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Home My WebLink About180-100 Irna ect Well History File Cover t~le XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be Scanned during a special rescan activity or are viewable by direct inspection of the file. J ~ ~)- / ~ ~ Well History File Identifier RESCAN DIGITAL DATA OVERSIZED (Scannable) [] Color items: [] Diskettes, No. [] Maps: [] Grayscale items: [] Other, No/Type ~ Other items scannable by large scanner [] Poor Quality Originals: OVERSIZED (Non-Scannable) [] Other: ~ Logs of various kinds NOTES: / \ D Other BY: BEVERLY ROBIN VINCENT SHERY~A~A WINDY DATE; ¢,/~,~C~./S/ ~/~p Project Proofing BY: ~OBIN VINCENT SHERYL MARIA WINDY Scanning Preparation BY: ~OBIN VINCENT SHERYL MARIA WINDY Production Scanning Stage 1 BY: Stage 2 BY: (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION 18 REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY. GRAY$CALE OR COLOR IMAGES ) PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: BEVERLY ROBIN VINCENT(~MARIA WINDY DATE//~ 7,~.~ IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: YES NO BEVERLY~VINCENT SHERYL MARIA WINDYDATE:)-(~-~.~ III IIIIIIIIIII II Ill RESCANNEDBY: BEVERLY ROBIN VINCENT SHERYL MARIA WINDY DATE: Isl General Notes or Comments about this file: Quality Checked (do.e) 12110/02Rev3NOTScanned.wpd Memorandum State of Alaska Oil and Gas Conservation Commission To: Well File: ~ -- ~)t/,~) DATE Cancelled or Expired Permit Action EXAMPLE: Point McIntyre P2-36AXX API# 029-22801-95 This memo will remain at the front of the subject well file. Our adopted conventions for assigning APl numbers, permit numbers and well names did not specifically address expired or canoelled permits. This omission has caused some inconsistencies in the treatment of these kinds of applications for permit to drill. Operators have asked us to adopt formal procedures for this class of permit application in order to prevent future database disparities. If a permit expires or is cancelled by an operator, the permit number of the subject permit will remain unchanged. The APl number and in some instances the well name reflect the number of preexisting reddlls and or muitilaterals in a well. In order to prevent confusing a cancelled or expired permit with an active well or multilateral these case sensitive well identifiers will be changed for expired and cancelled applications for permits to ddil. The APl number for this cancelled or expired permit is modified so the eleven and twelfth digits is 95. The well name for a cancelled or expired permit is modified with an appended xx. These procedures are an addendum to the APl numbering methods described in AOGCC staff memorandum "Multi-lateral (weiibore segment) Ddiling Permit Procedures, revised December 29, 1995. AOGCC database has been changed to reflect these changes to this permit. Statistical Technician E ON COMPANY, U.S.A. POUCH 6601 · ANCHORAGE, ALASKA 99502 EXPLORATION DEPARTMENT ALASKA/PACIFIC DIVISION March 17, 1981 Re: Pt. Thomson Unit No. 6 Permit No. 80-100 _ j_~STA Surf: Sec. 36, T10N-R22E, U~$TA ADL 47561 BH: Sec. 30, T10N-R22E, UM ~Co~ ADL 51667 ~ Arctic Slope, Alaska Mr. Hoyle H. Hamilton, Chairman Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Hamilton: Circumstances have occurred which require that Exxon defer for the present the plans to commence operations on the above oil and gas lease as outlined in our letter of application to you of August 29, 1980. As we are unable to state at this time the precise details regarding a resumption of plans for such operations, we are by this letter withdrawing the application for the permit to drill the subject well and will refile such application at a future date when we are in a better position to do so. We sincerely regret any inconvenience this change in plans may have caused you or your staff. Yours very truly, Robert K. Riddle RKR: et c: EPA Region Ten, Attn: Danford G. Bodien, P.E. A DIVISION OF EXXON CORPORATION COMPANY, U.S.A. POUCH 6601·ANCHORAGE, ALASKA 99502 EXPLORATION DEPARTMENT ALASKA/PACIFIC DIVISION March 17, 1981 'Re: Pt' Thomson Unit No. 6 LO/NS: 80-225 Surf: Sec. 36, T10N-R22E, UM ADL 47561 BH: Sec. 30, T10N-R22E, UM ADL 51667 Arctic Slope, Alaska Mr. Glenn Harrison, Director Division of Minerals and Energy Mgmt. 703 West Northern Lights Blvd. Anchorage, Alaska 99503 Dear Mr. Harrison: . Circumstances have occurred which require that Exxon ~efer for the present the plans to commence operations on the above oil and gas lease as outlined in our letter of application to you of August 19, 1980. As we are unabl~ to state at this time the precise details regarding a resumption of plans fbr such operations, we are by this letter withdrawing the application for the respective approvals issued by your office for this activity and will refile such application at a future date when we are in a better position to do so. We sincerely regret any inconvenience this change in ~lans may have caused you or your staff. Yours very truly, RKR :et c: EPA Region Ten, Attn: Danford G. Bodien, P.E. AOGCC, Attn: Hoyle H. Hamilton ADEC, Attn: Douglas Lowery DFLWM, Attn: William Copeland DF&G, Attn: J. Scott Grundy ECEIVED MAR 2 o 1 81 Alaska 0il & Gas Cons. Co~rnissio~ Anchorage A DIVISION OF EXXON CORPORATION November 14, 1980 Mr. A. R. Herman Division Drilling Manager Exxon Corporation P, O. Box 2180 HOUStOn, Texas 77001 Ret Point Thomson Unit Exxon No. 6 Exxon Corporation Permit No. 80-100 Sur. Loc.= 121fSNL, 1584~WEL, Sec 36, T10N, R22E ~. Bottomhole Loc.= 700~EWL, 800~SNL, Sec '30, T10N, R23E, UM. Dear Mr. Hermann= Enclosed is the approved application for permit to drill the above referenced well. Well samples and a mud log are required. A directional survey is required. If available, a taPe containing the digitized log information sba11 be submitted on al! logs for copying except experimental logs, velocity surveys and dipmeter surveys. Many rivers in Alaska and their drainage systems have been classified as important rorer he spawning or migration of anadromous fish. Operations in these areas are subject to AS 16,50,870 and the regulations promulgated thereunder (Title 5, ~Alaska Administrative Code}. Prior to commencing operations y~ may be contacted by the Habitat Coordinator's office, Department of Fish and Game. Pollution of any waters of the State is prohibited by AS 46, Chapter 3, Article 7 and the regulations promulgated thereunder {Title 18, Alaska Administrative Code, Chapter 70) and by the Federal Water Pollution Control Act, as amended. Prior to Mr. A. R. Hermann -2- Point Thomson Unit Exxon No. 6 November 14, 1980 commencing operations you may be contacted by a' representative of the Department of Environmental Conservation. Pursuant to AS 38.40, Local Hire Under State Leases, the Alaska Department of Labor is being notified of the issuance of this permit to drill. TO aid us in scheduling field work, we would appreciate your notifying this office within 48 hours after the well is spudded. We would also like to be notified so that a repre- sentative of the commission may be present to witness testing of blowout preventer equipment before surface casing shoe is drilled. In the event of suspension or abandonment, please give this office adequate advance notification so that we may have a witness present. Very truly yours, ~. t~a~il ton Alaska Oil & Gas Conservation commission Enclosure cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o/eno1. Department of Labor; Supervisor, Labor Law Compliance Division w/o eno1. E ON COMPANY, U.S.A. POUCH 6601 · ANCHORAGE, ALASKA 99502 EXPLORATION DEPARTMENT OFFSHORE/ALASKA DIVISION October 24, 1980 Request for Variance to Regulation 20AAC 25.035(C)(2) Mr. Hoyle H. Hamilton, Chairman State of Alaska , Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Hamilton: In letters dated August 29, 1980, Exxon filed applications for permits to drill the following Arctic Slope wells: Pint Thomson U~it__No._~,~ ~2) alaska' ~ta~e ..... "bi; N0~-. 