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CO 173
Conservation Order Cover Page XHVZE This page is required for administrative purposes in managing the scanning process. It marks the extent of scanning and identifies certain actions that have been taken. Please insure that it retains it's current location in this file. '~~ Conservation Order Category Identifier Organizing RESCAN~.-----~"' DIGITAL DATA OVERSIZED (Scannable with large plo~e.~nner) ~' Color items: [] Diskettes, No. ~"~Maps: [] Grayscale items: [] Other, No/Type [] Other items [] Poor Quality Originals: OVERSIZED (Not suitable for [] Other: plotter/scanner, may work with 'log' scanner) [] Logs of various kinds [] Other ' NOTES' BY: MARIA Scanning Preparation Production Scanning Stage I PAGE COUNT FROM SCANNED DOCUMENT: ~ PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: ~ YES NO BY: Stage 2 ~ARIA DATE: (..~ ~//'-- ~ /S/~'~-~ IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: ...... YES NO (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES) I I IIIIII General Notes or Comments about this Document: 5/21/03 ConservOrdCvrPg.wpd STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501 Re: THE APPLICATION OF ATLANTIC ) RICHFIELD COMPANY for a ) hearing to present testimony) to determine the pool rules ) for the development and pro-) duction of the Kuparuk River) Formation west of the Prud- ) hoe Bay Field. The contrac- ) tion of the Prudhoe Bay ) Kuparuk River Oil Pool and ) the naming of the field is ) considered as part of the ) application. ) Conservation Order No. 173 Kuparuk River Field Kupa ruk River Oi 1 Pool. Prudhoe Bay Field Prudhoe Bay Kuparuk River Oi 1 Pool. May 6, 1981 IT APPEARING THAT: ® Atlantic Richfield Company by letter dated November 25, 1980, requested the Alaska Oil and Gas Conservation Commission to take the necessary steps to adopt pool rules for the development and production of the 'Kuparuk River Formation west and north of the Prudhoe Bay Field. · Notice of a public hearing was published in the Anchorage Times on February 5, 1981. · A public hearing was held on March 25, 1981 at the Municipality of Anchorage Assembly Room, 3500 East Tudor Road, Anchorage, Alaska. Testimony was presented and oral and written statements were accepted. · The hearing was continued until April 8, 1981 at 4:30 PM. Additional written statements and maps were re ce ive d. FINDINGS: ® Oil was first discovered in the Kuparuk area when Sinclair Oil Company tested oil from the Kuparuk River Formation at their Ugnu No. 1 well in 1969. · Since 1969, more than 25 wells have been drilled and hundreds of miles of multi-fold seismic data have been acquired in an attempt to define the limits of the Kuparuk River oil accumulation. AGO 10023342 Conservation Ord(.~ No. 173 Page 2 · The area for the Prudhoe Bay Kuparuk River Oil Pool Rules was initially described on January 12, 1970 in Conservation Order No. 83-A and the area has not been changed since that date. · A fault, labeled the Eileen fault, exists in the western part of the Prudhoe Bay Field and the evidence indicates that this fault marks the western boundary of the oil accumulation defined as the Prudhoe Bay Kuparuk River Oil Pool. · There is doubt about the existence of the Eileen Fault north of the Prudhoe Bay Field and this area may have several faults. · Some of the area west and north of the Prudhoe Bay Field should be included within the area where a common accumulation is possible and not covered by the Prudhoe Bay Kuparuk River Oil Pool rules. · The Kuparuk River Formation interval in the Atlantic Richfield Company West Sak River' State #1 well appears adequate for defining the pool. · The area of oil accumulation appears to be ~controlled by structural dip and truncation to the south, trunca- tion of the formation to the west, northeast dip and possible faulting to the north and east, and a fault, the Eileen Fault, to the east. · The Kuparuk River formation consists of very fine to medium grained marine sandstone, usually occurring as three sand members separated by mudstones, siltstones and thinly bedded sandstones. 10. Sand members of'the Kuparuk River Formation west of the Eileen Fault could be a common pool and share the same fluid contact. 11. To date, no wells have established the existence of a gas cap in the Kuparuk River Formation. 12. Although water has been found in the Kuparuk River Formation, no oil-water contacts 'have been substantiated in any individual sand members. 13 . The aquifer underlying the Kuparuk River oil accumlation appears to be small in volume and the influx into the oil column is expected to be insignificant. 14. Preliminary development plans cover an area of 210 squares miles. AGO 10023343 Conservation Ord . No. 173 Page 3 15. Initial reservoir pressure is estimated to average 3100 psia. with a bubble point pressure of 3000 psia. 16. Solution gas drive is expected to be the primary recovery mechani sm. 17. Ail gas produced will be utilized, in accordance with 20 AAC 25.035 GAS UTILIZATION, for'use as fuel, safety flaring, artifical lifting of oil, and injection into the reservoir for storage until a gas sales pipeline is available. 18. It is proposed that when gas sales facilities become available, the injected gas will be produced from the injected area for fuel and for sale. 19. Waterflooding plans are being formulated for the re se rvoi r. 20. The blowout prevention equipment and its use should be in accordance with 20 AAC 25,035 BLOWOUT PREVENTION EQUIPMENT. 21. The Kuparuk River Field, the name proposed by the operator for the area to"be covered by the~se rules, is considered an appropriate name since it meets the required criteria. 22. Development is planned under state-wide spacing regulations. 23. In the northern latitudes, the convergence of governmental survey lines toward true north results in some governmental quarter sections of less than 150 acre s. 24. The drilling, completion and production from a well located in a governmental quarter section of no less than 125 acres will not adversely affect correlative rights. 25. Surface casing setting depths between 500 feet below the base of the permafrost and 2700 feet TVD will allow flexibility in the complex directional well programs. 26. Slotted liners,, wire wrapped screen liners with and without gravel packing, and open hole completions may offer a means to reduce formation damage and improve oil recovery. 27. The casing design criteria being used has effectively eliminated casing collapse. AGO 1002B~4 Conservation Orde{~ No. 173 ( Page 4 28. Installation of downhole and surface automatic shut-in valves could prevent an uncontrolled flow of oil or ga s. 29. A minimum subsurface safety valve setting depth of 500 feet should provide adequate protection from an uncon- trolled flow and should reduce the risk of damaging both the valve and the control line while running in the hole. 30. To properly regulate and operate the reservoir, performance must be carefully monitored and bottomhole pressure and gas-oil ratio test data must be obtained soon after production commences. 31. The contribution of each of the various perforated intervals in each producing well may be determined by running productivity profile surveys. NOW THEREFORE, IT IS ORDERED THAT Conservation Order No. 98-A is hereby amended by removing the following described area from the area covered by the Prudhoe Bay Kuparuk River Oil Pool Rules. T 11 N, R 10 E, U.M. T 12 N, R 10 E, U.M. Secs. 1,2,11,12,13,14,23, 24,25,26,35,and 36. T 11 N, R 11 E,U.M. ~'~ Secs. 1,.2,11,12,13,14,23, 24,25,26,35 and 36. T 12 N, R 11 E, U.M. Secs. 3,4,5,6,7,8,9,10, 11,14,15,16,17,18, 19,20,21,22,23,24, 25,26,27,28,29,30, 31,32,33,34,35 and 36. T 13 N, R 10 E, U.M. ~ Secs. 3,4,5,6,7,8,18,19, 20,29,30,31,32 and 33. T 13 N, R 11 E, U.M. Secs. 13,14,15,16,21,22, 23,24,25,26,27,28, 33,34,35 and 36. Secs. 17,18,19,20,28,29, 30,31,32 and 33. AGO 10023345 Conservation Orde~ No. 173 Page 5 NOW THEREFORE IT IS FURTHER ORDERED THAT the rules hereinafter set forth apply to the following described area: T 9 N, R 6 E, U.M. Secs. 1,2,11,12,13 and 14. T 11 N, R 8 E, U.M. ALL T 9 N, R 7 E, U.M. Secs. 1,2,3,4,5,6,7,8,9, 10,11,12,13,14,15, 16,17 and 18. T 9 N, R 8 E, U.M. Secs. 1,2,3,4,5,6,7,8,9, 10,11,12,13,14,15, 16,17 and 18. T 9 N, R 9 E, U.M. Secs. 1,2,3,4,5,6,7,8,9, 10,11,12,15,16,17 and 18. Secs. Secs. T 11 N, R 9 E, U.M. ALL T 11 N, R 10 E, U.M. ALL T 11 N, R 11 E, U.M. 3,4,5,6,7,8,9,10,11, 14,15,16,17,18,19,20, 21,22,23,24,25,26,27, 28,29,30,31,32,33,34, 35 and 36. T 12 N, R 7 E, U.M. 25,26,35 and 36. T 9 N, R 10 E, U.M. Secs. 1,2,3,4,5,6,7,8,9, 10,11 and 12. T 10 N, R 6 E, U.M. Secs. 1,2,3,4,9,10,11,12,13, 14,15,16,21,22,23,24, 25,26,35 and 36. T 12 N, R 8 E, U.M. ALL T 12 N, R 9 E, U.M. ALL T 12 N, R 10 E, U.M. ALL T 10 N, R 7 E, U.M. ALL T 10 N, R 8 E, U.M. ALL secs. T 12 N, R 11 E, U.M. 3,4,5,6,7,8,18,19,20, 29,30,31,32 and 33. T 10 N, R 9 E, U.M. ALL T 10 N, R 10 E, U.M. ALL T 10 N, R 11 E, U.M. Secs. 5,6,7,8,17,18,19 and 20. T 11 N, R 6 E, U.M. Secs. 25,26,35 and 36. T 11 N, R 7 E, U.M. Secs. 1,2,3,4,9,10,11,12, 13,14,15,16,17,18,19, 20,21,22,23,24,25,26, 27,28,29,30,31,32,33, 34,35 and 36. secs. Secs. T 13 N, R 8 E, U.M. 13,14,23,24,25,26, 27,28,33,34,35 and 36. T 13 N, R 9 E, U.M. ALL T 13 N, R 10 E, U.M. ALL T 13 N, R 11 E, U.M. 7,8,16,17,18,19,20,21, 28,29,30,31,32 and 33. AGO 10023346 Page 6 Rule 1. Name of Field The name of the field shall be the Kuparuk River Field. Rule 2. Definition of Pool The name of the Pool in the Kuparuk River Field shall be the Kuparuk River Oil Pool and is defined as the accumulation of oil that is common to and correlates with the accumulation found in the Atlantic Richfield Company West Sak River State No. 1 well between the depths of 6,474 and 6,880 feet. Rule 3. Well Spacing Not more than one well may be drilled on any governmental quarter section or ~gove'rnmental lot corresponding to it nor may any well be drilled on a governmental quarter section or governmental lot corresponding ~to it which 'contains less than 125 acres, nor may the Pool be opened in a well bore that is closer than 500 feet to any property line nor closer than 1,000 feet to the ~P~601 opened to the well bore in another well. Rule 4. Casing and Cementing Requirements (a) Casing and cementing requirements are as specified in 20 AAC 25.030. CASING AND CEMENTING. except as modified below. (b) For proper anchorage and to prevent an uncontrolled flow, a'conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe to the surface. (c) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze back, a string of surface casing shall be set at least 500 measured feet 'below the' base of the perma- frost section but not below 2700 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the casing to the surface. (d) The surface casing, including connections, shall have minimum post-yield strain properties of 0.9% in~tension and 1.26% in compression. (1) The only types and grades of casing, with threaded connections, that have been ~shown to meet the requirements in (d) above and have been approved for use as surface casing are the following: Buttress; Buttre s s; But tre s s; (A) 13-3/8 inch, 72 pounds/foot, L-80, (B) 13-3/8 inch, 72 pounds/foot, N-80, (C) 10-3/4 inch, 45.5 pounds/foot, K-55, AG0 10023347 Conservation Ord~' No. 173 Page 7 (2) The Commission may approve other types and grades of surface casing upon a showing that the proposed casing and connection can meet the post-yield strain require- ments in (d) above. This evidence shall consist of one of the following: (A) full scale tensile and compressive tests; (B) finite element model studies; or, (C) other types of axial strain data accep- table to the Commission. (e) Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze back may be approved by the Commission upon application. (f) The Commission may approve alternative completion~ methods (to 20 AAC 25.030 (b) (4) and (5)) upon application and presentation of data which shows the alternatives are based on accepted engineering principles. Such alternative designs may include: (1) slotted liners, wire wrapped screen liners, or combinations thereof, landed inside of open 'hole and may be gravel packed; (2) open hole completions provided that the casing is set not more than 200 feet above the productive zone. Rule 5. Automatic Shut-In' Equipment (a) Upon completion, each well which is capable of unassisted flow of hydrocarbons must be equipped with a commis- sion-approved (1) fail-safe automatic surface safety valve (SSV) capable of preventing 'an uncontrolled flow by automat- ically closing if such a flow should occur; and (2) fail-safe automatic 'surface controlled subsurface safety valve (SSSV), unless another type of subsur- face valve is approved by the Commission; this valve must be in the tubing string located at a depth of 500 feet or greater below ground level; the valve must be capable of preventing an uncontrolled flow by automatically closing if such a flow should occur. (b) A representative of the Commission will witness operation and performance tests at intervals and times as pre- scribed by the Commission to confirm that the SSV, SSSV, and all associated equipment are in proper working condition; and AGO 100233~+8 Conservation Order No. 173 Page 8 (c) A well that is not capable of unassisted flow of hydrocarbons as determined by a "no flow" performance test wit- nessed by a commission representative is not required to have fail-safe automatic SSV or SSSV valves. Rule 6. Safety Flares (a) The daily average volume of 250 MCF/day is permitted for a safety flare in the Central Production Facility operated by Atlantic Richfield Company. (b) Safety flare volumes for additional facilities may be approved administratively upon application. (c) Safety flare volumes may be increased or decreased admini stra tive l y. Rule 7. Gas-Oil Ratio ~Tests Between 90 and 120 days after continuous production and each six months thereafter a gas-oil ratio test shall be taken on each producing well. The test' shall be of at least 12 hours duration and shall be conducted at the normal .producing rate of the well. Test results shall be reported on Gas-Oil Ratio Test, Form 10-409. All tests run in a calendar month shall be reported by the 15th of the following month. Rule 8. Pressure Surveys (a) A static bottomhole pressure survey shall be taken on each well prior to initial sustained production. (b) Following initial sustained production from each governmental section, a transient pressure survey shall be taken on one well in the section after six months and after 18 months. (c) One of the wells from (b) above on each lease will be designated a key well and a transient pressure survey on this well shall be taken a~fter 30 months production and annually the rea fte r. (d) Bottomhole pressures obtained by a static buildup pressure survey, a 24. hour shut-in instantaneous test or a multi- ple flow rate test will be acceptable. (e) Data from the surveys required in this rule shall be filed with the CommisSion by the last day of the month follow- ing the month in which' each survey is taken.~ Reservoir Pressure Report, Form 10-412 shall be utilized for all surveys with attach- ments for complete additional data. 'Data submitted shall include, but are not limited to, rate, pressure, time, depths, temperature, and other well conditions necessary for complete analysis of each survey being conducted. The Pool pressure datum plane shall be 6,200 feet subsea. AGO 10023349 Page 9 (f) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (e) of this rule. (g) By administrative order, the Commission may require additional pressure surveys or modify the key wells designated in (c) of this rule. Rule 9. Productivity Profiles (a) During the first year of production, a production survey shall be run in each well which has multiple sand intervals open to the well bore. (b) Subsequent surveys shall be run in wells which exhibit rapid changes in gas-oil ratio, water-oil ratio, or pro-' ductivity. Subsequent surveys shall also be required in wells which have had remedial work performed to change the production profile unless the remedial work results in only one sand inter- val being open to the well bore. (c) Complete production survey data and results shall be recorded and filed with the Commission by the 15th day of the month following the month in which each survey is taken. (d) By administrative order, the Commission shall specify additional surveys should it be determined that the surveys submitted under (a).and (b) are inadequate. Done at Anchorage, Alaska and dated May 6, 1981. ~'oyl~H. ~amil~on, Chairman Alaska Oil and Gas Conservation Commission Harry W. 'Kugler, C6mmissioner Alaska Oil and Gas Conservation Commission Lo~n~ie C. Sm~h,~ommissioner Alaska Oil and Gas Conservation Commission AGO 10023350 June 14:1994 ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J, HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 Re: ADMINISTRATIVE APPROVAL NO. 173.11 The application of BP Exploration (Alaska) Inc. to use liquid level control (LLC) valves in those Milne Point Unit wells completed with electric submersible pumps (ESPs). Bruce J. Policky Milnc Point Exploitation Manager BP Exploration (Alaska) Inc. PO Box 196612 Anchorage, Alaska 99519-6612 Dear Mr. Policky: The referenced application was received May 18, 1994. At present, the packers in ESP Wells are set shallow, about 500', to prevent gas locking. There is also a permanent packer and screen assembly located below the pump which is designed to limit sand production. The ESPs have to be changed every 2 to 3 years, therefore ease and safety of pulling operations is a consideralion. The shallow packer depth makes well killing operations difficult and uncertain; potentially, not all of the gas is displaced from the well bore and formation damage is more likely to occur. The LLC is activated by shut-down of the ESP and is linked to thc wellhead shut-in system. Installation of thc LLC wdvc in a "hang-oW' packer will allow kill fluids to be circulated at near-formation depths prior to pulling the ESP and will provide subsurface shut-in capabilities below the pump. Thc Alaska Oil and Gas Conservation Commission has reviewed the evidence available and hereby authorizes, pursnant to Conservation Order 173,. Rule 5(a)(2), the use of liquid level controlled (LLC) safety valves in those Milne Point Unit wells being lifted by electric submersible pumps (ESPs) David W. Johns~,.._~ Chairman BY ORDER OF TIlE COMMISSION ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501~3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 June 29, 1992 ADMINISTRATIVE APPROVAL NO. 173.10 Re: Increase safety flare volumes for Kuparuk River Unit production facilities. W H Carter Kuparuk Operations Engineering Manager ARCO Alaska, Inc. P. O. Box 100360 Anchorage, AK. 99510-0360 Dear Mr. Carter: We have received your correspondence dated May 21, 1992 requesting an increase in the allowable safety flare volumes for the Kuparuk Central Production Facilities (CPF's). A review of pertinent data from meetings with ARCO personnel and correspondence received, supports the increase of allowable safety flares at .the Kuparuk River Unit CPF's. Although the increase is supported, the Commission has undertaken a review of safety flare practices at oil and gas production facilities in the state. Pending the outcome of this review the Commission hereby approves the flaring of gas to maintain safety flares 'and to permit purging of gas handling equipment at the rates specified for the following facilities. The daily average rate shall be calculated on a monthly basis. FACILITY APPROVED RATE 1. CPF-1 2. CPF-2 3. CPF-3 1600 MCF/DAY 1100 MCF/DAY 6OO MCF/DAY AGO 10023360 W H Carter -2- i June 29, 19892 These rates are retroactive to February 1992 when the metering problem was first detected. This approval supersedes Conservation Order 173 Rule 6 (a), Administrative Approval 173.5 and Administrative Approval 173.7 and will remain in effect until December 31, 1992. Sincerely, Russell A. Douglass Commissioner BY ORDER OF THE COMMISSION AGO 10023361 ALASKA OILAND GAS / CONSERVATION COMMISSION October 23, 1991 WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 173.9 Re: The application of Conoco, Inc., operator of the Milne Point Unit, for a temporary increase of the safety flare at the Central facilities in the Kuparuk River field to a maximum of 700 MCF of gas per day. Mr. David L. Bowler Division Manager Conoco Inc. 3201 C Street, Suite 200 Anchorage, AK 99503-3999 Dear Mr. Bowler: Your application was received on October 17, 1991 requesting approval for a temporary increase in the safety flare maximum limit at the Milne Point Central facilities from 250 MCF per day to 700 MCF per day. The increase will prove adequate operational efficiency to prevent shut-in production until a second gas injection well is completed and mechanical modifications to the gas system can be assessed and completed. Follow- ing all proposed changes in the gas system, the safety flare rate will be reconsidered as .to the appropriate rate. Pursuant to Rule 6 (c) of Conservation Order No. 173, the Alaska Oil and Gas Conservation Commission hereby approves a safety flare using a maximum of 700 MCF of gas per day for the facility described above. Sincerely, ,,' ,., ' r -'3 ..-~.,.,~ .~, ,~.....( VLonnie C. Commissioner , BY ORDER OF THE COMMISSION AGO 10023364 December 30, 1986 Telecopy No. (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 173.8 Re: Exemptions from Conservation Order No. 173, Rule 9(a), requiring production surveys. Mr. T. R. Painter Division Manager Conoco Inc. 320! "C" Street, Suite 200 Anchorage, AK 99503 Dear Mr. Painter: We have received your letter of December 12, ]986, in which you requested exemptions to the requirements of Conservation Order No. 173, Rule 9(a), for Conoco's Milne Point Unit wells B-10, C-i, C-2 and C-7. Due to impending shutdown of production and injection operations at Milne Point Unit (MPU), the Commission agrees that production profiles at this point would not provide data essential for monitoring reservoir depletion. Therefore, the production surveys required by Rule 9(a) of Conservation Order No. 173 for MPU wells B-10, C-l, C-2 and C-7 are suspended. W~hen production operations resume at MPU, then the production surveys for these wells will be required within twelve (12) months after regular production begins. Sincerely, ~,~. ~'"" Commissioner BY ORDER OF THE COIv~IISSION jo/3.AA173.8 AGO 10023379 November 10, 1986 Telecopy No. (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 173.7 Re: The application of ARCO Alaska, Inc., operator of the Kuparuk River Unit, to maintain a safety flare using 400 MCF of gas per day' at Central Production Facility No. 3 in the Kuparuk River Field. Mr. J. D. Weeks Kuparuk Operations Manager ARCO Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510-0360 'Dear Mr. Weeks: Your application was received on November 7, 1986 requesting approval for the. flaring of 400 MCF of gas per day to maintain a safety flare at the Central Production Facility No. 3 in the Kuparuk River Field. Pursuant to Rule 6(b) of Conservation Order No. 173, the Alaska Oil and Gas Conservation Commission hereby approves a safety flare using a maximum of 400 MCF of gas per day for the facility described above. S in~erely~ ',,., ...... Chairman BY ORDER OF THE COMMISSION jo/3.AA173 AGO 10023386 August 12, 1985 A D M I N I S T R A T I V E A P P R 0 V A L NO. 173.6 Re: The Application of Conoco Inc., operator of the Milne Point Unit, to maintain a safety flare of a maximum of 250 MCF of gas per day at the Central Facilities Pad in the Kuparuk River Field. Mr. John R. Kemp Manager of Alaskan Operations Conoco Inc. 3201 C Street, Suite 200 Anchorage, Alaska 99503-2689 Dear Mr. Kemp: Your application was received on August 2, 1985 requesting approval for the flaring of 250 MCF of gas per day to maintain a safety flare at the Central. Facilities Pad in the Milne Point Unit area of the Kuparuk River Field. Pursuant to Rule 6 of Conservation Order No. 173., the Alaska Oil and Gas Conservation Commission hereby approves a safety flare using a maximum of 250 MCF of gas per day for the facility described above. Yours very truly, Harry W. Kugle~ Commissioner BY ORDER, OF THE COMMISSION be:3.AA173 AGO 10023389 February 17, 1984 A D M I N I .S T R A T I V E A P P R 0 V A L NO. ].73.5 Re: ~"Yae appl~.cation of ARCO Alaska, Inc., operator of the Kuparuk River Unit,. to maintain a safety flare, us~ng ~50 MCF of gas per day, at Central Production Facility No. 2 in the Kuparuk River Field, Mr. J. D. %Teeks Kuparuk Operations Manager ARCO Alaska, Inc. P. O. Box 100360 Anc'horage, Alaska 9951.0 Dear Mr. Weeks: Your application was received .on February 15, 1984 requesting approval for the.flaring of 250 MCF gas per day as a safety flare at the Central Production Facility Mo. 2 in the Kuparuk River Ff,.eld. Pursuant to R%~le 6(5) .of Conservation Order No'. 173, the Alaska Oil and Gas Conservation Commission hereby approves a safety flare using a .maximum of ~50 MCF of gas per day for the Central Prodt~ctton Facility No. 2 in the Knpar~lk River Field. Yours very truly, Commissioner BY OMDER OF THE CO,ed!SS!ON ¸be AGO 10023390 December 12, !983 Re: A D M ! N I S T R A T I V E A P P R O V A L NO. 173.4 The Application of Conoco Inc., operator of the Mil. ne Point Unit, to qualify an' additional grade of casing for use as surface casing in the Kuparuk River Field. }{r. D. R. Girdler Production Engi~'tee'r Conoco Inc. 2525 C Street, Suite 100 Anchorage, Alaska 99501 Dear Mr.' Girdler: An application was received on December 9, 1983 requesting an additional grade of casing be approved for use as surface easing in the Kuparuk .River Field. 'In support of the request the aPplicant has presented a structural evaluation of' 9-5/.8 inch, 47 lb/ft., L-80 Buttress casing. The Ala. ska Oil and Gas Conserva. tion Co~fs~ton hms carefu!lv rev.tewe.d ali. of the data available and finds that the evidence submitted t.n accordance w~..th Ru:l~ 4(d)(2)(C) of Conserver,.on Order No. 173 indicates that this type. of casing does meet the requirements .of Rule 4(d) o.f the same conservation order. Pursuant to Rule 4(d)(2) of Conservation Order No. 173, Rule 4(d)(1) of the same order, as ame~.~ded by A.dmi'nistrative Approvals 173.2 and 173.3, is hereby further amend~.d by the Ala~ka Oil and Gas Conser~ation Commission and the fo~.lowtn, g types and grades of casing are approved for use as surface casing in the KuparUk River Field: AGO 10023393 Nr. D. R. Gird.~, December 12, Page, 2 (A) 13-,3t8" , (B) (C) (D) 10-3/4", (g) 10-3/ (F) 9-5/8"", , (0) ('ri) , 9' 5 / 8", (I:) (a) 72 lb/fl 72, lb/ft., 68 lb/ft., 45.5 lb/ft., 45.5 !b/ft., 36 lb/ft., i. 0 t'btf't., 36 th/ft., 40 lb /f't., 47 ,'!,b/ft. , L-80 Buttress. M~']-80 Buttress, K-55 Buttress. I{F,-ERW Attic Grade, J...,55 .Buttress. K-55 Buttress. K~.55 Buttress. t{F-ER~ Arctic Grade, J-55 Buttress. }{F.-E~g Arc, tic Grade, J-55 Bu. ttr~ss. Your~ very truly,, ~.!arr¥ t~. Kugler Co~i ~ s ion,er Mr. J. B. Kewin ~n.d Mr. R. ARCO Alaska, !inc. AGO 10023394 April 27, 1983 A D ~ I i~ I S T R A T I V E A P P R O V A L ~'70. 17_~.3 Re: 'fhe application, of ARCO Alaska, Inc., operator of the Ku.paruk River Unit, to qualify an additional grade of casing for use as surface casing in the Kuparuk River Field. Mr. J. B. Kewin ~.~ir. R. B. Grem~ley ARCO Alaska,. Inc. P. O. Box 3.60 Anchorage, Alaska 99510 Dear Messrs. Kewin and Grem],ey~ An application was received on April. 15, 1983 requesting that an additional casing ~rade be ap~rov.~d for use as surface casing in the Kuparuk River Field. In support of the request is a letter from ?DA E'ngineering sur~v~a'rizing the strain limit analysis of 10-3/4 inch, 45.5 pounds/foot, HF-.ERW Arctic Grade, J-55 Buttress casing. T'he Alaska Oil and .Gas Conservation Com~issio.n.. has carefu].ly reviewed all of tb.e data available to it and finds that evi- den. ce submitted t.n accordance with Rule 4(d)(2) indicates that this additional casing does meet the requirements of Rule 4(d), Con~ervation Order ~,~o. t 73. Pursuant to Rule 4(d)(2) of Conservation Order ~o. 173, and amended by Administrative Approval No. 173.2,. the Alaska Oil and ,.,as Conservation Con ..... is. sion hereby approves the fo!low'intel types and grades of casing, which includes types }~r~vious!y apioroved, for use as surf~ce casing in the Kuparuk River Field AGO 10023396 Messrs. Kewin ar~s Gremley April 27, 1983 Page 2 as fol lows (A) 13-3/8", 72 lb/ft., L-80 Buttress. (B) 13-3/8", 72 lb/ft., N-80 Buttress. (C) 13-3/8", 68 lb/ft., MN-80 Buttress. (D) 10-3/4", 45.5 lb/ft., K-55 Buttress. (E) 10-3/4", 45.5 lb/ft., HF-ERW Arctic Grade, J-55 Buttress (F) 9-5/8", 36 lb/ft., (G) 9-5/8", 40 lb/ft., (H) 9-5/8", 36 lb/ft., (I) 9-5/8", 40 lb/ft., K-55 Buttress. K-55 Buttress. HF-ERW Arctic Grade, J 55 Buttress. HF-ERU Arctic Grade, J-55 Buttress. Yours very truly, terto'n Chairman BY ORDER OF THE COMMISSION be AGO 10023397 February 25, t983 A D bf I ~. I ,e., T R A T I V E A P P R 0 V A I. ?.lO. 173.2 ,,_,-_ , ~ ~ ~z ._. . . ,- : . _._ :z ±. · ~. ....... ire: The application of ARCO Alaska, Inc., operator of t~.~e Kuparuk River Unit, to qualify additional sizes, f~rades, and weights, of casing for use as surface casing in the Knparuk River Field. ,hr. P. A. Vangusen District: Dril. ling( E ARCO Alaska, Inc. P. O. Box 360 Anchorage, Alaska 99510 Dear '~";r. VanDusen.: An application was received on December 15, 1982 requesting that additional casing sizes, weights, and grades be approved for. use as surface casing in the Kuparuk River Field. ~In support of the request, copies were furnished of the report "Synopis of Studies and Recommendation for Qualification of 9-5/8 inch. Casing for Sur.face Casing in the Kuparuk Unit"; also furnished were copies of the report "St'rt~ctural Evaluation of a 9-5/8 inch Buttress Threaded Casing Connection Under Axial Load." On January 14, 1983 additior~al information was furnishe<.f which consisted of a specifica'~ion .for Arctic Grade t:~F-E[{.~[~ J-55 Casing and ~"~bing dated May 4, 1982, and ~n A?;~F Tuboscope Report dated October 9, 1982 wb. ich includeq an Inspection' Certificate by Su'mito~no ??eta! Industries, Ltd., dated October 5, 1982. Additional infor~ation was furnished by letter dated February 6, 1983. . The Alaska Oil and Gas Conservatiop~ Coznmission has carefully re'viewed all of the data. available to it and finds that evi- dence submitted in accordance with Rule 4(d)(2) indicates t'hat additional casip.,.gs do meet the requiren%ents of Rule 4(d), Conservation Order No. 173. '- Im addition 'to t'he types and grades of casing, with threade.d connections, listed in Rule 4(d)(1) of Conservation Order !~'~o 173, the Commission buttress casing ~eet~ th~ requireme~ts of Rule 4(d)(1), was approved for use on. Ju. ly 20, 1976 and should also have been listed. AGO 10023418 i1 Mr. P. A. VanDus~n February 25, 1983 Page 2 Pursuant to Rule 4(d)(2) of Conservation Order No. 173, the Alaska Oil and Gas Conservation Commission hereby approves the following types and grades of casing, which includes types previously approved, for use as surface casing in the K'uparuk River Field as follows: (A) 13-3/8", 72 lb/ft., L-80 Buttress. (B) 13-3/8", 72 lb/ft., N-80 Buttress. (C) 13-3/8", 68 lb/ft., ~'~-80 Buttress. (D) 10-3/4", 45.5 lb/ft., K-55 Buttress. (E) 9-5/8", 36 lb/ft,, (F) 9-5/8", 40 lb/ft,, (G) 9-5/8", 36 .lb/ft., (H) 9-5/8", 40 lb/ft., K-55 Buttress. K-55 Buttress. HF-ERW Arctic Grade, J-55 Butt'ress. HF-ERW Arctic Grade, J-55 Buttress. Yours very truly, Harry W. Kugler Commi s s loner BY ORDER OF THE COMMISSION cc: J. B. Kewin H. D. t{aley, Conoco, Inc. be AGO 10023419 BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 May 10, 1994 David W. Johnston, Commissioner Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Dear Mr. Johnston: RECEIVED MAY 1 8 1994 Alaska 0il & Gas Cons. Commission Anchorage Pursuant to Kuparuk Pool Rule No. 5 requiring the use of surface controlled subsurface safety valves (SCSSSV), BPX (A) as Milne Point Unit operator,.. requests administrative approval to utilize liquid level control (LLC) valves as the subsurface safety valve in MPU electrical submersible pump (ESP) completions. In addition to providing reliable subsurface shut-in, LLC's will reduce operational risk and cost associated with ESP workovers. Attachment 1 depicts a typical Kuparuk ESP completion with a packer and tubing retrievable SCSSSV located at +/- 600' below surface. The shallow packer depth is necessary to prevent gas locking and subsequent damage to the ESP. In addition, there is a permanent hang-off packer and screen assembly located below the pump, which is designed to limit sand production through the ESP. Kuparuk ESP run life is 2-3 years; therefore, efficient pulling and running of ESPs is an essential part of MPU well operations. Prior to pulling a failed ESP it is necessary to perform well kill operations by circulating hydrocarbons out of the well and displacing with kill weight workover fluid. The shallow depth of the packer greatly complicates and adds risk to this process. Kill fluids are either circulated around the packer after it is released or through an annular vent valve. In either case, pressure drops are often too great to allow for efficient circulation without significant losses to the formation. If circulation cannot be established, the tubing is perforated below the packer and kill weight fluid bullheaded into the well. Bull heading in deviated wells will not efficiently displace all of the hydrocarbons; therefore, potential exists for gas to be trapped under the packer. Installation of a LLC valve in the hang-off packer will provide subsurface shut-in capabilities below the pump, eliminating need for the tubing retrievable SCSSSV and associated packer (See attachment 2). LLC's are nitrogen activated valves, set to open and close at predetermined bottom hole pressures, governed by the hydrostatic head in the wellbore (i.e. When the ESP shuts down, hydrostatic pressure in the wellbore will increase and close the LLC). Since a nitrogen charge keeps the LLC open, it will fail in the closed position. Although not actually controlled from the surface, activation of the LLC is directly linked to the surface controlled ESP and wellhead shut-in systems. In the event that subsurface shut-in is required (catastrophic failure of the tree), the ESP will automatically shut-in, allowing bottom hole pressure to increase; thereby, actuating the LLC valve. In addition, the LLC will provide a flow barrier during well kill and workover operations. This will reduce workover risk and cost during routine ESP replacements. The LLC valve has been successfully used by other operators in domestic U.S. onshore fields and has been used extensively in Russia. It is proposed to function test the LLC valves as follows: 1) Shut -in the ESP and close the wing valve. Monitor surface pressure and BHP via the ESP bottom hole pressure sensor ( If the sensor is not functioning, shoot fluid levels and calculate BHP). 2) When the pressure stabilizes, bleed off tubing pressure to +/- 100 psig. Continue monitoring surface pressure and BHP for 30 minutes. If the LLC is functioning, both surface and BHP should remain constant. If necessary, shoot another fluid level and calculate BHP. Granting this wavier will result in improved operating practices, reduced workover costs and risks and will extend the economic life of ESP wells in the Milne Point Unit. Therefore, BPX (A) contends that a favorable ruling will be in the best interests of the MPU working interest owners, the State of Alaska and will protect correlative rights. Give me a call at 564_-523_2 if you _ would like to set up a meeting to fur/her discuss this completion design change. Ve.~ truly yours,/~/"'~/"~ Milne'P~int Ex~ation Manager cc: S Rossberg, S Lynch, H. Mayson, T. Gray RECEIVED M~Y 18 1994 Gas Cons. Commission Anchorage WELL No. L-12 COMPLETION SKETCH MILNE POINT UNIT APl No.: 50-029-22334 PERMIT No.: 93-11 COMPLETED: 7-4-93 LAST WORKOVER: N/A 266 JTS. 2 7/8" TBG TOTAL WKM HANGER WITH 3" BPV PROFILE 16 JTS. 2 7/8" 6.5#/FT L-80 8rd EUE TBG. ELECTRIC SUBMERSIBLE PUMP CABLE NO. 2 CL-350 NOTES: ALL DEPTHS MEASURED KDB-SL = 51' KDB-GL = 28' MAX. ANGLE = 46' @ 4085' K.O.P. = 5O0' 4. SLANT HOLE: YES 5. TREE TYPE: WKM 2 9/16" APl 5000// W/ 2 7/8" 8rd TREETOP CONNECTION 6. MIN I.D. = OTIS 'X' NIPPLE (2.31,3" I.D.) @ 621' 7. COMPLETION FLUID: 10.2 PPG NaBr 8. STIMULATION: FRACTURE STIMULATION 150,000// 12-18 ISP BEHIND PIPE MK. LZ. LK P.ERFORATIONS DENSITY: 12 SPF, 5" CS(; GUNS 8751'-8771' MD (6940'-6955' TVD) 8812'-8832' MD (6987'-7002' TVD) 8854'-8864' MD (7019'-7027' TVD) 8878'-8888' MD (7038'-7045' TVD) 8910'-8940' MD (7061'-7085' TVD) 8950'-8980' MD (7093'-7117' TVD) 90,30'-9050' MD (7156'-7172' TVD) 7" 26#/FT L-80 CSG 587' 607' 619' 666' RECEIVED MAY 1 8 1994 maska Oil & Gas Cons. Commission Anchorage 2 7/8" OTIS FMX SCSSV ARROW HYDROW liP DUAL PACKER 2 7/8" OTIS 'X' NIPPLE (2.313" I.D.) 2 7/8" CAMCO KBMG MANDREL W/ 1" ORIFICE VALVE 246 JTS. 2 7/8" 6.5///FT L-80 8rd EUE '1'BG. 8471' 2 7/8" CAMCO KBMG MANDREL W/ 1" HOT OIL VALVE SET @ 3200 PSI 1 JT. 2 7/8" 6.5#/FT L-80 8rd EUE TBG. 8513' 2 7/8" CONE CHECK VALVE 2 JTS. 2 7/8" 6.5#/FT L-80 8rd EUE TBG. 8594' CENTRLIFT ESP, 251 STAOE, FC-925, 100 HP, 2145V/27A, GSBT, KRYTOX 8652' BOTTOM OF ESP 8706' BAKER MODEL 'D' PERM PKR W/ MILLOUT EXTENSION 8717' 20' OF 20 GAUGE SCREEN ON 4" BASE 8738' 6'LO 3 1/2" PUP JOINT 8744' CAMCO 'D' NIPPLE WITH A-2 BLANKING PLUG ON C-LOCK 8746' WlRELINE RE-ENTRY GUIDE 9224' PBTD _ CONOCO INC. ANCHORAGE DIVISION IAPPROVED BY: JHA DATE: 8-17-93 DRAFTED BY: G. FAST CAD FILE: W_COL12 _TYPIC.aL WE~~ gCHEMATIC __ _ -- - SHUT-IN FLUID LEVEL ~~-,~ WELL HEAD CASING TUBING -- SUBMERSIBLE PUMP CLOS LIQUID LEVEL SAFETY VALVE HYDRAULIC LOCK 3ER/RECEPTACLE -- PACKER WELL _ ,..~?-_~-POWER CABLE '":5%"~ z.-::.,..-.r-----~-'" PRODUCING --- FLUID LEVEL OPEN WELL t~,'f I 8 1994 oil & Gas Cons. Commissi, A~c~orage ARCO Alaska, Inc. ~' Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 May 21, 1992 Mr. David W. Johnston Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 RE: Safety Flares - Kuparuk River Unit Dear Chairman Johnston: ARCO Alaska, Inc. requests AOGCC administrative approval of an increase in the allowable safety flare volumes for the Kuparuk Central Production Facilities ("CPF's"). Rule 6 of Conservation Order No. 173 provides as follows: Rule 6. Safety Flares (a) The daily average volume of 250 MCF/day is permitted for a safety flare in the Central Production Facility operated by Atlantic Richfield Company. (b) Safety flare volumes for additional facilities may be approved administratively upon application. (c) Safety flare volumes may be increased or decreased administratively. Administrative approval No. 173.5 dated February 17, 1984 approved the flaring of 250 MCF/day as a safety flare at CPF- 2. Administrative approval No. 173.7 dated November 10, 1986 approved the flaring of 400 MCF/day as a safety flare at CPF- 3. Safety flare systems have been operating at each of the CPF's since the start-up of each of the facilities. Safety flare systems are necessary to assure the safe day-to-day operation of the facilities. RECEIVED / las/m .oil .& Gas Cons, ARCO Alaska, Inc. isa Subsidiary of AtlanticRichfieldCompany , ~. [~q _~...~.~ .,,,~ AR3B-6003-E; Mr. David W. Johnston May 21, 1992 Page 2 ARCO recently upgraded its safety flare system at CPF-1 so that it will burn smokelessly during flare events. As part of the upgrade, new metering systems were installed which more accurately measure the volumes of pilot, assist and purge gas which are necessary to operate the safety flare system. As a result of the new flare meters at CPF-1, we became aware that the daily volumes of pilot, assist and purge gas flared in the CPF-1 safety flare system are greater than previously thought. This caused us to investigate the volumes at CPF-2 and CPF-3 as well. We found that the safety flare volumes there were also greater than we had previously thought. Pursuant to Kuparuk Field Rule 6(c), ARCO respectfully requests administrative approval of the following changes to the safety flare volumes for each of the three CPF's: CPF-1 - CPF-2 - CPF-3 - 1,600 MCF/day 1,100 MCF/day 600 MCF/day These volumes have been necessary to operate the safety flare systems and necessary to assure the safety of each of the respective facilities. If you have any questions or desire further information, please call me at 265-1480. Very truly yours, W. H. Carter Kuparuk Operations Engineering Manager /cs johnston. Itt Safety Flare Purge Gas Safety Flare purge gas is high quality fuel gas which serves to perform the following vital safety functions: Prevent air intrusion into the flare tip and sweep out air that may leak into the flare system through valves, fittings, etc. This prevents formation of an explosive gas mixture in the flare piping. Vaporize and sweep out liquids that leak into or condense in the safety flare system. This helps maintain smokeless flare operations. Maintain safety flare system reliability by keeping flame at tip at all times regardless of ambient condition. Historically under severe weather conditions, pilot performance has been unreliable. Prevent flame flashback when significant back- mixing or leakage of air into the flare system resulting in burning from the inside and damage to the flare tip. Recent experience at Kuparuk has shown that damage to the safety flare system has been caused by inadequate purge gas rates. RECEIVED CPF-1 Safety Flare System New Smokeless Flare System has separate fuel meter to measure fuel usage for process and NGL flare pilots, backup purge and assist gas. Local flare tip has it's own meter for plant upset flare events. RECEIVED ,~laska Oil & 6as Cons. Commission 'anchorage CPF-1 NEW SMOKELESS FLARE EAST NGL TIP WEST NGL TIP EAST PROCESS FLARE BACKUP HP TIP NGL FLARE HEADER FT - 1400 Purge Gas FT-1058 E,..,~-,~ Purge Gas CPF FLARE HEADER LP TIP E = EXISTING N = NEW RECEIVED MAY 2 1 IB92 Alaska 0il .& Gas Cons. Commission ;Anchorage Eng Aide -LDS- 5/92 CPF-1 FLARE FUEL GAS HEADER ~- HP Pilots (3 ea) N ~- LP Pilots ( 3 ea ) N FI-1362B N HP Header Purge Backup FI-1362A N LP Header Purge Backup F1-1383 N , East Process Flare Purge Backup ~ NGL Pilots (3 East & 3 West ) N ~ NGL Assist ( East or West) E N East CPF E '"- Assist East CPF N Pilots 2 pilots only ) FLARE FUEL GAS HEADER I3C° E = EXISTING N -- NEW RECE VEE) Alaska 0il & Gas Cons. AllCtlO~'a(:Jt) ENO A.[DE-L,DS-5/92 CPF-2 Safety Flare System Safety Flare Purge gas is supplied as part of the plant fuel gas. Safety Flare purge gas balance. is determined by material Proposed Smokeless Flare systems, will meter purge, assist, and pilot gas similar to CPF-1. RrcCrclx/?-¢ CPF-2 FUEt GAS MATERIAL BALANCE FE - 1 O57 VENT VALVES TO FLARE ( leakage ) FLARE HEADER PURGES (7+ Dew Pt. Analyzers) GLYCOL SURGE TANK TO FLARE METHANOL TANK TO FLARE FI -1058 TO ~FLARE FE - 1051 FE - 1066A-C FE - 42026 A-F FE - 42006 ~)FE - 1053 GLYCOL STRIPPER GAS GLYCOL FLASH TANK GAS (estimate) FLASH DRUM MAKE-UP GAS (estimate) CRUDE SURGE DRUM MAKE-UP GAS (estimate) GAS LIFT COMPRESSOR (A,B,C) FUEL GAS UTILITY TURBINE GENERATOR (A-F) FUEL GAS UTILITY BROACH HEATER FUEL GAS ~ TO GAS COMPRESSION BURNED FUEL GAS FUEL GAS SUPPLY HEADER ESTIMATE FLARE VOLUMES BY DIFFERENCE WITH OTHER FUEL GAS USAGE RECEIVED MAY Alaska 0il & 6as Gons. (;ommiSSio~ Anchorage Eng Aide LDS- 5/92 CPF-3 Safety Flare System Safety Flare Purge and Pilot gas is supplied as part of the plant fuel gas. Total Safety Flare gas purge and pilot gas is determined by material balance. Proposed Smokeless Flare systems will meter flare gas similar to CPF-1. ~,~,.~.,-~'~ CPF-3 FUEL GAS MATERIAL BALANCE Fuel Gas System FI - 1147 mm,,,-- FI - 1489A BLANKET GAS TO SLOPE OILTANK ( Flare Purge ~ TO LP GLYCOL OVERHEAD RECEIVER ( Flare Purge ) F 9 FLARE HEADER PURGES ( 9 metered purges ) ~ TO HP FLARE Fl- 1489B FI - 1491A FI - 1491B GE FRAME 3 TURBINE GE FRAME 3 TURBINE RUSTON TURBINE ----- RUSTON TURBINE FI- 1490 ( ~ RUSTON TURBINE BROACH HEATER BURNED AS FUEL ESTIMATE FLARE VOLUMES BY DIFFERENCE WITH OTHER FUEL GAS USAGE ENG AIDE -LDS- 5/92 ARCO Alaska, Inc. '~ Post Office Bo^ 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 October 31, 1991 Mr. L. Smith Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 ENG ASST ENG A$ST SR G EOJ~VJ~ GEOL , ~G--E--~L ASST -- , STAT TECH I'STAT TECH !FILE __i Re' Revised Surface Casing Setting Depths Kuparuk River Field Dear Mr. Smith' This letter is to request Administrative Approval to vary from the existing Kuparuk River Field Rules, Conservation Order No. 173, to permit surface casing to be set as deep as 4200' TVD in development wells on pad 3R, which is a peripheral Kuparuk development pad. Pursuant to several previous discussions with you and your staff, which resulted in the establishment of Conservation Order Nos. 203 and 209, ARCO Alaska, Inc., has established a standard operating practice of setting surface casing 200' TVD below the base of the West Sak sands. In reviewing our geological structure maps, we estimate that for the pad in question the base of the West Sak will occur at a maximum depth of 4000' TVD. A depth of 4200' TVD would ensure that the multiple, discontinuous hydrocarbon-bearing sands occurring sporadically below the West Sak would be optimally isolated by the surface casing cement job. As stated in previous correspondence, our request for a deeper surface casing seat is made for the following reasons: . It is preferred to set the surface casing shoe 200' TVD below the West Sak sands. These sands can be better isolated with surface casing, as opposed to the past method of using production casing to isolate the sands. From a general review of Kuparuk well data, we feel that 200' TVD below the base of the West Sak will adequately ensure that casing is set below any small oil stringers sometimes found below the West Sak formation. RECEIVED AGO 10023362 ARCO Alaska, Inc_ is a Subsidiary of AtlanticRichfieldCompany NOV - 4 1991 0J] & Gas Cons. Coml~i$sion Mr. L. Smith October 31, Page 2 1991 . A better formation integrity test will be obtained prior to drilling into the Kuparuk sands. Although past formation integrity tests have been acceptable, drilling of the Kuparuk interval will be made safer with higher surface casing shoe integrity. . We feel that West Sak hydrocarbons can be safely drilled using a flow diverter stack on conductor casing. On previous Kuparuk development wells, the West Sak was safely drilled with a drilling fluid density of 9.0 ppg. The West Sak reservoir pressure is approximately 8.6 ppg equivalent, with no known gas/oil contact and a Iow solution GOR. . The information and experience gained from setting the surface casing deeper on previous pads indicate that the West Sak reservoir can be drilled safely with a conductor/diverter system. If you have any questions on the above, please call Steve Bradley at 265-4243. Sincerely, A. W. McBride Area Drilling Engineer AWM/SDB/bm AGO 10023363 RECEIVED ^taska. 0JJ & Gas Cons. Commissio[~ ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501o319'~ PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 May 23, 1991 Bob Soptei Coordinator-Env. Affairs Conoco Inc 3201 C St Ste 200 Anchorage AK 99503-2689 RE: SSSV Depth for MPU L-l, L-2, L-5, L-6, and L-7 Dear Mr. Soptei: I have received your letter of May 15, 1991 concerning the subsurface safety valve setting depth requirements as required by Rule 5 of Conservation Order #173. The Commission concludes that Conoco's intent was to be in full compliance with Rule 5 and that the less than 5% error in setting depths are inconsequential for the purpose of this rule. Your proposed procedure to make corrections only when subsequent workovers are performed upon each of these wells is fully acceptable. Sincerely, Lonnie C; Smith COMMISSIONER LCS/jt AGO 10023365 ARCO Alaska, I~ Post Offi~,...,ox 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 May 15, 1990 Mr. C. V. Chatterton Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Chatterton: SUBJECT: Revised Surface Casing Setting Depths Kuparuk River Field Pad 3G This letter is to request Administrative Approval to vary from the existing Kuparuk River Field Rules, Conservation Order No. 173, to permit surface casing to be set deeper than 2,700' TVD in development wells on pad 3G, which is a peripheral Kuparuk development pad. In previous discussions with you and your staff, which resulted in the establishment of Conservation Orders No. 203 and No. 209, ARCO Alaska Inc. established a standard operating procedure of setting surface casing at least 200' TVD below the base of the West Sak sands. In reviewing our geological structure maps, it is estimated that for the 3G Pad, the base of the West Sak will occur at a maximum depth of 2,870' TVD. A surface casing depth of 3,500' would ensure that the multiple, discontinuous hydrocarbon-bearing sands occurring sporadically below the West Sak would be isolated by the surface casing cement. A copy of ARCO's present Unit Development Status Map showing the location of the 3G pad with respect to the existing development of the CPF-1, CPF-2, and C PF-3 areas. Specific reasons for requesting a deeper surface casing setting depth are: I , It is preferential to set the surface casing at least 200' TVD below the base of the West Sak sands. These West Sak sands can be better isolated with surface casing than the old practice of attempting to isolate the sands with cement from the production casing. From a general review of Kuparuk well data, it has been observed that at least 200' TVD below the base of the West Sak 'sands will adequately provide that the sudace casing is set below any small oil stringers that are sometimes found below the West Sak formation. , A better formation integrity test will be obtained prior to drilling into the Kuparuk sands. Although past formation integrity test data has been acceptable, drilling through the Kuparuk interval will be safer with higher surface casing shoe integrity. AGO ].00Z3366 ARCO Alaska, Inc. is a Subsidiary of AllanticRichfieldCompany RECEIVED MAY 1 6 1990 ~:~,0Jl & Gas Cons, C0mmissb_. AR3L:q-.6003 -C Mr. C. V. Chatterton May 15, 1990 Page 2 . The West Sak hydrocarbon zones can be safely drilled using a flow diverter system on the conductor casing. On previous Kuparuk development wells, the West Sak was drilled safely with a drilling fluid density of 9.0 ppg. The West Sak reservoir pressure is approximately 8.6 ppg equivalent, with no known gas/oil contact and a Iow solution GOR. . Information and experience gathered from previously drilled pads in the Kuparuk River Field where the surface casing was set deeper than the established field rules indicates that the West Sak formation can be safely penetrated using a conductor/diverter system. Thank you for your consideration of this request. ARCO can furnish any further information you may need. Contact Mark Prestridge at 265-6952 if anything else is necessary. Sincerely, J. B. Kewin Regional Drilling Engineer JBK/MLP/mac Attachment cc: P. J. Archey 3G Pad General Wellfile AGO 10023367 RECEIVED 1 6 1990 .Oil & 6as Cons. ( ommiss[,oi KUPARUK RIVER UI~~ DRILL SITE LOCATIOh,~ KRU BOUNDARY 3-M KPA BOUNDARY 1-R 1-C 2-A 1-L 2-G 2-K I'WM 11116/88 AGO 10023368 Telecopy No. (907) 276-7542 December 19, 1989 Terri Skinner Sr Operations Eng ARCO Alaska, inc P O Box 100360 Anchorage, AK 99510-0360 Re: Key well change - lC pad Kuparuk River Unit Dear Ms Skinner: By this letter the Conm~ission acknowledges the replacement of key well 1C-04 with 1C-09 due to mechanical difficulties. Your notification of December 13, 1989 satisfies the requirements of Conservation Order No. 173, Rule 8, as modified by Conservation Order No. 230. Lonnie C Smith Commissioner Jo/A.RAD.90 AGO 10023369 ARCO Alaska, In~" Post Office. Jx 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 December 13, '1989 Mr. C. V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: Key Well Change Request for Kuparuk River Unit, Drill Site 1C Dear Mr Chatterton' ARCO ALASKA requests permission to change the key well designation at Drill Site lC for pressure reporting as required by State Conservation Order No. 173, Rule 8. Currently Well lC-04 is the key well, but a failed $SSV control line makes wireline operations in this well difficult. Due to the loss in control line pressure, the SSSV has failed in the closed position. This does not present a problem in daily operations because the well has been shut-in for several years as it produces at a GOR above the CPF-1 plant GOR limit. However, this condition does cause an operational and safety concern during wireline operations because the SSSV cannot be held open with conventional methods. It is proposed to replace Well lC-04 with Well lC-09. Well lC-09 is the direct offset to lC-04 as shown in the attached map. Well 1C-09 does not present any unusual hazards to wireline operations. Pressure measurements would be taken in the same manner as Well lC-04, with pressure bombs run to the middle of the C Sand after a 72 hour shut in period. If you have any questions, please call me at your convenience. Senior Operations Engineer Attachments ., RECEIVED Naska Oit & Gas Cons. AnChorage. ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany AGO 10023370 DEC 1. ':'.., tE)B9 ~nnhnr~nn AGO 10023371 ARCO Alaska, Inc. i Post Office Bo× 100360 Anchorage, Alaska 99510-0360 'Telephone 907 276 1215 ,~, April 13, 1989 Mr. C. V. Chatterton Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 SUBJECT: Revised Surface Casing Setting Depths Kuparuk River Field Dear Mr. Chatterton: This letter is to request Administrative Approval to vary from the existing Kuparuk River Field Rules, Conservation Order No. 173, to permit surface casing to be set as deep as 3000' TVD in development wells on pad 2K, which is a periph- eral Kuparuk development pad. Pursuant to several previous discussions with you and your staff, which resulted in the establishment of Conservation Order Nos. 203 and 209, ARCO Alaska Inc. has established a standard operating practice of setting surface casing 200' TVD below the base of the West Sak sands. In reviewing our geological structure maps, we estimate that for the pad in question the base of the West Sak will occur at a maximum depth of 2800' TVD. A depth of 3000' TVD would ensure that the multiple, discontinuous hydrocarbon-bearing sands occurring sporadically below the West Sak would be optimumly isolated by the surface casing cement job. To better orient you to the subject pad, included is a copy of our present Unit Development Status Map showing the location of the pad with respect to the existing development of our CPF-1, CPF-2 and CPF-3 areas. As stated in previous correspondence, our request for a deeper surface casing seat is made for the following rea- sons: · It is preferred to set the surface casing shoe 200' TVD below the West Sak sands. These sands can be better isolated with surface casing, as opposed to the past method of using production casing to isolate the sands. From a general review of Kuparuk well data, we feel RF. CEIVED AGO lO023B7Z ARCO Alaska, Inc, is a Subsidiary of AtlanticRichlieldCompany ..... ,f:.?:. ,Alaska.Oil a Gas Cons. Commissior~ '' Ar~chomge Mr. C. V. Ch~~''' rton April 13, 1989 Page 2 that 200' TVD below the base of the West Sak will adequately ensure that casing is set below any small oil stringers sometimes found below the West Sak formation. 2. A better formation integrity test will be obtained prior to drilling into the Kuparuk sands. Although past formation integrity tests have been acceptable, drilling of the Kuparuk interval will be made safer with higher surface casing shoe integrity. 3. We feel that West Sak hydrocarbons can be safely drilled using a flow diverter stack on conductor casing. On previous Kuparuk development wells, the West Sak was safely drilled will a drilling fluid density of 9.0 ppg. The West Sak reservoir pressure is approximately 8.6 ppg equivalent, with no known gas/oil contact and a low solution GOR. 4. The information and experience gained from setting the surface casing deeper on previous pads indicate that the West Sak reservoir can be drilled safely with a conductor/diverter system. If you have any questions on the above, please call Tom McKay at 265-6890. Sincerely, J. B. Kewin Regional Drilling Engineer JBK/TWM/ih Ltr01 3/23/89 cc: P. J. Archeyl~~ AGO 10023373 KUPARUK DRILL SITE RIVER UNIT LOCATIONS KRU BOUNDARY KPABOUNDARY~ 3-M 3-H 1-R 1-C 2-A 2-K 2-G 1-L AGO TWM 11/16/88 ARCO Alaska. Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 November 9, 1988 Mr. C. V. Chatterton Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Subject: Revised Surface Casing Setting Depths Kuparuk' 'f"//-' -' ~./ River Field ' Dear Mr. Chatterton: This letter is to request Administrative Approval to vary from the existing Kuparuk River Field Rules, Conservation Order No. 173, to permit surface casing to be set below 2700' from ground level in 3 exploratory wells within the Kuparuk River Oil Pool. The three subject wells and maximum anticipated surface casing setting depths are listed below. Wel 1 Name Surface Locati on Maxi mum Setting D, ept,h (,TVD) Kuparuk 34-11-10 No.1 .~O0'FSL, 900'FWL, Sec34, TllN, RIOE, t~ 3400' Kuparuk 9-12-10 No.1 1500'FNL, 780'FWL, Sec 9, T12N, RIOE, UM 3700' Kuparuk 3-11-8 No.1 210'FNL, 630'FEL, Sec 3, TllN, R8E, UM 2900' In Kuparuk 34-11-10 No. 1 and Kuparuk 9-12-10 No. 1 the revised setting depths are requested to allow surface casing to be set between the Ugnu and West Sak sands to accommodate coring of the West Sak Sand. It has been shown on previous Kuparuk development wells that the Ugnu can be safely drilled using a flow diverter stack on conductor casing and a drilling fluid density of 9.0 ppg. Our request for a deeper surface casing seat in Kuparuk 3-11-8 No. 1 is made for the following reasons: AGO 10023375 ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany RECEIVED I',:CV 1' A~aska Oil.& Gas Cons. Commissiou ', ~choragm ARCO Alaska, Ind[ Post Office I~ox 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 April 8, 1987 Mr. L. C. Smith Alaska Oil and Gas Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Smith' As discussed in your offices on Friday, April 3, ARCO Alaska, Inc. as Operator of the Kuparuk River Field is requesting amendments to Rule 8 of Conservation Order 173. These changes are needed to make the field rule more compatible with the current stage of reservoir management at Kuparuk. Attached are the suggested changes we discussed. If you have any questions, please call me at 263-4809. Sincerely, T. C. Skinner Senior Operations Engineer TCS-pg-O069 ARCO Alaska, inc. is a Subsidiary of AtlanticRichfieldCompany A G0 ]. 0 0 2 3 3 7 6 Mr. Lonni e April 8, 1987 Page 2 CONSERVATION ORDER NO. 173 PROPOSED RULE 8 Ao Bo De Ee Fe Ge A bottom-hole pressure survey shall be taken on each well prior to initial sustained production. (delete Section B). One well from each drill site will be designated a key well and a bottom-hole pressure survey on this well shall be taken annually. Bottom-hole pressures obtained by a static build-up pressure survey, a 24 hour shut-in instantaneous test, a multiple flow rate test or an injection fall-off test will be acceptable. Calcu- lation of bottom-hole pressures from surface data will be permit- ted for water injection wells. Data from the surveys required in this rule shall be filed with the Commission by the last day of the month following each calen- dar quarter in which a survey is taken. Reservoir Pressure Report, Form 10-412 shall be utilized for all surveys with attach- ments for complete additional data. Data submitted shall include, but are not limited to rate, pressure, time, depths, temperature and other well conditions necessary fore complete analysis of each survey being conducted. The Pool pressure datum plane shall be 6,200 feet subsea. Results and data from any special reservoir pressure monitoring techniques, tests or surveys shall also be submitted as prescribed in "E" of this rule. By administrative order the Commission may require additional pressure surveys or modify the key wells designated in "C" of this rule. AGO 10023377 Telecopy No. (907) 276-7542 January 14, 1987 Mr. T. R. Painter Divis ion Manager Conoco Inc. 3201 "C" Street, Suite 200 Anchorage, AK 99503 Dear Mr. Painter: The enclosed Administrative Approval (AA) No. 173.8 dated December 30, 1986 is a corrected copy that should replace the Administrative Approval No. 173.1, also dated December 30, 1986, which was recently sent to you. Please destroy all copies of AA No. 173.1 of that date. Sorry for this inconvenience, and please call me at 279-1433 should you have any questions. Sincerely, Commissioner Enclosure LCS: j ob AGO 10023378 Tom Painter Division Manager Conoco Inc. 3201 C Street Suite 200 Anchorage, AK 99503 December 12, 1986 Mr. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Chatterton: Conservation Order No. 173 Rule 9 Conoco requests exemption from Conservation Order No. 173 Rule 9 for Milne Point Unit wells B-10, C-l, C-2, and C-7. These wells are currently being supported by water injection but production and offset injection will be suspended in early 1987. Considering the circumstances, production profiles in these wells can not be justified. If you should have any questions please contact Don Girdler at 564-7637. Y~~T w/R. Painter Division Manager DRG/vv 500.~4 AGO 10023380 Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of ARCO Alaska, Inc. for a change in the minimum strain properties of surface casing used in the Kuparuk River Field. The Alaska Oil and Gas Conservation Commission has been requested, by letter dated November 7, 1986, to issue an order to amend Rule 4(d) of Conservation Order No. 173 to change the minimum strain requirements for the surface casing. A person who may be harmed if the requested order is issued, may file a written protest, prior to December 12, 1986, with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501 and request a hearing on the matter. If the protest is filed timely and raises a substantial and materia--~ issue crucial to the Commission's determination, a hearing on the matter will be held at the above address at 9:00 AM on January 7, 1987, in conformance with 20 AAC 25.540. If a hearing ~s to held', interested parties may confirm this by calling the Commission's office, (907) 279-1433, after December 12, 1986. If no such protest is timely filed, the Commission will consider issuance of an order without a hearing. Lonnie C. 'Smith Commissioner Alaska Oil & Gas Conservation Commission Published November 27, 1986 AGO 10023381 F STATE OF ALASKA ADVERTISING ORDER A0- ADVERTISING ORDER NO. 08-5577 Anchorage Daily News P. O. Box 149001 Anchorage, Alaska 99514-900.1 Alaska Oil & Gas Conservation ~ ssion 3001 Porcup~%e Drive Anchorage, Alaska 99501 AGENCY CONTACT Galyn Evans PHONE (907) 279-1433 DATES ADVERTISEMENT REQUIRED: DATE OF A.O. November 25, 1986 November 27, 1986 SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION UNITED STATES OF AMERICA STATE OF ~J ~ DIVISION. SS REMINDER INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. BEFORE ME, THE UNDERSIGNED, A NOTARY PUBLIC THIS DAY PERSONALLY APPEARED ~ WHO, BEING FIRST DULY SWORN, ACCORDING TO LAW, SAYS THAT HE/SHE IS THE ~~ OF~ PUBLISHED AT '_ _/~.~?~ _~ IN'SAID D~VISION ~'¢~ ANDSTATEOF ~ --AND THAT THE RATE CHARGED THEREON IS NOT IN EXCESS OF THE RATE SUBSCRIBED AND SWORN TO BEFORE ME THIS ~L_~ DAY OF~'~-~..~-~>.,~-~\~.ix. 19~ NOTARY PUBLI~ FOR STATE OF' MY COMMISSION EXPIRES u.:.C- 6 Alaska 0it & Gas ATTACH PROOF OF PUBLICATION HERE. I,--" ,Not,i~"~ 'i~'~bil'~:~i~'", ',, Alas~aOIl"and Gas", · conserv,'aflon commission', 'the'surface cas- ,, ,t .,'wi , /sTLonnie ¢.,:.smtth Cemml~slOner,' , Alaska' Oil, & :Gas Conservation ,cam,missiOn ' - P0b: NoVember 27, 1986 A0'-08;$577 ' 02-901 (Rev. 6-85) PUBLISHER AGO 10023382 Tom Painter Division Manager November 24, 1986 Conoco Inc. 3201 C Street Suite 200 Anchorage, AK 99503 Mr. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Chatterton: Conservation Order No. 173 Rule 9 Conoco requests exemption from Conservation Order No. 173 Rule 9 for the Milne Point C-5A well. This well is producing less titan 200 BOPD from two horizons; the Middle Kuparuk (10,784'-10,804') and the Laminated Zone (10,874'-10,882'; 10,894'-10,902'). The accuracy of flowmeters is limited by the low rates and the well is not supported by injection and therefore no productivity improvement is expected. Very , · · Division Manager DRG/kr cc: Well File Oil & Gas Co~. Commission Anchorage AGO 10023391 ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 November 7, 1986 Mr. C. V. Chatterton Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 SUBJECT: Proposed change to Field Rule 3c of Conservation Order No. 145 and Field Rule 4d of Conservation Order No. 173 Dear Mr. Chatterton' The purpose of this letter is to request changes in the following Prudhoe Bay and Kuparuk River Field rules; Rule 3c of Conservation Order No. 145 and Rule 4d of Conservation Order No. 173. Cur- rently, these rules require that surface casing in Prudhoe and Kuparuk must have minimum post-yield strain capacities of 0.9% in tension and 1.26% in compression. ARCO proposes that these strain capacities should be changed to 0.5% in tension and 0.7% in compression. The. forces that cause these strains are a direct result of permafrost thaw subsidence. See attachment for back- ground. There are three reasons why these changes should be made and they are as follows: 1. The present factors can result in over design. The original strain minimums of 0.9% in tension and 1.26% in compression were arrived at by applying a 1.8 design factor to a calcu- lated worst-case strain of 0.7% in compression and 0.5% in tension. This 1.8 design factor is only applicable when dynamic loading conditions exist. ARCO currently uses this 1.8 design factor on casing joint strength to allow for the tremendous impact loads which exist while running casing into the hole. Thaw subsidence is a static condition and does not require this large 1.8 design factor. Thaw subsidence design factors should be more in line with those used for the static conditions of burst and collapse which are 1.1 and 1.0 respec- tively. It should be noted that a casing failure caused by burst and collapse would be far more catastrophic than a surface casing failure due to thaw subsidence. Therefore, a 1.0 design factor should be utilized for thaw subsidence. RECEIVED AGO 10023383 ARCO Alaska, Inc. is a Subsidiary of AtlanllcRIchfieldCompany NOV 1 9 1986 Alaska 0il & Gas Cons. Commission Anchorage Page Two ~ Field Rules 3c & 4d November 7, 1986 2. The worst-case thaw subsidence strain calculations are very conservative and already have built-in design factors. The worst-case study strains are more than five times greater than those measured in the 5-spot thaw test which represented a producing period of 15 years. (Reference 1) This difference between measured and calculated strains is a good example of the magnitude of the "built-in" design factors. 3. More realistic design factors could result in considerable cost savings. Until recently, the field rules have not caused any inconvenience because all proposed surface casings have met the field rule requirements. Currently, alternate casing designs are being considered as part of our on-going effort to reduce drilling costs. Unnecessary additional design factors result in increased casing costs which are a significant percent of the total drilling cost. These costs not only impact drilling in current fields but also the feasibility of future marginal fields. In conclusion, ARCO Alaska, Inc. requests the administrative approval of the proposed field rule change which would eliminate the 1.8 design factor as applied to required post-yield strains for surface casing. If you have any questions or would like to discuss this matter further, please contact Rich Gremley at 265-1635. Sincerely, R. A. Ruedrich Dril ling Manager RAR/RBG/dmr misc:90 Reference 1. T. K. Perkins; J. A. Rochon; R. A. Ruedrich; F. J. Schuh; and G R Wooley; Prudhoe BaS Field Permafrost Casin~j and Well Design ~or ~haw Subsidence Protection, Atlantic Richfield Co., North American Producing Division, May 1975. RECEIV ED NOV 1 9 1986 AGO 1002338z~ ,'i AlaSka Oil & Gas Cons. Commission Anchorage' BACKGROUND Shortly after the discovery of the Prudhoe Bay Field, the industry became concerned with the possibility of casing and well damage as a result of permafrost thaw subsidence. In an effort to more fully evaluate thaw subsidence problems, the industry performed numerous laboratory, field and engineering studies. In 1973 Atlantic Rich- field and Exxon started thawing the permafrost in a closely spaced 5-spot well pattern. This thaw test was designed to simulate the thaw that would result from 15-20 years of production. The largest strains measured in the casing in this test are 0.13% in compres- sion and 0.08% in tension. In conjunction with the 5-spot thaw test, a computer model was developed to predict worst-case strains. These computed strains are the highest compressive and tensile strains that would result from the worst possible combination and relative thickness of sand and silt layers. The maximum thaw subsidence casing strains calculated by the model are 0.7% in compression and 0.5% in tension. A design factor of 1.8 was applied to these worst-case strains resulting in the current conservation order strains requirements of 1.26% in compression and 0.9% in tension. The following table compares the above mentioned strains. Compressi on Tensi on Measured 0.13% 0.08% Worst-case .7% 0.5% Conservation Order 1.26% 0.9% RECEIVED NOV 1 9 1986 'Alaska Oil & Gas Cons. Commission Anchorage AGO 10023385 ARCO Alaska, Inc. ~ Post Office Bu,, 100360 Anchorage, Alaska 99510-0360 Telephone 907 263 4509 'J. D. Weeks Kuparuk Operations Manager November 6, 1986 Mr. C. V. Chatterton, Chairman Alaska Oil & Gas Conservation 3001 Porcupine Drive Anchorage, AK 99501 Commission Dear Mr. Chatterton' Pursua vation Kuparu approv Facili startu requests a for CPF-3. This the 250 MCF/D safety flare permitted as approved by the Commission in Rule Conservation Order No. 173. nt to the provisions of Rule 6 (b) of the Conser- Order No. 173, ARCO Alaska, Inc., operator of the k River Field, respectfully requests administrative al to maintain a safety flare at Central ProdUction ty (CPF) No. 3. Presently, CPF-3 is scheduled for p in December,1 986. ARCO Alaska, Inc. hereby daily average safety flare volume of 400 MCF/D daily average is 150 MCF/D greater than for CPF-1 and CPF-2 6 (a) and 6 (b) of The primary reasons for the increased safety flare requirements are two-fold' Excessive CPF-2 as pressure at CPF-1 criteria minutes. meet the need for backpressures were encountered at CPF-1 and a result of the 24" flare tip design. Back- controllers and travel stops were installed and CPF-2 to meet the depressurization for plant blowdown to 5 PSIG within 15 The 36" CPF-3 flare tip has been designed to above depressurization criteria without the backpressure controllers or travel stops. 2) The larger CPF-3 flare tip requires a higher purge rate to prevent backburn. As always, if you or your staff have any questions regard- ing this request, or require additional information, please call me at the above listed number or T. Mark Drumm at 263-4212. ARCO representatives are available to discuss this with you at your convenience. Your prompt attention is appreciated. JDW'fl (0403) ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany RECEIVED NOV 1 3 1986 Naska Oil'& Gas Cons. Commission Anchorage AGO '1002338"/ KUPARUK RIVER UNIT IMMISCIBLE WAG INJECTION I. OBJECTIVES A. MORE EFFICIENTLY STORE GAS ONSITE B. MAINTAIN A-SAND PRODUCTION AT WATERFLOOD ONLY LEVELS. II. PROCEDURE Ao INJECT GAS IN TWO WELLS PER DRILL SITE AT AN OPTIMIZED RATE o MINIMIZE GAS BREAKTHROUGH MAINTAIN PRESSURE B. ROTATE GAS INJECTION WELLS III. PROPOSED PRojEcTs A. CPF-2 AREA B. CPF-3 AREA JBS:MLW:i 2/10/85 ~ A.f:, C-gCLE ~_ --~_V C'-/c ~E 3 , · C."J CLF_ , mUll I I, I imm · · · · , , gPF- 7~ PKo3~cT C, PF- $ p¢co ~c-i- 3G 3L lO IR IY 2U 2T 2X IA 2C 2J 2Z 2D 21 VV/~ CD IH IK IF iE ID IL il Id _J-- ~J.3~cq3 o~ IM 'l PROPOSED. MILNE. 'POINT UNIT KUPARUK WELL. .CASING PROGRAM :~ CE~EN~I'NG .PROGRA~ C0;!DUC~R'"'CASING: __ _ pERMAFRbST. CEIIE~T .ll) T~I£ 5~URFACE..· SU RFACE!.CASI NG: 'High .yield Arctic grade -cement across the permafrost wi th .convent i ona 1 .cement below per~mafrost. PRODUCTION CASING: Fi'~st Stage: Cl-a~'s ~"G" cement :displaced through :casing -shoe. .Second Stage- C.)ass "G" cement displaced through stage collar at -+ 4500'. · Third. Stage: Small amount of permafrost cement fo]lOwed by Arctic Pak bull;headed down the annulus. lb/it, H;40 PELP EST. TOC AT.5OO'[BOVE : UPPER ~CR~ACEOU$ S~D$ Stage collar at ± 4'500'. 'TVD. IIIIXX. E ICUPARU)C FORMATION .I m~_ I m i m i EXTE. RNAL CASING PACXER LO'~ER KUPARUK FORWATiON 26.0 lb/fl, L-80, BUTTRESS F,I.G,,.U R£_8_ ..... H. D. Haley Manager of Alaskan Operations August 2, 1984 Conoco Inc. 2525 C Street Suite 100 Anchorage, AK 99503 i: ...... ,L j I ST,:'.T TEC j FlkF;"'"'i~ I . j Ms. Earnesta B. Barnes Region X Administrator, USEPA 1200 6th Avenue Seattle, Washington 98101 Dear Ms. Barnes: Conoco Inc.', as Unit Operator, herewith submits a Form 4 application for an Underground Injection Control (UIC) Permit for the Mil.ne Point Unit Kuparuk River Waterflood/Pressure Maintenance Project. Attached to this letter of transmittal are Form 7520-6 and Attachments A, B, C, E, G, H, I, K, L, M, P, W, R, and T. Also included are maps, figures and tables supporting the subject application. Conoco will be available to discuss these details or to submit addition data. Please contact Jim Dosch at (907) 279-0611 with any questions or requests. Very truly yours, H. D. Haley Manager of Alaskan Operations RLD/kr Attachments cc: R. E. McKee, NAP, Houston, w/Attachments J. R. Kemp, NAP, Houston, w/Attachments J. T. Dosch, Anchorage, w/Attachments A. E. Hastings, Anchorage, w/Attachments R. J. Francis, Anchorage, w/Attachments R. L. Darr, Anchorage, w/Attachments Alaska Oil and Gas Conservation Commission, w/Attachments term ~DDrOVe(7. {Jn~tg IVO. zU~U-U~JeZ, tz x~r..e$ ~Y-JU-oo Form UN "STATES ENVIRONMENTAL PROTECTION ~GEN(' I. EPA I0 NUMBER . - Z~, ~ UNDERGROUND INJECTION CONTROL T/~ .~c * ~E PA PERMIT APPLICATION (Collected under the authorky of the Safe Drinking U UIC ~aterAct, Sec#ons 1421, 1422, ~ CFR 144~ -' READ A ~ACHED INSTRUCTIONS BEFORE STAR'TING " FOR OFFICIAL USE ONLY ~li~tion a~ro~ Data Received mo day yea~ mo day y~r P~rmit~ell N?mber Comments Facility Name Owner/Operator Name M~lne Po~n[ Un~ Conoco Street Address Street Address North Slope Borough 2525 C Street, Suite 100 ,,, , ..... , Ci~ State ZlPC~e Ci~ State ZIP C~e Anchorage ~ ~ ._-' . ~K~ ~ 99503 IV.'~NERSHiP STATUS (Mark 'x') ~:.~.~ ' ~ ~ _- V. SlCCO6ES .............. ~ A. F~eral ~ B. State ~ C. Private ,, D D. Public ~ E. Other (Explain) VI. WELL'S'TATUS [Mar, 'x'] ~. __~ __ . . . ' ' _~~~~.. . '- - , Date Stained ~ B. M~ification/Conversion ~. Propos~ O¢oratin~ , i i ~ __ i ~_ i I ~n- j nmi i .Vli..