by ExxonMobil or a predecessor company, and the lease and well currently is within the Cosmopolitan Unit operated by Pioneer. With respect to the 9 Point Thomson area wells, a sundry notice report was filed with the AOGCC on June 1, 2009, describing the location and well inspection and remediation work performed in March and April of this year. A copy of these reports, along with a summary of the well status is attached for your reference. Please advise if there is any further information we can provide in conjunction with this response. Sincerely, et DDP:jpc Enclosures xc: Mr. Tom Maunder — AOGCC "MID OCT 1 -0 2014. A Division of Exxon Mobil Corporation Well Name Point Thomson Unit #1 Point Thomson Unit #2 Point Thomson Unit #3 Point Thomson Unit #4 Alaska State C-1 Alaska State J-1 Staines River State #1 ExxonMobil Submittal Suspended and Shut in Well Status Current Filing Report Status Date Suspended June 1, 2009 Suspended June 1, 2009 Suspended June 1, 2009 Abandoned June 1, 2009 Suspended June 1, 2009 Abandoned Suspended June 1, 2009 June 1, 2009 West Staines State #2 Abandoned June 1, 2009 West Staines State #18-9-23 Abandoned June 1, 2009 9/23/09 Commentt� Location and Well inspected 3/2009. //'(.e�V� Location and Well inspected 4/2009. /77- a & V Location and Well inspected 4/2009. 1 I — Location and Well inspected 4/2009. / r7 V • Further remediation work planned for the 2009-10 winter season Location and Well inspected 4/2009. Ad • ��� Well inspected and remediated and site cleared in 4/2009. /oP • Location and Well inspected 4/2009. /7 9• ��� Location and Well inspected 4/2009. Further remediation work planned for the 2009-10 winter season Well is located on former ADL 0028377 Location and Well inspected 4/2009. Further remediation work planned for the 2009-10 winter season Ea~s~~e~~~ba! P~~c~u~t@on ~om~saereg~ Joint Interest U.S. - Alaska P.O. Box 195601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone 907 564 3789 Facsimile ~ ~,~' ~ , V '~-~~,~~~~~~~ ~ .J i..l f~ ~; ,~' /i~(1.~ ,~~~95~~ 119k *~t ~,~~:i ~A~l:i, ~Uf17 ' ~ har~~~ _ tr~PSSi4~~ E~onMabi~ ~~oc~~~~a~~¢ June 17, 2009 Mr. Johnny L. Aiken, Director North Slope Borough Planning and Community Services Department P.O. Box 69 Barrow, Alaska 99723 q-o t~0 Re: Tundra Travel Completion Report ~~+ O~c~QK1 . ~ Dear Mr. Aiken: ~' ~0~~ vr`~ ~ ~ ~~~~ Please find attached our 2009 Winter Tundra Travel Completion Report as required by North Slope Borough Conditional Use Permits. This Tundra Travel Completion Report pertains to the following activities authorized by the above permits: - Ice Road Construction from the Endicott causeway to the Point Thomson Unit Centra! Pad - Ice Road Construction to the Alaska State C-1 water source and other lakes from which water was withdrawn. - Tundra Travel /Ice Road Access - Point Thomson Unit Central Pad Mobilization & Construction - Well Inspections and Remediation The attached report reflects Tundra Travel activities through closure of the Alaska State C-1 ice road on May 19th, 2009, and includes the following elements: 1. Actual routes of travel and the location of all camps depicted on USGS topo maps 2. List of vehicles for off-road travel that has taken place 3. Statement of cleanup activities 4. Method of disposal of garbage and other camp debris 5. Report of known incidents of tundra damage and follow-up corrective actions C~ ~C-~ r~C~+~.~-~ cr~ ~ t ~~~.~`~ ~;~ Fe Division of ~xxo~ !4[~b[F ~e~~g~~rati~ry Mr. Johnny L. Aiken -2- June 17, 2009 If you have any questions, please contact me at 907-564-3617 or by email at mike.barker@exxonmobil.com. Thank you Sincerely, ~~~ .~ ~ ~ ~~ ~ ' Mike Barker Environmental & Regulatory Manager KDC:eaa Attachments cc: Lori Aldrich, ADEC Gordon Brower, NSB Nina Brudie, DNR Larry Byrne, DNR DMLW Steve Davies, AOGCC Josephina Delgado-Plikat, DNR John Easton, DNR DOG Gary Evans, ADEC Susan Harvey, Harvey Consulting Lee Kayotuk, Kaktovik Tom Maunder, AOGCC William Morris, ADFG Craig Perham, USFWS Matt Rader, DNR DOG Barrett Ristroph, NSB Gary Schultz, DNR DMLW Roy Varner, NSB Waska Williams, NSB Ryan H. Winn, USACE Jack Winters, ADFG ExxonMobil Production Company Alaska Interest - Joint Interest U.S. P.O. Box 196601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone June 1, 2009 Mr. Dan Seamount, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Sundry Report of Sundry Well Operations Exxon Mobil Corporation Point Thomson Unit #4 PTD No. 179-080 Sundry No. 309-077 Dear Commissioner Seamount: , \ ..~ 3` y"~ ~un aa ~ '~ ~~ ~ . ~ff li~ ~' ~. ~Qf?~; * ~ <~P~ ~ ~~S ~OPi~. ~d3s x .h ,~ ~~c~~rage E~onMobil Production Exxon Mobil Corporation hereby submits its Report of Sundry Well Operations for the wellhead inspection of the Point Thomson Unit #4 well on the North Slope. The well is plugged and abandoned, and the inspection was perFormed upon request of the AOGCC. The inspection results will assist in planning for the well remediation during the winter 2009-2010 season. During the wellhead inspection operation, the wellhead was exposed by excavating the gravel cover. The wellhead was visually inspected, and the well integrity was verified by checking for and recording pressures in the 9-5/8" casing and the 9-5/8" x 13-3/8" annulus; zero pressure was recorded in the casing and the annulus. Two new gate valves and one new needle valve were installed on the wellhead. At the compfetion of the weff inspection, the wellhead section was covered with gravel. Attached please find: Form 10-404: Report of Sundry Well Operations Daily Report of Well Operations Wellhead drawing Wellbore diagram Well plat Photographic documentation of the well If you have any questions or require additional information, please contact me at 907-564-3617. Sincerely, ~`~~-~ ~. ~~ D. Michael Barker Environmental and Regulatory Manager JAR:eaa Attachments A Division of Exxon Mobil Corporation ~: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ~ ~ ~ ~p ;;¢~~ ..! r.~ REPORT OF SUNDRY WELL OPERATION~~~~~ ~~i~ ~~~~ ~~~~` "`~~'~~a;,4~ ~ ~~~~~ra~ 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ Well Inspection 3 Performed: Alter Casing ~ Pull Tubing ^ Perforate New Pool ~ Waiver~ Time Extension ~ Change Approved Program ^ Operat. Shutdown ^ Perforate ~ Re-enter Suspended Well ~ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Exuon Mobil Corporation Development ^ Exploratory0 179-080 , 3. Address: PO Box 196601 Stratigraphic^ Service~ 6. API Number: Anchorage, AK 99519-6601 50-089-20009 , 7. KB Elevation (ft): 9. Well Name and Number: ~ 33 ' Point Thomson Unit No. 4 8. Property Designation: 10. Field/Pool(s): ADL 47563 ~ Point Thomson " 11. Present WeU Condition Summary: Total Depth measured 15,074 . feet Plugs (measured) Plugged to surface true vertical 13,194 . feet Junk (measured) None Effective Depth measured Surface feet true vertical Surface feet Casing Length Size MD TVD Burst Collapse Structural 91' 28" x 36" 91' 91' N/A N/A Conductor 2102' 20" 2127' 2127' 3060 1500 SurFace 3397' 13 3/8" 3422' 3422' 5380 2670 Intermediate 11862' 9 5/8" 11887' 10222' 7290 7100 Production 10730' 7" 15049' 13170' 13700 I 12460 13010 / 10760 Liner Perforation depth: Measured depth: N/A True Vertical depth: N/A Tubing: (size, grade, and measured depth) N/A Packers and SSSV (type and measured depth} N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Well Photographs Exploratory^~ Development ^ Service ^ Daily Report of Well Operations See Attachments 16. Well S~s a8er work: ~ Oil , ~~as WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ~,. i. j Sundry Number or N/A if C.O. Exempt: ~ ~ ~, 309-077 Contact Mike Barker Printed Name Mike Barker Title Environmental and Regulatory Manager ~ ~ Signature ~ Phone (907) 564-3617 Date 3 E a,as-~j Form 10-404 Revised 0 . 'a~`~ ~ , r >".~ ;~ E~ L~QG ~_ , ' ° ? ~~y SubmitOriginal Or~y ~;, . . ° ~~~~~~ ~~ ~,~ .~~~ : .~ ~ ., ~ ~ Daily Operations Log Point Thomson Unit #4 Well Inspection Sunday, April 19, 2009 • Headed to well site and began excavation. • Removed top 4' of cellar box and continued excavating. • Located top of first 13-5/8" flange, continued excavating. • Excavated to 8-1/2 feet. Found valves around head are encased in cement. Monday, April 20, 2009 Continued excavation around well cellar. Excavated down to 10'. Cut 4 more feet of cellar box out. Continued excavation. Tuesday, April 21, 2009 • Continued excavation. • Began jack hammering around valves. Located refrigerated conductor and lines, fluid in lines was crystallized. Unable to remove. • Applied heat to well head. • Rigged up to pressure test 13-3/8" X 9-5/8" annulus. Tested to 250/5000 psi for 5 min. Obtained good test. Rigged up to pressure 13 3/8" X 20" annulus and tested to 250/5000 psi, obtained good test • Removed outer 3-1/8 5 K valve on "B" section and replaced with new 3 1/8 5K valve. Installed 3" 3K X 3" 5K x-over on "A" section and installed new 3" 5K valve. Wednesday, April 22, 2009 • Welded a 6K Ib. rated collar on top of top flange to accommodate the hot-tap machine. • Pressure tested valves to 250/5000 psi for 5 min., obtained good test. ~ Rigged up hot tap machine on top flange and tested to 250/5000 psi, good test. Commenced hot tapping with 500 psi on unit. Pressure dropped when the flange was penetrated. Monitored for pressure and rigged down the hot tap. Zero ~ pressure observed, installed 2" ported plug with 1/2" needle valve and bull plug. • Back-fil(ed excavation and loaded out sleighs to go to next well. PT U #4 nn~E~oy spi~t Speedhead System Netes Csg head Approx 24" Tubi ng he ad oorox. 24" Marker post top flange tapped 2" ball valve on flange 4" LP 4-1/16" 5k. 13 5/8" ~ 2" ball valve and needle valve ~ ~ MPNiE P1(1Mf11d7R1 13 5/8" 5k.~ ~ Q I ~Nf! m-~~^rlcl aaL•re IA 8~ OAvalves are 3-1/8 5k ~ ~ SPrial #OA-10-2263 Exxon Mobil Corporation Pt. Thomson Unit #4 Well Schematic API #: 50089200090000 APTD #: 179-080 VVellhead has 20-3.+4" A and 13-.^:8" B sections tivith bl~nd; ?,QOQ psi flange cap and marker ~ement plug m 9-5i8° c~smg , i,~~,~ • ,, ' ;x , ; ",~ 1 CIC~ - 0' (75' BGL to surface),~ 4'" ~ . 30~' af 51' refrigerated conductor 5a sx r~ ~/ Arctic pac.k in 20' x 13-3+'£S" '~ 26' h+~le ~ 10.2 ppg and 13-3.~8' x 9-5+8" annuli '~ CaCI, 20' casing at 2, f27' == ~'~+ater TG~C in 20" x 13-3.~$" at ~~ ;~-TOC 2,90D ± 2,l00', 100 sx, arctic pack i,~~J fror~i 2, B00' to surface ~~-- TOC 3. t00`, 100 sx, 15 ppg permafrost r - t:_~ , cement follo~ved by 180 bbls arctic pack 13-3r8` at 3.422' 17" hole Haliiburton EZS\•' at 4,100' T casing cut of at 4,31 ~' TOC 4,040' in 9-~:8' casing Sottoi~~ ~f cemei~t at 4.400'±. 15~~ sx TC)C 8,~±p0'± ~4 9-5:8" ~t 1 I.~~i7 HaliibLarton EZSV at 13.3~i5' Halliburton EZSV at 13.555' Haliiburton EZSV at 14.~t20' Cement in 7' casmg at 15,Q07' 7" at 15,049' (13,170' TVD) Tota1 D 12-1;`4' hole ( iQ222' TVD) 13.6 Pp9 mud - TOC 13,37~', 15fl sx ~-.. ' : Baker P:4odel F1 at 13,423' . ~ . Pertorations 13,475' - 13.477' squeezed riwice ;,l~ ": with 150 and 2~0 sx class G ;~,~.- . Z'~~ Y. h~- Perforations 13,47~t' - 13.542', squeezed with 150 sx class G Perforations 13.550' - 13.5~2' ; TOC 13.625'+ 15.h PP9 mud Briclge Plug at 14;707' , ~'ertorati~ns 14;802' - 14.812' squeezed with 2Q0 sx, later cirilled out ' Perforatians 14,822' - 14.882' squeezed wi#h 150 sx, later drilied o~rt Baker rnodel F 1 packer at 14,930' ~' Perforatians 14;95fi - 14;976 ; squeezed witfi 1~0 ~t ;r sx class G ~. epth 15.074' (13,194' TVD} . Well schematic was prepared by Fairweather E& P Inc. Last updated in March-2009 ~ ~ S~A AS STAKEO 8 E A v F o R LONG =146°36 ~~ 621T No. 4 X= 424,317 Po~~t Hopson Y =5,914.985 Point Gordon ELEV =83~ 2T 2e O I I 32 33 34 35 o Y 900~ ~ I ~ ( 36 3 i ° ~~ TION N ~ I T 9 N ~'j I ~~ ~~ ~ I tif I 1 6 I 5 I 4 ~ 3 I 2 I ~ 1 I ~ `~ .-~- - - - -~- - i - - ~- ~ I 12 7 ~ 8 I 9 C I~ 10 ( 11 1 W W ~.V t I ~ ~ ! I I ! ~ -~- ---.- - ---~ - - - - --f-- - - ---~- - -1-- SCALE• 1~~= I MILE(5260~) CERTIFICATE OF SURVEYOR • , I he~eby certify thai I am properly ~egistered and K•~ , ,. ~ ~ Iicensed to practice land survey,ng in the State of Aloska , 'E,~~' and that th~s plat represents a locaT~on survey made by me .. - or under my supervis~on, ond that al~ dimensions and other ., ' details a~e correct. ' ' ~ ~~ o~; .,, , e~~~ - ~ ~ ~sL.. Date ^ Surveyor RECEIV~~ ( .~ 2 ~ '~~~ ~. ~r ~SS~ ~1~ $c Q.3S.1i•;3;J 4Vt. .~1:'~i,(1~ AnCt~lora~le ~ . ! ~a~ ~ . ,~ , ~ ~y ~ ~ ;, ~ , ~ ~;,~~~~~, as srt-Keo POINT THOMSON UNIT No_ 4 Surveyed for EXXON COMPANY U.S.A Surveyed by F M. LIN DSEY 8~ ASSOC. LAND 8~ HYDROGRAPHIC SURVEYORS Z502 West Northern Lighis Boulevard Box 4-b8 Anchoraqe Alaskc r a • r 4s �a. X' a 1 � wr �� ~ r 'C.�'� 1 � � tea- '_� .� `♦� til `� •'C' �i q • � .+�'n. <. � a r �. T rte". - y•v. +,� ��C. ��`�v,:::-+ r .k- 1- r PTU#4 wellhead as found., _ ~ ~ ~Y~ A~ :.~I ` .~~:f~ , _ ~ ~. ~ ~ ~~~ ~ -~ s ~.R ~~ ~ ,~~:~~_ ¢ - . ~ _:! - f " . ~ . , ~a:. . .. ~ . , -. . " ~ S..P\.. ~ Y . . ~ ... `~ ~. ~~ ~ ~ ~~,' .. ~ ~ ~ tl ,1 . ,~ ~ 1 . , .,~ .. . . •' p ~1~~~~~ `1 . ' .. .. ~ , y , ~ , ~ ~; ~ R . . . . l ~ .. ~ . ~-. ~ ~) `t . ^_,,,. ~` t . ,~ . - r. ~ - • . ~ ~ ~ ,~, ~ ~ ~4r.~ .~~ +~,~ : : ~'~ d ri~,, ~ ~. . . . y , ~ . ~`C , , ~ ~ .~ ~,'~ . ~'~ ,` 1 . ;.4, .. . . n~~ ~ `~. . . 1 , , , ~.tA~. '~jt . .. ~C. ' . ~ aV~{• A '1 ~ ;' . ` ~, t*. . . ~ ~ ~ ~> ( Y . . ~ " \,~ ` . ~~' - ~ 1 ... , ~ ~~~~ ~ . . . _ ~. . ~'~_$k. . . I ~ r '' ( f ' ~~ ~ i ! ~ ~ ` ~4 ~r~ ~' : ~, ~ ~' ~ ~.t~ ~ ,' . ,:y . ~ !~ ~,''. ~ ~~.~~j~~'`~ ~y. .,Z. .. ~ ~ . ,~f ,~ ~/M . 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' .p . `.` r~~ ~ly.~~~ ~ ~ . ,. , . . ~ ~ ~.. ~ '~.•; , ~ Y`~ r~~~ ~ PTU #4 wellhead new valves ~n~ ~ -~~~ f , ' ' y ~ ,lfr'y ~. ~ ~f~ ' -,.s .. ~._ ~-~ ` . - . .' ~ f J fr ` _. : . *''~ :.. ~ . . ~ - ~ d , ~ i r' _ af`~. < ~ a T" I~L , ~ - ,.,,,~ . t-' ~ S ~. _ _ r ~ s {" ~ j_. "!' ., << ` ~ , w i • . - . . 9~ • ~ f ~ ~.~~ ~y ~ . ~., ' /~' ,~ ' # ~ '~ . ~ ~ ' . Y ~ ~..j ~I~~/_M e;~2 'n~ , '~. ~' ~r°"_. , s. . ~ ' .: e y(/~~~~ {y ~a ~~.. .. . ~• r . ~,rf.I~~]r~~T'{7. i r~..e . ~a~ 4jb'-e '~ . .. .r~~~ ~,.. '. . ?. 7 i. g7 4 • `� PTU #4 wellhead—needle valve T . r r..F � �'`, ♦ ` .:� � ..lr♦-..,.'fit, ry� �T x v 1. w cD':• .: � t t . t . W-od'o-441k -2s 53 A AW, V T'sk I ls�v .-4077" in , '~_ ~ ~ ~ ~ ~ ~' r" ~~ ~~ ~, ~ ~ f~~ ~~ ~f~ ~~ ,~ r~ ~"`~, ~ ~ ~ ~ ~,.;~'~ ~.~ ~r~'~ ~ ~ ~ ~ ~ AL~SSA OIL A1~TD G~-,.S COI~TSER~ATIOI~T CO1~Il~IISSIOI~T Craig Haymes Alaska Production Manager E~onMobil Production Company PO Box 196601 Anchorage AK 99519-6601 Re: Point Thomson Unit, Pt. Thomson Oil Pool, PTLJ #4 Sundry Number: 309-077 Dear Mr. Haymes: SARAH PALIN, GOVERNOR 333 W. 7thAVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval ~et out in the enclosed form. As noted in the Inspection Procedure document submitted with the application the status of this well according to the official AOGCC records is P&A, although as the Commission pointed out in previous correspondence this is one of several wells so classifled that appear not to meet all of the applicable regulatory requirements for plugged and abandoned wells. We appreciate yaur inspection efforts as described in the applicatian. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.0$0, within 20 days after writ±en notice of this decision, or such further ~ime as the Cominission grants for goad cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Cominission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Seax~ount, Jr. ~ Chair DATED this~? day of March, 2009 Encl. ~,~(h"~` ,~t ~,P'~' . o~- ~.I~~~~~~~ ~ ~~~f 3~ ~~ STATE OF ALASKA 3~~~ ALASKA OIL AND GAS CONSERVATlON COMMISSIO~JEB ~~ 2(1O~ ~3f~s APPLICATION FOR SUNDRY APP Q ~n onr ~c ~Qn ~~K~~~~~~ ~0~~, ~pI11tTlISSIQt~ 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Alter casing ~ Repair well ~ Plug Perforations ~ Change approved program ~ Pull Tubing ~ Pertorate New Pool ^ Perforate LJ ^"''""' ~iver ^ , Other [ Stimulate ~ Time Extension ~ Site Inspecti~ Re-enter Susaended Well I-I 2. Operator Name: 4. Currenf Weli Class: 5. Permit to Drill Number: E~ocon Mobil Corporation Development ~ Exploratory 179-080 - 3 Address: ~ . Stratigraphic ~ Service ~ 6. API Number: PO Box 196601 Anchorage, AK 99519-6601 50-089-20009-0000 - 7. If pei~Forating, closest approach in poof(s) opened by this operation to nearest 8. Weff fVame and Number: property line where ownership or landownership changes: N/A Spacing Exception Required? Yes ^ No ^ Point Thomson Unit No, 4 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ADL 47563 - 33 - Point Thomson ~?' PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effecfive Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 15,074 ~ 13,194 - Surface SurFace See Attached None Casing Length Size MD ND Burst Collapse Structural 91' 30" 91' 91' N/A NIA Conductor 2,102' 20" 2,127' 2,127' 3060 1500 Surface 3,397' 13 3/8" 3,422' 3,422' S380 2670 lntermediate 11,862' 9 5/8" 11,88T 10,222' 7290 7100 Production 10,730' 7" 15,049' 13,170' 13700/12460 13010(4Q760 Liner Pertoration Depth MD (ft): PerForation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): N/A N!A N/A N!A N/A Packers and SSSV Type: N/A Packers and SSSV MD (ft): N/A 13. Attachments: Description Summary of Proposal Q 14. Well Class after proposed work: Detailed Operations Program ~ BOP Sketch ~ Exploratory Q Development ^ Service ~ 1~. Estimafed Date for 16. Well Status after proposed work: Commencing Operations: ~arch 1, 2009 Oil ~ Gas ~ Plugged [] Abandoned Q ~ 17. Verbal Approval: Date: WAG ~ GINJ ~ WIfVJ ~ WDSRL ~ Cort~mission Representative: , ~ 18. I hereby certify that the foregoing is true and correct to the be~t of m,y ' clwl ~~ ~~ntact Mike Barker / Jack Rickner Printed Name Crai g A. Ha es •~.' T i t ' A! a a r r'~:~ :~~ Ianager Signature Phone :l'a ~ (9 E+` SF)~i-.`s'~u -~ Cptu11VFTSS PE tlSE ~NLY Conditions of approval: Notify Commission so that a representative may witness Sundry tVumber: ~Q .- O~~ Plug Integrity ^ BOP 7est ~ Mechanical Integrrty Test ~ Location Clearance ~ Other. '~'~~~a~ ~~~ ~~.Y: ' ` ~1(l~; ~~'~-~~ [ ~~oS ~b~.~~.~'r~cO`'~~~~~~-C~.C~ C~~~cC-'~Cc~.~1c~~`~t/~ Subse R i d ~ t F q~en re orm equ : _ (~ \ ~ U.~' G~i~M~~cc~'~CC7'~ V-t"_ ~~\S Wl"; ~``` _~/~ APPROVED BY '~ Approved by: F r ~ I~ 1 COMMiSStONER THE COMMISStON Date: ~~! ~/ / Fnrm 10-403 Revised 06~~`~, ~ ~..i ~ ~ ~ J .. . _ _ 1 ExxonMobil Production Company P. O. Box 196601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone 907 564 3677 Facsimile Craig A. Haymes Alaska Production Manager Jt. Interest U.S. ~~ ~ ~ ~ ~~:~.R.,... ~~~ ~ ~ 2~~~ February 25, 2009 Mr. Dan Seamount Chairman Alaska Oil and Gas Conservation Commission ~33 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Sundry Application ta Inspect Exxon Mobil Corporation Point Thomson Unit #4 PTD No. 179-080 bear Commissioner Seamount: ~P~S ~ G~~ E~o n M o~ i~~~~i~ e~~~. c~; . Production ~r~~~' Exxon Mobil Corporation hereby submits an Application for Sundry Approval to perform a surface inspectior~ for additional remediation work including removing well fluids and the wellhead on the subject well. This inspection will be performed to verify the well integrify by checking for and recording pressures in the 9-5/8" casing and the 9-5/8 x 13-3/8" annulus. The inspection work wi~l be performed during the winter of 2008-09 to pro~ride information that will be used in detailed planning for removing of well fluids and the wellhead during the winter of 2009-10. Please find enclased the following information: 1) Form 10-403 Applicatior~ for Sundry Approval 2) Wellbore Schematic ~) Inspection Procedure 4) Photo of the Wellhead/Abandonment Marker at Present If you have any questions or require additional information, please cont~ct Mike Barker at 564-3617 or Jack Rickner at 564-3783. Sincerely, ~~) ~ ~ / CAH:eaa Attachments A Division of Exxon Mobil Corporation Euuon Mobil Corporation Pt. Thomson Unit #4 API #: 50-089-20009 PTD #: 179-080 Inspection Procedure Backqround Well Information The Point Thomson Unit #4 well was drilled in 1980. The well is abandoned, but requires removal of some well fluids and the wellhead to at least three feet below ground level consistent with current AOGCC regulations. Prior to removing the well fluids and wellheads, an inspection to verify the well's condition is desired. The 9-5/8", casing has a cement plug set at 0'-100'. Below the surface cement plug there is 10.2 ppg CaC12 brine on top of a cement plug at 4'040'-4,100' and a bridge plug at 4,100'. The 9-5/8" x 13-3/8" annulus contains arctic pack from surface to approximately 3,100' and a cement plug below. The 13-3/8" x 20" annulus contains arctic pack from surface to approximately 2,100' and a cement plug below. The well schematic is attached to this procedure. The reservoir section of the well is effectively plugged; therefore it is unlikely that high pressure will be encountered during the inspection. However, contingency plans and procedures will be included in the detailed inspection procedure to safely manage any well pressure encountered. The inspection will include the following steps: • General inspection of the well location to the extent possible (winter operations) • Excavation of gravel covering the wellhead and cellar • Visuaf inspection as to the condition of the wetlhead • Verification of the well integrity by checking for and recording pressures in the 9-5/8" casing and the 9-5/8 x 13-3/8" annulus o Perform diagnostic test if pressure is found (i.e., trapped vs sustained pressure) o Identify contents of the casing and annulus by attempting to get a sample • Clean up of location and leave well in a safe and secure condition The proposed inspection will be supported by on-site equipment and materials such as excavator, camp, transportation, fuel and other essential elements of remote operations. The following well inspection program is planned: 1. Insure all necessary permits and applications are in place. Notify AOGCC at least 10 days before operations begin. 2. Mobilize all personnel and equipment to the Point Thomson Unit #4 location. 3. Observe and record any signs of leaks in the area surrounding the well. Take photographs clearly showing the condition of the surrounding location. A detailed report documenting any found contamination will be prepared. 4. Heat the gravel around the wellhead. 5. Excavate gravel covering the well and cellar. Ensure access to all side outlets on wellhead sections. Monitor excavation with a four-gas monitor. 6. Install wellhead shelter, and rig up indirect fired hot air heater. Apply heat to wellhead shelter. Pump or vacuum the cellar dry when thawed. 7. Visually inspect the condition of wellhead side outlets valves, bull plugs, needle valves, test/grease ports, lock down screws, etc. Take photographs clearly showing the condition of the wellhead as found. Document any areas of concern. 8. Check pressures on the 9-5/8" casing and the 9-5/8" x 13-3/8" annulus. This may require the installation of needle valves and wellhead side out valves to facilitate recording and bleeding off pressures. In addition, operations such as removing VR plugs, hot tapping, and gate valve milling may be required to verify any well pressure. 9. If pressure is observed, then perform diagnostic testing to determine if the pressure is sustained casing pressure or trapped pressure. Record pressure bleed down and build up. In addition, record the fluid type and volume. Take fluid samples for possible analysis. 10. Take photographs clearly showing the condition of the wellhead as left. Backfill the cellar with gravel with allowance for gravel settling with time. 11. Ensure well is safe and secure. Chain 8~ lock close any valves above ground level. 12. Clean up location. Remove any fluid from the well for proper disposal. Take photographs clearly showing the condition of the location as left. 13. Fill out inspection report and file a Report of Sundry Wel! Operations (Form 10-404). Exuon Mobil Corporation Pt. Thomson Unit #4 Well Schematic API #: 50089200090000 APTD #: 179-080 Wellhead has 20-3/4" A and 13-5/8" B sections with blind, 5,000 psi flange cap and marker Cement plug in 9-5/8" casing :` ,;; .;;~ ,; R~ {,~-,;s".:r , ' ` 100' - 0' (75' BGL to surface), L~ -`' '` 30" at 91' refrigerated conductor 50 sx Arctic pack in 20" x 13-3/8" '; ~ ~ 2 pp9 * 26" hole and 13-3/8" x 9-5/8" annuli CaC12 ' 20" casing at 2,127' TOC in 20" x 13-3/8" at ~ Water ~_TOC 2,900'± 2,100', 100 sx, arctic pack ~ ;~ from 2,100' to surface ~; .*, TOC 3,100', 100 sx, 15 ppg permafrost , __, cement followed by 180 bbls arctic pack 13-3/8" at 3,422' 17" hole Halliburton EZSV at 4,100' 7" casing cut of at 4,319' TOC 4,040' in 9-5/8" casing Bottom of cement at 4,400'±, 150 sx TOC 8,900'± 9-5/8" at 11,887' 12-1/4" hole (10,222' TVD) 13.6 ppg mud ~ TOC 13,375', 150 sx Halliburton EZSV at 13,395' Baker Model F1 at 13,423' Perforations 13,475' -? 3,4?7' squeezed twice with 150 and 200 sx class G Perforations 13,478' - 13,542', squeezed with 150 sx class G Halliburton EZSV at 13,555' , Perforations 13,560' - 13,562' TOC 13,625'+ 15.6 ppg mud Bridge Plug at 14,707' , Perforations 14,802' - 14,812' squeezed with 200 sx, later drilled out " Perforations 14,822' - 14,882' squeezed with 150 Halliburton EZSV at 14,920' '~; ;; sx, later drilled out `':;'.~: . ~„~ ',; Baker model F1 packer at 14,930' '" '~' Perforations 14,956 - 14,976', squeezed with 100 Cement in 7" casing at 15,007' ~~ ~ sx class G 7" at 15,049' (13,170' TVD) Total Depth 15,074' (13,194' TVD) Well schematic drawn June 29"', 2007 by Jesse Mohrbacher, Fairweather E& P Services, Inc. Exxon Mobil Corporation Pt. Thomson Unit #4 API #: 50-089-20009 PTD #: 179-080 fi'.: . ~ ~. ~ . ,.4,'%.-'_. ~r.~ . . . .. V- 1 !. Z J ?.ap~ ~ ,. . , ~ y. F ,~~~i a "Y Y ,_, 1~ ~ _ ... }~ ~ . w~. r~ •~..A.~r . . '." -, _ ~ . ,. .R u .. .. ~-~~ tl~ r ~ ~W_ .. :k..r.. ~ ~ , :.1 ..t~~. - i x,~!S~ f ; ~. ~ . .:.e~ ..~ ^ y, f~~_~' ~A`d ~ •i ~~r .., ,~ ~,'' _"-`'"~: ~-, r+`Yw;.. ,~r'o .. , z t„3~ r:`;'-.. 5~ • FTOm; jac;.a., ior<~~er~e,u:orrnobii.corr; :Sent: UBor~day, :ions ~'I, 2~a9 9:`i? ~~~? To: ;Maunder, Thomas E {DOA) Subject: RE: AOGCC Sundr,~ i~o~tice Repor€s :or ~~ompieted ~ieid 3~.v~ivi~~ies Tom, the reports for the 9 well inspection/remediation wor;c at Point Thomson left my office this afternoon. Thanks for your patience. I°m now 1oo:cinq for contractors to bid the work to for the next winter's work for the 3 well remediation effort. If you have any questions regarding the recent work or next winter°s anticipated work, please call. Regards, Jack c~~,-o~~ Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Thursday, May 28, 2009 7:18 AM To: jack.a.ricknerra~exxonmobil.com Subject: RE: AOGCC Sundry Notice Reports for Completed Field Acitivities Hi Jack, Thanks for the update. I will look forward to receiving the reports. I agree with your intent to work to avoid the last minute crunch. c:alt or message with any details. Tom Maunder, PE AOGCC -----Original Message----- From: jack.a.rickner@exxonmobil.com Sent: Thursday, May 28, 2009 7:14 AM To: Maunder, Thomas E (DOA) Subject: AOGCC Sundry Notice Reports (mailto:jack.a.rickner@exxonmobil.com] for Completed Field Acitivities Tom, just a note to let you know I haven't been idle. Finally completed all the wellhead drawings, have all the attachments and photos together for all 9 wells. The package has been provided to our inhouse legal folks for there blessing. Hope to have their check off within a day or two. Will deliver to your office as soon as they catch my grammatical and spelling errors. Currently we are tentatively scheduling the summer stick picking work for July. Moving ahead on planning the winter remediation work for the PTU-4, West Staines #2, and the West Staines 18-9-23. Our current plans are to start the permitting, contracting, and procedure development (including which type of equipment to drill through the bridge plugs) this summer in hopes of avoiding a last minute crunch to obtain permits and equipment. That is our hope anyway. If you have any questions, please call. Regards, Jack Jack A. Bickner Pt. Thomson Well Inspection & Remediation Project 907-564-3763 281-217-4350 y~~~_`J8 • Maunsier, Thomas E (DOd~-) From: Maunder, Thomas E (DOA) Sent: Monday, May 11, 2009 8:18 AM To: Natasha Sachivichik Cc: jack.a.ricknerr~exxonmobil.com; Bill Penrose Subject: RE: PTU well inspection project AOGCC report status Thanks Natasha. That schedule should work. Tom Maunder, PE AOGCC From: Natasha Sachivichik [mailto:natasha.sachivichik@fainnreather.com] Sent: Monday, May i 1, 2009 8:16 AM To: Maunder, Thomas E (DOA) Cc: jack.a.rickner@e:oconmobil.~m; Bill Penrose Subject: RE: PTU well inspection project AOGCC report status Tom, i~~- o~~ Sorry for delayed reply. We should have the reports ready by the end of this week or beginning of the next week the latest. Thanks and regards,. Natasha Sach%v%ch%12 Senior Drilling Engineer Fairweather E&P Services, Inc. 2000 East 88th Ave., Suite 200 Anchorage, Alaska 99507 Direct:907-343-0405 Cell: 907-575-7156 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Thursday, May 07, 2009 12:29 PM To: Natasha Sachivichik Cc: jack.a.ilckner@e~oconmobil.com; Bill Penrose Subject: RE: PTU well inspection project AOGCC report status Natasha, et al, What sort of time frame are you looking at to submit all reports? I understand that submitting everything can help operational efficiency. Tom From: Natasha Sachivichik [mailto:natasha.sachivichik@fairvveather.com] Sent: Thursday, May 07, 2009 11:14 AM To: Maunder, Thomas E (DOA) Cc: jack.a.rickner@exxonmobil.com; Bill Penrose Subject: PTU well inspection project AOGCC report status 6/24/2009 _~.~~~~a • Tom, I am writing in regards to the yesterday's phone conversation between you and Bill Penrose about the status of the Sundry reports for 9 wells inspection and remediation project performed by F~cxonMobil. The field operations completed on April-29-2009. I would like to confirm that we are aware of the 30 days requirement to submit the reports and are currently working on generating these reports. Could you please let me know if you would like all 9 Sundry reports submitted at the same time. Thanks and regards, Natasha sach~v%ch~le Senior Drilling Engineer Fairweather E&P Services, Inc. 2000 East 88th Ave., Suite 200 Anchorage, Alaska 99507 Direct:907-343-0405 Cell: 907-575-7156 6/24/2009 • • IVlaurader, Th®aa~as E (®®a4) From: Maunder, Thomas E (DOA) Sent: Monday, March 23, 2009 10:14 AM To: jack.a.rickner@exxonmobil.com Cc: michael.d.murrey@exxonmobil.com; rob.g.dragnich@exxonmobil.com; mike.barker@exxonmobil.com Subject: RE: Wellhead Inspection Program ~ ~ ~ ~ ~ cf Jack, et al, Following up on our conversation, it appears that options 1 and 2 should not present major issues. I concur that it is not desirable to have an open excavation. It is certainly possible that an excavation would collect melt water and what rain might fall. For this case, if you equip the well so that it can be monitored and then rebury some portion, this does not seem dissimilar to how the well structures have been for 20 - 30 years. I think that your finding the A section valve still functional after all these years should give some confidence that the damage risk from reburial is likely low. The final determination will be Exxon's based on the conditions determined for each well. Call or message with any questions. Tom Maunder, PE AOGCC -----Original Message----- From: jack.a.rickner@exxonmobil.com [mailto:jack.a.rickner@exxonmobil.com] Sent: Sunday, March 22, 2009 4:33 PM To: Maunder, Thomas E (DOA) Cc: michael.d.murreyCexxonmobil.com; rob.g.dragnich~exxonmobil.com; mike.barker@exxonmobil.com Subject: RE: wellhead .Inspection Program Tom, we have a couple of concerns. From a safety standpoint, we would prefer not to leave an open excavation. And we are not sure if an open excavation would collect and retain water during the summer and then freeze as the temperatures cool. Not sure how this might impact tubing and needle valves through time. At this point, we think that we have three scenarios. (1) The wellhead basically at or above ground/pad level. (2) the wellhead just at or slightly below pad level. (3) the wellhead below at perhaps 3-4 feet below pad/ground level. If the well head is above the normal grade of the well pad, we would install the new gate valve(s), flange with 1/2" NPT threads, needle valve(s), and plug(s) in the end of the needle valve(s). That would allow us to read pressures in the summer time with relative ease. If the wellhead sections are just slightly below the pad level, we would like to leave the wellhead exposed and the valve(s) in place, flanged with needle valve(s) and plug(s) as above. There might be a slight dip in the surface of the pad but not significant. If the wellhead is some depth below grade (perhaps 3-4 feet), we have a number of options. It is this situation that I would like to discuss. We could: As proposed in our Curren procesures, install new 3" gate valves (left in open position), flange with 1/2" needle valve (left in open position), install 3/8" stainless tubing to the surface and have a second needle valve present so that pressures could be read (needle valve left closed, gauge removed and plug inserted in needle valve opening). The tubing could be banded to the wellhead and to the above ground marker. 1 ~,Ve could install the new ~ e valve (left in closed positiafi), flange, with 1/2" needle valve and a plug. After obtaining pressure reading, bury the gate valve(s) until the next time pressure readings are required. Again, an excavator would be required to gain access to the valves. Could leave the wellhead exposed with the walls of the excavated cellar sloped back at a shallow angle that would form more of a ramped walk way down to the wellhead. The valves could then be exposed for easy access. Valve handles could be chained or removed for security. The hole might resemble a depression that could be walked into and out of rather than a hole. The excavated area could be left open and return to at a later date to install a more conventional cellar if necessary. Valves installed and chained as above. If we found a well that did happen to have significant pressure that did not bleed off quickly, we would shut in well and contact our engineering group to decide on appropriate action including how to leave the well and confer with AOGCC. But on wellhead with no pressure or pressure that is quickly bled off, there are some concerns with leaving an open excavation as there are to leaving exposed wellhead sections, needle valves (with possible pressure that may build back with time), and marker posts. Would appreciate your views and input. Mike has discussed these options with our subject mater expert and with wellhead suppliers in Anchorage including Dave Craft with Cameron and Kevin Hite/Alan Mc Arthur with FMC. Mike, have I left out other options or would you like to add anything? Tom, as you know, we plan to remove the wellhead on the J-1 this winter and return to the area next winter to address the issues at PTU-4, West Staines #2, and the West Staines 18-9-23. The closure options for these three may not be as important as the others since we are scheduled to return and work on these. Would appreciate any insight you may wish to share. Regards, Jack Jack A. Rickner Pt. Thomson Well Inspection & Remediation Project 907-564-3783 281-217-4350 Thomas E jack.a.rickner@exxonrnobil.com Subject RE: Wellhead Inspection Program Hi Jack, I am in for a bit today. My preference would not to have valves buried however I do realize there is also a risk about surface as well. What are your thoughts? Tom -----Original Message----- From: jack.a.rickner@exxonmobil.com [mailto:jack.a.rickner@exxonmobil.com] "Maunder, 2 Sent: Saturday, March 21, 200 3:41 PM To: Maunder, Thomas E (DOA) Subject: Wellhead Inspection Program Tom, would you be available Monday morning to discuss a question regarding ExxonMobil's Pt. Thomson nine well inspection and remediation program. If available, please phone me at either of the numbers below. I am only a few minutes from you office and would not take more than 30 minutes of your time. I would like to discuss the question of how to leave the wellheads, especially the question regarding valuing arrangements (valves above grade to facilitate periodic checking of well pressures versus valves below grade and buried in gravel) If you are not available due to time constraints, please call and let me know. I'm scheduled to fly to Deadhorse Monday after lunch for Emergency Response Training and will not be available until Thursday. Your insight to this question would be appreciated. Regards, Jack Jack A. Rickner Pt. Thomson Well Inspection & Remediation Project 907-564-3783 281-217-4350 3 Y �Y�7�vr�6i�11y1e�d,1'27474TKiy � lllJxie�-LLT2�1 �LTLfC�]O lav(i1)Fj �11e� � • A,r.71 G)R (SL.