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200-141
XHVZE Imagei~-'.oject Well History' File Cover F~" 'le This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. oo_-L L Organizing .7cAN Golor items: [] Grayscale items: [] Poor Quality Originals: [] Other: NOTES: BY: Well History File Identifier ~//Rescan Needed DIGITAL DATA OVERSIZED (Scannable) [] Diskettes, No. [] [] Other, No/Type [] Maps: Other items scannable by large scanner BEVERLY ROBIN VINCENT SHERY~INDY OVERSIZED (Non-Scannable) ~' Logs of various kinds /¢~,,~ Othe~/~ DATE: ~ /SI Project Proofing BY: BEVERLY ROBIN VINCENT SHERYL~WINDY Scanning Preparation ? x 30: C-~.!~ BY: BEVERLY ROBIN VINCENT SHERY~~INDY DATE: ~¢'/~'¢~'~,,.~ /S/ Production Scanning Stage I PAGE COUNT FROM SCANNED FILE: BY: Stage 2 BY~ (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES ) PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: YES NO , IF NO IN STAGE 1 ~ PAGE(S) DISCREPANCIES WERE FOUND: __ YES NO BEVERL~VINCENT SHERYL MARIA WINDY DATE~~~. ~S' ~~ RESCANNEDB~': BEVERLY ROBIN VINCENT SHERYL MARIA WINDY General Notes or Comments about this file: DATE': Is~ Quality Checked 12/10/02Rev3NOTScanned.wpd e r? jL J, .,-.J 'I ¡ ~J e FRANK H. MURKOWSKI, GOVERNOR Al'fASKA. OIL AlO) GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501·3539 PHONE (907) 279-1433 FAX (907) 276-7542 December 22, 2005 Doug Morgan EXXON Mobil Production Co. POBox 2180 Houston, TX. 77252-2180 Re: Alaska State A-I Alaska State A-2 Alaska State G-2 PTD 174-014 PTD 200-141 PTD 182-208 ,. ·/('hl~~I.f,¡ t <2>~~u\!~·~~t.. ./ ~) f'j Dear Mr. Morgan: The Alaska Oil and Gas Conservation Commission ("AOGCC") completed a location clearance inspection of the above reference wells. The AOGCC inspection showed the location to be in compliance with 20 AAC 25.172 Offshore Location Clearance. The Commission requires no further work on the subject well or location. However, Exxon Mobil will remain liable if any problems should occur in the future with these wells. Final location clearance is hereby APPROVED for the above listed wells. cc: Richard Owen cc: Steve McMains cc: Well Files • • file:///Untitled Good Afternoon Jesse, As you are aware, we have some concerns with your proposal. Our geologist is concerned about the well being deep enough at 2300'. We can probably prevail over that concern. I had Tom look at the rig to determine if it was capable of drilling 6._" hole to 2300' and run 2300' of 5" at (?) 11.5 lb =29,9001bs. The manufacturer's broacher gives the maximum depth as 1500' and a main hoist rating of 12,000 lbs. (Wayne Westberg told Tom that has been increased to 15,000 lbs. Tom has also reviewed the GRI wells that were drilled with that rig starting on January 9 and continuing thru April 14, 1998 (during that period they were down about 2 weeks waiting for a conservation order). They also shut down on weekends. The well depths 1730', 2105' and 2030". Approximately 5800' of hole were drilled. Jesse, that rig appears marginal to do the work that you want, especially in the winter months, unless you know something that we don't. We probably would not settle for a shallowere depth. ~~ 2~1G ~°' ~l~~~~~ JUL , ~.~, ~. ao~-~~~ l `1 ~~`y-\O 7/25/00 2:56 PM lofl Fla~nan Disposal Well-Rig Equip~perations Review Subject: Flaxman Disposal Well--Rig Equip/Operations Review Date: Tue, 25 Jul 2000 15:25:37 -0800 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Blair Wondzell <blair_wondzell@admin.state.ak.us> Blair, INTRODUCTION Fairweather and Exxon propose to drill a disposal well on Flaxman Island using a rig available from a local water well contractor, M-W Drilling owned by Wayne Westburg. The proposed rig was used by GRI to drill 3 of the Houston coalbed methane wells in the Valley. I have reviewed the operation reports from the wells to determine what the rig has done and maybe gain some insight into how operations might proceed on the slope. We have received a brochure from M-W that describes their equipment. The rig is a single unit mounted on a truck. The truck provides all power necessary to elevate the mast, rotate and trip the drill string. Auxiliary equipment used on the Houston wells included air compressors, a BOP stack, mud pump and pits. The planned drill string for ,~ the well is 4 , 9.6#, aluminum drill pipe in 25' lengths. A conventional steel BHA would be used as well. M-W also has tarp enclosures and a large Tioga heater. GRI WELLS The GRI wells were designed with 10 conductor pipe at about 40', 7" surface casing at about 500' and 4-1/2" production casing to a maximum depth of about 2000'. The wells were drilling primarily using air as the circulating fluid. Once air equipment problems were sorted out, drilling with air seemed to be successful. The main problem encountered was hole stability since the air column gives no support to the open hole. The drill string and other rig equipment performed reasonably well, again after equipment problems were overcome. The reports do not have any information of any problem with drill string. Cold weather and a single tower, weekends off operating schedule severely effected the operations. It did seem that once the equipment was operating and kept operating that work could proceed reasonably. Two major hydraulic repairs were performed during the work period. in the first case, the rig was moved to Anchorage for 3 days of repairs. The second occasion required about a day of repairs at the rig site. The drilling operation using this type rig is somewhat different than "true oilwell" type drilling. Depending on the depth, the rig can employ two hoisting means. At shallower depths, hoisting is accomplished by using the top mounted jib crane. Based on the owners information, this crane is rated for 15000 # load. Based on the air weight of the drill pipe, 100% of the rated load capacity is about 1600'. For heavier loads; the drilling head hoist is used. This necessitates screwing the drilling head into each joint to pull it out of the well. I am unable to determine the lifting capacity from the brochure and I do not have that information from Mr. Westburg. He has indicated that using that capability, the ultimate depth capability of the rig could be 3000'. That capability was 7/25/00 3:25 PM 1 of 3 Fla~nan Disposal Well-Rig Equip/Operations Revie~ • employed on the Houston wells. The casing operation is also different. At the Houston wells, the casings were run using a crane since the rig is not capable of handing 40' casing joints. The casing operations went reasonably well on the Houston wells. Shallow cementing jobs were disasters with pumps and welds failing. The methods employed can best be termed really poor boy. On the deeper strings, more normal oilfield equipment was employed and these operations were generally more successful. The Houston reports do not inspire much confidence in the equipment used. It does appear that after accommodating the cold weather and crew schedule that the equipment did work reasonably well, although 2 significant breakdowns were encountered. Based on the reports, the rig capably drilled to a maximum depth of about 2100' in air. This is 200' shy of the proposed disposal well depth. I do not believe that the additional 200' will tax the rig and that it should be able to drill to the proposed depth. As noted, if mud is used the drilling loads would be reduced by bouyancy. FLAXMAN DISPOSAL WELL At the present time we have a drawing of the proposed disposal well and the information packet presented at the DGC meeting. Fairweather plans to mobilize the rig to the island by barge in mid September and drill the well as soon as possible after that. It is planned to seta 7" conductor at about 100' and 5"' casing at about 2300'. In the meetings I have attended, I have asked Bob Gardner if air or mud will be employed as the circulating fluid. I haven't gotten a complete answer. At present I believe air will be used in the 8-1/2" hole and a final decision has not been made for 6" or 6-1/8" hole. As noted, using mud will favorably effect hole stability and an added benefit will be the bouyancy effect on tubulars. COMMENTS One thing I think clearly comes out from the Houston reports is the effect that planning or less than adequate planning can have on an operation. I believe that the Fairweather/Exxon proposal enjoys a significant advantage in the operational experience of those proposing the work. Mr. Gardner and his associates have been players on the Alaska scene for more than 30 years. He has been involved in a number of Arctic operations and has demonstrated a very clear understanding of how to plan and execute operations on the Slope. The proposed plan is "out-of--the-box" thinking, something Mr. Gardner and Fairweather have been known for through the years. I don't believe that Fairweather/Exxon would come to us with a proposal that won't work. However we have not, thus far, received sufficient information to make our analysis. The history of the Houston wells raises a lot of questions that must be answered including... --How deep can the rig drill...is it stretched reaching 2300'? --Will mud be used in the 6" hole section? --Is the rig mechanically sound...will major spare parts be available at the site? --Can the rig effectively operate in the weather expected in late Sept thru Nov? 2 of 3 7/25/00 3:25 PM Fla~nan Disposal Well-Rig Equip/Operations Review I support the questions raised in your email to Jesse. Please tet me know what further information I can provide. Tom Tom Maunder <tom maunderCa.admin.state.ak_us> Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 3 of 3 7/25/00 3:25 PM ~~r ~- ~ • S ~r.~.~rop~r-~`5 1 car~c~c~.~c.~ ~ ~~~~~ 4o y~~t.~~. ~~ c~r~ ~-.k ~tcc,~~ ~, ~r~l~c~. ~02~~ C (~~~l~n•,s ~~eR~ ~1~~ ~~,~~ ~ ~~s~~ ~- ~ ~~ ~ ~~~ S ~ }-o ~t~ on c~.~vw:, ~U ~ ~~ ~e. ~ ~s~~ cnv~ c~~ ©~E~ ~~ ~ ~~ 1 ~`c ~ S ~ ~E~ ~ ~s ~J~b~cS (~D w ~ o,~~~ ~e~~~ ~o ~ ~ ~, ~~~ \ _~ ~vS~~~ ~'~~~ ~~~~~~<LS ~r~~~~~ r ~~~ ~~~~~~~~~~~~~i<~it~~~~~C~~~~~~~~~~~~~~~~~C~~~~~~C~~~~i<~~C~~~~~i;i<~~~~~~i<~~~~~~~~~~~~~it~C~~~~~~~i<~~~~C~~~~~~~~~Ci<~~ ~ ~ P, 01 ~ %K TRANSACTION REPORT ~ ~ JUL-25- 00 TUE 09 30 AM ~ ~ ~ ~ SEND (M) ~ ~ ~ ~ DATE START RECEIVER TX TIME PAGES TYPE NOTE M# DP ~ ~ ~ ~ JUL-25 09;22 AM 12022259297 7'33" 11 SEND (M) OK 097 ~ ~ ~ ~ ~ ~ TOTAL 7M 33S PAGES; 11 ~ ~ ~ ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~c~~~~~~~>K~~~~c~~~~~~~~~c~~~~~~~~~~~~~~~~c~~~~c~~~~~~~~~~~~~~~~~~~~~~~~~~ 3001 PORCUPINE DR, ANCHORAGE, ALASKA 99501 Ph:907-793-1241 /Fax: 907-276-7542 E-mail: steve_mcmains@admin.state.ak.us ~- To: Fax: Mike Henry 1-202-225-9297 From: Pages: Steve McMains ~ 1 pages (includes cover) Phone: Re: 1-202-225-5255 Qffshore Production Date: CC: 07!25!00 [Click here and type name] Urgent D Far Review ^ Please Comrreent O Please Reply ^ Please Recycle ttoc3~pt~ ~ \ i~Qce~p~~~~css~ts ~ c._o~~c~~©~q ~S~ ~~~-~~ p,~~~ F- ~ ~~~ Q `ems i~~ c~r~.~~- ~cs~ S c~ r~~~ c) ~o2~P C.. ~~~ PE ~v~ o~c, -- CGn'c~C~~~~ ~~ ~o~h~S ~~ ~~~~ ~ov~ ~ ~•S~a~ ~ ~ ~~~5 ~~~Cc P~ ~~ C~ (~ c ~~ ~S s ~l s ~`~. ~o ~ ~ ~~~~t ~ cc, ~~e'~~ crS wct'~ ~' vJ~- ~~~ ~~ ~ ~.~~ ~n ~.~~~~~~~ ~~~~~~S~~ro~p c~~ ~~~~- ~~a ~~ ~1~~-~C~ ~~ ~ 1~~~c ~-~.~~~c-s. ~~ ~ ~r ~ ~~ ~ S~o~S~~~~~~°b\~M S L ~~d c ~, c~~~~- ~ ~S ~~~~1~ ~~ 5 o~~~~ ~e~~.~ ~~ ~ ~ ~ ~~~~ ~,,~~~.~~ <~s Q~b~-~~ ~~~ ~i 50 L L i~ A 111 C / t l I D ri I I a pr w p ~~ ' ~` ~~~- T~y •,~ ~ , rF . _ ti,. ,~ ,: - ~ _ p EC ~ rrJ~`K. "o '4 r r .'~ ~~ " ~ Y "' ~ .: ~V s '~` ~: t a +~ A ~ ~ l i r~ S ~ s< Y` ~' ~ ~ t t ' ~ t ~ ~ 4 ? $ , ~~ ~ ~ r . . " ~.. , ~ h~~ ! 7 F A9 R ,~` .. r, n F~t ':a~ ~9 Y.,+L4-y)~',_ ^' x s .. ~) ~ ,~4p,,'~ '::k r ,a .~..-::.pH. ?y .r~ ...~ ~'h ,) y.., x, _. r. • • For over 125 years Ingersoll-Rand drills have had a major impact on the drilling community worldwide and have set the standard for quality, reliability, longevity, and performance. The T2W is no exception. In the 30,000 Ib. class, this newest addition to the I-R waterwell line offers flexibility and value you would expect in a much larger drill. Much of what makes the T2W a premium drill is not readily visible. Every component on this machine is selected for its proven reliability, long life, and maintenance-free characteristics. Further, the simple design, ease of operation, and flexibility of the T2W will continue to reap benefits far into the future. The patent-pending single-cylinder cable feed system, together with the single-pole derrick and rotary head, are the pulse of the T2W. The feed system is internal to the derrick, an arrangement that both protects the moving components from exposure to the elements of the typical drilling environment and rod handling operations, and assures the operator low maintenance and longer component life. The premium cylinder packing and sheaves were chosen for their superior quality and proven reliability, strength, and wear. Care has been given to reduce maintenance. All bearings, sheaves, pins, and other major components are larger than required and internal bearings are packed with a new, semi-solid, maintenance-free lubricating compound. Cables are easily replaced by attaching the new cable to the old one and pulling it into place. 1 e The double-ended rod, double-acting cylinder ©is constructed of the highest quality and most reliable packing materials available. The rotary head p moves up and down the derrick at a 3:1 ratio to the cylinder. The feed sheaves p and guide rollers p are constructed of Nylatron° GSM for long life and minimal wear. Premium galvanized feed cables ©operate at a 3:1 reaving ratio resulting in overall short cable length and less stretch. The cable, which is detachable at the wedge-type cable anchor O, is adjustable at the cable anchor external to the derrick p. U • • The 12 in. x 16 in. tubular derrick, though lighter weight than the traditional lattice-type derrick, provides superior strength and resistance to linear and torsional deflection. The standard derrick is designed to accommodate a casing hammer, dual wall systems, or drill and drive systems. Wide open on three sides, the T2W derrick provides more working space for the operator and helper. This open system minimizes manual labor and provides more room for handling augers, drillpipe, or casing. The 12,000 ft-Ib., 3-speed rotary head, standard on the T2W, is constructed of oversized gears, shafts, and bearings and provides tremendous range to optimize performance with augers, air/mud rotary, or a down-hole drill in any type of formation. The rotary head slides off the hole both left and right to load or unload drillpipe from the carousel or to clear the hole for handling pipe with the main hoist, auxiliary hoist, or sand reel. Built-in sensor systems reduce feed pressure when the rotary head slides off hole to prevent possible damage to the carousel and drillpipe. A similar system reduces hoist pressure when the jib boom moves off center. These safety systems protect the rig without interfering with operations. • Every Ingersoll-Rand machine that leaves the factory must first pass a series of rigorous performance tests. The T2W was put through an additional battery of structural and performance tests at the Garland Engineering Test Center to confirm that it is the exceptional drill it was designed to be. The rig was then driven down to the rugged hill country of South Texas where a non-I-R drilling contractor put the drill to work testing its limits. Day after day, this phenomenal drill exceeded everyone's expectations. :;. '~- ~~, v ~` ~` • ~.° a~ ed~a ~: r ~~ Simple, lightweight, and economical, the T2W is the most flexible waterwell drill in its class. With the T2W, there's no need for optional feed packages, or pipe handling systems, or special rotary heads that have either speed or torque. The standard T2W has more feed power and speed... more rotary torque and speed...more pipe handling versatility with a carousel, heavy drawworks, and a pipe rack than most larger, heavier, and more expensive rigs. The lightweight T2W base machine is mounted on a Navistar 2654 with a 300 HP engine. This rig is designed for on-board mud and development air. The larger T2W base machine, mounted on a Navistar 2674 with a 400 HP engine,. has an Ingersoll-Rand 750/300 compressor on board and can use one of several available mud systems. Standard equipment on both machines includes the 30,000 Ib. cylinder feed, high torque 3-speed head, carousel, jib boom, pipe rack, and 12,000 Ib. main hoist. • ~l~ -~i~.: The rotary head slides off hole to load and unload pipe from the carousel. Hydraulic carousel rotation is standard. Dual hoist and jib controls allow the helper to load and unload the carousel from the helper's side. With this system, the carousel can be used to handle pipe from top to bottom. The T2W is also set up to be used like a kelly system. Pipe changes can be made off the bottom by sliding the head off hole with the last drill pipe and adding pipe with the hoist. With this method, pipe can be stripped from the hole with the main hoist. The T2W is set up to handle pipe according to operator requirements. A carousel delete option is available if no carousel is needed. The main hoist and jib boom can be positioned over the hole or over the carousel or pipe rack, or positioned for working from a service truck. Dual controls allow the driller and/or helper to control pipe handling. T2W pipe handling sets a new standard for flexibility, safety, speed, and reduced manual labor. • a 400/200 compressor (available on base model one only) • four mud pumps, one with a 350 gallon swing-up mud pit • a large tool box with fold-down door and lock .-~. z.~l. ~ i, ,ems ~~ ~ ~y The T2W incorporates design features and operator benefits developed by Ingersoll-Rand engineers with years of experience and practical drilling knowledge. Service and support are provided by a large worldwide network of well-trained parts/service specialists. MANUFACTURER'S RATINGS Depth/Diameter 1,500 ft. (457 m)/6 in.-24 in. (152 mm-610 mm) Applications Waterwell/environmental, air rotary, DHD, auger AVAILABLE COMPRESSORS CFM/PSI 4001200 (11.33 m3/min/1,379 kPa) (optional-small base machine) CFM/PSI 750/300 (21.24 m3/min/2,068 kPa) (standard-large base machine) MATCHING POWER SYSTEMS Manufacturer/Model, HP @ RPM IHC, 530E Diesel/300 (224 kW) Cummins, N-14/400 (296 kW) @ 2,100 ROTARY HEADS Type 2-motor spur gear, tophead, 3 speed Torque/RPM 12,000 ft.-Ib. (113 Nm)/0-80 8,000 ft.-Ib. (75.325 Nm)/0-110 3,500 ft.-Ib. (3.95.4 Nm)/0-275 Swivel/Spindle 2-1 /2 in. (63.75 mm)/3-1/16 in. (77.8 mm) ID Other Features Hydraulic oft-hole slide, left/right HOISTING SYSTEMS 1) Function, Pull, Speed Main hoist w/jib boom, 12,000 Ib. single line, 150 ft/min. (5,443 kg., 45.7 m/min.) 2) Function, Pull, Speed Auxiliary hoist w/integral brake, 6,000 Ib. single tine, 100-300 ft/min. (2,722 kg., 30.48-91.44 m/min.) 3) Function, Pull, Speed Auxiliary hoist w/integral brake, 8,000 Ib. single line, 85 ft/min. (3,629 kg., 25.9 ft/min.) 4) Function, Pull, Speed Auxiliary hoist w/integral brake, 4,000 Ib. single line, 120 ft/min. (1,814 kg., 36.6m/min.) 5) Sand Reel 2,000 Ib. (907 kg.) capacity DERRICK Type, Features Single-pole, 12 in. x 16 in. (305 cm x 406 cm) structural steel tubing 50,000 Ib. rating (22,680 kg.) Centralizer Rear section swings out from either side; front section retracts with hydraulic cylinder Clearance 21 in. (533 mm) PIPE HANDLING The T2W is designed to drill in and out with the carousel or to drill in like a kefty rig and strip the hole with the main hoist. The standard unit includes a carousel, jib boom, and main hoist as well as a pipe rack. Pipe Sizes 3-1/2 in. or 4-1 /2 in. (89 mm or 114 mm) Carousel Capacity (9) 3-1 /2 in. x 20 ft. (89 mm x 6.1 m) or (7) 4-1 /2 in. x 20 ft. (114 mm x 6.1 m) Pipe Rack Capacity w/o carousel (12) 4-1 /2 in. x 20 ft. (114 mm x 6.1 m) or (20) 3-1 /2 in. x 20 ft. (89 mm x 6.1 m) w/carousel (10) 4-1 /2 in. x 20 ft. (114 mm x 6.1 m) or (15) 3-1 /2 in. x 20 ft. (89 mm x 6.1 m) OPTION SELECTIONS OVERALL DIMENSIONS Height: Travel/Drill Width Length: Travel/Drill Average Weight, Less Pipe Estimated Average Drilling Weight Auxiliary hoists (4) DHD lubricator Water injection (4) Mud pump (2 deck-mounted) Mud pump (mounted beside rear jack) Mud pump (w/swing-up 350-gallon mud pit) Large toolbox 11 ft. 7 in. (3.530 m)/41 ft. (12.49 m) 8 ft. (2.438 m) 33 ft. 9 in. (10.287 m)/30 ft. 9 in. (9.37 m) 44,630 (20,244 kg.) 50,500 (22,906 kg.) A~~x ~~ '~ ~ ~T "x r Alaska State A-1 (74-014~4nnulus Fluids • Subject: Alaska State A 1 (74-014)Annulus Fluids Date: Mon, 24 Jul 2000 13:41:19 -0800 From: Tam Maunder <tom maunder@admin.state.ak.us> To: Blair Wondzell <blair wondzell@admin.state.ak.us> Blair, As assigned, I have researched the files regarding the fluids !eft in the various annuli and the 9-5/8" production casing of the subject well. With two exceptions, I have found the information as presented in Fairweather's report of the winter work of 1998 to accurately show the various fluids left in the wellbore. The exceptions are discussed below. r~~~ ~ ~~ Refrigerated Conductor: 36 x 30 x 28 @ 80' x 54' x 80'. ~'ie refrigerated portion ofthis assembly originally had 50/50 ethylene glycol and water in the grculating system. Foam insulation was included as well and the' entire assembly was semen#ed to surface outside the 36". There is no information on the 50/50 mix having been removed prior to the original abandonment. Fairweather makes no mention of encountering any fluid when the casings were- severed and the pictures do not show anything unusual. 9-5/8" x 12-1/4" open hole: 4n Fainneather's diagrams, there is no notation of what fluid was in the hole when the 9-5/8" easing was cemented. According to Exxon's".reports, 13 ppg mud was in the well when the casing was cemented. Fainnieather's work would not have changed this. Following Fairweather's 1998 work, the only hydrocarbon fluid within the A-1 wellbore is Arctic Pack in the 13-3/8" x 9-5/8" annulusfrom 231' - 1996'. I have drawings depicting the originally abandoned condition and as modified by Fairweather in 1998. Let me know if you require further information. Tom 1 of 2 7/24/001:41 PM •• ~• All Depths RKB RKB = 41' MLLW Grade p15' MLLW ~ ~ 36", 32", 28", 20", .~ 0 ~ N M D" 13 3/8" and 9 5/8 Casings Severed at _ 66' RKB w85~ - Casing Cut/Perforated ~ at ~ 231' . } _ . . 824' Plug #4, 85 sx 5 *t5 Permafrost ~aC 3,400' to 3,200' 13.o peSM~ ~~I16'1S --~ 9,100' 4 ~ 15s' 1 b `~ 10450' Cement Plug #3 `~its_'~S 1o,soo' to 1o,s5o' 1 o,77s' 11,076' ~ Cement Plug #2 12,450' 511~-'1b~ 50 sx G 12,700' All Casings Removed to 66' RKB Except 36", 3/8" Wall Casing Removed to 46' RKB 36"x32"x28" Insulated/Refrigerated Structural Coring Cemented to Surface with 350 sx Permafrost Cement in 9 5/8" Casing and 13 3/8"x 9 5/8" Annulus from 231' to 66' RKB 20", 94#, H-40, Cemented to Surface with 2,400 sx Permafrost F.O. Collar ® 1996' 13-3/8", 72#, N-80 Cemented with 3,100 sx Permafrost and 250 sx G, Cemented to Surface Calculated TOC Behind 9-5/8" Casing ®9,100' CIBP 9-5/8", 43 & 47#, S-95 & P-110, Cemented with 2,250 sx G Perfs, 2 spf, 12,565'-12,610' and 12,620'-12,635' Cement Plug #1 12,900 EZ Drill Cement Retainer with 100 sx ~'1(S_.~s 100 sx G Squeezed Class G Squeezed Below Through EZ Drill ..,.;~~ ,_ ,, . _ 12,897 ~ 7" Liner, 35#, S-95, Cemented w/1,450 sx Class G 5-7/8" Open Hole LEGEND TD 14,206' ® 15.4 ppg Mud Cement Arctic Pack ® (Crude Oil Base) Diesel NO SCALE FAIR/EXKON/EX498A1 1:1 6/15/98 SR Figure 1 EXXON Company U.S.A. Alaska State A-1 Wellbore Schematic, April 1998 1,996' 3 376' } a . ` SCHEMA Tlc /~E~`RI ~ER,9 TEf~ C`0!~~' T0~ TO P/~Et/~NT ~rIN~ PERMAFRf~S T ,( r/yC o~~i-ef~ 28 "- 3L" ah~ (o Each-/"D froh-r hezdi -~ SO% ~/yco/ in W2fei- So/u t: orr /yco/ ~r!'fctrr/ fo e {r%ye ra f.'ors uni t f a~jdrox. /6 °F %h nth? r F 2 ~f °F : /7 u ry, ir-C r /yca/ ~`sNpp/y fray! °f/'"i~~rafion ur.'f /~ °.~ /y.c o J ~"supp/y header era ve/ we // pad urface C?ia. piPL° did. pi/~' Sealed of L8"O:a, ~oipe /afio~ r asse~6/y set C t°iy1 PH J/P!1 7Fo SUr7~d~° 20"Cas%nJi s"et of 800' F CPmPNfP4~ /'O Surfdel° /3~/S~Casiny sit a;t 3000 E CF/yiEhf~d fo SurfacE 9 S~ ~~ Cas %hy ~M 4 Z2-7S •• ~~ Welded Steel Plate and Abandonment Marker All Depths RKB RKB = 41' MLLW 25' Top Cement Plug "~ : }~ :.. fi '~ '' 't in 9-5/8" Casing _ : t . :; . _ ':' : ;. _ t:e~~~ ~ ~ _ ~~ _:; t , R,85' ~ . .'.'. ~=r ' - 30" Insulated Structural Casing "•` = '"`' '7 .> _ ;'~' Cemented to Surfoce with 350 Diesel in 9-5/8° Casing ~.:? - ~ s ; _.- - =' " f . x.. ~• •' ~ sx Permafrost from t,500' to 25 "';• ~`'~ ~ l '` _#~~` 824.° ,= _:; _- 20", 94#, H-40, Cemented to Surface with 2,400. sx Permafrost yc ~3r `f'~ Collor ® 1996' F.O 1,996' - ...., sv . Plug #4, 85 sx permafrost 376' 3 "' ''= • ~.. •`2'>"<~,'-• ~.:"•"~> `~r ' `~ : ` ` 13-3/8", 72#, N-$0 Cemented with 3,400' to 3,200' , -y': • := 3,100. sx Permafrost and 250 sx G, Cemented to Surface 100' 9 ' - Calculated TOC Behind 9-5/8" ' , =• :~; Casing ~ 9,100 10450' +j4; . r,i.~ ' CIBP Cement Plug #3 s~'~~ 10,900' to 10,650' 776' 10 :~- ... i<:-;~'-. :• ,;,:x .,,_ it ~` '-:{: ... , ~ - ~ 's 11 076' ~ 9-5/8", 43 & 47# S-95 & P-110, , Cemented with 2,250 sx G Cement Plug #2 50 sx G 12,450' = ~ ~ _ Perfs, 2 spf, 12,565'-12,610' 12,700' - '~ ~~ and 12,620'-12,635' Cement Plug #1 ' s::• ~:`' EZ Drill Cement Retainer with 100 sx 100 sx G Squeezed 12,900 . i ? ~ Class G Squeezed Below h EZ Orill Th ?'' roug gg7' 12 =`•t~~`-~ 7" Liner, 35#, S-95, Cemented , - w/1,450 sx Class G 5-7/8" Open Hole LEGEND ® 15.4 ppg Mud TD 14,206' Cement Arctic Pack ® (Crude Oil Base) Note: ~+ Diesel Current well status as of Post sundry 25-Feb-98 . schemotic to follow with completion report. NO SCALE FAIR/EXXON/FLAXAI-2 1:1 2/24/98 SR Figure 2 EXXON Company U.S.A. Alaska Stote A-1 Wellbore Schematic 0850 Pull Exxon Alaska State A-1 file (74-014) spud 3-23-75, abandoned 9-21-75 20" @ 824' w/ 2400 sx 13-3/8" @ 3376' w/ 3100 sx PF and 250 sx G, 17-1/2" hole logged, FIT to 13.5 ppg C~ Calculations: 13-3/8" in 20" 94# casing to 824' and then in 17-1/2" gauge hole to 3376' 824 x 1.0190 cubic ft/ft = 840 cubic ft (3376 - 824) x .6946 cubic ft/ft = 1772 cubic ft Lead cement volume: 3100 sx x .95 cubic ft/sx = 2945 cubic ft Tail cement volume: 250 sx x 1.15 cubic ft/sx = 288 cubic ft Open hole XS based on total cement volume = 2945 + 288 = 3233 total 3233 - (840 + 1772) = 621 cubic ft 621/1772 = 35% XS The report states, obtained full returns. It is not specifically noted that cement was circulated. It is not indicated that the plug was bumped. It is stated that the casing was tested to 3000 psi. During the re-abandonment in April, 1998 the casing strings were explosively severed approximately 40' below grade. A digital photo was provided showing all strings joined as a unit. Based on having attached a starting head to the 13-3/8" casing, it is clearly evidenced that there is cement in the 20" x 13-3/8" annulus. Based on the available records, the 13-3/8" casing was cemented to surface. Reports detail that Exxon pumped water from the reserve pit into the sea!!! It is also noted that there are two FOs in the 9-5/8". Lower one is at 1996' and upper one at 1003'. After disposal, ultimate plan is to squeeze through lower one and displace non-freezable fluid to surface through upper one. Disposal down 9-5/8" x 13-3/8" annulus began 8/12/75. Maximum reported injection pressure was 1250 psi but declined. Reported pressure about 3 hours after starting was 900 psi @ 5.5 bpm. Pressure continued to decline to 750 psi 4 hours after starting and 600 psi 13 hours after starting. 19 hours after starting total injection was reported to be 6000 bbls. Injection continued. August report notes that between 8/13 and 8/31 53534 bbls of reserve pit liquid was injected. Breakdown occurred at 700 psi and average pump in pressure was 250 psi at 75 barrels per hour. September report notes that between 9/1 and 9/15 17466 bbls was injected. Total 71000. 9/18/75 pumped produced oil into annulus followed by 300 bbl arctic pack. 9/18/75 squeezed 9-5/8" x 13-3/8" annulus via FO at 1996 with 300 sx PF. Pressure 1000 - 900 psi. Noted that annulus pressure was 25 psi. ~~ •• Summary of Operations Permanent Re-abandonment Exxon Company, U.S.A. Alaska State A-1 Flaxman Island Area, Beaufort Sea, Alaska Exxon Company, U.S.A. (Exxon) drilled the Alaska State A-1 well on Flaxman Island in the Beaufort Sea in 1975. At the completion of drilling and testing operations, the well was plugged downhole and at the surface. Prior to abandonment, diesel was placed in the 9- 5/8 inch casing from 1500 feet to within 25 feet of the surface. The diesel served as freeze protection in the event that the well was to be reentered at a later date. A 25 foot cement plug was set on top of the diesel. The A-1 wellhead was subsequently cut off in 1986 and a marker post affixed. Since drilling the well, Flaxman Island and neighboring islands have undergone natural erosion and migration due to wave and storm action. Exxon performed a site inspection at the A-1 well site and three other Flaxman Island area wells (Alaska State D-1, F-1 and G-2) on October 25, 1997. The well site inspection revealed several of the wells and related appurtenances had been exposed by erosion or could be in the future. Exxon elected to re-abandon the A-1 well in compliance with current AOGCC abandonment regulations to ensure that the well is not exposed or impacted by future erosion of Flaxman Island. Figure 1 depicts the final status of the A-1 well. Figure 2 presents the final condition of the well in relation to island level. The A-1 well was re-abandoned as part of a multi-well program that included re- abandonment of the Alaska State D-1 and F-1 wells. Final details for the D-1 and F-1 re- abandonment operations are covered under separate Reports of Sundry Well Operations. The re-abandonment of the A-1 well included the following operations: 1. Excavation to 6 feet below grade around the A-1 well to expose the well casings. Removal of the 36, 32, 28 and 20 inch casings to excavation depth to access the 13-3/8 and 9-518 inch casing strings. See Photo 1. 2. Dressed off the 13-3/8 and 9-5/8 inch casing stubs and install a 5000 psi WP slip on starting head on the 13-3/8 inch casing. Tested slip on head packoff to 1600 psi. 3. Installed a 7-1/16 inch, 5000 psi WP, double ram BOP stack fitted with one set each of blind and shear rams. See Photo 2. Tested the BOP stack to 600 psi maximum before pressure bled off through cement plug. No leaks in wellhead or BOP stack or pressure increase in annulus. AOGCC A-1 Sundry 06/15/98 1 ~• •• 4. Rigged up coiled tubing lubricator, BOP's and injector head. See Photo 3. Made up a 2-7/8 inch motor and 6 inch mill and drilled out the cement inside the 9-5/8 inch casing. Chased cement plug downhole to 230 feet while- milling on plug. No pressure on the 9-5/8 inch casing after drilling through plug. Pull out of hole (POH). 5. Run in hole (RIH) with coiled tubing to 335 feet. Encountered obstruction. Pressure tested against obstruction to 1200,1400, and 1500 psi in 5 minute increments with no bleed off. POH. RIH to 355 feet and displace diesel with 15.4 ppg saltwater base, non-freezing mud. Plug at 335 feet disappeared. RIH to 454 feet and encountered impassable obstruction (possible collapsed casing). Pumped mud down coiled tubing allowing mud and diesel to swap past obstruction. Recovered approximately 110 bbls diesel in surface tanks. POH. ~ ~5~~- vin ,o~-~a b.,y~.~ = ~5 tea' 6. RIH with 2-7/8 inch motor and 9-5/8 inch casing underreamer. Underreamed upper 250 feet of 9-5/8 inch casing. POH and rigged down coiled tubing unit. 7. RIH with explosive 9-5/8 inch casing cutter to 205 feet below grade. Detonated charge and cut casing. Casing perforated but unable to be pulled free from well. Confirmed ability to circulate down 13-3/8 x 9-5/8 inch annulus and up 9-5/8 inch casing. 8. Rigged up batch cementing unit and. circulated water down 13-3/8 x 9-5/8 inch annulus to clean up crude oil arctic pack in annulus. After cleanup of annulus, pumped. a 140 sack (24 bbl) permafrost cement plug down the 13-3/8 x 9-5/8 inch annulus and up the 9-5/8 inch casing. Reverse circulated water at 35 feet through 2-7/8 inch tubing to clean out any cement above 35 foot depth. Bled off approximately 15 to 20 gal of water out 9-5/8 inch casing while cement plug u-tubed down annulus and up casing. AOGCC representative declined to witness cementing operations. WOC overnight. 9. Rigged up a 6 inch O.D., 50 Ib Composition B explosive charge on rope and ran in well to 40 feet below grade. Detonated charge to sever casing strings. All strings cut with 32, 28, 20, 13-3/8, and 9-5/8 inch casings partially climbing out of hole due to explosive force. See Photo 4. Removed 36 foot long casing stubs from excavation. Inspected 13-3/8 x 9-5/8 inch annulus and found excellent quality cement in the annulus with no evidence of any residual crude oil in annulus. 10. Rigged up octagonal 50 Ib Composition B charge and ran in 36 inch outer casing to 40 feet. See Photo 5. Detonated charge. Unable to pull casing with crane and backhoe. Steam thawed casing. Recovered upper 20 feet of 36 inch O.D. 3/16 inch wall casing. Casing recovered in small sections due to inability of thin wall casing to withstand pulling force. 11. Beat the remaining 36 inch casing stub down a minimum of 20 feet below grade after consultation with Blair Wondzell of the AOGCC. AOGCC A-1 Sundry 06/15/98 2 ~~ ~~ 12. Backfilled the excavation and mounded the backfill approximately 10% to account for settling. See Photo 6. 13. Picked up all remaining debris on location and demobilized equipment to Deadhorse or other wells in the re-abandonment program. 14. A location clearance visit with the AOGCC and other agency representatives is scheduled for summer 1998 after the snow cover has melted. All liquid wastes recovered in the A-1 re-abandonment program were transported in secure vacuum tanks to Deadhorse and injected at Pad 3 in accordance with AOGCC, ADEC and EPA regulations. Waste hauling tanks and trucks were cleaned at Peak Oilfield Service Company's wash bay in Deadhorse. The A-1 wellhead and cemented casings were transported to the North Slope Borough Solid Waste Disposal Site for disposal. All clean scrap metal was sent for recycle. AOGCC A-1 Sundry o6nsi9s 3 Fiaxman Island Sea Ice Surface ~ 15' Level MLLW ~ 10' _.'•~~ .. 36", 3/16" Wall, Island Toe 20' Long Casing Left >20~ Below Grade NO SCALE FAIR/EXXON/EX498D4 1:1 5/26/98 a .. .~. :•, `. ~ " ' ~ To Mainland X25' Coast, Southwest Seafloor A-1 Well Casings Severed at 40' Below Grade Figure 2 EXXON Company, U.S.A. Alaska State A-1 Location, Elevation View, Looking Southeast Flaxman Island, Beaufort Sea Photo 1: Cutting away 36, 32, 28, and 20 inch casings Photo 2: 13-5/8 inch 5000 WP psi wellhead section with I from the R-1 well. 7-1116 inch 5000 WP BOP stack installed. Photo 3: Rigging up coiled tubing unit on the A-1 well. Photo 4: A-1 well casings after being cut and blown out of hole with 50 Ib Composition B explosives. ~~ ~~ • • ALASKA OIL AND GAS CONSERVATION COMMISSION F ~csxr~cs,~ ~~cS,rc 1 ~c-o~~c~- Meeting Subject Date/Time NAME -AFFILIATION TELEPHONE (PLEASE PRINT) 4. crz,l'L.H'., ~'yc,lz-nr~/' ~Yxcn /"1G~.' ~D!'~~/lv-':>~~~~ ~ /~SSe. `'!a ~rba~~i,~~~ ~, liv>e~-~i 9~7 ~Sg 3 ~~ ~'h;kE T3a~~ ~x~n~o~« ~©~-s~~ - spar W EN~D~I M A N A n) ,'~ o y Ct~ `~ 9 3- l z3 b ~LcQir U 1~td-c.e.C 1 ~4~9 ~~ c, c.