~pE' O~ PERMIT REQUESTED (Mark ~'andspec/fyifre,Uired) ," ~-~ __~ ...... ~.' Number of Exist- Number of Pro- Names) of field(s) or project(s) ~A. Individual ~B. Area ingwells posedwells H~Ine Point Unit Wate~flood/ 0 22 P~essu~e ~a~ntehance P~o~ect ., A. Class(es) B. Typ~s) C. If class is "other" or ~e is code 'x,' explain D. Number of wells per Wpe (if area permit) (enter c~sjJ (enter code(si) ~ ~. ~titudo B. kon~itudo Township and ~an~o., i[ ~ 13N 10E{ 13 (Complete the following questions on a separate sheet(s) and number accordingly; see instructions) FOR C~SSES I, II, Ill (and other classes) complete and submit on separate sheet(s) Attachments A-- U (pp 2-6) as appropriate. Attach maps where required. List attachments by letter which are applicable and are included with your application: I certify under the penalty of law that / have per~ona/!Y examined and am familiar w/th the information submitted in this docume~ and afl attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, / believe that the information is true, accurate, and complete. ! am aware that there are significant penalties for submitting fal~e information, including the possibility of fine and imprisonment. (Ref. 40 CFR 144.32} A. Nam; and Title ~YPe ;r Pr/n;) B, phone N0, (Are'a C~a and H. D. Haley - Manager of Alaskan Operations ~'~[C[~X/FS~ (907) 279-0611 EPA Form7620-6 {2-84) ' ...... "" '~'~ ~,~ (.~;,JS L;f)ll$. A. Conoco Inc. used the fixed radius method to determine the area of review. The area permit is for the Milne Point Unit and the area of review is for all lands underlying and one-quarter mile beyond the Unit boundary. Figure 1 indicates the current Unit boundary and well locations. B. A topographic map with the well locations as well as the surface facility locations within the review area is attached (see Figure 2). Figure 3'is a structure map on top of the injection interval. A flow diagram of the facJ. lities is shown on Figure 4. C. Table 1 provides a summary of the well data requested. No injec- tion well will be operated above fracture pressure. During an injectivity test performed in late 1982, surface injection pressure of 2600 psig was maintained with no evidence of pressure parting while injecting at the maximum rate of the surface equipment, 4600 BWPD. This surface pressure correlates to a 0.8 psi/ft, pressure gradient. Normal injection rates and pressures will be signifi- cantly lower than those obtained during the subject injectivity test. E. No Underground Source of Drinking Water (USDW) will be affected by the proposed injection, as all Unit wells will be cased through and cemented to prohibit any fluid migration. In addition, all injection will be through tubing and below a packer. The only USDW to be penetrated will be the Tertiary age water sands at ±3,000'. This water has a TDS of approximately 3300 ppm and will be' the source water for initial pressure maintenance injection. Also, this Tertiary water, after processing through a reverse osmosis unit, will be the potable water for the Milne Point Unit operations complex. G. The 300' gross interval of production is bounded on top and bottom by massive non-productive shale, sand-shale zones. Overlying the Kuparuk formation is a 900' thick shale interval. These shales have a porosity of approximately 8-10% and a permeability of 0.02-0.3 md. During the injectivity test performed in late 1982, a step-rate test was conducted with a maximum rate of 4600 BWPD at 2600 psig surface pressure. No evidence of pressure parting was observed. The B-1 well (Figure 5) provides the type log for the Mil.ne Point Unit that serves as the basis for the local stratigraphic nomenclature of the Lower Cretaceous interval. In B-l, the Middle Kuparuk interval is composed of two sandstone lobes; the upper lobe is termed the MK-1 and the lower lobe is termed the MK-2. Similarly, the upper and lower lobes of the Lower Kuparuk sandstone are termed LK-1 and LK-2, respectively. The term "Laminated Zone" is an informal name given to the thick sequence of coarsely to finely interlayered sandstone and shale that separates the Middle Kuparuk from the Lower Kuparuk. Two thin beds of sandstone that occur near the middle of the Laminated Zone are named, in descending order, the L-8 and L-9. E C E tV E D Alaska Oil & Oas Cons. Commission Anct~nr,~n~ H.(1)The projected ~verage daily injection rate is estimated to be 39,000 BWPD initially, increasing to 45,000 BWPD by 1989. Injec- tion will continue until approximately 1997 at which time an estimated 183 b~BW will have been injected while 53 b~O and 109 ~R~BW will have been produced. The initial injection rate per well will be 3,000 BWPD which, upon completion of Phase II development, will reduce to 2,000 BWPD per well. (2) Surface injection pressures are estimated at 1800-1900'~.".ps~g with surface facilities designed for a maximum of 2500 psig. (3) An inhibited sodium chloride/sodium bromide brine solution wi].], be utilized as the packer fluid to be retained in the annulus. (5) The source for this waterflood/pressure maintenance project will be the Tertiary Water Sands. The water source is located at approximately 3,000', identified on the B-1 type log (Figure 6), and has already been tested for both supply and compatibility with the proposed injection zone. Table No. 2 is a chemical analysis of the source water. Table 3 is a chemical analysis of water from the formation to be waterflooded. m~ Prior to rigging-up a drilling rig, conductor casing wi].l be set at 80', then cemented to the surface. Surface hole will be drilled to 2500'~ (TVD) with a 12¼" bit using a high viscosity freshwater-gelled mud. The 9-5/8" surface casing will be cemented to the surface in two stages with a high-yield Arctic grade across the permafrost and a conventional Arctic grade cement below the permafrost. Each well will be drilled from surface casing to TD (7200' ± TVD) with an 8~" bit using a low solids, lightly dispersed mud system. At TD, a short trip will be made to condition the hole prior to running the openhole logs. After the log runs, a conditioning trip will be made. Then 7" production casing will be run. Production casing will be cemented in three stages: (1) Class "G" cement displaced through the casing shoe, (2) Class "G" cement displaced through a stage collar at 4500'± (TVD), then (3) a small volume of permafrost cement followed by Arctic Pak to be bull-headed down the annulus. The completion assembly to be run will depend on whether the well is for water injection or production and if it will be hydraulically fractured. Flow tests will only be run on fractured wel].s where the frac fluid must be recovered. Packer fluid will be a 10.2 ppg sodium chloride-sodium bromide brine. Deviation of the wellbores will be monitored by Teleco-type survey tools in accordance with AOGCC requirements. There is no coring proposed for the development wells. Me Figures 7 and 8 are a wellhead drawing and a wellbore diagram, respectively, indicating the type and location of equipment. Q. The plugging and abandonment procedure will be as follows: (1) After the well is stabilized using a sodium chloride/sodium bromide weighted well fluid, a cement retainer will be set in the well ~100' over the perforated interval. The cement will then be squeezed through the retainer to provide a cement plug across each perforated interval by the balance method and will extend 100' above and 50' below the interval. This will be squeezed beneath the cement retainer with 50 sx. spotted on top of retainer. In addition to the cement plug across the perforated intervals, a 50-sack plug of permafrost cement will be spotted from ±150 to the surface. Below the permafrost interval, Class "G" cement with CaClo will be used. In the permafrost zone, permafrost cement will be u~ed. R. A Du Pont Company Annual Report is attached. Conoco is a wholly- owned Du Pont Company. A financial statement is included in the report. T. No existing EPA permits. U. Conoco operations consist of exploring for, developing reserves of, and producing crude oil and natural gas. Conoco, through subsidiaries, also refines, markets and transports petroleum products. OPTIONAL ATTACHMENTS I. The Milne Point testing program to date has been modified for each well. to fit the individual well's circumstances. However, the testing generally has been as follows: 1. During drilling operations, several of the wells were cored. This core was then analyzed and the chemical, and physical properties of the injection zone were determined. 2. Following completion, an extended flow and build-up test was conducted on several wells. The times vary but are approxi- mately 10-minute initial flow, 100-minute initial shut-in, 6-hour final flow, and a 24-hour final shut-in. 3. After analysis of this flowing and shut-in data, the following well parameters are arrived at: production rates, types of fluids, surface and bottomhole flowing pressure, and fluid properties. After analysis of the build-up, reservoir proper- ties are arrived at: kh, ko, s, and reservoir pressure. 4. An injectivitY test has also been performed on one well and the injectivity and estimate fracture pressure were deter- mined. Table 4 is a summary of the reservoir properties determined. K. The proposed injection program for the Milne Point Unit water- flood/pressure maintenance project is as follows (see Figure 4). Water will be pumped from three Tertiary source wells through equipment to remove solids and gas then going into a surge tank. From the surge tank, the injection water will be fed into the charge pumps, then through a flotation cell and on to the high pressure injection pumps. Once the water is pressurized, it will be pumped to the injection manifolds and through manual control valves, to the individual injection wells. The water is then injected into the formation via injection tubing beneath a packer' set at ±150' above the perforated interval. Figure 9 is a sche- matic of the proposed downhole injection system. P. The monitoring program will consist of daily pressure and rate measurement on each injection well as well as a total project injection volume. Each well will be profiled in accordance with the Alaska Oil and Gas Conservation Commission regulations to determine the scope of the injection. The profile will consist of either radioactive tracer profiles or temperature profiles or both. In addition to this, any change in either rate or pressure during.. normal injection will. be thoroughly investigated. :~:'~ i'i i ~ ~[ ,";, ;;h ¢' .,,,i Well Name Proposed We].]. Type MPU A-1 P&A MPU A-2 P&A MPU B-1 Water Source Well MPU B-3 TSI MPU B-4 P&A MPU B-4A TSI MPU B-5 P&A MPU C-1 TSI MPU C-2 TSI MPU C-3 TSI M?U C-4 TSI MPU D-1 TSI MPU D-2 P&A MPU D-2A TSI MP 18-1 P&A Kavearak Pt. No.32-25 TSI TABLE 1 Spud Date Bottomhole Location 2-5 -80 12-17-82 1-4-81 4-29-81 5-23-82 6-27-82 8-2-82 12-24-81 11-22-82 4-29-82 9-7-82 1-19-82 2-10-83 2-25-83 4-30-70 6-19-69 2113' FNL,2067' FEL Sec.23,T13N,R10E 4841' FNL,3133' FEL Sec.23,T13N,R10E 1427' FNL,4092' FEL Sec.19,T13N,R10E 462' FNL,964' FEL Sec.24,T13N,R10E 2306' FSL,2029' ~L Sec.18,T13N,RllE 1475' FNL,3514' FEL Sec.24,T13N,RlOE 924' FNL,1037' FWL Sec.20,T13N,RllE 913' FSL,2168' FEL Sec~10,T13N,R10E 1245' FSL,1433' FNL Sec.ll,T13N,R10E 4369' FSL,3651' FEL Sec.10,T13N,RiOE 885' FSL,732' FEL Sec.3,T13N,R10E 1564' FSL,914' FEL Sec.12,T13N,R10E 921' FSL,3715' FEL Sec.12,T13N,R10E 2089' FNL,678' FEL Sec.14,T13N,R10E 3850' FSL,3030' FWL Sec.ll,T13N,R10E 1360' FNL,1979' Sec.25,T13N,R10E Total Depth (Ft) Zone 10,180' ?~-2 9,208 ' None 9,635' MK-2 8,240' M!K-2 8,800' None 9,500' MK-2 9,530 ' None 10,442' LK-1,LK-2 MK-1 8,900' LK-1,LK-2 8,848' LK-1 ,LK-2 MK-1 9,400' MK-1 9,913' MK-2 8,300' None 9,340' MK-I&2 11,074' FEL 9,799' Well Name Proposed Well Type L-1 TSI M-! P&A M-lA TSI N-1 P&A N-lA P&A N-lB TSI Simpson Lagoon 32-14 Simpson Lagoon 32-14A P&A P&A TABLE 1 (Continued) Spud Date Bottomhole Location 4-28-84 307' FEL,2397' FNL Sec.8,T13N,R10E 2-23-84 2590' FNL,3334' FEL Sec.24,T13N,R9E 3-12-84 1148' FSL,1044' ~L Sec. 24,T13N,R9E 1-5-84 1089' FSL,1329' FEL Sec.30,T13N,RIOE 1-18-84 1139' FNL,2342' FEL Sec.31,T13N,R10E 4-28-84 1295' FNL,1202' FNL Sec.31,T13N,R10E 7-18-69 660' FNL,660' FNL Sec. 14,T13N,R9E 9-14-69 1100' FSL,660' FNL Sec.14,T13N,R9E' Total Depth (Ft) 9,500' 9,000' 10,282' 7,650' 8,634' 9,208' 10,483' 12,456' Zone TABLE 2 WATER ANALYSIS REPORT Well Name: Milne Point Unit, B-1 Water Well Formation: Prince Creek Sample Point: Bleeder Hose Date Collected: 11-1-82 ANALYSIS RESULTS Specific Gravity: 1.003 Resistivity at 73°F 1.650 OHMMeters PH: 7.20 MEQ/L MG/L MEQ/L MG/L Total Salts 3320 Sodium 46.4 1068 Hydrogen Sulfide 0 Chloride (CL) 53.5 1900 Magnesium (MG) 0.9 16 Sulfate (SO4) 0.0 3 Calcium (CA) 6.1 122 Carbonate (CO3) 0.0 0 Barium (BA) 0.0 0 Bicarbonate (HC03) 2.6 163 Iron (MG/L) Total 0 Diss 0.5 Hydroxyl (OH) Suspended Solids 8.8 OTHER ANALYSIS K 88 (MG/L) Trace Analysis Silver (AG) <.030 Nickel (NI) <.075 Aluminum (AL) <.15 Lead (PB) <.25 Boron (B) .11 Antimony (SB) <.25 Beryllium (BE) <.005 Tin (SN) .11 Cadmium (CD) <.015 Strontium (SR) 2.3 Chromium (L/t) <.03 Titanium (TI) <.025 Copper (CU) <.015 Thallium (TL) <.50 Iron (FE) .06 Vanadium (V) <.025 Manganese (MN) .19 Zine (ZN) <.025 Molybdenum (MO) <.05 Mercury <.002 Nitrate <1 Selenium <002 Arsenic <.002 ~O/L TABLE 3 WATER ANALYSIS REPORT Well Name: Milne Point Unit, B-1 Water Well Formation: Kuparuk Sample Point: Date Collected: 7-28-80 Specific Gravity: 1.0174 Total Salts Hydrogen Sulfide Chloride (CL) Sulfate (SO4) Carbonate (CO3) Bicarbonate (HCO3) Hydroxyl (OH) Potassium Strontium ANALYSIS RESULTS Resistivity at 68°F 0.28 OHM Meters PH: 7.40 MEQ/L MG/L MEQ/L 324.3 0.3 0.0 58.4 25233 Sodium 429.5 MG/L 9875 11500 Magnesium (MG) 13 Calcium (CA) 0 Barium (BA) 3560 Iron (MG/L) Total Suspended Solids 120 3.9 1.5 4.3 0.6 · 3 Diss 18 86 39 18 8.8 TABLE 4 Reservoir Properties Porosity: Middle Kuparuk Lower Kuparuk Permeability: Absolute Air Permeability Oil Permeability Range Middle Kuparuk Average Lower Kuparuk Average Average Water Saturation: Middle Kuparuk Lower Kuparuk Oil Viscosity (at 100°F) Oil Gravity (average) Bw at 3540 psi Bo at 3540 psi (reservoir pressure) Bo at 2125 psi BPP GOR Gas Gravity (Air = 1.00) .183 .215 50-4890 md 34-330 md 158 md 60 md .271 .210 40 cp 22°API 1.024 BBL/STB 1.153 BBL/STB 1.164 BBL/STB 290 SCF/BBL 0.65 Figure 1 Figure 2 Figure 3 Figure 4 Figure 5 Figure 6 Figure 7 Figure 8 Figure 9 LIST OF ATTACHMENTS Vicinity and Unit Expansion Map Topographic Map Structure Map with Faults Facilities Line Drawing B-1 Type Log B-1 Water Source Interval Log Wellhead Schematic Do~hole Casing Plat Downhole Injection Schematic Tab le 1 Tab le 2 Tab le 3 Table 4 Well Data Water Analysis Kup Water Analysis Reservoir Data Summary I If P $ 0 N . . · II ...... eC~ M ¥11me Point ,4 ~ 0 0 POIITT UNIT BOUNDARY RIVER PARTICIPATING ~ BOUND~Y ..,.~ · · · · '. · ::: Imlmlmmmmmmlmm ::::~ · ::::i:~ · : . O~L Ii/liBel · · · II ~ · · · · · · ..' lllmmmm~ Point 4 --- TI) N TI2N 0 I E ~ SCALE IN hl I LES CONOCO MILNE POINT i i ii · i UNIT ... · $ 30 ,31 t ~Z , · -' KUPARUK RI, ER P.~RTICi- / PATING ARE~ BDRY. lllll e*lli 'emleeee r/ ............ I, II ,NE: PT. UNIT BI]RY. ZI ' Z7 24 19 t$ 14 ! !1 , ! · ,. ¢o~o~o) i1~' ' '~ILflE POINT UNIT '!7 MIDDLE KUPARUK HORIZON · JULY 17, Ig84 C.I.:IO0' I" ; I ~1. I II OTHER PRODUCED WATER PRODUCED WATER BOOSTER PUMPS PRODUCED FLUtO ( IST. STAGE 2ND STAGE SEP SEP. L A TURBINE A! METER ANUAL NTEOL VALVE TO INJECTION WELL TO INDIVIDUAL~ INd. WELLS __ ii ii SEE CROSS~, SECTION A- ~ BELOW ~ SOURCE WATER · TO WELL PAD INJEC- TION MOD. WATER I I I I iii (cOnoco) MILNE POINT UNIT INdECTION 'FACILITIES II I · · MULTI-MEDIA FILTER INJECTION PUMPS x M. P.U. B-[ TYPE- LOG KELLY BUSHING ELEV. .E,~IDDLE KU?ARUK SkNDS LA~,~INATED ZONE LO\VER KUPARUK SANDS 7217(-6977] 7"~o(-~O~Ol ----1..8 ?;t041-70S4) 7~ · (-70 -L9 737~ ~-713~} 139f (-71511 7~Zl(-?lSi) 7442 1-7201) ' 7466 (-7226} J ~ ' ]] , ,;% ~ ~:' i '~ :,.--_'_ . / : .'~ ... ,,:.. I .. ·,,, i ! ,, ' ~')' ~ , ~1 ~-L_'-~..; ~ i . ':,3:- , · -;------, - ~. : ,a ~ :____ .- .- . , .,,.?~,%* ) .... .,,_:,~,. ..... .. :", "> ~ [~ ,i - ~ ' : . - , 'L..__i I: : ' ',':' '_ : i ,': _---?' ~ I . ; -i , i ; ", --J , . "- ' . i ' ~ ,] [ ,~ .r . .L.. . :., ; i ' ~ : I' ' :" ' · "..': ! ':) ]:: t I :. " ' : : ::E: i :! ';>_.1 . L] _ ? ' '-*-..- ! ;...: . . i ,,7::.~.---{, . :.. . .... ~ ~ .... :::. : ; ¢ ~"t i ,, FIGURE 13-1 TYPE-LO~ TERTIARY !,¥ATER SANDS Sl:>O N T'~J~E OU $ ' POTENT I AL t GAMMA RAY ./-/,-.///.-//,z/,z.,,~/,/.z/.~;- · t_-:i 'i~' - ' ~---'---';-~ d". 1 , 4 ',, -I FIGURE 6 TYPICAL WELLHEAD SCHEMAT~, NOTICE OF PUBLIC HEARING STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of ARCO ALASKA, INC., dated May 2, 1983, requesting an exception to Rule 4(c) of Conservation Order No. 173 in order to set surface casing deeper on three specific drill pads in the Kuparuk River Field than now allowed. Notice is hereby given that ARCO ALASKA, INC. has requested the Alaska Oil and Gas Conservation Commission, to issue an order granting an exception to Rule 4(c) of Conservation Order No. 173 for wells to be drilled from Pads 2Z, 2X, and 2C in the Kuparuk River Field. The exception is requested in order to provide a higher degree of integrety in isolating the potentially commer- cial hydrocarbon bearing Ugnu and West Sak zones by covering same with cement lifted from the shoe of the surface casing rather than with cement lifted from the shoe of the deeper production string. Parties who may be aggrieved if the order is issued granting the reference exception are allowed 10 days from the date of this publication in which to file a protest, in writing, stating in detail the nature of their aggrievement and their request for a hearing. The place of filing is the Alaska Oil and Gas Conserva- tion Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501. If such a protest is timely filed, a hearing on the matter will be held at the above address at 9:00 AM on May 16, 1983 at which time protestants and others may be heard. If no such protest is timely filed, the Commission will consider the issuance of the order without a hearing. C~~'~a er C~a~m~ Alaska Oil and Gas Conservation Commission AGO 10023392 TH~ AI'~CHEIRAGJ< TI~, BOX ~0 AN Cid ORAG~'~, ALASKA 99510-0040 AK OIL-GAS CONSERVA'£10N 3001 FORCUPINE Ok. AbC .ORAGE, AK 99501 DEBOY ~. AUSTIN , BEING UULY SWORN, ACCORDING TO LAW DECLARES: THAT SHE IS THE LEGAL CLERK OF THE ANCHORAGE TINES, A DAILY N~WSPAPER PUBL1SRED IN l:hM TOWN OF ANCHORAGE IN TH£ THIRD JUDICIAL DIVISION, STATE OF ALASKA, AND THAT THE NOTICE Of,.............,.,......... A0-08 5528 A COP~ OF WHICH I$ HERETO ATTACHED, WAS PUBLISHED IN....,...,,..,...... OF THE ANCHORAGE TINES. BEGINNING ON.............,......... ~NDiMG ON........,....,.,..,.,..... 1 ISSUE~ 1,1/04/83 11/04/83 THE SI, Z~ OF THIS AD ~AS............ 71 LIN'~S THE PRICE OF SIGNED.,...,. THIS AD IS..,.......... $ 21.30 IS.................... 1657560 ~ "-~YA'¥1~ OF ALASKA, NOTICE OF PUBLIC' HEARING ~" , STATE OF : ' Alaska 011 end G.s' - Conservation Commission . . Re: The application of ARCO ALASKA, I NC., dated October 25, 1983, requesting, an exceP- tion to Rule 4(c) o~: Conserva- tlo. n Or.der No..173'J.n or.der to am surface casmg m a.aee~er :'depth for wells'drilled fram pods 2A, 2B, 2D, 2F., 2G,.2H, and 2V In the KugaruR River 'Pleld;' - . . ..... :i,: '~'~{%';vi,'~!',, ',"', ~ ," '.","~ "/'~'~ ,',, ,,' ,,,:i~J;ice ',is, herebY::~J~en .that Al~¢~:'Alas'ka~:' l:n~,i,;." .has' .re- cepffon: to. Rule. 4(p_)~:o3 co. nser.- vatl0n Order NO..dZ~ mr aevm- o~ent wells to be drilled from. pa~lj2A, 2B~ 2D, 2F~ 2G, 2H, aha 2VJ~ the Kuporuic'Rlver' Field. -'FhJ [~-e~tlo~: :~.1~' .~l~io~ted.'-In orO to cemem: surface cas.ng bel~ '. the .West Sak;SandsJn me area at the fleld~l~er-g ,the ~o- terff. I ill,/ p~slluctI.Ke: ~t San'~ ~ would' be I~e~ ~'~teeted ad~l~ ~l~ted than Cidd~r"¢Urrent r~l.~j :~A. deeper sueface :~aslnq ~e~j ~as alreadY'~Se.en proveq to..U b sate practJpe. Ln. severm web in the same · m.,. gr~J~sd if the order grai%'lng the referenced request are:.,,ilowed 10 da,/s from the date ~f this publlcatlan In which to fire a protest, In writing, stat- lng. In detail the nature of their aggrlevement and their request for a hearing. The pla¢~ of fill Is the Alaska Oil and.Gas servatlon Commission, 31 )1 Porcu~ine Drive, Anchorm "Al~S.ko, 9950] .I f s~ch .a p'rotest Is Um.e.w fi!ea., a.'. h.~r:!ng..on.'! ~e . .mgtrer will De nevada' the:abe ~e address at 9:00 A.,M.'..'0n. Nave ~ ~ :'.16, 1983 at. wh ICh' ti me, r :..testonts .and othe. rs- m~y: "heaYd. If .no '~'such;"P~otest.' Is .'.tl:~lY filed,, the., (~0m~l%s ~llj; :onslde~ the ~sguan~'ot> .'.'order without a heart.rigid:"..,. ,<, .' , , ,. ~ ',',. ,,, , , .~ comm~sslone~'~. '/,. ~. I. Conse~vattsff'C0.~ m~'ss , ,,., , ,., t" i ~, , i,'F~'' ~ ;' ,,~',r :' / ~:: NoV~ 4~ ~e~, SUBSCRIBED AND S~ORN TO BEFORE ME THIS...,......,.....,.. NOTARY PUBLIC OF TH5 STATE Of' ALASKA 04 DAY OF NOV,1983 NY C,J~,~IS$ION EXPIRES.......,.....,. AGO 10023395 ARCO Alaska, Inc. 'ii North Slope District Post Office Box 360 Anchorage, Alaska 99510 Telephone 907 277 5637 James M, Posey District Landman January 20, 1982 Kay Brown, Acting Director Division of Minerals, Energy and Management Department of Natural Resources State of Alaska 703 West Northern Lights Blvd. Suite 100 · Anchorage, Alaska 99503 RE' Application for Approval of Kuparuk River Unit Dear Ms. Brown' Recently Amoco Production Company, P.O. Box 779, Anchorage, Alaska 99510 executed the Kuparuk River Unit Agreement and Kuparuk River Unit Operating Agreement on January 8, 1982. I am attaching 10 copies of the appropriate signature pages for your review and handling. Reference was made to Amoco Production Company in the Affidavit supplied as Exhibit C to the application. If you have any questions or if I can be of further assistance, please advise me. j~.ry trul~ . M. Posey ~ Land Manager SMW/JMP/ml Attachment cc: R. T. Anderson, Union Michael Arruda, Department of Law B. Giles, Amoco W. J. McMillian, ARCO J. Miller, BP R. W. Newton, Sohio D. M. Pilcher, BP S. M. Williams, ARCO ARCO Alaska, Inc. is a subs[diary of Atl,~nticRich/ieldCompany IN WITNESS WHEREOF, the parties hereto have executed' this Agreement on the dates opposite their respective sig'- natures. · ARCO Alaska, Inc. 711 West 8th Avenue P.O. Box 360 Anchorage, Alaska 99510 BP Alaska Exploration Inc. Title :' ~","C~'~'~ ~:~ One Maritime Plaza San Francisco, CA 94111 Attest: By- Title · Sohio Alaska Petroleum Company t00 Pine Street San Francisco, CA 94111 -29- Union 0il Company of California P.O. Box 7600 Los Angeles, California 90051 Exxon Corporation By: Title- 1800 Avenue of the Stars Dos Angeles, CA 90067 Attest · E~te: Attest: Mobil Oil Corporation By- ~ Tit!e' P.O. Box 5444, Terminal Annex Denver, Colorado 80202 ~te - Attest: Phillips Petroleum Company By' Title · 7800 E. Dorado Place Englewood, Colorado 80111 D~te · A~test - -30- Chevron U.S.A. Inc. By: Ti tle' 575 Market Street San Francisco, California 94105 Date: Attest- Amoco Production Company By: P.0. Box 779 Anchorage, Alaska 99510 Attest: APPROVED AND ACCEPTED: STATE OF ALASKA · By' Title: Date - Attest- STATE OF ALASKA THIRD JUDICIAL DISTRICT On this / day of December in the year on~e~t usand · ,~ . nine hundred and eighty-one, before me, I~:,,~k ~.- (~,%-,.--~-f , a Notary Public, State of ~a~ka, du!-z co~Issioned and sworn, personally appeared ~~ ~. -~~~~ ~o~ to me to be the /~~~ of ARCO Alaska, Inc., the cor~o~a~ion described in ~d ~hat executed the within inst~ent, and also kno~ to me to be the pe~son who executed the within inst~ent on beh~f of the co~po~ation therein n~ed, and ac~owledged to me that such co~po~ation executed the s~e. In Witness Whereof I have hereunto set my hand and affixed my official seal at Anchorage, A!askk the day and year in this certificate first above written. Notary Public, State of Alaska My Commission Expires-_ STATE OF ALASKA ) ) SS. THIRD JUDICIAL DISTRICT On this ~ day of December in e year one.lhousand nine hundred and eighty-one, before me, a Notary Pubiic~ State of Aiaska, duly co, lesioned ~d sworn, personally appeared '-~ kno~ to me to be the [~,-.-:..-.,,. of BP Alaska Exploration Inc., the co~po~ation described in and that executed the within instr~ent, and also ~o~ to me to be the person who executed the within instr~ent on behalf of the corporation therein n~ed, and acknowledged to me that such corporation executed the s~e. In Witness 'Whereof I have hereunto set my hand and affixed my official seal at Anchorage, Alaska the day and year in this certificate first above written. .. Notary Public, State of Alaska My Commission Expires: 3~/3/ ~P~ -32- STATE OF ALASKA THIRD JUDICIAL DISTRICT On this :~7~ day of December in the year one thousand nine hundred and eighty-one, before me, ~~°~o.~.-~~, a Notary Public, State of Alaska, duly co~imissioned and sworn, personally appeared known to me to be the of Sohio Alaska Petroleum Company, the corporation described in and that executed the within instrument, and also known to me to be the person who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such. corporation executed the same. In Witness Whereof I have hereunto set my hand and affixed my official seal at Anchorage, .A_-lask. a the day and year in this certificate first above written. Notary Public, State o£ Ala. ska My Commiss~ion Expires: STATE OF ALASKA THIRD JUDICIAL DISTRICT On this /~_~ day of December in the year one thousand nine hundred and eighty-one, before me,~ ...~/¢~ ~;/, ,,~/~_~_,. · a Notary Public, State of A£~ska, d.~,Y ,c35~issioned and sworn, personally appeared '~ f. "- ' ~ known to me to be the ~-cw.~.,~ ..... :.~_. ~ /-~-- of Union Oil Company of California, th'~ co~poration described in and that executed the within instrment, and also known to me to be the person who executed the within instrument on behalf of the corporation therein n~ed, and acknowledged to me that such corporation executed the same. In Wi.tness Whereof I have hereunto set my hand and affixed my official seal at Anchorage, Alaska the day and year in this certificate first above written. Notary ?~'blic, State of Ala. ska~ / My Comm~sion Expires: -33- STATE OF -A~ THIRD JUDICIAL DISTRICT On this ~ day offs/~_~/ in the year thousand nine h~undred a~Y ~.~ befo~ ~e,~~~~~~ , a Notary ~ublic, state o~~~y co.lesioned and sworn, personally appeare~~~~~ /~~ ~-- , known to me to be the ~~.~ of ~oco Production Company, the ~orpor' a6fon des6ribed in ~d that executed the within instr~ent. and also ~oE to me to be the person who executed the within instr~ent on behalf of the corporation there~ n~ed, and acknowledged to me that such corporation executed the s~e. In Witness Whereof I h her t _DI~z hand and affixed my official seal a .......... °.7, ~--~,~ e d~a and year in this certificate first above written. RS~ary Publi'~~ State of My Commissi~m Expires' IN WITNESS WHEREOF, the parties hereto have executed' this Agreement on the dates opposite their respective sig'- natures. ARCO Alaska, Inc. Ti ~l~e:/~/~ .~.f/D~ ~/~ ' 711 West 8th Avenue P.O. Box 360 Anchorage, Alaska 99510 Date: BP Alaska Exploration Inc. One Maritime Plaza San Francisco, CA 94111 Sohio Alaska Petroleum Company By' Title · 100 Pine Street San Francisco, CA 94111 Attest- Date / _. .. -29- Union Oil Company of California P.O. Box 7600 Los Angeles, California 90051 Exxon Corporation By: Title: 1800 Avenue of the Stars Los Angeles, CA 90067' Attest: E~te: Attes t: Mobil Oil Corporation By: Title: P.O. Box 5444, Terminal Denver, Colorado 80202 Annex Attest: Phillips Petroleum Company By: Title: 7800 E. Dorado Place Englewood, Colorado 80!11 E~te: A~te s t: -30- Chevron U.S.A. Inc. By- Ti tl e: 575 Market Street San Francisco, California 94105 Date: Attest: Amoco Production Company Ti tl e: i~l~s P.0. Box 779 Anchorage, Alaska 99510 ~ Date~ ~! Attest: APPROVED AND ACCEPTED: STATE OF ALASKA By: Title' Date: Attest: -31- ARCO Oil and Gas Co['-'""' ~ny North Slope District Post Office Box .360 Anchorage. Alaska 99510 Telephone 907 277 5637 Jerry J. Pawelek District Kuparuk Engineer December 16, 1981 Hoyle H. Hamilton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Hamilton: Re: Application for Additional Recovery Kuparuk River Field T 11 N, R 10 E, U.M. Sections 5, 6, 7, 8, 15, 16, 21 and 22 Pursuant to 20 AAC 25.400., ARCO Alaska, Inc. , a subsidiary of Atlantic Richfield Company, hereby submits for Alaska Oil and Gas Conservation Commission (AOGCC) approval the attached Application for Addi- tional Recovery for the subject area. This area is part of the Kuparuk River Field as defined in Conserva- tion Order No. 173. As we presented to the AOGCC in an informal meeting on October 9, 1981, the proposed additional recovery project, hereafter referred to as the Increment I Waterflood, will be a field demonstration, or "pilot", waterflood designed to optimize and reduce the risks of a possible full field waterflood. Increment I will involve 46 wells for both injection and production. This includes an existing 16 wells that will be part of the Phase I start-up in December of this year. An estimated injection rate of 50,000 BWPD will be suppli- ed by seven to ten Cretaceous source water wells. Increment I start-up is scheduled for early 1983. Some of the Increment I wells will be drilled on 160-acre spacing, some on 80-acre spacing, and some on 40-acre spacing for the purpose of optimizing well spacing. However, according to Rule 3 of the Field Rules, well density is limited to 160-acre spacing. We ARCO Oil and Gas Company is a Division of AtlanticRichlieldCompany December 16, 1981 Hoyle H. Hamilton Page Two are proposing that exceptions to this rule for our 40-acre and 80-acre wells in Increment I be applied for on a well-by-well basis prior to field unitization. After field unitization we anticipate requesting a change in the field .rules to allow for the denser spacing. If you have any questions about the attached informa- tion, please call me at 263-4205. Sincerely, ~I'~ ' .!."'~ ×2 ~ .~]. J. Pawelek Kuparuk District Engineer JSS/bl Attachments cc: J. S. Dayton G. L. Downey R. A. Flohr, Sohio G. H. Graham, Union P. Hardwick, BPAE W. H. McMillian D. W. Moore J. M. Posey A. J. Schuyler S. M. Williams File: KP 1.9-4 Application for Additional Recovery 20 AAC 25.400 Kuparuk River Field Increment I Waterflood Application for Additional Recovery 20 AAC 25.400 Kuparuk River Field Increment I Waterflood Summary The Increment I waterflood of the Kuparuk River Field is a field demonstration, or "pilot" waterflood. Its purpose is to optimize and reduce the risks of a possible full field water flood. As shown on Exhibit I, the Increment I waterflood will encompass the following area: T 11 N, R 10 E, U. M. Sections 5,6,7,8,15,16,21 and 22 Increment I will involve 46 wells for injection and production, drilled from two drill sites, lA and 1E. This includes an existing 16 wells, eight on each drill site, that will be part of the Phase I start-up this December. Of the 46 wells for Increment I, 16 will be on Drill Site lA. These wells will be on 160-acre spacing in a five-spot pattern. The other 30 wells will be on Drill Site 1E. Some of the 1E wells will be drilled on 40-acre five spot patterns and some on 80-acre inverted five-spot patterns. The use of different well spacings and patterns will help optimize the development of a p~ossible full field waterflood. All of the proposed injection and production wells, along with all existing wells in the area, are also shown on Exhibit I. An estimated injection rate of 50,000 BWPD will be supplied by seven to ten Cretaceous source water wells. These wells are planned to be drilled from Drill Site lB. Scheduled start-up for Increment I is early 1983. The operator for the Increment I waterflood will be ARCO Alaska, Inc. A 100% interest is held by ARCO in all of the leases included within the Increment I project. The address of ARCO, along with the names and addresses of the offset lease holders are included in Exhibit II. All offset acreage is either leased 100% by ARCO or jointly by ARCO, BP Alaska Exploration, Inc., and Sohio Alaska Petroleum Company. Application for Additional Recovery 20 AAC 25.400 Page Two Reservoir Description The name of the reservoir to be waterflooded by Increment I is the Kuparuk River Oil Pool. According to Rule 2 of the Field Rules (Conservation Order No. 173), this pool is defined as the accumulation of oil that is common to and correlates with the accumulation found in the Atlantic Richfield Company West Sak River State No. 1 well between the depths of 6,474 and 6,880 feet. Exhibit III lists the pools in which all existing wells in the Increment I area, as shown on Exhibit I, are currently completed along with the status of each well. In3~ction Wells and Casing Program As shown on Exhibit I, there are three existing production wells that will be converted to injection wells. These are the lA-7, 1E-lA, and the 1E-4. Attached, as Exhibits IV (a) through IV (f), are the log sections for each of these wells. The perforated interval in the Kuparuk River Oil Pool is indicated on the log sections for the 1E-lA and 1E-4. The lA-7 has not yet been perforated. The casing program for injection wells will be identical to that currently being used for Kuparuk producing we~lls and will be in accordance with 20 AAC 25.410. Surface casing will be 10-3/4" 45.5# K-55 BTC, set below bottom of permafrost and cemented to surface. Completion casing will be 7" 26# K-55 BTC set through the Kuparuk and cemented to 500' above the highest hydrocarbon bearing zone but not into the surface casing. The 10-3/4" x 7" annulus will be arctic packed. All casing will be pressure tested in accordance with 20 AAC 25 030 (e). A schematic of a typical water inject ion well casing program is attached as Exhibit V. Source Water For use as the source water for Increment I, ARCO plans to develop a limited portion of continuous water-bearing sands in the Upper Cretaceous interval. Seven to ten water source wells are planned to be drilled from Drill Site lB. Estimated injection rate is 50,000 BWPD. All source wells will be drilled, completed, and produced in accordance with all appli- cable regulations. JSS A-6 plication for Additional Recovery AAC 25. 400 Page Three Well Tests and Monitoring A number of wells in the Increment I area have been tested recently in preparation for Phase I start-up. A summary of these well tests is shown in Exhibit VI. The average test rate is about 2000 BOPD with an average GOR of approximately 400. Ail the wells tested were completed in the Kuparuk River Pool. During the first year of Increment I water injection, a pro- file survey shall be run in each well which has multiple sand intDrvals open to the wellbore. Subsequent surveys shall be run in wells which exhibit rapid changes in the injectivity index or have had remedial work performed to change the injec- tion profile unless the remedial work results in only one sand interval being open to the wellbore. Injection profile survey data and results shall be filed with the Commission by the 15th day of the month following the month in which the survey was taken. Ail injection volumes will be reported monthly per 20 AAC 25.430. Development Plan As previously mentioned, two drill sites, IA and 1E, exist within the area of the Increment I project. Eight wells on 320-acre spacing have been drilled on each drill site as part of the Phase I start-up in December of this year. A ninth well has just recently been completed on Drill Site lA, and the Rowan Rig No. 34 is currently drilling the lA-10. The remainder of the 16 wells on Drill Site lA, the additional 22 wells on Drill Site 1E, along with the seven to ten water source wells on Drill Site lB will all be drilled by early 1983 using at least two and possibly a third rig. The facilities for Increment I primarily consist of the water injection plant and the waterflood drill site facilities. Both the plant and the drill site facilities are being built in modular form. Structural steel began arriving at the Anacortes, Washington module fabrication site in September, 1981. Instal- lation and hook-up will follow with start-up of Increment I scheduled for early 1983. A brief summary of our development schedule is shown in Exhibit VII. JSS A-7 EXHIBIT II INCREMENT I PROJECT Operator and Offset Lease Holders Operator: J. J. Pawelek ARCO Alaska, Inc. P.O. Box 360 Anchorage, AK 99510 Offset Lease Holders: P. Hardwick BP Alaska Exploration, Inc. One Mar itime Plaza San Francisco, CA 94111 R. A. Flohr Sohio Alaska Petroleum Company 100 Pine Street San Francisco, CA 94111 EXHIBIT III Well Completion and Status Summary Increment I Area Well lA-1 lA-2 lA-3 lA-4 IA-5 lA-6 lA-7 Completion Interval Kuparuk River Pool Kuparuk River Pool Kuparuk River Pool Kuparuk River Pool Kuparuk River Pool Kuparuk River Pool lA-8 Kuparuk River Pool (Formerly West Sak #12) Current Status Shut In Shut In Shut In Shut In Shut In Shut In Cased but not yet perforated - This well will be con- verted to injection Shut In lA-9 Kuparuk River Pool Shut In iA-10 Drilling 1E-1 P & A 1E-lA Kuparuk River Pool Shut In 1E-2 Kuparuk River Pool Shut In 1E-3 Kuparuk River Pool Shut In 1E-4 Kuparuk River Pool Shut In 1E-5 Kuparuk River Pool Shut In 1E-6 Kuparuk River Pool Shut In 1E-7 Kuparuk River Pool Shut In 1E-8 Kuparuk River Pool Shut In West Sak #2 T.A. Note: Ail wells listed as Shut In are ready for Phase I start up. JSS A-9 I0 OPEN HoL~. 8i00 8200 8300 8400 8500 LOG, KU~RUK RiVd EXHIBIT FIELD 0.1 IV (a) I OOC IO ( I I ! i I¢ IOO 8100 8200 8500 8400 8500 4- ii -- EXHIBIT IV (b) LOG,,, KUPRRUK R!V~-. FIELD FD£ C~.N HOL~ LOG EXHIBIT IV (c) I0 I00 6800 o, D Z L ,ooo DEEP 111 2024410104 EXHIBIT IV (d) I i ~Y I00 6800 6900 7OOO 7100 7200 60 FDC o 2024410105, R~Y I00 O~N HOLE LOG KUPR~U~K RiVeR FIEEE) O.I 8600 OIL EXHIBIT IV (e) I000 8800 8900 9000 2024410106 i-ti t I I00 8600 7OO 8800 3900 9000 ~o ~ ,DC o 2024410107 TYP T C AL EXHIBIT V WATER (. INJECTION KUPARUK RIVER FIELD WELL 10-3/4" 45.5:I:I: K-55 SURFACE CAS lNG ! I. TUBING HANGER TUB IN(3 RETRIEVAL SSSV 3. SIDE POCKET MANDREL SEAL BORE ASSEMBLY 5, PACKER 6, NO-GO LAND lNG NIPPLE 7, 3 I/2" 9.2~ J-55 BTS~C COATED TUB lNG 7" 26:1:I: K- 55 PRODUCTION CASING EXHIBIT VI Kuparuk River Pool Well Test Summary Increment I Area Test Well Date lA-1 7/29/81 lA-2 8/1/81 lB-1 5/26/81 lB-2 6/24/81 1E-lA 8/21/81 1E-2 8/18/81 1E-3 10/19/81 1E-4 9/2/81 1E-5 11/12/80 1E-6 10/22/81 1E-7 10/28/81 1E-8 11/1/81 Oil Rate (BOPD) 2880 2971 153 2972 1606 2750 1241 400 2069 1395 1936 2985 GOR 380 410 N.A. 350 320 N.A. 454 540 365 402 387 443 PIA 2.6 4.5 0.14 3.28 1.80 3.88 0.67 0.66 3.58 0.74 1.37 1.98 JSS A-10 EXHIBIT VII Development Schedule Increment I Facilities - Commitment Facilities - Start Fabrication at Anacortes Start Drilling Additional Producers and Injectors Start Drilling Water Source Wells Facilities - Sealift Start-Up 7/81 9/Sl. 10/81 9/82 8/82 4/83 JSS A-11 'ARCO Alaska, Inc. Post Office Bo: 0 Anchorage, AI~ ,~,a 99510 Telephone 907 277 5637 December 16, 1981 John Katz, Commissioner State Department of Natural Resources Juneau, Alaska Re: Kuparuk River Unit Application Dear Commissioner Katz: Pursuant to AS 38.05 and 11 AAC 83. 300-395 ARCO Alaska, Inc., BP Alaska Exploration Inc., Sohio Alaska Petro- leum Company, and Union Oil Company of California, (the "Applicants"), submit for your review and appro- val the proposed Kuparuk River Unit Agreement. The Applicants proposing the Kuparuk River Unit Agreement are all lessees and owners of state oil and gas leases within the State of Alaska. The Applicants believe that the materials submitted with this appli- cation address the criteria listed in 11 AAC 83.303. upon which the Commissioner must base his finding that the Kuparuk River Unit Agreement is necessary and advisable to protect the public i~nterest. The following items are submitted as a part of this application: 1. Kuparuk River Unit Agreement, inc].udling all Exhibits, executed by the Applicants. 2. The Kuparuk River Unit Operating Agreement executed by the Applicants. 3. Exhibit A is the testimony of ARCO Alaska,. Inc., Sohio Alaska Petroleum Company, and BP Alaska Exploration Inc. given at the Alaska Oil and Gas Conservation Commission hearing on Conservation Order No. 73, held on March 25, 1981 which indicates the pertinent geo- logical, geophysical, engineering and well data and interpretations of this data in support of the application. In addition, supplemental information obtained subsequent ARCO Alaska, Inc.'is a Subsidiary of AtlanticRichfieldCornpany Commissioner John Katz December 16, 1981 Page 2 to the hearing is provided. Confidential maps and data have been supplied to the Division of Minerals Energy and Management, Department of Natural Resources, by ARCO Alaska, Inc. These maps are incorporated in this application by reference. Representa- tives of the Applicants are available to dis- cuss the matters submitted in this applica- tion. Finally, copies of an application to the Alaska Oil and Gas Conservation Commis- sion to initiate additional recovery pursuant to 20 AAC 25.400 (Increment I Application) is also included. 4. Exhibit B is the Applicants' explanation and justification of the differences between the standard State unit form and the Kuparuk River Unit Agreement form. 5. Exhibit C is a request by the Applicants to the Commissioner to certify the Kuparuk River Reservoir as capable of producing hydrocarbons in commercial quantities. The Applicants are submitting this application pur- suant to Title 38 of Alaska Statutes and regulations (11 AAC 300-395) adopted under that statute requiring agreement of the Working Interest Owners having rea- sonably effective control of Unit Operations and approval of the Commissioner to form a voluntary unit. Pursuant to Title 31 of the Alaska Statutes the Applicants are concurrently furnishing a copy of the Kuparuk River Unit Agreement and Kuparuk River Unit Operating Agreement to the Alaska Oil and Gas Conservation Commission, requesting a finding that the Kuparuk River Unit Plan of Development is in the interest of conservation and will not result in waste. The proposed Kuparuk River Unit Area includes approximately ~..~! 7x~7~ acres. It is. located on the North Slope of Alaska and adjacent to the Commissioner John Katz December 16, 1981 Page 3 Prudhoe Bay Unit. Rroduct ion commeD..~gd from the Kuparuk River Field Area on acreage wholly-owned by ARCO Alaska, Inc., on.December 13, 1981. The 100 leases included within the Unit Area were sold by the ~tate of Alaska before 1970. The lease form is substantially the same as that utilized in the Prudhoe Bay Unit. All leases within the unit outline provide for a one-eighth royalty to the State of Alaska. All other terms and conditions of the committed leases are the same throughout the Unit Area. As additional information, the following attachments are submitted to assist you in this approval: 1. A statement of the background of development and ownership in the Unit Area and the proposed Kuparuk Participating Area. (Attachment ~,). · 2. A listing of th'e parties who have not executed the Unit Agreement or Unit Operating Agreement and whose acreage is included within the pro- posed Kuparuk River Unit Area. (Attachment 3. An Affidavit as evidence of reasonable efforts by the Applicants to obtain joinder of the par- ties listed in (2) above. (Attachment .~). 4. A discussion of the appendices to the Unit form including the proposed Kuparuk River unit Emergency Storage Agreement and the proposal for handling field costs in the Kuparuk River Unit. (Attachment ~)..~,. Commissioner John Katz December 16, 1981 Page 4 If you or your staff have any questions or if we can be of further assistance in this review please advise us. Very truly yours, ARCO ALASKA, INC. Ti t 1 e. ,,, ~-~/~J//~_.~. Concurred by: SOHIO ALASKA PETROLEUM COMPANY By: Title: BP ALASKA EXPLORATION INC. UNION OIL COMPANY OF CALIFORNIA By: Title: EXHIB IT B KUPARUK RIVER UNIT APPLICATION Differences Between Kuparuk River Unit Form and Standard State Form The Kuparuk River Unit Working Interest Owners attempted to draft the proposed Kuparuk River Unit Agreement in the same format and language as the State form. However, there presently exist mi- nor differences in language and several substantive differences from the standard State form. The terms of the leases committed to the Kuparuk River Unit substantially differ from the terms of State leases which might be included in units subject to the standard State form. Therefore, many of the deviations which occur between the proposed Kuparuk River Unit and the standard State form. are required by the leases committed to the Kuparuk River unit. The following is an article-by-articlereview and discussion of the differences between the proposed Kuparuk River Unit Agreement and the standard State form. Every effort has been made to cover all deviations but we trust your staff will compare the two forms and request any further information that may be required. Recitals The recitals in our form include the recitals set in the stand- ard State form. In addition, three recitals have been added. These recitals include: 1. A discussion of the ARCO West Sak River No. 1 well cov- ered by state lease no. ADL 25649 which, along with other subse- quent wells, conf~.rmed the existence of a major oilfield on the Arctic North Slope of Alaska. 2. Recital regarding AS 31.05.110 of the Alaska Oil and Gas Conservation Act which indicates that the Working Interest Owners may validly integrate their interest to provide for unit- ized management, development and operation of ~the tracts as a unit. 3. A reference to AS 38.05.180(p) of the Alaska statutes (public lands), which indicates that Working Interest Owners may operate a cooperative or unit plan of development when determined and certified by the Commissioner to be advisable in the public interest. The Working Interest Owners do not view these as deviations from the standard State form, but merely clarifying the statutory bases on which unitization is accomplished. -1- Article 1 Article 1 sets forth the definitions utilized in the Unit Agree- ment. The definitions section is substantially similar to the State form except for the following modifications: a. A definition of the Kuparuk River Reservoir is included which identifies the Reservoir as th'e basis for the Kuparuk Participating Area. b. The Kuparuk Participating Area is defined. c. The definition of outside substances has been modified from the standard State form. The use of the word "con- sideration'' in the standard State form has been deleted since it may be construed to include only monetary consideration. Outside substances may be obtained by other than monetary consideration, and then injected into the Reservoir. d. The definition of Participating Area Expense included in the State form has been deleted since the Unit Oper- ating Agreement indicates that all area expense (Parti- cipating Area Expense) is considered unit expense. Also, the unit expense definition has been modified to reflect this change. e. The definition of "Paying Quantities" has been revised to delete the phrases dealing with the transportation and marketing of unitized substances. The Paying Quan- tities definition utilized by the Working Interest Owners is that definition which has been in force in the State of Alaska for considerable years and is the definition the Working Interest Owners have operated under since the time these leases were issued. f. The definition of "Reservoir" has been slightly modified to indicate the geological interpretation and confirma- tion that is necessary to identify Reservoir. g. A definition of Legal Subdivision of Land has been added to the Kuparuk River Unit Agreement. The acreage number is the same as the standard State form, but additional language has been added to ensure consistency with ConServation Order No. 173 and the remaining sec- tions in the Applicants form. The remainder of the definitions contained in the Unit Agreement and standard State form are the same, /'~"¥he /on----l~--~-~m~'i-n-~-~g- .... ~-~-'~'~"~-~n~6~ ......is that ~h.e .... effeCti~e date for the Kuparuk River Unit Agreement will be upon approval by the Commissioner. -2- Article 2 The Exhibits contained'in Article 2 are the same as those con- tained in Article 2 of the standard State form with exception of the following: Exhibit E in the proposed Kuparuk River Unit Agreement is the Unit Plan of Development contemplated in Exhibit G of the stand- ard State form. There is no plan of exploration since this is a development and production unit. However, the Unit Plan of Development does provide for investigation and studies of other oil producing horizons. Exhibit A indicates the royalty rate applicable to each tract in the Unit area. This is contemplated presently in the State form in Exhibit H. Finally, Exhibit E in the standard State form indicated in the schedule for the allocation of participating expense in the Kuparuk Participating Area has not been included. Participating Area Expense has been agreed to be shared by the Working Inter- est Owners as set forth by the Unit Operating Agreement. There are no net profit leases contained in the Kuparuk River Area and the Working Interest Owners believe that the section regard- ing Unit Expense has been specifically included in the standard State form to address those areas where~ a net profit lease is included in a proposed unit. The tract participations for the Kuparuk Participating Area are set forth in Exhibit.C. In addi- tion, as is noted in Article 7 of the proposed Kuparuk River Unit Agreement, there is an application pending for benefit of discovery royalty. That tract is number 22 and is in ADL 25633. The remaining sections of the Kuparuk River Unit and standard State form are the same. Article 3 Article 3 of the Kuparuk River Unit form and the standard State form are the same except for the following modifications: 1. An additional sentence has been added to Article 3.3 which indicates "Unit Operations, if conducted under and in compliance with approved Plan of Development, shall continue each Lease in the Unit Area in effect as if the Unit Operations were conducted on each tract so long as the particular Tract remains committed to this Agreement." This is a standard principle of unit- ization and is one of the bases for formation of a unit. 2. The standard State form contains Articles 3.4 and 3.5 dealing with rental settlement and minimum roy- -3- alty. Article 3.4 of the Applicant's form combines these two references into one article. 3. Article 3.6 of the proposal concerning surface and sub- surface operating rights is similar to Section 3.7 of the standard State form. However, this has been amended to reflect the provisions common to all the leases con- tributed to the Kuparuk River Unit. These additional provisions also are consistent with the basic theories of unitization where the unit area is operated as one lease. The remaining sections of Article 3 of the proposed Kuparuk River Unit Agreement are the same as the stand- ard State form. Article 4 Article 4 of the proposed Kuparuk River Unit and the standard State form are substantially similar. ARCO Alaska, Inc. has been designated the Unit Operator in the Kuparuk River Unit Operating Agreement by the Working Interest Owners and is qualified to be the Unit Operator under Alaska law. Article 5 Article 5 of the p~oposed. Kuparuk River Unit Agreement differs substantially from the standard State form. Initially, the section on plans of exploration in the State form has been deleted. The Kuparuk River Unit is not an exploration unit but a development and production unit. The sections regard- ing the Kuparuk River plan of development in the Applicant's form are substantially similar to the State form. Article 5.1.4 has been added and recognizes the bases for unitization, i.e. performance of all obligations for development and opera- tion consistent with the Unit Plan of Development satisfies the.obligations for performing operations on~ each and every' tract included within the Unit Area. The section in the State form dealing with Plans of Operation and the sections in Kuparuk River Unit form are substantially simi- lar. The first three subparagraphs of the standard State form have been deleted since they are inapplicable to the proposed Kuparuk River Unit. Finally, Article 5.3 of the Kuparuk River Unit regarding rate and development of production is different from the standard State form. Article 5.3 of the proposed Kuparuk River Unit in-- -4- dicates that the Commissioner may, after giving written notice to the Operator, require the Operator to modify the rate of de- velopment and production from the Unit Area. However, any modi- fication is limited by the terms in the remainder of the para- graph. This is not intended to preclude or in any way inhibit the Commissioner' s exercise of his authorities to prevent waste or a similar emergency condition. However, the Working Interest Owners have based development and financing of the Kuparuk River Unit on a plan of development which ultimately attains a production rate of 250,000 barrels per day. To vest the Commissioner with the authority to curtail either the rate of production or rate of development from that originall~ approved, absent an emergency or order from the Alaska Oil and Gas Conservation Commission, would frustrate the basic purpose of unitization as well as render impossible the long term financing of the venture. The Unit Plan of Development sets forth a phased plan which requires significant expenditure commitments over the next 10 years to bring about the optimum development of the field and provide the ultimate recovery of resources to both the Working' Interest Owners and the State. Often the selling of production payments or other means of financing is utilized to secure proper revenue for these projects. Potential modification of the rate of development or prospecting would impact the ability of the Working Interest Owners to secure such financing and may directly affect financing which has been arranged ir~ the past. In addition, the Working Interest Owners must often commit to purchase contracts five years in adwance to ensure that material and equipment are designed, purchased, fabricated and transported to the North Slope for installation. Any alteration of the rates of development of production would affect the development timing the Working Interest Owners pro-- pcsed in the Unit Plan of Development. The remaining provision set forth in the Applicants' form is substantially similar to the provisions contained in the stand-- ard State form. Article 6 Article 6 sets forth the Kuparuk Participating Area and provi- sions for expansion and contraction of the Kuparuk Participating Area. These provisions are substantially similar to the provi- sions set forth in the standard State form. Article 6.1.1 of the standard State form is not included in the proposed Kuparuk River Unit. Formal request for certification of the Reservoir as capable of producing in commercial quanti- ties is accompanied with this application. (Exhibit C). -5- Also, Article 6.3 sets forth provisions on Participation and other Participating Areas and contains provisions in addition to the standard State 'form where the parties do not agree on those new participating areas. Article 7 Article 7 of the proposed Kuparuk River Unit is different from that contained in the standard State form. The basic reasons for modifying the State form are that the provisions contained in the leases contributed to the Kuparuk River Unit differ sub- stantially from the provisions in the State form and the mean- ing of the royalty provisions of these leases is presently in litigation with the State of Alaska. Those leases set forth and contain provisions as follows: a. The same royalty owner and the same basic royalty rate throughout the Unit Area; b. Since the same basic royalty rate is applicable, it is the Working Interest Owner's view that the State has no interest in approval of the allocation of tract participations to the Kuparuk Participating Area, how- ever, the initial tract participations are set forth in Exhibit C, and the basis for final determination of tract participations is set forth in the Kuparuk River Unit Operating Agreement; c. The leases set forth basic provisions concernimg the calculation of the price or value of the royalty oil and are in litigation between the State of Alaska and all but one of the Applicants; d. The leases set forth terms of notice provisions for taking royalty production in kind, which the Appli- cants and the Department of Natural Resources wish to modify; and. e. The leases set forth provisions on the charges applic- able for cleaning and dehydration of 0il and gas pro- duced, which are disputed and which the Applicants and the Department of Natural Resources wish to settle. Therefore, Article 7.5 has been substantially changed to conform to the provisions of the Kuparuk River Unit Working Interest Owners' leases. However, an Emergency Storage Agreement has been negotiated with the Department of Natural Resources whereby the State of Alaska is entitled to store up to 300,000 barrels of Royalty Oil during an Emergency. In addition, the 1.eases have been amended to allow the State more flexibility of taking of unitized substances in kind and tendering back those substances to the Working Interest Owners. -6- Finally, the field costs applicable to cleaning and dehydration have not been~~gr~-~-'-a~'5~this date. However, the Applicants be- lieve that setlement of these issues with the State can be made during the pendency of this application. During the interim the Applicants shall charge the State eighty cents ($0.80) per barrel for cleaning and dehydration. When agreement is reached with the State, any sums paid over the settlement or under the settlement will be equalized to the date of commencement of production. Ap_p~n_d_i__x ...... I~,. has been reserved for the ultimate agreement of the parties, to be attached to the Kuparu~ River Unit Agreement. This matter is discussed in greater detail in Attachment 4. 7.8 of the Applicants form is similar to 7.9 of the standard State form. Eighty percent (80%) has been placed in the blanks of the standard State form as a fair and equitable percentage for recoupment of outside substances which are injected into the Reservoir. This is also the same amount contained in the Prudhoe Bay Unit Agreement. 7.9 of the Kuparuk River Unit form and 7.10 ~f the State form are substantially similar; however, references directly applicable to net profit leases in the standard State form have been deleted in the Kuparuk River Unit form. 7.10 of the Applicants' form recognizes the Emergency Storage Agreement set out in Appendix II. Article 8 Article 8 of the Kuparuk River Unit form and the standard State form are substantially similar. However, the last sentence in Article 8.2 of the Kuparuk River Unit form indicates that. if a facility is partially used for Unit operations and partially used for other operations the royalty shall be properly appor- tioned and payable on the substances utilized by the non-Unit operations. The Kuparuk Pipeline Company will be utilizing up to 20% of the power generation facility to generate the necessary power to assist in the transportation of the oil down the Kuparuk Pipeline. This use of fuel will not be considered for unit oper- ations. Article 9 Article 9 of the Kuparuk River Unit form and Article 9 of the standard State form are substantially similar. Article 10 Article 10 of the Kuparuk River Unit form and Article 10 of the standard State form are substantially similar. 10.9 of the -7- standard State form is included in Article 20.2 of the Kuparuk River Unit form. Article 11 Article 11 of the Kuparuk River Unit form and Article 11 of the standard State form are the same. Article 12 Article 12 of the standard State form and Article 12 of the Kuparuk River Unit form are the same with the exception of the last phrase, which indicates that upon application to the Commis- sioner, seasonal restrictions on operations or productions speci- fically required or imposed as a condition of the Unit Plan of Operations, may be considered since extensions of oper. ation or production pursuant to law or prevention due to Force Majeure. This is a necessary provision in light of the commitments made by the Working Interest Owners in the Unit Plan of Development since there are certain time coDstraints on meeting the provisions of that plan. Article 13 Article 13 of the Kuparuk River Unit form and Article 13 of the standard State form are the same. Article 14 Article 14 of the standard State form and Article 14 of the Kuparuk River Unit form are the same with the exception of the salvaging of equipment and rehabilitation upon termination sec- tion. In that section, the standard State form indicates that the Unit Operator shall salvage and remove all unit equipment within one year and rehabilitate the unit area to the satisfac- tion of the Commissioner within one year after that date. The Working Interest Owners have suggested modifications of this to allow for a three-year period to remove and salvage the unit equipment and an additional three years to rehabilitate the unit area. We believe that one year for salvaging' and removal of equipment which was transported and installed in the unit area over the thirty years, and one year to rehabilitate the unit area is unreasonable and therefore, suggest more liberal time periods to ensure that the unit equipment is properly salvaged and removed and the unit area properly rehabilitated to the. satisfaction of the Commissioner. Article 15 Article 15 of the standard State form and Article 15 of the Applicants' form are the same. -8- Article 16 Article 16 of the Kuparuk River Unit form and Article 16 of the standard State form are similar. We believe the intent of the standard State form is more clearly expressed in the provisions set forth in the Kuparuk River Unit form. These provisions indi- cate that where matters involve the State of Alaska, that the Unit Agreement shall control. However, in the case of any con- flict of terms between the Unit Agreement and the Unit Operating Agreement that involve only Working Interest Owners, the Unit Operating Agreement shall control. Articles 17, 18, 19 and 20 Articles 17, 18 and 19 of the Applicants' form are substantially similar to Articles 17, 18 and 19 of the standard State form. In addition, Article 21 regarding nondiscrimination has been added to set forth the Working Interest Owners' obligations under federal law. Conclusion There may have been some minor deviations between the Kuparuk River Unit application and the standard State form other than those mentioned above. Working Interest Owners have attempted to set forth the major deviations from the standard State form and set forth the reasons for deviation from the standard State form. The Working Interest Owners attempted to draft the Kuparuk River Unit form as consistent as possible with the standard State form, even though there are many provisions which the Working Interest Owners feel are inapplicable and inconsistent with the formation of a development and production unit. All the same we recognize the State's need for a standard unit form embodying general provisions applicable to the many State leases. We trust this sets forth the reasons for necessary modifications to the State form and we therefore request the Commissioner's approval of the Kuparuk River Unit form, and th.e modifications made to the standard State form. -9- EXHIBIT C Request to Certify the Kuparuk Reservoir as Capable of Producing Hydrocarbons in Commercial Quantities John Katz, Commissioner Department of Natural Resources Juneau, Alaska 99811 Re: Certification of Kuparuk River Reservoir Dear Commissioner Katz: Pursuant to 11 AAC 83.361, please consider this letter to be a request to certify the Kuparuk River Reservoir as a reservior capable of producing hydrocarbons in commercial quantities, as such term is defined in 1I AAC 83.395. In support of such request, please consi- der the data attached to this application, partic- ularly Exhibit A and the supporting material attached thereto, and the provisions of the Kuparuk River Unit Operating Agreement. The testimony given at the hear- ing on March 25, 1981 before the Alaska Oil and Gas Conservation Commission indicated the total recover- able reserves of the Kuparuk River Reservoir are estimated to be 1.25 billion barrels. The Working Interest Owners have determined these reserves are sufficient to repay the costs of drilling, development, production, transportation, and marketing, with a reasonable profit to the Working INterest Owners. As the actual estimates of the various Applicants con- cerning the commerciality of the Kuparuk River Reser- voir are proprietary to each Applicant, it is requested that if you or your staff have any questions or if any of the Applicants can be of further assistance in this review, please advise. Very truly yours, ARCO ALASKA, INC. Commissioner Katz Exhibit C Page 2 Concurred in by: SOHIO ALASKA PETROLEUM COMPANY BP ALASKA EXPLORATION INC. By: ~'~ Title: /~/f~ £ i g e-niT- UNION Oil, COMPANY OF CALIFORNIA Title :~Z~~~~~ / ATTACHMENT 1 APPLICATION FOR APPROVAL OF THE KUPARUK RIVER UNIT BACKGROUND AND OWNERSHIP INTEREST Ownership in the Kuparuk River Unit Area is shown on Exhibits A and B to the Kuparuk River Unit Agreement. ARCO Alaska, Inc., BP Alaska Exploration Inc., Sohio Alaska Petroleum Company and Union Oil Company of California, together own ap~Droximately 97%~ interest in the surface acres included in the Kuparuk River Unit Area. In addition, these parties also own o~f the reserves interest in the Kuparuk River Unit Area. This ownership Interest is sufficient to provide effective control over operations in the entire unit area. These parties repre- senting the aforementioned interest have agreed and executed both the Kuparuk River Unit Agreement and the Kuparuk River Unit Operating Agreement. For a brief description of the discovery and early delineation of the Kuparuk River Reservoir see Exhibit A. In January, 1981, a general meeting of the Working Interest Owners within the Kuparuk River Unit area was held in Dallas, Texas. Most Working Interest Owners within the Kuparuk River Unit Area were represented at that meeting. The drafting of the Kuparuk River Unit Agreement and the Unit Operating Agree- ment commenced in June, 1981. All Working Interest Owners in the Kuparuk River Unit Area have been afforded an opportunity to be represented. Over the past five months the unitization activities have continued and resulted in the attached Kuparuk River Unit Agreement and Kuparuk River Unit Operating Agreement. Ail parties whose acreage is included in the Kuparuk River Unit area have been offered the opportunity to join and execute the Kuparuk River Unit Agreement and Unit Operating ~greement. These parties have participated in the unitization activities, but final agreement has not yet been achieved between all parties. The attached affidavit of P. B. Norgaard, President of ARCO Alaska, Inc., on behalf of the Working Interest Owners who have executed these agreements, described the efforts that have been made by all of the parties who executed these agree- ments to obtain the joinder of the parties whose acreage is included within the Unit area but who have not executed the Unit Agreement. -1- ATTACHMENT 2 KUPARUK RIVER UNIT APPLICATION PARTIES NOT EXECUTING AGREEMENT AS OF DECEMBER 15, 1981 Working Interest Owner Tract No. Tracts Ownership Interest Exxon Corporation Mobil Oil Corporation Phillips Petroleum Corporation Chevron U.S.A. Inc. Amoco Production Company 58 59 82 83 84 85 86 97 98 99 100 36 57 57 36 9 26 71 72 72A 91 92 93 94 95 96 50% 50% 50% 50% 50% 50% 50% 50% 50% 50% 50% 50% 50% 50% 50% 16 2/3% 16 2/3% 16 2/3% 18 3/4% 16 2/3% 16 2/3% 16 2/3% 16 2/3% 16 2/3% 16 2/3% 16 2/3% ATTACHMENT 3 EVIDENCE OF REASONABLE EFFORTS TO OBTAIN JOINDER OF PARTIES AFFIDAVIT OF PAUL B. NORGAARD~' STATE OF ALASKA THIRD JUDICIAL DISTRICT The affiant, being duly sworn, states as follows: 1.. My name is Paul B. Norgaard and I am currently Presi- dent of ARCO Alaska, Inc., one of the applicants for the Kuparuk River Unit and the designated Unit Operator under the Kuparuk River Unit Operating Agreement. Previously, I held the position of Vice President of ARCO Alaska, Inc. with principal responsi- bility to supervise North Slope Operations for ARCO Alaska, Inc. During all material times, I have had ultimate responsi- bility for the negotiation of the Kuparuk River Unit Agreement and the Kuparuk River Unit Operating Agreement with the Working Interest Owners included within the Unit Area. 2. The Applicants have made separate offers to t'he Working Interest Owners listed in Attachment 2 'to this applica- tion to join the Kuparuk River Unit Agreement on various terms and conditions. At a meeting with representatives of all but one of the parties listed in Attachment 2 held on December 9, 1981, I believe the basis for agreement for the joinder of '~the above parties to the Kuparuk River Unit Agreement and Kuparuk - -1- River Unit Operating Agreement was developed. Subject to the approval of the managements of the parties listed in Attachment 2, I believe these parties will execute the Kuparuk River Unit Agreement and the Kuparuk River Unit Operating Agreement within a reasonable time after the date of this application. 3. Amoco Production Company (Amoco) was not represented at the December 9, 1981 meeting. Amoco's acreage is included in the Unit Area but not in the Kuparuk Participating Area. Reasonable efforts have been made to join Amoco. All copies of the Unit Agreements and the Unit Operating Agreements have been transmitted to Amoco. To this date agreement has not been reached with Amoco. Further your affiant sayeth not. DATED this /<f~day of ~ , 1981. '~ SUBSCRIBED AND SWORN TO before me this day' of Notary Public 'in 'and 'fO~ Alaska My Commission Expires- -2- ATTACHMENT 4 DISCUSSION OF EMERGENCY STORAGE AGREEMENT AND PROCEDURE FOR HANDLING FIELD COSTS IN THE KUPARUK RIVER UNIT AGREEMENT Both the method by which Lessees are to calculate and pay royalty to the State of Alaska and the obligation of Lessees, if any, to store royalty oil taken in kind by the State of Alaska on the leased premises has been the subject of litigation or discussion for several years, both in the Prudhoe Bay Area and in Cook Inlet. In an effort to resolve these troublesome uncer- tainties in the oil and gas lease, the Applicants and represent- atives of the Department of Natural Resources have sought to ob- tain some agreement with respect to both issues. Below is a discussion of the status of these .issues at the time of the filing of this Application. Royalty With respect to the payment of royalty, both the Appli- cants and representatives of the Department of Natural Resources have agreed that the differences between the State of Alaska and the Lessees respecting royalty payments may be divided into two areas: (i) the calculation of the value of royalty oil sold by the Lessees on behalf of the State (commonly referred to as the "downstream issues" ) and ( ii ) the calculation of what charges, if any, may be made under the terms of t~ oil and gas lease to the State of Alaska as a result of the State's taking its .,.royalty in kind, or being paid royalty in value (commonly referred to as the "field cost" issue). Further, representatives of the Department of Natural Resources and the Lessees have reached agreement that the downstream issues should be dealt with in the context of litigation presently in existence between the State of Alaska and the Working Inter- est Owners of the Prudhoe Bay Unit, styled, "'State of Alaska v. Amerada Hess Corporation, et al.," Alaska Superior Court No. 77-847, and this accord is reflected in paragraph 7.5 of the proposed form of Unit Agreement submitted with this Applica- tion. However, as the field cost issue was successfully settled with respect to the Prudhoe Bay Unit, representatives of the Depart- ment of Natural Resources and the Lessees have aglreed that good faith efforts should be made by both parties to negotiate a fair and equitable charge for the cost of cleaning and dehy- drating the State ' s royalty oil. Accordingly, on November -1- 18, 1981, the Lessees transmitted materials to the Director, Division of Minerals and Energy Management, which sets forth the basis for a charge of eighty cents ($.80) per barrel for the purposes of cleaning and dehydrating the State's royalty oil. These documents are incorporated herein by reference. Although agreement has not yet been reached between the Depart- ment of Natural Resources and the Applicants as to a recommended cost figure, the Applicants believe that resolution of this potential dispute is possible within the time frame of this Application, and accordingly, have res____erv_~l~~d~_~ as an exhibit reflecting the ultimate agreement with respect to the computation of field costs allowed in computing the value of roy- alty oil paid in value and in kind to the State of Alaska. Pending. the resolution of this dispute, it is the intention of the Applicants to begin deducting a charge of eighty cents ($.80) per barrel in computing the value of royalty to be paid the State in value or taken in kind. This charge will be retroactively ad- justed to the date of the commencement of production upon resolu- tion of this dispute. Emergency Storage Agreement Each of the leases committed to the Kuparuk River Unit provides "if necessary" furnish "storage~, for that the Lessee shall, , royalty oil the State has elected to take in kind, for thirty (30) days after the end of the calendar month during Which the oil is produced. There is disagreement between the State and the Appli- cants as to whether such storage can ever be necessary so long as the field is served by a major common carrier pipeline, and as to whether the Applicants can be required to furnish such storage if construction and operation of surface storage facilities of such magnitude is infeasible or legally impermissible on the North Slope 3f Alaska. Accordingly, representatives of the Department of Natural Re- sources and the Applicants have concluded that such disagreement should be settled and compromised under the terms of the Kuparuk River Unit Emergency Storage Agreement which is attached to the Kuparuk River Unit Agreement. This~ Agreement provides that on the occurrence of an emergency, as that term is defined in the Agreement, the State of Alaska may store up to three hundred thousand (300,000) barrels of its royalty oil by ex- changing the State's right to have such royalty oil delivered to the State on the date on which such oil would arrive at the inlet to the major oil pipeline for the right to recover such stored oil at a later date, all in accordance with the terms and conditions of the Emergency Storage Agreement. Under the terms of the Agreement the State may invoke an emergency only when a condition or series of conditions beyond the reasonable control of the State and which substantially impair the State's --2-- ability to continue to take its oil in kind occurs. The State may not utilize the Emergency Storage Agreement to take advanr tage of unfavorable market conditions which might otherwise induce the State to utilize the Agreement. Additionally, and as explained in Attachment 1, to this appli- cation the State's right to take oil in kind, and payment of royalty in value, has been substantially modified from that set forth in the leases committed to the Kuparuk River Unit. These rights, utilized in combination with the storage rights granted in the above Agreement should fully protect the State of Alaska in the event unanticipated disruptions should occur when the State is taking royalty oil in kind. -3- STATE OF ALASKA' ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501 Re: THE APPLICATION OF ATLANTIC ) RICHFIELD COMPANY for a ) hearing to present testimony) to determine the pool rules ) for the development and pro-) duction of the Kuparuk River) Formation west of the Prud- ) hoe Bay Field. The contrac- ) tion of the Prudhoe Bay ) Kuparuk River Oil Pool and ) the naming of the field is ) considered as part of the ) application. ) Conservation Order No. 173 Kuparuk River Field Kuparuk River Oil Pool. Prudhoe Bay Field Prudhoe Bay Kuparuk River Oil Pool. May 6, 1981 IT APPEARING THAT: Atlantic Richfield Company by letter dated November 25, 1980, requested the Alaska Oil and Gas Conservation Commission to take the necessary steps to adopt pool rules for the development and production of the Kuparuk River Formation west and north of the Prudhoe Bay Field. , Notice of a public hearing was published in the Anchorage Times on February 5, 1981. ~ A public hearing was held on March 25'~ 1981 at the Municipality of' Anchorage Assembly Room, 3500 East Tudor Road, Anchorage, Alaska. Testimony was presented and oral and written statements were accepted. The hearing was continued until April S, 1981 at 4:30 PM. Additional written statements and maps were received. FINDINGS: Oil Was first discovered in the Kuparuk area when Sinclair Oil Company tested oil from the Kuparuk River Formation at their Ugnu No. 1 well in 1969. Since 1969, more than 25 wells have been drilled and hundreds of miles of multi-fold seismic data have been acquired in an attempt to define 'the limits of the Kuparuk River oil accumulation. Conservation Order No. '173 Pa ge 2 , The area for the Prudhoe Bay Kuparuk River Oil Pool Rules was initially described on January 12, 1970 in Conservation Order No. 83-A and the area has not been changed since that date. A fault, labeled the Eileen fault, exists in the western part of the ?rudhoe Bay Field and the evidence indicates that this fault marks the western boundary of the oil accumulation defined as the Prudhoe Bay Kuparuk River Oil Pool. · There is doubt about the existence of the Eileen Fault north of the Prudhoe Bay Field and this area may have several faults. · Some of the area west and north of the Prudhoe Bay Field should be included within the area where a common accumulation is possible and not cowered by the Prudhoe Bay Kuparuk River Oil Pool rules. · The Kuparuk River Formation interval in the Atlantic Richfield Company West Sak River State ~1 well appears adequate for defining the pool. The area of oil accumulation appears to be controlled by structural dip and truncation to the south, trunca- tion of the formation to the west, northeast dip and possible faulting to the north and east, and a fault, the Eileen Fault, to the east. The Kup.