®A�ii1�11 190ROR January 29, 2009 CERTIFIER MAIL RETURN RECEIPT REQUESTED 7005 1820 0001 2499 5975 William Pecor ExxonMobil Production Company PO Box 199610 SCANNED Anchorage AK 99519-6601 Re: Notice of Revised Suspended Wells Regulations and Request for Verification of Suspended and Shut -In Well Information Dear Mr. Pecor: `( "'. -- o ,tU SARAH PALIN, GOVERNOR 333 W 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Enclosed are the Alaska Oil and Gas Conservation Commission's revised regulations regarding suspended wells (i.e., 20 AAC 25.110). Also enclosed are lists of suspended long-term shut-in and Point Thomson heritage wells operated by ExxonMobil Production Company or your predecessor companies. For each list, please verify the information for each well and provide any corrections by April 1, 2009. Location inspections required under 20 AAC 25.110 should be coordinated with Jim Regg at 907-793-1236 or jim.regg@alaska.gov. If you have any questions regarding this notice, please contact Tom Maunder at 907-793- 1250 or tom.maunder@alaska.gov. Enclosures Sincerely, Cathy P. Foerster Commissioner U.S. Postal Service,,. CERTIFIED MAIL. RECEIPT ' (Domestic Mail Only; No Insurance Coverage Provided) For delivery information visit our website at www.usps.com -■ 1 . t t i i Y It' 'llV,r _��,U. r,S IUCIir�rlS ■ Complete items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. 0 Print your name and address on the reverse so that we can return the card to you. ■ Attach this card to the back of the mailpiece, or on the front if space permits. 1. Article Addressed to: William Pecor ExxonMobil Production Co PO Box 199610 Anchorage AK 99519-6601 0 Agent 0 Addressee B. eived ted Name) C. D of elivery D. Is delivery adoess different from item 1f ❑rYes If YES, enter delivery address below: ❑ No 3. S ice Type Certified Mail 0 Express Mail ❑ Registered )Oeturn Receipt for Merchandise ❑ Insured Mail 0 C.O.D. 4. Restricted Delivery? (Extra Fee) ❑ Yes 2. Article Number (Transfer from service label) 7005 18_2 0 0001 2499 5975 PS Form 3811, February 2004 Domestic Return Receipt 102595-02-M-1540 Operator Suspended and Shut In WeRs PENNZOIL CO Field Current Date of Permit API Number Well Name Status Status Surface Location ......................................... .. Lease(s)................................... ......... *EXPLORATORY 166-064-0 50-831-10002-00-00 STARICHKOF ST 1 SUSP 4/1/1967 843 FNL 1841 FEL Sec 33 T 3 S R 15 W SM ADL0018790 Wednesday, January l4, 2009 Operator Suspended and Shut In WeAf s MOBIL OIL CORP Field Current Date of Permit API Number Well Name Status Status Surface Location .................................................... Lease(s)................................... KUPARUK RIVER 181-035-0 50-029-20573-00-00 KUPARUK 28243 1 SUSP 5/29/1981 470 FSL 605 FWL Sec 17 T 11 N R 11 E UM ADL0028243 Weelnesday, January 14, 2009 ExxonMobil Pt. Thomson Heritage Wells Identified May 18, 2007 in Commission Letter to Craig Haymes APC V KI. # PTD # Oper Rem. a Welt Name Field See Twp N/S Rng W/E PM Lease(s) 50-089-20001- MOBIL OIL W STAINES PT i I i 00-00 1691200 CORP ST 18-09-23 THOMSON 18 9 N 23J E j U 1 ADL 0028380 1 -�-- 50-089-20004- MOBIL OIL W STAINES *EXPLORAT 00-00 1750020 CORP ST 2 ORY 25 9 N 22 j E ! U ADL 002837 k 15T- 50-089-20005- 00-00 1760850 EXXON CORP THOMSONITHOMSON UNIT 1 PT T 32 10 N 23 I , E j U ADL 0047560 50-089-20006- EXXON THOMSON PT I i i 00-00 1770640 CORP UNIT 2 THOMSON 31 9 N 22 E U ADL 0047567 PT 50-089-20007- 00-00 50-089-20008- 1780050 EXXON CORP MOBIL OIL THOMSON UNIT 3 STAINES PT THOMSON IPT 1 34 10 j N 23 E I U ADL 0047558, ADL 0047559 00-00 1790010 CORP RIV ST 1 THOMSON 17_1 9 N 24 E U ADL 0047573 I i 50-089-20009- 00-00 1790800 - EXXON CORP THOMSON UNIT 4 PT THOMSON 32 10 N ' 22 j E ADL 0047563 50-089-20011- EXXON ALASKA ST PT I 1 j 00-00 1800460 CORP C 1 THOMSON 14 9 i N 23 } E U ADL 0028382 50-179-20007- ' EXXON ALASKA ST 00-00 1830450 CORP J 1 THOMSON 2� 3 -- 6 N 22 E -U ADL 0344033 20 AAC 25.110. Suspended dells (a) If allowed under 20 AAC ? 1(». the commission «i11, upon application by 111e operator under (b) of this section, approve the suspension of a well if (1) the well (A) encounters hydrocarbons of sufficient quality and quantity to indicate that the well is capable of producing in paying quantities, as reasonably demonstrated by well tests or interpretive formation evaluation data; for purposes of this paragraph, "paying quantities" means quantities sufficient to yield a return in excess of operating costs; (B) is a candidate for redrilling; (C) has potential value as a service well; or (D) is located on a pad or platform with active producing or service wells; and (2) the operator justifies to the commission's satisfaction why the well should not be abandoned, and, if the well is not completed, why the well should not be completed; sufficient reasons include the (A) unavailability of surface production or transportation facilities; (B) imprudence of security maintenance of a completed well in a shut-in status; (C) need for pool delineation and evaluation to determine the prudence of pool development. (b) An Application for Sundry Approvals (Form 10-403) must be submitted to and approved by the commission before plugging operations are begun in a well for which suspension is proposed, except that oral approval may be obtained from the commission if it is followed within three days by the submission of an Application for Sundry Approvals for final approval by the commission. Approval will be conditioned as necessary to protect freshwater and hydrocarbon resources. An Application for Sundry Approvals must include (1) the reason for suspending the well and information showing that the applicable criteria for suspension under (a) of this section have been met; and (2) a statement of proposed work, including (A) information on abnormally geo-pressured strata; (B) the manner of placement, kind, size, and location, by measured depth, of existing and proposed plugs; (C) plans for cementing, shooting, testing, and removing casing; (D) if the Application for Sundry Approvals is submitted after beginning wor1:, the name of the representative of the commission who provided oral approval, and the date of the approval; and (E) other information pertinent to suspension of the well. (c) At the operator's request accompanying the submission, information submitted to show that the applicable criteria for well suspension under (a) of this section have been met will be kept confidential (1) for the period specified under AS 31.05.035 (c), if the information is described in 20 AAC 25.071(b) ; or (2) for the time that the information has value as a trade secret, if the information is not described in 20 AAC 25.071(b) but is determined by the commission to constitute a trade secret under AS 45.50.940 . (d) A well approved for suspension must be plugged in accordance with the requirements of 20 AAC 25.112, except that the requirements of 20 AAC 25.112(d) do not apply if (1) a wellhead is installed or the well is capped with a mechanical device to seal the opening; and (2) a bridge plug capped with 50 feet of cement or a continuous cement plug extending 200 feet within the interior casing string is placed at or above 300 feet below the surface; the commission will waive the requirement of this paragraph for a development well drilled from a pad or platform, if the commission determines that the level of activity on the pad or platform assures adequate surveillance of that development well. (e) Until a suspended well has been abandoned or re-entered, the operator shall maintain the integrity of the location, provide the commission with a well status report every five years, and clear the location in accordance with 20 AAC 25.170(a) (2) or (b) or with 20 AAC 25.172(c) (2) or (d), as applicable. History: Eff. 4/2/86, Register 97; am 11/7/99, Register 152 Authority: AS 31.05.030 f ExxonMobil Production Com~y P. O. Box 196601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone 907 564 3677 Facsimile December 19, 2008 ~`rai~ i"iagr6ll@S Alaska Production Manager Joint Interest U.S. E~onMobil I'roc~r~cti®n ~~~% JAN ` ZDD~ Barrow, Alaska 99723 ~ ~j ~ ~~~ O Re: Point Thomson Unit #4 Conditional Development Permit Application Point Thomson Area Remediation Program North Slope, Alaska Mr. Johnny Aiken North Slope Borough Planning Department P.O. Box 69 Dear Mr. Aiken: Exxon Mobil Corporation proposes to perform inspections and remedial work at nine former exploratory wells and drill sites in the Point Thomson area. The Conditional Development Permit application and following project documentation are attached for the Point Thomson Unit #4 well: • Coastal Project Questionnaire including North Slope Borough Title 19 Analysis, • Project Description (including all maps), and • Application fee of $3,000. Additional permit applications or amendments to existing applications/permits will be submitted to the Alaska Department of Natural Resources, Alaska Department of Fish & Game, Alaska Department of Environmental Conservation, Alaska Oil and Gas Conservation Commission, and US Fish & Wildlife Service in January. Please call Rob Dragnich at 907-564-3711 or Mike Barker at 907-564-3716 if you have any questions. Sincerely, CAH/eaa Attachments cc: Shawn Stokes, ADEC Steve Schmitz,. DNR DOG Gary Schultz, DNR DMLW Nina Brudie, DNR DCOM Patricia Bettis, DNR DMLW Jack Winters, ADFG Tom Maunder, AOGCC Cindy Godsey, EPA Craig Perham, USFWS A Division of Exxon Mobil Corporation u - -~- Land Management ~ Regulations Permit Application °'*~-rwi'1' Permit Number Applicant Exxon Mobil Corporation Address P.O. Box 196601 Anchorage, AK 99519-6601 • NORTH SLOPE BOROUGH DEPARTMENT OF PLANNING AN DCOMMUNTI'Y SERVICES PERMITTING AND ZONING DIVISION Permit Type Date State ID Phone Conditional Development December 19, 2008 907-564-3617 Contact Person Mike Barker Project Name Point Thomson Unit #4 Well Inspection Location (TRS) 2,700' NSL 2,900' WEL Sec. 32 T10N 822E UM Unitized Field Name Zoning District Proposed Start Date February 1, 2009 Completion Date: August 31, 2011 Proposed Development Inspect well, check casing pressures and perform final well remediation. Purpose of Development See attached Project Description. ^ Fill/Dredge Material Acres ® Oil and Gas Wells Number of New Surface Holes: 0 ® Temp. Water Use Source Alaska State C-1 Pit and Lake 17 Equipment All terrain vehicles, trucks. Purpose Water for camp, ice road construction Maximum Amount 1,000,000 gpd All terrain vehicles, rolligon, ® Off Road Travel: Period of Travel Feb 1, 2009 -Aug 31, 2011 Equipment Steiger. aircraft Access to Site All terrain vehicles, aircraft ®Fuel Storage Type Diesel fuel stored in steel tanks Amount X10,000 gal on-mo I e t to ave o secon containment capacity per Handling Plan requirements for fuel transfers and handling. ^ Hazardous Type Amount Materials Storage Handling ® Solid Waste Treatment Backhaul to permitted facilities in Prudhoe Bay or incinerate on site. ^ Mining Mining Habitat ® Air Emissions Type Heavy equipment, trucks, heaters, generators ~o~t < 100 tons/yr All terrain vehicles, aircraft, trucks, heavy ® Noise/Vibrations Type equipment Amount <_ 110 dBA ^ Sensitive Habitat Floodplain Shoreline ® Transportation Type All terrain vehicles, aircraft, trucks ^ Marine Tanker Facility ^ Seismic Work ^ Utility Development ^ Recreational Development ^ Causeway Construction ^ Offshore Drilling ^ Residential Development ^ CD-ROM Included ^ Airport or helicopter Pad ^ Oil Transport System ®Snow Removal and Pad Location Point Thomson Unit #4 ~ • ATTACH TO THIS APPLICATION THE FOLLOWING: -GENERAL VICINITY MAP -SPECIFIC LOCATION MAP, INCLUDING NEARBY EXISTTING DEVELOPMENT AND NATURAL FEATURES -BYTE SPECIFIC FOOTPRINT (IN ESRI SHAPE FILE FORMAT) ON A CD-ROM -A DIGITAL GIS SHAPE FILE OR GEODATABASE OF THE PERMIT AREA WITH NO ATTRIBUTES. THE PROJECT SHOULD BE NAD 1927 ALASKA ALBERS OF GEOGRAPHIC -DESIGN PLANS (PLOT PLAN), ELEVATIONS, CROSS SECTIONS, PROFILES. AS APPROPRIATE -SUPPLEMENTAL INFORMATION, AERIAL PHOTOGRAPHS, STUDIES, ETC. (AS NEEDED) SEND TO:NORTH SLOPE BOORUGH, LAND MANAGEMENT ADMINISTRATOR PO BOX 69 BARROW, ALASKA 99723 PHONE: (907) 852-0320 ---------------------------------------------------- IHEREBY CERTIFY THAT THE FOREGOING IS TRUE AND CORRECT TO THE BEST OF MY KNOWLEDGE Authorized Signature z L-i ~~~~ Date Craig A. Haymes Name Alaska Production Manger Title FEE PAID ^ SPECIAL PLANNING COMMISSION MEETING ....$12,000.00 ^ DEVELOPMENT PERMIT... $2,000 + $500 PER WELL ^ ADMINISTRATIVE APPROVALS ...$1500.00 ® CONDITIONAL DEVELOPMENT PERMITS...$3,000.0 AMOUNT PAID $3,000 DECISION ^ ADMINISTRATIVELY APPROVED This is a minor amendment to a development pernut or is a use of land listed under administrative approvals for this zoning district. ^ REZONING APPROVED This proposed development substantially complies with the Master Plan, and a use permit is issued, conditioned on compliance with all relevant Master Plan conditions, lease stipulations and provisions of state and federal law and permits served there under. ^ DEVELOPMENT PERMIT APPROVED The proposed development meets all applicable mandatory Policies, represents the Developer's best efforts to implement all relevant best efforts and minimization policies, and as long as any conditions set forth in the accompanying letter are complied with, will represent a net public benefit. (See accompanying letter) ^ CONDITIONAL DEVELOPMENT PERMIT APPROVED This is a use of land that is listed as a conditional development for this zoning district or has been elevated by the Land Management Administrator to the Planning Commission. ^ PERMIT DENIED (See accompanying letter) Land Management Administrator Date If you wish to appeal this decision, use must submit written notice to the secretary of the Planning Commission prior to the next regularly scheduled meeting, stating the policy or policies in questions and the reason you believe the decision is incorrect. ~~ Project Description Point Thomson Area Remediation Program Exxon Mobil Corporation 1. Project Overview and Schedule Exxon Mobil Corporation (ExxonMobil), on behalf of itself and other Point Thomson area lease owners, intends to conduct various inspection and remedial actions at nine different former exploratory well sites in the Point Thomson area beginning during the winter of 2008-09. This project description covers the full range of remedial activities that are being planned although only a portion of the work may be .conducted during the winter of 2008-09. The entire program is expected to be completed by August 31, 2011. The timing of specific components will depend upon the status and plans for other activities in the Point Thomson area. A key consideration is the extent to which the Point Thomson Drilling- Program, which includes construction of a sea ice road from Prudhoe Bay to the Point Thomson area, proceeds during the winter of 2008-09. For instance, if the drilling program does not proceed as planned during the winter of 2008-09, certain remedial activities that can be conducted more efficiently and safely in conjunction with certain aspects of the drilling program may be deferred to when those activities are conducted. Any work that may be deferred is not time sensitive and deferral would not pose an environmental threat; the locations and wells are stable. A decision on remediation work to conduct this winter will be made following a determination of the drilling program activities that will proceed, development of detailed work plans, and receipt of the necessary permits. The work scope includes 1) conducting inspections of nine former exploration wells as required by Alaska Oil and Gas Conservation Commission regulations for suspended wells, 2) conducting further remedial work on plugged and abandoned wells, and 3) closure of the open reserve pit at the West Staines State #2 well location. Assuming receipt of all required permits and authorizations by January 30, 2009, the work will commence about February 1, 2009, and be completed by April 15, 2009. During the summer of 2009, the locations will be visited by helicopter to allow for further clean-up and inspections. If the sea ice road for the drilling program is not conducted during the 2008-09 winter season, the inspection and remediation work that is conducted during the 2008-09 winter season will be supported by agency-approved off-road vehicles such as steigers, cat trains or rolligons or a combination of all off-road vehicles and conventional vehicles on local ice roads. 2. Permit Requirements This project description provides information necessary to support the applications for permits, authorizations, and coverage under general permits summarized on Table 1 which are required to conduct the desired remediation work. Page 1 of 6 • Table 1-Permit Requirements i A enc Re wired Authorizations State of Alaska Department of Natural Alaska Coastal Management Program Consistency Resources (DNR) Determination; expected to operate under following General Concurrence Determinations - GCD-5 Equipment Crossing of Streams - GCD-19 Cross Country Movement of Equipment Winter/Summer - GCD-34 Ice Road and Ice Pat Construction in the NSB - GCD-45 Storage of Materials at Existing Pads in the NSB - GCD-49 Removal of Uncontaminated Gravel Structures • Lease Plan of Operations Amendment" • Land Use Permit for Off Road Travel** • Land Use Permit for Ice Roads (onshore) • Temporary Water Use Permits" Department of Fish and Title 16/41 Fish Habitat Permit""" Game Department of Reserve Pit Closure Plan Environmental Conservation Sec. 401 NPDES Water Quality Certfication** (ADEC) Alaska Oil and Gas • Sundry Notice Approvals for well work Conservation Commission AOGCC Borou ocal • North Slope Borough (NSB) • Conditional Development Permits for activity in a Resource Development District without a Master Plan (within PTU) • Develo ment Permits for activities outside PTU United States of America • Environmental Protection • Notice of Intent for coverage under NPDES General Permit AKG- Agency 33=0000 for Gravel Pit Dewatering~"" • Sill Prevention Control and Countermeasure SPCC Plan • US Fish 8 Wildlife Service • Letter of Authorization (LOA) for Inadental Taking of Polar Bears USFWS and Pacific Walrus** * Approval of the lease Plan of Operations is the primary authorization from DNR for conducting well and related operations on a lease. All of the former exploration well operations were conducted under an approved lease Plan of Operations. The status of these Plans of Operations is uncertain and ExxonMobil will work with the DNR/ DOG to determine appropriate authorizations for this work. ** Applications for similar activities were requested for the Point Thomson Drilling Program. Coverage under the existing requests to cover the remediation program will be requested rather than submittal of new applications. 3. Site Access Site access primarily will be accomplished through the use of vehicles traveling on ice roads or off-road vehicles. Helicopter or fixed wing aircraft will also be used depending upon activity for the Point Thomson Drilling Program and the logistical capabilities that are available. Figure 1 Page 2 of 6 • a shows the tundra and offshore ice road routes between the Prudhoe Bay area and the Point Thomson area. Figure 2 shows the specific drill site locations and tundra travel or ice road routes within the Point Thomson area. 4. Well Remediation Work There are nine former exploratory wells in the Point Thomson area at which ExxonMobil is planning to perform remedial work. The names of the wells and work being considered are shown on Table 2. Four of these wells have been plugged and abandoned (P&A'd) and five are suspended. All nine wells have wellheads that are partially or completely covered with gravel. ExxonMobil plans to excavate the gravel from around the wellheads, perform visual inspections of the wells, and install pressure gauges to verify there is no internal pressure. This work will be accomplished in the winter of 2008-09 and is not dependent upon the ice road or drilling program activities. Removal of debris and location clean-up will be performed at all sites as necessary. Tie excavated gravel will be retained on location. For the four P&A'd wells, ExxonMobiI plans to remove marker posts, cut and remove casings to at least three feet below natural ground level, and weld marker plates upon the casing stubs to conform to current AOGCC regulations and practices. This will also include removal of some hydrocarbon based fluids from within the wellbores and verifying the integrity of existing cement plugs or placing of new cement plugs. The specific actions to be performed on these wells will be addressed in Sundry Notice requests submitted to the AOGCC. For some wells, it may be necessary to mobilize a coiled tubing rig or other light duty drilling equipment to the area to conduct well remedial work. Table 2 -Point Thomson Area Wells Well Name Surface Location Well Status Planned Work PTU #1 1,320' NSL 660' WEL Suspended Inspection Sec. 32 T10N 823E UM PTU #2 2,615 NSL 1,801' WEL Suspended Inspection Sec. 3, T9N, R22E, UM PTU #3 660' NSL 711' WEL Suspended Inspection Sec. 34, T10N, R23E, UM Alaska State G1 660' EWL 660' SNL Suspended Inspection Sec. 14, T9N 823E UM Staines fiver St. #1 321' NSL 1,658' EWL Suspended Inspection Sec. 17 T9N 824E UM PTU #4 2,700' NSL 2,900' WEL P&A'd Inspection, well remedial work Sec. 32 T10N 822E UM Alaska State J-1 1,886' NSL 2,404' WEL P&A'd Inspection, well n:medial work Sec. 23 T6N R22E UM West Staines St. #2 848' SNL 50' WEL P&A'd Inspection, well remedial work, Sec. 25 T9N R22 UM reserve it closure West Staines St. 1,514' SNL 1,730' WEL P&A'd Inspection, well remedial work 18-9-23 Sec. 18 T9N R23E UM Page 3 of 6 • 5. West Staines State #2 Reserve Pit Closure The West Staines State #2 exploratory well site has an open but inactive reserve pit. The closure plan will include filling the pit and installing a gravel cap designed to eliminate ponding of surface water within the reserve pit footprint. An estimated 17,000 cy of fill material is required to fill the pit and construct the cap. It may be possible to obtain these amounts from existing gravel at the West Staines St. #2 pad and West Staines St. 18-9-23 pad approximately 2 miles to the north. Other sources of fill material are being evaluated and may be proposed to the ADEC as part of the closure process. Further details will be provided in the reserve pit closure plan that will be submitted to the ADEC for review and approval. 6. Water Requirements and Sources A temporary Water Use Permit (TWUP) was previously requested to obtain water from the Alaska State C-1 gravel pit. That permit application will be modified to also include additional shallow (non-fish bearing) lakes in the Point Thomson azea and the scope will be broadened to address this remediation project. If ice roads are used, water will be hauled using water trucks or tanks on conventional trucks. If off-road vehicles aze used, the water will be hauled in tanks placed on the off-road vehicles. 7. Logistical Support The remediation work will be supported by an existing camp at the PTU 3 pad, which was staged to support the Point Thomson Drilling Program and by one or more portable camps that may be transported to each location. These camps will be equipped with potable water storage tanks, gray water treatment plants, electrical generators, fuel storage tanks, and small incinerators. All camps will operate under valid public drinking water supply and environmental health/food services permits issued by the ADEC to the camp operators. Up to 10,000 gallons of fuel will be stored on location and will be re-supplied as needed. Pump houses will be located on the water source lakes and be fitted with ADF&G approved water intake structures. 8. Waste Management Solid, non-burnable wastes will be deposited into containers on site for back-haul to the Prudhoe Bay area for disposal. Any food wastes that could attract wildlife will be incinerated onsite, stored in enclosed containers awaiting periodic hauling, or hauled each day to the PTU 3 staging azea. Camp waste waters will be treated and discharged to the tundra by the camp operators in accordance with EPA's NPDES General Permit AKG-33-0000. Page 4 of 6 9. Wildlife Issues a Wildlife that could be in the area during the winter includes owls, ravens, arctic foxes, polar bears and brown bears. Polar bears are expected to be present in the azea and are known to den in the surrounding coastal environment. Brown bears inhabit the general area. It is unlikely they will still be active during the winter season but they may be present beginning in April when they emerge from their dens. LOAs from the USFWS for the incidental take of polar bears and Pacific walrus will be requested, and operations will be conducted in accordance with those authorizations. A Beaz- Personnel Encounter Plan which describes procedures to protect bears and personnel and avoid encounters has been prepared. The USFWS will be consulted as appropriate during planning and construction of ice roads and in conducting surveys to identify dens. If a polar bear den is identified, the USFWS will be notified and the transportation route will be altered to maintain at least one mile from bear dens unless otherwise approved by the USFWS. Approval for such changes will be addressed via the Land Use Permits. Project personnel will be instructed not to feed wildlife of any type or in any other way attempt to attract animals and birds either at the drill site or on ice roads. Food will be kept inside buildings or containers that minimize odors. Hazazdous materials will be kept in drums or other secure containers. Any bear sightings will be immediately reported to the site superintendent and the personnel in the azea warned of the location of the animal. Dedicated bear monitors will be maintained on location to look for and identify evidence of beaz presence in the project vicinity. Upon identification of bear signs or a sighting, the bear monitor will notify the site superintendent of the presence of bears in the area. Bear monitors will also be assigned to continually watch bears when present in the project vicinity. Qualified bear monitors from the village of Kaktovik or Nuigsut will be employed, if available, particularly during periods of potential subsistence use of the Point Thomson azea to monitor project activities and coordinate with onsite staff to ensure subsistence activities are not impeded. 10. Oil Spill Contingency Plans ADEC does not require oil discharge prevention and contingency plans be prepazed or approved for remediation projects including well entries such as aze being considered here. Spill Prevention Control and Countermeasure Plans (SPCC) as required by EPA regulations will be prepazed and in effect. Page S of 6 • 11.0 Communications and Supervision i An ExxonMobil designated representative will be on site at all times during operations. Twenty- four hour phone service will be available at the drilling or construction camp. The following persons or positions are designated contacts for the project. Name Title Phone/Email Mobile Phone TBD On-site TBD NA Su ervisors Mike Barker Regulatory 907-564-3617 907-223-9904 Mana er mike.barker exxonmobil.com Prior to the start of field operations this contact list will be updated and provided to the applicable agencies. 12.0 Environmental and Safety Training All North Slope based company and contractor personnel will complete an 8-hour unescorted training program provided by the North Slope Training Cooperative (NSTC), which will include receiving a Field Environmental Handbook, an Alaska Safety Handbook, and a North Slope Visitor's Guide. This training will provide the basis for compliance with lease terms and permit conditions/stipulations for most employees, including wildlife and environmental awareness training. Additional specialized training will be provided to employees as needed, including such topics as detailed waste analysis planning, manifesting, and permit compliance requirements. 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Box 196601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone 907 564 3677 Facsimile March 17, 2008 Commissioner Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 Re: Pt. Thomson Wells — Plugging and Abandonment Dear Commissioner Seamount: i7y. o,/JU Crai, ayenes 07� Alaska Production Manager / Joint Interest U.S. 1-7 U,Y5 1-77. 0&4 -7f v 561) 17?. 0 1?o EvzonMobil D qti Production /Z,9 /a0 '7�.oa�) RECEIVED MAN 1 8 x008 Alaska Oil & Gas Cons. Comnisft Anchorage In response to the Commission's December 7, 2007, letter to ExxonMobil, attached are sundry notices requesting the Staines River State No. 1, Alaska State C-1, and Point Thomson Unit No.'s 1, 2, and 3 wells be reclassified from abandoned to suspended status. Site inspection sundry notices, Form 10-404 reports and photos, are also attached for these five wells and the Point Thomson No. 4, Alaska State J-1, West Staines No 18-9-23, and West Staines No. 2 wells. We are making plans to conduct the inspection and remediation work described in ExxonMobil's letter of November 14, 2007, and the Commission's December 7 letter during the winter of 2008-`09. As you know, we submitted a Plan of Development for PTU to the Department of Natural Resources that calls for drilling operations to be conducted during the winter of 2008-'09. Approval of this plan by DNR will afford the opportunity to conduct the well remediation work described in our November 14 letter in conjunction with that drilling plan. We share the Commission's desire to conduct the remediation work in a timely and date certain manner, but we would like the opportunity to revisit the timing of the remedial work if the drilling program does not proceed as currently planned. We believe there are operational safety and efficiency factors that should be considered. Please note the Staines River State #1 well is under extended confidentiality as provided under AS 31.05.035(d) and 20 AAC 25.537(b). We have included its report as a separate, confidential attachment. We again thank the Commission for providing clarity around the issues and for providing adequate time for ExxonMobil to conduct a thorough and thoughtful review. Please feel free to contact me, Bill Pecor, or Rob Dragnich if you have any questions. Sincerely, SCANNED Attach ents cc: Mark Ireland, ConocoPhillips Vince LeMieux, Chevron A Division of Exxon Mobil Corporation SARAH PALIN. GOVERNOR �t t�t►a►�IScKA OIL AND G f 333 W 7th AVENUE, SUITE 100 CONSERVATION CONDIISSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 December 7, 2007 Craig Haymes Alaska Production Manager ExxonMobil Production Company PO Box 196601 Anchorage, AK 99519 Re: Pt. Thomson Wells — Plugging and Abandonment Dear Mr. Haymes, This is in response to your letter of November 14, 2007 responding to the Alaska Oil and Gas Conservation Commission's ("Commission") letter of May 18, 2007 regarding the condition of certain Pt. Thomson Unit wells. The schedule and plan for remedial work provided with your letter are acceptable subject to the following conditions: ExxonMobil will perform the proposed field work for the 2008 — 2009 winter operating season regardless of whether there are any concurrent drilling operations in the Pt. Thomson Unit. All of the diesel will be removed from the W. Staines State #18-9-23 (169-120) and W. Staines State #2 (175-002) wells. If any of the diesel cannot be removed, a Commission petroleum engineer or inspector shall determine whether the shallow wellbore plugs are competent, and ExxonMobil must take any reasonable actions the Commission determines are necessary. All current and future statutory and regulatory requirements and all applicable rules, orders; and permits of the Commission will be complied with unless a waiver to a specific requirement is timely and otherwise properly requested and granted by the Commission. To assist the Commission in ensuring that its files are complete and accurate, by March 31, 2008, please submit for each well a Form 10-404, a summary of the observations from the work performed last summer, and location photos. Finally, nothing above expressly or implicitly evidences the Commission's position with respect to the status of ExxonMobil or any other person as a current Pt. Thomson Unit operator, working interest owner, or lessee. If you have any questions, please call me at 793-1221 or Tom Maunder, PE at 793-1250. Sincerely, D Cathy . Foerster Commissioner ExxonMobil Production Comp:, P. O. Box 196601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone 907 564 3677 Facsimile November 14, 2007 Chairman John Norman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 Re: Pt. Thomson Wells — Plugging and Abandonment Dear Chairman Norman: Craig s. Imes Alaska Production Manager Joint Interest U.S. E�onMobil Production RECEIVED NOV 14 2001 Alaska Oil & Gas Cons. Commission Anchoropa We are providing this letter in response to the Commission's May 18, 2007, letter to ExxonMobil regarding Point Thomson area wells that are classified as plugged and abandoned. ExxonMobil, as Operator and on behalf of the working interest owners of nine of the listed Point Thomson area exploratory wells identified in the Commission's letter, has undertaken an extensive review of the current physical status of each of these wells. (As Operator of the remaining well, BP will respond directly to the Commission on it.) This work included reviewing ExxonMobil's and the Commission's well files, including confidential Commission files for one well, conducting on-site inspections to assess the physical integrity of each well site, and conducting a joint owner review of each well by technical experts. We are pleased to report that none of these activities have identified any imminent safety or environmental threat conditions from the wells. Attached are photos taken during the on-site inspections. The extensive reviews provide the basis for this response to the Commission's letter. While we believe the wells met AOGCC requirements when the prior P&A actions were taken and are safe in their current condition, we recognize that performing certain remedial work can further reduce any risk of an incident that may occur in the future. With that in mind, we have developed the attached schedule and plan to conduct remedial work on the wells. If the Commission concurs with this work program, ExxonMobil will prepare the appropriate sundry notices and begin to carry out the actions. As described in this letter and accompanying attachment, the plan contemplates conducting remedial work on certain wells in the near future and reclassifying the remaining wells to a suspended status. The wells with planned near term remedial work do not appear to have future utility while the wells identified for reclassification are capable of producing in paying quantities. We believe it would be premature to conduct work on these latter wells that may make it more difficult to utilize them in future development operations. There are other existing suspended wells in the Point Thomson Unit, and we view this action as consistent with current circumstances. We understand that reclassification will carry an obligation to abandon the wells in the future in compliance with regulatory requirements. ORIGINALA Division of Exxon Mobil Corporation Commissioner John Norman - 2 - November 14, 2007 Please note the plan calls for conducting the most intensive phase of field work in conjunction with the first winter drilling season of currently -planned Point Thomson Operations drilling, which is proposed to occur during the winter of 2008-09. We believe conducting this work in conjunction with this drilling program will offer significant operational safety and efficiency benefits. In the event the drilling program does not progress as proposed, we will work with the Commission to determine appropriate timing for the remedial work. We believe this plan responds to the Commission's request that ExxonMobil provide information and documentation to demonstrate that the wells meet the requirements for plugging and abandonment or provide a schedule and plan for bringing these wells into compliance and should address any concerns that may exist regarding compliance with AOGCC requirements for plugging and abandonment. As the Commission is aware, a number of changes have occurred in the requirements for plugging and abandonment of wells over the past 40 or so years. We believe these changes were generally sound and resulted in safer operations. In some cases, however, the changes created specific conflicts for operators, e.g., the 1986 regulations required installing marker posts while the 1999 regulations prohibited such posts (unless the land owner requests them). The planned work program will address these matters on the wells planned for near-term remedial work and through future actions on the remaining wells. Other regulatory changes involving placement of cement plugs and retainers, cementing of casing stubs, or requirements of fluids left in the well are more subtle. In general, it would be unnecessary and impractical to later attempt to modify many of these items, particularly those that exist at deeper depths in the wells. In the interest of transparency and clarity, we will address any variances or deviations from current regulations in our sundry notices filed with the Commission. We appreciate the Commission's help in providing clarity around the issues and allowing adequate time for ExxonMobil to conduct a through and thoughtful review. We look forward to your concurrence so we can proceed with the outlined work plans. Please feel free to contact me, Bill Pecor at 564-3766, or Rob Dragnich at 564-3711 if you have any questions. Sincerely, IZI?