~ -1 cI 3 -( 22 co G ~ K S ~ ~ .~C~ G-c-C_ • • x 100' Tubing/Casing Annulus Freeze Protected w/CaClz Brine. Stage Cementing Tooi ®%+1,100' Additional Potential Disposal Zones 1,715' - 1,750' 1,770' - 1,820' 1,990 - 2,070' x2,130' LEGEND t~f. Cement x2,300' NO SCALE FAIR/EXXON/2000/FLX 82000 1:1 7/14/00 SR 7' Surface Casing Permafrost Interface Q x1,050' 2 7/8" Tubing 5° x 2 7/8" Packer Potential Disposal Zone, 2,150' - 2,300' 5" Production/Disposal Casing Figure 2-1 Flaxman Island Disposal Well Well Schematic All Casings Cut x30' Below Grade 100' 7" Surface Casing Tubing Cut ®200' with 170' Cement Plug on Top. Permafrost Interface ® x1,050' Stage Cementing Tool ® x1,100' x2,130' LEGEND ?`y Cement All Perfs Squeezed x2,300' No scaLE FAIR/EXXON/2000/FLX2000 1:1 5/15/00 SR 5" Production/Disposal Casing 5" x 2 7/8" Packer Disposal Zone, 2,150' - 2,300' Figure 2-4 Flaxman Island Disposal Well Post Abandonment Well Schematic F:\LaserFiche\CvrPgs _ Inserts\M icrofi I m _ Marker.doc MICROFILMED 04/01/05 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE ,'\II"~' If' "';~........ ,.¡¡" ,'.; ') ') Permitto Drill 2001410 DATA SUBMITTAL COMPLIANCE REPORT 713112003 Well Name/No. ALASKA ST A 2 Operator EXXON CORP ~'/1~o. 50-089-20028-00-00 MD 2415 ~-~ '[VD 2364 Completion Dat 2/1912001 Completion Statu WDSPL Current Status P&A UIC Y REQUIRED INFORMATION Mud Log ~ Sample No Directional Survey No DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Log/ Data Digital Digital Type Media Fmt (data taken from Logs Portion of Master Well Data Maint) Interval Log Log Run OH I Dataset Name Scale Media No Start Stop CH Received Number Comments Well Cores/Samples Information: Name Interval Dataset Start Stop Sent Received Number Comments ADDITIONAL INFORMATION Well Cored? Y ~1~ Chips Received? ~ Analysis ~ Re. ce. ivy. d? Comments: Daily History Received? ~)/N Formation Tops Compliance Reviewed By: Date: P LUGG-_,NG & LOCATZON C L E_~_R3_NCE REPORT Stata cf Alaska 01L & GA~ C-~NSERVATICN CCM~IMSION ALASKA 01L AND GAS CONSERVATION COP ISSION December 19, 2002 FRANK 14. MURKOWSKI, GOVERNOR 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 F.E. Hand, Jr. Global Remediation, Major Projects - Upstream ExxonMobil 601 Jefferson KT 1244 Houston, Texas 77002-7901 Re: Final Location Clearances Alaska State A-2 (PTD 200-141) Alaska State A- 1 (PTD 174-014) Alaska State G-2 (PTD 182-208) Dear Mr. Hand: On August 22, 2002 our Inspector John Spaulding performed a final location clearance inspection of the recently abandoned Alaska State A-2. The A-2 well was plugged and abandoned during this last winter season. Inspector Lou Grimaldi witnessed the pressure testing of the deep plug on March 8 and Inspector John Crisp witnessed the severing of the casing strings below the mud line on March 14. In addition to inspecting the A-2 location, Inspector John Spaulding also examined the locations of the State A-1 and G-2 as well. During the past several years, much activity has taken place on Flaxman Island with the "re- abandonment" of the State A-l, drilling and abandonment of the disposal well State A-2 and the ultimate removal of the reserve pits at the A-1 and G-2 locations. During theses operations, AOGCC Inspectors have performed a number of inspections at this remote site. On this latest inspection, Mr. Spaulding found the locations to be in satisfactory condition and concluded that all wells be approved for final location clearance. The Location Clearance inspection showed the location to be in compliance with 20 AAC 25.172 (c) Offshore Location Clearance [natural island] and therefore the Commission requires no further work on the subject wells. However, Exxon Mobil remains liable if any problems were to occur in the future with any of the wells. If you have anY questions or need further information, please contact me at 907-793-1250. Sincerely, Thomas E. Maunder, PE Sr. Petroleum Engineer cc: Mr. Jeff Osborne, Fairweather E&P MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Camille Taylor, /~,~ DATE: Commissioner Tom Maunder, ~~" P. I. Supervisor THRU: August 22, 2002 Revised December 19, 2002 FROM: John Spaulding, SUBJECT: Petroleum Inspector Surface Location Clearances ExxonMobil Flaxman Island August 22, 2002: I traveled to Flaxman Island to conduct final inspection on the Alaska State A-2 (PTD 200-141). In addition to that recently abandoned well, the locations of the Alaska State A-1 (PTD 174-014) and G,2 (182-208) locations were inspected as well. A great deal of time and money was spent on these locations last winter and it showed. Both locations have reserve pits that were reclaimed and approved by the ADEC. The reserve pits are near the ocean and will be reclaimed by natural forces in the near future. The pad area and pits were in excellent condition. SUMMARY: I recommend final approval for the Alaska State A-2 as well as continued clearance approval for the Alaska State A-1 and G-2 locations. Attachments: Photo's NON-CONFIDENTIAL location Clearance Alaska State G-I&A-1 9-22-02is.doc ~n oo -l Ol l A B I C I D I E F G I H I I I J K L M 1 MEMORANDUM[ State of Alaska 2 I Alaska Oil and Gas Conservation Commission 4 TO: Julie Heusser DATE: =February 18, 2001 5 Chairman 6 I t SUBJECT: Mechanical Integrity Test 7 THRU: Tom Maunder ~,(.~rlfl~'~ .Exxon 8 P.I. Supervisor~1 /--' , 9 I :~ i~x~ cbX Flaxman Island Alaska State A-2 10 FROM: IChuck Scheve Point Thomson 11 Petroleum Inspector 12 NON- CONFIDENTIAL 13 14 Packer Depth Pretest Initial 15 Min. 30 Min. 15 Well lAK ST A-2 Type Inj. N T.V.D. 1992 Tubing 0 0 0 O Interval 16 P.T.D 200-141 Type test P Test psi 498 Casing 0 1520 1520 1520 P/F P 17 Notes: 18 Well 19 P.T.D. I Type Inj. I I T.V.D. Type testI Test psi I I Tubing Casing I 20 Notes: 21 Well 22 P.T.D I Type Inj. I I T.V.D. Type testI Test psi I ITubing Casing '1 23 Notes: 25 P.T.D. I Type testI Test psi Casing P/F 26 Notes: 27 Well ]Typelnj'l I~'V'~'I I~u~'n~l I I lintel'vail 28 P.T.D. I Type testI Test Psi Casing P/F 29 Notes:; 30 Type INJ. Fluid Codes Type TestI Interval 31 F = FRESH WATER INJ. M= Annulus Monitoring I= Initial Test 32 G = GAS INJ. P= Standard Pressure Test 4= Four Year CYcle 33 S = SALT WATER INJ. R= Internal Radioactive Tracer Survey V= Required by Variance 34 N = NOT INJECTING A= Temperature Anomaly Survey W= Test during Workover 35 D= Differential Temperature Test O= Other (describe in notes) 37 Test's Details I traveled to Flaxman Island to witness the initial MIT on Exxon's Alaska State A-2 Well. Pretest tubing and casing were 0 as expected. The 2 3/8 tubing by 5 1/2 easing annulus was then pressured up to 1520 psi and held for 30 minutes with no loss of pressure noted. 38 39 40 ... I Failures: 0 tests: 1/2 41 M.I.T.'s performed: 1_ Number of _ Total Time during hour 42 Attachments: cc.' 43 44 MIT report form 5/12/00 L.G. MIT AK State A-2 2-18-01 CS 2/21/01 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Camille Taylor, DATE: Commissioner Tom Maunder, ~~'~ P. I. Supervisor THRU: August 22, 2002 Revised December 19, 2002 FROM: John Spaulding, SUBJECT: Petroleum Inspector Surface Location Clearances ExxonMobil Flaxman Island August 22, 2002: I traveled to Flaxman Island to conduct final inspection on the Alaska State A-2 (PTD 200-141). In addition to that recently abandoned well, the locations of the Alaska State A-1 (PTD 174-014) and G-2 (182-208) locations were inspected as well. A great deal of time and money was spent on these locations last winter and it showed. Both locations have reserve pits that were reclaimed and approved by the ADEC. The reserve pits are near the ocean and will be reclaimed by natural forces in the near future. The pad area and pits were in excellent condition. SUMMARY: I recommend final approval for the Alaska State A-2 as well as continued clearance approval for the Alaska State A-1 and G-2 lOcations. Attachments: Photo's NON-CONFIDENTIAL location Clearance Alaska State G-I&A-1 9-22-02is.doc MEMORANDUM TO: Camille Taylor, Commissioner THRU: FROM: Tom Maunder, P. I. Supervisor State of Alaska Alaska Oil and Gas Conservation Co ,. ., DATE: August 22 ..- Location Clearances ExxonMobil Flaxman 'Island John Spaulding, Petroleum Inspector August 22, 200,2: I traveled to Flaxman Isl and ~ locations for final clearance. A great deal of time and money was showed Both locations have rese the ADEC. The reserve pits are .. forces in the near future. The SUMMARY: I recommend location clearances. .Attachments: Photo's,' NON-CONFIDENT, I'AL · ,. ~,/ ,/ ,./ /,,' / / / /' :' to inspect the Alaska State A-1 on these locations last winter and it pits that were reclaimed and approved by the ocean and will be reclaimed by natural area and pits were in excellent condition. " Alaska State A-1 and G-'~,,Iocations for final location clearance Alaska State G-I&A.I 9-22-02is.doc ExxonMobil Production Corn RO. Box 196601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone Jack, ,/iiliarns, Jr. Production Manager, Alaska Interest Joint Interest U.S. E onMobi! Production March 22, 2002 Mr.' Judd Peterson Reserve Pit Program Manager Alaska Department of Environmental Conservation 410 Willoughby Avenue, Suite 105 Juneau, AK 99801-1795 Re: Status Update for the ExxonMobil Flaxman Island Reserve Pit Closure Project at Alaska State A-1 and G-2 Dear Mr. Peterson: Enclosed is a status report for the ExxonMobil Flaxman Island Reserve Pit Closures Project. This report provides a brief discUssion of ExxonMobil's work progress at Flaxman Island this winter. If you have any questio'nS or require additional information, please contact Mike Barker at 907-564-3691 or Buddy Hand at 713-656-9179. Sincerely, DM'B:ddm Attachments drab 2002~FIUudd Peterson Update 3:.18.doc C: Dr. Steve Amstrup, USGS Jim Baumgartner, ADEC John Bridges, USFWS Gordon Brower, NSB Glen Gray, DGC Rick Lanctot, USGS Tom Maunder, AOGCC Bill Morris, ADF&G Gary Schultz, ADNR Bruce Webb, ADNR DOG Kellie Westphal, ADNR, DMLW RECEIVED' ~AR 2 7 2002 A Division of Exxon Mobil Corp~ Attachment I ExxonMobil Production Company Flaxman Island Reserve Pit Closures Alaska State A-1 and G-2 Project Project Status Report, March 18, 2002 This project status update has been prepared to inform state, federal, and Borough regulatory staff of the current project status, and ExxonMobil's plan to complete the reserve pit closures during this winter season. Since the. last status report on January 11, 2002, ExxonMobil has completed ice road construction and we are now removing the wastes from the island for offsite disposal. Work Completed to Date Beginning in late November 2001, ExxonMobil's contractor, Alaska Interstate Construction (AIC), began constructing the ice road to Flaxman Island and reached the Flaxman Island region by late January 2002. A short (three-mile) on-shore ice road segment approximately four miles east of Bullen Point was built in order to avoid a polar bear den. A 21 bed camp was mobilized to Flaxman Island on February 3, 2002. Excavation of the reserve pits began on February 24, 2002. As of March 18, 2002, approximately 14 kcy has been hauled to the Grind and Inject Plant at the Prudhoe Bay Unit Drill Site ~4. Excavation at the Alaska State G-2 reserve pit is complete and the work is currently focused on completing the Alaska State A-1 reserve pit prior to April 1st. Over 50 personnel are currently working on this project. Between ten to twelve large dump trucks are operating 24 hours per day. Other Information The USGS and USFWS have identified ten confirmed or possible polar.bear dens between Tigvariak Island and the Canning River. Six of the possible dens are on Flaxman Island. A detailed polar bear monitoring plan has been developed in cooperation with the USFWS and USGS. As of March 18, bears have emerged from three of these dens. Extensive monitoring of these bears and the remaining possible dens is being conducted jointly with the USGS and USFWS. Fresh water use for the project began on January 10. To date, three of the five permitted sources have been used. Volumes used from each source are shown in the attached table. The Alaska State A-2 disposal well has been plugged and abandoned. This work was witnessed and approved by the AOGCC. ,:laxman Island Ice Road Water Usage Summary 1/10/02 - 1/15/02 DUCK ISLAND MINE SITE 722,400 1/16/02 -2/18102 SHAVIOVIK RIVER MINE SITE 3,390,240 2/19/02 C-1 PIT 384,720 2/20/02 C-1 PIT ~ 262,080 2/21/02 C-1 PIT 193,200 2/22/02 C-1 PIT 184,800 2/23/02 C-1 PIT 102,144 .... 2/24/02 .,, C-1 PIT . 33,264 2/28/02 C-1 PIT 128,688 3/1/02 C-1 PIT 149,184 · 3/2/02 C-1 PIT 42,000 3/3/02 C-1 PIT 45,696 3/4/02 C.1 PIT 58,800 3~5/02 C-1 PIT 42,000 3/6/02 c-1 PIT 33,600 3/7/02 C-1 PIT 109,200 . 3/8/02 C-1 PIT 100,800 3/9/02" C-1 PIT '' 42,000 ~., 3/10/02 C-1 PIT 50,400 3/11/02 C-1 PIT 0 , 3/12/02 C-1 PIT 16,800 . 3/13/02 C-1 PIT 25,200 3/14/02 C-1 PIT 33,600 . 3/15/02 C-1 PIT 42,.000 .3/16/02 C-1 PIT 25,200 3/17/02 C-1 PIT 33,600 .... 3/18/02 C-1 PIT 33,600 , , , ,., , , ., ,., , ,, =, . ,. __ , ,., , ,,,, .. , . , , , , . _ Total Gallons: 6,285,216 3/19/02 Page 1 .. ExxonMobil Production ~' P.O. Box 196601 Anchorage, Alaska 99519-6601 907 56I 5331 Telephone .3any it P. Williams, ,Jr. ,action Manager, Alaska Interest Joint Interest U.S. E onMobil Production March 22, 2002 Mr. Tom Maunder Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3539 Re: Completion Report for ExxonMobil Production Company Alaska State A-2 Well Dear Mr. Maunder: Enclosed are three copies of the Well Completion Report for the Alaska State A-2. Well. The attached report contains an abandonment operations summary and well abandonment schematic. Electronic and paper copies of the USIT, temperature, and gamma ray logs for this well were transmitted previously to your office. If you have any questions or require further information, please contact Mike Barker at 907-564-3691. Sincerely, DMB:JM:ddm Attachment Dmb2002\completlon report Itt & repo~l 3-21-02.doc C: Glen Gray, DGC Judd Peterson, ADEC Bruce Webb, ADNR RECEIVED MAR ? ,200 A Division of Exxon Mobil Corporation . STATE OF ALASKA ALASKA(,.,,L AND GAS CONSERVATIOI .,OMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ,, 1. Status of Well Classification of Service Well OIL: GAS: SUSPENDED: ABANDONED: X SERVICE: , 2. Name of Operator 7. Permit Number ExxonMobil Production Company 200-141 3. Address 8. APl Number P. O. Box 196601, Anchorage, Ak 99519-6601,,*~ ..:_-.,~;. ~'..,,~,~;~: 50- 089-20028-00 4. Location of well at~--s131~e,1[ ~'-~".~..~-~ [ 9. Un, or Lease Name ) 1867' FSL, 2483' I~L, Sec. 27, T10N, R24W, UM.! ~.~~.~' Alaska State A At Top Producing Interval..[; '-~'. ,.~.[' -'-~--~'~-'~ v~ 10. Well Number Vertical Hole ,. ~ ........ #2 At Total Depth 11. Field and Pool Vertical Hole 5. Elevation in feet (indicate KB, DF, etc.) J 6. Lease Designation and Serial No. N/A KB = 15' MLLWI ADL 47556 12. Date Spudded1/27/2001 13' Date T'D' Reached I 14' Date C°mp' Susp' °r Aband' I 15' Water Depth' if °fish°re I 16' N°' °f C°mpleti°ns2/5/2001 3/0/2002. NA feet MSL 1 17. Total Depth (MD+'I'VD)2415, MD/TVD 18. Plug Back Depth (MD+TVD)31, I 19' Directi°na'Survey I2°' DepthwheresssvsetYes: X ,o: NA feet MD I2a'Thickness°f Permafr°stlooo'-1500, :~2. Type Electric or Other Logs Run , =, , 23. CASING, LINER AND CEMENTING RECORD SE'I-rING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BO'i-rOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 9-5/8,, 47# L-80 8' 84' KB 12-1/4" 70 sx CSII, 16 PP~t 31' 5" 18// N-80 7' 2395' KB 6-1/4" 163 sx G~ 15.8 ppg 31' 350 sx CSIII~ 12.2 PP9 ,, 24. Perforations open to Production (MD+TVD of TOp and Bottom and 25. TU'BING RECORD interval, size and number) SIZE "' DEPTH, SET (MD) PACKER SET (MD). 2246'-2256' MD/TVD 6 spf - (squeezed during P&A) 2-3/8" 2053' , 1992' '2264'-2274' MD/TVD 4 spf - (squeezed during P&A) (,Cut and Pulled to 189')! 2278'-2288' MD/i'VD 6 spf - (squeezed during P&A) 26. ACID, FRACTURE, CEMENT sQUEEZE, ETC. 2295'-2305' MD/TVD 6 spf - (squeezed during P&A) DEPTH INT.E. RVAL (MD) AMOUNT & KIND OF MATERIAL USED 2246'-2305, 60 sx G 15.8 PP~! , , , 27. PRODUCTION TEST Date Fiist prOduction I Method of Operation (Flowing, gas lift, etc.) I Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WA'I:ER-BBL CHOKE SIZE I GAS-OIL RATIO TEST PERIOD => 0 0 0 NAI NA Flow Tubing Casing Pressure cALCULATED OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (corr) Press. 0 0 24-HOUR RATE => 0 0 0 NA 28. CORE DATA , Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. None RECEIVED Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate !9. 30. GEOLOGIC MARKERS FORMATIO,, I'ESTS ., NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT.'DEPTH GOR, and time of each phase. ,, ;~1. LIST OF ATTACHMENTS Yellbore schematic, Summary of Rig Workover Operations ~;~. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ~. ~,/~~,,.~ ~/2--- -,7'~.-'~ c"Jl4'Z'"'</~),) _ Title_Alaska Produc.tion.Ma.nag.e_r Date ,,, , INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Form 10-407 Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, .observation, injection .for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other space on this form and in any attachments. Item 16 and 24: If this well is completed for separate Production from more than one interval (multiple completion), so state in item 16, and in item 24 show the productin intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. "' ' , ; ,r,~.~.,, ,,' ..~ ,, .,'.. ,' Item 21: Indicate whether f~,0,0!:ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- lng and the location of tl~e.,.cementing tool. '1[em 27: Method,, ,.~t~l~e~tiojt:,.F!owing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- ~,~ ,. ~ ;,~,., ,.,, . ,, ~ jection, Gas Inj ,e,~ .~,n, ShLlt[~, {~her-explain. Item. 28: .If.no cores taken, indicate '~none". All Depths RKB 2.6 bbl 15.6 ppg Permafrost Cement from 32' to 189' 9 5/8" and 5" Annulus Plug . Tested to 400 psi 9 5/8" and 5" Casing Cut off O 31' ~ 84' Steel Cylinder 'Poor Boy' Bridge Plug on Top of Tubing Stub O 189' 2 3/8" Tubing and Tubing/Casing Annulus Freeze Protected w/9.6 ppg NaCI Brine. 9 5/8" Conductor Casing Cemented w/70 sx 15.0 ppg Coldset II 2 3/8" Tubing Cjuf l) 189' Stage Cementing Tool ~ =1,238' 3/8" Tubing Cement in Tubing e 1990'4'_ LEGEND C emenf ~--'1. NaCl Brine NO sCALE 2 3/8" x-nipple ~ 2,043' WEG O 2,052' Float Collar 2,364' 2,595' 5" x 2 3/8" Packer ~ 1,992' Perforations: Squeezed w/60 sx (69 fl3) 15.8 ppg Class G Cement 2,246' fo 2,256' O 6 spt 2,264' fo 2,274' ~ 4 spt 2,278' to 2,288' ~ 6 spt 2,295' fo 2,505' O 6 spt 5" Production/Disposal Casing Cemented in two Stages w/165 sx, 15.8 ppg, Class. G and 350 sx, 12.2 ppg, Coldsef III Cement Projecfs\ExxonMobil\A-2 P&A\A-2 Flnal.dwg 5/18/02 JCO i · . Affochmenf 1 Alosko Sfofe A-2 Disposol Well Posf Abondonmenf Wellbore $chernofic ExxonMobil Production Company Alaska State A-2 Well Well Plug and Abandonment Operations Summary All depths measured RKB, unless otherwise noted. 1800, 3/2/02 - 0130, 3/3/02 Deploy heater to warm up wellhouse and wellhead. 1200, 3/3/02- 2200, 3/3/02 Confirmed wellhead and valves are operational. Verified approximately 25 psi on tubing. 1100, 3/4/02 - 0200, 3/5/02 Dewater cellar. R/U Halliburton. Safety meeting. Test Halliburton hardline to 3,000 psi - Test OK. Pressure test 9-5/8" annulus to 500 psi. Bled back to 450 psi four times. Hold at 400 psi - test is good at 400 psi. Pressure test 5" x 2-3/8" annulus to 1500 psi- Test OK. Establish injection down 2-3/8" tubing atl000 psi for 2 bbl/min rate. Inject 13.5 bbl 9.6 ppg NaC1 followed by 5 bbl fresh water and 60 sx 15.8 ppg Class G cement. Squeeze cement through perforations from 2246' to 2305'. Chase cement w/1 bbl fresh water and 6.5 bbl 9.6 ppg NaC1. Shut in 'Tubing after bottom hole plug set. WOC. R/D Halliburton. 1200, 3/5/02- 2000, 3/5/02 R/U Halliburton pump unit. Pressure test hardline to 2,000 psi. Pressure up tubing to 1500 psi w/9.6 ppg NaC1. Hold at 1500 psi 15 minutes. AOGCC inspector witnessed and approved test. Bleed off pressure and IUD Halliburton pump unit. 1200, 3/6/02.- 2330, 3/6/02 Check valves on tree. Prepare for tubing cut at 189' RKB. Remove gauges. Safety meeting. Remove swab valve. RIH with charge to 189'. Detonate charge. POH. RIH with second charge to 185'. Detonate charge. POH. 0800, 3/7/02- 2300, 3/7/02 R/U Halliburton pump unit. Pump down tubing and displace diesel (<1 bbl) in annulUs 0-184' BGL with 10 bbl fresh water. Take returns to open top tank on location. R/D Halliburton. Hook up air compressor to annulus. Reverse circulate with air to evacuate fresh water in tubing and annulus 0-1'8'9'. Disconnect air compressor. Pull tubing out of hole from 189'. R/U Halliburton cementing unit. Place 'poor boy' bridge plug on top of severed tubing at 189'. Place 2.6 bbl, 15.6 ppg Permafrost C cement from 32'-189'. R/D Halliburton. WOC. ExxonMobil Production Company Alaska State A-2 Well P&A 0530, 3/8/02- 2100, 3/8/02 AOGCC inspector witnessed depth of cement at 32' and 184' of tubing pulled from hole. Rig up for detonating charge at 31' (26' BGL and 6' below the toe of the slope of the island). Safety meeting. KIH w/detonating charge to severe 9- 5/8" and 5" casing strings at 31'. Detonate charge. Remove well house. Commence excavating well cellar and severed casing strings. All casing strings pulled to 31'. Well cellar removed. Backfilled excavation to grade with 10% mounding to account for summer thaw and settling. ExxonMobil Production Company Alaska State A-2 Well P&A Re: Alaska State A-2 P&A Subject: Re: Alaska State A-2 P&A Date: Mon, 25 Feb 2002 10:41:24 -0900 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Jesse Mohrbacher <jesse@fairweather.com> CC: AOGCC North Slope Office <aogcc_prudhoe_bay@admin.state.ak. us> Jesse, I received your message with the minor changes to the P&A plan for the A-2. I do not see any problems with the changes proposed. Good luck with the work out there. Have the onsite people stay in contact with the Inspectors 659-2714 or pager at 659-3607. Tom Maunder, PE AOGCC Jesse Mohrbacher wrote: Hello Tom, I had a meeting the other day with ExxonMobil ddlling staff in Houston and they requested a few minor changes to the A-2 program. None of the changes deviate significantly from the P&A program that previously received Sundry approval. The revised procedure is attached. The changes are summarized below with the only significant operational change in # 6 below. 1. Cement volumes and weights have been specified. 15 ppg cement will be used for both downhole and surface plugs. 2. The 9-518 x 5 inch annulus (cemented) will be tested to 500 psi and the 5 x 2-3~8 inch annulus will be tested to 1500 psi pdor to cementing operations. 3. The weight of the brine used to displace the squeeze job has been specified to match the 9.6~ brine in the tubing/casing annulus. 4. The poor boy bridge plug has been shown on the post abandonment schematic (attached). 5. The surface plug will be tested to 1500 psi. 6. We will be displacing the brine in the top 180 feet of the well with air pdor to setting the surface plug. This is described in step 9 of page 2 in the attached revised procedure. This step saves us from having to run in and out of the well to 185 RKB with tubing and during the cement job, eliminating the dsk of cementing the tubing in the hole and minimizing the amount of pipe handling by hand. The upper 35 feet of the 5 inch casing will need to be open after the cement job to facilitate the explosive casing cut. All of the above changes are improvements or clarifications to the program and are within AOGCC regulations. We will have a copy of the signed Sundry on-site, supplemented with the attached program. If you or your field staff have any questions, please contact Jeff Osborne (907-258-3446) or me at any time. Thanks for your assistance on these P&A projects. Jesse Mohrbacher Fairweather E&P Services, Inc. 650 N. Sam Houston Pkwy E., Suite 505 Houston, TX 77060 281-445-5711 281-445-3388 fax 281-413-8007 cell Tom Maunder <tom maunder~admin.state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 of 1 2/25/02 10:43 AM Alaska State A-2 P&A Subject: Alaska State A-2 P&A Date: Fri, 22 Feb 2002 10:07:57 -0600 From: "Jesse Mohrbacher" <jesse@fairweather.com> Organization: Fairweather E&P Services, Inc. To: <tom_maunder@admin.state.ak. us> CC: "Jeff Osborne" <josborne@fairweather.com>, "Al Robb II1" <al.j.robb@exxonmobil.com> Hello Tom, I had a meeting the other day with ExxonMobil drilling staff in Houston and they requested a few minor changes to the A-2 program. None of the changes deviate significantly from the P&A program that previously received Sundry approval. The revised procedure is attached. The changes are summarized below with the only significant operational change in # 6 below. 1. Cement volumes and weights have been specified. 15 ppg cement will be used for both downhole and surface plugs. 2. The 9-5/8 x 5 inch annulus (cemented) will be tested to 500 psi and the 5 x 2-3/8 inch annulus will be tested to 1500 psi prior to cementing operations. 3. The weight of the brine used to displace the squeeze job has been specified to match the 9.6~ brine in the tubing/casing annulus. 4. The poor boy bridge plug has been shown on the post abandonment schematic (attached). 5. The surface plug will be tested to 1500 psi. 6. We will be displacing the brine in the top 180 feet of the well with air prior to setting the surface plug. This is described in step 9 of page 2 in the attached revised procedure. This step saves us from having to run in and out of the well to 185 RKB with tubing and during the cement job, eliminating the risk of cementing the tubing in the hole and minimizing the amount of pipe handling by hand. The upper 35 feet of the 5 inch casing will need to be open after the cement job to facilitate the explosive casing cut. All of the above changes are improvements or clarifications to the program and are within AOGCC regulations. We will have a copy of the signed Sundry on-site, supplemented with the attached program. If you or your field staff have any questions, please contact Jeff Osborne (907-258-3446) or me at any time. Thanks for your assistance on these P&A projects. Jesse Mohrbacher Fairweather E&P Services, Inc. 650 N. Sam Houston Pkwy E., Suite 505 Houston, TX 77060 281-445-5711 281-445-3388 fax 281-413-8007 cell ~.~a2dw501.pdfl_ Type: Acrobat (application/pdf)l ~A-2 Well P&A Procedure.doc Type: WINWORD File (application/msword)] Encoding: base64 ] 1 of 1 2/22/02 7:17 AM 15 ppg, Permefroat Cema,! from 3S' fo lBS' in 5= CaeJng Steel Cylinder "Pear Boy" Bridge Plug on Top of Tublng Stub 0 185' Casrng Plug Te~led fe 1.500 I~1 5/&' x 5" Annulus Plug Tested to 50D 9 5/8" and 5" Casing Cut off · 30' 9 5/&" Conductor Caslng Cemented W/70 ~ 15.0 ppg Coldsef II 2 3/B" Tubrng Cut 0 185' 2 .~/' Tubing and Tubing/Ca.-lng Annulus Fr'ee2e Proled~d w/9.6 ppg NoCI Brine. Stage Cemenfln. g real · 5/8" Tubing Cement in Tubing 0 l ggo~ LEGEND 2 3/8" x-nrpple · 2,043' WEG 0 2,052' Cement NaCI Brlne, HO SC/~LE FAIR/r. XXON/2OOO/A2DW,50 I.DWG Float Collar 2,3.64)' Affachmenf 2 5" x 2 3/8" Packer · I,g92' PeHoraflon~: Squeezed w/51 ft, 15 ppg, Claes O Cement t~ 2,256' 0 $ spf 2,2.64' 2,278' fo 2,288' 0 6 apt 2,295' fo 2,505' · 6 spt 5" Productlon/Dlspesal Casrng Cemented In +we Stages w/1G5 sx, 15.8 ppg, Class G and 350 ex, 12.2 ppg, Coldaef III Cement Alaska State A-2 DTsposal Well Proposed Post Abandonment Wellbore Schematic ExxonMobil Production Company Alaska State A-2 Well Plug and Abandonment Procedure Background and Summary of Proposed Work The Alaska State A-2 well was drilled in February 2001 on the former Alaska State A-1 drillsite on Flaxman Island to support grinding and injection (G&I) of drilling wastes from the Alaska State A-1 and G-2 reserve pits. This island location is approximately 60 miles east of Prudhoe Bay and four miles offshore in the Beaufort Sea. Attachment 1 is a well schematic showing the current condition of the Alaska State A-2 well. G&I operations have been discontinued and the A-2 well needs to be plugged and abandoned in accordance with Alaska Oil and Gas Conservation Commission (AOGCC) regulations. This includes the following work: Squeeze a minimum of 50.5 cubic feet of 15 ppg Class G cement slurry below the tubing tail. , Set a minimum 150-foot length 15 ppg permafrost cement surface plug in the 5-inch casing. 3. Excavate and remove well cellar. , Cut off all casing strings a minimum of 5 feet below the toe of the slope of the island. The toe of the slope is estimated at 15 to 20 feet below pad level. , Backfill excavation and regrade island surface. Pickup any remaining debris on the location. The above work is required by 20 AAC 25.104(a), 20 AAC 25.112(c)(1)(D), 20 AAC 25.112(d). Attachment 2 shows the proposed post abandonment condition of the Alaska State A-2 well. Proposed Operations Program . Obtain all required permits and regulatory approvals before starting job. Anticipated permits include the following: · Application for Sundry Approvals, Form 10-403 (AOGCC); · Lease Operations Permit (existing); and · North Slope Borough Administrative Approval (existing) , Mobilize all required personnel and equipment to the Alaska State A-2 location on an as needed basis. Personnel will be required to comply with ExxonMobil standard health, safety and environmental policies including passing a drug test Alaska State A-2 1 18-Feb-02 o o . . o . , 10. 11. since January 1, 2002. All equipment mobilized to the site will be in proper working order and equipped with secondary drip pans to prevent spills. Hold safety meeting before starting work on the well and prior to each tour. The well is potentially a live well. A Job Safety Analysis review and documentation will be conducted prior to all critical operations such as cementing, pulling tubing, explosives work, pressure testing and excavation. Apply heat to the well house and wellhead with hot air heater(s). Function test wing, master and swab valves. Check pressures on 2-3/8 inch tubing, 5 inch x 2-3/8 inch and 9-5/8 x 5 inch annuli. Remainder of program assumes any annular pressures can be bled off. Pressure test 9-5/8 x 5 inch annulus to 500 psi. Pressure test 2-3/8 inch x 5 inch annulus to 1500 psi. Check for communication between tubing and 2-3/8 inch x 5 inch annulus. Rig up cementing head and establish injection rate. Pump 25 bbls of seawater. Mix and pump 51 cubic feet 15 ppg Class G cement slurry down tubing, chase with tubing wiper plug and displace with non-freezing 9.6 ppg NaC1 brine until wiper plug is near packer depth. Close in tubing and WOC. After WOC for specified period, pressure test plug to 1,500 psi. Rig down cementing head. If plug does not hold pressure, resqueeze perforations if acceptable injection rates can be attained. If resqueezing is not an option, rig up electric line unit and. perforate tubing above packer. Rig down electric line and rig up cementing head. Mix and set a 100-foot balanced cement plug in the tubing and tubing/casing annulus above the packer. Retest plug to 1500 psi. RIH with tubing severing charge to 180 feet below island surface (185 feet RKB). Cut 2-3/8 inch tubing. Circulate brine down tubing and displace all diesel in 5 x 2-3/8 inch annulus. Recover diesel in Class II waste tank. Rig up air compressor and hose on 5 x 2-3/8 inch annulus valve and displace brine in 5 x 2-3/8 inch annulus and 2-3/8 inch tubing with air, taking returns up the tubing. Nipple down wellhead tree valves and tubing bonnet. Pull tubing hanger and severed section of tubing from well. Run a "poor boy" bridge plug in the hole and set on tubing stub. Bridge plug will provide a base for the cement plug and be made of a 4 inch OD steel cylinder filled with sand or equivalent. Bridge plug will be lowered by rope into well and the rope recovered after placement on the tubing stub. Alaska State A-2 2 18-Feb-02 12. Rig up mixing and pumping module. Run 1 inch tubing to 30 feet below island surface (35 feet RKB). Mix and pump minimum 15.5 cubic feet (155 linear feet) of 15 ppg permafrost cement through 1 inch tubing to set surface plug in 5-inch casing. Have plug witnessed by AOGCC representative. Gently wash out the 5 inch casing with brine to 35 feet RKB to leave the casing free of cement. Recover displaced wellbore fluids for class II disposal. WOC. 13. Tag top of cement plug to verify depth. Allow AOGCC to witness tagging if desired. 14. Cut the well internally with a collision type explosive charge to severe the 5-inch and 9-5/8 inch casing strings at 25 feet below grade (30 feet RKB). 15. Excavate and remove well cellar box. Remove the casing and wellhead with onsite heavy equipment such as a loader or trackhoe. 16. Pick up any debris on location and demob to Deadhorse. 17. File new Form 10-407 with the AOGCC referencing the new P&A well status. 