~ruk River formation consists of very fine to medium grained marine sandstone, usually occurring as ~three sand members separated by mudstones, siltstones and thinly bedded sandstones. 10. Sand members of the Kuparuk River Formation west of the Eileen Fault could be a common pool and~ share the same fluid c~.)ntact. 11. To date, no wells have established the existence of a gas cap in the Kuparuk River Formation. 12. Although water has been found in the K~paruk River Pormation, no oil-water contacts have been substantiated in any individual sand members. 13 . The aquifer underlying the Kuparuk River oil accumlation appears to be small in volume and the influx into the oil column is expected to be insignificant. 14. Preliminary development plans cover an area of 210 squares miles. Conservation Ordei No. 173 Page 3 15. Initial reservoir pressure is estimated to average 3100 psia. with a bubble point pressure of 3000 psia. 16. Solution gas drive is expected to be the primary recovery mechanism. 18. 19. Ail gas produced will be utilized, in accordance with 20 AAC 25.035 GAS UTILIZATION, for use as fuel, safety flaring, artifical lifting of oil, and injection into the reservoir for storage until a gas sales pipeline is available. .. It is proposed that when gas sales facilities become available, the injected gas will be produced from the injected area for fuel and for sale. Waterflooding plans are being formulated for the · reservoir. 20. 21. 22. 23. The blowout prevention equipment and its use should be in'accordance with 20 AAC 25.0.35 BLOWOUT PREVENTION EQUIPMENT. The Kuparuk River Field, the name proposed by the operator for. the area to' be covered by these, rules, is considered an appropriate name since it meets the required criteria. Development is planned under state-wide spacing regulations. In the northern latitudes, the convergence of governmental survey lines toward true north results in some governmental quarter sectiQns of l~ss than 150 acre s. The drilling, completion and production from a well located in a governmental quarter section of no less than 125 acres will not adversely affect correlative rights. 25. 26. Surface casing setting depths between 5~0 feet below thc base of the permafrost and 2700 feet TVD will allow flexibility in the complex directional well programs. Slotted liners, wire wrapped screen liners with and without gravel packing, and open hole completions may offer a means to reduce formation damage and improve oil recovery. 27. The casing design criteria being used has effectively eliminated casing collapse. Conservation Ord Page 4 No. 173 28. Installation of downhole and surface automatic shut-in valves could prevent an uncontrolled flow of oil or ga s. 29. A:minimum subsurface safety valve setting depth of 500 feet should .provide adequate protection from an uncon- trolled flow and should reduce the risk of damaging both the valve and the control line 'while running in the hole. 30. To properly regulate and operate the reservoir, performance must be carefully monitored and bottomhole pressure and gas-oil ratio test data must be obtained soon after production commences. 31. The contribution of each of the various perforated intervals in each producing well may be determined by running productivity profile surveys. No. a rea Pool NOW THEREFORE, IT IS ORDERED THAT Conser~a'aion Order 98-A is hereby amended by removing the following described from the area covered by the Prudhoe Bay Kuparuk River Oil Rule s. T 11 Nt R 10 E~ U.M. Secs. 1,2,11,12,13,14,23, Secs. 24,25,26,35,and 36. T 12 N, R 10 E, U.M. 1,2,11,12,13,14,23, 24,25,26,35 and 36. T.. 11 N, R 11 E,.U.M. T 12 N, R 11 E, U.M. Secs. 3,4,5,6,7,8,9,10, Secs. 11,14,15,16,17,18, 19,20,21,22,23,24, 25,26,27,28,29,30, 31,32,33,34,35 and 36. 3,4,5,6,7,8,18,19, 20,29,30,31,32 and 33. T 13 N; R 10 E, U.M. T 13 N, R i1 E, U.M. 'Secs. 13,14,15,16,21,22, Secs. 23,24,25,26,27,28, 33,34,35 and 36. 17,18,19,20,28,29, 30,31,32 and 33. Conservation Orde~ Pa ge 5 173 NOW THEREFORE IT IS FURTHER ORDERED THAT the rules hereinafter set forth apply to the foll6wing described area: T. 9 N, R 6. Ej U.M. Secs. 1,2,11,12,13 and 14. T 11 N~ R 8 E, U.M. ~L Secs. SQcs. Socs. T 9 N, R 7 E, U.M. T 11 N, R 9 E, U.M. 1,2,3,4,5,6,7,8,9, ALL 10,11,12,13,14,15, 16,17 and 18. T 11 N, R 10 E, U.M. T 9 N, R 8 E~ U.M. 1,2,3,4,5,6,7,8,9, 10,11,12,13,14,15, 16,17 and 18. T 9 N, R 9 E, U.M. 1,2,3,4,5,6,7,8,9, 10,11,12,15,16,17 and 18. Secs. Secs. ALL T 11 N, R 11 E, U.M. 3,4,5,6,7,8,9,10,11, 14,15,16,17,18,19,20, 21,22,23,24,25,26,27, 28,29,30,31,32,33,34, 35 and 36. T 12 N~ R 7 E, U.M. 25,26,35 and 36. Secs. Secs. T 9 N, R. 10 E~ U.M. 1,2,3,4,5,6,7,8,9, 10,11 and 12. T_10 N, R 6 E, U.M. 1,2,3,4,9,10,11,12,13, 14,15,16,21,22,23,24, 25,26,35 and 36. T 12 'N, R 8 E, U.M. ALL T 12 N, R 9 E, U.M. ALL T 12 N, R 10 E, U M ALL T 10 N, R 7 E, U.M. ALL T 10 N,. R~8 E, U.M. ALL Secs, T 12 N, R 11 E, U.M. 3,4,5,6,7,8,18,19,20, 29,30,31,32 and 33. S@CS. Secs. Secs. T 10 N, R 9 E, U.M. ALL T 10 N, R 10 E, U.M. ALL T !0 N, R 11 E, U.M. 5,6,7,8,17,18,19 and 20. T !1 N, R 6 E~ U.M. 25,26,35 and 36. T 11 N, R 7 E~ U.M. 1,2,3,4,9,10,11,12, 13,14,15,16,17,18,19, 20,21,22,23,24,25,26, 27,28,29,30,31,32,33, 34,35 and 36. Secs. Secs. T 13 N, R 8 E, U.M. 13,14,23,24,25,26, 27,28,33,34,35 and 36. T 13 N, R 9 E, U.M. ALL T 13 N, R 10 E, U.M. ALL T 13 N, R 11 E, U.M. 7,8,16,17,18,19,20,21, 28,29,30,31,32 and 33. Conservation Ord~ No. 173 Page 6 .Rule 1. Name of Field The name of the field shall be the Kuparuk River Field. Rule 2: Definition of Pool The name of the Pool in the Kuparuk River Field shall be the Kuparuk River Oil Pool and is defined as the accumulation of oil that is common to and correlates with the accumulation found in the Atlantic Richfie.ld Company West Sak River State No. 1 well between the depths of 6,474 and 6,880 feet. Rule 3. Well Spacing Not more than one well may be drilled on any governmental quarter section or governmental lot corresponding to it nor may a.ny well be drilled on a governmental quarter section or governmental lot corresponding to it which,contains less than 125 acres, nor may the Pool be opened in a well bore that is closer than 500 feet to any property line nor closer than 1,000 feet to the Pool opened to the well bore in another well. Rule 4. Casing and Cementing R. equlrements (a) Casing and cementing requirements are as specified in 20 AAC 25.030. CASING AND CEMENTING. except as modified below. (b) For proper anchorage and to prevent an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe to the surface. (c) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects 'of permafrost thaw-subsidence and freeze back, a string of surface casing shall be set at least 500 measured feet below the base of the perma- frost section but not below 2700 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the casing to the surface. (d) The surface casing, including connections, shall have minimum post-yield strain properties of 0-.9% in tension and 1.26% in compression. (1) ~ The only types 'and grades of casing, with threaded connections, that have been shown to meet the requirements in (d) above and have been approved for use as surface casing are the following: Buttress; Buttre s s; Buttress; (A) 13-3/8 inch, 72 pounds/fOot, L-80, (B) 13-3/8 inch, 72 pounds/foot, N-80, (C) 10-3/4 inch, 45.5 pounds/foot, K-55, Conservation Ord~ No. 173 Pa ge 7 (2) The Commission may approve other t3~pes and grades of surface casing upon a showing that the proposed casing and connection can meet the post-yield strain require- ments in (d) above. This evidence shall consist of one of the following: · (A) full scale tensile and compressive tests; (B) finite element model studies; or, (C) other types of axial strain data -accep- table to the Commission. (e) Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze back may be approved by the Commission upon application. (f) The Commission may approve alternative completion methods ('to 20 AAC 25.030 (b)'(4) and (5)) upon application and presentation of data which shows the alternatives are based on accepted engineering principles. Such altermative designs may include: (1) slotted liners, wire wrapped screen liners, or combinations thereof, landed inside of open hole and may be gravel packed; (2) open hole completions provided that the casing is set not more than 200 feet above the productive zone. Rule 5. Automatic Shut-In Equipment (a) Upon completion, each well which is capable of ~nassisted flow of hydrocarbons must be equipped with a commis- sion-approved (1) fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow by automat- ically closing if such a flow should occur; and (2) fail-safe automatic surface controlled subsurface safety valve (SSSV), unless another type of subsur- face valve is approved by the Commission~ this valve must be in the tubing string located at a depth of 500 feet or greater be]ow ground level; the valve must be capable of preventing an uncontrolled flow by automatically closing if such a flow s}~ould occur. (b) A representative of the Commission will witness operation and performance tests at intervals and times as pre- scribed by the Commission to confirm that the SSV, SSSV, and all associated equipment are in proper working condition; and Conservation Ord Page 8 No. 173 (c) A well that is not capable of unassisted flow of hydrocarbons as determined by a "no flow" performance test wit- nessed by a commission representative is not required to have ~ fail-safe automatic SSV or SSSV valves. Rule 6. Safety Flares -. (a) The daily average '9olume of 250 MCF/day is permitted for a safety flare in the Central Production Facility operated by Atlantic Richfield Company. (b) Safety flare volumes for additional facilities may be approved administratively upon application. (c) Safety flare volumes may be increased or decreased a dmi nis tra tive 1 y. Rule 7. Gas-Oil Ratio Tests Between 90 and 120 days after continuous production and each six months thereafter a gas-oil ratio test shall be taken on each producing well. The test shall be of at least 12 hours duration and shall be conduCted at the normal .producing rate of the well. TeSt results shall be reported on Gas-Oil Ratio Test, Form 10-409. All tests run in a calendar month shall be reported by the 15th of the following month. Rule 8. Pressure Surveys (a) A static bottomhole pressure survey shall be taken on each well prior to initial sustained production. ~(b) Following initial sustained production from each governmental section, a transient pressure survey shall be taken on one well in the section after six months and after ]8 months. (c) One of the wells from (b) above on each lease will be designated a key well and a transient pressure survey on this well shall be taken after 30 months production and annually thereafter. (d) Bottomhole pressures obtained by a static buildup pressure survey, a 24 hour shut-in instantaneous' test or a multi- ple flow rate test will be acceptable. (e) Data from the surveys required in this rule shall be filed with the Commission by the last day of the month follow- ing the month in which each survey is taken. Reservoir Pressure Report, Form 10-412 shall be utilized for all surveys with attach- ments for complete additional data. Data. submitted shall include, but are not limited to, rate, pressure, time, depths, temperature, and other well conditions necessary for complete analysis of each survey being conducted. The Pool pressure datum plane shall be 6,200 feet subsea. Conservation Ord~'' No. 173 Pa ge 9 (f) Results and data from any special reservoir pressure monitoring techniques, tests,-or surveys shall also be submitted as prescribed in (e) of this rule. (g) By administrative order, the Commission may require additional pressure surveys or modify the key wells designated in (c). of this rule. Rule 9. Productivity Profiles (a) During the first year of production, a production survey shall be run in eaCh well which has multiple sand intervals open to the well bore. (b) Subsequent surveys shall be run in wells which exhibit rapid changes in gas-oil ratio, water-oil ratio, or pro- ductivity. Subsequent surveys shall also be required in wells which have had remedial work performed to change the production profile Unless the remedial work results in only one sand inter- val being open to the well bore. (c) Complete production survey data and results shall be recorded and f~led with the Commission by the 15th day of the month following the month in which each survey is taken. (d) By administrative order, the Commission shall sp3_cify additional surveys should it be determined, that the surveys submitted under (a) and (b) are inadequate. Done at Anchorage, Alaska and dated May 6, 1981. ~'oyl~H. famil~on, Chairman Alaska Oil and Gas Conservation Commission Harry W. Kugler, COmmissioner Alaska Oil and Gas Conservation Commission Lon~ie C. Sm~h,~'Comm!ssioner Alaska Oil and Gas Conservation Commission EXHIBITS I-1 II - 1 II - 2 II - 3 II - 4 ~qap of Kuparuk River Field Location Field Rules Boundary Structure .~p of Kuparuk River Formation Cross Section A - A, Cross Section B - B' II - 5 III - 1 III - 2 Isopach of Kuparuk River Formation ~iap of Oil Pool and Participating Area Type Log - West Sak No. 1 ' III - 3 III - 4 III - 5 V-1 V-2 V-3 V-4 Rock Properties Water Saturation vs. Height Above Water-Oil Contanct . Phase I Oil' and G~ Rate Development Drilling ,,' Wellbore Diagram Kuparuk W'ell Safety System Well Inflow Performance f-_., V-5 V-6 V-? V-8 V-9 Y~-,p of Phase I Area ,.. Drill site Layout Flow Diagram of CPF's Oil and Gas Process Kupartfl~ pipeline Route ~ow Diagram of' Crude Metering Facilities at CPF VIII - 1 ! I I I I I I I I I I..-- ·1 PRO .F['E. .S.A. = ARCO Alask POSE RULE REA .---'---- EXHIBIT mm ,mm m mm mm mm m m mm mm mm mm m m mmmm mm mm m mm mm m mmmm KUPARUK RIVER OIL POOL KUPARUI~ RIVER FIELD YR AY I I I I 13 I I 20 I I ' ,ii PROPOSED FIELD RULES AREA ~lPlO KUPARUK RIVER OIL POOL I I rmm-,,mmmmmm mmm mm mmmmm ARCO Alaska, Inc. EXHIBIT Tr-1 AREA MAP KUPARUK RIVER FIELD ~ ( NE PT. = /~ ~~~ ~~ ,, ~ ~ ..: ~~-- : ~ ~ALUBIK ~ ,~ ~ ~ ' ' ............~-~ I ,J~ ~ ~ ~11.~ ~ ~ ~ ' ~ . ~' - ' ' N. KUPARUK A/~i ._...~ : ~ ~~- :" / ~..- ~ ~ :' ARCO Alaska, I~ ~ I ~ ..... -/" ' o~non~.n~~~noH, ce~o=~ _~ : ~ ' / ~:: EXHIBIT~-2 ~__ ~:~ ~~~~ :. L I.~ ~:. [,~~~~~~. j----- --------- STRUCT.URE' MAP . .. .. KUPARUK RIVER OIL POOL TOP KUPARUK RIVER' FM. ~ ~-. KUPARUK RIVER FIELD HIGH GAMMA RAY SHALE AND UNNAMED'L- CRETACEOUS SHALES W. SAK 11 KIN W. SAK g I/V-E STI~IJCI'IJR, At CI~OSS SECTION KUPARUK RIVER FIELD VERT. EX. 20X W. SAK 12 · · : : · : W. SAK 8 W. SAK 6 ,. ,, '$200~ '5500~ ,.,.. -6000~ '6500~ ....,, - ?000~ ARCO Alaska, Inc. EXHIBIT~.3 Al -5600~ -6000~ - 650 O' -7000~ W. SAK 4 W. SAK 3 UNNAMEO L. cRETACEOUS -ii,':" sHALES '~I KUPARUK RIVER FM. ,HALE 10° DEVIATION ':" . W. SAK 2 (PROJECTED) W. SAK 7 SW-NE STRUCTURAL CROSS SECTION KUPARUK RIVER FIELD VERT. EX. 20X W. SAKI B! -5600' -6000~ -6500' -7000' ARCO Alaska, inc. SuD$1diar¥ Of AHanlicR~cl3fl,l~Coml3~ny EXHIBIT Tr -4 A / ''- · , 600 I~'LUBIK I, ,300 f 33-~29E "--" tiE. UGNU 1 ._. ,/ U U 0.(1 r'' . ' J~: EILE oE~N B 12 GWY -'" OKPUK 14 10~ [ ,/ ! . ~ / ~_ UNIT NPRA. B / .. I]o ,,""" /. I ::: 13 / I ~ I / ~ ARCO~Alaska, Inc. ~: , ·, / , ' EXHIBIT~ ;5 ~ I' 20 I . / '- ~ PROPOSED FIELD. . RULES AREA r----------"" ISOPACH MAP KUPARUK RIVER OIL POOL KUPARUK RIV~ER FM. , __ KUPARUK RIVER FI. ELD R BAY . 'J ,,,~,~, J ,'""~-~ /:"_ ~N E PT. : - -- - ..... ":~':,~ ~.: ._" ~ ~ .......... ' / ~_ ~BAY _ :-.~- ~ .. I ~ ~ ~ I ......................................... f ~ , . ~ _ - ~ ~EILEEN ..... : .............................. ~--- ........... '. ....... . ........... ~ ' 1 ,' N. KUPARUK l' ::' i ·~ / ::::~ ' =' PR U.D:HOE jm..m..mt ............................ ~ , ............... i ,---J ; = BAY · -~. .~._ m , ~ is ~S~ ~'" sl ~ L , UNIT -/, ~..~ . . ._.~ :, ./ : fi' -. .: ....... : .................. . .............. ~ ~ PROPOSED FIELD RULES AREA ~____..._....__, EXHIBIT~-I · ---------..............__._...._. D~~/~oia~s~ KUPARUK R;IVER OIL POOL --~vra~./ ., ~ , . ~ KUPARUK RIVER FIELD ................................... ~ ............. ..... ~ .............................. ........ ........... ., L L, ARCO Alaska, Inc. EXHIBIT ~-2 TYPE LOG ......... :.,':: '...ABCO ALASKA ]NC.-,".EXHIBIT ."' , ..-. .... . · . . , .:. ,.~ ',..~';;-~..~.~-~..~ · .. >:.:..... .... ', . ~' , -. ,~, ~,~ ,.:~.,:::-- KUPARUK RIVER FI~-LD ~.`..~..`..~::~:.`~``~.~`~.:..:;:`.~:.:`.:,....`~:::::.~::.;..`.:?.?.:.¢..~::.~..~.~.~ . ~:-;':.-. WATER SATURATION vS~'HE'iG'~'T'AB'O-¢"t~'~'O~D'~.','....' :~ 'o - -.~. , .: .... . ... . · '100~-- ...... ': ........... ' ...... ' .... ""' "" '"" ":" .... ~':? ':":"' "'"'"'"';:":~ ~:~ :'"':" "'" "" d .% · .f , O0 Upper Sand (Clean inlerval) and Middle Sand , % % ARCO ALASKA INC., EXHIBIT 111-3. AVERAGE RESERVOIR' ROCK PROPERTIES THICKNESS POROSITY (Ft.) (%) / PERIVIEABILIT¥, (Md.) UPPER SAND MIDDLE SAND LOWER SAN D 37 20 ' 125 8 20 250 24 21 100 . II! / I · 20 \ 'x 0 1982 1985 1990 1995 . - , · 2000 ,, ' . 2005 . .. t~RTH ~RC ' -~ CONDUCTOR ~i '~.. 16" 65¢, H-40 CSA 80' ARCTIC-PAK ANNULU.S CEMENT TO SURFACE i ;5 1/2" SAFETY VALVE /J~ i ~ -+ 1900' MD I ~ SURFACE CASING Z["'% I 0 ;5/4" 45. ~ K- 55 ....... CSA APPROXo 2700' SS. CEMENT TO SURFACE i ~hT' //~- ;5 I/2" GAS LIFT MANDRELS : (5-? TOTAL/VC. LL THROUGHOUT TUBING) ~ ;5 1/2" 9.2¢ J-55 BTC TUBI'NG ~i ~ .5 I/2"X 7" PACKER SETt 200' ABOVE KUPARUK ' [---I .~------~ PROFILE NIPPLE -'----------- WIRELINE GUIDE ::l: =: KUPARUK ~ -- HORIZON PRODUCTION CASING 7" 26~ K-55 ~ '~ CSA: 200' BELOW KUPARUK CMT. TO 500' ABOVE HIGHEST HYDROCARBON BEARING t; INTERVAL I · I ~ , 1' ' ' ARCO EXHIBIT ~-2 ......~ 'TYP ]:CAL KUPARUK WELL rDRTE~ ! 3- 25- 8 IjD~n~'', JAL j E~'~, JD DRTE D,R'~N r, ,. REVISIONS. ENSR , , , ,, 20037,, I0001,, , , % PRODUCTION SURFACE SAFETY VALVE TO FACILITY~ (SSV) LOWER MASTER VALVE -- FROM · - HYDRAULIC GROUND_ ~, __ SOURCE , , _ ELEVATION -, ,- I, il SUBSURFACE SAFETY VALVE (SSSV) · · .... A~CO EXHIBIT x2- 3 I , , TYPICAL KUPARUK WELL .... ! .... SAFETY SYSTEM , , t ' ' 309 NO: ~E~JI~30EI NO:t Dt,'l~ t,10: 3400 3000 2600 220O -5 OPEN HOLE TEST C-4 OPEN HOL-E;:T EST -5 CASED HOLE TEST i ARCO Alaska, Inc. ~., Subsidiary of All~nllcRichlieldComp,ny ARCO EXHIBIT "5;Z'- 4- OPEN HOLE VS. CASED HOLE INFLOW PERFORMANCE RELATIONSHIPS WELLS C-4 AND E-5 I I DATE, J DRAWt,I~ ENGR, MARCH 25, 8~. JAL AD NO~ JOB NO, JSUB.JOB NO:J J SCALE, DWG. ,, JSHT. or C-4 CASED HOLE TEST 1800 1400 1000 I ii I II BOPD ~ ~- Z005910000 8 REFEREHCE DRRUIHOS: -ARCO EXHIBIT ~- 5 KUPARUK PROJECT AREA MAP nD I SHT. "°'£0037 !00001scn~'' ,~OB NO! IUBJOB NO1Dy° N°'20057 I0004 DRILL SITE PRODUCTION ' HEATER . FLOWLINES TO CPF 1140' fr r r. i SWAE 0 N 490' DRTF DIqI'/N REVISION NOliTR 81_i3:~1:' DIg'I~ICT - ~1CH0¢1110~ ARCO EXH I B I T ~-6 KUPARUK PHASE ! TYPICAL DRILL SITE MAR. 25~1981 nDNO, JgC~, TO DRILL SITES TO KUPARUK PIPELINE TEST & PRODUCTION FROM DR ILL SITES CR !E SURe-'b: N,,~I DRUM SH IPP ING BOOSTER PUMPS PUMPS TEST HEADER PHASE GAS /'~IPR IMARY i-"/ N...S, E P &RA TOR,~ I WATER EI=E~TROSTA, T ];C ~ NC.',OALE SCEP/ GAS TEST t k,._,SEPARATOR,~ ACCU . OIL REFERENCE DRAWINGS: GAS LIFT 2ND STAGE COMPRESS ION T~ -GAS DEHYDRATION SCRUBBER INd[¢IION COMPRESSORS TO GAS INJECTION WELLS REVISION ,, ENGR , TO --"- WATER DISPOSAL VVELL NORTH ~L~P~.__D ~IA!_D_ICT - pJ,~Honn.~E ARCO EXHIBIT PRODUCTION FACILI~ EL~C_LtE~I IC "~¢p~OOQ OF / ¢ / :: ALASKA VIOINITF ~P ~~ · NO. I RI4E R I OE R I I E R ! 2E R ! ~E NoRm ~E DISTRICT - , .'o , ~ ~ - ARCO EXHIBIT~-8 ' ~-'" KUPARUK PIPELINE ~' "' ~ ~'~" ROUTE no .o, ~039' 0000]scaLEL- ~ [sliT'. K~ ,. ! ..... I ! MIJ OF ~ , ...... 2003910~5. pII OIL PRODUCTION F R OM SHIPPING ~ PUI,~ S STRAINER KUPARUK PIPELINE ESD VALVE REFERENCE DRR~[NGS: I I II I! il 2" !1 METER ! I I! !1 !1 4" METER II I 4" METER I -'--4" IFLowl PIG LAUNCHER METER PROVER. LOOP (UN ID IRECTIONAL ) -r--1 OIL SAMPLER REVISION ~O0~)lOl~'¢ 0~ All_MirlO RIOr-IL~LD fK!RTI-L_~OPE_~J~fRI~T - nNCHOnqOE KUPARUK P IPEL INE METER lNG FAC IL ITIES ~,~E.~/2 5/8 I ~ J ~no NO~o0~910001 NTS J or ,o..o. ~,,o,O~NO.Jo~oNo. I";~, for release AtlanticR ichfieldCompany Public Relations Department Post Office Box 360 Anchorage, Alaska 99510 Telephone 907 277-5637 KUPARUK RIVER OIL FIELD Questions and Answers' Q· Why is ARCO so enthusiastic about the opening of the Kuparuk oil field? What is its importance to the U.S., to the state of Alaska and to ARCO? Ae For the U.S., oil produced from Kuparuk wilI 'redUce the amount of oil that must be imported, thereby reducing the flow of U.S. dollars to other oil-producing areas of the world. For Alaska, the Kuparuk represents, the..fi.rst new oil production since the opening of the Prudhoe Bay field in 1977. It will provide additional state revenues from royalties and taxes, and will help to offset the anticipated drop in state income as production from Prudhoe Bay begins to decline in a few years. In addition, Kuparuk represents jobs, both for con- struction workers and permanent production employees. And it represents, contracts for hundreds o.f Alaskan businesses, a real boost to the private sector. Kuparuk is important to Atlantic Richfield because it justifies our company's confidence in North Slope production beyond Prud]~oe Bay. Aslowners of 57 to 59 per- cent of the oil, it means ARCO shareholdezs eventually will receive a return on their investment of billions of dollars in North Slope development. Q · A, The capacity of the Kuparuk pipeline is 190,000 barrels a day. Yet, you expect ultimate production to reach 200,000 to 250,000 barrels a day. How will that oil be transported? Our plan now is to expand th.e Kuparuk pipeline system with the· addition of a second line, to be r'eady whe~ additional pr. oduction comes onstream in early 1984. That is w]~en the second Central Production Facility is scheduled to go on line.. Page 2 of 3 Q. What will the 16-inch line be used for then? A · There are several options: It could be used to transport up to 20,000 barrels of water a day from the Beaufort Sea to the Kuparuk field, for water- flooding. Or it could be used to transport gas from Kuparuk to a conditioning facility at Prudhoe Bay, if one is constructed for gas sales. Q · A~ Q · How does the gravity of Kuparuk oil compare with Prudhoe Bay oil? from the Prudhoe reservoir. How much higher in sulfur is Kuparuk oil than oil from the Prudhoe reservoir. A. Kuparuk oil is 1.6 percent._.s..B~l~f.~Z...., ....... ~.~ coNp. ared to Q. Will production of oil from the Kuparuk mean the trans-Alaska pipeline must be expanded? Isn't it operating at capacity? Ae No to both questions. The pipeline .operators','A.l.~eska Pipeline Service Company, conducted tests last summer of the capacity of the pipeline and found it can carry 1.845 million barrels a day with the current 10 pump stations and the use of an additive to' reduce friction. The pipeline now is operating at 1.5 million barrels a day because that is the level the state of Alaska has determined is the optimum production from the Prudhoe Bay reservoir. The additional oil from Kuparuk can be handled at the pipeline's current capacity. Design capacity of the pipeline is 2 million barrels, with the construction of two additional pump stations. Only a major new discovery of oil would justify 'such an investment. lghat will production from Kuparuk mean to the state .in terms of increased revenues? A · At 8~,0~ barrels a daX initiR!_~2l.~..~.~I..lp~..from the Kuparuk field, the million a year-- or $400,000 a day -- from royalties and severance taxes alone. In addition, the state will have revenues from property taxes, income taxes, and other taxes· Page 3 of 3 Q ~ Q · Q · Q · Q · Will that income to the state remain constant? It will increase substantially when the Kuparuk field reaches its .~_l__t..~.m__a_.~._e__~.l~..u..,._C~_t..~,F, now expected to be _~_.5,,,.~.,,~...,O.~..O__Q_,,.:b~_a,._?.y_.,.e._!.,.s...._a_,,,,d..a.y~, .by, 1~9,8,,,6~.. Increased state income will come even sooner, however, because production is expected to increase to about 200,000 barrels a day early in 1984. This is contingent, of course, on the success of ~,,aterflooding to increase oil production. What is waterflooding? Water is injected into the reservoir through wells and is used to maintain reservoir pressure as oil is- produced. In practice, the water is injected behind the oil column to push tl~e oil through the sandstone to the producing wells. Is waterflooding used at Prudhoe? It is expected to be in place starting-in.:~1984. The f,irst phase of the' Kuparuk waterflood is expected to start first, in 1983. How do you protect against blowouts in Kuparuk wells? Every oil well drilled today is equipped with blowout preventers, weighin'g several tons, which automatically close off the wellhead if extreme pressures are en- countered during drilling operations.. The blowout preventers also can be operated manually. How often do blowouts occur? Blowouts are rare, on or off shore.. During nearly 25 years of oil production on the Kenai Pe. ninsula, there has not been a single major oil spill· Offshore production in Cook Inlet also has been free of. any significant oil spills during more than 16 years of operation. AtlanticR ichfieldCompany Public Relations Department Post Office Box 360 · Anct~orage, Alaska 99510 Telephone 907 277-5637 For Additional Information Contact' forrelease Susan Andrews (265-6847) PRODUCTION BEGINS AT KUPARUK RIVER OIL FIELD ANCHOK~GE, AK., December 16 -- The Kuparuk River oil field on Alaska's North Slope, America's newest major oil field, has gone into production and soon will be delivering up to 80,000 barrels a day to the trans-Alaska pipeline. . ...... ~.' ' According to ARCO Alaska, Inc., operator of the field, the 80,000 barrels a day production will mean income to the state of Alaska of about $135 million a year --'nearly $400,000 a day -- from royalties and severance taxes alone. In addition, the state will receive revenues from property tax, income tax, and other taxes. Startup of the giant Kuparuk oil field, one of the ten largest ever discovered in North America, has come three months ahead of schedule, according to Paul Norgaard, president of ARCO Alaska, Inc. When ARCO's board of directors gave the go-ahead in 1979 to spend $450 million for initial field degelopment, it was expected that production would begin April~l, 1982. ARCO was able to speed up completion by giving the project priority status, Norgaard said. A construction work force of 500 was busy this fall installing the production facilities that arrived on the summer sealift. During the past several weeks, a crew of 120 ARCO employees has worked round the clock to bring the facilities on line. ARCO owns all the state oil and gas leases in the 20-square mile area included 'in the initial development. Agreement is expected soon among leaseholders in the entire Kuparuk field to operate the field as a single unit, with ARCO as operator. - Mo r e - , Ultimate recovery, with successful waterflood, is expected to range between 1.2 and 1.5 billion barrels of oil. ARCO is-expected to olvn from 57 to 59 percent of the net production. Other major leaseholders are BP Alaska Exploration, Inc. and Sohio Alaska Petroleum Company. Smaller interests are held by Union Oil Company of California, Exxon USA, Mobil Oil Corporation, Phillips Petroleum Company and Chevron USA. ..' .. Initial production is from 40 ~¢ells, located on five gravel drill sites. Plans call for two additional central production facilities to be added over the next four years, boosting production from the Kuparuk to 250,000 barrels a day. That production level will require use of waterflood, a secondary recovery method. Expansion plans call for a second Central Production Facility to go into operation in 1984, boosting production tO about 200,000 barrels a day. A third facility is scheduled to start up in 1986, .raising the total to 250,000 barrels a day. By the time it is fully developed, Kuparuk is expected to have cost the owner companies an estimated $8 billion. Gas produced from the Kuparuk along with crude oil will be injected into the reservoir until gas sales take place sometime in tt{e future. At 80,000 barrels a day, it is expected that 35 million cubic feet of natural gas per day will be produced. Of that total, a portion ~¢ill be used as fuel for the field and about 25 million cubic feet a day will be injected. - More - A 16-inc]~ pipeline has been constructed to carry Kuparuk oil to Pump Station 1 of the trans-Alaska pipeline at Prudhoe Bay. The pipeline is owned by Kuparuk Pipeline Company and will be operated as a common carrier by ARCO Alaska, Inc. Kuparuk facilities include a 96-bed operations center which was delivered on the 1980 summer sealift and opened late that year. It includes dining and kitchen facilities, a theatre, card and game rooms and an exercise room. Kuparuk has its own water and sewage treatment facilities and its own power generating plant. .-, The Central Production Facility, in which natural gas and ~ater separated from the crude oil, was delivered on the 1981 summer sealift. It includes compressor equipment to compress the natural gas for injection into the reservoir. II. III. IV. V · Kuparuk Oil Field Fact Sheet Discovery Former Sinclair Oil Corporation, in a joint venture with British Petroleum, drilled the Kuparuk discovery well Ugnu #1 in 1969. (Sinclair merged with Atlantic Richfield Company that year.) Location A. The field is located 30 miles WNW of the ARCO base camp at Prudhoe Bay. B. It is situated on Alaska's North Slope .... '~ flat, tree- less plain stretching from the foothills of the Brooks Range to the Arctic Ocean -- some 260 miles above the Arctic Circle, and 1500 miles below the North Pole. Geology A. The Kuparuk oil producing formation is of Lower Cretaceous age located at an average depth of 6,300 feet (the Prudhoe Bay Reservoir by comparison is from 8,000 to 9,000 feet.) B. It consists of fine-grain marine sandstone -- usually occurring in three sand members separated by silt and shale -- with an average porosity of 23 percent and average permeability of about 125 millidarces. Reservoir A. Net sand thickness (the "pay") averages about 50 feet (compared to nearly 600 feet at Prudhoe). B. The average initial well rate for the Kuparuk is expected to be 1,500 barrels of oil per day (as compared to lg,000 at Prudhoe ) . C. Current plans call for the development of a 200-square- mile area. Oil Volume billion barrels. B. Total recoverable oil with successful waterflood.i,~ e"s 't"im~'t e"d ..... t'~' ~'e be t.w~.e-n "~i' ,'2 'and 1'~'5 Bi i"i i° n' b ar r e 1 s. C. The company estimates its Kuparuk oil productibn, .~nder water'flood, could total -50 million net barrels. a. ARCO has already booked more .than. 200 million barrels of oil as its share of proven primary reserves to date. b. ARCO expects to add another 550 million barrels from waterflooding and further field definition and 'Development. D. The Kuparuk oil has a gravity of 23 degrees APl (heavier than Prudhoe oil at 27 degrees.) VI. Significance A. Country 1. The Kuparuk ranks among the 10 largest oil fields discovered in U.S. history .... ~.. 2. Based on a peak production rate of 250,000 barrels a day (expected 1986) the Kuparuk will have the second largest daily production rate of any field in the United States, se'~ond only to Prudhoe Bay. 3. .Kuparuk produc.tion witl reduce the 'amount'of oil' must..be imported, thus reducing the flow of U.S. dollars to other oil-producing areas of the world. B. Company 1. The company's predicted Kuparuk oil production total of 750 million net barrels -- with successful waterflood -- is greater than its entire lower 48 net reserves of 700 million barrels (current). 2. Kuparuk production will enable Atlantic Richfield to maintain domestic production at current levels over much of the decade. 3. Kuparuk production in 1982 will more than offset the decline in the company's Lower 48 production. The company's 1982 domestic liquids production is expected to be 6 to 8 percent higher than its 1981 production level as a result of K,uparuk production. C. Alaska 1. Th"e Kuparuk represents the first new oil production since the opening of the Prudhoe Bay field in 1977. 2. Initial production (at 80,000 barrels/day) will mean about $135 million a year -- or $400,000 a day -- to the state from royalties and severance taxes alone. 3. The state will also receive revenues from property taxes, income'taxes and other taxes. 4. It represents jobs, both for construction workers and permanent production workers (a total of'l,200 to 1,400 at Kuparuk by winter 1983~84) and contracts for hundreds of Alaskan businesses. VI I. VIII. IX. Ownership and unitization A. Tl~ere will be eight owner companies. Those with major interests include ARCO Alaska, Inc., BP and Sohio. Those with minor interests include Union, Exxon, Mobil, Phillips and Chevron (percentage of ownership is still being worked out). B. ARCO Alaska, Inc., whose interest in the total field will be from 57 to 59 percent, will serve as operator. Pre-development period A. Kuparuk development was considered uneconomic at the time of development, requiring further definiti~on' through del~¥i~-~'~'~{-]~l~ile the nearby Prudhoe field (discovered by Atlantic Richfield in January 1968) was being developed. B. Six more exploratory wells -- five by ARCO -- were drilled at Kuparuk over the next 10 years. In 1978, ARCO and the BPAE/Sohio Group initiated a sixZw~Ii'eXploratory drilling program to define the area further. C. With rising oil prices and national need for domestic energy, ARCO management authorized $365 million in March 1979 for initial development of the central 20-section area of the field (100 percent ARCO owned) D. In 1980 and 1981, exploration more fully defined the field as crude prices increased further.. And with the economic incentive created by the exemption of new Arctic production from the Windfall Profit Tax, unitization for full field development was begun. Phase I Initial Development (December 1981 startup) A. Twenty square-mile sections (of an area covering 210 sections) are included in the initial development. 1. This development includes 40 active producing wells from five drill sites. 2.Production is expected to be aboUt 80,000 barrels of oil per day. 3. Initial natural gas production is expected to be about 35 million cubic feet/day. Gas above fuel requirements will be injected into the reservoir. - 4 - B. Phase I facilities' 1. Facilities to process the oil and ~as. Two gas compressor trains with a combined capacity to handle 103 million cubic feet/day of produced gas. 3. .A complete utilities complex. a. A 96-bed operations center. b. A 3S0-bed construction camp. c. Ten miles of gravel roads in the Phase I area. d. A 6,000-foot airstrip. e. A 300-foot vehicle bridge across the Kuparuk River. C. Oil is transported to Alyeska Pump Station #1 (start of the 800-mile Trans Alaskan Pipeline System between Prudhoe Bay and Valdez) via the Kuparuk Pipeline. 1. With a diameter of 16 inches, the 26-~ile-long pipe- line has throughput capacity of 190,000 barrels/day. 2. It currently includes four shipping pumps at the production facility. 3. It will add 80,000 barrels of oil per day to the 1.5 million/day currently being moved through the Trans Alaska Pipeline (1.845 mil'lion b/d capacity with current 10 pump stations). D. Total costs to Atlantic Richfield have eRcalated to $480 million. 1. Facilities' $270 million. 2. Developmental drilling- $110 million. 3. Start-up' $10 million. 4. Kuparuk pipeline' $90 million. X. Phase I Expansion A. This will include an additional eight drill sites, of which four are located in jointly-owned leases, and about 60 producing wells. ~ B. It will also include expansion of base camp and gas handling capabilities, requiring a third gas compression train to increase gas-handling capacity. C. An early waterflood demonstration project in the Phase I area will com~nence in early 198.3. (Water 'is injected into the reservoir to maintain pressure as oil is produced.) 1. This will include 17 water injection wells. 2. About seven water producing wells will provide about 50,000 b/d for injection. 3. Water injection facilities and a water distribution system will be located in the P~ase I development area. - 5 - XI. Xe XI. XI'I. Phase II development (Early 1984 start-up) A. Facilities to handle another 80,000 to 120,000 barrels of oil'per day will be added to support the development of the area southwest of the Phase I area. B. This development will involve 150 new producing wells from an additional 18 well sites', a second central production facility, connecting oil and gas trunk lines and expansions to the base camp. C. The Kuparuk Pipeline system will be expanded by the addition of a second line in early 1984. to. carry the extra oil to Alyeska Pump Station #1. Phase III development (1986 start-up) A. Facilities to handle another 50,000 to 80,000 barrels of oil per day will be added to support the development of the area northwest of the Phase I area. B. This development will include 110 producing wells from an additional 20 drill sites, a third central production facility and connecting oil and gas trunk lines and expansion to the base camp. Full field waterflood A. The potential full field waterflood program is scheduled to begin in 1986 with the Beaufort Sea as a possible water source. B. Full field waterflood will include source water facilities, injection facilities, distribution and freeze protection. C. Existing drill sites will be expanded for injection wells. D. Total injection wells will be about 340. Big picture A. Total cost of the Kuparuk project is in excess of $8 billion, of which ARCO's share will be about .$4.5 billion. B. Production is expected to hit a high of 250,000 barrels per day, and be maintained for several years. C. A total of about 800 wells (oil and gas, water and injection wells) will be drilled (the same as Prudhoe). EXHIBIT A Kuparuk River Unit The geological testimony presented by ARCO before the Alaska Oil and Gas Conservation Commission on March 25, 1981, regarding the Field Rules for the Kuparuk River Field requires updating resulting from (1) the addition of new well and seismic information; and, (2) input from all working interest owners as a result of seven technical meetings held between July 16 and August 31, 1981. The stratigraphic nomenclature of the Kuparuk River Formation described in Exhibit Q has been expanded to reflect additional stratigraphic studies and collective ideas and interpretation of all the working interest owners (Exhibit P). The correlation between the Kuparuk River Formation members as described in Exhibit Q relates to the "three sandstone members" described in the Field Rules Testimony (Exhibit III-2) as follows: Exhibit Q Field Rules Testimony Unit D Unit C C4 C3 ] C2 C1 Upper Sand Member Middle Sand Member Unit B Unit A Lower Sand Member Attached are two exhibits taken from the field rules testimony. These have been revised to reflect current thinking of the majority of the working interest owners. The structure map on the top of the Kuparuk River Formation and the SW-NE Structural Cross-section were revised to show structural closure on the northeast flank of the Field resulting from the interpretation of recently acquired seismic data in that area. It was agreed, in Task Force meetings, that the Kuparuk River Field accumulation is limited to the northeast by an oil/water contact and that a water phase of the reservoir separates the Prudhoe Bay Field and possibly other Kuparuk accumulations to the North. Also, this recently acquired seismic data indicates that the Eileen Fault is not continuous to the northwest of the Prudhoe Bay unit as was shown in Exhibit II-2 of the field rules testimony; but splays and terminates just west and north of the Prudhoe Bay unit boundary. NPR i~m I I I I I I I I I L----.I , I I ( ~mm I I I m .%00KPUK km / ALUBIK UG 11 0 0 o 15 0o .6 B 13 O ROPOSED FIELD RULES AREA ,I-' ,4, J m mmm m m mmm-m m m m m m mmmmmmmmmmmmm mmmmmmm KUPARU~ R~Vm=R o~m POOm KUPARUK RIVER FIELD III m m m ! _6500 t NE PT. GWY 33-29E EILEEN Bm N. KUPARU PRUDHOE BAY ,m UNIT Available Well Data mmm 0 Well Data not rele public x~ ARCO Alaska, lng: SublW:l~r'f of At~th:Rh:hf~C~¥ EXHIBI 2 STRUC E MA TOP KUPA K RIVE[ REVISED 12/11/81 KUPARUK RIVER UNIT ~YR AY FM '/4 10° DEVIATION W. SAK 3 HIGH GAMMA RAY sHALE AND UNNAMED L. CRE't'ACEOUS sHALES KUPARUK RIVER FM. : ,HALE W. SAK 2 (PROJECTED) W. SAK 7 W. SAKI SW-NE STRUCTURAL CROSS SECTION KUPARUK RIVER FIELD VERT. EX. 20X SOCAL 33-29E N. W. EILEEN I .... BI -5600' -6000' -6500' -7000' ARCO Alaska, Inc. Subsidiary of AtlanltcRlchtleldCompany EXHIBIT 3]; -4 REVISED 12/11/81 KUPARUK RIVER UNIT PROPOSED MILNE K UP.O U,-X POINT UNIT WELL C'.ASING B ~", 48 I~t, H-40 PELP CEMENTING PROGRAM CONDUCTOR CASING: PERM~ROST CEblENT 1'~ THE SURFACE. SURFACE CASING: LIGHT WEIGHT pERWAFi~::~ST LEAD SLUI~IY FOLLOWED 81' 500'-~ OF STA,OARO PERWAFR~T SLUR~. 9~, 36 lb/~, K-55, BUTTRESS PRODUCq'ION CASING: FIRST STAGE: LIGHT WEIGHT SLURRY FROW 500'! ABO~E UPPER CRETACEOUS TO I000'-~ ABOVE WIDOLE KUP~RUK '~ITH A STANDARD SLURRY TAIL TO COVER THE. KUPARUK FORWATIONS. -8£e~NO STAGE (DO~III,';~IF...ET.E) S'rA~D~D P£R~r~OS~ SLURmr r~ow TI~E 6ASIN$ SHOE TO TN BA:~E OF THE PERWAFROST AND UNWEIGHTED ARCTIGPAK FROW THE B.&SE; OF THE PE. RIAFROST TO THE SURFACE. WELLBORE FLUID: 9..9 l::Mi I~¢1 OR I0.~ PP'B EST. TO6 AT 500' ABOVE U.C.S. ':':':':' UPPER 6RETAOE~$ lilDOLE KUPARUK FOR),IATIO~ EXTERNAL 6ASING PAC,~..R :::::::::: L0~ER KUPARUK FORI, I. ATION T~ 26.0 Ib/ft, L-80, BUTTRESS FIGURE I II _ I m i INJECTION SINGLE M ILNE POINT UNI, KUPARUK RIVER FIELD WELL COMPLETION ALTERNATIVES SELECTIVE SINGLE SUBSURFACE SAFETY VALVE TUBING GAS LIFT MANDREL PACKER INJECTION MANDREL BIJST JOINT I~iDD L E' , , INJECTION Im,IANDREL PACKER FIGURE 9 c~ KUPARUK RIVER FIELD FULLFIELD WATERFLOOD PROJECT APPLICATION, FOR ADDITIONAL RECOVERY 84¸ II III KUPARUK RIVER FIELD FULLFIELD WATERFLOOD PROJECT APPLICATION FOR ADDITIONAL RECOVERY MAY 23, 1984 INTRODUCTION PROJECT OVERVIEW History of Kuparuk Unit Development Schedule Application for Additional Recovery Special Requests GEOLOGIC DESCRIPTION Fullfield Structure Fullfield Stratigraphy Increment I Geology IV INCREMENT I WATERFLOOD PERFORMANCE Increment I Object ives Drill Site 1E Drill Site lA Directional Permeability Tests FI ELD WATERFLOOD OPERATIONS Surveil lance Process Compl et i on VI FULLFIELD WATERFLOOD PERFORMANCE Performance Prediction Methodology Performance Pattern Selection VII WATERFLOOD FACILITIES Intake ,Structure Seawater Treatment Plant Distribution Lines Local Injection Plant Drill Site Distribution System V I I I SUMMARY ARCO Alaska, Inc. { Post Office Box 100360 Anchorage, Alaska 99510 Telephone 907 265 6513 Leland E. Tate Vice President March 23, 1984 C. V. Chatterton Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK RE: Kuparuk River Field Fullfield Waterflood Project Application for Additional Recovery Dear Mr. Chatterton, Pursuant to the provisions of 20 AAC 25.400, ARCO Alaska, Inc. (ARCO), on behalf of the Kuparuk River Unit Working Interest Owners, hereby applies for approval of the Alaska Oil and Gas Conservation Commission to implement a fullfield waterflood project for the Kuparuk River Oil Pool. This application includes the documentation required by 20 AAC 25.400. An affidavit of mailing indicating that the application has been transmitted to all interested leaseholders is attached to this letter. Ten copies of the appli- cation have been provided for your use. Please advise us of the date set for public hearing. Representatives of ARCO and the other Working Interest Owners will be available to discuss these matters, or provide additional information at your convenience. Very truly yours, L. E. Tare LET/ksm Attachments cc: Kuparuk River Unit Working Interest Owners ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompan¥ AFFIDAVIT OF SERVICE BY MAIL STATE OF ALASKA ) ) ss THIRD JUDICIAL DISTRICT ) Mary L. Weber, being first duly sworn, upon her oath, deposes and says: I am a citizen of the United States of America, over the age of 19 years, and employed as a secre- tary for ARCO Alaska Inc That on the ~3fD , . day of ~~~ , 1984, I deposited in the United States mail a true and correct .copy of the document titled "Kuparuk River Field, Fullfield Waterflood Project, Ap- plication 'for Additional Recovery" to each of the lease holders shown on Exhibit 4 of that same document. DATED at Anchorage, Alaska, this ~~Qday of ~~~ ~, 1984. 1984. Subscribed and sworn to before me this ~~ day of Notary Public in and for Al,aska My Commission ExPire~.3: ~/mZ,/~ RECEIVED FULLFIELD NATERFLOOD PROJECT .... ~) ,.',,'-,'-, 1984 KUPARUK RIVER FIELD APPLICATION FOR ADDITIONAL RECOVERY AlaskaOil & Gas Cons. Commissiort Pursuant to 20 AAC.25.400, ARCO AlFaska Inc. as Unit Operator, on behalf of the Kuparuk River Unit Working Interest Owners, hereinafter referred as the Kuparuk Owners, request approval to waterflood t_he Kuparuk RivEr Fl~l Pnnl to incre.ase oil recover~ from an estimate~F-l-0% OOIP to a primary plus seconda_r.y oil recovery o--f~-~-~out 30% OOIP. Based on current reservoir interpretation, fu~llfield -wa~terflood' is expected to yield approximately 1.6 billion barrels of oil under. combined primary and secondary recovery. Under--develoPment plan~s, water ln3ec"--~----tion 'facilit~s will be o"perat, ib,n'al by January: 1986 and will inject treated Beaufort Sea water-and p~oduced wa{er into the Kuparu'k River Oil Pool. In addition to approval to waterflood, the Kuparuk Owners make the following Special Requests. 1. Waterflood Permit Area The Kuparuk Owners request that the Alaska Oil and Gas Commission (AOGCC) allow the Waterflood Permit Area to be modified administratively upon application by the Unit Operator, so that its boundary coincides with or extends beyond the current Participating Area. The application to modify the waterflood boundary will set forth the changes to the Waterflood Permit Boundary by governmental section numbers, include a reasonable justification, and provide other supporting information. 2. Effective Date The Kuparuk Owners request that the effective date of this application be the date of approval by the AOGCC. This timing will enable the Kuparuk'Owners to proceed with 1984 waterflood plans. 3. Well Spacing Implementation of an efficient and effective waterflood could require well spacing closer than 160 acres per well as set forth in Conservation Order No. 173. Therefore, the Kuparuk Owners request that the AOGCC approve unrestricted well spacing within the approved Kuparuk Waterflood Permit Boundary within the Kuparuk River Field. Current Waterflood Permit Area Description (20 AAC 25.400 b.1,2,4) Water will be injected into the Kuparuk River Oil Pool, also referred to in this application as the Kuparuk River Reservoir. Rule 2 of Conservation Order No. 173 defines this pool as the accumulation of oil that is common to and correlates with the accumulation found in the Atlantic Richfield Company West -1- Sak River State No. 1 well between the depths of 6,474 and 6,880-feet md, or 6387.9 and 6793.9 feet, subsea. The West Sak-1 .well type log is shown on Exhibit 1. The Waterflood Permit Area depicted in Exhibit 2 is the area of. the Kuparuk River Reservoir for which the Kuparuk Owners are formulating water injection plans. The Waterflood Permit Boundary encircles the current Participating Area, and follows the outer boundaries ~'f the governmental sections listed in Exhibit 3. The Kuparuk Owners expect the' Kuparuk Participating Area to change as development of the Kuparuk River Reservoir yields new information on the extent of recoverable reserves. Therefore, the Kuparuk Owners make a special request to have the AOGCC administratively approve changes to the Waterflood Permit Area. Exhibit 2 also depicts the leased acreage held by the Kuparuk Owners and affected parties. ARCO Alaska, Inc. as operator for the Kuparuk River Unit will be operator of the fullfield waterflood program. The names and addresses of the Kuparuk River Unit lease holders and other affected parties are listed in Exhibit 4.. Waterflood Development Plan and Rate of Development (20 AAC 25.400.b.9) The Kuparuk Owners recognize that water injection is an effective secondary recovery method to help maximize oil recovery from the Kuparuk River Reservoir. Timely implementation of water injection will provide pressure support to help maintain oil production offtake and reduce solut'ion gas production. Current design of the waterflood project is based on the available reservoir performance data. It is necessary for the Kuparuk Owners to maintain flexibility in their plans and to modify development schedules and project scopes as new reservoir performance data and information requires. During 1982, the Kuparuk Owners received permission from the AOGCC to conduct Increment I Waterflood as a pilot project to optimize and reduce the risks of a fullfield waterflood. Throughout 1983, water from the Upper Ugnu Formation has been injected into waterflood patterns on Drill Sites lA and 1E (Exhibit 5). Preliminary data from the pilot has yielded valuable information on directional permeability in the reservoir and water injection profiles that will be useful for well spacing and orientation of future waterflood patterns. In 1984, upon approval by the AOGCC of this fullfield Application, two drill sites adjacent to the Increment I Waterflood pilot, Drill Sites 1F and 1G, will be waterflooded using source water capacity from the Upper Ugnu formation and available produced water volumes (Exhibit 6). Expansion of the waterflood should reduce pressure decline and solution gas production on the two drill sites. This should reduce producing GOR's in these areas, allow more oil to be processed through Central Production Facility No. I (CPF-1), and accelerate waterflood response from these drill sites. Increment I Waterflood as expanded to Drill Sites 1F and 1G will continue in the CPF-1 area during 1985, but no new drill sites will be waterflooded. CPF-2 should be operational in late 1984, and will process oil from the southwestern portion of the reservoir (Exhibit 7). -2- In 1986, treated Beaufort Sea water will be used to waterflood a total of eighteen drill sites in the-CPF-1 and CPF-2 areas (Exhibit 8). CPF-3 is currently scheduled to start up in early 1987, and will include water injection facilities. Ten drill sites in this area should be waterflooded before the end of that year (Exhibit 9). Drill sites developed after 1987 w~ll be waterflooded withih twelve months after they are brought on production. Ultimately, the entire reservoir within the Waterflood Permit Boundary will be waterflooded (Exhibit 10). Injection Water (20 AAC 25.400.b.7) Waterflood of the Kuparuk River Reservoir currently uses source water from the water bearing sands of the Upper Ugnu Formation. After 1986, source water will be Beaufort Sea water. Produced water from the Kuparuk River Reservoir will also be reinjected through separate surface handling facilities to avoid mixing with source water. The source and produced water rates are discussed below. Source Water Water from the Upper Ugnu Formation is currently produced from ten wells on Drill Site lB to supply water for the Increment I Waterflood. An additional well is used to monitor pressure in the water bearing sands (See Exhibit 11 for listing, Exhibit 13 for location). This source water supply will be used until early 1986, and'then discontinued. The source water well capacity from the Upper Ugnu Formation is estimated at 58,000 BW/D with existing downhole pumps. Average source water injection rate to date has been 48,500 BW/D. The Beaufort Sea source water will be filtered, chlorinated, and deoxygenated at the Seawater Treatment Plant (STP) located at Oliktok Point. The treated source water will flow through large diameter pipelines to local injection plants (LIPs) located at each CPF. The Beaufort Seawater Treatment Plant will have a nominal capacity of 400,000 BW/D. This capacity will be utilized for injection until about 1990 and then will decline as fillup occurs and as produced water rates increase. Produced Water Initial produced water rates from the Kuparuk River Reservoir will rise steadily over the life of the field. By the mid-1990's, approximately 300,000 BW/D or half of the peak water injection rate of 600,000 BW/D will be produced water. Well Descriptions (20 AAC 25.400.b.2,3,8) The locations of existing exploratory, production, and injection wells within the Waterflood Permit Area are shown on Exhibits 12 and 13. The completion interval for these existing wells is the Kuparuk River Reservoir. The exploratory wells within the Waterflood Permit Area have been either recompleted and renamed for use as producing wells, suspended, or abandoned (Exhibit 14). The status and a recent production test from each producing well in the current -3- producing area are listed on Exhibit 15. The wells in the field used currently for ga.s injection are li~ted in Exhibit 16. Water Injections Wells Current Injection Wells-(20 AAC 25.400.b.5) Drill Site lA has eight water -injection wells within 320-acre five-spot patterns. Drill Site 1E has t~elve water injection wells within 80-acre five-spot patterns on the western side, and 160-acre five-spot patterns on the eastern side. The status of each water injector is shown in Exhibit 17. Logs of each water injection well are shown in Exhibit 18. Future Injection Wells (20 AAC 25.400.b.2) The locations of future water injection wells will depend- upon the pattern selected for fullfield waterflood. The pattern is currently under evaluation. On a typical four section drill site, well locations for five-spot and line-drive patterns are shown on Exhibit 19. In either pattern, the drill site will have eight water injection wells, or two injection wells per section, to develop 320-acre patterns. Some peripheral drill sites, will cover areas other than four governmental sections, and will have more or less water injectors than the typical eight. A map showing the currently planned drill sites and the proposed number of water injectors to develop 320 acre patterns is shown on Exhibit 20. The fieldwide total of 417 injection wells includes the twenty water injectors on Drill Sites lA and 1E. The number and location of water injection wells necessary to optimize waterflood recovery from the Kuparuk River Reservoir may change. Therefore, approval of unrestricted well spacing will provide flexibility to maximize recovery through varied pattern configurations and spacing. Injection Well Completions (20 AAC 25.410) The completion design used for Increment I Waterflood water injectors is shown on Exhibit 21. During completion operations, integrity is tested by displacing fluids in the production casing with NaC1/NaBr brine after cementing, and holding a 3000'psi pressure for 15 minutes. This or a similar casing test will be performed on all future water injection wells. To detect any leaks which might occur after injection begins, the pressures in the annulus between the production casing and the tubing, and in the annulus between the producing casing and the surface casing are monitored daily. This practice will continue for fullfield waterflood. Increment I Waterflood results 'have indicated that injection well completions need to allow for control of water injection profiles, particularly in areas of the Kuparuk River Reservoir where two sand units are present. Possible well completions for profile control are shown in Exhibit 22, although future completions will not be limited to these designs. The "single" completion is the design currently used. The "selective single" completion is being field tested in well 1E-14, and has been installed on wells in Drill Sites 1F, 1G, and 1Y to gain additional operational information. The "dual" completion is under -4- study. All future water injection wells will be cased, cemented, and monitored as 'per 20 AAC 25.410 and Field Rule 4. Records and Reports (20 AAC 25.430) The operator will keep records of injected and produced fluid volumes, and reservoir and injection pressures, and will file reports to the AOGCC as required per 20 .AAC 25.340. ~ Notification (20 AAC 25.400.c) A copy of this application has been mailed to all the Kuparuk River Unit Working Interest Owners referenced on Exhibit 4 and parties owning acreage adjacent to the Kuparuk River Unit boundary. Attached to the cover letter transmitting this Application is an affidavit of mailing to the parties set forth on Exhibit 4. -5- KUPARUK RIVER FORMATION ...... ~ TYPE SECTION: WEST SAK RIVER ST. N e, , : i~ ~u,-'~'.- -- ~ . ;',1 ~ · , / ''['. ~:1 6656 .................. +'-~ -~ ............. , ...... ~ ~-.-~ .......... _-:.~ ..... _., ...... ~ ,- ~.. ......... ~.,.-~. _~ ~'- ~ ~-~' '~ ~ , ..... ~ ..... ~ ~ ....... ~ ..... ..................... o .... ~ .... ~. .-~_ II ~~~- _ .... ~'.r'll 2.......... I ~~ .... . q~: I EXHIBIT I EXHIBIT 3 KUPARUK RIVER FIELD WATERFLOOD PERMIT'AREA DESCRIPTION BY SECTION T10N,,. R8E, U.M. 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17 T10N, R9E, U.M. 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 17, 18 T10N, R10E, U.M. 6 T12N, R8E, U.M. I, 2, 11, 12, 13, 14, 23, 24, 25, 26, 35, 36 T12N, R9E, U.M. All 5'~. 6, 7~, 8, 9 , .15, 16, 17, 1,8, 1.9', 20~ 2:1, 22, 23, 25, 26,. 27, 28, 29, 30~ 31, 32, 33, 34, 35, 36 T12N , Rile TllN, R8E, U.M. 1, 2, 11, 12, 13, 14, 22, 23, 24, 25, 26, 27, 28, 32, 33, 34, 35, 36 TllN, R9E, U.M. All TllN, R10E, U;.~., Ail TllN, RllE, U,M. 5, 6, 7, 8, 17, 18, 19.~. 20~ 30 T13N, R8E, U.M.. , 13, 23, 24, 25, 26, 35~. 36 T13N, R9E, 15, 16, 17, 18, 19., 20, 211'., 22, 25, 26, 27, 2.81, 29, 30, 3'1, 32, 33, 34., 35, 36 EXHIBIT 4 KUPARUK RIVER FIE'LD LEASE HOLDERS J. C. Burnside AMOCO Production Co. 1670 Broadway Denver, CO 80202 L. E. Tate ARCO Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510 (Operator) M. G. Knowles BP Alaska Exploration Inc. One Maritime Plaza, Suite 500 San Francisco, CA 94111 T. A. Edmondson Chevron U.S.A. Inc. P. O. Box 8200 Concord, CA 94524 J. C. Bowen Exxon Company, U.S.A. P. O. Box 5025 Thousand Oaks, CA 91359 W. J. Clauser Mobil Oil Corporation P.O. Box 5444, Terminal Annex Denver, CO 80217 T. J. Jobin Phil lips Petroleum Company 8055 E. Tufts Avenue Parkway Denver, CO 80237 G. J. Abraham Sohio Petroleum Company 50 Fremont Street San Francisco, CA 94105 R. M. Barnds Union Oil Co. of California P.O. Box 6247 Anchorage, AK 99502 OFFSET LEASE HOLDERS C. Burg lin P.O. Box 131 Fairbanks, AK 99707 H. W. DeJong Diamond Shamrock 410 17th Street Denver, CO 80202 J. Y. Christopher Amerada Hess 1200 Milan, 6th Floor Houston, TX 77702 M. Thatch er Gulf Oil Corporation 5200 Stockdale Highway Bakersfield, CA 93309 H. D. Haley CONOCO Inc. 2525 C Street, Suite 100 Anchorage, AK 99503 J. W. Conwell Placid Oil Co. 550 W. 7th Avenue, Suite 1100 Anchorage, AK 99501 E. P. Nelson Texaco Inc. P.O. Box 4-1579 Anchorage, AK 99509 I I Kuparuk U nit._.~ Boundary Waterflood Perrr Exhibit 5 it Boundary -I I I I I I I r I r-..i I .I I I I I Year End 1983 Status ~~-~ Increment I Waterflood Natural Depletion Central Production Facility No.1 Operational Kuparuk Unit Boundary I I I I ! I I I I I I I =._.J I I I I I Exhibit 6 ! I I I I I I I I I Waterflood Permit Boundary I' I I r.-.J i .i I I I I Year End 1984 Status Increment I Waterflood and Expansion Natural Depletion Kuparuk Unit , Boundary I I I I I I __J I I I I I I I I I I I I' I I I l I CPF-2 ,I Il, I Exhibit 7 Waterfiood Permit Boundary "1 1 I I I I I l CPF-1 r~ I I I Year End 1985 Status Increment I Waterfiood & Expansion Natural Depletion CPF-2 Operational Oliktok Pt. STP Kuparuk Unit , Boundary I I I I I I I -I I I i I I I I I I I I I I I I Waterflood Perm it Boundary Exhibit 8 CPF-1 LIP I i-- -.I I I I I I Year End 1986 Status Increment II Waterfiood Natural Depletion Seawater Treatment Plant Distribution Lines Two Local Injection Plants Oliktok Pt. STP I I I i I I Kuparuk Unit._._~ Boundary Waterflood Permit Exhibit 9 Boundary CPF-1 LIP I I I _1 I I I I Year End 1987 Status ~ CPF-3 Waterflood Natural Depletion CPF-3 with LIP Operational I I I I I I Kuparuk Unit_.~ Boundary Exhibit 10 Waterflood Perm Oliktok Pto STP t' it Boundary I I I I Ultimate Status ~ Waterflood Ail wells Refer to completed Exhibit 13 Well Drill site lB WSW 1 WSW 2 WSW 3 WSW 4 WSW 5 WSW 6 WSW 7 WSW 8 WSW 9 WSW 10 WSW 11 EXHIBIT 11 · KUPARUK RIVER FIELD WATER SOURCE WELLS WELL STATUS in the Upper Ugnu fo~ locations. Formation. API Number 50- mid-Jan. 1984 029-20537 029-20812 029-20817 029-20833 029-20838 029-20851 029-20861 029-20864 029-20868 029-20876 029-20882 observation well active act act act act act act act act act ire 1ve 1ve lye lye lye 1ye lye lye EXHIBIT 14 KUPARUK RIVER FIELD EXPLORATORY WELLS WELL STATUS ."~1]. '..wells .completed in the'.~.uparuk River Reservoir. 'Wells' Inside Current.. 'Produci~n.'g..,A'rea · .API No. mid-Jan. .Shown ,on Well 5'0- "19,8.4 .E x,h i bi t iD r:i! 1 s i t..e ' 1 A .,.W. Sak 12 02'9-20313 n°w.:"~lA-08 13' "Drill site lib :..W. Sak '7 02.9.-20237 now lB-05 13 · :'Drill site lC ~,'~. :.$ ak '1 029- 20.0.9.0 ~s.uspended 13 ?D~ill site 1D '~.W, S'ak '8 029-2'0266 now .1D-08 1.3 ~'.'D.. r..: i 11 ~. S. i.t e 1 E ?W. ' iS'.ak .2 '0, 2'9 -,20.1' 3'4. su s p e nd,e d 13 "Drill site 2X .W, Sak .9 '02.9-20274, suspended 13 ,.Outs ide ' Current ,Produc i Kg "Area ~'MObi!! :MP ~1 :~17-11-11 'O'liktok Pt, Ug'nu ...1 W,...s~.ak .3 mW ' ..Sak ':4 w...Sak W....'S:ak ~1'~4 '.,.W...'.S.:~k ·:15 W.. 'S.ak 16 W. Sak .17 W. Sak W..S. ak 24 . D'29 ~230 0 5 2 su spe nded .1.2 · . G2'9~2D 573 su spe~n~ed 'i2 ~!~3 029 -.2070 i' a b:a ndon ed ' 1.2 029-'i!2 0009 s.US pe nded 12 .0, 29,2,01 39 suspended .i2, ~ 1.3 iLO'29:~72'.0 3'~'~3 ab:an~ on ed 1:2 ~: !.13' '0' 29 -.~20 ~27..5' S.'US.'ipe n tied ',...1.2 .0,29 ~2:0.41 ~9 .... s U s Pen d e d ~ 172 .0 2.9..e:~2:0.01 ~3 .s.us pe.n ded . ~ 1:2 029 ~':2 0 541 s u s pe nd.ed ":~ 1:.'2 0 29-20 54:2 s u s pen ded 02 9- 2 G69 9 suspended 0 29-2072 3' su spen~ed 1:'2 WELL Ail wells completed Refer to Exhibit 13 Well API Number 50- Drill site iA 1 029-20590 2 029-20599 3 029-20615 4 029-20621 5 029-20627 6 029-20630 8 029-20313 10 029-20673 Drill site lB 1 029-20465 2 029-20531 3 029-20588 4 029-20595 5 029-20237 6 029-20603 7 029-20616 8 029-20635 Drill site lC 1 029-20526 2 029-20532 3 029-20535 4 029-20547 5 029-20550 6 029-20564 7 029-20569 8 029-20585 EXHIBIT 15 KUPARUK RIVER FIELD PRODUCTION WELLS STATUS AND TEST SUMMARY in ~he Kuparuk · for locations. River Status mid-Jan. 1984 Test Date active active shut in shut in active active active active 01-12-84 01-11-84 01-08-84 01-09-84 01-12-84 01-11-84 shut in shut in shut in shut in shut in shut in shut in shut in shut shut shut shut shut acti shut shut in in in in in ve in in 09-15-83 Reservoir. Production Oil STB/D Rates Water Gas STB/D MSCF/D 1724 580 3335 352 2126 530 1151 521 1635 0 2351 18 1736 28 758 1668 1223 403 2401 1782 1402 Exhibit 15 Well Status Page 2 and Well API Number 50- Drill site iD 1 029-20393 3 029-20408 4 029-20416 7 029-20430 8 029-20266 Drill site 1E 2 029-20472 3 029-20477 5 029-20479 6 029-20493 7 029-20495 8 029-20496 11 029-20787 12 029-20736 15 029-20769 17 029-20793 18 029-20904 20 029-20895 22 029-20884 24 029-20857 25 029-20844 26 029-20840 28 029-20832 29 029-20828 Drill site IF 1 029-20889 2 029-20881 3 029-20853 4 029-20846 5 029-20807 6 029-20820 7 029-20830 8 029-20836 9 029-20983 10 029-20984 11 029-2099'3 12 029-21012 Test Summary Status mid-Jan. r984 shut in shut in shut in shut in shut in active shut in shut in active shut in shut in shut in active active shut in shut. in shut in active shut in shut in active shut in active active active active active active active shut in shut in active shut in active active Test Date Production Rates Oil Water STB/D STB/D Gas MSCF/D 01-08-84 332 5 341 01-10-84 470 0 734 01-13-84 874 0 1365 01-03-84 985 0 1411 01-12-84 859 0 1016 01-06-84 2527 269 4758 01-03-84 445 0 318 01-05-84 1803 0 1844 01-09-84 59 0 88 01-13-84 874 166 3498 01-12-84 256 34 988 01-06-84 635 0 663 01-08-84 404 46 537 01-07-84 543 1 894 01-04-84 1567 794 1649 01-08-84 552 149 2742 Exhibit 15~ Well Status Page 3 and Well Drill 1 2 3 4 5 6 7 8 9 11 12 13 Drill Drill 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 API Number 50- site 1G 029-20805 029-20813 029-20824 029-20835 029-20908 029-20890 029-20872 029-20849 029-21001 029-21008 029-21009 029-21016 site iH 029-20792 029-20770 029-20727 029-20741 029-20755 029-20763 site 1Y 029-20933 029-20941 029-20943 029-20948 029-20966 029-20958 029-20950 029-20944 029-20935 029-20934 029-20926 029-20913 029-20903 029-20910 029-20919 029-20927 Test Summary Status mJ.d-Jan. 1984 shut in active active active shut in active active active active active shut in active active shut in plugged shut in active shut in active active active active shut in active active shut in active active active active active active active active Test Date 12-27-83 12-29-83 01-03-84 01-08-84 12-31-83 01-01-84 01-12-84 01-11-84 01-09-84 Product ioh Rates Oil Water STB/D STB/D Gas MSCF/D 2159 0 3460 2058 0 3947 1808 0 642 3762 0 6375 2233 0 1822 1800 0 664 72 0 3 1909 0 2957 1961 26 3638 01-13-84 328 0 328 11-09-83 312 0 374 01-05-84 01-13-84 01-01-84 12-29-83 01-07-84 01-02-84 856 0 2271 0 3393 0 3080 25 3769 0 3019 0 1777 0 2196 0 2406 0 3104 2 1849 0 199 0 2134 0 1096 0 01-08-84 01-04-84 01-11-84 01-10-84 12-31-83 01-01-84 01-11-84 01-03-84 1245 3750 6202 4920 4377 6006 3385 2093 1772 4597 1380 161 1290 848 Exhibit 15 Well Status Page 4 and Well API Number 50- Drill site 2C 1 029-20962 2 029-20972 3 029-20968 4 029-20973 5 029-20978 6 029-20979 7 029-20975 8 029-20974 Drill site 2F 13 029-21032 14 029-21048 Drill site 2X 1 029-20963 2 029-20982 3 029-20987 4 029-20995 5 029-20985 6 029-20988 7 029-20991 8 029-20992 Drill site 2Z 1 029-20953 2 029-20960 3 029-20964 4 029-20965 5 029-20956 6 029-20957 7 029-20946 8 029-20924 Test Summary Status mi~-Jan. 1984 active shut in active active active active active active drilled drilled active active active active shut in active active active active active active shut in shut in shut in active shut in Test Date Production Rates Oil Water STB/D STB/D Gas MSCF/D 01-06-84 35 0 99 01-02-84 356 0 72 01-01-84 304 0 423 01-11-84 225 0 164 01-05-84 0 0 0 01-09-84 100 0 157 01-10-84 1060 1 682 01-03-84 01-05-84 01-08-84 01-02-84 01-09-84 01-12-84 01-07-84 4388 20 3885 0 3132 2 3926 2 4377 0 1796 0 361 0 2134 0 236 0 2903 0 1070 0 12-24-83 01-11-84 01-05-84 01-12-84 8435 3124 3060 351 3479 959 16 2601 296 2451 1950 Ail wells Refer to EXHIBIT 16 KUPARUK R~VER FIELD GAS INJECTION WELLS WELL STATUS completed Exhibit ,13 in'the Kuparuk for locations. Well API Number 50- Drill site lB 9 10 11 029-20655 029-20656 029-20657 Drill site lC 9 10 029-20859 029-20865 Drill site ID 029-20429 029-20417 029-20418 River Reservoir. mid-Jan. 1984 active active active active active active active active Ail wells completed Refer to Exhibit 13 Well Drill 7 9 11 12 13 14 15 16A Drill iA 4 9 10 13 14 16 1.9 21 23 27 30 EXHIBIT 17 KUPARUK RIVER FIELD WATER INJECTION WELLS WELL STATUS in the Kuparuk for locations. River API Number 50- site iA 029-20658 029-20669 029-20685 029-20688 029-20700 029-20706 029-20711 029-20713 -01 site 1E 029-20464-01 029-20478 029-20720 029-20725 029-20750 029-20751 029-20777 029-20905 029-20892 029-20858 029-20837 029-20814 Reservoir. mid-Jan. 1984 active active active active active active active active active active active active active active active active active active active active EXHIBIT 18 KUPARUK RIVER EIELD WATER INJECTION WELLS LOGS Refer to Exhibit 13 fo~. locations. Drill Site iA 1A-07 1A-09 iA-ii lA-12 lA-13 lA-14 lA-15 1A-16A Drill Site 1E 1E-lA 1E-04 1E-09 1E-10 1E-13 1E-14 1E-16 1E-19 1E-21 1E-23 1E-27 1E-30 KUPARUK RIVER OIL 5858 TO 6188 FEET, S~,'qSEA WATER INJECTION WEL~ 1A-07 APl ,5002920 65800 ~RMMA RR¥-FDN S NEUT. POROSITY-FDN S U ~ , , , , so~,~ dii _ BM -~ M S O ;' DENSITY-PON S D MEDIUM-OIL I I I'm'''l t ~ I Ilmmml SHRLLOW-DIL KUP'AMUK hllVlt::H UIL P'UL.;~L 5984 TO 6264 FEET, S}~"BSEA WATER INJECTION WEL",.. 1A-091 APl 5002920 66900 ORLIPER-FDN 8RMMR RR¥-PDN ,J S NEU?. POROSIT¥-PDNILS] S '% ~ M ~ ' ' ' , s% ~ M ¢' S D ;~ DENS I?¥-PDN S D O 200 B~I~FIRL K RESIS?IVITY, DEEP .................... MEDIUM-DIL .................... ~P~ SHRL.LON-DIL KUPAI~ILIK HlVb. H i;~IL'P'UUL [ 5991 TO 6245 FEET, SIJ~$EA [ WATER INJECTION WELL iA-111 APl 5002920 68500 I CRLIPER-FDN 8RMMR RR¥-PDN RESIS'rIVI?¥, DEEP ................ ,I , , HEDIUH-DIL ......... , , ....... , , SHRLLON-D IL KUpARUK RIVER OIL P~OOL I 5833 TO 6167 FEET, SI~~' SEA I WATER INJECTION WELL 1A-121 APl 5002920 68800 J CRL IPER-PDN GAMMA RAY-PON RESISTIVITY, DEEP .................... MEDIUM-OIL .................... ~P~., SHALLOW-OIL KUPARUK RIVER OIL POOL 5935 TO 6291 FEET, WATER INJECTION WE~,- 1A-13 APl 5002920 70000 j" OFIL IPER-FDN BRMMR RR¥-FDN NEUT. POROSI?Y-FDN , , I , :" BENS IT¥-FDN J. s% ~ M¢~ SD RESISTIVITY, DEEP ........' ~ , ......... ~PP~ MEDIUM-DIL ..... ,,,, , ,,~ ....... ~P~.. SHRLLON-D I L KUPARUK RIVER Oil PO~OL 6015 TO 6353 FEET, S~t', SEA WATER INJECTION WELL APl 5002920 70600 CRL I PF.R-FDN I BRHMR RR¥-PDN NF.UT. POROSIT¥-FDN OF. NS RF.SISTIVITY, D££P .................. I , lP~O.,. MP. DIUM-OIL ................. , , , SHRLLON-OIL KUPARUK RIVEH UIL I-'(;~;~L I 5894 TO 6210 FEET, SI¢C~SEA ] WATER INJECTION WELL 1A-15I APl 5002920 71100 I ORLIPER-FDN 8RMMR RR¥-FDN S B · BENSIT¥-FON 5 B RESISTIVITY, DEEP .... ,,~,l ~ I , ~ ,~,,I. ~ I MEDIUM-OIL .................... SHRLLON-OIL KUPARUK RIVER OIL POOL 5902 TO 6208 FEET,-Sl~' ,SEA WATER INJECTION WELL 1A-16A APl 5002920 71301 CRLIP~R-FDN BFIMMR RR¥-FDN S SD NEUT. POROSITY-PDN ' DPNS IT¥-PDN KUPARUK RIVER OIL POOL 5964 TO 6268 FEET, S( .;SEA WATER INJECTION WELL 1E-lA APl 5002920 46401 'I' ORL ! PER-PON ,~ t I I @RMMR RR¥-FON S LR?EROLO@~ DEEP NEUT. POROSITY-PON S LRTEROLOG,SHRLLON DENSI?¥-PDN S 0 MICRO SPH~R. POC. KUPARUK RIVER O~L ~OOL 5860 TO 6095 FEET, ~' ,~SEA WATER INJECTION WELL 1E-.04 APl .5002920 4.7800 . CRLIPER-FON C-~MMR RR¥-FON S D · DENS I'r¥-FON S NEU,r. POROSI,rT-F'ON[LS) S SD RESIS,rIVIT¥~ D£EP I lll .............. II M~DIUM-OIL ............... ,,I , ,~ SHBLLON-DIL · i I- T'I"ITiI , iii,, - ~ :~., ~ - ~ , KUPARUK RIVER OIL ~OOL 6075 TO 6344 FEET, S{ ,~SEA WATER INJECTION WELL 1E-091 APl 5002920 72000 CRL I PER-FBN I I I BRMMR RR¥-FDN S SD NEUT. POROSITY-PON · DENSITY-PON RES ! S.1, I V I"1'¥ DEEP ', ......, ,,, ..... ", / MEDIUM-OIL SHRLLOW-O IL KUPARUK RIVER O~L PO, rtL I §084 TO 6360 FEET, SU~..,EAI WATER' INJECTION WELL '1E-10I . API-5002920 72500 J ORL I PPR- PON @RMMR RR¥-PDN S NEUT. POROSITY-PON S S O DENSITY-PDN S O RESISTIVITY, DEEP ................... MEDIUM-OIL SHRLLON-BIL KUPARUK RIVER Oil POOL 6089 TO 6373 FEET, S( JSEA WATER INJECTION WELL 1E-13 APl 5002920 75000 CRL IPER-FDN I 6~RMMR RR¥-FON S NEUT. POROSITY-PON 2 DENSITY-PON SD RES I ST I V I TY, , DEEP .................. MEDIUM-OIL , ,,, .......,,, ...... SHRLLOW-D IL KUPARUK RIVER O~L POOL 6067 TO 6347 FEET, SUt .,EA WATER INJECTION WELL 1E-14 AP! 5002920 75100 CRL I PER-FDN @RMMR RR¥-FDN RESISTIVITY, DEEP MEBIUlI-BTL .................... SHRLLON-O I L KUPARUK RIVER OIL POOL 6053 TO 6341 FEET, $(' ..,SEA WATER INJECTION WELL 1.E-16 APl 5002920 77700 ORLIPER-FON S 8RMMR RR¥-PDN S O NEUT. POROSITY-PDN · DENSITY-PON so~) ~ M¢,~ SD RESISTIVITY,,DEEP M£D I UM-O I L i , , , ,,,il I I ,I IIIi'1 SH~LLON-DIL I CRLIP~R-FON KUPARUK RIVER OIL POOL 6003 TO 6380 FEET, SL( SEA WATER INJECTION WELL 1E-19 APl 5002920 90500 . 8RMMR RR¥-PDN S NEUT. POROSIT¥-F'DN S D · DENSI?¥-FDN P~Rl K OTTO R£SISTIVITY, DERP S MEDIUM-OIL S 0 SHRLLOW-D I L KUPARUK RIVER OIL POOL 5958 TO 6273 FEET, Sill ~SEA WATER INJECTION WELL 1E-21 APl 5002920 89200 ORLIPER-FBN S @RHHR RR¥-FBN S B NEUT. POROSI?¥-FDN ;" DENSIT¥-FBN s°4~ UB He1 SD RESIS?IVIT¥~,DEEP ......... ,,,, ...... AO~.._. M£DIUM-DIL , ...... ,~ ,, .......... ~ SHRLLON-DIL KUPARUK RIVER OIL POOL 5907 TO 6190 FEET, SI.J, SEA WATER INJECTION WELL 1E-231 APl 5002920 85800 ORLIPER-FDN ~'~ I I I ., I ~RMMR RR~-FON $ SD KUPRRI. K,~ l,. ~'~PRRL K NF~UT. POROSITY-PON · DENSITY-PON RP. SIS, TIVITY,' DEEP S MEDIUM-OIL so~ BU ~ ........ , ........... M '" S O SHRLLON-DIL KUPARUK RIVER OIL POOL 5924 TO 6212 FEET, SU~' .iEA WATER INJECTION WELL 1E-27 APl 5002920 83700 ORLIPER-FDN S <~ , . , , , 12~ ~ M~ 8RMMR RR¥-PON S O L1 ,,,'UU . -7 KU,~RRL K 2. ~,~RRL K NEUT. POROS IT¥-PDN ;' DENSITY-PDN $0 RESISTIVITY, DEER ......... i, ........ MEDIUM-DIL , SHRLLOW-D IL I KUPARUK RIVER OIL PgOL I 16048 TO 6328 FEET, SUI..;EA I IWATER INJECTION WELL 1E-301 I APl 5002920 81400 I ORLIP£R-FDN S @RMMR PRY-PON S D NEUT. POROSITY-PON S 2 DENSITY-PON S O RESIS?IVIT¥~ DEEP .................... ~p~,. H~D]UH-D~L .................. ,,~9~ SHRLLON-DIL Kuparuk River Field Waterflood Patterns On Drill Site Of Four Governmental Sections Five-Spot Pattern Line-Drive Pattern Producer ~ ConverSion to Water Injector Exhibit 19 AIO & 12 ~ 08 A8 I O8 Kuparuk Unit....~ Boundary I I o10 I I I I A8 I I I I I I I I I Al0 o10 A8 08 A8 08 A8 08 A8 O8 A8 08 A8 o8 A8 ~8 ~8 A8 o8 Waterflood Permit Boundary o6 Exhibit 20 O2 08 r~ A4 04 .'Kuparuk River Field Well Count per Drill Site 320 Acre Pattern Waterflood Development /X Water Injectors 403 Total O Producers 417 Total m Central Production Facilities Kuparuk River Field Present Completion Design Water Injection Well- Increment I Waterflood 1. Tubing Hanger 2. Tubing Retrievable SSSV 3. Gas Lift Mandrel 4. Seal Bore Assembly 5. Packer 6. No-Go Landing Nipple 7. 