3) Alaska State "E" No. 1 As stated in the permit applications, Exxon plans to use a 13-5/8" inch 5000 psi working pressure annular BOP as part of the blowout preventer system whose other components are rated for 10,000 psi. Although this is in accord with widely accepted safe industry practice and with American Petroleum Institute guidlines, it is in technical' violation of Miscel- laneous Boards, Commission regulation 20 AAC 25.035 at para- graph (C) (2). Exxon requests a variance to this regulation~_~ allow use of the 5000 psi WP annular preventer on these~our3wells A full discussion of the technical aspects of--o~'~ position was recently submitted to you in the form of a letter requesting revision of the subject regulation. This letter is included as an attachment for your reference in considering this request. RAM: jrh 240-500-200 A DIVISION OF EXXON CORPORATION Very truly yours, Robert K. Riddle COMPANY,' U. S.A. POUCH 6601 ' ANCHORAGE. ALASKA 99502 (907) 276~4552 COPY ALA.SKA OPE RA'rlONS WES'fERN DIVI,SION W MO~'III. TAYLC)I~ September 23, 1980 State of Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Gentlemen: Exxon requests revision of the recent]_y enacted Miscellaneous Boards, Commissions regulation 20 AAC 25.035 Blowout Prevention Equipment which at paragraph (c) (2) requires, in part, "the working pressure of any BOP and associated equipment must exceed the maximum surface pressure to which they may be ~subjected;..." On the surface, this appears to be an entirely reasonable requirement and little or no comment was raised during the review period prior to enactment. Careful consideration now reveals that the requirement is contrary to existing prudent drilling practice since "any BOP" includes the annular preventer whose working pressure might be required to exceed 5,000 psi depending upon interpretation of the undefined term "maximum surface pressure" and the unclear wording "to which they may be subjected." Current safe BOP selection practice for drilling higher pressure wells entails selection of ram-type preventers with a working pressure exceeding the anticipated surface pressure for any casing on which they are installed ~and selection of the annular preventer to exceed the anticipated surface pressure which would be ~encountered in well control operations. The intended use of the annular preventer is to provide initial Closure on any part of a drill string at relati, vely low pressure, in the event of a well kick, to permit the operator to analyze the problem. The operatOr would then proceed with well control operations using -the ~am-type preventers and/or the annular preventer depending on pressures and thc condition of the well. With current technology in equipment., abnormal pressure detection-and well control training, the initial pressure will normally not exceed 1,000 to 2,000 psi, and if well control procedures result in pressures in excess of 2,000 to '2,500 psi, prudent operating practice is to conduct the well control operation using the ram-type preventers thus effectively isolating the annular preven'ter from the higher pressure. That is to say, the annular preventer would not' be subjected to pressures exceeding 5,000 psi. ~ A DIV1SlOI'I OF EXXON CORPORATION State of Alaska .. September 23, l.( 0 ( Page 2 ': There have been no documented operational instances where an annular preventer having a working pressure greater than 5,000 psi wou].d have prevented a blowout, yet literal interpretation of the subject regulation could result in the requirement for such a Preventer.. . By design and operational usage, an annular preventer · s intended to provide for a limited range of functions under ]ow to moderate pressure, i.e. , ].ess than 5,000 psi. A regulatory requirement for a greater than 5,000 psi working pressure annular preventer distorts the purpose and operational usage of the annular preventer, potentially 'jeopardizing well control and safety under high pressures. Moreover, it is projected that several years would be required to design, shop test, and opera- tionally validate the reliability of 10,000 psi. annular pre- venters of the 16-3/4 inch or 18-5/8 'inch sizes required -in some drilling programs. This regulation could limit the availability of rigs for scheduled exploration drilling programs, require use of prototype equipme'nt during well control operations-, and result in no tangible advancement in technology or increased safety. Attached for your review is a general discussion of' blowout preventer equipment and the use Of preventers in"well control. In view of the problems discussed above, Exxon requests that 20 AAC 25.035(c) (2) be revised as follows: "the working pressure of any ram- type BOP and associated equipment must exceed the anticipated surface pressu~-e of any casing string on which it ~.s to be used and the working pressure of any annular BOP must exceed the pressure to which it may be subjected in well control operations; infor- mation submitted with' Form 10-401 must include anticJ, pated formation pressures to be encountered, the anticipated surface pressure for each casing string, antici, pated pres- sures to which the annular preventer may be subected in well control operations, and the criteria used to determine these pressures consistent with 20 AAC 25. 030 Casing and Cementing; ,: We believe the above requirement more clearly states the estab- lished criteria for selection of BOP equipment and will allow for the differing methods of program design now used by industry. Although we realize that your decision must be based on the -merits 'of the case, we would like to point out a recent precedent involving a USGS OCS regulation. This was a BOP requirement essentially identical to 20 AAC 25.035 (c) (2.) which was rev;ised along the lines proposed. Your consideration of this proposed revision is respectfully requested. T LP/RAM/kb Attachment 28-Z Yours very truly, ./"7~f/ ".,,~,, W. Monte Taylor GENERAL DESCRIPTION OF BLOWOUT PREVENTER EQUIPMENT AND USAGE A blowout'preventer (BOP) system consists of several engineering designed components that can be systematically operated in the event of unexpected flow from a well. The BOP system is used initially to close a well in, and thereafter to hold back pressure on the wellbore, while circulating a mud weight of sufficient hydrostatic pressure under controlled conditions to overcome the influx. Figure 1 is a schematic of a BOP system, commonly referred to as a BOP stack. The basic components are similar:, a wellhead connection to the previously set and cemented casing strings; pipe ram preventers; blind ram; an annular preventer; and a system of lines and valves to direct fluid into or out of the BOP when various components of the system are functioned for well control operations. The number and position of the pipe rams and blind ram may vary with particular requirements of a given well, the operator's well[, control procedures, and to some extent., on the complexity of the BOP system. The size, shape and control of the BOP system are specifically designed for a partJ, cular rig.. Major changes to a BOP stack often involve changes in handling procedUres andlauxilia, ry. rig equipment. The pipe rams, blind ram, and annular preventers are designed and used primarily for closing and sealing functions. They also have features that provide for redundancy and .secondary functions. Figure 2 is a schematic of the primary sealing method of t:he pipe rams, blind ram, and annular preventer. Pipe rams are semicircular concave' faced .components having primary sealing surfaces designed 'to match the outside diameter of the particular pipe in use. Blind rams are solid faced com- ponents, with elastic and metal sealing surfaces for closure and sealing with nothing opposite the ram. Some blind rams are equipped with pipe shearing-blades which can close, shear, and effect a seal. The rams are opened and closed by positive con- trolled: operating fluid applied to the ram piston. The annular preventer is equipp':ed with a large ring of elastic sealing material (rubber or neoprene) designed to close on open hole or around any size or shape pipe. The primary closing 'method is positive operating press'ute applied to a shaped pJ. ston resulting in a "squeezing out" effect of the elastic element. .Depending on the design of particular annular preventers, well- bore pressure from below may also act on the piston to "pressure assist" the squeezing of the element. The primary opening con- trol method is positive operating pressure applied to ti_he shaped piston to reverse its travel and allow, the element to