18. Return to location the following summer to pick up any minor remaining debris exposed after the snow melts, and to conduct a final location inspection with the AOGCC, ADNR, ADEC and any other agencies that require a site visit. Waste Disposal 1, All liquid wastes recovered in the abandonment program will be transported in secure tanks to either Pad 3 or Drillsite 4 in Deadhorse for injection disposal. . Solid waste (i.e., cellar box, casing, etc.) will be transported to the North Slope Borough Solid Waste Disposal Site for disposal. Alaska State A-2 3 18-Feb-02 ExxonMobil Production Com~ P.O. Box 196601 Anchorage. Alaska 99519-6601 907 561 5331 Telephone r'' Jacki 'illiams, Jr. Produ(~L ....Manager, Alaska Interest Joint interest U.S. eO0 E pnMobil Production Januaw 11,2002 Mr. Judd Peterson Reserve Pit Program M.anager Alaska Department of Environmental Conservation 410 Willoughby Avenue, Suite 105 Juneau, AK 99801-1795 Re: Status Update for the ExxonMobil Flaxman Island Reserve Pit Closure Project at Alaska State A-1 and G-2 Dear Mr. Peterson: EnclOsed is a status report for the ExxonMobil Flaxman Island Reserve Pit Closures Project. This report provides an updated schedule and a brief discussion of ExxonMobil's work plans at Flaxman Island this winter. If you have any questions or require additional information, please contact Mike Barker at 907-564-3691 or Al Robb at 713-656-9182. Sincerely, DMB:ddm Attachments drab 2002~Fl~Pete~on 1-7-02 Update.doc C: Dr. Steve Amstrup, USGS Mike Barker, ExxonMobil John Bridges, USFWS Gordon Brower, NSB Glen Gray, DGC Emily Kasradze, BP Rick Lanctot, USGS Tom Maunder, AOGCC Bill Morris, ADF&G Al Robb, ExxonMobil Gary Schultz, ADNR Dave Thomas, AIC Bruce Webb, ADNR DOG Kellie Westphal, ADNR, DMLW Steve Wright, ChevronTexaco A Division of Exxon Mobil Corporation Attachment I ExxonMobil Production Company Flaxman Island Reserve Pit Closures Alaska State A-1 and G-2 Project Project Status Report, January 2002 ExxonMobil Production Company (ExxonMobil) has initiated winter 2001-2002 field operations for the Flaxman Island Reserve Pit Closures Project. Since the last project status report on July 3, 2001, ExxonMobil has continued to provide for protection of the drilling wastes in place, and we are now preparing for future removal of the wastes from the island and offsite disposal. This project status update has been prepared to inform state, federal, and Borough regulatory staff of the current project status, and ExxonMobil's plan to complete the reserve pit closures during the winter 2001-2002 season. Work Completed to Date The drilling wastes were protected in place by providing a 110+ foot buffer zone on the north side of each reserve pit by moving the drilling wastes to the remaining reserve pit area south of the buffer zones. The drilling wastes remain covered with approximately two (2) feet of clean cap material. As-built drawings of the protected drilling wastes in the A-1 and G-2 reserve pits have been previously submitted. Equipment and materials remaining on-site include a front-end loader, trackhoe, spill response equipment, liner material, 6-man sleeper unit and approximately 3,000 gallons of diesel fuel. These items were left on-site to support summer reserve pit monitoring operations and to provide the ability to perform site maintenance operations during the summer and fall season. The site monitoring plan guided the monitoring program through the open water season. The A- l and G-2 reserve pits were monitored regularly by both ExxonMobil and USGS personnel during the open water season to ensure that drilling wastes were not at risk from shoreline erosion. Between October 1, 2001 and December 20, 2001, two trained and qualified employees of Alaska Interstate Construction (AIC) were assigned to the camp facilities on Flaxman Island. These two individuals repaired the existing runway, prepared the site for future work activity, and monitored and patrolled the island for polar bears. Beginning at the end of November 2001, ExxonMobil's contractor, Alaska Interstate Construction (AIC) began constructing an ice road to Flaxman Island and had reached the Bullen Point region by January 7, 2002. A map showing the generalized ice road route is attached. A short (three-mile) on-shore ice road segment approximately four miles east of Bullen Point is being planned in order to avoid a polar bear den. Revised Project Schedule A new project schedule has been developed and is enclosed. The revised schedule calls for remobilizing excavation equipment during the 2001/2002 winter season for removal of the drilling wastes from Flaxman Island. AIC plans to begin excavation by February 15 and to begin hauling drilling waste to the Prudhoe Bay Unit's G&I Facility at Drill site #4 by February 20. Site reclamation is scheduled to be complete by March 20. Other Information All regulatory approvals, have been received. Most recently, Alaska DNR issued additional temporary water use permits and ADFG issued associated fish habitat permits. The AOGCC has approved the plug and abandonment plans for the shut in disposal well. Three forward-looking infrared surveys of the ice road route and Flaxman Island were conducted by USGS in late November. After through review of these survey tapes and using other information such as radio collar data, the USGS and USFWS have identified eight confirmed or probable polar bear dens between Tigvariak Island and the Canning River (see attached map). Five of the dens are on Flaxman Island. A detailed polar bear monitoring plan is being developed in cooperation with USFWS and USGS. ExxonMobil Production Company Flaxman Island Reserve Pit Closures Alaska State A-1 and G-2 Project Revised Project Schedule, January 2002 Activity Revise Scope of Work, Plan Field Program, Amend Permits Monitor Reserve Pits Monitor and Patrol Island Construct Ice Road and Mobilize Excavation Equipment Excavate and Transport Drilling Waste from Island Disposal of Drilling Wastes Summer Cleanup and Site Clearance 2001 2002 C) Polar Bear Den Location with 1 Mile Buffer Radius Planned 60' Ice Road Alternate 60' Ice Road Private Land Scale: o 0.5 1 mile [Alternate Route] .. · Temporary By-passI , /. .., ..... . ,:.:.?,',:./~:...., .,. "'" · ".-.,, . ~.. ' .......... r~ , ....... -,,. "> ............... , :'>. /'-~'-'x. / r'"".'~"} "'"~, ~ ' .. (~} ' ..,, . , .., ~"'>....,,~. ",:, -"'"' ........ ,,, '~ ~)<.> o ~? /,}6," " / /..,,',..) -,... ,. ,,~. ,.~..., '~,... 5 ~ .(" .,,, .... _.<) C~ .') ("") .,.- ......... ,.., Haul Route to be ~ /' / .... . '" '" field Determined,.., ~:> ~..'~ E onMobil 2001 - 2002 FLAXMAN ISLAND ICE ROAD CONSTRUCTION ROAD DATE: SCALE: FIGURE: January 2002 1 ip14557a,dgn , . To Duck Island Mine Water Source t,'OG(;y LS?,,,d All) B,4 Y 16 Milesl Shaviovik River Water Source Polar Bear Den Location with 1 Mile Buffer Radius Ice Road Location to be Field Determined Ice Road Constructed as of 01/01/02 60' Offshore Ice Road Planned 60' Ice Road Alternate 60' Ice Road 60' Tundra Ice Road Private Land Ice Road Distance Scale: 1 I I I 5 miles BF. AUFORT SEA ',04, · .""""' ""'"1 [Alternate Route] Ill ~ q,0,.,. \ .. Haul Routetobe Badami Mine ;:::~"v ' field Determined Water Source ~,. ,, ::. , ,.,:,.,~_" .: .... ,." .~ ......... . ~. "~:; ' ~t'L ., '~".~" ,:'~ 7~:' ,p':c:.. > ~, ,, , ., ~ ,,, , ....... /' ,~.. --,_~ ~ ~ "~ .. ..... ~:;~, ~, ,/,r' ., ,, ~ ,~ ,, "" '--', ~--"" .:;' '~ '~ .... ~:, ~ ,'"~. ', ~. ~:' E onMobil 2001 - 2002 FLAXMAN ISLAND ICE ROAD CONSTRUCTION ROAD DATE: SCALE: FIGURE: January 2002 1 ip14557.dgn ExxonMobil Production Com~ P.O. Box 196601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone Jack( lilliams, Jr. Product~o~ Manager, Alaska Interest Joint Interest U.S. December 14, 2001 E rKonMobil Production Ms. Julie Heusser Commissioner Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Sundry Approval; Plug and Abandonment of ExxonMobil Alaska State A-2 Well Dear Commissioner Heusser: ExxonMobil Production Company hereby applies for Sundry Approval to plug and abandon the Alaska State A-2 W/ell. The anticipated commencement date of this work is approximately February 1, 2002.-- The well will be permanently plugged and abandoned by setting a 150-foot surface cement plug, cutting off all casing strings a minimum of five (5) feet below the mudline datum, excavating and removing the well cellar box, and regrading the island surface at the abandoned well location. Pertinent information attached to this application includes the following in triplicate: 1. Form 10-403 Application for Sundry Approval 2. A copy of the proposed abandonment procedure 3. Schematics showing the current and proposed condition of the wellbore If you have any questions or require further information, please contact Mike Barker at (907) 564-3691 or Jeff Osborne at (907) 258-3446. Sincerely, 't DMB:ddm Attachments dmb~Julie Heusser P&A A-2,doc c: Emily Kasradze, BP Judd Peterson, ADEC Al Robb, III, ExxonMobil Gary Schultz, ADNR-DMLW Bruce Webb, ADNR-DOG ORIGINAL RECEIVED Oil & Gas Coos. Commission A.cl~age A Division of Exxon Mobil Corporation STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 1. Type of Request: IX] Abandon [ ] Suspend IX] Plugging [ ] Alter Casing [ ] Repair Well ] Pull Tubing [ ] Change Approved Program [ ] Operation Shutdown ] Re- Enter Suspended Well Name of Operator ExxonMobil Production Company Address P.O. Box 196601, Anchorage, Alaska 99519-6601 Location of well at surface 1867' FSL, 2483' FWL, Sec. 27, T10N, R24E, U.M. At top of productive interval Vertical Hole At effective depth Vertical Hole At total depth Vertical Hole 5. Type of well: [ ] Development [ ] Exploratory [ ] Stratigraphic [X] Service ] Time Extension [ ] Perforate ] Vadance [ ] Other ] Stimulate 6. Datum Elevation (DF or KB) KB -- 15' MLLW 7. Unit or Property Name Alaska State A 8. Well Number #2 9. Permit Number 200-141 10. APl Number 50-089-20028-00 11. Field and Pool j N/A 12. Present well condition summary Total depth: measured 2415 true vertical 2415 Effective depth: measured 2364 true vertical 2364 Casing Structural Conductor Surface Intermediate Production Liner Length 64' 2395' feet feet feet feet Plugs (measured) Junk (measured) Size Cemented MD TVD 9.625", 47#, L-80 70 sx Call, 16 ppg 64' 84' 5", 18~, N-80 163 sx G, 15.8 ppg 350 sx CSlII, 12.2 ppg RECE}VEI DEC 2 8 2001 Perforation depth: measured True vertical 2246'- 2256' 6 spf ' 2264' - 2274'4 spf;, 2278' - 22~j~jljjjjS~Ii~-O~,~~iO, 2246' - 2256' 6 spf' 2264'- 2274' 4 spf; 2278' - 2288'6 spf; 2~1~ -01~5' 6 spf Tubing (size, grade and measured depth) 2 3/8" 4.7#, J-55 EUE Tubing, 2053' MD Packers and SSSV (type and measured depth) Halliburton 5" 15-18~ RH Packer, 1992' MD 13. Attachments [X] Description of Sumary Proposal [X] Detailed Operations Program [ ] BOP Sketch 14. 16. 17. Conditions of Approval: Estimated date for commencing operation 15. Status of well classification as: 1-Feb-02 If proposal was verbally approved [ ] Oil [ ] Gas [ ] Suspended Name of approver Date Approved Service Water (Class II) Injection Contact Engineer Nar~e/Number:., Jeff Os. borne / 907 258-3446 Prepared By Name/Number: Jeff Osborne / 907 258-3446 I hereby,~rt'ifv tl~at the~ foreaeing is true/a~d correct to the best of my knowledge S ig ned t , , ----,-'--~ '~)¢'~/J~~ ('~-~j~//~'~~ ~"~ Title ~ ~{~~ Date / Commission Use Only Notify Commission so representative may witness JApproval No. ,~,/'3/- Plug integrity ~ BOP Test Mechanical Integrity Test~ Original Signed By Approved by order of the Commission CAmmv 0ec#~li Form 10-403 Rev. 06/15/88 Location Clearance Subsequent form required 10- Commissioner Dates~/iJmi~t l?ripl~rcate I ORIGINAL ExxonMobil Production Company Alaska State A-2 Well Plug and Abandonment Procedure Background and Summary of Proposed Work The Alaska State A-2 well was drilled in February 2001 on the former Alaska State A-1 drillsite on Flaxman Island to support grinding and injection (G&I) of drilling wastes from the Alaska State A-1 and G-2 reserve pits. This island location is approximately 60 miles east of Prudhoe Bay and four miles offshore in the Beaufort Sea. Attachment 1 is a well schematic showing the current condition of the Alaska State A-2 well. G&I operations have been discontinued and the A-2 well needs to be plugged and abandoned in accordance with Alaska Oil and Gas Conservation Commission (AOGCC) regulations. This includes the following work: 1. Squeeze a minimum of 50.5 cubic feet of cement slurry below the tubing tail. 2. Set a 150-foot surface cement plug in the 5-inch casing. 3. Excavate and remove well cellar. , Cut offall casing strings a minimum of 5 feet below the mudline datum. Mudline is estimated to be 20 feet below pad level or 25 feet RKB. . Backfill excavation and regrade island surface. Pickup any remaining debris on the location. The above work is required by 20 AAC 25.104(a), 20 AAC 25.112(c)(1)(D), 20 AAC 25.112(d). Attachment 2 shows the proposed post abandonment condition of the Alaska State A-2 well. Proposed Operations Program , Obtain all required permits and regulatory approvals before starting job. Anticipated permits include the following: · Application for Sundry Approvals, Form 10-403 (AOGCC); · Lease Operations Permit (existing); and · North Slope Borough Administrative Approval (existing) , Mobilize all required personnel and equipment to the Alaska State A-2 location on an as needed basis. 3. Hold safety meeting before starting work on the well. The well is potentially a live well. Alaska State A-2 I . Apply heat to the well house and wellhead with hot air heater(s). Function test wing, master and swab valves. Check pressures on 2-3/8 inch tubing and 5 inch x 2-3/8 inch annulus. Remainder of program assumes any annular pressures can be bled off. Pressure test 2-3/8 inch x 5 inch annulus to 1500 psi. Check for communication between tubing and annulus. 5. Rig up cementing head and establish injection rate. Pump 25 bbls of seawater. Mix and pump 51 cubic feet cement slurry down tubing, chase with tubing wiper plug and displace with non-freezing brine until wiper plug is near packer depth. Close in tubing and WOC. 6. After WOC for specified period, pressure test plug to 1,500 psi. Rig down cementing head. If plug does not hold pressure, resqueeze perforations if acceptable injection rates can be attained. If resqueezing is not an option, rig up electric line unit and perforate tubing above packer. Rig down electric line and rig up cementing head. Mix and set a 100-foot balanced cement plug in the tubing and tubing/casing annulus above the packer. Retest plug to 1500 psi. 7. RIH with tubing severing charge to 180 feet below island surface (185 feet RKB). Cut 2-3/8 inch tubing. Nipple down wellhead tree valves and tubing bonnet. Pull tubing hanger and severed section of tubing fi.om well. 8. Rig up mixing and pumping module. Mix and pump 150 feet (15 cubic feet) permafrost cement surface plug in 5-inch casing. Have plug witnessed by AOGCC representative. Leave the top 30 feet of 5-inch casing free of cement. Recover displaced wellbore fluids for class II disposal. . 10. Cut the well internally with a collision type explosive charge to severe the 5-inch and 9-5/8 inch casing strings at 25 feet below grade (30 feet RKB). Excavate and remove well cellar box. Remove the casing and wellhead with onsite heavy equipment such as a loader or trackhoe. 11. Pick up any debris on location and demob to Deadhorse. 12. File new Form 10- 0~//~vith the AOGCC referencing the new P&A well status. 13. Return to location the following summer to pick up any minor remaining debris exposed after the snow melts, and to conduct a final location inspection with the AOGCC, ADNR, ADEC and any other agencies that require a site visit. Alaska State A-2 2 Waste Disposal All liquid wastes recovered in the abandonment program will be transported in secure tanks to either Pad 3 or Drillsite 4 in Deadhorse for injection disposal. . Solid waste (i.e., cellar box, casing, etc.) will be transported to the North Slope Borough Solid Waste Disposal Site for disposal. Alaska State A-2 3 _ __ 11 I1_~ ........ II. ilUll . · ~11 ~1 LEGEND ~ Clmm)t I~ HoCI Idr~ 2 3/8~ x-.minim $ Z.Od3' r~/W)O/JlMMt.l]~ t:l &/3t/Or SI IIII Alfachmm~i 1 B' x Z Z/l' I'HW' m 2.JEI4' b 2.274" 2.Z71' te Z,214' 2, Z~&' k~ Alaska St~te A--2 I:)lipaial Well Wellbore Sahema~a, April 2001 fmwq ~,1' tq lift~ w/"70 ~, I~,O Ntg 2 3/i" Tubin4 Gut ~ lIS' ..---! &/$" 'i'ul'J4ng LEGEND = a/l" s-nWk, · I.GIt' FIo~I C~all~ 2,304' 2.305'J mqd ~l m~ I Z..Z PPI" C4~IMt Iit A+taehmenf 2 Alaska Slat. A-2 Ol~pe~al Well Proposed Pa~ Abandanmenl Wellk)ore S~hernatia Alaska State A-2 Daily Injection Log Date: 0600 hrs 27-Mar-01 to 0600 hrs 28-Mar-01 Brine Freeze Diesel Freeze Injection Annulus Slurry Injected Seawater Flush Protection Protection Time SPM BPM Pressure (PSI) Pressure (PSI) (bbl) Injected (bbl) Injected (bbl) Injected (bbl) 0600-0700 0700-0800 0800-0900 0900-1000 1000-1100 1'100-1200 1200-1300 1300-1400 1400-1500 55-70 1.5-2 1000 0 80 10 1500-1600 55-70 1.5-2 1000 0 40 20 15 3 16,00-1700 1700-1800 1800-1900 1900-2000 2000-2100 2100-2200 2200-2300 2300-2400 0001-0100 0100-0200 0200-0300 0300-0400 0400-0500 0500-0600 Tot a Is 'i:.i:.i::::::i::iiii:. :?::::?::::?::::?::::::?::::::::::::::::: i!ii i:: ~:.:?:i::::~:~:: i[i~ [ii~i::::[:: i::::~l ii:.i i.::~ii::::::i::i~ii ~::!ii::ii~:: i ::'::~i::: i.!:::~i:::~i~i.!~!:i:i~ii~i:::~ii:!~?:~: 12 0 3 0 15 3 ::: :.:.. ............ ·: ...:: [ _.'._::~ ~ ~ ~ _: ~ _: _.' _:.~ ! ! ~ _::_: ! _:.~ ~ _::! _:.! ! ! ! ! _: ~ ._'.; ! ! ?.! ! ! !; ! ?.!; ~.! ! ! ~ ;:! ~ ..'? :~ Estimated Solid Waste Volume Processed 110 BBL Estimated Total Seawater Makeup Volume for Slurry (Total bbl injected minus solid waste valume processed) 10 BBL Average Slurry Density 10 PPG Average Slurry Temp 46 F Average Seawater Temp 45 F Average Diesel Temp 45 F Viscosity Agents Added Morning Tour Evening Tour Duro~le! 5 Sacks 10 Sacks Duovis 1 Sacks 1 Sacks HEC 1 Sacks Sacks IComments: ,~£CK£~ Alaska State A-2 Daily Injection Log Date: 0600 hrs 24-Mar-01 to 0600 hrs 25-Mar-01 Brine Fm~e Diesel Fre~e I~e~ion Annulus Slurry I~e~ed Seawater Flush Prote~ion Prote~ion Time SPM BPM Pressure (PSI) Pressure (PSI) (bbl) I~e~ed (bbl) I~e~ed (bbl) I~e~ed (bbl) 0600-0700 0700-0800 0800-0900 0900-1000 1000-1100 1100-1200 1200-1300 1300-1400 1400-1500 1500-1600 1600-1700 1700-1800 1800-1900 1900-2000 2000-2100 2100-2200 2200-2300 55-70 1.5-2 850 0 25 10 2300-2400 ~55-70 1.5-2 900 0 120 0001-0100 55-70 1.5-2 900 0 100 50 15 3 0100-0200 0200-0300 0300-0400 0400-0500 0500-0600 Estimated Solid Waste Volume Processed 245 BBL Estimated Total Seawater Makeup Volume for Slurry (Total bbl injected minus solid waste valume processed) 0 BBL Average Slurry Density 9.6 PPG Average Slurry Temp 40 F Average Seawater Temp 40 F Average Diesel Temp 40 F Viscosity Agents Added Morning Tour Evening Tour Durogel 23 Sacks 10 Sacks Duovis 1 Sacks 1 Sacks :HEC Sacks Sacks Comments: ExxonMobil Production Com~ P.O. Box 196601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone Jack~ 'illiams, Jr. Product .... , Manager, Alaska Interest Joint Interest U.S. May 4, 2001 E onMobil Production Mr. Tom Maunder Petroluem Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3539 RECEIVED F,!!AY 1,5 2001 Alaska 0il & Gas~.o.~'~'~ O0rnmissi0r Anchorage Re: Amended Application for Permit to Drill: Alaska State A-2 Well Dear Mr. Maunder: As you requested, attached is the amended ExxonMobil Form 10-401, Application for Permit to Drill for the Alaska State A-2 Well. This amended form is being submitted to correct the surface location on the original Application and Permit to Drill issued on December 21, 2001. When the Application for Permit to Drill was filed by ExxonMobil on September 7, 2001, we intended the surface location of the Alaska State A-2 well would be approximately 300 feet west of the abandoned Alaska State A-1 well. The following were considered prior to ExxonMobil's decision to move the well north-northeast where it would not interfere with operations. 1. All fuel had to be stored at least 100 feet from a body of water 2. Rolligon access was limited to the south side of the site 3. Camp, shop, and G&I facility location requirements 4. Need to position the injection line out of traffic area This revised location maintains a safe distance (375 feet) from the previously abandoned Alaska State A-1 well. Our amended Form 10-401 matches the final survey plat for the Alaska State A-2 location submitted previously with the Completion Report. If you have questions or require additional information, please contact Mike Barker at 907-564- 3691. Sincerely, ~ DMB:ddm Attachments Amended Form 10-401 for AK State A~2.doc Mike Barker Jesse Mohrbacher Al Robb A Division of Exxon Mobil Corporation , STATE OF ALASKA , ' ALASK~ ,LAND GAS CONSERVATION CON SSION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of work [X] Drill [ ] Redrill I 1 b. Type of well [ ] Service [ ] Development Gas [ X] Single Zone [ X ] Disposal [ ] Re-Entry [ ] DeepenI [ ] Exploratory [ ] Stratigraphic Test [ ] Development Oil 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool ExxonMobil Production Company, a division of Exxon Mobil Corporation 10' MLLW 3. Address P.O. Box 196601 6. Property Designation Anchorage, AK 99519-6601 ADL 47556 4. Location of well at surface 7. Unit or Property Name 11. Type Bond (See 20 AAC 25.025 1,867' FSL, 2,483' FEL, Sec 27, T1 ON, R24E, UM Alaska State A Statewide At top of productive interval 8. Well Number Number 8302 42 06 NA Well #2 At total depth 9. Approximate spud date Amount $200,000 1,867' FSL, 2,483' FEL, Sec 27, T10N, R24E, UM l-OCT-00 12. Distance to nearest property line 113. Distance to nearest well 14. Number of acres in property 15. Proposed depth (M D and TVD) 2,483I 374' to Alaska State A-1 2560 2,400'MD, 2.400q-VD 16. To be completed for deviated wells 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} Kick Off Depth N/A Maximum Hole Angle N/A Maximum surface 797 psig, At total depth (TVD) 1,060 psi 18. Casing Program Setting Depth Size Specifications Top Bottom Quantity of Cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 8.5" 7-5/8" 29.7# L-80 BTC 80' 10' 10' 80' 80' 25 sx Class Cold Set II 6-3~4" 5-1/2" 17# L-80 STL 2,390' 10' 10' 2,400' 2,400' 220 sx Class G, 92 Sx Cold Set III 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented MD TVD Structural Conductor Surface Intermediate Production Liner R E' C EIb/' E' i~i r!,'-'" 5 200l · ,~,last(a Oil & Gas Cor~s, Commissio~,~ Perforation depth: measured Anchorage true vertical 20. Attachments [ ] Filing Fee [ ] Property Plat [ ] BOP Sketch [ ] Diverter Sketch [ ] Drilling Program [ ] Brilling Fluid Program [ ] Time vs Depth Plot [ ] Refraction Analysis [ ] Seabed Report [ ] 20AAC25.050 Req. Contact Engineer Name/Number: Bill Penrose 907-258-3446 Prepared By Name/Number: Bill Penrose 907-258-3446 21. I hereby certify that the,,fc:~mgoing is true and correct to the best of my knowledge _/¢7 --'"'¥'~'~'-----'- ~,'~-'~"-,.-.3 Title ~<'~c~¢~,~,.~ '~,.-~.,.~..._~ Date '~O/~I Commission Use Only Permit Number lAP, Number I Approva, Date I See cover ,etter for other requirements '~;onditions of Approval: Samples Required: [ ] Yes [ ] No Mud Log Required [ ] Yes [ ] No Hydrogen Sulfide Measures: [ ] Yes [ ] No Directional Survey Req'd [ ] Yes [ ] No Required Working Pressure for BOPE: [ ]2M, []3M, [ ]SM, [ ]1OM, [ ]15M Other: by order of Approved By Commissioner the commission Date Form 10-401 Rev. 12-01-85 Ox.!GI , AL Submit In Triplicate ExxonMobil' Production Com~ Alaska Interest - Joint Interest U.S, P.O. Box 196601 Anchorage, Alaska 99519-6601 EX (onMobil Production May 4, 2001 RECEIVED Mr. Tom Maunder Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3539 MAY 10 2001 Alaska Oil & Gas Co~s. Commissior, Anchorage Re: Weekly Report for ExxonMobil Production Company Alaska State A-2 Well Dear Mr. Maunder: In accordance with Rule 5 of Disposal Injection Order #21 for our Flaxman Island Alaska State A-2 well, ExxonMobil hereby submits our injection report for the period March 16 through April 3, 2001. If you have any questions or require further information, please contact Mike Barker at 907-564-3691. Sincerely, R. G. Dragnich DMB:ddm Attachments cmb~enviro~ottomOl~state-federal agencles~launder-Weekly Report 5-3.doc c: D. M. Barker Glen Gray, DGC Judd Peterson, ADEC Bruce Webb, ADNR ExxonMobil Production Company Alaska State A-2 Injection Well March - April 2001 Project Injection Report Date: May 4, 2001 Report Period: 16-March-01 to 03-April-01 Injection operations commenced at the Alaska State A-2 well on March 16, 2001 and were suspended on April 3, 2001. Injection was by batch process during the entire period while attempting to get a continuous system in place for the thawing and processing of drilling wastes. Maximum daily disposal rates were approximately 100 cubic yards per day with an average daily waste disposal rate of 46 cubic yards per day. These disposal rates were lower than expected due to the high incidence of electrical and mechanical problems with the grinding and injection system and the large amount of metal and wood debris in the Alaska State A-1 reserve pit. Approximately 875 cubic yards of drilling waste was processed and injected into the A-2 well. Daily injection logs for all injection activity are attached. Circular recording charts are also attached for the time period of March 24 to April 3. Recorded injection data includes pump strokes, barrels per minute, injection pressure, annulus pressure, bbls of slurry injected, seawater flush quantities, and brine and diesel freeze protection quantities. Pump strokes, barrels per minute and pressures are often presented in a data range due to the fact that these data varied during the course of injection operations depending on the slurry solids content, pump performance, screen Plugging and other variables during injection. Tank strap measurements were used for rePorting of slurry injection quantities. Circular recording charts are not aVailable for the period of March 16 to March 23. At the beginning of injection operations, the chart recorder was found to have a faulty time clock. After attempting to fix the clock on-site, a replacement was ordered and replaced in the recorder by the March 24. Pressure data for the report period is the following: Average Injection Pressure: Annulus Pressure: 800-1000 psi at 2 bpm 0 (two gauges on annulus) Total quantities for the report period are as follows: Slurry Injected: Solid Waste Volume ProceSsed: Seawater Volume for Slurrying Waste: Seawater Flush Volume: Brine Freeze Protect Volume: Diesel Freeze Protect Volume: 4,421 bbl 4,216 bbl 205 bbl 945 bbl 325 bbl 77 bbl All Casings Cut ~,30' El~low Grade 7 5/8" Conducfor Casing Tubing Cur 0 200' with 170' Cemenf Plug on Top, Stage Cementing Tool t~ ~gOO' Permafrosf Interface ,050' C emenf --J CoCI2 Brine NO SCAL£ FAIR/£XXON/2OOO/FLX200O m2,000' . All Perfs i Disposal Zone, Squeezed 2,150' - 2,300' ~2.400' 5 1/2" Production/Disposal Casing 1:1 8/22/00 SR Proposed Alaska State A-2 Post Abandonment Schematic Alaska State A-2 Daily Injection L~u Date: 0600 hrs 24-Mar-01 to 0600 hrs 25-Mar-01 Brine Fre~e Diesel Freeze I~ection Annulus Slurry I~e~ed Seawater Flush Prote~ion Protection Time SPM BPM Pressure (PSI) Pressure (PSI) (bbl) I~e~ed (bbl) Inje~ed (bbl) I~e~ed (bbl) 0600-0700 0700-0800 0800-0900 0900-1000 1000-1100 1100-1200 1200-1300 1300-1400 1400-1500 1500-1600 1600-1700 1700-1800 1800-1900 1900-2000 2000-2100 2100-2200 2200-2300 55-70 1.5-2 850 0 25 10 2300-2400 55-70 1.5-2 900 0 120 0001-0100 '55-70 1.5-2 900 0 100 50 15 3 0100-0200 0200-0300 0300-0400 0400-0500 0500-0600 l;.;.;.i.i.i.i.i.i.i.i.i.i.i.:.:.:.~.:.:.~-i.;.;.:.:.:.: Estimated Solid Waste Volume Processed 245 BBL Estimated Total Seawater Makeup Volume for Slurry (Total bbl injected minus solid waste valume processed) 0 BBL Average Slurry Density 9.6 PPG Average Slurry Temp 40 F Average Seawater Temp 40 F Average Diesel Temp 40 F Viscosity Agents Added Morning! Tour Evening! Tour Duro~lel 23 Sacks 10 Sacks Duovis I Sacks I Sacks HEC Sacks Sacks Oil & Gas Cons. Comn~issic:~ Anchorsce IComments: Flaxman Island Reserve Pit Closures Alaska State A-I Pad Layout, March 2001 Flaxman Island Reserve Pit Closures Alaska State A-I Pad Layout, March 2001 ~00~ Commission ~ Cemenf -'] CoCI2 Brine NO $CAL£ ~m/[XXO~/~OOO/~LX2000 '~80' Stage Cementing Tool Q rog00' ~-2,000' All Parrs Squeezed ~2,400' "i- .' . . .i'. h :'; All Casings Cut ~.-. .., :] ~30' Below Grade "° "'.' ~ , . :,-."- .... ~' ; Tubing Cut O 200' with ;' 170 Cemenf Plug on Top. i' ., [. !.' !. , , j~'. 7 5/8" Conducfor Casing Permafrost Interface 0 ~1,050' 5 1/2" x 2 7/8" Packer Disposal Zone, 2,150' - 2,300' 5 1/2" Production/Disposal Casing 1:1 Proposed Alaska State A-2 Post Abandonment Schematic Aiasl,',a Oil & Gas Corm. Commission Anchorage ALASKA OIL AND GAS CONSERVATION COMMISSION Time MEETING- Subiect NAME - AFFILIATION TELEPHONE (PLEASE PRINT) ExxonMobil Production Com~' ~,~aska Interest -Joint Interest U.S.' P.O. Box 196601 Anchorage, Alaska 99519-6601 April 13, 2001 Distribution List Below RECEIVED E n ro°4b ¢ t o 2001 Oil & ~;as Cons. C0r~missi0n ~nc~0rage Re: Status Report for the ExxonMobil Flaxman Island Reserve Pit Closures Alaska State A-1 and G-2 Project Ladies and Gentlemen: Attached is the most recent Status Report for the referenced project. The enclosed report provides an updated summary of work completed to date and our revised Operations Plan for this winter's activities. As discussed with each of you in the past few days, we have made a course correction in this project. Instead of on-site disposal by grinding and injection, we now plan to haul the reserve pit wastes to Prudhoe Bay for injection during the 2001/2002 winter. Before leaving the island this winter, we will take precautionary measures to ensure the wastes will not be exposed by island erosion this summer. This modified Operation's Plan is underway and neCessary, to ensure continued protection of the drilling wastes from erosion. We are not aware of any new permits or amendments required by this change in our short-term activities this winter. The attached reports are intended to only cover operations during the remainder of this winter season. We intend to file a new plan of operations and necessary permit applications to allow hauling the waste to Prudhoe during the 2001/2002 winter. We appreciate everyone's cooperation. If you have any questions or require additional information, please contact me at 907-564-3691 or Jesse Mohrbacher with Fairweather E&P Services, Inc., at 907-258-3446. Sincerely, Mike Barker DMB:ddm .Attachments dmb\enviro~pt-tomOl~state-federal agenclesUudd Peterson U~ate 4-5-01.doc CZ Dr. Steve Amstrup, USGS' Judd Peterson, ADEC John Bridges, USFWS Robert Robichaud, USEPA Gordon Brower, NSB Gary Schultz, ADNR Bob Crandall, AOGCC The Honorable Lon Sonsalla, Mayor of Kaktovik Glen Gray, DGC / Bruce Webb, ADNR DOG Tom Maunder, AOGCCv Kellie Westphal, ADNR DMLW Pete McGee Jack Winters, ADFG ExxonMobil Production Company Flaxman Island Reserve Pit Closures Alaska State A-1 and G-2 Project Project Status Report, April 13, 2001 Field operations continued since the previous Project Status Report dated March 8, 2001 was submitted. The following project status update has been prepared to provide North Slope Borough, State and Federal regulatory personnel with the current status of the project and a revised Operations Plan for this winter. Work Completed to Date The camp continues to accommodate as many as forty personnel. Daily helicopter and rolligon trips are the norm. All clean cap material has been excavated from both the G-2 and the A-1 reserve pits. Waste material from the flare pits and reserve pits have been excavated and stockpiled. ExxonMobil Production Company discontinued grinding and injection (G&I) operations on Flaxman Island on April 4, 2001. Our current plans for this winter are to cover and protect the drilling wastes in an ADEC approved manner at the A-1 and G-2 locations until winter 2001/2002. We considered relocating the drilling waste from Flaxman Island to the Pt. Thomson #3 location on the mainland but warm weather and insufficient ice thickness have precluded safely carrying out this option. Ongoing work includes ripping, excavation, and the relocation of drilling waste material at both locations. A fully equipped field lab is operational and providing field analytical support for the excavation. Project Schedule The remaining tasks this winter for both the A-1 and G-2 locations include excavating waste material that is near the northern edge of the reserve pits, relocating the wastes to the southern edge of the reserve pits, covering the wastes, and demobilization of the G&I and support equipment. If complete demobilization of the project equipment by rolligon is not possible due to the ice road limitations or close of tundra travel in late April or early May, the remaining equipment will be demobilized by barge in summer, or left on the island for next winter's work activities. The disposal well will be plugged and abandoned next winter, when we return to the island to excavate drilling waste and dispose of it. Additional Information There is full-time polar bear surveillance. One bear den has been located this spring within one mile of the G-2 location. The sow and her two cubs have left the island and no further sightings of these three bears have been noted. Three other bears have been sighted near the camp without incident. DMB~enviroyttorn-01~state-federal agencles~Judd Peterson Update 4-5-01 .doc ExxonMobil Production Company Flaxman Island Reserve Pit Closures Operations Plan for Protection and Temporary Storage of Drilling Waste ExxonMobil Production Company (ExxonMobil) is continuing closure operations for the Alaska State A-1 and G-2 reserve pits. Since completion of the Alaska State A-2 injection well, approximately 850 cubic yards of drilling wastes have been disposed by grinding and injection (G&I) into the Alaska State A-2 injection well. The results of the injection disposal operations have been slower than anticipated due to mechanical and other operational problems with the G&I program. This has prompted a review of the G&I program and other disposal options for the drilling wastes. ExxonMobil has evaluated different options for the drilling waste disposal and determined the preferred approach at this time is to protect the drilling wastes from further island erosion during the next summer season, and return to the island next winter and dispose of the drilling waste. The following Plan covers the tasks necessary to implement a "protect in place" storage program for the drilling wastes at the Alaska State A-1 and G-2 locations. This procedure is intended to keep the drilling wastes protected from the ongoing erosion at Flaxman Island until the wastes can be removed in winter 2001/2002. This winter's "protect in place" program will involve excavation of wastes that are within approximately 100 feet of the north side of the island to provide buffer zones. These buffer zones will be sampled for clean closure and back-filled with clean cap material. The excavated wastes will be moved to the south side of the reserve pits, covered with reinforced Visqueen, and then covered with the remaining clean cap material to stabilize the drilling wastes. In general, operations at the G-2 reserve pit will be given pri°rity due to the limited time remaining for use of the ice road between A-1 and G-2. The Plan contains the following tasks: , Demobilize all unnecessary on-Site equiPment. This will include extra heaters, light plants, building enclosure, Cat 14G blade, snow blower, LATV pumpers, maxi-haul trailers, and other miscellaneous equipment. A boom truck will need to be mobilized to assist with rig down of the building. This lower priority work can be done while implementing the "protect in place" operations. , Excavate a 50-75 foot buffer zone on the north side of the G-2 reserve pit. Sample the reserve pit floor and side walls in this area to verify clean closure. Stockpile all G-2 drilling wastes in the remaining southern two-thirds of the reserve pit (see attached cross-sectional view). . Repeat step 2 for the A-1 reserve pit. The drilling wastes in the A-1 reserve pit will be removed to 50-75 feet from the northern edge of the reserve pit. Depending upon the level of reserve pit wastes remaining in the A-1 reserve pit, it may be necessary to transport some of these wastes to the G-2 reserve pit for storage. In both the A-1 and G-2 reserve pits, the drilling wastes may be mounded but will not be piled above the existing reserve pit berms. . Cover the drilling wastes in both reserve pits with reinforced Visqueen. This will keep the drilling wastes separate from the clean cap material and provide a visual marker between clean cap versus drilling waste material during future excavation. A snow barrier may also be used on the clean side of the Visqueen as a separation mechanism between the clean cap material and drilling wastes. , Fill the north side buffer zones with clean cap material and then cover the drilling wastes the remaining clean cap material. The clean cap material will be contoured to provide adequate protection to the drilling wastes, prevent sloughing and minimize any ponding or run-off from the capped reserve pit. , Demobilize all remaining equipment to Deadhorse with the exception of the CATCO 6-man sleeper, Hyundai 360 trackhoe, and one loader. Approximately 2000 gallons of diesel will be stored in a tank with secondary containment for summer use, if necessary. , Develop a site monitoring plan for the summer 2001. A plan of operations fOr the 2001-'02 winter operations will be developed and submitted with necessary permit applications, during the next few months. DMB:ddm DMB\envlro~pttom-01~state-federal agenciesUudd Peterson Update 4-5-01 .doc I 3' to 5' Clean Cap Matedal Drilling Waste Reserve Pit Bottom Clean Cap Fill Existing Gravel Pad ~. _ / / Island Bluff ~" , '~/.. :~ = ' · "' %,.,%~:% aufortSea Note: Drilling Waste Separated From Clean Cap Matedal by Reinforced Polyethylene and a 6" Snow Layer on Top of the Polyethylene Not To Scale ExxonMobil Production ComPany Flaxman Island Reserve Pit Closures ReServe Pit Protect In Place Diagram Cross Sectional View ExxonMobil Production Comp~r' P.O. Box 196601 Anchorage, Alaska 99519-6601 JameS,, Jranch Production Manager, Alaska Interest Joint Interest U.S. April 2, 2001 EYx, onMobil Production Mr. Tom Maunder Petroluem Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3539 Re: Completion Report for ExxonMobil Production Company Alaska State A-2 Well Dear Mr. Maunder: Enclosed are two copies of the Well Completion Report for the Alaska State A-2 Well. The attached reports contain a drilling operations summary, well schematic, completion schematic, survey plat, and injection test data. Electronic and paper copies of the USIT, temperature and gamma ray logs for this well were transmitted previously to your office. ExxonMobil will forward copies of the sonic log when Schlumberger has completed processing the data. If you have any questions or require further information, please Contact Mike Barker at' 907-564-3691 or Jesse Mohrbacher at 907-258-3446. Sincerely, DMB:JM:ddm Attachment Pttom-Ol\State-Federal Agencies\Completion Ltr & Report.doc C: Glen Gray, DGC Judd Peterson, ADEC Bruce Webb, ADNR bc~ D. M. Barker F. E. Hand J. Mohrbacher o - ( STA~E OF ALASKA ALASKA OIL. A~D GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status or Wall Classification of Servicl · OIL [~ GAS J~ SUSPENDED [] ABANDONED [] SERV,CE ~ Water .!njec_t.