31/2'' 9.2# J-55 BT&C Coated Tubing 5 10-3/4" 45.5# * K-55 Surface Casing Exhibit 21 *Current well completions use 9-5/8" surface casing 7" 26# K-55 Production Casing Kuparuk River Field Completion Alternatives Water Injection Well - Full Field Waterflood SELECTIVE SINGLE I TUBING PRODUCTION CASING GAS LIFT MANDREL SINGLE GAS LIFT MANDREL DUAL GAS LIFT MANDREL KUPARUK C SAND PACKER I PRODUCTION/ INJECTION MANDRELS BLAST JOINT PRODUCTION/ INJECTION MANDREL PACKER 2 PACKER PACKER BLAST JOINT CIRCULATING SLEEVE PACKER 2 KUPARUK A SAND Exhibit 22 MEMORAI L)UM Stat of Alaska T~U: Lonnie C. Smith C~mi ss i one r TELEPHONE NO: FROM: Blair E. Wondzell Senior Fetroleum Engineer SUBJECT: Use of 10 3/4", 45.5 lb/ft. KF-ERW Attic Grade, J-55 Buttress Casin§ for Surface Casing in the I~uf~aruk River Fi eld In /~RCO's April 15, 1983 letter to you, they requested Commission approval to use subject casing as surface casing in the I<uparuk Piver Field. Arco also presented a letter from PDA Engineering. titled "Strain Limit Analysis of 10-3/4", 45.5, lb/ft Casing, AFE 260948" dated ~tarch 23, 1983, The letter from PDA is "a summary of the conclusions reached during the analyses of the 10 3/4" buttress thread casing made from J55HF/ERW. steel." In addition to PDA's comments, stress strain curves of J55HF/ERW steel were presented. I reviewed the data contained in PDA's letter and made a cal- culation of joint strength utilizing'the procedure recomn~ended by' API which is contained in API Bulletin 5C3, formula 4.2.1. ~ased on my review and calculation, the 10 3/4", 45.5 lb/ft., Ii~'- EI,~W Arctic ~rade, J-55~,uttress casing meets the strain require- ments (0.9% in tension and 1.26% in compression) for surface casing in the Kuparuk River Field as specified in Conservation Crde'r ' 1%~o. 173. I recommended that we issue Administrative Approval No. 173.3 to allow ARCO to use 10 3/4", 45.5 Ib/ft, HI~-Elt~ Arctic. Crade, J-55 Buttress casing for surface casing in the t<uparuk .River Field. ~';' I)qlA!Rr~v 1' AGO 10023398 ARCO Alaska, Inc. Post Office BI ~60 Anchorage, Alaska 99510 Telephone 907 277 5637 /~pril 15, 1983 Mr. C. V. Chatterton State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 SUBJECT' Qualification of 10-3/4" 45.5 lb/ft HF-ERW Arctic Grade J-55 Casing Dear Mr. Chatterton' Attached is a letter from PDA Engineering summarizing the results of the strain limit analysis of 10-3/4" 45.5 lb/ft HF-ERW Arctic Grade J-55 casing. The analysis demonstrates that this casing exceeds tile Kuparuk River Field rule requirements for surface casing. Since extensive computer studies were previously done on 10-3/4" 45.5 lb/ft K-55 casing when it was initially qualified as surface casing, and considering that both K-55 and J-55 grade steels are designed to the same specifications except for ultimate strength, this letter should provide sufficient evidence to show that the casing meets the' post yield strain requirements stated in the Kuparuk'River Field Rules. Therefore, ARCO Alaska, Inc. requests that the Kuparuk River Field Rules be changed to read as follows: Rule 4, Section (d) (1) The only types and grades of casing, with threaded connections, that have been shown to meet the requirements in (d) above and have been approved for use as surface casing are the fol 1 owing' (A) 13-3/8", 72 lb/ft., L-80 Buttress. (B) 13 3/8", 72 lb/ft., N-80 Buttress. (C) 13-3/8", 68 lb/ft., MN-80 Buttress. (D) 10=3/4", 45.5 lb/ft., K-55 Buttress. (.F) 9-5/8", 36 lb/ft., K-55 Buttress. (G) 9-5/8", 40 lb/ft., K-55 Buttress. (E) 10-3/4", 45.5 1.b/ft., HF-ERW Arctic Grade, J-55, Buttress. . .. ~ ,','~ ., ' · . ~,. ~. ,., ARCO Alask,~ Inc. i ..... bsidh"l~y ot Allal~ticRichf,~ldCornp.~ny AGO 10023399 " Mr. C. V. Chatterton April 15, 1983 Page 2 (H) 9-5/8", 36 lb/ft., HF-ERW Arctic Grade, J-55 Buttress. (I) 9-5/8", 40 lb/ft., HF-ERW Arctic Grade, J-55 Buttress. We plan to spud 1Y-7 on or before May 7, 1983. The tentative plan is to run 10-3/4" 45.5# HF-ERW Arctic Grade J-55 Buttress casing in this well, contingent upon your final review and ~pproval of our proposal. If we can be of any further assistance, please contact either Rich Gremley at 263-4972 or myself at 263-4970. Sincerely, Area Drilling Engineer /~. B. Gremley Drilling Engineer JBK/RBG18'l lm cc: J. S. Dayton, AFA 322 L. B. Kelly, AST 306 J. F. Messner, ANO 316 R. A. Ruedrich, ANO 332 P. A. VanDusen, ANo 323 KT2 AGO 10023400 ., ENGINEERING 23 March 1983 Mr. Danny Bradley ARCO Oil and Gas Company Research & Development Department Post Office Box 2819 Dallas, Texas 75221 Subject: Strain Limit Analysis of 10-3/4" 45.5 lb/ft Casing, AFE 200948 Dear Danny- This letter contains a sun~ary of thelcJnclusions reached during the analyses of the 10-3/4 inch buttress thread casing made from J55HF/ERW steel. Because of the extremely plaStic behavior of this material, the actual failure conditions are difficult to predict, but have been shown to exceed the requirements of 1.26% pipe strain in compression and 0.9% pipe strain in tension. The results are briefly sun~arized below. Compression The worst-case condition was analyzed at a pipe strain of 4.73%. At this condition, the thread sealing force at the inner thread was 1636 lb/rad versus the nominal Fnakeup value of 4066 lb/rad. Worst-case conditions were' minimum makeup (1.5 turns), minimum coupling thickness, no friction and high plastic modulus. The material model used is shown in Figure 1. The conclusions reached from the compression analyses are that the low plastic modulus of J55HF/ERW steel and relative thickness of the coupling to the casing result in a condition that leads to buckling of the casing outside of the coupling before thread jumping can occur. This failure mode was observed in the one full-scale test. ..on the 13.-3/8 coupling that was allowed to creep stabilize. AGO 10023401 1560 Brookhollow Orive Santa Ama, C:A 92705- 5475 (714) 556-2800 Telex: 683392 Mr. Danny Bradley, ARCO -2- 23 March 1983 Tension The initial analyses for the tension loading condition resulted in forces at the first loaded thread which, when applied to the fine mesh model of that thread, resulted in deformations and strains highly inconsistent with the likelihood that the pre- dicted loads ceuld concentrate at that location. It was hypo- thesized that the finite element model used was not refined enough to model the local yielding of the thread faces accurate- ly when we consider the low plastic modulus of the material, thereby resulting in a poor representation of the thread loads along the length of the coupling. To obtain improved results, the finite element model used in the original analyses of the 13-3/8 inch coupling was used. This model contains 2,044 elements compared to 1,451 elements in the present model. A tension analysis was made using this model at a pipe strain of 1.14%. The material model used had a yield stress of 71 ksi and a plastic modulus 'of 286,800 psi as shown in Figure 2. This model was selected as being most representative of the stress-strain · behavior up to 2.5% strain. The maximum effective strain in the analysis was 2.36% in the element containing the loaded face of first engaged thread. The load on that face was 28.76 kips/rod. Applying the displacements and loads from this case to a detailed model of the thread resulted in a maximum effective strain of 4.3% at the thread root. Extensive Yielding occurred in the thread itself, increasing from 4.3% at the root ~o 40% at the crest. This again illustrates that the load .used in the analysis is higher than would actually be carried by that thread under actual conditions, The material model used for the detailed analysis was chosen to be the best representation of the stress-strain data up to'a strain of 6%.as shown in Figure 3. The strain value of 4.3% at the thread root is well below the strain capability of the material indicating that casing frac- ture will not occur at this load condition. Additional analyses are being conducted to better define the tension margin of safety. Our final report preparation is underway and we plan to complete the effort in approximately two more weeks' We apologize for the long time required to resolve' the tension analysis problems, but the problems encountered could not have been anticipated. As a result of the analyses, considerable insight was gained relative to the tension failure mode. Thank you very much for your patience. JGC: brd Encs: Figures l, 2 & 3 cc: Mr. Rich Gremley, ARCO/Alaska, Inc. Very truly yours, JamesOn. Crose Director, Advanced Technology , AGO 10023402 r L r .... ; ............. .......... ~{~,,~. ' . . _ ~'~(~,'~S,~o,,, c~ ,,', t,, \xt %f.~ ............ . ................. . , . · ' ; ...... : i .......~':"i'-'" :--- ; ...... .............. ::';:'"~ .... ~'" i : ...... ? ....~ ..... ."'"'i-'-" ........ :-- ':-: .......... "'. ;"'i" i' . .,. :" "/t 'i,i~ ' ~ , . :..-: .. -! ........ : .'. "~ ~ i:::.i..:-!..:.~.:--;'-:.-:i-..:::....~..:-:--. -i .... :. i ; ...... ...... I ' "~ ! .... ..: ; ';...'; i". i' : : : ' I. '1 :"I ......... ' : _.L._-~... r:'--': .... ~--'t~,~ ...... i-- ...... ~.'-T'--'.:: [7 ~7 ~ ~ r.----~-,-- ..... .:---:- ....... .. t ,.~.': ~, "i ......e: ;:.."': ',.' :' ' ' . · , . . t . ": : .... '.' "::'/~ ..... :' -..:: ...... ,::::~':", ':'i .':' ': '"; ' : I ' ~ ': ~ i' ./': ' ' I' :' . I' : '1: : ': ...... .'! ': ~ ......... , . ; . ' ' '. 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I:",:!:,:.1:::'; ".I::::;::::I .:;. I '~ ..... i ~ , .. .? i ' J.. ! ' i , J '"-~ · ' . j . . .. ..... ~ ........... ::-.~.-:.~-i.i:ii::':,'.~:-..!"-.~:i~ :.i::;or,-:i::..i'.i" ,,oS:...:. ,~.,c, ......... ,~. ~ .... .... ,~. ~-:. , · .. ................. i ................ : ..,: .......:;;,'., .'., .'.":.:.~. ,~,,:.~. . . . ; ,' . . ~ ,' · t , ," '.--' ............. 'T ........... ."'."--: .... .--.'.-':'.-:'.'".":',.----:T.--.":'":::'::: ............................... " .... :'": .... ~'' '! '"" "':''' "' · i ............. '. ".' :' '.: :'~. ::~:~"':~-.',:~,~,~:'::,':,,~,:, ~,'..e"i~.".4ii~i...:;i.;:::..ii!..;:.::.: ..... i:.:.i .... :.._::.. i..:. '::..: :.:i:::;i;iii: ::':: ::'": ========================== .... ::'":":"':':':=' ' "' .. i"i AGO 10023405 ARCO Alaska, Inc. i' Post Office B~. 360 Anchorage, Alaska 99510 Telephone 907 277 5637 April 15, 1983 Mr. H. J. Hedlund State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 SUBJECT: 7" 26# Arctic Grade HF-ERW J-55 Casing Dear Mr. Hedlund: As per your request, the following outlines the performance specifications for the 7" 26# Arctic Grade HF-ERW J-55 casing which are currently using as production casing in the Kuparuk River Field. Arctic Grade HF-ERW J-55 casing is a casing developed for ARCO Alaska, Inc. for Arctic conditions. It meets all the specifications for API J-55 casing plus additional specifications which make it suitable for low temperature service. All 'Arctic Grade HF-ERW J-55 casing carries the API logo for JL55 casing and has the same collapse, burst, tensile and strength ratings. Therefore, we utilize API J-55 ratings for all casing design calculations involving Arctic Grade HF-ERW J-55 casing. Attached please find a copy of Arctic Grade~ HF-ERW J-55 casing specifications prepared by our metallurgical engineering group. If we can be of any further assistance, please contact either Rich Gremley at 263-4972 or myself at 263-4970. .Sincerely, Area Drill ing Engineer JBK/RBG19:l lm R. B. Gremley Drilling Engineer cc: J. F. Messner, ANO 316 R. A. Ruedrich, ANO 332 P. A. VanDusen, ANO 323 KT2 ARCO Alaska, ~.c. is a subsidiary of AllanficRichfieldCompa.y AGO 10023/+06 SPECIFICATIONS FOR ARCTIC GRADE HF-ERW J-55 and HEAT TREATED SEAMLESS OCTG Second Edition May 4, 1982 ~CF.,tVE° AGO 10023~07 AtlanticRichfieldCompany {~ Date: Subject: May 5, i982 HF-:-_-RW and Edition Seamless Specifications, Second :-cm.'~_ec~icn: ~ado Loncaric - DFL - 645 To,,"Lccation: * .; ~,m Levelle - DHB - 624 Attaci~ed is the Second Edition of the specifications for arctic grades tuS~lars. These specifications can be distributed as you see fit to enlarge the number of mills capable to meet the specification. Pleasetdispose of the original specification dated April 8, 1982. You will note that the chemical requirements in Section 3 are enlarged to make room for Nippon Steel, Japan. The enlargement does not reduce the quality to meet our needs. As you know, each manufacturer has slightly different chemical compositions and the procedure in fabricating the pipes. A delegation from Nippon Steel, consisting of three engineers in manufacture, three researchers, three staff people and executive manager, visited me on April 23, 1982 and presented data which prove that their product with slightly different chemical composition meets our requirements. This, and my intention to enlarge, the number of manufacturers to stimulate the competition and. lower the price for the products were the reasons to enlarge the window for chemical composition in the specification, Sect i on 3. The toughness of their pipes are about 35-4OFt-Lb in the seam at -25°F and COD (Crack Opening Displacement) which a better measure for toughness than charpies exceeds our needs. is Two additional mills (Kawasaki and NKK, both Japanese) are stuggling to pull through the window, to meet the second edition of this specification. They think they will be in a position'to discuss their research progress with me toward the end of May, 82. ~o,u h~ve any qu.e=stions, Loncaric please let me know. AGO 10023%08 RL/kh CC' A.R.CO.-1 -A Messrs: H.N. L .M. D.T. j.F. E.C. R.F. Stansbury - DHB Sellers - ~A Hellinghausen - ARB Bartlett - DHB Hertweck - DKP ~a, i~;: ;.E~i~:e!~ - A F A Messner - AFA Cramp - ARB Fei - AP - 2 7 3 0 :?:~" ;::?'; "' .;,!:' .¢,? .,,., .. - 10 3 3...':!i.?. - 948 . .. .,,:.-~ ~:. :,.. ,'. - 612 - 640 - 1130 - 3417 Arctic SPECIFICATION Grade *HF-ERW J-55 Casing and Tubing by Rado Loncaric Section I Scope This specification covers HF-ERW casing, tubinQ and ~seamless coupling. It is in addition to API Standard 5A and in addition to API Standard 5LX regarding the ERW weld properties. The casing and tubing made to this specification are intended for use at arctic condition where toughness is required. The toughness is a tolerance for imperfections introduced into the tubes during transpo.rtation, handling and running into the well during severe cold. When installed into a well, the tubes will be exposed to higher temperatures (15°F to 40°F). Sect i on 2 Process of Manufacture Materi a 1: Pipe Production: Hot rolled coil with specified chemistry, and toughness Roll forming and controlled, High Frequency E'RW with through wall seam normalizing as per API Standard 5A, Section 2, Paragraph 2.1, b in such a manner that no untempered martensite remains. Smaller sizes such as 3 1/2" O.D. tubing maybe either seam normalized or full body normal ized. *High Frequency - Electric Resistance Weld . 1 of 7 AGO Chemical Nominal Secti on 3 Properties and Tests Composition~ Percent Carbon .09 Sil icone .25 Manganese 1.40 Phosphorus .025 Sulfur .005 Copper, i f added .35 Vanadium + Niobium + Titanium Individually V, Nb, Ti shall Carbon Equivalent (C.E.) (C Residual combined elements, not exceed .40%. 0.13. maximum not exceed .07 + Mn) shall not sLIch as Cr, Mo, exceed .30. Ni, etc., shall Any appreciable deviation from the above composition, especially the elements affecting the toughness, cleanliness and mill weldability shall be agreed upon and approved by the Purchaser prior to production. Test Frequency: One per heat. 2 of 7 AGO 10023z~10 I ............ ~,:.. .... a · Physical Longitudinal Yield Strength Tensile Strength Elongation Frequency: b. Transverse Tensile Test C $ Secti on 4 Properties and Tests at Room Temperature d · 55 to 80 KSI 75 KSI minimum 25% minimum One per heat e· As per API requirements Frequency: Weld Tensile Standard 5LX, Paragraph 4.4 of Paragraph 4.7 and ASTM One per Test As per API Standard Frequency: One Flattenin~l Test heat· 5LX, per heat. Paragraph 4.5 As p Freq All API conforming A370. and Paragraph As per API Standard 5LX, Paragraph 4.14, if applicable single length and Paragraph 4.15 for multiple length. Frequency: One per 50 single length. Weld Ductility Test er API Standard 5LX, Paragraph 4.22 uency: One per 50 single length. retests for b, c, d, and e shall be Standard 5LX. to the 4.8. made according to for 3 of 7 AGO 10023~11 f. Longitudinal Yield Strength at -25°F Yield strength Tensile Strength Elongation Frequency: 55 KSI Minimum 75 KSI 25% Minimum One per heat Secti on 5 H_ydrostatic Test As per API Standard 5LX, with the exception that the test pressure be held for not less than 10 seconds. Secti on 6 Dimensi.on.s~ ,..Weights and 'Length As per Purchase order. Secti on 7 ,, ,.Pipe Ends and Thread Protectors As per Purchase order. Secti on 8 Couplings Couplings for HF-ERW tubing and/or casing conforming to this and API Standard 5A, shall be seamless and, unless otherwise specified in the Purchase order, shall be of the same grade and strength as the casing and/or tubing. Chemical Composition- Phosphorus .010% Max. Sulfur .030% Max. 4 of 7 AGO 10023412 ' Coupling stock shall be heat treated either normalized or quenched and tempered to meet Charpy V-notch, transverse of 3OFt-Lb at minus 25°F. The type of coupling shall be as per Purchase order. Maximum allowable hardness shall be Rc22. Frequency of Charpy and Hardness Tests: One per heat. The coupling stock shall be inspected according to API Standard 5A~ Appendix C, SR2. Sections 9~ .10 and 11 As per AP I Standard 5A, the Purchase order and the attached guide to Manufacturing and Testing Process. Jointers and weld repairs on the body and/or weld seam are not acceptable. Toughness Requirements Weld seam shall have Charpy V-nOtch, transverse 15Ft-Lb at minus 25°F Body of the pipe shall have Charpy V-notch, transverse 2OFt-Lb at minus 25°F Maximum possible specimen size shall be used. Smaller specimen shall be as per ASTM 300. Frequency: One toughness test per 25 lengths. One weld seam transition curve shall be made for every 5 heats. Hardness Requirements 3 microhardness indentations on the outside, 3 indentati.ons on the midwall and 3 on the inside location of the weld seam shall be made and the results on each loCation averaged. Maximum hardness shall be less than Rockwell C hardness 22 or equivalent. Frequency: One per 50 tubes. 5 of 7 AGO 10023413 Microetchin~ Microetching of the weld seam area at 100x shall be made and photo make available. Frequency' One per 50 lengths. magnification ~ADO LONCARIC DATE 6 of 7 AGO 10023414 Manufacturimg I , Guide to .-" F'© C ~ S S for HF-i~..'N Casing an..d Tubin9 Steel Making Slab Making Coil Rolling Forming We lld i ng Removing of F1 ash UST'I on Weld Seam, 1st Inspection Sea'm Normalizing Coo.. i ng Sizi'ng Flying Cut-off Endi Cropping Hydrostatic Test USTIon Weld Seam, Visual & Dimensional Ins!pection 2nd Inspection 7 of 7 AGO 10023~15 Threadinp Threadin Coupling 'Inspection Make-up Drift TeTt Hydrostatic wi t h Cou .Protecto Measuri n and Wei gt Marking Oil Coating Test ling Make-up of Length ing i' SPECIFICATION by Rado Loncaric Arctic Grade J-55 Sea. mless.Tubin9 and Casin9 This specification is in addition to API Standard 5A. 1. Steel shall be fully killed, made to a fine grained practice. 2. Guideline for chemical composition' Carbon .2O% Phosphorus Frequency 3. Heat ~ 5, Silicone Mana§anese .35% 1.50% and Sulfur are maxima. of test: One analysis treatments a. Normalized or b. Quenched and tempered. Physical Properties Yield Tens Elon Freq Toug Body: Phosphorus Sulfur Vanadium .030% .010% .05% per heat. Strength' ile Strength: gation- 55 KSI Minimum, 80 Higher than 75 KSI 25% Minimum uency of Test: One hness Requirements: Charpy V-notch, Frequency of test: One per heat transverse, per heat KSI Maximum 2OFT-Lb at mi nus 25°F AGO of 2 10023~16 6. Hardness- Maximum hardness shall be Rockwell C of 22 or equivalent. Frequency of test' 3 indentations shall be averaged. Test shall be made per 50 tubes. 7. Couplings- Be Couplings for pipe confirming this specification shall be seamless and, unless otherwise specified on the purchase order, shall be of the same grade as the pipe. a. Toughness: Charpy V-notch, transverse 30 FT-Lb at -25°F Frequency of Test' One per heat b. Hardness: Rc max. 22 or equivaient (see 6 above) Frequency' One her heat Nondestructive Testing: Per API Standard 5A, SR2 0 LONCARI~ ~--~-~ ~ DATE 2 of 2 AGO 10023~17 ARCO Alaska, Inc. ",.~ Post OfficeE~... 2;60 Anchorage, Alaska 99510 Telephone 907 277 5637 January 19, 1983 Mr. Chat Chatterton State of Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99504 Dear Chat' Thank you for meeting with Landon and me last Friday to discuss our current operations at Kuparuk and our short term plans. As we discussed, we plan to warm up our Increment I Waterflood Pipelines with warm gas. There is a possibility '~-hat some gas may be flared during the warmup operation. We estimate the maximum volume that may be flared is 60 MMCF over 6 days. We had originally pla.nned to ask the State for a permit to flare this gas volume over and above our normal allowed operational flare. The Commission suggested that we try to absorb this additional flare volume in our normal operational flare allowable. We should be able to do this since we seldom use up the allowable. If it appears, however, that the allowable will be exceeded we will notify you immediately. Once again, it was a Harry, and we will plans with you. If call. pleasure to visit with you, Lonnie, and conti.nue to periodically discuss our you have any questions please give us a Ryan L. St ramp Kuparuk Operations Coordinator RLS/kjc & Gas Cons. COmmission Anchorage ARCO Alaska, Inc ..... Post Office .~, 353 Anchorage. Alas~.a 99510 Telephone 907 277 5637 January 14, 1983 Mr. C. V. Chatterton State of A1 aska Alaska Oil & Gas Conservation Commi s s i on 3001 Porcupine Drive Anchorage, AK 99501 SUBJECT' Qualification of 9-5/8" Surface Casing Kuparuk River Unit Dear Mr. Chatterton' Please find a summary of HF-ERW test results, AMF Tuboscope Inspection Report, and ARCO's specifications for Arctic Grade HF-ERW J-55. Please note that the specifications for Arctic Grade HF-ERW J-55 have been released to steel manufacturers around the world. The specifications are no longer proprietary information and can be obtained from our purchasing personnel in Dallas. This casing can be obtained by any compan~corporation or individual from any of the qualified manufacturers. If we can be of any further assistance, please contact either Rich Gremley at 263-4972 or myself at 263-4970. Sincerely, Area Drilling Engineer P. A. VanDusen District Drilling Engineer JBK/RBG2' 1 lm cc: J. S. Dayton, AFA 322 L. B. Kelly, AST 306 J. F. Messner, ANO 316 L. M. Sellers, ANO 332 P. A. VanDusen, ANO 323 K.4.8.1 G.6.8.8.4 ARC;'~; ',;,',: .... 'n,: s n. SuL'~idi,:wy of AtlanticRichfieldCompany AGO 10023~+21 Iii SUMMARY OF HF-ERW TEST RESULTS Casing Tensile Yield Elongation Coupl i ng Tensile Yield Elongation ARCTIC GRADE HF-ERW J-55 81,000 psi 71,000 psi 34% 78,000 psi 62,000 psi 57% API REQUIREMENTS min 75,000 psi 55-80,000 psi rain 24% min 75,000 psi 55 -80,000 psi min 24% Casing Tensile Yield Elongation Impact Body Weld Coupl i ng Tensile ARCTIC GRADE HF-ERW J-55 86,000 psi 76,000 psi 31% 50 ft lb 70 ft lb 86,000 psi Yield 67,000 psi Elongation 33% Impact 202 ft lb ARCO SPECIFICATION TESTED Ca -25F min 75,000 psi 55-80,000 psi mi n 25% 13 ft lb (half size sample) 10 ft lb (half size sample) rain 75,000 psi 55-80,000 psi min 25% 30 ft lb (full size sample) These pipe also meet all other API specification including flattening test hydrostatic test to 3800 psi, wall thickness, drift, weight, diameter and collapse. RE E VE D GREMLE/1 01/'13/83 AGO 10023422 JAN 1 Oi~ & Gas Cons. Commissior~ A, nchorag~ . , ~ ~" I TUBOSCOPE DI¥1S!ON AMF K.K. Aoyama Dai.ichi Mansions 4-14, Akasaka 8 chome, Minato-ku, Tokyo 107, Japan Akasaka P.O. Box 39 INSPECTION REPORT The following material has been inspected and accepted in accordance with API Specification 5A and Customer Specification Arctic Grade HF, ERW, J-55 Second editOr'-May 4, 1982. · APPLICANT PROJECT .. SUPPLIER- .: MANUFACTURE PURCHASE ORDER NO. PLACE OF INSPECTION · ARCO OIL and GAS COMPANY · KUPARUK FIELD · SUMITOMO CORPORATION · SUMITOMO METAL INDUSTRIES LIMITED · 20803-6202 · WAKAYAMA, JAPAN COMPLETION DATE OF INSPECTION - OCT. 9, 1982 ITEM NO. · 3 9-5/8 "O.D., AND COUPLING, RANGE 3, CASIHG QUANTITY MANUFACTURED 28 COILS 3 QUANTITY INS'~o~r_c ~ :u .... 372 . PC_S.. _ QUANTITY SHIP?ED 369 PCS 14,476.7 FT DESCRIPTION 40.0 #, ARCTIC GRADE HF ERW J-55, BUTTRESS THREADS HEATS 259.560 METRIC TON AGO 10023~23 Alaska Oit & Gas Cons, Commissio~ Anchorage - 2- I. INSPECTION Inspections were conducted according to API Customer Spec. Arctic Grade HF ERW-J55. 5A Std. and 1. Process of Manufacture The pipes were manufactured controlled rolled coils, rolled into a tubular shape and with the abutting edges welded from one side by an ERW process. T. he coils were manufacturered from killed steel produced by the basic oxygen process. 2. Weldin~ T'~e weld seam was heat treated by high frequency induction h6ater (through wall seam normalizing) and water cooled. -. 3. Sizing and Straightening Sizing was carried out with sizing rollers to give a slight reduction of less than 2 % on the O.D. in order the obtain the desired accepted O.D.. Straightening was made simultan- eously with the some procesS or With a rotary type straigntener. 4 Fla~_enina Test Flattening test were conducted on all pipes ~t 90° from the weld and 2 per coil at 0°. Results' 372 PCS TESTED 0 PCS REJECTED 372 PCS ACCEPTED 5. Hydrostatic Test before Threading Hydrosta,~c tes,.o were conducted on each pipe under the press,~re of 3,800 PS= for no less than 10 seconds. Resul ts ' 372 PCS TESTED 0 PCS REJECTED 372 PCS ACCEPTED 6. Ult'-.:sonic Examination- 1ST ACC~°T':'''r:~.~,,~ TEST AGO 1002~~+2z+ pipe body was inspected b~ an automatic rotating Ultrason~ seamine devise. Results' 372 PCS ZNSPECTED 0 PCS REJECTED, 372 PCS ACCEPTED -3- 7. Weld Repair No weld or body repairs were permitted. II. DIMENSIONS AND LENGTH 1. Diameter The outside diameter of the pipe as measured by gauging the circumference did not deviate from the nominal diameter by more than plus/minus 0.75 %. 2. .Wall Thickness ~he plate thickness at any point in the pijo.e did not deviate from %he nominal thickness by more than lb % and minus 12.5 %. 3. .Pipe End The bevelled ends were inspected, and in case of any damage rejected by our inspector. Results- 372 0 372 4. Visual Inspection PCS INSPECTED PCS REJECTED PCS ACCEPTED Each length of pipe was visually inspected for surface cracks, seams, overlaps and other imperfections. Results: 372 PCS TNSPECTED 0 PCS REJECTED.* 372 PCS ACCEPTED * See attached Rejection Report.(N/A) Acceptance for further fabrication 372 Pcs were accepted for further fabrication/inspection as foiTows. AGO 10023425 -4- III. INSPECTION - 2ND ACCEPTANCE TEST 1. The full length of pipe was inspected by the following ins- pection methods. a) Magnetic particle inspection in accordance with API Spec. 5A, appendix C, Sr-2. b) Ultrasonic Inspection in accordance to Mill Standard (10%). Results- 372 PCS INSPECTED _ 0 PCS REJECTED 372 PCS ACCEPTED 2. '~Threadine 'Buttress threads were cut on by a high efficiant threading machine with tungsted carbide tools. 3. Thread Inspection Each thread was inspected for accurate Lead, Taper, Stand Off, Hights of thread, length of thread etc. plus visual inspection and gage control and gauging practice. Resul ts' 372 PCS INSPECTED 0 PCS REJECTED* 372 PCS ACCEPTED * See attached Rejection Report. (N/A) 4. Couoling make up On each pipe a coupling was made up power tight to a position between base and apex of triangle per API Specification. The torgue limits were as per purchase order. Hin. 83,7.KG/.META~'!ax. 1859KC~/M _ 5. Thread Compound All thread were coated with BAKER SEAL thread compound. AGO 10023426 A~chcrag~ -5 - 6. Drift Test - As per purchase order Each pipe was drifted throughout its entire length with a cylindrical drift mandoel with 8.750 "O.D. (Special/~,z). Results- 372 PCS DRIFTED 0 PCS REJECTED 372 PCS ACCEPTED 7. Hydrostatic Test Hydrostatic tests were conducted on each pipe with the coupling power tight attached under a minimum pressure of 3000 PSI for · no less than 10 seconds. Results- 372 PCS TESTED 0 PCS REJECTED 372 ,PCS ACCEPTED 8. Measuring and Weighing Each length was measured and weighed with an outomatic devise. a) 40.0 FT flAX, 35.0 FT MIN. 39.23 FT AV. b) 40.0 LB/FT - KG/M - KG/FT 9. Marking Each pipe was marked with a shipping mark on the outside surface of the pipe as well as with a die-stamp marking on the pipe and coupling. a) Shipping mark' SAME AS PACKING LIST b) Pipe Die-stamp- ~ ~ 9 5/8 40.OOJ (SUMITOMO MARK) AGO 10023z+27 ' -6- c) Coupling Die-stamp- ~/a~ 40JE (SUMITOMO MARK) 10. Coating Mill Varnish Coating was applied on each pipe on the outside surface. 11. Protector Make Up Thread protectors for both pin and coupling ends were of the Arctic Type,Thread Compound was BAKER SEAL. IV. CHEMICAL PROPERTIES AND TESTS 1o Carbon Equivalent Standard Max. 30 % Actual Min. 24 % Max. 28 2. Physical Tests The preparation of test specimens and .the test were performed by the manufacturer under our supervision as per applicable Tensile Test Specification. a) Room temperature Base (Longitudinal) Results: SATISFACTORY (SEE ATTACHED INSPECTION CERTIFICATE) Base (transversal) Results- Weld (transversal) Results' AGO 10023~+28 - 7 - b) At minus 25°F Base (Longitudinal) Results: SATISFACTORY (SEE Weld (Longitudinal) Results: " (") 3. Weld Ductility Test Results: SATISFACTORY (SEE.ATTACHED 4. Charpy Impact Test at Minus 25°F ATTACHED INSPECTION Base Size of speciment 10 Results: SATISFACTORY Weld Size of speciment 10 Resul ts: SATISFACTORY .ca ) b) INSPECTION c) One weld transition Hardness Test X 5 MM (SEE ATTACHED INSPECTION X 5 MM (SEE ATTACHED I.NSPECTION curve oer 5 heats were a) Base (Coupling stock only) Results: SATISFACTORY (SEE B) ATTACHED CERTIFICATE) Weld Results- (NRC 22 Ma x .') (,,) 6. Microeraohic' Examination - CERTIFICATE) CERTIFICATE) supplied. INSPECTION On one weld gross-sectien out of 50 pieces micrographic examinations were performed. Results: SATISFACOTORY (SEE ATTACHED INSPECTION CERTIFICATE) 7. Collaps Test CERTIFICATE) (ATTACHED) AGO 10023429 CERTIFICATE) C.O.D. Curve. 8. Special Test Collaps tests were performed on one piece per heat at the minimum collaps pressure of 27570 PS~. ..... ~[!ilj ~ ~' ~:I~" Resul ts: SATISFACTORY -8- 9. Loading Supervision The loading was supervised during load out. Results: See the Attached Report. VI. CONCLUSION From the results of the inspection, the pipe item(s) and quantities described herein, were found to be of satisfactory quality in compli- ance with the specifications noted above. We verify that the inspection was performed in strict compliance with the above mentioned specifications, and the written inspection reports fur~ished shall represent good faith opinions only, and are not to be construed as warranties, or guarantees as to the merchantability, quality,.productiveness, or fitness for use of the pipe or other items inspected. No claim with respect to services sold shall exceed the purchase price of that service and AMF K.K., Tuboscope Division's liability shall be so limited regardless of loss or injury sustained by customer. AMF K.K. TUBOSCOPE DiV!SI .. · d. Te;,.:es for Supervisor Attachments: MILL CERTIFICATES INCLUDE ALL TEST RESULTS, PACKING LIST AND LOADING SUPERVISION REPORT. AGO 100234.30 [~llstomer -\rtiele ; St~MIT()M() METAI~ INDUSTRIES, WAKAYAMA STEEl_. WORKS 185o MINAT(h WAKAYAMA..IAI'AN 5g :ification ... VidJ. C .~tt. t~,.'..)i.l.:, %otl,oL.~g I.,.~~. ~ 3~ ~J' f~ Order Size ~'i-~2~.(~... Order Quantity ~A~],-~- Delivery Quantity I ":' Ikl K N,,tes. IItem ~ ~ ~ ~ Test ................................... ,., _~ (~ Unit= ~ 1 '~v"~'~d~o~;~ kg & ~ No. ,,f PieceICpm- In ~ ! , ::Inch. ~ ::: Feel Space Corn- A.B, NBor NS-=Nnminal Size ( No. Mill Work No. No. _..-'z ._ _- ............ ~ :N,,minal Weight ~[~ O.D. ~ Thickness ~ Length ~ Total_ Length ~ Weight -~ Total I.,,ngth ~-~ ~ '~'-,~ght-- p~ete plete :';,C t tl.~ 1 kg S :- Schedule SWG or BWG=Gaug, i4YT[;...}jJ>:i. ~-5/~~ ;~-t.~U~ t~--3 l~,..zO0' '57,81~. 3:,9 ~c';. . ".> 5,.,,; O · 2 B or Space=Bndy Te.. , [~:-'p ;.~ :i } W : Weld Test 14,410. i' '-:~ ' ...,~:/ {$ ~ Remarks a3 ,'t r:'~'; ',. i~i.~ ~ :. - ~ ~ ~ ~ ~ff~ ~ ~ Discription of Test l"ii,? i~',lv 3. Hydrostatic Test ~ ~' ' Weld leverse Magnetic _ ~ Zinc ':' ' ..... ~ ' ,;, ~ Dimension Flattening Ductility Bending Flaring Flange Crush Expansion Flattening Particle Ultrss0nic Eddy Coating Coa~ng Drift -] qr~ . ~ 3 ~'.);.];~;P.~ i [ , -;~ r, Good t.;,:-~' '"(;oo,~ Good ....... ~od -- ..:,.>'1 Lot ~l~ Tensile Test ~~ ~g ~ ~ ~ Chemical Composition (%) :';t~it../,)}'~xS'.'~' ' "';:'s,] or v.~. o, v.s. I T.S- G.L. ~ Test 2 EL. Cu, Cr, Ni, Mo.V or Ceq.=Xl00 N,B >'10000 i:[~ctrt%',' ...'_ ',. ~i:4~.' C: O No. ~ Xl~ Xl~ other elements (~~) =Xl000 o [~pa:t Toa; : ":., 5 ' 9 ~ :tlcr~graph[c Ex~littakion : .... I2 14 :;-'~ Z ':~< M in. Standard Max. Surveyor to ~g~[~. ~~{:~b~'~- ~n~b accordance with the requirements of the ~bove specification and the result of ail test ~re ~j~[~ ..... ' :- ~" /' --'~--~. ~_~z .... ~?_5. - -.~-'~- iff] Mamger of Quality System.~~&_ <) ~'- ~O/ .-' //~> ~;~ acceptable. Quality Control ~rt~~ No.; t ATTACHMENT TO TEST RESULT SUMITOMO METAl. INI)US'I'I~II~.S, I.TI), WAKAYAMA STF, I£1, WORKS 1850 MINATO, WAKAYAMA, JAPAN Work No. 'JI ,~1~ ,~,[ 1~ Tensile +est ¢i~,-;d;~ fL "}~: ~J~ 9~' Chemical lot ~: ~l~,:.~x~ -'. ~; '~ ~ ~ ~* ~ ~ Hardness " - C Si Mn P or ~ ,. ,, ~. s. T.s. ~. ~.. t~l~ ~ Ct I ................... Test EL. Cu. Ct, NJ, Mo. V O. ~ I P~[ Pgl in ' % 12 x 1~ x 1~ other elements ............................... ....... ................. ................... 1 I g 69100 8~0~ 2 ~3.0 g 8 1~ 114 20 3 3 ......... ~ 81100 ~ ~ 1~ 11~ _~[ ............. ......................... , L 137~ 19100 " 3~.9 C 1 1~ 115 21 3 .................. .......... :................ 0 2 ~ ~05~ 81a~ :' 31.~ L 6 14 I11 ............... ~ 81600 C 6 13 10~ ........ ............................... L ~z400 18I~ -, ~.8 C 6 13 109 i-- 3 a 7~ 81}~ " 33.5 L 8 12 10~ 20 ~ 81600 C ~ 11 105 L 713~ 77~ " 36.4 C 7 11 I05 _.~ M~,,. 550~ 1~000 15.0 L 8 25 160 [ ............................. - ........ Max. 80~0 - - g 9 23 IlO 25 5 - 35 Composition (?6) ....... ~4I ......................... or Ceq. ?~ B I~) .... . ..lear (-~a){fi~a)~[;.~) ~' I000 "~'//(~t; .......... ....... ..... ........... B2~81 .............. ..... ....... 0 '~ ..... ~ .......... ....... ....... ..... Slandard ~? 1. Bor Space Body Test(a~4~¢), W Wdd Test *~ L-Ladle ln~lysts, C~h, ck ~alysis 'No.' Work No. :oup I i 'J I 'iii ,i,t: ~ Tensile 'l'u-~t '78200 63000 19100 - ATTACHMENT TO TEST RESULT SUMITOMO Mi~'I'AI. INI)tJS'I'I;tllgS, I_,TD, WAKAYAMA STEEl. WORKS 1850 MINATO. WAKAYAMA. JAPAN EL. o-5 51.3 × 1ooo Chemical Cmnposition (?6) Cu, Ct, lqi, Mo, V or Ceq. xlO0 B 10000 ot her elements ¢ ~ a){l!~o> n~J~) × i000 .l> 0 0 ~,landaTd ............ [ Max. 80OU0 -- _ h,ta. ,1; 1. Bor Sl~,ce Body 'l'eslf/:lfd:~l;~. W Weld 'l'esl ((i/t;.;';I;) L-~ngic~i~l, C-gas,, (~ngitudinsl), D~al4 (bnfiitMinsl) · 2 L-Ladl~ Analyst~, C-Check analyai.~ '3 kJasiduats (Cr+~i) *i ~b+V+Ti ~S Ceq.~tHn/b NO.' Work No. ~IYT~'20 ~55 ATTACHMENT TO TEST RESULT . (lenstl~ Te~t ~t -iS'F) SUMITOMO METAl_, INL)I. JSTRIES, L' WAKAYAMA S'l'l~,l!;i, WORKS 1850 MINA'FO, WAKAYAMA, JAPAN 'il ~1~ ,~,~ I~ Tensile Test fi)l!~3o~i fE "1~: U3~ 5} Chemical Composition (%) Heat ~4o. N,t 1 P~[ ?~1 ~ 96 '~ l~ :< l~ ' other elmnents (~a)fAa)~S.~) x 1000 ................................. ............ D 79900 89~ " 19.6 ........................................ [ .......... .............. ~26811~ Z C 157~ I .................................... B~48111 3 C 13~ 187~ " 32.8 D lOOO0 835~ ', 30.8 ..................... -~ ~.~-- ~ .... ~-.~ ....... __ ~ .... ~ ...... o ~~- N ....................................... _ ........................... i ........................................ ......... M in. Standard Max. ...................... Not~. ~O l. U or Since-' Body Test(/¢~d:g), W 'Weld Test (~lii~5) L-~ngtt~tnal, C-B~st (~agltudteal}, D-~eld (~agltudinal) ~z L-l, adle Analysis, C~heck ~alyais ~3 Resid~ls (Cr+~t) ~ ~+V+Ii *~ Ceq.~ln/b No.' Wot k No. .............. (Coupll~ O O Standard Min. Max. dl ']1,~ ,[,~: 1~ Tensile 'I'~ Y. 1'. or Y. $. T. S. (;. I _ ._ PSi. ATTACHMENT TO TEST RESULT (Fensile ~est.. at -'Z~ ti' i-~ l~ ,_ t'?,L. 06 '!00 _ _ 33.6 55000 ,SIjMI'I'OM() MI~/I'AI, INI)IJS'I'RIES, l/FI), WAI<AYAMA S'I'I';I';I, W(;Ri<S 1~50 MINAT(), WAKAYAMA, .IAI'AN h~'.· 1. I3 or Space: Body 'Fest(l~}M~), W: Weld Test · z L-La-die Amal¥~£a, G-"q.;h~¢k a.ualy~.i~ Work No.: i4¥YId2095S ;j~ ~ ~ ~ ~J~ ~ ~ (~ 761) ATTACIIMENT TO IMPACT TEST RESULT SUMITOMO METAL INDUSTRIES, LTD. WAKAYAMA STEEL WORKS 1850 MINATO. WAKAYAMA. JAPAN ..... ; [ {fl~i~ Remarks Lot ~lgl~ 7~~ ~ ~ ~ ~ tl~ ~ tt"' ~. 4 ~' ] ~ ~ {~ Test Value~ Beat No. °r Direc ~----- , Test ~[ Test -tion Type of Specimen .{ ,[z f~ ~ Size Unit ...................... No. Temp. ~ 2 notch (mm) ~ 3 ~ 4 I 2 3 Average ] ............... - ............................................... BZ68167 I B --ZS~F I 2~ V 10 x 5 g ~ F 56 54 53 54 ............................................................. ~2481.70 3 :' " ...... ' "J" J 11 45 43 .... i ................ l ....................... , ............................................... i · ' 5 " " " ' ~ "~" 52 51 49 51 .................... ~._ - : ..................... ___ __ " I " " '~ " " ' " 53 5Z 52 52 .................. .................... j.......................... , .................................................................... " 9' " " ....... ' ~3 51 69 5I ' .............. lO ! .... " " 51 45 ~9 68 [ ...... .. .: , " 11 ..... ' ' " " " It ~ J Il. i3 ' - - min rain Standard I g F I - 1~ I ~otes. ~ I ...... B or Space ~ B~7 Test (~), W = Weld Test (~), H : Ha~ (~~) ~ ...... L = Longitudinal, T: Transverse, Z: Through Thickness ~3 ...... E == Absorbed Energy (~m$~v~--)'. 8: 8hear Area (~fii~), C: Cleavage Area (~t~i~), L: Lateral Expansion ~4 ...... K = Kgf'm, F ~ ~t'lb[, J ~ Joule, I = Kgf'm/cm~, 2 = lt'lbf/in~, ~ = PercenL M ~: mm, N ~ inch AGO 10023436 W?_rk__No.:. W~I~I20 ATTACIIMENT 'FO IMPACT TEST RESULT SUMIT¢)M() MIVFAL INDUSTRIES, LTD. WAKAYAMA STEEL WORKS 185/I MINATO, WAKAYAMA, JAPAN I Lot ~t~ '~ ~ ~ I~' J[~ ~ ~ t-~: q- 4 -< ~ ~ ~ {l~ Test Value . Direc ' - ~ -- or ~ ] Test Type of [ Specimen ~9~ · ~] ~ ~ ~ Each ". 'lz Yd Test -tion ! Size ; [ Unit l - i ' ~ Il, al HO. No. Temp. ~ ~?y.h .............. (mm~ ~3 ~4 ] [ [ , ' 3 ~ .............................................. ~ ............. i ~ _ . . ii Average ~Z48171 I 12 B -'25~'F T g~ V 10 x 5 ~ ~ i 47 , 41 41 41 43 ~ 4~ 46~ ............................................................... . 1~ .... ' " " , . ......... - .... I ..... ' .................... I Standard [ i i Notes. ~ ! ...... B or Space = B~y Test (~), W Weld Test (~), H ~ Haz (~~) ~ g ...... L ~ Longitudinal, T = Transverse, g = Through Thickness ~ 3 ...... E ~ Absorbed Energy (~m.~./pV--), S := Shear Area (~i~), C ~= Cleavage Area (~{q~i~), L :: Lateral Expansion (]g~l{~lff) ~4 ...... K = Kgf'm, F = ft'lbf, J = Joule, [ = Kgf'm/cm:, 2 = ft'lbf/in~, % = Percent, M =-~ mm, N := inch AGO 10023437 Work No.' ATTACHMENT TO IMPACT TEST RESULT SUMIT(.)MO METAL INDUSTRIES, I.T WAKAYAMA STEEL WORKS 1850 MINATO. WAKAYAMA. JAPAN ..... ~i~i''4y i' ~; ~ {~i Test Value [ (~:~ Re~nark.q Test ~1 Test -tion Type of Specimen {fi~)} ~ ~ ~ a ~ Each ;tz g~ {f~ [ ~ Size ~ I Unit ................... [ .... I ~ (~uplinl ) No. Temp. ~ 2 notch (mm)12-' 3 ~ 4 I 2 { 3 Average ] :_:~, :.~ ~782~ 2 . ,, . , ,, ,, ,, . 1~ _l 179 ] 174 1~ c;:<: ...... .......................... ~ ............................... 'I . ~ ............. . .~ , ............... ~ .................................... i ...... ............ I ................... i ............. I i , ......................... i ....................... - ......................... J i ....................... ~ ........... - ...... __ , I ........ ............. i I i . [ 'Tin 'Tin ' [ Notes. ~ I .... ;-B or Space = Body Test (~), W = Weld Test (~), H = Haz ~2 ...... L = Longitudinal, T = Transverse, Z = Through Thickness ~3 ...... E ~= Absorbed Energy (~m~./v~-), S 8hear Area (~~). C = Cleavage Area (~i~), L =- Lateral Expansion ~ 4 ...... K = Kgf'm, F = ft'lbf, J = Joule, ! ~ Kgf'm/cm~, 2 ~ ft'lbf/in:, ~ ~ Percent, M :: mm, N := inch ...... 0 0 Work No.: 1~2-09~ ~'~ ~ ~ ~ b-~ ~ ~ (N~ 761) ATTACIIMENT 'FO IMPACT TEST RESULT S[JMITOMO METAL INDUSTRIES, LTD. VqAKAYAMA STEEL WORKS 18,50 MINATO, WAKAYAMA. JAPAN Lot I -~L l~ ~ ~ J~ 153 ~ J'~: ~5 O~, -~ }~= & 4 X } ~ ~ {~ Test Value ] {'{~ Remarks ......... . : Il Or -tion Direc '1 I {~ ~- }l~,t }~o. { Test ~l Test ] Type of Specimen ~ ~3 e {~ Each .,z ~d {ia } ) ~ Size Unit - ~ ..... ~ - . ~ ~-~ (~in~ -{ No. { Temp. ~ 2 notch (mm) ~ 3 ~ 4 [ ] 2 } 3 Average i I ' l B248170 i ,' " " ~' I " " " 2 54 ' 3 ................................. I. ............. ~ ...................... ~ ---~. ...... ,, ,, - ,, i ................................... ] ......... ~ ..... " _5_ _:" ......................... ~5 . ' _~I 55 ~ 6:~... .................................... .............. ~ , ...................... . ........................ 1 ................. m ..... is _~} ..... 72 77 '- ' I [ I - .._0__ ....... ;'_................................................... ', ,, ,. ,, ,, tis !o4 , to7 . '_ 1. { ............................ " 10 " ~' " ~' " " " .................... I ........ - [ [min ,m n , Standard m i ] i [ ' : ~ ........................................................................ Notes. ~ I ...... B or 8pace = B~y Test (~), W = Weld Test (~$~), H ~ Haz ~ 2 ...... L: Longitudinal, T: Transverse, Z = Through Thickness ~ 3 ...... E = Absorbed Energy (~m $ w ~--). S = 8hear Area (~~). C = Cleavage Area (~~), L ~= Lateral Expansion ~4 ...... K = Kgf'm, F = ir'lb[, J = Joule, I = Kgf'm/cm:, 2 = ft'lbf/in:, ~ ~ Percent, M ~-: mm, N ~ inch Work No.: ~i~;~0~-$8 ATTACHMENT TO IMPACT TEST RESULT SUMITOMO METAL INDUSTRIES, I.TD. WAKAYAMA STEEL WORKS 1850 MINATO, WAKAYAMA, JAPAN Lot ~1~1~ J] ~ ~ H" Il5 ~ ~ t,- ~ 4 ] or Direc Test ~l Test -tion ] Ty~ of $pecimen ] ~e'~ ~0.,[ No. '~_ } Temp. ~2 ~ ~~' notch (mm) ................................................ " 1) ':' " " " " '" " ............................. .................................................................. ................. ' ....... ] ......... ] .... I ...................... ....................... ~ .............................................. , ................................ ....................................................................................... ......................... ...... , ............ .......................... . ~ imin ' ~ t I min Notes. ~ I ...... B or Space = B~7 Test (~), W ~ Weld Test (~), ~ g ...... L = Longitu0inal, T: Transverse, g = Through Thickness ~ 3 ...... E ~ Absorbed Energy (~m~v~--). 8: Shear Area (~~). ~4 ...... K = KgFm. F = ~t'lb[, J = loule, I = Kgf'm/cm~, 2 = ~t'lbf/in~, ~ = Percent, M ~ mm, N = inch AGO 10023440 No. : 10 Work No.: WA~fW20 ~ Transition Curve of ChatTy Impa¢= Tes= 1. Dire¢=ion : Transverse 2. Specimen Size: 10 x 10 x Zmm V Notch 3. Hea= No. : .B248171 1'00 ,' ~ 60 o 40 20 ,-, 8g ~: 60 ~ 40 2O -120 -100 -80 -60 -40 -20 0 +20 .. · '. Test Temperature (°F) AGO 10023z~41 No. : 11 ii'- Work No.: WYYW2095 (Casing) ATTACItMENT TO HARDNESS TEST RESULT Outs ide Middle Ins ide Heat No. No. 1 2 3 4 5 6 ~ 8 9 " 3248167 1 88.4 89.6 84.6 87.2 87.9' 83.9 86.1 87.9 8'3.2 2 88.8 90.2 86.2 87.1 88.6 87.2 85.1 85~9 89.4 3248170 3 85.4 90.5 86.0 85.2 87.6 87.0 84.9 '86.9 88.4 ,,, 4 86.7 89.9 85'7 84.9 88.1 84.6 84.0 87.9 83.8 "5 86.2 89.2 87.0 85.6 89.0 86.9 85.1 '89.0 85.2 6 87.0 90.5 84.4 85.2 88.3 84.5 84.0 88.3 85.5 3248171' 7 87.2 96.6 88.9' 88.1 89.0 88.2 89.6 88.9 87.7 · 8 88.8 90.7 87.6 86.3 89.5 86.4 85.2 89.1 8"4.9 , Standard max. RRB 99.0 (HRC22.0) , , Weld approx. 2 5mm _- approx.-, at~p ro~ ..... ~ 10mm 10mm (Coupling) ,, , , Out side Middle Ins ide Heat No. No. , .... 1. "2 3 4 5 6 7 8 9 X272603 '1 91.0 91.4 91.0 85.3 85.4 85.4 84.8 85.1 84.7 X278200 2 90.2 90.4 90.4 85.5 85.4 85.4 85.2 84.9 84.7 Standard max. HRB 99.0 (HRC22.0) 10mm 10mm approx. 2.5mm AGO 10023442 '! JAN 1 4 I gS No'. ~: 12 Work No. '. WYYW2095 S Micrographic. Examination ( xlOO ) Lot No. Outside Middle Inside 0 0 No. : 13 Work No.: WYYW2095S Micrographic Examl.ation ( xlOO ) Lot No. ,utside l[ddle nside 6") o o 4 No'. : 14 Work No.: WYYW2095S , . ldicrographic gxami~mtion ( xlO0 ) Lot No. t s ide ddle ~tde O 0 0 SPEC!FICATIONS FOR ARCTIC GRADE HF-ERW J-55 and HEAT TREATED SEAMLESS OCTG Second Edition May 4, 1982 Oil ~',~ Gas C:ona. (;ommm~n AGO 10023446 AtlanticRichfieldCompany Date: Subject: May 5, HF-ERW Edition 1982 and Internal Correspor~ ce Seamless Specifications, Second From/Location: To/Location: Rado Jim Loncaric - DFL - 645 Level le - DHB - 624 Attached is the S arctic grades tub distributed as yo capable to meet t original specific econd Edition of t. he specifications for ulars. These specifications can be u see fit to enlarge the number of mills he specification. Pleasetdispose of the ation dated April 8, 1982. You will note t are enlarged to enlargement doe hat the chemical requirements in Section 3 make room for Nippon Steel, Japan. The s not reduce the quality to meet our needs. As you know, each chemical composit pipes. A del egat engineers in manu people and execut and. presented dar slightly differen requirement So Th of manufacturers price for the pro window for chemic Sect i On 3. manufacturer has slightly different ions and the procedure in fabricating the ion from Nippon Steel, consisting of three facture, three researchers, three.staff ive manager, visited me on April 23, 1982 a which prove that their product with t chemical composition meets our is, and my intention to enlarge the number to stimulate the competition and. lower the ducts were the reasons to enlarge the al composition in the specification, The toughness of their pipes are about 35-4OFt-Lb in the seam at -25°F and COD (Crack Opening Displacement) which a better measure for toughness than charpies exceeds our needs. is Two additional mills (Kawasaki and NKK, both Japanese) are stuggling to .pull through the window to meet the second edition of this specification. They think they will be in a position to discuss 'their research progress with me toward the end of May, 82. I f/~yo,u halve any qu~_stions, Rado Loncarlc please let me know. RL/kh cc: Messrs: H · J. L. D. J. E. N. Stansbury - DHB - M. Sellers - ABA - E. Hellinghausen - ARB - E. Bartlett - DHB - T. Hertweck - DKP - A. V'an Dusen - AFA - F. Messner - AFA - C. Cramp - ARB - ~- ~'^q _ /rD _ 2 7 3 0 .......... '~,~ Oi~ L~, r'~ 10 3 3 ~r,'hm.-~, ' .... 9 4 8 ~' 61 2 AGO 10023447 640 1130 '~Z~ 1 7 Arctic SPECIFICATION Grade *HF-ERW J-55 Casing and Tubing by Rado Loncaric Sect i on I Scope This specification coupling. It is i addition to API St properties. The ca are intended for u required. The toug introduced into th and running into the well installed into a well, the temperatures (15°F to 40°F covers HF-ERW casing, tubing and seamless n addition to API Standard 5A and in andard 5LX regarding the ERW weld sing and tubing made to this specification se at arctic condition where toughness is hness is a tolerance for imperfections e tubes during transpo.rtation, handling during severe cold. When tubes will be exposed to higher ). Sect i on 2 Process of Manufacture Materi a 1: Pipe Production: Hot rolled coil with specified chemistry, and toughness Roll forming and controlled, High Frequency ERW with through wall seam normalizing as per API Standard 5A, Section 2, Paragraph 2.1, b in such a manner that no untempered martensite remains. Smaller sizes such as 3 1/2" O.D. tubing maybe either seam normalized or full body normal ized. AGO 10023448 *High Frequency - Electric Resistance 1of 7 Weld Sect i on 3 Chemical Properties and Tests Nominal Composition~ Percent Carbon .09 Silicone .25 Manganese 1.40 Phosphorus .025 Sulfur .005 Copper, i f added .35 Vanadium + Niobium + Titanium 0.13 maximum Individually V, Nb, Ti shall not exceed .07 Carbon Equivalent (C.E.) (C + Mn) shall not exceed .30. Residual combined elements, such as Cr, Mo, Ni, etc., shall not exceed .40%. Any appreciable deviation from the above composition, especially the elements affecting the toughness, cleanliness and mill weldability shall be agreed upon and approved by the Purchaser prior to production. Test Frequency' One per heat. 2 of 7 a · Secti on 4 Physical Properties and Tests at Room Temperature Longitudinal 55 to 80 KSI Yield Strength Tensile Strength 75 KSI minimum Elongation 25% minimum Frequency: One per heat b. Transverse Tensile Test C · d, e · As per API Standard 5LX, Paragraph 4.4 conforming to the requirements of Paragraph 4.7 and ASTM A370. Frequency: One per heat. Weld Tensile Test As per API Standard .5LX, Paragraph 4.5 and Paragraph 4.8. Frequency: One per heat. Flattening Test As per API Standard 5~LX, Paragraph 4.14, if applicable for single length and Paragraph 4.15 for multiple length. Frequency: One Weld Ductilit.s As per AP I Frequency: All retests -API Standard 50 single length. per Test Standard 5LX, Paragraph 4.22 One per 50 single length. for b, c, d, and e shall be 5LX. made according to 3 of 7 AGO 10023~50 f · Lo6gitudinal Yield Yield strength Tensile Strength Elongation Frequency: Strength at -25°F 55 KS I Minimum 75 KSI 25% Minimum One per heat As per API Standard pressure be held for Secti on 5 Hydrostatic 5LX, with the not less than Test exception that 10 seconds. the test Secti on 6 Dimensions~ Weights and 'Len~jth As per Purchase order. Secti on 7 Pipe Ends and Thread Protectors As per Purchase order. Sect i on 8 Coupli. n, cJS Couplings for HF-ERW tubing and/or casing conforming to this and API Standard 5A, shall be seamless and, unless otherwise specified in the Purchase order, shall be of the same grade and strength as the casing and/or tubing. Chemical Composition' Phosphorus Sulfur .030% Max. .010% Max. 4 of 7 AGO 10023451 '1 Coup 1 i ng quenched 3OFt-Lb Purchase stock shall be heat treated either normalized or and tempered to meet Charpy V-notch, transverse of at minus 25°F. The type of coupling shall be as per order. Maximum allowable hardness shall be Rc22. Frequency of Charpy and Hardness Tests' One per heat. The coupling stock shall be inspected according to API Standard 5A, Appendix C, SR2. Sections 9~ 10 and 11 As per AP I Standard SA, the Purchase order and the attached guide to Manufacturing and Testing Process. Jointers and weld repairs on the body and/or weld seam are not acceptable. Toughness Requirements Weld seam shall have Charpy V-notch, transverse 15Ft-Lb at minus 25°F Body of the pipe shall have Charpy V-notch, transverse 2OFt-Lb at mi. nus 25°F Maximum possible specimen size shall be used. Smaller specimen shall be as per ASTM 300. Frequency' One toughness test per 25 lengths. One weld seam transition curve shall be made for every 5 heats. Hardness Requirements 3 microhardness indentations on the outside, 3 on the midwall and' 3 on the inside location of shall be made and the results on each location Maximum hardness shall be less than Rockwell C or equivalent. indent at i.ons the weld seam averaged. hardness 22 Frequency' One per 50 tubes. AGO 5 of 7 10023452 Microetchin~ Microetching of the weld seam area at lOOx shall be made and photo make available. Frequency' One per 50 lengths. magnification ~RADO [/~CARIC DATE of 7 Manufacturing and Testing Guide to Process for HF-ERW Casing and Tubi n~ Steel Making Slab Making Coil Rolling Forming We l:di ng Removing of F1 ash UST on Weld Seam, Seam Normalizing 1st Inspection Threadin Threadin Coupling Inspection Make-up Drift Te~t Hydrostatic Test wi th CouIling .Protecto~ Make-up Measurinl of Length and Weighing Marking Oil Coating Coo,1 i ng Si zli ng Fly,ing Cut-off End Cropping Hydrostatic Test UST) on Weld Seam, 2nd , i Visual & Dimensional Inslpect i on Inspection 7 of 7 A,,I':'~'~ .... a Oil ~ Gas Cons.. CommJssim~ AGO ~002345~ SPECIFICATION ti:' Arctic. Grade by Rado Loncaric J-55 Seamless Tubing and Casing This specification is in addition to API Standard 5A. 1. Steel shall be fully killed, made to a fine grained practice. 2. Guideline for chemical composition' Carbon Silicone Managanese Phosphorus .20% .35% 1.50% .030% Phosphorus and Sulfur are maxima. Frequency of test' One analysis per 3. Heat treatments a. Normalized or b. Quenched add tempered. 4. P. hxsical Properties Yield Strength: Tensile Strength: Elongation: Frequency of Test: One 5. Toughness Requirements: Body: Charpy V-notch, 55 KSI Minimum, Higher than 75 25% Minimum per heat transverse, Frequency of test' One per heat Sulfur Vanadium .010% .O5% heat. 80 KSI Maximum KSI 2OFT-Lb at mi nus 25°F ]] of 2 AGO 10023455 "1 ' 6. Hardness: · Maximum hardness shall be Rockwell equivalent. Frequency of test: 3 indentations averaged. Test shall be made per Couplinos: Couplings for pipe confirming shall be seamless and, unless on the purchase order, shall as the pipe. C of 22 or shal 1 be 50 tubes. this specification otherwise specified be of the Same grade a. Toughness: Charpy V-notch, transverse 30 FT-Lb at -25°F Frequency of Test: One per heat b. Hardness' Rc max. 22 or equivalent (see 6 above) Frequency: One her heat 8. Nondestructive Testing: Per API Standard 5A, SR2 ONCARIC DATE 2 of 2 JAN 1 4 iS83 Oil ~, Gas '~' ~,. oons. Commissior~ AGO 10023456 ARCO Alaska, Inc. Post Office Bo" ) Anchorage, Ale's.,,.. 99510 Telephone 907 277 5637 DeCember 15, 1982 Mr. C. V. Chatterton State of Alaska Alaska Oil & Gas Conservation Commi ssi on 3001 Porcupi-ne Drive Anchorage, AK. 99501 SUBJECT: Qualification of 9-5/8" Surface .Casing Kuparuk River Unit Dear Mr. Chatterton- ARCO Alaska Inc.'s continuing experience in conducting develop- 'ment drilling activities in the Kuparuk River .Field has resulted in continued re-evaluation of our tangible equipment needs and specifications. More specifically, we have recently completed a detailed study to determine the feasibility of using 9-5/8" casing in place of the 10-3/4" casing currently utilized for surface pipe in our routine development and delineation wells. Attached for your reference and review is our "Synopsis of Studies and Recommendation for Qualification of 9-5/8" Casing for Surface Casing in Kuparuk River Unit." This report gives a detailed overview of our studies on the 9-5/8" casing, including a backround of previous surface casing qualifications and devel- opment of,.a"new light-weight high'strength. Arctic-grade steel Which we"propose to utilize. In anticipation of obtaining approval to utilize the 9-5/8" casing as surface pipe, we have ordered a'nd received approximate- ly 14,000', and have placed orders for an additional 37,000'. Currently, we have sufficient 10-3/4" casing on-hand for an additional 28 wells, or. approximately through May, 1983. Consid- ering a lead time of 3-4 months for ordering and receiving tubular goods, your prompt attention.and review of this' proposal would greatly facilitate our future planning efforts. RECEIVED Alaska Oil & Gas '.~,~ ~., C,,. .o. '°mmis$io,,7 Anchorage ARCO Alaska, Inc. is a subsidiary of AllanticRichfieldCompany AGO 10023z, 57 ,,, Mr. C. V. Chatterton December 15, 1982 Page 2 If we can be of any further assistance, please contact either Rich Gremley at 263-4972 or myself at 263-4970. Sincerely, Senior Drilling Engineer JBK:llm - District Drilling F~ngineer cc: J. S. Dayton, AFA 322 L. B. Kelly, AST 306 J. F. Messner, ANO 316 L. M. Sellers, ANO 332 P. A. VanDusen, ANO 32'3 K.4.8.1 G.6.8.8.4' KEW/M31 AGO 10023~58 SYNOPSIS OF STUDIES AND RECOMMENDATION FOR QUALIFICATION OF 9-5/8" CASING FOR SURFACE CASING IN KUPARUK RIVER UNIT Summary ARCO Alaska, Inc., is requesting the State of Alaska Oil and Gas. Conserva- tion Commission to~'-approve:9-5/8'' K-55 and HF-ERW J-55 36# and 40# buttress cas~.n~ for use in the Kuparuk River Field as surface casing. Attached is a Freport produced ~:PDA"'Engineeri'ng~which ARCO Alaska, Inc. is submitting as evidence that this casing meets the post-yield strain requirements stated in Kuparuk River Field Rules. The report shows that even~_.under extreme loading conditions the 9-5/8" HF-ERW J-55 36# and 40# buttress casing_.not onl.Y..m.eet~ but surpasses the State's requirements. ' ........... I ntroducti on As a well is drilled or produced, warm fluids are circulated through the wellbore. These fluids transfer heat to the surrounding permafrost, causing it to thaw. As the permafrost thaws, axial strains are imposed on the well casing by the subsidence of the surrounding soil. Previous extensive studies have established these expected casing strains. The computed theoretical worst case strains are 0.7 percent in compression a~d 0.5 percent in tension. Imposing a large safety factor of '1.8 on the worst-case strains results in the Prudhoe Bay .Field Rules requirements of 1.26 percent in compression and 0.9 percent in tension. These same requirements have been adOpted by the Kuparuk River Field Rules. These values are already conservative for Prudhoe Bay Unit wells; when applied to Kuparuk wells they are extremely conservative. Kuparuk wells have lower permafrost loads because total fluid production rates are lower (less than 6,000 BPD versus more than 10,000 BPD), production fluid inlet temperatures are lower (150°F versus 180°F), and 'the permafrost is shallower (1500'-1700' versus.' 1700'-1900'). It is clear tha~ any casing which meets these requirements will be more than adequate for use as surface casing in Kuparuk. The previous .... study of the 13-3/8" 72 lb/ft N-80 buttress casing, used as surface casing in Prudhoe Bay Unit wells, included the development of a computer'model to perform a stress analysis of the thr__.~_~ded connection and testing of~,i~ full-scale connections to measure strains and fal--~T~l~ads. The computer model was developed by PDA Engineering, using the publically available SAAS finite element model. The testing of the full scale con- nections was carried out jointly by ARCO Oil and Gas Co. and Global Engi- neering. ~esults showed that failure.in .tension was due. to p~n thread parting and tha~ f,ailure in compressiOn'was due to thread jumping. Corre' lation of computer results with full-scale test data developed confidence in the, ability of the computer model to predict the theoretical casing strains. Further analyses were then made in order to test 'and predict sensitivities and. to. predict final strain limits for design. This model was then used to pnedi~ the.theoretical..strains for 10-3/4" 45.5 lb/ft K-55 buttress"'casing. ~" These predicted values were used to qualify this casing for use as surface casing in Kuparuk. 1 Wooley, G. R., S.A. Christman, and J. G. Crose. "Strain Limit Design of 13-3/8" N-80 Buttress Casing" July 23, 1976 AGO 10023~+$9 i Results Recently the computer model was again used by PDA Engineering to predict theoretical strains in both 9-5/8" K-55 40 lb/ft buttress and 9-5/8" K-55 36 lb/ft buttress casing. Attached is'the repor.t prepared by PDA Engineering. In this report, sensitivity studies in both tension and compression were done. These involved varying pipe thickness, thread friction, thread makeup and coupling diameter in compression; and pipe thickness, coupling diameter and yield stress in tension. These sensitivity studies identified the worst-case conditions. These worst-case conditions were then used to. calculate the worst-case strains at the point of failure which greatly surpassed the existing Kuparuk Field Rule requirements. Since the completion o% this report, ARCO Alaska, Inc. has been working with several steel manufacturers in the development of a casing for use in the Arctic environment. This work has resulted in the development of a casing ca!]...ed.~F~ERW.i'i~55, This casing meets al.I'API specificatio~s~!and is suited fori'~'use¥,in"the'~Arctic environment. This casing ~s~superior'~to K-55 casing for use in the Arctic (see attached letter by Rado Loncaric, consulting Metallurgical Engineer, with ARCO Engineering Staff). Please note that PD~.~'~report 'mentions?'!K-55~casing?and'~not ~HF-~ERW J-55 PDA's report was completed before the development of HF-ERW. Because the metallurgical. pana~.te~s ..~hich.,effect~the computer,,., model .are~..the same, ARCO Alaska, Inc. '~felt.it was unnecessary to change the report to include HF-ERW J-55. Please note, that we intend to' use primarily HF-ERW J-55, and the K-55 grade as an alternative when HF-ERW J-55 is not available. All correspondence with the Alaska Oil & Gas Conservation Commission will specify the grade to be run. In addition to the strain ca!.culations, ARCO Alaska, Inc. carried out several i~reezeback.~calcg, lation~s. Freezeback occurs when the well is shut in for an extended period, allowing the thawed permafrost to re-freeze. As it freezes, it exerts pressure on the casing. These calculations showed that the worst case occurs when a well .is produced for 5-6 weeks and shut in for two years. Under these condii~i, ons ........ 9-5/8" 36 lb/ft casing would see a pressure is 450 psi below the maximum allowable pressure of 2650 psi (which assumes 7.5 ppg Arctic Pack in~the 7" x 9-5/8" annul'us). Conclusions Contained,in the report are worst case studies. ARCO Alaska, Inc. considers these cases to be unrealistically severe beCause they go well beyond the expected worst-case conditions for the Kuparuk River Field. Even though they are severe, the worst .case studies indicated failure in tension occurring at slightly above five Percent strain and failure in compression occurring at 1.85 percent strain. These values are both well above the requirements stated in the Kuparuk Field Rules which are .9% in tension and 1.26% in compression. In conclusion, 9-5/8" K-55 and HF-ERW J-55 36# and 40# buttress casing ~.~me~t~!~,~'or?' exceed the existing Kuparuk Field Rules requirements. We request that the Kuparuk Field Rules be changed to read as follows: ~ AGO 10023460 Rule 4, Section (d) (1) The only types and grades of casing, with threaded connections, that have~ been shown to meet the requirements in (d) above and have been approved for use as surface casing are the following: (A) 13-3/8 inch, 72 pounds/foot, L-80, Buttress; (B) 13-3/8 inch, 72 pounds/foot, N-80, Buttress; (C) 10-3/4 inch, 45.5 pounds/foot, K-55, Buttress; (D) 9-5/8 inch, 36 pounds/foot, K-55, Buttress; (E) 9-5/8 incK, 40 pounds/foot, K-55, Buttress; (F) 9-5/8 inch, 36 poundS/foot, HF-ERW J-55, Buttress; (G) 9-5/8 inch, 40 pounds/foot, HF-ERW J-55, Buttress; GREM1/Q AGO 10023461 REPORT ON HF-ERW ARCTIC GRADE J-55 CASING by Rado Loncaric I. Bac.kground Regula~r electric resistance weld _(ERW). pipes have inherent manufacturing defects' in the weld seam. They al so ,~.l ack" toughness, in the weld at lower temperatures. At the operational hoop stresses, the weld could split. The defects'" most' commonly present in the weld seam are penetrators and cold. welds. Penetrators are localized spots of incomplete fusion. Cold welds .have inadequate weld bonds. Primarily, these two defects and a few others (hook cracks, pin holes, etc.) contribute to physical weakness in the weld. .Br.ittleness. in the we~d results from erratic and irregular post weld heat treatments. Experiments have been conducted by progressive manufacturers to eliminate the defects in the weld and improve the welding condition and post weld heat ~treatment~. High speed cameras~were installed above the'weld to fOllow the welding process. They showed that the :location of current entry, current stability and current distribution, impurities in the steel, geometry of abutting edges, speed of welding, heat input,.etc., are critical variables which must be closely adjusted and controlled to obtain better properties in the weld. Computerized controls of the variables and .change to high frequency (HF) resulted in better pipes. As experience was gained in controlling the variables, the weld became stronger and tougher. In the mid-1981, the toughness of about 30 FT-LB was obtained consistently at +30°F in the weld. ARCO now uses these improved pipes as flow lines'in the Kuparuk secondary ' recovery project. II. Development of Arctic Grade Casing In December 1981, ARCO'~s specifications Were formulated for tubes suitable for use at lower temperatures, such as at -25°F and at -50°F. The speci- fications were discussed with four Japanese manufacturers for the purpose of further improving toug.hness and weld strength. The mills were receptive and their efforts continued to be directed toward several stages of steel and strip making and pipe manufact~ure as follows: Steel and Strip Making To obtain clean steel, the casings are made in a non-oxidizing atmosphere. This decreases the non-metallic inclusions to a very low level.. The addi- tion of calcium to the molten steel purifies the steel and eliminates the elongated manganese sulfide inclusions during hot rolling. The narrow range temperature controls (about + or -20°F) in slab heating, rough rolling, finish rolling, spray cooling of the strip and coiling result in a_.clean~ .~ine-grai~ed microstruct.u~re and homogeneity of properties in the coils. Automatic gauge controls improve~'dimensional accuracy of'the strip. Thus, ~hOt?~'str'iP'~?material"of good quality is obtained by the development of im- proved steel making..and hot rolling techniques. ~ .~ ' AGO 10023~+62 Pipe Maki. n~ The use of low chemistry steel, control of welding speed, current entrance and heat input, freezing of the grains in the weld after heat treatment result in a fine-grained ferritic structure. Due to the.small grain size, the structure it strong and tough.. The results show that the properties in the weld are at least equivalent or better than in the body of'the tubes. In February, 1982, the Japanese manufacturers conducted upon request, the following specific tests on the pre-production runs to evaluate the suit- ability of the new high quality pipes for arctic casing and tubing. la. Toughness Tests' Charpy transverse and longitudinal' transition curves in the weld, in the heat affected zone (HAZ) if any and in the body of the tubes. b. Crack Opening Displacement (COD) Test' Transition curves in the body of the tubes, in the heat affected zone and in the weld seam. 2. Physical tests (body and transverse seam)' Yield strength, tensile strength and elongation at room temperature, at +25°F, O°F, -25°F, -50°F. 3. Hardness .tests across the weld seam. · 4. Weld tensile test (across the weld) with a 1/8" deep notch in the weld at -60°F. 5. Col lapse tests. 6. Hydrogen Induced Cracking (HIC)tests. 7. Galling test; this was considered' necessary because of possible poor machinability (threading) of low sulpher steel. .. 8. Microstructure test in the body and in the weld seam to determine the grain size. During the test period of 3 weeks (one advanced mill) to 3.months all four mills obtained the results.summarized below: la. Charpy tran.sition temperature in the weld seam is at -25°F (Charpy results range from 2OFT-LB to 124 FT-LB) and the transverse transi- tion ,temperature in the body at -30°F to -40°F. b. Crack Opening Displacement at -25°F ranges from 20-29 mils' and at -40°F from 6.5 to 18.7 mils. (TAPS pipe has about 5 mils in the weld at +15°F). 2. The yield strength and the tensile strength increase for about 5 to 7 KSI at -25°F above that obtained at room temperature while elongation remains constant to about -40°F. At -60°F the elon- gation drops to about 12%. ~' 3. Hardness ranges from HRB 83-89 (about 16 HRC). AGO 10023463 4. Weld tensile test with a 1/8" deep notch in the weld seam pulled at -60°F, shows the yield strength 82 KSI, tensile strength 86 KSI and elongation 12%; the break occurred in the base metal (not in the weld). 5. Collapse pressure ranges from 4,860 PSI to 5,430 PSI (O.D. length ratio 1:4.7), API standard requirement, is 2,570 PSI. Collapse occurs in the body, not in the weld. No split in the weld. 6. Hydrogen induced cracking. - No cracking. 7. Galling test' Four make-ups and four breakdowns (Buttress) of the tube with 0.08%C and 0.005%S shows no galling; only slight surface discoloration 'after 4 tests. 8. Microstructure' Grain size 9-11. The above results show that high quality casing can be obtained in strip mills. The metallurgical propertieS"of the developed'casing surpasses requ.~.~.ements of?API..Standard 5A and AP!. ~tandard 5L.X. To differentiate the high"quality tough product from a regular ERW product, which has poor toughness in the weld seam, it was suggested to name the newly developed tubes *'!HF-ERW tough ~eam" or "HF-ERW Arctic Grade". The name was accepted by the four Japanese manufacturers and by ARCO. III. ARCO Specification for HF-ERW Arctic Grade J~55 Casing and Seamless · Couplings The specification developed by ARCO is based on the fact that the maximum stresses to which the casing is subjected when it is cold occur during transportation, during the make-up of the string and during the lowering of the casing into the hole. Only tension and bending stresses are involved. Hoop and compressive stresses are applied on the casing at higher tempera- ture when the casing is already in.the hole. Experience and fracture mechanics calculations show that a minimum of 15 FT-LB toughness in the weld and 20 FT-LB toughness' in the body at -25°F, crack opening displacement of about 10 mils in the' weld seam and elongation about 25% at the same temperature will give sufficient safety to handle and lower the casing into the hole and prevent degradation of the casing during transportation. The ARCO,~specification .... is"in'addition to applicable API' Standard 5A (Spec- ification for Casing, Tubing and Drill Pipe) and API'Standard. 5LX ·(Specific- ation for High-Test Line Pipe) regarding the physical properties. The yield strength is limited and mill hydrotest is extended to 10 seconds ............. The · frequencies of the tests are increased above the API Standards. The chemi- ~.~.,~composi. tio~.i].l.i~mits..the~carbon, con{e~t t0..~,.09% maxi. m~m,..sul.~ur to * High Frequency - Electric Resistance Weld AGO 10023464 0.005% max, and grain stabilizing .elements, such as Vanadium, Niobium and 'Titanium to 0.07%. Residual combined elements are limited to 0.40% max. and carbon equivalent to 0.30% max. The carbon equivalent insures weldability and the limit on residual elements requires that clean steel be used. Hardness is limited to NACE HRC 22 to prevent sulfide stress cracking. The through wall normalizing of the weld is required and determined by frequent microstructural analyses. The coupling is required to be seamless either quenched and tempered or normalized with maximum hardness and strength requirements. Because of the high stresses in couplings after the make-up, 30 FT-LB transverse toughness' at -25% is required. The couplings are inspected to API SR2,'N5 or 1/16 inch hole. ~ IV. HF-ERW Arctic Grade J-55 Casing Product Delivered to Alaska in November 1982 The production of the 7" O.D., 9-5/8" and 10-3/4" casing started in Septem- ber 1982. A reputable inspection company was engaged, the personnel of the company was trained in supervising the standardization of the test equip- ment. They were instructed to witness and verify all.mill results. Rado Loncaric witnessed the tests~ at the beginning of the production. The Inspection Certificate by Sumitom6 and verified by AMF Tubescope In- spection Company, show that the product obtained~'surpasses all the"require- ments'~'of'' ARCO 'and API~specifications. The toughnesses are.~3.5 to 6 times ~higher than specified. V. Comment As more production experience in the manufacture of HF-ERW Arctic Grade J-55 casing is gained, it will continue to improve. As of now, it is superior in .~toughnes~s.,?and. i'!uniformity to seamless API K and API .J grade casing. (signed) 11/14/82 RADO LONCARIC DATE GRE/J-55 AGO 10023465 ARCO Alaska, Inc. Posl office Dox :~:" · Anchora.(je, Ala,~'~ .!9510 Telephone 907 2b:~ 6513 Gary L. Downey Vice President ~Iay 7, 1982 C. V. Chatterton Chairman/Commissioner State of Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Subject: Application for Exception Rule 3 Well Spacing Conservation Order No. 173 Kuparuk River Field Kuparuk River Oil Pool Dear Mr. Chatterton: The Working Interest Owners of the Kuparuk River Unit request that the Alaska Oil and Gas Con- servation Commission grant an exception, to Kuparuk River Field Rule 3, Well SPacing, of Conservation Order No. 173 for the area affected by the'Incre- ment I ¥~aterflood pilot. This pilot waterflood was approved by the Commission in your letter of February 8, 1982. The area includes Sections 5, 6, 7, 8, 15, 16, 21 .and 22 of TllN-R10E, Umiat Meridian. We request unrestricted spacing for this area. The entire affected area and all surrounding acreage are' within the participating area of the Kuparuk River Unit. Two drill sites are included in the initial water- flood to be started in December, 1982. One of these, Drill Site 1E, is highly faulted and our plans call for drilling, on 40 acre spacing on Sections 16, and 80 acre spacing on Sections 15, 21, and 22. The waterflood will begin December, 1982. The denser well spacing will provide data faster for planning of the fullfield waterflood, and will also provide comparisons of sweep efficiency for the various well spacings used. 0il & 0~s .... C. V. Chatterton May 7, 1982 Page 2 Your prompt attention to this matter will be greatly appreciated. Very truly yours, G. L. Downey Vice-President, Arco Alaska, Inc. Unit Operator JSD/slz AGO 10023~67 ALASKA OIL AND -GAS CONSERVATI N COMMISSION Commi s s ioner Blair E. Wondzell Petroleum Engineer April 9, 1982 104/H Use of "Poleset" to Set Conductors, Prudhoe Bay and Kuparuk Oil Fields r. Conductors: Normally, conductors are set before rig move-in. The procedure used by ARCO is as follows: A 30" hole is augered to a depth of 80'. A 20" casing is set in the hole. The annulus is filled with either cement or with polyurethane foam (tradename is "Poleset"). The time period between setting the conductor and spudding the well may vary from a few days to a few weeks. From spudding to cementing of the surface pipe is normally 2-4 days. After the surface pipe is set, adequacy of placement of the conductor pipe becomes less important. cemented, conductors . If 'cement job is good, the annulus will be completely filled: A. If in winter, the cement used may freeze shortly after placement and would therefore be of low strength. B. If in summer, the cement may set-up before freezing, in which case the heat of hydration could melt the permafrost creating a micro-annulus at the cement/formation contact. . If the cement job is bad, the cement may be contaminated, or may not completely fill the annulus. In the extreme case, the conductor may move downward while hanging the surface pipe -- this is normally done with 170,000_+ lbs prior to setting the slips. This happened on various ARCO wells, such as DS 13-10 and DS 15-12. While drilling, the permafrost at the cement/formation face may melt, creating a micro-annulus along which slippage can occur or through which gas 'and/or fluids can flow. This occurred on ARCO Kuparuk "C" pad wells where gas migrated outside of the conductor pipe and was observed "bubbling" in the annulus. AGO 10023~70 'I L~nnie C. Smith 'ill 2 'i' ~pril 9, 1982 Foamed' Conductors A~.CO has submitted the mechanical properties of "Poleset" along with their request to use the product. Listed properties are as follows: compressive strength- 75-100 psi; tensile strength- 30-50 psi (30 psi for DS 15-2); shear strength - 38-50 psi; and density (foam) - 7.2-7.5 lb/ft. The greatest concern of the "Poleset" procedure is vertical movement of the conductor, therefore, the shear strength is the critical mechanical property. Using a cross, section area near the 20" conductor (minimum area) a shear strength of 50 psi, and a length of 80',' the shearing force is 191,000 lbs. By comparison, the ARCO conductors which moved down-hole were subjected to a force of approximately 170,000 lbs. Sohio cements a 20" x 30" insulated conductor in a 36" hole. Polyurethane foam is used between the 20" and 30" pipes. Presumably, this material would have about the same shear strength as the "Poleset" material proposed by ARCO. The ARCO procedure has the advantage in that the "Poleset" expands 13-15 times, therefore there should be no voids. Since there is no cement to hydrate, there should be no melting at the formation face.