— CA:rgd/jpc Attachments xc: Cmmissioner Cathy Foerster - AOGCC Commissioner Daniel T. Seamount - AOGCC Kevin Brown, BP Mark Ireland, ConocoPhillips Vince LeMieux, Chevron ORIGINAL Remedial Action Program Point Thomson Wells — Plugging and Abandonment Wells Affected Actions Timing PTU #1, PTU #2, PTU #3, - Conduct additional integrity investigations to include: - Conduct work during winter of 2008-09 PTU #4, Alaska State C-1, + Removal of gravel from around wellheads Staines River State #1, W. + Conduct visual inspection Staines State #18-9-23, W. + Install valves and pressure gauges Staines State #2, Alaska + Check for pressure in casing and all annuli State J-1 + Conduct further diagnostics as appropriate PTU #4 - Remove marker post - Conduct work in conjunction with first - Remove wellhead and casing to lower than 3' below year of Point Thomson delineation ground level drilling planned for winter of 2008-09 - Verify integrity of surface plug + Repair or replace as necessary - Remove near -surface arctic pack from 2 annuli and set cement plugs in annuli using top job techniques (plugs to be at least 50' long) - Install marker plate - Remove cellar - Conduct general location cleanup, and request final site clearance W. Staines State #18-9-23 - Remove marker post - Conduct work in conjunction with first - Remove diesel above surface plug year of Point Thomson delineation - Remove wellhead and casing to lower than 3' below drilling planned for winter of 2008-09 ground level - Verify integrity of surface plug + Repair or replace as necessary - Remove near -surface diesel from annulus and set cement plug in annulus using top job techniques (plug to be at least 50' long) - Install marker plate - Remove cellar - Conduct general location cleanup, and request final site clearance - 1 - W. Staines State #2 - Remove marker post - Conduct work in conjunction with first - Remove wellhead and casing to lower than 3' below year of Point Thomson delineation ground level drilling planned for winter of 2008-09 - Verify integrity of surface plug + Repair or replace as necessary - Remove near -surface arctic pack from annulus and set cement plug in annulus using top job techniques (plug to be at least 50' long) - Install marker plate - Remove cellar - Conduct general location cleanup, and request final site clearance Alaska State J-1 - Remove marker post - Conduct work in conjunction with first - Remove wellhead and casing to lower than 3' below year of Point Thomson delineation ground level drilling planned for winter of 2008-09 - Verify integrity of surface plug + Repair or replace as necessary - Install marker plate - Remove cellar Conduct general location cleanup, and request final site clearance PTU #1 - File sundry notice to change well classification from - Submit sundry notice within 90 days of abandoned to suspended AOGCC concurrence with action plan - Establish status reporting program in compliance with - Submit status report within 90 days of AOGCC regulations winter 2008-09 inspections PTU #2 - File sundry notice to change well classification from - Submit sundry notice within 90 days of abandoned to suspended AOGCC concurrence with action plan - Establish status reporting program in compliance with - Submit status report within 90 days of AOGCC regulations winter 2008-09 inspections PTU #3 - File sundry notice to change well classification from - Submit sundry notice within 90 days of abandoned to suspended AOGCC concurrence with action plan - Establish status reporting program in compliance with - Submit status report within 90 days of AOGCC regulations winter 2008-09 inspections -2- Staines River State #1 - File sundry notice to change well classification from - Submit sundry notice within 90 days of abandoned to suspended AOGCC concurrence with action plan - Establish status reporting program in compliance with - Submit status report within 90 days of AOGCC regulations winter 2008-09 inspections Alaska State C-1 - File sundry notice to change well classification from - Submit sundry notice within 90 days of abandoned to suspended AOGCC concurrence with action plan - Establish status reporting program in compliance with - Submit status report within 90 days of AOGCC regulations winter 2008-09 inspections -3- Point Thomson Area Drillsite Photos July 23, 2007 and August 22, 2007 ,::� "' 1, }. elf, 11 4A mew"*- Point Thomson Unit No. 2 Point Thomson Unit No. 2 �.ri % � err=`•," v i .. m 4t m > 'n S � S• Y ♦ t, S, y f !� r, 1. P , � s. ' S•a �N' 7r .'ala �i 3� r .. r T • w . t.� p„ t s1 i . +� , i is •!� :rt � . T �• 9 ^3, ,A � r:+ - . ' �( �7 *.+ 'F :'f `� �� � X' !'.m. q y'. • � ��y :tib-� y.�s. ���� f ����'� ;�. ��e Point Thomson Unit No. 2 :mss .tie• .,;" 'tea � r14s,;,i Point Thomson Unit No. 3 Point Thomson Unit No. 3 Point Thomson Unit No. 4 Point Thomson Unit No. 4 it .4 it N T. Al d4 Moe .7 vt 10 jo, I � 4,15. Sp Alaska State C-1 Alaska State C-1 �.•� a+ �' ..:b`A w . s" �.•f.:.. h1 �4J':�YyFe.s •NP: "'.i: _ - .. e- , ,� Vii- ♦ � •.AwAW r a �-'" a.$ ?ti„yc� �S. � +y�� _ .:""t Iry '�t►°`Y's c. � . `, y ti:`� m — �+R•F `-! .'�. "}�L o '�' ark ,4 �?�R�.,. r�'.L+rsy✓<�C`�•'' � +r��l�.� .l - - . ._� 'w ._ � 'all. •k. i 41 r i Opt, y - r�. - � y �„ R%`.' � ♦.K .: � • ♦ tai a \� Ul { 'R � <r-'. .. Y �..:t@. rs:� �[ '.-v:� .k �' ; ._:. � a+� :.��o+ vr• � A_ t �-�, t r •. � $ :e++c�'�«,� .F . ,.. �`:. �' �.. � � " r.m .► ''�`" yam. o _..-- �: _ - 3 ' � wT'R �. if �i � r� MS. �. ,.. �. ` .. ;S _ 9� �r � �i C f Y... e � i _ � � ' 1'. West Staines State #2 West Staines State #2 —,I. N, J: � �'�Ar 'f} �'��a i� .l7�,• � ORR yet„' •+v $ s.,t 44�,yN r s c 1, � ;L J *�.,•���`� � Y. K� ��.�` •� � i � . � 1 , . , } 1 . ;.1 •y I aka. � � �� ,�'tif-`"R � +1.�i�t c�C�'1 i�'ir y' ,yam tllo,�' Alaska State J-1 Alaska State J-1 ": mt pe jr Iv' mPoo `Ifs .k '� •IV ir ,YzS.!aAcY�� � ��y. �� `� � •' .. e, t M r acF•i�l+Y, 1 � � i , \ h � 1 ' �F��rw � .w» '' mow, . r� a .. � � r . , � ♦�./ '�{.r�Y � /�-tttq,�"S Tt�'3'„t� 3 ; �r r� r i _ as �i � Kms; `�.'+; 1 �.,,t.� .r s��R�l �' "st•�' '>r i' j r.: ;'. .. „, . �'`•; '� q -. �.� A �,1 -. ��s _ �:�'_ :�• �:�. � "" `..T S •;� �` !�• :r� �•�.� � ,'t.�i„ t✓F". a-1..2., '� !• rJ. � �'�r5; ryI7 S;` Jw ' SARAH PALIN, GOVERNOR AL[aKA OIL GALSW. AND S 333 7th AVENUE, SUITE 100 CONSERVATIONOCOMMISSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 August 14, 2007 Craig Haymes Alaska Production Manager ExxonMobil Production Company PO Box 196601 Anchorage, AK 99519 Re: Pt. Thomson Wells — Plugging and Abandonment Dear Mr. Haymes, This is in response to your letter of August 3, 2007 wherein you requested a ninety -day extension to the response time with regard to the condition of Pt. Thomson Unit wells as specified in the Commission's letter of May 18, 2007. It is stated that the additional time will allow further investigative work including site visits to the various wells. Your request is granted making your response due not later than 5:00 p.m. November 14, 2007 If you have any questions, please call me at 793-1221 or TJX Maunder, PE at 793-1250. SCANNED • ~~~ A.~as'~a rte, ~ a?',C~ ~as Cons~~r~/a~:iCrS^ '~',~ ?~v5~`+°~r'' 333 Jlfesti 7tr, AJerc ~~e, quite 1 X00 Ac^c~orage; Alaska 9950? -3539 ~~~~~~~~j1~~~~_?~~~ E~ ~ Nr ~ ~ ~ ~j ~~ l~l~ l M%~~ ~ ~ LOIJ~ ~~ ~ psi ~ £~~~ ~~~'-~, urYt ,~' '~ . Re: i't. ~f'hornsor? `v1/ells _ Plugging and Ahandonr~ent ~ . Ar~trora~~ 'Dear Commissioner Seamount; t'~~-~~~ lr~ response to the Commission's December 7; 2007, letter to ExxonMobil, attached are ~ Q Site inspection sundry notices, Form 10-404 reports and photos, are also attached for these five wells and the P,~int Thomson Na 4., , ,n,__t nt_:~__ pl.. rf .. ,,.,IL. ~ v < We are making plans to conduct the inspection and remediation work described in ExxonMobil's letter of November 14, 2007, and the Commission's December 7 letter during the winter of 2008 `09. As you know, we submitted a Plan of Development for PTtJ to the Department of Natural Resources that calls for drilling operations to be conducted during the winter of 2008-'09. Approval of this plan by DNR will afford the opportunity to conduct the well remediation work described in our !November 14 letter in conjunction with that drilling plan. We share the Commission's desire to conduct the remediation work in a timely and date certain manner, but vve would like the opportunity to revisit the timing of the remedial work if the drilling program does not proceed as currently planneda 1/Ve believe there are operational safety and efficiency factors that should be considered. Please note the Staines River Mate #1 well is under extended confidentiality as provided under AS 31~05.035(d) and 20 AAC 25.537(b). We have included its report as a separate, confidential attachment. We again thank the Commission for providing clarity around the issues and for providing adequate time for Exxonl~obii to conduct a thorough and thoughtful review, Please feel free :~o contact me, 13111 Pecor, or Rob ragnich if you .:have any ~{uestio.ns. Sincerer = - ~~-~• ~zacl'a~Y:e~~ts ~~ .~:,~ _~~ 1J~~j^'~, f-°ian~J; ~~r'OCC'.;~hi~1=ias STATE OF ALASKA MAR 1 $ 2008 ALAS~IL AND GAS CONSERVATION COMMON REPORT OF SUNDRY WELL OPERATIO#~ka Oii ~ Gas Cams, Comrrdssiot~ Atlt:hc-rarw 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ Site Inspection ~ Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver ^ Time Extension ^ Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Well ^ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: ExxonMobil Production Company Development ^ Exploratory^~ [~'1~ b ~ 79-80 ` 3. Address: PO Box 196601 Stratigraphic ^ Service ^ 6. API Number: Anchorage, AK 99519-8601 50-089-20009 7. KB Elevation (ft): 9. Well Name and Number: 33 Point Thomson Unit No. 4 8. Property Designation: 10. Field/Pool(s): ADL 47563 ~ Wildcat 11. Present Well Condition Summary: Total Depth measured 15074 feet Plugs (measured) See Attached true vertical 13194 r feet Junk (measured) None Effective Depth measured Surface feet true vertical Surface feet Casing Length Size MD TVD Burst Collapse Structural 66' 28" x 36" 91' 91' N/A N/A Conductor 2102' 20" 2127' 2127' 3060 1500 Surface 3397' 13 3/8" 3422' 3422' 5380 2670 Intermediate 11862' 9 5/8" 11887 10222' 7290 7100 Production 10730' 7" 15049' 13170' 13700 / 12460 13010 110760 Liner Perforation depth: Measured depth: 13475-477, 13478-542, 13580-562, 14802-812. 14822-882, 14956-976 True Vertical depth: 11673-674, 11875-735. 11752-754, 12931-946. 12960-13048. 14958-978 Tubing: (size, grade, and measured depth) N/A Packers and SSSV (type and measured depth) Baker Model F-1, 2 ea Baker F-1 @ 13423' + 14930 Retainers @ 4100', 13375', 13555' + 14920' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory0 Development ^ Service ^ Daily Report of Well Operations 16. Well Status after work: Oil ~ Gas ^ WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: Contact William C. Pecor Printed Name Willliam C. Pecor Title Point Thomson Coordinator Q~ Signature ~.~i~ G . ~~_,- Phone (907) 564-3766 Date 3 l4 pe ,~.-~„ Form 10-404 Revised 04/2006 ~ L c_ ~KI~ ~; Submit Original Only ~~~~' ~ ~ Exxon Mobil Corporation Pt. Thomson Unit #4 Well Schematic API #: 50089200090000 APTD #: 179-080 Wellhead has 20-3/4" A and 13-5/8" B sections with blind, 5,000 psi flange cap and marker Cement plug in 9-5/8" casing 5 100' - 0' (75' BGL to surface), 30" at 91' refrigerated conductor 50 sx ~ ,~ ° 26" hole Arctic pack in 20" x 13-3/8" ;+'; 10.2 p g and 13-3/8" x 9-5/8" annuli 20" casing at 2,127' CaCl 2 TOC in 20" x 13-3/8" at Water ,~TOC 2,900't 2,100', 100 sx, arctic pack from 2,100' to surface .~ TOC 3,100', 100 sx, 15 ppg permafrost cement followed by 180 bbls arctic pack r 13-3/8" at 3,422' 17" hole TOC 4,040' in 9-5/8" casing Halliburton EZSV at 4,100' 7" casing cut of at 4,319' ' ' 400' 150 - B f t 4 ±, sx ottom o cement a , TOC 8,900'± 9-518" at 11,887' 12-1/4" hole (10,222' TVD) Halliburton EZSV at 13,395' Halliburton EZSV at 13,555' 13.6 ppg ~ mud ~ c e - e c ~ TOC 13,375', 150 sx c c ' e c Baker Model F1 at 13,423' c c ~ Perforations 13,475' - 13,477' squeezed twice c with 150 and 200 sx class G c c Perforations 13,478' - 13,542', squeezed with ~ c 150 sx class G ~ Perforations 13,560' - 13,562' c c TOC 13,625'+ 15.6 ppg e mud `: 4 Bridge Plug at 14,707' r; Perforations 14,802' - 14,812' squeezed with h= 'e 200 sx, later drilled out A~. !,C ,, Perforations 14,822' - 14,882' squeezed with 150 Halliburton EZSV at 14,920' ~ sx, later drilled out ~- `~ Baker model F1 packer at 14,930' F -;~ Perforations 14,956 - 14,976', squeezed with 100 Cement in 7" casing at 15,007' sx class G 7" at 15,049' (13,170' TVD) Total Depth 15,074' (13,194' TVD) Well schematic drawn June 29'", 2007 by Jesse Mohrbacher, Fairweather E & P Services, Inc. • Point Thomson Unit No. 4 Drillsite Inspection August 22, 2007 This drillsite inspection occurred on August 22, 2007. As can be seen from the attached photographs, weather conditions were moderate (around 60 degrees F) and clear, allowing for good viewing conditions. There were no visible indications of well integrity problems nor were there indications of oil spills or stains on the pads and surrounding surtace waters. The pad was constructed of gravel over insulation, and the pad exhibited little signs of thermokarsting or other natural degradation over the areas underlain by insulation. The gravel was generally level and in good condition. The reserve pit had been backfilled and this area was thermokarsted. Gravel was not mounded appreciably around the wellbore, and the gravel in the cellar had settled leaving the top of the cellar exposed. The wellheads were not visible from the surface. The gravel surface around the wellbore appeared to have dried drilling mud mixed into the surtace of the pad. A small pipe extended about six inches above the pad near the cellar. A large pipe just off the gravel pad (150 feet north of the well) protruded about six inches above ground level, and there was some small metal pipe piling off the pad. There were minor pieces of insulation visible around the edges. There were no hydrocarbon sheens in the water in the cellar or nearby surtace waters. ,_ .._ ,., . .. f `~ ',. (, _ry r+° ~ ~ J 1w ~y~ . ~" Y3 L ~ ~±n4 ~_ f ~^~'., ~~ - ,tom- ~ '1 .~y,Ar 1 /` J. T.F ' ~ ~C'' is ~ ~ ~ ;l~~ 1'~ , ¢~ ~: ~ ." Point Thomson Unit No. 4 -1- ~~,,; _ _ Tq_ _ - .. . e.... ~ ..~~~ _ - ,~ '. ~.. Point Thomson Unit No. 4 -2- Point Thomson Unit No. 4 Point Thomson Unit No. 4 -3- Point Thomson Unit No. 4 -4- ,ll id', __..~ .-,;~aska 1'~~oduc_i € ~'la~age ~`i.'i.~i~i~/~(>LJ C! i~,Y~d~X~~.tQn ',. ol~.~an'~; ~Ei' ~~X ~ 76FJl ! Anchorage, Aid 99319 lie. Pt Thomson ~%elis -Plugging and Abandonment Bear i~Y- ~aymes, i- ~.; a~.~~~~.,- S - _ . This is in response to your letter of November 14, 2007 responding to the Alaska Oil and Gas Conservation Commission's ("Commission") letter of May 18, 2007 regarding the condition of certain Pt. Thomson Unit wells. The schedule and plan foa- remedial work provided with your letter are acceptable subject to the following conditions: 1. IJxxonMobil will perform the proposed field work for the 2008 - 2009 winter operating season regardless of whether there are any concurrent drilling operations in the Pt. Thomson Unit. 2. All of the diesel will be removed from the ~'. Staines State # 18-9-23 (I 69-120) and ~'. Staines State #2 (175-002) wells. If any of the diesel cannot be removed, a Commission petroleum engineer or inspector shall determine whether the shallow wel(bore plugs .are competent, and ExxonMobil must take any reasonable actions the Commission determines are necessary. 3. All current and future statutory and regulatory requirements and all applicable rules, orders, and permits of the Commission will be complied with unless a waiver to a specific requirement is timely and otherwise properly requested and granted by the Commission. To assist the Commission in ensuring that its files are complete and accurate, by March 31, 2008, please submit for each well a Form 10-404, a summary of the observations from the work performed last summer. and location photos. Finally, nothing above expressly or implicitly evidences the Commission's position with respect to the status of ExxonMobil or am other person as a current Pt. Thomson Unit operator. working interest owner. or lessee. If you have any questions. please call me ai 793» ! 22 f or Tom 1lilaunder. P1/ at 793-1250. Sincerely / a~ L%~ ~~' ~ o ~ % ' .d ~ ~ ~ ~ Cathy r'. t=oerster ~omm.issione° Exxoealitflo9se~ I~rodeactiion ~®a~apae~~ P. 0. Box 196601 Anchorage. Alaska 99519-6601 907 561 5331 Telephone 907 564 3677 Facsimile c~raa~ ~, ~ayeveex Alaska P ction Manager Joint Int~U.S. ~ ,~,; ~ . J ~ ~'~ ^~ .Pr®dttcti®r~ November 14, 2007 Chairman John Norman Aiaska Oii and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 Re: Pt. Thomson Wells -Plugging and Abandonment Dear Chairman Norman: We are providing this letter in response to the Commission's May 18, 2007, letter to ExxonMobil regarding Point Thomson area wells that are classified as plugged and abandoned. ExxonMobil, as Operator and on behalf of the working interest owners of nine of the listed Point Thomson area exploratory wells identified in the Commission's letter, has undertaken an extensive review of the current physical status of each of these wells. (As Operator of the remaining well, BP will respond directly to the Commission on it.) This work included reviewing ExxonMobil's and the Commission's well files,, including confidential Commission files for one well, conducting on-site inspections to assess the physical integrity of each well site, and conducting a joint owner review of each well by technical experts. We are pleased to report that none. of these activities have identified any imminent safety or environmental threat conditions from the wells. Attached are photos taken during the on-site inspections. The extensive reviews provide the basis for this response to the Commission's letter. While we believe the wells met AOGCC requirements when the prior P&A actions were taken and are safe in their current condition, we recognize that performing certain remedial work can further reduce any risk of an incident that may occur in the future. With that in mind, we have developed the attached schedule and plan to conduct remedial work on the wells. If the Commission concurs with this work program, ExxonMobil will prepare the appropriate sundry notices and begin to carry out the actions. As described in this letter and accompanying attachment, the plan contemplates conducting remedial work on certain wells in the near future and reclassifying the remaining wells to a suspended status. The wells with planned near term remedial work do not appear to have future utility while the wells identified for reclassification are capable of producing in paying quantities. We believe it would be premature to conduct work on these latter wells that may make it more difficult to utilize them in future development operations. There are other existing suspended wells in the Point Thomson Unit, and we view this action as consistent with current circumstances. Uve understand That reclassification Lvi!! cam; an obligation to abandon the wells in the future in compliance with regulatory requirements. A Division of Exxon Mobil Corporation Commissioner John Normar~ - 2 - ember 14, 2007 Please note the plan calls for conducting the most intensive phase of field work in conjunction with the first winter drilling season of currently-planned Point Thomson Operations drilling, which is proposed to occur during the winter of 2008-09. We believe conducting this work in conjunction with this drilling program will offer significant operational safety and efficiency benefits. In the event the drilling program does not progress as proposed, we will work with the Commission to determine appropriate timing for the remedial work. We believe this plan responds to the Commission's request that ExxonMobil provide information and documentation to demonstrate that the wells meet the requirements for plugging and abandonment or provide a schedule and plan for bringing these wells into compliance and should address any concerns that may exist regarding compliance with AOGCC requirements for plugging and abandonment. As the Commission is aware, a number of changes have occurred in the requirements for plugging and abandonment of wells over the past 40 or so years. We believe these changes were generally sound and resulted in safer operations. In some cases, however, the changes created specific conflicts for operators, e.g., the 1986 regulations required installing marker posts while the 1999 regulations prohibited such posts (unless the land owner requests them). The planned work program will address these matters on the wells planned for near-term remedial work and through future actions on the remaining wells. Other regulatory changes involving placement of cement plugs and retainers, cementing of casing stubs, or requirements of fluids left in the well are more subtle. In general, it would be unnecessary and impractical to later attempt to modify many of these items, particularly those that exist at deeper depths in the wells. In the interest of transparency and clarity, we will address any variances or deviations from current regulations in our sundry notices filed with the Commission. We appreciate the Commission's help in providing clarity around the issues and allowing adequate time for ExxonMobil to conduct a through and thoughtful review. We look forward to your concurrence so we can proceed with the outlined work plans. Please feel free to contact me, Bill Pecor at 564-3766, or Rob Dragnich at 564-3711 if you have any questions. Sincerely, / ~/~ ,: i ~ ~' Ali CA :rgd/jpc Attachments xc: Cmmissioner Cathy Foerster - AOGCC Commissioner Daniel T. Seamount - AOGCC Kevin Brown, BP Mark Ireland, ConocoPhillips Vince LeMieux, Chevron Remedial Action Program Point Thomson Wells -Plugging and Abandonment Wells Affected Actions Timin PTU #1, PTU #2, PTU #3,_ - Conduct additional integrity investigations to include: - Conduct work during winter of 2008-09 PTU #4, Alaska State C-1, + Removal of gravel from around wellheads Staines River State #1, W. + Conduct visual inspection Staines State #18-9-23, W. + Install valves and pressure gauges Staines State #2, Alaska + Check for pressure in casing and all annuli State J-'1 + Conduct further diagnostics as appropriate PTU #4 - Remove marker post - Conduct work in conjunction with first - Remove wellhead and casing to lower than 3' below year of Point Thomson delineation ground level drilling planned for winter of 2008-09 - Verify integrity of surface plug + Repair or replace as necessary ~--~ - Remove near-surface arctic pack from 2 annuli and ho c~l~Src` set cement plugs in annuli using top job techniques ~~~ (plugs to be at least 50' long) ~~/~~ - Install marker plate - Remove cellar - Conduct general location cleanup, and request final site clearance W. Staines State #18-9-23 - Remove marker post - Conduct work in conjunction with first - Remove diesel above surface plug (1~~ } year of Point Thomson delineation - Remove wellhead and casing to lower than 3' below drilling planned for winter of 2008-09 ground level - Verify integrity of surface plug IS air or replace as necessary poss~~p~• + Re (~~ c~\esE~ ~ p - Remove near-surface diesel from annulus and set cement plug in annulus using top job techniques (plug to be at least 50' long) - Install marker plate - Remove cellar - Conduct general location cleanup, and request final site clearance -1- W. Staines State #2 - Remove marker post - Conduct work in conjunction with first - Remove wellhead and casing to lower than 3' below year of Point Thomson delineation ground level drilling planned for winter of 2008-09 - Verify integrity of surface plug -~r~~~~'n + Repair or replace as necessary - Remove near-surface arctic pack from annulus and ~~5~~ set cement plug in annulus using top job techniques ' ~~ long) (plug to be at least 50 . a~C' - Install marker plate ~ - Remove cellar - Conduct general location cleanup, and request final site clearance Alaska State J-1 - Remove marker post - Conduct work in conjunction with first - Remove wellhead and casing to lower than 3' below year of Point Thomson delineation ho c`~'le.S~~ ground level drilling planned for winter of 2008-09 - Verify integrity of surface plug (np ~~ + Repair or replace as necessary ~~?'-N'~ - Install marker plate U ~ ~ - Remove cellar Conduct general location cleanup, and request final site clearance PTU #'I - File sundry notice to change well classification from - Submit sundry notice within 90 days of abandoned to suspended AOGCC concurrence with action plan - Establish status reporting program in compliance with - Submit status report within 90 days of AOGCC regulations winter 2008-09 inspections PTU #2 - File sundry notice to change well classification from - Submit sundry notice within 90 days of abandoned to suspended AOGCC concurrence with action plan - Establish status reporting program in compliance with - Submit status report within 90 days of AOGCC regulations winter 2008-09 inspections PTU #3 - File sundry notice to change well classification from - Submit sundry notice within 90 days of abandoned to suspended AOGCC concurrence with action plan - Establish status reporting program in compliance with - Submit status report within 90 days of AOGCC regulations winter 2008-09 inspections i -2- Staines Diver State #1 - File sundry notice to change well classification from - Submit sundry notice within 90 days of abandoned to suspended AOGC;C concurrence with action plan - Establish status reporting program in compliance with - Submit status report within 90 days of AOGCC regulations winter 2008-09 inspections Alaska State C-1 - File sundry notice to change well classification from - Submit sundry notice within 90 days of abandoned to suspended AOGC;C concurrence with action plan - Establish status reporting program in compliance with - Submit status report within 90 days of AOGCC regulations winter 2008-09 inspections -3- • ~~ ~ ~ .- ~' -- ~-> ~~ ~.. ~ ~_ i\liay ?3, 2007 : : ~~ = - ~ Commissioner Cathy Foerster Alaska Oil and Gas Conservation Commission 333 West 7~" Avenue, Suite 100 Anchorage, Alaska 99501-3539 Re: Point Thomson Wells -Plugging and Abandonment Dear Commissioner Foerster: - -: . _.._. _ ~,.,:J '~~;:.'~: :i We have received the Commission's letter dated May 18, 2007 regarding potential issues related to certain Point Thomson wells that were drilled and subsequently plugged and abandoned. Regulatory compliance is a core value for ExxonMobil, and we take all matters seriously. Our prior track record of voluntarily re-abandoning some wells and undertaking other remediation work in the Point Thomson Unit should speak to this. The May 18 letter requests that ExxonMobil respond within 90 days and either provide sufficient information and documentation to demonstrate the wells meet all requirements for plugging and abandonment, or to provide a schedule and plan for bringing the wells into compliance. We have begun an immediate review of the wells in question and have two requests of the Commission to help expedite that review: The well files for the Staines River St #1 well, which was drilled by Mobil in the 1979 timeframe and is under extended confidentiality, are not in our Anchorage office. It would facilitate our work to obtain a copy of the file from the Commission. 2. It would be helpful to obtain a copy of the concerns or issues identified in the Commission's review. We intend to conduct a thorough review of all of the wells in question and having any initial assessment by the Commission to check against as our work progresses may facilitate an earlier completion. It appears the wells on the list were operated by Exxon, Mobil or BP (formerly Sohio). To the extent another operator may be responsible for any of the identified wells we will work with the other owners to determine appropriate handling and response to the Commission. I will be out of town until May 31. Please contact Rob Dragnich at 907-574-3711 or Bill Pecor at 713-656-7064 to coordinate any information you are able to provide. Thank you for bringing these matters to our attention. Sincerely/y`ours, ..-- ~` C' I-l:jpc xc: Ang~;s ~iliaikv?', SP • flay 1 ~. 2i)07 Craig 1-laymes .alaska Production ~~tanager 1/xxon?Vlobil Production Company PO Box 19660 i Anchorage, AK 99~ 19 Re: Pt. Thomson Wells -Plugging and Abandonment Dear IVfr. Haymes, • ~,~~%~~ ~~~.t~, G~~f~~S~d~rT~ 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99 50 1-3 53 9 PHONE (907) 279-1433 FAX (90T,; 276-7542 During our review of the Pt. Thomson Eield in response to your recent applications for permits to drill, the Alaska Oil and Gas Conservation Commission ("Commission"j identified the following wells that, according to our records, are classified as plugged and abandoned but do not meet the requirements for plugged and abandoned wells under 20 AAC 2~.10~ - 20 AAC 2.172: W. Staines St. 18-9-23 W. Staines St #2 Pt. Thomson # 1 Pt. Thomson #2 Pt. Thomson #3 Pt. Thomson #4 Staines River St #1 Alaska State C- I Alaska State J-1 Challenge Island # 1 Within 90 days of receipt of this letter, either provide sufficient information and documentation to demonstrate that these wells meet all the requirements for plugging and abandonment, or provide a schedule and plan for bringing these wells into compliance. Also, please note that, under AS 31.0.090, the Commission cannot issue permits to drill to an operator that is in violation of a Commission regulation pertaining to drilling, plugging or abandonment of a well. The Commission reserves the right to pursue an Enforcement Action according to 20 AAC 25- ~3j. • C_ < ~ j-!ay mss j~1~+.~, I3. Z~O~ Pa~,e ? v t =inalli, nothing above shotiici be cvnstruecl to ~;ti idtnc:~~ e~pressl~ or implicitly the t~ummission's pc~siti~or v~•ith respect to the current status of Ecxon.~~ooi1 or any- Other person as a l~r_. ~~homs®n ur?