relax to its normal configuration. The significance of the designed oper- ational features of the annular preventer is discussed below. OPERATIONS During normal drilling operations, control of the well is main- tained by using adequate hydrostatic pressure from the mud column in the wellbore, monitoring of various drilling parameters, and through proper crew training. As stated previously, the blowout preventer system allows for closing in a well when unexpected flow occurs. The BOP unit is intended to provide the operator with a series of alternative operational functions, by use of the individual components, to control the influx by circulating fluid in the wel]bore. The control of the wellbore depends on properly designed equipment, prudent, operation of the equipment, and proper training of personnel performing the task. Pipe rams are considered the primary means of sealing around drill pipe and the .blind rams for sealing on open hole. Recog- nizing the adverse mechanical effect that could occur if the pipe rams were closed on other than their designed pipe size or if the blind rams were closed on other than open hole, .the annular preventer was designed to allow initial closing around irregular sizes and shapes. It is, therefore, generally the first preventer to be closed in an emergency. Well control can then be trans- itioned in an orderly .fashion to the primary pipe rams for long term sealing and operational Control. ~ Figure 3 is the closing-in procedure employed by Exxon. It is similar to the procedure used by any prudent drilling operator. Figure 4 represents calculations of various conditions of gas infux that would have to occur prior to closing the annular preventer in order for it to be subjected to initial pressure greater than 5,'000 psi. With operators and crews trained for abnormal pressure detection and we].] control in accordance with current standards, the likeli, hood of unexpected flow of the intensity and volume reflected by the example is extremely remote. For example, the pit volume increase alarm normally would have a sensitivity of 10 bbl or less. Respo'nse time for a trained drilling crew to check the well for flow and properly close the annular preventer, is two min. or less. Assuming influx rate equivalent to 20,000 bbl per day, the total, influx prior to shut in would be 38 bbl, which is much ].ess than the va].ues shown 'in Figure 4. Ac.cordingly, the annular preventer .would not be subjected to initial, closed-in pressures greater than 5,000 psi. After close-in, if the operator reasonably_ an? ticipates surface_pressures exceeding about 2.,500 P_s_i._, ..... _t_'j!_e__P~i.~_!?__e_ · rams are routinely used for primary s_.ga!__ing and control.l"unction- lng of either of the pipe rams or blind rams will J. solate the annular preventer from any subseque_.ljt,high well pressures th~'~'~- might occur during control operations. A secondary feature designed for and operationally engineered into the use of a blowout preventer system (the primary function is again to provide sealing) is the ability of moving pipe into or out of the wellbore under pressure. This procedure, called "stripping", is not a common occurrence during well control but is a desirable alternative to have available under some circumstances. It can be safely handled with existing components of the BOP system and trained crews. In some situations, strip- ping can be performed with the pipe rams or with the annular preventer or with a combination of the preventers. Due to its infrequent occurrence, the stripping procedure is generally employed only after considerable forethought and planning. Figure 5 shows a fundamental calculation to determine if strip- ping is a viable alternative. If there is an insuffJci.ent down- ward force (from the weight of the pipe already in the hole) to overcome the upward force generated by the unexpected influx, stripping cannot be performed and snubbing operations become the alternative. This is a less frequent occurrence and special, ty companies and equipment are necessary to perform the procedure. If stripping is a viable and necessary option, a historical preference, under low wellbore pressUre, has been to str:ip with the annular preventer. This procedure is somewhat less com- plicated, under low pressures, and reduces the possibility of damage to the primary sealing ram preventers that wOuld be used for subsequent control operations 'once stripping has been com- pleted. A generalized discussion of stripping with an annular 'preventer is presented in this paragraph. Recall that the annular pre- venter has a ring of elastic material, squeezed by a shaped piston upon application of pressure from the control accumulator and/or by we.llbore pressure assist. The higher the well pressure, the tighter the element ~s squeezed to mainta'Jn a pressure seal. As pipe is moved through the annular preventer, friction from the pipe body and the passage of the larger OD pipe 'tool joints causes wear of the element. The higher the wellbore pressure and the required closing pressure, the greater the wear. The greater the wear, the greater, the closing pressure must be to maintain a seal. For the annular preventer designed with well pressure assisting hydraulic closing pressure, the closing pressure can be rectuced to mini. mize friction (and thus wear) between the element and the .pipe and tool joint. At relatively, high wellbore pressures (2,000 to 2,500 psi), the hydraulic closing pressure can no longer be reduced sufficiently to prevent excessive wear due to pipe movement: through the element. Depending on the size of the annular preventer and pipe in use, o_penin_g_ pressure instead of closing presSure would have to be applied to the preventer to avoid excessive element friction and wear. Applying opening pressure i's considered to be an extremely hazardous procedure since a fluctuation in well pressure could allow the preventer to suddenly open. Even if the pipe rams were immediately closed, 3 uncontrol]_ed flow could jeopardize rig and crew safety. It.would be a matter of chance at this time whether a tool joint were opposite the closing pipe ram thus damaging it beyond subsequent sealing capability. For the annular preventer designed without wellbore assist, increasingly higher hydraulic closing pressures are required' to maintain the seal at higher and higher well pressures. Figure 6 'shows results of shop tests of the wear on an element (stripping cycles to failure) relative to increasing wellbore pressure and the resulting increase in closing pressure. Note the drastic reduction in element life when well pressure is increased from ].,500 to 3,000 psi. While the results of the tests may vary somewhat among preventers, the size pipe used or the type of element installed, it is Exxon's position that. the test: is strongly indicative of the results that will be obtained at higher well pressures. In other words, the stripping wear life of an annular preventer is greatly reduced at. increased we]lbore pressures. Of equal significance is the need for t~he element to maintain its sealing capability when repeated].y moving' the smaller diameter pipe body, then the larger d~ameter too]. joint and then the smaller diameter pipe body again through t'he pre- venter. The element's ability to maintain a seal under this procedure is related to the amount of wear and pressure to whi. ch · it is subjected. Although a provision is available for "slightly" reducing the amount of cloSing force on the element as the tool joint starts through, the opening and closing sequences of an annular preventer are not totally positive. Tills is due to the larger sealing and piston areas involved, the amour~t of probable wear, and the relatively large fluid Operating volumes. For these reasons, it is Exxon's normal policy not to attempt stripping operations using an annu.