~ As of March 9, 1982, ARCO' had foamed-in-place 7 conductors and had drilling through 5 of them. All of these conduct.ors were carefully monitored for slippage. Two slipped less than 1", slipped 2", 1 slipped 3 5/16", and i slipped 25 7/8" (DS 14-30). Slippage of about 3" would probably go unnoticed except for the monitoring sy stem. As a result of the slippage of DS 14-30, thought to be caused by incomplete fill up, ARCO is changing their placement technique. They are going from 1 placement pipe to 4, to insure better fi/l-up. }topefully, this will provide better jobs. CONC LUS ION: The "Poleset" procedure could easily result in better conductor placement than is 'currently being obtained by ARCO. The #Poleset" material is probably similar to the insulating material used in the 20" x 30" insulated conductors currently being used by Sohio and may provide a superior' job. RECOM~N DATIONS: I recommend that the Commission should approve ARCO's request to use #Poleset" as an alternative to cement when setting conductors for all wells in the Prudhoe Bay and Kuparuk oil fields. If the Commissioners have reservations, ARCO could 'be asked to p~rform'c0nductor strength tests (pull and/or loading) on both cemented and "'Poleset" conductors at intervals of I day' and 10 days after placement. AGO 10023471 ./ L~nnie C. Smith il 2 ~. Apr il 9, 1982 Foamed' Conductors: ! ARCO has submitted the mechanical properties of "Poleset" along with their request to use the prc~uct. Listed properties are as follows: compressive strength- 75-100 psi; tensile strength- 30-50 psi (30 psi for DS 15-2); shear strength - 38-50 psi; and density (foam) - 7.2-7.5 lb/ft. The greatest concern of the "Poleset" procedure is vertical movement of the conductor, therefore, the shear strength is the critical mechanical property. Using a cross section area near the 20" conductor (minimum area) a shear strength of 50 psi, and a length of 80', the shearing force is 191,000 lbs. By comparison, the ARCO conductors which moved down-hole were subjected to a force of approxi~mtely 170,000 lbs. Sohio cements a 20" x 30" insulated conductor in a 36" hole. Polyurethane foam is used between the 20" and 30" pipes. Presumably, this material would have about the same shear strength as the "Poleset" ~aterial proposed by ARCO. The ARCO procedure has the advantage in that the "Poleset" expands 13-15 times, therefore there should be no voids. Since there is no cement to hydrate, there should be no melting at the formation face. As of March 9, 1982, ARCO had foamed-in-place 7 conductors and had drilling through 5 of them.. All of these conductors were carefully monitored for slippage. Two slipped less than 1", 1 slipped 2", 1 slipped 3 5/16", and 1 slipped 25 7/8" (DS 14-30). Slippage of about 3" would probably go unnoticed except for the monitoring system. As a result of the slippage of DS 14-30, thought to be caused by incomplete fill up, ARCO is changing their placement technique. They. are going from 1 placement pipe to 4, to insure better fill-up. Hopefully, this ~will provide better jobs. CONCLUSION: The "Poleset" procedure could easily result in better conductor placement than is 'currently being obtained by ARCO. . The "Poleset" material is probably similar to the insulating material used in the 20" × 30" insulated conductors currently being used by Sohio and may provide a superior job. RE COM ~N PAT IONS: I recommend that the commission should approve ARCO's request to use #Poleset" as an alternative to cement when setting conductors for all wells in the Prudhoe Bay and Kuparuk oil fields. If the Commissioners have reservations, ARCO could be asked to perform'conductor strength tests (pull and/or loading) on both cemented and "Poleset" conductors at intervals of 1. day' and 10 days after placement. AGO 10023472 ALASKA OIL AND C--AS CONSERVATI©~ COMMISSION Commi s s ioner Blair E. Wondzell Petroleum Engineer April 9, 1982 ., .. 104/H Use of "Poleset" to Set Conductors, Prudhoe Bay and Kuparuk Oil Fields COndUctOrs: Normally, conductors are set before rig move-in. The procedure used by ARCO is as follows: A 30" hole is augered to a depth of 80'. A 20" casing is set in the hole. The annulus is filled with either cement or with polyurethane foam (tradename is "Poleset"). The time period between setting the .conductor and spudding the well may vary from a few days to a few weeks. From spudding to cementing of the surface pipe is normally 2-4 days. After the surface pipe is set, adequacy of placement of the conductor pipe becomes less important. Cemented, CondUctors: . If cement job is good, the annulus will be completely filled: A. If in winter, the cement used may freeze shortly after placement and would therefore be of low strength. If in summer, the cement may set-up before freezing, in which case the heat of hydration could melt the permafrost creating a micro-annulus at the cement/formation contact. . If the cement job is bad, the cement may be contaminated, or may not completely fill the annulus. In the extreme case, the conductor may move downward while hanging the surface pipe -- this is normally done with 170,000+ lbs prior to setting the slips. This happened on various ARCO wells, such as DS 13-10 and DS 15-12. While drilling, the permafrost at the cement/formation face may me]t, creating a micro-annulus along which slippage can occur or through which gas' and/or fluids can flow. This occurred on ARCO Kuparuk "C" pad wells where gas migrated outside of the conductor pipe and was observed "bubbling" in the annulus. AGO 10023473 I,~nnie C. Smith (. 2 i ~pril 9, 1982 Foamed' Conductors: ARCO has submitted the mechanical properties of "Poleset" along with their request to use the product. Listed properties are as follows: compressive strength- 75-100 psi; tensile strength- 30-50 psi (30 psi for DS 15-2); shear strength- 38-50 psi; and density (foam) - 7.2-7.5 lb/ft. The greatest concern of the "Poleset~ procedure is vertical movement of the conductor, therefore, the shear strength is the critical mechanical property. Using a cross section area near the 20" conductor (minimum area) a shear strength of 50 psi, and a length of 80', the shearing force is 191,000 lbs. ~y comparison, the ARCO conductors which moved down-hole were subjected to a force of approximately 170,000 lbs. Sohio cements a 20" x 30" insulated conductor in a 36" hole. Polyurethane foam is used between the 20" and 30" pipes. Presumably, this material would have about the same shear strength as the "Poleset" ~terial proposed by ARCO. The ARCO procedure has the advantage in that the "Poleset" expands 13-15 times, therefore there should be no voids. Since there is no cement to hydrate, there should be no melting at the formation face. As of March 9, 1982, ARCO had foamed-in-place 7 conductors and had drilling through 5 of them. All of these conductors were carefully monitored for slippage. . Two slipped less than 1", 1 slipped 2" 1 slipped 3 5/16" and 1 slipped 25 7/8" (DS 14-30) Slippage of about 3" would probably go unnoticed except for the monitoring system. , As a result of the slippage of DS 1.4-30, thought to be caused by incomplete fill up, ARCO is changing their placement technique. They. are going from 1 placement pipe to 4, to insure better fill-up. HoPefully, this will provide better jobs. CONC LUS ION: . The "Poleset" procedure could ~asily result in better conductor placement than is currently being obtained by ARCO. . The "Poleset" material is probably similar to the insulating material used in the 20" × 30" insulated conductors currently being used by SOhio and may provide a superior job. I recommend that the Commission should approve ARCO's request to use #Poleset" as an alternative to cement when setting conductors for all wells in the Prudhoe Bay and Kuparuk oil fields. If the Commissioners have reservations, ARCO could b~ asked to perform'conductor strength tests (pull and/or loading) on both cemented and "Poleset" conductors at intervals of 1 day and 10 days after placement. AGO 10023474 ALASKA OIL AND CAS CONSERVATIO~ CO~']~4ISSION Lonnie C. Smith Commissioner Blair E. Wondzell Petroleum Engineer April 9, 1982 104/ Use of "Poleset" to Set Conductors, Prudhoe Bay and Kuparuk Oil Fields Conductors: Normally, cond. uctors are set before rig move-in. The procedure used by ARCO is as follows: . A 30" hole is augered to a depth of 80'. A 20" casing is set in the hole.. The annulus is filled with either cement or with polyurethane fo am (tradename is "Poleset "). The time period between setting the conductor and spudding the well may vary from a few days to a few weeks. From spudding to cementing of the surface pipe is normally 2-4 days. After the surface pipe is set, adequacy of placement of the conductor pipe becomes less important. cemented, Conductors: If cement job is good, the annulus will be completely filled: A. If in winter, the cement used may freeze shortly after placement and would therefore be of low strength. Bo If in summer, the cement may set-up before freezing, in which case the heat of hydration could melt the permafrost creating a micro-annulus at the cement/formation contact. ao If the cement job is bad, the cement may be contaminated, or may not completely fill the annulus. In the extreme case, the conductor may move downward while hanging the surface pipe -- this is normally done with 170,000+ lbs prior to setting the slips. This happened on various ARCO wells, such as DS 13-10 and DS 15-12. . While drilling, the permafrost at the cement/formation face may melt, creating a micro-annulus along which slippage can occur or through which gas and/or fluids can flow. This occurred on ARCO Kuparuk "C" pad wells where gas migrated outside of the conductor pipe and was observed "bubbling" in the annulus. AGO 10023475 ', Poleset Backfill Cement DESCRIPTION-" Poleset is a high density modified polyurethane foam developed for backfilling wood, concrete and steel poles and pilings. The 2:1 ratio formula was developed especial- ly for application in extremely cold climates and also in soil with a high moisture content. When mixed together an exothermic reaction occurs causing the two chemi- cals to foam, expand 13 to 15 times in volume and bond with the pole or conductor (depending on applicatino) regardless of the material. The resulting foam will exhibit the following characteristics: Mechanical Properties: Compressive Strength Tensile Strength Minimum Shear Strength Denisty (foam) 75 psi 30 psi 85Psi · lb/ft3 NOTE' The above can be varied per specification requirements. Thermal Conductivity- Temperature Range' BTU K = .27 HR Ft°F Upper = 225°F Lower : -300°F Quantity Per Typical Conductor' 30" Hole- 20" dia. Conductor - 80' deep. 2.7271 ft3/ft x 80' = 218 ft3 218 ft3 x 4.5 lb/ft3 = 982 #. 982# ~ 9~7 lb/gal = 101 gal. lO1 gal ',- 42 gal/bbl = 2.4 bbl. 2.4 bbl unexpanded foam.will completely cement conductor in place. AGO 10023~,76 SUBJECT' DS 15-13 conductor cementing with Poleset (a Polyurethane system). OBJECTIVE: 1.' .Improved freeze - thaw protection. 2. Improved back fill bonding between conductor and formation. 3. Improved reliability of conductor installation during surface hole drilling. 4. Simplified cementing coupled wi th decreased conductor cementing cost. INSTALLATION- 1. Drill standard size conductor hol. e. 2. Make up standard size (diameter& length) conductor pipe. 3~ 1 Band (2) two wood 4"x4"x4', on opposite sides, to conductor. One 50' and' one 60' down from top end of conductor. Weld on metal stops to hold 4"x4"x4' in place. (See sketch). Attach (1) thermocouple directly to pipe with tape just above or adjacent to each wood 4"x4"x4'. (See sketch). 5.. Attach (1) thermocouple directly to each wood 4"x4"x4' with tape, approximately .3" to 4" out from pipe. Do not place in contact with metal or on outside edge of wood 4"x4"x4'. (See sketch). 6. Tape all four thermocouple leads every 5' to conductor pipe. (See sketch). 7, When attaching extension leads use adequate sealent tape to prevent moisture from entering splice. 8. Carefully run conductor in hole. 9, Cement in place with Poleset through hose or pipe down side of conductor or drop Poleset from .surface. 10. Bring Poleset up to within two feet of cellar floor. Back fill with gravel or dirt to cellar floor. TESTING' (tenative program) , Shoot elevation as follows' a. After weld-on-head is installed. b. Just before installing diverter. AGO 10023477 . e c. After installing diverter and just before spudding. Every four hours during spudding, landing 13-3/8" casing and until 24 hours after cementing 13-3/8" casing or longer if there is noticable movement. Monitor temperature. a. Before Poleset placement. b. Just after Poleset placement and for the next 24 to 48 hours until stabilization. c. Just before spudding, during spudding, landing 13-3/8" casing and until 24 to 48 hours after cementing 13-3/8" casing or longer until stabilization. Make appropriate observations during Poleset placement and during drilling operation. CONTINGENCY PLAN' · Should the cementing of the conductor with Poleset prior to spudding be deemed unsatisfactory, the test will'be cancel ed and a new con- ductor set adjacent to the test will be set using standard setting and cementi.ng methods and materials. , Provisions will be made to loosely (initially with l' of slack in chains or cables) tie the conductor to the rig's sub during spudding operation. Should conductor fail during spudding, it should be secured to the subbase and surface hole completed as soon as possible. AGO 10023478 ARCO Oil and Gas Company z' ' {SubleCt l Page No. By JDate AGO 100Z3479 mnrtllo engtneering~, testing servit~ inc. ! -- 5~01 BINTLIFF DRIVE. SUITE 550 · (~. /82-0590 · HOUSTON. TEXAS 77036 APPE ND I X P.E£EIVE Gas Cons, A~c~omge AGO 10023480 '¸7 ~k'"~,!~j[{j-I'~'~''~ 6,~GI BINTLIFI: DRIVE, .SUITE 550 ,{~ 782.O'5SO ·HOUSTON, TEXA~ '17~'~'~.$ REPORT OF' PHYSICAL PROPERTIES OF URETHAN FOAM REPORT NO.' 216-75E JULY 1975 TO' FORI'IARD ENTERPRISES HO U S'IO N, TE × d S INIkODUC rlON · .. The study reported herein is an engineering investigation of the physical properties of ureth,ane foam as produced by Forward Enterprises, Inc. The purpose of ·these tests was to determine compressive · strength, tensile strength, elastic limit, modulus o£ elasticity and shear strength. AUTHORIZATION This study was authorized by l.'~r. Dick Hannay on ~.,~ay 5, 1975. TESTING PROCEDURE The procedure used in testing the foam to obtain compressive strength, modules of. elasticity, elastic limit and shear strength at elastic limit consists in th'e per£ormance of compressions tests 3" diameter by 6" high or 6" diameter by 12" high specimens. The specimens were cast at room tempera- ture; ~owever, the molds were cooled 'to a temperature. of +20°F prior to casting. AGO 10023481 The specimens were stored at a termperature of -60°F until .._ ready for testing. T.h.,,:-: specJ, mens were tested at tempera- '~:u.~..s of -20°F, O'~F ar:d i ..... ~ing o'~ all s'",:,"', .. P,'-- ... t:, ..... ~;-':on:; ,~,~ :.-: ,.::,) ..... unde.r the direct stlper- "~ ~" ,'~'.":[ ' ;": ~ vlsi. on of !).Lon~:..~ .~,, :..~ ; . . n<.- .... u!ts obta_~ned ;f'rom c,':,i;';,,' ..... ,:--,-',c,'-, P~'~d te. ns';].e tests are COri~ll~.~ irt the ,Sp'r')r:q(lix July 31, 1975 AGO 10023482 j n~'~tHlio engin, eertfig & test~.ng service, inc. .~301 BINTLIFF DRIVE, SUITE 5~0 - (713} ?~ 9590 · HOUSTON, TEX.d~S 7703~ Temperature Tensile Strength, p.s.i -20"F 38.73 O0 °F -.' 30.39 +20°F 32.88 / · · · AGO 10023483 50- 40- r~ 30- · O. 4. # Foa~ Max. Comp· Strength -- 31.58 p.s.i. . E = 2521 p.s.i. Temperature 20 o 'F I 0.Ol Strain I 0..02 I 0.03 in. / in. AGO 10023484 80 70 60 50 20 10 0.01 -- B~OI BINTLIFF DRIVE, SUITE 660 · (7t,', ~2-0~gO · HOUSTON, TEXAS 7703~ 6 # Foam Max. Comp. Strength = 73.72 p.s.i. E = 4000 p.s.i. Temperature 20° F 0.02 0.03 0.04 Strain - ~ in./in. AGO 100234-85 ' l, k 80- 70- 60- 50- 40- 30- 20- 10- m ~1 BINTLIFF DRIVE, SUITE B80 · {713~ 7824~O * HOM~I'OI~I, TEXA~7703~ i' ax. Comp. Stress, ~ = ?6.59 p.s.i. E = 5714 p.s.i.' Stress at Elastic Limit, ~= 65.3 p.s.i. Temperature +20° F Water Foam 2:1 ensity 4.8 to 5.2 pounds 0.01 I - I i 0.02 0.03 Strain, ~ , in./in. AGO 10023486 8O 70 60 '~' 50 · ' .40 3O 20 10 mNrdllo e~sgi~~g & testt~ ~, inc. B~01 BINTLIFF DRIVE, SUITE EEO . (713) 782.0Eg0 - HOUSTON, TEXAS 7703~ ,~' Max. Comp. Strength, = 74.74 p.s.i. E = 6363 p.s.i. Stress at Elastic Limit, ~-- 53.5 p.s.i. Temperature 0° F Water Foam' 2'1 Density 4.8 to 5.2 pounds 0 0.01 0.02 0.03 0.04 Strain - ~ - in./in. AGO 10023487 DRIVE, SUITE ~01 BINTLIFF Place of Birth: Date of Birth: DIONEL E. Ponce, Puerto Rico February 17, 1932 BIOGRAP~ICALDATA A V I · E S Address: 12003 ~edgehill Lane Houston, Texas 77077 Citizenship: U.S. EDUCATION High 'School: University: Ponce High School, Ponce, Puerto Rico - 1946-1949 A & M College of Texas, College. Station, Texa~1949-1954 Bachelor of Science - Civil Engineering A & M College of Texas, College Station, Texas 1959-1961 Master of Engineering - Civil Engineering Texas A & M University, College Station, Texas 1961-1966 Doctor of Philosophy - Civil Engineering - Title of Dissertation, "Design of Substructures for Transmission Towers." EXPERIENCE January 1954-April 1954: Puerto Rico Iron Works - Ponce, Puerto Rico- Junior Engineer - Design of[Steel Structures, April 1954-April 1956: U.S. Army Corps of Engineers - Active Duty - Officer-in-Charge of pavement evaluation crew (6 months), assistant operations officer of 822nd Engineer. Aviation Battallion (12 months), Guam,.Marianas Islands. May 1956-December 1956: Spencer J. Buchanan & Associates, Bryan, Texas. Junior Engineer - supervision of construction of earthen levees and design of foundations for various projects. January 1957-November 1957: Boeing Air41ane Company - Melbourne, Florida, Junior Engineer to Designer B - Structural design and development of Weapon Support Equipment - Hormarc Missile Weapon System.. November 1957-June 1966: Spencer J. Buchanan & Associates, Bryan, Texas. Project Engineer to Chief Engineer. Positions include- project engineer-' 20 mile haul road - Dominican Republic, project engineer - design of sewage treatment plants, p?oJect engineer - structural design multi- story buildings and dormitories. Chief Engineer in charge of projects · such as evaluation and design of runways for airfield projects, foundations, for large'structures,.wharves, offshore structures, etc. June 1966-September 1969: Trinity Engineering TeSting Corporation, Austin, Texas. Soil and F$undation Consultant. Consulting services on dams, airfields, pavements and foundations for structures. October 1969-Present: Murillo Engineering and Testing Services, Inc., Rouston, Texas.. Vice President. Consulting 'services on dams, airfields, pavements, wharves, offshore structures and foundations for structures. AGO 10023488 80 70 50 ~o-~ 1~ ~x. Comp.. S~:~-~ngth, ~'= 77.02 p. s. i. ~o_i 1// ,,~ ~o~ ~:, ~m~.~,~.~ -~00 ~ .. ,~'~' ~. S ~o ~. ~ ~o,n~'', 20 ~0 0 0.01 0.02 0.03 0.04 0.05 Strain -'~ - in./in. . AGO 10023489 -'] PROFESSIONAL ACTIVITIES Registered Professional Engineer - Texas License NO. 16784 l~uerto Rico License No. 3923 Member National Society of Professional Engineers, Texas Society of Professional Engineers, American Society of Civil Engineers, Texas Section of American Society of Civil Engineers, Society of American Military Engineers and Colegio de Ingenieros, Arquitectos y Agrimensores de Puerto Rico. Member Chi Epsilon (Civil Engineering Honor Society), Member Reserve Officer Association, Member Associat. ion of Asphalt Technology. Position Held in Societies: President - Brazos Chapter TSPE - 1959 State Director, Brazos Chapter TSPE - 1959-1964 Vice President, Region II, TSPE - 1964-1966 President TSPE Credit Union - 1968-1969 President, Brazos Chapter ASCE -1964 President 420th Engr. Bde Reserve Officers Association - 1963 Chairman, Chapter Activities Committee, TSPE - 1961-1962, 'Goals of Engineering Education., TSPE- 1963-1967 Assistant Chairman, International Conference on Swelli'ng Clays, Texas A & M University - 1964 Elected "Engineer of the Year", Brazos Chapter TSPE - 1963-1964 Listed in Who's Who in the SoBth and Southwest - 1965-1968 Vice Chairman National ASCE Meeting, Houston, Texas, October 1972 PAPERS PRESENTED 1. "Isolation of Vibrations in the Foundation Elements of N,A.S,A. Manned Spacecraft Center Buildings" - April 1964 - Spring Meeting, Texas Section ASCE. 2. "Uplift Resistance of Underreamed Type Footings" - October 1963 - Fall Meeting of Texas Section ASCE. 3. "Testing of Tower Footings" - Edison Electric Institute - Transmission and Distribution Conference, Oklahoma City, Oklahoma, May 1963. 4. "Rigid Pavement on Elastic Solid Foundation for Super Jets" - Annual ASCE Environmental Engineering' Conference- Houston, Texas, October 1972. 5. "Pavimientos para Aviones de Chorros" - Tercera Reunion ConJunta, Mexico - Estados Unidos - Mexico City, October 1972. CiVIC'ACTIVITIES President: Bryan - College Station Exchange Club, 1963. President: South Briar Lake Community Association. MILITARY Lt. Colonel - U.S. Corps of Engineers - Reserve. Completed the 'following military education: Engineer. Officer Basic Course; Airport Engineer Course~ Chemical, Biological and Radiological Warefare Course; On-the-Job Training Supervisor Course, Company Grade Officer Course, Field Grade Officer Course, and U,S. Army Com~nand and General Staff College, AGO 10023490 "~RIL-~-~': ~O¥~INTLIFF DRIVE, SUITE 550 · 782 0590 ° HOUSTON, TEXAS 77036 URETHANE FOAM SPECIMEN 6" DIAMETER- ]2" HEIGHT 10O23491 URETHANE FOAM SAMPLES AFTER TESTING AGO I00£3~92 5601 BINTLIFF DRIVE, SUITE 550 · ,, 13) 782-0590 · HOUSTON, TEXAS 77036 URETHANE FOA~ SA~PLES AFTER TESTING AgO UNCONFINED COMPRESSION TEST TRIAXIAL COMPRESSION CELL ARCO Alaska, Inc. ~ Legal Division Post Office Box 360 Anchorage, Alaska 99510 Telephone 907 265 6540 Stephen M. Williams Senior Attorney April 8, 1981 Hoyle Hamilton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Harry W. Kugler, Commissioner Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Lonnie C. Smith, Commissioner Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE- Proposed Field Rules Kuparuk River Field, North Slope, Alaska Gentlemen' ARCO Alaska, Inc. (ARCO) thanks the Alaska Oil and Gas Conservation Commission for holding the hearing record open for a period of two weeks to receive additional testimony on the proposed Field Rules for the Kuparuk River Field. During questions the Commission indicated that it would like to include a rule regarding Production Surveys. Attached here- to is a proposed Rule 9 regarding Production Surveys to be included in the Kuparuk River Field Rules. If you have any questions concerning this proposal or if we can be of further assistance with regard to this rule please advise me. ARCO Alaska, Inc. is a subsidiary of AtlanticRichfieldCompany AGO 100Z3~96 Hoyle Hamilton, Chairman Harry W. Kugler, Commissioner Lonnie C. Smith, Commissioner April 8, 1981 Page 2 In addition, I am also transmitting on this date revised Exhibits I-l, II-l, II-2, II-5, and III-1. These exhibits are duplicates of the slides presented at the hearing. Also one additional copy is attached for the hearing record. Again ARCO thanks the Commission for the opportunity to make these additional comments and if further clarification is required please advise me. Very~ruly yours, SMW/dw Attachments AGO 10023497 Rule 9. ProductiOn Surveys During the first year of production from each well a survey will be made to determine the production profile from the Kuparuk interval. This survey is not required in wells which are perforated in only a single sand member. Survey results will be provided to the Commission by the last day of the month following the month in which the survey was taken. AGO 10023498 /!/// NPR A??; .I / :~,m.P'. L.U, ~ iL_. EXISTING ~U~DHOE g i ~ ' ' BAY FIELD RULES i- --' -:~ ~- I ,/ 17 ??!~ii!ii}-.-~ ..... J '---., N :::::::::::ill , U N U O. iii!i::i!i::i]l . 33- 29 E . 1 :iii:il~.. ~'~~-: "'" 180 :'.iii:i::ii~:i;ii!iiZiiii::i!::!?:::iii:} ,. ~3 :.:i ===================================== ::::::::::::::::::::::::::::::::: .~ ! PRUDHOE I · ii:::::i':.:::':i::i:::;:':ii:'.:;:ii B A Y 04 I I I I I I I---.I I I I I 2O RULES AREA PROPOSED F ELD I I ~ I ' I I :1 !1 I KUPARUK FIIVER OIL POOL KUPARUK RIVER FIELD I m am m m ,mm m m m m mm m -m m m imm m J EXHIBIT AGO 10023499 I ~ Available Well Data · , ..... ]- .......... i r~leased m ;OWell Data not , to pul3t[C' ~ ARCO Alask~a, Inc. KALUBIK II ~ ............ T-"~ , ~ I IE. UCNU ] t--" ..... J I ~ 33-29E ~ .......... .., ;"' j UG N U N O. I e L=_,, ,j~'EILEEN $~ I ICOLVILLE. el! ! [_..~ e e N.K.UPIARUK i"' 'a '" s i i--'~ ! ~80 ,; 2_ . ,L d'" KOOKPUK ~ , -- I , 13 ' e"~ [ PRUDHOE BAY ~), ~ ;' 0 ........................................... -~ _ ' iii-" *-----'[ UNIT s ~5 14 51 : I ' --I ~ ':~:"'~. I "I [ ..... I :1 '""' ''1 I l0 ~--i. 0 Well Data not released to public ..~.. .s · ]3 s _ ,,, : © s " ARCO Alaska, Inc. <~ -+ ~ ~,.'/ , ,I FIELD' 20° RULES' AR£A ........_i ' £XHIBIT I[-1 , PROPDS£D r----- anna u~p KUPARUK RIVER OIL POOL KUPARUK RIVER FIELD AGO 10023500 NPRA ,./,' --.J'i~ :(OOKPUK ~80 I / ~/~ / X i PRUDHOE " BAY 13 / I I I I I ! ! I 20 " PROPOSF:D FIF:LD I:IULI::$ AREA ! .o,oo° / , ! / / : UNIT KUPARUK RIVER OIL POOL KUPARUK RIVER FIELD Available Well Data 0 Well Data not released to public ARCO Alaska, Inc. Sub$1dlary of AtlantleRichflel~C~peny EXHIBIT ii 2 STRUCTURE MAP OP KUPARUK RIVER FM AGO 10023501 NPRA / /. /: · 15 20 PROPOSED FIELD 13 II10 , I / PRUDHOE , ~/]-- BAY .... ~ , / ,~__ UNIT / - ~/ , ..... ',.__, I ~/~~ &vailable Well Data .................................. ~.. ~ ' , EXHIBIT ~ '5.' RULES AREA ISOPACH MAP KUPARUK RIVER FM. KUPARUK RIVER OIL POOL KUPARUK RIVER FIELD AGO 10023502 NPRA · / /. / · /, ! ! ! ! ! ! ! ! ! I ! PROPOSED FIELD RULES ' O ! 20 ' AREA KUPARUK RIVER OIL POOL KUPARUK RIVER FIELD I :1 I I I I PRUDHOE BAY Available Well Data 0 Well Data not released to public ARCO Alaska, Inc. ~ Subsidiary of AtlanttcRlchfieldCompany EXHIBIT ]~-1 DEVELOPMENT AREA AGO 10023503 UNIT : Chevron Chevron U.S.A. Inc. P.0. Box 7-839, Anchorage, AK 99510 · Phone (907) 279-9666 T. L. Perryman Area Operations Superintendent Production Department April 7, 1981 PROPOSED KUPARUK RIVER POOL RULES CONSERVATION FILE NO. 173 Mr. Hoyle H. Hamilton Chairman Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Hamilton: As we had not received a copy of the proposed Kuparuk River pool rules in advance of the heari.ng held in Anchorage on March 25, 1981, we were not in a position to comment on the testimony presented that day. We appreciate your announcement that the record would be open for comments until 4:30 p.m., April 8, 1981. In that area between the Milne Point unit and the proposed area where ARCO is applying for new pool rules Chevron does not believe sufficient evidence is present to support the extension of the Eileen fault from the Prudhoe Bay field as a continuous fault. The fault could become segmented or dissipate in this area. Therefore, the contention it is an oil sealing fault in this area would be difficult to prove. Chevron recommends the area to be covered by the Kuparuk River pool rules. extend up to the Milne Point unit so as to also include at least Sections 16, 17, 18, 20, 21, 27, 28, 34 and 35 T13N, RIOE, U.M. Chevron would also support using the same pool rules for the Kuparuk River formation in the Milne Point unit area. :WCM:sj T. L. Perryman RECEIVED APR- ? lOSIj AGO 10023506 kl~il~ Oil & ~s Con~. f~ommllll~ AnolmmOl Mobil Oil Corporation EXPRESS MAIL P.O BOX 5444 DENVER, COLORADO 80217 G.G. JURENKA PRODUCING MANAGER EXPLORATION & PRODUCING DIVISION April 6, 1981 Alaska Oil and Gas Conservation Commi ss ion 3001 Porcupine Drive Anchorage, Alaska 99501 ATTENTION' Mr. H. H. Hamilton Commi ssi oner RE' PROPOSED KUPARUK RIVER FIELD RULES Dear Mr. Hamilton- Please refer to the AOGCC Hearing on March 25, 1981 in Anchorage on the above subject which record was to remain open until April 8, 1981. Mobil Oil Corporation has previously indicated support of the Kuparuk River Field Rules proposed by ARCO Alaska, Inc. After reviewing the testimony intro- duced at the hearing, we suggest further consideration be given to extending the area to be covered by subject Rules eastward to the Eileen Fault encountered in SOCAL 29-33E well. Precedent for describing and using faults as boundaries for reservoirs or portions thereof, has been established by the definition of "Main Area" in the Prudhoe Bay Unit Agreements. Should it be found desirable for the boundary of the proposed Kuparuk River Unit to be along said Eileen Fault, the Prudhoe Bay Unit Area could be amended to ex- clude the area west of the Fault. The area west of the Fault and inside the Prudhoe Bay Unit Area is not expected to be developed by the Prudhoe Bay Unit or to receive any Participation credit in the Prudhoe Bay Unit. cc' ARCO Alaska, Inc. Phillips Petroleum Company Chevron, USA AGO 10023508 Very truly yours, G. G./J~renka Produ ~l~g Manager RECEIVED APR - 7 1981 Alas~ Oil & Gas Cons. Commission Anchorage PHILLIPS PETROLEUM COMPANY ENGLEWOOD, COLORADO 80111 WOODSIDE II -- GREENWOOD PLAZA 7800 E. DORADO PLACE .'% NATURAL RESOURCES GROUP Exploration and Production April 3, 1981 Re: Public Hearing Alaska Oil and Gas Conservation Commission Conservation File No. 173 Application of Atlantic Richfield Company, Dated November 25, 1980, for an Order Setting Forth The Pool Rules for the Development and Production of the Kuparuk River Formation, West of the Prudhoe Bay Field Mr. Harry W. Kugler, Commissioner Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Sir: At this time Phillips Petroleum Company would like to submit additional testimony to that presented by ARCO at the Public Hearing on March 25, 1981. Testimony presented by ARCO was to the effect that the Kuparuk River Formation is separated into two areas of hydro- carbon accumulation by a large northwest-trending fault which is located within and on the western edge of the Prudhoe Bay Unit and is referred to as the Eileen Fault. Additional testimony presented by ARCO proposed that the existing field rules for the Prudhoe Bay Kuparuk River Oil Pool be contracted to the eastern boundary of the proposed Kuparuk River Field Rules Area, as presented in ARCO Exhibit I-1. Phillips Petroleum Company, in general, supports ARCO's presentation but proposes that the Eileen Fault be used as the eastern boundary for the Kuparuk River Field Rules Area and that the field rules boundary of the existing Prudhoe Bay Kuparuk River Oil Pool be contracted to coincide with this eastern boundary insofar as it applies to the Kuparuk River Formation. Ail indications are that the Eileen Fault is the natural division between the two accumulations of hydrocarbons in the Kuparuk River Formation. Adoption by the Commission of the Eileen Fault line as the eastern boundary for the Kuparuk River Field Rules Area would be advantageous for the following reasons: RECEIVED AGO 1002350~ APR - 6 1981 Alaska 0il & 6as Cons. Commission Anchorage Mr. Harry W. Kugler - 2 April 3, 1981 1. Such a decision would be in accordance with the testimony presented by ARCO at the Public Hearing March 25, 1981, regarding the known geology in the area. 2. Adoption of the Eileen Fault as the eastern bound- ary of the Kuparuk River Field Rules Area would be of great assistance when secondary recovery waterflood methods are applied to the Kuparuk River Formation. With the Eileen Fault as the eastern boundary, disputes concerning surface boundary locations with regard to secondary re- covery efforts would be minimized and perhaps eliminated entirely. 3. If commercial production is established from the Kuparuk River Formation underlying tracts on the western side of the Eileen Fault' which tracts are not presently included in the Kuparuk River Field Rules Area as sub- mitted by ARCO, then these tracts would be left in limbo with regard to early development of the Kuparuk River Formation and might suffer drainage from producing wells located to the west of the eastern boundary lines as now proposed by ARCO. However, by adopting the Eileen Fault as the eastern boundary for the Kuparuk River Field Rules Area, these tracts would be included in the new proposed field rules, their correlative rights could be safeguarded, and much earlier development of these tracts would be facilitated. For these reasons, Phillips urges the Commission to adopt the Eileen Fault as the eastern boundary for the Kuparuk River Field Rules Area. Very truly yours, LLIPS PETROLEUM COMPJ~XlY D~ing & Production Manager Western Division JKF/pdh AGO 10023505 , RECEIVED APR - 6 1981 Alaska Oil & Gms Cons. Commission Anchorage 10 11 12 13 14 15 16 17 18 t9 20 21 22 23 24 25 STATE OF ALASICA ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING REGARDING THE APPLI- ) CATION BY ARCO ALASKA ) INC., FOR: ) ) KUPARUK RIVER FIELD ) NORTH SLOPE, ALASKA ) FIELD RULES ) ) APPEARANCES: HOYLE HAMILTON, COMMISSION CHAIRMAN HARRY KUGLER, COMMISSION MEMBER LONNIE C. SMITH, COMMISSION MEMBER JEFF LOWENFELS, ASSISTANT ATTORNEY GENERAL March 25, 1981 9:00 A.M. BoroughAssembly Chambe Tudor Road Anchorage, Alaska APR - 6 1981 R & R COURT REPORTERS ,,,o, ~,-,.~,-. ,u,,~,o, ~o,, w.~,o ^v,,u. ,oo, w..,o ^v~lSkaOii& GasCons. Corn ."S O~ O O 10 11 12 13 14 15 16 1¸7 18 t9 2O 21 22 23 24 25 INDEX WITNESSES FOR APPLICANT: STEPHEN M. WILLIAMS JAMES C. MERRITT WILLIAM H. McMILLIAN PETE A. VAN DUSEN JOHN S. DAYTON PAUL B. NORGAARD QUESTIONING OF APPLICANT'S WITNESSES BY THE COMMISSION JOHN A.~IREADER QUESTIONS FROM THE AUDIENCE PAGE 15 25 30 44 47 92 94~ R & R COURT REPORTERS 810 N STREET. SUITE 1OI BOg W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-OB73 274-9322 272-7B1~ ANCHORAGE, ALASKA 99BO1 AGO 10031695 10 11 12 13 14 15 16 17 18 20 21 22 25 _2- P R O C E E D I N G S MR. HAMILTON: Good morning. I'm Hoyle Hamiltor Chairman of the Alaska Oil and Gas Conservation Commission and to my left is Commissioner Harry Kugler. To my immediate right is Commissioner Lonnie Smith, and to my far right is Assistent Attorney General Jeff Lowenfels who is our legal counsel for today. '~c This is a public hearing called by the Alaska Oil and Gas Conversation Commission in response to an application that was received from Atlantic Richfield Company requesting the Commission to issue an order setting forth the pool rules for the development and production of the Kuparuk River formation west of the Prudhoe Bay Field. Today the Commission will seek testimony regarding pool definition, well,,spacing, drilling and production requirements, the area to be affected by pool rules, a field name to be applied to this area and any other dat. that might be deemed necessary to prevent waste and for the safe and orderly development of the Kuparuk River formation in the affected area. Notice of this hearing was published in the Anchorage Times on February the 5th, 1981, and a copy of the public notice will be made part of the hearing record. I'd briefly like to go through the procedures that we're going to follow today. We'll first hear testimony from the Applicant, and they have indicated that that will probably take R & R COURT REPORTERS 810 N STREET. SUITE 1OI 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-OE73 274-9322 272-7B1~ ANCHORAGE. ALASKA 99501 AGO 10031696 10 1! 12 13 14 15 16 17 18 t9 2O 21 22 25 -3_ about an hour and a half~ to be followed by a brief recess which will probably be appropriate about that time. And then the applicant will be questioned by the Commission. Following that we'll take testimony from anyone else who would like to present testimony. Following that we'll take oral statements from anyon~ who would like to make an oral statements. Now, there's sign-up sheets in the back of the room and Betty Jane Erlich, if you woUld stand up, Betty Jane? She will take the people's names that are interested in giving testimony or making an oral statement, and also if you would like to submit a written statement, she will accept those back there. Now, if you would like to ask questions, please submit those to Betty Jane in writing and at the -- toward the end of the hearing< the commission will review those questions and we'll ask the ones that we think will help elicit information for the hearing. Does anyone have any questions before we start regarding the procedures we're going to follow? Okay. If not, I would like to call the applicant forward and see if they would like to start their testimony. And, please, if you do come up to ~present testimony or make an oral -- oral statement, please sit at the -- the seat by the microphone at the table and state your name and who you represent. MR, WILLIAMS: Mr. Chairman, members of the Alask Oil and Gas Conservation Commission, my name is Stephen M. Willia r & R COURT REPORTERS 8lO N STREET. SUITE rOI 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-OES7:2 - 277-O~73 274-9322 272-7~1~ ANCHORAGE. ALASKA 99BOi AGO '10031697 11 12 13 15 16 17 18 t9 20 21 23 25 -4_ I'm an attorney for ARCO Alaska~ Inc. ARCO Alaska, Inc., is a wholly owned subsidiary of the Atlantic Richfield Company. We appreciate the opportunity to present testimony today to the Commission regarding field rules for the Kuparuk River area. The purpose of today's hearing is to establish field rules for a new field which we are officially requesting be called the Kuparuk River Field. The proposed boundaries of the Kuparuk River Field are shown on Exhbit One-dash-one. These boundaries are all withi the geographic limits of the state of Alaska and subject to the jurisdiction of the Alaska Oil and Gas Conservation Commission. The existing field rules for the Prudhoe Bay Kuparuk River Oil Pool are set forth in Conservation Order Ninety-eight-A as amende by Conservation Order Number One-thirty-seven. The rules pro- posed today are similar to those existing rules with the excep- tion of specific modifications and changes discussed in later testimony. The existing rules now cover a portion of the proposed Kuparuk River Field as shown on Exhibit One as the shaded area. The existing boundaries of the Prudhoe Bay Unit are also iden- tified. We propose that the field rUles boundary of the existing Prudhoe Bay Kuparuk River Oil Pool be contracted to coincide with the eastern boundary of the proposed Kuparuk River field rules area as indicated on Exhibit One. This contraction would allow the proposed new field rules to cover this area. Testimony will establish that a separate oil accumulation exists in the proposed R & R COURT REPORTERS 810 N STREET. SUITE 1OI 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-O573 274-9322 272-7515 ANCHORAGE. ALASKA 99501 AGO 10031698 10 1! 12 13 14 15 16 17 18 t9 20 21 23 25 -5- Kuparuk River Field. The proposed field rules have incorporated input from other working interest owners in the proposed area. ARCO will present the following witnesses whose testimor has been prefiled with the Commission. The testimony will be adopted by each of the witnesses and each of the witnesses will be available for additional questions from the Commission. The witnesses include~James C. Merritt who will present testimony on geology; William H. McMillian who will present testimony regarding reservoir engineering~ Pete Van Dusen who will present testimony on drilling operations; John S. Dayton, who will pre. sent testimony on well completiOns, surface facilities, and the surveillance program; and Paul B. Norgaard, Vice President ARCO Alaska, Inc., who will summarize the testimony. In addition to addressing the proposed field rules directly, this testimony is designed to provide you a basic understanding of the reservoir and current development plans. It should be stressed that the development of the Kuparuk River Field is in an early stage. The data is limited and future data acquisition will play an important role on future development plans. Our testimony today reflects ARCO's plans and interpre- tations of existing data. Throughout this testimony reference is made to several different wells.~ For convenience sake and to facilitate reading the wells are designated by only the operator's name and well R & R COURT REPORTERS 810 N STREET. SUITE IO! 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-O573 274-9322 272-TBIE ANCHORAGE. ALASKA 991~01 AGO 10031699 10 11 19. 13 15 16 17 18 t9 2O 21 9.3 9.5 -6- number. ARCO would request that Commission members hold any questions they may have until the end of the presentation. If this procedure is acceptable, all witnesses will be available to answer any questions that the Commission members may have at the conclusion of the testimony. I would request at this time that the Commission swear in the persons who are going to testify today for ARCO Alaska Inc. MR. HAMILTON: Fine. We'll do that, Mr. Williams And that is acceptable, we w~ll wait until after your testimony and ask questions of your group. MR. WILLIAMS. Thank you Mr Chairman MR. KUGLER: Will those that are going to testify please stand up and raiSe their right hand? (MR. KUGLER SWEARS IN JAMES C. MERRITT WILLIAM H. · McMILLIAN, PETE A. VAN DUSEN, JOHN S. DAYTON, PAUL B. NORGAARD) MR. KUGLER: You may be seated. MR. MERRITT: Mr. Chairman and members of the Alaska Oil and Gas Conservation Committee, my name is James C. Merritt. I am presenting geological testimony on behalf of ARCO Alaska, Znc., which I will refer to as ARCO. I received a Master of Science degree in geology in 1966 from the University of North Dakota and have been employed as a petroleum geologist for over fourteen years, which includes ten years of Alaskan experience. R & R COURT REPORTERS 810 N STREET. SUITE IOI 509 W. 3RD AVENUE 1OO7 W. 3RD AVENUE 277-0572 - 277-O573 274-9322 272-71515 ANCHORAGE. ALASKA 99~O1 AGO 10031700 10 11 12 14 15 16 17 18 ~9 2O 21 24 25 _7- I have been employed by ARCO for the past eight year~, and am -- I am now currently the senior geologist for exploration and development of the Kuparuk River Field in the North Slope Dis- trict. The last two and a half years of my efforts have been concentrated on the geological aspects of Kuparuk exploration and development. Let me begin the geological testimony by showing you ARCO Exhibit Two-dash-one, is -- is a map of the portion of the Alaskan Arctic North Slope. Each square in the grid represents a six mile township. We propose thatthe field rules for the Kuparuk River Field apply to an area that covers about three hundred and fifty_six thousand, four hundred and eighty square miles, or about five hundred and fifty_seven -- excuse me, that was acres, or about five hundred and fifty_seven square miles. This area allows -- lies south of the Beaufort Sea shoreline east of the Colville River boundary of the NPR_A, and immediately west of the Prudhoe Bay Unit. Oil was first discovered in the Kuparuk area witn Sin- clair tested oil from Be Kuparuk Formation at the rate of one thousand fifty_six barrels of oil per day at their Ugnu Number One well in 1969. Subsequently other oil -- other Kuparuk accu_ mulations have been discovered in the vicinity; the Eileen and North Kuparuk areas of Prudhoe Bay Field, at Gwydyr Bay located north of the Pruhoe Bay Unit, and also at Milne Point immediately northwest (sic) of the Kuparuk area of accumulation. During the R & R COURT REPORTERS 810 N STREET. SUITE lot 509 W. 3RD AVENUE 1OO7 W. :~RD AVENUE 277-0572 - 277-0573 274-9322 272-7E~1~ ANCHORAGE. ALASKA 99501 AGO 10031701 10 1! 12 !4 !5 16 17 18 2O 21 22 9.5 -8- eleven years between 1969 and 1980, the industry has drilled twenty_five wildcat and estension wells in attempts to define tht limits of the Kuparuk oil accumulation. ARCO has drilled and joined in the drilling of all but seven of these wells. Further- more ARCO will join or join in the drilling of four additional tests in 1981. These are the Sohio West Sak Numbers Sixteen and Seventeen, and the ARCO West Sak Number Eighteen and Twenty. Tw¢ additional wells, the West Sak Thirteen and Fifteen, have not been released to the public record and therefore these data do not apply -- do not appear as supporting testimony. It is the data -- It is the subsurface data from the twenty-five wells and hundreds of miles of multi-fold seismic data that are sued for the following geological interpretation. All the exhibits that you will be seeing were originally constructed by myself or under my direct supervision. Expert assistance was received from our research group in Dallas, our geophysical, and engineering, land and. legal departments in Anchorage. I show you now Exhibit Two_dash .... Two-dash-two, a structure contour map on the top of the Kuparuk River Formation. The contour interval is one hundred feet. The contoured part covers the area west of the Prudhoe Bay Unit, east of the Colvill~ River, and south of the Beaufort Sea. The Sinclair Ugnu Number One well is located in the north-central part of the contoured area. Subsurface control data for the structural mapping is supplied by twenty of the exploratory wells. R & R COURT REPORTERS 810 N STREET. SUITE IOI 1509 W. 3RD AVENUE 1OO7 W. 3RD AVENUE 277-O572 - 277-O573 274-932'~ 272-7~51~ ANCHORAGE. ALASKA 991~01 AGO 10031702 10 1! 12 15 16 17 18 t9 2O 21 22 25 _9- The feature is a southeasterly plunging anticlinal nose that is about twenty_six miles wide and twenty-two miles long. Data from eight wells establishes the northeast flank of this feature. Over eight hundred feet of north dip is measured from the West Sak Eleven well, drilled on the crest of the feature, to the Socal Simpson Lagoon wells. Although the south flank is less well defined, five wells from which data has been released show at least fi~e hundred and fifty feet of south dip. Dip rat~ vary up to three degrees maximum, or about two hundred and seventy-five feet per mile., Structural closure to the southeast is well established by well control. The northwest dip from the West Sak Eleven and the Kalubik Creek Number One wells to the Colville Number One well is created by the erosion of the Kuparuk River formation by a lower Cretaceous unconformity that places younger Cretaceous rocks on top of progressively older rocks to the west. This unconformity truncates the Kuparuk River forma- tion along a northeast/southwest line just east of the Kookpuk and Colville Number One wells and west of the Kalubik Creek and the West Sak Number Eleven wells. The truncated edge of the Kuparuk is placed immediately east of the Kookpuk and Colville Number One wells because regional isopach mapping of the pre- Kuparuk rocks indicates that erosion of the lower rocks is minimal. These same younger lower Cretaceous rocks truncate the Kuparuk River formation along a poorly defined line drawn betwe~ R & R COURT REPORTERS 810 N STREET. SUITE 1OI 1509 W. 3RD AVENUE lOO7 W. 3RD AVENUE 277-O572 - 277-O573 274-9322 272-7515 ANCHORAGE. ALASKA 99BO1 AGO 10031703 10 11 12 13 14 15 16 17 18 t9 20 21 23 25 -10- Mobil's north Kuparuk well and Sohio's -- and Sohio's M-pad wells in the Prudhoe Bay Field. In the Kuparuk River Field area, the turncation is placed about two to three miles downdip from well control. This is based on the rate of thinning in the ~Kuparuk River formation due to truncation. A large northwest-trending fault is shown along the wes boundary of the Prudhoe Bay Field. This separates the two areas of accumulation, and is commonly referred to as the Eileen fault. The downthrown block is to the southwest with displacement ranging from a;hundred and fifty to three hundred fifty feet. The fault was encountered in the Socal Thirty-three-twenty-nine-E well below the Kuparuk formation where more than two hundred feet of Jurassic section was faulted out. It was also found in the ARCO Highland State Number One well, where all of the Kuraruk section and a portion of the upper Kingak shale was faulted out. Seismic data indicates the fault continues tothe northwest towards the Beaufort Sea, where it separates the Simpson Lagoon wells of the -_ of the Kuparuk River Field from the Milne Point and Kaverak Point wells. The two red lines labeled A-A-prime and B-B-prime show the location of two structural cross-sections that will be shown as Exhibits Two_three and Two-four. I show you now -- I show you know ARCO Exhibit Two-dash_three, which is cross-section A-A-prim which extends from west to east between the Sinclair Colville Number One well and the ARCO West Sak Six .... Six well, and R & R COURT REPORTERS ANCHORAGE. ALASKA g9501 AGO 10031704 10 11 12 13 14 15 16 17 18 i9 20 21 22 23 25 -11- parallel to the structural axis of the feature. The logs used on the section.are the gamma ray/dual induction laterolog and thc SP logs. The depth reference is feet below sea level, and the vertical exaggeration is twenty times. The cross-section illus- trates the southeast structural dip from the crest at West Sak Eleven and the northwest dip due to truncation between the West Sak Eleven and the Colville Number One well. I have projected truncation o~-'the formation downdip and east ofi~:the West Sak Number Six well. I show you now ARCO Exhibit Two-four, which shows struc- tural cross-section B-B-prime. It was constructed across the tructural axis of the Kuparuk River Field, extending from the northeast to the southeast between the Northwest Eileen Number One well and the Sohio -- and the Sohio West Sak Number Four well. The vertical exaggeration' is twenty times. The West Sak Number Two well is projected along structural strike into the line of section. This section illustrates both the south- dipping flank and the north-dipping flank of the feature, and the existence of the Eileen fault between the Northwest Eileen well and cutting the socal Thirty-three-twenty-nine_E well. The Kuparuk formation consists of very fine to medium grained marine sandstone, usually occurring as three sandy mem_ bers separated by mudstones, siltstones and thinly bedded sand- stones. In those areas of greater than three hundred feet of Kuparuk formation, all three sandstone members or their silty/ R & R COURT REPORTERS 810 N STREET. SUITE lO! 509 W. 3RD AVENUE IO0'7 W, 3RD AVENUE 277-0572 - 277-OB73 274-9322 272-71~1B ANC"ORAGE. ALAS~ A, 9~[$0' AGO 10031705 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 _12- shale equivalents are present. In those areas of less than three hundred feet of thickness, usually less than three of the sand- stone members are present. This section~ B-B-prime, shows the formation thinning to the south by truncation by the lower Cretaceous unconformity. North of the crest of the feature, thinning of the formation also occurs by intraformational unconformities or by nondeposi- tion, causing -- causing updip coalescence of sands within the formation. Refer again to Exhibit Two-three, which is cross-section A_A-prime. This section illustrates the Kuparuk formation resting conformably on Kingak shale and overlain by an unnamed lower cretaceous shale, which rests unconformably on Kuparuk and Kingak. The formation is completely truncated by a lower Cre- taceous unconformity between the West Sak Eleven and the~C01ville Number One wells. Also the lower sand members thins to the east along this section. T~is next slide is ARCO's Exhibit Two_dash-five, which is an isopach map showing the distribution of the total thickness of the Kuparuk River formation. The contour interval is a hun- dred feet. Data from thirty-wells was used to construct this map. The Colville River is located on the west, the Beaufort Sea shoreline to the north, and the Prudhoe Bay Unit outline on the east. The thickest section of six hundred and sixty-four feet was encountered in the Placid Beechey Point well, located in the R & R COURT REPORTERS 810 N STREET. SUITE 1OI 1509 W. 3RD AVENUE IO07 W. 3RD AVENUE 277-01572 - 277-0573 274-9322 272-7Bt5 ANCHORAGE. ALASKA 99~O$ AGO 10031706 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -13- northeast part of the map. Thinner sections occur along the northeast -- northwest and the southeast boundaries where the fomration thins or is missing by truncation. In general, in areas of less than two hundred feet, the Kuparuk formation thin~ rapidly by erosional turncation. The red lines show the locatioi of cross-sections A-A_prime and B-B-prime. Please refer again to Exhibit Two, the structure map on top of the Kuparuk formation. To date no wells have estab- lished the existance of a gas cap. The trapping mechanism of the Kuparuk River field is the truncation of the Kuparuk River sand- stone reservoir by non_porous Cretaceous rocks across the updip part of the plunging structural nose. The trap is completed by structural dip closure to the northeast, southeast, and to the south. Structurally the trap has over nine hundred feet of clo_ sure as measured from the West Sak Eleven well located on the crest of the structure, to the West Sak Number Six and the Simpso Lagoon wells~ the structurally lowest wells in the field. Twenty-one wells were used to define %he currently indicated limits of the reservoir of the Kuparuk River Field. Eighteen had at least one oi-saturated Kuparuk sand member. Two are dry holes ARCO's West Sak Number Six produced water when tested and the Simpson Lagoon Thirty_two-fourteen appears to be water-bearing on the logs despite having residual shows of oil on sidewall samples. The Kuparuk Reservoir is missing in the Sinclair Col- ville Number One and the Union Kookpuk Number One wells. Of the R & R COURT REPORTERS 810 N STREET. SUITE IOI 509 W, 3RD AVENUE IOO7 W. :~RD AVENUE 277-O572 - 277-O573 274-9322 272-7B15 ANCHORAGE. ALASKA 99~01 AGO 10031707 10 11 12 13 15 16 17 18 ~9 2O 21 24 25 -14- seventeen oil-saturated wells, thirteen produced oil in signifi_ cant quantities when tested. These wells are the Simpson -- Simpson Lagoon Thirty, two-fourteen, the Ugnu and East Ugnu wells and the West Saks Number One, Number Two, Number Three, Number Four Number Seven, Number Eight, Number Nine, Number Eleven, Number Twelve, and Number Fourteen. Four wells, although oil- saturated, failed to test paying quantities of oil due to forma- tion damage, poor quality reservoir rock or other factors. Thes~ wells are the Kalubik Creek Number One, the Socal Thirty_three- twenty-nine-E, and ARCO's West Sak Number Five and Number Ten. We know that there is an oil/water contact, but its exact depth is not known. No oil/water Contacts have been sub- stantiated in any individual sand members. The highest occurrenc of water has been observed at sixty-five-forty--eight feet below sea level in the West Sak Number Six well, but other wells have encountered hydrocarbons deeper than this. We currently inter- pret the oil/water contact as a surface with a slight north dip. We interpret that all sand members of the Kuparuk River .formation west of the major sealing Eileen fault are in a common pool and share the same fluid contact. In the Kuparuk River Field communication between the individual sand members exists through coalescence of sand members as was illustrated'in the cross-sections, and juxta juxtaposition of the small -- of sand across small faults. The following testimoney by Mr. McMillian will elaborate on the Kuparuk reservoir rock and fluid properties r & R COURT REPORTERS 810 N STREET. SUITE IOI 1509 W. 3RD AVENUE 1OO7 W. 3RD AVENUF 277-O572 - 277-OB73 274-9322 272-7B11~ ANCHORAGE. ALASKA 99BO1 AGO 10031708 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -15- and reservoir performance studies. Thank you. MR. McMILLIAN: Mr. Chairman, and members of the Alaska Oil and Gas Conservation Commission, my name is William H. McMillian. I am presenting reservoir engineering testimony this morning on behalf of ARCO Alaska. I recevied a Master's degree in physics from LSU in 1971. After having served four years as an officer in the Air Force, I began employment in 1975 with ARCO as a petroleum reservoir engineer. My experience in- cludes various assignments in West Texas, Dallas and Alaska where I have conducted reservoir engineering studies of oil and gas fields under primary depletion~ waterflooding and enhanced oil recovery. The last one and a half years of my efforts have been concentrated on the development of the Kuparuk River Field. My testimony this morning will incude a description of basic Kuparuk reservoir rock and fluid properties, a summary of reservoir performance studies and comments on well spacing. All of the exhibits that will be presented were originally constructE - under my direct supervision, and expert assistance was received from ARCO personnel at our Production Research Center near Dallas and from our geological group here in Anchorage. Let me begin this testimony by showing you Exhibit Three dash-one, a map which depicts our interpretation of the extent of hydrocarbons in the Kuparuk. The outer boundary includes the potential limits of the formation~ and the inner boundary, the solid black line, defines the area that is presently planned r & R COURT REPORTERS 810 N STREET. SUITE lOI 1509 W. 3RD AVENUE lOO7 W. 3RD AVENUE 277-O572 - 277-0573 274-9322 272-TBIS ANCHORAGE. ALASKA 99BOI AGO 10031709 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -16- for development. Determination of this preliminary two hundred and ten square mile area for development has been based on interpretation of well logs, core data and production tests for net pay. There is considerable uncertainty in picking net pay in Kuparuk that will be resolved only after commencement of production. Oil in-place volume for the Kuparuk within _- within this inner boundary,is estimated to be in the range from three- point_five to four-point_four billion stock tank barrels. Average porosity is twenty to twenty-one percent, and average water saturation is thought to be twenty-five to thirty percent from core data. The wide range in oil in-place estimates is appropriate in view of the sparsity of well control over much of the Kuparuk area. The objective of our current delineation drilling program is to test strategic areas in the northern part ofthe field and along the south and southwest boundaries of the field in order to remove some of the uncertainties in mapping the accumulation. I show you now Exhibit Two, a type_log from the West Sak Number One well. The logs used in this type log are the gamma ray on the left and the dual induction log on the right. And this exhibit identifies three sand units in the Kuparuk. A general description of these three sand units is as follows: The upper sand in yellow and the middle sand in gold arc lithologically similar. They are very fine to coarse grained to R & R COURT REPORTERS 810 N STREET. SUITE lOl 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-OB73 274-9322 272-7EilB ANCHORAGE. ALASKA 9915OI AGO 10031710 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -17- pebbly quartzitic sandstones that lack bedding features due to bioturbation. Glauconite and siderite occurrence ranges from zero to very abundant. Porosity and permeability in these membe~ ranges from very poor to excellent and varies with grain size and the abundance of siderite cement and glauconite. The orange is the lower sand a very fine to fine · grained quartzitic sandstone that is well sorted, clean and commonly interbedded with thin siltstone and mudstone. Porosity and permeability is generally fair to excellent in this member and varies with grain size. This zonation has been used in the Kuparuk reservoir modeling studies which will be discussed later in my testimony. The next exhibit, Exhibit Three, summarizes reservoir rock properties for the various sand members of this type well. Initially reservoir pressure in ~e Kuparuk averages thirty_one hundred pounds. Reservoir temperature is approxii? ~i~ mately a hundred and fifty-five degrees. At these conditions oil gravity averages twenty-three -- twenty_three degrees API, ranging from twenty-five degrees in structurally high wells to below twenty degrees downdip near the water-oil contact. The formation volume factor averages one-point_two_one_five stock tank barrels per barrel of reservoir fluid and the solution GOR averages four hundred sixty standard cubic feet of gas per barrel of oil. There is an apparent correlation between reservoir fluid properties and subsea depth. The oil tends to be more viscous R & R COURT REPORTERS 810 N STREET. SUITE IO! 509 W. 3RD AVENUE 1007 W, 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7~ll5 ANCHORAGE. ALASKA 99~05 AG0 10031711 10 11 12 13 14 15 16 17 18 t9 20 21 22 23 24 25 -18- and have a lower oil gravity at deeper structural locations. There are also similar correlations with depth for formation volume factor and solution GOR. The bubble point of the Kuparuk reservoir fluid average three thousand psia, approximately a hundred pounds below the initial reservoir pressure. As a result, the Kuparuk River reservoir is thought to be undersaturated which means that there is no gas cap or free gas at initial conditions. The aquifer underlying the Kuparuk River oil accumula_ tion appears to be small in volume because of unconformities downdip to the southeast and due to faulting to the northeast. Accordingly, aquifer influx into the oil column is expected to be insignificant. Early production and early pressure perfor_ mance shoUld substantiate this assumption. The water_oil contact has not been observed in any individual sand members of Kuparuk wells. Since the highest occurrence of water was in the West Sak Seven --- West Sak Numbe~ - Number Six well, _- in the West Sak Six at sixty-five-forty_ eight feet subsea, and other wells have encountered hydrocarbons at deeper subsea elevations, it is interpreted that the water- oil contact is a tilting surface with a slight north dip. Although water saturation in the Kuparuk is a key factor in determining in-place hydrocarbon volumes and predicting pro- duction performance in the field, Water saturation cannot be easl determined. Conventional analysis of electric logs for calcula. R & R COURT REPORTERS 810 N STREET. SUITE IOt BO9 W. 3RD AVENUE 1OO7 W. 3RD AVENUE 277-0572 - 277-01573 274-9322 272-7315 ANCHORAGE. ALASKA 99501 AGO 10031712 Ly 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 tion of water saturation cannot be applied to the Kuparuk forma- tion due to thin bed effects and the presence of shales, sider and glauconite throughout the rock. Accurate determination of water saturation requires taking oil base cores in selected wells. Information from careful analysis of these cores provides a correlation of water saturation with formation permeability, porosity and height above the water_oil contact. This correla_ tion is called a Leverett J-function. Specialized J_functions have been derived for the Kuparuk sands using oil-base core data from the West Sak Seven and E-Five wells. We believe on the basis of our current study that it is appropriate to have a separate J_function correlation for each of the lithologic units previously identified. Let me direct your attention to Exhibit Four which shows the water saturation distribution for three sand members having average permeability and porosity. As you can see, the water saturation decreases with the distance above the water-oil~con- tact and we believe that the water saturation at any point in an actual well profile can be acceptably determined by the use of the J_function. We have conducted studies concerning depletion -- pres- sure depletion performance in the filed for several years. We feel that we have developed an adequate description of reservoir characteristics despite the shortage of well control, and have carefully applied our knowledge of well tests and fluid flow data r & R COURT REPORTERS 810 N STREET. SUITE IOI 1509 W. 3RD AVENUE 1OO7 W, 3RD AVENUE 277-O572 - 277-OE73 274-1a322 272-TBIB ANCHORAGE. ALASKA 99B0! AGO 10031713 10 11 12 13 14 15 16 17 18 t9 2O 21 22 25 -20- in predicting field production performance. Solution gas drive is the primary recovery mechanism in the Kuparuk Field since there is no primary gas cap and it is believed that the aquifer will provide little or no natural pressure support. Several primary recovery reservoir models of the Kuparu~ have been constructed by ARCO over the past five years in order to obtain reservoir performance simulations. These models have ranged in complexity from a large_cell, two_dimensional model to a much more detailed study involving a series of three-D finely gridded models having as many as eighteen layers each. The reservoir performance in these studies has been incorporated with well bore effects and surface facility constraints to pre- dict field performance under a variety of possible operational scenarios. The current reservoir model for Kuparuk includes in-flow performance relationships, effect of formation damage~ well bore hydraulics for natural flOw and artificial lift~ and controls to simulate a variety of surface facility configurations Although no long_term production data is yet available, we have calibrated model results with actual well test data gathered over the past eleven years. Initial rates anticipated for Kuparuk wells are directly related to producing well flow efficiency, a function of well bore damage. At the present time, most unstimulated Kuparuk wells have exhibited flow efficiencies averaging less than fifty .' R & R COURT REPORTERS 810 N STREET. SUITE IO! E~O9 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-O573 274-9322 272-7~1ES ANCHORAGE. ALASKA 99150'1 AGO 10031714 10 11 12 13 14 15 16 17 18 20 21 22 23 25 -21- percent. We believe that this level of apparent well bore damage can be reduced by more efficient completion methods or by frac- ture stimulation of the wells. A more complete discussion of our endeavors in this area will be provided in subsequent testi- mony by Mr. Dayton. In anticipation of achieving better results we have assumed flow efficiencies of eighty percent in all of our model predictions. Let me direct your attention now to Exhibit Five, model output of oil and gas rate versus time for ARCO's Phase One development under primary depletion. These curves come from a three-D model study study that was performed in 1979 at the time of our initial commitment to develop Kuparuk. More well data it now available and our forecasting tools we believe have been improved, but this exhibit is still appropriate to show the characteristics of primary depletion for the Kuparuk. ARCO's Phase One development will be discussed later with maps in terms of specific facility design, drilling program and scheduling, but for this discussion ~et~me~j~u.st point out the following scope of this project: Twenty square miles of one hundred percent ARCO leases; one central production facility five drill sites: forty producing wells on three hundred twenty- acre spacing; two to three gas injection wells; and a twenty- . seven mile oil line from Kuparuk to the Trans-Alaska Pipeline Pump Station One. Exhibit Five shows that there is decline of oil produc- R & R COURT REPORTERS 810 N STREET. SUITE IOt 1509 W. 3RD AVENUE 1OO7 W. :BRD AVENUE 277-OS72 - 277-0573 274-9322 272-751B ANCHORAGE. ALASKA 9{)601 AGO 10031715 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -22- tion rate throughout the life of the project. Initial oil rate is nearly eighty thousand barrels per day, but the first year average is about sixty thousand barrels per day. This decline in producing rate is typical for solution gas drive reservoirs. We intend to develop the field down to a hundred and sixty acre well spacing as proposed in Rule Two. This is consis- tent with State-wide field rules and allows us to better maintair oil production rate. This well spacing should improve interwell communication and increase recovery. It is also compatible with our plans to waterflood the field. Solution gas drive reservoirs exhibit an increase in gas rate once the free gas evolves in the reservoir to a satura- tion greater than the critical gas saturation. This increase in produced gas occurs about three years after start-up accordin¢ tothis forecast. In the Phase One projeCt, some of the produced gas will be used as fuel in the production facility and base camp. All remaining gas will be returned to the reservoir through gas injection wells. Gas injection during primary production will help reservoir pressure and may provide minor recovery benefits due t¢ high-pressure gas drive. However, we anticipate break-through of injected gas into production wells close to the injection area. Since there is no primary gas cap in Kuparuk, gas will be injected into the oil column. This is significantly different from saturated reservoirs such as Prudhoe Bay Sadlerochit in r & R COURT REPORTERS 810 N STREET. SUITE 1Ot 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-0573 274-9322 ~72-7BIB ANCHORAGE. ALASKA 99501 AGO 10031716 10 11 12 13 14 15 16 17 18 t9 20 21 22 23 25 -2B- which gas is injected into the gas cap, increasing the energy of the gas cap drive. Injected gas in Kuparuk may channel through the reservoir and force the nearby wells to be shut-in due to high gas production. When gas sales facilities become available, the injected gas will be produced from the injection area for fuel and for sale. Estimates of oil recoverable under primary methods range from eight to. fourteen percent of original oil in-place. This wide range of estimates is due to several uncertainties. There is uncertainty in the reservoir description, an important para_ meter in determining the amount of oil to be recovered. Addi- tionally, the effects of gas injection on recovery are difficult to assess at this time because of uncertainty with regards to channeling and sweep efficiency. And a final parameter which can significantly a~fect primary recovery is the estimate of producing well abandonment rate. We use an abandonment rate of a hundred barrels per day per well in these studies, but it is apparent~that this factor can change substantially as economic conditions change. Initial ARCO commitment to Kuparuk development was announced in 1979 at which time only primary production could be justified economically. Since that time we have been encouraged by successful delineation drilling and by improving economic conditions to consider an increase in the scope of the project both in terms of areal extent and with regard to secondary r & R COURT REPORTERS 810 N STREET. SUITE rOI BO9 W. 3RD AVENUE ~007 W. ::3RD AVENUE 277-O572 - 277-O573 274-9322 272-7BI5 ANCHORAGE, ALASKA 99BOI AGO 10031717 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -24- recovery operations. We believe the optimum recovery method in t light of the current economic and operating environment is water_ flooding. Waterflood technology is well established in the oil industry, although problems associated with operating water injection facilities in the Arctic environment have been studied for the first time by Brudhoe Bay Unit engineers. One of %he major qu~Btions for Kuparuk waterflooding is the identification of a water source. ARCO is presently testing the feasibility of producing water from some upper Cretaceous sands. An alterna- tive water source is the Beaufort Sea. Plans for early water_ flood test-- testing in Kuparuk are dependent upon establishing the upper Cretaceous as a viable source, however, eventual full field waterflood plans can proceed normally regardless of whether the Cretaceous or the Beaufort Sea is our ultimate water source. We are studying waterflood potential for Kuparuk to address the following parameters: First, oil recovery due to pattern waterflood in the various areas of the field. Second, oil rate anticipated from field-wide waterflood development. And, third, the planning of production facilities to accommodate waterflood. Further detailed information regarding stratification possible faulting, the level of injecti~ty, reservoir fluid properties, the presence of any natural fractures, aquifer e- R a R COURT R£PORT£RS 810 N STREET, SUITE 10! 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-O573 274-9322 272-7BIB ANCHORAGE. ALASKA ~950' AGO 10031718 he 10 11 12 13 14 15 16 17 18 2O 9.2 23 25 -25- activity and other parameters must be obtained before we can predict waterflood recovery with confidence. Thank you. MR. HAMILTON. Thank you, Mr. McMillian. MR. VAN DUSEN: Mr. Chairman, and members of the Commission, my name is Pete Van Dusen, and I'm the district drilling engineer for ARCO A%aska, Incorporated, North Slope District here in Anchorage. I've worked in exploration and development drilling in Prudhoe Bay, Kuparuk and on the North Slope since~ii~early in 1975. I am here today to explain the impact of proposed Rule Three pertaining to casing and cementing requirements, proposed Rule Four pertaining to blowout prevention equipment and prac- tices and to make comments on related subjects. Generally, proposed Ruled Three is consistent~with 20 A~C 25.030 of the Alaska Oil and Gas Conservation Commission Regulations in that casing and cementing programs must be design~ to: One, provide adequate protection of all fresh waters. Provide -- Number Two, provide adequate pro~ection of productive formations. And, three, provide protection from any pressure that may be encountered including external freezeback within the permafrost. In addition /~proposed Rule Three is similar in form and R & R COURT REPORTERS 810 N STREET. SUITE IO! 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-0573 274-9322 272-7B15 ANC,ORA~E. ALASKA ~,O' AGO 10031719 -26- 1 content to Conservation Order Number Ninety-eight-A, Rule Three, 2 as amended by Conservation Order Number One-thirty-seven, Rule One. These conservation order rules pertain to casing and cementing requirements for Prudhoe Bay Kuparuk River Oil Pool 5 and are presently in effect along and within the eastern edge 6 of the proposed Kuparuk River Field. As such, proposed Rule 7 Three represents a geographic extension of an existing -- exi 8 conservation order with the following notable differences: Number one, the specific sizes and types of casing are suitable for use within the proposed field boundaries are so 11 indicated in Section (e). THese sizes and types have been tested and field proven to provide adeqnate produc-- protection for 13 further operations. A combined total of over three hundred oil gas injection, and water source and disposal wells have been successfully drilled and produced in Prudhoe Bay Unit without a single failure attributable to permafrost freezeback or thaw 17 subsidence. Over forty wells including exploratory and delinea_ 18 tion wells have been drilled in the Kuparuk field with similar one hundred percent positive results on those tested. Number two a mechanism by which other sizes and types of surface casing may be approved for use in the future is pro- lived in sections (e) (4) and (f). Number three, alternate completion designs to cementing and perforating are allowable in section (h). These alternates include~.slotted liners, wire wrapped screen liners with or wi R & R COURT REPORTERS 810 N STREET..SUITE 1OI 509 W. 3RD AVENUE 1OO7 W. 3RD AVENUE 277-0572 - 277-O573 274-9322 272-7515 ANCHORAGE, ALASKA 991501 AGO 10031720 10 1! 