~t JiOerat~r or lessee. l you ha~,•e any questions, please ca11 me at 793-1221. • To: Cathy Foerster, Commissioner May 9, 2007 Fr: Tom Maunder, PE Re: Status of Pt. Thomson Area Wells Yntroduction: As instructed, an assessment of the wells in the Pt. Thomson area was performed. The purposes of the assessment were to determine if the condition of the wells met the regulatory requirements in effect when operations were completed some years ago as well as if the wells would meet the now current regulatory requirements. There are a total of 21 wells in the general area (14 ExxonMobil + 1 ConocoPhillips + 6 BP). This document will only address the ExxonMobil wells. Recommendation: Based on examination of the well files, it is my assessment that 5 of the 14 ExxonMobil wells are Plugged and Abandoned in accordance with the now current regulations. The remaining 9 wells should be considered Suspended and AOGCC's databases should be changed to reflect this more accurate well status. ExxonMobil should be required to perform the work necessary to properly plug and abandon the wells. Discussion: There are 4 versions of the plugging requirements in effect depending on when the work was actually accomplished. A summary of the effective dates of the various regulations is listed below and copies of the regulations are attached. Requirements have become more proscriptive through time. There were major amendments to the AOGCC regulations effective 4!2/1986. These included significantly more proscriptive requirements for plug locations and lengths, a suspended well classification and included requirements for removal of the wellhead and casing "... at least 3' below rig grade." In the 11/7/99 amendments, the cutoff requirement was changed to "... at least 3' below original grade." Prior to 1980, 50' cement plugs were required above hydrocarbon zones and at surface with heavy mud-laden fluid between plugs. After 1980 100' of cement was required above hydrocarbon zones and casing stubs were required to be covered. Neither regulation explicitly required cutting off the wellhead and casings, although removal of all "... structures and installations ..." was required as part of location cleanup in the 1980 regulations. Effective Date 9/30/1967 DNR, 11 AAC 22 4/13/1980 AOGCC, 20 AAC 25 4/2/1986 AOGCC, 20 AAC 25 11/7/1999 AOGCC, 20 AAC 25 The physical downhole work on 7 of the 14 ExxonMobil operated wells was completed prior to April 13, 1980 and physical downhole work on 6 of the remaining wells was completed prior io April 2, i 986. The last well, Alaska State A-2, was plugged and abandoned in 1Q 2002 according to the 11/7/99 regulations. Regardless of when physical operations were completed in the legacy wells, letters were submitted (most in November • 1986) requesting the status of the wells be changed from suspended to abandoned. These requests followed physical inspection of the locations for site cleazance subsequent to removal of upper casing heads and installation of abandonment markers. No downhole work was performed subsequent to removal of the drilling rig. It is interesting that following the completion of downhole work that nearly every well was labeled suspended, and that term is not defined in AOGCC regulations until the 1986 amendments. Temporary abandonment is first addressed in the DNR regulations effective 9/30/67. Examination of the files for the ExxonMobil wells reveals that, so faz as I can determine, the wells have been effectively abandoned downhole. All wells had cement placed over productive intervals and usually employed retainers or bridge plugs. One well, Alaska State J-1 does not have any open hole plugs, but the well appazently did not encounter hydrocarbons. The intermediate casing shoe was squeezed below a retainer. Moving up hole, most wells had a portion of the production casing (7") cut and pulled. In all cases except Pt. Thomson #1, a retainer and/or a cement plug were placed on top of the stub. There was no specific requirement to cover the stub prior to April 13, 1980, although in 3 subsequent wells the cut top of the 7" was isolated. Wells generally had a retainer andlor cement placed at about 2500' with non-freezing fluids placed above it. Non-freezing fluids included CaCl2 brine and diesel. Where annuli were not cemented, non-freezing fluids such as arctic pack and diesel were placed. No well had all casing head heads removed. It appeazs that the casing heads from any casings smaller 13-3/8" were removed and the casings cut below the lowest flange depth. A blind flange with the abandonment post attached was then bolted to the flange. It is important to note that Exxon performed "re-abandonment" work on 4 of these wells that were located on the barrier islands offshore in 1998 - 1999. The offshore islands were being eroded, and it was likely that the well casings would be exposed possibly resulting in spills. Exxon specifically stated that the work would "... plug and abandon the wells according to current regulations." The 4 wells were re-entered, liquid hydrocazbons (diesel) removed, cement plugs placed and casings cut off well below sea level. These 4 wells and the Alaska State A-2 are the only wells that meet the plug and abandon requirements effective since April 2, 1986. Based on examination of the well files, it is my assessment that 5 of the 14 ExxonMobil wells aze Plugged and Abandoned in accordance with current regulations. The remaining 9 wells should be considered Suspended and carried as such in the AOGCC database. ExxonMobil should be required to perform the work necessary to properly plug and abandon the wells. Tom Maunder, PE Sr. Petroleum Engineer ExxonMobil Operated Wells Pt. Thomson Unit Area "'_~' Well PTD Date Date Work to Effective Re ulation? Comment Assessed Actual Required Work Suspended P&A 9/30167 4/13180 4!2186 1117/99 Status W. Staines St 169- 8/13170 5/1/73 by YES YES NO NO Diesel in annulus and Suspended Remove fluids, place 18-9-23 120 sun casin .Not cutoff. lu s, cutoff wellhead Alaska State A-1 174- 9/6175 * by letter YES YES NO YES Re-abandoned 1998 -1999. Plugged and None 014 11/86 Abandoned W. Staines St. #2 175• 5/26/75 * by letter YES YES NO NO Diesel incasing 150' - Suspended Remove fluids, place 002 9186 2279'. AP in annulus. Not plugs, cutoff wellhead cutoff Pt. Thomson #1 176- 1218177 * by letter YES NO NO NO No plug above cut 7" at Suspended Remove fluids, place 085 11186 4000'. Diesel in casing. plugs, cutoffwellhead AP in annulus. Not cutoff. Pt. Thomson #2 177- 8/1217$ * by letter YES YES NO NO AP in annulus. Diesel in Suspended Remove diesel. Cutoff 064 11186 casing at 40'. Not cutoff. wellhead. Remove some AP. Pt. Thomson #3 178- 714179 * by letter YES YES NO NO AP in annulus. Diesel in Suspended Remove diesel. Cutoff 005 11/86 casing at 40'. Not cutoff. wellhead. Remove some AP. Staines River St 179- 7121/79 11/5186 by letter YES YES NO NO Diesel in casing at 100'. Suspended Remove diesel, place #1 confidential 001 11186 Not cutoff, lu s, cutoffwellhead Pt. Thomson #4 179- 12/20/80 * by letter NA YES NO* NO* AP in 2 annuli. No diesel. Suspended Cutoff wellhead. 080 11/86 Not cutoff. Remove some AP. Alaska State C-1 180- 7114181 * by letter NA YES NO* NO* AP in 2 annuli. No diesel. Suspended Cutoffwellhead. 046 11/86 Not cutoff. Remove some AP. Alaska State D-1 180- 2/16/82 * by letter NA YES NO YES Re-abandoned 1998 -1999. Plugged and None 101 11/86 Abandoned Alaska State F-1 181- 5/30182 * by letter NA YES NO YES Re-abandoned 1998 -1999. Plugged and None 140 11/86 Abandoned Alaska State G-2 182- 8/19/83 * by letter NA YES NO YES Re-abandoned 1998 -1999. Plugged and None (confidential 208 11/86 Abandoned Alaska State J-1 183- 6/14184 * by letter NA YES NO* NO* No open hole plugs. No AP Suspended Cutoff wellhead. 045 11/86 or diesel. Not cutoff: Remove some AP. Alaska State A-2 200- 318/02 by NA NA NA YES Plugged and None 141 sundry Abandoned i NO*-no liquids present. MEMOR NDUM ALASKA OIL AND C-AS CONSERVATION COMMISSION of Alaska TO- St af f DATE February 9, 19 83 ~ FILE NO l'~S ~'~. TELEP'HONE NO. .~' FROM PJarry W. Kug ler Commissioner SUBJECT' Extended Confidentiality. Currently the AOGCC hold data on the following 12 wells in an indefinitely extended confidential period: FO~ER ~LL N~.~ P~E EkTE OPEP~%~R & N~ AP1 ~?'~EER 05/06/79 01/30/80 12/31/80 01/11/81 04/24/81 07/24/81 0~/20/81 04/20/82 05/12/~ o51z5182 Union Oil Co. Texaco, Inc. f~evron U.S.A. Chevron U.S.A. Atlantic Richfield Co. ~%ion Oil Co. of Calif. Mobil Oil Corporation Conoco Inc. Mobil Oil Co~poration Oonoco Inc. East Z~rrison ~ay St. #1 Tulugak #1 E~le ~. #~ X~ lukpuk #1 West Sak 25606 #13 Cannery Loop Unit 91 Staines River St. #1 O~ydyr Bay State 91 6~ydyr Bay State Unit #1 Mi]ne Point Unit #A-1 50-703-20001 50-057-20001 50-073-20001 50-057-20002 50-029-20345 50-133-20323 50-0~9-20008 50-029-20375 50-029-20396 50-029-20376 oz/19/~ o6/~/~ Fa~Dn Cozp. Union Oil Co. of Calif. Point Thcmson Unit #4 Cannery Loop Lhit #2 50-0 89-20009 50-133-20333 O2-001A(Rev l 0/79) DItPARTMItNT Ol.~ NAT[~R,AL RESO[~RCES MINERALS AND ENERGY MANAGEMENT February 3, 1983 ES BILL .~FIEFFIELD, ~,O~_~_~NG~__' Pouch 7-03~ C. V. Chatterton, Chairman Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Re: Release of well data from Pt. Thomson Unit No. 4 Well Dear Commissioner Chatterton: By letter dated January 10, 1983, I requested that you release confidential data from 18 wells located on the North Slope which no longer qualified for extended confidentiality. In preparing that list, the division inadvertently omitted an additional well, the Exxon Pt. Thomson Unit No. 4, which should have been included. I hereby authorize and request release of the data from that well. In order that the affected party may have an opportunity to submit comments, if any, prior to release of the well data. the data should not be released to the public until March 11, 1983. Si ncerely, ' !~ Director cc: E. D. Stout Exxon Corporation RECEIVED FEB - 4 1983 Alaska 011 & Gas Oons. Commission Anchorage September 4, 1981 Exxon Company, U.S.A. 3301 wC~ Street P.O. Box 6601 Anchorage, Alaska 99502 Final Abandonment Location Clean-up Inspection Point Thomson Unit No. 4, Sec. 32, T10N, R22E, UM. Gent le~en ~ Our representative inspected this site on August 11, 1981. It was found 2hat the clean-~ was aoceptable and that there was a pr c~er we 11 marke r. Consequently f ina1 abandonment of Point Thomson Unit }~o. 4 is approved. Sincerely, Lonnie C. Smith ALASKA OIL AND GAS CONSERVATION COMMISSION Thru~ Royle R. Ramilto~ Chairman C~missioner j Do ug Amos ~, ~ Petroleum Inspector August 27, 1981 Conduct Abandonment Inspection on Exxon's Point Thomson Unit No. 4 Well, 'Sec. 32, TiON, Permit No. 79-8c~ Res_day. Aught.. 11., 1981~ As the attached pictures show, the location is in good condition. There is a proper abandonment marker on the well and the pad is smooth and mud pit has been filled. Therefore I recommend that the c~mission grant to Exxon a final abandonment for this location. In summary z I conducted the final abandonment inspection on Exxon' s Point Thomson Unit 84 well. FILE iNFOR!LtTION: Operator ~XX~I~ ~-,~. ~,~05. ~, Address ~', '~~0¢~ ~;¥ ~ Surface L-ocat'iou of Well _Z_fglO___~'t. F ~gL, tO00 Ft. F ~L, ~URFACE ABANDO':'IENT REPORTO 20 AAC 25, '\RTICLE 2 ! Date Downhole P & A 20 AAC 25.120: WELL ABANI)ONHENT ~bXRKER: D~a. Steel Post (4"Min.) ¥~-='2 Length (10' Min.) ~ Height Above Final Grade l.evel (4' blin.~ ~1 , Top of Marker Pipe Closed with: Cement Plug Screw Cal~ Welds Set: On Well tlead ~, On Cutoff Casing ~, In Concrete Plug D~stance Below Final Grade Level ~ Ft. ~,~ in. Side Outlets: All Valves and Nipples Removed ~ All Openings Closed , With Blinds , With Cement ~ , Other INFOILHATION BE,\IJWELI)I']I) DIRI']Cq'ELY TO M~RKER POST' (List t;~ere Different from File Information) ' Operator ~~ ~, ~ ~ Unit or Lease Name ~. ~~o~ Well Number ~. ~~0~ ~~ ~~ , Surface Location of Well: .~00 Ft. Fg6 L, .%~ Ft., FWS., Sec 3Z , r ~0 0 , R 20 AAC 25. 170: LOCATION CLEAN-UP PITS: Filled In t/ , Liners Removed or Buried w'''~, Debris Removed SURFACE OF PAl) AND/OR LOCATION: Rough Other , Smooth /, Contoured , Flat ~Compacted CLEAN UP OF PAD AND/OR LOCATION: Clean L~, Pipe Scrap , Iron Scrap Paper , Other , Wood , Hud , Cement , SURROUNI)ING AREA: Wooded , Brush , Tundra L/% Grass Sand , Other , Dzrt , Gravel CONDITION SURROUNDING ARE,\' Clean Other Trash from Site__ , Trees and/or Brush from Clearing Site ACCESS ROAD: Dirt , Gravel__, Ice__ , Other CONDLTION ACCESS ROAD AND SURROUNI)ING: Clean Rough Smooth Trash from Operations OtherTrees and/or Brush from Clearing Road __,l~ [ REMa\INING TO BE DONE: ~0~ ~'' RECOHtlENI). APPROVAL OF ABANDONHENT: Yes ~, No Final Inspection /'" INSPECTED BY ~)g~ ~ ~Ot~ 05/26/81 ~ ~~ ~.~ ,~z~ ~,-.a~. k 4 , ~ ans. .. ,~ ~rw2sM ~ Y,~~ __.~r+~ ~.Z~. '""'~ Oo } S e M 0 i n~ V z ~. -~ ~~ ~3 ~~ .~ Z y ~~ Z ~- -~ O • I m~ x 0 f~ • ` ~~~k 0 LT . e*d 8-~~ -s~ 0 a-®a P~. Th~.+MsoH *- 4 8-i©~ P~. THo w~4oh ~4 -~ g. ~~- e ~ Pt. Tti.~s•~ #~ q. ~` ~~~~ . ~ rtNd ~~ ~~} ._i.l) ~_~P' g - t t - 8 I P'~. T4~o r-+Sor1 ~' 9~ $-~~sl W~, 1L-e~soh ~ ¢ ~n ~~ .. ~" - ~,~'' t@` . _ _ ~~ ..a. o.. . ~... _ ,~:~~ ~Os`•~ :vu 6~~ ~..... vm.. ~-:~ ~.. rs~''.`:. !Yi 6•JI.iWAY Frown air Look-n9 ~.~-5~' E) (.ON COMPANY, U.S.A. POUCH 6601 · ANCHORAGE, ALASKA 99502 PRODUCTION DEPARTMENT ALASKA OPERATIONS July 7, 1981 Mr. Lonnie C. Smith, Commissioner Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Smith: In accordance with Alaska Oil and Gas Conservation Commission regulations, Article 2, Abandonment and Plugging, 20 AAC 25.120, Well Abandonment Marker and 20 AAC 25.170, Location Cleanup, it is respectfully requested that a program be initiated to inspect wellsites at Prudhoe Bay during the first part of the week of August 10, 1981 or during the week beginning August 17, 1981. Please notify us if these dates are convenient and if so, which is preferable. The sites to be visited and inspected are as follows: Duck Island Wells #1 and 2 on Duck Island Pad #1 Pt. Thomson #1 Pt. Thomson #2 Pt. Thomson #3 Pt. Thomson #4_ Canning River B-1 It is requested that the inspection of Duck Island Pad #2 (site of Duck Island #3 well) be deferred until the summer of 1982 since drilling on this location will resume during the 1981-82 winter season. Mr. D. E. (Dave) Galloway (263-3756) is our contact for finalizing the aforementioned inspections. ALH:~ag Very truly yours, Drilling Manager A DIVISION OF EXXON CORPORATION EXXON COMPANY U.S.A. SUSPENDED nil, I~ _ _ Duck Is. Unit #1 Pt. Thomson Unit #1 Pt. Thomson Unit %2 Pt. Thomson Unit #3 ~,, PLUGGED & ABANDONED Canning River Unit B-1 Pt. Thomson Unit #4 June 4, 1981 Exxon Company U.S.A. ~ P. O. Box 6601 Anchorage, Alaska 99502 Re: Alaska Oil ~nd Gam Conservation Commission Regulations Article 2, ABANDONMENT AND PLUGGING, 20 AAC 25.120 WELL ABANDONMENT MARKER and 20 AAC 25.170 LOCATION CLEAN UP. Gentlemen: In regard to the above referenced 'regulations, your attention is called to an attached list of wells which, acc.ording to our records, have not received a final location inspection and approval of clean up. In compliance with 20 AAC 25. 170 Section -(a), "Within one year of suspension or aba.ndonment of an on- shore well", all clean up work is to be finished. Section. (b) provides the means for an extension of time if a valid reason exists. Section (c) provides for on site inspection. Consequently, we are presenting~th.e following list of you~ abandoned and/or suspended wells. ~Many of these are now more than one year old and are not in compliance with regulations. Others should have the final inspection completed this summer while weather permits. This list covers the years 1975 to date. There may be some earlier wells that also need inspec- tion. If you have any earlier wells to be inspected this summer please inform us. Therefore, we are requesting a schedule from you for this summer when our field inspectors can accompany your representa- tives to these sites for the final clean up inspection. You.rs truly, Commissioner LCS/JKT:be E ON COMPANY, U.S.A, POST OFFICE BOX 4279 · HOUSTON, TEXAS 77001 EXPLORATION DEPARTMENT GULF/ATLANTIC DIVISION ALASKA [PACIFIC DIVISION R.D · OTTMANN OPERATIONS GEOLOGY Mr. Hoyle H. Hamilton, Chairman Alaska Oil & Gas Conservation Commission 3001 Porcupine Dr%va Anchorage, Alaska 99501 Re: CONFIDENTIAL Exxon Point Thomson Unit No. North Slope, Alaska Dear Mr. Hamilton: We are attaching two copies of Form P-7, Well Completion or Recompletion Report and Log, for the captioned well ~ich was plugged and abandoned on December 20, 1980. Also, we submit the following data: (1) One set of washed and dried samples from 2170' to 15,074'. (2) ~ One blueline and one sepia print 6f the complete mud log from 2170' to 15,074'. (3) One composite sepia, one composite~blueline print and a digital magnetic tape of the following open hole logs: Dual Induction-LaterlOg BHC Sonic Compensated Neutron-Formatio~ Density Compensated Formation Density (4) Summary of formation test data. (5) Core chips taken at 1' intervals from the following cores: Core No. 1 2 3 4 Interval 13,512' - 13,572' 14,791' - 14,799.' 14,799' - 14,811' 14,973' - 15,013' A DIVISION OF EXXON CORPORATION Mr. Hoyle H. Hamilton Page two January 19, 1981 $ OONFiOEN1]AL (6) One copy of Sperry-Sun gyroscopic survey. Please note that the above material is marked confidential and should be kept confidential in accordance with the provisions of 11 AAC 2.535(f). Yours very truly, ~ · R. D.' Ottmann RDO:RLL:et attachments Alas~ 0~ & ~s oons. (:;ommission SUBMIT IN DUPLI~ TE OF ALASKA ~s,~ OIL AND GAS CONSERVATION COMMITTEE ' ' WEll CC)MPLETION (DR RECOMPLETI(DN REPC)RT AND I.C)G* , la. TYPE 0F WELL: oll.,,.~:t.L ~ ~^s,,.gUn :---~__ DaY [] Other Wildcat b. TYPE OF COMPLETION: ..F.. Abandoned ~xxon Cor~ration .. w~o. No. 4 3. ADD~E~3 OF OP~RATO~ . P. O. BOX 2180, Houston, Texas 77001 ~0. r~D~OO~.ORW~C~T 4. Loc~rmx or wzL~ (Repo~ location cleari~ ong in acc~r4anc~ wi~A anp ~ate~equirem~.~)* Wildcat ~,su~c. 2700' NSL & 2900' ~L, Sec. 32, T10N, R22E, ~, u.S~C..T..a..~..l~O~aO~ O~V~) North Slope, Alaska AZ top Drod. Interval re~0rted below ~t tot,~ de~ 3025' NSL & 3090' ~L, Sec. 29, T10N, R22E,. UM, Sec. 29, T10N, R22E, North Slope, ~aska ~. ~T ~O. 79--80 [ ] 17. ~. CASING~ 1~. D.~ 5PUDD~ 14. D~ T.D. ~C~ 15. DA~ CO~ ~USP O~ ABAS. 16. ~V~ONS (DF.~, RT,GR. ~)" 4-13-80 [ 8-20-80 ' 12--20-80 33' KB ..... "- - 15,074 ~ [ Surface [ _ I~ lg 1Q~ ~ ~ / ,~ - r'-r'~r~ ~.~bD0~ING~VAL(S) OF ~IS COMP~ION--TOP, BO~OM. N~E (MD AND See attac~ent for Test Data ] Yes NFIDENTIAL ii. TYPE ~,.~CTRIC A_ND OTHI!it~ LOGS RUN DIL, BHC Sonic, FDC-CNL, Dipmeter, Velocity CASING RECORD (ReDort all strlnlis set in well) CASING SiZE J WEIGHT LB/FT. DEPTI-I SET (M.D) HOLm. SIZ~ See Attac~mett LINE~ R3EC Oi~D CP_~liLN TING RECOi%D l,t?. iUBING RE COP,*D SIZE i~.Mo~ PU~ , I i1'1 I~J J PACI(ER SET (MD) SCP, EEN IMD) DisI~i~Hi SET (M2D) ACID. si!eT. PRODUCTION SIZE I TOP (liD) BOTTOM (MD) j SACKS 28 PEP~FORATIONS OPV-~I TO PRODUCtiON iint~rval, size and number) 14,956'-14,976' w/4 spf (squeezed) 14,807'-14,812' & 14,822'-14,877' w/4 spf (set BP at 14,707') 13,478'-13,542' w/4 spf (squeezed) 30. DATE FIRST PI%eDUCTION J PllODUCT1ON MEI ({OD iFlowh'g. ~a& IiIL. pumping--size alia type of pump~ See Attachment J zx~o ' - IWELL STATUS iProducing or ] GAS-OIL .... OIL GRAVITY-Alii Alaska Oil f~aa Con~ Casing Record, Acid & Squeeze Cement Jobs, Core Data, Test Data :.a I n.reby ~L thaC the foregoing and at~ached mformatmu is complete and ~orrect as determined from all available record~ C ~ ~.. ~uDery~sor '($e. In.ructio.. aha S~c.. [or Agaifion~l D~m o. Reverse Side) INSTRUCTIONS General: This form is des,gned for submHtmg a complete and correct well completion report end log on all types of lands and leases in Alaska. Item: 16: Indicate which elevation is used as reference (where not otherwise shown) for depth measure- ments given in cther spaces on lhis form and in any attachments Items 20, and 22:: If this well is completed for separatc production from more than one ,nterval zone (mulliple completion), so state in item 20, and in dam 22 show the prcJuc~ng interval, or ~ntervals, lop(s), bottom(s) and name (s) (if any) for only the interval reported in item 30 Submit a separate report (page) on this form, adequately identif,ed, for each addHional ~nlel val to be separately produced, show- ing the additional data pertinent to such interval It®m26: "Sacks Cement": Attached supplemental records for this well should show the detads of any mul- tiple stage cementing and the location of the cementing tool. Item 28: Submit a separate completion report on this form for each inlerval to be separately produced. (See instruction for items 20 and 22 above). 34 ~UIVIMAIEV OF' FORMAT{O~ '~{1'~ ,'~C'LUDIN(; ~NTE~tVA[. T~.,.~TED. PRF. S,S'URi~ DATA *~N'X)~OV]J~IF~S OF O1~i GAS.. ...... WATF. R AND MUD I~IEA$ DEPTH. , , ~, .... SEE ATTACHMENT Tertiary Surf Surf Paleocene 9165 8023 Thomson Sd 14,802 12,930 Pro-Miss 14,976 13,099 · *Hr COl{{':. DATA. A'I'rAc'I! BRIEF D~DSCRIPITIONS OF LITIIOLOGY. POROSITY, FRAC'TURI~S. APPA.R.~NT DIPs AND [)I~."I'iK(..'TEI) SlIOWS OF' OIL, GAS OR %VAT]5'I! s i ,, -. , , s , s~ , SEE ATTACHMENT _ ...... CONFIDENTIAL sPeed,j-sun CONFI d. A Fouch~ Pres,dent Mr. Jim Onisko Exxon Co., Inc., U.S.A. Pouch 6601 Anchorage, Alaska 99502 September 23, 1980 Re: Our Boss Gyroscopic Survey Job No. Boss-16666 Point Thomson Unit #4 Wild Cat Field North Slope, Alaska Date of Survey:_-September 17,_1980 Operator: Kirk Afflerbach Dear Mr. Onisko: Please find enclosed the "Original" and twenty-four (24) copies of our Boss Gyroscopic Multishot Directional ~Survey on the above well. Thank you for giving us this opportunity to be of service. Yours very truly, KB/kc Enclosures SPERRY-SUN, INC. Ken Broussard District Manager RECEIYEO JAN ? 0 1981 AI3sk,a Oil & Gas Cons. Commission Anchorage XXON COMP~,qY USA T. THOMSON WILDCAT NORTHSLOPE ALASKA BOSS GYRO SURVEY 'TRUE MEASURED VERTICAL DEPTH DEPTH SUB SEA TVD DATE OF SURVEY VERTICAL SECTION SEPT ,-AGE 17, 198.0 .. SPERRY'SUN, INC- RECORD OF SURVEY COURSE COURSE DOG'LEG INCLINATION 'DI~EC"~'i'ON ...... SEV .......... R'EC'T'ANG DEG MIN DEG MIN DEG/IO0 -NORTH/S DIRECTION N-OT-36-OO'-W BOSS-166-66 TOTAL ULAR C'6'OR'~'iNATES ......... VERTICAL OUTH EAST/WEST SECTION 2.00.;3_0 ........199 · 99 0.00 0.00 100.00 100.00 300.00 299.98 ~00.00 399.97 -$3,00 "oRIdiN 'A¥"'SUliFACE .............. O"bO N 67,00 0 ~+8 S 7~+ 18 E ,80 ,1'9 S 166.99 ........ 0 .... ,4-,9.' ............. S 7zl, 53 E . ..07 ............... ?; .................. .5.~,.S 266,98 0 36 S 69 ~1 E .15 ,89 S 366.97 0 41 S 63 18 E .11 1.3~ S 0.00 E 0.00 · 67 E -,28 1,96 E -.8~ 3.07 E -1.25 ~.09 E -1,87 '50'0.00 600.00 700.00 800.00 799.95 900.00 899.95 1000.00 999.9~ 1100.00 1099.9~ 1200.00 1199.9q 1300,00 129'~',93 '~99.9f ......... 466i~7 ..... or~4 .... S'67'23 599.96 566,96 0 42 S 80 30 E ,20 699,95 66__6..~J~ 0 36 S 67 ~8 E ........,.17 .................... 766,95 0 33 S 63 ~1 E ,06 2,80 S 866,95 0 28 S 7~ 5 E ,12 3,15 S 1!9 .9 o 30 s 65 23 E .3o ....... 1266,93 0 37 S 83 23 E ,21 '=T"l ~,07 S dO'S ..... 5'0'8 E S 6,1~+ E S ' 7.23 E 8.1~+ E 8.97 E 9.67 E 10.17 E 10.76 E 11.69 E -2,89 -3,33 -3,85 -~.28 -~,67 -5,21 -5'58 1~00,00 1399,93 1366,93 0 28 S 65 0 E 1500.00 lZ}99.92 1600.00 1599.92 1700.00 1699.92 1466.92 0''3-~ ........ ~ ~1 .... 0 E 1566.92 0 18 S 17 0 E 1666.92 0 19 S ~7 0 E --176'~.'-92 0 22 S 46'41E 1866.92 0 18 S 21 0 E 1800.00 1799.92 1900'.00 1899.92 12,59 [ i$,29'E 13,69 E 13,97 E 14,~0 E 1fl,73 E -5,93 -6,56,,~,~, -7,23 -7.70 -8.67 Li O00.O0 1999.92 1966.92 100.00 2099.91 2066.91 200.00 2199.~1 2166.91 2300,00 2299,91 2~00.00 2399,91 2500,00 2600.00 2599.90 2700.00 2699.90 2800.00 2799,90 2900.00 2899.90 0 16 $-30' '36 E 0 21 S 19 Il E 0 19 S 60 0 E 2266.91 0 18 $ 65 35 ~ 2366,91 0 13 N 88 0 E 06 7"22 S lo 7.71 s 23 ° 8,1~ S 03 8.39 S 41~ 8,99 S { , ;18 , 8. Z$ · 37 9, 24+66,91 0 20 $ 61 5~ [ 2566.90 0 38 S 73 18 E 2666.90 0 33 $ 37 36 E 2766.90 0 16 S 17 36 E ~31 2866.90 0 15 S ~9 ~8 E ;1~ , 91 S 9.5 ..... S 10.05 S lO.42 s ,, l~.9~-'E 15.16 E 15.50 E 15.98 E 16,{0 E 16,85 E l?,d,~ E i"8"82-'E 19,06 E -9,1~ -9,65 -10,12 -10,43 -10,58 '10,77 '11,17 -11.81 -12,85 XXON COMPANY USA L~T.,_.THOMSON #__~ ..... WILDCAT NORTHSLOPE ALASKA MEASURED VERTICAL DEPTH DEPTH SEA TVD r'AGE 2 D. ATE._.OF S_U_B__V_E:¥.. SEP~T :1.7~j_c)_80_ VERTICAL SECTION DIRECTION N--07-36-00-~ SP~RRY-SUN~ INc, RECORD OF SURVEY C._O.~_ R S E .................... C_O~.U__R..S_E .......... O_Q_G -_~_Lg INCLINATION DIRECTION SEV BEG MIN DEG MIN BEG/lO0 33000.00 2999.89 2966.89 0 27 3100.00 3099.89 3066.89 0 q8 2_o_o_.. o, o .... ~19.~._88 ........ 3_16_6._._8~8 ~. ........... o .... 1_5~.~. 3300.00 3299.88 3266.88 0 16 3~00.00 3399.88 3.'566.88 0 15 3500.00 3~+99.88 3~+66.88 0 3! N 75 5 E 3600.00 3599.87 3566.87 1 8 N ~ 30 E 37_O_O_._Eq_~ ~ 6_~ 9_. 7 ~_ _._.__3666_ ._7._~ ................. ~,__,.~2 ................. N.._.8_~_L-W 3800.00 3799.22 3766.22 7 9 N 15 0 W 3900.00 .3898.18 3865.18 9 17 N 23 30 W I~OOO.O0 3996,61 3963,61 10 58 AiO0.O0 Aogw,~2 ~061,42 12 59 q300.O0 q287.72 q25q.72 16 51 ~O0.OO ~382.71 q3~9.71 19 33 ~500.00 ~600.00 i ~___Z70J ,.0.0., ~800,00 ~+900.00 ~}OSS- 16666 .... 5300.00 5qO0.O0 RECTANGULAR COORDINATES VERTICAL NORTH/SOUTH EAST/WEST SECTION S 8~ 18 E ;02 9,93 S ' 2'~'o ......... ~,~,,s 1~'08 8~.7~S .... . ............. .3. ~. P. 7 ................... '.,.,._, _9 8.. S . 2~.85 5.79 N 2 ~. ~+5 19.20 N I, N 21 53 W 2~;05 5~t.53 N N 18 53 W 2'~20 102.q2 N N 19 30 W 2.71 131.91 N ~5~7.~2 ~53~.~2 25 ~6 N 19 ~656.24 ~. 6~3.~2~, ............ ~ 5___5 .... 47~2.27 ~709.27 32 21 N 19 53 W 3'.~ ?==J 295.0~ ~825.16 ~792.16 35 ~0 N 20 0 W 3.32, _~ 3~7.61, l~ ~2 w ~.'~' ~'~o~. .~_iLU,:_ ...... ~O~...~.._s~o. _iO00,O0 ~905,11 ~872,11 38 8 N 100,00 q983.61 {950.61 38 25 N 51~0.~1 5107.~1 38 16 N 19 17 W .23 I 579, 5218.77 5185.77 38 33 N 19 12 W .29 638. L5-5~oo.oo 5600.00 5800.00 5900.00 · ' 19'60 [ -13.18 20.20 E -12.7.'5 ............... ~_.o..sz., E. -l~_._~ c'"' _ 20.9:3 E -12.56 21.38 E -12.67 22.03 E -12.67 22.5~ E -11.6q ,.. ' 22...~.6._E. -6.87 ...... 19,89 E 3,11 15.06 E 17.0~ 8,15-E .... 33.97 · 22 E 5~.03 17.59 W 103,85 27.87 W 13q.qq N 39.75 W N 53.27 W 209.25 .N ................. 6--8~''88 W ........... N 86.37 W 303.87 N 105.~5 W 358.50 07 N 125.83'W 417.16 ql N 1q6.66 W ~77.7~ ~2 N 188.1~ W 599.21 07 N 208.62 W 660.06 5296;73 526'~)'~'~-~ ~9 1 N 19 3& U °53 697.i5 537~;55 53q1.55 38 5~52.51 5419.51 5530.68~5~97.68 38 2~ N 19 17 U ~57 873.82 5608.79 5575.79 38 53 N 19 53 W ;61 932.65 N 229.~3 W 721.37 N 250.70 W 782.75 iN ............27~,,.1.2 ....W ..........8~3,3_~ N 293.08 W 90q.91 N 31~.02 W 965.99 !EXXON COMPANY USA i PT, THOMSON g4 WILDCAT NORTHSLOPE ALASKA BOSS GYRO SURVEY i TRUE MEASURED- V E ~T I C'A'--~ DEPTH DEPTH SUB COURSE SEA INCLINAT TVD DEG MI SPERRY-SUNs INC. RECORD OF SURVEY COURSE DOG-LEG ION ..... D-iRECTION S E'~/- N DEG MIN DEG/IO0 PAGE DATE OF SURVEY SEPT 17, lg~30 VERTICAL SECTION BOSS-16666 TOTAL RECTANGULAR CO0-RDINATES NORTH/SOUTH EAST/WEST E~YICAL SECTION 6i0o.oo 5764.61 6_2_o o~, o o._ 5842._2.0 __ 6300.00 59i9.53 6400,00 5996,83 5653.73 38 42 5731.61 39 0 580~,.20 39_1.3 5886.53 39 29 5963,83 39 16 N 19 17 W .42 991.67 N 335,03 W N 19 23 W .31 1050.86 N 355.80 W N 18 42 W .49 1110,48 N 376,58 W N 18 12 W N 18 36 W 1170,63 N 396,45 W 1230.82 N 416,47 W 102f;27 1088.68~'~ 1150.51 i2i~;Tg 1275.09 6500,00 6600.00 6700_~00.__ 6800,00 6900,00 oTz.v6 6151.01 611 62_28 , 21 .......619 6304.36 627 6378.49 634 8.01 39 24 5.2i .... 39 .... .3~2 1,56 41 15 5.49 43 3 N 18 12 W ,59 N 18 12 W ,40 N 17 53 W ,24 N 16 0 W 2,11 N 14 36 W 2.03 1291,22 N 1351,78 N 1412,21 N 1474,19 N 1538.91 N 436.56 W 1337.62 456.47 W 1400.27 476,16 W 1462,78 495.03 W 1526,71 512.72 W 1593.20 7ooo.oo 7100,00 7200,00 7300,00 7400.00 6450.03 6519.84 6589.17 6659.11 6730.70 7600.00 _7700.00 7800,00 7900,00 -64i7,03 ..... 6486.8~ 45 51 6556.17 46 22 6626,11 44 52 6697,70 43 41 8000.00 9100.00 8200.0O 8300.00 8400.00 6803.66 6770,66 ~42-'36 6877,08 6844.08 42 56 6950,33 6917.33 42 52 7023,58 6990,58 42 57 7096,64 7063,64 43 lO 7169.39 7242.19 7315.11 7388.06 7461.02 7136.~9 A3 ~9 7209.19 43 5 7282.11 43 16 7355.06 43 3 7~28.02 ~3 14 N 15 24 W 2,68 1606,70 N N 11 ~6 W 1,31 N 10 12 W 1.13 N 9 18 W 1.63 N 8 ~0 W 1.31 -~--~ U 1.09 N 8 i7 w N 7 ~7 W .35 N 7 2~ W .28 N 7 17 W .23 1676,60 N m===~1747,~6 N 'o17.78 N 1886, 75 N m~1954.39 N 2021,58 N Z2088.98 N ....I~156,47 :]:::m"2224.18 N 229-2.25 N 2~60,23 N 2428,05 N 2495,88 N 2563.73 N 545.10 U 558.72 W 6Yb-783-~ ...... 581,63 N 59i.61 W 601,41 W 610.93 W 61g. 92 W 628.64 W 637.29 W 646.18 W 655.23 W 1733.96 1805.90 1-877-,'~ ] 1947,10 2015,47 2083.36 2151,43 2219,51 2287,79 N 7 12 U N 7 42 W .53 N 7 30 W .23 N 7 23 W ,23 N 6 53 W .39 664,09 W 672.59 W. 2 3'5 2A24,96 2q93.38 2561,~8 2630,16 0 o-.'o o- 8600.00 __~700.00 8800,00 R900.O0 -f'5~n. 16 7607.51 7680.92 7754.49 7827.82 750i,16 7574.51 42 52 7647,92 42 41 7721,49 42 35 7794.82 43 5 N 7 17 W ,54 N 7 0 W ,22 N 6 23 W .45 N 5 53 W .35 N 5 47 W .50 2631.40 N 2698.84 N 2766.29 N 2833-,-g-~- N ......... 2901.26 N 68i. Ol w 26-g~ ,-~-6 689.46 u 2766.32 697.38 W 2R34.22 ?-'0'q-2-6-3 W-- P 901 · ~ 3 7i i.54 w 2969.88 EXXON COMPANY USA P_T.,__THOM SON ~q .... WILDCAT NORTHSLOPE ALASKA _Bg_S_S.__G_Y~.R_O_$ U R V E_Y TRUE HEASURED VERTICAL DEPTH DEPTH SPERRY-SUN, RECORD OF SURVEY SUL .... COURSE ...... ~CqURSE SEA INCLINATION DIRECTION TVD DEG MIN DEG MIN 9000.00 9100.00 .__9 2 ~o. o...o o 9300.00 9400.00 7975,05 7942,05 42 47 8 0 4 8,7.8 ........ _8._0_1~5_,~B______ 4_~_. 1 ~ 8122,59 8089.59 62 39 8196,~ 816~,~ ~2 8 9500,00 8270-~-~-~ 8237,43 42 25 9600.00 8344.67 8311,67 41 43 ._9.? 0_0. · 0_0 ........8 z+ 19,39 .... 8_3~ 6 · 39 .... ~1_.35 9800,00 8494,78 8~61,78 ~0 33 9900,00 8570,93 85~7,93 ~0 16 N 6 6 W N 5 42 W . _N__.5__3_LW_____. N 5 17 W N 5 36 W lOOO0.O0 8647.72 8614.72 39 24 lOlO0.O0 8725.21 8692.21 39 0 _IO~Po~oo .... 8803,36 ..... 8770_,36 38_12 10300,00 8882,19 8849,19 37 45 10400,00 8961,68 8928,68 36 57 0600,00 9123.22 9090,22 35 25 0700,~00____ 9205,27 _.9172,27 ....... 34_18 10800,00 9287,95 9254,95 34 10 10900,00 9371,03 9338,03 33 28 PAGE D A~T E___Of__$ U.R_Y_ EX ...... _$ E_E T__I. 7, _ 1 VERTICAL SECTION DIRECTION N-O7-36-OO-W BO~S_r_l_6666 INC, D OG-LE__G __T~OT AL .......... SEV RECTANGULAR COORDINATES VERTICAL DEG/iO0 NORTH/SOUTH EAST/WEST SECTION ,86 2968,67 N 718,56 W 3037,63 · 60 3035,89 N 725,51 W 3105,18.~ .,_5.8 ~_0~ .~_. N .............. 7 t2_,.kkW .3_~_ 2 · 6 $ · 46 3170.30 N 738.4q W 32~0.12 · 56 3237,~2 N 744,84 W 3307,49 6 W .44 3304.39 N 751.11 W 6 W .70 3371.12 N 757.07 W 7.. W~, ~~_~_?..,_3.1__N........... 7_6]_,_0_L~___ 36 W 1,13 3502,75 N 768,75 W 36 W ,28 ~3567,37 N 773,95 W 36 W ,87 3631,22 N 30 W ,40 ~ 3694,22 N 2~W ... 1,0~~~756~5 N ~0 W .82 ~ 3878.~1 N 3374.70 3441.64 3573.66 3638.39 779,09 W 3702,36 784,10 W 3765,47 792.25 W 3889.11 796,11 W 3949.63 4008.96 4067,15 4179,95 4235,12 · N 3 ~7 W ,89 ~ 3937.80 N 799.63 W N 2 0 W 1.00m 3996,1~ N 802,33 W N 2 0 W 1,12 ~05~3.6__.N ............. 8~0g,33 W N 0 42 W ,74 4109,50 N 805,65 W N 0 30 E ,97 ~i65,15 N 805,76 W 11000,00 11100.00 I_i_2.q_Q_..O_Q 11300.00 11400.00 11500, O0 11600,00 t. 1 lO.o., o o 11800,00 11900,00 9454.84 9-q21.84 95.39,25 9506,25 32 12 9.62~..,_2_~ .... 95~9_L._2_9 .... 31 ..... 16. 9710.03 9677.03 30 ~1 9796.z9 976~.29 ~o 6 9883,16 9850,16 29 17 9970,68 9937,68 28 34 __10058,.43 ...... 10025e43 ... 28 45 10146.16 10113.16 28 37 10234,13 10201,13 28 10 18 E ,82 A219,69 N .50 E ,79 4273.30 N .N___2__2_tE :. ....... 1. ,_OD ~:~ . 35 E ,59 ~377,28 N 30 E 1.13 4427.77 N N '~ 5'4 ~'E 1. ~4 44~'~-'~"05 N N 7 41_ E ,81 4525.02 N N _ _8_ .48 E ..D_6_ 4._57.2_. ~ 8_? N 10 30 E .83 4619,79 N N 11 30 E ,65 4666.47 N 805,37 W 4289,14 804,53 W 4342,17 802.,_7_5._W ...... .~3~.9,03 800,51 W 4444.70 797-39 W 4qgq,33 792,49 W 4542,53 786,35 W 45R9,27 771.43 Id 4681.2Z+ 762.36 W 4726.30 EX ON COMPANY USA _P T~ .T_~9 _N..S.p_N ~ ~ WILDCAT NORTHSLOPE ALASKA BOSS GYRO SURVEY MEASURED VERTICAL DEPTH DEPTH SUB SEA TVD SPERRY'SUN, INC. RECORD OF SURVEY COURSE COURSE DOG-LEG I N-~-L INA Y I ON DIRECTION SEV DEG MIN OEG MIN DEG/100 DATE OF SURVEY VERTICAL SECTION DIRECTION TOTAL RECTANGULAR NORTH/SOUTH PAGE 5' - SEPT 17, 1980 N-~3 6-- 0 0- u BOSS-1GGGG COORDINATES vE-RT I ~'AL EAST/WEST SECTION 2000.00 10322.55 10289,55 2100.00 10q11,32 10378.32 _12200 · 0~0..~.10_500 · 39 10q67,39 12300.00 10589.57 10556.57 12qO0,O0 10679.15 106/+6.15 27 31 N 15 0 E 27 19 N 18 36 E 26 ~5 N 22 30 E 27 4 N 22 6 E 25 ~1 N 21 2/+ E 1,76 /+7'11.91 N 1,67 ~755,97 N 1,86 ~798,51 N 751.67 W 4769-93 738,37 W ~811.85 722./+~ W /+851.90 705.27 W 48~~ 688.81 W 4929.85 · 36 ~8/+0.~8 N 1./+2 q881.63 N 12500.00 10769,90 10736,90 12600.00 10861.~1 10828./+1 __L2.T_OO._q.o ...... i_0_~53,06 10920,06 12800.00 110~+~.70 11011.70 12900.00 11136.6~ 11103.6~ 23 58 N 23 18 E 23 35 N 25 5~ E 23 35 N 22 12 E 23 37 N 19 36 E 22 41 N 20 36 E 1,89 ~920.46 N 1.12 ~957.11 N 1,~8 ~993.63 N 1.0/+ 5031.02 N l.O1 5067.9~ N 672,86 ~ 4~-~3 656,09 ~ 5000.3~ 639,80 W 503~.3R 625.52 W 5069.56 612,02 W 5104.36 13000.00 112~9.16 11196.16 13100.00 11322,01 11289.01 ~3200.._00__11~15,16 11382.16 13300.00 11508.57 11/+75.57 13~00.00 11602.08 11569.08 ]~06~00 11695,88 11662.88 13600.00 11789.97 11756.97 _137o0,oo i1_8_~.17 ii851,17 13800.00 11978.3/+ 11945.3~ 13900.00 12072.61 12039.61 21 55 N 20 0 E 21 41 N 23 .30 E 20 59 N 2/+ 12 E 20 50 N 25 /+8 E 2O 40 N 29 18 E 1-d)-"'~5 N ~1 ~0 E 19 40 N 33 36 E 19 32 N 3/+ 5/+ E 19 48 N ;57 6 E 19 10 N 39 5q E · 80 ~ 5103.53 N 1.32 5138.01 N · 74 5171.28 N · 59 _! ! 5203.62 N 1.25 ~5235.02 N 1.07'-~ 52~'.93 N · 75 5295.~7 N .q6 ~ 5321.20 N 1.13 537/+.52 N 598.85 W 5137.90 585.10 W 5170.25 570.39 W 5201.2q 555.31 W 5231.35' 538.94 W 5260.31 521.~0 W 528~.6g 503,19 W 5313.52 484,31 W 5338.51 ~6q,53 W 5362.87 ~q3.79 W 5386.00 14000.00 12166.9/+ 12133.94 19 36 1/+100.00 12261.20 12228.20 19 26 _t~.2_q.Q_.. 09 i_2~!5._,7_2 i.~.3_2__2_,.L2 ..... 18 /+ i lq$O0.O0 12/+50,'61 12/+17,61 18 6 l~/+OD,O0 125~5,60 12512,60 18 3.8 lq500.O0 1~600,00 1~700.00 lq800.O0 N A1 0 E N 42 5~ E N 43 36 E N /+5 5/+ E N ~6 54 E 126/+0.57 12607.57 iR 12 N-4'~L6 12735.92 12702.92 16 53 N 45 /+8 12831.88 12798.88 15 ~6 N 51 18 12928.39 12895.39 14 35 N 57 12 ,57 .66 ,78 .37 5399,77 N /+22.25 W 5q08.18 5/+2/+,61 N 399,92 W 5~29.85 :. ..... 5~./+.871,~.0...N ...... :377.56 W 5450.q7 5q70.81 N 355.35 W 5469.75 5492.35 N 332.74 W 5/+88.11 E ,/+2 551/+.00 N E 1.32 5535.05 N E 1.91 5553.67 N E 1,94 5568.98 N 310.11 W 5506.58 ~88.55 W 552q.59 267.55 W 55q0,27 2q6.35 W 5~'52.64 225.21W 5562,97 I_EXXON COMPANY USA ..P__T_o__ T H__O]Vt_.SON .... ~5 .... ~ILDCAT NORTHSLOPE ALASKA [__..B_O..S $ _.GYRO_ .SURVEY ..... T?_UE .. MEASURED VERTICAL DEPTH DEPTH VERTICAL SECTION DIRECTION PAGE S_EZP_T_i_Z t.1 N-O7-36-OO-W SUB SEA TVD SPERRY-SUN~ INC, RECORD OF SURVEY COURSE ....... CO.U~.S~ ........... D,~Gy~L_E~ INCLINATION DIRECTION SEV DEG MIN DEG MIN DEG/IO0 T O_~k: RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST BQSS_-_16666 VERTICAL SECTION 1~+950.00 t3073,72 1.'30A'.0.72 1~ '~5 N ~7 2q £ ,99 5588,67 N 21q. o87 W * * .T H E. C A L C II.L._A..T_I_O__N~__A_EL~B A_$ E O__ 0 N . T. PI. E] I.~_I~._~_l~__O I:'_ .... C U_.RY._A ~T_ U~E E~ M E T H O_O .... ,.. *. 5567.99 HORIZONTAL DISPLACEMENT : 5592,80 FEET AT NORTH 2 DEG, 12 MIN, WEST (TRUE) START OF SURVEY WAS 33.00 FEET ABOVE SEA LEVEL CONFIDENTIAL EXXON COMPANY USA t.P_~.._..THO~S~N ~4 WILDCAT NORTHSLOPE ALASKA _B~_S~_G~R.__O~ S~RVEY DATE OF SURVEY SEPT PAGE 7" 179 1980 BOSS-16666 INTERPO SPERRY-SUNe INC. LATED RECORD OF SURVEY TRUE MEASURED VERTICAL _ _ .D_E.P_TH DEPTH__ 1 q.oo., ............. _3000. SUB SEA TVD -33, 967. ,TRUE ELEVATION 33. -967. TOTAL RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST 2000. 2000, 1967. 3000, 3000. 2967. 4000. ........... 3997. 3964. -1967. -2967. -3964. O. N O. E 3, S 10. E 7 · S i~. -E .... 11. S 20. E 35. N 8. E 5000. 60_0~, 7000. 8000. 9000. 10000. Eo_. ............ 12000. 13000. 14000. 4905, 4872, 5687, 5654. 6450. 6417. 