%~o~ (D$~posal] ~. NI~e of Operator " ~~ 7. Permit Number ~x~nMobil Production Company V~ 200L141 ~[ Addr~ ~t~ ~. APl Numb,r P.,O. Box 196601~ Anchorage, AK 99519-6601 ~.~~1 ' s0-089-20028-00 ~. L~don ot w~lt ~t ~uH~ ..... ~.~'~:~ 9. Unit o~ L~a ~ -~ Alaska State A 1867' FSL, 2483' FWL, Sec 27, T10N, R24E, UM ; ~.~.~ .... A[ T~ Pr~ucing Inta~al .... ~0. Wall Vertical Hole ~ ~_....~ .... ~- ..... ~. ~2 P'ool , ,, 5. Election in t~et [indicata KB, DF, arc.) ~. L~[a D~;gaat~on and S~rl~l No. KB =, 15' MLLW APL 47556 NA 27~Jan-O1 '05-Feb-01 Completed ~Feb-01. J '. NA ,,~s~ J ' 1 ' 2415''MD/TVD 2364' ~/TVD Y~S~ . ~o~ ' ~ . ~A . ,,,mo ~ 1000'-1500' GL: 22. Typa Elastic or Othar Log, Run , . , ,C,~e~ Hple: So. nic~ U$IT~ Gamma Ray, ..Temperature ~ ..... , ................... , , . SE~ING DEPTH CASING SIZE ~.PER FT. GRADE TOP BOSOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 350 sx CSIII,i 12.2ppi , , , ,, ,,,, .... 24. Perloration, open to P'rod cli0 IMp*TVD. ol Top and Bottom ano 25. TUI~j'N~ a IE C O ~ O .... int,rval, size and number) SIZE DEPTH SET (MO) P~'CKER S'ET (M~) 2246'-2256, H~/~VD 6 s~ 2.375'" 2053' 1~2" .... ....... : ..... , , 2264'-2274' ~9/~V9 4 s~ ' 2278'-2288' ' H9/~?9 6 spf ~.'. .... . AC~. ~RACTU~. CEMENT Sau~Ez~.'~TC. 2295 '-2305" H~/~V9 6 . s~ DEPTH INTERVAL IMO) AMOUNT ~ KIND?F MATERIAL USeD ........ ......... , .... . , , ........... ~,. ,,. , , ,. ,, ........ 27. PRODUCTION TEST Date FJrlt Produclmn j Meth~ ot Operal~on IFIowtng. ~t hit, ,lc.) · 19-~eb-01 ~. ~es~)~ ~ate~ [~ec~lo~ (Dls~osaZ~ See i~c~io~ ~es~ .......... ~esul~s. 'Da,eof Test Hour, T,st~ pRODUcTION FOR OIL.BBL GAS-MCF WATER~BBL CHOKE SIZE JGAS.OILRATIO TEST PERIOD ~ I r ....... Flow Tub,ng :C~,ngPr,~,ure ' CALCULATED OI'~.BB~ GAS.MCF WATER.BBL OIL GRAvITy.APl (corrJ Pre,. ~4.HOUR RATE ~ ....... ~8. CORE DATA ...... ....... Br~el de~rip,o~ of lithology, poroHty, fracture,, apparent dlpt and pr,~nca ol od. ~t or walar. Submit core ch~pl. Sagavanirktok Formation: Interbedded sandstone, siltstone, shale and ...... . ....... coal sequences. Show of oil over shakers at approximately 1300 ft. No cores or samples taken. ................. Form 10-407 ' Submit in duplicate Rev. 7.1-80 CONTINUED ON REVER~E SIDE , , 29. 30. GEOLOGIC MARKER$ , ·FORMATION TESTS ' · NAME ..... Include intervBI tested, p. retlur~, dtta, all fluld~ tecover~l and grivlly, MEAS. DEPTtt TRUE VERT. DEPTH GOR, and t~, ol,achphm~. , , , , . . . 'Sagavanirktok , See attached injection test results. 31. LIST OF Survey Plat, Operations Sugary, Injection Test Data, Well Schematic, Completion Sche ~~' ~~ ~~ ~ Alaska Pr'oduction' Manager ~/~ .... matic. , INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1' Classification of Service Wells' Gas injection, water injection, steam injection, air injection, salt water disposal, water supply [or injection, observation, injection Ior in-situ combustion, Item 5: Indicate which elevation is used as reference (where not otherwise ¢~own) [or depth measurements given in o~,her spaces on this form and in any attachment~. Item 16 and 24: If this well is completed Ior separate production [rom more than one interval (multiple completion), so state in item 1G, and in it.em 24 show the producing"interval~ for only the interval reported in item 27. Submit a ~parate form for each additional interval to be separately' produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.}. , Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation' Flowing, Gas Lilt, Rod .Pump, Hydraulic PumP, Submersible, Water In- jection, Gas Injection, Shut-in, Other.explain. ,, ., Item 28: If no cores taken, indicate "none". IO.-407 ~ - ExxonMobil Production' Company Alaska State A-2 Well Drilling Operations Summary Date 31-Dec-00 02-Jan-01 03-Jan-01 to 11-Jan-01 12-Jan-01 to 14-Jan-01 15-Jan-01 to 22-Jan-01 23-Jan-01 to 27-Jan-01 28-Jan-01 to 31-Jan-01 01-Feb-01 02-Feb-01 03-Feb-01 to 05-Feb-01 06-Feb-01 07-Feb-01 08-Feb-01 09-Feb-01 Operations Begin flooding rolligon trail to Flaxman Island from mainland. Complete flooding of rolligon trail. Begin warmup and assembly of camp and moblization of location essentials. Haul materials and equipment to location. Set cellar, rig subbase and spot rig over cellar. Rig up shakers on mud tank. Rigged up drilling enclosure around drilling rig. Complete rig up for drilling. Spud well on 27-Jan. Drilled 12-1/4 hole to 97'. Ran 4 jts 9-5/8", 47#, L-80 casing to 84'. Cemented casing in place with 70 sx Coldset II cement, 16 ppg. WOC. Installed 11" 3000# SOW wellhead A section. Install 6" diverter system. Function tested same for AOGCC witness. Drilled 6-3/4" hole from 97' to 605'. Survey inclination at 483' with no result. Drill to 708'. Survey at 650' (3 degrees). Change out charge pump hose then plug bit due to debris in replacement hose. POH and unplug bit. Drill ahead to 730'. Drill ahead from 730' to 1600'. Survey inclination at 980' (1 degree) and 1500' (2 degrees). Drill ahead from 1600' to 1900'. POH to change bit. Drill ahead to 2415'. Make wiper trip to 1900'. Survey at 2027' (2 degrees) and 2390' (2 degrees). POH Run 2402' of 5", 18#, N80, LTC casing. Circulate and condition mud. Work on cementing unit to ready same. Mix and pump approximately 15 bbl, 15 ppg G cement. PTO unit on cement mixing pump went down. Made decision to circualate cement out of hole. Circulate and reciprocate casing while waiting on parts for cementing unit. Replace PTO unit on cementing skid. Mix and pump first stage of cement job. Pump 50 bbls water preflush followed by 163 sx of 16 ppg class G with 2% CaC12 and 1 gal/sx FP-6L. Full returns during stage. Reciprocated and landed casing with float shoe at 2395' Dropped stage tool opening cone and open stage tool with 700 psi. Circulate well. Pumped second stage. Pump 20 bbl water preflush followed by 350 sx, 12.2 ppg Coldset III permafrost cement with 1 gal/sx Fp-6L through stage tool at 1238'. Full returns during stage. Bumped plug and closed DV tool with 2600 psi surface pressure. Nipple down diverter, set casing slips, test packoff to 3000 psi. Nipple up 11" x 7-1/16" 3000 psi wellhead B section and 7-1/16" 10-Feb-01 to 11-Feb-01 12-Feb-01 13-Feb-01 14-Feb-01 15-Feb-01 to 17-Feb-01 18-Feb-01 19-Feb-01 20-Feb-01 21-Feb-01 to 23-Feb-01 5000 psi annular preventer. RIH with 2-3/8" cleanout string and drillout stage tool. Pressure test casing to 1000 psi, casing would not hold more than 500 psi. Rig up Schlumberger for cased hole logging. Log slim sonic, temperature log, USIT, and gamma ray. RIH with cleanout string and tag junk at 2359'. Circulate well and retest casing with same result. POH. Pick up RTTS and isolate leak at DV tool. Rig up Schlumberger and set bridge plug at 1250'. Circulate and wait on BJ' s for squeeze job. Rig up for squeeze job. Circulate and balance hole with water. Mix and pump 1.5 bbl cement on top of retainer. Pull 4 jts out of hole. Reverse out tubing. Close annular and squeeze ~,5 bbl cement behind casing at 3000 psi. Pressure bled off to 2850 after 15 minutes. Pressure up to 3000 psi and shut in well. WOC. Bleed off 3000 psi and POH. RIH with cleanout string. Drill hard cement from 1240' to 1248'. Test casing to 1100 psi. Test OK. Drill out retainer at 1250'. Circulate while waiting on fuel for heaters during blow. POH and lay down cleanout BHA. RIH with bit and scraper, drill on retainer at 1338'. POH due to torque. RIH w/o scraper, drill on retainer at 1338' and run to bottom. Pressure test casing to 1500 psi, OK. POH. RIH with scraper run to bottom and reverse out to clean up hole. Displace 8.9 ppg mud with 9.6 ppg NaC1 brine. POH. Pick up 2-3/8" x 5" Halliburton hydraulic set packer completion and RIH. Continue RIH with completion. Set packer at 1992' with 2900 psi to shear out ball. Pressure test annulus to 1500 psi. AOGCC representative witnessed 30 minute mechanical integrity test of 2-3/8" x 5" annulus. Wait on Schlumberger. Rig up Schlumberger. Continue rigging up Schlumberger. Perforate 5" casing with 1- 11/16" strip guns from 2295'-2305' ~ 6 spf, 2278'-2288' ~ 4 spf, 2264'-2274' ~ 6 spf and 2246'-2256' ~ 6 spf. Rig down Schlumberger. Perform step rate injection test. Inject 1 bpm ~ 460 psi, 2 bpm~ 670 psi, 3 bpm @ 825 psi, 4 bpm ~ 1060 psi and 5 bpm ~ 1340 psi. Inject 650 bbl waste fluids from drilling operations in two batches. Displace tubing with 40 bbl 9.1 ppg brine followed by 1 bbl diesel. Rig down drilling rig and associated equipment. Transition to G&I phase of project. 84' 9 5/8" Conductor Casing Cemented w/70 sx 15.0 ppg Coldset II Tubing/Casing Annulus Freeze Protected w/9.6 ppg NaCI Brine. Stage Cementing Tool ~ 1,258' 2 3/8" Tubing LEGEND Cement 2 3/8" x-nipple @ 2,043' WEG @ 2,052' Float Collar 2,364' 5" x 2 5/8" Packer @ 1,992' Perforations: 2,246' fo 2,256' @ 6 spt 2,264' fo 2,274' @ 4 spt 2,278' fo 2,288' @ 6 spt 2,295' fo 2,505' @ 6 spt NO SCALE 2,395' 5" Production/Disposal Casing Cemented in two Stages w/165 sx, 15.8 ppg, Class G and 550 sx, 12.2 ppg, Coldsef III Cement FAIR/EXXON/2OOO/AKA2DW.DWG 1:1 5/4/01 SR Alaska State A-2 Disposal Well Wellbore Schematic ~ .......... ~ '~BuRToN ENER'GY SERVICES H A L L I B U RT 0 N ~' ~te J Account Rel)resentative Completion Products Completion Guide 6900 Arctic Blvd., Anchorage, Alaska Office: (907) 275-2607 ~ ~___/i ,,,~_.__ 1 0 Customer Oust Representative .... Well Field Date Fairweather Disposal well Flaxman IS February 13, 200] Casing Size Casing Weight Casing Grade From To Tubing Size Tubing WeightTubing Grade Tubing Thread ' 5" 18# N-80 0 2400 2 3/8" 4.7# J-55 EUE ~ 9 Casing Size Casing Weight Casing Grade From To Base Pipe $ize BasePipeWt, Base Pipe Grade 9asePipeThread ~asing Size Casing Weight Casing Grade From To Screen Size Screen Tyl~e Screen Material Screen Gauge ~laximum Deviation Deviation Thn~ Peris Maximum Dogie8 KOP Looator Type Center of Pkr. Elem. RKB PBTD 10 2002.00' 6.6 2400' Brine 9.7# 55 I Non. Perforated ,, '"--- 7 ':Item # '~ Description , ' , I.D,. 'O:D,. · Len~t,h , ,, D~pth.' ! .. KB 6.60 0...00 _- 10 * Tubing Hanger 7.000 3.083 0.68 6.60 ~/~ i' 10 *Pup Joint 1.995 3.083 5.57 7.28 9 2 3/8" 4.7# J-55 EUE Tubing 60its. 1.995 3.063 1969.43 12.85 ' 8 2 3/8" 4.7# L-80 EUE Pup Jt. 1.995 3.083 9.98 1982.28 II :! 7 Halliburton 5" 15-18# RH Packer 1.927 4.120 ,4.10 1992.26 ! ~ ~- 6 2 3/8" 4.7# L-80 EUE Pup Jr. 1.995 3.083 ' 7.98' 1996.36 5 2 3/8" 4.7# J-55 EUE Tubing, 1 jt 1.995 3.083 32.98 2004.34 : 4 2 3/8" 4.7# L-80 EUE Pup Jr. 1.995 3.083 6.11 2037.32 , ' ~ 6 3 Halliburton 2 3/8" X Nipple 1.875 3.083 1.25 2043.43, 2 2 3/8" 4.7# L-80 EUE Pup Jr. 1.995 3.083 7.95 204,4.68 --.-- 5 I Halliburton POP 1.950 3.490 0.45 2052.63 , , 2053.08 .... ----4 " , ,,, , __ _ __ __ __ __ __ __ __ -- __ TiON R24E UM AK N N.T.S, Sec 27 Alaska State 'ALASKA STATE A-2' Geodetic Position (NkD27) Latitude 70' 11' 24. Z1" North Longitude 140' 00' 4?.?0" Wes[ Alaska State Plane Coordinates Zone 3 Y = 5,B19,048 feet X ---- 498,S52 fee%. Geodetic Position (NADB3). Latitude 70' 11' 53,45" North Longitude 146' 00' 58.24" West Universal Transverse Mercator Zone 6 (eM = 147° ~rest) Y = ?,787,345 meters X - §87,211 meters Notes: 1. All dimensions are in lest, Z. This survey performed for Fairweather E&P Services, Inc, on November 1-2. 2000, THE "ALASKA STATE A-2" WELL LOCATION WAS SURVEYED USING A TRIMBLE 4000SSi GPS RECEIVER OPERATING IN STATIC SURVEY MODE. SURVEY DATA WAS POST-PROCESSED USING NGS "CORS DATA" FROM STATIONS "FAIR", LOCATED 1N FAIRBANKS AND "CENA", LOCATED IN CENTRAL, ALASKA. THE WELL IS SITUATED WITHIN SECTION TOWNSHIP 10 NORTH, RANGE 24 EAST, UMIAT MERIDIAN, ALASKA AND IS 2488'(FT) FROM THE EAST BOUNDARY AND 1867'(FT) FROM THE SOUTH BOUNDARY OF SECTION 2?. I hereby certify that I am properly registered and Licensed to practice land surveying in the state of Alaska. This plat represents a location survey made by me and a_llfl~j~a~,j/slons and other details are ~~ S, Ne~an, ~ a0a4 ,- ~ gatd Location Survey For: ALASKA STATE A- INJECTION WELL FLAXMAN ISLAND ALASKA For ] (onMobil Production ExxonMobil Production Company Alaska State A-2 Well Injection Test Results 19-Mar-01 Injection Fluid: Fresh Water Tubing: 2.375" ~ 2353' Perforations: 2246'- 2256' ~ 6 spf 2264' - 2274' ~ 4 spf 2278' - 2288' ~ 6 spf 2295' - 2305' ~ 6 spf Injection Summary: Pump 3.5 bbl at 0.65 bpm until pressure increase seen. Pumped water at 1 bpm with 460 psi tubing pressure, 2 bpm ~ 670 psi, 3 bpm ~ 825 psi, 4 bpm ~ 1060 psi and 5 bpm ~ 1340 psi. Chased fresh water with 10 bbl 9.1 ppg NaC1 brine for freeze protection. No pressure on well alter displacing tubing with 9.1 NaC1 brine. . , ~;.....; .......... r~.~...,. ............ ~ ....... o~~ ....................................... , ~} D~ ~,~ ~l~ , C~SE~E I.D. 4~ ~I 6 BBL/MIN 4~ PSI 6 ~/MIN 4000 POI 6 B~/MIN ~ 4~ ~I 6 B~IN ~ 40~ ~I 6 ~L~IN ..... .... ' ...... - - 10:39:36 ........................ 1I~ ................... FAIR~EAIHER .................... c~ __ ~ ,- ~ ~ - __ ~ ......... ~ - _ ...... -- JESSE ............ ~m~om. ~.. ~ ........... / .... 2j ...... ................. 'RIG/~ELL[ -" ~ - . - -~ .... ~ .......... ~ -~ ...... ~ .... ~ ...... ~ .~ ~ ........ ~ ...... INOEC IESI BRO~N ExxonMobil Production Corn P,O. Box 196601 Anchorage, Alaska 99519-6601 March 16, 2001 Jamei: ' ~ranch ~'~00~'~// Production Manager, Alaska Interest Joint Interest U.S. E: onMobi[ Production Mr. Glenn Gray Project Analyst State of Alaska Office of the Governor Division of Governmental Coordination P. O. Box 110030 Juneau, AK 99811-0030 RE: Second Status Update for the ExxonMobil Flaxman Island Reserve Pit Closures Alaska State A-1 and G-2 Project Dear Mr. Gray: Please find enclosed the second status report for the referenced project. The enclosed report provides an updated schedule, summary of work completed to date, an "as built" disposal well schematic, and a map showing the ice road location. If you have any questions or require additional information, please contact Mike Barker at 907- 564-3691 or Jesse Mohrbacher with Fairweather E&P Services, Inc., at 907-258-3446. Sincerely, , .... / / JM:DMB:ddm Attachments: dmb~envtro~ttom-Ol\State-Federal Agencies\Glenn Gray Office of Governor. doc C: Steve Amstrup, USGS John Bridges, USFWS Gordon Brower, North. Slope Borough Bob Crandall, AOGCC John Kuterbach, ADEC Tom Maunder, AOGCC Pete McGee, ADEC Jesse Mohrbacher, Fairweather Judd Peterson,.ADEC Robert Robichaud, USEPA Gary Schultz, ADNR The Honorable Lon Sonsalla, Mayor of Kaktovik Bruce Webb, ADNR DOG Kellie Westphal, ADNR DMLW Jack Winters, ADF&G ExxonMobil Production Company Flaxman Island Reserve Pit Closures Alaska State A-1 and G-2 Project Project Status Report, March 8, 2001 ExxonMobil Production Company (ExxonMobil) commenced grinding and injection (G&I) operations for the Flaxman Island Reserve Pit Closures Project on March 16, 2001. Field operations have continued unabated since the previous Project Status Report dated January 3, 2001 and are anticipated to continue at least through April 2001. The following project status update has been prepared to provide North Slope Borough, State and Federal regulatory personnel with the current status of the project including a revised schedule and an "as built" disposal well construction diagram. Work Completed to Date Since early January, all drilling, excavation, disposal, and support equipment has been mobilized to the A-1 location. The camp has accommodated as many as forty personnel. Daily helicopter and rolligon trips are the norm. The well has been drilled and completed on February 20, 2001, (see Attachment 1), drilling equipment demobilized, and the grind and inject (G&I) system has been mobilized and rigged up. Over 3,000 cubic yards of clean cap material has been excavated from the A-1 reserve pit and waste material from the flare pits at the A-1 location (approximately 700 cubic yards) has been excavated and stockpiled. Ongoing work includes the removal of clean cap material at the G-2 location and construction of the ice road between the A-1 and G-2 locations. Drilling wastes at the A-1 location are also currently being thawed for input into the G&I system. A fully equipped field lab is operational and providing field analytical support for the excavation. Updated Project Schedule An updated project schedule is provided in Attachment 2. Completion of the disposal well took approximately a month longer than previously estimated due to longer than anticipated mobilization, rig up and drilling timeframes. Since then, the drilling equipment has been demobilized and the G&I equipment rigged up. The updated project Schedule includes the remaining tasks of excavating the clean cap and waste material at the G-2 location, transportation of the G-2 wastes to the A-1 location, G&I of the A-1 and G-2 wastes, plug and abandonment of the well and rolligon and/Or barge demobilization of the G&I and support equipment. If complete rolligon demobilization of the project equipment is not possible due to the clOse of tundra travel'in late April or early May, the remaining equipment will be demobilized by barge in summer. Other Information There is full time polar bear surveillance. No bears have been sighted this year. Agency visitors to the project site have included Mr. Chuck Scheve from AOGCC, Mr. Bruce Webb from DNR, and Mr. John Bridges from USFWS. There have been a few minor, non reportable spills of hydraulic fluid, glycol, etc., and there has been one reportable spill, two gallons of diesel, on January 14, 2001. All of the spills occurred on the snow covering the gravel pad and were immediately cleaned. ADEC was notified of all spills as required, or as a courtesy. Flaxman Island Reserve Pit Closures Project Status Update 84' 9 5/8" Conductor Casing Cemented w/70 sx 15.0 ppg Coldsef II Tubing/Casing Annulus Freeze Protected w/9.6 ppg NoCl Brine. Stage Cemenfi.n,g Tool O 1,258 3/8" Tubing LEGEND Cement 2 5/8" x-nipple @ 2,045 WEG @ 2,052' Float Collar 2,564' 5" x 2 3/8" Packer @ 1,992' Perforations:' 2,246' fo 2,256' @ 6 spt'~~'~'"~ ~.~ 2,264' fo 2,274' ~ 4 spt 2,278' fo 2,288' @ 6 spt 2,295' fo 2,505' ~ 6 spt NO SCALE 2,395' 5" Production/Disposal Casing Cemented in two Stages w/165 sx, 15.8 ppg, Class G and 550 sx, 12.2 ppg, Coldsef III Cement FAIR/EXXON/2OOO/AKA2DW. DWG 1:1 5/4/01 SR Alaska State A-2 Disposal Well Wellbore Schematic Attachment 1 Attachment 2 ExxonMobil Production Company Flaxman Island ReServe Pit Closures Alaska State A-1 and G-2 Project Project Schedule, Mar 2001 2001 Activity Start Finish Rolligon Mobilize Drilling Rig/G&l 05-Jan 15-Jan Drill and Complete Disposal Well 27'Jan 20-Feb Remove Overburden From^-1 and i i - ~ ' ' G-2 Reserve pits 13-Feb 15-Mar I i ! i [ ' I Thaw Waste Material 02-Mar 30-Apr Gdnd and Inject Waste Material 07-Mar 30-^pr ' Construct Ice Road from G-2 to A-1 04-Mar 10-Mar Plug andAbandonlnjectionWel, 1-May 5-May iii i !.', ii iiiii ' iii Demobilize AIl Equipment · 07-Apr 21-APr (Possible Summer Demobilization) 22-July 04-Aug Summer Debris Cleanup and Agency Prepare and File Reports 01-MAY 30-May 0J-Aug 07-Aug Site Inspection AIRSTRIP 0 600 1200 SCALE IN FEET F'AIR/EXXON/2OOO/ICE2 . 1:1PS 3/7/01 ALASKA STATE A-1 AND A-2 (PROJECT BASE CAMP, 2000/2001) B~,d b~oB T SOURCE: AEROMAP AERIAL PHOTO 7/1:~/98, NORTH SLOPE ROLL#98-18C:-1 -Affc]chmenf .~ FIc~xm(]n. Islc~nd Ice Road Roufe .. STATE g-2 .... AI B I C I D ! E I F I G I H I I I J I K I L IM~ 1 ~ MEMORANDUM ~', , i State of Alaska i 2 "~ i l.v- I Alaska Oil and Gas Conservation Commission 4 TO: Julie Heusser ~'I\/~ l DATE: February 18, 2001 [ 5 Chairman/I4 ! i 6 I I ~ ~.~_/~ ~ ~,,~,SUBJECT: Mechanical Integrity TestI -- 7 THRU: iTom Maunder ]~! ~! Exxon 8 !. P.I. Supervisor r,, ~-t~' ~\ Flaxman Island I 9 I~~' Alaska State A-2 _ 10 FROM: Chuck Scheve Point Thomson 11 Petroleum Inspector _ 12 NON- CONFIDENTIAL -- 13 14 Packer Depth Pretest Initial 15 Min. 30 Min. 15 Well AK ST A-2 Type Inj. N T.V.D. 1992 Tubing 0 0 0 0 Interval I 16 P.T.D. 200-141 Type test P Test psi498 Casing 0 1520 1520 1520 P/F P 17 Notes: 18 Well 19 P.T.D. ] Type Inj. I I T.V.D. Type testI Test psi [ ITubing 20 Notes: 22 P.T.D. Type test Test psi Casing P/F 23 Notes: 24 Well I Type Inj. 25 P.T.D. Type testI IT'V'D' Test psi I ITubing 26 Notes: '27 Well 28 P.T.D. [ Type Inj. I I T.V.D. Type testI Test psi I ITubing Casing I I [ IIntervalP/F 29 Notes: 30 Type INJ. Fluid Codes Type Test Interval 31 F = FRESH WATER INJ. M= Annulus Monitoring I= Inta Test :32 G = GAS INJ. P= Standard Pressure Test 4=' Four Year Cycle 33 S = SALT WATER INJ. R= Internal Radioactive Tracer Survey V= Required by Variance 34 N = NOT INJECTING A= Temperature Anomaly Survey W= Test during Workover 35 D= Differential Temperature Test O= Other (describe in notes) 36 [ .,_ 37 Test's Details .. I traveled to Flaxman Island to witness the initial MIT on Exxon's Alaska State A-2 Well. Pretest tubing and casing were 0 as expected. The 2 3/8 tubing by 5 1/2 casing annulus was then pressured up to 1520 psi and held for 30 minutes with no loss of pressure noted. 38 39 40 o 41 M.I.T.'s performed: 1_ Number of Failures: Total Time during tests: 1/2 hour 42 Attachments: cc.' 43 44 MIT report form 5112100 L.G. MIT AK State A-2 2-18-01 CS 2/21/01 MEMORANDUM TO: Julie Heusser Commissioner THRU: FROM: P.I. Supervisor Chuck Scheve Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: SUBJECT: Diverter Function Test New Contractor New Rig # Exxon Alaska State A-2 Point Thompson NON- CONFIDENTIAL Operator Rep.: Dennis Lott Contractor Rep.: Mike LaOran,qe Rig phone: MISC. INSPECTIONS: Location Gen.: OK Well Sign: OK Housekeeping: OK (Gen.) Drlg. Rig: OK Reserve Pit: NIA Flare Pit: 'N/A Op. phone: 448-1511 Op. E-Maih Rig E-Mail: ACCUMULATOR SYSTEM: Systems Pressure: 3000 Pressure After Closure: 2100 200 psi Recharge Time: .. 120, FullRecharge Time: 1:15 Nitrogen Bottles: .3 Empty psig psig min:sec min:sec F , , ,. , PIF P P _, P P MUD SYSTEM INSPECTION: Light Alarm Trip Tank: N/A NIA Mud Pits: OK OK Flow Monitor: NIA NIA GAS DETECTORS: Light Alarm Methane OK OK H2S: OK OK DIVERTER SYSTEM INSPECTION: Diverter Size: Divert Valve(s) Full Opening: Valve(s) Auto & Simultaneous: Vent Line(s) Size: Vent Line(s) Length: Line(s) Bifurcated: Line(s) Down Wind: Line(s) Anchored: 7" in. Yes Yes 6" in. 100" ft. no Yes Yes , Turns 'Targeted I Long Radius: N/A Test's Details I traveled to EXxons Alaska State A-2 location on. Flaxman island and witnessed the diverter function test on the Dyna Tec RD20 rig. The rig though small and ill equipped by north slope standards should be adequate for the scope of the work planned. The diverter system consisting of a 7 1/6 annular, a full opening knife valve, and 100' of 6" vent line functioned extremely Well as did the accumulator unit. The knife valve opened instantly and the annular closed within seconds of being activated. The vent line is a single stright line constrution very well anchored and directed away from all equipment and activity on location. The gas detection systems were tested and worked very well. There were two non compliance items noted. Two Iow pressure valves were installed in the hyd lines to the annular, these were replaced prior to the function test, and the back up nitrogen bottles on the accumulator unit were empty, replacement bottles were ordered and will be installed upon ardval. Total Test Time: ,3, hours CC:C: D~v-'6'~er Test (for inspectors) BFL 11120/00 Number of failures: 2 Attatchments: Diverter Dyna Tec RD20 1-31-01 CS.xis A B I C ID El F G Hill J K L IM' 1 MEMORANDUM State of Alaska - 2 I Alaska Oil and Gas Conservation Commission 4 TO: Julie Heusser ~,~'i ,,~D~- DATE: February 18, 2001 5 Chairman~"' 6 t SUBJECT: Mechanical Integrity Test 7 THRU: Tom Maunder Exxon 8 P.I. Supervisor "a ~' ~ ~1\ Flaxman Island 9 I 10 FROM: Chuck Scheve :Point Thomson 11 Petroleum Inspector 12 NON- CONFIDENTIAL 13 14 Packer Depth Pretest Initial 15 Min. 30 Min. 15 Well AK ST A-2 Type Inj. N T.V.D. 1992 Tubing 0 0 0 0 Interval I 16 P.T.D. 200-141 Type test P Test psi 498 Casing 0 1520 1520 1520 P/F __P 17 Notes: 19 P.T.D. Type test Test psi Casing PIF 20 Notes: 21 WellI T.V.D. I 22 P.T.D. I Type Inj. I Type testI Test psi I ITubing 23 Notes: Type testI Test psi I ITubing Casing P/F 26 Notes: 27 Well P/FI 28 P.T.D. [ Type Inj. I D. Type testl I T.V. Test psi I ITubing 29 Notes: 30 Type INJ. Fluid Codes Type Test Interval 31 F = FRESH WATER INJ. M= Annulus Monitoring I= In tia Test 32 G = GAS INJ. P= Standard Pressure Test 4= Four Year Cycle 33 S = SALT WATER INJ. R= Internal Radioactive Tracer Survey V= Required by Variance ·34 N = NOT INJECTING A= Temperature Anomaly Survey W= Test during Workover 35 D= !Differential Temperature Test O= Other (describe in notes) 37 Test'sI Details I traveled to Flaxman Island to witness the initial MIT on Exxon's Alaska State A-2 Well. Pretest tubing and casing were 0 as expected. The 2 3/8 tubing by 5 1/2 casing annulus was then pressured up to 1520 psi and held for 30 minutes with no loss of pressure noted. 38 39 41 M.I.T.'s performed: ~_ Number of Failures: 0_ Total Time durinfl tests: 112 hour 42 Attachments: c¢: 44 MIT [eport form 5/12/00 L.G. MIT AK State A-2 2-18-01 CS 2/21/01 ,.- ,,, Al B I C I D I F G H I ~ I J I K I L M 1 MEMORANDUM I State of Alaska 2 I Alaska Oiland Gas Conservation Commission 4 TO: Julie Heusser DATE: February 18, 2001 5 Chairman 6 I t SUBJECT: Mechanical Integrity Test 7 THRU: Tom Maunder /~¢j~ 8 P.I. Supervisor"'-~ >,' ' r'~. _ _ \ Flaxman Island 9 J ~ !;)', Alaska State A-2 10 FROM: Chuck Scheve Point Thomson 11 Petroleum Inspector 12 NONr CONFIDENTIAL 13 14 Packer Depth Pretest Initial 15 Min. 30 Min. , 15 Well AK ST A-2 Type Inj. N T.V.D. 1992 Tubing 0 0 O 0 Interval I 16 P.T.D. 200-141 Type test P Test psi 498 Casing 0 1520 1520 1520 PIF P 17 Notes: 18 Well 19 P.T.D. I Type Inj. I I T.V.D. Type testI Test psiI I Tubing 20 Notes: 22 P.T.D. Type test Test psi Casing P/F 23 Notes: I. 24 Well I Type 25 P.T.D. Type testI IT'V'D' Test psi I ITubing 26 Notes: 27 Well I Type Inj. 28 P.T.D. Type testI IT'V'D' Test psi I ITubing Casing I 29 Notes: 30 Type IN J. Fluid Codes I Type Test Interval 31 ,F = FRESH WATER INJ. M= Annulus Monitoring I= In tia Test 32 G = GAS INJ. P= Standard Pressure Test 4= Four Year Cycle 33 S = SALT WATER INJ. R= Internal Radioactive Tracer Survey V= Required by Variance 34 N = NOT INJECTING A= Temperature Anomaly Survey W= Test during Workover 35 ' D= Differential Temperature Test O= Other (describe in notes) 36 I traveled to Flaxman Island to witness the initial MIT on Exxon's Alaska State A-2 Well. Pretest tubing and casing were 0 as expected. The 2 3/8 tubing by 5 1/2 casing annulus was then pressured up to 1520 psi and held for 30 minutes with no loss of pressure noted. 38 ..... 39 41 M.I.T.'s performed: 1_[ Number of Failures: 0.0, Total Time during tests:[ 1/2 hou_~r 42 Attachments: cc..._[: 43 ,,_ 44 MIT report form 5/12/00 L.G. MIT AK State A-2 2-18-01 CS 2/21/01 Re: Flaxm~an Island Contacts Subject: Re: Flaxman Island Contacts Date: Wed, 17 Jan 2001 15:29:10 -0900 From: Tom Maunder <tom_maunder@admin.state.ak. us> To: Jesse Mohrbacher <jesse@fairweather.com> CC: AOGCC North Sope Office <aogcc_prudhoe_bay@admin.state.ak. us> Jesse, We have received your proposal for perforating the Flaxman Island disposal well without using a lubricator. Your proposal was reviewed by myself and the Inspection group. While not using a lubricator would certainly simplify your operation, we believe that not having a lubricator is an unacceptable risk and your proposal is not acceptable. We understand that your planned initial perforation interval is 20'. We suggest that consideration be given to shooting the interval in 2 run& The necessary lubricator length for a 10' gun and other tools should be able to be accommodated in your derrick. We understand that rig up is underWay and that operations could get underway this weekend. Please keep in contact with our North Slope office to coordinate witnessing your diverter function test. Their number is 659-2714. Good luck with the project. Tom Maunder Petroleum Engineer AOGCC Jesse Mohrbacher wrote: > Hello Tom, > Bill Penrose mentioned that you needed some contact #'s for our project. > Please find attached a project phone list including Flaxman location phone > #'s. > Also, I wanted to make sure you received our fax regarding wireline BOP's > last Friday. Please contact me at 907 258 3446 if you didn't. > Thanks, > > Jesse Mohrbacher > Vice President > Fairweather E&P Services, Inc. > Houston, TX > 281 445 5711 / 281 445 3388 fax > Anchorage, AK > 907 258 3446 / 907 258 5557 fax > Nane: Project Phone List. xls > Project Phone List. xls Type: Microsoft Excel Worksheet (application/vnd. ms-excel) > Eno)ding: base64 1 of 2 1/17/01 5:46 PM E & P SERVICES, INC. 3-Jan-O 1 Mr. Glenn Gray Project Analyst State of Alaska Office of the Governor Division of Governmental Coordination P. O. Box 110030 Juneau., AK 99811-0030 Status Update for the ExxonMobil Flaxman Island Reserve Pit Closures Alaska State A-1 and G-2 Project Dear Mr. Gray: Please find enclosed a status report for the referenced project. The enclosed report is intended to provide updated information relating to the project's schedule, equipment listing, and work plans based on the progress made during the past few months of planning and engineering. If you have any questions or require additional information, please contact the undersigned at 281-445- 5711, Mike Barker (ExxonMobil) at 907-564-3691, or A1 Robb (ExxonMobil) at 713-656-9182. Sincerely, FAIRWEATHER E&P SERVICES, 1NC. Jesse Mohrbacher Vice President CC~ A1 Robb III, ExxonMobil Bruce Webb, ADNR DOG D. Michael Barker, ExxonMobil Forrest E. Hand, ExxonMobil Gary Schultz, ADNR Gordon Brower, North Slope Borough Jack Winters, ADF&G Steve Amstrup, USGS John Kuterbach, ADEC John Bridges, USFWS Judd Peterson, ADEC Kellie Westphal, ADNR DMLW Pete McGee, ADEC v/~TToobert Robichaud, USEPA Region X m Maunder, AOGCC 715 L Street · Anchorage, Alaska 99501 · (907) 258-3446 · FAX (907) 258-5557 650 North Sam Houston Parkway East, Suite 505 · Houston, Texas 77060 · (281) 445-5711 · FAX (281) 445-3388 ExxonMobil Production Company Flaxman Island Reserve Pit Closures Alaska State A-1 and G-2 Project Project Status Report, January 3, 2001 4/,~,4.,~ J44/../6' 4rich°to;s C°rnrniee/.or/ ExxonMobil Production Company (ExxonMobil) is continuing with the implementation of the Flaxman Island Reserve Pit Closures Project. Field operations on the project commenced on October 1, 2000 and the project is now transitioning into the winter operations phase. ExxonMobil has prepared the following project status report to provide North Slope Borough, State and Federal regulatory personnel with the current status of the project. Work Completed To Date ExxonMobil mobilized a camp and other support equipment to Flaxman Island on October 1, 2000. The camp was manned for 51 days to prepare the site for rig mobilization and to monitor and patrol the work area for the presence of polar bears. During this time, the on-site crew assisted USGS scientists that were conducting polar bear research by providing current reports of polar bear sightings and providing a stopover point for the helicopter operations during USGS field activities. There are no known polar bear dens within a mile of the project's planned work activities. Subsequent to the polar bear monitoring activities, ExxonMobil has collected ice thickness and water depth data in the vicinity of Flaxman Island and determined that sea ice thickening would be necessary for the haulout of heavy loads to the Island. Seawater flooding of the sea ice in the vicinity of Flaxman Island was completed on January 2, 2001. Project Schedule The projec, t schedule is provided in Attachment 1. Factors including rig availability and the likelihood of nor. being able to demobilize the rig by barge moved the well drilling phase of the prOject until early winter. The schedule includes a rolligon mobilization of'the drilling equipment followed by rolligon mobilization of the grind and inject equipment. Work tasks remaining to be completed are identified in the project schedule. The schedule calls for demobilization of all project equipment by mid April. In the event rolligon demobilization of the project equipment is not possible due to unexpected delays and the close of tundra travel in late April or early May, the equipment will be demobilized by barge in summer. On-site Equipment The basic equipment planned for on-site use is listed in Attachment 2. This equipment list is more detailed than what was previously submitted in the Project Description. The only substantive changes to the equipment spread are the elimination of the desalination unit and jaw crusher and the addition of four (4) ground heaters for thawing drilling waste and a high shear submersible pump for slurrying the thawed drilling waste in the reserve pit. The desalination unit was eliminated because large quantities of fresh water were not necessary on location during operations in October and November 2000. The jaw crusher has been omitted because the drilling waste is now planned to be thawed prior to introduction into the grind and inject system. Flaxman Island Reserve Pit Closures Project Status Report The Work Program The materials handling portion of the grind and inject system has been modified slightly. Rather than crushing the frozen drilling waste prior to processing, the drilling wastes will be thawed in place, slurried and pumped into the grind and inject processing system. A high shear submersible pump will be used in the A-1 reserve pit to pump thawed slurry into the grind and inject system. This approach will help ensure that the existing bentonite gel in the drilling waste becomes fully hydrated prior to contact with the seawater diluant. This process is anticipated to reduce the quantity of viscosity additives necessary for the injection slurry. Thawing of the drilling wastes will be accomplished with the use of four (4) closed loop circulating glycol ground heaters, each rated at 310,000 btu per hour. These ground heaters are used regularly in arctic and sub-arctic winter construction activities throughout Alaska. Addition of these heaters does not require any new permits for the project or modifications to existing project approvals. A revised schematic layout and process flow diagram for the grind and inject system are enclosed as Attachments 3 and 4, respectively. The final drilling program for the disposal well has been approved by the Alaska Oil and Gas Conservation Commission. The Alaska State A-2 well will be drilled to 2,400 feet and cased with five (5) inch casing. After completion, the well will be perforated across selected disposal zones between 2,150 feet and 2,375 feet as measured on the existing Alaska State A-1 well logs. Attachment 5 is a schematic for the Alaska State A-2 disposal well. ' This work program is in compliance with all agency permit applications and approvals that have been made for the project. Continuous planning and engineering has resulted in improvements to the project while the overall approach of on-site grinding and injection of the drilling wastes remains the same. J/IN 1 8 2001 :. Flaxman Island Reserve Pit Closures Project Status Report -~-Attachment 1 ExxonMobil Production Company Flaxman Island Reserve Pit Closures Alaska State A-1 and G-2 Project Project Schedule, January 2001 2001 Activity Start Finish i JAN I:I';B MAlt i APR MAY I EquipmentR°llig°n M°bilize Drilling Rig/G&I 01 -Jan 15 -Jan :..:"72 :J;--~}~.