[ar preventer, _regard] ess of its pressure rating., when well pressure exceeds 2,000 t~-'"'2-~-~00 psi. Our pract i ce is supported by the experience of Otis Engineering Corporation's worldwide stripping and snubbing oper- ations. Otis' views on the subject are reflected in their letter of February 11, 1980, Figure 7. Supporting documentation can also be found in API Recommended Practices for Bl_owout. PreVention Equipment Syst'.ems RP53 Page i4, Figure 8. Preventer sysl:.em arrangements £or 5,000, ]0,000, and 15,000 psi pressure ratings may utilize annular preventers rat:ed for 5,000 psi. In summary, by design and operational usage, an annular preventer .is intended t:.o provide for a limited range of functions under l. ow to moderat, e pressure, i.e. , [ess than 5,000 psi. A ~-egu'l. atory requirement for a great:er than 5,000 psi work. Jng pressure annu];~r preventer d-istc>rt$ the purpose and operational usage o[' the annular prevent;er, p.ot:ent:ially jeopardizing well. control and safety under high pressures. Morc,.over, it is projected that several years would be required to design, shop test,, and oper- ationally validate the reliability of 10,000 psi annu].ar pre- venters of the 16-3/4 inch or ]8-5/8 inch sizes required in some drilling programs. Th'is regulation could 1. imit the availability of rigs for scheduled exploration drilling Programs, require rise of prototype equ~t)ment during well control operations, and result in no tangible advancement in technology or increased safety. TLP/RAM/rms 211-A TYPICAl(" BLOWOUT PREVE N,.='E R STACK CHOKE L NE Iv BELL NIPPLE ANNULAR PIPE RAM I [ BLIND RAM PIPE RAM ! i KILL LINE WELLHEAD FIGURE I PI PE RAM BLIND RAM ANNULAR OPERATING PISTON PIPE RAM SEAL:lNG ELEMENT /.~__ OPENING FLUID FLUID .. OPERATING ' PISTON BLIND RAM SEALING ELEMENT OPENING -- F FLUID L CLOSING FLUID ELASTIC SEALING ELEMENT CLOSING/-1, ~~_CLOSI NG CHAMBETM ] -- PR EVENTER BODY FIGURE 2_ LAND, PLATFORM & JACK-UP OPER~T10~ FULL BOP STACK ON COMPETENT CA~NG CLOSING-IN PROCEDURE rF ANY OF THE FOLLOWING OCCUR' , 1. HOLE NOT TAKING CORRECT AMOUNT OF MUD ON TRIP. 2 GAIN lin PIT VOLUME. 3 INCREASE FLOY~ ACROSS SHALE-,~HAKER. 4 D~ILLING BREAK. ,5 INCRE/kSE OR DECREASE IN PUMP PRESSURE. 6. GAS CLrl' MUD OR CHLORIDE INCREASE. I 1. PICK UP KELLY FEET UNTIL TOOL JOINT CLEARS ROTARY TA'BLE. (P~/o.r ~j3ec~,-out ~'~ou~ hav~ b~J,~ ~ to 2. SHUT DOWN MUD P~PS. 3 CHECK WELL FOR FL~ IS WELL FLOWING SHUT WELL IN AS FOLLOWS NOTIFY 5LtPER INTENDENT &,ND TOOL PUSHER IMMEDIATELY! OPEN CHOk~ LIIfE VALVE OIg BoP J CONTROL PANEL J ,, CLOSE ANNULAR BOP CLOSE CHOKES I RECORD SHUT-IN DP /JND CS~ PRES,S;LJRES, AND PIT LEVEL GAIN 1 CONTROL WELL AS DIRECTED RESUME OPERATIONS AS DIRECTED FIGURE 3 REQUIRED INFLUX FOR INITIAL WELL SHUT-IN PRESSURE TO EQUAL 5,000 PSI Well TD-Ft Barrels of Gas Influx Drilling With A With A Mud Wt-ppg .2 RPg Kick 4~ ppg Kick 13,000 10.0 389 242 . 15,000 12.0 293 156 17,000 14.0 227 98 ! WELLBORE CONFIGURATION 5 inch drill pipe 9-5/8 inch casing 540 ft., 6-1/2 inch drill collars 8-1/2 inch hole. Fi gure 4 LENGT-t?' OF PIPE THROUGH ANNULAR REQUIREB~0 FO. Vs WELL RE STRIP PRESSURE 16 14 12 I0 8 6 4 2 0 . .. OD.iD I 0 2 4 6 8 I0 WE'LL PRESSURE ---IO00psi IOpp9 MW YANCE) FIGURE 5 STRIPPING TEST RESULTS 18 3/'4" AND 16 3/4"- 5000 PSi ANNULAR 1500 CLOSING 1000 CHAMBER PRESSURE PSI 500 O0 PSI~WELL PRESSURE-----~1500 PSI 6 NATURAl. OR NI'TRILE ELEMENTS 3/8" TOOL JOINT ON 5~s DRILL PIPE 5OO STRIPPING 1OO0 CYCLES 1500 E) ON COMPANY, U.S.A. POUCH 6601 · ANCHORAGE, AI_ASKA 99502 EXPLORATION DEPARTMENT ALASKA/PACIFIC DIVISION Re: August 29, 1980 Exxon Point Thomson Unit No. 6 Surface: Sec 36, T10N, R22E, UM Bottom hole: Sec 30, T10N, R23E, UM Surface: ADL 47561 Bottom hole: ADL 51667 Arctic Slope, Alaska Permit No.: Mr. Hoyle H. Hamilton, Chairman Alaska Oil & Gas Conservation Commission State of Alaska 3001 Porcupine Drive Anchorage, Alaska 99504 Dear Mr. Hamilton: Exxon Corporation submits the following in regard to the captioned well: (1) State of Alaska, Oil & Gas Conservation~q_mmitt_a~Permit to Drill, Form 10-401, in triplicate with ~riplicate copies of the location plat and contingency plan. (2) Exxon Check No. 3492 dated August 29, 1980 in the amount of $100.00 in payment of the required permit fee. Concurrently with this application, we are filing with the State Division of Minerals and Energy Management the following: (1) A plan of operation describing the drilling pad, rig, supply, waste and sewage disposal, and pollution prevention. (2) Vicinity and location plats. Surface and bottom hole locations lie within the Point Thomson Unit; surface location being situated on lease ADL 47561 and bottom hole location within lease ADL 51667. It is our plan to construct the drill site during the winter of 1980-81 and to spud the well in March, 1981. Approximately seven months will be required for drilling and testing. Yours very truly, Robert K. Riddle RKR: e t attachments c: EPA Region X - Attn: Mr. Danford G. Bodien, P.E. U.S. Army Corps of Engineers - Attn: ColOnel Lee R. Nunn A DIVISION OF EXXON CORPORATION COMPANY, U.S.A. POUCH 6601 · ANCHORAGE, ALASKA 99502 EXPLORATION DEPARTMENT ALASKA/PACIFIC DIVISION August 19, 1980 Re: Exxon Point Thomson Unit No. 6 Surface: Sec 36, T10N, R22E, UM Bottom Hole: Sec 30, T10N, R23E, UM Surface: ADL 47561 Bottom Hole: ADL 51667 Arctic Slope, Alaska LO/NS: .Dr. Ross G. Schaff Acting Director Division of Minerals & Energy Mgmt. 703 West Northern Lights Blvd. Anchorage, Alaska 99503 Dear Dr. Schaff: Exxon Corporation filed an application with the Alaska Oil & Gas Conservation Commission for a permit to drill the subject well together with our check in the amount of $100.00 in payment of the required permit fee. It will be drilled as a directional side- track to a bottom hole location on lease ADL 51667. Additionally, and in accordance with the requirements of the subject oil and gas lease and applicable regulations, we submit the following: (1) A plan of operations describing the drilling pad, rig supply, water supply, waste and sewage disposal and pollution prevention. (2) Plats showing the loca. tion and vicinity of pad and (a) Survey plat (b) Area Operations maps: Exhibit A (.1) Scale 1"=2000' '" Exhibit B (2) Scale 1"=10,000' As stated herein it is our plan to construct the dr~lI the winter 1980-81, state and federal approval permitting, and to commence drilling operations in March 1981. Approximately seven months will be required for drilling and testing. The rig and camp will remain on location until ~he following winter. Yours very truly, Robert K. Riddle RKR:et c: EPA Region X - Mr. Danford G. Bodien, P.E.,Ak. Oil & Gas Conservation Commission - Hoyle H. Hamilton, U.S. Army Corps of Engineers - Colonel Lee R. Nunn A DIVISION OF EXXON CORPORATION Form 10-401 REV. 9-1-78 STATE OF ALASKA ALASKA O! L AND GAS CONSERVATION COMMISSION SUBMIT IN T ,ATE (Other instructions on reverse side) PERMIT TO DRILL OR DEEPEN Ia. TYPE OF WORK DRILL b. TYPE OF WELL OIL GAS 2. NAME OF OPERATOR OTHER DEEPEN [] SINGLE MULTIPLE 17--I ZONE F-l ZONE L..J' ~i :i; API #50-08q-20014 6. LEASE DESIGNATION AND SERIAL NO. ADL 47561(Surf)ADL 51667(BH 7. 1F INDIAN, ALLOTTEE OR TRIBE NAME 8., 'UNItlFd~ ~M OR LEASE NAME Point T~iomson Unit 9. WELL NO. Exxon No. 6 10. FIELD AND POOL, OR WILDCAT Wildcat 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) Exxon Corporation 3. ~DRESS OF OPERATOR P. O. Box '2180, Houston, Texas 77001 4. LOCATION OF WELL At surface 121' SNL and 1584' WEL, Sec. 36, TION, R22E At proposed prod. zone 700' EWL and 800' SNL, Sec. 30, TlON-R23E? U.M. 13.DISTANCE IN MILES AND DIRECTION FROM NEAREST TOWN OR POST OFFICE* 45 miles east of Deadhorse, Alaska Sec. 30, T10N-R23E, U.M. 12. 14. BOND INFORMATION: Oil & Gas Conservation, 5134049, State Bond File B-1-L $100,000.00 TYPE Surety and/or No. Amount 17.NO..ACRES ASSIGNED TO THIS WELL 15. DISTANCE FROM PROPOSED * LOCATION TO NEAREST 800ISNL of Unit PROPERTY OR LEASE LINE. FT. (Also to nearest drig, unit, if any) lS. DISTANCE FROM PROPOSED LOCATION Approx TO NEAREST WELL DRILLING, COMPLETED, ' OR APPLIED FOR, FT. 14,000' .NE of Exxon Pt. Thomson No. 2 16,~ No. OF ACRES IN LEASE 1243 19. PROPOSED DEPTH 13,400' TVD 14,650' MD 21. ELEVATIONS (Show whether DF, RT, CR, etc.) +4.5' MSL (Ground) 23. PROPOSED CASING AND CEMENTING PROGRAM 20. ROTARY OR CABLE TOOLS Rotary 22. APPROX. DATE WORK WILL START Location 1/1/81, Spud 3/15/81 SIZE OF ttOLE ~ ~SIZE OF CASING WEIGHT PER FOOT GRADE SETTING DEPTH' Quantity of cement 40" 36x32x28 Insulated Re~ri'oera~ed 85' 'To surface with permafrost cemen' 26" 20" 133 K-55 2~100' To surface with permafrost cemen 17-1/2" 13-3/8" 72 L-80 3,300' Approx TOC ~ 2.600' 12-1/4" 9-5/8" 43.5 P-110 11.340' Aooro× TOn 7.nnn' 8-1/2" 7" 29/32/35 P-11010,450/13.700/14'.