12 13 14 15 16 18 2O 21 24 25 -27- gravel packing, and open hole "barefoot" completions. While present studies justifying these types of completions are not as yet complete, it appears that such completions may offer a means to reduce formation damage and improve Q~er-all recovery. One recent open hole completion in Prudhoe Bay Unit and two recent open hole tests in the Kuparuk have all given positive results. It is proposed that the field rules should contain language permitting such completions on a drilling permit basis and not require Conservation Order exceptions each time one is proposed. Number four, section (ki~ represents an addition to Conservation Order Number One-thirty-seven, Rule One, and embodies Alaska Oil and Gas Conservation Commission Regulation 20 AAC 25.030 (d) pertaining to the use of non-freezing fluids. Simply stated, within the permafrost interval nOn-freezing flui~ will be placed inside casing or inside any annulus between two strings of casing. Non_freezing fluids will also be left inside any tubing string unless such fluids can be continuously heated to maintain a temperature above the freezing point of the fluid. An example would be Central Production Facility Disposal Well Number One which has a circulating glycol system to war.m the dis- posal - dispos&t tubing which often contains freezable fluids. Number five, section (1) ~as an addition to Conservation Order Number One-thirty-seven Rule One. We considered early in 1980 to resolve a conflict between sections (h) and (k) in the R & R COURT REPORTERS 810 N STREET, SUITE 10! 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-O573 274-9322 272-7BIB ANCHORAGE. ALASKA 9950"1 AGO 10031721 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 25 -28- event that a productive horizon is identified between five hundre~ and seven hundred feet below the permafrost. We now feel that this producing condition will be a very special situation should it arise, and should be handled by special exception to the Con- servation Orders rather than by field rules. We therefore request that section (1) be deleted. Number Six, Conservation Order Ninety-eight-A, Rule Thre~ as amended by Conservation Order Number One-thirty-seven, Rule One, is otherwise acceptable in its present form. This includes allowable surface casing setting depths between five hundred feet below the base of the permafrost and twenty_seven hundred feet TVD. We desire to retain this allowable depth range in order to maintain flexibility and assist us in oUr complex directional program. I now direct your attention to proposed Rule Four relating to blowout prevention equipment and practice. Again, referring to existing Conservation Order Number One-thirty-seven, Rule One, the notable changes or additions proposed are as follows: Section (.a) .... Number one, section (a) is reworded to indicate that the blowout prevention equipment and its use shall be in accordance with API Recommended Practice Fifty-three except as modified by this section. This rewording'-- rewording ensures consistency with the Alaska Oil and Gas Conservation Commission Regulation Number 20 AAC 25.035(a) (1). R & R COURT REPORTERS 810 N STREET. SUITE IOI ~509 W. 3RD AVENUE IOO7 W. 3RD AVENU~ 277-O572 ~ 277-O573 274-9322 272-TBIS ANCHORAGE. ALASKA 9950' AGO 10031722 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -29- Number two, section (c) is revised to state that the ~ working pressure rating of the blowout prevention equipment shal be in excess of the maximum anticipated surface pressure with a factory test pressure of twice the working pressure ratings. This wording is consistent with good oilfield practice and is consistent with 20 AAC 25.035(c) (2) and anticipates a reduction in field pre-sure over time. Number three, section (e) relates to test pressure and is revised to allow testing of the bloWout prevention equipment at a pressure in excess of the maximum anticipated surface pres- sure. In addition, testing of the blowout prevention equipment is specified whenever such equipment is changed. These bring section (e) into conformance with 20 AAC 25.035(d) (1). In all other respects, proposed Rule Four is identical with existing Conservation Order Number One-thirty-seven, Rule One. The changes which have been proposed will ensure con- formance with existing regulations and are consistent with good oilfield practice. This consludes my testimony on proposed Rules Three and Four and related Kuparuk subjects. Thank you. MR. HAMILTON: Thank you, Mr. Van Dusen. MR. DAYTON: Mr. Chairman, members of the Alaska Oil and Gas Conservation Commission, my name is John S. Dayton, and I am presenting engineering testimony on behalf of ARCO r & R COURT REPORTERS 810 N STREET. SUITE 1OI BO9 W. 3RD AVENUE fOOT W. 3RD AVENUE =.-o~= - =~-o,~ =~-~== =~'~'" AGO 10031723 ANCHORAGE. ALASKA 99501 10 11 12 13 14 15 16 17 18 ~9 2O 21 22 23 24 25 -30- Alaska, Incorporated. I received my bachelor of science degree in chemical and petroleum refining engineering in 1974 from Colorado School of Mines and have been employed as a petroleum engineer since that time. I have been employed by ARCO for the past twenty months and am currently the senior operations engi- neer for development of the Kuparuk River Field in our North SLope District. All of my efforts have been concentrated on the surface production facilities and well completion aspects of Kuparuk development since my employment with ARCO. Prior to employment with ARCO, I was employed by Amoco Production Company where my assignments included various operations and facilities engineering assignments in Wyoming, Colorado, and Cook Inlet, Alaska. My testimony today will touch on three topics. First, I will typical Kuparuk well design and well completion technique alternatives we are investigating. Following that, I will describe in general the surface production facilities we will install or have already installed in our Phase One development of the Kuparuk River Field. Thirdly, I will present our field- wide reservoir surveillance plans. Development drilling in the twenty section Phase One area commenced in October of 1979 with a single drilling rig. Subsequently a second drilling rig has been ~rought into the area and a total of twenty-six Kuparuk wells have been drilled and cased to date. Oour development drilling progress is illustrated r & R COURT REPORTERS 810 N STREET. SUITE 101 BO9 W. 3RD AVENUE IOO7 W. :~RD AVENUF' 277-OB72 - 277-01573 274-9322 272-TE~tB ANCHORAGE. ALASKA 991~01 AGO 10031724 10 1! 12 13 15 16 17 18 20 21 22 23 25 -31- on Exhibit One. Fourteen of these wells have not yet been per- forated. Two or three injection wells are also planned from Drill Site "B" to accommodate disposal of produced gas back into into the Kuparuk oil pool. We will complete Phase I development drilling on three hundred and twenty acre spacing by December of 1981. I will now show you Exhibit Two, which is a simplified wellbore diagram which illustrates the design of a typical Kuparu producing well. This design is consistent with our proposed Field Rule Number Three. From initiation of continuous produc- tion, gas lift will be used to artificially lift produced fluids Our seven inch twenty-six pound K-55 production casing was selected to allow gas lift in three and a half inch tubing. The typical completion has five to seven gas lift mandrels in the tubing string which will allow -- provide flexibility required by fluctuation in gas lift supply pressure, well productivity, and produced water-oil ratio. In accordance with proposed Field Rule Number Five, each well capable of unassisted flow of hydrocarbons to the surface will be equipped with a surface safety valve on the wellhead and a subsurvace safety valve in the tubing string at a depth of five hundred feet or greater below ground level. Our present control sustem design incorporates high and low pressure pilots as shown on Exhibit Three. Each safety valve has its own inde- pendent high/low pilot.' The surface safety valve and subsurface r & R COURT REPORTERS 810 N STREET. SUITE IO! 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-O{573 274-9322 272-7Bll5 ANCHORAGE. ALASKA 99BO! AGO 10031725 l0 ll 12 13 14 15 16 17 18 2O 21 '22 25 -32 - safety valve will close when either an out of range high or iow pressure condition is detected. With the current Kuparuk development well casing progran there is no safety advantage to setting the subsurface safety valve below the permafrost. Previous research in the Prudhoe Bay Field concerning casing collapse forces generated by free--- freeze-thaw-back cycles has resulted in the Alaska Oil and Gas Conservation Commission approved casing design criteria which has effectively eliminated the casing collapse problems experien¢ in early Arctic wells. To allow reaching development well loca- tions from centralized drill site locations without excessive hole angles, the kickoff point in some wells has been moved to as high as five hundred feet~below ground level. A minimum sub- surface safety Valve setting depth of five hundred feet will provide adequate distance to perform any required wireline work. Shortening the hydraulic control line length to the subsurface safety valve and limiting the line to the vertical portion of the hole will reduce the risk of damaging both the valve and the control line while running in the well. This in turn reduces the probability of control valve failures and the associated high Cost repair work. Therefore, we submit the requirement of placing the subsurface safety valve below the permafrost should be waived in favor of a more shallow setting depth. Our present subsurface safety falves are a tubing retrievable, spring actuated flapper type valve which requires r & R COURT REPORTERS 810 N STREET. SUITE 1OI 609 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-O1~73 274-9322 272-7~$1B ANCHORAGE. ALASKA 995OI AGO 10031726 ,d 10 11 12 13 14 15 16 17 18 9.0 21 9.3 25 -33- positive pressure on the control line to open. The internal profile within this valve has been designed such that in the event the valve bcomes inoperable, the valve can be mechanically locked open by wireline and a separate wireline retrievable sub- surface safety valve can be installed in the profile. The wireline retrievable valve is similar in design and will functior off the same hydraulic control line. The disadvantage of the smaller wireline retrievable subsurface safety valve is that it has a restricted internal profile and therefore must be pulled prior to performing any other wireline work such as reperforatin¢ pressure surveys, production logs or changing gas lift valves. During the production testing of the exploratory wells associated with Kuparuk River oil pool, bottom_ho~.le pressure information consistently indicated a high degree of "skin" damage or impediment to flow'in the near wellbore region. This phenomena has also been experienced in our developmental well tests. Varios measures are being taken in attempts to identify the source of and remove near wellbore damage in order to achieve better well flow efficiencies. These activities can be grouped~ as follows: Drilling fluid studies, perforating technique studie stimulation technique studies, and open hole completion tests. Varying types of mud sustems, including oil base, fresh water base, and salt water base muds have been tested in an attempt to identify which produced the minimum amount of skin R & R COURT REPORTERS 810 N STREET. SUITE IO1 E~O9 W. 3RD AVENUE IOO7 W. :~RD AVENUE 277-O572 - 277-O573 274-932''~ 272-7B15 ANCHORAGE. ALASKA 99501 AG0 10031727 10 11 12 13 14 15 16 17 18 2O 21 22 24 25 -34- damage. There are approximately twenty test points available to compare the effectiveness of these various mud systems. Present we are -- we are unable to draw even tentative conclusions since inspection of the data reveals that the numerical sampling is to small, and the results are too widespread to formulate any con- clusions on tke system which minimizes skin damage. We are currently using an oil base mud system for drilling Phase One development wells. However, high costs, safety concerns, and environmental liabilities associated with any oil base mud syste~ make this system less desirable than water base mud systems. Our efforts will continue in the future using various mud systems in order to come up with a system that does minimize skin damage near the wellbore. We have used both through tubing and casing type well perforators in Kuparuk River wells. Neither technique has resulted in consistent, unstimulated well flow efficiencies in excess of sixty percent. Plans are being made in using a tubing suspended perforating system whiCh will combine the advantages of both the through tubing and casing type perforators. Large perforating guns with deep penetrating charges are used below a packer with a net pressure differential into he wellbore to assure immediate flow into the well to clean perforations of cement and formation debris. In addition, the perforation den- sity will be increased to twelve perforations per foot, which should maximize the effective communication between the reservoiz R & R COURT REPORTERS 810 N STREET. SUITE ~OI 609 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O672 - 277-0673 274-9322 272-7B1~ ANCHORAGE. ALASKA 9BBO1 AGO 10031728 10 11 12 14 15 16 17 18 t9 2O 21 22 25 -35- and the wellbore. Development of an effective perforating tech- nique which would result in well flow effeciencies approaching eighty percent, would eliminate the need for immediate well stimulations. To date the only successful solution to the problem of skin damage has been to stimulate the well with a hydraulic fracture treatment. This type of stimulation is designed to provide a highly permeable flow path through~the damaged region. Well flow efficiencies greater than one hundred percent have bee~ achieved with fracture stimulations. Attempts to increase flow efficiency through acid type stimulations have been unsuccessful to date, and in fact have actually increased wellbore damage. Two Kuparuk wells have been production tested with open- hole completions in an attmept to determine if the skin damage typically observed in Kuparuk wells was introduced during the drilling operations, casing cementing operations and/or was a function of poor wellbore to formation communication.~ Both open hole tests still exhibited flow efficiencies below sixty percent. Subsequent -- subsequent to open-hole testing, liners were run and cemented in both wells and cased hole production tests were performed for comparison purposes. Please direct your attention now to Exhibit Four which illustrates the results oflthis work. In these tests well deliverability in the cased hold tests ranged from fifty to seventy percent of that previously observed in the open-hole tests. Based on these initial field observations we R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-0573 274-9322 272-7B15 ANCHORAGE. ALASKA 991~O1 AGO 10031729 10 11 12 13 14 15¸ 16 17 18 t9 20 21 22 23 24 25 -36- feel that open-hole completions may be a practical solution to maximizing well deliverabilities without high cost stimulations and that the open-hole completion option should be maintained as proposed in Field Rule Number Three. Our plans are to pursue additional field tests to further substantiate our preliminary findings. We recognize potential shortcomings of open-hole completions with our gas injection and waterflood plans. If vertical isolation ofthe different pay intervals is required in the future, liners could be set at that time. We have not observed any excessive sand production during open-hole tests and have had no problems in setting liners following these tests Accordingly, we do not anticipate that hole sloughing or sand production will present problems for extended production periods using open-hole completions. ARCO's Phase One development area is located approxi_ ma~ely twenty-six miles west of the Trans Alaska Pipeline System Pump Station Number One. I now direct your attention to Exhibit Five. As Mr. McMillian previously stated, the development.area encompasses twenty sections and will have five drill sites, Eac~ drill site with eight producing wells on three hundred and twent~ acre spacing~ one central production facility which I will refer to as the CPF, two to three gas injection wells near the CPF, and a twenty_seven mile sixteen-inch pipeline connecting the CPF wit~ TAPS Pump Station Number One~ The Phase One development plans for drill sites include R & R COURT REPORTERS 810 N STREET. SUITE lO! 1509 W. 3RD AVENUE IOO7 W. :~RD AVENUE 277-O572 - 277-O573 274-9322 272-751B ANCHORAGE, ALASKA 991501 AGO 10031730 10 11 19. 13 14 15 16 17 18 ~9 2O 9.1 22 23 25 -37- five pads, each with approximate--- each approximately eleven hundred and forty feet long and four hundred and ninety feet wide. A typical drill site layout is illustrated on Exhibit Six which I now show you. Each pad will initially contain eight producing wells on one hundred and twenty foot spacing. Each well after completion will be housed by an insulated wellhead shelter. From the wellhead, production and test flowlines are connected to two-phase production and test headers whiCh run the length of the pad. Compressed, dehydrated gas from the CPF is diverted from a similar header back to each wellhead shelter for artificial lift. This gas will also be used as fuel for the .drill site production heaters. Fluids from the production and test headers are routed in separate coils through this heater to improve the flow characteristics betweenthe drill site and CPF. All well control and data gathering functions at the drill sites will be performed manually with the exception of the well safety shut-in systems. The rate of crude production from each well and gas lift gas flowing to each well will be regulated by manually adjusted chokes. Normally, the flow from the eight wells -- eight wells flows to the production header and advances tothe CPF for processing. Any individual well may be routed to the test header for production tests at the CPF.. Normally, one well from each drill site will be set up to test at any given time, and its production will flow to the CPF via the test heade R & R COURT REPORTERS 810 N STREET. SUITI~' IOI 1509 W. 3RD AVENUE ~OO7 W. 3RD AVENUE 277-O572 - 277-0573 274-9322 272-7~1~ ANCHORAGE, ALASKA 99~O"1 AGO 10031731 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 25 -38- Separate production ~ test and gas lift lines are routed from each drill site to the CPF. These lines are supported above ground with a minimum ground clearance of five feet at the supports. The design of the support system is similar to the Prudhoe Bay Unit flowline designs. The CPF can be subdivided into three major types of facilities. All of them are located together in the Phase One area as previously shown -- shown on Exhibit Five. These sub- divisions are: oil and gas processing facilities, utilities, and support facilities. I will briefly describe for you the major components in each of these categories. I now direct your attention to Exhibit Seven, which is a simplified flow diagram of the oil and gas process at the CPF. The oil and gas process facilities include a single train process system. Production and test fluids will enter the CPF , through the individual production and test lines from~!~he five drill sites. At the CPF these streams will be combined into a large common production header or two test headers. The main production stream first enters a three-phase separator. The oil then proceeds through an electrostatic coalescer and a crude . surge drum, and is shipped to TAPS Pump Station Number One throu( the Kuparuk Pipeline. The test production streams enter one of two three-phase test separators. The separated fluids are dis_ tributed into the respective oil, gas and water lines downstream of the primary separator. Design throughput for the oil train R & R COURT REPORTERS 810 N STREET. SUITE fO! ~509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-O573 274-9322 272-715t~5 ANCHORAGE. ALASKA 99~01 AGO 10031732 rh 10 11 12 13 14 15 16 17 18 ~9 2O 9.1 25 _ 39- in the Phase One CPF is eighty thousand barrels per day of oil. Produced gas from the production and test separators is combined:.and enters the first stage of the primary compression system at fifty psia--- excuse m~, fifty psig. Low pressure gas evolved from the electrostatic coalescer and crude surge drum is compressed to fifty psi and is combined with the gas from the primary separator. After the first stage of compression to four hundred and twenty-five psi, the gas is dehydrated and facility fuel is taken from the main train. The remaining gas is then compressed in the second stage to fourteen hundred psi. The first stages of compression are accomplished with gas-turbine driven centrifugal compressors. Initially there will be two compression trains with a third on order for early 1983 start-up Artificial gas -- lift gas is returned to the drill sites at twelve hundred to thirteen hundred psi. Produced gas not requirt for artificial lift is compressed to four thousand psi with electrically driven reciprocating compressors, and is reinjected into the Kuparuk formation in the gas injection wells located at drill site "B". Produced water from the primary separator and two test separators is combined and sent to an accumulator. This water is then pumped into a disposal well located on the CPF pad. Initial water disposal capacity will be four thousand barrels per day. "The Phase One water handling capacity was kept minimal because very little water production is expected until a field r & R COURt REPORTERS STREET. SUITE IO! BO9 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-O573 274-9322 272-7EtB ANCHORAGE. ALASKA 991501 AGO 10031733 10 11 12 13 14 15 16 17 18 tg 2O 21 22 23 24 25 waterflood is installed. The system is, however, readily ex- pandable and large lines have already been installed to handle future water production. Two horizontal process safety flares are installed at the flare pit just south of the CPF. One flare is a spare and only one flare is in service at any given time. The two flares are installed at a sufficient distance apart to allow maintenance work on one flare while the second flare is in service. The insurvice flare is supplied with continuous pilot gas. Flare assist gas is available to accomplish smokeless flaring. Consis- tent with our proposed Field Rule Number Eight, flare volumes will not exceed pilot gas quantities other than in cases of emergency or operational necessity. The CPF utilities include a cirCulating process cooling system, waste heat recovery system on all turbines for normal process and building heat, a fourteen megawatt power plant, direct fired heater for backup heat, sewage treatment plant, a water treatment plant for supplying potable water, and a multi- channel microwave communication center These utilities are in place at this time with the exception of the waste heat recover5 systems on the turbines which will be installed later this year. Other support facilities includes a three hundred and fifty bed construction camp, ninety-six bed operations center three thousand foot airstrip with hanger and fueling station vehicle garage a warehouse, fabrication - and a fabrication r & R COURT REPORTERS 810 N STREET. SUITE 101 BO9 W. 3RD AVENUE 1007 W. :~RD AVENUE 277-O572 - 277-O573 274-9322 272-7151B ANCHORAGE. ALASKA 99~$O1 AGO 10031734 10 11 12 13 14 15 16 17 18 t9 2O 21 24 25 -41- shop. These facilities are in place at this time. ~ I now refer you to Exhibit Eight which indicates the route of the Kuparuk Pipeline between our development area and the Trans Alaska Pipeline System. The Kuparuk Pipeline system will consist of the booster and shipping pumps at the CPF, crude metering facilities at the CPF a twenty_seven mile long sixteen inch diameter pipeline connecting the CPF with TAPS Pump Station Number One, and power generation facilities at the CPF to run the booster and shipping pumps. This system is owned by Kuparuk Pipeline Company, a wholly owned subsidiary of the Atlantic Richfield Company. and will be operated by ARCO Alaska, Incor- porated as agents for Kuparuk Pipeline Company. The Kuparuk Pipeline system is being designed and constructed by ARCO Oil and Gas Company as the agents for the Kuparuk Pipeline Company. The pipeline has a working pressure rating of fourteen hundred and forty psig and design capacity of one hundred and ninety six thousand barrels per day with a single pump station operating at the maximum working pressure. Initial capacity of this system will be one hundred and twenty_five thousand barrels per day with a discharge pressure of seven hundred and twenty psi at the CPF. Additional pump capacity will be required to upgrade the system to design capacity. I show you now Exhibit Nine which is a simplified flow diagram of the Crude metering facilities to be located at the CPF.~ Three meters in parallel measure the crude oil flow with R & R COURT REPORTERS 810 N STREET. SUITE IO1 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-OB72 - 277-O573 274-9322 272-7Bt5 ANCHORAGE. ALASKA 99~01 AGO 10031735 10 11 12 13 14 15 16 17 18 ~9 2O 22 23 25 -42- the meter outputs going to a totalizing flow computer for cor- rected total flow rate and cummulative volumes. The metering system includes a fourth meter run which will be used to calibra~ meters from other locations in the CPF. A unidirectional meter prover is included in the metering skid. Kuparuk Pipeline throughput will also be measured as it arrives at TAPS Pump Station Number One. This measurement will be continuously compared to that of the oil leaving the CPF for leak detection purposes. Any significant discrepancy in the volume balance of the system will result in an alarm at the CPF. Previous speakers have mentioned various data will be required to monitor reservoir performance, define reservoir properties and provide the basis for effective reservoir manage- ment. I would like to outline for you our plans for obtaining this data. The information can be separated into three types~ bottom_hole pressure measurements, well testing, and production logs. Throughout the productive life of the reservoir, it will be important to obtain bottom-hole pressure information for prudnet reservoir management. All reservoir pressures will be reported at the common subsea datum elevation of sixty-two hundred feet. This elevation is the approximate average eleva- tion for the center 6f the oil productive Kuparuk River sands in the Kuparuk River oil pool. R & R COURT REPORTERS 810 N STREET. SUITE IO! 509 W, 3RD AVENUE IOO7 W, 3RD AVENUE 277-0572 - 277-0573 274-9322 272-751B ANCHORAGE. ALASKA 99501 AGO 10031736 I 10 11 12 13 15 16 17 18 t9 2O 21 22 23 25 -43- The initial static reservoir pressure will be measured in each well prior to continuous production by either performing a bottom-hole pressure bUildup test or simply measuring the bottc hole pressure after the well has been shut in for an extended period. After ninety to one hundred and eighty days of continuou production, the bottom'hole pressure will be determined in one key well on each lease block, which consists of four governmental sections. In the more distanct future, the bottom-hole pressure in the designated key wells will be measured on an annual basis as specified in proposed Field Rule Number Six. Additional periodic bottom_hole pressure measurements will also be required to examine unusual performance in individual wells. Accurate production data is a critical portion of any reservoir surveillance and management program. In accordance with proposed Field Rule Number Seven, production volumes from each well will3_be measured on a semi-annual basis under normal operating conditions to determine the producing gas-oil ratio. These tests will determine oil, gas, and water production rates, oil gravity, oil basic sediment and water content, gas lift volumes, ahd flowing temperature and pressure at the controlling choke. Additionally, more frequent well tests will be taken as required for proper production allocation and prudent reservoir surveillance and operational decisions. Production surveys are planned for all wellsi~with multiple pay intervals during the first year of production to R & R COURT REPORTERS 810 N STREET. SUITE 1OI EO9 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-O573 274-9322 272-7B1~ ANCHORAGE, ALASKA 991~O1 AGO 10031737 10 11 12 13 15 16 17 18 ~9 2O 21 23 25 -44- determine the contribution from the various Kuparuk sand members described in previous testimony. Subsequent surveys will be run in wells which exhibit rapid changes in oil production, gas-oil ratio or water-oil ratio, and in wells which have had remedial work performed to change the production profile. Mr. Chairman~and members of the Commission this con- cludes my prepared testimony today, and I believe Mr. Norgaard will now sun~arize the testimony. MR. HAMILTON: Thank you, Mr. Dayton. MR. NORGAARD: I thought the back was the safest place, that,s why I hid back there. . Mr. Chairman members of the Alaska Oil and Gas Conser- vation Commission, I am Paul Norgaard. I am a vice president of ARCO Alaska and manager of ARCO's North Slope District. The field rules proposed today officially establish the name of this new major oil accumulation as the Kuparuk River Field. Approval of these rules will insure that development practices ir this reservoir will be uniform and that conservation of natural resources will be upheld. These best engineering techniques and -_ and construction methods are currently being applied in the Kuparuk development and will minimize environmental impact and insure maximum efficient recovery of oil from -- and gas from the field. The proposed rules addressing casing and cementing, blowout prevention equipment and and automatic shut-in equipment R & R COURT REPORTERS 810 N STREET. SUITE 101 50g W. 3RD AVENUE 1007' W. 3RD AVENUE 277-0572 - 277-O573 274-9322 272-751ES ANCHORAGE. ALASKA 99501 AGO 10031738 10 11 12 13 15 16 17 18 t9 20 21 24 25 -45_ are needed to insure safe drilling completion and operation of the wells in the Kuparuk River Field. The bottom_hole pressure surveys and gas-oil ratio tests proposed will provide sufficient surveillance and data to manage the field to achieve maximum economic recovery of oil and gas consistent with sound engineeril practices. The well spacing proposed also provides for ecomomic recovery of oil and gas consistent with good conservation practices. Our testimony today and field rules request is based on our current knowledge of the Kuparuk oil accumlation. The development and knowledge.of the Kuparuk is in an early stage. Delineation drilling will continue over the next few years to further define the areal extent of the reservoir. Four wells are being drilled this wnter season to provide key data on which to cuild future plans. In this context, it is important to have a development plan that is flexible to accommodate a broad range ~.of eventualities. Our current expansion plans call for a staged development on the prospective two hundred and ten section -_ two hundred and ten square mile area shown on Exhibit Three-One. Two or three additional producing facilities are anticipated. These facilities will be similar to the central production facility described earlier. These stand-alone facilities will be capable of oil, gas and water separation, gas dehydration and compression and produce water handling. These facilities also will have the capability to treat and pump produced and source R & R COURT REPORTERS 810 N STREET. SUITE 1OI 509 W. 3FID AVENUE IOO7 W. 3RD AVENUF 277-0572 - 277-0573 274-9322 272-7515 ANCHORAGE. ALASKA 99SO1 AGO 100317B9 10 11 12 13 14 15 16 17 18 2O 21 22 24 25 -46- water for distribution to the drill sites for injection. Waterflood is envisioned as a key part of the expansion plan. We are currently working on the first increment of water- flood which will assess recovery, optimum well spacing and facility design. As stated earlier, a critical item of water- flooding is water source. Studies on this source will be com- pleted later this year. Waterflood development is planned to be staged following prior primary development of the field. The specifics of the development plan are contingent upon the results of current and future delineation work in the Kuparuk and our water source studies. Substantial modification of the expansion plan may be required as more well data becomes available both from delineation drilling and early production history and as other prospective working interest owners become involved. Today's testimony by ARCO ~laska reflects our interpre- tation of the existing data and our resulting action and plans. The proposed rules, however, incorporate input from. other -- othE interested owner company as ARCO Alaska is only one of several companies wi~h productive acreage in the Kuparuk River Field. On behalf of ARCO Alaska, I do thank you for the opportunity to testify, and we submit that the proposed rules are in the best interest of ~he State of Alaska. I thank you. MR. HAMILTON: Thank you, Mr. Norgaard. I think it might be appropriate now to take a little recess here and let' R & R COURT REPORTERS 810 N STREET. SUITE IOI 509 W. 3RD AVENUE 1OO7 W. ,~RD AVENUE 277-0572 - 277-0573 274-9322 272-7515 ANCHORAGE. ALASKA 991501 AGO 10031740 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -47 - use the clock on the wall and be back in say ten minutes at twenty-five ' til. (OFF THE RECORD) (ON THE RECORD) MR. HAMILTON: We will reconvene the hearing at this time. I would like to clarify a point before we start off with questions for the -- the applicant's panel here, but we had a sign-up sheet in the back of the room and we supposedly' were to have two sign-up sheets, those who wanted to wanted to testify and those who wanted to give -- make an oral statement, and we didn't differentiate between the two, so at this time I would like to read the names that are ~on the list and see who are prepared to give oral statements or testimony. And the first name is John Reader, and he's already indicated I believe that he's going to make an oral statement, is that right? MR. READER: Thatl, s right, Mr. Chairman. MR. HAMILTON: Let,s see, Wilma Zellerhoffer? MS. ZELLERHOFFER: I have no statement to make. MR. HA~ILTON. An oral statement.? MS. ZELLERHOFFER: No statement. MR. HAMILTON: Statement? MS. ZELLERHOFFER: No, neither. MR. HAMILTON: Neither, okay. Mr. Morrison with Chevron? MR. MORRISON: Well~ we may have a statement R & R COURT REPORTERS 8tO N STREET. SUITE 101 ROe W. 3RD AVENUE IOO7 W. ;3RD AVENUE 277-O572 - 277-0573 274-9322 272-7E15 ANCHORAGE. ALASKA 99BO1 AGO 10031741 10 1! 12 13 14 15 16 17 18 t9 2O 21 23 25 _48- later on depending upon what is said here today, but nothing in writing. MR. HAMILTOn: Okay. Mr ....... MR. KUGLER: I told that gentleman there that we would have a _- leave the hearing open for two weeks. MR. HAMILTON~ Oh, at least. MR. L~WENFELS~ Mr. Chairman, do you want to accept these into evidence before we have any questions? MR. HAMILTON: Yes. Okay. Mr. Williams? MR. WILLIAMS. Thank you, Mr. Chairman. Mr. Chairman, members of the Commission, for the record, individuals testimony referred to exhibits and the exhibits are numbered and will be presented to the clerk as numbered Roman Numeral One- dash_one for myself, Roman Numeral Two through Roman i~Numeral Five for Mr. James C. Merritt~ Roman Numeral Three through Roman Numeral Five for William H. McMillian, and Roman Numeral Five through -- One through Roman Numeral Five-dash-nine for John S. Dayton. At this time I am also presenting the rec_-n the hearin¢ clerk with a copy of the testimony along with a copy of the exhibits which were presented today on the screen. These exhibit are the same as presented on the screen , so I would move their adoption and admission by the Commission. MR. HAMILTON: They will be made part of the hearing. R & R COURT REPORTERS 810 N STREET. SUITE IOI 609 W. 3RD AVENUE IOO7 W. :~RD AVENUE 277-O572 - 277-0573 274-g322 272-7~1B ANCHORAGE. ALASKA g91501 AGO 10031742 10 11 12 15 16 17 18 ~9 2O 29. 23 25 -49- MR. WILLIAMS: They will, thank you~ Mr. Chairmai MR. HAMILTOn: Mr. Williams I presume the gentlemen sitting over to my left are the panel that you have here to answer our questions? MR. WILLIAMS: These are the witnesses who were sworn in, testified this morning. MR. HAMILTON: Okay. Thank you. Who wants to start? MR. KUGLER: I would like to ask Mr. Merritt a couple questions here. Your Exhibit Two-dash-two of the structu~ map .... MR. MERRITT: Um-hm. MR. KUGLER? ..... :~ on that map we have several dry hole symbols and we have a great deal of dots that I assume mean oil wells? MR. MERRITT. They were to imply that these were wells, or control points. On the _- on the maps that were shown - shown as Slides, the red -- the ones that were indicated red are control points, but the data is not Yet available to the public. The black dots were the data that was used to construct the maps as well as the dry hole symbol maps. MR. KUGLER: I see. On our exhibit then we do not have red dots and ..... MR. MERRITT. MR. KUGLER: That's right. That was ..... We have black dots. I believe maybe R & R COURT REPORTERS 810 N STREET. SUITE '10! 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE :277-0572 - 277-OI573 274-9322 272-7~1B ANCHORAGE, ALASKA 99B01 AGO 10031743 10 11 12 13 14 15 16 17 18 t9 20 21 22 25 -50- that that exhibit maybe be made -- made part of this record so we'll know red dots and black dots. MR. WILLIAMS~ We will see that ...... MR. MERRITT. Yes, MR. ,WILLIAMS~ ..... that is done. MR. KUGLER: Okay. Whether red or black, do all the dots indicate that a well head had been drilled? MR. MERRITT. Eighteen -- well, Sixteen and Eigh- teen, Sixteen is currently drilling and Eighteen is commencing to drill shortly. So to answer your question ~ no. Sixteen and Eighteen will be drilled probably by the time this ...... MR. KUGLER. Um-hm. MR. MERRITT: ..... becomes public. MR, KUGLER. So this map then, Eighteen for example indicateS a ...... MR. MERRITT. Eighteen was ...... MR. KUGLER: .... location? MR. MERRITT: ..... was stuck on there to indica~ that our -- it was a proposed location that we were going to be currently drilling ..... MR. KUGLER: Um-h~. MR. MERRITT: ..... this season. Again, it was color coded, and I thought I spelled ..... MR KUGLER. Thank you. MR. MERRITT ...... it out in the testimony~ but R & R COURT REPORTERS 810 N STREET. SUITE 1OI ~O9 W. 3RD AVENUE 1OO7 W. 3RD AVENUE 277-O572 - 277-O573 274-9322 272-7BI5 ANC~OR^~. A~AS~A ~eo. AGO 10031744 10 1! 12 13 14 15 16 17 18 t9 2O 21 23 25 -51- not -- not very obvious on this map. MR. KUGLER: No. MR. MERRITT: We'll correct that. MR. KUGLER: Let's move over to your Eileen faul In your cross section that went through the Eileen well over in the Prudhoe Bay Unit, as well as the Thirty-three,dash-twenty_ nine-E ..... MR. MERRITT: Um_hm. MR. KUGLER ...... it indicated that there was a fault between the wells and that you encountered the fault in the Thirty~,three-twenty-nine-E well below the Kuparuk River formatior MR. MERRITT: Yes, we -- we correlated that with nearby wells, and it appears that the ~fault penetrates that well just--- just immediately below the formation, whi~'h would put the Kuparuk completely downthrown with respect to the Northwest Eileen well. MR. KUGLER. Um-hmo MR. MERRITT: And also we have a control point, we believe that the Eileen -- the fault trunc_- or faults out the Kuparuk formation and the ARCO Highland State well, so there are two subsurface points of control on this Eileen fault. MR. KUGLER: Um_hm. And the throw on the fault ranges from a hundred and fifty to three hundred and fifty feet? MR. MERRITT: Yes, that is correct. MR KUGLER: And how much did it - was the thro~ R & R COURT REPORTERS 810 N STREET. SUITE lO! ~509 W. 3RD AVENUE IOO7 W. ~RD AVENUE 277-0572 - 277-O573 274-9322 272-7Bll5 ANCHORAGE, ALASKA 99501 AGO 100317~5 10 11 12 13 14 15 16 17 18 t9 2O 21 22 24 25 -52- here in the ..... ? MR. MERRITT: tn the Socal welll it's, about two hundred I believe. MR. KUGLER. About two hundred? MR. MERRITT: Yes. >; MR. KUGLER: So if it varied in the near vicinit] of the - the Socal Thirty~three-twenty-nine_E well. and in the Eileen well , there could be juxtaposition of the sands? MR. MERRITT. Yes, it's possible. MR KUGLER: Yeah. MR.. MERRITT: At the vari--- if the variation is that range. MR. KUGLER? Do you think there could be communi- cation of the reservoir in the Prudhoe Bay and this Kuparuk River area? MR. MERRITT. Well, the -- I do have another slide that would maybe illustrate it, but maybe if I could go through this to see if it explains it better. The upper sand and the middle sand of the Socal well, and that's Exhibit Two- four, was perforated and tested together, and there was oil recovered on a drill stem test. That lower -- the lower level perfs is approximately the same subsea depth or -- across the fault as a wet test in the lower sand in the Northwest Eileen well. So we had a water test at the same depth as oil production across the fault. So we believe that even if the sands may be r & R COURT REPORTERS 810 N STREET. SUITE 10! BOg W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272~TBIB ANCHORAGE. ALASKA 991~Of AGO 10031746 10 11 12 13 14 15 16 17 18 ~g 9,0 21 29, 23 9,4 25 -53- juxtaposition across that fault, we believe the fault is still sealing. length .... MR. KUGLERI Um-hm. At this point? MR. MERRITT: At this point. MR. KUGLERI You say it's sealing the entire MR. MERRITT: We hsve ...... MR. KUGLER~ ....... of the fault, north, south? MR. MERRITT~ Well, we _- we looked to the north toward the Kuparuk and the -_ the Kaviart Point wells, and the Milne Point wells~ that they have oil tests downdip from water tests in the Kuparuk. We feel that if -- if the Eileen fault is not a separator, then there's probably a series of faults betwen the Kuparuk Field and the other, Milne Point, Kaviart Point wells that separate those from the Kuparuk accumulation. MR. KUGLER: Um'hm. MR. MERRITT: Based on depth of oil tests versus water tests. MR. KUGLER: Okay. Well, let me re-ask a questio then and maybe I didn't catch the answer. Do you -- you're sayi that yes, there is communication between the Kuparuk--- Prud~oe Bay-Kuparuk River oil pool? MR. MERRIT~: No, I -- No, ...... MR. KUGLER~ ...... Or not? MR. MERRITT: No~ I believe it's-- there's R & R COURT REPORTERS ~,o ~ ~. ~m~ ,o, ~oo w. ~ ^w~u~ ,oo, w. ~= ^~ ~hO.^~. ^~$~ ~o~o, AGO 10031 747 10 11 13 14 15 16 17 18 t9 2O 21 22 9.5 -54- sealing. I believe the fault ..... MR. KUGLER: Ail is sealing and there ..... MR. MERRITT: Yes. MR. KUGLER: ..... is no communication? MR. MERRIT~'~ No communication. MR. KUGLER: Do you think the far west end of the Prudhoe Bay Unit then ~ought to be in this field? MR. MERRITT~. The far -- the upthrown side? MR. KUGLER: The acreage that is in the Prudhoe Bay Unit now that is separated from the Kuparuk River production in the Prudhoe Bay Unit should it be in this proposed KUparuk River field? MR. MERRITT: Well, because the fault does drift to the west as it goes down, and the fault -- the Prudhoe Bay boundary was established at -- at the location of-c~he fault with depth. We would have Kuparuk in the Prudhoe Bay in--- within the on the down turn strata at fault in the field rules area proposed for the Kuparuk River Field. Upthrown I believe should -- should remain within the Prudhoe Bay ~ield. MR. KUGLER~ Well, your proposed boundary is the same as the Prudhoe Bay Unit? ..... MR. MERRITT: Welt, -- Oh, yes,, . ..... - MR KUGLER ~ .... And (indiscernible) MR. MERRITT: .... okay. I'm sorry. MR KUGLER: Yeah. r & R COURT REPORTERS ~,,o N S','R~E','. S~,','~ ,0, ,~0~, ~,. ~R,~ A\,EN~ ,00~ W. ~R~ ^V~,U~ =~-o,~- =?~-o~ =~-~== ~='?~'~ AGO 10031748 ANCHORAGE. ALASKA 9915OI 10 ll 12 13 14 15 16 17 18 2O 21 22 24 -55- MR. MERRITT: Right. MR. KUGLER~ Now I'm talking about production east of that now ...... MR. MERRITT. Okay. We -- okay. We ...... MR. KUGLER ...... what might be possible. MR. MERRITT: ...... do not believe -- ~ight not we do not believe the Socal Thirty-two-t~enty-nine-E well will partici--- will -- will provide production for the Kuparuk field It does not appear to be a producible well. MR. KUGLER: Will it contribute? MR. MERRITT: We don't think so. We exclude tha~ from our development area at this time. 'MR. KUGLER: , Do you think a~mile west of there will contribute? MR. MERRITT: Well, it's hard to say at this point, we'll be drilling some more wells downdip from our Phase One area here shortly. MR.. KUGLER~ Alright. Still talking about Exhibit'~o-dash-two~ I:~-- and I am to understand that th~s is ~ simplified structure map and that there's a lot of faults in the~ that are not shown? MR. MERRITT. We do see a lot of faults on the seismic record particularly on the northeast flank where the dips are a little steeper. MR. KUGLER. Um-hm. R & R COURT REPORTERS 810 N STREET. SUITE ~01 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-OB73 274-9322 272-7151~ ANCHORAGE. ALASKA 991501 AGO 10031749 10 11 12 13 14 15 16 17 18 2O 21 9.3 9.4 25 -56- MR. ~ERRITT: These faults do not appear to be --well, they're quite varied as far as the displacement and the area that they, ll cover. They don't seem to go very far. We excluded them from this map to -- to keep the structure simpl and to try to best illustrate the aecumulation as we see it. MR. KUGLER: Do you find any faults that would compare with this fault that you have labelled the Eileen fault? MR. MERRITT: We see some faults with throws up to a hundred fifty feet on the seismic record. MR. KUGLER: Um_hm, MR. MERRITT:- And --- But it's difficult to tra these faults over more than a couple miles with any degree of certainty. MR, KUGLERo So you think they die out ...... ? MR. MERRITT: Yes. MR. KUGLER: And-- but the Eileen fault on your seismic continues? You don,t see it dying out? MR. MERRITT. It's -- we have pretty good eviden as it goes further on up to the north first our seismic data is kind of sparse across that fault. We don't have, you know, the magnitude of control like we do on the faults within the field. MR KUGLER~ Um-hm. MR. MERRITT: But we believe that it's there if not as illustrated, something very close to it or ...... MR. KUGLER. Yeah. Is ...... R & R COURT REPORTERS 810 N STREET. SUITE 10! 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-OB73 274-9322 272-7B1~ ANCHORAGE. ALASKA 991~O1 AGO 10031750 C=_ 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 -57- ME. MERRITT~ ..... some type of fault system that separates the (indiscernible due to coughing) point from Kuparuk ...... MR. KUGLER: Say in the Milne Point area is it -- could it have been shown by just a structural low there or .... ? MR. MERRITT: That,s a possibility, yes. Or another fault. MR. KUGLER: Another fault, not the Eileen? MR. MERRITT: Not the Eileen. MR. KUGLER: This might be ...... MR. MERRITT: One further norther. ~R. KUGLER. This might be a group of faults .... MR. MERRITT. Yes. MR. KUGLER: ..... and not a single fault? MR. MERRITT: Right. MR. KUGLER: That,s all.- MR HA~!ILTON~ I have a auestion MR. KUGLER. Okay· That's all I have right now. MR. H~ILTON~ Along the same questioning that Mr. Kugler was pursuing, the western limit that you show on you~ Exhibit Two for the proposed field rules, which follows the out- dine of the existing Prudhoe Bay Unit, do you see any reason why that,?couldn't as well follow the -- that fault trace (ph) of the Eileen fault? MR. MERRITT: No. that would be fine. R & R COURT REPORTERS 810 N STREET. SUITE 1OI 509 W. 3RD AVENUE 1OO7 W. 3RD AVENUE 277-O572 - 277-0573 274-9322 272-7~1~ ANCHORAGE. ALA.~KA 99BO1 AGO 10031751 10 1! 12 13 15 16 17 18 2O 9.1 22 23 25 -58- MR. HAMILTON. Is there any reason ..... MR. MERRITT~ I have no problem with that.- MR. HAMILTON: And the fault tract that you've shown on your Exhibit Two-dash_two, is there enough ~control and is this Exhibit accurate enough to -- to make a description of the western-- or the eastern of this field rules area if we decided to use the fault? MR. MERRITT: I believe there's enough control on it. It's been fairly well substantiated through the Prudhoe Bay Unit, and we do have some seismic control that supports the extension to the northwest. We feel pretty confident that's -- that,s a pretty good boundary. MR. HAMILTON: In your proposal, your applicatio~ I should say you propose the name for the field and the Kuparuk River Field and the name for~3;the pool of Kuparuk River oil pool In our regulations the naming fields and. ;.pools, an operator can propose more than one name. He can propose two alternates also. Do you have any other names that you'd like to propose as alternates or do you want to have just one? Give you your chance if you want to propose a different name there. (Laughter) MR. HAMILTON: Also in your proposed rules - or not in your rules themselves but in your testimony, you've been using a datum I believe of sixty-two hundred feet subsea for your pressu~e..survey -- survey work, and you did not have th r & R COURT REPORTERS 8tO N STREET. SUITE '10~1 509 W. 3RD AVENUE IOO7 W. ~RD AVENUE 277-0572 - 277-0573 274-9322 272-7BI5 ANCHORAGE. ALASKA 99501 AGO 10031752 .t 10 12 13 15 16 17 18 2O 21 22 25 datum mentioned in your proposed rules, and we often incorporate a datum in _- in the proposed rules. But do you have any ob- jection if ~'.;.incorporated that -- that datum in the proposed rules? MR. NORGAARD~ This is Paul Norgaard, and the answer'~is no. No objection. MR. KUGLER: I>.havesanother question of Mr. Merritt. What were proposed in here is to define an area over which a set of pool rules would apply. Do you think the Milne Point area that these rules would not be applicable there? MR. MERRITT: I believe they would be 'applicable there, but there -- again there's some information in that area that we do not have, so we would like to not to supply testimon, to bring that in at this time. MR. KUGLER, Well, if the -- the Commission in its wisdom it has this knowledge , it inlcuded tha~ would you find any disagreement with that? MR. MERRITT: No. No,,that would be fine. MR~~" KUGLER: And that would in-m-- the pool-- pool rules and the field would include that area, no problem there? MR. MERRITT. I have no problem with that. MRs HAMILTON: This is a general question that anyone who feels like answer .it, but in your testimony you mentio that your proposed field rules have incorporated input from othe r & R COURT REPORTERS 8tO N STREET. SUITE rOI 1~O9 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-01572 - 277-O573 274-9322 272-7BI5 ANCHORAGE. ALASKA ~)950! AGO 100B1753 ~ed 10 1! 12 13 14 15 16 17 18 ~9 2O 21 22 23 25 -60- working interest owners,in the proposed field rules area, would care to name who~ thase other working interest owners were or -- or;~.no%? MR. NORGAARD. I don.t think we have any problem in indicating who they are. Who -- who here can -- this is Paul Norgaard again. Who _- who can best answer that? MR. MERRITT: Well, we -- we supplied input from Sohio and BP, or BP mainly. That's =- that was the bulk,of the input. MR. NORGAARD: Who was made aware or who sent -- who _- who were -- was provided copies of our __ our testi- mony beyond.Sohio -'and BP that we know? MR. HAMILTON: okay. MR. KUGLER~ Would there be any other interest owners in the field ...... MR. WILLIAMS. Mr. Chairman, I believe there ... MR. KUGLER? ... Or in the proposed field? MR. WILLIAMS ..... I believe there are t~o separate questions there. I believe that other working interest owners, Sohio BP, Conoco and Mobil'.~ were supplied copies of the proposed rules, and I belie~e.:that -- and EXXON, and SOHIO-B] I believe was suppl~ed with copies of the testimony. MR. HAMILTON: Okay. Thank you, Mr. Williams. MR. KUGLER. Well' I had the question in the proposed area of the field rules, are there any other interest R & R COURT REPORTERS 8~o N STREET. SUITE ~0~ ~09 W. 3RD AVENUE I007 W. :~RD AVENUE 277-O572 - 277-01573 274-9322 272-7B1~ ANCHORAGE. ALA.~KA 99~O1 AGO 10031754 l0 ll 12 13 15 16 17 18 20 21 22 23 24 25 owners other than these? MR. NORGAARD. I'm sure there's several. MR. WILLIAMS: Everybody within the proposed fie] rules area was covered. · MR. NORGAARD; Was contacted. MR. WILLIAMS. With the proposed rules. MR. KUGLER: I see. Okay. Well, for right now I don~t have any more on the ~- the geological end of it. I think we want to move onto the engineering? MR. HAMILTON: Why don,t we move -- I have some questions regarding your -- your suveillance proposals. We might get into that area for now. In reviewing your proposed rules for surveillance, I know they're _-- (Off record discussion) MR. HAMILTON: You're proposing to take transient surveys on each well within the firs~ six months of production. Or pardon me. Excuse me. One well on each lease of four govern- ment sections, ninety to a hundred days after start up. And it seems to me ~o be kind of a large area with not enough density of surveys initially to start off in initial stages of productior of the field. I know Prudhoe Bay we started with a more dense survey program and then relaxed that as we started acquiring data. Would you have any objections if -_ if the Commission made a little heavier density for these transient surveys~ initially then ..... ? R & R COURT REPORTERS 810 N STREET. SUITE IOI 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0[";72 - 277-0573 274-9322 272-TBIB ANCHORAGE. ALASKA 99BO'1 AGO 10031755 10 1! 12 15 14 15 16 17 18 t9 2O 21 22 25 -62- MR. DAYTON: Well, I think -- I think the testim¢ actually states that we will take the static bottom-hole pressure in every well prior to commencing production. MR. HAMILTON: That,s right. MR. DAYTON: Okay. !And then we would _- they would - as production commences and we go on, we would identify the - the key wells as we call them which would be the one well per four governmenal sections. I believe the proposed rules shows that we will identify the key well within the first year to production. '~R. }[AMILTON: Yeah, that's correct. That's what you're proposing. I'm saying, for the key well program that maybe every four governmental sections is a little larger spacing than we would like to have initially in that area. MR. NORGAARD. ThiS is Paul Norgaard again. I think the thinking that we have with respect to surveys, as com_ pared to Prudhoe if you will, is that originally we will be looking at a natural depletion system rather than a system where _- where we .... we are having gas cap or aquifer energy ~ph) , and therefore the need for the density in the surveys from a reservoi engineering point, which is basically what we're looking for, does not exist. It's -- it's very __ it's a very different mechanism and thereforec a very different nee~ in our eyes. That's -- that,s the reason for our requesting the rule. MR. HAMILTON: We _-. we certainly recognize too R & R COURT REPORTERS 810 N STREET. SUITE 1OI 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-O573 274-9:322 272-7ESlE ANCHORAGE, ALASKA 99B01 AGO 10031756 ny 10 1! 12 13 14 15 16 17 18 2O 21 22 25 -63_ that you -- you're not working with another Prudhoe Bay Field over here, and we don't want to saddle you with probably as much data acqnisition as we have at Prudhoe. I don't think it's : necessary either, but we may in our final order come out with something a little more dense than you,ve submitted as proposed rules. But we'll consider what you've submitted here. Another thing:% you mentioned that you're going to submit this information that -_ that you're acquiring on your pressure survey work by the fifteenth of the month following the time that you've acquired the data~ and we found with Prudhoe Bay that that didn't work too well. That didn't give the operator enough time to get that data cmmpiled and get it into our hands, and we had to grant an extension. In fact we've changed that pool rule to allow thirty days following the acquisition of the data. Now are you sure you want to go with the fifteen or .... ? MR. DAYTON: We would certainly be ammenable to thirty. (Laughter) MR. HAMILTON. We don't want to get in the posit~ where you're starting to be in violation of our pool order or pool rule and we want something that isworkable. That's all the questions I have along that line right now. Ron, do you have? ..... MR. SMITH: Yes. This is Lonnie Smith. I have some questions for Mr. McMillian. You stated that -- at the end r & R COURT REPORTERS 810 N STREET. SUITE 1OI 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 27?'-0572 - 277-0573 274-9322 272-75t5 ANCHORAGE. ALASKA 99501 AGO 10031757 on 10 1! 12 13 15 16 17 18 t9 20 22 23 25 -64- of the first paragraph on page two of your testimony that there was considerable - ~there is considerable uncertainty in pickii net pay," will you please recount what these uncertainties con_ sist of? MR. MCMILLIAN: This is Bill McMillian. The undertaint~es Ghat we see at the present time have to do ~ith the water __ water saturation uncertainty that I have detailed in my testimony regarding using electrical logs for water satura- tion, and this is part of that predetermination~ two, determina- tion of porosity from logs appears to be a matter for some subjective interPretation also because of the presence of mineral other than quartz, mainly glauconite -- glauconite and heavy mineralS like siderite or perhaps even some pYrite. Interpreta- tion of the density log for example, the neutron log and perhaps eVen the sonic log is -- is very difficult for porosity., In addition because permeability varies with grain size and the grain size distribution changes are very subtle in the Kuparuk, we found that.it:'~is quite difficult at this time to look at a set of logs and make a specific determination of pay.on the basis of porosity cut-off for example. MR. SMITH: Okay. Then I'm to understand that this is the -- these, are'.~.~he main reasons probably for the uncertainty and the -- the variation in recoveries from this reservoir and the low recovery of eight percent? MR. McMILLIAN? No, sir. The uncertainty in R & R COURT REPORTERS 810 N STREET. SUITE 101 ~O9 W. 3RD AVENUE 1OO7 W. 3RD AVENUE 277-OB72 - 277-0573 274-9322 272-7~1B ANC"ORAGE. ALASKA ~O' AGO 10031758 10 11 12 13 14 15 16 17 18 20 21 22 23 25 _65- recovery is really independent of the oil in place uncertainty. As I perceive it, uncertainty in recovery is due to a number of things, principally critical gas saturation is an uncertainty, we have no extended production history, and then in our phase one area as I stated in testimony~; the uncertainty with which we assess break through of injected gas also adds to the ambi- guity and recovery factor. MR. SMITH. Now is the ..... MR. DAYTON: I might -- I might add also that whether or not the aquifer is active would have another profound impact on recovery factor on your primary depletion. MR. SMITH: Bill, on the -- again on the recover~ how do th~e-_- how do these recoveries of this eight~to fourteen percent that you project compare with other solution and gas drive reservoirs recoveries? MR. DAYTON: Are you ...... MR' SMITH: Low, high,~?a~erage? MR. DAYTON: For other solution gas drive reservoi in the Aower 48 .with which I'm familiar, these are probably low. ~ I think the reasons for this, maybe the primary reason would be ~; the abandonment rate. A hundred barrel ~ac day abandonment rate due to the conditions on the North Slope would be considered extremely high for depletion reservior anywhere else in the MR. HAMILTON: I have a point of clarification. United States. r & R COURT REPORTERS 8lO N STREET. SUITE 1OI 509 W. 3RD AVENUE 1OO7 W. 3RD AVENUE 277-O572 - 277-0573 274-9322 272-7~15 ANCHORAGE, ALASKA 99501 AGO 10031759 CS 10 1! 12 13 14 15 16 18 2O 21 22 25 -66- MR. SMITH: Go ahead. MR. HAMILTON: Just a point of clarification. The eight to fourteen percent recovery that you've testified, you would be estimating for that reservoir, that--now that just is primary recovery solution gas drive? MR. McMILLIAN: Yes, sir. And it corresponds to my Exhibit Five which shows pressure depletion throughout the life of the project. MR. HAMILTON: If your waterflooding test are planned (indiscernible due to coughing) your early experience you gained from your waterflooding that you're going to propose down the road is Successful, then you could possibly improve those recoveries from that eight to fourteen percent? MR. McMILLIAN: We expect to improve it, yes, sir. MR. HAMILTON: Fine. One more question, back on the -- this -- your surveillance testimony, and I think this is probably Mr. Dayton's -- could field this question, you mentioned in your testimony that you were going to run productiol logs and you planned them for oil wells with multiple pay inter- vals during the first year of production, and then on subsequent surveys on wells that exhibited rapid changes in -- in their production characteristics, we would probably like to see some- thing like this written in the -- the pool rules, and you did not propose anything of that nature in the pool rules, but do yo R & R COURT REPORTERS 810 N STREET. SUITE 10! 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-751~ AGO 10031760 ANCHORAGE. ALASKA 99501 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 25 -67- see any objection if we'd write something like that in here to require that information as you obtain it on that basis? MR. DAYTON: No, we do not propose a pool rule in those -- in that light, but I think we would be ammenable to a program such as outlined in the testimony. MR. HAMILTON: Because we probably will write something like that in the pool rules. MR. SMITH: I had a couple of questions for Mr. Van Dusen from his testimony. Pete, when you referred to, let's see, it's on page three, did I understand you correctly there that you testified that you -- you want to delete the section (1). You -- you submitted, a section (1) in the propose~ rule, but you -- but you're recommending deletion of that? . I'm not quite with you there on the ..... MR. VAN DUSEN: The ..... MR. SMITH: It's page three of ,,,,, MR. VAN DUSEN: Section (1) dealt with a very special case where a producing formation would occur immediately under the surface pipe, very shallow in other words. It also dealt with the fact that there was a zone which we could set the surface pipe, five hundred feet below the permafrost to twenty- seven hundred feed TBD. Should the -- should the producing zone occur immediately below the surface pipe, and the pipe had been set at twenty-two hundred feet, then there was a conflict by having five hundred feet of cement on top of that according R & R COURT REPORTERS 8,0 N S~R~ET. SU,TE ,O, ~O~ W. 3.D AVENUE ,007 W. 3RD ^W.UE =7~-o~7= - =~7-o~73 =~-e~== ~7=-7~,~ AGO 10031761 ANCHORAGE. ALASKA 99~OI 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -68- to the casing cementing regulations, and also being able to put a nonfreezing fluid in the annualist, the two strings of pipe. In our earlier testimony we had tried to cover this one special case and it's a very rare case, and we realized upon review that if that ever did occur and it may never, that it would be better just to request a conservation order, a special conservation order, rather than have it written into th( field rules. We felt it was very confusing and it would probabl never occur, but if it did it would be better to come back on a permanent basis and request a conservation order exception. MR. SMITH: Okay. Pete, where I think I'm confused, you said in your earlier testimony you proposed this, was that pre-- presubmittals to these rules, is that what you're ....... MR. VAN DUSEN: I believe Rule --Rule Three as you have it before you has section (1) in it, and we're asking that we just delete that from the~rule ...... MR. SMITH: Okay. MR. VAN DUSEN: .... we've got before you. MR. HAMILTON: Mr. Dayton, I had one more questio dating back on ~his surveillance proposal again. In your Rule Six that you're proposing regarding bottom-hole pressure surveys it seems to be very similar to what we've written before in other pools, particularly over at Prudhoe, and in there it calls for a twenty-four hour shut in to get your build up test and I R & R COURT REPORTERS 810 N STREET. SUITE 'O' 309 W. 3RD AVENUE IOO7 W. 3RD AVENUE =77-o~,= - =7~-o~,3 =74-~2= 27=-7~,~ AGO 10031762 ANCHORAGE, ALASKA 99505 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -69- was just wondering, from the pressure information you've seen over in the Kuparuk River area, do you think twenty-four hours is adequate to obtain the -- the best information? MR. DAYTON: This is Mr. Dayton. Most of our tests which we have performed to date exhibit that we can get to the straight line portion of the curve where we can extrapolat~ to a bottom-hole pressure within approximately twelve hours. MR. HAMILTON: I see. MR. DAYTON: So twenty-four hours should be very sufficient. MR. HAMILTON: Okay. Thank you. MR. SMITH: For Mr. Van Dusen, would you please be more specific as to why you desire to maintain a maximum casing setting point of twenty-seven hundred feet when approxi~~ mately twenty-one hundred feet would be adequate in this area where the permafrost is only about sixteen hundred feet thick? MR. VAN DUSEN: Primarily the main reason is for our directional control, setting the casing too shallow often- times means that in these highly directional wells that approac fifty-five and sixty degrees by the time we have reached, the bottom of the surface pipe, causes us to have to drill out in a much softer formation. By putting the pipe down deeper allows us to extend the directional hole out further and still reach a TVD where the shale strata has good substance to us --to it and the directional driller doesn't have problems. One-- one exampl, R & R COURT REPORTERS 810 N STREET. SUITE I0! 509 W, 3RD AVENUE IOO7 W. ::3RD AVENUE 277-O{572 - 277-O573 274-9322 272-7815 ANCHORAGE. ALASKA 99501 AGO 10031763 10 11 15 17 18 tg 2O 9,2 9,3 -70- is is that it is a tendency if the pipe is set too shallow that the angle of the hole will fall off very dramatically coming out of the surface pipe. But by having the pipes at a little bit deeper, having a little bit more of a straight section from the -- the final generation of the angle to the deeper setting point, we're able to drill that well without the angle falling off drastically and continue it down a hole. Well, that extra three or four hundred feet is very important actually. MR. SMITH: Okay. Did I understand you to say that in -- that also it's -- there's less competent zones at the higher elevation for setting the casing? MR. VAN DUSEN: Yes, I believe so. You come out of your gravels in the permafrost, I believe the zones just below that and before you hit the more firm shales are-- are a little less competent. MR. SMITH: Would you care to comment on whether or not the shorter set -- the -- the shallower set casing, say at twenty-one hundred feet versus the twenty-seven hundred feet setting point, what relative difference there might be in the ability to circulate cement and get the -- either better or poorer cement jobs one versus the other? MR. VAN DUSEN: Well, the deeper -- the deeper you set your casing, of course, you reach a point -- you reach an ultimate point where it's difficult to circulate to the sur- face, but our experience in Kuparuk as well as Prudhoe is 'is tha R & R COURT REPORTERS ANChOR^GE. ^L^SK^ ~O, AGO % 10 11 12 13 15 16 17 18 2O 21 22 23 -71- at twenty-seven hundred feet TVD it is very rare that we lose circulation because of a formation that will accept fluid. We -- we can circulate all of the heavier permafrosts and Arctic set cements and also the lighter fondue (ph) cements that we use to the surface without a problem. I don't believe that tha~ a problem there. MR. SMITH: Well, you -- I had another question here having to do with the -- you-- one of your quotes -- I would quote that you mentioned one of the reasons was for your complex directional programs, and I suppose you've just -- have you fully addressed that, 'cause the complex directional programs are for what reason? MR. VAN DUSEN: The spacing of the pads and the development of the field requires that we reach out a certain given distance requiringthat some of our wells are as high in the fifty degree range and to reach bottom-hole locations. So we are -- there-- there is an economic break even point in the present forty section -- twenty section development with the five pads that requires some of our wells be high angled. MR. SMITH: Okay. You have -- well, you might mention -- have -- that some of the alternatives you may have looked at to get to this economic Point of those five pads. What would be some of the alternatives that maybe you have explored, or have you? I -- Well, have you looked at -- I mean against or padding (ph)? R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7~15 ANCHORAGE, ALASKA 995Ot 's AGO 10031765 10 11 12 13 15 16 17 18 t9 2O 21 22 23 25 -72- MR. NORGAARD: This-- this is Paul Norgaard. Mt -- let me take that question. I think I -- I have a broadez perspective of -- of the ±otal than-- than any of the people here right now. I think one of the -- when we're looking at the angles that we're going to drill and the safety of the pads, that's an economic -- economic question without a doubt. It's also an environmental question. And therefore we have a tendency to space the pads, the drilling pads as far apart as we can, which gets Pete into his -- his angles. The further apart they are, the fewer there will be, and therefore the less the environ- mental impact on the area. And -- And that is something that we watch very closely. Of course, we watch economics as well, and we do reach a break point where you -- you just can't kick the wells out to -- to like you do in Huntington Beach, to a ninety degree or -- or an eighty degree angle on the Slope. You reach a break point so -- and that's what we're -- we're struggling with. So it's both an ecnomic and an environment. And it's a trade-off of the -- when you get to an economic, it's a trade-off of drilling costs versus gravel costs versus flowline costs, and that's the kind of economic study that's done. Does that answer your question? MR. SMITH: Yes. Have you explored an alternati~ such as slant hole drilling rather than -- versus a kick-off type directional hole? R & R COURT REPORTERS 8lO N STREET. SUITE '10! 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7BIB ANCHORAGE. ALASKA 99501 AGO 10031766 10 11 12 13 15 16 17 18 ~9 2O 21 25 -73- MR. NORGAARD: Well, Slant -- again Paul Norgaaz Slant-hole drilling are used, indicating there where you'd actually tip the rig in an angle as you -- as you start drilling? MR. SMITH: Yes. MR. NORGAARD: On the North Slope? (Laughter) MR. NORGAARD: With fifty knot winds? MR. SMITH: Well, I'm just asking the question. MR. NORGAARD: I think I've answered it. MR. SMITH: Okay. With regard to cement jobs on the conductor, Pete, you might elaborate if you can on -- if you -- I know the -- the rule that you're proposing is similar to what we've done in the past, require circulation of the cement. Have you had any difficulty getting circulation of %he cement and in place--- and proper placement on the conductor pad? MR. VAN DUSEN: You're saying the conductor pipe, are you referring to the surface pipe or the conductor pipe? MR. SMITH: The conductor pipe. MR. VAN DUSEN: I -- I believe the rules now read that you fill that anulus with cement, it doesn't require that you Circulate cement in the conductor pipe anulus. MR. SMITH: Okay. And -- but you have had --- R & R COURT REPORTERS 810 N STREET. SUITE IO, 509 W. 3RD AVENUE IOO7 W. ~RD AVENUE 277-OB72 - 277-0573 274-9322 272-7815 ANCHORAGE. ALASKA 99~O1 AGO 10031 767 10 11 12 13 15 16 17 20 21 22 23 -74- Have you done anything special, or are you doing anything diffe- rent than what you have been doing? MR. VAN DUSEN: Well, yes, you're aware that we have tried a few new conductor pipe cementing techniques out in the Kuparuk whereby we have circulated cement to the sur- face by placing two pipes down the conductor pipe, which is set at about eighty feet, and then pumping the cement down those small pipes and allowing it to circulate to the surface, that would be one thing that we have tried on the most recent seapad wells. tent results? MR. SMITH: Does this appear to give more consis MR. VAN DUSEN: It's hard. to say. We -- there are several techniques used in both Prudhoe and Kuparuk, but properly done, I believe either technique is -- is acceptable. Either circulating cement to the surface, or allowing cement to fall from the surface to the bottom in the conductor hole. Both have been successfully used throughout the North Slope. MR. SMITH: Now I have a question for Mr. Dayton On the -- your proposed gas lift system, is this to be a closed system? For instance, I mean, will there be necessary to vent or flaring of gas due to use of this gas for gas lift purposes? MR. DAYTON: No, sir, not under normal circum- stances. MR. HAMILTON: You are proposing though to have R & R COURT REPORTERS 810 N STREET. SUITE 10! BOIB W. 3RD AVENUE IOO7 W, 3RD AVENUE 277-0572 - 277-0573 274-9322 272-TBIB ANCHORAGE. ALASKA 991~O1 AG0 10031 768 10 11 12 13 15 16 17 18 2O 22 25 -75- a -- a safety flare as I understand, was that .... ? MR. DAYTON: Yes, we are. Yes, we are. MR. HAMILTON: At this time do you know what volumes of gas you will need for that safety flare? MR. DAYTON: Normally our pilot requirements would range from a hundred and fifty to two hundred and fifty MCFD. MR. SMITH: Okay. Mr. Dayton, you stated that there are no safety advantages to setting the SSS valve below the permafrost. If you assume the possibility of freezable fluid being somehow trapped in the tubing or the tubing anulist how soon could a permafrost freezeback occur following, one, the drilling and completion operation, or, two, say six months or a year production operation? MR. DAYTON: Okay. This is Mr. Dayton. Our studies done by our computer analysis of thermal models do indi- cate that after the drilling of a well, it would normally requir four to five days to achieve freezeback, and that thaw bog (ph) would expand with time as we bring more heat from the Kuparuk formation and the times required for freeze back on --- at depths such as that would be in excess of four days, five days. As you come closer to the surface, that freeze-back time does decrease. MR. SMITH: Well, if the SSS valve is set only five hundred feet from the ground surface and. within the perma- R & R COURT REPORTERS 810 N STREET. SUITE lO1 EO9 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-OE73 274-9322 272-751E ANCHORAGE. ALASKA 9960' AGO 10031769 10 11 12 13 14 15 16 17 18 t9 2O 21 23 25 -76- frost zone, could freezeback collapse or burst the tubing below the SSSV? MR. DAYTON: I can't really answer that com- pletely. I would think that -- that it would be possible after a long extended shut-in period if you had a noncompressible fluid such as water, which would expand upon freezing. MR. SMITH: So a possible additional parameter here might be the -- the shut-down time of the well at any point after the safety valve is set, due to the length -- to guard against some -- for instance, in the early stage here, right now you're drilling, perforating, completing wells, puttir a safety valve in there, and then maybe have a long extended shut-down period. It's, of course, the real key to it is havin~ no freezable fluids in there and ...... MR. DAYTON: During the early stages we would expect that-- that we would have extremely small amounte~of wate within a produced fluid stream. MR. NORGAARD: Can I respond to that? MR. SMITH: Yes. MR. NORGAARD: This is Paul Norgaard, Lonnie. I -- With respect to your question, could you wind up with~'~he tubing actually breaking? We did have some freezeback early in -- in Prudhoe, and I don't recall an instance when the tubing actually broke. It was squashed, it was damaged, but I don't recall it ever actually losing its integrity. We went in and --- R & R COURT REPORTERS 8,O N STREET. SUITE ,OI 509 W. 3RD AVENUE ,OO7 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7B1~ ^NCHOR^~E. ^L^SK^ ~,o, AGO 10031 770 10 11 12 13 14 15 16 17 18 2O 21 22 24 25 -77- and sludged them out so the tubing itself has quite a bit of capability to withstand any actually splitting action. As far as what it would take in order for this freezeback to occur, obviously there's -- there's always an opportunity for almost anything in an oil operation, and I would never say that it couldn't happen, but the practices and the'techniques that have been used and are being used. leave it extremely remote. It -- it would take a serious of very strange events to wind up leavim freezable fluids within the-- the area where it would impact a safety valve. MR.. SMITH: Thank you. MR. HAMILTON: Well, you are proposing to say set your safety valve approximately five hundred feet depth. If it were -- if it was required to set that valve at a deeper depth, would you have any problems with your well that you've kicked off at a shallow depth, running that safety valve down through the ...... MR. NORGAARD: Could -- could I ....... MR. HAMILTON: .... drop (ph) point? MR. NORGAARD: Could I defer that question for just one moment and say something that I should have said before Again, this is Paul Norgaard. MR. HAMILTON: Certainly. MR. NORGAARD: When we went back into the Prudho wells that-- that had collapsed., we would have been much better R & R COURT REPORTERS ~,o N S~REE~. SU,~E ,O, ~O~ ~.~R~ A~.~E ,OO~ w. ~RO =~-o~= - =~-o~ =~-~== =~=-~'" AGO 10031771 ANCHORAGE. ALASKA 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 25 -78- off if the safety valve had been above the collapse rather than below the collapse. Having the safety below the collapse made it very difficult for us to go in and repair the damage, having a -- a safety valve under -- underneath. If the safety valve had been above, at five hundred feet, then we could have retrieved the safety valve, we could have gone ahead and repaire the wells much simpler, much cleaner and much safer. That was one of the -- the major problems we had in repairing the well, so with the direction that yoU're -- you're talking about, Lonni I think if that were to happen, the world and we and Alaska woul be better served with the safety valve at five hundred feet. There are others who can speak more intelligently on this than I. I don't know if they're in the room., but -- but who were present when we were-- we were attempting to correct the -- the freezeback problem. Excuse me. MR. HAMILTON: Okay. My question is, if -- if you're kicking some of these wells off as shallow as five hun- dred feet and you've got the -- the well bore already deviated, do you have operational problems runing that down-hole safety valve down below that"deviation point? Say if the requirement was like Prudhoe Bay where you had to set them down below the permafrost? MR. DAYTON: This is Mr. Dayton. The-- Many of the wells, or the wells we have drilled to date and run pipe in do have the safety valves down below the permafrost level at r & R COURT REPORTERS 810 N STREET. SUITE IOI BOg W, 3RD AVENUE 1OO7 W. 3RD AVENUE 277-O572 - 277-OES73 274-g322 272-TBIB ANCHORAGE, ALASKA 995Ol AGO 10031772 e i 10 11 12 13 15 16 17 18 2O 21 22 25 i ii -79- this point. To date we have not experienced too many problems, but we are very early, we haven't really had to work with these things very much to this point, and we feel that moving them up into the straighter portion of the hole would just increase the odds that this thing's.~going to work, and it's going to make it that much more reliable, and the more reliable it is, the safer it's going to be. MR. HAMILTON: Thank you. MR. SMITH: How many wells do you anticipate kicking off as shallow as five hundred feet or say above six- teen hundred feet? MR. VAN DUSEN: TheY"re almost all kicked off~-- This is Van--- Pete Van Dusen, almost all wells are kicked off at fifteen hundred feet or shallower and none have been kicked off above five hundred feet. Five hundred feet is our shallowes kick-off point at this time. MR. SMITH: Okay. MR. HAMILTON: I have a few general questions, and whoever choses to field these, just go ahead, but -- How is the construction of your oil line going and what are your plans now for your initial start Up later? MR. NORGAARD: This -- this is Paul Norgaard. We're having problems. We wouldn't be in'the Oil business if we didn't have problems. 'Our start-up is still targeted to be - to be the same. It would towards the end of the first quarter R & R COURT REPORTERS 8tO N STREET. SUITE 10! BO9 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-O573 274-9322 272-751~ 00~177 3 ANCHORAGE. ALASKA 99~O1 ~G0 1 10 11 19. 13 14 15 16 17 18 20 21 22 23 25 -80- of '82. But we are having problems with material deliveries for the Kuparuk Pipeline. We had some heavy seas and had some difficulty getting equipment from Japan that we need, and we're looking at alternate options, and-- but start-up is still prograr to be the same. We don't see anything-- anything that will pre- clude starting up in the first quarter. MR. HAMILTON: Maybe, Mr. Norgaard, you can answE this question, too. Will the custody transfer point for the State's royalty oil be at the -- the inlet to your Kuparuk Pipe- line? ,'.. MR. NORGAARD: I see some heads out there shakin¢ yes. I believe the answer to that is yes, and -- and the reason I believe it has to be is because it is a common carrier and we anti"- anticipate other crudes to be entering that pipeline with time other than Kuparuk. MR. ~AMILTON: Okay. Thank ~ou. MR. SMITH: Mr. Dayton, you mentioned the phrase "safety concerns" having to do with -- associated with the oil- base mud systems. Would you elaborate on that some? MR. DAYTON: This is Mr. Dayton. Mr. Van Dusen may be able to elaborate on that a little bit more, but there'.s there's certainly some safety considerations associated with having a large pit full of a volitile substance around a rig where some of it -- there's always a potential for a spill and there is some running machinery there, some engines in the r & R COURT REPORTERS 810 N STREET. SUITE 10! E~O9 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7BIB ANCHORAGE. ALASKA 99501 AGO 10031774 .ed 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -81- vicinity which could act as an ignition for it. MR. VAN DUSEN: This -- this is Pete Van Dusen. I'll broaden out on that just a bit here. It's more of a relati' thing than anything. Properly handled on the rig, oil phase and oil based fluids are used universally, and all--- almost entirel~ safely as far as I know. However, you -- you have to recognize that water base fluid is completely safe whereas the oil base fluid does have the-- the basic oil parts in it. MR. SMITH: But it is my understanding generall~ that oil base mud won't just burn per se like oil would burn? It ..... MR. VAN DUSEN: No, sir, that's correct. MR. SMITH: It inhibits itself. MR. VAN DUSEN: In all of the areas of the rig that handle this type of mud, regardless of whether it's oil bas( or water base are all class one, division one wired where there are no open sparks, lighting, wiring, everything. There are no motors in contact with oil base systems. The engines and that portion of the rig, the power portion of the rig is all separate( off by pressurized modules that-- that won't allow oil base muds vapors or anything within that area. MR. SMITH: Okay. MR. HAMILTON: Mr. McMillian, you mentioned that you were considering both the . upper Cretaceous and the Beauf¢ Sea as possible source water for your waterflood. Have you R & R COURT REPORTERS 810 N STREET. .~UITE rOI 1509 W. 3RD AVENUE 1OO7 W. 3RD AVENUE 277-O572 - 277-O573 274-9322 272-7BII5 ANCHORAGE. ALASKA 99B01 AGO 10031775 rt 10 1! 12 15 16 17 18 t9 9.0 21 23 25 -82- considered that either or both would be suitable as far as compatible with the formation out there? Have you made those determinations yet? MR. McMILLIAN: This is Mr. McMillian. Yes, we have acquired samples of water from. the Kuparuk formation itself and from the upper Cretaceous sands that would be candidate water supply sands, and also from the Beaufort Sea. And in the laboratory have done some mixing experiments and then -- and at this time do not see any compatibility problems with the wate~ MR. HA~4ILTON: Okay. I know you're still in the stage of formulating your plans for waterflooding, but is there some rough estimate of time when you think you might be initiating your water flooding? MR. McMILLIAN: Let me refer that to Mr. Norgaar¢ since he signs the AFD. MR. NORGAARD: We -- We -- This is Paul Norgaar( Like everybody, we have plans. And we -- we do intend as early as possible to initiate a water injection pilot. The earliest possible that could be would be in '83. And that would be our objective. Whether we can accomplish that or not, is -- is -- only time will tell. It -- it's a difficult task, but there's some awfully good people who are sitting next to me who are attempting to accomplish it. And that's our plan. MR. HAMILTON: Thank you. MR. SMITH: Would any of you care to remark on R & R COURT REPORTERS 8lO N STREET. SUITE 10! 1509 W, 3RD AVENUE 1OO7 W, 3RD AVENUE 277-OB72 - 277-0573 274-9322 272-7BI5 ANCHORAGE. ALASKA 99~0l AGO 10031776 10 11 12 13 14 15 16 17 18 t9 20 21 22 23 24 25 -83- the possible alternatives seriously considered other than water flooding? ...... MR. McMILLIAN: This is Mr. McMillian, ..... MR. SMITH: ...... For secondary recovery? MR. McMILLIAN: We have within ARCO screened various so-called enhanced recovery processes. The ones that we consider most seriously in addition to waterflooding were CO-2 missible (ph) flood, and in situ combustion. Because of the economic of these cases and because of the technologically unproven state of both of these processes as we see it for the North Slope, we ruled those out in favor of waterflood which had the economics and had the proven nature that we were looking for MR. SMITH: Mr. Dayton, in your testimony you mentioned about the completion technique that you're using -- utilizing on the wells or propose to use to increase the flow efficiency, and you mentioned tubing suspended perforating systeI Is this a new perforating technique? Would you elaborate on tha~ some? I -- I don't think we're familiar with that exactly. MR. DAYTON: Yeah. This is John Dayton. I woul~ say that it is a new technique to the North Slope. It is not a completely new technique to some areas down South. What the system consists of is starting from the bottom and working your way up the well would be a given length of perforating guns simil to casing type hollow carrier perforating guns, and you can run the -- about the largest guns you can get in that casing is about R & R COURT REPORTERS 810 N STREET. SUITE 10! 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-O573 274-9322 272-7BIB ANCHORAGE. ALASKA 99505 AGO 10031777 ar 10 11 12 13 14 15 16 17 18 2O 21 22 23 25 -84- five-inch guns. In this we can put larger perforating charges. As we go on up the hole we've got, as I said, a length of that, given length based on your log base. We've got some ,- an assembly that allows us after the guns are fired to drop that assembly to the bottom of the hole and then work with wireline tools below the end of the tubing. There is a perforated joint of tubing which allows flowing the well with the assembly still on the bottom of the tubing, and there is a firing head which you drop a bar from the surface, and this bar basically just slides down the tubing and strikes this detonating head, and the detonating head ignites the primer cord which ignites the charge~ which are set below the packer. So the packer is set at the time the -- the gun is fired. MR. SMITH: Okay. Ans so this is a more or less a permanent-- you go in with your permanent completion equipment and-- and the perforator hung below it and -- and do your thing and ..... MR. DAYTON: We drop the bar ...... MR. SMITH: ..... completei,'it then. MR. DAYTON: ..... and -- and it fires and then we can subsequently go in with a wireline and jar on that release assembly, drop the guns and the subs down to the bottom of the hole, and now we have open tubing. MR. SMITH: You mentioned the lower well -- differential pressure in the well bore, I suppose then you don't R & r COURT REPORTERS 810 N STREET. SUITE I01 509 W. 3RD AVENUE 1OO7 W. 3RD AVENUE 277-O572 - 277-0573 274-9322 272-7515 ANCHORAGE. ALASKA 99501 AGO 10031778 10 11 12 13 14 15 16 17 18 t9 20 21 9.9. 24 25 -85- -- that you can unload the tubing fluid or part of it ...... MR. DAYTON: Yes, you would have ...... MR. SMITH: ..... to where ...... MR. DAYTON: ...... You would have an option of about any cushion weight, total hydrostatic head that you'd wish to run all the way from -- from open tubing to a full column of some lighter fluid. So that's adjustable. MR. SMITH: Okay. When you run the tubing in with this gun, they you put the wellhead on it before you do thi ? MR. DAYTON: Yes, sir. The wellhead is on. MR. SMITH: In your drill site plat, shown t Five-six, you show a hundred and twenty foot spacing between the wellheads, and this is for the initial three hundred and twenty acre development plan. When you go to a hundred and sixty acre development, how -- what -- how do you -- where do you put the other wells? On this pad or on another pad? What kind of an arrangement do you go to? MR. DAYTON: The concept which we have -- our plans are for Phase One would be to add some additional gravel on the opposite side of that pad on the side where we now show the camp sewage lagoon? And to extend that and to put another row of wells for one hundred and sixty acre locations down that other side of the pad. MR. SMITH: Okay. MR. HAMILTON: Mr. Dayton, are you planning on R & R COURT REPORTERS 8'10 N STREET. SUITE IOI 509 W. 3~D AVENUE IOO7 W. :~RD AVENUE 277-O572 - 277-0573 274-9322 272-7Bl~ ANCHORAGE. ALASKA 991~O1 AGO 10031779 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -86- using the fuel gas for generating your electrical power out in that area? MR. DAYTON: Yes, we are. Yes, we are. MR. SMITH: Mr. Dayton, in general the -- the metering -- the testimony having to do with the -- the metering of the crude oil and the schematic of the metering station and prover loop is a little less detailed than what we would like to see from Ithe standpoint of our evaluation of it. I might mention some of our concerns are the -- and maybe you can address it somewhat. For example, the -- what type of meters, the manufacturer and rating do yo~-- are you going to have -- utilize there? Are these four inch meters you're proposing, are they adequate just for the initial Phase One, or will you~be increasing the meter size later? MR. DAYTON: The -- the three four-inch meters in combination will provide enough capacity for the -- the pipe- line as it is now. The hundred and ninety-six thousand barrels per day. MR. SMITH: Okay. But what -- what type and brand of meters are those? MR. DAYTON: They're -- they're Brooks meters. The exact, you know, serial number and line I do not have availa] with me here today, but we can certainly furnish you that. MR. SMITH: Well, are they a turbine meter or PD meter? r & R COURT REPORTERS 810 N STREET. SUITE lO! EO9 W. 3RD AVENUE lOO7 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-751~ ANCHORAGE. ALASKA 99~5OI AGO 10031780 le 10 11 12 13 15 16 17 18 t9 2O 9.1 22 23 9,5 -88- arrived it. MR. SMITH: Well, we -- we would specifically like to know on your computer program and set up there how -- how these things will be handled and how you arrive at the quality and quantity determinations and what part is manual and what part's in the computer and -- and what's the source of those things that are in the computer, how they get in there. S( we-- we certainly need more elaborate detail on this whole meterJ set up I think. MR. DAYTON: Okay. There is certainly -- or currently some correspondence in the mail to your office at this time which more thoroughly describes what is in this system. MR. SMITH: Well, perhaps that will take ...... MR. DAYTON: Any additional correspondence which you would require, we'd be happy to furnish. MR. SMITH: Well, that's most of mine. MR. KUGLER: Just one ...... MR. SMITH: Someone --'Betty Jane brought this up and I don't know who -- i~S;~un~i~,-~ I don't know who sent it up. I don't think it's ..... MR. KUGLER: I've got one question for Mr. Daytoz On your Exhibit Five-dash-four, which is the -- shows the per- formance relationships between cased hole and open hole. The lower line here is BOPD with just an arrow. Is there -- is thi a constant scale along here or is there a reason why there;'s no. R & R COURT REPORTERS 810 N STREET. SUITE IOI ~BO9 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-01573 274-9322 272-7BI5 ANCHORAGE, ALASKA 99~O1 AGO 10031781 ng 10 1l 12 15 16 17 18 21 9.3 25 -87- MR. DAYTON: Yes, it's a turbine meter. MR. SMITH: Okay. Well, I was under the impres- sion previously that you were going to use PD meters, and we didr think they were big enough. Well, along this same line, you proposed a fourth leg there in your schematic for the proving of other meters for the facility. And it seemed to us that you were into an accounting problem if you use it the way you've shown it, possibly because you'd -- you'd be proving the meter and -- and it would also be going down the line for the -- you'd have to have a meter ticket on it. So is there something I don't know there or is -- would it have been better to have in series with one of the other meter legs or separated just to the meter prover loop for that? MR. DAYTON: This is Mr. Dayton again. I think the key to this is the flow computer which we have indicated here And this computer allows us the opportunity to take oil from the header with the other four-inch meters, take it through this smaller loop, or smaller meter run, and calibrate that meter through the prover loop with a given 'quantity of oil and -- and know exactly what the total count was from that meter during the entire test sequence. So we have a current cumulative volume of everything went -- that went through that meter and we have now recalibrated that meter during the sequence. So we could go back and adjust that volume if it proves that the meter was off originally with the new meter factor which we have just R & R COURT REPORTERS 810 N STREET. SUITE lOt 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-057:3 274-93,2,2 272-7B1B ANCHORAGE. ALASKA 9950! AGO 10031782 't 10 11 12 13 14 15 16 17 18 2O 21 22 25 -89- MR. DAYTON: That is a linear scale along the bottom there ...... MR. KUGLER: Linear. MR. DAYTON: ...... with barrels of oil per day increasing to the right. We did intentionally leave -- leave off the rates ....... MR. KUGLER: I see. MR. DAYTON: ..... As you can see there is a variation on here between those ..... MR. KUGLER: There are two different wells there I guess ..... MR. DAYTON: Right. MR. KUGLER: ...... I see that. MR. DAYTON: I would state that the-- the well exhibiting the higher rate there is -- is -- I would have to classify as anomalous for our development area. It's anomalous~ high. MR. KUGLER: I see. Is the C-4 more .... ? MR. DAYTON: The C-4 as it turns out is probably anomalously low for an average well. MR. KUGLER: I see. So what you're saying is average in the field is ..... MR. DAYTON: Is in between those two. MR. KUGLER: ..... is not here and not illustrat~ It's .... R & R COURT REPORTERS 810 N STREET. SUITE tOt 50~) W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-OE~73 274-932:2 ANCHORAGE, ALASKA 99501 AGO 10031783 d ~ 10 11 12 13 14 15 16 17 18 2O 21 24 25 -90- MR. DAYTON: That's cormect. MR. KUGLER: ..... between these? I see. MR. DAYTON: That's correct. MR. KUGLER: Alright. Well, I ...... MR. SMITH: Well, all this shows then really is that regardless of how good the well is, that ..... MR. DAYTON: We have ...... MR. SMITH: ..... with difference in the com- pletion technique, it amounts to about fifty percent ...... MR. DAYTON: Right. The ...... MR. SMITH: ...... one way or the other? MR. DAYTON: ..... the open hole completion technique has consistently amongst two tests exhibited improve- ments in well deliverability. MR. SMITH: I know you mentioned that you recog- nized the problems with later control over waterflooding and things like that. I would be interested in how you planned to overcome some of those problems such as this -- blowing the hell out of these big guns and twelve shots per foot and -- and then later injectivity control in -- in the three zones. Can you elaborate on that at all at this time? MR. DAYTON: It -- I -- We can foresee that isola tion of zones after a high density perforation with big holes could present a problem. I think there are techniques available to -- such as scab liners or squeezing of perforations to -- to R & R COURT REPORTERS STREET. SUITE 10! 1~O9 W. 3RD AVENUE IOO7 W, 3RD AVENUE 277-OB72 - 277-O573 274-93.92 272-7~t1~ ANCHORAGE. ALASKA 99BO1 AG0 10031784 10 11 12 13 14 15 16 17 18 t9 2O 21 22 23 24 25 -91- try to control conformance and -- and correct gas productivity problems in our producing wellS. MR. NORGAARD: This is Paul Norgaard. Let me offer another -- another observation. That the sands we're dealing with are relatively thin sands. They're not Prudhoe type sand, and therefore that there probably isn't going to be a lot of attempts to isolate water out of a particular sands, and we're definitely not shooting the intervals between the sand: .~so there's lots of blank pipe in a well in order to separate sand from sand. MR. DAYTON: This is John Dayton again. Let -- on the band tool system which we described before, I should have elaborated a little bit more and said that we can shoot multiple intervals below that thing without continuous perforations betwe, We can space guns however we see fit with blank subs in between. MR. SMITH: Okay. MR. HAMILTON: Do you have any more questions? That's all the questiOnls we have at the present time. And we'll --if some come up from the audience, you may be asked questions a little later. MR. WILLIAMS: Mr. Chairman, for the record at this time, and in -- consistent with recommendations in other conservation orders of the Commission, we would formally request an amendment to Rule Number Six regarding the submittal of the reservoir pressure report form twelve to the thirtieth day fol- R & R COURT REPORTERS 810 N STREET. SUITE IO! 1509 W. 3RD AVENUE tOO7 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7Bt6 ANCHORAGE. ALASKA 9OBOI AGO 10031785 n. 10 11 13 15 16 17 18 2O 21 25 -92- lowing the month in which the test was taking rather than the fifteen day. MR. HAMILTON: Okay. Thank you. Is there anyon~ else that would like to present sworn testimony today? We'll take that at this time. If not, we have one person here who wants to give an oral statement, and I'll call on him first, and I'll ask if there's anyone else after that. Mr. Reader? COURT REPORTER: Excuse me, Mr. Reader. Could I get you to get -- take the microphone up and bring it over to that table? MR. READER: Want me to just sit over here? MR. HAMILTON: That would be fine. MR. READER: Mr. Chairman, members of the Commis- sion, my name is John A. Reader, and I am senior attorney for Sohio Alaska Petroleum Company. On behalf of BP Alaska Explora- tion Incorporated and Sohio Alaska Petroleum Company, which I will refer to as the BP Sohio Group, I wish to offer a supplemen- tary statement to the testimony submitted on behalf of ARCO. The BP Sohio Group commenced exploration on the North Slope in 1958, and in 1964 it acquired the Kuparuk Field leases jointly with Sinclair, now ARCO. The BP Sohio Group is now one of the major lease holders in the Kuparuk Field. Leases in whic~ the BP Sohio -- BP Sohio Group have interest cover approximately seventy percent of the area included within the proposed Kuparuk River Pool Rules. The BP Sohio Group has participated in explor~ R & R COURT REPORTERS 810 N STREET. SUITE IO1 1509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O~572 - 277-01573 274-9322 272-7BI~B ANCHORAGE, ALASKA 99BOI AG0 10031786 10 11 12 13 14 15 16 17 18 2O 21 25 -93- tion drilling in the Kuparuk River Field from the beginning starting with the CQlville Number One well in 1966 and the discovery well Ugnu Number One in 1969. In total the BP Sohio Group has participated in thirteen of the twenty-five explorator, wells in the proposed Kuparuk River Field area. As a result of several years of appraisal and evaluatio activities in the field, the BP Sohio Group is now in the proces of planning together with ARCO for the timely and efficient development of the field including secondary recovery evaluation It is expected that the field development will be carried out pursuant to a unit operation, and negotiations looking toward unitization have been underway and considerable progress has bee] made. The BP Sohio Group has actively worked with ARCO in drawing up these proposed pool rules and would recommend to the Commission that they be implemented. We can also state that we generally support ARCO's testimony today. We believe these rules will provide for the safe and efficient development of the Kuparuk River Field while minimizing environmental impact and are in the best interests of all concerned. We thank the Commission for this opportunity to submit a statement in support of the Kuparuk River Pool Rules. I have also had a request from Sohio and BP that we hold the record open for approximately ten days if -- if possible. We have had only about one working day to review the actually testimony, and R & R COURT REPORTERS 810 N STREET. SUITE IO! 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7~15 ANCHORAGE. ALASKA 99B01 AGO 10031787 I 10 11 12 13 14 15 16 17 18 t9 20 21 22 23 24 25 -94- although we are at this time satisfied with it, we may have additional comments based on some of the questions that have bee] asked. Thank you. MR. HAMILTON: Thank you, Mr. Reader. We plan on holding the hearing record open for at -- at least two weeks, unless someone wants it held open longer. We will take that int( consideration also. But if anyone wants to talk about that, the can come forward. Otherwise at the end of the hearing I will announce how long it will be open, but it will be a minimum of at least two weeks. At this time is there anyone else who would like to make an oral statement? Alright. We do have some questions that were received. I don't know who they came from. There's no name here and they-- they don't say who they're addressed to, but i assume it's the applicant since they are the only one that's testified, so -- Mr. Williams, if you would -- I'll Put these questions to your group and you can have whoever would like to answer these How will gas injection back into the oil zone affect plans or performance of secondary recovery? yeah, the microphone has been moved over here. It's more inconvenient now, but you can move it back if you would like to the center table. Would you care to have that repeated? R & R COURT REPORTERS 810 N STREET. SUITE IOI Bog W. 3RD AVENUE 1OO7 W. :~RD AVENUE 277-0572 - 277-0fl73 274-9322 272-7BI1~ ANCHORAGE. ALASKA 99{~O1 AGO 10031788 10 11 12 13 14 15 16 17 18 2O 21 22 25 -95- MR. McMILLIAN: Would you please? MR. HAMILTON: Okay. How will gas injection back into the oil zone affect plans or performance of secondary recovery? MR. McMILLIAN: This is Mr. McMillian. We are currently within ARCO evaluating waterflood and all areas of our planned development of the Kuparuk. One of those areas is the gas injection area. We have not finalized these studies. We do anticipate that there will be some impact of the gas injec~ tion on waterflood recovery, but I'm not prepared at this time to quantify what that impact is. MR. HAMILTON: Okay. The next question: On what basis is the whole southwest area being proposed to be included and covered by the field rules? MR. WILLIAMS: I believe Mr. Merritt will answer that question. MR. MERRITT: Well, the map that we had on the wall as Exhibit Two shows an intraclinal (ph) feature (indis,i~ cernible due to coughing), and realizing that we are processing-- in the process of defining that portion of the field, but reason~ extension of the released data now would support that we could include this part of the area in the field rules, or that the Kuparuk formation is present in that location. MR. HAMILTON: Okay. Thank you. The third question I -- has already been answered, so I -- I won't ask thai r & R COURT REPORTERS 810 N STREET. SUITE IOI 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-O572 - 277-O573 274-9322 272-7B1B ANCHORAGE. ALASKA 99B01 AGO 10031789 ble 10 11 12 13 14 15 16 17 18 20 21 25 -96- Okay. We had another questions: Will copies of today' testimony and exhibits and proposed rules be~ available to the public, this is asked by Mr. Morrison, W.C. Morrison, or I gues it's "mister," but -- Yes, they will. We will have records available in our office the public can examine. The transcri t will be available as soon as it's typed, and that may take a week and a half or something like that, but all the other s and so forth will be there in the meantime if anyone would care to come by and examine them. And we can also make proviSions for checking out copies for the -- on a limited time to indivi- duals if they'd like to reproduce any of the exhibits. Well, I haven't heard anything to the contrary about extending the hearing record -- or being kept open further than two weeks, so at this time I would like to say it well be kept open until four-thirty p.m. on April the 8th, 1981. And with that the hearing is closed. (OFF THE RECORD) END OF PROCEEDINGS R & R COURT REPORTERS 810 N STREET. SUITI=' lOI 509 W. 3RD AVENUE IOO7 W. 3RD AVENUE 277-0572 - 277-O573 274-9322 272-7BIE$ ANCHORAGE. ALASKA 99~O1 AGO 10031790 10 11 19. 13 14 15 16 17 18 i9 20 9.1 9,2 9.3 CERTIFICATE UNITED STATES QF ~ERICA ) ) SS. STATE OF ALASKA ) I, Meredith L. Downing, Notary Public in and for the State of A&aska, residing at Anchorage, Alaska, and Electonic reporter for R & R Court Reporters, do hereby certify: That the annexed and foregoing transcript of hearing was taken before me on the 25th day of March, 1981, beginning at the hour of 9:00 A.M., at the Borough Assembly Chambers, Tudor Road, Anchorage, Alaska; That the witnesses were duly sworn to testify to the truth, the whole truth, and nothing but the truth; That this transcript as heretofore annexed is a true and correct transcription of the testimony, taken by me elec- tronically and thereafter transcribed by me; That the transcript original has been retained by me for the purpose of filing the same with the Alaska Oil and Gas Conservation Commission, Anchorage, Alaska. I am not a relative or employee or counsel of any of th. parties, nor am I financially interested in this action. IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this 31st day of March, 1981. N6~y Pub~ic~i~h~and~aska My Commission expires.~ 5/3/82 SEAL r & R COURT REPORTERS 810 N STREET. SUITE lO! BO9 W. 3RD AVENUE ,007 W. 3.D AVENUE =77.oB7= - =7~-o,~s ~74-9322 2'~'~'" AGO 10031791 ANCHORAGE. AkASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ARCO ALASKA, INC. KUPARUK FLARING SIGN IN PLEASE NAME (PIAgASE PRINT) AGO 10023514 Mobil March 25, 1981 ALASKA OIL & GAS CONSERVATION COMMISSION at the Public Hearing, March 25, 1981 on the Kuparuk River Formation Pool Rules Mobil Oil Corporation supports the testimony given by ARCO Alaska, Inc. today, and their proposed pool rules for the development and production of the Kuparuk River Formation. Max B. B~azley ~ ~) AGO 10023510 KUPARUK RI.VER FIELD NORTH SLOPE, ALAS~ FIELD RULES TESTIMONY BEFORE THE ALASKA OIL AND GAS CONSERVATION COIW~ISSION PRESENI'E~ BY ARCO ALASKA, INC, MARCH 25, 1981 AGO 10023601 AGENDA KI]PARUK FI~D RUI2~ ~%{ARC~ 25, 1981 II. III. IV. Ve VI. VII. VIII. ~U6TIC~ GEOLOGICAL RESERVOIR ENG~ING DRILLING WELL COMP~ION~, FACILITIES AND ~IT,T,~CE Plq~ S~Y P~ FITUD RULES EXHIBITS, STEPHEN M. WILLIAM~ JAMES C. MERRITT WILLIAM H. MCMILLIAN PETE A. VANDUSEN JOHN S. DAYTON PAUL B. NORGAAED AGO 1002B602 BEFORE TEE ALASKA OIL AND GAS ~ATION ~SSION I. EffRDDUCTION Mr. Chairman, members of the Commission, my name is Stephen M. Willi~ns, Attorney for ARCO Alaska, Inc. (hereinafter referred to as "ARCO"). ARCO Alaska, Inc. is a wholly owned subsidiary of the Atlantic Richfield Company. We appreciate the opportunity to present this testimony regarding the Field Rules for the Kuparuk River Area to the Comnission today. The purpose of today's hearing is to establish Field Rules for a new field which we are officially requesting be called Kuparuk River Field. The proposed boundaries of the Kuparuk River Field are shown on Exhibit I - 1. These boundaries are all within the geographic boundaries of the State of Alaska and subject to the jurisdiction of the Alaska Oil and Gas Conservation Conmtission. The existing Field Rules for the Prudhoe Bay Kuparuk River Oil Pool are set forth in Conser- vation Order No. 98-A, as amended by Conservation Order No. 137. The rules pro- posed today are similar to those existing rules with the exception of the specific modifications and changes discussed in later testimony. i The existing rules now cover a portion of the proposed Kuparuk River Field as shown on Exhibit I - 1 as the shaded area. The existing boundaries of the Prudhoe Bay Unit are also identified. We propose that the field rules boundary of the existing Prudhoe Bay Kuparuk River Oil Pool be contracted to coincide with the Eastern boundary of the proposed Kuparuk River Field Rules area as indicated in Exhibit I - 1. This contraction would allow the proposed new field rules to cover this area. Testimony will establish that a separate oil accu- mulation exists in the proposed Kuparuk River Field. AGO 10023604 I-1 The proposed field rules have incorp(~r-~tled input from other Working Interest Owners in the proposed field rules area. ARCO will present the following witnesses whose testimony has been prefiled with the Commission. This testimony will be adopted by each of the witnesses and each of the witnesses will be avilable for additional questions from the' Comnission. The witnesses include: (1) James C. Merritt, who will present testimony on the geology; (2) William H. McMillian, who will present testimony regarding reservoir engineering; (3) Pete Van Dusen, who will present testimony on drilling operations; (4) John S. Dayton, who will present testimony on well completions, surface facilities and the surveillance program; and (5) Paul B. Norg~_ard, Vice President ARCO Alaska, Inc., who will summmrize the testimony. In addition to addressing the proposed Field Rules directly, this testimony is designed to provide you a basic understanding of the reservoir and current develop- ment plans. It should be stressed that the development of the Kuparuk River Field is in an early stage, The data is limited and future data acquisition will play an important role on future development plans. Our testimony today reflects ARCO's plans and interpretations of this data. ARCO would request that Commission members hold any questions they may have until the end of the presentation. If this procedure is acceptable, all wit- nesses will be available to answer any questions that Con~nission members may have at the conclusion of the testimony. I-2 AGO 10023605 II. GEOI/R3ICAL INTROD~I~ Mr. Chairman and members of the Alaska Oil and Gas Conservation Commission, my name is James C. Merritt. I am presenting geological testimony on behalf of ARCO Alaska, Inc. (which I will refer to as ARCO). I received a Master of Science degree in geology in 1966 from the University of North Dakota and have been employed as a petroleum geologist for over fourteen years, which includes ten years of Alaskan experience. I have been employed by ARCO for the past eight years, and I am currently the senior geologist for exploration and development of the Kuparuk River Field in the North Slope District. The last two and one-half years of my efforts have been con- centrated on the geological aspects of. Kuparuk exploration and development. Let me begin the geological testimony by showing you ARCOExhibit II - 1, a map of a portion of the Alaskan Arctic North Slope. Each square in the grid represents a six mile township. We proposethat the field rules for the Kuparuk River Field apply to an area that covers about 356,480 acres; or about 557 square mites. This area lies south of the Beaufort Sea shoreline, eas~ of the ColvilleRiverboundaryofNPR-A, and in~iatelywest of the PrudhoeBayUnit. Oil wasfirst diScovered in the Kuparukareawhen Sinclair tested oil from the KuparukFormation at the rate of 1,056 BCUD at their Ugnu #1 well in 1969. Subsequently other Kuparuk accumulations have been discovered in the vicinity; the Eileen and North Kuparuk areas of Prudhoe Bay Field, at Gwydyr Bay II - 1 AGO 10023607 ', II. located north of the Prudhoe Bay unit, and also at Milne Point imT~diately northeast of the Kuparuk area of accumulation. During the eleven years bet- ween 1969 and 1980, the industry has drilled 25 wildcat and extension wells in an attempt to define the limits of Kuparuk oil accumulation. ARCO has drilled and joined in the drilling of all but seven of these wells. Further- more, ARCO will drill or join in the drilling of four additional tests in 1981. These are the Sohio West Sak Nos. 16 and 17 and the ARCO West Sak Nos. -- 18 and 20. Two wells, the West Sak Nos. 13 and 15, have not been released to the public record and therefore do not appear as supporting testimony. It is this subsurface data from 25 wells and hundreds of miles of multi-fold seismic data that are used for the following geological interpretation. Ail of the exhibits that you will be seeing were originally constructed by myself or under my direct supervision. Expert assistance was received .from our Research Group in Dallas and our Geophysical, 'Engineering, Land and Legal Departments in Anchorage. STRUCTURE I now show you ARCO Exhibit II - 2, a structural contour map on top of the Kuparuk River Formation. The contour interval is 100'. The contoured part covers the area west of the Prudhoe Bay Unit, east of the Colville River, and south of the Beaufort Sea. The Sinclair Ugnu #1 well is located in the north-central part of the contoured area. Subsurface control data for the structural mapping is supplied by twenty of the exploratory wells. The feature is a southeasterly plunging anticlinal nose that is about 26 miles wide and 22 miles long. Data from eight wells establishes the northeast flank of the feature. Over 800 feet of north dip is measured II - 2 AGO 10023608 from the West Sak #11 well, drilled on the crest of the feature, to the Socal Simpson Lagoon wells. Although the south flank is less well defined, five wells from which data has been released show at least 550 feet of south dip. Dip rates vary up to 3© maximum (about 275 feet per mile). Structural closure to the southeas~ is well established by well control. The northwest dip betweem the West Sak #11 and the Kalubik Creek #1 and the Colville ~1 wells is created by the erosion of the Kuparuk River Forma- tion by a Lower Cretaceous Unconformity that places younger Lower Cretaceous rock on top of progTessively older rocks to the west. This unconformity trun- cates the Kuparuk River Formation along a northeast/southwest, line, just east of the Kookpuk #1 and Colville #1 wells and west of the Kalubik Creek #1, and West Sak #11 wells. The truncated edge of the Kuparuk is placed iranediately east of the Kookpuk #1 and Colville #1 wells because regional isopach mapping of the pre-Kuparuk rocks indicates that erosion of the older rocks is mini- malo ~ These same younger Lower Cretaceous rocks truncate the Kuparuk River Formation along the poorly defined line drawn between Mobil's north Kuparuk well and Sohio's M-pad wells in the Prudhoe Bay Field. In the Kuparuk River Field area, the truncation edge is placed about two to three miles downdip from well control. This is based on the rate of thin- ning in the Kuparuk River Formation due to truncation. A large northwest-trending fault is shown along the west boundary of the Prudhoe Bay Unit, separating the two areas of accumulation, and conm~nly referred to as the Eileen fault. The downthrown block is to the south- west with displacement ranging from 150 to 350 feet. The fault was en- countered in the Socal 33-29E well below the Kuparuk River Formation, II - 3 AGO 10023609 . where more than 200 feet of Jurassic" section was faulted out. It was also found in the ARCO Highland State ~fl well, where all of the Kuparuk section and a portion of the upper King~ shale was faulted out. Seismic data indicates the fault continues to the northwest towards the Beaufort Sea, where it separates the Simpson Lagoon wells of the Kuparuk River Field from the Milne Point and Kaverak Point wells. The two red lines labled A-A' ~nd B-B' show the location of tw~) structural cross-sections that will be shown as Exhibits II - 3 and II - 4. I show you now ARCO Exhibit II - 3, cross-section A-A', which extends from west to east between the Sinclair Colville #1 well and the ARCO West Sak ~6 well and parallel to the structural axis of the feature. The logs used on the section are the ~ Ray/Dual Induction Laterolog and the SP Logs. The depth reference is feet-below-sea-level, and the vertical exaggeration is twenty times. The cross-section illustrates the southeast structural dip from the crest at West Sak #11, and the northwest dip due to truncation between West Sak #11 and the Colville #1 well. I have projected truncation of the formation downdip and east of the West Sak #6. I show you now ARCO Exhibit II- 4, which shows structural cross-section B-B'. It was constructed across the structural axis of the Kuparuk River Field, extending from the northeast to the southwest between the N. W. Eileen #1 well and the Sohio West Sak ~4 well. The vertical exaggeration is twenty times. The West Sak F2 well is projected along structural strike into the line of section. This section illustrates both the south-dipping flank and the north-dipping flank of the feature, and the existence of the Eileen fault between the N. W. Eileen #1 well and the Socal 33-29E well. II - 4 AGO 10023610 III. STRATIGRAPHY The Kuparuk River Formation consists of very fine to medium grained marine sandstone, u~:~_-]ly occurring as three sandy members separated by mudstones, siltstones and thinly bedded sandstones. In those areas of greater than 300 feet of Kuparuk River Formation, all three sandstone members or their silty/ shale equivalents are present. In those areas of less than 300 feet of thickness, usually less than three of the sandstone mem~rs are present. This section shows the formation thinning to the south by truncation by the Lower Cretaceous Unconformity. North of the crest of the structure, thinning of the formation also occurs by either intraformational unconformity or by nondeposition, causing updip coalescence of sands within the formation. Refer again to Exhibit II - 3, cross-section A-A'. This section illustrates Kuparuk River Formation resting conformably on Kingak shale and overlain by an unnamed Lower Cretaceous shale, which rests unconformably on Kuparuk and Kingak. The formation is completely truncated by a Lower Cretaceous Unconformity between the West Sak #11 and Colville #1 wells. Also, the lower sand members thins to the east along this section. The next slide is ARCO Exhibit II - 5, which is an isopach map showing the distribution and total thickness of the ~uparuk River Formation, The contour interval is 100'. Data from 32 wells was used to construct this map.. The Colville River is located on the west, the Beaufort Sea shoreline II - 5 AGO 10023611 to the north, and the Prudhoe Bay Unit outline on the east. The thickes~ section of 664 feet was encountered in the Placid Beechey Point well, located in the northeast part of the map. Thinner sections occur along the northwest and the southeast boundaries where the formation thins or is missing by truncation. In general, in areas of less than 200 feet, the Kupa&-uk Formation thins rapidly by erosional truncation. The red lines show the location of cross-section A-A' and B-B'. OCCURRENCE OF PE'IBOLEUM Refer please to Exhibit II - 2, the structure map on top of the Kuparuk River Fol~:mtion. To date no wells have established the existence of a g;us cap. The trapping mechanism of the Kuparuk River Fi(Id is the truncat ion. of the Kuparuk River sandstone reservoir by non-porous younger Cretaceous rocks across the updip part of the plunging structural nose. The trap is com- pleted by structural dip closure to the northeast, southeast, and to the south. Structurally the trap has over 900 feet of closure as measured from the West Sak #11, located on the crest of the structure, to the West Sak ~6 and the Simpson Lagoon wells, the structurally lowest wells in the field. Twenty-one wells were used to define the currently indicated limits of the reservoir of the Kuparuk River Field area. Eighteen had at least one oil-saturated Kuparuk sand n~r. Two are dry holeS: ARCO's West Sak River State ~ produced water when tested, and Simpson Lagoon 32-14 appears to be water-bearing on the logs despite having residual shows of oil on sidewall samples. The Kuparak Reservoir is missing in the Sinclair Colville #1 and the Union Kookpuk #1 wells. Of the seventeen oil-saturated wells, thirteen produced oil in significant quantities when tested. These wells II - 6 AGO 10023612 I are the Simpson Lagoon 32-14A; the Ugnu and East Ugnu wells; and the West Saks #1, ~2, #'3, #4, #7, &8, #9, #!1, #12, and #14. Four wells, althouF~ oil-saturated, failed to test paying quantities of oil due to formation damage, poor quality reservoir rock or other factors. These wells are the Kalubik Creek #1, the Socal 33-29E, and ARCO's West Sak ~5 and #10. We know that there is an oil/water contact but its exact depth is not known. No oil/water contacts have been substantiated by any individual sand members. The highest occurrence of water has been observed at 6,548 feet below sea level in the West Sak ~. well but other wells have encountered hydrocarbon deeper than this. We currently interpret the oil/water contact as a surface with a slight north dip. We. interpret that all sand members of. the Kuparak River Formation west of the major sealing Eileen fault are in a comTon pool and share the same fluid contact. In the Kuparuk River Field, conrntmication between the individual sand members exists through (1) coalescence of the sand members as was illustrated in the. cross-sections, (2) juxtaposition of the sand across small faults, The following testimoney by Mr. McMillian will elaborate on the Kupartuk reservoir rock and fluid properties, and reservoir performance studies. II - 7 AGO 10023613 Ie II. III .. RESERVOIR ENG~G Mr. Chairman and members of the Alaska Oil and Gas Conservation Co~ssion, my name is William H. McMillian. I am presenting reservoir engineering testimony on behalf of ARCO Alaska, Inc. (which I will refer to as ARCO). I received a Master's degree in Physics from Louisiana State University in 1971. After having served four years as an officer in the U. S. Air Force, I began employment in 1975 with ARCO asa Petroleum Reservoir Engineer. My experience includes various assignments in West Texas, Dallas, and Alaska where I have conducted Reservoir Engineering Studies of oil and gas fields under primary development, waterflood, and enhanced oil recovery. The last one and one-half years of my efforts have been con- centrated on the development of the Kuparak River Field.' My testimony today will include a description of basic Kuparak reservoir rock and fluid properties, a s~ of reservoir performance studies and conments on well spacing. Ail of the exhibits that will be presented were originally constructed under my direct supervision. Expert assistance was received from ARCO personnel at the Production Research Center near Dallas and our geological group in Anchorage. IN-PLACE HYD~~N VOLUMES Let me begin this testimony by showing you ARCO Exhibit III -1, a map depicting our interpretation of the extent of hydrocarbons in the Kuparuk III - 1 AGO 10023615 River formation. The outer boundary includes the potential limits of the reservoir and the inner boundary defines the area that is presently planned for development. Determination of this preliminary 210 square mile area for develounent has been based on interpretation of well loEs, core data and production tests for net pay. There is considerable uncertainty in pickin¢ net pay that will only be resolved after conrnenc~nt of production. 0il in-place volume for the Kuparuk is estimated to be in the range from 3.5 to 4.4 billion stock tank barrels. Average porosity is 20 - 21% and average veater saturation is 25 - 3(Fo from core data. The wide range in oil in-place estimates is appropriate in view of the sparsity of well control over much of the Kuparuk area. The objective of the current de- lineation drilling pro~/~am is to test strategic areas in the northern part of the field and along the south and southwest boundaries of the field in order to remove some of the uncertainties in mapping the accumulation. III. RES~OIRROCKPNDPERTIES I show you now ARCOExhibit 'III - 2, a type-log fromWest SakNo. 1 well which includes identification of the three sand units in the Kuparuk. A general description of these units is as follows: Upper Sa~.d (~ellow) and ~i..ddle ~and (Gold): These members are lithologically similar They are very fine to coarse grained to pebbly, quartzitic sandstones that lack beddin~ features due to bioturbation. Glauconite and siderite occurrence ranges from zero to very abundant Porosity and permeability in these members ran¢es from very poor to excellent and varies with III - 2 AGO 10023616 IV. gTain size and the abundance of siderite cement and' glauconite. Lower Sand (Orange): A very fine to fine grained quartzitic sandstone that is well sorted, clean and comronly interbedded with thin silts~one and mudstone. Porosity and permeability is generally fair to excellent in this n~r and varies with grain size. This zonation has been used in the Kuparuk Reservoir modeling studies which will be described later in my testimony. ARCO Exhibit III - 3 ~izes reservoir rock properties for the various sand members of the type well. FLUID PROPERTIES Initially reservoir pressure in the Kuparuk River Formation averages about 3,100 psia. Reservoir temperature is approximately 155°F. At these con-. ditions, oil gravity averages 23° API, ranging from 25° in structurally high wells to below 20© downdip near the water-oil contact. 0il formation volume factor averages 1.215 stock tank barrels per barrel of reservoir fluid and solution gas-oil ratio average 460 standard cubic feet of gas per barrel of oil. There is an apparent correlation between reservoir fluid properties and SUbsurface depth. The oil tends to be more viscous and have a lower oil gravity at deeper structural locations. .We have also made similar correlations with depth for formation rolL, ne factor and solution gas-oil ratio. The bubble point of t{uparuk reservoir fluid averages around 3,000 psia, approximately 100 psia below initial reservoir pressure. As a result, the Kuparuk River Reservoir is thought to be undersaturated, which means there is no gas cap or free gas at initial reservoir conditions. III - 3 AGO 10023617 V. IN-PLACE SATURATIONS The aquifer underlying the Kuparuk River oil acc~nulation appears to be small in volume because of unconformities downdip to the southeast and fa~ulting to the northeast. According, aquifer influx into the oil column is expected to be insignificant. Early production and pressure performance should substantiate this assumption. The water-oil contact has not been observed in any individual sand members of Kuparuk wells. Since the highest occurrence of water was in the West Sak No. 6 well at -6,548 feet subsea elevation and other wells have encountered hydrocarbons at deeper subsea elevations, it is interpreted that the water- oil contact is a tilting surface with a slight north dip. Although water saturation in Kuparuk interval is a key factor in the determination of in-place hydrocarbon volumes and prediction of production performance in the field, it cannot be easity determined. Conventional analysis of electric well logs for calculation of water saturation cannot be applied to the Kuparuk formation due to thin bed effects and the presence of shales, siderite and glauconite throughout the rock. Accu- rate determination of water saturations requires taking oil base cores in selected wells° Information from careful analysis of these cores provides a correlation of water saturation with formation permeability, porosity and height above the water-oil contact. This correlation is called a Leverett J-function. Specialized J-functions have been derived for the Kuparuk Sands using oil-base core data from West Sak No. 7 and Kuparuk E-5 ,, wells. We believe on the basis of our current studies that it is appropriate III - 4 AGO 10023618 to have a separate J-function correlation for each of the lithologic units previously identified. · Let me direct your attention to ARCO Exhibit III - 4 which shows the water saturation distribution for three sand members having average permeability and porosity. As you can see, the water satulration decreases with the distance above the water-oil contact. Water saturation at any point in an actual well profile can be acceptably determined by use of the J-function. Pressure Depletion Performance ARCO has conducted studies concerning pressure depletion performance in the Kuparuk Field for several years. We feel that we have developed an adequate description of reservoir characteristics despite the shortage of well con- trol and have carefully applied our knowledge of well tests and fluid flow data in predicting field production performance. Solution gas drive is the pr~ recovery mechanism in the Kuparuk Field since there is no primary gas cap and it is believed that the aquifer will provide little or no natural pressure support, Several primary recovery reservoir models of the Ku~aruk have been constructed by AR(D over the past five years in order to obtain reservoir performance simulations. These models have ranged in complexity from a large-cell, 2-dimensional model to a much more .detailed study involving a series of 3- dimension~ finely gridded models having as many as eighteen layers. The reservoir performance in these studies has been incorporated with downhole well bore effects and surface facility constraints to predict field per- formance under a variety of possible operational scenarios. The current III - 5 AGO 10023619 Kuparuk reservoir model includes in-flow performance relationships, effects of formation damage, well bore hydraulics for natural flow and artificial lift, and controls to simulate a variety of surface facility configurations. Although no long tern production data is yet available, we have calibrated model results with actual well test data gathered over the past eleven years. Initial rates anticipated for Kuparuk wells are directly related to producing well flow efficiency, a function of well bore damage. At the present time, unstim~ated Kuparuk wells have exhibited flow efficiencies averaging less than 50%. We believe that this level of apparent well bore damage can be reduced by more efficient completion methods or by fracture stimulation of the wells. A more complete discussion of our endeavors in this area will be provided in subsequent testimony by Mr. Dayton. In anticipation of achieving better results, we have as~ flow efficiencies of 80To in all of our model pre- dictions. Let me direct your attention to ARCO Exhibit III - 5 which is model output of oil and gas rate versus time for ARCO's Phase I develo~nent under primary depletion. These curves come from 3-dimensional model studies that were performed in 1979 at the time of our initial conn~tment to develop Kup~ruk. More well data is now available and our forecasting tools have been improved, but this exhibit is still appropriate to show characteristics of primary production. ARCO's Phase I development will be discussed later in terms of specific facility design, drilling program and scheduling, but for this discussion, let me point out that the scope of this project includes the following: III - 6 AGO 10023620 1) 20 square miles of 10(F0 ARCO leases 2) One central production facility and five drill sites · 3) Forty producing wells on 320-acre spacing 4) 2-3 gas injection wells 5) 2?-mile oil line from Kuparuk to the Tr~ms-Alaska Pipeline Pump Station 1 ARCD Exhibit III - 5 shows that there is a decline of oil production rate throughout the life of the project. Initial oil rate is nearly 80,000 barrels per day but the first year average is about 60,000 barrels per day. This decline in producing rate is typical for solution gas drive reservoirs. We intend to develop the field down to 160-acre well spacing as proposed in Rule 2. This is consistent with state-wide field rules and allows us to better maintaJm oil production rate. This well spacing should improve interwell communication and increase recovery. It is also compatible with our plans to waterflood the field. Solution ~as drive reservoirs exhibit an increase in Ds rate once the free gas evolves in the reservoir to a saturation ~reater than critical Ess saturation. This increase in produced ~as occurs about three years after start-up accordinE to this forecast. In the Phase I project, some of the produced gm~ will be used as fuel in the production facility and base camp. All remaining gas will be returned to the reservoir throuEh gas injection wells. Gas injection during primary production will help reservoir pressure and may provide minor recovery benefits due to hi,h-pressure gas drive. However, we anticipate break-through of injected Eas into production wells close to the injection area. Since there is no primary gas cap in Kup~uk, gas will III - 7 AGO 10023621 be injected into the oil column. This, is significantly different from saturated reservoirs such ~s Prudhoe Bay (Sadlerochit) in which ~as is injected into the gas cap, increasing the energy of the gs~ cap drive. Injected ga~ may channel through the Kuparuk reservoir and force the nearby wells to be shut-in due to high gas production. When gas sales facilities become available, the injected gas will be produced frcm the injection area for fuel and sales. Estimates of oil recoverable under primary methods range from 8 to 14 per- cent of the original oil in-place. This wide range of estimates is due to several uncertainties. The reservoir description is an importer parsmeter in determining the amount of oil recovered. Additionally, the effects of gas injection on recovery are difficult to assess because of uncertainty with regards to channeling and sweep efficiency. A final parameter which can significantly affect primary recovery is the estimate of producing well abandonment rate. We used an abandonment rate of 100 barrels per day per well in these studies but it is apparent that this factor can change sub- stantially as economic conditions change. VII. SECONDARY RECOVERY STUDIES Initial ARCO conmitment to Kuparuk develo~nent was announced in 1979 at which' time only primary production could be justified economically. Since that time we have been encouraged by successful delineation drilling and by improving economic conditions to consider an increase in the scope of the project both in terms of areal extent of development and with regards to secondary recovery operations. Optimum recovery method in light of the III - 8 AGO 1002B622 ,,, current economic and operating environment is believed to be waterflooding. Waterflood technology is well established in the oil industry although problems associated with operating water injection facilities in the Arctic environment have been studied for the first time by Prudhoe Bay engineers. One of the major question for Kuparuk waterflooding is the identification of a water source. ARKD is presently testing the feasibility of producing water from some Upper Cretaceous sands. An altern'~.tive water source is the Beaufort Sea. Plans for early waterflood testing in Kuparuk are dependent upon establishing the Upper Cretaceous as a viable source, however, eventual full-field water- flood plans can proceed normally regardless of whether Cretaceous or Beaufort Sea is the ultimate water source. We are studying waterflood potential for Kuparuk to address the following paramet ers: 1) Oil recovery due to pattern waterflood in the various areas of the field. 2) Oil rate anticipated from field-wide waterflood development. 3) Plan of production facilities to acconmodate waterflood. Further detailed information regarding ~-~tificat'ion, possible faulting, level of injectivity, fluid properties, presence of natural fractures, aquifer activity and other parameters must be obtained before we can pre- dict waterflood recovery with confidence. III - 9 AGO 10023623 IV. DRILLING My name is Pete VanDusen. I am the District Drilling Engineer for ARCO Alaska, Inc., North Slope District, in Anchorage. I have v~rked with exploration and development drilling at Prudhoe Bay, Kuparuk and the North Slope since early lg75. ~ I am here tod~y to explain the impact of Proposed Rule 3 pertaining to casing and cementing requirements, Proposed Rule 4 pertaining to blowout prevention equip~nent and practice and to make coranents on related subjects. Generally, Proposed Rule 3 is consistent with 20 AAC 25.030 of the Alaska Oil and Gas Conservation Conmlission Re~tlations in that casing and cementing proErsn~ must be designed to: 1. Provide adequate protection of all fresh waters. 2. Provide adequate protection of productive formations. 3. Provide protection from any pressure that may be encountered, including external freezeback within the permafrost. In addition, Proposed Rule 3 is Similar in form and content to conservation Order No. 98-A, Rule 3, as ~mended by Conservation Order No. 137, Rule 1. These conservation order rules pertain to casing and cementing requir~ents for Prudhoe Bay Kuparuk River Oil Pool and are presently in effect along and within the eastern edge of the proposed Kuparuk River Field. As such, the proposed Rule 3 represents a geographic extension of an existing conservation order with the following notable differences' IV - 1 AGO 10023625 Specific sizes and types of surface casing which are suitable for use within the proposed field boundaries are so indicated in Section (e). These sizes and types have been tested and field proven to pro- vide adequate protection for further operations. A combined total of over 300 oil, ~ injection, water source, and disposal wells have been successfully drilled and produced in the Prudhoe B~y Unit without a single failure attributable to permafrost freezeback or thaw subsi- dence. Over 40 wells including exploratory/delineation wells have been drilled in the Kups~k field with similar 10(F0 positive results on those tested. 3~ A mechanism by which other sizes and types of surface casing may be approved for use in the' future is provided in sections (e)(4) and (f). Alternative completion designs to cementing and perforating ~re allowable in section (h). These alternates include slotted liners, wire wrapped screen liners, with or without gravel packing, and open hole "bsmefoot" completions. While present studies justifying these types of completions are not, as yet, complete, it appears that such completions may offer ~ means to reduce formation damage and improve overall recovery. One recent open hole completion in the Prudhoe Bay Unit and tv~ recent open hole tests in the Kupsmuk ~ll have given positive results. It is proposed that the field rules should contain language permitting such ccrmpletions on ~ drilling permit basis and not require Conservation Order exceptions each time one is proposed. IV - 2 AGO 10023626 . 5~ e Section (k) represents an mtiition to Conservation Order No. 137, Rule 1, and embodies Alaska Oil and Gas Conservation Cxonmission Re~lation 20 AAC 25.030 (d) pertaining to the use of non-freezing fluids. Simply stated, within the permafrost interval non-freezing fluids will be placed inside casing or inside any annulus between two strings of casing. Non-f. reezing fluids will also be left inside any tubing string unless such fluids can be continuously heated to maintain a temperature above the freezing point of the fluid. An example would be Central Production Facility Disposal Well #1 which has a circulating glycol system to warm the disposal tubing which often contains freezable fluids--i Section (1) was an addition to Conservation Order No. 137, Rule 1. We considered, early in 1980, to resolve a conflict be~n sections (h) and (k) in the event that a productive horizon is identified between 500 and 700 feet below the permafrost. We now feel that this producing condition will be a very special situation should it arise and should be handled by special exception to the Conservation Orders rather than by Field Rules. We therefore request that Section (1) be deleted. Conservation Order 98-A, Rule 3 as amended by Conservation Order 137, Rule 1 is otherwise acceptable in its present form. This includes allowable surface casing setting depths between 500' below the base of the permafrost and 2,700' TVD. We desire to retain this allowable depth range in order to maintain flexibility and to assist us in our complex directional progrsn~. AGO 10023627 I now direct your attention to proposed Rule 4 relating to blowout prevention equipment and practice. A~ain, referring to existing Conservation Order No. 137, Rule l, the notable chan~es or additions proposed are as follows: . Section (a) is reworded to indicate that the blowout prevention equipment and its use shall be in accordance with API Recon~nended Practice 53 except as modified by this section. This re~or~g ensures consistency with Alaska Oil and Gas Conservation ~ssion Regulations 20 AAC 25.035(a) (1). . Section (c) is revised to state that the working pressure rating of the blowout prevention equipment shall be in excess of the max~ anticipated surface pressure with a factory test pressure of twice the working pressure rating. This wording is consistent with good oilfield practice, is consistent with 20 AAC 25.035(c)(2) and anticipates a reduction in field pressure over time. . Section (e) relates to test pressures and is revised to allow testing of the blowout prevention equipment at a pressure in excess of the maximum anticipated surface pressure. In addition, testing of the blowout prevention equipment is specified whenever such equipment is changed. These revisions bring section (e) into conformance with 20 AAC 25.035(d)(1). In all other respects, proposed Rule 4 is identical with existing Conser- vation Order No. 137, Rule 1. IV - 4 AGO 10023628 The changes which h~ve been proposed will ensure conformance with existing retaliations and are consisten~ with ~ood oil£ield practice. This concludes my testinony on Proposed Rules 3 and 4 and related Kuparuk subjects. IV- 5 AGO 10023629 I. V. Wk~l, C(1VIPLETIGNS, FACILITIES AND SURVEITJ~ PRCKiRA~ II. Nr. Chairman and members of the Al_~__ka Oil and Gas Conservation ~ssion, my name is John S. Dayton s_nd'I sm presenting engineering testimony on behalf ; of ARCO Al~%ka, Inc. I received my Bachelor of Science degree in Chemical and Petroleum Refining Engineering in 1974 from Colorado School of Nines and have been employed as a petrOleum engineer since that time. I have been employed by ARCO for the p~st 20 months and mm currently the Senior Operations Engineer for development of the Kuparuk River Field in our North Slope District. All of my efforts have been concentrated on the surface production facilities and well completion aspects of Kuparuk development since my employment with ARCO. Prior to employment with ARCO, I was employed by Amoco Production Company where my assignments included various operations and facilities engineering assignments in Wyoming, Colorado, and Cook Inlet, Alaska. My testimony today will touch on three topics. First, I will describe typical Kupmruk well design and well completion technique alternatives we are investi- gating. Following that, "I will descr'lqS~'-"in general the surface production facilities we will install or have already installed for our Phase I development of the Kuparuk River Field. Thirdly, I will present our field- wide reservoir surveillance plans. PHASE I W~I, CO~LETIONS Development drilling in the 20 section Phase I area comrenced in October, V-1 AGO lO02B6B1 1979 with a single drilling rig. Subsequently, a second drilling rig has been brought into the area, and a total of 26 Kuparuk wells have been drilled and cased to date. Our development drilling progress is illus- trated on ARCO Exhibit V - 1. Fourteen of these wells have not yet been perforated. T~o or three injection wells are also planned frcm Drill Site "B" to acconnodate disposal of produced gas back into the Kuparuk oil pool. We will complete Phase I develot~nent drilling on 320-acre spacing by December, 1981. I now show you ARCO Exhibit V - 2, which is a simplified wellbore diagrmn which illustrates the design of a typical Kuparuk producing well. This design is consistent with our proposed Field Rule No. 3. From initiation of continuous production, gas lift will be used to artificially lift produced fluids. Our 7-inch 26 lb/ft K-55 production casing was selected to allow gas lift in 3-1/2 inch tubing. 1 The typical completion has five to seven gas lift mandrels in the tubing string which will provide flexibility required by fluctuation in gas lift supply pressure, well productivity, and produced water-oil ratio. III. SAFETY SHUT-IN SYSTEMS In accordance with proposed Field Rule No. 5, each well capable of unassisted flow of hydrocarbonsI to the surface will be equipped with a surface safety. valve (SSV) on the wellhead and a subsurface safety valve (SSSV) in the tubing string at a depth of 500 feet or greater below ground level. Oar pre- sent control system design incorporates high/low pressure pilots as shown on ARCO Exhibit V - 3. Each safety valve has its own independent high/low pilot. V - 2 AGO 10023632 The SSV and SSSV will close when either an out of range high or low pressure condition is detected. With the current Kuparuk development well casing program, there is no safety advantage to setting the SSSV below the permafrost. Previous research in the Prudhoe Bay Field concerning caS.lng collapse forces generated by thaw-freeze- back cycles has resulted in the ACE~C approved casing design criteria which has effectively eliminated the casing collapse problems experienced in early Arctic wells. To allow reaching development well locations from centralized drill site locations without excessive hole angles, the kickoff point in some wells has been moved to as high as--~'00' "below ground level. A mininmm SSSV setting depth of 500 feet will provide adequate distance to perform any required wireline work. Shortening the hydraulic control line length to the SSSV and limiting the line to the vertical portion of the hole will reduce the risk of damaging both the valve and control line while running in the well. This in turn, reduces the probability of control valve failures and associated high cost repair work. Therefore, we suhnit the requirement of placing the SSSV below the permafrost should be waived in favor of a more shallow setting depth. Our present SSSV's are a tubing retrievable, spring actuated flapper type valve which requires positive pressure on the control line to open. The internal profile within this valve has been designed such that in the event the valve becomes inoperable, the valve can be mechanically locked open by wireline and a separate wire!ine retrievable SSSV can be installed in the profile. The wireline retrievable valve is similar in design and will V - 3 AGO 10023633 IV. function off the same hydraulic control line. The disadvantage of the smaller wireline retrievable SSSV is that it has a restricted internal pro- file and, therefore, must be pulled prior to performing any other wireline work such as reperfora~ing, pressure surveys, production logs or changing gas lift valves. ~ION TECHNIQUES During the production testing of the exploratory wells associated with Kuparuk River oil pool, bottom-hole pressure buildup information consistently indicated a high degree of "skin" ~e or impedin~nt to flow in the near wellbore region. This phenomena has also been experienced in our develop- ment well tests. Various measures are being taken in attempts to identify the source of, and remove near wellbore danmge in order to acheive better well flow efficiencies. These activities can be grouped as follows: 1. Drilling fluid studies 2. Perforating technique studies 3. Stimulation technique studies 4. Open hole production tests Varying types of mud systems including oil base, fresh water base, and salt water base muds have been tested in an attempt to identify which produce the minim%~ amount of skin d~T~gge. There are approximately 20 test points available to compare the effectiveness of these various mud V - 4 AGO 10023634 systems. Presently, we are unable to draw even tentative conclusions since inspection of data reveals that the numerical ssmpling is too and the results are too widespread to formulate any conclusions on the system which minim~Tes skin damage. We are currently using an oil base mud system for drilling Phase I development wells. However, high costs, safety concerns, and envLronmental liabilities associated with any oil-base mud system make this system le~s desirable than water-base mud systems. Our efforts will continue in the future using various mud systems in order to come up with a system which does minimize skin damage near the wellbore. We have used both through tubing and casing type well perforators in Kuparuk River wells. Neither technique has resulted in consistent, unstimulated well flow efficiencies in excess of 60 percent. Plans' are being made in using a tubing suspended perforating system which will combine the advantages of both the through tubing and casing type techniques. Large perforating guns with deep penetrating charges are used below a packer with a net pres- sure differential into the wellbore to assure inrnediate flow into the well to clean perforations of cement and formation debris. In addition, the perforation density will be increased to 12 perforations per foot, which should maximize effective ccmmmication between the reservoir and the well- bore. Development of an effective, perforating, technique which would result .. in well flow efficiencies approaching 80 percent, could eliminate the need for inm~diate well stimulations. To date, the only successful solution to the problem of skin damage has been to stimulate the well with a hydraulic fracture treatment. This type of stimulation is designed to provide a highly permeable flow path through the damaged region. Well flow efficiencies greater than lO0 percent have V - 5 AGO 10023635 been achieved with fracture stimulations. Attempts to increase flow efficiency through acid type st imnlat ions have been unsuccessful to date, and in fact have actually resulted in additional wellbore ~. Two Kuparuk wells have been production tested with open-hole completions in an attempt to determine if the skin da~e typically observed in Kuparuk wells was introduced during .drilling operations, casing cementing operations and/or was a function of poor wellbore to formation comnmmic~tion. Both open hole tests still exhibited flow efficiencies below 60 percent. Subsequent to open-hole testing, liners were run and cemented in both wells and cased hole production tests were performed for comparison. Please direct your attention now to ARCO Exhibit V - 4 which illustrates the results of this work. In these tests, well deliverability in the cased hole tests ranged from 50 to 70 percent of that previously observed in the open hole tests. Based on these initial field observations, we feel that open-hole completions may be a practical solution to maximizing well deliverabilities without high cost stimulations and that the open-hole completion option should be maintained as proposed in Field Rule No. 3. Our plans are to pursue additional field tests to further substantiate our preliminary findings. We recognize potential shortcomings of open-hole completions with our gas injection and waterflood plans. If vertical isolation of the different pay intervals is required in the future, liners could be set at that time. We have not observed any excessive sand production during open-hole tests and have had no probl~ns in setting liners following the tests. Accordingly, we do not anticipate that hole slough/nE or sand production will present problems for extended production periods using open-hole cc~letions. V-8 AGO 10023636 V. PHASE I DEVEI~ FACILITY D~ION ARCO's Phase I development area is located approximately 26 miles west of the Trans Alaska Pipeline Syst~n (TAPS) Pump Station No. 1. I now direct your attention to ARCO Exhibit V - 5. As Mr. McMillian previously stated, the development area encompasses 20 sections and will have five drill sites, each with eight producing wells on 320-acre spacing, one Central Production Facility (CPF), 2 to 3 gas injection wells near the CPF, and a 27 mile, 16-inch pipeline connecting the CPF with TAPS Pump Station No. 1. DRILL SITES The Phase I development plans for drill sites include five pads, each approximately 1,140 feet long and 490 feet wide. A typical drill site layout is illustrated on' ARCO Exhibit V -. 