~ q:.:-}; ?;:->>,~: , ~ ! J, ~,~;~ :/~i~.~ :~ f :,~-'i:"~'~; ~-~s>..~::-~x:.:~>~:.;~>'~'~'~i:ii~i~._..I~ ~>~.;~>;>. :.~ .... .......... Drill and Complete Disposal Well 15-Jan 30-Jan ::-' :,;':~.~:.;.~: ....i I ....:..~1...$.:., Remove Overburden From A- 1 and G-2 15-Jan 15-Feb .:::.~;~:[~: ~!'~...~i~:~ '" Reserve Pits '='--;.~ "~i~! ~:'i ~i Demobilize Drilling Equipment 01-Feb 05-Feb i;.-i~i ..... -~;.'~_~ .................................... Thaw Waste Material at A-1 01-Feb 07-Apr .'.~.~:i-~;~#;>.i:~ 2 :~i[g-~L~:~. i ~iiii ........ ~ ............ ~ .' z~,'..'/,~: i ~,~i:.~' Grind and Inject Waste Material 07-Feb 07-Apr ......... ~::..~ ........... ~,...,'.,,: ...... } ...... :,. Construct Ice Road from G-2 to A-1 15-Feb 21-Feb :;~_~:-' Excavate and Haul G-2 Wastes to A-1 21-Feb 07-Mar ................. ~-?.-: ,::,~-= ........... Plug and Abandon Injection Well 07-Apr 15-Apr :~ _,~:,.. .................... Demobilize All Equipment 07-Apr 21-Apr ~-;:~,:-~-~:-i i ~ l ................. ~':~:':: :'-'~ Prepare and File Reports 01-May 30-May ........... ' .......... Summer Debris Cleanup and Site 01-Aug 07-Aug ~ Inspection Attachment 2 ExxonMobil Production Company Fiaxman Island Reserve Pit Closures Alaska State A-1 and G~2 Project Project Equipment List Equipment Common to Both Drilling and Grind and Inject Operations · 30 Man Camp w/2 ea 250 KW gensets (1) Complete · 3500 gal Camp Fuel Tanks (2) · 570 bbl Fuel Storage Tanks (2) · RD85 Rolligon for Fuel and Water (1) · F350 Crew Cab Pickup for Bear Monitoring (1) · 40' x 100' portable building (1) · Hyundai 360 Excavator (1) · Cat 320 Excavator (1) · 950 Loader (1) · Forced Air Heaters, 800,000 btu (6) · 966 Loader (1) · 350 KW Gensets (2) · D6Dozer(1) · 185 Cfm Compressor (1) · Light Plants (4) · 100 HP Boiler (1) 'Driliing Phase: · Ingersoll Rand RD20 drilling rig, complete with mud system, pump and diverter system · Cementing Unit · Electric Logging Unit Grind and Inject System: Process Tank # 1 · 5 x 6 Centrifugal Pump (1) · 4" Vertical Gallagher Pump (1) Process Tank//2 · 5 x 6 Centrifugal Pump (1) System Equipment · Seawater Pump (1) · Transfer Pump 1 (1) · Transfer Pump 2 (1) · ALS II Shaker and Stand (2) Attachment 2 1 Grind and Inject equipment cont. Ground Heaters, 310,000 btu (4) · Submersible High Sheer Pump w/Hyundai 110 Excavator for Handling · Vacuum Blower 100 hp (1) · Single Vacuum Hopper (1) · Shock Tank (1) · MTS-14 Rotary Mill (2) · Cuttings Auger (1) · J165 Injection Pump (1) · J 100 Injection Flush Pump (1) · Backup Injection Pump (1) Additional Tanks and Equipment · 100 bbl Square / with agitator (3) · 400 bbl Round / Horizontal (1) · 25 bbl Vacuum Tank (2) · 30ydEndDump RECEIVED Aocflorag~e C°n~mission Attachment 2 2 Attachment 3 Bnne S~rage 100 bbls Tank Skid MTS 14 I~1 MIS 14 Mill -- T~ ......... :.: ......... .-.: I ! I 1 ! ! ! ! ! ! ! ! ! ! ! i, Tank $k~2 I ! I I I ! I I I ! I I I I I I I I l I ! I ! ! ! ! ! ! ! ! ! ! ! ! 1 ! ! 1 ! ! ! ! ! ! ! ! ! ! ! ! ! 1 ! ! ! ! 1 ! ! ! ! ! ! ! ! ! ! ! ! 1 ! ! ! R CF. J N] ~t~iSsioo Attachment 4 Matedal from reserve pit Material from reserve pit ~ Coarse Screen Gar~her Process Loop Ver'dcal Tank #1 Pump 115 bbls Underfiow to slop tank Classified Slurry Storage Tank #2 190 bbls Icl Classified Slurry Classified Slurry Storage Tank Storage Tank 100 bbls 100 bbls Tdplex Pump J ' 5bbls/min~1000 ,-- J~N 1 ¢ ZO Alaska Oil & Gas Cons. Corn, Anchorage ~ission Attachment 5 2 %" Hole =80' 9 518" Conductor Casing Tubing/Ca~ng J~nulus Freeze Pmlocto~! w/CaCl2 Br~no. -- 6 %" Hole Permafrost Interface @ = 1,000 LEGEND Cement NO F'XIR/£XXON/2OOO/FLXB2.000 Stage Cementing Tool @ = 1,200 1:1 11115/00 Rev.1 2 3/8" TUbing 318" Packer Shoe S A 2030' Potential Dlsposal Zone. 2150' - 2,375' Production Disposal Casing · Alaska 0il ~ ~as Cons AnChorage' ~mmi~ f~ Floxmon Islond Disposol Well Proposed Alaska State Wellbore Schematic E & P SERVICES, INC. 2-Jan-00 Mr. Alvin G. Ott Regional Supervisor Habitat and Restoration Division Alaska Department ofFish and Game 1300 College Road Fairbanks, AK 99709 RECEIVED JAN 1 1 ZOO1 Alaska Oit & Gas Cons, Commission Anchorage Revisions to Polar Bear Awareness and Interaction Plan ExxonMobil Flaxman Island Reserve Pit Closures Alaska State A-1 and G-2 Project Dear Mr. Ott: Please find enclosed the most recent version of the Polar Bear Awareness and Interaction Plan for the referenced project. Changes to the Plan have been made in accordance with ADF&G's August 28, 2000 comments and ExxonMobil's September 7, 2000 clarification letter. ExxonMobil and Fairweather are currently preparing to mobilize equipment to Flaxman Island to commence winter operations. All on-site employees will be familiarized with the Plan before working on-site. If you have any questions or require additional information, please contact the undersigned at 281-445-5711 or Mike Barker at 907-564-5711. We appreciate the Departments input and participation in this project. Sincerely, FAIRWEATHER E&P SERVICES, INC. Jesse Mohrbacher Vice President CC: A1 Robb III, ExxonMobil Bruce Webb, ADNR DOG D. Michael Barker, ExxonMobil Forrest E. Hand, ExxonMobil Gary Schultz, ADNR Glenn Gray, DGC Gordon Brower, North'Slope Borough Jack Rickner, ExxonMobil Jack Winters, ADF&G John Kuterbach, ADEC John Bridges, USFWS John McDonagh, ADEC/JPO Judd Peterson, ADEC Kellie Westphal, ADNR DMLW Pete McGee, ADEC Robert Robichaud, USEPA Region X ,/Tom Maunder, AOGCC 715 L Street · Anchorage, Alaska 99501 · (907) 258-3446 · FAX (907) 258-5557 650 North Sam Houston Parkway East, Suite 505 · Houston, Texas 77060 · (281) 445-5711 · FAX (281) 445-3388 ExxonMobil Production Company Anchorage, Alaska FLAXMAN ISLAND RESERVE PIT CLOSURES ALASKA STATE A-1 AND G-2 PROJECT FLAXMAN ISLAND, BEAUFORT SEA, ALASKA POLAR BEAR AWARENESS AND INTERACTION PLAN January 2001 E:~onMobil Produ,cti~on TABLE OF CONTENTS 1. Introduction and Project Summary ........................................................................ 1 2. Plan of Cooperation ............................................................................................... 1 3. Polar Bears ............................................................................................................ 1 4. Protected Status of the Polar Bear .......................................................................... 2 5. Project Personnel Orientation Program .................................................................. 3 6. Project Camp and Lighting Systems ...................................................................... 3 7. Polar Bear Watches ............................................................................................... 4 8. Polar Bear Monitoring Systems ............................................................................. 5 9. Reporting .............................................................................................................. 5 ATTACHMENT A ........................................................................................................ 6 ATTACHMENT B ........................................................................................................ 7 FIGURES Figure 1: Figure 1. Flaxman Island Vicinity and Proposed Project Travel Routes ........ 9 1.0 Introduction and Project Summary ExxonMobil Production Company (ExxonMobil), a division of Exxon Mobil Corporation, intends to permanently close the reserve pits at the Alaska State A-1 and G- 2 locations on Flaxman Island in the Beaufort Sea beginning in September 2000 and reaching completion in May 2001. Previous work at these and other ExxonMobil locations on the barrier islands has resulted in the permanent plugging and abandonment of all wells on the islands. Only the A-1 and G-2 locations have associated reserve pits. Flaxman Island is undergoing natural shoreline erosion and the contents of the reserve pits (drilling wastes) could become exposed to the sea in the coming years, if not removed. Figure 1 depicts the general project work area of Flaxman Island. ExxonMobil is in the process of permitting an on-site disposal well at the A-1 location to facilitate these closures. The overall project requires the removal and disposal of a total of 15,000 to 25,000 cubic yards of drilling wastes presently contained in the pits. The approach to this project is to drill a Class II disposal well and to grind and inject all drilling wastes from both reserve pits as well as associated flare pits. This approach minimizes both off-site transportation requirements and overall environmental impacts, including the associated risk of spills from trucking operations, noise impacts, fugitive air emissions (both exhaust and dust), and other potential environmental disturbances. The following Polar Bear Interaction and Awareness Plan has been developed in accordance with 50 CFK Subpart J. The primary purpose of the plan is to provide work crews with an understanding of the importance of polar bear safety precautions and to help develop practices that will ensure safety for bears and humans. 2.0 ' Plan of Cooperation The planned pit closure activities are unlikely to interfere with subsistence activities. The Flaxman Island area is over 50 miles from the village of Kaktovik and village residents do not routinely hunt in the project area. However, due to the duration of the project activities, it is reasonable to expect that at various times hunters and/or other travelers will pass through the project area. The project camp will be able, within limits of available resources, to provide limited food, shelter and fuel to native hunters and travelers, particularly during periods of inclement weather. A Plan of Cooperation to mitigate potential subsistence conflicts is required by 50 CFR Subpart J when relevant to project activities. ExxonMobil plans to visit the villages of Kaktovik, Nuiqsut and Barrow prior to the startup of project activities for the express purpose of acquainting village residents with the project objectives, schedule and availability of emergency logistical support to travelers through the project area. In addition, it is anticipated that local residents will be employed on the project in various capacities. -1- 3.0 Polar Bears ExxonMobil and its contractors recognize that Flaxman Island and surrounding areas are potential areas of polar bear use. In the past, polar bear dens have been located along the bluffs of Flaxman Island. Polar bears are known to be faitlfful to denning habitat type. Flaxman Island and the nearby coastal bluffs provide suitable habitat for denning polar bears. Polar bear winter feeding habits are dependent upon hunting seals and feeding on marine mammal carcasses. The only known marine mammal carcasses in the general area are usually those harvested by Kaktovik during the whaling season. Kaktovik's improved carcass disposal and handling practices has led to fewer polar bear and human interactions. Presently, there are no known mammal carcasses in the vicinity of the project area. Polar bears often hunt seals in open water areas and in leads and polynyas. Open water is not expected to occur in the immediate vicinity of the project area except in late summer to perhaps October 2000. However, it should be emphasized that polar bears may be found in the area at any time of the year, including the deep winter period of hard freeze up. It is in recognition of this possibility that the following Polar Bear Awareness and Interaction Plan has been developed to cover the proposed project operations. 4.0 Protected Status of the Polar Bear The polar bear is a marine mammal species fully protected by provisions of the Marine Mammal Protection Act (MMPA). The Federal agency responsible for management of 'polar" bears is the U.S. Fish and Wildlife Service (USFWS). The USFWS has published regulations authorizing the incidental, unintentional taking of small number of polar bears during oil and gas industry operations year round in the Beaufort Sea and adjacent northern coast of Alaska. The MMPA explicitly states that a moratorium has been placed on the "take" of any marine mammal. "Take", as defined by the Act, means to "harass, injure, capture, kill or to attempt to harass, injure, capture, kill" a marine mammal. However, it is vitally important that opportunities are reduced to a minimum for accidental encounters between marine mammals and project personnel that might result in a take, including takes by harassment. Experience highlights this need. The lethal take of a polar bear did occur in January 1990 at the Stinson exploratory offshore well site in West Camden Bay. While that take may have been unavoidable and necessary in order to insure the protection of personnel who were working on the sea ice near a drilling rig, the Polar Bear Awareness and Interaction Plan set out below draws upon that experience and others in an effort to prevent a recurrence during this program. The polar bear is a subsistence resource available to Alaska Natives. Natives, in cooperation with Canadian native hunters, have over the past few years developed a management plan to insure that subsistence takes from this jointly shared Beaufort Sea polar bear population do not exceed biologically acceptable limits. It is possible that a -2- number of members of the ExxonMobil and contractor crews will be Alaska Natives who, as subsistence hunters, might otherwise be authorized to take polar bears. However, Natives employed in the program are governed by rules and procedures, which extend to all employees. During periods of active employment, when traveling to and from the project area, and during active service at the project locations, no subsistence hunting is in any way authorized. A Native crewmember may be assigned tasks as a polar bear watch person. In the course of these assigned duties, he may be required to use deterrent measures including the use of firearms which is authorized only on the basis of a crew member designated to carry out such measures and not because the crew member might otherwise be entitled to subsistence hunting rights. 5.0 Project Personnel Orientation Program All ExxonMobil and contractor personnel will receive an environmental orientation before beginning work tasks in the project area. In most instances, the orientation will be given in Anchorage or upon initial arrival at contractor facilities in Deadhorse. A major feature of the orientation will consist of viewing "Polar Bears: Safety and Survival", a video prepared by the Alaska Oil and Gas Association (AOGA) in cooperation with experts from the Federal and State wildlife regulatory agencies. This training film covers the life history and the biological status of the Beaufort Sea polar bear population; the Marine Mammal Protection Act as it applies to bears; and the measures to be taken to minimize human/bear encounters. A minimum of two project personnel will also be trained in polar bear deterrence. This training, which has been approved by both the Alaska Department of Fish and Game and the U.S. Fish and Wildlife Service, will be provided to select individuals that may be required to perform hazing operations to protect human health and welfare. Only properly trained personnel will have access to the firearm(s) that will be maintained on- site. Project personnel will stay at the CATCO camp located adjacent to the work location. When personnel are working around the camp or anywhere on Flaxman Island, the following fundamental principal will bind their work: That EARLY DETECTION AND SAFE AVOIDANCE PROCEDURES are the best guarantee that a harmful encounter (for either bears or people) will not occur. Please refer to Attachment B, "Polar Bear Interaction Procedures" which will be distributed to all project crew at the orientation. 6.0 Project Camp and Lighting Systems The camp will have a lighting system to illuminate walkways and entry areas around the camp. Although camp lighting will assist workers in seeing any bears that may be within the immediate camp area, these lights will not illuminate bears at a distance from the camp and immediate work area of the A-1 site. Personnel will be instructed to always look outside before leaving a camp building in case a bear is nearby. Work locations will -3- also be lighted but again will only be illuminated in the immediate work areas. Personnel will be reminded to be extra cautious when working outside during evening hours and hours of darkness and remain within the lighted work areas. The camp and on-site equipment will be skid mounted and fit closely to the ground to prevent polar bears from hiding under structures. Wheeled equipment such as loaders and rolligons will be left constantly running and are not anticipated to be a likely hiding place for polar bears. Camp garbage will be backhauled to Deadhorse on a regular basis by rolligon or aircraft. All food wastes will be maintained indoors until such time of backhaul. Dumpsters on-site will be standard North Slope Borough Landfill type and will be used solely for non-food related solid waste such as scrap debris, metal and empty material containers. No bear-proof dumpsters are planned for the project since all food related wastes will be backhauled on a regular basis. No bear alarms are planned at the facility. Project personnel will be in radio contact throughout the work and camp areas. Two-way VHF radios will be present in the camp and project heavy equipment. The presence of a polar bear in the project vicinity will be first announced over the radio system, then additional personnel will be notified as necessary if working away from radio contact. 7.0 Polar Bear Watches ExxonMobil intends to maintain two (2) dedicated polar bear monitors during project activities to provide 24-hour polar bear watch capability. A visual inspection of the camp area, Flaxman Island and the surrounding sea ice will be made by the designated polar bear watch persons to look for bears or signs of bear presence on a regular basis. Project 'pers6nnel will be instructed to report any polar bear sightings or interactions to the designated watch person and the on-site supervisor. The intent of these visual inspections is to achieve early detection of the presence .of bears. In the event a bear is sighted, the watch person will not attempt to undertake hazing or harassment actions upon the initial encounter unless absolutely necessary. These procedures will be practiced by trained personnel only after a bear has been deemed to be a risk and other non-confrontational procedures such as avoidance, retreat and waiting have failed to alleviate the bears curiosity and presence. When it has been determined by subsequent inspection that bears are no longer present in the work vicinity, the alert will be lifted. In the event that a bear remains in the vicinity of the project location for a prolonged period, Mr. John Bridges of the USFWS (907-786-3810) will be contacted for advice on possible measures to deter the bear from use of the work area. In addition to the USFWS, Mr. Dick Shideler of the Alaska Department of Fish and Game (ADF&G) will be contacted and informed of the situation. Deterrent or hazing measures may include Iow level helicopter flights, fire cracking or noise shells or firing beanbag shells. Both the USFWS and ADF&G will be consulted on the most appropriate hazing method to use for the given situation. -4- While human safety is the top priority, it is vitally important to emphasize that the early detection and avoidance measures are equally designed to prevent encounters that might result in harm to humans and bears. 8.0 Polar Bear Monitoring Program If polar bears are sighted in the project work areas, the watch person will systematically collect and record all data. To the extent that safe observation permits, behavioral data will be collected (see Attachment A, "Daily Polar Bear Sighting Log"). Any crew member who sights a polar bear or polar bear sign, such as tracks, should immediately communicate the details of that sighting to the watch person responsible for maintaining the log. To the extent available, the activity log will record observations such as group size, age, sex, reaction, duration of interaction, and closest approach. Any data acquired will be made available to the USFWS and the ADF&G periodically during the project. It is also important that the actual time spent undertaking polar bear observations be part of the journal record. Biologists require this information in the course of collecting accurate statistics in their study efforts. 9.0 Reporting The USFWS and the ADF&G will be given reports of any polar bear sightings as soon as practical. Any other potentially useful information such as possible den locations will also be provided. Reports will be made to: Mr. J:Ohn Bridges USFWS - Marine Mammals Section 1011 East Tudor Road Anchorage, Alaska 99503 Telephone: 907-786-3810 Fax: 907-786-3816 And Mr. Dick Shideler ADF&G- Habitat Division 1300 College Road Fairbanks, Alaska 99709-4173 Telephone: 907-459-7283 Fax: 907-456-3091 In the event advice is required in dealing with a problem bear or if an actual bear/human encounter occurs, the individuals listed above should be contacted immediately. -5- ATTACHMENT A DALLY POLAR BEAR SIGHTING LOG Location: Watchperson: Date: Signature Maximum Visibility: (mi/yds) Time: Sightings: Species: Group Size: Age:__ Sex:~ Reaction: Duration of Interaction: Closest Approach: General Weather Conditions: Other Comments: -6- ATTACHMENT B Polar Bear Interaction Procedures Prior to initially working at a location, scan the surrounding area for evidence of bears. Check with the designated watch person to make sure no bear signs have been reported. The surrounding area must be "bear free" prior to initiation of work. . The designated watch person will maintain the watch from the perimeter of the work location(s). Work crews at locations removed from the main work crew will maintain radio contact with the watch person. All work crews will maintain a retreat area at each work site such as a rolligon, camp unit or vehicle. 3. Take no food outdoors to avoid attracting bears. . In the event a bear is sighted, retreat to a secure location such as a rolligon, vehicle or camp unit. Report all bear sightings to the designated watch person and on-site supervisor as soon as it is safe to do so in a secure location. Do not remain in an unsafe situation to view or photograph a bear. 5. Look outside prior to leaving a camp building. 6. Use common sense. The proposed Polar Bear Action Levels are the following: Level 1. Level I will be maintained during all field activities and will include the following standard polar bear avoidance techniques: · Dedicated watch person(s); · Control of food and food wastes; · Observation of any tracks; and · Appropriate lighting of camp and work areas. Level 2. Level 2 will become effective immediately upon the sighting of a polar bear. Level 2 response actions will include the following: · Temporary stoppage of work to inform all personnel; · Assessment of the situation by the contractor field supervisor and the ExxonMobil representative; · Resumption of work with a minimum of two (2) dedicated bear observers or elevation to action Level 3; and · Notification of ExxonMobil and agency personnel. -7- Level 3 Level 3 will be implemented if a bear becomes a potential or real threat to personnel. Level 3 actions will include all of the following: · Complete stoppage of work; · Retreat to safe observation areas such as a rolligon or heavy equipment cab, camp units, or other protected areas; · Continued observation until the bear has safely left the area; and · Notification of appropriate agency and ExxonMobil personnel. -8- SITE LOCATION ~ NOT TO SCALE ~/S,~L4/VD /--ALASKA STATE A-1 ~ /(,.oJEct .As~ cA~', ~ooo/2oo~) / ~ ~ ~ ROLLIGON / 0 3750 7500 SCALE IN FEET rAIR/£XXON/2OOO/FLAXO0 1:7500 '//14/00 Figure 1 Flaxman Island Vicinify and Proposed Projecf Travel Roufes BROWNLOW PT. I-IZ- I ' I~'IU ' DUI Y.t~ tO~Y.;~ 7./ ;3 RE: RECE /ED Wireline PerForating of the Alaska State A-2 Well Tom, further to our earlier conversation regarding wtreline perforating, we tu-e planning to perforate the well without a lubricator and use wireline BOWs and a packoffas a substitute. Our rationale for this is the fi~llowing: ']., Perforating operations will be conducted in an overbalanced colurnn with approximately 9,3 ppg brine in the hole. Ihe packer will. have already been set. . In the unlikely event there was any pressure on the well after perforating, we could bullhead through the wing valve and down the tubing to kill the well. Thc wireline BOP' s will be able to seal off the tubing with wire in the hole in the event any pressure was present after perforating. Fmlhermore, if absolutely necessary, the master could be closed to cut the wireline and secure the well. Please refer to the attached wellhead schematic and wireline BOP sketch, , It is extremely unlikely that any pressure will be seen after perforating since we will have already drilled the section on diverter and other data in the area shows a seawater gradient to depths up to 3,500 R. . 'l,'he potential exposure by the above practice is if the per.~brating guns became stuck in the tree upon removal. This is also very unlikely because the 1-1 ] / 16 inch perlbrating guns will be retrieved through 2-3/8 inch tubing (1,901 inch drift) and then pulled through the tree. The master and swab tree valves are 2-9/I 6 inch bore making the potential for getting stuck in the tree negligible. The well will be checked for pressure before running in the hole and prior to pulling through the ti'ce. . Utilizing the wireline BOP's will physically be .a satyr procedure because the drilling crew will not have to handle the large diameter lubricator in the small derrick. We believe that utilization tffthe wireline BOP's will provide an equal, level of security to the well operation while making the perforating process a simpler field operation, If you have any questions regarding the above plan, please contact me or Jesse Mohrbacher al your earliest convenience at 907-258-3446. Thank you fbr your attention to this matter. l Fax Transmittal Sheet [] Utl~ont ~ For Review (Including Cover Sheet): ~ [] Please Commod ~easo Reply [] Pleeoo Recycle · Comments: RECEIVED ~!~! 12 2001 Oil & ~ Cons. Com~. 715 L, street, Anchorage, Alasl(a 99501 Voice.' (gO7) 258-3446 Fa~. (907) 25~-5557 Subject: Date: Wed, 10 Jan 2001 10:52:23 -0600 From: "George Scott" <george@fairweather. com> To: <Tom_Maunder@admin.state.ak. us> CC: '"jesse@fairweather. com'" <larry@fairweather. com> Tom: As discussed yesterday I am sending you a revised Drilling Procedure Summary for the Alaska State A-2 Disposal Well. This replaces the original summary recieved by you September 7, 2000. The key change is that now we will be running open hole logs (Platform Express-Sonic) including a caliper log. Please let me know if you require further information. Regards George Scott Sr. Project Manager Fairweather E&P Services Inc. Name: ALASKA STATE A.doc ~ALASKA STATE A.doc Type: Microsoft Word Document (application/msword) Encoding' base64 I of 1 1/10/01 1:08 PM ALASKA STATE A-2 DISPOSAL WELL DRILLING PROCEDURE SUMMARY 1. Excavate and install cellar with metal floor and riser. . o . Move Rig over cellar and rig up. Rig RKB-ground 5'. MAJ 12-1/4 inch used bit and drill 12-1/4" hole to +/- 80' RKB. Circulate clean and POOH to run casing. Run 9-5/8" pre cut and threaded 43.4 lb./ft. L-80 BTC casing to 80' RKB. Make up cement head and hang in casing elevators. Cement conductor casing with 70 sacks of 15 ppg Cold Set II permafrost Cement (Calculated annular volume plus 150% excess). Put cement returns in mud tank and treat to prevent cement from settling. 5. Drain riser in cellar. WOC. Slack off casing weight. , . , , Cut off casing and weld on an 11" 3000 psi x 9-5/8" WP starting head (A-Section). Install a 9-5/8" x 7-1/16" 5000 psi adapter. Install 7"x 5000 psi diverter spool with 6 "diverter line with hydraulic actuated valve. Function test the diverter system. An AOGCC representative is to witness the function test. Note: AOGCC requires 24 hours prior notification. M/U 6-3/4" slick drilling assembly and RIH to PBTD and drill out conductor shoe and drill straight hole to 2400' RKB. Single shots are to be taken every 500', unless deviation over 1.5 degrees is observed at which time a decision will be made on increasing the frequency of the surveys. At TD, take final single shot survey and circulate and condition mud for logging. POOH. Note a 4-arm caliper will be run from TD to the bottom of the conductor to help determine cement volumes and centralizer placement. Run 5" 18 lb/ft. LS R-2 SCC LTC casing. The casing will be equipped with a float shoe and collar 1 joint up from the shoe, as well as centralizers. In addition an FO stage collar will be located at +/- 1200' RKB approximately 200' below the estimated bottom of the permafrost. Run casing to within 5-10' of TD and circulate and condition for cementing. See attached centralizer and cement program. M/U cementing head, and rig up at surface to reciprocate casing during 1 st stage of cementing. Cement casing to surface in two stages. Stage 1 is to extend from TD to 1200' RKB. And consist of 163 sacks of Class G cement plus additives, 35% excess. Stage 2 will be cemented from 1200' RKB to surface and consist of 535 sacks (700% excess) of Cold Set III permafrost cement. Reciprocate casing during first stage of cementing. Put cement returns in mud tank and treat to prevent setting up. Drain diverter and flush to below wellhead. (Refer to caliper log.) Drilling Procedure Summary (continued) 10. Pick up diverter spool. Set casing slips with tension on casing. Cut off casing and remove diverter spool. Dress casing stub. Install 11" x 5" pack off. Install tubing spool (B-Section). Test pack off to 3,000 psi. NU 7" 3000 psi x 7" 5000 psi DSA and 7-1/16" annular, Function test annular. PU 2-3/8" clean out string. 11. RIH with 3-7/8 inch bit and casing scraper. Drill out FO Collar and 5 "casing to the float collar. Circulate the hole clean displace to 9.2ppg NaCI brine. Pressure test casing to 1500 psi. POOH. Run minimum 4.180" gauge ring to assure packer clearance. Note: If required a diesel top up will be done. 12. RAJ Schlumberger and run a USIT cement evaluation and correlation log. From TD to bottom of conductor. Confirm that the cement job is acceptable. 13. RU and run 2-3/8" 4.7ppf 8md EUE J-55 tbg. A 5" x 2-3/8" packer will be set at 2000' RKB and tubing mule shoe to be located at +/- 2030' RKB. A profile will be run in the tubing to back up the packer setting operation. 14. Install the 2-3/8" tubing hanger and land Tubing. Back out landing joint. Remove 7" annular. N/U tree (C-Section) Test tubing pack off to 3000 psi. 15. Pressure test tree and casing to 3000 psi. (A two-way check valve will be available if needed.) 16. Drop ball down tubing and shear out to set packer. Ball is set to shear at approximately 2000 psi. (Check packer running and setting guidelines.) 17. Pressure test the packer by pressuring up the annulus to 2500 psi and observing tubing for by- pass. Hold the test for 30 minutes. Bleed off, pressure up on 2-3/8" tubing to 2400 psi to expend ball seat. (Refer to attached packer procedure.) 18. Rig up Schlumberger with lubricator and test to 1500 psi. RIH with tubing gun. And perforate the 5" casing with 6 SPF 0 deg phasing over a 20' interval over the selected disposal zone in the interval 2,300'-2,360' RKB. RD Schlumberger. (Correlate with offset Alaska State A-1 Well.) 19. Rig up to pump down tubing. Perform step rate injection test to establish injection rates and pressures. Limit Rate to 6 BPM. 20. Pump excess drilling and completion fluids down the well. Clean 3-U mud tank. 21. Bullhead NaC1 down robing for freeze protection. Top w/Diesel if required. RD release rig. AlaSKA OIL AND GAS CONSERVATION COMMISSION / ,r i / ! TONY KNOWLES, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 James F. Branch Alaska Production Manager ExxonMobil Production Company, a division of Exxon Mobil Corporation P O Box i 96601 Anchorage, AK 99519-660 ! Rc~ Alaska State "A" Well #2 ExxonMobil Production Company Permit No: 200-141 Sur. Loc. 1542'FSL, 2598'FEL, Sec. 27, T10N, R24E, UM Btmhole Loc. 1542'FSL, 2598'FEL, See. 27, T10N, R24E, UM Dear Mr. Branch: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill docs not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations arc made. Additionally, a Disposal Injection Order must be issued by the Commission prior to initiating disposal operations. The blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035; and the mechanical integrity (MI) of the injection well must be demonstrated under 20 AAC 25.412 and 20 AAC 25.030(g)(3). Sufficient notice (approximately 24 hours) of the MI test before operation, and of the BOPE test performed before drilling below the surface casing shoe, must be given so that a representative of the Commission may witness the tests. Notice may be given by contacting the Commission petroleum field inspector on the North Slope Pager at 659-3607. Commissioner BY ORDER OF THE COMMISSION DATED this 2 / ~ day of December, 2000 dif/Enclosures cc: Department ofFish & Game. Habitat Section w/o encl. Department of Environmental Conscrvation w/o encl. Flaxman Island PTD Subject: Flaxman Island PTD Date: Thu, 14 Dec 2000 05:58:59 -0900 From: Julie Heusser <julie_heusser@admin.state.ak. us> To: Tom Maunder <tom_maunder@admin.state.ak. us> Tom, I'm out of the office today and Friday. From my perspective, the Flaxman A-2 PTD is okay. Assuming the PTD has gone through the other commissioners for review (and they have no concerns) - it's okay for an approval letter to be dra~ed and signed. Cheers Julie T'oyyt I m 1 of 1 RE,: Alaska'State A-2 Subject: RE: Alaska State A-2 Date: Thu, 7 Dec 2000 11:02:31 -0600 From: "Jesse Mohrbacher" <jesse@fairweather. com> To: "Tom Maunder" <tom_maunder@admin.state.ak. us> CC: "Al Robb" <ali_robb@email.mobil.com>, "Jack Rickner" <jack. a.rickner@exxon.com>, "Larry Ross" <larry@fairweather. com>, "George Scott" <george@fairweather. com>, "Mike Barker" <dmbarke@upstream.xomcorp.com> Tom, we have evaluated the possibility of temperature logging for the proposed A-2 disposal well and we have some concerns about this potential operation. Temperature logging during the cased hole logging program would not be a major addition or effort due to the fact that we would be in cased hole with no perforations and we would have Schlumberger on-site for the cement evaluation logs. Temperature logging at a later date during or ater the completion of G&I operations presents the following difficulties and risks to the program: 1. Interruption of G&l operations during the disposal process for a temperature log risks creating a problem with the well such as a stuck logging tool or swabbing sand into the wellbore during the logging operation. Such a problem could cause a significant delay in the project schedule and potentially include the necessity of remobilizing a rig or other major equipment for remedial work. . The temperature log may be inconclusive due to the injection operations and the temperature of the injection fluid which is estimated at about 40 F. We have discussed this situation with Schlumberger and they have indicated that since this well is an injector, it is likely that the temperature profile will match the injection fluid temperature from top to bottom unless the tool was able to get below the perforations that were accepting the fluid. We plan to perforate about 20' near the bottom ofthe wellbore and we are not keen on running a logging tool into this area of the well for fear of getting it stuck. 3. If a temperature log is to be run during the injection process or at the end of the operation, a crane and logging unit will need to be mobilized. This is an extra operation in an alreadytight project schedule. 4. If we waited to log the well until after the G&I operations, again the possibility of sticking the tool could impair or delay the P&A of the well. We are trying to eliminate potential risks throughout the project that could cause project delays and compromise our ability to demobilize the project by the end of the rolligon season, about May 1. Given the above ooncerns, we request that temperature logging program during or afer the injection process be avoided. Please contact me at your earliest convenience if you require further information on this or any other issue on this project. Regards, Jesse Mohrbacher. 1 of 4 12/14/00 9:58 AM Re: Alaska State A-2 Subject: Re: Alaska State A-2 Date: Thu, 30 Nov 2000 10:25:40 -0900 From: Tom Maunder <tom_maunder@admin.state.ak. us> To: George Scott <george@fairweather. com>, Jesse Mohrbacher <jesse@~.fainNeather. com> George and Jesse, Thanks for the information and the best wishes. We are moving to wrap everything up from the approval side for the permit and the DIO. A ley question we have is when is spud reasonably expected. If the PTD were not issued until Dec 7 or 8, will that affect your schedule. I have a couple of other questions and comments to help us understand your operations. Yesterday, Jesse indicated that you might downsize the tubing to 2-3/8" due to the close clearance. Will that ID be sufficient for you to be able to run a perfgun if you need to add perfs? I suspect a 1-11/16" gun would likely be able to be run. As we understand the process, it looks like you will be pumping your disposal volumes in batches of maybe 1500 to 2000 bbls per day. Is that correct?? Are you planning to start your injection batch with seawater and when done with the slurry batch follow it with seawater to keep your wellbore clean? Early on it was indicated that you would be using the DSR unit/system that might have been on Granite Point. Is that correct?? While you are injecting we would like to know how you will be monitoring pressures? Is the system continuous and automatic? We are interested in the formation's pressure response as the disposal process continues. Single, daily values for rate, tubing pressure and annulus pressure are not what we consider adequate for surveillance. Where the slurry ultimately is emplaced is also of concern. To quantify that information we are considering having you run temperature surveys. One would be run in conjunction with your bond log and the other at some later time, maybe after 100 - 125 k barrels has been injected. Would you investigate how to best gather the later temperature information? We do appreciate you logistics concerns do not wish to cause a severe impact. An initial step rate test will be a requirement of the disposal injection order, we are considering also requesting one at the conclusion of disposal. We look forward to your comments to these discussion points. George Scott wrote: Tom- I am sending you the requested casing info. with the change from 5-1/2" to 5 "casing. Hope all is going well at that end and that you and your family are doing well. All the best for the upcoming holiday season/ Regards George Scott Sr. Project Manager Fairweather E&P Services Inc. Narre: Casing design.xls Casing design.xls Type: Microsoft Excel Worksheet (application/vnd. ms-excel) Enooding: base64 1 of 2 11/30/00 10:28 AM Flaxdispwelldiverteretall01200.txt Subject: Re: Flaxman Island Reserve Pit Closure Project Date: Thu, 12 Oct 2000 16:27:43 -0800 From: Blair Wondzell <blair wondzell@admin.state.ak.us> Organization: State of Alaska, Dept of Admin, Oil & Gas To: larry@fairweather.com CC: Tom Maunder <tom maunder@admin.state.ak.us> Larry Ross' wrote: 7" > Mr. Wondzell, I am a Fairweather E & P employee and currently I am w orking > on the Flaxman Island A-1 and G-2 reserve pit closure project. I am in the > process of procuring the equipment needed to drill a service well (injection > disposal well) on the A-1 location, and am requesting a meeting with you on > Wednesday or Thursday of this week, if possible, to discuss the foll owing > issues. > 1. Diverter System A. The need for one B. Size of diverter and line. If required, we would propose annular > with a single 6" straight line without bifurcation. Ans.1. After reviewing the A-1 mud log, we think a diverter is in ord er. A diverter with a single 6" vent line meets regulations and will be acceptable. > 2. Drilling Fluid Flow Sensor > A. The need for one. The proposed plan would be to take retu rns from the > well into a small tank in the cellar and then pump them up to the sh aker > located on the mud tank. With the Driller being right over the cella Page 1 Flaxdispwelldiverteretall01200.txt r, see > no need for this as he can continuously monitor the flow. Ans.2. We agree that a "Fluid Flow Sensor" is not needed. > 3. Degasser A. The need for one. Ans.3. We agree that a "Degasser" is not necessary. > 4. Drilling Fluid Measuring System > A. Would a stroke counter for the mud pump with the Pit Le vel Indicator > on the 150 Bbl mud tank suffice instead of a trip tank? Ans.4. We agree that the stroke counter for the mud pump with the "Pi t Level Indicator" will be acceptable. > 5. Gas Detection > A. Would one sensor for methane and hydrogen sulfide gas 1 ocated at the > cellar/rig floor area be sufficient? Ans.5. We agree that one "Methane" and one "Hydrogen Sulfide Gas" der ector located at the cellar rig floor will be acceptable for the drilling operations , however, if the gases (H2S and Methane) could concentrate inside the "tent", then additional detectors should be used. Not covered by our regulations, but you sho uld also consider the need for C02 detectors inside the "tent". Page 2 Flaxdispwelldiverteretall01200.txt Please let me know what time would fit into your schedule. Regards, Larry E. Ross Page 3 RE: Alaska~State A-2 ..... Original Message ..... From: Tom Maunder [mailto:tom maunder~.admin.s~ate.ak, us] Sent: Thursday, November 30, 2000 4:01 PM To: Jesse Mohrbacher Cc: Julie Heusser; Bob Crandall Subject: Re: Alaska State A-2 Thanks for the response Jesse. We look forward to your further reply. Tom Jesse Mohrbacher wrote: > Hello Tom, thanks for the note. > December 7 or 8 wi//be OK with us for PTD approval. Regarding the > perforating, 1-'11/16" guns will work and we have been discussing this with > Schlumberger. > > For injection operations, we will no doubt start off with seawater initially > then switch over to slurry. Our goal is to inject somewhat continuously at > around 2.5 to 3 bbl per rdnute but we will surely have some shutdowns that > will require first a seawater flush followed by a brine flush for freeze > protection. We are very aware of the need to have a sound flushing > procedure to prevent plugging off of the tubing or perfs We have backup > pumping capability for this purpose as well. The injection system will be the Swaco DSR unit (with modifications) that > was on the GP Platform. It is being readied in their yard and if you would > like to take a look at it, please contact Larry Ross in our Anchorage > office. > > Injection pressures will be measured at the pump and will be recorded > continuously on a paper pen recorder. Injection volumes will be recorded by > a stroke counter and rates will be calculated from this data. We don't > anticipate varying the pump speed on a frequent basis. The Casing/Tubing > annulus will be monitored daily by reading the gauge on the annulus at the > wellhead. We expect this value to stay at zero. > We will investigate the temperature logging scenario and get back to you as > soon as possible. I will also need to discuss this with ExxonMobil. > P/ease contact George, Larry or me if you have any other information needs. > We appreciate your assistance and interest in this project. Thanks, Jesse. > > ..... Original Message ..... > From: Tom Maunder [mai/to:tom maunderC, admin, state, ak. us/ > Sent: Thursday, November 30, 2000 1:26 PM > To: George Scott; Jesse Mohrbacher 2 of 4 12/14/00 9:58 AM RE: Alaska' State A-2 Subject: Re: Alaska State A-2 > George and Jesse, > Thanks for the information and the best wishes. We are moving to wrap > everything up > from the approval side for the permit and the DIO. A fey question we have > is when is > spud reasonably expected. If the PTD were not issued until Dec 7 or 8, will > that > affect your schedule. I have a couple of other questions and comments to > help us > understand your operations. > Yesterday, Jesse indicated that you might downsize the tubing to 2-3/8" due > to the > close clearance. Will that ID be sufficient for you to be able to run a > perf gun ff > you need to add perfs? I suspect a 1-11/16" gun would likely be able to be > run. > As we understand the process, it looks like you will be pumping your > disposal volumes > in batches of maybe 1500 to 2000 bbls per day. Is that correct?? Are you > planning to > start your injection batch with seawater and when done with the slurry batch > follow it with seawater to keep your wellbore clean? Early on it was indicated that you would be using the DSR unit/system that might have been on Granite Point. Is that correct?? While you are injecting we would like to know how you will be monitoring pressures? Is the system continuous and automatic? We are interested in the formation's pressure > response as the disposal process continues. Single, daily values for rate, > tubing pressure and annulus pressure are not what we consider adequate for surveillance. > Where the slurry ultimately is emplaced is also of concem. To quantify > that > information we are considering having you run temperature surveys. One > would be run > in conjunction with your bond log and the other at some later time, maybe > after 1 O0 - > 125 k barrels has been injected. Would you investigate how to best gather > the later > temperature information? We do appreciate you logistics concerns do not > wish to cause 3 of 4 12/14/00 9:58 AM RE.: AlaskEt State A-2 .(-,' (' > a severe impact. > An initial step rate test will be a requirement of the disposal injection > order, we > are considering also requesting one at the conclusion of disposal. > We look forward to your comments to these discussion points. > George Scott wrote: > > > Torn- I am sending you the requested casing info. wCth the change from > 5-1/2" > > to 5 "casing. > > Hope all is going well at that end and that you and your family are doing > > well. All the best for the upcoming holiday season/. > > Regards > > George Scott > > Sr. Project Manager > > Fairweather E&P Services Inc. > > Nane: Casing design.xls > > Casing design.xls Type: Microsoft Excel Worksheet > (appllcation/vnd. ms-excel) > > Eno)ding: base64 4 of 4 12/14/00 9:58 AM USDW Protection Geologic Prognosis Alaska State A-2 Properly cemented surface casing will protect any near-surface formation waters that may have less than 10,000 PPM salinity. Well log analysis in the nearby Alaska State A-1 well indicates water-saturated sands below a depth of about 2,150 feet TVD have formation water salinities greater than 10,000 ppm NaC1. Surface casing will be set at 2,400 feet TVD and will be cemented back to surface. Steve Davies November 29, 2000 Re: [Fwd: Program Modifications to Alaska Stat~ ' -2 Well] Subject: Re: [Fwd: Program Modifications to Alaska State A-2 Well] Date: Tue, 28 Nov 2000 14:01:15 -0900 From: Robert Crandall <Bob_Crandall@admin.state.ak. us> Organization: DOA-AOGCC To: Tom Maunder <tom_maunder@admin.state.ak. us> Tom: Considering this well is 300' away from a well with a very good set of openhole logs, the gamma ray on the usit log will be adequate for perforating. I have no hesitation about approving this request. RPC Tom Maunder wrote: Bob, We briefly discussed this proposed change on the Exxon A-2 disposal well. Would you send an reply back with your thoughts on the request. Thanks. Tom Subject: Program Modifications to Alaska State A-2 Well Date: Wed, 22 Nov 2000 14:33:58-0600 From: "Jesse Mohrbacher" <jesse@fairweather. com> To: "Tom Maunder" <torn_maunder@admin. state, ak. us>, "Blair Wondzell" <blair_wondzell@ admin, state, ak. us> CC: "Larry Ross" <larry(~fairweather. com>, "George SootY' <george@fairweather. com> Gentlemen: Fairvveather is in the process of revising the drilling program for the Alaska State A-2 Disposal Well to incorporate new and additional information into the program. The program modifications include minor adjustments to the casing program, cementing volumes, and additional details. As part of this process, we do not plan to run open hole logs This will reduce open hole risk and not effect the overall objective of the injection disposal well. Correlation to proposed disposal zones previously identified in the nearby (300') A-'I well will be provided by the cased hole logging program that will include the USIT log and gamma ray. Please advise us at your earliest convenience if there are any objections to the above logging plan. The amendments to the casing and cementing program will be submitted to the Commission next week. Thank you for your attention to this matter and all of the pre~fous assistance that has been provided to Fairweather on this project. Sincerely, Jesse Mohrbacher Vice President Fairweather E&P Services, Inc. 1 of 2 11/28/00 2:38 PM FlaxDispwellanswersll3000.txt Subject: RE: Alaska State A-2 Date: Thu, 30 Nov 2000 15:43:45 -0600 From: "Jesse Mohrbacher" <jesse@fairweather.com> To: "Tom Maunder" <tom maunder@admin.state.ak.us> CC: "George Scott" <george@fairweather.com>, "Larry Ross" <larry@fairweather.com> Hello Tom, thanks for the note. December 7 or 8 will be OK with us for PTD approval. Regarding the perforating, 1-11/16" guns will work and we have been discussing this with Schlumberger. For injection operations, we will no doubt start off with seawater ini tially then switch over to slurry. Our goal is to inject somewhat continuous ly at around 2.5 to 3 bbl per minute but we will surely have some shutdowns that will require first a seawater flush followed by a brine flush for free ze protection. We are very aware of the need to have a sound flushing procedure to prevent plugging off of the tubing or perfs. We have bac kup pumping capability for this purpose as well. The injection system will be the Swaco DSR unit (with modifications) t hat was on the GP Platform. It is being readied in their yard and if you would like to take a look at it, please contact Larry Ross in our Anchorage office. Injection pressures will be measured at the pump and will be recorded continuously on a paper pen recorder. Injection volumes will be recor ded by a stroke counter and rates will be calculated from this data. We don' t anticipate varying the pump speed on a frequent basis. The Casing/Tub Page 1 FlaxDispwellanswersll3000.txt ing annulus will be monitored daily by reading the gauge on the annulus at the wellhead. We expect this value to stay at zero. We will investigate the temperature logging scenario and get back to y ou as soon as possible. I will also need to discuss this with ExxonMobil. Please contact George, Larry or me if you have any other information n eeds. We appreciate your assistance and interest in this project. Thanks, J esse. ..... Original Message ..... From: Tom Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Thursday, November 30, 2000 1:26 PM To: George Scott; Jesse Mohrbacher Subject: Re: Alaska State A-2 George and Jesse, Thanks for the information and the best wishes. everything up from the approval side for the permit and the DIO. have is when is spud reasonably expected. , will that affect your schedule. to help us understand your operations. We are moving to wrap A key question we If the PTD were not issued until Dec 7 or 8 I have a couple of other questions and comments Yesterday, Jesse indicated that you might downsize the tubing to 2-3/8 " due to the close clearance. a perf gun if Will that ID be sufficient for you to be able to run Page 2 OCT, 26, 2000 8'30AIvI EXXON ixlO, 7148 P, 2 ExxonMobll Production Company P.O. l~ox 196601 Anchorage, Alaska 99519-6601 James F, Branch Production Manager, Alaska Interest Joint Interest U.S. October 16, 2000 E:C(onMobil Production Mr. Daniel T. Seamount Alaska Oil and Gas Conservati(~n Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Attn: BlairWondzell, Senior Petroleum Engineer Re: Application for Underground Disposal of Oilfield Wastes: Flaxman Island Disposal Well, Alaska State A-2 Dear Mr. Wondzell: ExxonMobil Production Company, a division of Exxon Mobil Corporation, submits this application for a Disposal Injection Order for the Alaska State A-2 disposal well on Flaxman Island in the Beaufort Sea. An Application for Permit to Drill for the Alaska State A-2 well was submitted to the Commission on September 7, 2000. As discussed in the APD, the overall project entails excavation and disposal of 15,000 to 25,000 cubic yards of drilling wastes from the Alaska State A-1 and G-2 drill sites on Flaxman Island. The drilling wastes will be processed using grind and inject equipment and disposed of in the A-2 disposal well that is to be drilled on the same pad as the Alaska State A-1 well, Please find attached information as required by 20 ,&AC 25.252(c), (d) and (h). If you have any questions or require additional information, please contact D. Michael Barker at 907-564-3691 or Jack Rickner at 281~96-3280. Sincerely, ~.~---~ ~,~ ,, DMB:ddm C: D. Michael Barker, ExxonMobit Riki Lebman, JPOIDGC Bob Loeffier, DNR Jesse Mohrbacher, Fairweather Jack Rickner, ExxonMobil Al Robb III, ExxonMobil OCT, 26, 2000 8'30AM BXXON NO, ?i~,8 P, i ExxonMobil P.O. Box 196601 Anchorage, Alaska 99519-6601 Facsimile Cover Sheet To: Company: Fax: Phone: From: C0_m_pany: Fax: Phone: ExxonMobil (907) 564-3789 (907) 561-5331 Total Page.s: · L.,/z,,/.,. Comments: ,C~/l ~ ....... ,,~r ~,'~ ;s,,'¢-_,~,~,~ ~o_~ ,,_~:.~.:.~'-~/. --. CONFID_E N_TI^LIT'[/__~(~:ri (~:' ,, -, i i i II -. -- THIS TRANSMITTAL IS INTENDED ONLY FOR THE USE OF THE INDIVIDUAL/ENTITY TO WHOM/WHICH IT IS ADDRESSED, AND MAY CONTAIN INFORMATION THAT IS PRIVILEGED, CONFIDENTIAL, AND/OR EXEMPT FROM DISCLOSURE. IF YOU ARE NOT THE INTENDED RECIPIENT, OR THE EMPLOYEE OR AGENT RESPONSIBLE FOR DELIVERING THE TRANSMrl-rAL TO THE INTENDED RECIPIENT, THEN YOU ARE HEREBY NOTIFIED THAT ANY EXAMINATION, DISCLOSURE, COPYING, DISTRIBUTION, OR THE TAKING OF ANY ACTION IN RELIANCE ON, OR WITH RESPECT TO, THE CONTENTS OF THIS TELECOPIED INFORMATION I$ STRICTLY PROHIBITED. IF YOU HAVE RECEIVED THIS TRANSMITTAL IN ERROR, THEN PLEASE IMMEDIATELY NOTIFY THE SENDING PERSON BY COLLECT PERSON-TO-PERSON TELEPHONE CALL TO ARRANGE FOR RETURN OF THE ORIGINAL TRANSMll-I'AL DOCUMENTS TO US AT OUR EXPENSE. THANK YOU. ..... ii .... · ---_1 .... j_~ .......... C:~cr~a~nl~TBMP~Oavcr~heeLd oc ExxonMobil Production Company Anchorage, Alaska APPLICATION FOR UNDERGROUND DISPOSAL OF OILFIELD WASTES FLAXMAN ISLAND RESERVE PIT CLOSURES ALASKA STATE A-1 AND G-2 PROJECT FLAXMAN ISLAND, BEAUFORT SEA, ALASKA October 2000 E) onMobil p. ,. :~ oduction 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0 Table of Contents Page Property Description and Plat [20 AAC 25.252(c)(1)] ............................................... 1-1 List of Operators and Surface Owners [20 AAC 25.252(c)(2)] .................................. 2-1 Affidavit [20 AAC 25.252(c)(3)] .............................................................................. 3-1 Geologic Information [20 AAC 25.252(c)(4)] ........................................................... 4-1 4.1 Depth of Permafrost ....................................................................................... 4-1 4.2 Sagavanirktok Sandstone ................................................................................ 4-1 4.3 Injection Zones ............................................................................................... 4-1 4.4 Confining Layers ............................................................................................ 4-1 Well Logs [20 AAC 25.252(c)(5)] ............................................................................ 5-1 Casing and Cementing program [20 AAC 25.252(c)(6)] ............................................ 6-1 Fluids to be Injected [20 AAC 25.252(c)(7)] ............................................................. 7-1 Injection Pressure [20 AAC 25.252(c)(8)] ................................................................. 8-1 Fracture Information [20 AAC 25.252(c)(9)] ............................................................ 9-1 Formation Water Analysis [20 AAC 25.252(c)(10)] .................................................. 10-1 Freshwater Aquifer Exemption [20 AAC 25.252(c)(11)] ........................................... 11-1 Mechanical Condition of Wells [20 AAC 25.252(c)(12)] ........................................... 12-1 Mechanical Integrity of Disposal Well [20 AAC 25.252(d)] ...................................... 13-1 Figure 1-1 Figure 6-1 List of Figures Property Plat and Location of Area Wells ..................... . ....................... 1-2 Proposed Alaska State A-2 Wellbore Schematic Exhibit 3-1 Exhibit 9-1 Exhibit 9-2 Exhibit 9-3 List of Exhibits Affidavit of Mr. James F. Branch ..... ' 3-2 Injection Scenario 1 ............................................................................. 9-3 Injection Scenario 2 ............................................................................. 9-14 Injection Scenario 3 ............................................................................. 9-25 Table 6-1 List of Tables Casing and Cementing Detail Summary ............................................... 6-1 List of Attachments Alaska State A-1 Well Logs Disposal Injection Application i 1.0 Property Description and Plat [20 AAC 25.252(c)(1)] The Alaska State A-2 disposal well will be located on Flaxman Island on State of Alaska lease number ADL 47556 which is owned 100% by ExxonMobil. This lease comprises 465 acres of uplands and 2,095 acres of tidelands for a total of 2,560 acres. One well has been drilled on this lease, the Exxon Alaska State A-1, which was a vertical hole drilled, plugged and abandoned in 1975. The A-1 well was subsequently re-abandoned in 1998 to cut off the casing below the toe of the island. The surface location of the ExxonMobil Alaska State A-2 disposal well will be 300 feet west of the Alaska State A-1 location. Exxon drilled two other wells on Flaxman Island, but not from this lease. The Exxon Alaska State D-1 was drilled as a vertical hole about 4.5 miles to the west-northwest and was plugged and abandoned in 1982. The Alaska State G-2 directional well was drilled from a surface location about one (1) mile to the southeast of the Alaska State A-1 surface location to a bottom hole location about 1.5 miles to the northeast of the Alaska State A-1 surface location. The Alaska State G-2 well was plugged and abandoned in 1983. The locations of the proposed ExxonMobil Alaska State A-2 disposal well and the abandoned Exxon State A-1 well are shown in Figure 1-1. Location information for the A-1 well is the following: Alaska State A-1 Lease Number: Surface Location: Bottom Hole Location: Measured Depth: True Vertical Depth: ADL 47556 2982 feet FSL & 1542 feet FEL, Sec. 27-T 10N-R24E, Same 14,206 feet Same Disposal Injection Application 1 - 1 R 24E 21 28 55 4 22 27 £xxonMobll £xxonMobll Ala,,,ka Stale A-2 Alaska Stcde A-1 X=498,237 \ / X=498,537 Y=$,918,728 ~/Y=5,9128, 54 5 25 26 55 2 T 10 N T 9 N o o o o z o x x CERTIFICATE OF SURVEYOR I hereby certify that I am property registered and licensed to practice land surveying In the State of Alaska and that fhls plat represents a location survey made by me or under my supervision, and that all dimensions and other details are correct. Date Surveyor Notes: Flnal survey plat to be =ubmiffed fo ADGCC prior to spud of well. Figure 1-1 ExxonMobil Alaska State A-2 Located in SE 1/4 Protracted Sec 27, TI ON, R24E Umiaf Meridian Surveyed for £xxonldobil Production Company Surveyed by Terra Surveys, LLC Disposal Injection Application 1 - 2 2.0 List of Operators and Surface Owners [20 AAC 25.252(c)(2)] The operator of lease number ADL 47556, where the proposed A-2 disposal well is to be drilled, is: ExxonMobil Production Company 3301 C Street, Suite 400 P.O. Box 196601 Anchorage, AK 99519-6601 The surface owner for the lease is the State of Alaska. There are no other surface owners or operators within a one-quarter mile radius of the surface location of the Alaska State A-2 disposal well. Disposal Injection Application 2 - 1 3.0 Amdavit [20 AAC 25.252(c)(3)1 The affidavit of Mr. James F. Branch, Production Manager, Alaska Interest, ExxonMobil Production Company, is attached as Exhibit 3-1. Disposal Injection Application 3 - 1 EXHIBIT 3-1 AFFIDAVIT OF JAMES F. BRANCH PRODUCTION MANAGER, ALASKA INTEREST EXXONMOBIL PRODUCTION COMPANY State of Alaska Second Judicial District I, James F. Branch, declare and affirm that I have personal knowledge of the matters set forth in this affidavit, and that on the /d; r'flay of.,c,~ c.,'~.,o e~,~---~ 2000, the following surface owner was provided a copy of this permit application by placing said copy in the United States mail with postage prepaid and certified at Anchorage, Alaska. State of Alaska Department of Natural Resources Division of Mining, Land & Water 550 W. 7th Ave., Suite 1070 Anchorage, AK 99501-3579 Bob Loeffier, Director There are no other surface owners or operators within a one-quarter mile radius of the proposed Alaska State A-2 disposal well. Ja~;a~ F. Branch / Subscribed and sworn before me this //~ r/t6 day of L//~)~ 2000. Notar~ublic in and fc;r the S~tate of Alaska Dis~ Applic~ion 3-2 4.0 Geologic Information [20 AAC 25.252(2)(4)] This section includes information on the depth to the base of permafrost and the nature and distribution of the sediments in the proposed injection zone and of the confining zones which bound it. 4.1 Depth to Base of Permafrost The shallowest and average depth to the base of the permafrost, as determined by the operator's geologist, is 1,050 and 1,500 feet respectively. This determination is based on the moving resistivity curve over this interval. 4.2 Sagavanirktok Sandstone The injection zone is contained within the nonmarine Sagavanirktok Sandstone that is present in the Exxon Alaska State A-1 well from the surface to a depth of 7,710 feet. The formation is comprised of sandstone, conglomerate, siltstone, shale and coal. This formation is gradational to the underlying marine Colville Shale that is comprised of a thick sequence of shale, minor sandstone and bentonite. 4.3 Injection Zones The proposed injection zones are present between the depths of 2,150 feet and 2,350 feet as recorded on the logs of the Exxon Alaska State A-1 well. For the purposes of this application, all formation depths are referenced to the A-1 well. The lithologies at this depth are primarily sandstone and conglomerate with minor siltstone and coal lenses. The sand and conglomerate units are poorly cemented with probable intergranular porosity. On the logs, these zones appear to exhibit good properties for fluid injection. A reasonable estimate of porosity and permeability for these unconsolidated zones is 32% and one (1) darcy, respectively. Perforations are not planned above 2,150 feet in the A-2 disposal well. The proposed injection zones located between 2,150 feet and 2,350 feet will be selectively perforated starting at the deepest available zone. Approximately 20 feet of perforations should be sufficient at the bottom of this interval for the planned injection operations. If additional perforations are needed at a later time, they will be made in the next available unperforated zone above those previously perforated. 4.4 Confining Layers There are several zones of siltstone containing minor amounts of sandstone and pebbles in the Alaska State A-1 well above the proposed disposal zones. These are located near 1,300 feet and 1,500 feet with the primary confining zone located between the depths of 1,920 and 1,960 feet. These nonporous and nonpermeable Disposal Injection Application 4 - 1 layers will form effective upper seals and prevent the upward migration of injected fluids. The presence of permafrost above this depth will also prevent the upward migration of injected fluids. Numerous layers of siltstone are also present at depths greater than 2,500 feet, which is below the proposed injection zone. Examples of these siltstone layers are present at depths of 2,750 feet to 2,770 feet and from 2,860 feet to 2,920 feet. These lower nonporous and nonpermeable layers will be effective barriers to downward migration of the injected fluids. Disposal Injection Application 4-2 5.0 Well Logs [20 AAC 25.252(c)(5)] Well logs showing the spontaneous potential (SP), gamma ray and resistivity curves for the Exxon Alaska State A-1 well are enclosed with this application. The interpreted lithology has been added to the SP/Resistivity log for the depth range of 1,250 to 2,900 feet in the A-1 well. Copies of the Exxon Alaska State G-2 well logs, which remain classified as confidential indefinitely, are available in the files of the AOGCC. After the Alaska State A-2 disposal well has been drilled, a complete correlated set of logs will be filed with the AOGCC that shows the correlation between the Alaska State A-1 well and the A-2 disposal well. Disposal Injection Application $ - 1 6.0 Casing and Cementing Program [20 AAC 25.252(c)(6)] The casing and cementing detail for the proposed Alaska State A-2 disposal well is shown in Figure 6-1. The 5-1/2 inch casing will be cemented in two stages. The first stage will extend from TD to 900 feet and consist of approximately 45 sacks of Coldset III cement followed by 133 sacks of Class G cement. The second stage will extend from the cementing collar at 900 feet to the surface and consist of 453 sacks of Coldset III permafrost cement. The casing and cementing program is summarized in Table 6-1. After cementing the 5-1/2 inch casing, the casing will be pressure tested to 1,500 psi, then perforated across the. selected disposal zone(s). Approximately 20 feet of perforations will be made at or near the bottom of the available disposal zone section. Although Figure 6-1 shows the entire disposal zone to be perforated, it is unlikely that it will be necessary to perforate the entire disposal section during the project. After perforating the well, a step rate injection test will then be run to establish injection rates and pressures. Hole Casing Size Size 9-5/8" 7-5/8" 6-3/4" 5-1/2" Table 6-1 Casing and Cementing Detail Summary ExxonMobil Production Company Alaska State A-2 Disposal Well Casing Depth Depth Float Description Shoe (RKB) Top Length Equipment Cement Vol 29.7# L-80 80' Surface 80' none Cold Set II 50 sx 17.0# L-80 F.C. G 133 sx STL 2,400' Surface 2,400' F.S. Cold Set III 498 sx Disposal Injection Application 6 - 1 ~-80' 7 5/8' Conductor Casing Tubing/Casing Annulus Freeze Protected w/CaCl2 Brine. Stage Cementing Tool ~) '~-go0' Permafrost Interface O ~1.050' Tubing ~2,000' 5 1/2' x 2 7/8" Packer LEGEND Cement NO SCALE r^,./Exxo./2000/F~xB2ooo ~:~ 8/z3/oo ~2,400' I P otential Disposal Zone. 2,150' - 2,350' 5 1/2' Production/Disposal Casing SR Figure 6-1 Proposed Alaska State A-2 Wellbore Schematic Disposal Injection Application 6 - 2 7.0 Fluids to be Injected [20 AAC 25.252(c)(7)] The primary waste fluids to be injected are the approximately 15,000 or more cubic yards of drilling waste which accumulated as the result of the drilling of the Exxon Alaska State A-1 and G-2 wells. These wastes were subsequently left in the respective reserve and flare pits after drilling and covered over, as per then current AOGCC regulations. Additional drilling wastes associated with former flare pits and those created by the drilling of the disposal well will also be ground and injected in the Alaska State A-2 disposal well. Soil borings and analyses conducted during site assessments in 1998 and 1999 indicate that these reserve pits and flare pits contain drilling wastes with varying levels of hydrocarbons and associated levels of metals such as barium and chromium. Drilling wastes from the Alaska State G-2 well will be transported by truck over an ice road for processing at the State Alaska State A-l/A-2 location. A portable grind and inject system will be mobilized to this site for disposal of all drilling wastes. Estimated production rates for this system will be approximately 250 to 400 cubic yards (1,200 to 1,900 bbl) of waste material per day. Processed slurry for injection will be checked for adequate injection properties prior to being pumped downhole. Slurry weight will be approximately 11.5 pounds per gallon with the solids content limited to about 20% by weight and the funnel viscosity maintained at 65. Solids in the drilling wastes will be initially ground to 50 mesh size or smaller during startup of the grinding and injection operation. After startup, the processing particle size will be adjusted as necessary during the grinding and injection operations. Bentonite or polymer viscosifiers will be used as necessary to maintain proper slurry viscosity thereby reducing the potential of well plugging. Approximately 200,000 barrels of injection slurry (including seawater makeup) is anticipated for the disposal of 15,000 cubic yards of drilling wastes. The total volume of injection slurry could be greater than this amount depending upon the volume of waste material required to be disposed. Disposal Injection Application 7-1 8.0 Injection Pressure [20 AAC 25.252(c)(8)] The estimated surface injection pressure for the Alaska State A-2 disposal well is 1,000 psi at an injection rate of five (5) barrels per minute. This estimate is based on hydraulic flow calculations for the surface piping and well tubing and the limited field data for annular injection in the Alaska State A-1 well. In the A-1 well, reserve pit fluids were pumped down the 13-3/8 x 9-5/8 inch annulus and out the 13-3/8 inch casing shoe at 3,376 feet. The surface injection pressure for this activity was 250 psi at a rate of 1.25 barrels per minute. This field data is consistent with the estimated surface injection pressure discussed above when formation depth, annular cross sectional area and pumping rates are considered. After completion of the well, ExxonMobil will perform a step rate injection test to establish injection rates and pressures. The step rate test will be incrementally increased to pump rates approximately 100% in excess of the maximum anticipated pumping rates for waste disposal. Pressure falloff data will also be collected. Disposal Injection Application 8 - 1 9.0 Fracture Information [20 AAC 25.252(c)(9)] Injection disposal of the A-1 and G-2 drilling wastes is expected to create a vertical fracture(s) in the disposal formation. Simulation model results of the theoretical formation fracture pattern is included as Exhibits 9-1, 9-2 and 9-3. The fracture model shows a vertical single fracture starting at 2,225 feet and propagating away from the wellbore and being confined above by the siltstone layer located at 1,920 to 1,960 feet. The model has been run for the following three injection scenarios. 1. Injection at five (5) barrels per minute for 30.6 continuous days resulting in 220,000+ bbls of fluid injected. 2. Injection at five (5) barrels per minute for five (5) continuous days, 37,000+ total barrels injected. o Injection at five (5) barrels per minute for five (5) continuous days then stopping injection for one (1) day, followed by repetition of the five (5) day pumping period, until 213,000+ total barrels of fluid are injected. In all three modeled cases, the fractures are bounded above by the siltstone-confining layer. Injection Scenario 1 (Exhibit 9-1) is anticipated to be the most extreme injection program possible for the project. This scenario assumes that 220,000 bbl (7,200 bbl/day) of slurry would be injected continuously for 30.6 days at five (5) bbl/min. These rates are at or above the maximum processing and injection capacity of the proposed grinding and injection system. This scenario also assumes that injection will continue unabated for 30.6 days. This will be nearly impossible given the need for regular maintenance for the grinding and injection system. Although this unrealistic, worst-case modeled scenario does fracture into the primary confining layer at 1,920 to 1,960 feet, it does not break through to the zones above. Scenario 2 (Exhibit 9-2) models the basic injection program of five barrels per minute for five continuous days. Under this scenario, the formation fracture does not reach the confining layer. Scenario 3 (Exhibit 9-3) is a reasonable representation of what can be expected during injection operations. Under this scenario, slurry is injected at five bbls per minute for five (5) days, then shut down for one day and restarted again for a total of 213,000 bbl injected. The results of this scenario are essentially the same as for Scenario 2 where the fracture is completely confined by the siltstone layer from 1,920 to 1,960 feet. ExxonMobil anticipates processing between 250 and 400 cubic yards of drilling waste per day during grind and inject operations. These rates are equal to continuous slurry injection rates of 2.3 to 3.7 bbls per minute and are significantly lower than those Disposal Injection Application 9 - 1 modeled above. The perforating plan also calls for perforating the lowest available disposal zone in the wellbore which is anticipated to be at least 100 feet below the 2,225 foot depth that is specified as the starting depth of fracture in the fracture model. Therefore, the fracture model uses conservative assumptions to magnify potential consequences of the anticipated fracture regime. The fracture model results show simple vertical fractures. The fracture regime will likely consist of a primary vertical fracture(s) with multiple smaller fractures adjacent to and splitting off of the primary fracture(s) in an oblique fashion. This will have an increased effect on the ability to dissipate fluid and solids from the wellbore and will decrease the lateral extent of the primary fracture. Disposal Injection Application " 9 - 2 EXHIBIT 9-1 FRACTURE MODEL INJECTION SCENARIO I Injection Rate: Injection Duration: Injection Volume: 5 bbl/min 30.6 days (44,091 min) 220,150 bbl Disposal Injection Application 9 - 3 October 11, 2000 Page 1 6:05 pm FracproPTlO.O Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island5 Fracture Analysis Options Conventional 3D Model Run From Job-Design Data No Convection or Settling Lithology Based Reservoir Vertical Fracture Model Wellbore and Perforations Results Summary Model has run until (min) 44090.80 Fracture length (ft) 1344.95 Fracture upper height (ft) 301.28 Fracture lower height (ft) 153.43 Max width at well (in) 0.18 Dimensionless Cond. Ratio 0.00 Fracture efficiency Propped length (ft) Propped upper height (ft) Propped lower height (ft) Avg. prop. conc. (lb/ft2) 0.01 0.00 0.00 0.00 0.00 Total fluid (bbls) Min Surface Pressure (psi) Max Hydraulic Power (hp) 220150.36 271.19 44.01 Total sand (klbs) Max Surface Pressure (psi) Avg Hydraulic Power (hp) 0.00 359.60 34.57 Dist from Wbore (ft) 0 168 336 504 672 841 1009 1177 1345 Width @ Center (in) 0.18 0.17 0.17 0.16 0.15 0.14 0.12 0.09 0.00 Run from Design Data Only Disposal Injection Application 9 - 4 October 11, 2000 Page 2 6:05 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island5 Treatment Schedule Elapsed Clean Prop Stage Stg Time Fluid Volume Conc. Prop. # min:sec Type (kgal) (ppg) (klbs) W'bore Fluid 2% KCL 0.8 1 23:48 LINEAR 30 GW 5.0 0.00 0.0 2 30:days LINEAR 30 GW 7550.0 5.00 37750.0 Slurry Proppant Rate Type (bpm) 5.00 5.00 100-Mesh Scheduled clean vol (kgal) Scheduled slurry vol (kgal) 7555.00 9262.18 Scheduled sand total (klbs) 37750.00 Disposal Injection Application 9 - 5 October 11, 2000 Page 3 6:05 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island5 Fluid Parameters Ail Fluid info is at a reservoir temperature of 45.0 (°F) All Viscosities at Shear Rate of 511 (1/sec) Fluid Name SPEC 4000 4 2% KCL LINEAR 30 GW Init. Rheology Viscosity 284.8 0.958 19.80 n' 0.300 1.000 0.525 K' 0.468 2.000e-05 0.008 Rheology @ 4.0 hours Viscosity 263.8 0.958 11.21 n' 0.316 1.000 0.629 K' 0.393 2.000e-05 0.002 Gel Density 1.000 1.01 1.000 Spurt Loss 0.0 0.0 2.00 Wall Building 0.002 0.0 0.003 Flowrate #1 7.50 10.00 10.00 Fric Press #1 93.59 96.64 72.00 Flowrate #2 15.00 20.00 20.00 Fric Press #2 154.0 335.1 185.0 Flowrate #3 30.00 40.00 40.00 Fric Press #3 486.1 1161.7 398.9 wB Fric Mult 1.000 1.000 1.000 Wellbore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction Multiplier. Viscosity is displayed in (cp) K' is displayed in (lbf.s^n/ft2) Gel Density is displayed as (sg) Spurt Loss is displayed in (gal/ft2) Wall Building is displayed in (ft/min½) Friction pressure is displayed in (psi/1000 ft) Friction is displayed for longest wellbore segment Disposal Injection Application 9 -6 October 11, 2000 Page 4 6-05 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Location: Format'n: Job Date: Filename: Flaxman Island Disposal Well North Slope, Alaska 8-30-00 Flaxman Island5 Leakoff Parameters Reservoir type Filtrate to reservoir fluid perm. ratio, Reservoir pore pressure (psi) Initial fracturing pressure (psi) Reservoir fluid compressibility (1/psi) Cold filtrate viscosity (cp) Hot filtrate viscosity (cp) Cold reservoir viscosity (cp) Hot reservoir viscosity (cp) Porosity Gas Leakoff Percentage User Spec Kp/K1 1 8OO 1100 5.00e-004 1.00 1.00 1.00 1.00 0.32 100.00 Reservoir Parameters Reservoir temperature (°F) Depth to center of Perfs (ft) Perforated interval (ft) Initial frac depth (ft) 45.00 2225 150 2225 Layer Parameters Lay Top of Top of # zone Stress zone (ft) (psi) (ft) 1 0.0 1360 0.0 8.0e+06 2 1700.0 1144 3 1820.0 1501 4 1840.0 1222 5 1920.0 1552 6 1960.0 1572 7 1970.0 1412 8 2375.0 1990 9 2600.0 2080 Young's Poisson's Top of modulus ratio zone (psi) (ft) 0.25 1700.0 2.3e+06 0.20 1820.0 1.0e+06 0.35 1840.0 2.3e+06 0.20 1920.0 8.0e+06 0.25 1960.0 8.0e+06 0.25 1970.0 2.3e+06 0.20 2375.0 8.0e+06 0.25 2600.0 8.0e+06 0.25 . 1700. 1820. 1840. 1920. 1960. 1970. 2375. 2600. Total Ct (ft/minh) 4.124e-05 1.298e-04 1.298e-04 2.558e-04 4.124e-05 4.124e-05 1.742e-03 4.124e-05 4.124e-05 PoreFluid perm. (md) 1.00e-04 1.00e-03 1.00e-03 4.00e-03 1.00e-04 1.00e-04 1.00e+03 1.00e-04 1.00e-04 Disposal Injection Application 9 - 7 October 11, 2000 Page 5 6'05 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island5 Lithology Parameters Layer Top of # zone (ft) Lithology 1 0.0 Shale 2 1700.0 Sandstone 3 1820.0 Coal 4 1840.0 Sandstone 5 1920.0 Shale 6 1960.0 Shale 7 1970.0 Sandstone 8 2375.0 Shale 9 2600.0 Shale Top of Fracture Top of zone Toughness zone (ft) (psi' inh) (ft) 0.0 2000 1700.0 800 1820.0 1000 1840.0 800 1920.0 2000 1960.0 2000 1970.0 800 2375.0 2000 2600.0 2000 0.0 1700.0 1820.0 1840.0 1920.0 1960.0 1970.0 2375.0 2600.0 Tip Effects Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 Disposal Injection Application 9 - 8 October 11, 2000 Page 6 6'05 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island5 Wellbore Configuration Segment Segment Tubing Tubing Casing Length Type ID OD ID (ft) (in) (in) (in) 2100 Tubing 2.992 0.000 0.000 50 Casing 0.000 0.000 4.408 Tubular Goods are defined to the TOP of the deepest set of perforations that are being modeled° Top of Perfs - TVD (ft) Bot of Perfs - TVD (ft) Perf Diameter (in) # of Perfs 2150 2300 0.400 900 Time min:sec 0:00 Near Wellbore Friction Parameters & Perf Multiplier Flow Rate #1 Flow Rate #2 Delta P Perf Coeff (bpm) (bpm) (psi) Multiplier 0.00 0.00 0.00 1.00 Disposal Injection Application 9 - 9 October 11, 2000 Page 7 6'05 pm FracproPT10.0 Hydraulic Fracture Analysis WellName' Flaxman Island Disposal Well Location' North Slope, Alaska Format'n- Job Date' 8-30-00 Filename: Flaxman Island5 Model Parameters Fracture Growth Parameters (Conventional 3D Model) Crack Opening Coefficient 0.7000000 Rock Deformation Coefficient 0.4000000 Channel Flow Coefficient 1.0000000 Fluid Radial Weighting Exponent set to default of Rock Deformation Coeff / 10. Proppant Model Parameters Minimum Proppant Concentration (lb/ft^2) Minimum Proppant Diameter (in) Volume Fraction of Proppant in Slurry Proppant Drag Effect Exponent Proppant Radial Weighting Exponent Proppant Convection Coefficient Proppant Settling Coefficient Quadratic Backfill Model Quadratic Backfill Coefficient Stop Model on Screenout 0.20 0.008 0.60 8.0 0.2500 10.00 1.00 ON 0.50 ON Initial Leakoff Area Coeff Closure Leakoff Area Coeff 1.00 0.03 Minimum Fracture Height OFF Near Wellbore Friction Exponent 0.50 Disposal Injection Application 9 - 10 October 11, 2000 Page 8 6:05 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Location: Format ' n: Job Date: Filename: Flaxman Island Disposal Well North Slope, Alaska 8-30-00 Flaxman Island5 Proppant Data Proppant Name TemprdLC-163 CarboEP-2040 100-Mesh Cost (S/lb) Bulk Dens (lbm/ft3) Packed Porosity Specific Gravity (sg) Turbulence Coeff a Turbulence Coeff b Diameter (in) Perm @ 0 psi Perm @ 2000 psi Perm @ 4000 psi Perm @ 6000 psi Perm @ 8000 ps~ Perm @ 10000 ps~ Perm @ 12000 psx Perm @ 14000 Perm @ 16000 ps~ Perm @ 18000 ps~ (D) (D) (D) (D) (D) (D) (D) (D) (D) (D) 0.0 0.0 0.070 93.70 96.00 115.8 0.415 0.433 0.300 2.57 2.71 2.65 0.930 1.20 1.39 0.930 1.20 1.39 0.031 0.025 0.006 530.0 375.0 40.00 530.0 342.0 40.00 360.0 295.0 40.00 174.0 220.0 40.00 69.00 141.0 40.00 32.00 91.00 40.00 32.00 51.00 40.00 32.00 40.00 32.00 40.00 32.00 40.00 Disposal Injection Application 9-11 Stress Profile 800 ,'"I- ........ ; : 1080 ~ ........................ ; ........................ 136O 1640 920 i 2200 2480 -t ' 27~0 -' ..... ~ ......... : ............... ~ ............... i 3040 -, : . · ....... 3320 -' P:~-mea=.h'.¥ ................... :111 3~00 , r' ~ 000 ~ 500 2000 Closure Stress (psi) Fracture Dimensions 3000 1400 I 1 O5O 7o0 Propped Length (fl) 35O 1-' f I I I I I -.!. I- 350 700 1050 Hydraulic Length 1400 Fracture Profile I Stre....[ Mod... i ~l'J!]! il ; Concentration of Proppant in Fracture (lb/fi2) Width Pro... 175(t 2000 :. !- ::. i- : 25OO EXHIBIT 9-2 FRACTURE MODEL INJECTION SCENARIO II Injection Rate: Injection Duration: Injection Volume: 5 bbl/mm 5.1 days (7,372 mm) 36,846 bbl Disposal Injection Application 9 - 14 October 6, 2000 Page 1 7:04 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island5 Fracture Analysis Options Conventional 3D Model Run From Job-Design Data No Convection or Settling Lithology Based Reservoir Vertical Fracture Model Wellbore and Perforations Results Summary Model has run until (min) Fracture length (ft) Fracture upper height (ft) Fracture lower height (ft) Max width at well (in) Dimensionless Cond. Ratio 7372.30 435.07 262.08 150.75 0.12 0.00 Fracture efficiency Propped length (ft) Propped upper height (ft) Propped lower height (ft) Avg. prop. conc. (lb/ft2) 0.01 0.00 0.00 0.00 0.00 Total fluid (bbls) Min Surface Pressure (psi) Max Hydraulic Power (hp) 36846.64 262.93 76.45 Total sand (klbs) Max Surface Pressure (psi) Avg Hydraulic Power (hp) 0.00 624.56 34.06 Dist from Wbore (ft) 0 54 109 163 218 272 326 381 435 Width @ Center (in) 0.12 0.12 0.12 0.11 0.11 0.09 0.08 0.06 0.00 Run from Design Data Only Disposal Injection Application 9 - 15 October 6, 2000 Page 2 7:04 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island5 Treatment Schedule Elapsed Clean Stg Time Fluid Volume # min:sec Type (kgal) Prop Stage Slurry Proppant Conc. Prop. Rate Type (ppg) (klbs) (bpm) W'bore Fluid 2% KCL 0.8 1 23:48 LINEAR 30 GW 5.0 2 7370:46 LINEAR 30 GW 1258.3 -- -- 0.00 0.0 5.00 5.00 6291.7 5.00 100-Mesh Scheduled clean vol (kgal) Scheduled slurry vol (kgal) 1263.33 1547.86 Scheduled sand total (klbs) 62 91.67 Disposal Injection Application 9 - 16 October 6, 2000 Page 3 7:04 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island5 Fluid Parameters Ail Fluid info is at a reservoir temperature of 45.0 (°F) All Viscosities at Shear Rate of 511 (1/sec) Fluid Name SPEC 4000 4 2% KCL LINEAR 30 GW Init. Rheology Viscosity 284.8 0.958 19.80 n' 0.300 1.000 0.525 K' 0.468 2.000e-05 0.008 Rheology @ 4.0 hours Viscosity 263.8 0.958 11.21 n' 0.316 1.000 0.629 K' 0.393 2.000e-05 0.002 Gel Density 1.000 1.01 1.000 Spurt Loss 0.0 0.0 2.00 Wall Building 0.002 0.0 0.003 Flowrate #1 7.50 10~00 10.00 Fric Press #1 93.59 96.64 72.00 Flowrate #2 15.00 20.00 20.00 Fric Press #2 154.0 335.1 185.0 Flowrate #3 30.00 40.00 40.00 Fric Press #3 486.1 1161.7 398.9 WB Fric Mult 1.000 1.000 1.000 Wellbore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction Multiplier. Viscosity is displayed in (cp) K' is displayed in (lbf-s^n/ft2) Gel Density is displayed as (sg) Spurt Loss is displayed in (gal/ft2) Wall Building is displayed in (ft/minh) Friction pressure is displayed in (psi/1000 ft) Friction is displayed for longest wellbore segment Disposal Injection Application 9 - 17 October 6, 2000 Page 4 7-04 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Location: Format'n: Job Date: Filename: Flaxman Island Disposal Well North Slope, Alaska 8-30-00 Flaxman Island5 Leakoff Parameters Res Fil Res Ini Res ervoir type trate to reservoir fluid perm. ratio, ervoir pore pressure (psi) rial fracturing pressure (psi) ervoir fluid compressibility (i/psi) Cold filtrate viscosity (cp) Hot filtrate viscosity (cp) Cold reservoir viscosity (cp) Hot reservoir viscosity (cp) Porosity Gas Leakoff Percentage User Spec Kp/K1 1 80O 1100 5.00e-004 1.00 1.00 1.00 1.00 0.32 100.00 Reservoir Parameters Reservoir temperature (°F) Depth to center of Perfs (ft) Perforated interval (ft) Initial frac depth (ft) 45.00 2225 150 2225 Layer Parameters Lay Top of Top of # zone Stress zone (ft) (psi) (ft) Young's Poisson's Top of modulus ratio zone (psi) (ft) 1 0.0 1360 2 1700.0 1144 3 1820.0 1501 4 1840.0 1222 5 1920.0 1552 6 1960.0 1572 7 1970.0 1412 8 2375.0 1990 9 2600.0 2080 0.0 8.0e+06 0.25 0.0 1700.0 2.3e+06 0.20 1700.0 1820.0 1.0e+06 0.35 1820.0 1840.0 2.3e+06 0.20 1840.0 1920.0 8.0e+06 0.25 1920.0 1960.0 8.0e+06 0.25 1960.0 1970.0 2.3e+06 0.20 1970.0 2375.0 8.0e+06 0.25 2375.0 2600.0 8.0e+06 0.25 2600.0 Total Ct (ft/minh) 4.124e-05 1.298e-04 1.298e-04 2.559e-04 4.124e-05 4.124e-05 1.766e-03 4.124e-05 4.124e-05 PoreFluid perm. (md) 1.00e-04 1.00e-03 1.00e-03 4.00e-03 1.00e-04 1.00e-04 1.00e+03 1.00e-04 1.00e-04 Disposal Injection Application 9 - 18 October WellName: Location: Format'n: Job Date: Filename: ! Flaxman Island Disposal Well North Slope, Alaska 8-30-00 Flaxman Island5 2000 Page 5 FracproPT10.0 Hydraulic Fracture Analysis : : Lithology Parameters 7:04 pm Layer Top of # zone (ft) Lithology 1 0.0 Shale 2 1700.0 Sandstone 3 1820.0 Coal 4 1840.0 Sandstone 5 1920.0 Shale 6 1960.0 Shale 7 1970.0 Sandstone 8 2375.0 Shale 9 2600.0 Shale Top of Fracture zone Toughness (ft) (psi-inh) 0.0 2000 1700.0 800 1820.0 1000 1840.0 800 1920.0 2000 1960.0 2000 1970.0 800 2375.0 2000 2600.0 2000 Top of zone (ft) 0.0 1700.0 1820.0 1840.0 1920.0 1960.0 1970.0 2375.0 2600.0 Tip Effects Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 Disposal Injection Application 9 - 19 October 6, 2000 Page 6 7:04 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format ' n: Job Date: 8-30-00 Filename: Flaxman Island5 Wellbore Configuration Segment Segment Tubing Tubing Casing Length Type ID OD ID (ft) (in) (in) (in) 2100 Tubing 2.992 50 Casing 0.000 0.000 0.000 0.000 4.408 Tubular Goods are defined to the TOP of the deepest set of perforations that are being modeled. Top of Perfs - TVD (ft) Bot of Perfs - TVD (ft) Perf Diameter (in) # of Perfs 2150 2300 0.400 900 Time min:sec 0:00 Near Wellbore Friction Parameters & Perf Multiplier Flow Rate #1 Flow Rate %2 Delta P Perf Coeff (bpm) (bpm) (psi) Multiplier 0.00 0.00 0.00 1.00 Disposal Injection Application 9 - 20 October 6, 2000 Page 7 7'04 pm FracproPT10.0 Hydraulic Fracture Analysis WellName' Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island5 Model Parameters Fracture Growth Parameters (Conventional 3D Model) Crack Opening Coefficient 0.7000000 Rock Deformation Coefficient 0.4000000 Channel Flow Coefficient 1.0000000 Fluid Radial Weighting Exponent set to default of Rock Deformation Coeff / 10. Proppant Model Parameters Minimum Proppant Concentration (lb/ft^2) Minimum Proppant Diameter (in) Volume Fraction of Proppant in Slurry Proppant Drag Effect Exponent Proppant Radial Weighting Exponent Proppant Convection Coefficient Proppant Settling Coefficient Quadratic Backfill Model Quadratic Backfill Coefficient Stop Model on Screenout 0.20 0.008 0.60 8.0 0.2500 10.00 1.00 ON 0.50 ON Initial Leakoff Area Coeff Closure Leakoff Area Coeff 1.00 0.03 Minimum Fracture Height OFF Near Wellbore Friction Exponent 0.50 Disposal Injection Application 9 - 21 October 6, 2000 Page 8 7'04 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Location: Format'n: Job Date: Filename: Flaxman Island Disposal Well North Slope, Alaska 8-30-00 Flaxman Island5 Proppant Data Proppant Name Cost (S/lb) Bulk Dens (lbm/ft~) Packed Porosity Specific Gravity (sg) Turbulence Coeff a Turbulence Coef Diameter (in) Perm @ 0 ps Perm @ 2000 ps Perm @ 4000 ps Perm @ 6000 ps Perm @ 8000 ps Perm @ 10000 ps Perm @ 12000 ps Perm @ 14000 ps Perm @ 16000 ps Perm @ 18000 ps f b 1 (D) 1 (D) 1 (D) ]. (D) 1 (D) 1 (D) 1 (D) 1 (D) ]_ (D) ]. (D) TemprdLC-163 CarboEP-2040 100 0.0 0.0 0.0 93.70 96.00 115 0.415 0.433 0.3 2.57 2.71 2.6 0.930 1.20 1.3 0.930 1.20 1.3 0.031 0.025 0.0 530.0 375.0 40. 530.0 342.0 40. 360.0 295.0 40. 174.0 220.0 40. 69.00 141.0 40. 32.00 91.00 40. 32.00 51.00 40. 32.00 40. 32.00 40. 32.00 40. -Mesh 70 .8 00 5 9 9 O6 00 00 00 00 00 00 00 00 00 00 Disposal Injection Application 9 - 22 170O 1800 1900 2O0O 2100 2200 2300 2400 2500 2600 2700 Stress Profile i 1000 1500 2000 2500 3000 Closure Stress (psi) 5OO Fracture Dimensions I 375 250 125 Propped Length (ft) 125 250 375 Hydraulic Length (ft) 5OO Fracture Profile Rockrty... [ Stress ... Modul... Porc P.. · :.. ::..... :..'.'..:... :: .::: ::4.. · ..... ; ~ :i'.::.:.? :-: ?.: .:..?:'.:::: { ::" "'..::'~ [~ · '.::-:'..::i:':-'"...i.::.::l .'" '! : !::.:: :?!'??:::Y:..:::.:':?-:: .....~.~ 1 ..-. :..~ ~'.:.' :..: ...: :.' · -:...':.: i! ~ :....:..: "4.....: :.' .. ":" 3...'3 ::":... :: :.::i' .......... :::. i~ ~ :'5 ....::.""':..':. :: · .: .. ~~ O0 ': :. :.::'.' '::k'.'." :i.l .. '.' ' · · ...-.:. :......:::.:.:. :.. ,:j · · . '""..3 ..... :." "...: :'l · ·: ::.:...- ...........11 ...... · · .':::"' ". ':.." '.:' j · ' '" I · ... '....:... · .:. i~' ·" · ".':.'"i.. i'. '":': ..["'I : ' ':' J ;.:.:'7::::.:.:.i?.i:::~;..:;:; ;: .;.~ 2~50.'...J ·'....:... '".. .. ;. '::;j ....... : :...:':'.":.::::'..? '..:. ~ ...' ...... .'..'.' ":'i-'"': ::-:'~ ........ ,: :.: .~ .... :..'.-.:'. :..:..'.~/.: .. Concentration of Proppant in Fracture 0b/ft2) - I' Width Profile (in) I r). q 0 O. e, I -- 15O0 1750 2(.)o0 2500 '>'; 50 - EXHIBIT 9-3 FRACTURE MODEL INJECTION SCENARIO III Injection Rate: Injection Duration: Injection Volume: 5 bbl/min 34.6 days (49,866 min): 5 days rejection followed by 1 day shutdown. Repeated for 34.6 days. 213,284 bbl Disposal Injection Application 9 - 25 October 6, 2000 Page 1 6:58 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island4 Fracture Analysis Options Conventional 3D Model Run From Job-Design Data No Convection or Settling Lithology Based Reservoir Vertical Fracture Model Wellbore and Perforations Results Summary Model has run until (min) 49866.70 Fracture length (ft) 375.21 Fracture upper height (ft) 256.91 Fracture lower height (ft) 150.53 Max width at well (in) 0.11 Dimensionless Cond. Ratio 0.00 Fracture efficiency Propped length (ft) Propped upper height (ft) Propped lower height (ft) Avg. prop. conc. (lb/ft2) 0.01 0.00 0.00 0.00 0.00 Total fluid (bbls) Min Surface Pressure (psi) Max Hydraulic Power (hp) 213284.13 261.36 55.86 Total sand (klbs) Max Surface Pressure (psi) Avg Hydraulic Power (hp) 0.00 456.39 33.86 Dist from Whore (ft) 0 47 94 141 188 235 281 328 375 Width @ Center (in) 0.11 0.11 0.11 0.10 0.10 0.09 0.07 0.05 0.00 Run from Design Data Only Disposal Injection Application 9 - 26 October 6, 2000 Page 2 6'58 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Location: Format'n: Job Date: Filename: Flaxman Island Disposal Well North Slope, Alaska 8-30-00 Flaxman Island4 Treatment Schedule Elapsed Clean Stg Time Fluid Volume # min:sec Type (kgal) Prop Stage Slurry Proppant Conc. Prop. Rate Type (ppg) (klbs) (bpm) W'bore Fluid 2% KCL 0.8 1 23:48 LINEAR 30 GW 5.0 2 7370:15 LINEAR 30 GW 1258.2 3 8810:15 SHUT-IN 0.0 4 ll:days LINEAR 30 GW 1258.2 5 12:days SHUT-IN 0.0 6 17:days LINEAR 30 GW 1258.2 -- -- 7 18'days SHUT-IN 0.0 8 23:days LINEAR 30 GW 1258.2 9 24:days SHUT-IN 0.0 10 29:days LINEAR 30 GW 1258.2 11 30:days SHUT-IN 0.0 12 35:days LINEAR 30 GW 1258.2 -- 0.00 0.0 5.00 5.00 6291.2 5.00 100-Mesh 0.00 0.0 0.00 5.00 6291.2 5.00 100-Mesh 0.00 0.0 0.00 5.00 6291.2 5.00 100-Mesh 0.00 0.0 0.00 5.00 6291.2 5.00 100-Mesh 0.00 0.0 0.00 5.00 6291.2 5.00 100-Mesh 0.00 0.0 0.00 5.00 6291.2 5.00 100-Mesh Scheduled clean vol (kgal) Scheduled slurry vol (kgal) 7554.47 9261.53 Scheduled sand total (klbs) 37747.35 Disposal Injection Application 9- 27 October 6, 2000 WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island4 Page 3 FracproPT10.0 Hydraulic Fracture Analysis Fluid Parameters 6:58 pm Ail Fluid info is at a reservoir temperature of 45.0 (°F) All Viscosities at Shear Rate of 511 (1/sec) Fluid Name 2% KCL LINEAR 30 GW Init. Rheology Viscosity 0.958 19.80 n' 1.000 0.525 K' 2.000e-05 0.008 Rheology @ 4.0 hours Viscosity 0.958 11.21 n' 1.000 0.629 K' 2.000e-05 0.002 Gel Density 1.01 1.000 Spurt Loss 0.0 2.00 Wall Building 0.0 0.003 Flowrate #1 10.00 10.00 Fric Press #1 96.64 72.00 Flowrate #2 20.00 20.00 Fric Press #2 335.1 185.0 Flowrate #3 40.00 40.00 Fric Press #3 1161.7 398.9 WB Fric Mult 1.000 1.000 Wellbore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction Multiplier. Viscosity is displayed in (cp) K' is displayed in (lbf-s^n/ft2) Gel Density is displayed as (sg) Spurt Loss is displayed in (gal/ft2) Wall Building is displayed in (ft/minh) Friction pressure is displayed in (psi/1000 ft) Friction is displayed for longest wellbore segment Disposal Injection Application 9 - 28 October 6, 2000 Page 4 6:58 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Location: Format'n: Job Date: Filename: Flaxman Island Disposal Well North Slope, Alaska 8-30-00 Flaxman Island4 Leakoff Parameters Reservoir type Filtrate to reservoir fluid perm. ratio, Reservoir pore pressure (psi) Initial fracturing pressure (psi) Reservoir fluid compressibility (i/psi) Cold filtrate viscosity (cp) Hot filtrate viscosity (cp) Cold reservoir viscosity (cp) Hot reservoir viscosity (cp) Porosity Gas Leakoff Percentage User Spec Kp/K1 1 80O 1100 5.00e-004 1.00 1.00 1.00 1.00 0.32 100.00 Reservoir Parameters Reservoir temperature (°F) Depth to center of Perfs (ft) Perforated interval (ft) Initial frac depth (ft) 45.00 2225 150 2225 Layer Parameters Lay Top of Top of # zone Stress zone (ft) (psi) (ft) Young's Poisson's Top of modulus ratio zone (psi) (ft) 1 0.0 1360 2 1700.0 1408 3 1820.0 1501 4 1840.0 1222 5 1920.0 1552 6 1960.0 1572 7 1970.0 1412 8 2375.0 2030 9 2700.0 2160 0.0 8.0e+06 0.25 0.0 1700.0 8.0e+06 0.25 1700.0 1820.0 1.0e+06 0.35 1820.0 1840.0 2.3e+06 0.20 1840.0 1920.0 8.0e+06 0.25 1920.0 1960.0 8.0e+06 0.25 1960.0 1970.0 2.3e+06 0.20 1970.0 2375.0 8.0e+06 0.25 2375.0 2700.0 8.0e+06 0.25 2700.0 Total Ct (ft/minh) 4.124e-05 4.124e-05 1.298e-04 2.558e-04 4.124e-05 4.124e-05 1.742e-03 4.124e-05 4.124e-05 PoreFluid perm. (md) 1.00e-04 1.00e-04 1.00e-03 4.00e-03 1.00e-04 1.00e-04 1.00e+03 1.00e-04 1.00e-04 Disposal Injection Application 9 - 29 October WellName: Location: Format'n: Job Date: Filename: ! Flaxman Island Disposal Well North Slope, Alaska 8-30-00 Flaxman Island4 2000 Page 5 FracproPTlO.O Hydraulic Fracture Analysis Lithology Parameters 6:58 pm Layer Top of # zone (ft) Lithology 1 0.0 Shale 2 1700.0 Shale 3 1820.0 Coal 4 1840.0 Sandstone 5 1920.0 Shale 6 1960.0 Shale 7 1970.0 Sandstone 8 2375.0 Shale 9 2700.0 Shale Top of Fracture Top of zone Toughness zone (ft) (psi-inh) (ft) 0.0 2000 1700.0 2000 1820.0 1000 1840.0 800 1920.0 2000 1960.0 2000 1970.0 800 2375.0 2000 2700.0 2000 0.0 1700.0 1820.0 1840.0 1920.0 1960.0 1970.0 2375.0 2700.0 Tip Effects Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 Disposal Injection Application 9 - 30 October 6, 2000 Page 6 6:58 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island4 Wellbore Configuration Segment Segment Tubing Tubing Casing Length Type ID OD ID (ft) (in) (in) (in) 2100 Tubing 2.992 0.000 0.000 50 Casing 0.000 0.000 4.408 Tubular Goods are defined to the TOP of the deepest set of perforations that are being modeled. Top of Perfs - TVD (ft) Bot of Perfs - TVD (ft) Perf Diameter (in) # of Perfs 2150 2300 0.400 900 Time min:sec 0:00 Near Wellbore Friction Parameters & Perf Multiplier Flow Rate #1 Flow Rate #2 Delta P Perf Coeff (bpm) (bpm) (psi) Multiplier 0.00 0.00 0.00 1.00 Disposal Injection Application 9 - 31 October 6, 2000 Page 7 6'58 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Flaxman Island Disposal Well Location: North Slope, Alaska Format'n: Job Date: 8-30-00 Filename: Flaxman Island4 Model Parameters Fracture Growth Parameters (Conventional 3D Model) Crack Opening Coefficient 0.7000000 Rock Deformation Coefficient 0.4000000 Channel Flow Coefficient 1.0000000 Fluid Radial Weighting Exponent set to default of Rock Deformation Coeff / 10. Proppant Model Parameters Minimum Proppant Concentration (lb/ft^2) Minimum Proppant Diameter (in) Volume Fraction of Proppant in Slurry Proppant Drag Effect Exponent Proppant Radial Weighting Exponent Proppant Convection Coefficient Proppant Settling Coefficient Quadratic Backfill Model Quadratic Backfill Coefficient Stop Model on Screenout 0.20 0.008 0.60 8.0 0.2500 10.00 1.00 ON 0.50 ON Initial Leakoff Area Coeff Closure Leakoff Area Coeff 1.00 0.03 Minimum Fracture Height OFF Near Wellbore Friction Exponent 0.50 Disposal Injection Application 9 - 32 October 6, 2000 Page 8 6'58 pm FracproPT10.0 Hydraulic Fracture Analysis WellName: Location: Format'n: Job Date: Filename: Flaxman Island Disposal Well North Slope, Alaska 8-30-00 Flaxman Island4 Proppant Data Proppant Name TemprdLC-163 100-Mesh Cost (S/lb) Bulk Dens (lbm/fts) Packed Porosity Specific Gravity (sg) Turbulence Coeff a Turbulence Coeff b Diameter (in) Perm @ 0 psi Perm @ 2000 psi Perm @ 4000 psi Perm @ 6000 Perm @ 8000 psi Perm @ 10000 ps~ Perm @ 12000 ps~ Perm @ 14000 ps~ Perm @ 16000 ps~ Perm @ 18000 ps~ (D) (D) (D) (D) (D) (D) (D) (D) (D) (D) 0.0 0.070 93.70 115.8 0.415 0.300 2.57 2.65 0.930 1.39 0.930 1.39 0.031 0.006 530.0 40.00 530.0 40.00 360.0 40.00 174.0 40.00 69.00 40.00 32.00 40.00 32.00 40.00 32.00 40.00 32.00 40.00 32.00 40.00 Disposal Injection Application 9 - 3 3 170O 1800 1900 20OO 21 O0 2200 2300 2400 2500 i_o'- High I' '.!Il" "' ' 2700 : i ' " 1000 1500 Stress Profile ,,'.'1 .... '"" · ' '.' '. :. 'i': ..:'.: "." .: ':'1 ' .':: .': '.':i ::" .i;i: 'i .:. · .. . ........ . · .. . . . ... · . 2000 2500 3000 Closure Stress (psi) 5OO Fracture Dimensions 375 25O Propped Length (fi) 125 125 25O Hydraulic Length (ft) 375 500 ; . = Fracture Proffie Rockty... Stress ... Modul... ],6i.;, 'P..72 .:: ..: ....:.: ...:. ! . · ' :: :?~i'i:i;: ::?:' !~ . !.i :'.~: :!:... :::? i!: 1'"'~¢.)."~c~ :i 2'.:' :.:':.14 ::. · .i . .. ?'. i:::. i::: .... .i · :......: · .. .... .. · .. . . '.' :' :X i.. !:: ?.:.'.. i':: .'.. !! ' · '- '- · :. ::.:....: ..: .. :..,..:.. . ...:. : [5::'. !::..:.!Z:':::.:...'!::'.:.:? ' '. " · .'.'.' ....: .. · ........ · . · · ':i.::'.. :. :.. '.:'. '" .. '.: .... '. ::.:'-....:; i ::' ;:.: ::./ :..': :~ ':250~1' :' ?. ?.::: ~::: i;.'i~{ {..2-,.'so.:. :v ........... . .....- . ".':' ":Z!:.; .':-'.'Z!:. ':" .' ."* ."' ". .... Concentration of Proppant in Fracture (lb/ft2) Width Profile (in) i tJ 5 0 0.5 I ' ! 75{! 2O110 2'750 10.0 Formation Water Analysis [20 AAC 25.252(c)(10)] Class II waste disposal by injection is permitted regularly in aquifers with a Total Dissolved Solids (TDS) concentration greater than 10,000 PPM. TDS concentrations in the proposed injection zones, located between depths of 2,150 feet and 2,300 feet in the Alaska State A-1 well, are conservatively estimated as being between 20,000 and 30,000 PPM based on log analyses. The calculation for this analysis is presented in the attached Schlumberger report. Disposal Injection Application 10 - 1 ]~40 A~¢I,~: ~Oulevacd At, ciao, ago. Alaska 99503 (9071 271~ ! 700 Fax 1907~ 56~-S3~ 7 Schlumberger - August28,2000 Mr. Jesse Mohrbacher Fairweather E&P Services 715 [ Street Anchorage, AK 99501-3335 Dear Jesse: The following is a Spontaneous Potential (SP)interpretation report as requested by you. The SP log for Exxon Company, USA well #1 Alaska State "A" was evaluated to identify the salinity of the formation water at depths from 2150 ft to 2375 ft. The interpreted results are based on information obtained from the Dual Induction- Laterolog run 5 field print (date 9-5-75) provided by the client. Well Information: Company: Well: Field: County: State: Location: APl Number: Field Print: Exxon Company, USA #1 Alaska State 'A" Wildcat North Slope Alaska 2982 ft FEL & 1549 ft FSL, Section 27, Township, 10N Range 24E 089-200003-00 Dual Induction - Laterolog Depth of Interest 2150 ft to 2375 ft Interpretation Procedure: Identify SP deflection from shale baseline to clean, water filled sand Determine temperature at depth Determine Rmf at temperature Calculate Rmfeq = 0.85 x Rmf Obtain Rmfeq/Rweq from chart SP 1 Obtain Rweq from chart SP 1 Convert Rweq to Rw using chart SP 2 Obtain NaCl concentration from chart GEN 9 Attached are charts SP 1, SP 2, and GEN 9. Disposal Injection Application 10 - 2 Calculations: Inputs SSP = -35MV Rmf = 1.3r/.m @ 58° F Temp Re servoir = 58°F Calculations Rmfeq - 0.85xl .3 = 1.105~/- tn Rmfeq = 3.1 Rweq Rweq - 0.33E/- m Rw = 0.30ff2 - tn NaCl = 25,000 pprn The above calculations assume a temperature gradient of 1.8 °F/100 ft with a temperature of 79 °F at 3379 ft based on the Dual Induction - Laterolog heading. In addition, the calculated salinity assumes the dissolved solids in the formation water are NaCI. If you have any questions regarding the above calculations, please feel free to call me at (907)273-1771. Sincerely, Douglas Hupp, P.E. Senior Log Analyst Reservoir Management- GeoQuest Disposal Injection Application 10 - 3 Rweq Determination from EssP clean formations SP-1 This chart and nomograph calculate the equivalent forma- tion water resistivity, Rwcq, from the static spontaneous potential, £ssP, measurement in clean formations. Enter the homograph with EssP in mV, turning through the reservoir temperature in °F or °C to define the Rmfeq/R~,eq ratio. From this value, pass through the Rmfeq value to define R,,,,,q. For predominantly NaCI muds, determine Rmfeq as follows: a. If Rmf at 75°F (24°C) is greater than 0. I ohm-m, correct Rmf to formation temperature using Chart Gen-9, and use Rmf~ = 0.85 Rmf- b. If Rmf at 75°F (24°C) is less than 0.1 ohm-m, use Chart SP-2 to derive a value of R~f~q at formation temperature. E. ruml~le: SSP = 100 mV at 250°F Rmt'= 0.70 ohm-m at 100°F or 0.33 ohm-m at 250°F Therefore, Rmfeq = 0.85 x 0.33 = 0.28 ohm-m at 250°F R,,,,,q = 0.025 ohm-m at 250°F EssP = -Kc log (Rmfm/R~,m) Kc = 61 + 0.133 T°F Kc = 65 + 0.24 T°c 0.3 0.4 0.5 0.6 0.8 1 3 4 5 6 8 10 2O 30 40 50 +50 0 -5O -100 -150 EssP. static spontaneous potential (mY) R,~,~/R,,,,~ 0.3 0.4 0.6 0.8 1 6 8 10 2O 40 -200 (ohm-m) ~ ~'""~'°*Disposal Injection Application 0.01 0.02 0.04 0.06 0.1 0.2 0.4 0.6 1 4 6 10 2O 40 60 100 Rweq (ohm-m) _ 0.001 0.005 0.01 0.02 . 0.05 0.2 0.5 1.0 10 -4 R,,,, versus Rweq and Formation Temperature SP-2 (English) c ~hlumberger 0.001 0.002 0.005 0.01 0.02 0.05 0.1 0.2 0.5 1.0 2.0 0.005 0.01 0.02 0.03 0.05 0.1 0.2 0.3 0.5 1.0 2 3 4 5 R,,, or R.~f (ohm-m) These charts convert equivalent water resistivity, R,,,,,q, from Chart SP-1 to actual water resistivity, R,,,. They may also be used to convert Rmf to Rmfeq in saline muds. Use the solid lines for predominantly NaCI waters. The dashed lines are approximate for "average" fresh formation waters (where effects of salts other than NaCI become signifi- cant). The dashed portions may also be used for gyp-base mud filtrates. Example: Rweq = 0.025 ohm-m at 120°C From chart, R,,, = 0.031 ohm-m at 120°C Special procedures for muds containing Ca or Mg in solution are discussed in Reference 3. Lime-base muds usually have a negligible amount of Ca in solution; they may be treated as regular mud types. 