~50 500"above potential hvd ,dro- carbon zone BLOWOUT PREVENTERS' A 20" annular blowout preventer with diverter lines will be installed on the insulated conductor, as shown on the attached sketch. The diverter will be removed while opening the 17½" hole to 26" to 2,100'. The same diverter system will be used on the 20" conductor. A 13-5/8", 5000 psi' WP annular BOP and three 13-5/8", 10,000 psi WP ram type preventers will be installed on the 13-3/8" casing as shown on the attached sketch, and will be used along with a~ 10,000 psi WP choke manifold during drilling and well testing. BOP installation and testing will be in compliance with Alaska State Regulations effective April 13, 1980. Anticipated surface pressures are shown in the casing design section. Pressure on the 5000 psi WP annular BOP will never be allowed to exceed its design working p r e s s u re. /D~BOV~ SPACE DESCRIBE PROPOSED PROGRAM: If proposal is to deepen give data on. present productive zone and proposed ~ / ne~v. productive zone. If proposal is to drill or deepen dixectionally, give pertinent data on subsurface locations and measured and true /J/ ~ticalypths' Give bl°w°ut preventer pr°g~am' 24.1 hereby certif~rtha~hef'For~i~g is/rue and Correct / / / (This space for State SAMPLES AND CORE CltlPS REQUIRED MUD LOG ~YES [] NO ~ YES DIRECTIONAL SURVEY REQUIRED ~YES [] NO CONDITIONS OF APPROVAL, IF ANY: OTHER REQUIREMENTS: [] NO A.P.I. NUMERICAL CODE 50-089-20014 PERMIT NO. 80-100 APPROVAL DATE November 14, 1980 APPROVED BY ~s~'~,~ _ ~,~ ~~~~ TITLE --'; DATE 11/14/80 *See Instruction On Reverse Side BY ORDER OF THIZ CO~ISStON EXXON COMPANY, U.S.A. PLAN OF OPERATIONS EXXON POINT THOMSON UNIT, WELL NO. 6 General This well will be drilled as a directional hole. The surface location will be 121 feet SNL, 1584 feet WEL, Section 36, T10N, R22E and the bottom hole will be located approximately 700 feet EWL, 800 feet SNL, Section 30, T10N, R23E, U.M. The drill site, located approximately 45 miles east of the Prudhoe Bay East Dock, will be constructed during the winter of 1980-81 and the well spudded about March 15, 1981. Approximately seven months will be required for drilling and testing. Loffland Brothers Rig No. 162 will be used to drill this well. This rig and a 78 man Exxon owned camp will be moved from Point Thomson Unit Well No. 4 which is about four miles west of the proposed location. -Natural Environment The drill site for the proposed well is located on Point Sweeney approximately 450 feet inland from the Beaufort Sea shoreline. The nearby onshore terrain is a typical low lying coastal plain with scattered small lakes. Surface vegetation is typical tundra with mosses, lichens, grasses, and sedges being most dominant. Elevation of the proposed drill site is approximately five feet above sea level. The proposed well is in the continuous permafrost zone of northern Alaska where the depth of permafrost is approximately 1,600 feet and the active surface layer or thaw zone is from one to three feet. Since the ground cover acts as insulation limiting the depth of the active layer, removal or damage to the ground cover, particularly in areas of any appreciable slope, is a major factor in causing erosion. Consequently, every possible effort will be made to protect the surface from unnecessary damage. There are no established roads, airstrips, housing, or other facilities in the area and, because of the nature of the terrain, heavy vehicular traffic can operate only during the winter season while the ground and surrounding sea ice are frozen. Prudhoe-Deadhorse is the nearest staging area and airstrip with permanent facilities for handling cargo and housing personnel. Arctic climatic conditions include relatively cold temperatures year- round. Strong winds, small annual precipitation, and visibility strongly influenced by the combination of winds and coastal sea ice condition are factors contributing to an extremely harsh environment. Page 2 Temperatures vary from a high in the 40 to 60°F range in the summer to a low of -50 to -60°F in the winter which, with the chill factor may reach -100"F or lowe~depending on the severity of winds. Surface winds are predominantly from the east at an average velocity of 12 miles per hour along the coast with a velocity range of 35 to 50 mph associated with winter storms. Total annual precipitation is in the range of 4 to 6 inches which includes 12 to 48 inches of snowfall. Various species of wildlife exist in the area. During the winter months, when the major part of activities are planned, wolves, wolverines, foxes, polar bears, and caribou may be present. Bird life is limited primarily to the raven, snowy owl, gyrfalcon, and ptarmigan, with waterfowl and most other birds having migrated from the area for the winter. Logistics Access to the proposed location during the winter of 1980-81 will be provided by an ice road along the shoreline of the Beaufort Sea extending from Prudhoe Bay East Dock to Point Sweeney and continuing in a southerly direction to the location. Additional ice roads will also be required in 1980-81 from Point Sweeney to the gravel source and also to Lake No. 8 in Sections 22 and 23, T9N, R23E which will be the principal water source for this well. Upon completion of drill site construction, the drilling rig, camp, and supplies will be moved in the winter of 1980-81 to the proposed~location over ice roads. These road routes are shown by Exhibits "A" and "B" which are attached. An ice landing strip, approximately 2000 feet long, will be constructed to facilitate air transportation during the winter of 1980-81. During the winter, if bulky equipment must be delivered on short notice or large shipments can be accumulated, an oCean ice landing strip for Hercules aircraft may be constructed on the sea ice. Major supplies of mud, cement, casing, and miscellaneous drilling supplies will be transported to the location and stockpiled before spring breakup so as to permit operations to continue through the summer. Sufficient fuel will be stored on site to permit operations to continue through spring breakup. Additional fuel, equipment, and supplies required for summer operations will be hauled~by Rolligons or barges. After breakup, personnel and light consumables will be transported by helicopters or other state approved means. All support equipment not required for summer operations will be moved out before~breakup.~ Page 3 Drill Site Construction Contingent upon regulat6~y approval, location preparation will commence in the winter of 1980-81 as soon as freeze-up is sufficient to facilitate movement of construction equipment to the job site. The drill site layout for this well will be approximately 725' x 575' overall as shown by Exhibit "B". The gravel pad at this site will be five feet thick and will require a total of approximately 55,000 cubic yards of fill material. This material will be obtained from a mine located in Sections 14 and 15, T9N, R23E. The development and operation of this mine, which will be a central source of fill material for construction activities in the Point Thomson area, will be covered by separate permit applications to appropriate government regulatory agencies. Rubber tired loaders and belly dump trucks will be used for the loading, hauling, and placement of material for the new location. -Water for drill site construction will be obtained from Lake No. 8 in Sections 22 and 23, T9N, R23E, UPM. The proposed sequence for drill site preparation will be as follows: Construct ice access road along shoreline of the Beaufort Sea from Prudhoe Bay to Point Sweeney and on to the location and also the gravel source. · Activate temporary construction camp for 40-60 persons at gravel source and move in remainder of construction equipment from Prudhoe Bay. · Construct ice roads from (1) Point Sweeney to Point Thomson Unit No. 4 location and (2) the gravel source to Lake 8 in Sections 22 and 23, T9N, R23E. · · · Construct a five foot thick gravel drill site as per Exhibit "B". Move in drilling rig and camp upon completion o~ons~ruc~.~on. Construct 2000 foot long ice airstrip· ~ ..... ' ......... ~- Drilling Operations The proposed location will be spudded about March 15, 1981 using Loffland Rig No. 162. The wellbore will be designed for annular injection for the subsurface disposal of waste liquids. This capa- bility will be established prior to breakup so that drilling operations may continue through the summer season. '.' .