7169, 7136, 7901, 7868, 8648, 8615, 9455, 9422. .... io 3, io ¥6.- 12167. 12134. -4872. -5654, -6417. -7136. -7868, 404, N 126. 992. N 335. 1607. N 530. 2292. N 637. 2969. N 719. '-8615. -9422. 3631. N 4220, N -10290, -11196, '1213~. 4712. N 5104. N 5400. N 779 · 805. 752. 599, 422. 1A950, 13074. 130ql. -13041, 5589. N 215, W IN¥~'RPO~T-~b--coo~-INATES FOR EVERY 1000.00 FEET OF MEASURED DEPTH FROM 0.00 FEET TO 14950.00 FEET EXXON COMPANY USA PT, tHOMSON ~4 NORTHSLOPE ALASKA DATE OF SURVEY VERTICAL SECTION DIRECTION PAGE'1 SEPT 17~ 1983 N-O7-36-OO-W 90SS GYRO SURVEY -TRUE MEASURED-- ~R~CAL DEPTH DEPTH 0.00 0.00 100.00 100,00 200.00 199,99 - 300.00 299,98 400.00 399,97 RECORD OF SURVEY ____SUB FEB 1 (~065E COURSE DOG-LEG SEA-- IN~EiN~TION DIR~d¥ION SEV ATLV'O, Oil & Gas ~ Cq~l;Sion D E G I'.I I N D E G / 100 Aqchorage -33.00 ORIGIN AT SURFACE 67,00 0 q8 S 7~ 18 E ,80 166.99 0 qq S 74 53 E .07 266.98 0 36 S 69 41 E ,15 366,97 0 ~1 S 63 18 E ,11 BOSS-16666 TOTAL RECTANGULAR COORDINATE~S ...... V ~-~-TT-~-A' L NORTH/SOUTH EAST/WEST SECTION 0,00 N · 19 S · 54 S 0,00 E 0 · 67 E - 1.96 E - 3,07 E -1 4,09 E -1 ,89 S 1.3~ S ,00 ,28 . e~.,,, ,87 500.00 ~99.97 600.00 599.96 7oo_.~o ..... 6.9~.~5 800,00 799,95 900.00 899.95 [--~000.00 999.94 iioo.oo 1099.94 __~_~ 0_o .__oo ....... i 199.9A i~oo.oo i-~-~.93 14GO.GO ~$~.~ 466.97 566.96 666.95 766.95 866.95 0 34 S 67 23 E ,12 0 42 S 80 30 E ,20 0 36 S 67 48 E ,17 0 33 S 63 41 E ,06 0 28 S 74 5 E .12 0 25 S 59 41 E ,12 0 13 S 84 30 E ,24 0 30 S 65 23 E ,30 0 37 S 83 23 E 0 28 S 65 0 E 1,80 S 5,08 2,09 S 6,14 2,39 S' 7,23 2,80 S 8,14 3.13 S 8,97 E -2,46 E -2,89 E -3,33 E -3,85 E -4.28 1500,00 1499,92 1600.00 1599.92 1700.00 1699.92 180~. oo ..... ii¢9;-~2 1900.00 1899.92 2000,00 1999,92 2100,00 2099,91 2200.00 2199.91 2300,00 2299.91 2400.00 2399,91 i500.00 2499.91 600,00 2599,90 700,00 .... 2_699,90 2800,00 2799,90 2900,00 2899,90 966.94 1066.94 1166.94 1266.95 1366.93 1466.92 1566.92 1666.92 1766.92 1866.92 034 S 41. 0 E 0 18 S 17 0 E 0 19 S q7 0 E 0 22 S 46 41 E 0 18 S 21~ 0 E i ~ I .2~ 32 Iii , .16 · 05 I=.l.i. 16 Z ' ¢ '3 . ,06 ;10 ,23 1966.92 2066.91 2166.91 2266.91 2366.91 0 16 S 30 56 E 0 21 S 19 11 E 0 19 S 60 0 E ~--18 ....... ~--6'5 35 E 0 13 N 88 0 E 2466.91 0 20 S 61 5.3 E 2566.90 0 ~8 s 73 t 8 E 2666.90 0 33 S 37 36 E 27-F~6-;-90 0"16 S 17 36 E 2866.90 0 15 S ~9 48 E ,03 .14 ,18 .31 .37 .31 .lq 3,42 S 9.67 E -4.67 5.62 S 10.17 E -4,94 3,82 S 10.76 E -5.21 4.07 S 11.69 E -5.58~- 4,30 S 12,59 E -5,93 4,85 S 13,29 E 5.91 ~~.97 E 7,22 S.... E~q,gq E 8.62 ~~6.85 E 8.91 S ~17,6~ E 9.~5 S 18.~& E 10.05 S ~ 8; 82" E' 10.~2 S 19,06 E -7,2 -7,70 -8.16 -8.67 -9.14 -9.65 -10.12 -10.43 -10.58 -10,77 -11.17 -11.81 -12,85 EXXON COMPANY USA ,_P_T,_ THOMSON_ WILDCAT NORTHSLOPE ALASKA rJ~.O S $_ .G ¥ R O_ SURVEY TRUE M E A S Ch-E'[~ VERTICAL DEPTH DEPTH INC. cOU.RSE__~ DOG-LEG D A T_____E__O F =: S_U R___V= E Y ...... VERTIC&L SECTION DIRECTION ECO SURVEY SUB COURSE TOTAL "PAGE 2 S_EPT 1_.7_,_1_~8¢,_ . N-OT-3G-OO-W' D__O_$_S_-__~6 6 6 6 SEA INCLINATION TVD DEG MIN DIRECTION SEV RECTANGULAR DEG MIN DEG/iO0 NORTH/SOUTH COORDINATES EAST/WEST VERTICAL SECTION 3100,00 3099.89 _32_00,00 ...... 3199.88___ 3300.00 3299.88 3400.00 3399.88 2966,89 0 27 3066.89 0 48 __3,166.R8 0 15 3266,88 0 16 3366.88 0 15 S 71 23 E .24 10.68 S N 19 23 E .91 10.15 S ._S._.38~0_E .9~ .......... S 80 35 E .19 9,87 S S 84 18 E .02 9.93 S 19,60 E 20.20 E 2_0_,_57... E. 20,93 E 21,38 E -13.18 -12.73 -~2.,3r'=',, -12.56 -12.67 L!500.O0 3'~99.88 3z~66,88 600.00 3599.87 3566.87 . 70.0., 0_0 ....... 3699.7/~ ...... 3666._74 3800. O0 3799.22 3766.22 3900.00 3898.18 3865.18 0 31 I 8 4_22 7 9 9 17 N 75 5 E .30 9.84 S N q 30 E 1.08 8.7q S, N ___ 8 __3 0_W.~3__,.2 7 .......... 3 ,._9_.8__S N 15 0 W 2.85 5,79 N N 23 30 W 2.45 19.20 N 22,03 E 22,5~ E 19,89 E 15,06 E -12.67 -11,64 3.11 17.04 jO00.O0 ,%996.61 100.00 ~09~.,~2 2~ _0_,_0_0 ..... 41 _9_1_. 51 q300.00 q287.72 q.~oo.oo 4382.71 4500.00 q~76.11 4600.00 4567.42 4700,00 4656,24 ~800.00 4742,27 4900.00 ~825.16 i-T6oo.oo 5 oo.oo oo.oo 3963.61 q061.42 4158,51 6254.72 43~9.71 qqq3.11 4534.42 4623.2~ ~709.27 4792.16 10 12 16 19 22 25 28 32 35 58 59 z~2 51' 33 18 55 21 ~0 23 0 W 1.69 ..._j 35.35 N 2i 53 w 2.03 ~ 54.53 N 20 36 V 1_.!~ ;",""-- 76.83_.N 18 53 W 2.20 ~ 102.42 N 19 30 W 2.71 ~ 131,91N 19-23 W 2,75 L.L. 165,59 N 19 23 W 3.47 Z 204,00 N 8,13 E · 22 E 8,43 W 17,59 W 27.87 W 39,75 W 53,27 U 33.97 54.03 77.27__ 103,85 13q.4~ 169.39-"- 209,25 4872.11 38 N 20 17 W 3.18~ 2~7.19 N N 19 53 W 3.4q~ 295.04 N N 20 0 W 3.32 347.61 N _6.~_8 8, 86.37 105,45 N 19 ~2 W 2,~7 q04.07 N 125,83 W 303.87 358.50 417.16 4950,61 5028.97 ..... 5107,ql 5185,77 38 25 38_2q ........... 38 16 38 33 N 1~ 36 W ,29 q62.ql N N,._i~_~6_J~_.' ...J2 ....... 520_,_9q_3_~~ N 19 17 W .23 579,42 N N 19 12 W ,29 638,07 N 1~6.66 .....1.67,~.0.W 188.14 208.62 477.7~ 538_.51 ..... 599,21 660,06 5500,00 5296,73 5600,00 5374,55 5700,00 5452,51 5800.00 5530.68 ~qno. nfl ~AOR.7~ 5263,73 5341,55 5419,51 5~97,68 5575,79 39 1 38 ~7 38 46 38 2~ 38 53 N 19 36 W .53 697,15 N N 20 0 W .3q 756.24 N N 20 0 W .02 815,09 N N 19 17 W ,57 873-82 N N 19 53 W ,61 932,65 N 229,43 250,70 2!2,12 293,08 31~.02 721.37 782.75 843.91 904.91 965.99 EXXON COMPANY USA PT, THOMSON Nq WILDCAT NOFTHSLOPE ALASKA BOSS GYRO SURVEY TRUE MEASURED VERTICAL DEPTH DEPTH SUB ~-A TVD PAGE 3, - . DATE OF SURVEY SEPT 17, 19~0-. ~-A L~-~ ~'~ l; i ON-D 1 R ~ ~ T'I- 0 N---N :"O ?-~'3 ~ ;'00 -W -' SPERRY-SUN~ INC. RECORD OF SURVEY COURSE COURSE DOG-LEG TOTAL INCLINATION -'DIRECTION SEV .... ~CTANGULAR COORDINATES DEG MIN DEG MIN DEG/iO0 NORTH/SOUTH EAST/WEST BOSS-16666 V ~-F~ t I C AL' SECTION 6100.00 5764.61 6200.00 5842.20 6300.00 5919.53 6400.00 5996,83 5731.61 39 0 N 19 23 W .31 1050.86 N 355.80 5809.20 39 13 N 18 q2 W .Aq 1110.q8 N 376.58 5886.53 39 29 N 18 12 W ,~1 1170,63 N 396,A5 5963,83 39 16 N 18 36 W ,33 1230,82 N 416,47 ~d27.2 1088.6 1150.5 1212.7 1275.0 7 1 8 9 j 6600.00 6151.01 6700.00 6228.21 C-800.00 630q.36 6900.00 6~78.q9 '- 76~ oVoo 7100,00 651 7200.00 658 7500.00 665 7AO0.O0 673 ---~'~'~'~9~ ..... 39'-%8 N i8 i2 W--.59 f~9i.22 N 436.56 6118.01 39 24 N 18 12 W .qO 1351.78 N 456.47 6271,36 41 15 N 16 0 W 2,11 1474,19 N 495.03 63qS,q9 q3 ~ N lq 36 W 2,03 1538,91 N 512,72 6.os-'-gAz7 03 45 ' J ....................... 2'Y~ 1606.70 N 529.60 9.8~ 6A86.24 45 51 N 11 36 W 1.31~___________1676.60 N 545.10 9.17 6556.17 fig 22' N 10 12 W .... 1,1.3~_1747,36 N __558'72 9,11 6626,11 qq-52 0,70 6697,70 43 41 N 8 30 W 1,31~ 1886,75 N 581,63 j i600.00 6877i08 .. 700.00 6950 33 7800.00 7023.58 7900.00 7096,6~ 1.09z 195~.39 N .33C~ 2021.58 N ,35~ 2088.98 N ---6-~'7-~)'.&'6 ..... 42--~'~ N 8 17 W 591.61 68'~q.08 ',2 56 N s 17 u 6oz.~z G917.3~ ~2 52 N 7 q7 N 610.93 6990,5R ~2 57 ......N 7 25 W .e8 2156.q7 N~ 619.-~2 7063.6~ 43 10 N 7 17 W .23 2224.18 N 628.64 1400.2 1462.7 1526.7 1593.2 --1662o~ 1733.9 1805.9 1'~7~ ~ 1947,1 2015,4 2083.3 2151.~ 2219.5 2287.7 3 6 0 l 0 6 3 ! 9 ~000.00' 7 16~1'~9 ~]00.00 7242.19 8200.00 7315.11 8300.00 7388.06 8~00.00 7461.02 713~-.39" 43 2¢ .... N 7 12 U .32 2292,25 N 6~'-7;2'9-g' ' ' 7209,19 43 5 N 7 42 W .53 2360.23 N 646,18 W 7282,11 43 16 N 7 30 W .23 2~28,05 N 655,23 W 7355,06 q3- 3 N 7 23 W ,23 2~-g5~--§~ N 664,09 W-- 7428,02 43 14 N 6 53 W ,39 2563,73 N 672,59 W 3 424.96 493.38 561,78 630,16 ~6oo.oo 76o7.51 8700.00 7~o.9P ~,800.00 7754.~9 7501.16 ...... 42 46 --~ 7 17 W ,54 2631.q0 N --681.01 7574,51 42 52 N 7 0 W .22 2698,84 N 689,~6 7647,g2 A2 41 N 6 23 W ,45 2766,29 N 697,38 7721.~q 42 35 N 5 53 W .35 ..... ~833.'6~-N-- 704'.63 2698.~6 2766.32 2a3A.22 2901.93 EXXON COMPANY WILDCAT ___ D A_T E_- O_F__S U.R_V_E Y_ ..... PAGE 4 N-07-36-00-~ VERTICAL SECTION DIRECTION rJORTHSLOPE UOSS._gyRo F ri s-u b--- DEPTH 9100.00 9200.00 9300.00 9400,00 9500.00 9600.00 ~700.00 .... 9800.00 9900.00 j-16T Too- :10100.00 i10200.00 10300.00 10400,00 10600.00 10700.00 10800,00 10900,00 11000,00 11100.00 11200,00__ ._ 11300.00 11~00.00 ~1500,00 1600,00 1700,00 11800,00 ALASKA SURVEY TRUF SUB COURSE VERTIC~C ......... SE~ .... INCLINATION DEPTH TVD DEG MIN SPERRY-SUN, INC, RECORD OF SURVEY COURSE DOG~E~ ...... DIRECTION SEV DEG MIN DEG/IO0 -"~9(~1.35 7868,35 ......... 42 15 N 6 6 W .86 7975.05 7942.05 42 47 N 5 42 W .60 ~0~8.78 ...... 8015.78 ...... 42 13 ...... N _ ~ 5._30___W_____._58_ __ 8122.59 8089.59 42 ~9 N 5 17 W .46 .~QSS~166.66 ....... T__OT. AL Re E-~-A NG ULA R COORDINATES NORTH/SOUTH EAST/WEST SECTION 2968.67 N 718,56 W 3035.89 N 725.51 W 3103.13_N __132_,_1.0___W_ ._ 3170.30 N 738.44 W 3037.63 3172.[ 3740.12 8196,44 8163,fl4 q2 8 N 5 36 W ,56 8270.43 8237,fl3 42 25 N 5 6 W ,q4 8344.67 8311,67 41 43 N 5 6 W ,70 8419,39 .... 8386,39 ..... Al 35_ N _ 5~17_W. ,.L~ .... 8494.78 8461.78 40 33 N g 36 W 1,13 8570.43 8537,93 40 16 N 4 36 W ,28 8647,7~- 8614',~2 39 2~ N 4 36 W ,87 8725.21 8692,21 39 0 N 4 30 W .40 8803.36 8770.36 ......... 38_12 ...... N __3_23 W 1.06 ~ - ~882,19 8849.19 37 g5 N 3 47 W ,51 8961,68 8928,68 36 57 N 3 30 W 9042,05 9123,22 9205,27 9287,95 9371,03 9fl54,84 9539,25 9624,29 9710.03 9796.29 9883.16 9970.68 10058.43 10146.16 6oo9.05 ........ 36'- 4 9090,22 35 25 9172,27 ...... 34 18 9254,95 34 10 9338,03 33 28 N 2 0 %4 1,00 N __ 2 .... O_U ......... 3_..i _~_ N 0 42 W .74 N 0 30 E .97 9421% 8'4 ......... 32'-39 9506,25 32 12 95.91 ,.29 .... 31__16 9677,03 30 41 9763.29 30 6 9850.16 29 17 9937.68 28 34 10025.43 ..... 28 45 10113.16 28 37 N 0 18 E ,82 N 1 30 E ,79 N 2_23__E ...... k,.O_5 ...... N 2 35 E ,59 N 4 30 E 1,13 3237,~2 N 744.8q W 3307.49 3304,39 N 3371,12 N 3k3_L, 31__JN 3502,75 N 3567,37 N 751.11 W 5574.70 757,07 W 5441,64 363.08__W~ 768.75 W 3573.66 773.q5 W 3638,39 3631,22 N~ 3694,22 N 3a17.86 N t~ 3878,41 N L.L-- 3996,16 N ~ q053,26 N 4109,50 N 4165,15 N 779.09 W 784.10 W 788.q0 W 792.25 W 796.11 W 799.63 W 802.33 W __8Q.!~3_3__w~ . 805,65 W 805.76 W 3702,36 3765.47 3827,73 388q,ll 3949,63 4008,c. 4067.1b ,q. 129_.03 4179.95 4235.12 N 6 54 E 1.4q N 7 41 E ,81 N _ _ 8_ 4 R _E ..... ,.~ 6 N 10 30 E ,83 4219.69 N 4273.30 N ~%25...8_7 N ........ 4377.28 N 4~27.77 N 4477.05 N 4525.02 N 4572._48 N 4619.79 N 805,37 W 4289.14 804,53 W 4342,17 60~,15_._W . 800.51 W 4444.70 797.39 W 4494.33 792.49 W q5q2.53 786.35 W 4589.27 7J_%u%7___W ..... ~ 6.3 5. ~ o 771.q3 W 4681,24 7~o.~4 W 47P¢.30 C t EXXON COMPANY USA ~ I PT. THOMSON ~4 "WILl'CAT - NORTHSLOPE aLASKA BOSS GYRO SURVEY MEASURED VE DEPTH D 12100.00 10 I 12200.00 10 12300.00 10 12400.00 10 SPeRRY-SUN, RECORD OF SURVEY TRUE SUB COURSE COURSE RfI~-L SEA I'NCLINATi6~ -'-6IREC'f~ON EPTH TVD DEG MIN DEG MIN DATE OF SURVEY VERTICAL SECTION DIRECTION PAGE '5 SEPT 17, 198-0 . N-07-36'-OO-W--- BOSS-16966 INC, DOG-LEG SEV DEG/iO0 TOTAL RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST VERTICAL SECTION 3;~;~'~'~.~ ---162-~-'~'~'.5 ....... ~7'-jl ....... N 15 0 E ~.~2 ~0~.~2 2~ ~ N ~ ~G E 500.39 ...... 1046Z. 3~ ..... 26 45 N 22 30 E 589.57 10556.57 27 4 N 22 6 E ~.Z5 ZO~.~S 2~ ~Z N 2Z ~ E 1.76 4711.91 N 751.67 1.67 4755.97 N 738.37 1.86 4798.51 N 722.q4 · 36 4840.38 N 705.27 1.42 4881.63 N 68~.81 W 47 W 48 W 48 W 48 W 49 51. ~i.1. 29.85 !2500.00 10 2600.00 10 __ 2700.00 .... 10 12800.00 11 12900.00 11 t13000.00 13100.00 13200.00 13300.00 13400.00 13500.00 13600.00 t_13700.00~ 13800.00 13900.00 861.41 10828.41 23 35 N 25 5~ E 953.06 10920.06 23 35 N 22 12 E 044.70 11011.70 23 37 N 19 36 E 136.64 11103.64 22 ~1 N 20 36 E 11322.01 11289.01 1l~15.16 11382.16 .... 11 508.57 .... 11475~7 ..... 11602.08 11569.08 21 ~ .......... ~--20 0 E 21 41 N 23 3O E 20 ~9 N 24 12 E 20- 50 ......... N-'25--416--~' 20 AO N 29 18 E 11695.88 11662.88 11789.97 11756.97 1188~.17 11851.17 11978.34 11945.34 12072.61 12039.6L 1.89 4920.46 N , 672.86 W 1.12 4957.11 N 656.09 W 1,48 4993,63 N 639,80 W ~ .. 1.04 5031.02 N 625.52 W 1.01_.._] 5067.94 N 612.02 W i · 80~-.--. 5103,53 N 598.~5 W 4966.23 5000.3~ 5034.38 I 5 0 ~ ~ : 5~ 5104.36 513fT§6-- 5170.25 19 55 N 31 30 E 19 40 N 33 36 E 19 32 N 34 54 E 19 48 ........ N-~7 6 E 19 10 N 39 54 E 1 0 · 75'--'"''5293 47 N 503.19 W .46 5321.20 N 484.31 W · 79 5348.42 N 464.53 W 1.13 5374.52 N 443,79 W 5201.29 5~i.35 5260.31 __ 5287.~ 5313,52 5338.51 53R6.00 14000.00 14100.00 14200..00 14300.00 14400.00 12166.94 12133.94 12261.20 12228.20 .... 12355.72 .... 12322.72 12450.61 12417.61 12545.60 12512.60 19 36 N 41 0 E 19 26 N 42 5fl E 18 41 N 43 36 E 18 6 N 45 54 E 18 18 N 46 54 E · 57 5399.77 N 422.25 .66 5424.61 N 399.92 · 78 5448.40 N 377.56 · 93 5470.81 N 355.35 · 37 5492.35 N 332.74 5408]-18 5429.85 5450.47 5488.11 I14500.00 14600.00 t_1470.0~00 12640.57 12735.92 12831.88 1292~.39 lS 12 N 45 36 E 16 53 N 45 48 E 15 46 N 51 1R E 1~ 35 N 57 12 E 12702.92 12798.88 12~95.39 · 42 5514.00 N 310.11 1.32 5535.05 N 288.55 1.91 5553.67 N 267.53 1,94 5568,98 N 246,35 5506.58 5524.59 5540.27 5'~ 5'2.6 ~ EXXON COMPANY USA PT, THOMSON ~q WILDCAT NORTHSLOPE ALASKA BOSS_GYRO SURVEY DEPTH PAGE DA~.E._OF__SU~_VE.Y _SER~_l_7~_1980. VERTICAL SECTION DIRECTION N-O7-36-OO-W TRUE SUB VERTICAL SEA DEPTH TVD SPE'RRY-SUN, INC. RECORD OF SURVEY ......... COURSE ...... COURSE__~DgG-LEG INCLINATION DIRECTION SEV DEG MIN DEG MIN DEG/iO0 __T.~T_~L RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST O_O.S_S__-.1 6 6 6G _ VERTICAL SECTION lq950 · O0 _** THE_CALCULATIONS ARE_BASED 5588.67 N 21q.87 W _ON _THE. MINIM. U.M R_A_D_I..U_S_P_F__C_U_R_V_A_I'_UR_L_M_ETH_O_D ** 5567.99 HORIZONTAL DISPLACEMENT = 5592,80 FEET AT NORTH 2 DEG, 12 MIN, WEST (TRUE) ABOVE SEA LEVEL ~EXXON COMPANY l_P T.__.THOMSON_~4 WILDCAT NORTHSLOPE ALASKA BOSS_~_YRO_SURVEY USA MEASURED DEP TH SPERRY-SUN, INC. INTERPOLATED RECORD OF SURVEY DATE OF PAGE SURVEY SEPT 17, 198~ ooss-166&G TRUE VERTICAL SUB SEA TRUE DEPTH TVD ELEVATION i ..... 10 20 30 AO 60 7O 110 120 130 140 O · 00. 00. 00. 00. 00. 00. 00. 00. 00. 00. 00. 00. 00. 00. O. -33. 33. 1000, 967. -967. 2000. 1967. -1967. 3000. 2967. -2967. 3997- 3964. -3964. 4905. A872. -fl872. 5687. 5654. -5654, 6450. 6417. -6417. 7169. 7136. -7136. 7901. 7868. -7868. 8648. 8615. -8615. 9455. ' 9422. -9422, 10323. 10290. -10290. 11229. 11196. -11196, 12167. 12134. -12134. 14950. 13074. 13041. -13041. TOTAL RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST O. N O. 3. S 10. .. 7. S 15. E 11. S 20. E 35. N 8. E 404. N 126· W 992. N 335. W 1607, N 530. W 2292. N 637. W 2969. N 719. W 3631. N 779. 4220. N 805. 4712. N 752. 5104. N 599. 5400. N 422. 5589. N 215. W ~N~ERPOLATED COORDINATES FOR EVERY 1000.00 FEET OF MEASURED DEPTH FROM 0.00 FEET TO 14950.00 FEET .CONF!DENT-!AL ., , , Ii t ~ ~ , ! I i i I I I i ~=' ' - ' :' f~' ; ' : ; '~ . ~ , , ' i i ; i ; i ; ; i i i ; i , i i i ~ i , ' I i , ir, i , i i ; '.! ! , , _. . ! i 4~ .... : , i i , i i i i i i 1 i i ; i ', i : , , , .. ii ~ , i i i i i , ~ , , , i , i , ~ , . .,~'' ! ! I ', i ! ! 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Operator, Wel 1 Name and Number Reports and Materials to be received by: ; -- ~-~/ Date Completion Report Well History S~ples Mud Log Core Chips Core Description Registered Survey Plat Inclination Survey Directional Survey Drill Stem Test Reports Production Test Reports Logs Run Digitized Log Data Required I Yes Yes k/'e s , Yes Date Received , Remarks I TEST DATA Exxon Point Thomson Unit No. 4 Page 3 TEST NUMBER DATE TYPE TEST INTERVAL CUSHION HOURS TESTED PROD'N FOR TEST PERIOD CHOKE SIZE FLOW RATE FLOWING TBG PRESS TBG SIZE IFP ISIP FFP FSIP ~ 3C 12/9/80 Prod'n through Perfs 13,478'-13,542' (4 spf) Diesel 30.3 97 bbls load oil + 90 bbls acid water 1/8 (1) 2-7/8 (1)Well died after 30.3 hrs. CONFIDENTIAL TEST NUMBER DATE TYPE TEST INTERVAL CUSHION HOURS TESTED PROD'N FOR TEST PERIOD CHOKE SIZE FLOW RATE FLOWING TBG PRESS TBG SIZE IFP ISIP FFP FSIP TEST DATA Exxon Point Thomson Unit No. 4 2D 11/5/80 DST through Perfs 14,807'-14,812' (4 spf) 14,822'-14,877' (4 spf) Nitrogen 27 (1)54 bbls water 3 11/29/80 DST through Perfs 13,478'-13,542' (4 spf) Nitrogen 11.7 (1)10 bbls 0 & GCM 4/64 (2) 2-7/8" 8043 psi 9795 psi (1)Reversed Out. (2)Fluid did not reach surface. 2-7/8" 5550 psi 6973 psi 2263 psi 4767 psi (1)Tool Plugged Page 2 3B 12/4/80 Prod'n through Perfs 13,478'-13,542' (4 spf) Diesel (1)No Test 2-7/8" (1)Could not break down perfs for acid job. gONFIBENTIAL Page 1 TEST DATA Exxon Point Thomson Unit No. 4 TEST NUMBER DATE TYPE TEST INTERVAL CUSHION HOURS TESTED PROD'N FOR TEST PERIOD CHOKE SIZE FLOW RATE FLOWING TBG PRESS TBG SIZE IFF ISIP FFP 10/3/80 DST through Perfs 14,956'-14,976' (4 spf) Nitrogen + 7000' Diesel 8.4 120 bbls 30/64 ( 1 ) 30 125 psi 2-7/8 3174 psi 6212 psi 9989 psi (1)Based on 3-1/2 hour stabilized test 2 10/13/80 DST through Perfs 14,802'-14,812' (4 spf) 14,822'-14,882' (4 spf) Nitrogen + 7200' Diesel 11 128 bbls water 64/64" (1)250 BWPD 130 psi 2-7/8" 3963 psi -- 6950 psi 10,240 psi (1)Based on 3 hour stabilized test 2B 10/25/80 DST through Perfs 14,807'-14,812' ( 4 spf) 14,822'-14,877' ( 4 spf) Nitrogen + 7400' Diesel Tool Malfunctioned 2C 10/31/80 S ~ 2-7/8" 2-B CONFIDENTIAL ( CORE DATA Exxon Point Thomson Unit No. 4 Core #1 Core #2 Core #3 Core #4 13,512' - 13,572'. Rec. 42.5' sandstone, med gry to gry-brn, vf to fg, silty, poor to fair porosity with oil staining. 17.5' shale, med gry, silty. Dip 15-25°. 14,791' - 14,799'. Rec. 2.5'. Shale, blk, silty. 5.5' siltstone, med gry to blk, poor porosity with oil staining at 14,791.5', 14,793.8' and 14,795.3'. Dip 0O. 14,799' - 14,811'· Rec. 12' shale, blk, silty with thin interbeds of sandstone, silty, dk brn, vfg. Oil staining at 14,800 5' 14 803 5' and 14,809' Dip 0O · ~ , · · · 14,973' - 15,013'. Rec. 12.5' sandstone, dk gry, vf to mg, poorly sorted, poor to fair porosity with oil staining. 27.5' argillite, blk, satin sheen. Dip 0-10°. RECEIVED JAN 2 0 1981 Alaska 0i1 & Gas Cons. Commission Anchorage GONFIDENllAL CASING RECORD Exxon Point Thomson Unit No. 4 25. Casing Size Weight Lb/Ft Grade CASING RECORD (Report all strings set in well) Depth Hole Set (MD) Size Cementing Record Amount Pulled 28" x 36" insulated conductor 20" 133 K55 13-3/8" 72 N80 9-5/8" 47 S0095 7" 35/32 Pll0 91 ' 42" 2127 ' 26" 3422' 11,887' 15,007' 17-1/2" 12-1/4" 8-1/2" to surf w/permafrost cmt 9100 sx permafrost cmt 835 sx permafrost cmt 2800 sx class G cmt 501 sx class G cmt None None None None 4285' ACID AND SQUEEZE CEMENT SUPPLEMENT Exxon Point Thomson Unit No. 4 29. ACID, SHOT, FRACTURE, CEMRNT SQURRZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MAT~:RIAL US~:D 14,954-14,956' 14,956'-14,976' 13,560'-13,562' 13,475'-13,477' 13,475'-13,477' 13,478'-13,542' 13,478'-13,542' Block sqz w/150 sx class G cement Sqz w/100 sx class G cement Block sqz w/150 sx class G cement Block sqz w/150 sx class G cement Block sqz w/300 sx class G cement 13,200 gallons 6-1/2% HCL + 1-1/2% HFL acid + 10% MUSOL in 3 stages using 300 ball sealers. Sqz w/150 sx class G cement RECEIVED 3AN ? 0 1981 Alaska Oil & Gas Cons. Commission Anchorage P-.-4 1-70 STATE (~ ALASKA OIL AND GAS CONSERVATION CO/V~I~EE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS APl NU1.{ERICAL CODE 50-089-20009 CONFIDENTIAL 6 LEASE DESIGNATION AXD SEHIAL SUI~MIT ~ DU~LICA~ (¢ ADL 47563 O,L [] G*, ~ o?.~- Wildcat ~'gLL 2 NAME OF OP~..ATOR Exxon Corporation ,, 3 ~,Z~D~SS o~' oPau, To~ Pouch 6601, hnchorage, Ak. 99502 4 LOCA~ON OF WFJ.~ Surface: 2700' NSL & 2900' WEL, Sec. 32, T10N, R22E, UM, North Slope, Alaska BHL (Proposed): 850' SNL & 3860' WEL, Sec. 29, T10N, R22E, UM, North Slope, Alaska IF INDI^]~ ALOTi-EE OR TRIBE NAME 8 I'NIT FAI%M OR LEASE NA3~E Point Thomson Unit g WF~LL NO No. 4 10 FD kND POOL OR %VILDCAT Wildcat I1 S~C T R !%{ (BO~TOM HOLE Sec. 29, T10N, R22E, UM 12 PERMIT NO 79-80 13 REPORT TOTAL DEPTH AT END OF MONTH CHANGES IN HOLE SIZE, CARING AND CEIV[ENTING JOBS INCLUDING DEPTH SET A3~D VOL~ USED PF~P~FORATIONS. TF-STS ANT) i~ESULTS FISHING JOt~4~ JL.~NK LN HOLE AND SIDE-/-P~ACI~gD HOLE AND A.NY OTHER SIGNIFICANT CHANGES IN HOLE CONDITIONS Finished trip out of hole. Laid down DST tool and ran a conventional production test with open ended tubing using a 54 barrel diesel cushion. Attempted but could not break down perforations with 8000 psi. Tripped in hole with a 1-5/16 inch perforating gun and could not get below 12,653'. Reversed out the 54 barrel diesel cushion and tripped tubing out of hole. Tripped in hole with tubing and spotted a 20 barrel oilfaze mud pill on bottom. Perforated 13,478' to 13,538' with 1 spf. Ran in hole with open ended tubing to 5 feet above packer, and displaced mud in tubing with 75 barrels diesel. Stabbed into packer, broke down perforations with 7800 psi at 1/2 BPM. An injection rate of 1-1/2 BPM at 7000 psi was established with 33 barrels of diesel. Acidized with 13,200 gallons 6-1/2% HCL, 1-1/2% HFL, 10% MUSOL in 3 stages using 300 ball sealers. Displaced acid with 72 barrels diesel. Total load to recover is 172 barrels diesel and 315 barrels acid water. Opened well to flow on a 1/8 inch choke. After 30 hours 16 minutes the' well died. Cumulative recovery during flow period was 90 barrels diesel and 30 bar,.rels acid water. Reversed out 7 barrels diesel and 60 barrels water (75 barrels diesel and 225 barrels acid water not recovered). Set retainer at 13,395' and squeeze cemented perforations with 150 sacks class G cement. Cut 7 inch casing at 4319' with Tri-State casing cutter. Pull and lay down 107 joints (4,285') 7" casing. Set cement retainer in 9-5/8" casing at 4100'. Pumped 23.2 barrels cement below the retainer. Pick up out of the retainer 3 feet and spot 5.4 barrels cement on top of retainer. With open ended drill pipe at 3900', the 9-5/8" casing was displaced with 400 barrels of 10.2 ppg CaCl2 water. Injected mud and surface fluids down the 13-3/8" x 9-5/8" annulus, followed by 50 barrels water, 100 sacks of 15.0 ppg Permafrost cement and 180 barrels Arctic Pack. Pumped 50 barrels water, 100 sacks of 15.0 ppg Permafrost cement and 350 barrels of Arctic Pack down the 13-3/8" x 20" annulus. Pulled drill pipe out of hole to 100' and spotted a 50 sack Permafrost cement plug from 0' to 100'. Removed BOP and "C" section, cut off 9-5/8" casing below the top of the "B" section and installed a 13-5/8" blank flange to top of wellhead. Well marker was placed on top of flange and the well ~ed and abandoned at 0900 hours December 20, 1981. This will be the final report on the well. R[CEIVLb h.,~b~-~:~, ~ant~re,~ ~Fue -- m~ Supervisor - 2OJ t, ,. 4 ,. ,,. E ON COMPANY, U.S.A. POUCH 6601 · ANCHORAGE, ALASKA 99502 PRODUCTION DEPARTMENT ALASKA OPERATIONS Mr. Hoyle H. Hamilton Chairman of Commission State of Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Dear Mr. Hamilton: In conversation with Blair Wondzell, the attached was requested pertaining to the Plug and Abandonment of the Exxon No. 4 Point Thomson Unit Well. If you require something further on this matter or have questions pertaining to the attached, please call. A. L. Hermann CMR:sjm 295-654-120 Attachments cc: R. L. Longstreet R. K. Riddle A DIVISION OF EXXON CORPORATION RECEIVED !980 Alaska 0~I & G~s Cons. Commission I POINT THOMSON No. 4 PLUG & ABANDONMENT PROCEDURE This procedure begins subsequent to the 7" Production Casing Block Squeeze Plug - Back procedure. i , Separate the blowout preventer stack from the wellhead at the 13-5/8" 10,000 psi flange on the bottom of the lower most ram preventer. , Nipple-down the D-section and the 9" 10,000 psi x 13-5/8" 10,000 psi Double Studded Adapter. · Nipple-up the 11" 10,000 psi x 13-5/8" 10,000 psi Spacer Spool to the C-section and the stack to the adapter. Replace upper rams with 7" casing rams. Test flanges to 5000 psi. · Run into the hole with a Tristate casing cutter for 7"-32~/ft Pll0 casing. · Cut the 7" casing at 4300'. Rig up a 7" casing spear on 3-1/2" drill pipe. · Spear the 7" casing in the C-section. Pull the 4300' of 7" casing and lay it down. ~ Place 3-1/2" pipe rams in upper rams. seals. Test upper ram to 3500 psi. Test bonnet 9. Rig-up Schlumberger lubricator and test to 2000. 10. Make a Gauge Ring and Junk Basket run to 4200' in the 9-5/8" 47~ casing. 11. Run into the hole with a Halliburton EZSV Cement Retainer for 9-5/8" 47~/ft casing to 4100'. Set the retainer. Retainer must be inspected and filled with grease as per Anchorage Drilling Bulletins 12 and 13. 12. POOH and rig-down Schlumberger. 13. Run into the hole with a stinger for the above retainer on 3-1/2" drill pipe work string. Halliburton latch in Plug-catcher is to be run 90'~above the stinger. Depth of 3-1/2" work string. Volume of work string: 4100 ft. 30.4 bbl. Cement volume in pipe afte~~',, job' ~ ~.~I~~~T!A,~~:t~ ~L' Casing fill above retainer Icement):~ / Pt. Thomson ~4 Plug and A~ donment Procedure Page 2 14. Sting into the retainer. Set down 20,000 lb. on the retainer to test it. Apply 1000 psi annulus pressure. Establish injectivity with 13.6 ppg. mud. Do not exceed 3000 psi. 15. Mix 28.6 bbl of Class G cement in a recirculating blender as follows; Class G Cement Water CFR-2 Halad 22A HR7 Thickening Time Slurry Yield Slurry Density 150 Sacks 15.9 bbl 1.0% 0.5% 0.30 % 3 hours, 45 minutes + 1.07 cu. ft./sack 16.3 ppg 16. Pump the following down the 3-1/2" work string: 2 bbl fresh water 8 bbl viscous pill (weight 9.0 ppg, viscosity 300+ sec. ) 28.g bbl cement 17. Set cement above and below the retainer as follows' Pump; Halliburton latch in plug 24.3 bbl 13.6 ppg mud Release annulus pressure. Pick up out of the retainer 3 ft. and pump the following: 5.4 bbl 13.6 ppg mud Latch and shear the plug. Allow the cement plug to balance. Pick up 70 ft. and reverse out. 18. Displace the 13.6 ppg mud in the casing with 10.2 CaC12. Casing volume is 295 bbl. Use 50 bbl fresh water pre-flush ahead of the CaC12. Avoid mixing mud with CaC12. Use reverse circulation to displace mud. NOTE' Inhibit CaC12 as follows' 25 gal/100 bbl Corexit 7720 10 gal/100 bbl Corexit 7675 These chemicals are at the Exxon pad. Pt. Thomsonf'~4 Plug and AbK .donment Procedure Page 3 19. POOH, lay down drill pipe. Keep hole full with CaC12. Lay down stinger. 20. Inject all remaining waste fluids on location down the 9-5/8" x 13-3/8" casing annulus. Bullhead 100 sacks of Class G cement followed by Arctic Pack from 3100 ft to surface. (Approximately 20 bbl cement plus 180 bbl Arctic Pack) 21. Bullhead 100 sacks of Class G cement followed by Arctic Pack down the 13-3/8" x 20" casing annulus from 2100 ft to surface. (Approximately 20 bbl cement plus 350 bbl Arctic Pack) 22. Run into the hole to 3100 ft. circulate 70° - 80° CaC12 water for 2 hours. 23. POOH to 100 ft. Keep hole full with CaC12 water. 24. Mix and spot 50 sacks of permafrost cement slurry as follows as a balanced plug. Use recirculating blender. Take returns to the reserve pit. 50 sacks Permafrost cement (15.0 ppg), 8.3 bbl (348 gallons) fresh water total. Approximate thickening time: 7+hours. Yield = .93 cf/sk. Retain surface samples to determine if they properly harden. 25. POOH, lay down rest of drill pipe. Flush BOP above B-section. Ensure that casing is filled to surface w/cement. 26. Nipple down BOP and C-section. Remove secondary seal from 9-5/8" casing and cut the casing off below the top of the B-section. Pt. Thomson( '+ Plug and Abandonment Procedure Page 4 26. Install a Blind Flange on top of the B-section with the following 'bead welded' on top as per AOGCC Regulations' EXXON CO. USA, DIV. OF EXXON CORP. STATE POINT THOMSON UNIT WELL ~4 2900' WEL and 2700' NSL Sec. 32, T1ON, R22E, U.M. The above is to be welded upon the marker post of the following specifications' At least 4" in dia. At least 10 ft long At least 4 ft above ground level Weld the top of the post closed. CMR/sm/rms 210 -T Sen~for SuperBising Engineer O~-~e r ~ i on $/S up e r i n~t~e~ t l iL i,.J'' ii'iii 7" PRODUCTION CASING PLUG BACK AND BLOCK SQUEEZE PROCEDURE POINT THOMSON NO. 4 i , , , , Install the following blowout preventer arrangement: Top Rams: Middle Rams: Bottom Rams: 3-1/2" Pipe Rams Blind Rams 3-1/2" Pipe Rams Test the rams to 10,000 psi. Have all necessary crossovers, T1W valve and BPV in the open position on the rig floor. Install and test Schlumberger lubricator to 2000 psi. Make a gauge ring and junk basket run to 13,410 DIL. Run into the hole with a Halliburton EZ drill SV cement retainer for 35 ppf. casing and set it at 13,395 CBL-1 .... Retainer must be inspected and filled with grease as per attached Anchorage Drilling Bulletins 12 and 13 Pull out of the hole and rig down Schlumberger. Run into the hole with a stinger for the above retainer on a 3-1/2" drill pipe work string. Halliburton latch-in Plugcatcher is to be run 90 feet above the stinger. Test surface lines to 7000 psi. Set down 20,000~ on retainer. Depth of 3-1/2" DP Work String: Volume of Work String: Cement Volume in Pipe after Squeeze: Casing Fill Above Retainer: 13,395 CBL-1 98.7 bbl* 0.67 bbl 19 ft. *Assumes 804 ft of 15.50 grade G drill pipe. Sting into the retainer. Apply 3000 psi Annulus Pressure Establish injectivity into the perforations with 13.6 ppg mud. Do not exceed 6000 psi. NOTE: If injectivity is not established, set a 50 ft. balanced plug on top of the retainer as follows: Pick up above the retainer 5 ft. Mix and pump 4 bbl of the cement in step 7 Pump 97.8 bbl of 13.6 ppg mudl Pick up 60 ft. and reverse out Go to step 10 RE£EJVED DEC2 ? !ggO Oil & ~, Cons. Commissio. Anchorag~ . Mix 28.6 bbl of Class G cement in a recirculating blender as follows- Class G Cement Water CFR 2 Halad 22A HR7 Thickening Time Slurry Yield Slurry Density 150 Sacks 15.9 bbl 1.0% 0.5% 0.11% 3 hours345 minutes 1.07 ft /Sack 16.3 ppg · Pick up out of the retainer. Pump the above cement and the necessary fluids into the 3-1/2" work string as follows: 15 bbls of fresh water 15.9 bbls of cement Halliburton Latch-in Plug 3 bbls of fresh water 60 bbls of 13.6 ppg mud · Sting into the retainer. Squeeze the perforation by pumping 35 bbls of 13.6 ppg mud as follows. Do not exceed 6000 psi. (1) If squeeze pressure is achieved before the full 35 bbls of mud has been pumped or before the plug latches; Pick up above the retainer 20 ft. Reverse out excess cement. Leave cement plug above retainer top @ 13,375 CBL-1 (2) If squeeze pressure is not reached by the time that the full 35 bbls have been pumped and the plug latches; Pick up 3 ft above the retainer and shear the plug Pick up 20 ft above the retainer Reverse out This leaves cement plug @ 13,375 CBL-1. 10. After reversing out clean, circulate bottoms up. Pull out of the hole. Lay down all but 4600' of 3~" work string on the way out of the hole. 11. Proceed to 7" casing cutting and pulling procedure. Engi~n{r ~~ Senior Supervising Engineer 0 ~ ' endent CMR-/rms 295-654-355 210-J lworm N'o P--4 ~ S- 1-70 STATE ( ALASKA OIL AND GAS CONSERVATION COMMI'I-rEE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS I OZL ~ G*I [] wgLL wgLL OTHER 2 NAME OF OP~.ATOR Exxon Corporation 3 ADDRESS OF OPER.ATOR Wildcat CONFIDENTIAL AP1 NUAIER1CAL CODE 50-089-20009 LE~SE DESiG]qAT~ON AND SLqqlAL NO ADL 47563 Pouch 6601, Anchorage, Alaska 99502 SUBMIT IN DU'PLICA~ IF INDIA~T ALOT ~.,~1~ OR TRIBE 8 L~IT FA/{M OR LEASE NA3~E 4 ~CA~ON ~ W~-T~ Surface: 2700' NSL & 2900' WEL, Sec. 32, T10N, R22E, UM, North Slope, Alaska BHL (Proposed): 850' SNL & 3860' WEL, Sec. 29, T10N, R22E, UM, North Slope, Alaska Point Thomson Unit 9 W~ No. 4 l0 FI~'.LD AND POOL OR WILDCAT Wildcat 11 SF.~ T R 1%I (BOT'TOM oa.mc'riv~ Sec. 29, T10N, R22E, 12 P]!~RNIIT NO 79-80 UM 13 REPORT TOTAL DEPTH AT END OF MON'I"H CH. ANGES IN HOLE SIZE CASING AND CEMENTING JOBS INCLUDING DEPTH SET AiN'D VOLU'M]~ USED PERFORATIONS TF~TS A.ND H.ESULTS FISHING JOB~ JL.'-NK IN HOLE AND SIDE-TRACKED HOLE A.~D ANY O7~ER SIGNIFICANT CI-IANGES IN HOLE CONDITIONS B~ran a conventional DST from perforations 14,807'-14,812'; 14,822'-14,877' and had a misrun due to a tool malfunction. Retested perforations 14,807'-14,812'; 14,822'-14,877' using a nitrogen cushion. On a 27 hour flow test fluid did not reach the surface. Shut in for 25 hours 12 minutes and reversed out 54 barrels of water. Set a bridge plug at 14,707' and pressure tested to 4000 psi for 20 minutes. Perforated 13,560'-13,562' with 4 spf and squeeze cemented below a retainer set at 13,555' with 150 sacks class G cement. Perforated 13,475'-13,477' with 4 spf and squeeze ceraented below a retainer set at 13,465' with 150 sacks class G c~t. Drilled 1.5' of retainer set at 13,465' and lost returns with 15.1 ppg mud at a rate 1% BPM. Regained returns and finished drilling retainer. Set retainer at 13,360' and squeeze c~ted perforations 13,475'-13,477' with 300 sacks of class G cement. Cement set up while pumping so the bottom 35 joints of drill pipe contained solid cement. Drilled out retainer and cement to 13,483'. Cleaned out hole to 13,555' and reduced mud weight to 13.6 ppg. Perforated 13,478 ' to 13,542' with 4 spf and set a Baker Model F-1 packer at 13,423 '. Ran a conventional DST using a nitrogen blanket. Opened tool for an 11 minute initial flow. Closed for a 75 minute initial shut in. Reopened for an 11 hour 28 minute final flow. Formation fluid did not surface. The down hole shut in device malfunctioned so closed in at the surface for 19 hours and 15 minutes. Reversed out 10 barrels of oil and gas cut mud (75% ~ud 25% oil). Tripping out of hole with test tools at end of month. RECEIVED ! W lii/ll-ll~ilTI A / .... , buHI'IULN/I/-IL Alaska Oil & Gas Cons. Commission Anchorage hereby ce~[~,that t]3e foregoing ,~ true ~ eom-ect .O_,13r~:~l,.X?-~ ~n~,. -- /~ · . I_~ ~ .,~ ~~v~ 0 SzG~~~~~ ~ Operations Gao]Oov ~~mh~ 15, 198 oil and gas conoervatbn commiflee bythe 15~ of the succ~dlng mon~ ~le. otherwise d~rk~d, ~ , / "~ q · I ! 1000 2000 3000 B Section LA Section 30"@91' refrigerated ~'F'~;~7- ?~(~ /D~: O conductor ' (so 400O 5O00 60OO 7000 8000 9000 10,000 11,000 12,000 13,000 14,000 15,000 20"@ 2127' 26 Hole z/oo ' (~ ~c~ 3 13,000 I TOC 2900+' 13,500 Isolation Squeeze Perforations 13,478-13,542 Hallzburt~n FZSV ~ 13,555' Perforations 13,560-13,562 14,000 TOC 8900+ ' 14,500 9-5/8" @ 11,887' 12-1/4" Hole (10,222 TVD) 15,000 TOC 13625+' Cement @ 15,007' 7" @ 15,049' (13,170' TV[{) 8-1/2" l{o]e ~ TD 15,074' (13,193' TVD)~1 Bridge Plug ~14,707' Baker Model F1 ~ 14,740 Perforations ] 4,807-14,8 ] 2 . ~f 14,822-14,877 % ~ ~%~]~Hall~burt°n FZgV 8 14,920' ~" 11' ~PorforatzOn~ ~ 14,956-14,976" RECEIVED Exxon No. 4 Point Thomson Unit DEC ! 2 19g, O Alaska Oil & Goo Cons, Commission Anchora,qe Form 10-40~ REV. 1-10~'/3 Submit "intentions" in Triplicate & "Subsequent Reports" In Duplicate STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE ----~~NDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen "APPLICATION FOR PERMIT--" for such proposals.) WELL I---J OTHER Wildcat 2. NAME OF OPERATOR Exxon -uompany, U.S.A. 3. ADDRESS OF OPERATOR P. O. BOX 2180, Houston, 4. LOCATION OF WELL At surface 2700' NSL and 2900' Texas 77001 WEL, Sec 32, T10N, R22E,U.~ 13. ELEVATIONS (Show whether DF, RT, GR, etc.) 33' RT 14. Check Appropriate Box To Indicate Nature of Notice, Re 5. APl NUMERICAL CODE 6. LEASE DESIGNATION AND SERIAL NO. 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 8. UNIT, FARM OR LEASE NAME Point Thomson Unit 9. WELL NO. Exxon No. 4 10. FIELD AND POOL, OR WILDCAT Wildcat 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) · Sec. 29, T10N, R22E, U.M. 12. PERMIT NO. )crt, or Other Data NOTICE OF INTENTION TO: TEST WATER SHUT. OFF FRACTURE TREAT SHOOT OR ACIDIZE REPAIR WELL PULL OR ALTER CASING MULTIPLE COMPLETE ABANDON* CHANGE PLANS (Other) SUBSEQUENT REPORT OF: WATER SHUT-OFF ~ REPAIRING WELL FRACTURE TREATMENT ALTERING CASING SHOOTING OR AClDIZlNG ABANDONMENT* (Other) (NOTEt Report results of multiple completion on Well Completion or Recompletion Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all I~rtlnent details, and give pertinent dates, including estimated date of starting any proposed work. It is proposed to plug and abandon the above-captioned well as per attached well bore sketch. The work described is to begin December 14, 198Q. '6. I hereby c,~h~fTo~/?ls true an, correct/ ::::::c.,o-, RECEIVED DEC ! 2 ]9 0 Alaska 0ii & Gas Cons. Cor~mlssion Anchorage _ DATE , CONOITIONSOF~,PPROVA/IFAN~: / DY O,~D:R OF THE COMMISSION See Instructions On Reverse Side I Appn:>ved Cepy Returned FOrm N'o P--4 STATE l, ALASKA OIL AND GAS CONSERVATION COM~I'I-rEE SUBMrT ~ DUPLICATE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS Wildcat NA2~E OF OP~tATOR Exxon Corporation AZ~Z~-%S"Or' 6~zs..'ma Pouch 6601, Anchorage, Alaska 99502 4 ~CA~ON OF WFJ~L Surface: 2700' NSL & 2900' WEL, Sec. 32, T10N, R22E, UM, North Slope, Alaska BHL (Proposed): 850' SNL & 3860' WEL, Sec. 29, T10N, R22E, UM, North Slope, Alaska CONFIDENTIAL 50-089-20009 LEASE DESTGNA.'/ON A~D SEI~IAL NO ADL 47563 IF INDiA]~ &L,OTT'EE OR TRIBE NAME 8 L~IT F.~P&A OR LEASE Point Thomson Unit 9 WE~ NO NO. 4 ~0 FLFJ~ A_ND POOL OR WILDCAT Wildcat Sec. 29, T10N, R22E, UM 12 PI/~q.MIT ~o 79-80 13 REPORT TOTAL DEPTH AT F.~D OF MONTH CIg3%.NGES IN HOLE SIZE, CA~ING AND C~N~F2qTZNG JOBS INCLUDING DEP~ SET ~ VOL~ US~ P~O~TIONS ~TS ~ ~SUL~ FISHING JO~ JL~K ~ HO~ AND S1DE-~CK~ HOLE ~D ~Y O~R SIGNIFIC~T ~~ ~ HO~ ~ITIONS Ran a conventional DST from perforations 14,956' - 14,976' using a combination diesel/nitrogen cushion. Opened tool for 20 minute initial flow. Closed for 3 hour, 41 minute initial shut in. Reopened for final flow. The diesel cushion surfaced in 1 hour, 25 minutes. Formation fluid surfaced in 4 hours, 19 minutes. During a 3% hour flow period the well flowed water at an average rate of 306 BPD. Shut in for 9½ hours and reversed out. Set cement retainer at 14,920' and squeezed perfs with 100 sacks of cement. Perforated with 4 spf 14,802' - 14,812'; 14,822' - 14,882' and set a Baker packer at 14,766'. Ran a conventional DST using a combination diesel/nitrogen cushion. Opened tool for 10 minute initial flow. Closed for 94 minute initial shut in. Opened for final flow. Diesel cushion surfaced in 4 hours. Formation fluid surfaced in 7% hours. On a 3 hour flow test the well flowed water at the rate of 250 BPD. Could not shut in so reversed out. Set a cement retainer at 14,760' and squeezed perfs with 200 sacks of cement. Drilled out retainer and packer and cleaned out hole to 14,900'. Perforated with 4 spf 14,807' - 14,812'; 14,822' - 14,877' and set a Baker packer at 14,740'. Attempted to DST but had a misrun due to a tool malfunction. At the end of the month - preparations are under way tore~~ ~/~y%~~~r~!L~ CONFII TIN..' Y NOV,9', s~o,~~~,,6)]~c~~ Operations Geozogy ~ November 14., 1980 I I I I II II Il I I II Il I I ........ I I I I ! I II I! I Il ! oil and ggl co~ervatbn ¢ommiffee bythe 15~ of the muGc~ding mon~, ~IIM Otherwise d, rec~d. ~c)rm ~To P.--4 ~ B- I-1'0 STATE O~F ALASKA OIL AND GAS CONSERVATION COMMITTEE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS SUBMIT 12q' DIIPLICAT~ NAME OF OP~:I~ATOR Exxon Corporation ADDRESS OF OPERATOR Wildcat Pouch 6601~ Anchorage, Alaska 99502 4 ~CA~ON OF wF~J. Surface: 2700' NSL & 2900' WEL, Sec. 32, T10N, R22E, UM, North Slope, Alaska BHL (Proposed): 850' SNL & 3860' WEL, Sec. 29, T10N, R22E, UM, North Slope, Alaska AP1 NI/MERICAL CODE CONFIDENTIAL o-o8 -2ooo L~ASE DESIGNATION A\'D SElqIAL NO IF INDIA~ Ai_,O~' ~E~ OR TRIBE NAME ADL 47563 8 L.~IT F.~ OR LEASE NA3~E Point Thomson Unit 9 W~L.L NO No. 4 10 FLEL,D A-ND POOL OH WILDCAT Wildcat SEC T R M (BOTTOM HOLE Sec. 29, T10N, R22E, UM P~R~I IT NO 79-80 '13 REPORT TOTAL DKPTH AT E.ND OF MONTH CHA~NGES IN HOLE SIZE CA~ING Ai~D CI~5/IF~NTING JOBS INCLUDING DEP~-H SET ~ VOL~ USD P~O~TIONS. ~TS ~ ~SUL~ FISHING JO~ J~K ~ HO~ AND SIDE-~C~D HO~ ~D ~Y O~R SIGNIFIC~ ~~ ~ HO~ ~ITIONS Stuck drill pipe came free after a 200 barrel "Black Magic" pill had been on spot for 12% hours. The pill was circulated out of the hole and injected down the 9-5/8" x 13-3/8" casing annulus. Ran FDC-CNL tool and could not get below 12,300'. Ran in hole with open ended drill pipe to 12,757' and attempted to run a slim hole FDC-CNL tool but could not get below 13,000'. Open hole logging program was terminated. Set 7" casing at 15,049' and cemented with 601 sacks class G cement. Had partial returns while cementing. Drilled out cement inside 7" casing to 15,007' and ran the following surveys: Formation Density - Compensated Neutron Cement Bond Log Gyro Survey Velocity Survey Perforated 14,954' - 14,956' with 4 spf and squeeze cemented below a retainer se~ a~-~925' with 150 sacks class G cement. Drilled out cement and retainer. Perforated 14~956' - 14~7~' with 4 spf and set a Baker Model F-1 packer at 14,930'. Preparing to run in hole with DST tools. SuPervisor - SmNXDV',,'V~'~~-W'~T~TL~ 0p~r. Geology ~,~. _October 15~. 1980 NOTE--Roi)art on this form is required for each calendar month% regQrdless of the status of o~eratians, and must I~ filed In duplicate with the oil and gas conservation committee by the 15th of the sueceeding month, mlle,e otherwme d~rected. E)f ON COMPANY, U S.A POUCH 6601 · ANCHORAGE, ALASKA 99502 907/276-4552 ,.x,o I September 23 1980 {~ STAT TEC Alaska Oil and Gas Conservation Commission Mr. Russ Douglas 3001 Porcupine Drive Anchorage, AK 99501 Dear Mr. Douglas, As per your conversation with R. L. Westbrook the afternoon of Tuesday, September 16, please find the following justification of anticipated maximum surface pressure for the Exxon Pt. Thomson ~4: True Vertical Depth = 13,100 ft. Formation Pressure = 15.3 ppg Gas Gradient = 0.185 psi/ft. Conversion: 1 ppg = 0.052 psi/ft. Maximum Anticipated Surface Pressure = (15.3 x 0.052 - 0.185) x 13,100 MSP = 8,000 psi We propose to test our blind blowout preventer rams to the above pressure rather than to the 9000 psi value submitted on the Sundry Notice and Report on Wells dated 11/21/79. This 9000 psi value represents preliminary pressure predictions which have since been refined as reflected above. If you have any questions, CMR/rms cc: R. L. Westbrook R. K. Riddle J. B. Willis A OlVgO~00~ ~×ON CORPORATION please feel free to call me~'..~ ' ".';'~.,, ".~, ~,~,,~, ,~ -~ Very truly yours, g , '-" o ~:,f ~.~l _ I~:':~ ,, ' ~;~, ~-; ~f ~z'm No P--4 ~ ~- 1-70 STATE O(r ALASKA OIL AND GAS CONSERVATION CONU~ITTEE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS WgLL ~VgL~ OTHg! SUBMIT IN ]3UPLICA'I~ NAME OF OPERATOR Exxon Corporation ADDRESS OF OPERATOR Wildcat Pouch 6601, Anchorage, Alaska 99502 4 ~CA~ON ~ WELL Surface: 2700' NSL & 2900' WEL, Sec. 32, T10N, R22E, UM, North Slope, Alaska BHL (Proposed): 850' SNL & 3860' WEL, Sec. 29, T10N, R22E, UM, North Slope, Alaska CONFIDENTIAL AP1 NL'A,~ER/CAL CODE 50-089-20009 LEASE DESiGNATZON AND SERIAL NO ADL 47563 IF INDIA]~ ALO'TT'EE OR TRIBE 8 L.~IT F.~ OR LEASE NAME Point Thomson Unit 9 %~ELL NO No. 4 10 FLFLD AND POOL OR WILDCAT Wildcat 11 S~ T R M (~OM HO~ o~ Sec. 29, T10N, R22E, UM PERMIT NO 79-~30 ,, 13 RE. PORT TOTAL DEPTH AT END OF MONTH CHANGES IN HOLE SIZE CASING AND C~NIENTING JOBS INCLUDING DEPTH SET AND VOLU'M]~ USED PERFORATIONS TESTS AND HESULTS FISHING JOB~ J~K ~ HO~ AND SIDE-~CKED HOLE ~D ~Y O~ SIGNIFIC~T ~~ ~ HO~ ~ITIONS Because of excessive drag and torque, 6% diesel was added to the mud system at 14,150'. A final total depth of 15,074' was reached August 20, 1980 and the following open hole logs were run: Dual Induction Bore Hole Compensated Sonic Four attempts were made to get a Formation Density/Compensated Neutron log but we could not get the tool below 12,208'. While tripping in the hale on August 28, the drill pipe was stuck with the bit at 15,000'. A 150 barrel E-Z spot pill failed to free the pipe after being on spot for 41 hours. The E-Z spot pill was circulated out of the hole and injected down the 9-5/8" x 13-3/8" casing annulus. A free point was run and indicated the drill pipe stuck at 13,890'. Plans are to use a 200 barrel "Black Magic" pill to free the drill pipe. During the month mud weights were increased from 14.2 to 15.~ pp__p~and the following cores were cut: 14,791' to 14,799' 14,799' to 14,811' 14,973' to 15,013' CONFIDENTIAL Core # 2 Core # 3 Core #4 hereb~i,~ ?~ore~S~ltrue~rree~ Supervisor - mum._~-g~k~;~ ~./~/r~t///w~-~ Oper. Geology ~,~ September 15. 1980 NOTE--Report on this form is required for ~ch calendar ~th% regardless of the Status of operations, Grid must ~ filed iff dupli~te with the oil end gas conservat~n commiflee bythe 15~ of the suec~dieg mon~, ~le~ Otherwise d~rected. ALASKA OIL AND GAS CONSERVATION COMMISSION File September 16, 1980 Russell A. Douglass~ Petroleum Engineer B.O.P.E. testing Exxon Pt. Thomson Unit %4 Received a call from Mr. Westbrook this p.m. 9/16/80. He informed me that Exxon is unable to test the blind rams in their BOP stack to the full 10,000 psig on the Pt. Thomson Unit %4 well. The casing will be tested to 8000 psig and the blinds may be tested then. The permit indicates a maximum anticipated surface pressure of 9000 psig, but he indicated new calculations support an MSP of only 8000 psig. I informed him that if that is the case an 8000 psi test would be adequate. I later talked with A1 Hermann, Exxon Drilling Manager. He in- formed me they were preparing a memo substantiating their claim and would send that to us shortly. ~AD ~ ng Fm'm Ho P--4 ~ ~- 1-70 STATE (~. ALASKA OIL AND GAS CONSERVATION COMMITTEE SUBMIT IN DUPLICA~ MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS I O,L ~ ~*. ~ o.,,.. Wildcat WKLL WgLL % NAMe- OF OPERATOR Exxon Corporation 3 ADDKEss OF OPERATOR Pouch 6601, Anchorage, Alaska 99502 4 ~CA~ON OF WEL~ Surface: 2700' NSL & 2900' WEL, Sec. 32, T10N, R22E, UM, North Slope, Alaska BHL (Proposed): 850' SNL & 3860' WEL, Sec. 29, T10N, R22E, UM, North Slope, Alaska CONFIDENTIAL 50-089-20009 LEASE DESIGNATION A%D SEFiIAL NO ADL 47563 IF INDiA)X ALOi ik~ OR TRIBE NAME 8 L~IT F.~ OR LEASE NA2AE Point Thomson Unit 9 WELL XO No. 4 l0 ."~[F_,I~ A-ND POOL OR WILDCAT Wildcat 11 SF, C T R 1%I (BO'I'I'OM HOLE oa,r~naw~ Sec. 29, T10N, R22E, UM 12 PERMIT NO 13 REPORT TOTAL DEPTH AT END OF MONTH CHA~NGES IN HOLE SIZE CARING AND CLWIENTING JOBS INCLUDING DEPTH SET AND VOLU1VIES USED PEP, FOHATIONS TESTS AND HESULTS FISHING JOB~ JI. TATK I.N HOLE AND SIDE-TRACKED HOLE AND ANY OTHER SIGNIFICANT CHANGES IN HOLE CONT)ITIONS During the month an 8½" hole was directionally drilled to a measured depth of 14,132'. Core #1 was cut from 13,512' to 13,572'. Mud weight was increased from 12.5 to 14.2 ppg. CONFIDENTIAL AU8 i 5 't980 Alaska 0~1 & Gas Anchorage i - ,_~,..,~~~~SuDervisor-Oper. Geology D.~ August 15, ]gR0 . NOTE --Report on this form il required for ~ch calendar ~th% regardless of the status of ogeratio~, Grid must ~ filed In dupli~te with the oil and gas conservatbn commiHee bythe 15~ of the suee~ding mon~, ~le~ otherwis~ d~rected. E? ON COMPANY, U.S.A. POUCH 6601 · ANCHORAGE, ALASKA 99502 EXPLORATION DEPARTMENT ALASKA/PACIFIC DIVISION Dr. Ross G. Schaff Acting Director Division of Minerals & Energy I4gmt. 703 W. Northern Lights Blvd. Anchorage, Alaska 99503 ~' coM~ July 24, 1980 ]r~-} 3 [NO Re: Point Thomson Unit No. 4 GE0~ Section 29, T10N, R22E, U. ADL 47563 Arctic Slope, Alaska j { STATT~ LO/NS 79-155 ~AII~ Dear Dr. Schaff: Our Plan of Operations for the subject drilling operation (dated October 18 and approved December 20, 1979) provided for the stockpiling of fuel, and other major supplies at the location prior to spring breakup and for the transport of all supplies thereafter to be made by helicopter or other state approved means. As it now appears that an additional 350,000 gallons of fuel and 50 tons of test equipment will soon be required we ask that the "Construction and Operating Plan" be amended to permit th~-~r~nsp6~ta~i0~ bY tug and barge of these required additional supplies from the Prudhoe West Dock to the site. The fuel will be pumped directly from the barge to the storage tanks at the site. The supplies will be offloaded from the barge to a rolligon and thus moved to the required position on the gravel pad. An early approval of this amendment of the subject plan will be sincerely appreciated. Should there be any questions please do not hesitate to let us know and every effort will be made to respond immediately. Yours very truly, Robert K. Riddle RKR: et c: EPA Region X - Mr. Danford G. Bodien, P.E., Alaska Oil & Gas Conservation Commission - Mr. Hoyle H. Hamilton, U.S. Army Corps of Engineers - Col. Lee R. Nunn A DIVISION OF EXXON CORPORATION ALASKA OIL AND GAS CONSERVATION COM~I'Iq'EE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS (t CONFIDENTIAL SUBMIT IN I3UI~LICATE ~ APl NLr~iERICA.L CODE 50-089-20009 NAME OF Exxon Corporation Pouch 6601, Anchorage, Alaska 99502 LEASE DESiGNA~ON A\'D SERIAL NO ADL 47563 ~ IF INr)IA]~ ,~-LOTIE~. OR TRIBE lq~.M]E I o,, ~ o,. ~ o,.=. Wildcat WKLL WgLL 8 L~IT F.~ OR LEASE N~E Point Thomson Unit 9 %V~ NO No. 4 4 ~CA~ON OF WF_J~ Surface: 2700' NSL & 2900' WEL, Sec. 32, T10N, R22E, UM, North Slope, Alaska BHL (Proposed): 850' SNL & 3860' WEL, Sec. 29, T10N, R22E, UM, North Slope, Alaska 10 FIF_.LD AND POOL OR %VILDC~T Wildcat I1 SEC T R 5I (BO~'TOM HOLE O~mCTlWF3 Sec. 29, T10N, R22E, UM 12 P~,~IIT NO 79-80 "13REPORT TOTAL DEPTH AT END OF MONTH CHAI'~GES IN HOLE SIZE CASING AND Cia,%/[EN~'IqlNG JOBS INCLUDING DEPTH SET AJ~D VOL~ US~ P~O~TIONS ~TS ~ ~SUL~ FISHING JO~ JL~K ~ HO~ AND SIDE-~C~D HOLE ~D ~Y O~ SIGNIFIC~T ~~ ~ HO~ ~ITIONS Directionally drilled with a 12¼" bit to a measured depth of 11,887' and ran the following open hole logs: Dual Induction BHC Sonic Formation Density - Compensated Neutron Dipmeter Set 9-5/8" casing at 11,887' and cemented with 2800 sacks 15.8 ppg class G cement. Estimated top of cement at 8950' from temperature survey. Injectivity was established down the 9-5/8" x 13-3/8" annulus by injecting 200 barrels of mud at a maximum rate of 4 BPM with 550 psi pressure. Drilled out of 9-5/8" casing with an 8%" bit to 11,897' and performed a pressure integrity test. Leak off occurred at 16.2 ppg EMW. Ran a Sperry Sun gyro survey. Squeeze cement the 9-5/8" casing shoe below a retainer set at 11,820' with 200 sacks class G cement. Drilled out retainer and made 10' of new hole. At 11,907' performed a pressure integrity test with leak off occurring at 17.3 ppg EMW. At the end of the month an 8½" hole is being directionally --~i~%~7-a--~ a measured depth of 12,200' with 12.5 ppg mud. CONFIDENTIAL h.~,~"~ t~,m ~.,~.~ ~ ~-~ ~ Acrea -~ .... nd Well ~ - ~ ~ ~ ~valuae_i2~ ~an~ _,.~/ July 15 ~ , NOTE--Report on this form is required for eo~ calendar ~th~ regardless of the status of ;p~r~o~ must ~ filed in dupli~te with the oil and got conlervatbn commiflee bythe 15~ of the suec~ding mon~, ~le~ otherwese ~nrected. RECEIVFD JUL Oil & ~as uo~. ,,.;ommisslo~ Anchorage ~rm No P--4 ~ ~- I-?0 STATI,,./F ALASKA OIL AND GAS CONSERVATION COMMI~EE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS I oz~ ~ G*I E O?gt! WKLL ~gLL NAME OF OP~%ATOR Exxon Corporation ADDRESS aP Wildcat Pouch 6601, Anchorage, Alaska 99502 4 SUBMIT IN I~UPLICATE '~API NUA{ERICAL CODE 50-089-20009 4 ~CA~ON OF WELL Surface: 2700' NSL & 2900' WEL, Sec. 32, T10N, R22E, UM, North Slope, Alaska BHL (Proposed): 850' SNL & 3860' WEL, Sec. 29, T10N, R22E, UM, North Slope, Alaska CONFIDENTIAL LEASE DESiGNATiON A\'D SERIAL NO ADL 47563 ? IF INDiA)$ ALoT'r'EE O]~ TRIBE NAIVE 8 ~.~IT F.~RA{ OR LEASE NAME Point Thomson Unit 9 WELL NO No. 4 10 FLF/~D A_ND POOL OH WILDCAT Wildcat 11 SEC T R M (BO'I'TOM HOLE Sec. 29, T10N, R22E, UM , , 12 P~R/VIIT N'O 79-80 "13 REPORT TOTAL DEPTH AT F2qD OF MONTH CHA~NG~S IN HOLE SIZE CASING A1VD C~MENT!NG JOBS INCLUDING DEPTH SET AND VOLLrM'ES USED PERFOHATIONS TESTS A.ND HESULTS FISHING JOBS JL~K LN HOLE AND SIDE-TRACKED HOLE AND A. NY OTHER SIGNIFICANT CHANGES IN HOLE CONDITIONS Finished nipple up and on 5-5-80 drilled out of 13-3/8" casing with a 12¼" bit. At a drill depth of 3445' a pressure integrity test was performed. Leak off occurred at 12.2 ppg EMW. Squeeze cement the 13-3/8" casing shoe below a retainer set at 3350' with 270 sacks permafrost. Drilled out retainer and performed pressure integrity test with leak off occurring at 12.2 ppg EMW. Drill to 3482' and resqueeze shoe below a retainer set at 3324' with 320 sacks permafrost. Drilled out retainer and obtained a leak off of 12.4 ppg EMW. Set a retainer at 3372' and squeezed 13-3/8" casing shoe with 400 sacks permafrost. After drilling out retainer, a leak off of 13.3 ppg EMW was obtained. Resumed drilling. At 3599' the hole was kicked off to the north using a Dyna Drill. Subsequent pressure integrity tests were performed at drill depths of 6235' and 7412' with leak off occurring at 11.3 ppg and 11.1 ppg EMW, respectively. A 12¼" hole is now being directionally drilled at a measured depth of 9955'. CONFI ENTI L 14 ,hereby{ll~.l~xa~r~eandcom Acreage and Well SXGNEDVV~.'X~',V.~'~r'~--~--'hTLE~k2~O~~%I%I/4~'~~--~ Rval~a~4On M~~r~ D~ June 13, 1980 NOTE--Regort on this f~ is required for ~ch calendar ~nth% regardless of the status of ogerotiofls, and must ~ filed in dupli~te with the oil and gas conlervat/on commiflee bythe 15~ of the suec~dieg mn~, ~le~ otherwise d~rected. Form 10-403 Submit "1 ntentlons" In Triplicate ' REV. 1-10-73 & "Subsa~luent Reports" in Duplicate STATE OF ALASKA s. Apl NUMERICAL CODE OIL AND GAS CONSERVATION COMMITTEE 50-089-20009 -'~ 6. LF_J~SE DESIGNATION AND SERIAL NO. SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen ADT, 47563 use "APPLICATION FOR PERMIT--" for such proposals.) 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 1. OIL GAS WELLI----I WELL L.--J OTHER Wildcat Exxon Corporation Point Thamson Unit Pouch 6601, Anchorage, Alaska 99502 Exxon No. 4 ..... ,0. o, At surface 2700' NSL and 2900' WEL, Sec. 32 ~[~hura~e '"'m~ldcat ~2E, U.M. 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) B.H.L. 850' SNb 3860' W~T, Sec. 29, T10N, R22E, U.M. 13. ELEVATIONS (Show whether DF, RT, GR, etc.) 12. PERMIT NO. .Z~prox. 8.3' G.L. 79-80 14. Check Appropriate Box To Indicate Nature of Notice, Rel3ort, or Other Data NOTICE OF INTENTION TO: ~ SUBSEQUENT REPORT OF: FRACTURE TREAT MULTIPLE COMPLETE FRACTURE TREATMENT ~ ALTERING CASING SHOOT OR ACIDIZE ABANDON* SHOOTING OR ACIDIZING ~ ABANDONMENT* L.__.J REPAIR WELL CHANGE PLANS (Othlr) modification of diverter assmelb~ J (Other) ~ procedure re use of cement (NOTE, Report results of multiple completion on Well ~_ A3"~t-.1~. P.-~'3'K C~mltlltlon or Recompletion Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work.. ,.. To reduce the possibzlzty of trapping fresh water between casing strings and causing internal ireezeback, we prefer to place Arctic Pack rather than cement in the 13-3/8"x20" annulus. We also )refer to place the Arctic Pack at the completion of the well rather than when the 9-5/8" casing is ~et, thus retaining the option to inject into either the 9-5/8"x13-3/8" annulus or the 13-3/8"x20" · unulus. This also provides a backup annulus in case the primary injection annulus should plug for ~me reason. Accordingly we intend to place Arctic Pack in the 13-3/8"x20" casings' annulus to a [epth of approximately 1550' and permafrost cement from 1550' to 2127' (casing shoe) at the :ompletion of the well. The Arctic Pack and cement will be pu~ in place from the surface as !ollows: 1. Pump fresh water preflush 2. Pump cement (approximately 1000 sacks permafrost) 3. Pump Arctic Pack (approximately 300 barrels, 7.2 ppg) ~. As depicted in the attachments, the installed diverter assembly differs from that which we )reviously sukmitted as follows: 1. The 6" butterfly valve with tee handle at the rig floor was replaced with a 10" ball valve which is hydraulically operated. The ball valve is controlled by the same signal as the Hy- dril annular preventer such that when the Hydril is closed the ball valve automatically opens. 2. The 6" diverter lin&--~a-~-~eplaced w~h a"'10" li~e'. 3. The 6" butterfly valves controlling flow to the reserve and burn pits were placed with 10", full opening gate valves. 4. The 20", 2000 psi annular preventer was replaced with a 29%",500 psi annular preventer. (This space for Sta~se) // CONDITIONS OF ~P~R~)VAL, IF AI~Y."~ Drillinc June 4, 1980 COMMI See Instructions On Reverse Side Approved Copy Returned Fill L~ne 30"Casing 30" .500 P SI 29 I/2 500PSI Hydril MSP 30" 500PSl 50" 500PSI :50" Casing DIVERTER FOR 26" HOLE EXXON NO. 4 POINT THOMSON UNIT / Flowline NOTES: 1. · Ball valve & Hydril controls to ~e interconnected such that when the Hydril is closed the ball valve is automatically opened. Both gate valves to be in the open position while drilling. Act uator FCameron I0" 150~' I~./ ANSI ball valve. T ~ i0" Line Pipe 3' (To Cleor Subbase) T36"x 32"x 28" Pad Level To Reserv( Pit ~ ~ Opening _ LGate Valve', DIVERTER FOR 17-1/2" HOLE EXXON NO. 4 POINT THOMSON UNIT F~II L,ne 50"Casing ~ J 30" 500PSII 29 112" 500PSl Hydril MSP / Flowline I soo s, I J,, 30" 500PSI J 30" Casing NOTES: 1. Ball valve & Hydril controls to be interconnected such that when the Hydril is closed the ball valve is automatically opened. 2. Both gate valves to be in the open position while drilling. F: 20'3000 ]-~ Weld-on Flange 20 3000 11 II A SECTION 20" Cas,ng ~ 36"X 32"X 28" J Actuator J/cameron g 150 Pit I I // ANSI ball valve, 3'(To Clear Subbase) :J... Pod Level Opening Gate Valve'. J~ATo Burn Pit Condu~or. ~,,,~,o s,-~ STATE(,,.. AJ.A,S~ OIL AND GAS CONSERVATION COMMII-I'EE SUBMIT I1~ 13UPLICATI~. MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS I o,,. ~ G,, ,7"'J o,.,, Wildcat WKLL ~'~LL Exxon Corporation Pouch 6601, Anchorage, Alaska 99502 ~ON OF WEL~ Surface: 2700' NSL & 2900' WEL, Sec. 32, T10N- R22E, UM, North Slope, Alaska BHL (Proposed): 850' SNL & 3860' WEL, Sec. 29, T10N-R22E, UM, North Slope, Alaska CONF!DEN'I'I&t kin' k~mCAL CODE 50--089--20009 LEASE DESiG~A.~ION AN-D SEEIAL NO ADL 47563 IF IND]A~ ALOil-EE OR TRIBE 8 %.~IT F.~RM OR LEASE Point Thomson Unit 9 fv~ NO No. 4 10 ~'~ ~ND ~L OR WILDCAT .Wildcat o~ Sec. 29, T10N-R22E, UM 12 PElt.MIT NO , .79-80 '~ RE~'&RT' TOTAL DEPT%q AT Fled OF MONqTH CHA~N'GF~S IN HOLE SIZE CASlNG A~ C~NG JOBS INCLUDING D~ SET ~ VOL~ US~ P~O~TIONS ~TS ~ ~SUL~ FISHING JO~ JUnK ~ HO~ AND SIDE-~CKED HOLE ~D ~Y O~ SIGNIFIC~T ~G~ ~ HO~ ~ITIONS Spudded well at 2400 hours 4-13-80 w/17½" bit. Drilled to 2170' and ran a BHC~Sonic/Caliper survey. Then opened the hole from 17%" to 26". Set 20" casing at 2127' and cemented with 4000 sacks 14.6 ppg. and 5100 sacks 15.0 ppg. permafrost. Cement circulated to the surface. Drilled a 17%" hole to 3435' and ran the following open hole logs: Dual Induction BHC Sonic Caliper Set 13-3/8" casing at 3422' and cemented with 835 sacks permafrost. Injectivity was established down the 13-3/8" x 20" annulus by injecting 200 barrels of mud at a maximum pressure of 725 psi. At the end of the month we are nippling up BOP stack. %' ~"'~'J~.~,~G=~'°-~°~"''~'~4~/Actg· Ac~'_eage ~nd Well sto~=,~w~-.,.. ~,-,, ~l.)~ =~u~ Evaluation Manager ~,~ May ,,, 12~ 1980. LI I_1 l_ II I II I I I III I I J II I II I '~ I _ I ,1 I II II II mi I NOTE--Report on this form is required for ~ch COlendor ~thj regardMss of f~e etotus of ooerotioflm, O~d must ~ filed in dupllc°le wit~ the oil and gas conservation oommiHfl by the 15~ of the suoc~ding moa~, mien otherwis, d,r4cted. Alaska Oil and Gas Conservation Cc~ion Ho~le H. Hamilton /~~ Lonnie C. Smith /10'~ Petrole~ Ir~r May 13, 1980 Witness B.O.P. E. Test and Ird~0ect location at EX,Oh'S Point ~n No. 4 Well. Sec.32, T10N, R22E, U.M. Pe~t No. 79-80 Thur~, ~ 8,~ .1.989~ After witnessing the C.O.~.O. Meter Proving, Z traveled to Exxon's Point ~n No. 4 Well to witness B.O.P.~.. test. Friday, May 9, !.98..0~ Testing of the B.O.P.E. ca~l~E~ced at 5~30 p.m. this &ate and ~ concl~ 5-10-80 at 5~30 p.m. I f//led out an A.O.G.C.C. Test Report, ~hlch is attached. In ~ I witnessed the successful testing of the B.O.P.E. a~d i~spected the loca~ at Exxgm's Point T~n No. 4 Well. Att~___~~ I ta~ to Dago Toloudis on 5-12-80 in ref~ to the Blir~ P~ms test. The ftttir~ needed to test the Rems to 5000 p~i arrived 5-11-80 and will he /nstalled and Rams tested to 5000 psi. Our office shall he con~ and given the re~alts of the test. Attachment.. Mr. Dago Toloudis, Ex~nn representative, contacted Lonnie Smith on 5-19-80 and informed him that the fitting had been installed ~nd the Blind Rams had been success~ly tested, to 5000 psi. Attad~nts (1) Date A~A~' ~ Inspector D~ ~AWO~ Wel i~xxoM_No. ~ Operator ~;(oA/ ~. ~/o~,~. Representative Wel'l _'~la/_~ T~6~.~ J/o.~ Permit # Location: Sec ~ T/D~RZZ6 M~o _/~%asing Set @ ~.~5 ft. Drilling Contractor ~;~;J~) Rig # /(~ Representative. q~~.'~7.~ '- Location, General Well Sign O~ General Housekeeping Reserve pit ~ Rig ~ BOPE Stack Annular Preventer Pipe Rams ~ , ~ Blind Rams Choke Line Valves H.C.R. Valve Kil'l Line Valves_ Check Valve Test Results: Failures Test Pres sure ~ 000 ~ooo ACCUMULATOR SYSTEM Full Charge Pressure ~0~) psig Pressure After Closure /-f~)~6) psig 200 psig Above Precharge Attained: 0 min~/ sec _ Full Charge Pressure Attained: ~ min ~ sec Controls: Master 69~ Blinds switch cover Remote _Kelly and Floor Safety Valves Upper Kelly--est Pressure Lower Kelly ~ Test Pressure Ball Type {'3~ Test Pressure Inside SOP ~ Test Pressure~ Choke Manifold ~ ~ Test Pressure_5~ No. Valves ~ I Repair or Replacement of failed equipment to be made within days Inspector/Commission office notified. Remarks: ~/../A/O ~;~$ ~/&.~ AJO~ ~6 r~-s/-~/-~ ,to ~ DO~ ~_ CC - Operator ' ~ ~ , ~ cc -Supervisor Inspector ~~ ~ Test Time_. ~--4-- hrs. No. flanges ~ Adjustable Chokes .... / Hydrauically operated choke EXPLORATION DEPARTMENT AI. ASKA/PACl FIC DIVISION November 26, 1979 Re: Exxon Point Thomson Unit No. 4 4 ENG - __ j 3GEOL/ "'/"~TAT'T~-- 'CONFER: FILF~ - Mr. Lonnie C. Smith Chief Petroleum Engineer Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Smith: Attached for your information and files is Sundry Notice amending the Permit to Drill or Deepen Form 10-401 filed with you October 18, 1979. Although triplicate filing is all that you require, we have included four copies of the notice so that you may return to us a signed copy for our files. Yours very truly, RKR: et attachments RECEIVED f'i0V 2 8 lgTg 0il & A DIVISION OF EXXON CORPORATION Form 10-403 REV. 1-10-73 Submit "Intentions" in Triplicate & "Subsequent Reports" in Duplicate STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen Use "APPLICATION FOR PERMIT--~' for such proposals.) Wildcat 2. NAME OF OPERATOR Exxon Corporation 3. ADDRESS OF OPERATOR P. O. Box 2180, Houston, Texas 77001 4. LOCATION OF WELL Atsu,ace 2,700' NSL and 2,900' WEL, Sec. 32, T10N, R22E, U.M. B.H.L. 850' SNL 3860' WEL 13. ELEVATIONS (Show whether DF, RT, GR, etc.) Approx. 8.3 ' G.L. 14. Check Appropriate Box To Indicate Nature of Notice, Re 5. APl NUMERICAL CODE 6. LEASE DESIGNATION AND SERIAL NO. ADL 47563 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 8. UNIT, FARM OR LEASE NAME Point ~n Unit 9. WELL NO. ]~=(on No. 4 10. FIELD AND POOL, OR WILDCAT Wildcat 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) Sec. 29~ R10N~ R22E~ U.M. ].2. PERMIT NO. ~ort, or Other Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF [_...._J PULL OR ALTER CASING L.l.U FRACTURE TREAT MULTIPLE COMPLETE SHOOT OR ACIDIZE ABANDON* REPAIR WELL CHANGE PLANS (Other) SUBSEQUENT REPORT OF: FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE= Report results of multiple completion on Well GomDletlon or Recompletion Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all Dertlnent {letalls, and give Dertinent dates, including estimated date of starting any proposed work. (a) Des±gn for the 2,200' of 20" casing ~ill be as follows: Top 365': 133 #/ft. K-55 Grade, buttress Bottom 1835': 94 #/ft. H-40 Grade, Short threads and collars. (b) Design for the 16,725' of 7" casing will be as follows: 0-12,500 ft. - 32 ~/ft. Pll0* 12,500-16,725 MD - 35 #/ft. Pll0* * Couplings sized to maintain burst rat~. g .of pipe body. Burst safety factor 1.312 Collapse safety factor 1.15 · Max. surface pressure - 9000 psi. · 16 ppg inside and outside of 7". · Collapse based on 0 psi interval pressure. · Burst based on tubing leak near surface. (c) Design (d) Design for Conductor and Surface Hole Diverter Assembly attached. for BOP Stack attached. ~~.~ 16. I hereby certify that the foregoing is true and correct SIGNED ~~~~~--~~~T ITLE DrillingY~nager CONDITIONS OF/~PROVAL, IF .~N~.' ~COMMIS$!ON~ See Instructions On Reverse Side DATE I~pproved ~ I~fiturned 5000 PSI. · ! .... Hyd .ril GK Annular ' Pr.ev. entor -- . . ' · "j- ~. 6 " o. 41-3/4 .o . 28-]'/~ · 66- 3./._4. To Shale Shakers ' Pit i ~.B~utterfly '6" Div rter Lines; 28x32x36 Ref. Surface Hole Diverter Assembly "T" Handle on Rig Floor 20'MspHydril I " ' 11- 'A" Section 1 20" Riser' 20" RK B LEVEL i t Pad ~,eve 1 Conductor Diverter Assembly "T" Handle on 'Rig-Flod~ RKB LEVEL t. To Shale Shakers I · . . · . Wing to Burn' Pit utter ly ' Valv ro Reserve. ! 6" Di erter lines. ! , ~ .. 20" by 30" SQage 8I i t Pad L'evel t~ovenber 29, .1.979 Point Thomson Unit Exxon I~o. 4 Exxon Corporation Permit No. 79-80 Sur. Loc.j 2700' NSL, 2900' ~L, Sec. 32, TION, R22E, UN. Bottomhole Loc.~ 2000* SNL, 3700° ~EL, Sec. 29, T101~, R22~, UH. ~r. Crandall D. ,~ones Manager, Alas.ka/l~aoifto Division · xxon Corporation P. O, BOX 2180 Houston, Texas 77001 Dear Itt. C~andal I l Enclosed is the approved application for per, it to drill the above referenoed well. Wail samples, core chips and a mud log are required. A direc- tional Hrvey ~s required. If available, a tape containing the digit~sed log infor~ation on all logs shall be submitted for copying except experi~ental logs, velocity surveys and dip~eter suz~eys, Many rivers ,in Alaska and their drainage systems have been classified as important for the spawning or migration of anadro~ous fish. Operations in these areas are sub~ect to AS 16.$0.870 and the regulations pr~ulgate~ thereuader (Title 5, Alaska ~in~strative Code). Prior to cosu~encing operations you may be contacted by the Habitat Coo~dinator*s office, Depar~nt of Fish and Pollution of any waters of the State is prohibited by AS 46, Chapter 3, Article 7 and the regulations promulgated thereunder (Title 18, ~laska Adm~nistrative Code, Chapter 70) and by the Federal wate~ Pollution Control ~ct, as a~ended. Prior to Mr. Crandal 1 D. Jones Point Thomson Unit Exxon No. 4 -2- November 29, 1979 coumencing operations you may be contacted by a representative the Department of Environmental Conservation. Pursuant to AS 38.40, Local Hire Under Stake Leases, the Alaska Department of LaJ~r Ks being not~£ied of the ~ssuance of th~s porm~t to drill. To a~d us in scheduling field work, we would appreciate your not~fying this office within 48 hours after the well is spudded. We would also l~ke to ~ notified so ~t a repre- · en~va of ~ c~s,~ mF~ ~ pre~nt to wA tness testing o~ blowout preventer ~uA~nt ~ore surface casAng shoe is drAll~. the event of sus~ension or abandonment, please gLve th~s off,ce adequate advance notA~lcat~ton ac that we may have a tness present, Very truly yOUrS, HOy 1~ H. Halnt 1 ton Chairman of Alaska Oil & Gas Conservation Commission Enclonre cos Departnont o£ Fish & .~ane, Habitat Section w/o encl. Department of Environmental Conservation Department o£ Labor! Supervisor, Labor Law Compliance Div~s~oa w/o encl. / p,~__l?"~ lo x ~o TO ~ iNCh 7 x lo ,NCHeS '.'U"~ 1323 NEUFFEL & ESSER CO MADE IN USA ~ ~00 0 E ( ON COMPANY. U.S.A. POST OFFICE BOX 2180. HOUSTON, TEXAS 77001 EXPi. ORATION DEPARTMENT AI. ASI~A/PACIFIC DIVISION CRANDAI. I. D. JONI~S MANAGI~R October 18, 1979 Point Thomson Unit No. 4 Section 29, TION, R22E, UM ADL 47563 Arctic Slope, Alaska Mr. Hoyle H. Hamilton Chairman, Alaska Oil and Gas Conservation Commission State of Alaska 3001 Porcupine Drive Anchorage, Alaska 99504 Dear Mr. Hamilton' Exxon Corporation submits the following in regard to the captioned well: (1) State of Alaska, Oil and Gas Conservation Committee Permit to Drill, Form 10-401, in triplicate with triplicate copies of the location plat and contingency plan. (2) Exxon Check No. FC 50998, dated October 18, 1979, in the amount of $100.00 in payment of the required permit fee. Concurrently with this application, we are filing with the State Division of Energy and Minerals Management the following' (1) A plan of operation describing the drilling pad, rig, supply, waste and sewage disposal, and pollution prevention. (2) Vicinity and location plats. It is our plan to commence work in mid December, 1979; the drilling rig is to be on location and drilling operations commenced in mid February, 1980, and will be completed in five to six months. An application dated October 18, 1979 was submitted to the U. S. Army Corps of Engineers to conduct operations in the navigable waters of the Beaufort Sea for the drilling of Well No. 4. Sincerely, RECEIVED c: EPA Region X-Attention: Mr. Danford G. Bodien, P. E A DIVISION OF EXXON CO~PO~ATIO~ · · U. S. CORDS O~ Engineers -Attention' Lt Colonel Lee COMPANY, U.S.A. POST OFFICE BOX 2180 · HOUSTON, TEXAS 77001 EXPLORATION DEPARTMENT ALASKA/PACIFIC DIVISION CRANDAI. I. D. JONES MANAGER October 18, 1979 Third Plan of Further Development and Operation Point Thomson Unit Arctic Slope, Alaska Mr. Thomas Cook Director, Division of Minerals and Energy Management 323 East Fourth Avenue Anchorage, Alaska 99501 Dear Mr. Cook' Exxon Corporation as Unit Operator by letter dated November 18, 1977 filed an application with the Director, Division of Minerals and Energy Management, for approval of a Plan of Further Development and Operation for the Point Thomson Unit, consisting of operations for drilling and testing the proposed Point Thomson Unit No. 2 well. By letter dated May 25, 1978, the Director approved such Plan until January 1, 1979, at which time another Plan was to be due. This Plan was complied with by the drilling and testing of the No. 2. well, which was suspended on August 12, 1978. On January 12, 1978, Exxon Corporation, as Unit Operator, filed an application with the State Oil and Gas Conservation Committee for a Permit to Drill the proposed Point Thomson Unit No. 3 well, and on the same date a lease Plan of Operations with various exhibits was filed with the Director, Division of Minerals and Energy Management. On March 9, 1978, your Division approved the Plan, as amended under your reference, LO/NS 78-6, and on July 13, 1978, the Oil and Gas Conservation Committee issued the Permit to Drill. This plan was complied with by the drilling and testing of Well No. 3. Operations were concluded with the removal of miscellaneous drilling equipment July 21, 1979. A second Plan of Further Development and Operation dated September 13, 1978 was filed and subsequently approved October 9, 1978 for the period until January 1, 1980. Article 10 of the Point Thomson Unit Agreement provides in part that from time to time before the expiration of any existing Plan of Further Development and Operation, the Unit Operator shall submit for the approval of the Director a Plan for an additional specified period for the development and operation of the unitized land. Exxon Corporation, as Unit Operator of the Point Thomson Unit, hereby requests that you consider the enclosed Plan of Operations, as its proposed Third Plan of Further Development and Operation specified in said Article 10, suc~"~, upon approval by ..,v,s,. Mr. Thomas Cook October 18, 1979 you to constitute the further drilling and operating obligations of the Unit Operator under the Unit Agreement from the date of its approval by you until January 1, 1981, at which time another Plan shall be due. Sincerely, OCR:cb EXXON CORPORATION Unit Ope..rator Crandali D. Jones Enclosure Form 10=401 REV' SUBMIT IN TRIP4'~ (Other mstruct)on~; reverae s~de) STATE OF ALASKA ?,, OIL AND GAS CONSERVATION COMMITTEE PERMIT TO DRILL OR DEEPEN 1L TYPE OF WORk DRILL b TYPE OF WELL OIL GAS WELL ,g ~'ELL g 2. NAME OF OPERATOR 77001 ~ER DEEPEN F'l ~:k~ Oil & Gas Gons. bom,ms~ SINGLE Exxon Corporation 3 ADDRESS OF OPERATOR P. O. Box 2180, Houston, Texas 4. LOCATION OF WELL At surface 2,700' NSL and 2,900' WEL, Sec. A, p.o,o..d ~oa ,on, (BHL: 2000' SNL and 3,700' WEL, Sec...29, TION, 13 DISTANCE IN MILES AND DIRECTION FROM NEAREST TOWN OR POST OFFICE* 45 miles East of Deadhorse, Alaska 32, TION, R22E, U.M. 850'SNL 3860'WEL) R22E, U.M. E API #50-089-20009 6 LEASE DESIGNATION AND SERIAL NO ADL 47563 7 IF IN'DIA~, ALLOTTEE OR TRIBE NAME 8 UNIT FARM OR LEASE hAME Point Thomson Unit 9 WELL NO Exxon No. 4 10 FIELD AND POOL, OR WILDCAT Wildcat 11 SEC., T , R. M . (BO]-FOM HOLE OBJECTIVE) Sec. 29, TION, R22E, U.M. 14 BOND INFORMATION ~Oil & Gas Conserv. ation ~urety srm/or No 15. DISTANCE FROM PROPOSED * LOCATION TO NEAREST PROPERTY OR LEASE LINE, Fr. (Also to n~atcsl dng umt ~f any) 850' SNL of Lease (BHL) 18 DISTANCE FROM PROPOSED LOCATION TO NEAREST V,'ELL DRILLING, COMPLETED, OR APPLIED FOR, FT Approx. 13,200' West of Exxon 21 ELEVATIONS (Sho~ whether DF, RT, CR. etc.) Approx. 8,3' G.L. 5134049 State Bond Fi l~_ R-1-4 16 No OF ACRES IN LEASE 2560(each lease) l 9 PROPOSED DEPTH 14,470' TVD #2 Pt. Tho son . 16,725' MD. TO THIS WELL 20 ROTARY OR CABLE TOOLS Ro ta ry 22 APPROX DATE WORK WILL START Location :12-15-79 Spud '3-1-80 23 PROPOSED CASING AND CEMENTING PROGRAM SIZE OF HOLE 'SIZE OF CASING { WEIGHT PER FOOT GRADE ] SETTING DEPTH Quant. y of cement 40" 36"x32"x2~ Insulated/Re~rigera]~ed 85' To Surface. 26" .. 20" 94 .H-40 2.~200' To Surface. ,, ~ !..7-1/2" 13-3/8" 72 N-80 3.,400' (see"Subsurface InjeCtion'' below., 12-1/4" 9-5/8" 47 Soo95 +__12,000' . Approx. TOC @ 7~000' 8-1/2" 7" 32/35.. PllO +_ 16,725' 500' above potential hydrocarbon zone Subsurface Injection: It is planned to drill the 26" hole to 2,200' (below predicted permaforst) and cement 20" casing to surface with permafrost cement. 17-1/2" hole will then be drilled to 3,400'. A 13-3/8" string of casing with FO cementing tools at 2,700' and 2,550' will be run to 3,400' and cemented with top bf cement at approximately 2,700'. Sands between 2,200' and 2,700' will provide a wastewater injection zone. While drilling the 12-1/4" hole for 9-5/8" casing, wastewater and other surplus fluids will be injected into these sands through the 20" x 13-3/8" annulus. Before the 9-5/8" casing is run into the hole, a second stage cement job will seal the 13-3/8" casing to surface with permafrost cement. It is planned to set the 9-5/8" casing into the pressure transition ~ IN ABO%~E SPACE DEgCR/BE' Ia~DPOSED PROGRAM If pro~ u ~o d~en ~ve ~ta on presem producUvc zone and pro~s~ '~'- ~ produc~ve zone If pto~ ~ to ~ o~ dee~n ~o~)', ~ve ~ment dau on sub.face Io~t~ons ~d m~sur~ ~d ~ue m~~~[~~~~ ~A~ October 18, 1979 ~~,MaD~g~r~ Alaska/Pacific, Cranoal ~ h_ ,lon~.s [, .j '" .)a),IVl~ion ., for State off~cg use) J~O~A~ s~Y MUD LOG A.P.I ~RICAL CODE PERMIT NO. ~n on APPROVALDATE APPOVED BY TITLE f' h a '{ wm", *See Instruction Off Reverse Side DATE 11 29 79' INSTRUCTIONS General: A filing fee of $100.00 must accompany application for permit to drill or deepen. Checks shall be made out to State of Alaska Department of Revenue. This form is designed for submitting proposals to perform certain well operations, as indicated, on all typess of lands and leases for appropriate action by the State agency, pursuant to applicable State laws and regulations. Any necessary special instructions concerning the use of this form either are shown below or may be obtained from the Division of Oil and Gas. ITEM 1' Use this form, with appropriate notations, if the proposal is to redrill to the same reservoir at a different subsurface location or redrill to a new reservoir. ITEM 13: Attach hereto a neat, accurate plat or map, drawn to scale, showing the site or proposed site for this location, distances from section, distances from section line, lease line, if any, and other information that is pertinent. Refer to Section 51,050 of Oil and Gas Regulations. ITEM 14: Enclose drilling bond on Form 10-402 with this application for permit to drill, or deepen, unless covere-_ - other suitable bond. ITEM 15 and 18: If well is to be, or had been directionally drilled, use subsurface location of hole in any present or objective productive zone. Subsurface Injection (continued)' zone and provide for wastewater disposal into saltwater sands projected to occur between the 13-3/8" casing shoe at 3,400' and the planned 7,000' TOC for the 9-5/8" casing. Blowout Preventers: A 20" annular blowout preventer with a diverter line 'will be installed on the insulated conductor; the diverter will be removed while opening the 17-1/2" hole to 26" to 2,200' The same diverter system will be used on the 20" conductor. A 1~-5/8", 5,000 psi WP annula'r, BOP and three 1_'3-5/8", 10,000 psi 'WP ram type. preventers will be installed on the 13-3/8" casing and will be usea through well testing. BOP installation and testing will be in accordance with Exxon standards, which require pressure testing on initial installation, when any component is changed, and at least once weekly thereafter; all BOP's will be function tested each trip. Drilling crew proficiency tests of well shut-in procedures will be conducted at least once each week with each crew. Point Thomson No. 4 WELLBORE SKETCH Injection Interval ;."lYf Permafrost Cement -'L"~ to Surface ' -'!4~)35" x 32" x 28" !.*'.[ Insulated Conductor ~.i~ 9 85' i~,[ Permafrost Cement j!~ to Surface ~ 20" Conductor 2200' FO Cementer (a 2SS0' FO Cementer ~ TOC 0 Approxtnmtely 2700' Pe~frost C~nent 13-3/B" Surface Casing ~m 3400' 12-1/4" Hole for 9-5/8" Casing Injection tn 13-3/B' x 20" Annulus Permafrost Cement Befto°rSeU~;ef~:ng 9-5/8" Casing 12-1/4" Hole for 9-5/8" Castng ~ Setting Depth Second Stage Cementing of 20" x 13-3/8" Annulus Wel lbore Sketch ell) Before Testing Injection Interval TOC l) Approx. 7000' g-S/B' Protective Casing ~ * 12,000' TOC SO0' above Hydrocarbon Bone 7" Production Castng ~ 16,725' COMPANY, U.S.A. POST OFFICE BOX 2180- HOUSTON, TEXAS 77001 EXPLORATION DEPARTMENT ALASKA/PACIFIC DIVISION CRANDAI..L.. D. ,JONES MANAGIn'R October 18, 1979 Point Thomson Unit No. 4 Section 29, TION, R22E, U. M. ADL 47563 Arctic Slope, Alaska Mr. Tom C. Cook Director, Division of Minerals and Energy Management Department of Natural Resources State of Alaska 323 East 4th Avenue Anchorage, Alaska 99501 Dear Mr. Cook' Exxon Corporation filed an application with the Alaska Oil and Gas Conservation Commission for a permit to drill the subject well together with our check in the amount of $100.00 in payment of the required permit fee. It will be drilled as a directional sidetrack to a bottom hole location on the same lease, ADL 47563. Additionally, and in accordance with the requirements of the subject oil and gas lease and applicable regulations, we submit the following- (1) A plan of operations describing the drilling pad, rig supply, water supply, waste and sewage disposal and pollution prevention. (2) Plats showing the location and vicinity of the pad and well. scale 1"=1 mile. Exhibit A - Location and area topography plat showing pad layout. Exxon No. 4. Point Thomson Unit, scale 1":2000'. Exhibit B - Ice Road and Rolligon Haul Route. As stated herein, it is our plan, State approval permitting, to commence initial operations about mid December, 1979; rig move in and actual drilling operations are to be commenced in mid February, 1980, and conclude five to six months later, and the rig removed the following,winter. OCR:cb Enclosures Sincerely, A DIVISI E ON CORPO TI · p c: o~)~ ~eg~on ~-~r. Danford .G, Bod~en~ . E Alaska Oil & Gas Conservadon_bommlssion'-~r~Ko Hoyle ~f Hamilton U. S. Corps of Engineers-Lt. Colonel lee munn, , Point Gordon AS STAKE D POINT THOMSON UNIT No. 4 LAT. : 70° 10'40 52" LONG :146036' 33 61" X: 424,$17 Y :5,914,985 ELEV = 8 $' Point Hopson 26 36 SCALE. I" ' = I MILE(5250) CERTIFICATE OF SURVEYOR I hereby certify that lam properly registered and licensed to practice lend surveying in the State of Alaska and that th~s plat represents a location survey made by me or under my supervision, and that all dimensions and other details ore correct. Date Surveyor iii AS STAKED POINT THOMSON UNIT No. 4 Located in _ NE I/4 SEC $2,TION, R22E~.UM~AK. Surveyed for EXXON COMPANY U.S.A i i Surveyed by F.M. LIN DSEY t~ ,,ASSOC. LAND ~ HYDROGRAPHIC SURVEYORS 2502 West Northern Lights Boulevard Box 4-08 Anchoraqe Alaskc PLAN OF OPERATIONS POINT THOMSON UNIT, EXXON NO. 4 Surface Location: 2700' NSL and 2900' WEL Section 32, TION, R22E UPM, North Slope, Alaska Bottom Hole Location: 850' SNL and 3860' WEL Section 29, TION, R22E UPM, North Slope, Alaska Attached Exhibits show the following: Local and area topography around location (Exhibit A). Planned winter access roads which are to be constructed and gravel sources (Exhibit B). Proposed location layout including well position, reserve pit, sanitary waste pits, burning pit, and fuel storage area (Exhibit A). Location and type of water supply (Exhibit A). Natural Environment The proposed drilling location shown on the attached Exhibit A lies approxi- mately three miles west of Point Thomson Unit Exxon No. 2 and is situated 800 feet inland from the Beaufort Sea coastline. The surrounding terrain is low lying coastal plain with mud flats and scattered small lakes. Surface vege- tation is typical tundra with mosses, lichens, grasses, and sedges being most dominant. Elevation of the proposed drill site is approximately 8.3 feet above sea level. The proposed well is in the continuous permafrost zone of Northern Alaska where the depth of permafrost is approximately 1,600 feet and the active surface layer or thaw zone is from one to' three feet. Since the ground cover acts as insulation limiting the depth of the active layer, removal or damage to the ground cover especially in areas of any appreciable slope is a major factor in causing erosion. Consequently, every possible effort will be made to protect the surface from unnecessary damage. There are no established roads, airstrips, housing, or other facilities in the area and, because of the fragile nature of the terrain, heavy vehicular traffic can operate only during the winter season while the ground, streams, and lakes are frozen. Prudhoe-Deadhorse, located approximately 41 miles west of the location, is the nearest staging area and airstrip with facilities for handling cargo and housing personnel. Page 2 Arctic climatic conditions include relatively cold temperatures year round. Strong winds, small annual precipitation, and visibility strongly influenced by the combination of winds and coastal sea ice condition are factors con- tributing to an extremely harsh environment. Temperatures vary from a high in the 40 to 60°F range in the summer to a low of -50 to -60°F in the winter which, with the chill factor, may reach -lO0°F or lower depending on the severity of winds. Surface winds are predominantly from the east at an average velocity of 12 miles per hour along the coast with a velocity range of 35 to 50 mph associated with winter storms. Total annual precipitation is in the range of 4 to 6 inches which includes 12 to 48 inches of snowfall. Various species of wildlife exist in the area. During the winter months, when the major part of activities are planned, wolves, wolverines, foxes, polar bears, and caribou may be present. Bird life is limited primarily to the raven and ptarmigan, with waterfowl and most other birds having migrated from the area for the winter. Construction and Operating Plan A 78 man camp owned by Exxon will be used with Loffland Rig No. 162 in the drilling of Point Thomson Unit Exxon No. 4. The camp and rig are presently located at Point Thomson Unit Exxon No. 3 site, 8-1/2 miles east of the proposed location. Location work will be started in mid-December 1979, contingent upon State and Federal approval, provided freeze-up is sufficient to facilitate movement of heavy equipment to the location using Rolligons. It is planned to move the rubber-tired vehicles over the Rolligon road after a suitable route has been established. The tentative Rolligon route is shown on Exhibit B. It is cur- rently planned to utilize a self-sustaining construction camp until Exxon's camp at Point Thomson Exxon No. 3 can be moved and activited to provide housing during the construction of the drill site. After completion of the location, the drill rig will be moved in. In order to protect personnel during the latter move, it may be necessary to utilize the self-sustaining camp unit. Also it is anticipated that for operation during this period, emergency shelters may be provided along the overland route. The sequence of moving camp and equipment to the area should be as follows' * Lay out road route with an empty Rolligon at earliest possible time. * Activate the self-sustaining camp site at Exxon No. 4 Point Thomson Unit. * Construct ice roads for water and gravel haul. * Move in earthmoving equip~:,~ ~,~ ~ Page 3 * Commence pad construction. * Move in the Exxon camp at suitable time thereafter. * Move in additional earthmoving equipment (if required) and finish pad. * Move rig. * Water trucks will be used to complete and maintain haul roads during construction operations. The Point Thomson Unit Exxon No. 4 location shown in Exhibit A will be approximately 730' x 710' overall and, with a five foot gravel pad, will require approximately 60,000 cubic yards of gravel. The proposed gravel source is from gravel bars in the vicinity of Sections 4 and 5, T9N, R22E, UPM, Sections 32 and 33, TION, R22E, UPM, Sections 3, 10 and 11, T9N, R21E, UPM, and Sections 11, 14, 23, 25, 26 and 36, T9N, R2OE, UPM. In addition it may be necessary to reclaim gravel from the drill site of Point Thomson Unit, Exxon No. 2 located in Section 3, T9N, R22E, UPM. Locations are shown on Exhibit B. Gravel removal and hauling will be accomplished using rubber-tired loaders and belly-dumps for direct movement; however, when necessary, the gravel will be placed in piles for convenient loading. Movement will be over sea ice roads along the coast and ice roads constructed of snow and water to protect the existing land surface. Only the exposed gravel deposits above the water line will be removed to ensure that no holes remain at the borrow area which could cause fish or animal entrapment after spring flooding. The planned drilling location will accommodate the rig and equipment, camp, and support facilities. The site is to be overlain with sufficient gravel to act as an insulation barrier to prevent thawing of the permafrost during summer operations. Wooden matting will be used under the drilling rig and mud pumps for stability and as a further aid in preventing permafrost degradation. All pits are to be diked. A 190' x 190' x 10' deep reserve pit will be used to retain cuttings, excess drilling fluid, and drainage around the rig. The level in this pit will be kept as low as possible to prevent migration of fluids and provide capacity in case of an emergency such as a severe well control problem. The well will be designed for annular injection which will permit subsurface disposal of wash and melt water, excess drilling fluid, and well test liquids. A 60' x 60' x 6' deep burning pit will be located a safe distance from the rig to permit emergency burning of hydrocarbon test liquids. Fuel storage will be approximately 300,000 gallons in welded steel tanks located within a 60' x 130' x 6' deep, plastic lined pit area. All excavated topsoil or tundra from the pits will be stockpiled at an accessible site adjacent to the location in order that the pits may be restored as nearly as possible to the original condition at the time of back-fill and clean-up operations as required by a~able regulations. Page 4 An ice landing strip approximately 2,000 feet long will be constructed with snow and water to provide air transportation during winter operations. Helicopters will be the primary mode of transportation during summer operations. The Loffland Rig 162 will be moved in as soon as pad is ready from Point Thomson Unit Exxon No. 3 over an ice road. Actual drilling and evaluation operations will require six to seven months and plans are to stockpile materials and supplies to permit operation after breakup. After completion of the well, the rig may be left on location until the following winter. Major supplies of mud, cement, casing, fuel, and miscellaneous drilling supplies will be transported to the location and stockpiled before spring breakup. If bulky equipment must be delivered on short notice or large shipments can be accumulated, an ocean ice landing strip off the coast for Hercules aircraft may be constructed. After breakup, personnel and light consumables will be transported by helicopters or other State approved means. All support equipment not required for summer operations will be moved out before breakup. C_amp Facilities An Exxon owned 78 man camp for rig personnel will be moved in from Point Thomson Unit Exxon No. 3. Sewage and gray water from the kitchen and shower areas will be discharged in separate lines and will be introduced into an approved waste disposal unit installed at the site. Sewage, water, and garbage use and disposition will be as follows: 1. Sewage Disposal A Steel Fabricators, Inc. biological sewage disposal unit, owned by Exxon, which complies with the requirements of the State of Alaska and the EPA for water quality in the area of operation will be installed. A 75' x 60' x 10' deep sanitary waste pit is provided for the treated liquids discharge. Also, a 25' x 60' x 10' holding pit is planned to allow diverting the unit discharge in the event of a treating plant upset. 2. Water_Suppl~ Potable water for the camp facilities will be hauled from small lakes near the rig and a large, eight-foot deep lake in Sections 22 and 23, T9N, R23E, UPM, approximately nine miles east-southeast of the location. A snow melter will be used to supplement the rig requirements until shallow lakes closer to the rig thaw in the summer. The water will be processed through a Steel Fabricators, Inc. water treating unit before use in the camp. Additionally, gray water from the camp will be used for mud and rig wash water. Page 5 e Garba.ge and Waste Disposal Burnable garbage and wastes will be disposed of in a McNaulin- Goder Model-1510 trash incinerator unit. Some of the more readily combustible products, such as paper, wood, and cardboard, may also be open burned. Noncombustible wastes, such as scrap metal, tires, batteries, and drums, will be hauled to Deadhorse and final disposal will be in accordance with State Waste Management requirements. Development Plans If oil is discovered in sufficient quantities to warrant future development, the Prudhoe Bay to Valdez oil pipeline will be the probable marketing outlet from the area. Oil and casinghead gas would be processed through central oil gathering facilities with oil being pipelined to the Trans-Alaska line passing approximately 41 miles to the west. If commercial quantities of gas are discovered, development of a gas market outlet will be related to studies to market gas from the Prudhoe area. Surface Protection and Restoration Plan As previously mentioned, precautions will be taken to protect the surface by not beginning operations until after freeze-up and by using snow and ice roads during winter. At the completion of the well, the location and adjoining area will be cleared of all waste materials. All pits will be backfilled and leveled. Special procedures for drilling and subsurface equipment are required by the unique characteristics of the permafrost area. Casing cement used through the permafrost zones is of special composition to reduce possibility of freezing and other casing problems. Casing is run and cemented through the permafrost, and in the event of production or interruption of operation, the uncemented casing must be protected by the use of non-freezing fluid. TLP: JGW: et 10/24/79 CONTINGENCY PLAN POINT THOMSON UNIT EXXON NO. ~omrnJsslor~ The objective of this plan is to list major operating and contingency requirements to ensure a safe and efficient operation throughout the drilling activity. The location has been designed to provide containment of any drilling operation effluents that could be considered as pollutants. The 190' x 190' x 10' deep reserve pit will receive and contain all drill cuttings, excess mud material, wash and drain water from around the rig, and have the capacity for use in the event of a severe well control problem. Sewage and kitchen waste water will be processed through a Steel Fabricators, Inc. biological treating system with excess sludge being incinerated and the disinfected liquid contained in a sanitary waste pit; a separate sanitary holding pit is provided to divert the treating plant effluent in the event of a system malfunction. A burning pit is located clear of the rig to permit flaring of gas during production testing. The burning pit may also be used for the open burning of wood, paper, and other burnable trash, and for the burning of well fluids in emergencies. Production test fluids will normally be produced to tanks and disposed of by subsurface injection. All fuel will be stored in steel tanks; primary fuel tanks will be located in a plastic membrane lined fuel storage area. An important feature of the drilling plan is the provision of annular injection capability for subsurface injection of waste fluids. Two injection zones will be provided as follows. After setting and cementing the 20-inch conductor at 2200 feet (below the permafrost zone) 17-1/2-inch surface hole will be drilled to 3400 feet and 13-3/8-inch casing set and cemented back to about 2700 feet. The interval from 2200 to 2700 feet will then be available for injection while the 12-1/4-inch intermediate hole is drilled to the expected pressure transition zone of about 12,000 feet. Prior to setting intermediate casing the 13-3/8 x 20 inch annulus will be cemented through full opening sleeves at 2550 or 2700 feet. After the 9-5/8-inch intermediate casing is set and cemented back to about 7000 feet, the interval from 3400 to 7000 feet will be used for injection for the duration of drilling. Excess mud, well waste waters and collected well test fluids will be injected in the zones provided. Liquid levels in the sanitary waste pit, sanitary holding pit, and burning pit will be maintained below ground level after breakup to prevent migration of any liquid out of the pits. The reserve pit will be maintained at a minimum level at all times to provide for containment of well fluids in the event of an upset. All pits will be pumped out to a minimum level and waste water injected into the injection zone before abandoning the location. The entire operation is planned so that no fluids associated with the operation will be discharged on the surface outside the location. The drilling contractor will be required to develop a comprehensive SPCC Plan to prevent pollution as a result of any drilling rig operations. In addition to drip pans under the engines and rig machinery, the rig area will be located within a drainage system to direct any rig waste into the reserve pit. All oils, greases, and chemicals are to be stored within the rig drainage area. Good housekeeping will be stressed on all parts of the~o~ation with emphasis on minimizing contamination of the peripheral draina~ e~m~'he.~oa~. Any minor spill of oil will be collected using sorbent material for'~i~~l~. incinerator. Page 2 Personnel safety and well control are the uppermost factors in well design and operational planning. Sufficient data are available to plan the well for evaluation of the geologic objectives, provide for subsurface disposal of waste water, and conduct a safe drilling operation. Advanced abnormal pressure technology will be used to predict and detect changes in formation pressure to permit adjusting the casing and drilling fluid program to control the well. Emphasis will be placed on well control equipment and procedures to permit circulating out a formation "kick" in an orderly manner if it should be necessary and any hydrocarbons in the influx will be diverted to the burning bit and burned. In the event of an unplanned upset resulting in uncontrolled well flow, the following basic procedures will be followed' le Divert flow to burning pit as the first defense against a spill. Switch the flow to the reserve pit when the safe working level is approached in the burning pit. The design capacity of the reserve pit is 64,000 barrels which will be maintained at a maximum, practical working capacity at all times by keeping mud and fluids use at a minimum and pumping fluids into the annular injection well whenever possible. 2. Prepare plans for drilling a relief well from an alternate location. 3, The well will be ignited, if the situation warrants, only after discussion with proper governmental agencies and Exxon management. Major supplies of mud, cement, casing, fuel, and miscellaneous supplies will be transported over winter roads or flown directly to location. After breakup, light consumables will be transported by helicopter or other State approved means. A Rolligon will be on location for any local movement of water or fuel as permitted by 1 and conditions. A Catastrophe Organization consisting of specifically designated personnel will be activated to cope with an emergency such as an out-of-control drilling well. The Drilling Section of the Catastrophe Organization is responsible for performing the well control function which includes all surface well control procedures as well as plans for a relief well. Immediate action will be taken to minimize environmental damage and institute cleanup operations. The basic relief well plan involves construction of another surface location approximately 3,000 feet west of the original well's surface location. The most likely time for a severe well control problem to develop would be before May, prior to setting 9-5/8-inch protection casing, which would allow sufficient time to construct the location and spud the relief well before breakup. The planned relief well location would permit the relief wellbore to penetrate the flowing zone near the out-of-control well with a 7,000 foot or less horizontal displace- ment. In the event insufficient time is available to initiate the relief well, a rig could be mobilized using barges after breakup to drill a relief well. Both relief well plans are predicated on emergency approval of all phases of the operation by all state and federal regulatory agencies, i~,~ ~-~ ~ TLP: JGW: et 10/24/79 ivl~oway Islands t D~nkum Sands Narwhal I /J"/C C~/~,/.G Jeanette I APPROX ICE ROAD Karluk I Pole I Stockton Islands Lmn Pt PoLe Belveder~ Island Challenge I I Alaska I Duchess I North Star I Lookout e wo, oso~'~ '*% /'~'/c¢/z d T~amak Island ~ a g u i r e Isl a n d s ~ *'.. " EXXON No 3 P% THOMSON %0 '' ..... . ............ . ~ Reha~e m UNIT ee Prego VAB~ ~'~ ~.. · ..... ... · I · · · · ~- Z~ Pt "-...... : '"" I ~ ' ~ ]/ 1 ~ d~ ' ""~""" ,',Well ''*.._ P, no0 ~ P,.... I *. ...... ~,~ .S ..~ - - - ' V~B. ,. I~T T~MSON UNIT _ - 0~. ~2" ', ~,n~os , . ~_.' ~o - ~ EXXON No.g , ' '"" ...... '~...~.~"J ..,,;..,""~" ~ APPROX ROLL IGON - ,, ~' ~ , I . ' HAUL ROAD ~ J ze I ' ' ' , , REVISED ~C R 10-15-7. ,,,,~ J ~ t ~. REVISED ,G S 79i , · ~ " " PROPOSED ~ ~ ,' ' c ,~ J ICE ROAD & ROLLIGON HAUL ~ ,'~ EXXON COMPANY U.S.A ~ -,> LEGEND ' : · 0 POSSIBLE GRAVEL SOURCE BY . { ' ~, SCALE ~,Z50,~O EM LINDSEY & ~~C ln,lectton Interval ~'.~Y~ Per. frost C~ent · 'L"'~ to Surface gt~l~i~ 36' x 32" x ~8" ~;~ Insulated Conductor ;,'J Pe~fmst C~nt ~.J ~ Surface ~" Co~uc~r FO C~enter ~ 2550' ~ C~enter e 2700' ~C e AppmxJ~tely 2700' Pe~frost C~ent 13-3/8" Surface Casing e ~00' 12-1/4" Hole for 9-5/8" Casing Injection tn 13-3/8" x 20" Annulus Point Thomson No. 4 WELLBORE SKETCH Permfrost Ce~nt to Surface Before Setting 9-5/8" Casing 12-1/4" Hole for g-S/B" Casing e Setting Depth Second Stage Cementing of 20" x 13-3/8" Annulus Wel lbore Sketch eTD Before Testing Injection Interval TOC e Approx. 7000' 9-5/8" Protective C&stng ~ t 12,000' TOC 500' above Hydrocmrbon Bone 7" Production Casing ! 16,725' F~e/ CR-13 ~/7~ CASIhG CASIhG Si DE Bottom Top CASING A':~ ~JBII,3 EZ£TGN "~ -~ P?~£S. ~ ?£SIST. ~/ z~ -tcp cf STP£'S2~ ,. %~/0 27 scczion Ti"SiO>[ bozto~ tension lbs lYs ZOO0 its PP£SSU72 !~_ L' l _-2LD LSl . I~0oo o /~ ~bo~¥~ o ? Foraulae - Collapse resistance in tension = X (Collapse pressure ratify) ~urst Pressure = ~? + Depth ( Hyd. Gr. II --.5) BF (Bouyancy Factor) = ~.oo - (o.o~53 x Xua w~. z) Ca!culat~ons: To%al Ccst F C~-~ OR-13 FiElD C;~qI!;G A>~ TUBIhJ E:£IGN 2ASthG · CASING SIZE -- ~O' YCL2 SiZE ~ttom Tcp Wt. Grade ~r. raad lbs STAT2_ __ D:--~E /~) - Z (. '7 $ DESIGN BY · ~?fD GR. i O,~'~2/~__ k%-3 W?. II ~'/~. :~VD. GR. II ~TSiON ~ ~'7~%~4 ~F C0iL~SE C0/L~3SE CDP E.~Z? -top of S5'P~[:G~4 ?PSSS. ~ IfS!ST. PP~SSU~ scctzcn TE -SION bottom tc"s~on lbs lOGO ILs ~s~ rs~ vsI YT2LD -~ // · J'20 0/I oo 2&7o I,.3'7_ 17oo 1~3o_ I: 39 Y=Tens:le L.o~d/P~pe Yield Strength C0 2 I 6 a _ :_ '-' .,, __-. ~,0 ~' ,-I", t ,' i:'l,'l: ', '- I I :~ ';- I ],,I',',t /i i - -F'- ~.:-I.. i-. oJ , :-' ' I '", ',' I /-'1 :, - -1'-'1 ' ' :'l I I'- I_. ,-.._.' ' _ _'' " ,' , - ,- I - ; I . "/ - ;'., ] .~,- ,~. , .... .,/_, ,_,,.l ,~ - - - ~ , ' I , , C ' I ' ~ '~ 'I' -' .... ~,.~--: , :-'--:! '. ' ,-t/: i ' I,':'1, i r,-;i .-:':--',:-~.- U~-' ::' ',T-,T:.- !' "-: ~_i t I',i'~~ I::~"',: t :,.t-. , ~ornulae: Collapse resistance in tension = X (Collapse pressure retire) ~urst Pressure = ~P + Depth ( }{yd. Gr. II ---5) AF (Bouyancy Factor) = z.oo - (o.oz53 x ~,~ua wt. z) Calculations: CHECK LIST FOR NEW WELL PER~LFTS 1. Is the permit fee attached .......................................... 10. 2. Is well to be located in a defined pool ............................. 3. Is a registered surveyplat attached ...... ~ ~ ~e'il .... i ........... 4. Is ~11 located proper distance f~cm pr~~~ 1 ....... 5. Is well located proper distance fr~ other w~lls .................... ~v / Is sufficient underdicated acreage available in this pool ........... 6. ~ well to be deviated .............................................. Is operator the only affected party ................................. / 9. Can permit be approved before ten-day wait.... ........ ....''''''' .... Does operator haves bond in force ........ --..-- .............. · Is a conse~tion order needed ...................................... , , 12. Is administrative approval needed ................................... 13. Is conductor string provided ........................................ 14. Is enough cement used to circulate on conductor and surface ......... ~1 cement tie in surface and intermediate or production strings ... 16. Will cement cover all known ~roductive horizons ..................... O~pany Yes No Re~arks Item Approve Date (1) Fee ~"~,.. ! 17. Will surface casing protect fresh water zones ....................... ;;ill all casing give adequate safety in collapse, tension and burst. Does BOPE have sufficient pressure rating - Test to /-~o psig . Approval Recked: 18. 19. Additional Requirements: Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. 't1' 00000o, 11 0o0000 1111 O0 O0 1111 O0 O0 11 O0 0000 11 O0 0000 11 O0 O0 O0 11 O0 O0 O0 11 0000 O0 11 0000 O0 I1 O0 O0 11 O0 O0 111111 0000oo 111111 000000 77777777'77 7777777777 77 77 77 77 77 77 ;7 77 77 77 77 77 000000 000000~' O0 O0 O0 O0 O0 000o O0 0000 O0 Oo O0 O0 O0 O0 0000 oo 0000 O0 O0 O0 O0 O0 000o00 000000 7777777777 1777777777 77 77 77 77 77 77 77 77 77 77 77 17 666666 11 666666 1i 66 1111 66 1111 66 11 66 11 66666666 11 66666666 66 bb 66 66 11 66 66 66 66 666666 llllll 666666 111111 000000 0o0000 O0 oo O0 OO O0 0000 O0 0000 O0 O0 O0 O0 O0 O0 0000 O0 0000 oo O0 OO O0 O0 000000 000000 000000 000000 O0 oo O0 O0 O0 0000 O0 0000 oo O0 O0 O0 O0 O0 0000 O0 0000 O0 O0 O0 O0 O0 000000 00o000 44 44 44 44 44 44 44 44 44 44 44 44 4444444444 4444444444 44 44 44 44 44 44 CCCC M iv) CCCC PPPP tqRF~R C M~ M~4 C P P P, R C M ~ ~ C P P R R C M M C ..... PPPP RRRR C M M C p Ft R C ~i M C P lq iq CCCC M ~ CCCC P R R *START* USLR PCAL [10707,61004] dOB MONITOR $w8 ~LIOE40 SEP-80. *START* *START* USER PCAL [10707,61004] 000 MONITOR bw8 KL10E40 hEP-80. *START* U O DDDD U U O O U O D D O O D D U U D O U O D P UUUUU DDDD SHIP SHiP SEQ. H H OO0 ELLEn. H H 0 0 L M H u 0 E HHHttH 0 0 ~.EEE H H 0 [) L H H UOO ELEEL 3845 DATL 2b-OCT-80 3845 DAT~ 26-OCT-80 22:48:5] 22:48:5] SUMMARY OF DATA RECORDS NUMBk~ [J5 RECORDS: 2317 I.,ENGI'~ OF RECORDS: 994 BYTES L~.NGTH Ltl" LAST RECOPD: 994 BYTES FIL~] IkAiL~.R LENGTh: 62 DITES ~ILE NAME: EDIT .001 MAXIMUM PHYSICAL RECORD L~NGTH: NEXT ~lLk NAME: rAPE IRAILEH L~,NGIM: 132 BYTES TAPE NAME: 61004 SERVICE NAME: kDll TAPE CONTINUATION NUMBER: 01 NEXT ~APk NAME: C[)MMENTS: 1024 BYTES DATE: 80/10126 DEPTH 800,000 700.000 600.000 500.000 400.000 300.000 200.000 100,000 50.000 MN EMONiC SP NPHI fCNL C2 SP GP NPHI }CNh C2 SP GR NPHI ~CNL C2 SP NPHi fCNL C2 SP G~ NPHI PCNL C2 SP GR NPHI FCNL C2 SP GR NPHi fCNL C2 SP NPHI fCNL C2 NPH! FCNL C2 VAL -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 -999 .'999 UE .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 .250 ,250 MN fsMUNIC ILD GR RHOB GR GR GR RHOB GR GR GR RHUB GR ~HOB GR GR ILD GR ~HOB GR GR ILD GR GR GR RHOB GR ILD RHUB GR OR VAL -999 -999 -999 24 7 -999 -999 -999 25 8 -999 -999 -999 23 10 -999 -999 -999 23 8 -999 -999 -999 34 8 -999 -999 -999 58 9 -999 -999 -999 25 9 -999 -999 -999 19 10 -999 -999 -999 15 -999 iJE .250 .250 .250 .297 .400 .25O .250 .250 .484 .800 .250 .250 .250 .500 .300 .250 .250 .250 .094 .900 .250 .250 .25O .250 .900 .250 .250 .250 .938 .400 .250 .250 .250 .484 .600 .250 .250 .250 .000 .250 .250 .250 .133 ,250 MNEMONIC IbM CALl NRAf ILM CALl NRAT DT CALk NRAT UT CALk NRA£ UT CALl NRAI DT ILM CALk NRAT kLM CALl NRA'I DT IbM CALl NRAT DT CALl NRAT DT VALUL -999.250 -999.250 -999.250 206.000 -999.250 -999.250 -999.250 20b.000 -999.250 -999.250 -999.250 200.875 -999.250 -999.250 -999.250 196.000 -999.250 -999.250 -999.250 180.250 -999.250 -999.250 -999.250 192.250 -999.250 -999.250 -999.250 205.250 -999.2b0 -999.250 -999.250 199.500 -999.250 -999.250 -999.250 200.000 MNEMONIC SFbU DRHU NCNb Ci ~FLU DRHU i~CND C1 DRHU NCNb CI 6FbO DRHU NCNb Ct SFbU DRHO NCNb C1 SFI,U DRHU NCNb C! DRHU NCNb C1 ~f'bU DRHU NCNb Ct ,5It LU DRMU NCNb C1 VALUE -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.2b0 -999.250 -999.250 -999.250 -999.250 -999.250 -99~.