6 which I now show you. Each pad will initially contain eight producing wells on 120' spacings. Each well after completion will be housed by an insulated .wellhead shelter. From the well- head, production and test flowliues are connected to two-phase production and test headers which run the length of the pad. Compressed, dehydrated gas from the CPF is diverted from a similar header back to each wellhead shelter for artificial lift. This gas will also be used as fuel for the drill site production heaters. Fluids from the production and test headers are routed in separate coils through this heater to improve the flow character- istics between the drill site and CPF. All well control and data gathering functions at the drill sites will be performed manually with the exception of the well safety shut-in systems. V-7 AGO 10023637 The rate of crude production from each well and gas lift g~s flowing to each well will be regulated by manually adjusted chokes. Normally, the flow from the eight wells flows into the production header and advauces to the CPF for processing. Any individual well may be routed to the test header for production tests at the CPF. Normally, one well from each drill site will be set up to test at any given time, and its production will flow to the CPF via the test header. Separate production, test, and gas lift lines are routed from each drill site to the CPF. These lines are supported above ground with a minLmum ground clearance of five feet at the supports. The design of the suppor~ system is similar to the Prudhoe Bay Unit flowline designs. CENTRAL PRODUCTION FACILITY The CPF can be subdivided into three major types of facilities. All of them are located together in the Phase I area as previously shown on Exhibit V - 5. These subdivisions are: 1) Oil and gas process facilities, 2) Utilities, and 3) Support facilites. I will briefly describe for you the major components in each of these categories. I will now direct your attention to ARCO Exhibit V - 7 which is a simplified flow diagram of the oil and gas process at the CPF. The oil smd gas process facilities include a single train process system. Production and test fluids will enter the CPF through the individual production and test lines from the five drill sites. At the CPF these streams will be combined into a large comTon production header or two test headers. The main production stream first enters a three-phase separator. The oil then proceeds through an electro- V-8 AGO 10023638 static coalescer and a crude surge dry, and is shipped to TAPS Ptm~ Station No. 1 through the Kuparak Pipeline. The test production streams enter one of two three-phase test separators. The separated fluids are distributed into the respective oil, gas, and water lines downstream of the primary separator. Design throughput for the oil train in the Phase I CPF is 80,000 barrels per day of oil. Produced gas from the production and test separators is combined, and enters the first stage of the primary compression system at 50 psig. Low pressure gas evolved from the electrostatic coalescer and crude surge drum is com- pressed to 50 psig and is combi~_.ed., with the gas from the primary separator. After the first stage of compression to 425 psig, the gas is dehydrated and facility fuel is taken from the main train. The remaining gas is then com- pressed in the second stage to 1400 psig. The first two stages of compres- sion are accomplished with gas-turbine driven centrifugal compressors. Initially, there will be two compressor units with a third on order for early 1983 start-up. Artificial lift gas is returned to the drill sites at 1200 to 1300 psig. Produced gas not required for artificial lift is compressed to 4000 psig with electrically driven reciprocating compressors, and is reinjected into the Kuparuk formation in the gas injection wells located at Drill Site "B". .. Produced water from the pr~ separator and two test separators is com- bined and is sent to an accumulator. This water is then pumped into a dis- posal well located on the CPF pad. Initial water disposal capacity will be 4000 BPD. The Ph~_?~e I water handling capacity was kept minimal because very little water production is expected until a field waterflood is installed. The system is readily expandable and large lines have already been installed V - 9 AGO 10023639 to handle future water production. Two horizontal process safety flares are installed at the flare pit just south of the CPF. One flare is a spare and only one flare is in service at any given time. The t~o flares are installed at a sufficient distance apart to allow maiutenance work on one flare while the second flare is in service. The inservice flare is supplied with continuous pilot gas. Flare assist gas is available to accomplish smokeless flaring. Consistent with our proposed Field Rule No. 8, flare volumes will not exceed pilot gas quantities other than in cases of emergency or operational necessity. The CPF utilities include a circulating process cooling system, waste heat recovery system on all turbines for normal process and building heat, four- teen meEawatt power plant, direct fired heater for backup heat, sewage treat- ment plant, water treatment plant for supplying potable water, and multichaunel microwave conmmmication center. These utilities are in place at this time with the exception of the waste heat recovery systems on the turbines which will be installed later this year. Other support facilities include a 350-bed construction camp, 96-bed operations center, 3000-foot airstrip with hangar and fueling station, vehicle garage, warehouse, workshop, and fabrication shop. These facilities are in place at this time. VI. KUPARUK PIPELINE SYSTEM I now refer to you to ARCO Exhibit V -8 which indicates the route of the V - 10 AGO 10023640 I . Kuparuk Pipeline between our development area and TAPS. The Kupartuk Pipeline system will consist of the booster and shippinE pumps at the CPF, crude meterinE facilities at the CPF, a 27 mile lone 16-inch diameter pipeline connectinE the CPF with TAPS Pump Station No. 1, and power ~eneration facili- ties at the CPF to run the booster and shipping pumps. This system is owned by Kuparuk Pipeline Company, ? wholly owned subsidiary of Atlantic Richfield Company and will be operated by ARCO Alaska, Inc. as a~ents for Kuparuk Pipe- line Company. The Kuparuk Pipeline system is beinE designed and constructed by ARCO Oil and Gas Company as the a~ents for Kups~-uk Pipeline Company. . The pipeline has a working pressure rating of 1440 psig and design capacity of 196,000 BPD with a single pump station operating at. the maximum ~orking pressure. Initial capacity of this system will be 125,000 BPD with a discharge pressure of 720 psig. Additional pump capacity will be required to upgrade the system to design capacity. I will show you ARCO Exhibit V - 9 which is a simplified flow diagram of the crude metering facilities to be located at the CPF. Three meters in parallel measure the crude oil flow with the meter outputs going to a total- izing flOW computer for corrected total flow rate and cunnmlative volumes. .The metering system includes a fourth meter run which will be used to cali- brate meters from other locations in the CPF. A unidirectional meter prover is included on the metering skid. Kuparuk Pipeline throughput will also be measured as it arrives at TAPS Pump Station No. 1. This measurement will be continuously compared to that of the oil leaving the CPF for leak detection purposes. Any significant discrepancy V - 11 AGO 10023641 in the volume balance of the systen will result in an alarm at the CPF. VII. RESERVOIR SURVEII~ANCE PROGRAM Previous speakers have mentioned various data which will be required to monitor reservoir performance, define reservoir properties, and provide the basis for effective reservoir management. I would like to outline for you our plans for obtaining this data. The information can be separated into three types: 1. Bottom-Hole Pressure Measur~nents 2. Well Testing 3. Production Logs BOTTOM-HOTF, PRESSURE MEASUREMENTS Throughout the productive life of the reservoir, it will be important to obtain bottom-hole pressure (BHP) information for prudent reservoir management. All reservoir pressures will be reported at the conmnon subsea datum elevation of 6200 feet. This elevation is the approximate average elevation for the center of the oil productive Kuparuk River sands in the Kuparuk River oil pOOl. The initial static reservoir pressure will be measured in each well prior to continuous production by either performing a bottom-hole pressure buildup tes~ or simply measuring the BHP after the well has been shut in for an extended period. A~ter 90 to 180 days of continuous production, the ~HP will be determined in one key well on each lease block, which consists of four governmental sections. In the more distant future, the EHP in the V - 12 AGO 10023642 design,.ted key wells will be measured on an annual basis as specified in proposed Field Rule No. 6. Additional periodic EHP measurements will also be req~Jred to examine unusual production performance in individual wells. Accurate production data is !~ critical portion of any reservoir surveillance and management program. In accordance with proposed Field Rule No. 7, production volumes from each well will be measured on a semi-annual basis under normal operating conditions 'to determine the producing gas-oil ratio. These tests will determine oil :_.g._.~,_ and water production rates, oil gravity, oil BS & W content, gas lift volumes, and flowing temperature and pressure at the controlling choke. Additionally, more frequent well tests will be taken as required for proper production allocation and prudent reservoir surveillance and operational decisions. PRODUCTION LOGS Production surveys are planned for all wells with multiple pay intervals during the first year of production to determine the' contribution from each of the various Kuparuk sand.mem~e~-S-~escribed in previous testimony. Subse- quent surveys will be run in wells which exhibit rapid changes in oil production, gas-oil ratio or water-oil ratio, and in wells which have had remedial work performed to change the production profile. V - 13 AGO 10023643 Members of the Al~ska Oil and Gas Conservation Conmission, ladies and gentlemen, my name is Paul Nor~_~rd. I am Vice President for ARCO Alzska Inc's North Slope District. The field rules proposed today officially establish the name of a new major oil field - Kuparuk River Field - on the North Slope, Alaska. Approval of these rules will insure that Kuparuk River Field development practices will be uniform and that correlative rights and conservation of natural resources will be upheld. The best engineering techniques and construction methods are being applied in Kuparuk development to minimize environmental impact and insure maximum efficient recovery from the field. The rules addressing Casing and Cementing, Blowout Prevention Equipment and Practice, and Automatic Shut-in Equipment are needed to insure safe drilling com- pletion and operation of the wells in the Kuparuk River Field. The Bottomhole Pressure Survey and Gas-Oil Ratio Tests proposed will provide sufficient surveil- lance and data to manage the field to achieve max~ economic recovery of oil and gas consistant with sound engineering practices. The well spacing proposed also provides for economic recovery of oil and gas consistant with good conservation practices. The remainder of our prac~ti_c_es_ will be accordance with the existing Alaska Oil and Gas Conservation CoRmission Regulations. Our testimony today and field rules request is based on current knowledge of the Kuparuk oil accumulation. The development and knowledge of the Kuparuk is in an early stage. Delineation drilling will continue over the next few years to fur- ther define the areal extent of the reservoir. The four wells being drilled this winter season will provide key data on which to build future plans. In this con- text it is important to have a development plan that is~ flexible to accomodate a VI- 1 AGO 10023645 broad rmnEe of eventualities. O~r current expansion plan calls for a ~ed develo~nen~ on ~he prospective 210 square mile area shown on Exhibit III - lo Two or three additional production facilities are anticipated. These facilities v~uld be similar to the Central Production Facility described earlier. These stand-alone facilities would be capable of oil, ~as and water separation and treatment, Eas dehydration and compression and produced w~ter h~udlin~. These facilities v~uld also have ~he capability to ~reat and pum~ produced and source w~ter for distribution to the drill si~es for injection. Waterflood is envisioned ~s a key part of the expansion plan. We are currently working on the first increment of w~terflooding which will ~ssess recovery and optiraize well sp~cing and f~cility design. As stated e~rlier a critical item in w~terfloodiug is developing the w~ter, source. Studies will be completed later this year. The w~terflood development would be sta~ed following prim~ develop- ment of the field. The specifics of the development plan are contingent upon the results of current and future delineation work in the Kuparuk. Substantial modification of the expansion plan n~y be required as more well data becomes available both from delineation drilling and early production history and other prospective Working Interest Owners become involved. Today's testimony by ARCO Alaska, Inc. reflects our interpretation of the existing data and our resulting action and plans. The proposed rules, however, incorporate input from other Interested Owner Companies. ARCO Alaska, Inc. is only one of several companies with productive acre~e in the Kuparuk River Field. On behalf of ARCO Alaska, Inc. I would like to thank you for this opportunity to testify. We submit that the propOsed field rules ~re in the best interest of the State of Al~_ska. AGO 100236~6 VII. P~ FIELD RULES KUPARUK RIVER OIL POOL KUPRAUK RIVER FTk-~D The rules which follow pertain to the following area' Sections 1, 2, 11, 12, 13, and 14 T10N. R9E~ U.M. Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10 11, 12, 13, 14, 15, 16, 17, and 18 Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10 11, 12, 13' 14, 15, 16, 17,'and 18 T9N~ R9E~ U..M,. Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 15, 16, 17, and 18 Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, and 12 T!0N.,. R6E~ U.M.. Sections 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 27, 35 and 36 T10N, R7E. U.M. T10N, RSE, U.M. _~rl, TiON~ RIOE~ U.M. _AT J, TION~ allE~ Ui-M. Sect ions 5, 6, 7, 8, 17, 18, 19, and 20 Tll N~ R6E, U.M. Sections 25, 26, 35, and 36 TI]N, R7E, U:M.. Sections l, 2, 3, 4, 9, 10, 11, 12 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36 TllN~, RSE~ U.M. ALL AT J, TllN,, R10E, U.M. ALL VII - 1 AGO 10023648 '., TllN, RllE~ U.M. Sections 5, 6, 7, 8, 17, 18, 19, 20, 29, 30, 31, and 32 ~, RTE, U.M. Sections 25, 26, 35, and 36 T1, 2N~ RBE~ U.M. Ail T12N~ RiOE~ U.M. Sections 2, 3, 4, 5, 6, 7, 8, 9, 1~i"-"11, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36 T12N, Rll#~ U.M. Section 31 T13N, RSE, U.M. Sections 13, 14, 23, 24, 25, 26, 27, 28, 33, 34, 35, and 36 T13Nt R9E~ U.M. Sections 3, 4, 5, 6, 7, 8, 9, 10, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36 T!3. N~ RIOE, U.M.' Sections 19, 29, 30, 31, 32, and 33 Rule 1. Definition of Pool The Kuparuk River Oil POOl, Kuparuk River Field, is defined as the accumulation of oil that is common to and correlated with the accumulation found in the ARCO West Sak River State No. I well between the depths of 6,474 and 6,880 feet. Rule 2. Well Spacing Not more than one well may be completed in this pool in a gove~tal quarter section or governmental lot corresponding thereto, nor shall any well be com- pleted in this pool in a governmental quarter section or governmental lot corresponding thereto which contains less than 125 acres. No pay shall be opened in a wellbore closer than 500 feet from a property line where ownership changes or closer than 1,000 feet from any pay in the same pool opened to the wellbore of another well. VII - 2 AGO 10023649 Rule 3. Casing and Cementing Retirements (a) (b) (c) (d) (e) (f) (h) Casing and cementing programs shall provide adequate protection of all fresh waters and productive formations; and protection from any pressure that may be encountered, including external freezeback within the perma- frost. For proper anchorage and to prevent an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface, and sufficient cement shall be used to fill the annulus behind the pipe to the surface. For proper anchorage, to prevent an uncontrolled flow and to protect the well from the effects of permafrost thaw, a string of surface casing shall be set at least 500 measured feet below the base of the permafrost section but not below 2700 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the pipe to the surface. The surface casing shall have minimum post-yield strain properties of 0.9% in tension and 1.26% in confession. The following types of casing, with threaded connections, are approved for use as surface casing: (i) (2) (3) (4) 13-3/8 inch, 72 pounds/foot, L-80, Buttress, 13-3/8 inch, 72 pounds/foot, N-80, Buttress, 10-3/4 inch, 45.5 pounds/foot, K-55, Buttress, or other types of casing meeting the requirements of (d) which have been approved by the Conmission for use as surface casing at another location on .the North Slope. The Conm~ssion may approve other types of surface casing upon a showing that the proposed casing connection can meet the requir~ents of (d) above. This evidence shall consist of one of the following: (i) (2) (3) full scale tensile and cc~0ressive tests, finite element model studies, or other types of axial strain data acceptable to the Conmission.. O~her means for maintaining the integrity of the well from the effects of pen~kfrost thaw may be approved by the Conmission upon application.. Production casing shall be landed through the completion zone. Sufficient cement shall be used to cover and extend at least 500 feet above each hydrocarbon-bearing formation. As an alternative, the casing string may be set and adequately cemented at an intermediate point and a liner landed through the completion zone. If such a liner is run, the casing and liner shall overlap by at least 100 feet and the annular space behind the liner shall be filled with cement to at least 100 feet above the casing shoe, or the top of the liner shall be squeezed with sufficient cement to provide at least 100 feet of cement between the liner and casing. If such a liner is VII - 3 AGO 10023650 (J) (k) (i) run, sufficient c~nent shall be used to cover and extend at least 500 feet above each hydrocarbon-bearinE zone or to the top of the liner, whichever is less. Alternate liner designs may be utilized through the completion zone providing such designs are supported by sound engineering principles. Such alternate designs include: (i) slotted liners, wire wrapped screen liners, or comb~tions thereof, landed inside of open hole; slotted liners, wire wrapped screen liners, or cca~binations thereof, landed and gravel packed inside of underreamed open hole. Alternately to the above, the productive interval may be completed as an "open hole completion" provided that the casing string is set not more than 200 feet above the completion zone and sufficient cement used to extend at least 500 feet above the hydrocarbon zone. Casing and any cemented liners, after being c~nented, shall be satisfactorily pressmre tested to not less than 50% of min~ internal yield pressure or 1,500 pounds per square inch, whichever is less. Such testing shall not be required for conductor casing specified in Paragraph (b) above. No well shall be produced through the annulus between the tubing and the casing, unless a cement sheath extends from the top of the pay to the shoe of the next shallower casing string. Within the perms~rost intervals, fluids which have a freezing point above the minimum permafrost temperature mmst not be left in the annulus between any two .strings of casing or inside the casing. Such fluids may be left inside the tubing across perm~rost intervals in wells in which the wellbore is continually heated such that the minimum wellbore temperatttre is above the freezing point of the fluid. With regard to cement placement, a conflict may arise between (h) and (k) in cases where a hydrocarbon-bearing interval occurs between 500 and 700 measttred feet below the base of the permafrost and the surface casing has been set at or near the min~ depth allowed by (c). The requirement for 500 feet of cement above the hydrocarbon-bearing interval may not allow sttfficient distance for the contaminated interface between the cement and the nonfreezing fluid. In designing the placement of the nonfreezing fluid and the cement below, a ~ distance of 200 feet mnst be allowed for this contaminated interface, depending upon the method chosen. For these cases, the minimtun ca~nent requirement for the first hydrocarbon-bearing interval below the base of the permafrost shall be reduced from 500 to 300 feet. VII -4 AGO 10023651 R1Lle 4. (a) (b) (c) (d) (e) Blowout Prevention Equi~nent and Practice The blowout prevention equipment and its use shall be in accord~ce with AP1 ~ded Practice 53, '~lowout Prevention Equipment Systems", except as modified by this section. Ail blowout prevention equipment ~hall be maintained in good operating condition at all times and shall be adequately protected to insure reliable operation under the existing weather conditions. Ail blowout prevention equipment shall be checked for satisfactory operation daily. Before drilling below the conductor string, each well shall have installed at least one remotely controlled annular type blowout preventer and flow diverter system. The annular preventer installed on the conductor' casing shall be utilized to permit the diversion of hydrocarbons and other fluids. This low pressure, high capacity diverter system shall be installed to provide at least the equivalent of a six-inch line with at least two lines venting in different directions to ensure downwiud diversion and shall be designed to avoid freeze-up. These lines shall be equipped with full- opening valves or other valves approved by the Conm~ssion. A schematic diagram, list of equipment, and operational procedure for the diverter system shall be submitted with the application Permit to Drill or Deepen (Form 10-401) for approval. The above requir~nents n~Y be waived for subsequent wells drilled from a multiple drill site. Before drilling below the surface casing, all wells shall have three remotely controlled blowout preventers, including one equipped with pipe r~ms, one with blind rams, and one annular type. The blowout preventers and associated equipment shall have a working pressure rating in excess of the maxinmmm anticipated surface pressure from zones to be penetrated and a factory test pressure of twice the working pressure rating. The associated equipment sh~J1 include a drilling spool with min~ three- inch side outlets (if not on the blowout preventer body), a min~ three- inch choke manifold, or equivalent, and a fill-up line. The drilling string will contain full-opening valves above and inn~diately below the kelly during all circulating operations with the kelly. Two emergency valves with rotary subs for all connections in use will be conveniently located on the drilling floor. 0~e valve will be an inside blowout preventer of the spring-loaded type. The second valve will be of the manually-operated ball type, or any other, type which will perform the same function. Ail ram type blowout preventers, kelly valves, emergency valves and choke manifold shall be tested to their working pressure rating or to a working pressure in excess of the max~ anticipated surface pressure from zones to be penetrated. Such testing shall be conducted when equipment is installed or changed and at least once a week thereafter. Annular pre- venters shall be tested to 50% of working pressure rating when installed or changed and at least once each week thereafter. VII - 5 AGO 10023652 Rule 5. Automatic Shut-In Equi~ent Upon cc~pletion, each well capable of flowing hydrocarbons to the surface sh~.ll be equipped with a su/table safety valve installed at a depth of 500 feet or greater below ground level. Such valve will automatically shut-in the well if an uncontrolled flow occurs. Ail producing wells will be equipped with a surface safety valve which will automatically shut-in the wells in .the event of an emergency. Rule 6. Bottomhole Pressure Survey Prior to initial continuous production from each well, a maximum bottomhole pressure test shall be taken. A bottomhole pressure survey shall be taken in one well on each lease which consists of four governmental sections between 90 and 180 days after comrencement of production. A key well bottomhole pressure survey will be taken annually thereafter. These key wells will be determined within two years of establishing production from a drill pad. Until such time as the key well has been determined, a bottcmhole pressure survey will be taken annually in the smme well as chosen for the initial survey after commence- ment of production. Bottomhole pressures obtained by a static buildup pressure survey, a 24-hour shut-in instantaneous test or a multiple flow rate test will be acceptable. The datum of the test and other details will be determined by the.. operators subject.to approval by the Conmission. The test results shall be reported on Reservoir Pressure Report Form P-12 which shall be filed with the Conmission by the fifteenth day of the month, following the month in which each test was taken. Rule 7. Gas-Oil Ratio Tests Between 90 and 120 days after continuous production starts and each six months thereafter, a gas-oil ratio test shall be taken on each producing well. The test shall be of at least 12 hours duration and shall be made at the producing rate at which the operator ordinarily produces the well. The test results shall be reported on Gas-oil Ratio Test Form 10-409 within fifteen days after completion of the survey. The Conmission shall be notified at least five days prior to each test. Rule 8. Gas Venting or Flaring The venting or flaring of gas is prohibited except as may be authorized by the Ccrmnission in cases of emergency or operational necessity. AGO 10023653 I-1 II - I II - 2 II - 3 II - 4 II - 5 III - 1 III - 2 III - 3 III - 4 III - 5 V-1 V-2 V-3 V-4 V-5 V-6 V-7 V-8 V-9 EXHIBITS Nap of Kuparuk River Field Location Field Rules Boundary Structure .~p of Kuparuk River Formztion Cross Section A - A' Cross Section B - B' Isopach of Kuparuk River Formation ~i~p of Oil Pool and Participating Area Type Log - West Sak No. 1 Rock Properties Water Saturation vs. Height Above Water-Oil Contanct Phase I Oil and Gas Rate Development Drilling Wellbore Diagr~n Kuparuk Well Safety System Well Inflow Performance Nap of Phase I Area Drill Site Layout , Flow Diagram of CPF's Oil and Gas Process Kuparuk Pipeline Route Flow Diagram of Crude Metering Facilities at CPF VIII - 1 AGO 10023655 SIMP. LG EXISTING BAY FIELD NE PT. R U LQE~OE WY fill m m I I I d,,,, KOOKPUK I I I I I I I I I I---.1 ROPOSED F KUPARU KALUBIK UGNU NO. ~ · I OLVlLLE 04 03¸ ~)E. UGNU · 07 12 se 33-29E I~'EILEEN ! ! N. KUPARU C ELD RULES~iAREA ~, ARCO Alaska, Inc .,.........,...... i~ EXHIBIT T- lIVER OIL POOL~ i, I( RIVER FIEI~D I" Ii ~, AGO PRUDHOE BAY UNIT 10023656 ~YR AY -T, .............. $ ....................................... ~ ....................... I ~b$1dllry of Atlilnt~Richfi~l<:tCo4~plny .p~_O_.D.20 [ EXHIBIT TI':""i ; ~r - AREA MAP POSE FIELD RULES AREA ---'- --------- , · ARCO Alaska, Inc. L-mm.I 13, KUPARUK RIVER OIL POOL KUPARUK RIVER FIELD , AGO 10023657 'i I I I I I UGN , ,, :j ! I ' 33-29 E . .~ooo GWYDYR BAY - ! N. KUPARU.,~ , , / , PRUDHOE i I /~ BAY' / /' ~ UNIT: ,; I · ;;i...:,~:..:',:.'.,.:.., '/."~','""":!~."~"::::'::':",'" "'.:"" '":' ''~ · '"' '"' " "'':...:.d;.. --' 10 · ~.. ·; ~',~ :~:::.,!',~,%~,t',~ ;'~':".:'. ~: · -, .....'.'....: . . .,,:: : . ·, · ' ' · :~ .., '- ..... """; m" ARCO Alaska, Inc. ...'. - . ....,,. ....... , , , , " ' ' . ' ,i ~' su~m~-~vo~ ..... · . ·., · . . L . . · . · ~ -~ - · ~ ~ ,i -- !..,:;.......:. . ...';':,.,:'.?;;..:.;:.:' ". .: . .· '..'.....:.- . · .'.. - ....' : ....' ? .· .."" .:6,o,:, ,....' /.' i ".' 'j · "...,:'.'..,:: ...... ..' .... m ' " '~' "' '" ' '" .... '; " ' '-" -' ' / I · ...':..-;-.' ,:. zo ." ,.??"',' i' ..... . "",... EXHIBIT "*"":'' '"'"'"'""''""'"' ' ' '*~' ' ' '" ''~"'r'' '"' ~,~U cTu R ~M ./,...::~,;;.; o :.:::".':!;..h..~.' _~ PR~13t"3~1:'1"3 I:'ll:'/r'3.1:lll/l:C:::: A~:~pCA'Ir?i(,',~'~p--,m--mmm-,--m.-m-,.'..!~,?.., ;', :~¥~":'.':i:~''' i!.:~,.""'/,.:"'.".'(!;,"'.'.. '. I mmmvmvv'm--"m,~"' mm .m~-,,-,-n,,,,~ mmvn-.,.I,,,,~,~,~ ,i,'""~mlm.,,.-,l'~. m./j..,. ~!..... .. · ..,, .......: -: :,. ,' ...... :. :':";~':'~i'!:"i::"?'!:: ':'";"':'"!:;":':'? "'' "'''''''-'''"'"'''"''''''-'''"J'""*':"'"':'"n,v'.='n ,,,,n ..... ~..., .: . . . .. .. .:.. . :. . .. .. .: ,,:. ;. .. . , : .. . . . . ..,.~., .,:;. 'ri. i:.~'il; ';. ,..,;.iii! ;ii.;. i'!:;~':'.'.:: .i.:'.'. '..'";"' :"..!'.'......'. KUPARUK RIVER OI L::,: p O O L'!; '"'" ': :'~::';!i;'~:.i::iii':~{:::))::: :::!;i!ii~:.;'"':'''' ':'' ' '.:' "' ":../ii.}.:" .' . '."... ,.~"' KUPAR :' · 'j~; ,-.,-'.'..' :, ~ :... ,'.~', . · . : . · ... ::' :..' . . .' , , .' ...... ,..: .. · ~:~,-,,..', .... .:. . ., ....... : .... ..... : .. ...... ..... .. . ~','.,;?i~i:.'..'.::,: ,", t.u :~::!:~i.;..:...~,:.t..'.... :.,. · .... ,,.' ..:.". ..... ,'. : : ,;:. ,:'..,~,., , .. · · . ' ' . . ,.,,~;~:...,.,...~.. _ :,.::..,:.~..,~.::.::.,,.. ...: .....,....~:, ..... ..., KUPARUK -.---, ,...-,.,,.,...,~,..~.~,,.,, ..... .. .... ...... - .. ,. . '"~" ' "~' ;~J"l~?'"~?~"?-~'"~"~'~,l" ' u?~'~":'"' ;? :;~"~4' ' '/i~'~"'l!;'~ '?";: r~?; ' '; ' "~'" ~'/~'i~; ~"'; ".~t..."'.~ ~ :~'~: ~')~'~'~ . .i.:~.~,~ ;.r...2;. ~.,.; ;,~ ~,,~;.~ ~ ..,' ;;i',':' ': ". '~'~"~ ::i~*'Pr "~:~'''~ '~ ' '' ' '' ?'.n~'q;%~- r ·., n"~.?'~'~1~? 'i~'i~' '~:': :' ~:: '' . ''' '':~., ~-, ..4...~ ...~1, ~. ..... ~: : '.' ....... .... ..: "; ': "':' ;... ':'-~ "*. '..- ''"- ,' ' ...""%" '?"::' '"":·' .. ;., ,..... :,.:.:'" ..... .:'%' '?'~::'" ?'": ?'' ~ "' '~" '"' ;"' f;"' ""' "'''' '"~ ?: :''" '''' '.......; ' f{: '...'' "..-..:"'"..4'"' '" '¥" "' :""" .i: :'"'" ' ." ":..... ''' ;...' '"" ;'' ': ':"~' 4'~ : ": :'~'.;.'''':'''''' · , ...1¥~."' :' ;"~'": ' '. '...: .:. , , '' ':;':; :?.' :"''"'"'., :" ..... ';".. ' . . · f' .'~P ":.." ''"'" '· .... :.' ,.. ;~n' ~...~. ";: ' ' ;'.:.. ": .': :!'., %."' J':'" '. .. '.-" ': "':'~':'...." '.." ' ' ' '~": .:'~'~.'" ' ' :' *': ",'. ': "" :' · ' ""~'~':" ' ' ........ ~.,1~ - ,:..' . . .... · . ':" '~' "1.. ' . .o . .i..~r.: :. . ..... . ' ' "' ". ' '!:" * ;" ": '' ,~,m~... . . ' '', ',..' ', . '.'. ' .':.,"',." ' '"'~ '. ": '!. .' .;' ."t . .. ~'~ '· !li"l' :' ': '"" ' ' ' } · '~'"';"":'" '~'"" ~:'~';i :'3,' ....... : ." ".' .'" · ;.' .. '.. ..",l~.,-. ' .' ''. ..... - " ..... '." ' ."-.'. '· ".. ' ' : ":." '" ".'.7'" 'i;v.: .:4-.~,...'.',..:.., : ...... · "' . ' '., ' ,' .. '. "L- ':'.-,i '.. " '' ...... . "" ' ' · . ' ' · ',· '.':: '" '"'.'"" W. S~ 9 5oo' ,ii ,. · · .eood .?ood 30o' ~GO 100 Z3 65 B '5600' '6000' -6500~ -?000~ W. SAK 4 ~~GH GAMMA RAY SHALE ' AND ,":~ ' i~!:;;~:~,' UNNAMED L. CRETACEOUS ** ~K'UPARUK RIVER FM, . - .~.~ ~~ ~-.-.-...' .. ,,....;, ::.:,: ~i~;;" /f; ; KINGAK SHALE 10° DEVIATION W. SAK 3 ~ W. SAK 2 JECTED) W. SAK 7 SW.NE STRUCTURA£ CROSS SECTION KUPARUK RIVER:FIELD VERT. EX. 20X W. SAK 1 .... · · .v SOCAL 33-29E · . I I N. W. EILEEN 1 ARCO Alaska,/nc. Subsidiary o~ AtlanllCRichflelCiCompany EXHIBIT .4 BI '5600' ... '6000' '6500' ... '7000' AGO i0023659 i...I NE .+ 6oO ' /uo u r---J// ~E. UGNU 1 12 33- 29 E i~'EILEEN B t 8 p G BAY I ! 20 i I/ PRUDHOE! /,/! ..... . BAY · NPRA !? · I/' I I I i I I ~,. I I I I' 13 I UNIT '-'1 ,,// ' ARCO Alaska, Inc. s,.,,.,,~, og Alta~k::Richflei4Co41NMny EXHIBIT ~ :5 " PROPOSED FIELD RULES AREA r---:------""""" KUPARUK RIVER OIL POOL KUPARUK RIVER FIELD ISOPACH MAP · KUPARUK RIVER .FM. AGO 10023660 NPRA// /. t ' ~ ~-"'~ ~* ~ ~ ' ' ~ BAY ~ UGN NO. I · ~-- ~ k. ~ E~EE~ " ~~co~,~ e~ l~.e · · ~--~- - ~21 17 ! [ 13 I ~ j PRUDHOE . ..... , ! ', BAY ~ ~ ~ I UNIT 110 ~! I I I I I I ...................... '"' ............................ ~ ....................................................................................... ~ ................ ARCO Alaska, Inc. ~ ............. Subl, ldilry OI A,kinflcRlchfl~k:!Complny ~D ' EXHiBiT 3]:E:1 : .P.R.O. POSED FIE RULES AREA ,'-------------" · -- --------------------------~ DEVELOPMENT A'REA KUPARUK RIVER OIL POOL KUPARUK RIVER FIELD AGO 10023661 D~L 1 'I ARCO Alaska,, Inc. ,:EXHiBiT ~-2 TYPE LOG AGO 10023663 0 .~.-~..~; ~ --. · . .~. ;?~:i"7- ~', ..?'.-~__ - ~,. :.;': - i~' .~.. ...- .. . _ !~ . ~ ... .... . . .~ .. ~ . ::~ ~ ';~. .. ~ ..-:I~-i . · ~ .,'.' - ~ · . ..... ~ ~ · . - ~.~-,- . ~ · -,. ~'. ~ ..~ .?...~. . ,, ~ . ARCO ALASKA INC.; EXHIBIT 111-3. AVERAGE RESERVOIR ROCK PROPERTIES THICKNESS (F-'t.) POROSITY (%) UPPER SAND MIDDLE SAND LOWER SAN D 37 20 8 20 24 21 PERMEABILITY (Md.) · 125 250 ..2 100 ! % % , \ % IGH' Upper Sand (Sideritic Intere;al) .. Upper Sand (Clean inlerval) and Middle. Sand ,, Lower Sand · . ,.~ :' WATER"SATU AGO 10023665 20 · ! ! 0 1982 ,... GAS MMSCFID .......... E' ,..-....- OIL MSTBID i~..", ~..:. ~' ';: .--. ,. ,. :.-:'f' .: '..~. ~7 ~,E: .."; 1985 1990 1995 2000 · 2005 . . . : '.'. '. - .... : .,~ ,.-::~ .... -..iii. :.. ': :: -~ :.' 0 0 __ KUPA D -~ . OONDUCTOR /I ~ 16" 65~ H-40 CSA 80' ARCTIC-PAK ANNULU.S-----,-- CEMENT TO SURFACE , :;5 i/2" SAFETY VALVE_,,// e _+ 1900' MD I ' i SURFACE CASING ~ I ! ~ 10 ;3/4" 45.5~ K-55 ~ i ' CSA APPROX, 2700' SS. , CEMENT TO SURFACE ~ ;5 I/2" GAS LIFT MANDRELS ,,... (5-7 TOTAL/WELL THROUGHOUT TUBING) : / 3 I/2" 9.2::1:1:J-55 BTC TUBING ~ ~ ;5 I/2:"X 7" PACKER SET: 2:00' ABOVE KUPARUK -.~------------ PROFILE NIPPLE (:::T::5~-_._.___._ W:rRELINE GU.]:DE :: :: KUPARUK -'; ;; HORIZON I ' PRODUCTION OAS ZNG , 7" 26:1:I: K-55 --I ~- CSA + 200' BELOW KUPARUK CMT. TO 500' ABOVE HIGHEST HYDROCARBON BEARING INTERVAL. . ' ' ......... ' ARCO EXHIBIT ~- 2_ ......... TYP ZCAL KUPARUK WELL .... I J ........... ........... ' '~os .o,' ~o~' No=lb~,e m, "' .... i°r'' REV: :,DRTE DR'.tN .... REVISIONS, ........... ENOR , ,,,, | , { ..... 200'5710001, I AGO 100~3668 j HIGH/LOW PILOT · (2 PRS. )--~ 'PRODUCTION SURFACE SAFETY VALVE ~ TO FACILITY (SSV) LOWER MASTER VALVE ,. FROM - HYDRAULIC .. GROUND SOURCE ELEVATION - - SUBSURFACE SAFETY VALVE (SSSV) i I , J - , , mill -- ................. ARco EXHIBIT ~- 3 ............... TYPICAL KUPARUK WELL SAFETY SYSTEM, ...... , ........., ""~'";s-2'5-S'il~'~'"~jAL..... 1 ~"'~" aD'''.. .......... '" '~ "'°' ~~, ~I''~' l ~'' ",,- ............................ 200'5710002 AGO 10023669 ' :5400 3000 2600 220O 1800 -5 OPEN HOLE TEST C-4 OPEN HOLE TEST C-4 CASED HOLE TEST CASED HOLE TEST ARCO Alaska, Inc. Subsidiary of AllanllcRichlieldComp-ny ARCO EXHIBIT ~Z-4 OPEN HOLE VS. CASED HOLE INFLOW PERFORMANCE RELATIONSHIPS WELLS C-4 AND E-5 MARCH 25,81 JAL AD NO: SCALE, i SHT - I J?p .o, isu~.Jos "o:lowo..o, OF 1400 I000 AGO i0023670 BOPD" ~- 2003910000 ~> 0 0 L~ TI~N REFERENCE DRR~INGS: DRTE DRUN NORTH SLOPE DI~D!.ICT AR CO EXHIBIT KUPARUK PROJECT AREA MAP l REVISION EN~n lid 1'1o,200;~710000 1sCRLEI IS"T. 1140' I I C) 0 0 (3', DRILL SITE PRODUCTION HEATER FLOWLINES TO CPF 12" 6" GAS ! ! 140'---d' RESERVE PIT--~~ ! I L, o'_o"j (TYPICAL) I !~ ~6d-d' CAMP 490' t REFERENCE DRAWINGS: REVISION ENOR .= aRCO EXH I B I T ~Z'-16 KUPARUK PHASE TYPICAL DRILL SITE DRTEt II DRRVNw .MAR. 25,1981 ho.o, ISCnL~, JOB NOI IUOJO~ NO1DWO NOI TEST 8~ PRODUCTION FROM DR ILL SITES TO KUPARUK PIPELINE ,.~ I CRbDE S UR G"E LI DRUM SH IPP ING BOOSTER PUMPS PUMPS TO DRILL .-...- SITES GAS LIFT TEST HEADER PHASE GAS FIPR IMARY I'"~ ~,..S, EPARA TOR,~] WATER TEST t l'~ EPARATOR,~,2 2ND STAGE COMPRESSION GAS E[,_E,CTROST/NT ~C ~= OIL NQ..OALESCEF~/ [ T~ GAS DEHYDRATION ACCU . SCRUBBER INd[OTION COMPRESSORS TO GAS INJECTION WELLS REFERENCE DRRWINGS: REVISION ENGR TO WATER D I SP OSAL WELL t NORTH ~LO~E DIg. TnlCT - i~HOR~ ARCO EXHIBIT ~- KUPARUK CENTRAL PRODUCTION FAC IL I~ "~oo39~o~ I'~"'[' NTS ~> 0 0 0 O~ ,.4 o o 0~ REFERENCE DRAWINGS= OIL PRODUCTION FROM SHZPPZNG PUIVPS KUPARUK P IPEL INE STRAINER R II II II !1 I! /!1 ~' II METER I! METER ~ ESD P ZG VALVE LAUNCHER IVETER PROVER LOOP ( UN ZD ]'RECT TONAL OIL SAMPLER REVISION , ,, t ARCO EXHIBIT ~-9 KUPARUK PIPELINE METER lNG FAC IL ITIES ~"°~39,0001 I'cnL~' NTS I,"T' o~ BP Alaska Exploration, Inc. 510 L Street, Suite 307 Anchorage, Alaska 99501 Sohio Alaska Petroleum Company 3111 C Street, Pouch 6-612 Anchorage, Alaska 99502 March 25, 1981 BEFORE THE ALASKA OIL AND GAS CONSERVATION COMMISSION KUPARUK POOL RULES Mr. Chairman, members of the Commission, my name is John A. Reeder and I am Senior Attorney for Sohio Alaska Petroleum Company. On behalf of BP Alaska Exploration, Inc. and Sohio Alaska Petroleum Company, which I will refer to as the BP/Sohio group, I wish to offer a supplementary statement to the testimony submitted on behalf of Arco. The BP/Sohio group commenced exploration on the North Slope in 1958, and in 1964 it acquired its Kuparuk Field leases jointly with Sinclair, now Arco. The BP/Sohio group is now one of the major leaseholders in the Kuparuk Field. Leases in which the BP/Sohio group have interests cover approx- imately 70% of the area included within the proposed Kuparuk River Pool Rules. The BP/Sohio group has participated in exploration drilling in the Kuparuk River Field from the beginning, starting with the Colville No. 1 well in 1966 and the discovery well, Ugnu No. 1, in 1969. In total, the BP/Sohio group has participated in 13 of the 25 exploration wells in the proposed Kuparuk River Field area. As a result of several years of appraisal and evaluation activities in the field, the BP/Sohio group is now in the process of planning, together with AGO 10023511 Arco, for the timely and efficient development of the field, including secondary recovery evaluation. It is expected that field development will be carried out pursuant to a unit operation; negotiations looking toward unitization have been underway and considerable progress has been made. The BP/Sohio group has actively worked with Arco in drawing up these proposed pool rules and would recommend to the Commission that they be implemented. We can also state that we generally support Arco's testimony today. We believe these rules will provide for the safe and efficient development of the Kuparuk River Field, while minimizing environmental impact, and are in the best interests of all concerned. We thank the Commission for this opportunity to submit testimony in support of the Kuparuk River Pool Rules. BP Alaska Exploration, Inc. Joh~f' A.' Reeder S~io Alaska Petroleum Company AGO 10023512 AGO 100~3B13 AGO 10023509 ARCO Oil and Gas C~' any Pos', Office B:)x 3.50 ,.%r',cl~or~ge. Alasha 99517 ~etep!~one 907 277 5637 Jerry J.,. District F;uparuk Engin.~cr March 16, 1981 Conmissioner Lonnie Smith Alaska Oil and Gas Conservation Con, mission 3001 Porcupine Drive' Anchorage, AK 99501 Dear Commissioner Smith: In an informal meeting on January 29, 1981, you expressed concern the Kuparuk Pipeline Company had not yet contacted the Comnission' to describe metering and meter proving facilities under authority of 20 AAC 25. 230. This letter has been prepared in response to that request. The crude oil metering system for the Kuparuk Pipeline consists of 12" NPS inlet and outlet header piping with three (3) 4" Brooks Parity Turbine Meter runs and provision for a 4" meter run to include a 2" Brooks Fractional Parity Turbine Meter. The meter runs will include inlet and outlet block valves, strainers, turbine meters, straightening vanes, local instrumention (pressure gauges, theaters, .pressure relief valves), and instrumentation required for remote proving (temperature transmitters, pressure transmitters and one (1) Waugh Multi-Channel Liquid Flow Computer). F. H. Maloney will provide a skid mounted 8" NPS ANSI 600fi unidirectional Maloney UNIBALL Meter Prover and instrumentation suitable for remote proving and local proving. Maloney will also provide a True Cut Sampling System, with all associated equip- ment, to be installed in the 12" outlet header. This crude oil metering system basically models the system at TAPS Pump Station No. 1 with exception to the particular vendors used to supply the equip- merit. All the equipment referenced in this letter was purchased as per latest AP1 Standards quoted in the Alaska Oil and Gas Conservation Conntission Authority 20 AAC 25. 230. Attached for your reference is a basic mechanical flow and instrumentation grawing showing the intended facility. If you have any further questions or conments, let us know and we will be happy to address them. Very truly yours, .... ~'"~ ~J. Pawelek mlk SERVICE '. / /..,. ~ I 'C~r ATLANTIC RICHFIELD COMPANY ~'~0J[C T KU?ARUK PROJECT NOTES: SERIES %90.... APR -8 19,81 Alaska Oil& Gas Cons. ComrniSsi°13 VEEDER-ROOT's low cost ticket printer ' lets voutotalize and' " prin production records quickly remotely and economically '"" SERIES 7690 ... flnger-t.ip, printout for productior Easy Operation Just by pressing a button, the Series 7690 System gives you direct and positive ON/OFF control over remote motors and circuits. You can monitor transactions displayed on both a batch counter and an accumulative totalizer. And when you press the stop button, the system cuts off the production process, if desired, and automatically prints transaction infor- mation on a ticket. The complete operating sequence is simple. Insert the ticket and press the control switch to START PRINT. The ticket is held in place-initial reading is printed-the LED batch counter resets to zero-and a special interlock relay closes to energize an external circuit for remote process operation. Your printer is now ready to accept input signals from the system's pulse transmitter. Operation data accumulates in the printer and is displayed on two counters. The optional LED batch counter shows the amount of that particular transaction, the accumulative totalizer displays the sum of all transactions. When you press the print control switch to FINISH PRINT, the optional interlock relay immediately opens and de-energizes the external circuit. The final reading is printed and the ticket released.., a clear, accurate, permanent record with multiple copies. Best of Two Worlds The Series 7690 System is unusual 'in today's modern world of instrumentation. It combines the highest state of the art in both mechanical and electroni~c technologies.., tough and rugged, sensitive and precise. Outstanding in the art of advanced mechanical technology is the impact mechanism that does the actual printing. Built for long life with minimum service, the printing mechanism is adapted from Veeder-Root's time-tested Meter Register Dupli- cator.., highly respected in the petroleum industry for its reli- ability. The drive portion of the print mechanism features Iow inertia and minimum friction, further extending its lOng life. Veeder-Root engineers, experts in data acquisition and control designs have skillfully interfaced the mechanical printer with advanced electronic art specially chosen for the greatest electrical noise immbnity. Using common 115v-ac, the printer's own power supply provides'for all its internal needs. It also provides regulated +5 v-dc and unregulated +12 v-dc that simplify hookup with a variety of input devices.' The interlock relay supplies 115 v-ac to control external circuits for a wide range of applications. ~ . The Right System For You Whatever your control and record job, there is a Series 7690 System for you. Choose either an Accumulative Start or Zero Start model. Accumulative models ensure complete accountability. When the Start button is pressed, the total of the preceding. transaction is pdnted. At the completion of the transaction, the Finish Print total includes both present and preceding amounts. The transaction's actual output is obtained by subtracting the initial amount from the final amount. Zero Start models initially print all Zeros. The Finish Print is the actual total of the transaction. Subtracting is not necessary. ,~ I II I / VEEDER- OOT COMP,.~N,,~,. , Rack or Table Mount Models Printer is available in either rack or table mounL Table mount model shown. Rack mount model is 12" / wide between mounting centers. / Optional LED Display / of Accumulated Count for Each Production Run, / LED readout permits monitoring of individual lots. LED display is reset to zero at beginning of each start pdnL Complete Info~ On A Variety of Ticket Sizes Machine or proce fication, consecuti number and total duced are printed rickel And intem~ are provided to at a variety of ticket Tamper Proof To prevent tampering with printed information, He ticket is held in the printer and can be removed only aft all data has been printed. J___ I I IIII II I . .................. Light illuminates when 115v-ac ex- ............. /`.;~`.;~;% ..... . .. ....... . ~ ~.i'4.,t.,.,,,~. ,, r,,"'",., ,~,*, ternal power is available in the printer. .. ~_ Input Pulse Transmission Accepts signals from UL listed Series 1871 pulse transmitter or Series 7671 solid state pulse transmitter. Adapts to other inputs, including TTL, photoheads and many existing cus- tomer pulse circuits. .. . 'Remote Process Control '" In addition to initiating the starL/print, .. depressing the rocker switch actuates optional interlock' relay that per- mits external control of a mOtor starter relay or other electrical equipment., :. Variable 'Product Identification An optional feature can be ordered to provide the digits 1, 2 and 3 as 'codes for identifying separate products, machines or processes on the printed ticket. Three-position selector switch must be prOvided by the user. ~Heavy Duty Print Mechanism Printing head is the time-proven unit ~:,'..i '. used by the petroleum industry for 30 years, Electrically actuated impact printing ensures legible print through .multi-copy carbon pack. Seven-Figure Nonreset Accumulative Totalizer Located below ticket slot, the seven- figure accumulative totalizer ensures accurate recording of all product totals. The Printed Ticket... Your Complete Record. tNSER~' FACEDOWN ~ TH~S ENO · "".,": ' Actual style and size of print ,...?"'2 4 5 ? · :,.~. · · ':;.,C ;F., · .. Basic forms and carbon packs can be prepared to your own design. They can display your company imprint, space to write a department or product name, date, signatures, and other details specifically tailored to your accoUnting and record keeping. Data printed by the Series 7690 System includes the amount or number of units in a lot or transaction-gallons, quarts, barrels, feet, yards, items, ' etc. There is a three-digit serial number that advances one number for each transaction, alert- ing you to any m~ss~ng ticket by an out-of-sequence number. A two-letter code for product, location or other identification purposes is also included. If you want, you can order an option of three externally controlled digits for further classification of product, process, or machine. The printer accommodates the most popular ticket size 41/8 by 73/4 inches (104,78 by 196, 85 mm), and accepts tickets up to 47/8 inches, (123,8 mm) wide. Usually a two-part ticket is sufficient, but by using proper weight paper and carbons, up to seven copies can be printed clearly and legibly. Movable guides and adjustable stops make it easy to locate the proper print position. 5 The Series transmit in shafts, gea~ generators. Veeder-Ro~ SERIEE Series 1 Rt M ar' E~; ali User Signal P Special system i current signal p~ It allows easy ti~ circuits and mo~ with positive dis meters. 12 or 24 minimum, are c, 7690 System. L~ printer's termina SpecificatiOns MECHANICAL Figures: Nonreset totalizer with 7 figures for quick visual reference. Accumulative printer has 7 figures. Start print consists of product identity (two alpha characters selected internally to A, El, C, D, E, F, G, J, K, P, and R), consecutive sales number (3 figures), product reading (7 figures on Accumulative Start model, 5 figures on Zero Start model) and special identifiers available on request. Finish print includes product identity, lot number and production reading finish Ticket: Accommodates popular ticket size 41/4 in. by 73/4 in. (104.65mm by 196.85mm) and can accept tickets to 47/8 in. (123.7mm) wide. Movable guides and an adjustable stop simplify locating the print position on the ticket. The printer automatically holds the ticket in position until final print is made Reset: Start Print and Finish Print accomplished electrically Environment: To be sheltered from weather with a temperature range -+-41° to 106°F (+5° to 50°C). Storage temperature is 0° to 150°F (-17.8° to +65°C) Net Weight: 27.5 lb ELECTRICAL Voltage: Input is 115v-ac or can be factory converted to 230v-ac. Accepts line frequencies of 50 to 60Hz Internal Power Supply: +12v-dc unregulated, 0.1 amp available at Terminal No. 10 for external use. +5v-dc regulated, built-in circuit protection against continuous overload and short circuit, 0.1 amp available at Terminal No. 9 for external use Connections: Line cord provided for main power. A terminal strip is provided for input control functions and Iow voltage power supplies Inputs: Field adaptable. Pulser input t)sing internal or' external supply, 'l-FL input using internal or external supply, VR solid state pulser Series 7671 using internal or external supply Line Protection: Electronic circuits fused for 1.0 amp. Reset motor fused for 5 amp Count Speed: Accumulative Start model: 1800 cpm. Zero Start model' 1.200 cpm 1.750 ] - (44.5mm) (304.8mm) . _ %' ?,',' .- -: ;-'i, ',~ :' ,2:~ "",'"':"'; '; ': ','~: ~r.'~ ~?,; ,,,, ', ,,: ,. ".',,' ', ', '~,' ,:¥:~, /' :,:~,. ,.;i,~,F~=::,.'' ' .', ,,"',.':, .. ,:,,; ',,r ,~,{{' ",, ,,(~',¢, ,'.:,: ': ,: ............ ; ......... ' ..:.%;. ' -~ .. · .. ,,, ,,,, u,,}m=~;m.' '":' / ' "~ "I ',, ~,': ? . ,. · ~,,-~.:;. ,;,',~ ;~ ," ~,'~4~. - ... ~..~ = 12.688 ~ 0.719 (322.3mm) (18.3mm) 14.250 (361.9mm) 13.125 (333.4mm) 6.970 ( 177.0 m m) (269.9mm) · . . . . ...... ""?""':"'"""" ;"::: ....... :i-'i ':':"":"~; · ,r." ' .,-,, ,. :,,',, ,.'-, · : ",i,'~; "" . ~., ,,, .., . ,. ' "; .'.' ............. , , . ..... · - ,-.;' ., ,~ ~ . . .%.,. · . ..- .,' ... ~ % ¥ ! · · . ,'; ""'"' ':': 'i~! "" ":' ' ':'" ' ... . . ..:,',. )~-..: .,~;.~;, ........ " ,~, ~ ~:,'. :~, ' .t · · · ' '~ ~"'"": ~!ii:"'""" "'*' ::' :';:"':' ':'/j~ ":'"'" :': :':;"' :'! 6 f't 1.3 7 5 (1.8m) (34.9mm) 1.875 (47.6mm) THE 7690 FOR YOU... To get the final details on how the Series 7690 Ticket Printer Will best help You in industrial applications, call your local Veeder-Root Authorized Distributor. Or write directly to · Veeder-Root, Digital Systems Division, Hartford, Connecticut 06102. If you like, call. Our phone is (203) 527-7201. Ask for extension 425, 484, 485, 201 or 380. The Total Capability Company VEEDER-ROOT Digital Systems Division Hartford, Conn. 06102--(203) 527-7201 ^ v~o~ ,Nousr.,£s co~^~.~- VEED£R-ROOT WORLD WIDE: ARGENTINA; t)uenos Aires · AUSTRALIA: Melbourne · IgRAZIL: gao Paulo 363~ CANAOA: Toronlo · ENGLAND: CI0yd0n, Surrey · SCOTLAND: Dundee · WESt' GERMANY: Neidh'msen/hlder A5 '"'~? 7 u.s,~, F. H. MALONEY C(LMPANY. UOX 2.~7. tl(}U.%1'ON. 'IEXAS Wa. ret-Draw Calibration o£ Displaced Vol.[ Ty~e..ofl~rover. Desi~n:i nld;t-~,': i~;nnl. {Date: Pipe . -'-d~;)Wall Average C a n Scale Reading Prover Volume Below Press. Cu. Ia. Zero + Zero ' PSIG : . ' Cu. In. Cu. In. 5S 1 1 5,!. 9 5 TOTA I, 2311.4l 231'.)8 ~ctual ~uantity Read Cu. In. AverS. Temp, Prover 't File: 9-5/47 CAI, IBRATION REPORT Meter Prover Serial No. P-S1 170.9 Certified Con:ainers Used . N%m. Size Gal. [ ~ I0 Volume Cu. In.[I/~4.95 ' ~311.~t Serial No. ;;1i14 ] IGSi 4680 4G7~ Averg. Temp. Temp. Correction Liquid Factor Drav, m 14 1 i t18..95 67.5 67.5 1S 232.6.-1 i .... 191~ 23394 .... 23311 .... 200 233()~ " 2O5 ,t 711 I 9589~.~,36 1307 58 1 ! 5,t. 95 15 2311 .-11 15 21t312 4 73 . ,. TOTAL 9,,~.):~. 3~ 1297 97203 58 115,t.95 15 'i f; 231 O8 1';9B 23107 2')4 - -~ 23102 19(i NECK 231 ~7 [ 2ol D I.:Atf -[ ,!82 · .1._(,.. ,I 1 233fli 23312 2330G . 469 · 97193.36 1169.95 2327.41 2330.1 ' " 23311 " 2330,~ " 482 - f'AI..('[ U,AT TOTAL i)5lg.()G . 36 : 13ltl -I Certify that this Calibration was done in accordance With l* Vol. Adj. to 60° at Calibration Pressure From To. 11.:;Y~, 95 1: :'}:;()-1. 223O8. I ! :i :! 1 '2. O0 ,I 73. ',.-, .,~.. ] 169.95 ~,~'qC~x.-~,l ' ' 23300. ~7193. 2:::.11 ! )"'*' l.d 172F)~1. Total average volume (~ 60OF and calibrating pressure .. : (Not corrected for pressure effects) " 972° ~ . 03 (Calibrating pressure to atmospheric) ..-::.:' a' '' m: [..q9981,~ 971g:_~.95 .'. that this jsa True and Exact C. Pr~sst~re correction ~act°~* for~ ~teel in prover ' 'J ~: Copy of the Original Data .:~:/'~: (Calibrating ~ressure to atmbsvheric) J . ' ::' Sheet. .~:.::.:' '~: ~-::"~;)'~f'~:- ": i ~~-- . . . . . ... 97igt) !3 ..:- /~'_LQ':;?%i:':,.:Z?,.'~ ~.~t~:~'::";: :'/:_ :i ' atmospheric pressure : ' ':t::::. . . ~-[ ', ~ . '):t:~ [ "'WITNESS -' ~' -' TITLE '" REPRESENTING I [7f~-5~. : : ~: '~l ~:~ : ' j '.: ,. . · .: ' ' ~ --j . I-Trot .n,. '?. -t.-.'l ;~ I - ' '~I /5-( ' 'a~- ~ .......... ~'- '..::: ~'77 ': ' '~ : 4':~- ' :':'' - [ .......... . ~ ,. (.-=?~': ~(-- -'-;." - 'j ' '- _.- ..Y. 't: J ~mlt~is.~[~,~~ :i ' . :',>;:~-7 ~.:-'2 :.~ - : ez.i:::q ::;."'~:: if · ' cc,,~,~ R';'_ ~ ENG ' 1 ENG ' ~'":- 2 ENG ;~ (:.EOL ,~T ',T TEC~? ST.',,T TECT-' ............... H. D. Hale,/ Manager of Production Ventura Division March 13, 1981 Conoco Inc. 290 Maple Court Ventura. CA 93003 (805) 642-8154 ?CONFER: State of Alaska Alaska 0±1 & Gas Conservation Committee 3001 Porcupine Drlve Anchorage, Alaska 99501 Gentlemen: Last February you recelved a letter from Mr. Vic Lyon wlth Conoco in Houston askin~ that the Mllne Point unit be included in the area for which Arco has asked and proposed a set of Kupurak Rlver formation fleld rules. This is to advise that Conoco now wishes to exclude the Milne Point unit from these rules and we will continue to operate under the state wide rules. As YOU are aware, we have three producine formations at Milne Point and we are now drillin~ confirmation wells. For this reason it ls believed that we should have a separate set of regulations applicable to the different formations prevalent in the Mllne Polnt unlt, and a set of field rules wlll be proposed by Conoco after we have determined the unit boundaries and have accumulated additional reservoir data. Very truly yours, H. D. Haley Division Nana~er of Production mc ADVERTISING ORDER Anchorage 840 West Fourth Avenue Anchorage, Alaska 99501 NOTICE TO PUBLISHER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISE- MENT MUST BE SUBMITTED WITH INVOICE. A!a~a Oil and Cas Conservation Omm~ssion 3001 Porcupine Drive ~mchorage, Alaska 99501. VENDOR NO. 2. PUBLISHER DEPT. NO. A.a. NO. 4055 DATE O F_.A ~. ~nrua~ 3, 1981 DATES ADVERTISEMENT REQUIRED: _~mbruazy 5, 1981 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. BILLING ADDRESS: AFFIDAVIT-OF-PUBLICATION UNITED STATES OF AMERICA STATE OF Alaska Third DIVISION. BEFORE ME, THE UNDERSIGNED, A NOTARY PUBLIC THIS DAY PERSONALLY APPEARED Edith Yan WHO, BEING FIRST DULY SWORN, ACCORDING TO LAW, SAYS THAT HE/SHE IS THE Legal Clerk OF The Anchorage Times PUBLISHED AT Anchoraqe IN SAID DIVISION __~AND STATE dE Alaska AND THAT THE ADVERTISEMENT, OF WHICH THE ANNEXED IS A TRUE COPY, WAS PUBLISHED IN SAID PUBLICATION ON THE 5th DAY OF February 1981, AND THEREAFTER FOR 00 CONSECUTIVE DAYS, THE LAST PUBLICATION APPEARING ON THE 5th .DAY OF February 19 8~, AND THAT THE RATE CHARGED THEREON IS NOT IN EXCESS OF THE RATE lx 4 inches $16.80 L79181 CHARGED PRIVATE INDIVIDUALS. SUBSCRIBED AND SV~pRN TO BEFORE ME THIS 10th DAY o~February ~1_9~!. NOTARY PUBLI~S/FOR STATE OF_ Alaska MY COMMISSION EXPIRES. ..May lstr 1982 REMINDER- ATTACH INVOICES AND PROOF OF PUBLICATION. AGO · NOTICE,OF PUBLIC: ' ,. , · ~ "CO~,MI SSfON · ".' Co~v.'otl0n File No.'J?.3.' e;..T....,,~ ~11" ' ' ~' ~':"' , ' vember; 2t~: 198ClA. fO~."J~t~; O'rdi~r ,-setting "for'f.h the-i~J3ooT.r'i~le~ for -,'the dlev~lol~h~enf.~hcl, p~qdbcflon · 0f the Koporuk River Formo- · .flon,.'..west of' the PFudhoe Boy Field. ................... :"' .~)trc"~ is:h~'/~'i~'~;'eh'that At- -I~ntlc;.Rlchfleld .Company h0s · requested the.,' A'losldo .OII ond · Gas. C0ns~v~]fiprt ~;~l~imi_~.'jon to Issue or~ ~rd~'r setting fbrth the 'pool roles ,'fbr tNe'.'develop- ment and production of. the Ku- por. uk: River. For~at. lar) west of · ··t~fe·· Prudl3oe* ;Bay commission .wil~ s~k' festlmbny n order· to name the' fletd,' de- 'fine thai pool,· dete¢~e~the ' wefts, Impo~e ~os$1~le'~ri~In~ and · produ~:flon requlrem~ents , and .consider.' any and dll qther ' .data. that might be dee~ed ;nec- ' essa'fy for-th~e.i S~fe and orderly deyeloPment df the area and the · I~r~ventl0n'"of ·waste.. The con- .fractlqn of*the area of the pres- [.*&htly ~lefined Prudhoe. Bay Ku- 'l~'ruk River OII Pool ~vili also be .considered. .~ · · "." Notice:' I~' further'giVen ,,,at o · public hearing will be held at I' 9.~00 AM, We.d. nes. d.oy; March 25, .1981 In the. Municipality 'of .An- ~.'chorage Assembly Room, 3500 .. Eost.-Tudor Road, A.r%cl~orage, -'4Alasl~a.' 'All 'J~teresf~d.; persons .and~.pnrties 'a~es~i~'.to ~ive 'tes:flmo~*..,:. ,:.?i2~ ~.. :;,..~'i . · ,. . ~,.,.R...)., ~'0'rr~_'~. ~r~ ....... ~:.-'... Alaska OII and*~as'* ': '..". Conservation'Com~lssti~t: I . ;:.. Aa-08 ~55 ~" ' , ,'~~,:~ _~., '.~, ~,1: ,'.' i' ,',, ,, ,, . ~,. Pub,."~'e§£~FY.'5~',i 981 .' .... ' ,.. ,. ... 10023515 NOTICE OF PUBLIC HEARING STATE OF ALASKA Alaska Oil and Gas Conservation Commission Conservation File No. 173 Re: The application of Atlantic Richfield Company, dated November 25, 1980, for an order setting forth the pool rules for the development and production of the Kuparuk River Formation, west of the Prudhoe Bay Field. Notice is hereby given that Atlantic Richfield Company has requested the Alaska Ofl and Gas Conservation Commission to issue an order setting forth the pool rules for the development and production of the Kuparuk River Formation west of the Prudhoe Bay Field. The Commission will seek testimony in order to name the field, define the pool, determine the area to be affected, deter- mine the optimum spacing of the wells, impose possible drilling and production requirements and consider any and all other data that might be deemed necessary for the safe and orderly develop- ment of the area and the prevention of waste. The contraction of the area of the presently defined Prudhoe Bay Kuparuk River Oil Pool will also be considered. Notice is further given that a public hearing will be held at 9:00 AM, Wednesday, March 25, 1981 in the Municipality of Anchor- age Assembly Room, 3500 East Tudor Road, Anchorage, Alaska. Ail interested persons and parties are invited to give testimony. Harry W. Kugler Commissioner Alaska Oil and Gas Conservation Commission AGO 10023516 ARCO Oil and Gas~' ~pany North Slope'._ ,strict Post Office Box 360 Anchorage, Alaska 99510 Telephone 907 277 5637' Jerry J. Pawelek District Kuparuk Engineer November 25, 1980 Mr. Hoyle Hamilton State of A1 aska Alaska Oil and Gas Conservati on Commi ssi on 3001 Porcupine Drive Anchorage, AK 99501 Gentlemen: Attached for your consideration is a-list of field rules which ARCo Oil and Gas Company proposes as changes to the present Alaska Statewide Conservation Rules. These rules would define as the Kuparuk River Field a new area west and north of the ex- isting Prudhoe Bay Unit which is not now defined. A portion of this area is currently being developed by ARCo. These rules will apply to the Kuparuk River Oil Pool within this new, potentially productive area called the Kuparuk River Field. They will define the geologic interval effected, detail certain drilling practices to be used within the area, and out- line the completion and producing practices to be followed if the defined interval is productive. ARCo, by this letter, requests that the Commission take what- ever steps necessary to get these rules adopted. If a hearing is required, we would recommend Wednesday, February 25, 1981, for the hearing date. ~ "~"~ .............. '~" Si nerely, /. d. d. Pawelek District Kuparuk Engineer JJP/JFM:sp Attachment RECEIVED DEC- 1980 Alaska 011 & Gas Cons. Commission Anchorage ARCO Oil and Gas ComparW is a Division o[ AllanticRichfiefdComp~ny AGO 20023527 PROPOSED FIELD RULES KUPARUK RIVER OIL POOL KUPARUK RIVER FIELD The rules which follow pertain to the following area: T9N, R6E, U.M. TION, RIOE, U.M. Sections l, 2, ll, and 12 T9N, R7E, U.M. Sections l, 2, 3, 4, 5, 6, 7, 8, 9, 10, ll, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 27, 28, 29, 30, 31, 32, 33, and 34 Sections l, 2, 3, 4, 5, 6, 7, 8, 9, 10, ll, and 12 TION, RllE, U.M. T9N, R8E, U.M. NONE Sections l, 2, 3, 4, 5, 6, 7, 8, 9, 10, Il, and 12 TllN, R6E, U.M. Sections 25, 26, 35, and 36 T9N, R9E, U.M. Sections 3, 4, 5, 6, 7, 8, 9, and l0 TION, R6E, U.M. Sections 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 35, and 36 TllN, R7E, U.'M. Sections l, 2, 3, 4, 9, 10, ll, 12, 13,./]..4, 15, 16, 17, 18, 19, 20, 21, 22~ 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36 TllN, R8E, U.M. TION, R7E, U.M. ALL ALL TllN, R9E, U.M. TION, R8E, U.M. ALL TION, R9E, U.M. RECEIVED DEC- ]980 Alaska 011 & Gas Cons. Commission Anchorage ALL TllN, RIOE, U.M. ALL ALL AGO 10023518 ,, TllN, RllE, U.M. Sections 5, 6, 7, 8, 17, 18, 19, 20, 29, 30, 31, and 32 T12N, R7E, U.M. Sections 25, 26, 35, and 36 T12N, RllE, U.M. Section 31 T13N, R8E, U.M. Sections 13, 14, 23, 24, 25, 26, 27, 28, 33, 34, 35,-~nd 36 T12N, R8E, U.M. ALL T12N, R9E, U.M. ALL T12N, RIOE, U.M. Sections 2, 3, 4, 5, 6, 7, 8, 9, 10, ll, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36 T13N, R9E, U.M. Sections 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36 T13N, RIOE, U.M. Sections 19, 29, 30, 31, 32, and 33 Rule 1. Definition of Pool The Kuparuk River Oil Pool, Kuparuk River Field, is defined as the accumulation of oil.,~..that is common to and correlated with the accumulation found in the ARCO West Sak'River State No. 1 well be'i~ween the depirh'S?'of 6,474 and 6,880 feet. Rule 2. Well Spacing Not more than one well may be completed in this pool in a governmental quarter section or governmental lot correspondi.ng thereto, nor shall any well be com- pleted in 'this pool in a governmental quarter section or governmental lot corresponding thereto which contains less than 125 acres. No pay shall be opened in a wellbore closer than 500 feet from a property line where ownership changes or closer than 1,000 feet from any pay in the same pool opened to the wellbore of another well. AGO 10023519 Rule 3. Casing and Cementing Requirements (a) Casing and cementing programs shall provide adequate protection of all fresh waters and productive formations; and protection from any pressure that may be encountered, including external freezeback within the perma- frost. (b) For proper anchorage and to prevent an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface, and sufficient cement shall be used to fill the annulus behind the pip6 to the surface. (c) For proper anchorage, to prevent an uncontrolled flow and to protect the well from the effects of permafrost thaw, a string of surface casing shall be set at least 500 measured feet below the base of the permafrost section but not below 2700 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the pipe to the surface. (d) The surface casing shall have minimum post-yield strain properties of 0.9% in tension and 1.26% in compression. (e) The following types of casing, with threaded connections, are approved for use as surface casing' (1) 13-3/8 inch, 72 pounds/foot, L-80, Buttress, (2) 13-3/8 inch, 72 pounds/foot, N-80, Buttress, (3) 10-3/4 inch, 45.5 pounds/foot, K-55, Buttress, (4) or other types of casing meeting the requirements of (d) which have been approved by the Commission for use as surface casing at another location on the North Slope. (f) The Commission may approve other types of surface casing upon a showing th~.at,.the proposed casing conn~ection can mee.~t.~.~he requirements of (d) aboVe. This evidence shall Consist of one'Of the following: (1) full' scale tensile and compressive tests, (2) finite element model studies, (3) or other types of axial strain data acceptable to the Commission. (§) Other means for maintaining the integrity of the well from the effects of permafrost thaw may be approved by the Commission upon application. (h) Production casing shall be landed through the completion zone. Suffi- cient cement shall be used to cover and extend at least 500 feet above each hydrocarbon-bearing formation. As an alternative, the casing string may be set and adequately cemented at an intermediate point and a liner landed through the completion zone. If such a liner is run, the casing and liner shall overlap by at least 100 feet and the annular space behind the liner shall be filled with cement to at least 100 feet above the casing shoe, or the top of the liner shall be squeezed with sufficient cement to provide at least 100 feet of cement between AGO 10023520 the liner and casing. If such a liner is run, sufficient cement shall be used to cover and extend at least 500 feet above each hydrocarbon- bearing zone or to the top of the liner, whichever is less. Alternate liner designs may be utilized through the completion zone providing such designs are supported by sound engineering principles. Such alternate designs include: (1) slotted liners, wire wrapped screen liners, or-combinations thereof, landed inside of open hole; (2) slotted liners, wire wrapped screen liners, or- combinations thereof, landed and gravel packed inside of underreamed open hole. Alternately to the above, the productive interval may be completed as an "open hole completion" provided that the casing string is set not more than 200 feet above the completion zone and sufficient cement used to extend at least 500 feet above the hydrocarbon zone. (i) Casing and any cemented liners, after being cemented, shall be satis- factorily pressure tested to not less than 50% of minimum internal yield pressure or 1,500 pounds per square inch, whichever is less. Such testing shall not be required for conductor casing specified in Paragraph (b) above. (j) No well shall be produced through the annulus between the tubing and the casing, unless a cement sheath extends from the top of the pay to the shoe of the next shallower casing string. (k) Within the permafrost intervals, fluids which have a freezing point above the minimum permafrost termperature must not be left in the annulus between any two strings of casing or inside the casing. Such fluids may be left inside the tubing across permafrost intervals in wells in which the wellbore is continually heated such that the minimum w,ellbore temperature is above.the freezing ~o~nt of the fluid. (1) With regard to cement placement, a conflict may arise between (h) and (k) in cases where a hydrocarbon-bearing interval occurs between 500 and 700 measured feet below the base of the permafrost and the surface casing has been set at or near the minimum depth allowed by.(c). The requirement for 500 feet of cement above the hydrocarbon-bearing interval may not allow sufficient distance for the contaminated inter- face between the cement and the nonfreezing fluid. In designing the ~ placement of the nonfreezing fluid and the cement below, a maximum distance of 200 feet must be allowed for this contaminated interface, depending upon the method chosen. For these cases, the minimum cement requirement for the first hydrocarbon-bearing interval below the base of the permafrost shall be reduced from 500 to 300 feet. AGO 10023~21 Rule 4. Blowout Prevention Equipment and Practice (a) The blowout prevention equipment and its use shall be in accordance with API Recommended Practices 53, "Blowout Prevention Equipment Systems", except as modified by this section. All blowout prevention equipment shall be maintained in good operating condition at all time and shall be adequately protected tSo insure reliable operation under the existing weather conditions. All blowout prevention equipment shall be checked for satisfactory operation daily. (b) Before drilling below the conductor string, each well shall have installed at least one remotely controlled annular type blowout preventer and flow diverter system. The annular preventer installed on the conductor casing shall be utilized to permit the diversion of hydrocarbons and other fluids. This low pressure, high capacity diverter system shall be installed to provide at least the equivalent of a six-inch line with at least two lines venting in different direc- tions to ensure downwind diversion and shall be designed to avoid freeze-up. These lines shall be equipped with full-opening valves or other valves approved by the Commission. A schematic diagram, list of equipment, and operational procedure for the diverter system shall be submitted with the application Permit to Drill or Deepen (Form 10-401) for approval. The above requirements may be waived for subsequent wells drilled from a multiple drill site. (c) Before drilling below the surface casing, all wells shall have three remotely-controlled blowout preventers, including one equipped with pipe rams, one with blind rams, and one annular type. The blowout preventers and associated equipment shall have a working pressure rating in excess of the maximum anticipated surface pressure from zones to be penetrated and a factory test pressure of twice the working pressure rating. , (d) T'~e'associated equipment shal~'~ include a dri"~q"ing spool with minimum three-inch side outlets (if not on the blowout preventer body), a minimum three-inch choke manifold, or equivalent, and a fill-up line. The drilling stringwill contain full-opening valves above and immediately below the kelly during all circulating operations with the kelly. Two emergency valves with rotary subs for all connections in use will be conveniently located on the drilling floor. One valve will be an inside blowout preventer of the spring-loaded type. The second valve will be of the manually-operated ball type, or any other type which will perform the same function. (e) All ram type blowout preventers, kelly valves, emergency valves and choke manifolds shall be tested to their working pressure rating or to a working pressure in excess of the maximum anticipated surface pres- sure from zones to be penetrated. Such testing shall be conducted when equipment is installed or changed and at least once each week thereafter. Annular preventers shall be tested to 50% of working pressure rating when installed or changed and at least once each week thereafter. AGO 10023522 Rule 5. Automatic Shut-In Equipment Upon completion, each well capable of flowing hydrocarbons to the surface shall be equipped with a suitable safety valve installed at a depth of 500 feet or greater below ground level. Such valve will automatically shut-in the well if an uncontrolled flow occurs. All producing wells will be equipped with a surface safety valve which will automaticallzF shut-in the wells in the event of an emergency. Rule 6. Bottomhol.e Pressure Survey Prior to initial continuous production from each well, a maximum bottomhole pressure test shall be taken. A bottomhole pressure survey shall be taken in one well on each lease which consists of four governmental sections between 90 and 180 days after commencement of production. A key well bottomhole pres- sure survey will be taken annually thereafter. These key wells will be determined within two years of establishing production from a drill pad. Until such time as the key well has been determined,.a bottomhole pressure survey will be taken annually in the same well as chosen for the initial survey after commencement of production. Bottomhole pressures obtained by a static buildup pressure survey, a 24-hour shut-in instantaneous test or a multiple flow rate test will be acceptable. The datum of the test and other details will be determined by the operators subject to'approval by the Commission. The test results shall be reported on reservoir pressure report Form P-12 which shall be filed with the Commission by the fifteenth day of the month, following the month in which each test was taken. Rule 7. Gas-Oil Ratio Tests Between 90 and 120 days after continuous production starts and each six months thereafter, a gas-oil ratio test shall be taken on each producing well. The test shall be of at least 12 hours duration and shall be made at the producing rate at which the operator ordinarily produces the well. The test results shall be reported on gas-oil ratio test Form 10-409 .within fifteen days after completion of the survey. The Commission shall be notified at least five days prior to each test. Rule 8. Gas Venting o.r Flaring The venting or flaring of gas is prohibited except as may be authorized by the Commission in cases of emergency or operational necessity. 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L (( LONER RECEIVED DEC- 3 ]980 Alaska Oil & Gas Cons. Commission Anchorage AGO 10023525