- ~ Page 4 · An impermeable plastic sheet will be installed under the drilling rig to collect liquid drainage and direct it to the well cellar for recovery and disposal. The reserve pit will be used to retain cuttings, excess drilling fluids, and drainage around the rig. Welded steel tanks, located in a 60' x 130' x 6' deep plastic lined pit, will provide 410,000 gallons of fuel storage capacity. Water for drilling operations will be taken from Lake No. 8 in Sections 22 and 23, T9N, R23E and other lakes nearer the drill site during' the summer months. A snow melter may also be used to supple- ment rig water requirements. Potable water will be processed through a state approved Met-Pro 250 GPM water treating unit before use in the camp. Disposal of Waste Materials The following waste material procedures will be observed during drilling operations. After completion of the well, any remaining materials will be removed from the drill site. le e Drilling Mud will be injected in the casing annulus. Cuttings from the wellbore will be backfilled in the reserve pit when the location is abandoned. · Sewage Effluent and Gray Water: Sanitary sewage will be treated with a state approved Met-Pro Series 14007 sewage disposal unit. Treated effluent from this unit will be combined with gray water from the camp kitchen and bath- rooms in a steel storage tank and used in drilling mud or rig wash water. Any surplus quantities of this liquid will be discharged in the casing annulus. · Domestic Garbage will be disposed of in a state approved Menaulin-Goder Model 1510 incinerator. · Combustible Wastes such as paper, wood, and cardboard will be incinerated or open burned. 0 Noncombustible Wastes such as scrap metal, batteries drums, wirelines, etc. will be hauled to a state approved site for disposal. · Well Test Fluids: Produced gas will be flared. Produced liquids will be injected in the casing annulus or hauled to a state approved site for disposal. · Waste Oil will be injected in the casing annulus or hauled to a state approved site for disposal. Page 5 Surface Protection and Restoration Plan Surface transportation to the drill site will be only over ice roads during the winter or by barge during the summer. Special procedures for drilling and subsurface equipment are required by the unique characteristics of the permafrost area. Casing cement used through the permafrost zones is of special composition to reduce possibility of freezing and other casing problems. Casing is run and cemented through the permafrost, and in the event of production or interruption of operation, the uncemented casing must be protected by the use of non-freezing fluid. At the completion of the well, the location and adjoining area will be cleared of all waste materials. Velocity Survey Prior to the completion of the well, a veloci~ty survey, one of the essential components of the drilling operation, will be made. The procedure will require a 40" diameter cased hole, 40 feet deep, located on the drill pad a short distance from the well bore which will be filled with brine water just prior to detonation. Experimentally, one pound charges of Nitromon primers or an equivalent amount of Primacord will be used as well as an airgun as the energy source; the Nitromon serving the dual purpose of cavi~ating the hole and supplementing the airgun as an energy source. As this well will be directionally drilled, experimentally 3 foot strips of Primacord placed in a groove in the ice several inches deep at several points along the surface trace of the directional hole (approximately one such location for each 1000 fe~t of departure from surface location of the borehole) as well as an airgun will be used as the energy source. This will provide for more direct velocity measurements and compensate for permafrost thickness as well as ray path distortion. As a further alternative in the event neither of the above develop satisfactory data, we propose to use a steel tank 10 feet in diameter and 20 feet high filled with water with the air gun as the energy source. Development Plans If oil is discovered in sufficient quantities to warrant future development, the Prudhoe Bay to Valdez oil pipeline will be the probable marketing outlet from the area. Oil and casinghead gas would be processed through central oil gathering facilities with oil being transported to the Trans-Alaska Pipeline System. If commercial quantities of gas are discovered, development of a gas market outlet will be related to studies to market gas from the Prudhoe area. AVL: 1 jm 7-21-80 CONTINGENCY PLAN POINT THOMSON UNIT EXXON NO. 6 The objective of this plan i's to outline major operating and contingency requirements to ensure a safe and efficient operation throughout the drilling activi'ty. POLLUTION CONTROL The location will be designed to provide containment of any drilling operation effluents that could be considered as pollutants. The reserve pit will receive and contain all drill cuttings, excess mud material, wash and drain water from around the rig, and have the capacity for use in the event of a severe well control problem. Sewage and kitchen waste water will be processed through a State approved biological treating system with excess sludge being incinerated and'the disinfected liquid contained in a steel holding tank. Treated effluent may be used as drill water, if needed, with excess being injected as described below, A separate sanitary holding pit will be provided to store the treating plant effluent in the event of a system malfunction. A burning pit will be located clear of the rig to permit emergency burning of any produced hydrocarbons resulting from well testing or an upset as well as routine burning as per the Plan of Operations. All fuel will be stored in steel tanks; primary fuel tanks will be located in a plasti'c membrane lined fuel storage area. An important feature of the drilling plan is the provision of annular injection capability.for subsurface injection of waste fluids. Two injection zones will be provided as follows. After setting and cementing the 20" conductor at 2100' (which is below the permafrost zone). 17½" surface hole will be drilled to 3300' and 13-3/8" casing set and cemented back to about 2600'. The interval from 2100' to~2600' will then be available for injection'while the 12¼" intermediate hole is drilled to the expected pressure transition'zone of about 12,000'. After the 9-5/8" intermediate casing is set and cemented back to about 7000', the interval from 3300' to 7000' will be available for'injection for the duration of drilling as well as the 13-3/8" x 20" annulus. Excess mud, well waste waters and collected well test fluids will be injected in 'the zones provided. Liquid levels in the sanitary holding pit and burning pit will be maintained below ground level after breakup to prevent migration of any liquid out of the pit while the'reserve pit will be maintained at a minimum level at all times to provide for containment of well fluids in the event of an upset. All .pits will be pumped out to a minimum level and waste water injected into the injection zone before abandoning the location. The entire operation is planned so that no fluids associated with the operation will be discharged on the surface outside the location. The drilling contractor will be required to develop a'comprehensive site specific SPCC plan to prevent pollution as a result of any drilling rig operation. Drip pans will be installed under the engines and rig machinery. All oils, greases, and chemicals are to be stored within the protected areas. Good housekeeping will be stressed on all parts of the location, with emphasis.on minimizing contamination of the peripheral drainage from the pad. An on-site oil spill cleanup crew will be designated within the drilling crew. These personnel will be given instruction in the prevention and initial control of oil spills. Most minor operational spills of oil will be collected with sorbent material and disposed of by inci'neration. Equipment and material, which will be listed in the SPCC Plan, will be kept on location for the purpose of building containment dikes and berms and'for oil spill cleanup. 