2.6 Disposal Injection Application 10 -5 Resistivity of NaCI Solutions Gen-9 Conversion approximated by R2 = R, [(T, + 6.77)/(T2 + 6.77)]°F or R2 = R~ [(T~ + 21.5)/(T2 + 21.5)]°C 10 8 1 0.8 0.6 0.5 0.4 0.3 .......... 0.2 0.1 0.08 0.06 0.05 0.04 0.03 0.02 0.01 _ °F 50 °C 10 20 I I I I I I I I I 75 100 125 150 200 250 300 350 E 400 ,OOo -. 30 40 50 60 70 80 90 100 120 140 160 180 200 I ! I I ! I ! I I Il'Ill I I .I 10 _ 25 __ 30 _ 40 __ 50 400 500 1000 1500 2000 2500 3000 4000 5000 10,000 15,000 20,000 Temperature (°F or °C) C ~ hltjmberc~' Disposal Injection Application 10 -6 11.0 Freshwater Aquifer Exemption [20 AAC 25.252(c)(11)] Freshwater is not present in wells in the area. Therefore, issuance of a freshwater aquifer exemption in accordance with 20AAC 25.440, is not necessary. Disposal Injection Application 11 - 1 12.0 Mechanical Condition of Wells [20 AAC 25.252(c)(12)] The only well located within one quarter mile of the proposed Alaska State A-2 disposal well is the Alaska State A-1 well. This well is located 300 feet due east of the A-2 well. The A-1 well was drilled as a straight hole in 1975 and suspended that same year. The status of the well was changed to plugged and abandoned after additional surface well work in 1986. The A-1 well was re-abandoned in 1998 due to continued erosion of Flaxman Island. The A-1 well has two (2) casing strings across the proposed disposal zone(s). These casings include the 9-5/8 and 13-3/8 inch strings, which are set at 11,076 feet and 3,376 feet, respectively. A string of 20 inch casing is also set at 824 feet. The 13-3/8 inch x 9- 5/8 inch annulus has previously been cemented from 1,996 feet to 3,376 feet through a F.O. collar at 1,996 feet. Both the 13-3/8 inch and 20 inch casing were cemented to surface during drilling with full returns and cement was tagged inside the 13-3/8 inch casing prior to drilling out of the casing shoe. The 13-3/8 x 9-5/8 inch annulus and the 9- 5/8 inch casing were also freeze protected through the permafrost zone at the time of suspension with Arctic pack in the annulus and diesel in the casing. During re- abandonment operations in 1998, the diesel in the 9-5/8 inch casing was displaced by 15 ppg drilling mud prior to cementing of the 9-5/8 inch casing and the 13-3/8 x 9-5/8 inch annulus from 231 feet to surface. All casing strings were then cutoff 35 feet below grade. Upon inspection after cutoff, all annuli including the 20 inch x structural casing annulus, the 13-3/8 x 9-5/8 inch annulus and the 9-5/8 inch casing had good cement plugs at the surface. Based on the above cementing records and field documentation, the A-1 well has good mechanical integrity and is isolated across the proposed disposal zone(s). Disposal Injection Application 12 - 1 13.0 Mechanical Integrity of Disposal Well [20 AAC 25.252(d)] The disposal well will undergo a series of mechanical integrity tests and evaluations during construction and operation. Subsequent to cementing of the 5-1/2 inch casing to surface, the casing will be cleaned out and pressure tested to 1,500 psi for 30 minutes. The cement job will also be evaluated by USIT cement evaluation logging tool or equivalent. ARer running the completion packer and tubing, the casing/tubing annulus will also be pressure tested to 1,500 psi for 30 minutes. Mechanical integrity will be monitored daily during injection operations by recording the pressure on the tubing/casing annulus. At the conclusion of injection operations, the Alaska State A-2 well will be plugged and abandoned in accordance with 20 AAC Chapter 25, Article 2. Disposal Injection Application 13 - 1 STATE OF ALASKA ALAS~ )ILAND GAS CONSERVATION COl~(' .SSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work IX] Ddll [ ] Redrill lb. Type of well [ ] Service [ ] Development Gas [ X] Single Zone [ X ] Disposal [ ] Re-Entry [ ] Deepen [ ] Exploratory [ ] Stratigraphic Test [ ] Development Oil 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool ExxonMobil Production Company, a division of Exxon Mobil Corporation 10' MLLW (grade) 3. Address P.O. Box 196601 ~6. Property Designation N/A Anchorage, AK 99519-6601 ADL 47556 4. Location of well at surface 7. Unit or Property Name 11. Type Bond (See 20 AAC 25.025) 1,542' FSL, 2,598' FEL, Sec 27, T10N, R24E, UM Alaska State A Statewide At top of productive interval 8. Well Number Number 8302 42 06 NA Well #2 At total depth 9. Approximate spud date Amount $200,000 1,542' FSL, 2,598' FEL, Sec 27, T10N, R24E, UM 1-Dec-00 12. Distance to nearest property line I13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and 'I'VD) 2,598'I 300' to Alaska State A-1 2,533 2,400'MD, 2.400'TVD 16. To be completed for deviated wells 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} Kick Off Depth N/A Maximum Hole Angle N/A Maximum surface 797 psig , At total depth (TVD) 1,060 psI 18. Casing Program Setting Depth Size Specifications Top Bottom Quantity of Cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stagedata) 8.5" 7-5/8" 29.7# L-80 BTC 80' 10' 10' 80' 80' 50 sx Class Cold Set II 6-3/4" ,..5...1,~' ~ L-80 STL 2,390' 10' 10' 2,400' 2,400' 133 sx Class G, 453 Sx Cold Set III 19. To be completed for Redrill, Re-entry, and Deepen Operations. ,, Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented MD 'rVD Structural Conductor Surface Intermediate Production Liner RECEIVED Perforation depth: measured ~a!Sk8 @i & Gas Cons. ~mmission . true vertical , ArtchoEt§8 20. Attachments [ X] Filing Fee [ X ] Property Plat [ ] BOP Sketch [ X ] Diverter Sketch [ X] Drilling Program [ X] Drilling Fluid Progra [ ] Time vs Depth Pict [ ] Refraction Analysis [ ] Seabed Report [ ] 20AAC25.050 Req. Contact Engineer Name/Number: Bill Penrose 907-258-3446 Prepared By Name/Number: . Bill Penrose 907-258-3446 21.1Signedhereby certify that the..~._fore~ing ~---'~is true and. correct to ~t h e..b.c~t.....of my knowledge James F. Sra~.~l/'~~--~r/",.//"'~'"""-~/'"-~aska Production Manager / 'Date Commission Use Only I I ApP'r"°val Date rSee c°ver letter Permit~_/,~//~Number AP ~N..~) b.e..r~_~_~.. ,2.Z~4:~ ~.~ -(..~ /,¢~ .-.~/-~C~ for other requirements Conditions of Approval: Samples Required: [ ] Yes ~No Mud Log Required [ ] Yes ~ No Hydrogen Sulfide Measures: [ ] Yes J~ No Directional Survey Req'd [ ] Yes ~, No Required Working Pressure for BOPE: [ ]2M, [~]3M, [ ]5M, [ ]10M, [ ]15M Approved By D Taylor Se;::~moum Commissioner the commission Date Form 10-401 Rev. 12-01-85 Submit I n Triplicate ExxonMobii Production Company Alaska State A-2 Disposal Well Drilling Procedure 1. Excavate and install cellar with base plate. . Move rig over cellar. M/U 9-1/2 inch drilling assembly and drill 9-1/2 inch hole to 90 feet RKB. POH. . Clean out cellar and mn 7-5/8 inch, 29.7 lb/f1, L-80, BTC casing to 80 feet RKB. Hang casing on base plate. . Cement conductor casing with 50 sacks of 15 ppg Cold Set II permafrost cement (calculated annulus volume plus' 263% excess). Cut off casing and weld on 7-5/8 inch x 7 inch 5,000 psi WP starting head. Install 7 inch, 5,000 psi diverter spool with a 6 inch diVerter outlet. . NFLI 7 inch, 5,000 psi WP diverter and 6 inch diverter line with hydraulic valve. Function test diverter system. AOGCC representative to witness test. o . . 10. M/U 6-3/4 inch drilling BHA and RIH. Drill 6-3/4 inch straight hole to 2,400 feet RKB, taking single shot surveys every 500 feet. At TD, take final single shot survey, circulate and condition hole for logs and POH. chlumberger and run Platform Express logging package consisting of gamma ray neutron, lithology density and resisti~ty sondes. R/D Schlumberger. Make a cleanout run to TD and circulate and condition hole for running casing.. POH. Run 5~'/2 inch, 1~ lb/ft, L-80, STL casing to 2,400 feet with stage cementing collar at 900 feet RKB. 11. Cement casing to surface in 2 stages. First stage to extend from TD to 900 feet RKB and consist of 45 sacks of Coldset III permafrost cement and 133 sacks Class G cement with additives. Second stage to extend from cementing collar at 900 feet RKB to surface and consist of 453 sacks (700% excess, if necessary) of Cold Set III permafrost cement. RIH w/~ inch clean-out assembly and clean out ~ inch casing to the float collar. Pressure-test casing to 1,500 psi. POH.~, R~GE[VED 0 7 2000 t"~.'~ ~¥~\\ c~ \,,~e.~-N-q. c'-, ~'~ ~ ~ ~ ~~aska ~ & GasCons. Commission Drilling Procedure 13. 14. R/U Schlumberger and run USIT cement evaluation tool to TD. Confirm acceptable cement job. Perforate 54~ inch casing at 6 spf across selected disposal zones between 2,150 and 2,375 feet. Initial perforations will be in the deepest available disposal zone(s) with shallower zone(s) unperforated as a contingency. R/D Schlumberger. 15. Run 2-7/8 inch, 4.7 lb/fi, N-80, 8rd, EUE completion. Packer to be located at 2,000 feet RKB and tubing tail to be located at 2,030 feet. 16. Freeze protect by circulating CaC12 brine into annulus, then set packer. 17. Pressure test completion to 1,500 psi for 30 minutes. 18. Perform step rate injection test to establish injection rates and pressures. 19. N/D diverter, N/U tree. Test tree to 1,500 psi. 20. Pump excess drilling and completion fluids down well and flush tubing with diesel. Release rig. o o o z 0 x x .< R23 E R24E 18 19 17 20 16 21 15 22 14 15 24 3O 31 29 32 28 CERTIFICATE OF SURVEYOR I hereby certify fhaf I am properly registered and licensed fo practice land surveying in the State of Alaska and that this plat represents a location survey made by me or under my supervision, and that all dimensions and other details are correct. 34¸ ,.E_xxonMobll Alaska State A-2 X=498,257 Y=5,918,728 26 25 36 55 SCALE IN MILES Date Surveyor Notes: Final survey plot to be submitted fo AOGCC prior fo spud of well. Alaska State A-1 is located ;500' due East of Alaska State A-2. ExxonMobil Alaska State A-2 Located in SE 1/4 Protracted Sec 27, TI ON, R24E Umiat Meridian SurveYed for ExxonMobil Production Company Surveyed by Terra Surveys, LLC RIG BEAUS GROUND LEVEL CELLAR FLOOR I BELL NIPPLE AND FLOW UNE 7' DIVERTER DIVERTER SPOOL 7' x 7 5/8' CASING HEAD 7 5/8' CASING Em DIVERTER UNE* HYDRAUUC DIVERTER VALVE 0 0 0 *NOTE: DIVERTER LINE WILL BE ANGLED UPWARD SUFFICIENTLY TO BRING THE END ABOVE GROUND LEVEl_ BOP Schematic Fla×man Island Drsposol Well Alaska Sfafe A-2 RECEIVED SEP 07 2000 Gas Cons.Comm;s$1on' ' A. nchora,~e CASING PERFORMANCE PROPERTIES Size Weight Grade Cnxn. (In.) (Ib/ft) ALASKA STATE A-2 CASING PROPERTIES AND DESIGN Internal Collapse Tensile Streng. Yield Resist. Joint Body (psi) (psi) (1000 lbs) (1000 lbs) TVD MD (Ft RKB) (FT RKB) Design Safety Factor* T B C 5 18 Limited LTC service J-55 Spec. 5200 7390 331 343 2,400 2,400 * Tensile design safety factor is calculated using pipe weight less buoyancy. Burst design safety factor is calculated using the TD formation pressure. Collapse design safety factor is designed assuming complete evacuation of the casing. 9.40 6.52 6.72 CASING SETTING DEPTH RATIONALE 9-5/8" 80' RKB 5" 2400' RKB Conductor to provide stability of surface soils and amchor for drilling diverter. Production casing to provide hole stability for injection operations. Alaska State A-2 Flaxman Island, Beaufort Sea, Alaska Casing Cementing Program Operator Name: Fairweather Ex~' & Prod Inc Well Name: Flaxman Island sposal Well Job Description: Conductor Pipe Date: August 25, 2000 Proposal No: 179650771E JOB AT A GLANCE Depth (TVD) Depth (MD) Hole Size Casing Size/Weight: Pump Via Total Mix Water Required Cement Slurry CS II Density Yield Displacement Water Density 80 ft 80 ft 9.5 in 7 5/8in, 29.7 Ibs/ft Casing 7 5/8" O.D. (6.875" .I.D) 29.7 # 206 gals 50 sacks 15.0 ppg 1.02 cf/sack 4 bbls 8.4 ppg Operator Name: Fairweather Ex.pi & Prod Inc Well Name: Flaxman Islan{ sposal Well Job Description: Conductor Pipe Date: August 25, 2000 Proposal No: 179650771E FLUID SPECIFICATIONS VOLUME VOLUME FLUID CU-FT FACTOR Cement Slurry Displacement CEMENT PROPERTIES 51 / 1.02 Slurry Weight (ppg) Slurry Yield (cf/sack) Amount of Mix Water (gps) AMOUNT AND TYPE OF CEMENT = 50 sacks Cold Set II + 43.3% Fresh Water 3.7 bbls Water @ 8.4 ppg SLURRY NO. 1 14.95 1.02 4.13 RECEIVED SEP 07 2000 Alaska Oi'i & Gas Cons. Commission Anchorage Repoff Printed on: August 25, 2000 12:39 PM Gr4129 Operator Name: Fairweather Exp~ & Prod Inc Well Name: Flaxman Island" sposal Well Job Description: Conductor Pipe Date: August 25, 2000 Proposal No: 179650771 E WELL DATA ANNULAR GEOMETRY ANNULAR I.D. I DEPTH(fi) (in) MEASURED I ' TRUE VERTICAL 9.500 HOLE I 80 I ~o SUSPENDED PIPES DIAMETER (in) J WEIGHTI O.D. I I.D. (lbs/fi) DEPTH(fi) MEASURED I TRUE VERTICAL' 80 I 80 ?.~25 I s.s?5 I 29.7I Mud Density Mud Type Est. Static Temp. Est. Circ. Temp. 8.60 ppg Water Based 67°F 40 ° F VOLUME CALCULATIONS 80 ft x 0.1751 cf/ft with 263 % excess = TOTAL SLURRY VOLUME = 50.9 cf 50.9 cf 9 bbls RECEIVED 2000 Aqchorage Report Printed on: August 25. 2000 12:39 PM Gr4115 Operator Name: Fai~veather F__~' & Prod Inc Well Name: Flaxman Island' sposal Well Job Description: Monobore Casing Date: August 25, 2000 Proposal No: 179650771E JOB AT A GLANCE Depth (TVD) Depth (MD) Hole Size Casing Size/Weight: Pump Via Total Mix Water Required Lead Slurry CS III Density Yield Tail Slurry G + 2% A-7 Density Yield Displacement Mud Density Lead Slurry CS III Density Yield Displacement Mud Density Stage No: 1 2,400 ft 2,400 ft 6.75 in 5 in, 15 lbs/fi Casing 5"O.D. (4.408".1.D) 15# 5,042 gals 2,320 ft 45 sacks 12.2 ppg 1.64 cf/sack 133 sacks 15.8 ppg 1.16 cf/sack Stage Collar set {~ 44 bbls 8.8 ppg 900 fi 453 sacks 12.2 ppg 1.64 cf/sack 17 bbls 8.8 ppg Report Printed on: August 25, 2000 12:39 PM Page Operator Name: Fairweather Ex,pi & Prod Inc Well Name: Flaxman Island(' 'sposal Well Job Description: Monobore Casing Date: August 25, 2000 Proposal No: 179650771E FLUID SPECIFICATIONS STAGE NO.: 1 VOLUME FLUID CU-FT VOLUME FACTOR Lead Slurry 73 / 1.64 Tail Slurry 154 / 1.16 Displacement CEMENT PROPERTIES Slurry Weight (ppg) Slurry Yield (cf/sack) Amount of Mix Water (gps) Amount of Mix Fluid (gps) STAGE NO.: 2 VOLUME CU-FT FLUID VOLUME FACTOR Lead Slurry Displacement CEMENT PROPERTIES Slurry Weight (ppg) Slurry Yield (cf/sack) Amount of Mix Water (gps) Amount of Mix Fluid (gps) 742 I 1.64 AMOUNT AND TYPE OF CEMENT = 45 sacks Cold Set III + 1 gals/100 sack FP-6L + 96.2% Fresh Water = 133 sacks Class G Cement + 2% bwoc Calcium Chloride + 1 gals/100 sack FP-6L + 44.3% Fresh Water 43.8 bbls Mud @ 8.8 ppg SLURRY SLURRY NO. 1 NO. 2 12.20 15.80 1.64 1.16 8.79 5.00 8.80 5.01 AMOUNT AND TYPE OF CEMENT = 453 sacks Cold Set III + I gals/100 sack FP-6L + 96.2% Fresh Water 17.0 bbls Mud @ 8.8 ppg SLURRY NO. '1 12.20 1.64 8.79 8.80 Report PHnted on: August 25, 200012:40 PM Gr4129 Operator Name: Fairweather Ex,!p.~ & Prod Inc Well Name: Flaxman Islan({ sposal Well Job DesCription: Monobore Casing Date: August 25, 2000 Proposal No: 179650771E WELL DATA ANNULAR GEOMETRY ANNULAR I.D. (in) 6.276 CASING 6.750 HOLE DEPTH{fi) MEASURED I TRUE VERTICAL 80 I 80 2,400 I 2,400 SUSPENDED PIPES DIAMETER (in) J WEIGHTI . .. .. DEPTH(fi):.· '..' · · O.D. I I.D.' (lbs/fi)·MEASURED ITRUE VERTICAL 5.000 I 4.408 I I 2,400 I2,400 STAGE: 1 Float Collar set (~ 2,320 ft Mud Density 8.80 ppg Mud Type Water Based Est. Static Temp. 56 ° F Est. Circ. Temp. 40 ° F VOLUME CALCULATIONS 500 ft x 0.1122 cf/ft 1,000 ff x 0.1122 cf/fl 80 ff x 0.1060 cf/ft with 30 % excess = with 30 % excess = with 0 % excess = TOTAL SLURRY VOLUME = 72.9 cf 145.8 cf 8.5 cf (inside pipe) 227.2 cf 40 bbls STAGE: 2 Stage Collar set (~ Mud Density Mud Type Est. Static Temp. Est. Circ. Temp. 900 ft 8.80 pPg Water Based 67°F 400F VOLUME CALCULATIONS 80 ft x 0.0785 cf/ff 820 ft x 0.1122 cf/ft with 0 % excess = with 700 % excess = TOTAL SLURRY VOLUME = ... 6.3 cf 735.7 cf 742.0 cf 132 bbls Report Printed on: August 25, 2000 12:39 PM Gr4115 ~80' 7 5/8" Conductor Casing Tubing/Casing Annulus Freeze Protected w/CaCI2 Brine. Stage Cementing Tool O =900' Permafrost Interface O ~,1,050' 2 7/8" Tubing LEGEND Cement NO SCALE FAIR/EXXON/2OOO/FLXB2000 -~2,000' .5 ,~" x 2 7/8" Packer ~2,400' Potential Disposal Zone, 2,150' - 2,500' 5 ~" Production/DispOsal Casing - \ 1:1 8/23/00 SR Flaxman Island Disposal Well Proposed Alaska State A-2 Wellbore Schematic ExxonMobil Production Company Drilling Fluid Program, Pressure Calculations, and Drilling Area Risks Alaska State A-2 Disposal Well Drilling Fluid Properties: Density PV YP Funnel Vis Initial Gel 10 Minute Gel APl Filtrate pH % Solids 8.8 - 9.6 8 - 20 20 - 60 100 - 300 10 - 20 20 - 40 <15 8-10 5-10 Drilling Fluid ,,System: One 200-bbl "3U" mud mixing/handling system containing: 200-bbl pit Mud mixing hopper and pump Fluid agitation One linear-motion shale shaker Mud return line with towline jet and check flapper Maximum Anticipated Surface Pressure: The maximum anticipated surface pressure (MASP) for the 6-3/4 inch hole section will be the formation pore pressure (less a full gas column to the surface)at TD. Based on offset well data, the highest mud weight expected in the 6-3/4 inch hole section is 8.8 ppg (0.442 psi/t~) at the section TD of 2,400 feet. Complete evacuation of the wellbore, except for a 0.11 psi/ff gas gradient, is assumed. 6 inch hole section MASP (pore pressure) (2,400 f0(0.442 - 0.11) -- 797 psi MASP in the 6-3/4 inch hole Section will therefore be 797 psi. With a diverter on the well, it will not be possible to shut in the well if such a situation developed.' The diverter will be routinely function tested during the drilling of the well. Fluid Program, Drilling Well Proximity Risk: The nearest wellbore to that of A-2 Disposal Well is the Alaska State A-1. The A-2 well is proposed to be drilled fi.om a surface location 300 feet west of the A-1 well. The A-1 well was drilled as a straight hole and the A-2 is also planned as a straight hole. ExxonMobll will survey during drilling every 500 feet and use care to drill a straight hole. Drilling Area Risks: The primary drilling risks in the shallow (<2,500 feet) formations in the Flaxman Island area are those of subsurface water flows and hole washouts. These are routine surface- hole drilling problems that can be controlled with mud rheologies, temperatures, flowrates and time spem circulating. Mud rheologies will be maximized for stability of the unconsolidated surface formations, especially through the permafrost interval. The mud will also be kept as cool as practicable to minimize permafrost interval destabilization. Flowrates in unconsolidated intervals will be kept to a minimum to avoid excessive washout unless it becomes. apparent that higher flowrates will allow penetration rates that will finish the hole section more rapidly. Disposal of Muds and Cuttings: All waste drilling fluids and cuttings will be stored on the drilling location until the disposal well is completed and injection established. Excess drilling and completion fluids will be injected immediately after completion of the well. Solid drilling wastes will be temporarily stored on-site then ground and injected into the disposal well along with the reserve pit contems from Alaska State A-1 and G-2 wells as soon as possible during the 2000/2001 winter season. All Casings Cut ~30' Below Grade -~-80' 7 5/8" Conductor Casing Tubing Cut O 200' with 170' Cement Plug on Top. Stage Cementing Tool O =900' Permafrost Interface {~ ~1,050' LEGEND Cement r -~ CaCi2 Brine NO SCALE FAIR/EXXON/2OOO/FLX2000 1:1 8/22/00 ~2,000' All Perfs Squeezed ~2,400' 5 ~.7%" x 2 7/8" Packer Disposal Zone, 2,150' - 2,500' 5~" Production/Disposal Casing / SR ' Flaxman Island Disposal Well Proposed Alaska State A-2 Post Abandonment Schematic ExxonMobil Production CompS,'~ , P.O. Box 196601 Anchorage, Alaska 99519-6601 Jarne~ Branch Production Manager, Alaska Interest Joint Interest U.S. September 7, 2000 E x, onMobil Production Mr. Daniel T. Seamount, Commissioner Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Attention: Blair Wondzell, Senior Petroleum Engineer Re: Application for Permit to Drill: Flaxman Island Disposal Well, Alaska State A-2 Dear Mr. Wondzell: ExxonMobil Production Company, a division of Exxon Mobil Corporation, hereby makes application for a Permit to Drill a Class II disposal well (Alaska State A-2) on Flaxman Island in the Beaufort Sea. The overall project entails excavation and disposal of 15,000 to 25,000 cubic yards of drilling wastes from the Alaska State A-1 and G-2 drill sites on Flaxman Island. The drilling wastes will be processed using grind and inject equipment and disposed of in this Class II injection well that is to be drilled at the Alaska State A-1 location. Drilling wastes will be excavated at this time because beach erosion threatens the integrity of the existing sites. The A-2 well will be drilled during the fourth quarter of 2000 with the rig mobilization by rolligon as soon as tundra travel and sea ice conditions allow. This mobilization effort is anticipated in early December. At the completion of drilling operations, the rig will be demobilized by rolligon. Subsequent to drilling the well, the contents of the A-1 and G-2 reserve pits will be excavated, ground, slurried and injected down the A-2 disposal well during the winter of 2000/2001. The well will then be plugged and abandoned per AOGCC regulations prior to the demobilization of all equipment from Flaxman Island. The well is planned to be a straight hole to 2,400 feet and will be located on the same drilling pad and approximately 300 feet west of the previously drilled Alaska State A-1 well. ExxonMobil proposes to survey the well during drilling every 500 feet. This variance from the deviation rules in 20 AAC 25.050 is requested because the A-1 well is abandoned and not a producing well. ExxonMobil'will monitor deviation of the well to ensure a straight hole. ExxonMobil proposes to drill the well to TD using a 7 inch diverter system. This diverter will be equipped with a single 6 inch diverter line and hydraulically actuated valve. The diverter system has been sized accordingly with the 6-3/4 inch hole size that is planned to TD. For the Alaska State A-1 well, surface hole was drilled to 3,378 feet on diverte.r without incident. ~,C~E~VE~ Mr. Blair Wondzell 2 September 7, 2000 Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill per 20 AAC 25.005 (a). 2) Fee of $100.00 payable to the State of Alaska per 20 AAC 25.005 (c) (1). 3) A plat showing the well's proposed surface and bottomhole locations per 20 AAC 25.050 (c) (2). 4) A diagram of the BOP equipment to be used as required by 20 AAC 25.035 (a)(1) and (b). 5) A complete proposed casing and cementing program is attached as per 20 AAC 25.030. A wellbore schematic is also attached, visually depicting the proposed well and completion design. 6) The drilling fluid program, in addition to the requirements of 20 AAC 25.033 are attached. 7) A copy of the proposed drilling program is attached. 8) Based on offset well information, ExxonMobil does not anticipate the presence of H2S in the formation to be encountered in this well. 9) The following are ExxonMobil's designated contacts for reporting responsibilities to the Commission: 1) Completion Report (20 AAC 25.070) Bill Penrose, Fairweather E&P Services, Inc. (907) 258-3446 2) Geologic Data and Logs Bill Penrose, Fairweather E&P Services, Inc. (20 AAC 25.071) (907) 258-3446 If you have any questions or require additional information, please contact D. Michael Barker at (907) 564-3691or Bill Penrose at (907) 258-3446. Sincerely, /AJttMa:cBhPments c:~data\wlnword~lmb\envlro~ttom~000 Permlttlng~AP, D letter,doc C: D. Michael Barker, ExxonMobil Riki Lebman, JPO/DGC Jesse Mohrbacher, Fairweather Bill Penrose, Fairweather Jack Rickner, ExxonMobil Al Robb III, ExxonMobil proposed rule, Alaska State A-2 DIO Subject: proposed rule, Alaska State A-2 DIO Date: Tue, 19 Dec 2000 16:03:19-0900 From: Wendy Mahan <Wendy_Mahan~admin.state.ak.us> Organization: doa-aogcc To: dmbarke~upstream.xomcorp.com CC: Robert P Crandall <bob_crandall~admin.state.ak.us> Mike, This is the currently proposed surveillance role for the DIO. Please review and let us know if you have problems with any of the requirements. Thanks, Wendy Rule 5 Surveillance Prior to initiating disposal operations and after an inactive period greater than 3 months, a step rate injection test meeting the Commissions criteria must be conducted and a static temperature survey must be obtained. During disposal, operating parameters must be monitored and evaluated continuously. Monitored parameters should include disposal rate, surface pressure, annulus pressure solid waste volume processed, slurry, water flush, and freeze protection volumes pumped, slm~ density, viscosity, and temperature. Parameters must be recorded continuously as practicable and tabulated daily. During disposal, the operator must submit the original charts or legible copies and daily tabulations on a weekly basis. When operational parameters indicate additional surveillance is prudent, subsequent step rate injection tests and static temperature surveys will be obtained and the Commission notified. At the completion of injection operations, or annually if the operation extends beyond one year, a report evaluating the performance of the disposal operation and summary of surveillance activity and results must be submitted by July 1. 1 of 1 12/20/00 11:01 AM ]940 A~CI,C Boulevaul Su,le. 3OD Aritho, age.. Alaska ~907) 273 1700 Fax (907) 5BI .$317 Schlumberger August28,2000 Mr. Jesse Mohrbacher Fairweather E&P Services 715 L Street Anchorage, AK 99501-3335 Dear Jesse: The following is a Spontaneous Potential (SP)interpretation report as requested by you. The SP log for Exxon Company, USA well #1 Alaska State "A' was evaluated to identify the salinity of the formation water at depths from 2150 ft to 2375 ft. The interpreted results are based on information obtained from the Dual Induction - Laterolog run 5 field print (date 9-5-75) provided by the client. Well Information: Company: . Well: Field: County: Sl~ate: Location: APl Number: Field Print: Exxon Company, USA #1 Alaska State 'A" Wildcat North Slope Alaska 2982 ft FEL & 1549 ft FSL, Section 27, Township, 10N Range 24E 089-200003-00 Dual Induction - Laterolog Depth of Interest 2150 ft to 2375 ft Interpretation Rrocedure: Identify SP deflection from shale baseline to clean, water filled sand Determine temperature at depth Determine Rmf at temperature Calculate'Rmfeq = 0.85 x Rmf Obtain Rmfeq/Rweq from chart SP 1 Obtain Rweq from chart SP 1 Convert Rweq to Rw using chart SP 2 Obtain NaCI concentration from chart GEN 9 Attached are charts SP 1, SP 2, and GEN 9. Disposal Injection Application 10 - 2 Calculations: Inputs SSP =-35MV Rmf = 1.3Dan @ 58°F Temp Reservoir = 58°F Calculations Rmfeq = 0.85xl .3 = 1.105~- tn Rmfeq = 3.1 Rweq Rweq = 0.33~-m Rw = 0.30D · m NaCl = 25,000 pprn The above calculations assume a temperature gradient of 1.8 °F/100 ft with a temperature of 79 °F at 3379 ft based on the Dual Induction - Laterolog heading. In addition, the calculated salinity assumes the dissolved solids in the formation water are NaCI. If you have any questions regarding the above.calculations, please feel free to call me at (907)273-1771. Sincerely, Douglas Hupp, P.E. Senior Log Analyst Reservoir Management- GeoQuest Disposal Injection Application 10 - 3 Resistivity of NaCI Soluti .,s Gen-9 Conversion approximated by R2 = R~ [(T~ + 6.77)/(T2 + 6.77)]°F or R2 = R~ [(T~ + 21.5)/(T2 + 21.5)]°C 10 8 6 5 4 1 0.8 0.6 0.5 0.4 0.3 0.2 0.1 0.08 0.06 0.05 . . . 0.O4 '" E ~Ooo~ lO 25 ~ 40 _ 50 0.03 0.02 0.01 °F 5O °C 10 I I I I I I I 75 100 125 150 200 250 300 350 400 20 30 40 50 60 70 80 90100 120 140 160 180200 I I I I I I I I I I I ! I I I I J Temperature (°F or °C) Disposal Injection Application 1500 2000 _ 2500 _ 3000 ' -- 4000 _ 5000 -- - ~o,ooe _- :_,.. 15.ooo :_. 20.0oo 10 -6 ii iiii ,,1 , i iiiii ,, Rweq Determination from EssP clean formations SP-1 This chart and homograph calculate the equivalent forma- tion water resistivity, R,,,¢q, from the static spontaneous potential, EssP, measurement in clean formations. Enter the nomo~aph with EssP in mY, turning through the reservoir temperature in °F or °C to define the Rmfeq/Rwcq ratio. From this value, pass through the Rmteq value to define R~,,~. For predominantly NaCI muds, determine Rmfcq as follows: a. If Rmt' at 75°F (24°C) is greater than 0.1 ohm-m, correct Rmf to formation temperature using Chart Gen-9, and use Rm£eq = 0.85 Rmf. b. If Rmf at 75°F (24°C) is less than 0. I ohm-m, use Chart SP-2 to derive a value of Rmf,~ at formation temperature. Exumple: SSP = 100 mV at 250°F Rmf = 0.70 ohm-m at 100°F or 0.33 ohm-m at 250°F Therefore, Rmfeq = 0.85 X 0.33 = 0.28 otun-m at 250°F R,,,o4 = 0.025 ohm-m at 250°F EssP = -Kc log (Rmfm/R,,,,:q) Kc = 61 + 0.133 TOE Kc = 65 + 0.24 Toc 0.3 0.4 0.5 0.6 0.8 1 4 5 6 8 10 20 30 40 5O Rmfeq/Rweq 0.3 ~l. , -. .t -. x~A.X\N-. : ' - ,:, . ! - ,..~:_q..~%_" .~: .... -.~ : ~,_. , ', ~,' .:..:.: ' ' I ~'-_.~-~ ~,....~.~ .~..~.~., ,, - .- . ., :. . .~_'~=~,.~__: ,--~_--~ ' :' ' ~.. '',x~ x,:k,,~ · ' .: ' - . _--__iZ- ,.,.,,,,i.._~._xt,,~ x:,~ :..~_ : - .2. t,' : ~, , ~ ' - ', .. ' ' .-¥~,:h--_ _ __ ' I. ; "-- ~0;: ' ' ' '::-':-: ..... Formation :.-_z_---:::-_--'t~ ~o~'oo~__ :~ ~-..':_---~_~---- temperature :~ 0.4 0.6 0.8 1 2 4 6 8 10 20 40 +50 0 -50 -100 -150 -200 EssP, static spontaneous potential (mY) Rmleq (ohm-m) ~'<u~'~t~'~Disposal Injection Application 0.01 0.02 0.04 0.06 0.1 0.2 0.4 0.6 1 4 6 10 20 4O 6O 100 · Rv~q (ohm-m) _ 0.001 [. o.oo$ 0.01 0.02 0.05 0.1 0.2 0,5 ¸ 2.0 10 -4 Rw versus Rweq and Formation Temperature SP-2 (English) c 0.001 . · [ .'~.~ 400°F ~ 300°F ...... !,\\..\..~.'x ,ooo~ i "'~"i ' i': ~"~"~'~: ' :' ~'~'~ 75°F ration :'- "' ...... ................. , : .......................... " .... ~ N,.,..~,.~-',- ...,.. _.~,., .~. _ , . . ,~, .,,,:..,t,. ,,, --~ ~ _ -- ~ ..................................... t ..................... :'~ ~ ""~ .... ~- ~ ...... ~ ..................................... L ........................... ~,."~ .:'~,~2.~..~:. "~,~.~..j _'~...~._~JOo,c.,, · -- .............................................. ' 'N"':. ',.- -'~--'"'~--_~ '- ~Ono, c. '- .......................... .___::____ ....... _ . ~ q~~.:~....× __~~~ ............................................. ._ , .............. .,. x'-..~_~-__.,___~o~o .: : · ' I" '" ',: ' ' t"~ '-3~~'. :,,, ,, , ,,,,,, , , , , , , , , , ,,,,,,'' 0.002 0.005 0.01 0.02 0.05 0.1 0.2 0.5 1.0 2.0 0.005 0.01 0.02 0.03 0.05 0.1 0.2 0.3 0.5 1.0 2 3 4 5 Rw or Rmf (ohm-m) These charts convert equivalent water resistivity, R,,,m, from Chart SP-1 to actual water resistivity, R~,. They may also be used to convert Rmf to Rmf~q in saline muds. Use the solid lines for predominantly NaCI waters. The dashed lines are approximate for "average" fresh formation waters (where effects of salts other than NaCl become signifi- cant). The dashed portions may also be used for gyp-base mud filtrates. Example: Rweq = 0.025 ohm-m at 120°C From chart, R~, = 0.031 ohm-m at 120°C Special procedhres for muds containing Ca or Mg in solution are discussed in Reference 3. Lime-base mUds usually have a 'negligible amount of Ca in solution; they may be treated as regular mud types. Disposal Injection Application 10 - 5 FORM NO. 173-0063B SETTLEMENT OF ACCOUNT THE ATTACHED CHECK IS IN FULL PAYMENT FOR THE ITEMS SHOWN BELOW AND CONSTITUTES RECEIPT E)~,ON COMPANY, U.S.A. A DIVISION OF EXXON CORPORATION ALASKA INTEREST ORGANIZATION AGENT ACCOUNT DESCRIPTION State of Alaska, Dept. of Revenue Permitting AppliCation Fee Flaxman Island Remediation Project 2000 Permitting Fees PAY TO TH E ORDER OF E)~ON COMPANY, U.S.A. A DIVISION OF EXXON CORPORATION ANCHORAGE, ALASKA September 6, 2000 89-75 1252 CHECK NUMBER 10200 100.00 $ , , · State of Alaska Department of Revenue · 550 West 7th Avenue,'Suite 570 Anchorage, AK 99501-3555 THE FIRST NATIONAL BANK OF ANCHORAGE, ALASKA "'0 ;,0 20.0,' ALASKA INTEREST ORGANIZATION AGENT ACCOUNT WELL PERMIT CHECKLIST... ,~COIVI_P._A~Y ,~",xLx:z~4.,/,/~/~~,/_.. WELL NAME. ,,~- ~.. PROGRAM: exp FIELD&POOL /1//~Z~. ~~N~-T'(~LAS~ ,.~'~:'~1/'/~..~'- '~~/---. GEOLAREA ADMINISTRATION o 2. 3. 4. 5. 6. . 8. g. 10. 11. DATE 12. //, z:~,, ~-~ 13. ENGINEERING 14. ./ dev reddl serv ',/ wellbore sag ann. disposal para req ,- ~-~~ UNIT# .... ~4~,~ ON/OFFSHORE Permit fee attached ....................... ~ N Lease number appropriate ................... ~)~L~ .~~ ~ /~~ Unique well name and'number .................. /,v~,~/ ~ '~_.~ .<:,~-.~ ~/'~ .. Well located in a defined pool .................. Well located proper distance from drilling unit boundary .... ,-, , ..... ,- , ., , ~ ,_,- 9_..,' x .... Well located proper distance from other wells .......... .,~._.Y-~ N '/~'~-'~ ..eS..~.~.~ ,~.,~_..Z(/.'y[~,~- -,~.¢'~. ~-! /~,~=~'w~ ~ -/~ r,~:- ~.>~, ~/.~.~~, Sufficient acreage available in drilling unit ............ ,,,z'/~ Y N ,,.c, .... , If deviated, is wellbore plat included.-:~ ............. ,~V",~ Y- NN ~ V",z-r"~c.~l' ~-.-~ll'.:' t~/',,,,~'/'7,~'~' .5'~,"~,~--~....,/ /.,.~,.,~-<.~.[_..) ~ ~,,'~n'f~ Operator only affected party ................... Operator has appropriate bond in force ............. Permit can be issued without conservation order ........ Permit can be issued without administrative approval ...... Can permit be approved before 15-day wait ........... Conductor string provided ................... 15. Surface casing protects all known USDWs ........... 16. CMT vol adequate to circulate on conductor & surf csg ..... 17. CMT vol adequate to tie-in long string to surf csg ........ 18. CMT will cover all known productive horizons .......... 19. Casing designs adequate for C, T, B & permafrost ....... 20. Adequate tankage or reserve pit ................. 21. If a re-drill, has a 10-403 for abandonment been approved... 22. Adequate wellbore separation proposed ............. 23. If diverter required, does it meet regulations .......... 24. Drilling fluid program schematic & equip list adequate ..... 25. BOPEs, do they meet regulation ................ 26. BOPE press rating appropriate; test to psig. 27. Choke manifold complies w/APl RP-53 (May 84) ........ 28. Work will occur without operation shutdown ........... 29. Is presence of H2S gas probable ................. GEOLOGY 30. Permit can be issued w/o hydrogen sulfide measures ..... ~ 31 Data presented on potential overpressure zones · . . . · .... .. · 32. Se,sm,c analys,s of shallow gas zones ............. AP~R DATE 33. Seabed condition survey (if off-shore) ....... ' ...... ~ /'('. Z? -~,D 34. Contact name/phone for weekly progress reports [exploratory only~Y-'~N I ANNULAR DISPOSAL35 With proper cementing records, this plan ~ ~ iA) will contain waste in a suitable receiving zone; ....... APPR DATE (B). will not contaminate freshwater; or cause drilling waste... to surface; (C) will not impair mechanical integrity of the well used for disposal; (D) will not damage producing formation or impair recovery from a pool; and (E) will not circumvent 20/LAC 25.252 or 20 AAC 25.412. GEOLOGY: ENGINEERING: UIC/Annular COMMISSION: c:\msoffiCe\wordian\diana\checklist (rev. 02117/00) · *~"~,.¢/. , Comments/Instructions: , ,~ .~ ~,/,.. Cl rll "I;