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 DEPTH 1700.000 1600o000 1500.000 ]400.000 I 300.000 1200.O00 1100,000 1000.000 900.000 SP G~ NPBi ~CNL C2 SP GR NPHI fCNb C2 SP GR NPHI fCNL C2 SP GR NPHI FCNL C2 tip GR NPH1 FCNL C2 SP GR NPH1 FCNL C2 tip GR NPHI iiCNL C2 SP GR NPttl }CNL C2 mPHi ~CNL C2 VALUE -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999,250 -999,250 -999,250 -999.250 -999,250 -999,250 -999.250 -999,250 -999.250 -999,250 -999,250 -999.250 -999.250 -999,250 -999.250 -999.250 -999,250 -999.250 -999.250 -999,250 -999,250 -999.250 -999,250 -999,250 -999,250 -999.250 -999.250 -999.250 -999,250 -999.250 -999.250 -999.250 -999.250 -999,250 -999.250 -999,250 -999.250 -999.250 -999.250 MN LMUNIC II,D GR GR GR iLD GR RHOB GR RHQB GR GR 1LD GR RHUB GR GR ILD GR GR GR iLD GR GR GR GR RHOB GR GR iLO GR Gk GR GR GR VALUk -999.250 -999.250 -999.250 19.906 7.000 -999,250 -999,250 -999.250 32.250 10.000 -999,250 -999.250 -999,250 25.094 12.000 -999.250 -999.250 -999.250 34,250 12.400 -999.250 -999.250 -999.250 25.891 12.200 -999.250 -999.250 -999.250 ]1.859 12.500 -999.250 -999.250 -999.250 45.813 12.800 -999.250 -999.250 -999.250 20.703 9.500 -999.250 -999.250 -999.250 21,109 9.500 IbM CALl NRA1 DT CALl NRAT DT CALl NRAI DT ILM CALl NRA1 DT 1bM CALl DY CALl DT CALl NRA1 DT CALl NRAT DI CALl NRAT DT VAbUE -999.250 -999.250 -999.250 72,750 -999.250 -999.250 -999.250 118.063 -999.250 -999.250 -999.250 114.000 -999,250 -999.250 -999.250 121.625 -999.250 -999.250 -999.250 174.500 -999.250 -999.250 -999.250 111.875 -999.250 -999.250 -999,250 189.875 -999.250 -999.250 -999.250 205.875 -999.250 -999.250 -999.250 200.]75 MNEMUN1C S~hU DRHO NCNb C1 DRHU NCNb C1 8FLU DRHO NCNb C1 8FbU DRHO NCNb C1 DRHU NCNb C1 SFLU DHHU NCNb Cl SFbU DRHU NCNb CI S~bU NCNb C1 fiFbU DRHU NCNL CI VAbU~ -999.260 -999.250 -999.250 -999.250 -949.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -99~.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.~50 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.Z50 -999.2b0 -999.250 -999.250 -999,250 26C0.000 2500.000 2400.000 2300,000 2200.000 2100.000 2000.000 1900.000 1800. 000 MN kMUN1C SP GR C2 SP GR NPHI fCNL C2 SP GR NPH1 FCNL C2 SP GR NPHI FCNL C2 SP NPHI ~CNL C7 SP GH NPHI ~CNL C2 SP NPHI ~CNL C2 SP GR NPHI FCNL C2 SP GR NPH1 ~CNL C2 VALUE -53.750 -999.250 -999.250 -999.250 24.000 -57.750 -999.250 -999.250 -999.250 24,906 -60.250 -999.250 -999.250 -999.250 17.862 -60.500 -999.250 -999.250 -999.250 23.296 -63.000 -999.250 -999.250 -999.250 23.899 -59.250 -999.250 -999.250 -999.250 19.069 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999,250 -999.250 -999.25O -999,250 MN EMtJN lC GR RHOB GR GR ILL GR GR GR 1Lb GR RHOB GR iLD GR RHOB GR GR RHUB GR GR ILD GR HHOB GR GR ILD GR GR GR ILD GR GR ILD GR RHt)B GR VALUk 1.259 -999.250 -999.250 34.694 15.700 1.225 -999.250 -999.250 27.802 16.200 1.236 -999.250 -999.250 41.242 16.300 2.128 -999.250 -999.250 40.466 15.100 1.803 -999.250 -999.250 31.593 14.600 )03.753 -999.250 -999.250 22.703 11.400 -999.250 -999.250 -999.250 23.500 11.300 -999.250 -999.250 -999.250 31.469 10.~00 -999.250 -999.250 -999.250 23.891 10.200 MNE~ION1C IbM CALl NRAT DT CAb1 NRA1 D~ CAb1 NRA'I DT ILM CALl NRA'£ DT CALl NRAI' DT CALl NRAT DT IbM CALl NRA~ UT CALl NRAI DT IbM CALl NRAT DT VALUE 1.419 -999.250 -999.250 165.950 1.406 -999.250 -999.250 161.950 1.330 -999.250 -999.250 152.350 2.168 -999.250 -999.250 172.100 1.837 -999.250 -999.250 155.350 8550.6o6 -999.250 -999.250 204.375 -999.250 -999.250 -999.250 171.875 -999.250 -999.250 -999.250 !59.125 -999.250 -999.250 -999.250 136.750 MNEMUNIC SFhU DRHU NCNb C1 DRHU NCNb C1 ,5FbU DRHU nCNb C1 $FbU DRHO NCNb C1 $FhU DRHO NCNb C1 $~bU DRHO NCNb Cl SFb0 DRHU NCND Cl SFLU ORHO NCNb C1 $1~ bO DRHU NCNb C1 VALUk 1.b44 -999.250 -9~9.250 22.321 l./0b -999.250 -999.250 24.148 -999.250 -999.250 17.481 2.089 -999.250 -999.250 20.042 2.4Ob -999.250 -999.250 22.469 0.B02 -999.250 -999.250 lB./lb -999.250 -9~9.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 ~500.000 3400.000 3300.000 3200,000 3100.000 3000.000 2900.000 2800,000 2700,000 SP -61.500 GR -999.250 NPH] 48.345 FCNb 45.474 C2 -999.250 SP -27.000 GR -999.250 N?HI 55.381 FCNb 36.036 C2 18.01] SP -37.750 GR -999.250 NPHI -99925.000 FCNL -999.250 C2 17.912 SP -44.000 GR -999.250 NPHi -99925.000 ~CNb -999.250 C2 20.176 SP -41.250 GR -999.250 NPHI -999.250 ~CNL -999.250 C2 17.962 SP -30.000 GR -999.250 NPHI -999.250 fCNL -999.250 C2 17.811 BP -37.000 GR -999.250 NPHI -999.250 bCNb -999.250 C2 18.264 SP -50.50O GR -999.250 NPHI -999.250 FCNL -999.250 C2 23.698 BP -49.000 GR -999.250 NPH1 -999.250 fCNh -999.250 C2 26.465 Mh LMONIC ILD GR RHUB GR GR GR GR GR GR GR GR GR GR GR GR GR GP GR GR GR GR GR VALLIE 1.898 65.200 2.173 64.100 27.000 2.443 O.200 2.495 50.029 18.800 1.306 -999.250 -999.250 39.519 16.600 1.038 -999.250 -999.250 27.458 14.600 1.528 -999.250 -999.250 42.162 16.400 1.096 -999.250 -999.250 77.855 20.400 2.489 -999.250 -999.250 55.887 21.000 1.019 -999.250 -999.250 27.630 12.bO0 1.127 -999.250 -999.250 28.319 11.100 MNEMONIC IbM CALl NRA1 IbM CALl NRA~ DT CALl NRA'I DT IbM CALl NRAT DT CALl NRA% DT CALl CAI.Il CALl DT IbM CALl NRAI DT 1.830 lb.400 4.048 131.750 2.312 13.100 4.818 123.200 1.472 -999.250 -999.250 157.250 1.180 -999.250 -999.250 191.550 1.556 -999.250 -999.250 136.350 1.148 -999.25O -999.250 165.000 2.t43 -999.250 -999.250 128.100 1.107 -999.250 -999.250 lbl.500 1.318 -999.250 -999.250 169.900 MNEMONIC ,Si' 60 DRHO NCNb C1 DRHO NCNb C1 DRHU NCNb C1 SFbU URHU NCNb C1 DRHO NCNb C1 6FLU DRHU NCNb CI ~bU DRHU NCNb C1 8FbU DRHU NCNb Ct ~3FbU DRHU NCNb C1 VAbUm q.543 0.084 201.630 -999.250 2.055 0.000 lbJ.020 17.481 1.b44 -999.250 -999.250 17.333 1.225 -999.250 -999.250 20.395 1.803 -999.250 -999.250 11.728 1.159 -999.250 -999.250 11.284 2.582 -999.250 -999.250 17.481 1.419 -999.260 -999.250 23.210 1.380 -999.250 -999.250 25.136 D~PTH 4400.000 4300.000 4200,000 4100.000 4000.000 3900.000 3800.000 ]700.000 3600,000 MNLMUNIC SP NPHI C2 SP GR NPHi FCNL C2 SP GR NPH1 C2 GR NPHi ~CNL C2 SP GR FCNL C2 SP NPR1 ~CNL C2 SP GR NPHi C2 SP GR NPH1 C2 SP GR NPHI f CNL C2 VALU -75. -999. 37. 77. -999. -78. -999. 3~. 81. -999. -78. -q99. 38. 79, -999. -93. -999, 36, 75. -999, -90. -999. 19. 99. -999. -90. -999. t7. 80. -999. -999. 34. 54. -999. -79. -999. 46. 42. -999. -71. -999. 48. 39. -999. 250 250 427 649 250 000 250 846 081 250 000 250 958 365 250 250 25O 950 9]3 250 000 25O 417 957 25O 000 250 684 652 250 750 250 581 912 250 750 250 960 900 250 063 250 640 468 25O MNEMONIC lbD GR GR l LD RHUB GR ILD GR RHOB GR ILD RHOB GR ILD RHOB GR GE GR ~HUB GR GR ILD GR RHOB GR GR GR GR GR GR GR VALUE 2.630 64.800 2.304 66,400 36.200 2,466 62.400 2.328 62.000 29.300 2.051 61,000 2,284 63.600 28,500 0.920 42.600 2.145 43,200 23.000 1,556 32.000 2.267 33.800 18,500 1.368 36.800 2,212 37,200 18.300 1.529 37.400 2.213 36.000 23.500 1.419 48.800 2.160 51.400 23.400 2.238 52.700 2,004 48.000 27.700 MNEMONIC CALl NRAT DT CALl NRAT DT IbM CALl NRAT CALl NRAI CALl NRA£ DT ILM CALl NRAT DT ibm CALl NRAT DT IbM CALl NRAT DT ILM CALl DT VALUL 3.048 15.;00 3.O00 114,350 2.831 14.900 3.34% 114.350 2.291 14.000 3.610 115.000 1.138 13.950 3.516 130.700 1.92t 21.400 3.224 120.500 1.044 16.350 3.592 125.300 1.995 17.500 3.712 12b.900 1.675 18.000 4.088 136.200 2.639 19.900 4.576 138.850 MNEMUNIC Si. bo DRHU NCNb C1 DRHU NC Nb C1 6I" LU DRHO NCNb C1 SFLU DRHU NCNb C1 ORftO NCNb CI ;SFbU DRHO NCNb C1 ,Si; LU DRHU NCNb Cl SFLU DRHO NCNb C1 8f bU DRHU NCNb C1 VAbU~ 5.445 0.030 -999.250 4.831 0.059 2U0.5OO -999.250 4.055 O.008 281.424 -999.250 1.83; 0.008 Z04.264 -999.250 3.767 0.039 205.980 -999.250 5.152 0.01] 298.5~4 -999.250 4.556 0.115 192.192 -999.250 4.742 0.062 lU3.012 -999.250 5.bbb 0.046 172.45~ -999.250 DLPTH 5300.000 5200,000 5100.000 5000.000 4900.000 4800.000 4700.000 460O.O0O 4500.000 MN EMON1C SP GR NPHi FCNL C2 GR NPHI ~CNL C2 SP GR NPH1 FCNL C2 SP GR NPH1 FCNL C2 SP GR NPHi FCNL C2 SP NPhl FCNL C2 SP fir NPHI FCNL C2 $P GR NP~i FCNL C2 SP GR NPH1 FCNL C2 VALUE -84.750 -999.250 36.316 86.229 -999.250 -97.250 -999.250 35.073 85.800 -999.250 -68.250 -999.250 34.731 84.084 -999.250 -77.250 -999.250 37.956 76.362 -999.250 -89.000 -999.250 33.382 85.800 -999.250 -66.750 -999.25O 37.015 70.356 -999.25O -87.000 -999.250 35.24O 81.510 -999.250 -90.000 -999.250 37.208 81.510 -999.250 -83.500 -999.250 39.334 74.217 -999.250 MN LNioN IC ILD GR RHUB GE GH ILO GR GR GR GR RHOB GR GR ILD RHUB OH GR 1LD GR RHOB GR GR ILD GR GR GR 1LD GR RHOB GR GR GR GR GR RMOB GR GR VALUE 2.443 62.300 2.265 61.300 30.200 1.977 50.600 2.299 49.800 22.400 2.965 73.500 2.307 75.100 39.100 2.443 66.700 2.307 66.200 34.400 2.466 59.5OO 2.288 64.000 35.400 3.251 70.300 2.343 76.300 38.200 2.228 67.700 2.292 63.100 30.100 1.959 58.400 2.276 58.100 31.700 2.051 55.800 2.272 59.100 34.900 CALl NRAT DT ibm CALl NRAT DT IbM CAbI N~A~ DT IbM CALl NRAT DT CALl NRAI DT 1LM CALl NRA1 CALl NRA£ DT CALl NHAI DT IhN CALl NRAI bT VALUE 3.048 13.450 3.418 112.U50 2.559 13.100 3.538 114.900 3.404 14.000 3.524 113.250 2.831 13.350 3.054 115.900 3.020 15.350 3.308 113.700 3.532 18.650 3.712 114.350 2.704 15.350 3.640 114.850 2.377 13.o50 3.b88 116.600 2.512 14.200 3.472 117.200 MN~.MUNiC SFLO DRHO NCNb C1 S~bO DRHO NCNb C1 Sf, 6U DRHU NCNb Ct SFbU DRHU NCNb C{ 6F6U DRHO NCNb C1 SFbU ORHU NCNb C1 S~ bO DRHU NCNb C1 SFbU DRHU NCNb C1 SF6U DRHU NCNb C1 VAbU~ 5.916 0.010 30~.022 -999.250 4.900 0.050 2B3.998 -999.250 5.495 0.022 282.2U2 -999.250 4.8/5 271.986 -999.250 5.801 0.035 2~8.288 -999.250 4.875 0.018 -999.250 0.057 2~0.131 -999.250 4.966 0.062 2U8.288 -999.250 4.920 0.046 274.989 -999.250 D~PTH 6200,000 6100.000 6000.000 5900.000 5800.000 5700.000 5600.000 5500.000 5400.000 MNbMONIC SP GR NPH1 FCNL C2 SP GR NPHI FCNL, C2 SP GR NPHI ~CNL C2 SP GR FCNL C2 SP GR NPHI FCNL C2 SP GR NPHI FCNL C2 ,SP GR NPHI ~CNL C2 GR NPH1 FCNL C2 SP GR NPH1 FCNL C2 VALUk -107.000 -999.250 50.501 87.087 -999.250 -66.250 -999.250 34.781 84.084 -999.250 -49.500 -999.250 36.432 71.214 -999.250 -59.250 -999.250 35.782 85.800 -999.250 -49.500 -999.250 39.312 68.640 -999.250 -5b.500 -999.250 31.279 79.794 -999.250 -82.750 -999.250 35.628 90.090 -999.250 -120.000 -999.250 38,889 87.945 -999.250 -lOb.000 -999.250 36.749 93.522 -999.250 MNLMUNiC 1LO GR 1LD GP HHOB GR GR iLO GR GR GR RHOB GR GR GR GR GE 1LD GR RHOB GR GR RMOB GR GR GE GE ILD GR GR GR VAGUE 2.148 36.900 2.209 39.800 24.100 3.342 6].]00 2.387 61.900 37.700 3.873 79.100 2.189 81.800 42.700 3.311 76.400 2.364 81.100 37.700 3.767 88.000 2.363 87.200 43.700 1.738 75.000 2.398 77.900 ]7.50O 1.b90 59.000 2.231 55.]00 38.000 1.271 34.900 2.141 35.400 19.100 1.355 44.900 2.198 44.]00 23.500 MNLMON lC ibm CAbi NRAT OT CALl NRAT DT ILM CALl NRAT DT ibm CALl NRAT DT ibm CALl NRAT DT CALl NRAT CALl NRAI CALl NRA1 DT CALl NRAI DT VA6UE 2.b55 13.300 3.468 108.850 3.733 13.u00 3.304 98.400 3.797 14.b50 ].450 108.600 16.800 3.520 108.550 3.436 18.b00 3.818 112.200 1.BS/ 14.050 3.b64 111.450 1.780 13.200 3.528 120.250 1.330 12.700 3.504 123.800 1.459 12.950 3.432 118.550 MNE.~UN ~,C ,SFbU DRHO NCNb C1 8~bU DRHU NCNb Cl SFbO DRHO NCNb C1 DRHU NCNb CI SFbO DRHU NCNb C! DRHO NCNb C! SFbU DRHU NCNb C1 DRHU NCNb C1 SfbU DRHO NCNb C1 VAbUb 4.b13 0.01] 3BB.b74 -999.250 ~.~07 0.053 284.42/ -999.250 4.5Z9 0.059 Z5;.400 -999.250 5.754 U.030 299.013 -999.2b0 4.9bb 0.092 271.128 -999.250 2.831 0.013 257.829 -999.250 2.b30 0.039 305.448 -999.250 2.b19 0.0]1 301.1~4 -999.250 2.559 0.014 323.031 -999.2b0 DEPTH 7100.000 7000.000 6900.000 6800.000 6700.000 6600.000 6500.000 6t00.000 6300,000 MNEMONIC GR NPHI C2 SP GP NPHI fCNL C2 SP NPH1 fCNL C2 SP GR NPHi FCNL C2 SP GR NPHI FCNL C2 GR NPHI FCNL C2 SP GR NPHi ~CNb C2 $P GR FCNL C2 SP NPHI fCNL C2 VAL -47 -999 39 64 -999 -111 -999 26 123 -999 -116 -999 33 100 -999 -118 -999 27 111 -999 -115 -999 31 94 -999 -98 -999 3O 97 -999 -52 -999 3O -999 -107 -999 32 113 -999 -120 -999 182 -999 UE .5OO .250 .875 .350 .250 .250 .250 .770 .981 .250 .000 .250 .683 .815 .250 .000 .250 .763 .540 .250 .250 .250 .453 .380 .250 .000 .250 .429 .812 .250 .000 .250 .448 .924 .250 .25O .250 .695 .256 .25O .000 .250 .098 .754 .250 MN EM[)N lC GR GR GR ILO RMUB GR ILL GR RMUB GR GR ILL GR RHOB GR 1Lb GR GR GR ILO RHOB GR GR 1LD GR RMOB GR GR ILD GR GR 1Lb RHUB VAL 4 78 2 84 38 2 28 2 28 21 1 42 2 35 28 1 33 2 31 2] 1 31 2 28 21 1 35 2 34 40 2 65 2 71 45 1 42 2 36 30 J 29 2 30 18 .018 .700 .345 .800 .000 .312 .400 .288 .300 .500 .959 .900 .277 .900 .600 .432 .400 .244 .000 .700 .585 .000 .235 .800 .400 .585 .200 .213 .400 .700 .421 .000 .328 .700 .900 .259 .400 .220 .500 .200 .803 .000 .~71 .000 .700 MNEMUNIC CALl DT IbM CALl NRAI UT CALl DT CALl NRAI DT IbM CALl NRAT Dr ILM CALl NRAT DT IbM CALl NRAI DT CALl NRAI DT IbM CALl NRAT DT VALUE 3.O64 16.700 3,812 120.200 2.555 1/.250 2.934 96,300 2.333 14.350 3.344 102.400 1./54 15.350 3.076 99.800 1.995 13.900 3.110 100,700 1.?85 14.850 3.330 111.700 2.405 16.100 3.888 107.300 1.556 13.350 3.200 109.700 2.032 13.500 2.458 88.950 MNEMUN1C SFLU DRHO NCNb C1 DRHU NCNb C1 DRHO NCNb C1 DRHO NCNb C1 Sf'bU DRHU NCNb Cl fit" bO DRHU NCNb C1 SFbU DRHO NCNb Cl DRHO NCNb C1 SFbU DRHU NCNb C1 VAbU~ 4.956 0.111 2~1.950 -999.2b0 0.025 0.022 301.553 -~99.250 0.054 ]45.532 -999.250 4.445 0.040 343.200 -999.250 5.248 0.049 308.8~0 -999.250 4.950 0.014 310.173 -999.250 J.048 0.157 205.920 -999.250 5.540 0.016 JO9.198 -999.250 b.48b 0.026 4/1.906 -999.250 DEP'I H 8000.000 7900.000 7800°000 7700,000 7600.000 7500.000 7400.000 7300.000 7200,000 MNEMONIC SP GR NFHI t~CNb C2 SP G~ NPH! ~CNL C2 SP GR NPHI ~CNb C2 SP O~ NPH I FCNb C2 SP GR NPHi FCNL C2 SP GR NPHI ~CNL C2 SP GR NPHI ~CNL C2 SP GR NPH1 ~CNL C2 GR NPHI FCNL C2 VAL -58 -999 3O 8] -999 -63 -999 28 93 -999 -59 -999 3O 86 -999 -999 29 88 -999 -56 -999 29 86 -999 -56 -999 31 81 -999 -43 -999 38 61 -999 -4b -999 36 66 -999 '38 -999 39 60 '999 .250 .250 .579 .655 .250 .750 .250 .177 .522 .250 .750 .250 .771 .229 .250 .000 .250 .691 .374 .250 .750 .250 .84b .229 .250 .250 .250 .010 .510 .250 .000 .250 .917 .776 .250 .000 ·250 .574 .066 .250 .000 .250 .193 .489 .250 MNEMUNIC ILD GR RHOB GR iLD GR RHOB GR GR RNOB GR GR lbD GR RHUB GR ILD OH RHOB GP GR lbD GR RHOB GR GR lCD GR GR G~ IbD GR OR iLD GR RHOB VAL 5 92 2 87 41 .754 .200 .472 .900 .]00 4.446 92.400 2.500 96.500 36.900 5 88 2 88 39 5 9O 2 95 42 5 92 2 92 5 9O 2 97 4b 113 2 115 54 2 106 2 99 45 0 117 2 113 45 .Sbl .600 .463 .100 .300 .248 .400 .527 .500 .600 754 '200 · .437 .700 .q00 .445 .400 .462 .]00 .300 .162 .500 .332 .000 .900 .655 .200 .354 .400 .800 .631 .300 .385 .700 ,000 MNEMONIC IbM CALl NRAT DT IbM CALl NRAI DT CALl NRA'I DT CALl NRAT DT CALl NRAI DT IbM CALl NRA'I DT IbM CALl NRAf DT i6M CALl NRAI DT CALl NRA]~ DT VALUE 5,152 21.550 3.408 99.850 3.908 21.500 3.432 92.900 5.152 21.500 3.428 105.050 4.gbb 21.550 3.388 96.000 5·012 21.550 3·356 97.500 4,742 21.500 3.450 97.150 2.~58 21.550 3.904 112.050 2.377 21,550 3.87b 12b.150 0·855 18.700 4·108 125.200 DRHO NCNb C1 SFbU DRHU NCNb C1 SFbO DRHU NCNb CI DRHU NCNb Cl 8Fbu DRH(J NCNb CI SFL, U ORHU NCNb C1 DRHU NCNb C1 $~bU DRHU NCNb C1 SFbU DRHU NCNb C[ VAbUk 1.178 0.139 285.285 -999.250 3.311 0.132 302.874 -999.250 1.178 O.15b 293.4Jb -999.250 1.041 0·194 -999.250 U.792 0.135 283.998 -999.250 0.151 212.844 -999.250 4.529 0.084 232.089 -999.250 4.093 0.094 245.3U8 -999.250 1.78b 0.070 228.22B -999.250 DLPTH 8800.000 8700.000 8600,000 8500.000 8400.000 8300.000 8200.O00 8 1 O0. 000 MN ENONIC SP G~ NPHI C2 SP GR NPHI ~CNL C2 GR NPHI FCNL C2 SP GR ~CNL C2 SP GR NPH1 FCNL C2 SP GR NPH! ~CNL C2 SP GR NPHI ~CNL C2 NPMI fCNL C2 SP GH NPMI FCNL C2 VAL -52 -999 22 112 -999 -48 -999 33 72 -999 -48 -999 77 -999 -48 -999 3O 84 -999 -52 -999 29 83 -999 -53 -999 25 105 -999 -48 -999 ]1 78 -999 UL .750 .250 .508 .398 .250 .750 .250 .856 .072 .250 .250 .250 .776 .649 .250 .250 .250 .582 .942 .250 .000 .250 .653 .226 .250 .500 .250 .802 .534 .250 .500 .250 .211 .936 .250 -57.750 -999.250 31.b85 79.365 -999.250 -56. -999. ]4. 70. -999 . 50O 25O 805 356 25O MN EMUNIC iLO GH HHOB GR GH GR RHDB GR GR ILD OR RHUB GR GR ILD GR HHUB GR GR GR RHUB GR GH RHUB GR GR 1Lb GR GR GR ILD GR HHOB GR GR GR RHUB GR VAL 5 71 2 71 ]5 3 gq 2 96 40 98 2 97 42 5 90 2 97 36 UE .916 .900 .517 .300 .bOO .837 .000 .461 .000 .800 .221 .20O .507 .200 .600 .297 .800 .500 .000 .200 5.970 85.900 2.424 89.800 34.000 6.194 78.700 2.444 85.]00 ]5.]00 5.152 95.@00 2.504 98.800 41.200 3.981 92.900 2.464 94.300 41.900 3.342 87.800 2.425 92.800 t9.000 ILM CALl NRAT DT CALl NRAf DT IbM CALl NHAT DT CALl NRAI' DT CALl NRAT DT ILM CALl NRAf DT CALl NRA1 DT CALk NRAI DT ibm CALl NRA1 UT VAbUk 5.540 21.550 5.168 90.550 3.873 21.550 3.444 95.400 2.754 21.550 3.746 95.300 4.920 21.550 ].584 94.450 5.340 21.550 3.248 94.100 5.049 21.550 3.126 9].500 4.831 21.550 3.448 95.850 4.169 21.550 3.458 95.150 3.436 21.550 3.68O 96.250 MN~MUNIC DRHU NCNb C1 b~,bU DRHU NCNb C1 8fLU DRHU NCNb Cl 6FLU DRHU NCNb C1 SFLU DRHU NCNb C1 SFbU DRHU NCNb C1 5FLU DRHU NCNb C1 bFbU DRHO NCNb C1 DRHO C1 VADUk 8.1Lb 0.1o3 314.~8b -999.250 b.bb8 0.070 205.122 -999.250 4.018 O.ZO0 211.128 -999.250 0.855 0.139 285.Z85 -999.250 1.244 O.llb 281.424 -999.250 7.047 0.107 519.1/b -999.250 6.730 0.142 275./02 -999.250 5.764 0.154 272.844 -999.250 1.516 0.154 255.bU4 -999.250 DEPTH 9800.000 9700.000 9600,000 9500.000 9400.000 9300.000 9200,000 9100.000 9000,000 MN SP GR NPHI FCNh C2 NPHI FCNI, C2 SP GR NPHI FCNL C2 SP GR NPHI FCNL C2 GR NPHI FCNL C2 SP GR NPHi fCNL C2 SP GR NPHI FCNL C2 SP GB NPHI [-CNL C2 SP GR NPHi FCNL C2 kAL -67 -999 28 100 -999 -84 -999 28 129 -999 -65 -999 31 79 -999 -90 -999 25 132 -999 -999 28 92 -999 -66 -999 28 96 -999 -999 28 98 -999 -74 -999 28 96 -999 -55 -999 36 65 -999 UE .000 .250 .413 .386 .250 .5OO .25O .245 .558 .250 .000 .250 .155 .794 .250 .750 .250 .530 .132 .250 .500 .250 .437 .664 .250 .250 .250 .359 .096 .250 .000 .250 .462 .670 .250 .250 .250 .908 .525 .250 .500 .250 .572 .637 .250 MN GR GR ILD GR GR GR ILL GR GR (JR 1LO GR GR GR ILD GR RHOB GR GR IbD GR GR GR iLO GR GR GF GR GR GR iLO GR RHUB GR VAL 5 72 2 7~ 27 5 2 58 27 5 88 2 94 _39 4 62 2 67 30 4 8O 2 79 ]4 4 72 2 09 28 5 77 2 77 ]4 UE .000 .535 .300 .900 .546 .100 .459 .900 .500 .152 .900 .479 .100 .700 .093 .000 .417 .200 .000 .831 .200 .479 .500 .200 .bi] .o00 .455 .600 .700 .445 .500 .464 .600 .700 5.105 74.800 2.425 77.100 33.000 4.966 72.900 2.386 77.300 28,300 MNEMONIC ILM CALl DT CALl NRA'I' DT CALl NRAT DT ILM CALl NRAT OT 1LM CAbI NRAT DT CALl NRAT DT 1LM CALl NRAt CALl NRA1 Dr 1bM CALl NRAT DT VALUE 5.345 17.850 3.108 88.750 6.368 15.200 2.890 84.800 4.786 21.550 3.436 91.600 5.058 16.050 2.844 87.750 4.529 19.550 3.296 91.o50 4.965 16.650 3.00% 90.250 5.291 18.850 3.280 89.b00 5.346 17.400 3.218 90.200 4.571 17.800 3.564 92.500 MNEMONIC 6[.bO DRHO NCNb C1 DRHO NCNb C1 8FLU DRHU NCNb Cl SFbO DRHU NCNL C1 $FbU DRHU NCNb C1 SFbU DRHU NCNb Cl 5FLU DRHU NCNu C1 SF'bU DRHU NCNb C1 DRHU NCNb C1 VALUE ~.lOb 0.149 308.022 -999.250 9.2~0 O.OOb 393.822 -999.250 U.13B 0.128 211.551 -999.250 7.J79 0.049 384.384 -999.250 5.598 0.092 291.120 -999.250 b.485 0.050 295.010 -999.250 7.555 0.079 311.464 -999.250 b.130 0.03U 311.025 -999.250 5.058 0.082 240.240 -999.250 DEPTH 10700,000 10600.000 10500.000 10400.000 10300.000 10200.000 10100.000 1bOOboO00 9900.000 GR NPHI f'CNL C2 GR NPH1 fCNL C2 SP GR NPHI fCNL C2 SP GR NPHi fCNL C2 SP GR NPHI FCNL C2 SP GR NPHi fCNL C2 SP NPHi FCNL C2 NPHI FCNL C2 SP GR NPHI FCN[, C2 VALUE -56.000 -999.250 28.973 85.800 -999.250 -52.250 -999.250 28.721 86.229 -999.250 -53.250 -999.250 28.332 93.093 -999.250 -56.750 -999.250 30.706 85.800 -999.250 -58.500 -999.250 31.366 87.51b -999.250 -58.250 -999.250 25.350 110.682 -999.250 -59.250 -999.250 33.652 7].359 -999.250 -64.250 -999.250 24.391 115.830 -999.250 -64.000 -g99.250 21.603 1i4.972 -999.250 MNkMONiC ILO GR GR GR lbD GR GR ILO GR RHUB GR GB ILO GR GP GR ILO GR GR GR 1LD GR GR GR ILD GR GR GR GR GR GR iLD GR GR GR VAL 5 90 2 92 41 5 88 2 97 34 6 97 2 95 41 6 94 2 94 38 7 84 2 85 39 9 89 2 90 34 6 93 2 104 39 4 69 2 69 29 4 65 2 63 32 Uk .861 .800 .519 .800 .500 .546 .100 .532 .200 .100 .081 .700 .521 .800 .300 .252 .300 .488 .500 .100 .178 .200 .546 .400 .800 .727 .000 .476 .500 .600 .026 .500 .449 .400 .500 .966 .200 .415 .900 .100 .966 .400 .396 .400 °300 MNEMONIC IbM CALl NRAT DT CALl NRAT UT IbM CALl NRAT OI Ibm CALl NRAT DT IbM CALl NRA£ DT IbM CALl NRAi DT 1LM CALl NRAI DT CALl NRAT DT ibm CALk NRAI DI VALU~ 5.649 20.450 3.260 85.050 5.3q6 20.400 3.290 85.]00 5.754 21.450 3.234 84.100 5.910 20.55O 3.532 87.000 6.855 19.600 3.300 85.450 9.290 19.000 3.104 87.800 5.546 21.100 3.644 89.250 5.248 lb.bL0 2.930 87.950 4.920 14.000 2.724 88.650 MNkMUN1C DRHU NCNb C1 SFLU DRHU NCNb CI SFLU ORHU NCNb C! ORHU NCNb C1 DRHO NCNb C1 SfbU DRHU NCNb Ct 8FLU DRHO NCNb C1 DRHO NCNb C1 SFbO DRHO NCNb C1 VAbOk 0.982 0.10B 281.424 -999.250 o.918 0.108 274.500 -999.250 1.441 0.064 295.152 -999.250 ~.318 0.096 289.140 -999.250 8.1Ob 0.104 300.300 -999.250 13.428 O.0b0 324.753 -999.250 0.855 O.0b? 205.122 -999.250 0.194 0.04] 322.008 -999.250 1.198 0.121 2U8.288 -999.250 11600.000 11500.000 1!400.000 11300,000 11200,000 11100.000 11000o000 10900.000 lOgO0.O00 MNLMUNIC 8P GR NPHI ffCNL C2 SP GR NPHI FCNb C2 8P GR NPHI fCNL C2 SP GR NPHI FCNL C2 8P GR NPHi fCNL C2 SP GR NPHI FCNL C2 SP GR NPHI FCNL C2 SP GR NPHI FCNL C2 SP GR NPHI FCNL C2 VAb -50 -999 31 83 ,.999 -56 -999 33 82 -999 UE .781 .250 .144 .655 .250 .750 .250 .455 .368 .250 -55. -999. 29. 86. -999. -40. -999. 32. 78. -999. -59. -999. 35. 79. -999. -48. -999. 33. 77. -999. -38. -999. 30. 86. -999. -44. -999. 31. 81. -999. -43. -999. 39. 81. -999. 750 250 705 229 250 594 25O 586 936 250 5O0 250 146 794 25O 500 250 849 649 250 000 25O 281 658 250 25O 25O 858 510 250 500 250 58] 510 25O MNkMONIC IBD GR RHOB GR GR ibD GR GR lbo GP RHOB GR GR GR RHuB GR GI~ IbD GR RHt)B GR GR IbD G~ GR ILD GR GR GR lbo GR 14FLUB GR GR ILO GR HHUB G~ VALU · 93. 2. 94. 43. m 94. 2. 101. 41. · 94. 2. 98. 38. · 93. 2. 92. 40. . 102. 2. 100. . 9~. 2. 98. 42. . 96. 2. 94. 37. . 99. 2. 101. 38. 88. 2. 92. 42. 102 800 518 375 000 966 600 515 300 400 966 900 516 100 200 918 700 453 100 900 248 400 532 800 200 920 600 522 400 20O 152 60O 471 100 9OO b49 ]00 473 200 900 486 000 552 500 700 IbM CALl NRAI UT ibm CALl NRAT OT ibm CALl NRAT DT 1 LM CALl NRAT OT CALl NRAI CALl NRAI DT CALl NRAT DT ILM CALl DT iLM CALl NRA1 DT VALU~ 4.828 19.200 3.300 83.450 4.786 19.000 3.476 87.050 4.966 19.450 3.424 83.950 5.008 20.250 3.434 87.450 5.152 19.200 3.424 87.000 4.65~ 20.0OO 86.950 5.012 19.550 3.126 86.050 5.495 18.750 ~.~32 85.950 b.252 21.500 3.510 85.050 MNEMUNIC DRHO NCNb C1 8FbU DRHO NCNb Cl 8f hU DRHU NCNb C1 SF'bU DRHU NCNb C1 SFLU DRHU NCNb Cl 8FLU ORHO NCNb C1 Sf bO ORHO NCNb C1 SFbU UHHO NCNb C1 DRHU NCNb C1 VAbUk 0.840 0.100 281.853 -999.250 b.081 0.079 288.288 -999.250 0.071 281.424 -999.250 b.355 0.065 -999.250 O.OU9 -999.250 5.916 0.102 274.500 -999.g50 0.194 0.055 2U3.998 -999.260 1.2a4 0.040 278.u50 -999.250 1.379 0.097 315.182 -999.250 DEPTH 12500.000 12400.000 12300,000 12200.000 12100.000 12000.000 11900.000 11800,000 11700.000 MN EMON1C aP GR FCNL C2 ~P GR NPHI FCNb C2 SP GR NPHI fCNL C2 6P GR NPHi FCNL C2 SP NPHI fCNL C2 SP GR NPHI fCNb C2 SP GR NPH1 FCNL C2 SP NPHI fCNL C2 SP GR NPHI f CNI, VALUE -43.500 59.600 -999.250 -999.250 -999.250 -46.250 64.900 -999.250 -999.250 -999.250 -41.500 62.400 -999.250 -999.250 -999.250 -41.000 51.400 -999.250 -999.250 -999.250 -36.500 49.800 -999.250 -999.250 -999.250 -37.500 54.200 -999.250 -999.250 -999.250 -39.250 -999.250 4.070 1.716 -999.250 -29.875 -999.250 40.672 67.782 -999.250 -37.625 -999.250 32.849 82.368 -999.250 kM(JNIC GR RHUB GR GR RH{]B Gh lbo GR GR GR ]bD GR GR GR 1LD OR RHt]B GR GR ILD GR RHOB GR GR lbo GR G~ ILD GR RHC]~ GR GR GR VALUE 3.311 -999.250 -999.250 63.400 -999.000 3.873 -999.250 -999.250 62.800 -999.000 3.1]3 -999.250 -999.250 58.400 -999.000 3.251 -999.250 -999.250 58.700 -999.000 3.076 -999.250 -999.250 59.600 -999.000 {.565 -999.250 -999.250 65.800 -999.000 3.631 80.800 2.176 49.800 -999.000 3.b04 90.400 2.481 84.250 36.600 4.{28 94.5O0 2.553 93.813 30.700 MNEMONIC CALl NRAI DT CALl NRAT DT CALl DT CALl NRAT IbM CALl NRAT DT IbM CALl NRAT DT ibm CALl NRAI' DT IbM CALl NRA T OT CALl NRAI DT VALUE 3.105 -999.250 -999.250 80.800 3.698 -999.250 -999.250 87.100 2.992 -999.250 -999.250 88.400 2.831 -999.250 -999.250 90.500 2.055 -999.250 -999.250 90.100 3.251 -999.250 -999.250 88.300 3.162 7.900 0.006 92.050 3.738 14.900 3.604 91.750 4.020 16.050 3.472 85.450 MNkMUN iC DRHO NCNb C1 DRHU NCNb C1 DRHU NCNb C1 SFbU DRHU NCNb C! SFLU DRHO NCNB C1 DRHO NCNb CI SFbU DRMO NCNb C1 NCNb C1 $FLU DRHO NCNB C1 VAbUb 2.965 -999.d50 -999.250 -999.250 3.133 -999.250 -999.~50 -999.250 Z.729 -999.250 -999.250 -999.250 2.512 -999.250 -999.250 -999.250 2.~99 -999.250 -999.250 -999.250 2.992 -999.250 -999.250 -999.250 3.499 0.192 1.710 -999.250 4.142 265.6~4 -999.250 4.~28 0.081 265.122 -999.250 DEPTH 13400,000 13300.000 13200.000 13100.000 lc]000.000 12900.000 12800.000 i2700.000 12600.000 MNEMONIC SP GR NPHI C2 SP NPHI C2 SP GR NPHi FCNL C2 SP NPHI I.CNL C2 SP GR NPHI C2 SP GR NPHI C2 GR NPH1 C2 SP GB NPHI FCNL C2 SP GR NPH1 fCNL C2 VALUE -36.500 56.200 -999,250 -999,250 -999.250 -34.750 52.300 -999.250 -999.250 -999.250 -37.000 58,800 -999.250 -999,250 -999,250 -41.000 51.000 -999.250 -999.250 -999o250 -42.500 54.200 -999,250 -999.250 -999.250 -38.500 57,600 -999.250 -999.250 -999.250 -38,000 50.600 -999.250 -999,250 -999,25O -40,500 57,900 -999,250 -999.250 -999.250 -43,250 63.500 -999,250 -999,250 -999,250 iLD GR GR GR GR RHOB GR GR 1LD GR RHOB GR GR ILD GR RHOB ILD GR RHUB GR GR GR GR I LD GR RHUB GR GR iLD RHOB GP GR iLL) RHUB GR VALUE 5.i52 -999,250 -999,250 50.400 -999.000 4.487 -999,250 -999,250 50.900 -999.000 4,487 -999,250 -999.250 52,400 -999,000 4,285 -999.250 -999.250 48.400 -999,000 4.055 -999.250 -999.250 47.500 -999.000 3.733 -999.250 -999.250 54.000 -999,000 4,207 -999,250 -999.250 48,200 -999.000 3,698 -999.250 -999,250 56.100 -999.000 2.b79 -999.250 -999.250 60.100 -999.000 MNEMONIC AbM CALl NRAT OT IbM CALl NRAI DT ibm CALl NRA'£ DT CALl NRAT DT 1bM CALl NRAI DT ibm CALl NRAT DT CALl NRAI DT ibm CALf NRAI OT CALl NRA'I DT VALUE 5.445 -999,250 -999.250 80,800 4.40b -999.250 -999.250 82.100 4.446 -999.25O -999.250 81.000 4.130 -999,250 -999.250 82.100 3.908 -999.250 -999.250 83.050 3.b98 -999.250 -999,250 82.700 3,837 -999.250 -999.250 79.700 3,43b -999.250 -999,250 85.200 2.249 -999.250 -999.250 89,600 MNEMUN lC Si, LO DRHU NCNb Ct DRHO NCNb C1 ~FbU DRHU NCNb C1 DRHO NCNb C! DRHO NCNb C1 DRHU NCNb C1 ~FLU ORHU NCNb Cl SFLU DRHU NCNb C1 SFLU DRHU NCNb CI VAbUE 5.495 -999,250 -999.250 -999.250 4.285 -999.250 -999.250 -999.250 4.529 -999.2b0 -999.250 -999.250 4.055 -999.250 -999.Z50 -999.250 3.90B -999.250 -999.250 -999.250 3,Lbb -999.2b0 -999,250 -999.250 4.2~b -999.250 -999.250 -999.250 2.938 -999.250 -999.250 -999.250 2.148 -999.250 -999,250 -999.250 14300.000 14200,000 14100.000 14000.000 13900.000 13800°O00 1~700.000 13600.000 13500.000 MN~MUNIC SP GP NPH1 FCNL C2 SP GR NPHi fCNL C2 SP GR O~~ NPHI PCNL C2 SP GR NPHI fCNL C2 SP GR NPhI ~CNL C2 SP GR NPHI FCNL C2 SP G~ NPHI fCNb C2 SP GR NPHI FCNL C2 SP GR NPHi fCNb C2 VALUE -68.500 58.600 -999.250 -999.250 -999.250 -72.000 60.900 -999.250 -999.250 -999.250 -75.500~"~ 46.400 -999.250-999.250-999.250 -35.500 59.000 -999.250 -999.250 -999,250 -32.500 60.200 -999.250 -999.250 -999.250 -35.250 45.0OO -999.250 -999.250 -999,250 -38.250 59.000 -999.250 -999.250 -999.250 -42.000 45.800 -999.250 -999.250 -999,250 -5?.250 39.600 -999.250 -999.250 -999.250 tMONIC ill GR RHUB GR GR GR RHUB GR GR ILO GR c~ RHt)B GR ¢~ c GR GR GR ibD GR RhUB GR GR GR RHOB GR GR GR RHOB GR GR GR GR GR ILD GR R~UB GR G~ VALUE 4.055 -999.250 -999,250 61.800 -999.000 4.742 -999.250 -999.250 58.000 -999.000 11.803 -999.25O -999.250 50.300 -999.000 4.966 -999.250 -999.250 52.900 -999.000 5.248 -999.250 -999.250 5b.400 -999.000 6.730 -999.R50 -999.250 49.900 -999.000 6.026 -999.250 -999.250 50.300 -999.000 6.310 -999.250 -999.250 46.700 -999.000 8.710 -999.250 -999.250 44.900 -999,000 MNEMONIC IbM CALl NRAT DT ibm CALl NRA~ OT IbM CALl NRA£ DT 1bM CALl NRAI DT CALl NRAT OT ILM CALl NRAT DT CALl NRA1 DT 1bM CALl NRA~ D~ CALl NRA1 DT VALUE MNEMUi41C 3.908 5FLU -999.250 DRHU -999.250 NCNb 83.500 C1 4.786 ~FLU -999.250 ORhO -999.250 NCNb 82.100 C1 13.062~'~ SFLO -999.250 DRHU -999.250 NCNb 77.100;~''~ Cl 5.058 6FLO -999.250 D~HO -999.250 NCNb 82.800 C1 5.248 SFLU -999.250 DRHO -999.250 NCNb 82.450 C1 b.918 SFbU -999.250 DRHU -999,250 NCNb 80.450 C1 b,252~ ~FLU -999.250 DRHU -999.250 NCNb 78.950 k C1 7.178 6flu -999.250 DRHO -999.250 NCNb 79.b50 C1 9.402 SFLU -999.250 DRHU -999.250 NCNb 80.700 Ct VALUE 4.055 -999.250 -999.250 -999.250 5.J4b -999.250 -999.250 -999.250 10.471 -999.250 -999.2b0 -999.250 q.78b -999.250 -9~9.250 -999.250 5.54b -999.250 -999.250 -999.250 8.472 -999,250 -999.250 -999.250 b.48b~ -999.250 -999.250 -999.250 B.b30 -999.2b0 -999.250 -999.250 lU.000 -999.250 -999.250 -999.250 DEPTH 15110,000 15100.000 15000.000 14900.000 14800.000 14700.000 14600.000 1~500.000 14400.000 MNEM[]N lC 8P GR NPHI FCNL C2 SP NPHI FCNL C2 6P GR NPHI fCNL C2 SP GR NPH! fCNL C2 SP GR NPHI FCNL C2 GR NPHi FCNL C2 SP GR NPHI ~CNL C2 ~P GR NPHi FCNL C2 bP GR NPHi FCNL C2 VALUL -54.000 0.400 -999.250 99.250 -55.000 0.300 -999.250 -999.250 -999.250 -62.000 87.000 -999.250 -999.250 -999.25O -71.250 71.700 -999.250 -999.250 -999.250 -51.500 85.400 -999.250 -999.250 -999.250 -59.000 142.000 -999.250 -999.250 -999.250 -02.500 52.500 -999.250 -999.250 -999.250 -64.500 107.000 -999.25O -999.250 -999.250 -68.000 81.300 -999.25O -999.250 -999,250 MNI~MUN 1C RFI£JO GR GR IbD OR GR GR 1LD GR GR GR GR GR IbD GR RHOB GR GR iLD GR RHOB GR RHOB GR OR iLD GR RHOB GR lbD GR RHLJl{5 O~ VALUE 8.166 -999.250 -999.250 50.600 -999.000 8.241 -999.250 -999.250 64.700 -999.000 8.318 -999.250 -999.250 52.500 -999.000 9.462 -999.250 -999.250 64.500 -999.000 5.598 -999.250 -999.250 72.000 -999.000 2.355 -999.250 -999.250 136.400 -999.000 4.169 -999.250 -999.250 60.600 -999.000 4.786 -999.250 -999.250 111.000 -999.000 5.248 -999.250 -999.250 57.000 -999,000 MNi~MUNIC ibm CALl NRAI DT CALl DT CALl NRA1 DT 1bM CALl NRAT DT CALl bRAT DT IbM CALl NRAT DT CALl NRAI DT 1LM CALl NRAT DI CALl NRAT DT VALUE 9.462 -999.250 -999.250 68.650 9.462 -999.250 -999.250 138.200 9.727 -999.250 -999.250 73.500 10.568 -999.250 -999.250 75.750 5.970 -999.250 -999.250 8b.bO0 2.443 -999.250 -999.250 124.450 3.873 -999.25O -999.250 84.7O0 4.875 -999.250 -999.250 95.500 5.545 -999.250 -999.250 80.000 MNkMUN lC SFLU DRHU NCmb Cl 8FbU DRHO NCNb C1 8ELU DRHO NCNb C1 DRHU NCNb C! SFbU DRHU NCNb C1 Sf'bU ORHO NCNL C1 DRHU NCNb C1 DRHU NCNb C1 DRHO NCNb Cl VALUk ll.80j -999.250 -999.250 -999.250 12.02~ -999.250 -999.250 -999.250 14.050 -999.250 -999.250 -999.250 12.1~4 -999.250 -999.250 -999.250 10.093 -999.250 -999.250 -999.250 3.B~7 -999.250 -999.250 -999.250 5.9~0 -999.250 -999.250 -999.250 7.447 -999.250 -999.250 -999.250 5.546 -999.250 -999.250 -999.250 DAT[II~I ~PECi~ICATION BLOCKS: ENTRY lC ~OUL SVURD# 1 DEPT 2 SP DiLf ] ILD DIL~ 4 ILM DtL~ 5 S~LU DILj 6 GR DIL 7 GR CNi, 8 CALl CNL/ 9 DRHO CNL' 10 NPH1CNL~ 11 ~MOB CNb~ 12 NRAT CNL 1] NCNb CNL 14 ~CNL CNL 15 GR BHC ~ 16 DT BHC ~ 17 C~ BGT 18 C2 BGT 19 GR DLL UNITS AP1 AP1 AP1 APl FILE# SIZE EXP PROC SAM REP D~PT SHl~'l ~T 0 0 O 0 0 4 0 0 i b8 0 0 MV 7 I 0 0 0 4 0 0 1 68 0 O UHMM 7 12 46 0 0 4 0 0 1 68 0 0 OHMM 7 12 44 0 0 4 0 0 1 b8 0 0 OHN~ 7 22 I 0 O 4 0 0 I 68 0 0 GAPI 7 ]1 32 0 0 4 0 0 I 68 0 0 GAPI 42 31 32 0 0 4 0 0 1 b8 0 0 IN 42 28 I 0 0 4 0 0 1 08 0 0 G/C] 42 44 0 0 0 4 0 0 1 68 0 0 PO 42 68 3 0 0 4 0 0 I 68 0 0 G/C] 42 35 I 0 0 4 0 0 1 68 0 0 C/C 42 42 I 0 0 4 0 0 1 b8 0 0 CPS 42 ]4 92 0 0 4 0 0 1 b8 0 0 CPS ~2 34 93 0 0 4 0 0 1 68 0 0 GAPI 60 31 32 0 0 4 0 0 1 68 0 0 US/f bO 52 32 0 0 4 0 0 1 b8 0 0 IN 70 28 13 0 0 4 0 0 I b8 0 0 IN 70 28 24 0 0 4 0 0 1 b8 0 0 GAPI il 31 32 0 0 ~ 0 0 1 b8 0 0 LENGTM: CUNPAN~: WELL: fILLD: RANGE,: TOWN: SECTION: STATE: INFORMATION 174 ~TES RECORD PT. THOMSON ~ILDCAT 1ON N. SLOPE ALASRA SCHLUMBERGER COMPUTING CENT~ 10707,61004 R~EL NEADER LENGI'H: 112 bYTES REEL NAME: P.C.A.L. SERVICE NAME: EDIT REEL CONTINUATION NUMBE~: 01 PREVIOUS REEL NAME: COMMENTS: LIS FORMAT CUSTOMER TAPE DATE: 80110120 TAPE hEADER LENGTH: 112 BYTES TAPE NAME: 61004 DATE: 80/10/26 SkRVICE NAME: EDIT TAP~ CONTINUATION NUMBER: 01 PREVIOUS TAPE NAME: C~MMENT~: TAPE COMMENTS RUN ONE-LOGGED 19-APR-80/JOB #60775/CASING DR1LLER 30" 9 69 /BIT SIZE 17.5/~PE FLU1D ~GM/DEN$ 8.9/V1SC 25/PH 9.5/FLUID bUS6 ~2.2/ PUN T~U-LGGGED 27-APR-$0/JOB #bl002/CASING DRILLER 20" ~ 2127/ T2Pk ~LUJD ~wG/DENS 9.0/VISC 70/P~ 8.0/FLUID LOSS 16 ML RM .86 ~ 75 D~/RMF .94 ~ 68 D~/RMC N-A/EM ~ BHT .75 PUN ~HREE-LOGGEO lb-OliN 80/JOB #61003/CASING DRILLER 1~.375 8 3422' BlT bIZE 12.25/TYPE ~LU~D LIGNO/OLNS 10.I/¥ISC ]4/PH lu-5/~LUID LOSS 7.6 ML/RM 1.85 9 62 DF/RMF 1.6b ~ 64 DF/RMC 2.04 ~ b0 D~/BM ~ BHT °90] ~ ~27 RUN ~UUR LUGGED 2b-AUG-80/JOB #61004/CABING DRILLER 9.~25 @ 11887 BIT SiZE 8.E/T~Pk FLUID LIGNO/DENS 15.6/VISC 51/PH ll.2/FLUID LOSS 4.2/EM !.43 8 54 D~/RMF .70 ~ 54 D~/RMC 3.b4 ~ 54 D~/RM ~ BHI .41 9 ~88 DF/ EXIT PII,E HEADER [,ENGIH: 62 BYTES ~Ih5 NAM~: ~DIT .001 MAXIMUM PHYSICAL RECORD LENGTH: 10~4 BYTES PREVIOUS ~IL5 NAME: FILE COMMENTS ~ORD 17 IS AN EXTRA GAM~A RA~ RUN THE ~ULL LENGTH O~ T~E ~LL ON DATA t~ORIV!AT 8PI~.CII~ICAT1UN LENGTH: 7'70 BITES ~YPE 0 SIZE 1 R&P CUD~ 0 llllII IIiIII 11 I1 11 II 1I II 11 1I II ii lIIlIi YY YY YY ~Y YY YY 000000 000000 44 44 000000 O00000 44 44 00 00 00 O0 44 44 00 00 00 00 44 44 00 0000 00 0000 44 44 00 0000 O0 0000 44 44 00 00 00 00 00 00 4444444444 00 O0 O0 00 00 00 4444444444 0000 O0 0000 00 44 0000 O0 0000 00 44 00 O0 00 00 44 00 O0 00 00 44 000000 000000 44 000000 000000 44 *STARi* USER PCAL [10707,b1004] JOB SHiP MONI]'OR SW$ hL10E40 SEP-80. ~'ILE: DSKHlVERi~Y,004<057>[10707~6:10041 CREATED: PRINTED: 26-OCT-80 22:4 QUEUE SWII'CHES: /~ILE:~'ORT /COPI~S:I /SPACING:I /LIMIT:lb4 /PORMS:NORMAL 3845 DAT~ 2b-OCT-80 26-OCT-80 22: 44: 26 22:48153 SHIP ~Q : PCCC THANKS 6H]PP1NG iNSTRUCTI[}NS ISSUED 26-OCT-80 17:29 BY CMC PCCC ,T SSSSSSSS HM HM SSSSSSSS MM MH SS HH HH SS HM HH SS HH HH SS ~H H~ SSSSSS HHHHHHHHHH SSSSSS HHHHHHHHHH SS HH HH SS HH MH SS HH HH SS HH HH $SSSSSSS HH HH SSSSSSSS HH HH I1 ii II II Iili IIII II II 1i II 1I II I1 Ii II II III1 IIII PPPPPPPP PPPPPPPP PP PP PP PP PP PP PP PP PPPPPPPP PPPPPPPP PP PP FP PP PP PP ~TTTTTTlll O00OO0 TTTTTTTT~I 000000 TT O0 O0 TT O0 uO TT O[] OO TT Ob OO ~T O0 O0 TT O0 O0 TT OD TT OO dO TT O0 O0 TT 00 UO I'T OOOOUO TT O00000 *START* 0SkR PCAL [10707,b1004] dom SHiP SELl. 3845 MONITOR SWS KLIOE40 SEP-80. *START* FILE: DS~H:SHIP.TO<255>[I0707 61004j CH~AIED: 2b-OCT-80 PRINTED: 20-OCT-80 2~:49:09 QUEUE SWI'fCHES: /~ILE:FORT /COPIES:I /SPAC1NG:I /hlMif:l~4 /I;OR~S:NORMAL DATm 26-UCI-80 22:48:53 17:29154