'If required, additional per- sonnel and equipment can be rapidly mobilized from either oil spill contractors or the Alaskan Beaufort Sea Oil Spill Response Body (ABSORB) Organization, of which Exxon is a member. For spills beyond the capability of the on-site cleanup crew Page 2 ~ to contain or clean up, the Exxon North Slope Oil Spill Response Team, as outlined in the Exxon North Slope Emergency Manual, which is in final preparation, will be activated to the degree required by the severity of the spill. WELL CONTROL AND PERSONNEL SAFETY Personnel safety and well control are the uppermost factors in well design and operational planning. 'Sufficient data are available to plan the well for evaluation of the geologic objectives, provide for subsurface disposal of waste water, and conduct a safe drilling operation. Exxon and key contract supervisory drilling personnel will be experienced in well control detection and procedures and will be graduates of a certified well control school. Abnormal pressure technology will be used to predict and detect changes in formation pressure to permit adjusting the casing and drilling fluid program to control the well. Emphasis will be placed on well control procedures and equipment to permit circulating out a formation influx in an orderly manner if it should be necessary. Any hydrocarbons in the influx will be diverted to the burning pit and either burned or injected into the annulus. In the unlikely event of an unplanned upset resultingin uncontrolled well flow, the following basic procedures will be followed: le Divert flow to burning pit as the first defense against a spill. Switch the flow to the reserve pit when the safe working level is approached in the burning pit. The capacity of the reserve pit will be maintained at a maximum, practical working capacity at all times by keeping mud and fluid levels at a minimum and pumping fluids into the injection annulus when possible. . 3. Finalize plans for drilling a relief well from previously determined available locations. Site selection will be strongly influenced by the bottom hole location of the flowing well at the time of loss of control. Ignite well fluids at the Wellhead, if the situation warrants, only after discussion with proper governmental agencies and Exxon management. Major supplies of mud, cement, casing, fuel, and miscellaneous supplies will be transported over winter roads or flown directly to location prior to breakup. After breakup, light consumables will be transported by helicopters. ARolligon will be on location for any local movement of water or fuel as permitted by land conditions. Tubulars and wellheads, along with gravel for preparing a relief well location, will be maintained at a suitable location in the area. In the extremely unlikely event of an out-of-control well, both the Exxon North Slope Well Emergency Response Team and the North Slope Oil Spill Response Team, as outlined in the previously mentioned Exxon North Slope Emergency Manual, will be activated. The Well Emergency Team will be responsible for performing all well control functions, which includes all surface well control procedures, as well as plans for rapid implementation of an appropriate relief well plan. The Oil Spill Response Team will be responsible for taking immediate action to minimize environmental damage and to institute cleanup operations as required. The ABSORB Oil Spill Contingency Plan Manual, which is in final preparation, contains detailed oil spill scenarios, detection, containment, and cleanup information. An outline of a relief well plan, which will be site specific, will be contained in the Drilling Program for the well. General information concerning relief well planning and logistics will be contained in the Exxon North Slope Emergency Page 3 ~Ma~bal. The bas ,an will involve construction either an onshore or offshore location and drilling either a straight or directional well designed"to penetrate the flowing zone near the original wellbore. The relief well location will be 'selected to optimize both rapid location construction and design of a safe, reliable relief well program. As mentioned previously, contingency tubulars and gravel dedicated specifically for relief well use will be maintained at a location in the vicinity. These tubulars are designed to permit pumpihg kill weight fluid at a sufficient rate to kill a blowout in the Pt. Thomson/Beaufort Sea area. All relief well plans are predicated on emergency approval of all phases of the operation by all State and Federal regulatory agencies. Alaska Island · · ii i mill I ' m ii iii PROPOSED .. EXXON No.6, Ptthomso, Unit Lot. 7'0° 11'04.71" Lono~146° Z5' 45.41" . y = 5,917, 253 x = 446,767 1 TOPO FROI~ FLAXMAN ISLAND (A-4 8r, A-5), AK CERTIFICATE OF SURVEYOR I hereby certify that I am properly registered and licensed to practice land surveying in the State of Alaska and that this plat represents a location survey made by me or under my direct supervision and that all details are correct. DATE I"= I MILE ., - , ._ . .'. i . i mil i PROPOSED WELL LOCATION EXXON No. 6 POINT THOMSON UNIT LOCATED IN SECTION 56,TlON,R22E,U.M. iii i i FOR EXXON COMPANY U.S.A. ilU i . mil i BESSE, EPPS & POTTS ANCHORAGE, ALASKA ' '544-1352 im __ iim i i Point Tho so unit Ex×of o. SUBSURFACE INJECTION: After setting the 9-5/8" casing into.the pressure tran- sition zone (11,340' MD), waste fluids and hydrocarbons will be injected into saltwater zones from 3300' to 7000' down the 13-3/8" x 9-5/8" annulus. CASING DESIGN CRITERIA: See attached Wellbore Sketch for design Surface- 13-3/8" @ 3300' · Burst - Considers gas gradient to the surface causing lost returns at the shoe assuming maximum expected leakoff gradient. External fluid weight 9.0 ppg. Maximum '~ Pressure (MSP) MSP = (Max. shoe leakoff gradient - gas gradient) casing depth (16.0 x .052 - 0.10) 3300' 2,416 psi · Permafrost Freezeback - Considers maximum external collapse gradient of 1.44 psi/ft and minimum internal fluid weight of 9.0 ppg. Maximum Collapse Pressure (MCP) MCP = (Max. external gradient -min. fluid gradient) max. permafrost depth (1.44 - 9.0 x .052) 2500' 2,430 psi · Permafrost Thaw Subsidence - 13-3/8" 72#/ft L-80 Butt post yield strain . performance exceeds the requirements based on worst case well spacing. Safety Factors Burst 1.443 Collapse 1.00 Tension 1.50 PROTECTIVE 9-5/8" @ 10,500' TVD = 11,340' MD · Burst - Considers gas kick of sufficient intensity and volume to cause lost returns assuming maximum expected leakoff gradient and casing filled with water. External fluid weight 9.0 ppg. Maximum c-.~rfccc Pressure (MSP) MSP = (max. shoe leakoff gradient - water gradient) casing TVD = (19.0 x .052 - 8.33 x .052) 10,500' = 5,826 psi · Collapse - Considers surface pressure = 0 psi, internal fluid weight 8.33 ppg and external fluid weight 12.5 ppg Maximum ~ Pressure (MCP) MCP = (External fluid gradient - internal fluid gradient) casing TVD - surface pressure (12.5 x .052 - 8.33 x .052) 10,500' - 0 2,277 psi Point ~homson Unit Exx .to. 6 ®~ Safety Factors Burst 1.443 Collapse 1.00 Tension 1.50 PRODUCTION 7" @ 13,400' TVD = 14,650'MD · Burst - Considers shut-in gas well surface pressure on kill weight packer fluid and external fluid weight of 15.5 ppg. Maximum sa, faee pressure (MSP) MSP -- (Max. kill wt. fluid gradient - gas gradient) Casing TVD (15.5 x .052 - 0.18) 13,400' 8,388 psi · Collapse - Considers surface pressure = 0 psi, internal fluid weight = 0 ppg and external fluid weight = 15.5 ppg Maximum Collapse Pressure (MCP) MCP = (External fluid gradient - internal fluid gradient) casing TVD - surface pressure = (15.5 x .052 - 0) 13,400' - 0 = 10,800 psi · n Safety Factors , Burst 1.312 Collapse 1.125 Tension 1.50 WELLBORE & CASING DESIGN SKETCH POINT THOMSON UNIT EXXON NO. 6 · ~,---- O' 29~7ft P-11 LTC ~-10,450' 32#/ft P-11( LTC 13,700 35#/ft P-1.10 LTC ] ~" 36" x 32" x 28" Insulated Conductor @ 85' .:;. ~o' "'133#/ft K-55 Butt Conductor @ 2100' '~ Waste Fluids and Hydrocarbon Injection '~ ZOne , ~ TOC ~ approximately 2600' 13-3/8" 72#/ft. L-80 Butt Surface Casing ~ 3300' Waste fluids and hydrocarbon injection zone TOC @ approximately 7,000' 9-5/8" 43.5#/ft P~-110 Butt Protective Casing @ 11,340' 7" Production Casing @ TD TYPICAL 2000 PSI W.P. DIVERTER STACK AND LINE FOR USE ON 30" AND 20" CONDUCTOR CASING PT. THOMSON UNIT EXXON NO. 6 Butterfly Val ye Flowline __ ?rip Ta_~k r 2,000 psi W.P. Annular BOP ~) To Burn Pit Minimum 6" Diverter Line 20" Spool or 20" Casing To Reserve Pit 28"x 20" Swage .l~Full opening hydraulically operated valves interlocked such that the diverter line valve will always be open before annular BOP ts closed. 2~Full opening, normally open valves to control flow to reserve ~nd burn pits KILL I TRIP TANK _Component Speci fi cati ons ANNULAR BO P 5000 psi W.P. RAM BOP Pipe 10,000 psi W.P. SPOOL I .A=.o. I Blind l0,000 psi W.P. I i' m i Pipe 10,000 psi W.P. I RAM BOP I m CHOKE MANIFOLD 1. Screwed Plug or Gate Valve - 2" size provided with A-section 2. Screwed Plug Valve - 2" size 3. Screwed Tapped Bullplug with Needle Valve and Pressure Gage 4. Flanged Plug or Gate Valve - 2" size provided with wellhead $. Flanged Plug Valve - 2" size with companion flange to protect valve flange face 6. Flanged Plug or Gate Valve - 2" minimum size 7. Flanged Tee - 2" minimum size 8. Flanged Flapper Type Check Valve - 2" minimum size 9. Flanged Hydraulically Controlled Gate Valve- 4" minimum size 10. Flanged Plug Valve - 4" minimum size. Gate valve not acceptable. ll. Top of Annular Preventer must be equipped with an AP1 Flange Ring Gasket. All flange studs must be in place. 12. The I.D. of the Bell Nipple must not be less than the minimum I.D. of the BOP stack. NOTE: All valves on kill and choke lines lO,O00 psi W.P. TYPICAL ARRANGEMENT OF 13-3/8" lO,O00 PS! W.P. BOP STACK FOR USE OF 13-3/8" SURFACE AND 9-5/8" PROTECTIVE AND 7" PRODUCTION CASING PT. THOMSON UNIT EXXON NO. 6 Alaska Island - Island PROPOSED -~ ~ , EXXON No.6, PtThomson Unit '~-'~u~-o~r ~_~ I ~at. '",'0° ~'04.7~" ~~o 28 27 ~nt 26 I 25 / ~ 30 29 , 28 J ................. EX ~ ' '"--. ~ ~ -~" .... T'IO N TOPO FROM FLAXMAN ISLAND {A-4 ~ A-§),AK I": I MILE CERTIFICATE OF SURVEYOR I hereby certify that I om properly registered and licensed to practice land surveying in the State of Alaska and that this plat represents a location survey made by me or uCder-my..: direct supervision and that all details are correct. PROPOSED WELL LOCATION EXXON No. 6 POINT THOMSON UNIT LOCATED IN SECTION ;56~TION~.R2ZE~ U.M. ,. EXXON COMPANY U.S.A. BY BESSE, EPPS & POTTS ANCHORAGE ~ ALASKA 344-1352 · February ll, 1980 Mr. H. J. Flatt Exxon Headquarters Drilling Manager Exxon Company, U.S.A. P. O. Box 2180 Boom 3005 Houston, TX 77001 Dear Sir: With reference to your' inquiry regarding the use of large bore annular preventers, Otis has bad no experience stripping pipe using any annular type preventer above 10 3/4 I.D. We have had some experiences down through the years with emergency stripping of drill pipe, sizes 3 1/2 through ~ 1/2, using the 7 1/16 I.D. annular preventer under 3,000 psi, but in each case we either had adeOuate pipe in the hole or our conventional snubbing equip- ment available for stripping purposes. We regularly strip 1.315 O.D. through 2 7/8" O.D. using a pre- sized, molded stripper element similar to Hydrll's RS Stripper, Composite Catalog, Page 3674. Most routine offshore workover is conduCted with 1.315 O D. pipe stripped through a molded stripper element sized to fit ~ 1/16 bore equipment, 3;000 psi maximum, We have used dual .element stripping techniques but employ this method to lengthen element life as opposed to increasing working pressure ranges. Stripping with either the. molded or annular type presents major problems.when considering the change in areas as the Joint upset moves through the seal area from two standpoints: 1) Sufficient pipe weight must be present to pull the Joint through the seal area, and 2) Strict attention must be placed on the type of Joint used. No. square shoulders must be present and a very shallow angle must be used for the diameter transition. I would suggest that smaller pipe diameters in relation to large - bore annular preventers could present a problem unless the elastomeric material is adequately backed up by metal. One other' concern is the tendency for the elastomeric materials to flow easily when the pressure differential approaches or exceeds the modulus of elasticity. This means that without near perfect metal backup, higher pressure sealing is not practical. We experience a certain amount of difficulty in the ram type preventer as well, and must be constantly aware of and accommodating to the metal backup configuration. Otis Engineerin9 Corpora%lon A HAJ.~B URTON Fi gure 7 Mr. H. J. Flatt Page Two February 11, 1980 One point I should mention is, the industry also uses the term stripping %o indicate %he movement of pipe through ram type I have assumed in your inquiry we are talking about annular type equipment as opposed to ram type equipment. Our.principal experience has been with ram type equipment, using '~ipe sizes up through 7" O.D. and pressure up through 18,000 psi. %'he large pipe has been stripped with ram type BOP's against 2,000 psi and the smallest pipe has been associated with ram type BOP's and 18,000 psi. We would, if required to rig up on an existing stack, test all BOP's including the annular to rated working pressure but would not attempt to strip more than 5,000 psi using a 7~1~16.I.D. annular preventer. We believe,increaseS in bore will reduce this maximum drastically as 18 3/4 I.D. is reached. ' I hope the foregoing is useful in helping'you arrive at a decision but if additional information is necessary, please contact me. Yours very truly, OTIS ENGINEERING CORPORATION ?hillip S/Sizer / .PSS:mc cc: Mr. Homer Davis I CI t) CL CE CH FIG. ".I).4 ARRANGEMENT CHRdRA*CL Triple [(am Type Preventer.%, Rt, ()ptional. I I I I I I CH FIG. 2.I).5 ARRANGE,MENT Ctt R. dRA*CHA, 'Annular preventer, A, may have SM working pressure rating. t t I I (I , I ) I CH CL · ' Fl(;. 2.1).6 A R It:\ NG E M F; NT CH t{dRdA*CI. TYPICAL BLOWOUT PREVENTER ARRANGEMENTS FOR SM, IOM, AND 155I RATED WORKING PRESSURE SERVICE- SuBSEA INSTALLATION I 1 I I I I I ( i , t ) I I CH FI(;. 2.I).7 ARRAN(iEMENT CH ltd g<tA'A'CL FC~ CR-13 1/72 CAGING ASD TU~It;G DESIGN CASING S~PR/NG CASING SIZE CObZYfY STATE HOLE SIZE' ~?oq~ WT. I . HYD GR. i ~L.,,"D ~. II ~-'/g. }[YD. GR. II pz~/f~. M.S.?. . I~TERVAL Bottom Top ' DESC.~PTi0N :;EIGHT TEYSION .~,[IbS}d~4 TDF COLLAPSE -COLL~PSE CDP BUP£T !i;T?.'t?'ZAL BDF P?J~ CCi W~ BF_ -top of ST~'dG~H P.~SS. ~ P~S!ST. P~SS~ Wt. Grade ~nread W/O BP section TEI~SiON bott~ tension Y~LD lbs lbs !030 lbs psi nsi psi 3300 GS/~'' H3qo. 0 I13'-/o ~J,S, p-no /OJ"oo Formulae: Collapse resistance in tension = X (Collapse pressure ratir~) ~urst Pressure = ~P + Depth ( }{yd. Gr. II --.~) Calculations: ... T~al Cczt BF (Bouyancy Factor) = ~.. oo - ( o. o~-5 3 x ~.:ua w~;. 'r ) } j~;~ ~o x ~o 'to ~ ~NC. ~ × ,o ,,~..~ 46 '1323 KIEUFFEL. & E$$ER CO. ~IADE IN U.S.A. i1~6 o / Item Approve CHECK LIST FOR NEW WELL PERMITS C~m~y Date %. -! %'to.. . 1. Is the permit fee attached ......................................... (2) I~c. /~ (3) k~min./~ (4) ~___~. ~ .... g-ZS-Fo 2. Is well to be located in a defined pool ............................ 3. IS a registered survey plat attached '" 4. Is well located proper distance frcm pru~=rty · · 5. Is well located proper distance frcm other wells ......... 6. Is sufficient undedicated acreage available in this pool ............ ~_~ _ / be deviated 7. Is .%~11 to ............................................. 9 Can permit be approved before ten-day t .......... 10. Bees operator have a l~nd in force ............................... .... 11. Is a conservation order needed ...................................... .. 12. Is administrative approval needed ................................... 13. Is conductor string provided ........................................ 14. Is enough cement used to circulate on conductor and surface ......... 15. Will c~ment tie in surface and intermediate or production strings ... 16. Will cene_nt cover all known productive horizons ..................... Lease & Well No. ~ Yes No , / Additional Requirements: 17 Will surface casing protect fresh water zones ....................... ~ _~ 18. Will all casing give adequate safety in collapse, tension and burst.. ~ 19. Does BOPE have sufficient pressure rating - Test to ,o, oo~~ q~" psig .. ~ _App,. oval ~=cc~ed: