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Home My WebLink AboutCO 207 e e Image Project Order File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. e / 0 cl. 0 7 Order File Identifier Organizing (done) o Two-sided 1IIIIII1111111 I1II1 o Rescan Needed 111111111111111I111 RESCAN ~olor Items: o Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) o Maps: o Other Items Scannable by a Large Scanner o Diskettes, No. D Other, NolType: D Poor Quality Originals: OVERSIZED (Non-Scannable) o Other: o Logs of various kinds: NOTES: Date 9 7 Job o Other:: BY: C Mari0 /s/ ~{J Scanning Preparation BY: ~ x 30 = Date q /7 / oft; + 1111111111111111111 /s/ W1iP = TOTAL PAGES 3 J Y- (Count does not include cover sheet) 'AAf /s/ V VI Project Proofing BY: ~ Maria) Dateq 7/0h Production Scanning 1111111111111111111 Stage 1 Page Count from Scanned File: "6' 5' (Count does include cover sheet) V YES Page Count Matches Number in Scanning Preparation: Date:q 17/ ofo NO BY: ~ /s/ MP NO Stage 1 BY: If NO in stage 1, page(s) discrepancies were found: YES Maria Date: /s/ 111111111111111111I Scanning is complete at this point unless rescanning is required. ReScanned 111111111111111111I BY: Maria Date: /s/ Comments about this file: Quality Checked 11/1111111111111111 10/6/2005 Orders File Cover Page.doc Index Conservation Order 207 PRUDHOE BAY FIELS, LISBURNE OIL POOL I. October 26, 1984 2. November 15, 1984 3. November 23, 1984 4. November 29, 1984 5. December 7, 1984 6. March 22, 1985 7. May 15, 1985 8. August 7, 1985 9. August 12, 1985 10. September 30, 1985 II. January 7, 1986 12. August 19. 1986 13. August 28, 1986 14. February 6, 1987 15. March 6, 1987 16. April 3, 1987 17. June 1, 1987 18. April 6, 1989 19. June 22, 1989 20. March 25, 1992 21. November 5, 1992 22. August 9, 1993 23. August 12, 1993 24. October 21, 1993 25. June 15, 1994 26. May 14, 1996 27. June 5, 1996 28. July 8, 1996 29. August 31, 2006 Notice of Hearing, affidavit of publication, address notifications Arco Alaska's request for adoption of pool rules Inter-office memo re: 11/8/84 meeting Transcript of hearing Sohio Alaska ltr re: Lisburne Field Rules Testimony AOGCC ltr re: Arco's request for an exception Arco's request for admin approval Arco's request for a waiver from Rule 3 AOGCC ltr to Arco informing operator of approval of Admin Approval Arco's request Admin Approval for K-55 Casing Arco's request to conduct a test on a 5 spot well pattern to evaluate directional permeability Arco's request to include Sec 29 into pool rules Notice of Hearing Arco request Admin Approval for additional flaring duration (CO 207.5) Arco's authorization to flare-startup of the Lisburne Depropanizer unit Arco request Admin Approval for injection of treated seatwater into L2-30 (CO 207.7) Arco's request for a pressure monitoring program for a 2 year observation Lisburne Waterflood Review Arco request to Modify Rule 10 Arco's request to flare at LPC, Module 4926 Arco's request for a short-ternl downhole separation test for L5-24 Arco's request for amendment to pool rules Recommended Amendments for Lisburne Oil Pool AOGCC ltr re: Amendment to pool rules Arco's request for approval for flaring up to 60 MMscf of gas Arco's request for approval to use reservoir pressure data obtained from acoustic liquid level measurements to meet the annual pressure survey requirement AOGCC response to 6/5/96 œquest Arco's request to revise Rule '7 Prudhoe Bay Filed - Annual Surveillance Reporting requirements to AOGCC Ì'. ""~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: Request by ARCO ALASKA, INC.) et al to present testimony ) to revoke Conservation Order) No. 83-C and adopt new rules) for the Lisburne Oil Pool ) in the Prudhoe Bay Field. ) Conservation Order No. 207 Prudhoe Bay Field Lisburne Oil Pool January 10, 1985 IT APPEARING THAT: 1. ARCO Alaska, Inc., on behalf of itself and Exxon Corpo- ration, requested the Alaska Oil and Gas Conservation Commission to hold a public hearing in order to receive testimony for the revocation of Conservation Order No. 83-C and establishment of new pool rules for the development and depletion of the Lisburne Oil Pool in the Prudhoe Bay Field. 2. Notice of the public hearing was published in the Anchorage Times on October 26, 1984. 3. A public hearing was held at the Municipality of Anchorage Assembly Room, 3500 East Tudor Road, Anchorage, Alaska on November 29, 1984. 4. Members of the staff of ARCO Alaska, Inc. presented testimony on behalf of itself, Exxon Corporation and Sohio Alaska Petroleum Company. Exxon Corporation presented a statement in full support of the testimony. The hearing record remained open until 4:30 pm, December 10, 1984. Timely comments were submitted by Sohio Alaska Petroleum Company and Mr. Kelley Everett~. FINDINGS: 1. The Lisburne Group underlies the Sadlerochit Group and consists primarily of shallow marine limestone and dolomite with lesser amounts of shale, silt, sand, and chert. 2. Shaly or silty beds are fairly continuous over a broad area and are useful for correlation. 3. The Lisburne Group is characterized by abundant natural and predominately vertical fractures which allows for fluid movement through the carbonates as well as the thin silty and shaly beds. Conservation Ori No. 207 Page 2 '~ January 10, 1985 4. The Lisburne Group of carbonate sediments was penetrated in it entirety by ARCO Prudhoe Bay State Well #1. The top of the Lisburne Group was encountered at a measured depth of 8,790 feet and the base at 10,440 feet measured depth. 5. The Lisburne Group has been partially or fully pene- trated by numerous wells. Oil and gas has been encountered within the Lisburne Group as low as 10,050 feet subsea within the area described by Conservation Order No. 83-C. 6. Evidence indicates that an oil reservoir with an associated gas cap exists and that an oil pool should be defined. The hydrocarbon accumulation may appropriately be defined as the Lisburne Oil Pool. 7. The Lisburne Reservoir is an anticlinal structure that is bounded on the north by the Prudhoe Bay-Niakuk fault complex, by truncation and/or the Mikkelson Bay fault to the east and by dip of 135 feet per mile to the south and west. 8. Evidence is sufficient to establish a definitive gas-oil contact at 8,600 feet subsea. Data are anomalous and insufficient to definitively establish an area-wide planar oil-water contact for the Lisburne Oil Pool. 9. The affected area described in Conservation Order No. B3-C. appears to be adequate in the eastern portion of the Lisburne Oil Pool but should be expanded westward to reflect the current structural interpretation. 10. A spacing unit of one producing well per governmental quarter section appears adequate to drain the reservoir. 11. Conductor casing set and cemented a m~n~mum of 75 feet below surface should provide adequate anchorage for a diverter system. 12. The effects of permafrost thaw-subsidence and freeze back loadings can be mitigated by setting and cementing surface casing of sufficient strength at least 500 feet below the base of the permafrost but no deeper than 5000 feet true vertical depth. 13. Several casing types and grades that are approved for use as surface casing in the Prudhoe Oil Pool and the Kuparuk River Oil Pool are appropriate for this pool. 14. Perforation of cemented casing or liners, slotted liners, screen wrapped liners, gravel packs and open hole completions appear to be equally effective completion techniques. Conservation Orc No. 207 Page 3 ~ January 10, 1985 - 15. Significant concentrations of hydrogen sulfide gas were encountered in a production test of the ARCO Pingut State Well No. 1 and smaller amounts of hydrogen sulfide gas have been reported from other wells. 16. Installation of automatic surface shut-in valves is appropriate to prevent an uncontrolled flow of oil or gas. 17. Installation of automatic down hole shut-in valves in the tubing below the premafrost is appropriate to prevent an uncontrolled flow of oil or gas. 18. The flaring of a limited amount of gas will be neces- sary for the safety purposes and for operational necessities. 19. To aid in the evaluation of the effectiveness of the reservoir depletion, the reservoir pressure and the gas-oil ratio of wells should be monitored on a regular and continuous basis. 20. Current studies indicate that a daily oil rate of 160,000 barrels will not be detrimental to ultimate hydrocarbon recovery. However, pool withdrawal rates in excess of 160,000 barrels of oil per day may affect ultimate recovery. 21. Conservation Order No. 83-C is out-of-date and should be replaced. 22. state of Lisburne data for recovery Evidence is insufficient to determine the prudency of the art methods for enhancement of recovery from the Oil Pool. Pilot field projects are necessary to develop determination of the applicability of methods for enhancement. 23. Evidence indicates that the injection of produced gas into the gas cap will retard the rate of decline in reservoir pressure. 24. The average initial reservoir pressure for the Lisburne Oil Pool is 4,490 pounds per square inch at an 8,900 foot subsea datum. Reservoir temperature approximates 1830 Fahrenheit at the datum. 25. The Lisburne Oil Pool contains in excess of 3 billion barrels of Original Oil In Place (OOIP). Primary depletion may recover no more than 7 percent of the OOIP. 26. It appears that most if not all of the Lisburne Oil Pool lies within the current boundary of the Prudhoe Bay Unit. However, it is possible that the pool limits may extend beyond the Prudhoe Bay Unit boundary. Conservation Oré Page 4 January 10, 1985 No. 207 ........... o~ 27. Terms of the Prudhoe Bay Unit Agreement provide for the expansion of the Prudhoe Bay Unit boundary and for the establishment and expansion of an initial participating area for the Lisburne Oil Pool. 28. Management of the Lisburne Oil Pool under terms of the Prudhoe Bay Unit Agreement will effectively protect correlative rights, prevent waste and insure the maximum hydrocarbon recovery. NOW, THEREFORE, IT IS ORDERED THAT the rules hereinafter set forth apply to the following described area and is referred to in the order as the affected area: UHIAT MERIDIAN T10N, R13E Sections 1 , 2 3 , 10, 11, and 12. , T10N, R14E Sections 1 , 2 , 3 , 4, 5 , 6, 7 , 8 , 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 35, and 36. T10N, RISE All. T10N, R16E All. T10N, R17E Sections 3 , 4 , 5 , 6 , 7 , 8, 9 , 10, 15 , 16, 17, 18, 19, 20, 21, 22, 27, 28, 29, 30, 31, 32, 33, and 34. T11N, R13E Sections 1 , 2, 3, 4 , 7 , 8, 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. T11N, R14E All. T11N, RISE All. T11N, R16E All. T11N, R17E 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. T12N, R13E Sections 35 and 36. T12N, R14E Sections 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28, 31, 32, 33, 34, 35, and 36. T12N, RISE 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. T12N, R16E Sections 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. Conservation Orc Page 5 January 10, 1985 No. 207 - - Rule 1. FIELD AND POOL NAME. The field is the Prudhoe Bay Field and the pool is the Lisburne Oil Pool. Rule 2. POOL DEFINITION. The Lisburne Oil Pool is defined as the accumulations of oil and gas which occur in stratigraphic sections which correlate with the stratigraphic section found in the Atlantic Richfield-Humble Prudhoe Bay State No.1 well between the depths of 8,790 feet measured depth and 10,440 feet measured depth. Rule 3. WELL SPACING. The spacing unit shall be one producing well per governmental quarter section. No pay may be opened in a well closer than 1,000 feet to the pay opened in another well or opened in a well which is closer than 500 feet to the boundary of the affected area. Rule 4. CASING AND CEMENTING. a) 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. Rigid high density polyurethane foam may be used as an alternate to cement, upon approval by the Commission. The Commission may also administratively approve other sealing materials which are supported by sound engi- neering principles and performance data. b) Surface casing to provide proper anchorage for equipment to prevent uncontrolled flow, to withstand anticipated internal pressure and to protect the well from the effects of permafrost thaw-subsidence or freeze back loadings shall be set at least 500 feet, measured depth, below the base of the permafrost but not below 5000 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the casing to the surface. c) Surface casing types and grades approved for use through the permafrost interval include: 1) 13-3/8 inch, 72 pounds/foot, 2) 13-3/8 inch, 72 pounds/foot, 3) 13-3/8 inch, 68 pounds/foot, L-80 Buttress; N-80 Buttress; l1N-80 Buttress. Conservation Ore Page 6 January 10, 1985 No. 207 c~ -- d) The Commission may administratively approve additional types and grades of surface casing through the permafrost interval upon a showing that the proposed casing and connection can withstand the permafrost thaw-subsidence and freeze back loadings which may be experienced. Evidence submitted to the Commission shall include: 1) full scale tension and compression testing; or 2) finite element model studies; or, 3) other types of axial strain data acceptable to the Commission. e) Alternate casing programs may be administratively approved by the Commission upon application and presentation of data which show the alternatives are appropriate, based upon accepted engineering principles. Rule 5. COMPLETION PRACTICES. Wells completed for production may utilize casing strings or liners cemented through the productive intervals and perforated, slotted liners, screen-wrapped liners, gravel packs or open hole methods, or combinations thereof. The Commission may administra- tively approve alternate completion methods where appropriate. Rule 6. HYDROGEN SULFIDE. a) Drilling and production equipment and operations shall be in accordance with: 1) 20 AAC 25.065(c)(I) detection monitoring, (2) contingency and control, and (3) training; 2) 20 AAC 25.065(b) prior to penetration of the top of the Lisburne Group for all step-out wells surrounding the Pingut St. No.1 well, located 1142' FSL, 1298' FWL, Sec. 24, TIlE, RISE, UM, or step-outs from any subsequent well with hydrogen sulfide concentrations greater than 25 ppm; 3) API RP 55, Conducting Oil and Gas Production Operations Involving Hydrogen Sulfide, First Edition, October, 1981; and 4) API RP 7G, Section 8, Drill Stem Corrosion and Sulfide Stress Cracking, Eighth Edition, April, 1978 when drill pipe utilized has a yield strength- greater than 95,000 psi. Conservation Or( Page 7 January 10, 1985 No. 207 - Rule 7. AUTOMATIC SHUT-IN EQUIPMENT. a) Any well which is capable of unassisted flow of hydrocarbons must be equipped with 1) a fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow; and 2) a fail-safe automatic surface controlled subsurface safety valve (SSSV).This valve must be in the tubing string and located below permafrost. The valve must be capable of preventing an uncontrolled flow. For operational necessity the Commission may administratively waive the surface controlled requirement. b) A representative of the Commission will witness performance tests at times prescribed by the Commission to confirm that the SSV, SSSV, and all associated equipment are in proper working condition. c) When requested by the operator, a representative of the Commission will witness "no-flow tests" to verify that a well is no longer capable of unassisted flow. Upon approval by the Commission, the operator will no longer be required to maintain the SSSV's in that well until any subsequent workover or stimulation of the well makes it again capable of unassisted flow. The Commission may require additional "no-flow tests" following subsequent well work. Rule 8. GAS VENTING OR FLARING. a) The venting or flaring of gas is prohibited except for operational necessities and for safety volumes set out in this rule; b) A daily average volume of 1,000 MCF per day is approved for the safety flare at the Lisburne Production Center; c) Volumes of gas to provide safety flares for additional facilities may be approved by administrative order upon proper application; d) The volumes of gas for safety flares may be decreased or increased by administrative order; and e) Gas flaring may be approved by administrative order during commissioning of new equipment, purging, and start-ups after major repairs or interruptions. Conservation Orc Page 8 January 10, 1985 No. 207 ---- Rule 9. GAS-OIL RATIO TESTS. a) Between 90 and 120 days after regular production commences and each six months thereafter a gas-oil ratio test will be taken on each well for as long as it produces oil; b) The gas-oil ratio tests will be for a m~n~mum of four hours and shall be taken at the normal producing rate of the well; and c) The results of the gas-oil ratio tests will be reported on Form 10-409, Gas-Oil Ratio Test and will be submit- ted in January and July of each year. Rule 10. PRESSURE SURVEYS. a) A static bottomhole pressure survey shall be taken prior to production or injection on each well drilled to the pool and results reported on Form 10-412, Reservoir Pressure Report; b) The pressure datum for the Lisburne Oil Pool is 8,900 feet subsea. The Commission may administratively amend this datum or create an additional datum when more information on the reservoir is available. c) Prior to July 10, 1987 the operator shall submit to the Commission a program to adequately monitor the reser- voir pressure during depletion. Before the above date, any transient pressure surveys taken shall be timely submitted on Form 10-412 to the Commission. Rule 11. UNITIZATION. To ensure the protection of correlative rights and to prevent waste, the Lisburne Oil Pool shall be administered in accordance with the Prudhoe Bay Unit Agreement. Rule 12. PILOT PROJECTS. Upon application, the Commission may administratively approve field pilot projects, well production and injection tests and other field operations necessary for the purpose of developing a prudent enhanced recovery method and reservoir depletion program. Conservation Or! Page 9 January 10, 1985 No. 207 '- Rule 13. POOL OFFTAKE RATE. No more than 160,000 barrels of oil per day may be produced from the Lisburne Oil Pool. However when evidence can be presented to the Commission showing that a higher offtake rate will not affect ultimate recovery, the Commission may increase the daily offtake rate by administrative order. Rule 14. CONSERVATION ORDER NO. 83-C. Conservation Order No. 83-C is hereby cancelled. DONE at Anchorage, Alaska and dated January 10, 1985. ~ OJ L if.,.~~ --<lltr (;/ ~ v~ò 7¡;"1 )JjJ ~'7'- V ,11< ({rt. .,-';7 ...~ 1/\ (r~ .::> , " I f\( . ~ È;-, ~: :,. >;.,,'!:1;1 ....J,\ \,'1. \ ~ 0!&rf,:,'úZ\;j~f:) {J \-~~~ -::,c', t\'I\;~' '\: ':' '-' ~ ~)¡~ 1) ,>"- " /;..'." ^. '-~~J~"Ç.I. ,...f">,· co''''' ~Ui.J . ~tJ,~· .~u H;r~ w.~ler, Co issioner Alaska Oil and Gas onservation Commission (L œ n, Lonnie C. Smi , ßommissioner Alaska Oil and Gas Conservation Commission ~ ~K~ Llrß\\I~ ,[ (~~', I~F . I O.J ,J i í r ~.~~ ~. ~\ ~ ffi\ CQ2 ~(j {R.\ L~ ~ u=Ü cilJ ~ \1 ÚÛ ..,~ I í I / / / / FRANK H. MURKOWSK/. GOVERNOR AI~ASIiA. OIL AND GAS CONSERVATION COMMISSION 333 W. 7fH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAJ< (907)276-7542 ADMINISTRATIVE APPROVAL NO. 207.17 ADMINISTRATIVE APPROVAL NO. 311B.01 ADMINISTRATIVE APPROVAL NO. 329A.01 ADMINISTRATIVE APPROVAL NO. 341D.01 ADMINISTRATIVE APPROVAL NO.345.01 ADMINISTRATIVE APPROVAL NO. 452.01 ADMINISTRATIVE APPROVAL NO. 457A.01 ADMINISTRATIVE APPROVAL NO. 471.01 ADMINISTRATIVE APPROVAL NO. 484.01 George Blankenship GPB Field Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Blankenship: Conservation Order No. 492, dated June 26, 2003, amended the conservation orders adopting pool rules for all pools within the Prudhoe Bay field to add rules addressing sustained annulus pressures in devel- opment wells. Upon further review, the Commission has determined that paragraph 6 of these annulus pressure rules should be clarified. Paragraph 6 provides that before a shut-in well is placed in service, any annulus pressure must be relieved to a suffi- cient degree that specified annulus pressures at operating temperature will not be reached or exceeded. However, paragraph 3 of the annulus pressure rules contemplates that there may be wells that can be safely operated with an annu- lus pressure in excess of a maximum specified in paragraph 6, and in such cases it would not be practicable or meaning- ful to relieve annulus pressure to the degree required under paragraph 3 when placing a shut-in well in service. In addi- tion, the Commission may approve different pressure limits for well start-up on a case-by-case basis under paragraphs 4 and 5. SCANNEL AUG 0 6 20D3 July 29, 2003 Page 2 of2 Accordingly, Conservation Orders No. 207, 311B, 329A, 341D, 345, 452, 457 A, 471, and 484 are amended to replace paragraph 6 of the annulus pressure rules adopted in Conservation Order No. 492 with the following revised paragraph 6: -~- '~ 6. Except as otherwise approved by the AOGCC under para- graph 4 or 5 of these rules, before a shut-in well is placed in service, any annulus pressure must be relieved to a suffi- cient degree (a) that the inner annulus pressure at operating temperature will be below 2500 psig for wells processed through the Lisburne Production Center and below 2000 psig for all other development wells, and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3, but not paragraph 5, of these rules may reach an annulus pressure at operating temperature that is described in the operatorl s notification to the AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. DATED at Anchorage, Alaska and dated July 29,2003. ....~J \. ~. ---...... ~ é~-.---_, ! /i /). . //--»-_:d:--" (1...-, ,. .//: ~/Li" ," / . ßC/' . ~ L.3aráh}alinD D e T. Seamount, J~ y Ruedric Chair Commissioner Commissioner ";;'9,_ BY ORDER OF THE COMMISSION "-' ~/ WALTER J. HICKEL, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION ~ . . 3001 PORCUPINE DRIVE' ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 June 15, 1994 ADMINISTRATIVE APPROVAL NO. 207.16 Re: Additional flare volume, Lisburne Production Center, Prudhoe Bay Unit. 1. L. Harris Engineering Supervisor LisburneIPoint McIntyre Engineering ARCO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Dear Mr. Harris: We have received your letter of June 15, 1994 requesting additional flare volume at the Lisburne Production Center (LPC) in the Prudhoe Bay Unit. The additional flare volume is required to facilitate tie-in of the second Point McIntyre Drill Site and some modifications to the LPC process systems. The Commission approves flaring up to 60 MMcf of gas over and above the designated safety flare of the LPC during these operations. Work is expected to commence on or about June 28, 1994 and continue until work is complete. It is understood that gas flaring will be kept to a minimum whenever possible, and all volumes will be reported monthly on Alaska Oil and Gas Conservation Commission form 10-422. All gas produced in excess of the 1000 Mcf/d safety flare volume is subject to AS 43.55.020, and will be disposed of in a safe manner by flaring or used for lease operation. Sincerely, ¿~~ tJ fL/~~ Russell A. Douglass Commissioner BY ORDER OF THE COMMISSION ALASKA OIL AND GAS CONSERVATION COltlMISSION May 20, 1993 WALTER J. HICKEL, GOVERNOR $r.·~~~E : F ~~~~ ~Å 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 ADMINISTRATIVE APPROVALN~;~ Re: Additional flare volume, Lisburne Production Center, Prudhoe Bay Unit. Mr. David W. Hanson Permit Coordinator Prudhoe Bay/Lisbume ARCO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Dear Mr. Hanson: We have received your letters of May 12 and 14, 1993 requesting additional flare volume at the Lisburne Production Center (LPC) in the Prudhoe Bay Unit. The additional flare volume is required to facilitate the shutdown and subsequent startup of the Lisburne Production Facility. The shutdown is required in order to tie-in the production pipeline from the Pt. McIntyre Field and perform upgrades to the LPC necessary for the processing of Pt. McIntyre production at this facility. The Commission finds the additional flare volume to be an operational necessity, and hereby approves flaring up to 400 MMcf of gas over and above the designated safety flare of the LPC during shutdown and startup. Operations are expected to commence on or about June 10, 1993 and continue until work is complete. I t is understood that gas flaring will be kept to a minimum whenever possible, and all volumes will be reported monthly on Alaska Oil and Gas Conservation Commission form 10-422. All gas produced in excess of the 1000 Mcf/d safety flare volume is subject to AS 43.55.020, and will be disposed of in a safe manner by flaring or used for lease operation. Sincerely, ¿-_.Ua.~ Russell A. Douglass, ¿ommissioner BY ORDER OF THE COMMISSION .@ printed on recydrrl paper b y C. fJ . ì·~~ : ¡ , . i II . I ! ¡ I \ I ,\ ! , I \ : ~ ~ " ^ \ ji"\ I in\. \\ I í 1.\ ..~ ¡/!\ \ ~. .; ALASIi.A OIL AND GAS CONSEIIVATION COltlltlISSION November 17, 1992 ADMINISTRATIVE APPROVAL NO. 207.14 Re: L5-24 downhole separation test. Mr. J.. L. Harris Operations Engineering Supervisor Lisburne/Point McIntyre Engineering ARCO Alaska, Inc. . P. O. Box 100360 Anchorage, Alaska 99510-0360 Dear Mr. Harris: "-'"- WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501~3192 PHONE: (907) 279-1433 TElECOPY: (907) 276-7542 We have received your letter of November 5, 1992 requesting approval to perform a production test using the Lisburne L5-24 well. The test will utilize a coiled tubing completion which is expected to act as a downhole separator and will require annular production of the gas. The test will prove whether or not gas can be separated downhole to provide a gas source with high flowing pressures. Pursuant to Rule 12 of Conservation Order No. 207 the Commission hereby approves the annular production of gas in L5-24 during the proposed test. c SQ~'_ L:~- C., Russell A .~ougla~ f/ Commissioner~ BY ORDER OF THE COMMISSION (,,"¡ !"'-c r" \ I. 1· ; I , ì ( I I , : \ ! I~ II ' ¡ I II - J _1.-- i! ! '\- I 1\ f' ; ¡ , / Ú If' \ \. j . I r \\ ::J n i " .! - WALTER J. HICKEL, GOVERNOR ,., . ~ ALASKA OIL AND GAS CONSERVATION COltlMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TElECOPY: (907) 276-7542 March 31, 1992 ADMINISTRATIVE APPROVAL NO. 207.13 Re: Additional flare volume, Lisburne Production Center, Prudhoe Bay Unit. Mr. W. R. Worthington EOC Supervisor Prudhoe Bay Operations ARCO Alaska, Inc. P.O. Box 100360 Anchorage, Alaska 99510-0360 Dear Mr. Worthington: We have received your letter of March 25, 1992, requesting additional flare volume at the Lisburne Production Center (LPC) in the Prudhoe Bay Unit. The additional flare volume is required while performing maintenance and modifications to the NGL plant. The Commission finds the additional flare volume to be an operational necessity, and hereby approves flaring up to 50.0 MMcf of gas over and above the designated safety flare pilot of the LPC. Operations are expected to commence on or about April 1, 1992 and continue until work is complete. It is understood that gas flaring will be kept to a minimum whenever possible, and all volumes will be reported monthly on Alaska Oil and Gas Conservation Commission form 10-422. All gas produced in excess of the 1000 Mcf / d safety flare pilot volume is subject to AS 43.55.020, and will be disposed of in a safe manner by flaring or used for lease operation. Sincerely, ¿fiC. ~ Russell A. Douglass Commissioner BY ORDER OF THE COMMISSION ~ / - ADMINISTRATIVE APPROVAL NO. 207.12 - NOT USED - ~ June 29, 1989 Telecopy No. (907) 276-7542 ADM I N I $.T RAT ,I V)f. A P Y R 0 ,V_A_.~ N _º~,. 207,.11 Re: Pressure Monitoring, Lisburne Oil Pool, Prudhoe Bay Field. Ronald G.H. aba Regional Operations Engineer Lisburne Engineering ARCa Alaska, Ine POBox 100360 Anchorage, AK 99510-0360 Dear Hr Dba: In June of 1987 a two year plan for monitoring Lisburne Oil Pool pressure in the Prudhoe Bay Field was proposed by ARCO Alaska, Inc. and approved by the Alaska Oil and Gas Conservation Commis- sion (the Commission) under Conservation Order (C.O.) 1207. By letter dated June 22, 1989, ARca Alaska, Inc. has requested modifications to Rule 10 of c.o. #207. The Commission has-reviewed the proposed modifications and discussed the pressure monitoring program and results with representatives of ARca Alaska, Inc. The Commission has de- termined that the modifications to Rule 10 of c.o. #207 are appropriate at this time. The data necessary for developing a prudent enhanced recovery method and reservoir depletion program will continue to be obtained. Therefore, the Commission hereby amends Rule 10 of C.O. #207, to read: a) All new wells shall have an acceptable pressure survey, as defined in part (c), taken prior to regular production or injection. b) One pressure survey per producing drillsite per year shall be taken. Pressure surveys from producing or water and gas injection wells may be used for this pressure requirement. Pressure surveys covered in section (a) may be substituted for a drillsite pressure. c) Acceptable pressure surveys include static surveys, RFT/FMT, pressure buildup and falloff tests, and multi-rate pressure transient tests in production or injection wells. Other quantitative methods may be administratively approved by the Commission. Ronald G.H. aba ARCO Alaska, Inc. -2- June 29, 1989 d) The pressure datum for the Lisburne Oil Pool is 8900 feet subsea. The Commission may administratively amend this datum or create an additional datum when more information is available on the reservoir. e) Data from the pressure surveys, along with additional pressure data obtained through proper management of the reservoir, shall be filed on form 10-412 by the last day of the month following the month that the pressure survey was obtained. Submitted pressure data shall include other information as necessary such as rate, time, depth, tempera- ture, and well conditions to allow for a complete analysis of the pressure survey. f) The operator shall schedule an annual meeting with the Commission to review the pressure monitoring progr~ and discuss future plans for reservoir management. Sincerely,._,-"-" .- ¡L k 'i / ... ·1·\ ~ .-J --~ ..'.... '- _."_ .-' .__c- \, _ .; ~._-/ I, c:.n../V""-{. . ~~o/......... ~ . . - Lonnie C ~h Connnissioner BY ORDER OF THE COl1MISSION dlf/3.AA207 BY ORDER OF THE COMMISSION dlf/3.AA207 Si}lcerely!_ ,--; , . / ,/ j , (I., ~/" I ~ /~.. .,,,·..r d1. '. __..).A~ ,-*t~ !j' ¥ . ,--.J . Lonnie ' 8mi th Connnissioner 2. Continue water injection into L2-18. 3. Convert L2-32 to water injection. 1. Increase/redistribute water injection into current water injection wells L2-10, L2-16 and L2-24. By correspondence dated April 6, 1989, on behalf of ARCO Alaska, Inc. you have requested expanding Lisburne Oil Pool, Pilot Waterflood on Drill Site (DS) L2. A meeting with the Commission was held April 6, 1989 to discuss the proposed expansion, pilot history and future plans. The Commission has determined the proposed expansion of the DS L2 pilot waterflood is necessary to provide additional reservoir performance data required for the prudent planning of a full scale waterflood program. The Commission hereby approves the following expanded operations of DS L2 pilot waterflood. Dear l1r Harris: Re: Drill Site L2 Pilot Waterflood Expansion J L Harris Sr Operations Engineer Lisburne ARCO Alaska, Inc POBox 100360 Anchorage, AK 99510-0360 Te lecopy I~o. (907) 276-7542 t1 o. 20l.1Q ADHINISTRATIVE APPROVAL 1 - - -_- .~'-_ -.a-' - _ ~ ~~_.. '-- ,-- --:-. April 12, 1989 ! I ! i I __< n n', ,.J u', n ¡ November 24, 1987 Telecopy No. (907) 276-7542 ADM I N 1ST RAT I V E A P PRO V A L N .0. 207.9 -- -- Re: Lisburne Southern Pilot Waterflood Project C H Robinson Sr Operations Engineer Lisburne ARCa Alaska, Inc POBox 100360 Anchorage, AK 99510-0360 Dear Mr Robinson: By correspondence dated November 19, 1987 ARCO Alaska, Inc requested approval to expand a pilotwaterflood project in the Lisburne Oil Pool of the Prudhoe Bay Field approved April 17, 1987. The proposed pilot will evaluate injectivity, benefits of pressure maintenance, implementation strategies, and feasibility of waterflood operations in the Lisburne Oil Pool. The pilot will include an additional three injection wells (L2-6, L2-10, L2-16) and one producing well (L2-14) enclosing a pattern of approximately 320 acres drilled from the L2 drilling pad. Fluid injection into the Lisburne Oil Pool is governed by Area Injection Order No.4 issued to ARCO Alaska, Ine on July 11, 1986. The Commission has determined the proposed pilot project to be a necessary step for the purpose of developing a prudent enhanced recovery method for the pool. The pilot project will not create waste, and is approved as proposed. In addition to the reports required by Title 20, Chapter 25 of the Alaska Administrative Code, a report sunnnarizing the facts and progress of the project will be submitted every six months by the 20th day of the month following the reporting period. . S.25erely, ¡) 7~~# Lonnie C Smith Commissioner BY ORDER OF THE COMMISSION jo/3.AA207 July 23, 1987 Telecopy No. (907) 276-7542 ADM I N 1ST RAT I V E A P PRO V A L N O. 207.8 Re: Lisburne facilities shutdown flare approval. B. T. Kawakami Lisburne Operations Coordinator ARCO Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510-0360 Dear Mr. Kawakami: We have received your letter of July 20, 1987 requesting additional flare volume for a planneà shutdown and restart of Lisburne production facilities. Purpose of the planned shutdown is to make facility changes to problem areas identified during startup and the past seven months of operations. The Commission finds that the shutdown is an operational necessity and that additional flare volume is required. The Commission hereby approves flaring an additional 200 M}4SCF at Lisburne Production Facility and Lisburne Gas Injection drill site combined. Flaring is scheduled to begin August 6, 1987 when facilities will be shut down, and end when all facilities have been restored to operational status. It is understood that flare volUme will be kept to a minimum, and all gas flared under this authorization shall be metered and is subject to AS 45.55.020(e). ¿;iSincerel~. C , ( £-. \' ~ i C"~,~·· ~(-d Lonnie C. Smith Commissioner BY ORDER OF THE COMMISSION jo/3.AA.207 ~~~- April 17, 1987 Telecopy No. (907) 276-7542 ADM I N I S T RAT I V E - -- - APPROVAL - ~ N O. 207.7 Re: Lisburne Pilot Waterflood Project. Mr. B. T. Kawakami Lisburne Operation Coordinator ARCO.Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510-0360 Dear Mr. Kawakami: By correspondence dated April 9, 1987 ARCO Alaska, Inc. requested approval to conduct a pilotwaterflood project in the Lisburne Oil Pool of the Prudhoe Bay Field. The proposed pilot will evaluate injectivity, benefits of pressure maintenance, implemen- tation strategies and feasibility of waterflood operations in the Lisburne Oil Pool. The pilot will include four injection wells and one producing well enclosing a pattern of approximately 145 acres drilled from the L2 drilling pad. A phased injection startup beginning with L2-30 and continuing with L2-24, L2-20 and L2-28 w111 commence on or about April 22, 1987. Fluid ~njection into the Lisburne Oil Pool is governed by Area Injection Order No. 4 issued to ARCO Alaska, Inc. on July 11, 1986. The Commission has determined the proposed pilot project to be a necessary step for the purpose of developing a prudent enhanced recovery method for the pool. The pilot project will not create waste. The pilot project is approved as proposed. In addition to the reports required by Title 20, Chapter 25 of the AAC, a report summarizing the facts and progress of the project will be submitted every six months by the 20th day of the month following the reporting period. ~ref' \) 'vi . 2¡..~.;~ -~. /, ;~Lonnie C. Smith Commissioner BY ORDER OF THE COMì1ISSION dlf/3.AA207 r=-~" Harch 12, 1987 Telecopy No. (907) 276-7542 ADM I N 1ST RAT I V E A P PRO V A L N O. 207.6 Re: Lisburne facilities depropanizer unit startup flaring. l~. B. T. Kawakami Lisburne Operation Coordinator ARCO Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510-0360 Dear Mr. Kawakami: We have received your letter of l-1arch 6, 1987 requesting flaring of gas during the- commissioning and startup of the Lisburne facilities depropanizer unit. The COIDnlission hereby approves a flare total of 300 MMSCF during commissioning and startup of the Lisburne facilities depropanizer unit per rule 8(e) of Conservation Order 207. Startup of the unit is expected to begin in late April, 1987. It is understood that the flare volume will be kept at a minimum, and all gas flared under this authorization shall be metered and is subíect to AS 43. 55 . 020 ( e) .. <oJ Sinç.ere ly, (-.. -1"/ . ¡O.~ \ f ~3· ¡ - \ I J3-v-.....-vv'-< !. - r/ l Lonnie C.- Smith Commissioner BY ORDER OF THE COMMISSION dlf/3.AA207.5 February 6, 1987 Telecopy No. (907) 276-7542 ADM I N 1ST RAT I V E A P PRO V A L N o. 207.5 Re: Request by ARGO Alaska, Inc. for extension of flare duration during startup and commissioning of the Lisburne Production Center (LPC). Mr. Ben T. Kawakami Lisburne Operations Coordinator ARCO Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510-0360 Dear Mr. Kawakami: By letter dated February 6, 1987, ARCO Alaska, Inc. has requested additional time for flaring during startup and commissioning of the Lisburne Production Facility. A flare volume of 4.4 ~~SCF of gas over a 60-day period was approved in August, 1986 with Administrative Approval No. 207.4. Your request indicates additional time is needed for commissioning and startup of the second gas injection compressor, but the original approved flare volume is sufficient to complete this task. Therefore, by this letter ARca Alaska, Inc. is hereby authorized to extend gas flaring until the second gas injection compressor at the LPC is operational. It is understood that the flare volume will be kept at a minimum, and all gas flared shall be metered and is subject to AS 43.55.020(e)~ S~7.in. S re,lY ~ Ý ~ /~ ~?/ Lonnie C. Smith Commissioner BY ORDER OF THE COMMISSION jo/3.AA207.5 August 14, 1986 TELECOPY NO. (907) 276-7542 ADM I N 1ST RAT I V E A P PRO V A L N O. 207.4 Re: Request by ARGO Alaska, Inc. to flare gas during the commissioning and start-up of their Lisburne Oil Pool production and injection facilities. 1'·lr. Ben T. Kavlakami Lisburne Operations Coordinator ARGO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Dear Hr. Kawakami: By letter dated August 7, 1986, ARCO Alaska, Inc. has requested approval to flare Bas during the commissioning and start-up of the Lisburne Oil Pool production and injection facilities. It is understood that the facilities consist of oil processing, gas processing, and gas injection equipment which require sequen- tial conwissioning and start-up; therefore flaring of produced gas "\<]i11 he necessary until the gas inj ection compressors are running smoothly. It is understood that in-so-far as possible, equipQent which does not require hydrocarbon throughput will be cO~liBsioned prior to start of production and, further, various equipMent, when possi.ble, will be commissioned simultaneously and that all reasonable efforts will be made to minimize gas flaring. Therefore, by this letter, ARca Alaska, Inc. is hereby authorized to flare up to 4.4.BSCF of produced gas over a 60 day period which is now planned to commence in December, 1986. It is understood that the flared volumes will be kept to the minimum necessary to accomplish equipment check-out and facility start-up and that all gas flared under this authorization shall be ~etered and is subject to AS 43.55-020(e). Yours very truly, ~.,:_~ rfiJ~~l Lonnie C. Smith Commissioner BY ORDER OF THE COHHISSION dlf:BEH:3.AA207 BY ORDER OF THE COMMISSION be:RAD:3.AA207 Yours very truly, N~IJ I~~ Harry vI. Kugler Commissioner Bottom hole pressure monitors will be placed in all production strings during the testing. Testing will continue through startup of the Lisburne production facilities. Since this testing is necessary for the purpose of developing a prudent reservoir depletion program and enhanced recovery method by authority of Conservation Order No. 207, Rule 12, the Commis- sion hereby approves the Lisburne Interference Test. By letter dated January 7, 1986, ARCO Alaska, Inc. has requested permission to perform a Lisburne Interference Test to evaluate directional permeability in the Wahoo Formation. The test will be conducted on a five spot well pattern consisting or wells L2-20, L2-24, L2-26, L2-28, and L2-30. Dear Mr. Kawakami: Mr. Ben T. Kawakami Lisburne Operations Coordinator ARca Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Re: Request by ARCa Alaska, Inc. to perform a Lisburne Interfer- ence Test to evaluate directional permeability. ADM I N 1ST RAT I V E A P PRO V A L N O. 207.3 January 9, 1986 October 3, 1985 ADM I N I S T RAT I V E A P PRO V A L N O. 207.2 Re: The application of ARCO Alaska, Inc. to qualify an additional grade of casing for use as the top two joints of surface casing for wells drilled to the Lisburne Oil Pool of the Prudhoe Bay Field. Mr. John J. Guerrero Acting Regional Drilling Engineer ARCO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Dear Mr. Guerrero: An application was received on October 1, 1985 requesting that approval be given to use 68#, K-55 casing as the top two joints of the 13-3/8" surface casing instead of L-80 for wells drilled to the Lisburne Oil Pool of the Prudhoe Bay Field. Evidence previously submitted to the Commission indicates this weight and grade of 13-3/8" casing is structurally acceptable. Pursuant to Rule 4(d) of Conservation Order No. 207, the Alaska Oil and Gas Conservation Commission hereby approves the use of 13-3/8", 681, K-55 casing through the permafrost interval or portions thereof for surface casing in Lisburne development wells. . Yours very truly, ~ ¿J (h.L~ ~a~ry ¿ Kug;:;7 Commissioner BY ORDER OF THE COMMISSION be:3.AA207 BY ORDER OF THE CO~IISSION be:3.AA207 ~'y4J. t!t~ Harry W. Kugler Commissioner Yours very truly, \~e have received your request, dated May 15, 1985-, requesting an p.xception to Rule 3 of Conservation Order No. 207 to drill the subject well as the center well of a five well pilot interference test. It was stated that data from this well will vastly improve the understanding of the Lisburne Reservoir and should point towards appropriate enhanced recovery methods. The Commission has studied the data available and is in agreement with the benefits to be derived from the drilling of this well. Therefore, by this letter, the Alaska Oil and Gas Conservation Commission authorizes the drilling of the Prudhoe Bay Unit No. L2-26 well to a target located at the common corner of Sections 7, 8, 17 and 18, TI1N, RISE, U.M. The action is pursu- ant to Rule 12 of Conservation Order No. 207. Dear Mr. Fithian: Mr. T. L. Fithian ARCO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Re: The application of ARCO Alaska, Inc. to drill the Prudhoe Bay Unit No. L2-26 well in the Lisburne Oil Pool of the Prudhoe Bay Field. ADM I N 1ST R AT I V E A P PRO V A L N O. 207.1 N:ay 21, 1985 #29 Prudhoe Bay Field - Annual Surveillance Reporting Requirements to AOGCC Group 1 IPA Group 2 GPMA Group 3 Satellites -~..---".~_...- ----.------ f---.--.. . ..----- Annual Surveillance Report 15-Mar 15-Jun 15-Sep ---..- ....._~_.._~~._---- ---------..__._._~-- ---.--- -- --...------- _._.._"~----,- _._~------ ----_._-----~--- f---.-~--.~--.---.----...-- Annual Overview Presentation 22-Mar 22-Jun 22-Sep -""~'._'- ...---.--- ~._. -- ~--_._--_.."----_.._---,-- -. --.-- Production Period to be Covered Jan 1-Dec 31 Apr 1-Mar 31 Jul1-Jun 30 Amends Order/Rule Group 1 -IPA OilPo~I~.__.__._____ _ . Order Date Comment - - -----_..,._,._---------,-_._~-"~~ -,---_._._"-~-,------- ._~-~----_.~.__._--------,---._._----- Note C0341 E (modified Pool Definition to Prudhoe Oil Pool C0341 D Rule 11 11/30/2001 include a portion of Put River Sandstone) -_._-----------------~.,_.._.,--_.__._-- . ----------~-----_._--_._--- -_._---_._--_._,.,_.,_.~" Put River Oil Pool C0559 11/22/2005 Corrected 2/14/2006 Group 2 - GPMA Oil Poo~~___ -_.-----------, ---, -'--"'-"---'--~-- . . ._____.~~i~Eurne____ºº207, 20?~___._ _~_m___ Niak!J~j_________º_º-329A ~uJ~___ . .___ _f\J~,!~__~~~~ho~~ay ______ CO!~~_F3ule ~_.__ ______. _______n__. Pt. M91ntyr~_.__.. C03178 Rule 15 Raven Oil Pool C0570 Rule 10 --. ..----- WesTSeach Oil Pool --(;0311 8 Rule~- ---·-----·-·f_._f'!o ·~~Ie on --ª~i'{ei"ance repo.'!s 6/4/1996 += ~~~~~~~90904 ..----==-~=======~_=___ -- 8/9/2006 ._~-------+- ...._....._~_._..._..._._---~-_.- 8/1/2000 i . (;.~~up~-:)!_~~h~~ª~te~!~-º_~~_~~o~.__ __________.____ _____.___.____..... .________. .. ._._ ____~lJrora . ___-º04578 RuJ~ª__.________.~!25/200~____ _._~~~~_c:_ted 8/~!?-º_º-~._ .___.. ___Un. ___. _~!eallis _ __ cq~?_~ Rule ~ ____ . _5/29/2002 -----t- _.__ _ _ _. ___._ .. _ _ Mi~nigh~~6~ --- - - gg~g~:~~; ~ -- - --- - ~%~~~0060 . +--.- . ---- ~- - -- . ._______._._ ..__.._.__.. ..__..._____._..._..__ ....__._.__._.____.__...._.. _....-L..._.. . m .._____ Polaris' C0484A Rule 9 11/3/2005 l.... ....... l'" '...... ."- -_. .......... , - ~...o-..........__ .. -t' "'~ .. --...-... JJ . . Subject: [Fwd: [Fwd: Re: surveillance report dates]] From: Jane Williamson <jane _ williamson@admin.state.ak.us> Date: Fri, 20 Apr 2007 13:03:59 -0800 To: Jody J Colombie <jody_colombie@admin.state.ak.us>, Dave Roby <daveJoby@admin.state.ak.us>, Cathy P Foerster <cathy _foerster@admin.state.ak.us>, Alan J Birnbaum <alan _ bimbaum@law.state.ak.us> CC: Stephen E Mcmains <steve_mcmains@admin.state.ak.us>, art Saltmarsh <art_saltmarsh@admin.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us> There is something I didn't get around to before I left and that was to administratively amend the COs for PBU to include reporting dates agreed to verbally with BP (and DNR). Really, only pt. Mcintyre and Borealis have the wrong dates in the eo's. The others are either ok, or not explicit. Attached are the COs affected. I'm not sure how you want to handle. Jody. Please put this in the following CO files along with the attachment. Group 1 - IP A Oil Pools Prudhoe Oil Pool C0341D Put River Oil Pool C0559 Group 2 - GPMA Oil Pools Lisburne C0207, 207 A Niakuk C0329A Rule 9 North Prudhoe Bay C0345 Pt. McIntyre C0317B Raven Oil Pool C0570 West Beach Oil Pool C0311 B Group 3 - Prudhoe Satellite Oil Pools Aurora C0457B Boreallis C0471 Midnight Sun C0452 Orion C0505A Polaris C0484A -------- Original Message -------- Subject:Re: surveillance report dates Date:Thu, 31 Aug 2006 17:27:45 -0800 From:Jane Williamson <iane williamson(a?admin.state.ak.us> Organization:State of Alaska To:Lenig, David C <David.Lenig(cl}bp.com> References:<CBF4D8E92B5A 704 79F64416582F6A17CB81AEO(cl}bp lancex005.bp l.ad.bp.com> Oops Lenig, David C wrote: Hi Jane, 10f3 4/23/2007 9:50 AM l"- ..-. l" ......... ""-~.....-... .....~....-....._- ~....t"........... --"""UJJ . . didnJt get the attachrnent. David From: Jane Williamson Sent: Thursday, August 31,20065:14 PM To: Lenig, David C Subject: Re: surveillance report dates E-mail is fine. Attached is a list of the pools and orders/rules that will be amended with the Admin approval. Take a look and see if this looks right to you. (Note, I'm only listing the rules that are affected by the new dates - there may be additional amendments unrelated to the surveillance requirements that I've not listed.) I'm flexible on the date for the Overview presentation. I'd be fine with specifying it to be within one or two months of the report date rather than the POD overview that you've noted. What would you prefer? Lenig, David C wrote: Jane, Here is a table showing the dates for the various Reports and Presentations. I've added the production period as well. The IPA review date remains problematic due to the proximity to spring break but we seem to work around it each year. Would you prefer that I put this in a letter requesting the changes? I know we talked about this a little while ago I just haven't found the time. Thanks, David Plan of Development Production Period Jul1-Jun30 IPA GPMA March 15 June 15 September 15 March 22 June 22 September 22 March 30 June 30 September 30 Jan1-Dec31 Apr1-Mar31 Satellites Annual Surveillance Report Annual Overview Presentation -----Original Message----- From: Jane Williamson [mailto:jane williamson@a~min.state.ak.us] Sent: Thursday, August 31, 2006 2:30 PM To: Lenig, David C Subject: surveillance report dates Hi David. When you get a second, could you please send back an e-mail that lists all the surveillance report dates that we've agreed to for all PBU pools (including GPMA)? Also, do you have dates for surveillance reviews? I'll go through the list and make sure the Conservation orders are correctly worded, then put out administrative amendments as necessary. I checked with Cammy and she said an e-mail is fine for starting the 20f3 4/23/2007 9:50 AM La.. ..-. LA. ..-. ........-. ............ -..........-.......-- ~-t'....,.... --"'-""'JJ . administrative action process. Thanks. Jane 'VVillial11S0n~ PE <iane "vvilliamson(Zi!admirLstate..al(.Lls> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission . Content-Type: application/vnd.ms-excel surveillance report.xls Content-Encoding: base64 30f3 4/23/2007 9:50 AM -#28 ARCO Alaska, Inc. .. Post Office B. 0360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 . 31fJ4t '2,..01/"r ~~ ~~ July 8, 1996 Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Request to Revise Conservation Order 207, Rule 7 Prudhoe Bay Field, Lisburne Oil Pool Request to Revise Conservation Order 311, Rule 6 Prudhoe Bay Field, West Beach Oil Pool Request to Revise Conservation Order 317, Rule 8 Pt. Mcintyre Oil Field, Pt. Mcintyre & Stump Island Pools Request to Revise Conservation Order 329, Rule 5 Prudhoe Bay Field, Niakuk Oil Pool RECEIVED SEP 06 1996 Dear Mr. Johnston: AlasKa on 2. Gas Cons. Commission ÄncJ,oTzge ARCO Alaska, Inc., Operator of the Lisburne, West Beach, Point Mcintyre and Stump Island Oil Pools, BP Exploration (Alaska), Inc., Operator of the Niakuk Oil Pool, and Exxon Company USA, Working Interest Owner in these Pools, request that the Commission revise the requirements of Conservation Orders 207, 311, 317, and 329 to require only a surface safety valve for wells capable of unassisted flow. Similar to the previously approved requests from the Kuparuk, Milne Point, and Prudhoe Bay Units, the purpose of this request is to remove the subsurface safety valve requirement which will allow more efficient operation of the fields while maintaining a safe operation. Additionally, this will bring consistency to all Pools currently flowing into the Lisburne Production Center (LPC). Conservation Order 345 for the North Prudhoe Oil Pool, the other Pool currently flowing into the LPC, does not require subsurface safety valves. This letter, which should be considered our joint formal request, is divided into three main sections covering the background, proposal, and justification for this action. BACKGROUND The pool rules referenced above (Conservation Orders 207, 311, 317, and 329) require each well be equipped with both surface and subsurface safety valves for all wells capable of unassisted flow of hydrocarbons. The subsurface safety valve requirements in North Slope fields were originally requested by us based on the low level of experience with arctic production operations. After many years of safe operations, these concerns no longer exist. We have gained substantial arctic operating experience and now possess an extensive infrastructure operated by a highly skilled work force. ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany AR3B·60Q3-C Mr. David W. Johnston, ChaiA Re~uest to Revise Conservation Order 207, Rule 7 Request to Revise Conservation Order 311, Rule 6 Request to Revise Conservation Order 317, Rule 8 Request to Revise Conservation Order 329, Rule 5 Page 2 . One of the main concerns during the early years of arctic operation was the potential freeze back of the permafrost. Subsurface valves were used to protect against the risk of loss of well control due to casing collapse during freeze back of the permafrost. The uncertainty relating to this risk, however, was eliminated with the improved design of casing strings and cement capable of withstanding the thaw - freeze back forces. Over nineteen years of production operations on the North Slope have clearly demonstrated that this is no longer an area for concern. In the Lower 48, as in Alaska, subsurface safety valves are used primarily in offshore applications where wells and platforms are at risk due to hurricanes, oceangoing ships, and subsea mud slides. The use of subsurface safety valves in onshore wells in the Lower 48 is very rare and generally restricted to wells with extremely high levels of hydrogen sulfide, located in heavily populated urban areas. Consistent with the industry's practice in the Lower 48, the use of subsurface safety valves is not required or in use in any of the other onshore fields in Alaska outside of the North Slope. PROPOSAL We propose that Conservation Order 207, Rule 7, Conservation Order 311, Rule 6, Conservation Order 317, Rule 8, and Conservation Order 329, Rule 5 be revised to eliminate the subsurface safety valve requirement for all wells, and to require a surface safety valve only in wells capable of unassisted flow of hydrocarbons. The pilot actuated surface safety valve is capable of automatically closing to prevent an uncontrolled flow. Surface valves will continue to be tested as required by the AOGCC every six months. For clarity, a copy of the current rules and proposed new rules are attached (Attachments 1- 8). Removing the requirement for subsurface valves in the Lisburne, West Beach, Pt. Mcintyre, Stump Island, and Niakuk Oil Pools is consistent with the Commission's statewide regulation, 20 AAC 25.265, which imposes a universal subsurface valve requirement only for offshore wells. JUSTIFICATION Subsurface safety valves provide only a redundant level of protection to the surface safety valve. The risks which were thought to justify the extra protection provided by subsurface safety valves have proven to be either absent or extremely unlikely in the Oil Pool wells flowing into the LPC. In fact, subsurface valves actually create a small element of risk, as numerous downhole well operations are performed each year just to service and maintain existing valves. In addition, the requirement for subsurface valves may preclude or hinder the development and application of various alternate completion techniques being studied to extend the life of these fields. Mr. David W. Johnston, ChaiA Request to Revise Conservation Order 207, Rule 7 Request to Revise Conservation Order 311, Rule 6 Request to Revise Conservation Order 317, Rule 8 Request to Revise Conservation Order 329, Rule 5 Page 3 . Please note that we are not asking for a waiver of a statewide rule as 20 AAC 25.265(b) does not require either a surface or subsurface safety valve for onshore wells. Our proposal is to continue to exceed the requirements of the statewide rules by continuing to install and maintain surface safety valves. These revisions will result in a significant improvement in the efficiency of operations for all the pools flowing into the LPC. It is not our intent to remove or disable operational subsurface valves in wells in these Pools. However, if the operation of a well's subsurface valve becomes problematic, the Operator will decide if the subsurface valve should be repaired, removed, or disabled based on criteria adopted by the Owners. These revisions conform with prudent oil field management and will not adversely affect ultimate recovery. Please contact us if you have any questions or need more information. Our phone numbers are 263-4431,564-5433, and 564-3689 for the ARCO, BPX, and Exxon contacts respectively. ~cerel~~ "lf~ (J. A. Leone \'~anager GPMA ARCO Alaska, Inc. /JJf~~ A. N. Bolea Asset Manager GPMA BP Exploration (Alaska), Inc. Attachments . . Attachment 1 Current Conservation Order 207, Rule 7. Rule 7. Automatic Shut-In Equipment a) Any well which is capable of unassisted flow of hydrocarbons must be equipped with 1) a fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow; and 2) a fail-safe automatic surface controlled subsurface safety valve (SSSV). This valve must be in the tubing string and located below permafrost. The valve must be capable of preventing an uncontrolled flow. For operational necessity the Commission may administratively waive the surface controlled requirement. b) A representative of the Commission will witness performance tests at times prescribed by the Commission to confirm that the SSV, SSSV, and all associated equipment are in proper working condition. c) When requested by the operator, a representative of the Commission will witness "no-flow tests" to verify that a well is no longer capable of unassisted flow. Upon approval by the Commission, the operator will no longer be required to maintain the SSSV's in that well until any subsequent workover or stimulation of the well makes it again capable of unassisted flow. The Commission may require additional "no-flow tests" following subsequent well work. . . Attachment 2 Proposed Revised Conservation Order 207, Rule 7. Rule 7. Automatic Shut-In Equipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. 1. Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. 2. A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for the Commission on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working condition. , ,. Attachment 3 Current Conservation Order 311, Rule 6. Rule 6. Automatic Shut-in Equipment (a) Upon completion, each well which is capable of unassisted flow of hydrocarbons shall be equipped with: i. a fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow. ii. a fail-safe automatic subsurface safety valve (SSSV), unless another type of subsurface valve is approved by the Commission, installed in the tubing string below the base of the permafrost capable of preventing an uncontrolled flow. (b) A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no-flow" performance test witnessed by a Commission representative or by other means, is not required to have fail-safe automatic SSSVs. (c) For projects receiving Commission administrative approval, the requirements for fail-safe SSSV equipment may be waived. (d) SSSVs may be temporarily removed as part of routine wellwork operations without specific notice to, or authorization by, the Commission. RECEIVED SEP 0;'; 1996 Alaska Oil 8, G:1S Cons. Commission AnchcTr:ge . . Attachment 4 Proposed Revised Conservation Order 311, Rule 6. Rule 6. Automatic Shut-In Equipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. 1. Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. 2. A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for the Commission on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working condition. . . Attachment 5 Current Conservation Order 317, Rule 8. Rule 8. Automatic Shut In Equipment a. Upon completion, any well which is capable of unassisted flow of hydrocarbons to the surface shall be equipped with: i. a fail-safe automatic surface safety valve (SSV) capable of preventing uncontrolled flow. ii. a fail-safe automatic subsurface safety valve (SSSV), unless other type of subsurface valve are approved by the Commission, shall be installed in the tubing string below the base of the permafrost and be capable of preventing an uncontrolled flow. b. A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no-flow" performance test witnessed by a Commission representative, is not required to have fail-safe automatic SSSV's. c. SSSVs may be temporarily removed as part of routine well operations without specific notice to, or authorization by the Commission. RECE\VEO r; E.P 0 b '\996 '" ., ~ . missIon 0'.'\11 ,J ,,' (;()'H'· com . . kn \ e, U'-"-' A\t\$ . -., 'j" \·.qilt\~ k¡·,,"~ ~ . . Attachment 6 Proposed Revised Conservation Order 317, Rule 8. Rule 8. Automatic Shut-In Eauipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. 1. Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. 2. A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for the Commission on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working condition. . . Attachment 7 Current Conservation Order 329, Rule 5. Rule 5. Automatic Shutln Equipment a. Upon completion, each well shall be equipped with: i. a fail-safe automatic surface safety valve (SSV) capable of preventing uncontrolled flow. ii. a fail-safe automatic subsurface safety valve (SSSV), unless other types of subsurface valve are approved by the Commission, shall be installed in the tubing string below the base of the permafrost and be capable of preventing uncontrolled flow. b. A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no flow" performance test witnessed by a Commission representative, is not required to have fail-safe automatic SSSV's. c. Safety valves may be temporarily removed for not more than 15 days as part of routine well operations or repair without specific notice to, or authorization by the Commission. The SSV and SSSV may not be simultaneously out of service without specific authorization from the Commission. i. Wells with SSV's or SSSV's removed shall be identified by a sign on the wellhead stating that the valve has been removed and the date of removal. ii. A list of wells with SSV's and SSSV's removed, removal dates, reasons for removal, and estimated re-installation dates must be maintained current and available for Commission inspection on request. d. The Low Pressure Sensor (LPS) systems shall not be deactivated except during repairs to the LPS, while engaged in active well work or if the pad is manned. If the LPS cannot be returned to seNice within 24 hours, the well must be shut-in at the well head and at the manifold building. i. Wells with a deactivated LPS shall be identified by a sign on the wellhead stating that the LPS has been deactivated and the date it was deactivated. ii. A list of wells with the LPS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for Commission inspection on request. . . Attachment 8 Proposed Revised Conservation Order 329, Rule 5. Rule 5. Automatic Shut-In Equipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. 1. Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. 2. A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for the Commission on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working condition. RECEIVED Q CD 0 I; 1906 ....JLI '1...,.. v Alaska OB 8l Gas Cons. Commission Anchorage FROM': GPMr.J i=lNCHORi=lGE . Fi=lX NO. I 2634894 . GREATER POINT MciNTYRE AREA SSSV MANAGEMENT IMPLEMENTATION 8/8/96 08-09-96 13131 P.02 PLAN <I «/ I. Purpose The purpose of this implementation plan is to provide a means to consistently manage the usage and removal of subsurface safety valves (SSSV) from Greater Point McIntyre Area (GPMA) wells. The procedures, and other information have been reviewed with and approved by ARCO, Exxon, and BP Exploration management. II. Background On ,1998, the Alaska Oil and Gas Conservation Commíssion (AOGCC) approved Conservation Order No. _ (see Appendix I) which modified: Field Rule NO.7 for the Lisburne Oil Pool. Field Rule No.6 for the West Beach Oil Pool, Field Rule NO.8 for the Point MCIntyre & Stump Island Oil Pools, and Field Rule No.5 for the Niakuk Oil Pool. The Order eliminated the requirement for SSSVs in wells in these Pools (Conservatîon Order 345 for the North Prudhoe Bay Oil Pool, the other poor currently flowing in the Lisburne Production Center, does not require subsurlace safety valves). A Safety Valve System (SVS) including a surface safety valve (SSV) is still required for each well. c The requirement for SSSVs was included in the origìnal field rules for these Pools because of a relatively low level of experience In Arctic production operations at that time. One of the prìmary concerns was the potential for freeze back of permafrost and the impact this may have on casing collapse and subsequent well control problems. The North Slope operators have demonstrated that the concern regarding casing collapse has been adequately addressed by the proper design of casing, annular fluids, and cementing systems for Arctic conditions. Additional justification for removing the AOGCC requirement for SSSVs was provided by many years of safely operating on the North Slope, a highly skilled workforce, and an extensive infrastructure. III. General Information Environmental Issue ,for consistency! minor wording changes relating to SSSVs were made in both the EOA & .wOA Oil IJischarg.,- Prevention and Contingency Plans (dC-Pian ") and have been submitted to the Alaska Department of Environmental Conservatíon (ADEC) and other approprîate agencies as updates to the C·Plans. No changes to other environmental plans are necessary. General Removal Approach S~SV removals/deactivations will generally occur in the order listed below assuming that the criteria and approvals outlined in the Criteria and Procedure sections are addressed. It is the 1 FROM·; GPMÞ1 RNCHORRGE , FRX NO.; 2634894 . 68-69-96 13;32 REATER POINT MciNTYRE AREA SSSV MANAGEMENT IMPLEMENTATION PLAN 8/8/96 P.63 1\ ;jY)/ intention of ARGO and BPX to utilîze many of the existing SSSVs for as long as reasonably possible. There are no target dates established for SSSV removal/deactivation. 1) Remove K-Valves. These SSSVs result ín various operational problems and In most cases require back pressure to be held on the well to prevent nuisance shut-ins. The end result is reduced oil production rates and incremental wireline and operator costs. 2) Disable/remove safety valves with current chronic problems. An example of this is a well with a chronic hydraulic leak in the control line system which requires frequent operator attention (Le.. repressuring the hydraulic fluid reservoir on the pa.nel two or more times a day. 3) Pull wireline-retrievable (WRSSSV) or dìsable tubing-retrievable (TRSSSV) SSSVs at next wireline opportunity_ SSSVs add incremental wirelîne costs and a small element of risk through additional wireline runs. It is not recommended to make wíreline unit rig-ups specifically to pull/disable an SSSV. 4) Utilize remainder of SSSVs until an operational decision to remove/disable is made. It Îs. recognized that there is a cost to disable or remove a subsurface valve. As a result, many of the subsurlace valves will remain in service and will be gradually phased out as they impair well operations and require costly maintenance to keep them functional. Operations Standard Operating Procedures The GPMA Drill Site SOPs have been revised to reflect the minor operational changes resulting from the SSSV removaVdeactivation. These changes have been communicated to the GPMA Drill Site Operators via the Management of Change guidelines. IV. Criteria It is expected that the removal/deactivation of SSSVs in the GPMA will not be accomplished immediately, but will be conducted in a phased approach over several years. The SSSV$ will be removed/deactivated based on operational and economic considerations. However, some wells may continue to have functioning SSSVs based on their productive potential, proximity to faCilities, potential for envíronmental impact, special corrosion concerns, or well usage. Producers are segregated into two categories based on total fluid and gas rates. Listed below are the cr'iteria to be utilized when considering an SSSV for rem ova I/deactivation. Category I - Producers 2 FROM·' GPMhI ANCHORRGE ~ FRX NO.1 2634894 4IIÞ -.,rREATEA POINT MciNTYRE AREA SSSV MANAGEMENT IMPLEMENTATION 8/8/96 09-09-96 13132 P.04 PLAN o # The following wells will be da$ignated as Category I wells and will be required to have a functional SSSV in the GPMA: .... ,'........-......, ....... · Every producing well until deOISioned~~~..~~~.lu~t.~Aland reclassified. ""- · Covcr-.cd undor this last bullet aro-a{A)I producing wells at Point Mcintyre, West Beach, North Prudhoe Bay, and Niakuk~ will be oonsidered Catogory I due to their close proximity to open water and regardless of their actual rates. · Producing wells that have unllfted rates greater than or equal to 5000 BLPD or greater tha.n or equal to 25 MMSCFPD, · Producing wells that have unlifted rates less than 5000 BLPD and less than 25 MMSCFPD but have special concerns such as proximity to facilities or populated areas, potential for environmental impact, special corrosion concerns, or well usage as determined by the GPMA Superintendent (ARCO)/PE Supervisor (BPX). ".,.,.....,~.... ....--....-.....,.... '..... '" ' ....., Exc!p~iQ.{1;_6.Q.YJ;)ßJ9\J~.iD9 we.!.! may be exempted from this category b~o¡nt agfee.m~nt of) thE(yvel~:$ ~orkíng 111:~rest ?wn~respcoHvo Field Manager, and reclassífíëèfãš-CffiegõiÿlT. '...- ~.._.- ,¡;.~_.- ...., ",..' . ,. Category " - Producers Category II wells include all producing wells not included in Category I and are not required to have an SSSV. Any designation into this category requires a written recommendation by the GPMA Drill Site Supervisor (ARCO) and approval by the GPMA Superintendent (ARCQ)/PE Supervisor (BPX). Wells included in thìs Category are: · Producing wells that have unlifted rates less than 5000 BLPD and less than ~5 MMSCFPD, and have not been classified as Category I. · Producing wells with unlifted rates greater than or equal to 5000 BLPD or ~ªD~9x... .a.cw.al ~O.2.~,MMSCFPD that have been reclassified as Category II by the~ ..... ¿~~~.~t,.~~respcotil{e Field Manager. Injection Wells Gas injection wells, both natural gas and manufactured miscible gas, will continue to require SSSVs based On their potential deliverability and the risk of personnel safety. Water inlection wells will not require SSSVs. New Wells All new completions will be assigned to an SSSV Category by the GPMA Drill Site Supervisor based on projected usage and rate estimates provided by the Surveillance Engineer (see Appendix II). All Category I wells will have an SSSV included in the completion design. Wells designated as Category II will be approved as such by the GPMA Superintendent (ARCO)/PE Supervisor (BPX) and will not be completed with an SSSV. All completions which do not have an SSSV will have a profile at 50o± feet~s'u~ for setting a safety device if needed at a later date. .--^---- 3 FRO~I GPMe ~NCHOR~GE F~X NO.1 2634894 4IIÞ 0e-09-96 'REATER POINT MciNTYRE AREA SSSV MANAGEMENT IMPLEMENTATION PLAN 8/8/96 13133 ¢P When initial stabilized production rates are available from the new completions, the GPMA Field Engineer will verify that the well was assigned to the proper SSSV Category. No action is required for wells which produce at or below the maximum rate criteria for the pre- completion SSSV Category. If any well exceeds the maximum rate criteria for the pre- completion SSSV Category, the GPMA Drill Site Supervisor (ARCO) or Sr. Wireline Coordinator (BPX) is required to tskê the necessary action to get the well in complianCe with the Implementation Plan within 60 days- (Le.. either inctall an SSSV or get Fiela Manager approval to designate ClS CAT II). V. Procedur~ There are two procedures in this section. The first outlines the processes which will be used to a) identify the;....lrllij~.I!1~~0kP-~dUç.i.r'g~e!J..t.-'\ru¡J2J..m~~ªl~@~a~S-QnA ~9.y~rt~ly ~~. ~ The second proce ure êfëfin~s the steps to be followed when it IS desirea ~ ,~ remove an SSSV fro 11 service. ,!-<'~' '.,.....' ..' . ".. ...... .., .-..-...-.-...---.--......-...........-.-...'-.-. ",. ",......-....... ",/..-...."" .'".......'''.. ',' ,..,.... Procedure #1 - Initial Dettermination of Catl!gory of Producerç The first step in the SSSV removal/deactivation process is the determination of which wells in the field are În each Category. ThIs section describes the methodology for identifying the Category of those wells, based on liquid and gas rate cutoffs. A) Initial Procedure: ') The GPMA Field Engineer will identify all GPMA producing wells whioh have estimated unlifted rates greater than 5000 BLPD or greater than 25 MMSCFPD, at any time during the previous 12 months. 2) Wells which fall into this group, and CURRENTLY have VALID estimated un lifted rates less than 5000 BLPD and less than 25 MMSCFPD, will be deleted from the list. Well test data is considered valid as a basis for estimate only if the test was conducted within the previous SIX months, was deemed a "good" tast for allocation purposes, and the choke was In the full open position. 3) Wells which do not have valid well test data will be re-tested. 4) The Category of each well will be Identified based on the gathered valid well test data and the Category I & II criteria outlined in the previous section. NOTE: If a well qualifies for Category II, Procedure #2 must be followed to obtain proper authorization to remove/deactivate the well's SSSV. 5) A listing of all GPMA wells grouped by Category will be distributed by the GPMA Field Engineer to the GPMA Drill Site Supervisor (ARGO) and the Sr. Wireline Coordinator (BPX). RECEI\/ED 4 ~r~) () tò 19-QG ..... 1.._, ... " , "" ' /l,1!ask<l Oii 8, Gas Cons, Comm"zsioo AnchcíêQ:;; P.05 FROM.: GPMR RNCHORRGE , FRX NO.1 2634894 . REATER POINT MciNTYRE AREA SSSV MANAGEMENT IMPLEMENTATION 8/8/96 08-09-96 13133 PLAN 6) Functional testing and maintenance for all Category I SSSVS will be carried out according to the regulations and procedures in eHect prior to . 1996. B) Periodic Update to Category Determinations: The list of Category I and Category" wells (by production rate) will be updated each quarter by the GPMA Field Engineer to reflect any changes in production characteristics of the wells. The updated list will be distributed to the GPMA Drill Site Supervisor (ARCQ)/Sr. Wireline Coordinator (BPX). Wells that are currently Category II but have Category r production characteristics will be retested within three days and a SSSV will be installed within sixty days jf the test rate is equal to or greater than 5000 BLPD or 25 MMSCFPD. The GPMA Field Engineer will ensure that all of the Category I SSSVs have been tested within the preceding six months. Procedur, #2 - Procedure for SSSV Exemption/Removal The purpose of this procedure is to ensure that a consistent approach is taken when considering the exemption of a subsurface safety valve (SSSV) from a GPMA well. Each decision to remove/deactivate an SSSV may impact the safety of the well operation and should be carefully weighed regardless of rate. It is important to consider the various impacts of well energy, po1ential corrosion damage, safety, potential environmental impact, economics, and future well usage in the SSSV removal decision process. Procedure: " ~"'....--'-'-' ... '.. . " M . .,.a" .'. .'0" '.. .' "...I-'~*-----~' ( Note: This procedum does not currently apply to producìng wells at Point Mçlntyrs, West ') .... Beach, North Prudhoe Bay, and Niakuk. SSSVs wi/! continue to be maintained and tested in 1 . '. those wells (as per the Category I criteria above). _ ...... ._....."'......~._. ..._1 " "H' . ,......----.,..........~-. ," ...... ' ..... ,...' ...~ 1} Obtain a velìd well test. 2) Use the following table to determine the appropriate level of approva.1 necessary to remove/deactivate an SSSV: Well Test Rate Formation Gas Req'd Approval CAT BLPD Rate Level # MSCFD I 2 5000 or ;:0: 25000 No Removal ~ Deactivati orfC:¡ I <5000 but and <25000 but No Removal rff SpecÍI!!II Consideration Special Consider. Deaçtivatio D (see CAT I Criteria) (see CAT I Criteria\ II .c5000 and < 25000 GPMJ\ Supt(ARCO)/ PE Suøv(BPX) 5 P.06 FROM: GPI:t¡:: ¡::HCHOR¡::GE . F¡::X HO.: 2634894 4IIÞ REATER POINT MciNTYRE AREA SSSV MANAGEMENT IMPLEMENTATION 8/8196 08-09-96 13:34 P.07 ~;( qfY PLAN ~".~.' ~ "'...... I II 1 moo I O'J ~250ÒO I ~W~"'S WI~ I i el{"~· Mihâ ._--__. - _. '...... I _.~_._'_____'_.",. ,... .........-- --.............-'...... ~¡¡-- ---~ ,.....-.---.--. ~- ....¡...~------.........- '~.~..., "-.., ( ., SSSVs will be maintaì~ed and tested i~ wells with rates in this range unless removal !:.J 't., approved by thH well's Working Interest Owners. ~ ,.....,_ _.,~." .--, ."' ......._...........__. ___...--...,..,."..,..._.._......, .-------..-...---.........-----......",'.--_._1.'· ..-. -- '0' 3) The GPMA Drill Site Supervisor will prepare the REQUEST FOR GPMA SSSV EXEMPTION FORM (see Appendix III) and submit it for approval. The GPMA Field Engineer will retain the original approved form in their files, and will distribute a copy of it to the appropriate personnel listed on the bottom of the form. 4) Following the removal/deactivation of the SSSV, the GPMA Field Engineer will ensure that the appropriate information is entered in the EOAJWOA Subsurface Safety Valve Master Database for tracking SSSV removals/deactivations on a Operator-wide basis. 5) The GPMA Field Engineer is responsible for making and distributing the appropriate changes 10 the Wellbore Schematic. 6) The GPMA Drill Site Supervisor is responsible for ensuring that a sign is placed on the outside of the wellhouse indicatìng "CAT II-NO SSSV11. In addition, a CAUTION tag will be utilized in the wellhouse (at the tree needle valve and on the hydraulic panel) to denote that the SSSV has been removed/disablgd. VI. SSSV/SSV TestingfMaintenance During. the first 12 months following ~nl!!.alexecution of the Implementation Plan,. all of the potential Category II wells will beceva¡üãte~ by the GPMA SuperIntendent (ARCO)/PE Supervisor (BPX) as to~ctive SSSV requirement. Those wells which are granted an exemption and are approved for operation without SSSVs will require no further testing or maintenance of the SSSV. Conversely, the wells for which there is no exemption of the SSSV requirement will continue to be tested and maintained in aocordance to the procedures in effect prior to ;::¡.I-19~ª-""rAII wells will continue to be tested at the current six month frequency until they are~ate~eCisioncG. Testing Testing will be conducted to meet requirements set prior to , 1996, and test frequency will continue to be once every six months. The SSSV testing be conducted in conjunction with the regularly scheduled State-witnessed testing of the well's Safety Valve System (SVS). Surface safety valves (SSV) and low pressure pilot valves/switches on all wellS except water injectors will continue to be State-tested on current 6 month schedule as per current AOGCC regulations, It should be noted that when an SSV fails a State test, the valve must be repaired or replaced no later than the next calendar day. In addition, GPMA operating procedures dictate that a low pilot/switCh failure on a prod'tÇiet1!~ '\frtrs one of the 6 KL .... r, ED V~ L: 19Qh :> . iU I ..¡v ,,,. .. C' f'~ i'''-¡11m;SSìon A\askç1 On g, Gas 0,',," vû AnchGf2.g;:) FROMl GP.M~ ANCHORAGE 'FAX NO.1 2634694 4IIÞ 0a-09-96 REATER POINT MciNTYRE AREA SSSV MANAGEMENT IMPLEMENTATION PLAN 8/8/96 13135 p.0a ~ ~/ following actions: 1) the pilot/switch be repaired immediately with a man-watch on the pad until repairs are completed or, 2) the well is shut-in at the wellhead and manifold building. The GPMA Field Engineer will continue to coordinate State-testing as well as maintain SVS test records for the field. Maintenance The emphasis of the well SVS maintenance program in the GPMA will be on the surface safety valves and pilot valves/switches. This equipment has been demonstrated to be more reliable in part because of its accessible location. The only sssvs which will be maintained will be thOSê Category I wells identified in the Criteria section as required to have functional SSSVs in place and the Gas Injection Wells. VII. Tracking/DocumentQtion The GPMA Field Engineer is responsible for the tracking system to document the status of the SSSVs for each well in the field. 1) Bøquest For GPMA SSSV Exemption FQrlJJ~ - The GPMA Field Engineer will retain the original approved hard copy in their files and will distribute a copy to the personnel listed on the bottom of the form. 2) EONWOA Subs~rface Safety Valvê Master Database· This will be the central tracking database for each area of the field The GPMA Field Engineer will ensure the database is updated when the approved removal/deactivation forms are receÎved and the well work has been completed. It will not be necessary to enter an SSSV which has been removed from service on the Safety Defeated Log (SOL) since the removal is being tracked on a master database. VIII. Communication The GPMA Drill Site Supervisor wÎII ensure that the fOllowing items are completed: Wellsite 1) $ígn on outside of wellhouse (red metal background with whìte letters) for wells without SSSVs~ required verbiage - "CAT II-NO SSSV'I. 2) CAUTION tags on the tree needle valve and on the hydraulic panel indicating: "SSSV Not in ServIce". Well Records 7 FR0t:11 GPt\¡:¡ ¡:¡NCHORRGE , , FRX NO.1 2634894 . REATeR POINT MciNTYRE AREA SSSV MANAGEMENT IMPLEMENTATION 8/8/96 08-09-96 13135 P.09 PLAN ~ d7 ') Wellbore Schematics - The GPMA Field Engineer will make the proper notations on the wellbore schematics to Indicate that an SSSV is not in service, or that an SSSV Is not installed. IX. Program Revjew Proces§ Initial Plan Assessment An Initial Plan Assessment will be conducted by the Operator's HSET Departments beginning six months atter the Implementation Plan is instituted in the field. The purpose of the assessment will be to evaluate and report to management on Plan compliance, Plan deficienCies, and make a recommendation on whether future HSET assessments are required. Annual Review The annual review process is viewed as a very important component of managing SSSV utílization and removal in the GPMA. As experience is gained, it may become necessary to adjust the management of the process. The GPMA Drill Site Supervísor will be responsible for initiating the annual review process. ExxonŒnDsnooJel be invited to participate in the annual review because of their contribution to the ðevelopment of the criteria utilized in the Implementation Plan. It is suggested that the annual review should accomplish the following objectives: 1) Review the status of SSSV removal/deactivation in the field. Examples of information to be included are number of valves removed/deactivated. types of wells Impacted, any notable problem areas, assess risk of the current implementation plan, identify wells which crossed Category lines following the removal/deactivation of the SSSVs. 2) Review the decision criteria and make recommendations to revise the criteria if necessary. 3) Report the staWs of the SSSV removal/deactivation progress to management. 8 #27 .. / J :i ~ i ¡ :\ \ . / ; ~ . . -,. "'",- - ~ .-....... '~~, ; t,j t -:\, ~ -' ....;\-:.~: U TONY KNOWLES, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE. ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 June 5, 1996 Joseph A. Leone Manager, Greater Point McIntyre Area ARCO Alaska, Inc. P.O. Box 100360 Anchorage, AI< 99510-0360 Jp Dear Mr. Leone, The Commission received your inquiry regarding acoustic liquid level measurements in Lisburne wells. Acoustic measurements have been used to determine well and reservoir pressure for many years. The concern we have is that the measurements are representative of reservoir conditions and that accuracy is reasonable. Your example indicates over 90% of the data sample falls within 5% or less of measurements made with electronic or mechanical downhole gauges. F or practical purposes this accuracy may be reasonable for most reservoir management applications. Detailed reservoir transient tests, interference tests, pulse tests and the like may require more sophisticated downhole tools with better precision and accuracy. /' The pool rule indicates those types of pressure tests which can be used for fulfilling pressure measurement requirements. We expect the operator or owners of the pool to determine the tools best suited for the job using good oilfield engineering practices. Should analyses indicate inaccurate data, then remedies can be implemented. We would ask that acoustic measurements be identified on Form 10-412, Reservoir Pressure Report, and recommend that an occasional check on the accuracy be done. If you have any other questions or comments on reservoir pressure measurements, please contact Jack Hartz at 279-1433. Sincerely, #26 · r< «(. ,r-' ~(.\l- I" e COMM COMM Joseph A. Leone Manager Greater Pt. Mcintyre Area RECEIVED ~~ ~Sl'fb &-r ~~ ARca Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 May 14,1996 MAY 1 6 199,6 Alaska Oil & Gas Cons. commission Anchorage STATTEC Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Fn.E.. m 'c...o ~01 Re: Reservoir Pressure from Acoustic Liquid Level Measurements in Lisburne Wells Conservation Order No. 207, Rule 10 Prudhoe Bay Field, Lisburne Oil Pool Dear Mr. Johnston: ARCO Alaska, Inc., Operator of the Lisburne Oil Pool, requests Commission approval to use reservoir pressure data obtained from acoustic liquid level measurements to meet the annual pressure survey requirement of paragraph (c) of Rule 10, Conservation Order 207 (as amended by Administrative Approval No. 207.11, dated 6/29/89) for Lisburne wells. This measurement method is only proposed for those Lisburne wells which when shut-in have no liquid above the perforations, or have only an oil liquid phase present in the well bore. This measurement method yields acceptable data for reservoir management purposes and allows this data to be obtained without imposing mechanical risk to the well by running wireline gauges in the wellbore. This method also allows the required data to be obtained at lower cost than with wireline gauges resulting in improved operating efficiency and higher ultimate recovery. As currently written, paragraph (c) of Rule 10 states that: "Acceptable pressure surveys include static surveys, RFT/FMT, pressure buildup and falloff tests, and multi-rate pressure transient tests in production or injection wells." It does not address which measurement methods are acceptable to perform these surveys. Historically, static pressure surveys have been conducted by running either slickline or conductor line conveyed pressure gauges in the well down to or near the depth of the perforations and recording the pressure at depth. Obviously, this technique imparts a mechanical risk to the well bore should problems be encountered while running the gauges. Even though these wireline gauges are designed to withstand the harsh environment and handling involved with their deployment in the well, in some cases, the gauges have been damaged, necessitating additional runs, and thus, additional risk to obtain the data. The acoustic liquid level method involves an acoustic determination of the liquid level in the wellbore by generating a pressure pulse at the surface and recording the echoes from jewelry in the well (nipples, gaslift mandrels, packers, etc.) and the liquid level. A microphone in the test equipment converts the pressure echoes into electrical signals which are recorded on a strip chart. The acoustic velocity of the pulse is obtained from the time required for the pulse to travel a known distance to each item of jewelry. The depth of the liquid level can then be determined by applying this velocity over the time span between the last "seen" piece of jewelry in the tubing and the recorded reflection from the liquid level. An accurate pressure gauge is used to measure the shut-in wellhead pressure at the surface. Pressure in the tubing above the liquid level is determined by adding the shut-in wellhead pressure to the product of the gas pressure gradient and the true vertical depth in question. Pressure below the liquid level is determined by adding the shut-in wellhead pressure, the pressure exerted by the gas column from the surface to the liquid level, and product of the liquid gradient and true vertical depth below the liquid level. In wells which make both water and oil, the liquid gradient is not known for certain, and consequently, calculated pressures below the liquid level in these wells are questionable. ARCO Alaska, Inc. is a Subsidiary of AtianticRichfieldCompany "Joseph A. Leone Ur. to David W. Johnston Alaska Oil and Gas Conservation Commission Re: Reservoir Pressure...Conservation Order No. 207, Rule 10 . e Page 2 However, in shut-in wells which exhibit gas from suriace to the periorations, or which make only oil, and therefore, would have a known liquid gradient, calculated pressures can be obtained which agree very well with wireline conveyed pressure gauges. This was demonstrated in 38 pressure surveys run in Lisburne wells of this type during 1993-1995 in which static bottom hole pressures from both wireline conveyed pressure gauges and liquid level pressure measurements were determined. The data obtained from these surveys were compared and the results are shown in the attached graph. As can be seen, the pressures obtained by the liquid level method agreed very well with those obtained using the wire line gauges. We believe that the liquid level data is sufficiently accurate for reservoir management use and is preferable due to the elimination of mechanical risk to run wireline gauges and lower costs. Therefore, if the Commission agrees this meets the requirements of paragraph (c) of Rule 10 of Conservation Order No. 207, ARCO Alaska would like to use the acoustic liquid level method to conduct static bottom hole pressure surveys in Lisburne wells, which when shut-in have gas from suriace to the periorations or have only an oil liquid phase present in the wellbore. Please contact me if you require additional information or action from us. ~~~j~- Attachment JAL:HGL:my xc: A. N. Bolea J. F. Branch K.J.Fuhr M. G. Griffith J. W. Groth R. W. Janes H. G. Limb W. McMahon M. P. Worcester FileFP BPXA (MB 7-2) Exxon (Anchorage) A TO-420 Exxon (Houston) ATO-470 BPXA (MB 7-2) A TO-496 Exxon (Houston) A TO-2090 REcetVED MAY 1 6 1996 Alaska Oil & Gas Cons. Commission Anchorage ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany LISBURNE FIELD STATIC VS. LIQUID LEVEL BOTTOMHOLE PRESSURE COMPARISON , 4500 RECEIVE - 4000 ~ 3500 Q. - en ...I UJ > UJ ...I ~ 3000 a :::::¡ :æ o a: ~ ~ 2500 ED J. Oil & Gas Cons. Comm Anchorage 2000 o Constant z factor (z=0.7) . Iterative z factor* IDEAL FIT LINE . - - . - - . +5% LINE . - - . . - - -5% LINE e * Accounts for z factor changes due to gas press & temp increases with depth 1500 1500 2000 2500 3000 3500 BHP FROM STATIC SURVEY (PSIA) 4000 4500 38 data points from 1993, 1994, and 1995 5/14/96 *5 ARca Alaska, Inc. . Post Office Box 100360 Anchorage Alaska 99510-0360 Telephone 907 276 1215 . ~. J) ~~ ."~~'F~ ~ '<'~': ..'~: ...~ ". June 15, 1994 Mr. D. W. Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Road Anchorage, AK 99501-3192 Re: Proposed Flaring of Gas Lisburne Production Center Dear Mr . Johnston, APtl.oì.JI... ARCO Alaska, Inc. (ARCO), as Operator of the Lisburne Production Center (LPC), requests Commission approval for flaring up to 60 MMscf of gas at the LPC during the period of June 28 - July 5,1994. The purpose of this flaring will be the safe evacuation of hydrocarbons from the surface production system necessitated by the tie-in of the second Point McIntyre Drill Site (PM-2) and some minor modifications to the LPC process systems. Operationally, all attempts have been made to reduce the amount of black smoke and the flaring of gas will be kept to a minimum. All gas volumes flared will be included on the producer's report(s) of gas disposition filed monthly. If you have any questions or desire additional information, do not hesitate to call me at 265-6538. £f(IL Engineering Supervisor Lisburne/Point McIntyre Engineering JLH/jm ARCO Alaska, Inc. Is a Subsidiary of Allantic Richfield Company RE(£\VED JUN Î 6 '\994 [\\a3\Za 0\\ & Gas Cons. Commission . - Anchorage it24 ALASKA OIL AND GAS CONSERVATION COMMISSION October 21, 1993 c~¿)· ~û'1 ~¥&¥Œ t &~&~~& WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TElECOPY: (907) 276-7542 Andrew D. Simon Manager, Lisburne/Point McIntyre ARCO Alaska, Inc. POBox 100360 Anchorage, Alaska 99510-0360 ... Re: Amendment to the Lisburne Pool Rules Dear Mr. Simon: Commission regulations 20 AAC 25.515 and 25.245 allow for surface commingling of separate pools and production to common facilities with monthly well testing. At this date more detailed criteria are spelled out for West Beach and Pt. McIntyre production under Conservation Orders 311 and 3 17. The Commission agrees that Lisburne pool rules should be consistent with these two orders. Conservation Order No. 207, however does not provide the administrative instrument for making the changes proposed in your August 9, 1993 correspondence. To accommodate both our concerns regarding the Lisburne pool rules, the Commission invites the Lisburne owners to propose a general consolidation and re-write of existing pool rules. The Commission believes that administrative burdens will be reduced with one conservation order for the pool. Future modifications to the consolidated order may be made by issuing an amended order. At anyone time only one order would exist for the pool which would eliminate some of the current confusion that arises from having multiple orders for a single pool. The Commission welcomes your comments regarding this concept and is available for further discussion. Sincerely, rH~nH~d nfl r~(:rdcd paper b y c.o. -:\t23 ~.. ... , . . . Recommended Amendments Lisburne Oil Pool Conservation Order No. 207 Rule 7. AUTOMATIC SHUT-IN EOUIPMENT. Amend rule to add a new subsection (d), as follows: d. SSSVs may be temporarily removed as part of routine well operations without specific notice to or authorization by the Commission. Add the following new rules: Rule 15. SURFACE COMMINGLING AND COMMON FACILITIES. a. Production from the Lisburne oil pool may be commingled on the surface with production from other pools prior to custody transfer. b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the Commission monthly in both computer file and report formats. 1. Conduct well tests to determine production rates for each well. 11. Production from each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. 111. Sum the TMP volume for all wells in all pools. IV. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e. metered/TMP) v. Calculate each well's actual monthly production (AMP) volume as: AMP = TMP x Allocation Factor .R~... r: r ¡: I \ IFf) t... \... L J \I ~-,. ~.. " i ,^" 1 2 199';( !"\db, ,.. v Alaska Oil & Gas Cons. CDrnmiss\CH' Anchorage ,..' " »- . . Recommended Amendments Lisburne Oil Pool Conservation Order No. 207 c. NGLs will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the Commission. d. Each producing well will be tested at least twice each month. Wells that have been shut in and cannot meet the twice monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. e. Optimum test duration and stabilization will be determined on a well by well basis by the operator. f. Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on-line water cut measurement devices. g. API gravity will be determined for each well annually by an API/MPMS approved method. h. Gas samples will be taken and analyzed for composition from each non- gas lifted producing well yearly. 1. Quarterly allocation process reviews will be held with Commission. J. This rule may be revised or rewritten after an evaluation period of at least one year. Rule 16. PRODUCTION ANOMALIES. In the event of oil production capacity proration at or from the LPC, all commingled pools produced at the LPC will be prorated by an equivalent percentage of oil production recognizing mechanical limitations and operational constraints. REEEj t ¡ ~,"O ~ ··1 (" 1 ? 199';t f),UO -, >,.; " . - 'SS\CW Alaska QiI& Gas Cons. vomU), . Ancnorage :ff22 .. ' ARCO Alaska, Inc.. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 263 4275 .' ~~ ~~ Andrew D. Simon Manager Lisburne/Point Mcintyre August 9, 1993 Mr. D. W. Johnston, Chairman State of Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Request for Amendment to the Lisburne Pool Rules Conservation Order No. 207 Dear Mr. Johnston: As was discussed at the recent Pool Rule hearings, modification of those Lisburne Pool Rules dealing with surface commingling, common production facilities and production anomalies is necessary to achieve consistency with the Pool Rules recently issued for the West Beach Oil Pool (Conservation Order 311, dated February 5, 1993), and the Point McIntyre and Stump Island Oil Pools (Conservation Order 317, dated July 2, 1993). Also, we propose Rule 7 of Conservation Order No. 207 be changed to be consistent with the corresponding rule in the Pool Rules for the Pt. McIntyre and Stump Island Oil Pools, Conservation Order 317, Rule 8. The proposed amended rule would remain more stringent than required under 20 AAC 25.265. We believe administrative approval is appropriate in this case. Both Conservation Order No. 311 and Conservation Order No. 317 are very recent, and are based upon public hearings held on January 13, 1993 and March 24,1993, respectively. For the foregoing reasons, ARCO, as Operator and on behalf of itself and the other Lisburne working interest owners, requests the Commission amend the existing Lisburne Pool Rules, Conservation Order No. 207, as reflected in the attachment to this letter. Please contact me if you require additional information or action from us. Sincerely, A\) ~~ Andrew D. Simon Manager Lisburne/Point McIntyre RECEIVE ADS:GKP:md ^ Ui" '1 ') 1093 .<,_,1(, <",.1\ Attachments Aìaska Oil & Gas Cons. LvwrmsS\u Anchorage ARCO Alaska, Inc. Is a Subsidiary of Atlantic Richfield Company #21 .. . ARCO Alaska, Inc. Post Office B ^ 00360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 . ~~ ~~ November 5, 1992 D. W. Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Subject: L§-24 Downhole Separation Test-Sundry Approval Dear Dave: Sundry approval is requested for a short-term test on Lisburne Well L5-24. The test will involve oil and gas separation downhole with gas being produced up the 3 1/2" x 9 5/8" annulus and low GaR oil production up a coiled tubing string into the 3 1/2" production tubing string. Temporary piping will connect the annular production to the L5-22 well slot. We request approval to conduct this test without subsurface safety valve (SSSV) control of the annular fluids. Subsurface control of tubing production will be operational. A surface safety valve (SSV) will be placed on the 31/2" x 95/8" annulus. Dedicated manning during the production test up the annulus is planned. Annular production is planned to last no more than two weeks, and the downhole equipment will be removed within one month of installation. Gas compression limitations restrict production throughout the North Slope. Successful downhole separation could provide a gas source at high flowing surface pressures 0,100-1,500 psi). This could potentially make additional gas compression and injection economically attractive since compression ratios and required horsepower will be lower. Also, the gas could potentially be used to provide for raw gas lift thereby reducing overall gas handling. While hydraulics and gas separation calculations suggest that gas can be separated downhole to provide a gas source with high flowing pressures, a test of this concept is needed for verification. Key objectives of the test are to determine the effectiveness of separation and to determine pressure drops in both the annulus and tubing for projection in longer-term applications. A schematic of the proposed test completion of L5-24 and a test procedure are attached. The downhole separation would be accomplished through the installation of approximately 750' of 2" coiled tubing hung in the 3 1/2" tubing with a hydraulically set packer. The bottom of the coiled tubing will be below all perforations. Low GaR oil production will be produced up the 2" coiled tubing and will travel to the surface via the 3 1/2" tubing. A circulating valve RECEIVED ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany NO\! .- 9 1992 Alaska Oil & Gas Cons. ttrrnffi1SS\on Anchorage . . Mister Johnston November 5, 1992 Page 2 will be installed at 9,890' MD to allow gas production into the annulus. Temporary piping will connect the L5-24 annulus to the L5-22 well slot and a SSV will be installed at the L5-24 casing valve. The well will be continually manned during production of the annulus. A short test is also planned to produce all fluids up the tubing to determine if the well's GOR is reduced due to the coiled tubing being submerged in liquid, below the gas productive perforations. L5-24 currently produces 760 BOPD and 17.1 MMSCFD at an FrP of 728 psi. During the test, it is estimated that approximately 9.5 MMSCF will be produced through the annulus with a surface flowing pressure of 1,100-1,300 psi. Options for downhole SSSV control of the annular gas production have been investigated with several vendors. Problems have been encountered finding a design which is fail-safe yet would not cause excessive pressure drops in the gas stream, thereby defeating the purpose of this downhole separation test. With the SSV and continual manning of the test site during annular flow, safe, short- term operation can be assured. If the test proves successful, longer-term options for subsurface control of annular production will be investigated. Your timely approval of this short-term downhole separation test on L5-24 would be appreciated. Please call me at 265-6538 if you have any questions concernin~~ J. L. Harris Operations Engineering Supervisor Lisburne/Point McIntyre Engineering JLH/MJW /mmh Attachments RE(EJVED NOV - 9 1992 Alaska OiJ & Gas Cons. Commission Anchorage .ø:œ~,IIm:.ile<aSUbi~eúI~låIfIIi~ . . DS L5-24 Proposed Procedure for Downhole Separation 1. Perform MIT test on 3 1/2" x 9 5/8" annulus. Monitor 13 3/8" annulus pressure. Insure no communication between 9 5/8" x 133/8" annulus before proceeding with test. 2. Rig up temporary piping from 3 1/2" x 9 5/8" annulus to L5-22 well slot. Install 55V. Pressure test piping. 3. Equalize and pull dummy gas lift valve at 9,890' 55. Install 3/ 4" circulating valve. 4. Hang 745' of 2" coiled tubing from retrievable packer set at 9,880' MD. RD CTlJ. 5. Produce well up 3 1/2" tubing while applying lift gas on annulus to unload. 6. When annulus is unloaded, begin production up both tubing and 9 5/8" annulus. Well will be manned throughout test and pressures will be monitored. Well will be flowed for maximum of two weeks up annulus. 7. Pull coiled tubing and packer. 8. Pull circulating valve. Run dummy GL V. 9. Rig down temporary piping from annulus. RE€EIVED NO\! -- 9 1992 Alaska Oil & Gas Cons. CommissiOn Anchorage ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany #20 SENT BY:ARCO AK. INC. ; 3-25-92 1:06PM FIELD SUPPORT/OPS~ FROM AOGCC;# 1/ 1 ARCO Aluklt Inc. . Post omc¢ Box 100360 AnChoragé, A1~.k" 00510-0960 Tèlephone 907 276 1215 . March 25, 1992 ~~ ~". Mr. Russell A. Douglass. Commissioner State Of Alaska Alaska 011 and Gas Conservation Commission (AOGCC) 3001 Porcupine Drive Anchorage. AK 99501-3192 Dear Mr. Douglass: Sub/ect: Elata at LPC. Modul9 4926 (NGL. PlanH. for Maint. & Mods. AAI requests approval to flare up to 50 MMSCF of gas st the U~ Production Contor (LoPC) in the Lisburne Participating Area of the Prudhoe Bay Field. The flaring will occur in conjunction with required maint9nance and modific:;;Jti(')n~ tn thê NGL Plant (Module 4g26). The flared cas is a combination of hA~tød fuel gas, NGL'$, and propaM from the prOOOGS piping and vessels in the module. The heated fuel gas is being used to vaporize the light liquids which are residual in the process Aqllipmant ~ft9r draining and recov9ry in tho LÞC. ProcGas ....essel inventories will be reduced as -much as possible to minimize lost product and flaring. Flaring is planned to begin April 1 and should be complete by April 15, 1992. The actual restart date is pltmm:d by April 7, thus the extra time until April 16 is to allow for unfore5fHBn co.ntingancies which may result In delayed restart of the module. The requested flare volume is 50 MMSOF_ Contingencies have been built into this figure to allow for the potentia' of a delayed restart. EVAry f:Jftort will be made to keep flaring to a minimum whenover possible and all votume5 will be reported on the Monthly Gas Disposition Report, Alaska Oil and Gas Conservation Commission form 10·422_ Plêasê call me at 659.5g22, If you have any questions. I apologize for the short Il;Inn nature of this request, and In the future will endeavor to give you more advance notice. Sincerely, J :r-. ¿Jt<¿JvJJdr. ' _. W.R. Worthington EOC Supervisor PrudhoQ Bay Operations II It Z-r;;> 7. I ~ , ~ 3 - z. 5" - {'"L-- RECEIVED ~1r-\D 2 ç- lqO? IJ,t-.r\ ::> ¡,,-J.~ Alaska WI & Gas Cons. Commission Anchorage ARCO Alaska. Inc. I. a Subsidiary of AtJantlcRichfie!dCompany y -:£. ,-fèÞV J<+- 63 N ~ If,o¿ #19 1\ I \ . I 1 ARCO Alaska, Inc. Post Ollice Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 ? ~cS /J-~Ie ' June 22, 1989 ~ ,c';') Ü I..,. , '~-<-I\\"-'vV ) Ul ~ l~ Ó}V,-<.y· ~ I"f~<~ \. - tv D/~~ ~-T7' f¿~) .. Mr. C. V. Chatterton Chairman , Alaska Oil and Gas Conservation Commission State of Alaska 3001 Porcupine Drive Anchorage, AK 99501 Dear Mr. Chatterton: Modifications to Rule 10, Conservation Order Number 207 R.A) COMM coM. __ c6M~ __ RES-~~~ ._ SR- ËNG ~ SFf ËNG \. ËNGASST \ ENGÃSST \ SRGËÖL { GEOL ASST\ GEocÃsst1 _ --tÃYTECH \ s ._,.__ sTÀfl'ECH\ FïL-e " AAI, as operator of the Lisburne ,field, has recently completed the second year of a two-year pre:ssùre Monitoring Program in order to comply with Rule 10 of the State of Alaska Oil and Gas Conservation Commission (AOGCC) Order 207, Fiëld Rules .for the Lisburne Field. It is timely to revisit this program to determine if any optimizations can be made to ensure that the data received is of the most value to the Lisburne Owners and to the AOGCC. Our review has led us to recommen4 that several changes be made to the existing Pressure Monitoring Program. Attachment 1 is a copy of the existing Rule 10 which you approved upon our recommendation in 1987. As you will recall, the program ~as basically laid out for a two-year period to "test" the feasibility of such a program in a reservoir as complex as the Lisburne. Attachment 2 is a copy of AAI's recommendation for the 10 modified Pressure Monitoring Program This proposal has been reviewed. and approved by all -Lisburne Owners. We believe that this proposed '. program is superior to the existing program for several reasons, including: It eliminates or reduces the acquisition of data that would not be required for optimum field operation or development. Production impact is therefore minimized. It allows the operator to concentrate the pressure surveillance effort in the areas of most importance to reservoir understanding. RECEIVED JUN 2 2 1989 ARCO Alaska, Inc, Is a Subsidiary 01 AllanllcRlchlleJdCompany Alaska Oil & Gas r:ons. Commission AnchlJrage,m' I, ." '~.. Mr. C. V. Chatterton June 22, 1989 Page 2 Due to the stratified nature of the Lisburne, pressure data from such procedures as buildups, falloffs, and statics are dominated by the zone of highest permeability, and do not represent the actual conditions in some of the tighter intervals. However, this pressure data is still valuable for use in such endeavors as:' ," Calibration of the Full Field Model. -- Understanding production mechanisms in different areas of the field. ' . Indications as to the impact of pressure support in the field, such as with gas reinjectIon and waterflood. Obviously, RFT /FMT'ð.ata is superior for the case of a stratified reservoir. Although it is our intention to _continue to collect RFT /FMT data when appropriate, this proposed Pressure Monitoring Program augments this effort with valuable data. .' Work recently completed by ARCa Alaska., Inc. has identified areas of the Lisburne field that are dominated by specific producing mechanisms. A map of these areas has been included as Attachment 3. It is the intention of the proposed Pressure Monitoring Plan to obtain one pressure data point per year in each one of these ar~as, with additional data as required for good reservoir understanding. As can be seen from this map, these areas roughly equate to a geographical distribution by drillsite. Therefore, for clarity and ease of administration, this proposed modification to Rule 10 includes one~ pressure data point per year per drillsite. As has been seen from past" experience, considerably more pressure data than the minimum requirements will most likely be gathered, and all data will continue to be transmitted to the AOGCC monthly through existing procedures. " ~ " .' In summary, Lisburne has successfully completed two years of its Pressure Monitoring Program, and it appears prudent to modify this program at this time. The plan outlined in this memo addresses the AOGCC's concerns about adequate pressure monitoring of the reservoir, as well as increasing the flexibility for the operator to gather data that will promote the best RECEIVED JUN 22 ]989 Alaska Oil & Gas ConGo CommisGiOIl Anchorage ·/ / .... Mr. C. V. Chatterton June 22, 1989 Page 3 reservoir understanding possible from a stratified reservoir, such as the Lisburne. We have a meeting scheduled with you and your fellow commissioners on June 27th to discuss ou~,proposal in more detail. We look forward to seeing you then. Sincerely, . 1,¿.lJt11. O~"k7J ~~ R. G. M. Oba Regional Operations Engineer Lisburne Engineering , ' RGMO:MAN:HB "Attachments cc: P. Coyne J. D. Dayton J. A. K. Humphrey Exxon ATO - 476 BP Exploration, " I' I' ~~ , . " RECEIVED JUN 2 2 198~¡ Alaska Oil & Gas Cons. Commissiou Anchorage / "/' / .~.. Attachment 1 EXISTING LISBURNE PRESSURE MONITORING PLAN CONSERVATION ORDER 207 RUlE 10. PRESSURE SURVEYS A) All new wells shall have an acceptable pressure survey, as defined in part (c), taken prior to sustained production or injection. B) One pressure survey per producing drïllsite quadrant per year shall be taken. Water injection well pressure surveys may be used for the quadrant well. Pressure surveys from sectiðn (A) may be substituted for a drillsite pressure. t/ C) Acceptable pressure surveys include static surveys, RFf /FMT, pressure buildup and falloff tests, and multi-rate pressure transient tests in production or injection wells. Other quantitative methods may be administratively approved by the Commission. v' D) The pressure datum for the Lisburne Pool is 8900 feet subsea. The Commission may ~dministratively amend this datum or create an additional datum when more information is available on the .. reservoir. v E) Data from the pressure surveys, along with· additional pressure data obtained through proper management of the reservoir, shall be filed on form 10-412 by the last (jay of tp,e month following the month that the pressure survey was obtained. Submitted pressure .' data shall include other information as necessary such as rate, time, depth, temperature, and well conditions to allow for a complete analysis of the pressure survey. ¡j F) The Operator will review the scope of the pressure monitoring progr~m with the commission before July 1, 1989 to determine if a useful program can be implemented. .,t' .' " RECEIVED JUN 2 2 19B'· Alaska Oil & Gas Cons. l;l"II\I:)~v Anchúrage : . . ,.'t. .. .' . , . .../ I II . , 'I / Attachment 2 PROPOSED LISBURNE PRESSURE MONITORING PLAN CONSERVATION ORDER 207 RULE 10, PRESSURE SURVEYS v A) An new wells shall have an acceptable pressure survey, as defined in part (c), taken priC?r to ~ed prôduction or injection. B) One pressure survey per producing drtl1site per year shall be taken. Pressure surveys from producing or water ånd gas injection wells may be used for this pressure requirement. Pressure surveys covered in section (A) may be substituted for a drtllsite pressure. C) Acceptable pressure surveys include static surveys, RFf /FMT, pressure buildup and falloff tests, and multi-rate pressure transient tests in production or injection wells. Other quantitative methods may be administratively approved by the Commission. '. D) The pressure datum for the Lisburne Pool is 8900 feet subsea. .. The Commission may' administratively amend this datum or create h an additional datum when more information is available on the reservoir. / "I \;" V E) Data from the pressure surveys, along with additional pressure data obtained through proper management of the reservoir, shall be filed on form 10-412 by the last day of the month following the , , month that the pressure survey was obtained. Submitted pressure~ rz data shall include ot.her inform. ation as necessary such as rate, time, . depth, temperature, and well conditions to allow for a complete analysis of the pressure survey. ,. .-.,. "'i... '. , , R E ( E I V E Do_ JUN 2 2 1989 I< 0',1 & Gas Comj, l;oilllnis!:JOII Alas a Anchorage / ~ . '.. '.l jr. Attachment 3 , , STATE PRESSURE MONITORING PROGRAM KEY PRODUCING AREAS ~ '. .,:- LGI AREA~~~~~~ ~~ GAS CAPpÞORT "'~""""""""~""""" ~""" ~,,~ :-.~~~"', -~"""""""""""""'~ L5 AREA ~''''''''''~~ :-.'~~'õ: - LS-29 SOLUTION GAS WITH GAS ~,,, CAP SUPPORT LS-28 , ~5-24 LS-32 ,1''''; m n m LGI-4 --. L5·15 LOWER L 1 AREA SOLUTION GAS WITH GAS CAP SUPPORT ~ Ø) en ~ Ø) g to- e:: Z 1\) r-v Qo >C> ::I Ø) C"> VJ gC) CJ g 'ã5~") - C) <.D o = :3 <.D 3 ëj¡' ..? 0' ::> ',,~ L2-32 ? L2-28 L2-13 W ATERFLOOD AREA WATERFLOOD SUPPORT < L2 m o L2-3 . . L3-31 L3 AREA SOLUTION GAS + AQUIFER INFLUX L4 AREA TOO NEW TO TELL . :1., " *11 <6 í ) / . ¿ (J ' ~::.J. -- LISBURNE WATERFLOOD REVIEW LISBURNE ENGINEERING APRIL 6, 1989 '-.-- '-" ~- ARCO Alaska, Inc. Post Office B.____ 00360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 - ~.~ ~" "--~ April 6, 1989 Mr. L. C. Smith Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Subject: Lisburne Waterflood Expansion Dear Mr. Smith: ARCO Alaska, Inc., as operator ö'f the· Lisburne Oil POO}i requêsts approval to conduct expanded waterflood operations (specifically, the conversion of Well L2-~2 to injection) at Drill Site L2. The planned operations have been formulated to provide additional recovery from the Lisburne. Additionally, the near term development objectives of this expansion include: · Obtain field demonstrated waterflood behavior iñ a timely and cost effective manner · Reach an injection-to-withdrawal (I/W) ratio of at" leasf ône to one · Mitigate decreasing reservoir pressure-- resuíting~ from primary prod ucHon · Provide short tetm tedu(:tions;; ìil field gas prÖduction through GaR suppression td'- maximize field oil offtake The expanded operati:oRs include: .1) incÞeäse/re(Ustribu~e wafer injection into wells already on ilijectiotf ('L2-10, L2-16; aJid~ L2-24), 2) continue water injection into: We1L L2:f8, and:: 3) cón~rtWelr ~2~~2 to. water inject.i.0n service:~ The data:: obtained· £röm', theS·ê··opêiàtions' will Dè' (1ómbined wfth that· obtained from previous watetfloôtf oper'atiðrl~'_ a~d-' studies irf ordef' tó properly evaluate this .·methôdHofrocot'éty:· Oñi~ a ·fúll.:.fiéld:-15'asis~ ARCO Alaska; tne. is a Subsidiary of AllanticRichfieldCompany '-' .-<~ Mr. L. C. Smith Page Two Apri13,1989 "- Attached is a copy of the presentation we have discussed on this date which summarizes the history, understanding, and details of this project. Please feel free to contact me if additional information is required. Sincerel y, iÆ 11Þ-~ J. L. Harris Sr. Area Reservoir Engineer Lisburne Engineering JlH/dg Attachment '- .~ LISBURNE W A TERFLOOD REVIEW 4/6/89 OUTLINE · RECOVERY ESTIMATES · WATERFLOODIDSTORY 1. NORTHERN.DS-L2 2. SOUTHERN DS-L2 3. INITIAL DS-L2 EXPANSION · FUTURE W ATERFLOOD PROJECTS 1. DS-L2 CONTINUED EXPANSION 2. DS-L3 OPERATIONS 3. LARGE SCALE WATERFLOOD · SUMMARY .--' .~.- LISBURNE RECOVERY ESTIMATES · TOTAL PRIMARY RESERVES 212 MMSTB GROSS ( 10 % OOIP ) · WATERFLOODPOTENTIAL 40-110 MMSTB GROSS ( 2 - 6 % OOIP ) I/ß()A'·', .- f' "_./ .,"~ WATERFLOOD UNCERTAINTIES 1. W ATERFLOOD TARGET ZONES 2. ULTIMATE SWEEP EFFICIENCY 3. ULTIMATE GOR/WOR BEHAVIOR 4. ZONAL CONFINEMENT OF INJECT ANT 5. RESERVOIR PRESSURE RESPONSE 6. RECOVERY TIMING -~. .- '- --" LISBURNE WATERFLOOD HISTORY · NORTHERN DS-L2 PATTERN WATERFLOOD - 1987 · SOUTHERN DS-L2 PATTERN WATERFLOOD - 1988+ · INITIAL DS-L2 EXPANSION - 1988+ -~..r ---- '-- NORTHERN DS-L2 PATTERN WATERFLOOD · MAY - NOVEMBER 1987 · INJECTION INTO WELLS L2-24, L2-28, AND L2-30 (W AHOO ZONES 7 & 6 ONLY) · CUMULATIVE INJECTION - 300MBW ~~' --~ "-- .- 4. LOW INJECTION- EFFICIENCY (20%) 5. NO OFFSET WELL PRODUCTION RESPONSE 3. RAPID BREAKTHROUGH 2. MINIMAL IMBIBITION NOTED 1. NEARLY 100% OF INJECTION INTO ONE LAYER /. .i -\ . (S A Z) (/ <; :;}' ·'er, _¡r', " ~. )' ~jl í?·c:,.A " .'. · KEY OBSERVATIONS NORTHERN DS-L2 PATTERN WATERFLOOD '''-~ '.~ .~ .,---" ~ -,- NORTHERN DS-L2 PATTERN WATERFLOOD · CONCLUSIONS 1. LIMITED ADDITIONAL RECOVERY FROM SAZ LAYER 2. W ATERFLOOD T ARGET MAINLY IN LOWER ZONES 3. INJECTION PROFILE MODIFICATION REQUIRED IN WELLS COMPLETED WITH SAZ LAYER 4. WELL COMPLETIONS MUST REMAIN SIMPLE -~~ · RECOMMENDATION 1. INITIATE W A TERFLOOD OPERATIONS IN SOUTHERN DS-L2 AREA 2. TARGET ZONES - WAHOO 6-4 ._~~- ~ L2-32 þ ~ . ~ ~ I ~ ~ ~ I L3-5 ( ~ . L2-30 I L2-28 ~... ~. ~ L2-33 . ~ ~L~-26. . ~L2-2~ L2-·20 L2-1 ~ . I. I L3-11 .1 Ie L2 -6" L2-141 /L.2-16 I ~~~~~~~,~~~~"~~ ~'I ."/1. · I ( L2-10I L2-8 L3-15 ~ L2-3 ! . ~~,~",~-,::,,"'~"~'~~'~"~1~~~~'\::,,~""~~1>,,*,""~"'':';''~~1>,',~,~~;,.,'\""~'t.'~~~-'::~'"''''~;';;1>,~~~'''''~%'~''''''''«:~''~~'''''~~~''':I\'''''~'''"""''\'''1~~''''§.,~~'''''''''''':~~'·''''''''''·''''~'''''''''''·'''''''''~"'."'~"""."" . L2-13 L2-29 . . L1-2 ( DS L2 NORTHERN PILOT AREA It L2-21 . L 1-1 . . L2-25 ( o . . L2-30 ·INJECT ION PROF ILE PILOT WATERFLOOD NORTHERN PATTERN I - . k c . _. _.- I· - , '. , - - -- , .. ~ ~1_ t-r . -"',- -.. ~ ,~ :'\. ~ ..1 :1 - === == ~-_..- . L2-28 INJECTION PROFilE PILOT WATERFlOOD NORTHERN PATTERN i: r ,',.. . - - ~ - - - (, .\ -- _. _. .~ ~ -_. _~ 1 , ; tt==2 tt:::;.. _. fi::s.:vu l2 -24 [NJEC T ION PROF IlE PilOT WATERFlOOD NORTHERN PATTERN I - .. .],:~.: :~. : :;~.;: ;~ f ., 'r~ ( (,( ( f ;~.: ~ ., : : ~ ~ ,~~ - : _::...ú:,,;,.c,,,( ...,-.-- r:~ ~? ::: > :~ .. .....'.'-..'.,~ .' ~- ." ." - . .. - ,- , .-- :.:: ''': :~::.: ~, ..' ._:. .,;:. - ~ ~_. ,,~. , fi.:s.:r.- . . . SOUTHERN DS-L2 PATTERN WATERFLOOD · JANUARY 1988 - NOVEMBER 1988 · INJECTION INTO WELLS L2-10, L2-16, AND L2-24 (WAHOO 6 - 4 ONLY & L2-24 IN SAZ) · TOTAL INJECTION - 1260 MBW · CUMULATIVE INJECTION TO DATE - 1560 MBW . . . . . SOUTHERN DS-L2 PATTERN WATERFLOOD · KEY OBSERVATIONS 1. INJECTION PROFILE PROPORTIONAL TO ØH 2. SWEEP EFFICIENCY @ BREAKTHROUGH LESS THAN 5% (AGREES WITH DYKSTRA-PARSONS) 3. PRESSURE RESPONSE NOTED IN INJECTORS 4. GOR ST ABILIZA TION/DECLINES IN OFFSET PRODUCERS . s. DECREASED OIL DECLINES IN SOME OFFSET PRODUCERS 6. LOW OFFTAKE FROM CENTER PRODUCER (L2-14) MAKES PERFORMANCE MONITORING DIFFICULT 7. NORTHERN DS-L2 WELLS CONTINUE TO BE INFLUENCED BY L2-24 SAZ INJECTION 8. TRACER BREAKTHROUGHS NOTED BUT LOW WATER CYCLING . 9. RESERVOIR FAULTING MAY REDUCE OPTIMUM WATERFLOODSWEEP . . . SOUTHERN DS-L2 PATTERN WATERFLOOD · CONCLUSIONS 1. ZONAL CONFORMANCE OF INJECTANT IN LOWER ZONES SIGNIFICANTLY IMPROVED OVER SAZ INJECTION 2. INJECTION VOLUMES PREDICTABLE 3. POTENTIAL FOR RESERVOIR PRESSURE INCREASES . · RECOMMENDATIONS 1. CONTINUE LOWER ZONE W ATERFLOOD 2. INITIATE WATERFLOODINLOWER WAHOO 7 3. INCREASE INJECTION TO ACHIEVE I/W RATIO TO AT LEAST 1:1 4. EXPAND W A TERFLOOD TO INCLUDE ENTIRE DS-L2 REGION 5. CONTINUE PLANNING EFFORTS FOR LARGE SCALE W A TERFLOOD FOR FULL FIELD . . . OS L2 SOUTHERN PILOT AREA . e L2j32 . L 1-1 L1 L2 -30 L3-5 e . e e L2-28 . L2 -33 L2-26 e L2-29 L2-24 . e e L2 -25 L2-20 L2-18 L2 - 21 L3-11 e e e e e . L2 -1 3 L2-10 L2-8 L3-1 5 L2-3 . 0 • • DS L2 PRODUCED - SOURCE WATER COMPARISON 20000 15000 Q, W I 10000 Q4 5000 U SOUTHERN { PILOT WF D J F M A M J J A S 0 N D J F M A M J J 1986 1987 1988 DATE ATER ,�iE GUN UAHY WATER A S 0 N D J F M 1989 • 11 . . l2-16 INJECTION PROFILE PILOT WATERFLOOD SOUTHERN PATTERN . L2-10 INJECTION PROFILE INJECTION VS. PORE FOOTAO( w-' ISOLATED t SOUTHERN PATTERN I - I - . ,,7., ;-:,IJ" : :,,:,,:...: :ao:_: .'-. // ~~\~: - : ;~;~¡~ ~r! :~}:~_: (J :: ~$~1:~ ~ !~~ ~~ i == ; .. : ~ : ¡¡: :..: . . . .-.. .. .-. .-. ._. .... . . .... .-. .-. .-. .-..- . . . ._- ._. .-. .-. ._. . -, .:.:: ::: ::: =: =:..=: :: <~:~ =~~~~~~~ ~ r,~;~~~i :_: ::: :::: ::-::5= J:;~~;; ;;.-m¡..§?; -..: ~: ;~~~~I . ;;; ;;;;~-;~ ~ ~ ~~~ ~~~ ~~~5S=F ~ 1'!ê~~; ~!¥~;; ¡¡¡;-: -: -:-~..,. :.. .- _:~~;~~~:~ ~ .:::::: : :~:~=:.::=::~ :j:~ j:¡j~¡ j;¡j~j¡~~; YÞ\~~ .~~~~\~~ '~S~:- .~-; )~ ,~~?< ~~ ;~~;~ - .. ".' .-. .-. .-,.-.. . .~ '::)~: :::::: ::: ::: : ::: :~:=~: :=: ::; . .-. _. .-. _..-. .-. : :;~;;~i: ~:; :;: ~ffi~~ ~, ~~~ ~: '~~¡ ~~~;~ ~:: ., . ._.. . .-... .., .-. ._. .-. .-. .-. " . .-. ._. . '. .,.' .-.. ._... ,... .-.. . .-- ._. .-- .-. ¡~~~; ;~; ~;; ;~ ~~ i~~ :§i ¡~i ¡~i ::¡ ¡ ; ~':: ;:~: '~: j ~: L~: ¡;: :~::..;~ . ~ ~ ~. . . _. - 1\::'11£._ ftl!....- . aDRILLSITE L2 . TRA~R BREAKTHROUGH . L2-30 . . L2-28 . HTO 33 da,. . L2-26 days C,t4 . L2-14 . ~-16 L2-6 C14 284 C14 days ff1 dliys 141 dliya . . . L2-8 Co6O . 181 da,. BT TIME BT VOLUME BT WFJ .T . TRAC'FR DAYS DLS I2.U 12-6 Co6O f/ 12-10 189 98,000 11/30/88 lITO f/ 12-24 328 571,400 01/02/89 C14 f/ 12-16 284 460,100 11/21/88 12-8 C14 f/ 12-16 67 98,500 (17/28/88 Co6O f 12-10 148 7/,000 10/20/88 12 - 14 lITO f/ 12-24 196 191,000 09/15/88 12 - 20 C14 f/ 12-16 104 173,000 09/06/88 lITO f/ 12-24 33 33,000 04/06/88 . 12-26 lITO f/ 12-24 33 33,000 04/06/88 L2-30 lITO fl 12-24 33 33,000 04/06/88 . . L2-20 ... L2·18 . . . INITIAL DS-L2 EXPANSION · NOVEMBER 1988 - PRESENT · TOTAL INJECTION - 1730 MBW · CUMULATIVE INJECTION TO DATE - 3290 MBW · L2-18 CONVERSION TO INJECTION (W AHOO 6-4, AND LOWER WAHOO 7) . · INJECT INTO LOWER WAHOO 7 L2-10 MARCH 1989 L2-16 MARCH 1989 · INCREASE L2-24 RATE DECEMBER 1988 · OPEN LOWER WAHOO 7 TO PRODUCTION L2-14 MARCH 1989 . . . · INITIAL DS-L2 EXPANSION . CONCLUSIONS 1. NO RAPID WATER BREAKTHROUGH NOTED TO DATE (EXCEPT WELL L2-24) 2. INJECTION RATE PREDICTABLE 3. NEAR WELLBORE ZONAL CONFINEMENT (NO SAZ) DEMONSTRATED FROM INJECTOR PERFORMANCE 4. LOW WATER CYCLING (10-20%) · · RECO~ENDATIONS 1. CONTINUE TO EXPAND WATERFLOOD TO REACH I/W OF 1:1 2. PROCEED WITH PLANNED PROFILE MODIFICATION IN WELL L2-24 3. CONVERT WELL L2-32 TO WATER INJECTION SERVICE (LOWER WAHOO 7 & 6-4) 4. PREPARE FOR ADDITIONAL CONVERSIONS TO ACHIEVE I/W OF 1:1 · .. . . . INITIAL DS-L2 EXPANSION 5. PLAN FOR W ATERFLOOD EXPANSION TO DS-L3 6. CONTINUE STUDIES FOR LARGE SCALE W A TERFLOOD . . 2 . L1-2 L2 -30 L3-5 L 1-1 . . . . L2-33 . L2-29 . L2 -25 L2-21 L3-11 . . . L2-6 . . L2 -1 3 L2-8 L2-3 . OS L2 INITIAL WF EXPANSION AREA ./ m 00 I d- I m 0 0 DS L2 PRODUCED -SOURCE WATER COMPARISON 20000 15000 10000 h 5000 u D J F M A M J J A S 0 N D J F M A M J J 1986 1987 1988 DATE INITIAL L2 TER uLV V1Y /ltll 4l „n1LR A S 0 N D J F M 1989 • • . . . LISBURNE FUTURE WATERFLOOD PROJECTS · CONTINUE EXPANSION OF DS-L2 WATERFLOOD - 1989 · OBJECTIVES 1. OBTAIN TIMELY FIELD DEMONSTRATED BEHAVIOR 2. REACH IIW RATIO OF 1:1 3. MITIGATE DECREASING RESERVOIR PRESSURE . 4. REDUCE REGION GAS PRODUCTION THROUGH GOR . SUPPRESSION · SPECIFIC OPERATIONS 1. EXPAND INJECTION INTO LOWER WAHOO 7 - 3/89 2. PROFILE CONTROL (SAZ) IN WELL L2-24 - 4/89 3. CONVERT WELL L2-32 - 4/89 4. EVALUATE CONVERSION OF WELL L2-30 (OR ADDITIONAL PATTERN DEVELOPMENT) . -----------------------------------------] ~--- E . L3-5 L1 2-28 L 1-1 . . L2-26 1 . L2 9 L2 - 21 . L2-6 . L2 -13 L2-8 L2-3 . ..... ,/ WELa- 32 SCHEMA TIC AP I # 50-029-21778-01 . 2 ..oIIIIIIIII -.J 3. ...... 4. .J .J 5 .J .J x x 6 . ~ ~"'''I """,... """,.. """,.. ~~~~~ ",,,, 8 -9 :~~~~ 7 ."" ."" ."" :~~~~ '''''''- 10 o 11 o o 12 o o o 13 . 14 ~"""""""""~ ~"""""""""~ . Well Status: Producer Surface Location:2085FSL, 1 164FWL,Sec 18/T 1 1 N,R 15E,UM Top Lisburne Loc: 1749FNL, 1 077FEL,Sec8,T 1 1 N,R 15E,UM RKB To Tubing Hanger: 29,6 Feet Top of Wahoo: 14256 MD/ 8647 SS Datum: 14777 MD/8900SS Reference Log: LDT /CNL 2/4/88 Annulus Fluids: Seawater w/2500' diesel cap. Workover Recompletion: 12/17/88 1, 30 MD--2.875" TBG HANGER,2-7/8"X6.5# L-80,IPC 2, 2189 MD--CAMCO SSSV TRDP-1 A-SSA 2.312" ID 3. 2285 MD--CHEM.I NJ MANDREL CAMCO KBMG-L TS 4. 4453MD--13 3/8" x 72#,L-80 CSG. SET 5, GAS II FT MANDRELS 250 l' MER LA 1-1/2" DUMMY TG . 7250' MERLA 1-1/2" DUMMY TG 1 1 147' MERLA 1 -1/2" DUMMY TG 13803' MERLA 1-1/2" w/lntegral Latch RKED 6. 13910 MD - BAKER 'H-B' RETRIVABLE PACKER 2-7/8" X 9-5/8' 7, 14010 MD - TOP OF 7" X 29 # L -80 II NER 8. 1410Q FI Mf) - OTIS 'XN' NIPPLE 2,25"ID 9, 14121 ELMD - BAKER SHEAR SUB/TUB I NG TAl L 10. 14231 ELMD - BOT OF 9-5/8" X 47# L-80 CASING 11. WAHOO 7 PERFORATIONS - 19 HOLES 4" CSG 14281,84,86,90,98 14302,05,07,09 14325,28,31,36,47 14351,53,55,57,71 12, WAHOO 6 PERFORATIONS - 17 HOLES 14388,95 14415,20,32,56,75,79,89,96 14520,39,43,48,81,82,99 13, WAHOO 5 PERFORATIONS - 7 HOLES 14664 14714, 16, 33, 35, 60, 61 14. 15198 ELMD-- PLUG BACK DEPTH (TAGGED 12-15-88) 1" DUMMY BK2 2-1/8" TT 2-1/8" TT 2-1/8"TT 2-1/8" TT Note: Taaaed down with Eline @) 14750'ELMD 12-30-88 HOLE ANGLE THRU W AHOO-- 58-65 DEGREES MAXIMUN HOLE ANGLE--65 DEGREES @) 6000MD Max. H2S Measured · 20 PPM Revision Date: 1-23-89(6) . L2-32 Conversion . · nlSCUSSION Conversion of L2-32 to source water injection in lower W7, 6 and 5 should be done as soon as approved. Conversion of this well will increase the Wahoo 7 injection/withdrawal ratio (I/W ratio) to 0.84 and will increase the Wahoo 6-4 I/W to 1.71 when completed. At current conditions, this well is producing over 8400 RVBPO voidage in Wahoo 7 and 940 RVBPO in Wahoo 5-6 for 900 BOPO at 11000+ GOR. Conversion of this well should increase injection 5500 BWPO for a net change of 15000 RVBPO. Expected cost is $ 35 M which includes funds for surface equipment and labor. Total L2 injection is expected to reach 25,000 BWPO when completed. Plotted below are the expected rates for OS L2 continued on primary production vs. converting L2-32 to injection. Based on scaled model results, the ultimate recovery is expected to increase by 1120 M BO during the economic life. · L2-32 WAHOO 5-7 WF c c. m t- en : . _\..L "-T" _I. [t:::,'uuuuu U~.U... . .. ¡ ¡ ! i ..... ¡ i ,¡, . 4000 . ~w .. ,~::.~wwn ~';~ nu~wy"^,~~,,,~^ ^ ~t"n'~W~W'W'iw^w,wm'~~'1wwWWMw't^· "ww '1""w" ,~'^. i ...... ¡ ~ ¡ · L2 PRIM RATE 3500 . ".... , ~,~ ' 'W. 00 " - . ..+. : i .........&-....... L2 PRIM + L2-32 WF : ¡ '......: : : "'"",,, ,¡ ',,^W'^'T^ -- ~:~'c.::"..;.u ^' , l i : .... ~ ¡ '¡ ···1 : ~ . "lu nr ... r:·." "00"', 3000 2500 1500 500 'U'-¡-_. 1 000 ^U · co co m o m m N m m "lit m m <Ø m m co 0) m o o o N N o o N v o o N <Ø o o N 9- 9- 9- 9- 9- 9- . . . LISBURNE FUTURE WATERFLOOD PROJECTS . · EXPAND WATERFLOOD OPERATIONS TO DS-L3 1. LATE 1990 STARTUP 2. PERMANENT FACILITY/FLOWLINE INSTALLATION ( PWH - 50 MBW/D ) 3. SECOND DRILLING RIG TO PREPARE REGION - 1990 ( 160 ACRE WELLS ) 4. PHASED INJECTION STARTUP 5. FUTURE EXPANSION TO INCLUDE FULL DRILL SITE 6. TOTAL FACILITY COST - $35.6MM . . . . . SECONDARY RECOVERY FIGURE 111-1 ......... ......... ....................... L5-21 T.. ~ ....................... L5- ~ ~ ~ L5-24 ~("\ DS-L5 ~ ......... ............. ~ ~ I ~ ......... ......... ............. L4-2 L 0 L4-3 L ,............ / L4-30 . . LISBURNE 1989 FIVE YEAR PLAN . DRILLED WELLS o PROPOSED WELLS ~ PRESENT INJECTORS ~ PROPOSED INJECTORS · . · . · . · . · . · - . . . , Lisburne Waterflood Expansion Source Water Pipeline Network - Base Case "\ L5 L2 1(1 IIIIII11 /""'''''''''''''''''''''''11 ,II ", III I" I' 6" D1ameter I" Temporary L1ne ,l ~ CEX1s\t1n9) 'Il' T"", III I" 1'" I,I III I,I I" III III ,II, 8" D1a. 6600' 12" D1a. 15800' _ - ill 8" D1a. 18500' _:=r- --- - ..... 8" D1a. .......... 13800' ..... . - ...... LPC L3 ..... ..... I - L4 12" D1ameter 15000' - LInes for Waterflood ExpansIon . - - - - Proposed for Large Scale Waterflood ESIP '- .. PGV 312189 . . · LISBURNE LARGE SCALE W A TERFLOOD · PHASED EXPANSION APPROACH 1. DS-L2 1 989 2. D S - L 3 1 9 9 0 3. DS-L4&L5 199 1 · · CURRENT DESIGN BASIS 1. INVERTED 9-SPOT PATTERN 2. 160-ACRE WELL SPACING 3. MAX. INJECTION RATE 125MBW/D 4. PWH RATE 100MBW/D 5. TOTAL FACILITY COST $75MM · EXPECTED W ATERFLOOD PERFORMANCE 1. ADDITIONAL RECOVERY 40-110 MMSTB 2. PEAK INCREMENTAL RATE 10-35 MSTB/D · . LISBURNE o o 0 0 ·····~·r ...... .::. ·........···..·..·....·..........l....··......·........······....·1.....·.......···.....··........··..1......· . . . . · LISBURNE W A TERFLOOD REVIEW SUMMARY · LARGE POTENTIAL RECOVERY TARGET · UNCERT AINTIES STILL REMAIN · EXPANSION OF DS-L2 WATERFLOOD WILL ADDRESS ISSUES · · WELL L2-32 CONVERSION INTEGRAL PART OF EXPANSION AND LARGE SCALE PROGRAM (APPROV AL RECOMMENDED) · . Ll~Hl.;KNr. t'LLV I W A II:.KrU",,",U h\ITERIM REPORT . NOVEMBER 20. 1987 Lisburne Pilot Waterflood Sequence of Events . ~fay 1. 1987 · Injection was started in L2-30D at 1000 BWIPD at vacuum. ~lay 10. 1987 · Water production in L2-26D increased to 60 BWPD from 5-10 BWPD. Approximately 9000 barrels of water had been injected at breakthrough. July 16, 1987 · RA tracer log identified the L2·30D injection profile as 70%+ at 10640 to 10660' MD. Remainder was distributed in zone 6. July 11, 1987 · Injected fluorescein dye in L2-30. July 15, 1987 · Dye arrival at L2-26 indicated possibilty of multiplc breakthrough zones. July 20, 1987 · L2-30D water injection was shut-in. July 22, 1987 · The water production rate in L2-26D peaked and quickly began falling to pre-injection levels. July 23, 1987 · A step-rate injectivity test was perfonned on L2-30D. Injection of 8900 BPD achieved at supply-line pressure of 2500 psi. No evidence of fracturing observed. August 15, 1987 · Water injection was started in L2-24 at 1000 BPD at vacuum. . August 17, 1987 · L2-30D was put back on production. Tritium injected into L2-24. August 25, 1987 · The L2-24 injection rate increased to 2000 BPD. Remained on vacuum August 30, 1987 · The L2-24 injection rate increased to 3000 BPD. Remained on vacuum Septembcr 7, 1987 · RA tracer log idcntified the L2-24 injection profile as 100% of the injection entering between 9900-9910' MD. The log was run at 3000 _ 5000 BPD with no difference in profiles. September 20, 1987 · The L2-24 injection ratc is increased to 5000 BPD with wellhead pre" increasc to 100 psi. September 27. 1987 · L2-30 zones 4 and S acid treatment apparently broke into zones 6 anJ October 1. 1987 · Injection test in L2-30 long string killed shon string production. confirmed suspected communication between zoncs 5 and 6. October 11, 1987 · Breakthrough occurred at L2-26 from L2-24 injcction after 174 MB W cumulative injection. October 14-16, 1987 · Breakthrough occurred at L2-30 from L2-24 injection after 186 MBW cumulative injection. . · · · . Ll~ölJK~t. t'll..U 1 W A 11:.l';~LUUL INTERIM REPORT . NOVEMBER 20.1987 Lisburne Pilot Waterflood Sequence of Events (continued) October 15. 1987 · L2-28 Shut-in to prepare for injection testing. decreased to 1000 BWD. L2-24 injection rate October 16. 1987 · Breakthrough occurred at L2-20 from L2-24 injection after 190 MBW cumulative injection. October 18. 1987 · L2-28 put on injection at 1200 hrs. 2000 BPD. L2-24 injection shut-in for production test. October 23. 1987 · L2-24 CTU/nitrogen lifted 250 bbl water. Well would not sustain natural flow. October 26. 1987 · Injected fluorescein dye tracer in L2-28. Water breakthrough occurred at L2-26 as watercut increased from less than 10% to 40%. Choked L2-28 injection rate to 1000 BPD. October 30. 1987 · Attempted RA tracer log injection profile of L2-28. . November 14, 1987 November 21, 1987 November 23, 1987 November 24, 1987 November 25, 1987 November 26, 1987 November 29, 1987 . December 12, 1987 December 13, 1987 January 21, 1988 January 25, 1988 February 6, 1988 February 10, 1988 February 11, 1988 February 21, 1988 February 22, 1988 February 23, 1988 . February 27, 1988 . EXHIBIT 3 . Lisburne Pilot Waterflood Interim Report May 20, 1988 Sequenc:e of Events o L2-28 conve.rted back to production after total injection ()f 34 Mbbls of water. o Temporary injection into L2-28 to acquire an injection profile log. o L2-16 perfc)rated in Wahoo Zones 4, 5, and 6. o L2-24 converted back to production after total injection c)f 224 Mbb1s of water. o L2-l4 perfc)rated in Wahoo Zones 4, 5, and 6. o L2-l4 stimulated with 15\ BCL in Wahoo Zones 4, 5, and 6. o L2-16 stimulated with 15\ HC1 in Zones 4, 5, and 6. o L2-10 perforated in Wahoo Zones 5 and 6. o L2-10 stimulated with 15\ HCL in Wahoo zones 5 and 6. Well took acid on vacuum - suspect isolation sleeve not set and actually re-acidized Wahoo Zone 7. o L2-10 stimulated with 15\ HCL in Wahoo Zones 5 and 6. o Initiated pulse test in southern pilot waterflood by pulsing L2-14. o Ran production log in L2-14 to determine producing profile. o L2-24 converted back to water injection. o L2-16 converted to water injection. o Acquired injection profile log in L2-16. o Ran gas lift valves in L2-14 to assist producing the well. _ _ o L2-10 converted to water injection. o Conducted step rate injectivity test in L2-l0. . March 3, 1988 March 5, 1988 March 6, 1988 March 6, 1988 March 16, 1988 March 20, 1988 March 30, 1988 . April 6, 1988 April 18, 1988 April 27, 1988 R. M. Lance 5/20/88 . . . EXHIBIT 3 Lisburne Pilot Waterf100d Interim Report May 20, 1988 Sequence of Events (Continued) o L2-24 tagged with radioactive tracer (tritiated water) . o Conducted surface pressure fall-off test in L2-10. o L2-16 passed State witnessed casing integrity test. o L2-10 passed State witnessed casing integrity test. o Acquired injection profile log in L2-10. o L2-24 passed State witnessed casing integrity test. o Circulated out gelled diesel from annulus and ran gas lift valves in L2-6. o Initiated imbibition test in L2-6 by injecting 5000 bbls of source water. Returned well to production. o Began second injection cycle of imbibition test in L2-6. Acquired injection profile log. Returned well to production. o Began third injection cycle of imbibition test in L2-6. · May 8. 1988 May 11. 1988 May 18. 1988 May 23. 1988 May 25. 1988 May 25. 1988 · . . EXHIBIT 3 Usburne PIlot Waterflood Interim Report November 20, 1988 SEQUENCE OF EVENfS L2-14 reperforated in Wahoo Zones 4.5 and 6. L2-14 restimulated in Wahoo Zones 4. 5. and 6. Conducted surface pressure fall-off test in L2-16. Began fourth injection cycle of imbibition test in 1..2-6. Injected radioactive tag (Cobalt 60) to trace injected waters in L2-10. . Injected radioactive tag (Carbon 14) to trace injected waters in L2-16. June 13. 1988 Installed pressure gauges in L2-6 for a Wahoo Zone 4 communication test. June 16. 1988 Initiated water injection into L2-6 to acquire injection profile log. June 18. 1988 Pulled pressure gauges from L2-6. July 2. 1988 Installed pressure gauges in L2-6 for a Wahoo Zone 5 communication test. July 4. 1988 Initiated water injection into L2-6 as part of the Wahoo Zone 5 communication test. July 7. 1988 Attempted to retrieve pressure bombs in 1..2-6. Unable to latch bombs and attempt to fish. Returned 1..2-6 to production July 29. 1988 Installed pressure gauges in L2-14 for a ten day pressure build up SUlVey. July 31. 1988 Acquired injection proffie log in L2-10. · . . · Increased injection pressure in L2-16 from 1300 psi to 1600 psi. Corresponding rate at 1600 psi was 3000 BWPD. Aug. 6. 1988 Conducted surface pressure fall-off test in L2-10. Aug. 5. 1988 Aug. 8. 1988 Decreased injection pressure in L2-16 from 1600 psi to 1400 psi. Corresponding rate at 1400 psi was 2500 BWPD. Aug. 10, 1988 Conducted two day injectivity test in L2-6 with stuck pressure bombs in the Wahoo Zone 5 isolation packer. Aug. IS, 1988 Conducted a perforation acid wash in L2-10 to remove scale deposits. Sept. 23, 1988 Increased injection rate in L2-24 from 1000 BWPD to 2500 BWPD. Oct. 27, 1988 Increased injection rate in L2-24 from 2300 BWPD to 4000 BWPD · · . . · LISBURNE PILOT W ATERFLOOD SEQUENCE OF EVENTS Nov. 11, 1988 Nov. 24, 1988 Nov. 25, 1988 Dec. 1, 1988 Jan. 7, 1989 Jan. 8, 1989 Jan. 12, 1989 Feb. 4, 1989 · Feb. 26, 1989 Feb. 27, 1989 Mar. 16, 1989 Mar. 25, 1989 Mar. 26, 1989 · Acid wash performed at L2-6 to dissolve fill on top of packer. Subsequently were unsuccessful in fishing pressure bombs. L2-18 passed State witnessed casing integrity test. L2-18 converted to water injection service. Increased injection rate in L2-24 from 4000 BWPD to 9500 BWPD. Conducted surface pressure fall-off test in L2-18. Conducted step rate injectivity test in L2-18. Injected radioactive tag (Cobalt 58) to trace injected waters in L2-18. Acquired injection profile log in L2-18. Perforated lower Wahoo Zone 7 in L2-14. Stimulated lower Wahoo Zone 7 in L2-14. Pulled isolation sleeve in L2-10 to expand water injection to include Zone 7. Perforated lower Wahoo Zone 7 in L2-16. Stimulated lower Wahoo Zone 7 in L2-16 to expand water injection to include Zone 7. 1 ??oo 9000 8000 7000 6000 5000 4000 3000 2000 1000 900 800 700 600 ~ 500 ~ ¡.¡.¡ 400 U V) .... 300 0 ~ ¡:Q 200 100 90 80 70 60 50 40 30 20 10 . . L2-06 Oil, Water, and Gas-Oil Ratio ~~~~~ o o . /J~ , ~,~~ 1fu ~~ 1t;,: \vr~'\ :- ~ ~? : (i) - ' . . .' / It I I If I / ,I' ~ ::: II I" ,. .11 " I" " " ,. " " .. " , .' . .' " " " " .: I :. : ,'. I: I '.' : :: ',' , ,I ',' ,1,. " " ., ð ~, , ," ." ," "~, ," ," , .. , ' , - I - , . , . I :: ~ , t " I " , '. , : " ~ . -, ., , · · · , · · · , , , 10187 , , , . , . " " .' .' I , " '. " " " . . . , " , " . " I " , " , , \ " " , , , , . , , , . . , I , . , , . "1 .' II I , , :~ I , , ,.1 " ,.' ., , " " " , · , · · · It " " " II , I , . , , , I · · · I , , " It II , , , , I , \ " '. , , , , ~ 'I , I , I , I -.- Oil Rate -e- Gas-Oil Ratio . . " " " II " II " , , , , , , I I , '.. t, , ~ I I 'I, , .,. , 'JI , 1'1. \ , I ~ .: II , , " I ¡: , 'I I, " I, " I I I , I , , , , , , , , " " " " " ,I " " .. ~ - - , I 1988 . . " II I I , I , I I I , , , , , . . , , , , \ , \ ,,~ \. II ". " , , ,~ " , , , I ' : ~' --/ , , , , . . I I I II " II . , - - - - Water Rate , , , '\ ., , I ~, , , " , ,~ : " , .' I J ~_' , . 40189 RLMIIRA TE 4/3/1989 1??oo 9000 8000 7000 6000 5000 4000 3000 2000 1000 900 800 700 600 ~ 500 ~ ~ 400 U VI .... 300 0 ß ~ 200 100 90 80 70 60 50 40 30 20 10 . 10188 , I , I , I · · · · , I , I , I I I I I I I I I I . I I I I . I I I I I , , I " :' ~ . L2-08 Oil, Water, and Gas-Oil Ratio u ~ ,¡J\j ('I o o ~ " I ,. I, 9> ' , Or \ ,', 1-, ',: " ,'~~-~ A _ :";;~;J\" '-'.:' "'-~.J: ~----... s " @ ~'-"." \.' '....,' \, \ , \...' ~ ..: .. /\ ,'\ I .... , ,,' \~".... I \ , '/ ....------ n -8- Oil Rate --e--- Gas-Oil Ratio - - - - Water Rate ~ " " , , , " , , " " , , , , / . . . 40189 RLM/lRA TE 4/3/1989 . L2-14 1??oo 9000 8000 7000 6000 5000 IN 4000 3000 C) 2000 ~~ o ó' . ~I Oil, Water, and Gas-Oil Ratio ^ ~rI rtN ~o o 1000 @) 900 Q( 800 700 600 ~ e 500 tn ~ 8 L" ® U400 ~ (5) tn iii 8 300 \~ f f2 ~ 200 G , 100 90 80 70 60 50 4() 30 20 10 110187 ~ Oil Rate '" ~ (!i) . . II " I I I " ,I I I I ' I" , , " '. " " I, I . I . .. , , . I I . . .' , r , I I r I I , , , I I , I, " I, , I : . " \, , 1988 -e- Gas-Oil Ratio .. o . ,I . . I " , I , ' , , I '~', I' I I . , I , , , , , . , " , . I , , I I " , " , , " I I " ,. , " 'a' , " ',I I " '"I I ,I ,1,1 I I' - - - - Water Rate @) Ci) 4t, 40189 . . . TMK/IRA 1E 4/3/1989 10??oo 9??oo 8??oo 7??oo 60000 50000 40000 3??oo 2??oo ~w 8000 7000 6000 5000 4000 3000 ø:1 2000 f-< en ~ U en 61~ ~ ~~ ø:1600 500 400 300 200 100 90 80 70 60 50 40 30 20 10 . . L2-20 Oil, Water, and Gas-Oil Ratio o .... '-~ -- ~- ~ ~ ~-'-<J ~~ (1) , 1bl- EiÞ . .. " " " . . , hi. I ~ I ' I I , '. l- I ~" " I ',' I ',' I I I,' , · 'f I " I " ' " , J ' '.' , I .. ~ .~ to', I ,tJ " I " I I I I I . I I I I I I I ,1,,_- ,., , I I, , , " I , ,.... " " 10187 -8- Oil Rate /'''''-~ ~~, , . , , I , , " , . , . I , . I , I I . . I I · · · · , · . · . I I I I I . I , ~ " t-_, " , of' , . . . " , , I . 1\ I ,\,.... , , , ,-'" " ' , , , , . , , I " . ; '. '. , ,-~ , .' . ' , . ,- I I . I " . 1988 ~ Gas-Oil Ratio - - - - Water Rate . Q . . . " .. f . @ 40189 RLM/IRA TE 4/3/1989 \~ 8??oo 7??oo 60000 50000 40000 30000 2??oo ~~ 8000 7000 6000 5000 4000 3000 ~ 2000 E-< CI') ~ U CI') 5~ ~~ ~600 SOO 400 300 200 100 90 80 70 60 50 40 30 20 10 . 10187 I , I · I · , · , \ -' , "t · It " " " , " ,-'./. · " , ~ · " , " , ,,, , . " , L2-26 . Oil, Water, and Gas-Oil Ratio t') -@)- Oil Rate , I , I , ~ I' " " " I' I' I' 1 , , T ~-"z._~ t, , " I I' ,r " ~: '...,4 " I .. ' " " " " " · · · I I , I , " I .. I I Q CD ) ( v <D{ ~oo~ ,I I ,....'\ I , , , , , " " , -~ ,1 - .. ' " - _....._ ~ I , -.......,'..... i ., , "-I!Ir' '" . ',' "".... '.... .... ' \ - , ....... ' I \ . -, - l I ' , , , I 'I , , 'I " " ,,(3 ~ ~I ~ I, ','''\ "". I ....---- , I , , , '".. , 'I' f .", I " , , , . , , I , , , I I, . . , , I, " " " I, " " " " " , " ."., I' I' .' " .' .' I " " " " " ~ I , 1988 -e- Gas-Oil Ratio ,. " , o ) t'i ~\ œ 40189 - - - - Water Rate . . . RLM/lRA TE 4/ 3/1989 100000 90000 80000 70000 60000 50000 40000 30000 20000 w 8000 7000 6000 5000 3000 Gq 2000 COO G V o a8w Tao a4 600 500 400 300 200 WO 80 70 60 6a 20 10 L2-30 Oil, Water, and Gas -Oil Ratio �1 i mi, n n u CM1 -- KNISHIMM-_SZL nil n 80287 - 0 Oil Rate 1988 Gas -Oil Ratio 40189 - - - - Water Rate RML/IRATE 4/ 3/1989 #17 ARCO Alaska, Inc. ) Post Office bv'X 100360 Anchorage, Alaska 99510-0360 Telephone 907 263 4206 'oj {~v~h Þ ~o1 ~ cO f.; vir- ~ ~ '~} pJ J~J (0 '-- John S. Dayton Manager lisburne Engineering June 1, 1987 Commissioner C. V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: Conservation Order No. 207, Rule 10 Dear Mr. Chatterton: ARCO, on behalf of the Lisburne Owners, is proposing a pressure monitoring program for a 2 year observation period in the Lisburne Reservoir in fulfillment of Rule 10 of Conservation Order No. 207. The proposed program is attached. Modifications were made to the proposal that was presented to you during the May 14, 1987 informal meeting at your offices. These modifications reflect the discussion we had regarding the proposed program. Changes were made to Section (F) regarding the time pe- riod of plan observation and possible modification of the plan should it be needed. The remainder of the plan remains unchanged. Should you have any questions or concerns, please call me at 263-4206. Sincerely yours, \ f\ /---" ...t' ',: ':h. L CI..1 ....'''1 fj S. Dayton ,,/ I Lisburne Engineering Manager JSD/WHC/nm WHC2 84 Attachment xc: P. L. Coyne N. J. Freestone Exxon SAPC ~I;¡ ~'~ ,""" ~~.. !1 .....\:,:=,', '.", ~~" 1"'" ¡, ì""':1 ,~ ij~... :I....~ '"", !l., I: __i ~"i : \. '., " . ¡~¡aS¡Œ o¡¡ ,& Gas CíHI~:;. ARca Alaska, Inc. is a Subsidiary 01 AtlantlcRichfieldCompany c;ö '¡\}~i¡I¡Jf'..·'"·'r. ¡1/v ï / (.,'....~..,..),.'....n.......,~;.,~.,\./.:.,.i\:,A '~"" ~~{"..,., '";,-;~;/'''' I·""r,·,,~'· \~ \\j\<..) J:;:'" -I'::"":~" "~<L::~ ::", ~" I ',",~' ~. .'" ~ '. ,'. 0' r:,:: :;,') ~::~~ 1;'\ I ~ '"..','¡ ~. 'I.,;....'" "..'. ...... .. . ......~=-j _.;' ,;".._,.-," 'I ~, .' :' :' .". \~~ , II ~ , .' ,\,...'.' -._- "'j 'I /2,. t:;:~~;"¡"'TEJ: P.~3;:'~1~..... ..', ~:" 't" ~ç:: ('~ r..,' . (\ ~,!,...~ '.,.' ~ ~ 'I ·,\~E=1[] ') STATE PRESSURE MONITORING PLAN CONSERVATION ORDER NO. 207 RULE 10, PROPOSED PRESSURE SURVEYS .A) ALL NEW WELLS SHALL HAVE AN ACCEPTABLE PRESSURE SURVEY, AS DEFINED IN PART (C), TAKEN PRIOR TO SUSTAINED PRODUCTION OR INJECTION. B) ONE PRESSURE SURVEY PER PRODUCING DRILLSITE QUADRANT PER YEAR SHALL BE TAKEN. WATER INJECTION WELL PRESSURE SURVEYS MAY BE USED FOR THE QUADRANT WELL. PRESSURE SURVEYS FROM SECTION (A) MAY BE SUBSTITUTED FOR A QUADRANT SURVEY. C) ACCEPTABLE PRESSURE SURVEYS ARE STATIC SURVEYS, RFT/FMT, PRESSURE BUILDUP OR FALLOFF TESTS, AND MULTI-RATE PRESSURE TRANSIENT TESTS IN PRODUCTION OR INJECTION WELLS. OTHER QUANTITIVE METHODS MAY BE ADMINISTRATIVELY APPROVED BY THE COMMISSION. D) THE PRESSURE DATUM FOR THE LISBURNE Oil POOL IS 8900 FEET SUBSEA. THE COMMISSION MAY ADMINISTRATIVELY AMEND THIS DATUM OR CREATE AN ADDITIONAL DATUM WHEN MORE INFORMATION ON THE RESERVOIR IS AVAILABLE. E) DATA FROM THE PRESSURE SURVEYS SHALL BE FILED ON FORM 10-412 BY THE LAST DAY OF THE MONTH FOLLOWING THE MONTH IN WHICH EACH SURVEY IS TAKEN. SUBMITTED PRESSURE DATA SHALL INCLUDE OTHER INFORMATION SUCH AS RATE, TIME, DEPTH, TEMPERATURE, AND WELL CONDITIONS TO ALLOW FOR A COMPLETE ANALYSIS OF THE PRESSURE SURVEY. F) THE OPERATOR WilL MONITOR PRESSURES ACCORDING TO THIS PROGRAM DURING A TWO YEAR OBSERVATION PERIOD. SHOULD THE LISBURNE OPERATOR DETERMINE THAT THE PLAN NEEDS TO BE MODIFIED, THE COMMISSION MAY BE PETITIONED BEFORE THE TWO YEAR PERIOD EXPIRES TO MODIFY THE PLAN. #16 tII:: 'J...o1 '. AReo Alaska, Inc. ) Post Office Box) 1 00360 Anchorage, Alaska 99510-0360 Telephone 907 216 1215 Mr. C. V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 ~~ 1..ìi...,;1''''''''(#-''I' '.~~ ~ .j' IJ /1",,1·..·_·· , . ..... ',~~~=.J~ I ...."..,.'~~..'"C=J I I --'T-', "'_"1__"" ¡"', I I Y -,"-"'~,',: '",,,...,,,.""-~ If ST",-\ r !! t,;,"'>:"!!' J '(';:;r. ';""('f" '1. r.,."-.I ~} ~~¡~¿:::~._"_E~~'>", ': ({ I~."~) ~_. ,J11k!.,Æ 1,1 , ... r [.~r . ~ I ,I' April 3, 1987 Re: Injection of Treated Seawater into the Lisburne Reservoir Through Lisburne Well L2-30 Dear Mr. Chatterton: This letter is to provide notification to the Commission of ARCO Alaska, Inco's intention to begin water injection into the Lisburne Reservoir using Well L2-30. Current plans call for injection of treated seawater from the Prudhoe Bay Seawater Treatment Plant to begin on April 22, 1987. The commission will be notified of our pressure testing plans for this well as soon as they are available. If you have any questions, please contact me at 265-6254. BT~ B. T. Kawakami Lisburne Operations Coordinator 'r:",...: r,', ".., ~~\ i~~ r'~~~ ~~~~ \,'1 .,,1 ',' ARCO Alaska, Inc. is a Subsidiary of AtlanlicRichfieldCompany :t '"</ ) ) bc: J. Ashford/S. Kruse J. Eastlack/R. Tapia G. Griffin/M. Schall S. Hasund S. Preston/J. Collogi A. Tadolini S. Ronzio #15 I~ ARCO Alaska, Inc. Post Offf lox 100360 , ,.. Anchora~\Alaska 99510-0360 ß £";//1/\' Telephone 907 276 1215 çv w" h-(/5 March 6, 1987 Mr. C. V. Chatterton, Chairman Alaska Oil and Gas Commissioner 3001 Porcupine Drive Anchorage, Alaska 99501-3192 rE9~~~~"-~ ).~~r'¡ir¡.f , "","C.·r~)~ ~'.1.. , R,·..·,· l"~ rG'!-· _ ':':," .r,:: \...~_ , sn FI'.',:~ ---=-1- ...., h,~ .,:"-:1....., .'-_ ,>U'¡ 1::[,,I::j ~~h;~A."- '_--, n. '....... r . ,.:1, '.'. ,,,. (,',.rr- .2;.~'.~ ..,:.¡ .r~~.~ =-. , , C,'/"' ,~: i .';.. r--:-r- 'i.{f·!'ë.~:;:~d'iù;-"r i~ fi ci - Ä r:':3 'T 7-- !;~.r,~\ 'r' 'n: fjH '": E:~~~~'T-iCijl ,..f'LE: - --...".._--~ R E: Authorization to Flare - Startup of the Lisburne Depropanlzer Unit D.ear Mr. Chatterton: ~~ ~~ ARGO Alaska, Inc. requests approval for flaring of gas during the commissioning and startup of the Lisburne Production Facilities Depropanizer Unit. This unit is a "stand-alone" unit which separates butanes and heavier from the gas stream. The rest of the lisburne facilities can operate with or without the depropanlzer unit operating. Since the decision to start up the depropanizer unit was' under review when the previous Lisburne facilities startup flare authorization was requested, depropanizer unit startup flaring was not included in that request. We now estimate depropanizer unit startup to begin in late April, 1987. We request that flaring which occurs as a result of operational problems in Lisburne facilities other than the depropanizer unit .D.2t be included In this startup flare request, but be handled as operational necessities as provided for in Conservation Order 207, Rule 8. On this basis, ARCO Alaska, Inc. requests permission to flare 300 MMSCF during the commissioning and startup of the Lisburne facilities depropanizer unit. This volume is for equipment depressuring and blowdown during the startup. Should you desire additional information or have any questions, please contact me at 659-8647 or 265-6254. Sincerely, '8. T. K~ RECEIVED MAR 1 0.1987 Alaska 011 & G as Cons. CQmm!~sf"- ~ '1f'h'1r""'~ B. T. Kawakami Usburne Operation Coordinator BTKlplw ARca Aluk.. Inc. 118 Sublldl8ry 01 AII8nllcRlchlleldComp8ny #14 ARca Alaska, Inc. ) Post Office Box. 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 Mr. Lonnie Smith Alaska Oil and Gas Conservation Commission (AOGCC) 3001 Porcupine Dr. Anchorage, AK. 99501-3192 ,;~~'n!2... ? /I~/ Itì ! .... 1........... ~~ ~~ r "'1 "\\~I ,..~- ,', ~i ",~.Ii 'H...JC2 \ ._.~~' "",,'"'" I'VI ."1'==-*1 ..- tI{\ ~I \ . ,....... ";;',;ÿ.·;-IE· -! :/.\ :',~'.> ,;,,) Y ,.J..k.. . ß\,:::;st"'-\ YE c:¡'~l:i T'~~L '\ t.!l~':'J-"'---'-" AÂ'L-.ð ?, (5 February 6, 1987 SubJect: Prudhoe Bay Unit, Lisburne Oil Pool Lisburne Production Center(LPC) Startup Flaring Request For Additional Flaring Duration Dear Mr. Smith: ARGO Alaska, Inc. (AAI) requests approval for additional flaring duration at the subJect facility for continuation of startup and commissioning activities. On August 7, 1986, AAI requested approval for flaring of up to 4.4 billion SCF of gas over a sixty (60) day period at the Lisburne production facilities for commissioning and startup of the facilities. The AOGCC approved this request on August 14, 1986. To date, we have experienced startup problems which have extended the startup flare needs beyond our original 60 day estimate. We have successfully completed startup on those facilities which enable us to produce the well streams, send saleable oil to TAPS and process and inJect all produced water and gas. The primary activities remaining (excluding the startup and commissioning of the depropanizer unit, which will require an additional permit) is the commissioning and startup of the second gas inJection compressor, which is currently under way. However, we do not expect this to be completed before our sixty day time period runs out on February 9, 1987. Consequently, we request permission to continue startup flaring until the compressor is started up and is fully operational (currently expected by the end of February). Because we have one inJection compressor operational, we expect flaring during the startup of the second compressor to be limited and at this time, we do not anticipate requiring additional flare volume above the originally permitted 4.4 billion SCF. All gas volumes flared will be included on the Producers Report(s) of gas disposition filed monthly with the AOGCC. If you have any questions or desire additional information, feel free to contact me at 659-8647. Sincerely, - r-- ß@¡~: RECEIVED B. T. Kawakami Lisburne Operations Coordinator ¡.~ t 8 0 6 1987 Alaska Oil & Gas Cons. Commission Anchorage ARGO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany #13 y Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of ARCO Alaska, Inc. for an expansion of the Lisburne Oil Pool boundary. in the Prudhoe Bay Unit of the Prudhoe Bay Field. The Alaska Oil and Gas Conservation Commission has been requested, by letter dated August 19, 1986, to issue an order to include Section 29, Township 12 North, Range 14 East, Umiat Meridian within the boundary of the Lisburne Oil Pool as de- scribed in Conservation Order No. 207. Parties who wish to protest the granting of the referenced request are allowed 15 days from the date of this publication in which to file a written request for a hearing. The place of filing is the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501. If a protest and request for hearing is timely filed, a hearing on the matter will be held at the above address at 9:00 AM on September 29, 1986 in conformance with 20 MC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, (907) 279-1433, after September 12, 1986. If no such protest is timely filed, the Commission will consider the issu- ance of an order without a hearing. þPþ Lonnie C. Smith Commissioner Alaska Oil & Gas Conservation Commission Published August 28, 1986 #12 '1'--- ~f' ' I ·,1'/11 Jt~ :C.., "1 ! I'À:i¡r:-:,~ ."'.,. IJ)J u ". . I I , I~~ IHi ~ Iv; , x:J4íIY." , Þ1r"'Yf . r:::' ¡ :1 !VI I ! I . .... '·':1 "'f"1, ; . , 'wi j I ee::J·) ß' 4' '1'rfl:t .."..~ ,I' ,~~ ARCO Alaska, In( i Post Office ....ji( 100360 Anchorage, Alaska 99510-0360 Telephone 907 263 4206 /-kfr;" Þ 'i' 1M A<- f- ¡(C'S r~~¡¡( ¿h~. ¿; I þ¿-!g &1" À """\ ", <,) John S. Dayton Lisburne Engineering Manager August 19, 1986 Commissioner C. V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 Dear Mr. Chatterton: RE: Conservation Order No. 207 Conservation Order No. 207, dated January 10, 1985 established the Field Rules for the Lisburne Pool and the area to be covered. A geologic review indicates that the Prudhoe Bay Fault cuts across the southeast corner of Sec. 29, T12N,R14E, within the Lisburne interval. Recent 3-D seismic data in this area is presently being processed and future development could be indicated. This section, however, is not included in Conservation Order No. 207. Because the Prudhoe Bay Fault forms the northern boundary of the Lisburne Pool, Section 29 will be included in the application to form the Lisburne Participating Area (a map of the proposed LPA, with Section 29 highlighted, is attached), and should be operated under Conservation Order No. 207. Section 29 is part of Tract 26 of the Prudhoe Bay Unit and will remain in both the Permo-Triassic and Lisburne participating area.s following the unit contraction next year. ARC 0 , on behalf of the Lisburne Owners, hereby requests the Commission to include Section 29, T12N,R14E in the area governed by Conservation Order No. 207. s~nCe~lY yours, ~ )-. Jj. G~ ~ S. Dayton f JSD:JPG/kh 61-3 attachment RECEIVED cc: A. Davies - SAPC W. W. Eckert - Exxon, Houston .AUG 2 1 1986 Alaska Oil & Gas Cons. Commission Anchorage ARCO Alaska, Inc, is a Subsidiary 01 AtlanticRichlleldCompany \T,,) ~ '"I!>- ~~ ", + -+- .,¡¡.. rE ~~j ~ -I- {I,' ~~" ",ry, ~IJIII__IJI!IIII .-.-..-..,,,,.,.t'... + + j$ )~ $ -+ -+ &t::~ ,_...,-_...+,_._-'-'- --,-----<\-.-.-.--. ~f ,~, ~~. 1$1> 4· ..1)- ¡L II '~ i ' In~ \' .1"1 + -.-11-.--.-. il' -} t JM~ ,:11 ,...-..-..1/, t··..·..·--·..··-·· + -+ .I}- ".,-,-----'-1 }---.. .-.-.-'"1r'--.... ....~,.,..._ia_ + '''Ii~ ."J! .:NBI .:¡ '1 I', II II t. #11 ARCOAlaska, Inc. . Post Office Be )0360 Anchorage, AlaSKa 99510-0360 Telephone 907 276 1215 ') ~~,.~ ~~ January 7, 1986 í)f) 201-3 .j;bl'1e 1-?-f0 AMK Mr. C. V. Chatterton Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Request 'for a Lisburne Interference Test to Evaluate Directional Penmeabil ity Dear Mr. Chatterton: ARCO Alaska, Inc. requests permission to conduct a test on a 5 spot we 11 pat tern to eva 1 uate direct i ona 1 penneab i 1 it y of the Lisburne Wahoo format ion. Th i s penneab i 1 i ty data wi 11 be used to opt imi ze waterflood (secondary recovery) as well as primary deveiopment. The 5 spot wells are L2-20, L2-24, L2-26 (dual canpletion, center well), L2-28, and L2-30 (dual completion). There will be semi-permanent bottom-hole pressure gauges hung frana gauge hanger above the norma 1 swab va 1 ue in a 11 seven st rings. A second swab valve will be mounted above the gauge hanger. All bottom- hole pressures will be continuously canputer monitored. To evaluate permeability, L2-26 (center well) will be flowed (estimated start date, January 15, 1986) and BHP will be monitored in all strings. After the effects of flowing the well have been seen in the other 4 we 1 1 s (est imated 2 months), L2-26 wi 11 be shut in for approx imately 2 months for pressure bui ld-up. Then all five wells will be flowed until October, 1986 (approximately 4 months), at which time L2-26 will be shut in and bottom-hole pressure monitored. Flow wï1l continue in the other four wells right into the Lisburne Facil ity Start-up, currently planned for December, 1986. All flow frcm the Lisburne Interference Test will be routed through the Prudhoe Bay Drillsite 18 test separator. During all flow time periods, the L2 drillsite will be manned 24 hours a day. The data wh i ch wi 11 be gathered fran the Lisburne I nterference Test wi 11 aid in developing the field in the most efficient manner and prov i de max imun 0 i 1 recovery. Consequent 1 y, ARCO Alaska, Inc. re- quests approval be granted for conducting this testing. bO) T ;:~ Ben T. Kawakami Lisburne Operations Coordinator RECEIVED BTK/0015 J.A. N 0 7 i386 Alaska 011 01 '-'..:..;;, u'.Jd~. lJummission ARCO Alaska, Inc. is a Subsidiary 01 AtlanlicRlchfieldCompany Anchorage #10 ARCO Alaska, Inc. 'J Post Office Bó.. /00360 Anchorage, Alaska 99510-0360 Telephoflle 90'7 276 1215 zo7 ( I, il 'f /,1 ;;...., I e ~~ (j.¿ ~~ ~ ( -( (~'"(''' 'j) w yø+·e., IJ f} 20 1, ~ &?l1 It) . ~ - '.:S Øev A( September 30,1985 Mr. C. V. Chatterton Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 SUBJECT: K-55 Casing - Lisburne Pool Dear Mr. Chatterton: ARCO Alaska, Inc., requests administrative approval to use 68 lb, K-55 casing as the top two (2) joints of the 13-3/8" protective casing instead of L-80 for wells drilled to the Lisburne Oil Pool of the Prudhoe Bay Field. As the top two (2) joints of the protective string, this casing will be inside the conductor pipe and will. alª9.b~. £2!!1.P.'±~,!.~I:Y..~," b é~:£,~.~.9....Þ.l",..£.~.~~!l...!.~· This casing was approved for use in the Prudhoe Bay Field (Sadlerochit Oil Pool) on October 24, 1984. JJG/kjs JFM/131 RECEIVED OCT 0 11985 Alaska Oil & Gas Cons. Commission Anchorage ARCO Alaska, Inc, is a Subsidiary of AllanticRichfieldCompany v g ~ r~ f¡:::;;,~~' f"~ ()~ j #9 Enclosure ~ ÞJ. ~~ Harry \v. KUgl~::-7 be:l.K Yours very truly, This is to advise you that the Commission issued Administrative Approval No. 207.1 on May 21, 1985 authorizing the drilling of this well at the proposed location. Mr. D. K. Chancey ARCO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska. 99510-0360 Dear Mr. Chancey: We have received your letter, da.ted August 7, 1985, requesting a spacing exception for the Prudhoe Bay Unit No. L2-26 well in the Lisburne Oil Pool. August 12, 1985 #8 ARCO Alaska, Inc. ) Post Office Box 100360 Anchorage, Alaska 99510 Telephone 907 276 1215 . ~I 1'"'1 Ç-fII'ZI-a.! })fr"',J tL ,. b HR tA 1./ ¡.Jwl(. ð !I. ~6hø., "øðd$""¡ ) .--. ,.......,. ~1IItr.t.. COMM ~-~~ CO~.;~ M . .__..:~I" , ,.....0f'1"."-··/r6~. ~ '~,.;,./~. ;¡~ I . R(:S, f:N(~~"ID.· . r-""11-'~ 1/-' \~ . . ..,;.. "", ,"'. ,. ¡......';, - ~ . ..." ". SR ENG"--\ ENG... ~ .'SR GEOL \ ~f.;~~j~~ Ef\!G AS,.... 'sTAtTECH\~ :STA TTECI-f(8 "ÞfCÈ:-- .., . August 7, 1985 Mr. C. V. Chatterton, Chairman State of Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 Dear Mr. Chatterton: RE: Waiver of Lisburne Oil Pool Well Spacing Rules As operator of the Lisburne oil pool, ARCO Alaska, Inc. requests a waiver from Rule 3 (Well Spacing) of the Conservation Order No. 207 for the Lisburne oil pool. This waiver is for the proposed Well L2-26. If approved, the Lisburne Well L2-26 (Attachment 1) will be the center producing well for the five-well (Wahoo) interference test. This interference test will be the first stage of a three phase program intended to provide data for the reservoir depletion program and future secondary recovery efforts. After interference testing is complete, this well will be the fifth producer in the limited drain- age area test. The five-well pattern is currently being evaluated for future implementation of a five-spot, 160 acre spacing pilot waterflood proj ect with L2-26 being used as the center inj ection well. The pilot waterflood would enable evaluation of the full field secondary recovery potential in the Lisburne Reservoir. The water injection and secondary recovery permit request will be presented in a separate letter. The proposed location coordinates for this well are as follows: Surface Location: 1908' FSL, 1200' FWL, Sec. 18, T11N, RISE, UM Target Location: 0' FSL, 0' FWL, Sec. 8, T11N, RISE, UM (-8,900' SS) TD: 303' FSL, 336' FWL, Sec. 8, T11N, RISE, UM (-9,400' SS) The proposed spud date for this well is August 13, 1985. RECEIVED ,ttUG 0 ? JOðr Alaska 0'/ ~:J / & G as Cons AnChorage . COIT1JnisSion ARCO Alaska. Inc. is a Subsidiary of AtlanlicRichfieldCompany C. V. Chatterton August 7, 198 'it Page 2 We request your speedy consideration of this waiver. If you have any questions concerning this matter, please call me at 265-6330. Very truly yours, ;'\1)!1 6~) 0% ,-.~.-I'../ v J - D. K. Chance DKC:EGP/kh 04-2 attachment cc: P. L. Coyne - Exxon T. L. Fithian - ARCO RECEIVED AUG 0 7 1985 Alaska Oil & Gas Cons. Commission Anchorage EGP 04-2 l- t/') W I- W o z w a: w IL. a: w I- Z - W z a: ::) m t/') .J ,.. 'I- Z W ~ :I: o e:( l- I- e:( ~* - / t<)'X: '(")x '(") l- t/') w 0.1- '(") ~ '--... ~ OJ W C\J '-QJ CL (j) Ul~ ~ <[ : .U1 (f)N '-/ <.D I N ..J ) ) ",,"Oì O. 0> 0 """w 000::: 0- 0 0 - N 0 <.0 N ""'"If- ~ -l w CD w (j) l..J.. . Z - (f) 0 ...... . w , 0 --1 (j) c:X: u N en >- .-J 0 ::> 0 J 0 N / ~N .- - N - ['-- - OJ "'\ <:;:j"" .J ) r<) )( - - -1(- ....... ........... .... ~~ X " 'x I I I RECEI'VED .l\UG 0 7 1985 AlaSka Oil & Gas C01S. Commission AnChorate I I #7 May 15, 1985 .J..1/(// (!D.... /'" ) t,lL C/ n.' .",."'- r / VJ / frJ]. /<",'ø""'''''''''~''''ø'' rt _,#" ",""II" / ~~ ~~ ARca Alaska, Inc. Post Office ) 100360 Anchorage, Aláska 99510-0360 Telephone 907 276 1215 Mr. C. V. Chatterton Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 SUBJECT: Lisburne L2-26 Permit to Drill Dear Mr. Chatterton: Enclosed are: o An application for Permit to Drill Lisburne L2-26, along with a $100 application fee Diagrams showing the proposed horizontal and vertical projections of the well bore A diagram showing the proximity to wells L2-30, L2-28, and L2-24, the only wells within 200' of the proposed well A diagram and description of the surface hole diverter system A diagram and description of the BOP equipment o o o o o A copy of the certified "As Built" conductor survey Well L2-26 is an 80-acre well location and is the center well of the 5 well pilot interference test discussed in the public hearing of November 29, 1984. According to Rule 12 of Conservation Order No. 207, we request administrative approval of an exception to Rule 3 (well spacing) for this well. Data from this well will vastly improve our understanding of the reservoir and should point towards appropriate enhanced recovery methods. RECEIVED MAY 1 7 1985 Alaska 011 & Gas Cons. Commission Anchorage ARCO Alaska. Inc. Is a Subsidiary 0' AtlantlcRlchlleldCompany )' ) We estimate spudding this well about August 17, 1985. If you have any questions, please call me at 263-4610 or Don Breeden at 263-4963. Sincerely, í.L<jÂ¡L T. L. Fithian Area Drilling Engineer TLF/DEB/tw PD/L82 Enclosures RECE/I¡ MAy ED A./liska. 1 ? J9fJ~ Oil & ut, Gq$ C. AI1Ch 0'18. Co OtâUe íl1rnisSiO/1 #6 ',.- '1\ ~ \'" _1 /j 0 ;¿o l- Harch 22, 1985 Hr. J. S. Dayton ARca Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Dear Mr. Dayton: The Alaska Oil and Gas Conservation Commission has received ARca Alaska, Inc.'s letter, dated March 7, 1985, requesting anexcep- tion to the logging requirements of 20 MC 25.536(a) for wells to be drilled for production from the Lisburne Oil Pool in the Prudhoe Bay Field. The request was slightly modified during a meeting at the COlnmission's office on Narch 20, 1985. The logging plan requested is as follows: 1) Survey one well drilled from each Lisburne development pad from the shoe of the conductor pipe to total depth with complete electric or radioactive logs. 2) Survey the first well drilled into each governmental section from the shoe of the surface casing to total depth with complete electric or radioactive logs. 3) Survey all other wells with complete electric or radioactive logs through the entire penetrated section of the Lisburne Oil Pool, as defined in Conservation Order No. ,_~07, and survey that portion of the hole from above the Put River Sand or Sag River Sand through the base of the Sadlerochit Formation with an appropriate radioactive log or logs. The Commission has examined the proposal and concluded that the above program will provide definitive logging data for pool management. Hr. J.S. Dayton Harch 22, 1985 Page 2 Therefore, by this letter, the Alaska Oil and Gas Conservation Cormnission approves the logging program detailed above for development wells drilled to the Lisburne Oil Pool. This approval is pursuant to 20 MC 25.536(c). Yours very truly, //. ~/J *~ ¿J'&f~ Harry vJ'. Kugler Conunissioner BY ORDER OF THE CO~IISSION cc: Paul Hartin - Sohio Alaska Petroleum Co. F . Ht-JK.l #5 I, ^! r '/.\ r"~~ \ ,~, C ,~, "';' ,p /''\,....1 \ ',.'". R ;, ;.- ',..'" .,,,.l :~,,:t .'1'\' ...."'h C;ONS[:EVP.T¡O:'J CO~/:M¡8G¡ï..i¡\! AU.::··é.". :X'_ i\ C':.~') ~.èf?MM._~ CO;~t:;;::~i\~',:\ ,.~., ~"":"J r',~v p l'II(,"P1r -'vi' COMM ..-. ¡" ,t"." \, ,,' ,,"¡h,..;¡,,)~J;\¡ ~~~t~COIV\M~Z<~ ~~t6(S~ET, SAN FRANCi'~' ~~W i ..... ~ ~¡^-Jc 4 3 t. " , r .I" n~G '.-~~ December 7, 1984 I c...¡ 1 GEOl r-r'2(jEq~' ¡'T 3 Gf.Ot~ ¡~ STATTFC · , " STi\T T"::C" ~d~;~'=~1 i. ~.I~F: "......, I ~OHI~ OFFICE COpy SOHIO ALASKA PETROLEUM COMPANY c. V. Chatterton, Commissioner Alaska Oil & Gas Commission 3001 Porcupine Drive Anchorage, AK 99501 Re: Lisburne Field Rules Testimony Dear Commissioner Chatterton: Pursuant to the Commission's instructions given at the November 29, 1984, Public Hearing, Sohio as a major working interest owner of the planned Li sburne Reservoi r development, herewith submits additional comments to the record prior to its closing at 4:00 P.M. December 10, 1984. Whilst Sohio fully supports the proposed Li sburne Reservoir field rules as submitted by ARCo Alaska, Inc., it considers that several comments, both oral and written, presented by ARCo during its testimony require clarification as briefly discussed below: (i) Reservoir Performance Sohio's reservoir engineering studies have indicated that the reinjection of excess produced gas within the Lisburne gas cap will assist in maintaining reservoir pressure; however, the impact of such, injection upon hydrocarbon recovery cannot be predi cted wi th conf idence at this time. In some of our studies benefits could be realized by gas cap expansion; in others, sustained injection, coupled with the geological complexity of the reservoir and in particular the na tural fracture system, may adversely affect overall recovery. The working interest owners will gain important knowledge by their prudent planning of a proposed pilot operation in 1985, that will furnish key data with respect to further development of the Li sburne Reservoir. For the initial development, it is planned to conserve excess produced gas by reinjecting same into the Li sburne gas cap, concurrently wi th formula ting the optimum recovery mechanism to maximize field reserves. R r- ,-,--,.,. r'f:'""~r\ "i II-Lt. 'i \2 r:'·l.~ \.. ~~ L. b I" ~,~." ,n ·1 '7 '''HIli , '.' .!.. ¡ .ì~; u'+ A1asl<a 0:1 ¿~ Ca:; Cü:'d, Cornm:ss!:)n 'j ,II C~ V~ Chatterton, Commissioner Page 2 (ii) Lower Lisburne (Alapah) Potential As referenced in the testimony, a planning datum of 9300 feet subsea is currently being assumed for a lower limit of the Phase I or Initial Development Area. Sohio is in general agreement with the opinions expressed with regard to the uncertainties that exist in the continui ty and producibili ty of the Lower Li sburne (Alapah) and Upper Lisburne (Wahoo) below 9300 feet subsea. However, Sohio believes that sufficient encouraging evidence from well tests does exist to warrant significant effort to further appraise this potentially large resource~ As a consequence, Sohio will continue to pursue plans for the expeditious drilling and appraisal of the entire Lisburne Reservoir. (iii) Sag Delta No. I Well During cross-examination of the ARCo Alaska, Inc. wi tnesses, oral statements were made to the effect that the production test resul ts from Sag Del ta No. I well (Alapah) were indicative of the accumulation being anomalous and a separate pool. Sohio considers the overall distribution and continui ty of fluids wi thin the Lisburne Reservoir to be complex, but nonetheless characterized by a single accumulation or pool. (iv) Unitization As stated in the foregoing, Sohio is most supportive of the application for field rules for the Lisburne Reservoir. Further, it is considered important that the oil and gas leases included in the field rules area be unitized and that all parties' correlative rights are preserved by the establishment of an appropriate Lisburne participating area prior to the commencement of regular production. Very truly yours, rJ' ¿ \L.. ,r '~..- I' ,~' 'r· ~ ~ G. J. Abraham GJA/SED-II03L:kal cc: J. C. Bowen - Exxon Corporation L~ E~ Tate - ARCo Alaska, Inc~ P. J. Martin - Sohio Alaska Petroleum Company #4 R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3fm AVENUe. 277-0572··277-0573 277-8543 2727515 ANCHORAGE, ALASKA 99501 Alaska Oil & Gas Cons. Commission Anchorage /" -t';/ Ù(.7// ./~/¿--: 3-/1-%7 g;ø-- qFAèe C};fJ RECEIVED DEC 1 71984 November 29, 1984 9:00 A.M. 3500 Tudor Road Anchorage, Alaska CHAT CHATTERTON, Chairman LONNIE SMITH, Commissioner LISBURNE FIELD RULES PUBLIC HEARING OIL AND GAS CONSERVATION COMMISSION STATE OF ALASKA 1 :f 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 1 2 3 4 5 6 7 8 9 10 11 12 ( 1:3 14 15 16 17 18 19 20 21 22 23 24 25 -2- PRO C E E DIN G S MR. CHATTERTON: If we may corne to order? The And we will call this gathering to order. And the date is the 29th of November, 1984, and it's just approximately 9:00 o'clock and we're at 3500 Tudor Road in what used to be the Assembly's chambers, but now I don't -- we don't have a name for it, but it's the ex-Assembly chambers. And we're gathered here for a matter that has to be brought before the Commission's attention. I can -- my introductions are very simple from the head table up here. To my immediate right is Commissioner Lonnie Smith, to my immediate left is Meredith Downing, she is the -- from R & R Court Reporters and will be taking the proceedings of this meeting, and I am Chat Chatterton with the -- with the Commission. And without -- well, I guess to make it legal we better ask -- incidently, Commissioner Harry Kugler cannot be with us today. He had other plans in another part of the world, so we'll struggle along without him, but what normally is his duty we'll now ask Commissioner Lonnie Smith to read into the record the subject of this hearing and so forth. Go ahead, Lonnie, please? MR. SMITH: Thank you, Chat. "Notice is hereby given that ARCO Alaska, Incorporated, has requested the Alaska Oil and Gas Conservation Commission to hold a public hearing in order to present testimony to redefine the Lisburne Oil Pool rulee for the development and exploitation of this pool in the Prudhoe Bay Field. The public hearing will be held at 9:00 A.M., Thursday, R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 .. 277-0573 1007 W 3RD AVE:.NUf:_ 272 7515 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1 2 3 4 5 6 7 8 9 10 11 12 I 13 14 15 16 19 20 21 22 23 24 25 .( 1 -3- November the 29th, 1984, here in the Municipality of Anchorage Assembly Room, 3500 East Tudor Road, Anchorage, Alaska. All interested -- interested persons and parties are invited to give testimony." And this was advertised in the Anchorage Times on October the 26th, 1984. MR. CHATTERTON: Thank you, Lonnie. The -- just on the format of this -- of these proceedings, it shall be conducted in accordance with Title 20-A (ph) of the Alaska Administrative Code, Chapter 25, Section 540. And just to briefly summarize what that section says, why, we shall have testimony from the applicants first and any others that wish to testify, offer direct testimony, why, please, you'll be recognized upon the completion of the applicant's testimony, and we will at our discretion permit applicant to cross examine any other person giving testimony. Oral statements are permitted. They will follow the conclusion of all direct testimony by any person. We 17 will also accept written statements, and we have at the back of 18 the room from the Commission Lucy Chali. She will be -- has paper and pencil, so if you wish to write out questions, you may see her, and she will bring those questions to the Commission, and they will be asked if the Commission believes they are pertinent to the subject before us. They will be asked of the person that they're -- the question is directed towards. We will -- I think the -- I've been told that the direct testimony will probably take something on the order of about an R Be R COURT REPORTERS 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVl:èNUI:_ 272 7515 -4- 1 hour and 15 minutes, an hour and 20 minutes. Upon conclusion of 2 the direct so we can all gather forces, why we'll take about a 15- 3 minute break so that I can overcome my nicotine fit. 4 And with that, why, steve, I would ask you -- Hi, Mark, 5 how are you doing? I -- I would ask you to proceed? 6 MR. WILLIAMS: Thank you. Mr. Chairman, members 7 of the Alaska Oil and Gas Conservatoin Commission, ladies and 8 gentlemen, my name is Stephen M. Williams. I'm an attorney 9 with ARCO Alaska, Inc., the operator for the eastern operating 10 area of the Prudhoe Bay Unit. ARCO, Exxon Corporation, and 11 Sohio Alaska Petroleum Company are all -- are all owners of 12 leases which overlay the Lisburne Reservoir. The owners have 13 requested this public hearing before the Commission pursuant 14 to the provisions of 20 AAC 20 -- 25.520 to consider the adoption 15 of field rules for the development of the Lisburne Oil Pool. 16 THe application for field rules was formally filed in November, 17 1984. Prefiled testimony was also delivered to the Commission 18 on November 26th, 1984. Confidential meetings were held with 19 the Commission on October 30, 1984, to review ARCO/Exxon reservoir 20 interpretation and on November 8th,j 1984, to review Sohio 21 reservoir interpretation. ARCO requests that the application 22 and prefiled testimony be made part of the public record. These 23 documents support the application for field rules for the Lisburne 24 Oil Pool. Several represetnatives of ARCO will present testimony 25 today. Our testimony will provide a geological description R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W, 3RD AVENUl:, 272 7515 -5- 1 of the Lisburne Reservoir, a reservoir analysis, discussion of 2 reservoir development plans, a description of the facilities 3 necessary for development of the Lisburne Reservoir, a discussion 4 of well design, and, finally, a summary of the testimony and 5 discussion of the proposed field rules for the Lisburne Oil 6 Pool. Our intent today is to emphasize the key points, and 7 provide updated information to the Commission gained through 8 the delineation and testing activities conducted by the owners 9 over the last several years. 10 Afterwards, the owners request that a panel be formed 11 at the conclusion of the testimony to provide a forum from which 12 the Commission may ask questions on specific matters provided 13 in the testimony. 14 It appears that original field rules were adopted for 15 the Prudhoe Bay Lisburne Oil Pool in Conservation Order Number 16 83-C. This order was adopted January 12th, 1970. The commission 17 is requested to revoke Conservation Order Number 83-C, nad adopt 18 revised field rules for the Lisburne Oil Pool. ILnformation 19 gained over the past years has provided operational information, 20 and sets forth the need to modify these rules., We have proposed 21 a revised set of field rules for your consideration. These 22 proposed rules are contained in Appendix One. 23 The following witnesses will present testimony today: 24 Linda Okland will provide the geological testimony; Don Chancey 25 will provide the reservoir analysis testimony and the well R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AVENUE 272 7515 -6- 1 operations testimony; Don Breeden will provide the drilling 2 testimony; Ron Beach will provide the facilities description; 3 and Leland Tate will provide a summary of the testimony. Each 4 of the witnesses has included in their pre-filed testimony a 5 biographical statement setting forth their respective 6 qualifications. 7 Mr. Chairman, we request that the witnesses be sworn 8 in at this time? 9 MR. CHATTERTON: Fine, Steve, if -- if you will 10 all stand, those that are planning to testify? Lonnie? 11 LINDA OKLAND, DON CHANCEY, DON BREEDEN, 12 RON BEACH and LELAND E. TATE 13 were duly sworn in under oath. 14 MR. CHATTERTON: Thank you, gentlemen. 15 MR. WILLIAMS: Thank you, Mr. Chairman. Linda 16 Okland will begin the testimony today witht the ge- -- geological 17 description of the Lisburne Reservoir. 18 MR. CHATTERTON: All right. Linda -- if I may 19 interrupt, Steve, you requested that the November 26th pre-filed 20 testimony and the letter of application for a nearing on the 21 pool rules be included in the record, and the Commission so 22 orders that it is included in the record. 23 MR. WILLIAMS: Thank you, Mr. Chairman. 24 MR. CHATTERTON: Linda? 25 MS. OKLAND: My name is Linda Okland. I am 1 R & R COURT REPORTERS 810 N STREET, SUITE 101509 W. 3RD AVENUE 1007 W. 3F~D AVENUE 277-0572 - 277-0573 277-8543 272 7515 ANCHORAGE, ALASKA 99501 -7- a senior geologist with ARCO Alaska, Incorporated. I received a 2 masters of arts degree in geology from the University of North 3 Dakota in 1978, and I have been employed as a petroleum geologist 4 by ARCO since 1978. I worked in Midland, Texas, for two years 5 before coming to Alaska in 1980. I have been working on the 6 Lisburne Reservoir since January, 1982. 7 MR. CHATTERTON: Linda, the Commission has 8 considered your qualifications and certainly feels that you 9 can qualify and do qualify to testify as an expert witness. 10 MS. OKLAND: Thank you. My testimony today 11 will include a geologic description of the Lisburne Reservoir. 12 Oil was discovered in the Lisburne Reservoir with the 13 drilling of the Prudhoe Bay State Number One well in 1968. 14 Exhibit One is a map of a portion of the Arctic Slope of alaska 15 in the vicinity of the discovery well. The Lisburne Reservoir 16 is bonded on the north by the Prudhoe Bay Fault, on the northeast 17 by a major cretaceous unconformity, and by gentle dip to the 18 south and southwest. The area for which Lisburne field rules 19 are proposed is outlined on Exhibit Two. It coincides generally 20 with the northeastern portion of the Prudhoe Bay Unit. 21 MR. WILLIAMS: Linda, just 22 MR. CHATTERTON: Linda, if I may interrupt -- 23 see if I know what to do. Do you know, Meredith? We'll throw 24 the circuit breaker. 25 COURT REPORTER: One, two, four, six, eight and R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVE.NUE. 272 7515 -8- ten. 2 MR. CHATTERTON: One, two, and four. We did 3 pretty well. 4 MR. SMITH: That's perfect. ;) MR. CHATTERTON: What ones did we push? 6 (Laughter) 7 MR. CHATTERTON: I apologize for the interruption, 8 Linda, but perhaps we can see better now. Thank you. 9 MS. OKLAND: To date 27 wells have penetrated 10 the Lisburne within the area outlined. These wells are high- 11 lighted on the map. Four of the wells indicated are north of 12 the Prudhoe Bay Fault. Of the remaining wells, 13 produced 13 oil or oil and gas on test in the Lisburne Reservoir. One well 14 produced water and two were apparently tight. Five wells which 15 penetrated less than 100 feet of the Lisburne Reservoir, and 16 one well in which the Lisburne was severely truncated, were 17 not tested in the Lisburne interval. The Lisburne sectoin of 18 one well was lost due to stuck pipe before it could tested. 19 The Lisburne Group underlies the Sadlerochit Group. 20 The Lisburne Group is subdivided into the Wahoo and Alapah 21 formations, each of which is typically about 1 ,000 feet thick 22 in the Prudhoe Bay area. Exhibit Three is a portion of the 2:3 log from Prudhoe Bay State Number One. The top of the Lisburne 24 group occurs at a measured depth of 8790 feet, and the base 25 at 10,440 feet measured depth. The Wahoo-Alapah boundary is R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUi:. 272 7515 -9- at approximately 9,500 feet measured depth. 2 Both Wahoo and Alapah consist predominantly of shallow 3 marine limestone and dolomite, with lesser amounts of shale, 4 silt, sand, and chert. Shaly or silty beds are fairly continuous, 5 and are useful for correlation. However, they do not constitute 6 efefctive field-wide barriers to fluid movement because they 7 are thin, of variable permeability, and are breached by fractures. 8 Dolomite and chert are irregular in their distribution. Dolomite 9 is a relatively minor component of the upper Wahoo, but becomes 10 more prevalent lower in the section. A thick, shaly, dolomitic 11 interval occurs at the base of the Wahoo. This interval 12 stratigraphically separates the Wahoo from the Alapah. 13 Porosity in the Lisburne Reservoir is predominantly 14 post-depositional in nature, and is controlled by a complex 15 interaction of factors, including depositional facies, leaching, 16 and dolomitization. 17 natural fractures are abundant throughout the Lisburne 18 Reservoir. Many of the fractures are partially to completely 19 filled with calcite cement, but unmineralized fractures are 20 also present. The fractures are predominantly vertical or near 21 vertical, with no strong directional trend. Storage capacity 22 in the fractures is small, but their contribution to permeability 23 is significant. 24 Exhibit Four is a structure map on the top of the Wahoo 25 formation, with a contour interval of 200 feet. The Lisburne R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 w. 3F~D AVENlk 272 7515 1 2 :3 4 5 6 7 8 9 10 11 12 ( 1:3 14 15 16 -10- reservoir is bounded on the north by the a major east-west trending fault complex. Closure is created by faulting on the north, by truncation on the east, and by dip of 135 feet feet per mile to the south and west. Exhibit Five is a north-south cross-sectoin frm ARCO/Exxo~ Gull Island State Number Two to ARCa/Exxon Sag River State Number One. The vertical exaggeration is approximately 44 to one. This cross-section and the east-west cross-section which follows show the general structure and correlations in the upper part of the Wahoo. As illustrated in this cross-section, Lisburne sediments dip to the south gently, away from the fault. Within the boundaries of the proposed field rules area, the top of the Lisburne Reservoir occurs at depths ranging from 8,300 feet subsea in the north to about 9,300 feet subsea in the southwest. Exhibit Six is an east-west cross-sectoin from ARCa/Exxon West Beach State Number Two to Sohio Sag Delta State Number 17 Five. The vertical exaggeration on this cross-section is 18 approximately 40 to one. This cross-section shows that the 19 Lisburne Reservoir is truncated to the east by a major Cretaceous 20 unconformity. In this area, the Lisburne Reservoir is overlain 21 by impermeable Cretaceous shale. 22 The truncation begins just to the east of the Sohio 23 Sag Delta Number Six well, and is shown by a heavy wavy line 24 on the structure map. A lighter wavy line indicates where the 25 Wahoo has been removed'and truncation of the Alapah begins. R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 1007 W. 3RD AVENUE:. 272 7515 509 W, 3RD AVENUE 277-8543 ANO-lORAGE, ALASKA 99501 a .4 5 6 7 8 9 10 11 12 ( 13 14 15 16 17 18 19 -11- East of tis line Wahoo is not present. On the west, the Lisburne 2 Reservoir is partially truncated by a smaller unconformity of probable Permian age. The trapping mechanism in the Lisburne, as ln the Permo- Triassic Reservoir, is provided by faulting to the north and truncation to the east. THe downdip limits of the reservoir are determined by low proven oil saturation at approxoimately 9,300 feet subsea. This contact is gradational. The areal limits of the proposed field rules area were selected to enclose all potentiallyi commercial portions of the Lisburne Reservoir. A gas cap is present in the area, with a gas-oil contact estimated at 8,600 feet subsea. Above 9,300 feet subsea, sediments of the Lisburne formations are oil-stained where porous. Reservoir quality is determined by porosity development. Despite considerable variations in porosity, there appears to be good lateral communicatoin among porous zones both above and below 9,300 feet subsea. Oil-stained rock also occurs below 9,300 feet subsea. 20 We do not know at this time the extent or continuity of oil 21 in this part of the section. Uncertainty still exists in the 22 sustained producibility of oil in the Alapah and the Wahoo below 23 9,300 feet subsea. Present development plans are limited to 24 9,300 feet subsea and above. If producible oil is established 25 below this depth in the future, however, we anticipðtethat..it R & R COURT REPORTERS 1 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W 3RD AVENUl 277-0572 - 277-0573 277-8543 272 7515 ANCHORAGE, ALASKA 99501 -12- 1 could be commercially developed in conjunction with the shallower 2 Lisburne oil. Therefore, we request that one set of field rules 3 be granted for the entire Lisburne Reservoir within our proposed 4 development area. As drilling proceeds, we will conduct tests 5 of the Lisburne interval below 9,300 feet subsea, and if viably 6 producible, these intervals will be included in our development 7 plans. 8 This concludes my prepared testimony -- testimony. 9 Donald K. Chancey will now present the reservoir analysis 10 testimony. 11 MR. CHATTERTON: Thank you, Linda. Don? 12 MR. CHANCEY: My name is Donald K. Chancey. 13 I received a bachelor of science in engineering in 1975 from 14 the University of Texas. following graduation, I went to work 15 for ARCO as a petroleum engineer. In 1982, I moved to Alaska 16 and have been working on the Lisburne Reservoir since that time. 17 I am a member of the Society of Petroleum Engineers and a 18 Registered Professional Engineer in the State of Texas. 19 MR. CHATTERTON: Don, the Commission finds you 20 qualified as an expert witness to testify on the matters before 21 us. 22 MR. CHANCEY: Thank you. My testimony today 23 will include a description of the Lisburne Reservoir, a summary 24 of rservoir performance studies, and comments on well spacing. 25 Exhibit Seven is a map of the proposed Phase One 1 R &R COURT REPORTEH5 810 N STREET, SUITE 101 509 W, 3RD AVENUE 1007W 3r·~D AVENUt: 277"0572·277"0573 277-8543 2727515 ANCHORAGE. ALASKA 99501 -13- 1 development area for the Lisburne Reservoir. The area outlined 2 for development was determined by well logs, core data, production 3 tests, and reservoir analysis. 4 Within the proposed development aea, ARca estimates 5 3 billion stock tack barrels of original oi-in-place with 6 500 billion standard cubic feet of free gas in place. 7 The average prosity of the productive interval is 8 approximately 10%, determined from logs and core data where 9 available. 10 Two methods of calculating water saturation have bee 11 evaluated by ARca and Exxon. The first method involves the 12 conventional analysis of electric well logs calibrated to oil 13 base cores. The second method utilizes water saturation data 14 obtained from several oil base cores to calculate a Buckley- 15 Leverett J-function. This J-function provides a correlation 16 of water saturations with formation permeability, porosity, 17 and height above the water-oil contact. Water saturations at 18 any point in a well profile caIn be determined by use of the 19 J-function. The various methods yield an average water saturation 20 of 20 to 40% within the developable oil column. 21 Initially, the reservoir pressure in the Lisburne 22 formation averages about 4,490 pounds per square inch at 8,900 23 feet subsea datum with a reservoir temperature of 1830 Fahrenheit. 24 The oil gravity averages 270 API. The oil formation volume 25 factor averages 1.385 reservoir barrels per stock tank barrel, R & R COURT REPORTERS 1 810 N STREET SUITE 101 277-0572 - 277·0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 2727515 -14- and the solution gas-oil ratio is 830 cubic feet per barrel 2 as measured in the bottomhole sample from West Bay State Number 3 One on March 1, 1982. In-place Lisburne crude is saturated 4 and has a viscosity of 0.7 centipoise. 5 The primary recovery mechanism in the Lisburne Reservoir 6 is thought to be predominantly solution gas drive with some 7 additional pressure support provided by gas cap expansion. 8 There is a possibility that gravity drainage may increase oil 9 recovery. If the natural fracture pattern is vertically extensive, 10 reservoir boundaries could be crossed and a natural flow path 11 for segregation of oil and gas provided. 12 Produced gas, after deduction for field fuel, will be 13 initially reinjected into the Lisburne. Gas will primarily 14 be injected into the Lisburne gas cap, but perhaps also down 15 dip to help minimize regional pressure gradients. This will 16 maintain higher reservoir pressure and increase recovery. 17 Although some water production has been seen in drillstem tests, 18 little water has been produced during the production tests. 19 We do nöt expect to have strong aquifer support. Recovery is 20 estimated to be in the range of seven to 22% of original oil 21 in place with primary depletion and gas reinjection. 22 Several reservoir simulators have been built by Lisburne 23 owners to model the Lisburne reservoir. I will describe ARCa's 24 modeling efforts. Initially, a single well model was built 25 to match the nine-month production test at West Bay State Number R & R COURT REPORTERS 1 810 N STREET, SUITE 101 509 W, 3RD AVENUE 1007 w. 3f~D AVENUE 277-0572 - 277-0573 277-8543 272 7515 ANCHORAGE. ALASKA 99501 -15- One. The model consisted of 15 radial cells with increasing 2 radii around the well bore. Well logs of -- and some cores 3 provided the basis for 15 layers to present -- to represent 4 the Upper Wahoo. This model was matched to the production test 5 history and the results were applied to the cnostruction of 6 a 2-D strip model. As shown on Exhibit Eight, a north-south 7 cross-sectoin was drawn through West Beach State Number Two, 8 West Bay State Number One, South Point State Number One, and 9 Sag River State Number One. From this cross-section a strip 10 model with 60 cells in the north-south directoin nad 18 layers 11 covering the Upper Wahoo was built. There is one cell in the 12 east-west direction with the width of that cell varying to ( 13 14 15 16 17 approximate the original oil-in-place. Although there is only limited production data from which to match the model, the odels indicate that individual wells may show a substantial decline, but infill drilling will maintain total field withdrawal rates. Several wells have shown a tendency to go to high gas- 18 oil ratios in a short period of time. The model also indicated 19 that our recovery could be increased if the field is drilled 20 on 160 acre spacing rather than 320 acre spacing. 21 Natural flow tests have been conducted on several wells 22 indicating a tight matrix with permeabilities ranging from 0.1 23 to two millidarcies. These permeabilities have been confirmed 24 by routine core analysis. However, history matches with a single 25 well simulator indicate that higher permeabilities were required R Be R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVI:::NUI::: 272 7515 -16- 1 to support the rates between 1,000 and 2,000 barrels per day that 2 were seen during the two-month productin test in each of five 3 wells. Near-well stimulation was also required. At least prt 4 of the observed near-well stimulation and the enhanced matrix 5 permeability are attributed to the natural fracture system. 6 Acidizing or hydraulic fracturing cleans up the well- -- the 7 wellbore damage and enhances the natural fracture productivity. 8 To date we have performed 76 drillstem tests, 40 in 9 the Wahoo and 36 in the Alapah. Short term flow tests, usually 10 of two months duration, were run in the Lisburne intervals of 11 West Bay State Number One, South Point State Number One, Pingut 12 State Number One, south Bay State Number One, and Sag Delta 13 Number Six. From these short term tests, we have confirmed 14 that the Lisburne Reservoir is capable of producing at well 15 rates in the 1,000 to 2,000 barrels of oil per day range. These 16 earlier tests provided only hints of potential operational and 17 GOR problems. 18 In mid-December of this year development of the Lisburne 19 Reservoir will commence with the drilling of 320-acre spaced 20 wells on drillsite L2 as shown on KExhibit Nine. Current plans 21 call for 160-acre well spacing during Phase One primary 22 developmentd, but other spacing will be evaluated as additional 23 production occurs. Drilling will take place from six drillsites. 24 Drilling of 320-acre spacing wells will be completed during 25 the third quarter of 1987 and infill drilling to 160-acre spacing R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUt:_ 272 7515 -17- 1 will be completed by 1989. The ultimate planned well count 2 could reach 210 wells on 160-acre spacing. While we have provide¿ 3 manifolding for up to 20 gas injectors at LGI and L6, four gas 4 injectors will be complted in time for the late 1986 start-up. 5 Pendindg results of initial development, further primary 6 development could develop the edge regions of hte reservoir 7 durign the time period from 1990 through 1992 as shown on Exhibit 8 Ten. Up to four rigs will be utilized during this development 9 program. 10 While drilling will be a major activity during the next 11 seven years, several other development activities will also 12 be vigorously pursued. Because of the long lead times required 13 for secondary and enhanced oil recovery projects, the time period 14 prior to start-up of the Lisburne production facility in late 15 1986 is extremely important. Major efforts will be made during 16 this time to obtain the data required to evaluate the best 17 ultimate recovery plan for the Lisburne Reservoir. Information 18 must be otained n formation producing characteristics, recovery 19 mechanisms, flow characteristics, formation continuity, fluid 20 compatibility, and reservoir limits. One of the first tests 21 is planned to begin in early 1985. South Point State Number 22 One may be placed on long term production test to determine 23 extended production characteristics, such as oil rate, bottomhole 24 pressure, GOR, and water production. It is anticipated that 25 the test will last until field start-up. This information will R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272 7515 6 7 8 9 10 11 12 I 13 \ 14 15 16 17 18 19 20 21 22 23 24 25 -18- 1 be used to confirm equipment design assumptions and to provide 2 early production data for computer model simulations. 3 ARCO, Exxon and Sohio are presently designing a five 4 well interference test to be conducted from drillsite L2 during 5 mid-1985. One 80-acre well will be needed which will require an exception to the field rules requested today. The purpose of this test is to determine effective vertical and horizontal reservoir permeabilities, directional permeability trends, and zonal isolation. Another part of this test will be a limited drainage area test to obtain early information on how the reservoir fracture and matrix systems produce under finite reservoir conditions. this information will assist in our understanding of the reservoir performance during primary and secondary recovery. Other tests may be conducted as prudent to obtain the informatoin required to select a appropriate secondary/enhanced recovery method. Upon completion of limited drainage tests and pending continued positive results from laboratory studies, a pilot waterflood test is planned. Satisfactory pilot waterfloo¿ performance could lead to a commitment to a full-field waterflood project. Gas injectivity tests may be conducted and tests will be made to determine the extent of gas cap communication with the oil column. The current goal is to gather enough information to permit commitment to a full field secondary/EaR project by early R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 1007 W 3'~D AVENUE 2727515 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 -19- 1 1989. 2 This concludes my testimony on reservoir analysis and 3 I would now like to introduce Don Breeden who will speak on 4 drilling and well design. 5 MR. CHATTERTON: Thank you. Don, you may proceed. 6 MR. BREEDEN: Thank you. My name is Don Breeden. 7 I am a senior drilling engineer for ARCO. I'm a 1973 graduate 8 from Montana State University with a bachelor of science degree 9 in mechanical engineering. I have ten years of oil and gas 10 industry experience, with nine of those years in drillingl and 11 workovers. I was hired by ARCO Alaska's driling department 12 in 1979 and have since worked about equal times as a drilling 13 engineer and drilling foreman. I have worked on the Lisburne 14 Reservoir since October, 1983, initially as a rig supervisor 15 on South Bay State Number One and since March as a drilling 16 eng ineer. 18 MR. CHATTERTON: Thank you, Don. The Commission finds you qualified to testify as an expert witness. And, Don, perhaps if you would not mind, if you would speak up a little 17 19 20 better, why, perhaps the audience can hear. I -- and maybe 21 I can, too. 22 MR. BREEDEN: My testimony includes a brief 23 description of drilling and well design for the Lisburne Reservoir. 24 As with other North Slope oilfields, we will be 25 directionally driling the Lisburne wells from centrally located R & R COURT REPORTERS 1 810 N STREET SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVE-NUl 272 7515 -20- 1 gravel pads. Drilling procedures and well design for the Lisburne 2 Reservoir will be very similar to those now used in the Prudhoe 2 Bay Field. The casing program is the same, except that the 4 casing will be set deeper as appropriate for the Lisburne. 5 As shown on Exhibit 11, a 20-inch conductor casing will 6 be set 75 to 80 feet below pad level and cemented to surface 7 using the "polesetR" method. This is the primary cementing 8 method used by ARca on the Prudhoe Bay Unit conductors. It 9 has sufficient strength, provides some added insulating qualities, 10 and has reduced or eliminated the incidence of conductors settlins 11 while driling surface holes. 12 After the conductor has been set, a drilling rig will 13 be moved in and a diverter system will be installed on the 14 conductor. This system will include an annular preventer and 15 two diverter lines vented in different directions. The system 16 will be set to automatically open the valves on the diverter 17 lines if the annular preventer is closed. A 17-1/2 inch hole 18 will be drilled to a depth between 4,000 and 5,000 feet true 19 vertical depth where 13-3/8 inch surface casing will be set 20 set and cemented back to surface. this increaßed setting depth 21 will provide added kick tolerance. This is a necessary 22 precaution since the next section of hole will be drilled through 23 the drawndown Permo-Triassic gas cap before setting intermediate 24 casing. 25 The casing head and a 5,000 psi blowout preventer stack R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W 3RD AVENUl 272 7515 -21- 1 will be installed and tested consistent with Commission 2 requirements. A 12-1/4 inch hole will be drilled below surface ;~ casing into the shale between the Sadlerochit and the Lisburne. 4 An intermediate string of 9-5/8 inch casing will be set near 5 the top of the Lisburne and will be cemented to provide at least 6 500 feet of coverage over the Sag River sand, or the Put River 7 sand, if present. The 9-5/8 inch by 13-3/8 inch annulus will 8 be left temporarily uncemented so that it can be used for 9 injection of excess driling fluids. That annulus will then be 10 filled with cement and arctic pack to a point below the base 11 of the permafrost. 12 An eight and a half inch hole will be drilled through 13 the Lisburne production interval. After logging, a seven-inch 14 production liner will be set and cemented. 15 The casing program I have just described is planned 16 for the early development wells. Other completion methods and 17 casing programs will be considered as our knowledge of the 18 reservoir and drilling conditions grows. 19 Alternative completion methods are a major area of 20 interest. Slotted liners, screen liners, and open-hole 21 completions have been used with good results in other carbonate 22 reservoirs around the world. with some refinements in drilling 23 technology, high angle drain holes may also prove to be beneficial 24 to efficient reservoir drainage. 25 The possibility of running two weights and grades of R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 w. 3r~D AVENU[ 272 7515 -22- 1 surface casing will also be evaluated early in the development. 2 Generally, the loads due to permafrost thaw-subsidence and 3 freezeback are significantly greater than the loads imposed 4 while drilling. A combination string of surface casing could 5 be run with the accepted permafrost design casing through the 6 permafrost interval and the lighter weight and grade casing 7 below the permafrost. The suitability of the surface casing 8 for permafrost service on the drilling island will be verified. 9 An overall reduction of casing sizes will also be 10 considered. The stated casing program includes the contingency 11 to set a seven and five-eighths inch drilling liner across the 12 Sadlerochit and a five-inch linter through the Lisburne production 13 interval if required by hole conditions. If that contingency 15 does not occur, there may be strong economic incentive to reduce hole and casing sizes. A final point on the casing program is that it is designed 14 16 17 for hydrogen sulfide service, as are the completion equipment, 18 tubing, and wellhead equipment. 19 H2S first appeared during testing of Pingut State Number 20 One. During that test, the concentration stabilized at about 21 1400 parts per million. Sag Delta Number Six contained a 22 comparatively low concentration of about 25 parts per million. 23 The other Lisburne wells showed only trace amounts of ten parts 24 per million or less. Production test history indicates the 25 high concentrations of H2S are confined to the area around R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277·0572 . 277·0573 509 W, 3RD AVENUE 277·8543 ANCHORAGE. ALASKA 99501 1007 W 3RD AVE'.NUE 272 7515 -23- 1 pingut State Number One. 2 We will follow safe drilling practices, keeping in mind 3 the affects of this gas on both people and equipment. To insure 4 personnel safety, we will continuously monitor for the presence 5 of H2S. A readily available supply of H2S scavenger, such as 6 zinc carbonate, will be maintained to treat the entire mud system, 7 if needed. Emergency operating and remedial procedures will 8 be drawn up and posted and a supply of personnel equip- 9 protective equipment will be kept at the well site. All personnel 10 on the rig will be informed of the dangers of H2S, and all rig 11 site supervisors will be trained for operations in an H2S 12 environment. 13 These practices will be followed throughout the Lisburne 14 development until drilling history proves they are not required. 15 In addition, on all wells drilled into the area of Pingut State 16 Number One, we will follow the recommendations in API RP49, 17 "Safe Drilling of Wells Containing Hydrogen Sulfide". 18 The nature of the wells to be drilled requires the use 19 of grade G-105 drill pipe. Some of the high angle nad long 20 departure wells may require grade S-135 drill pipe. These 21 materials are susceptible to sulfide stress cracking, but c~n 22 be used safely under the controlled conditions recommended in 23 Section Eight, "Drill Stem Corrosion and Sulfide Stress Cracking,' 24 of API RP7G, "Drill Stem DEsign and Operating Limits". We will 25 follow those guidelines as appropriate. R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AVENUI:. 272 7515 -24- 1 This concludes my testimony. Ron Beach will now present 2 the facilities description. :3 MR. CHATTERTON: Thank you, Don. Ron? ·4 MR. BEACH: My name is L. Ron Beach, and I am 5 the Lisburne Facilities Planning Engineering Supervisor 6 responsible to ARCO Alaska for the integrity and workability 7 of the Lisburne production facilities.. 8 I am a 1974 graduate of the Colorado School of Mines 9 with a bachelor of science degree in chemical and petroleum 10 refining engineering. I have been involved in the design, 11 construction, maintenance or operation of hydrocarbon processing 12 facilities for the past ten years. 13 I have been an emloyee of Atlantic Richfield since 1980 14 whereupon I was first a senior process design engineer for coal 15 gasification and synthetic fuel systems. AFter that, i was 16 a project manager responsible for designing and constructing 17 oil and gas processing facilities, both on platforms in the 18 Gulf of Mexico and on land. Presently, I am the Facilities 19 Planning Engineering Supervisor for the Lisburne project. 20 MR. CHATTERTON: Ron, the Commission finds you 21 qualified to testify as an expert witness. 22 MR. BEACH: My testimony today will include 23 a description of the Lisburne facilities. 24 The Lisburne development area is located within the 25 Prudhoe Bay unit northeast of the Trans Alaska Pipeline System R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVb..NUb.. 272 7515 ,{ -25- 1 Pump station Number One. The develoment will have five onshore 2 9rill sites, one offshore drilling island, one jpad for gas ;3 injection only, one Lisburne production center, interconnecting 4 roads and flowlines and a six-mile 16-inch diameter oil sales 5 line from the LPC to TAPS Pump Station One as shown in Exhibit 1 2. 6 The development plan for the onshore drill sites includes 7 four drill sites skirting the shoreline of Prudhoe Bay with 8 a fifth drill site some three miles inland to the southeast 9 near the west bank of the Sag River. the five drill sites are 10 L1, L2, L3, L4, and L5. Drill site L1 will have slots for 32 11 wells, while lthe remaining onshore drill sites will each contain 12 slots for 36 wells in two rows on 60-foot centers. From the 13 wellhead, production flowlines are connected to three-phase, 14 oil, gas and water, production and test headers, one production 15 and one test header per row of wells as shown in Exhibit 13. 16 The two production headers are joined outside the drill site 17 module just upstream of the drill site emergency shut down valves 18 as are the two test headers. The production header and the 19 test header are then routed to separate coils in an indirect- 20 fired drill site heater where the fluids are heated to 1400 21 Fahrenheit to improve the flow characteristics between the drill 22 site and the LPC. All external lines between the individual 23 well wing valves and the heater inlet flanges will be insulated. 24 The great majority of Lisburne production wells are 25 expected to be naturally-flowing. Should some wells require R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3HD AVENUl 272 7515 -26- 1 artificial lift, high pressure gas is available at the drill 2 sites. Headers, laterals and chokes for gas lift will be 3 installed as necessary. 4 All well control and testing functions at the drill 5 sites will be performed manually buy a drill site operator with 6 the exception of the well safety shut-in systems, which are 7 automatic, and the drill site emergency shut down system which 8 can either be triggered manually or automatically by certain 9 out of limit conditions. 10 Data gathering at the drill site will be both a manual 11 and automatic function. The Lisburne data gathering system 12 will continuously monitor the flowing status, pressures, and 13 temperatures of the producing wells at the drill sites. This 14 data will be under a drill site operator's supervison via his 15 monitoring station within the drill site module. Wells on test 16 will have continuous monitoring of pressures, temperatures and 17 flows off each leg of the test seperator. 18 The rate of production from each well will be regulated 19 by manually adjusted chokes. Normally the flow from the wells 20 is routed to the production header and advances to the LPC for 21 processing. Any individual well may be routed to the test header 22 by manual operation of divert valves at a manifold skid located 23 near the wellhead. Usually, only one well will be on test at 24 each drill site at any given time. 25 The sixth drilling location is the -- in the Lisburne R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 w. 31~D AVENUE 2727515 -27- 1 development area is a proposed gravel island within the confines 2 of Prudhoe Bay, approximately 13,000 feet offshore and conected 3 to the shoreline by a gravel causeway as depicted in Exhibit 4 12. While the processing scheme for the production from this 5 location is the same as that for the five onshore drill sites 6 previously described, some significant differences exist which 7 are enumerated. 8 First, there are slots for 40 wells on the island, of 9 which 32 are to be producers and eight are gas injectors similar 10 to those on the Lisburne gas injection pad which will be described 11 later. These wells are in two rows as onshore, but on ten-foot 12 centers to minimize island size. this closer wellhead spacing 13 was chosen to minimize potential environmental impacts at this 14 location and to reduce investment. 15 To prevent degradation of the island structure due to 16 wave and/or ice action, partial slope protection may be installed 17 at the time of the island's construction. 18 The proposed causeway to shore will not be slope protected, 19 but will be built with a one to seven vertical to horizontal 20 slope as this is a more cost effective approach for this two 21 and a half mile long structure. The production line from the 22 island, the gas injection line to the island and the power cable 23 to the island will be buried in the causeway to prevent damage 24 by any natural or accidental occurrence. 25 The produced gas in excess of that consumed as fuel R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVE-NUl::. 272 7515 -28- 1 will be reinjected into the Lisburne gas cap. This accomplished 2 at drill site L6 located offshore in the northern pjart of the 3 reservoir as well as from the onshore pad drill site LGI. Two 4 gas injectoin locations are required in order to distribute 5 the injected gas over the entire gas cap. 6 Due to the proximity of the Lisburne development area 7 to the existing Permo-Triassic facilities, the maximum jpractical 8 use will be made of the existing roads and pipeline lconstruction 9 pads. new access roads and pipeline construction pads will 10 only be built in those areas where new pipeline right-of-ways 11 are being established. All roads and pads will be constructed 12 from locally mined gravel. 13 Production flows to the LPC from the drill sites through 14 a system of partially trunked flowlines as {sic} also shown 15 in Exhibit 12. 16 The reinjection gas line to L6 and uses the same pipeline 17 route as the flowlines from L1. Drill sites L1, two, and L6 18 take fuel gas off this line. The reinjection gas line branches 19 at drill site L1 before going into the causeway or on to LGI. 20 As with production lines, either branch can be shut in without 21 affecting the flow of gas to the second destination. Should 22 down dip injection be necessary, provisions have been made to 23 allow for this injection at each of the drill sites with some 24 facility modification. 25 The Lisburne development requires the installation of R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3f~D AVENUE 272 7515 -29- 1 an independent production facility since the existing Permo- 2 Triassic flow stations lack the capacity to handle in the near 3 term all the oil and gas currently planned to be produced from 4 the Lisburne Reservoir. The plot plan of the Lisburne production 5 center is shown in Exhibit 14. 6 The Lisburne production center separates the crude feed 7 stream into oil, gas, and water as depicted in Exhibit 15, the 8 overall process flow diagram. Nominal design rates for the 9 LPC are 100,000 barrels per day of oil, 10,000 barrels per day 10 of water, and 600 million standard cubic feet per day of natural 11 gas. The crude oil is processed to TAPS specifications 12 (Indiscernible, whispered conversation) 13 MR. BEACH: Okay. 14 UNIDENTIFIED: The slide won't drop. 15 MR. CHATTERTON: Minor technical difficulty, 16 MR. BEACH: Yeah. 17 MR. CHATTERTON: don't worry. That looks 18 right side up. 19 MR. BEACH: Okay. This is the plot plan for 20 the LPC, and the next slide then is the process flow diagram 21 that's currently being described. 22 The crude oil then is processed to TAPS specification 23 and pumped to the pipeline while the gas and produced water 24 are separated and reinjected into the Lisburne and Tertiary 25 or Credaceous sands. The crude feed streams enter the LPC and R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272 7515 1 2 :3 4 5 6 7 8 9 10 11 12 ( 13 14 15 16 17 -30- are minfolded into a single header. The crude proceeds to the high pressure separator. Free gas and water are separated in this vessel. Oil then flows to the interstage crude heater where its temperature is raised. Liberated gas is separated and the oil is gravity fed to a pair of electrostatic treaters where it is dewatered to the TAPS specification. The separated water is combined with the free water from the high pressure separator and pumped into a disposal well located at the LPC pad. Oil from the treaters is then further flashed and the remaining solution gas is liberated. The oil is cooled, metered and pumped to TAPS Pump Station Number One. The gas is compressed and dehyrated by contact with triethylene glycol to a water dew point of minus 40° Fahrenheit at 500 pounds per square inch gauge. The gas is compressed to injection pressure in two trains, each train using a gas turbine driven centrifigal compressor systems. The first stage of compression raises the gas pressure to approximately 1500 18 pounds per square inch gauge at which point 10% of the stream 19 is removed for use as plant fuel. The remaining gas then proceeds 20 to the second stage of compression which increases the pressure 21 to 4700 pounds per square inch gauge and routing into the gas 22 reinjection pipeline. 23 Five horizontal process safety flare tips, three high 24 pressure and two low pressure, will be installed at the flare 25 pit to the north of the LPC. Because the flare volumes will R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3fW AVF._NUl:. 272 7515 -31- 1 not exceed exceed pilot and purge gas quantities of one million 2 cubic feet per day other than in cases of emergency or operational 3 necessity, the flare is not designed for smokeless operation. 4 The three high pressure flar tips are identidal, and each is 5 capable of handling 50% of the high pressure relief. Each low 6 pressure flare tip is capable of handling 100% of the low pressurE 7 relief. Interconnecting piping and sufficient spacing will 8 be provided to allow the isolation of anyone high pressure 9 or low pressure tip so that it can be taken out of service without 10 compromising plant safety. 11 The automatic gas detection system at all Lisburne 12 facilities will include hydrogen sulfide monitoring due to the 13 presence of the substance in parts of the reservoir. This system 14 provides a safe and efficient means of dealing with the presence 15 of H2S. The Lisburne production center design criteria for 16 H2S has considered all relevant industry, state, local, and 17 federal regulations, and has incorporated industry experience 18 and good engineering practice to ensure personnel, environmental, 19 and equipment safety. 20 As with other North Slope facilities, the Lisburne 21 production center will be provided with a fire and gas safety 22 system including automatic hydrocarbon dgas detection, halon 23 deluge system and a firewater system. Fire and gas alarms will 24 trigger operator response for initiation of the emergency shut 25 down system. R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 2727515 -32- 1 The Lisburne production center utilities include 2 circulating process heating and cooling Isystems, a fourteen 3 megawatt power plant with appropriate spare capacity, a plant 4 and instrument air system, a heating and ventilating system, 5 and direct fired heaters for utility, life support and back- 6 up process heat. Other support facilities, which include a 7 data acquisition system that will be linked by microwave to 8 the Prudhoe Bay Unit communications center, local and central 9 control rooms, maintenance facilities, and warehousing space. 10 Major maintenance shops are currently planned to be shared with 11 the existing Prudhoe Bay Unit facilities. Living quarters will 12 be built in the proximity of the existing Prudhoe Bay operations 13 center. 14 These facilities will require between 80 and 100 North 15 Slope assigned personnel per shift, or approximately 180 people 16 total, for operation, maintenance, and on-site engineering. 17 These numers do not include drilling or workover rig crews, 18 contract maintenance personnel, consruction crews, or Anchorage 19 based staff support. 20 This concludes my testimony today regarding Lisburne 21 facilities. Don Chancey will now discuss well operations. 22 MR. CHATTERTON: Thank you very much. Don, 23 if you would like to proceed again? You've been sworn in. 24 MR. CHANCEY: My testimony today will touch 25 on two topics. First, I will describe our typical well design R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3Fm AVENUL 272 7515 -33- 1 and the alternatives for well completions that are being 2 investigated. Then I will present our field wide reservoir 3 surveillance plans. 4 Exhibit 16 is a simplified wellbore diagram which 5 illustrates the design of a typical Lisburne completion. We 6 have selected a seven-inch, L-80 production liner. You will 7 noitce we plan to run two and seven-eighths inch or three and 8 one-half inch tubing with five or six gas lift mandrels supplied 9 with dummy valves. This completion scheme will give us the 10 freedom to artificially lift if it becomes necessary. The number 11 of mandrels will provide the flexibility needed due to 12 fluctuations in gas lift supply pressure, well productivity, 13 and produced water/oil ratio. 14 Paraffin deposition has been seen in tubing and flowlines 15 during the two-month tests of several Lisburne wells. Several 16 alternatives are under consideration for controlling this paraffiL 17 deposition. The method which we currently plan to employ will 18 call for injection of chemical inhibitors through downhold valves 19 installed in the tubing. Other possibilities that continue 20 to be investigated are insulated tubing to maintain the 21 temperature of the fluid stream above the wax crystallization 22 point, gelled packer fluids, and periodic tubing washes washes 23 with hot oil or praffin solvents to remove wax deposits that 24 form despite preventative measures. 25 In the interest of operating the Lisburne Reservoir R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272 7515 -34- 1 in a similar manner as other Prudhoe Bay Unit reservoirs, 2 :3 subsurface safety valves will be installed in all wells capable 4 of natural flow. 5 Drillstem testing has indicated that the unstimulated 6 Lisburne flow capacity is low, and in fact the Lisburne intervals 7 will often not flow prior to some form of stimulation. The 8 testing demonstrated that the reservoir was tight with an average 9 unstimulated permeability of less than two millidarcies. 10 One explanation for the low unstimulated flow capacity 11 is formation damage during drilling operations. This hypothesis 12 is supported by the severe fluid loss observed in two wells 13 when initially drilling the reservoir and after acidization. 14 What we have seen prior to well stimulation is essentially a 15 matrix only response. Comparing the permeabilities both before 16 and after stimulation indicates that there is a ten to 20 fold 17 improvement in conductivity between purely matrix flow and 18 composite fracture and matrix flow in the Lisburne Reservoir. 19 A second explanation for flow imrovement is that the 20 acid cleans up the partically calcite filled fractures. 21 Therefore, in our efforts to improve Lisburne flow 22 efficiencies, we are looking into three areas of well completion. 23 These areas are drilling fluids, stimulation methods, and 24 alternate completions, each of which will be discussed below. 25 In attempting to minimize skin damage from drilling, R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272 7515 -35- 1 and to improve our ability to interpret open hole logs, various 2 types of mud systems, including oil base, salt water basae, 3 and fresh water base systems, have been tried. No decision 4 on optimum mud system has been made, but we plan to continue 5 trying different mud systems to evaluate the effedt they have 6 on drilling and producing Lisburne wells. 7 We are in a very early stage of defining the most 8 effective stimulation method. Our approach is designed to provide 9 maximum flexibility. We will acidize, test the zone with regard 10 to productivity, and possibly perform an acid fracture on the 11 or a propped fracture treatment. 12 Alternative completion designs may offer opportunities 13 to minimize flow obstructions around the wellbore. One of the 14 configuraions that merits study is open hole completions. 15 Although no open hole completions have been performed in the 16 Lisburne wells to date, the method has been successfully employed 17 worldwide in other carbonate reservoirs and in sandstone 18 reservoirs on the North Slope. Several open hole tests have 19 been performed in the lisburne Reservoir. No excessive formation 20 sloughing was observed during these tests, nor were problems 21 setting pipe experienced following the test. Therefore, we 22 do not anticipate any problems with open -- with hole sloughing 23 in an extended production period using open hole completions. 24 With a naturally fractured reservoir, it may be 25 appropriate to only perforate the bottom of the commercial oil R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W, 3f"D AVENUI:. 2727515 -36- 2 zone in producing wells. This will minimize gas coning and cycling if gas gravity drainage is a dominate reservoir drive mechanism. It might also eliminate the need for a costly :3 4 workover program to remove performatoins producing predominantly 5 gas. 6 Other completion schemes such as lateral drainholes 7 may be worth testing during the development of the Lisburne 8 Reservoir as another means of overcoming the low well flow 9 efficiencies encountered thus far. 10 As has been noted earlier, data will be required to 11 monitor reservoir performance, define reservoir properties, 12 and provide the basis for effective reservoir management. I 13 will now outline our plan to -- for obtaining this data. This 14 information is categorized into two areas. The areas are bottom- 15 hole pressure measurements, and well testing. 16 For prudent reservoir management, it will be important 17 to maintain an updated isobar map of bottom-hole pressures. 18 These pressures will be reported at the common subsea datum 19 elevatoin of 8,900 feet. 20 An initial static reservoir pressure will be measured 21 on each well prior to significant production. This will be 22 done by either a pressure build-up test or by simply measuring 23 the bottom hole pressure after the well has been shut-in for 24 an extended period. The initial static pressure surveys will 25 be used to update the pressure isobar map using the development R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RO AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 31"0 AVENUE 272 7515 -37- 1 -- during the development drilling program. Because of the 2 extended pressure buildup periods required to obtain accurate 3 pressure measurements, for economic reasons, we would prefer 4 flexibility in obtaining follow-up pressures. At least one 5 well per drill site will have a representative pressure taken 6 annually following field start-up. The pressure surveys will 7 be filed with the Commission annually. 8 A critical aspect of any reservoir surveillance nad 9 management program is accurate production data. Production 10 volumes from each well will be measured on a semi-annual basis 11 under normal operating conditions for a minimum four-hour period. 12 Four-hour test periods have proven sufficient in other reservoirs 13 with similar well rates to give representative data. The test 14 will determine oil, gas, water rates, oil gravity, oil basic 15 sediment and water conten"t, and flowing temperature and pressure 16 at the choke. More frequent tests will be talken as required 17 for proper production allocation between wells and prudent 18 reservoir surveillance nad operational decisions. The test 19 results will be filed with the Commission semi-annually. 20 Some production logs will be run in selected Lisburne 21 wells, and this data will be provided to the Commission. However, 22 surveys will not be run on a routine basis in all wells, because 23 it is doubtful they will be of technical value in performing 24 in performance monitoring of this reservoir. Since the 25 Lisburne is a naturally fractured reservoir, production surveys R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 w. 3RD AVE-NUL 272 7515 -38 - in the wellbore will not necessarily indicate the proper quantity 2 of fluid being produced from individual porous intervals within 3 the reservoir. In addition, we plan to hydraulically fracture 4 many of the Lisburne wells to increase productivity. The induced 5 fracture will obscure flow origin -- fluid origin and cause 6 uncertainty in any results derived from production logs. 7 Relatively low well production rates in the seven-inch liners 8 and free gas influx further complicates interpretation of 9 production logs. 10 Lots run to date have not been able to distinguish ga/oil 11 or oil/water contacts. The combination of low reservoir porosity 12 and low formation water salinity place the standard neutron 13 tools outside their design range for formation evaluation, and 14 therefore, cased hole neutrol logs will not be run on a routine 15 basis to monitor fluid contacts. Some experimental tools may 16 be run in selected Lisburne wells to evaluate our ability to 17 monitor fluid contacts and these logs will be provided to the 18 Commission. There are no cased hole logging tools available 19 today which have been shown to be able to monitor fluid contacts 20 under the Lisburne Reservoir conditions. We will continue to 21 evaluate new logging tools and analysis techniques as they evolve. 22 This concludes my testimony today. i would now like 23 to introduce Leland Tate, who will summarize our testimony. 24 MR. CHATTERTON: Thank you, Don. Leland, please? 25 MR. TATE: Mr. Chairman, members of the Alaska R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W, 3RD AVENUE 272 7515 1 2 a 4 5 6 7 8 9 10 11 12 ( 1:3 14 15 16 17 18 19 20 21 22 28 24 25 ¡~ -39- Oil and Gas Conservation Commission, ladies and gentlemen. My name is Leland Tate. I am vice president of engineering and extension exploratoin for ARCO Alaska, Inc. I received a bachelor of science degree in petroleum engineering from Texas Tech University in 1970. I've worked in Alaska for ARCO for the past nine years, and I have direct responsibility for the Lisburne design and field development. MR. CHATTERTON: Fine, Leland, we certainly find you qualified as an expert witness to testify here. MR. TATE: Thank you. As discussed today, ARCO and the other owners have been evaluating the Lisburne Reservoir for some time. The data and information gained to date has allowed the owners to commit the full field development of the Lisburne. However, even with this commitment, the parties still need to acquire additional data and information to optimize production techniques and to maximize oil recovery. The development of the Lisburne poses some unique problems. This reservoir has different geological characateristics from the other reservoirs discovered on the North Slope and will provide challenges to both the owners and the Commission. The owners are committed to a safe and environmentally sound operation. The facilties are designed to operate in a safe and efficient manner and provide built-in protection to -- to both our employees and the environment. The reservoir data programwill provide valuable R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 1007 W. 3F<D AVENUE 272 7515 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 -40- 1 information and data concerning the Lisburne for orderly and 2 efficient reservoir development. 3 And the drilling program will meet or exceed the 4 requirements noted in the Commission regulations and utilize 5 valuable information gained from pre- -- previous drilling 6 activities. 7 The development of the Lisburne Reservoir provides 8 opportunities for both the owners and the State of Alaska. 9 ARCO and the other owners look forward to meeting the development 10 challenges with you and bringing into production another major 11 field on the North Slope. 12 The three owners are currently lnegotiating to establish 13 a Lisburne participating area within the Prudhoe Bay Unit prior 14 to the start-up of full field production. We anticipate these 15 agreements will will be completed in early 1986. 16 We would like to thank you for the opportunity to -- 17 the opportunity to provide this testimony today and are now 18 available for -- to -- to address any comments or questions that 19 you might have. 20 MR. CHATTERTON: Thank you, Leland, very much. I 21 would say we will have several questions. I would say that this 22 would be an appropriate time to take a short break. We'll see 23 during the break -- period of the break, why, please if there are 24 any others that wish to testify, make any statements, oral or 25 written, why, if you will please let me know, fine, and don't R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE:. 272 7515 -41- 1 forget if you have questions of the testimony we've heard so far, 2 why, please alert Susie -- Lucy Chali. Lulubelle at the back of 3 the room. With that, why, we'll take a break and we're off the 4 record. 5 (Off record) 6 (On record) 7 MR. CHATTERTON: Thank you. If we may corne to 8 order again. Before we -- we do have a person that wishes to 9 make a testimony -- or -- or read something into the record. 10 Before we proceed to that that, Steve, if I can -- are we on the 11 record, and I forgot to ask that? 12 COURT REPORTER: (Nods affirmative.) 13 MR. CHATTERTON: Okay. We've reconvened after 14 a coffee break or something. 15 Steve, you -- you handed me a set of slides which are the 16 ones that we saw on -- projected during the direct testimony. 17 Do you wish to put those into the record? 18 MR. WILLIAMS: Yes, Mr. Chairman, We'd like to 19 move the adoption of those into the record by the Commission at 20 this time, please? 21 MR. CHATTERTON: Fine, sir. That -- that is so 22 ordered. 23 MR. WILLIAMS: Thank you. 24 MR. CHATTERTON: Mr. Ames, would you like to make 25 a statement, sir? R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 w. 3RD AVE'.NUE:. 272 7515 -42- ( 1 MR. AMES: Thank you. Mr. Chairman, members of 2 the Commission, ladies and gentlemen. My name is Carter S. Ames. 3 I'm an attorney with Exxon Company USA. 4 As a major working interest owner of the Lisburne 5 Reservoir development, Exxon fully supports the Lisburne field 6 rules testimony presented by ARCO at this hearing today. 7 We would also like to submit into the record a letter 8 confirming this statement. 9 MR. CHATTERTON: Fine. Thank you. We -- you 10 have that with you, Carter? 11 MR. AMES: Yes, I do. 12 MR. CHATTERTON: Okay. We will accept that and 1:3 -- into the record and thank you very much. 14 MR. AMES: Thank you. 15 MR. CHATTERTON: Okay. Are there any others that 16 wish to present any testimony, make any statements? And, Luci 17 Chali, at the back of the room, has anyone handed you any 18 questions? 19 MS. CHALI: No, I don't have any. 20 MR. CHATTERTON: Okay. It seems like we then may 21 have done all the formalities and we're down to where if the 22 Commission is smart enough, why, we might ask a few questions of 23 -- of the people that have testified here. And we'll start off, 24 Lonnie, would you like to start the questioning that we have? 25 MR. SMITH: Okay, Chat. I think my first question R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVE'-NUf:. 272 7515 -43- here is -- is for Don Chancey on page nine of the submitted 2 testimony. Don, at the bottom of the page there you mention 3 you stated the average porosity of 10%. Is this effective 4 porosity or a total porosity, that 10% porosity? 5 MR. CHANCEY: That would be total porosity. 6 MR. SMITH: Okay. And on the next page you spoke 7 about the the average water saturations of -- with a range of 8 20 to 40% within the developable oil column -- column. Is this 9 variance of 20 to 40% due mainly to the different methods used to 10 solve for the water saturations, or primarily dependent on the 11 porosity variations? 12 MR. CHANCEY: It's due to quite a few things, 13 Mr. Commissioner. It's due to height above a contact, porosity 14 variations, permeability variations, and the method used to 15 calculate. 16 MR. SMITH: Okay. So porosity variations were in 17 there also? 18 MR. CHANCEY: That's correct. l!) MR. SMITH: Okay. And in the next -- next 20 statement there on that page, under fluid properties, is the 21 reservoir temperature of 1830 Fahrenheit also at the 8900 subsea 22 datum? 24 MR. CHANCEY: Yes. MR. SMITH: Okay. MR. CHANCEY: That's correct. 2:~ 25 R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUI:. 272 7515 -44- 1 MR. SMITH: Okay. Don, on page 12 you spoke 2 about the modeling in the top paragraph there, and you -- did ;~ your model work consider any other spacing than the 160 and 320- 4 acre? And if so, what magnitude of recoveries were indicated? 5 MR. CHANCEY: That's the only two cases of field 6 spacing that we ran our model at is the 160 and the 320-acre. 7 And it did show an increase going to the 160-acre spacing. Q 8 Can you give me anything on the magnitude of increase or ...? 9 MR. CHANCEY: It was less than 5%. It was a 10 small change, but we deemed it to be significant. 11 MR. SMITH: Chet, I think that's all the questions 12 I have for Don. I can go into the section, or would you like to 13 interject some questions here on this earlier ......? 14 MR. CHATTERTON: Well, I'd just piggyback right 15 on the back of that one, if I may, Don. At some point in time as 16 you proceed and gain information on this reservoir and investigate 17 the potentials for any type of inhanced recovery, why, I presume 18 you would at that time probably maybe refine the advantage of 19 spacing, both ......? 20 MR. CHANCEY: That's correct. Well spacing is an 21 area which we will continue to study and refine as we get 22 additional data and we'll come back to the Commission when it 23 becomes appropriate to do so. 24 MR. CHATTERTON: Very fine. Very fine. No, why 25 don't you proceed, Lonnie, ..... R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 27275E5 !I 1 :2 :3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 -45- MR. SMITH: Okay. MR. CHATTERTON: if you wouldn't mind, and then we'll ...... MR. SMITH: Okay. Well, my next question is directed to Don Breeden. And, Don, on page 17 your remarks there about the drilling and setting the casing to -- for setting the 13-3/8ths casing as deep as 5,000 feet, do you anticipate penetrating any hydro- -- hydrocarbon bearing zones above 5,000? MR. BREEDEN: No, we do not. MR. SMITH: So the -- some of the sands, hydrocarbon bearing sands and -- that really have no name so far as I know, and then -- and then there's other like the Ugnu and West Sag, those don't appear over to the east portion here or you plan any ....... MR. BREEDEN: perhaps I could ..... MR. TATE: Lonnie, it might appropriate for Linda Okland to address your question. MR. SMITH: Okay. I'm sorry. Linda? MS. OKLAND: We have reviewed the shallower sediments in that area and we have not -- we've examined the logs and the mud logs available over the interval. We have not observed any indication of significant accumulations of 23 hydrocarbon. There is a very minor amount of methane that is 24 presumed to be biogenic. It's common in the Prudhoe Bay area. 25 It does not indicate any significant accumulation of hydrocarbon R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272 7515 -46- 1 in that interval. 2 MR. SMITH: Okay. 3 MR. CHATTERTON: May -- we're -- we're going to 4 need a little clarification here. I think we're maybe talking 5 about apples and oranges here. Your statement, Linda, does it 6 not apply only to that area of interest that was shown on exhibit 7 -- a map which is now known as Exhibit Nine which depicts 8 depicts about six drill sites, and maybe you're not referring to 9 the extreme westerly portion of -- that you wish the field rule 10 boundary to be expanded to include? 11 MS. OKLAND: Westerly or easterly? 12 MR. CHATTERTON: Westerly. 1:3 MS. OKLAND: We did examine the upholes throughout 14 the area where we planned development and including as far as 15 J-one. 16 MR. CHATTERTON: Your statement is is includinS 17 as far as J-one? 18 MR. TATE: Chat, I think your -- your -- your 19 analysis is correct. In the extreme far western age where but 20 where we are continuing to ask for -- for the field -- for the 21 area to be covered, we probably haven't looked at it all the way 22 over there. 23 MR. CHATTERTON: That -- that's what I ..... 24 MR. TATE: It's beyond our current development 25 boundary. R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 .. 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 31~D AVENUl 2727515 I{ -47- 1 MR. CHATTERTON: I'm trying to establish that I think that what Linda just said in response to Commissioner Smith's question was referring primarily to the area that has the SlX drill sites as depicted on Exhibit Nine? 2 :~ 4 5 MS. OKLAND: Primarily. That is correct. It 6 went a little bit beyond that boundary, but I think you're correct 7 in that it does not extend to the area you asked about. 8 MR. CHATTERTON: Okay. Thank you. Does that 9 help a little bit? 10 MR. SMITH: Yeah, that -- I was going to -- in 11 fact, in examination of the J-one log we see some of these things, 12 and that particular one is -- was our observational thing. 13 Well, to carry that a little bit further and whichever is 14 the most appropriate to answer the question, there -- there have 15 been some 27 wells drilled in this area and -- penetrating the 16 Lisburne, and, Don, I think you're the most appropriate one, has 17 there been a problem with the casing design used in those wells 18 and is it similar to what you're proposing here? 19 MR. BREEDEN: Lonnie, I'm not familiar with all 20 of those wells. I'm familiar with a few of them. There's been 21 a bit of a variety of casing programs. A lot of them have had a 22 liner set across the Lisburne, similar set-up as this. South Bay 23 State, we did set our surface casing a little deeper. That 24 particular well, with some other work we were doing on it, we 25 had 11-3/4 liner, nine and five-eighths intermediate string, and R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUEè 272 7515 -48- 1 then a seven-inch liner through the Lisburne. So there's been 2 quite a variety. There have been a few wells with surface pipe 3 set at this depth that we propose. 4 MR. SMITH: Well, you have indicated that the 5 primary reason for increasing the surface string setting depth 6 was to provide added kick tolerance. Has there been a particular 7 problem with the drilling in some of the other wells in the way 8 they were cased or drilled? 9 MR. BREEDEN: No, there hasn't. 10 MR. TATE: Lonnie, may I ..... 11 MR. SMITH: Yes. 12 MR. TATE: interject a thought here? I 13 think what -- what you're seeing in this casing program is an 14 optimization on -- on most of those 27 wells we're talking about. 15 What we're doing is we're setting the casing deeper in order to 16 protect against drilling through the Sadlerochit Res- -- the 17 the Sadlerochit, which you know is gas -- gas saturated in most 18 of the intervals we're going to be drilling here, so it's just 19 an added degree of protection while we drill through that more 20 than anything else. The casing plus close monitoring of the -- 21 the mud systems, weight and other properties give us a better 22 comfort margin if you will to be able to handle any kind of 23 problem that we might encounter. 24 Is -- is that fair, Don? 25 MR. BREEDEN: Yes. R & R COURT REPORTERS 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 w. 3RD AVENUI:. 2727515 -49- MR. TATE: Okay. 2 MR. SMITH: Do you have any other question on :3 that part? 4 MR. CHATTERTON: I will when I get my turn. 5 MR. SMITH: Well, I'll go on to -- let's see here. 6 On page 20, Don, you mention the possible need to utilize grade 7 G-105 and S-135 drill pipe in certain cases. How does the yield 8 strength of these grades of drill pipe differ from the recommendeë 9 grade in the API recommended practices 49 publication? 10 MR. BREEDEN: RP-49 recommends that grades with 11 yield strengths of 90,000 -- 95,000 psi or less be used in a 12 hydrogen sulfide environment. 105, of course, has a 105,000 psi 13 yield strength. API RP7G provides with reference to some other 14 specifications as well as in Section Eight, means of controlling 15 the environment that drill pipe is used in or that its use is 16 acceptable. 17 MR. SMITH: Okay. Well, what are some of the 18 things outlined in Section Eight of RP7G that -- that you consider 19 the guidelines to be used as a minimum that you consider 20 appropriate? Do you plan to start off using them when you're 21 using drill pipe like this or what ......? 22 MR. BREEDEN: Yes, in the area where we are 23 expecting H2S. A couple of the precautions that are normally or 24 routinely taken, maintaining mud weight to avoid a kick, and 25 minimize gas cutting in mud system. Another one indicates water R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUI::. 272 7515 -50- 1 based mud is to maintain a high pH to more or less neutralize the 2 H2S in the drilling mud and somewhat in the formation, in your 3 well bore. Also oil based muds are effective, oil wet steel 4 is not susceptible to sulfide stress cracking. 7 Yeah, I understand. Page 26 is my MR. SMITH: MR. BREEDEN: MR. SMITH: Okay. Thank you. ;) 6 There are some other 8 next question for -- I think that's Don Beach. This is just a 9 little clarification point I think. In the second paragraph there 10 you state while the gas and produced water are separated and 11 reinjected into the Lisburne and Tertiary or Cretaceous sands. 12 will you clarify where each is to be injected? 1:3 MR. BEACH: I -- again, I'm going to defer that 14 one to a more appropriate person here and I think we actually may 15 have two different answers for you depending on the gas and the 16 water. So, Linda, if you would take a crack at -- at the water, 17 and, Don, I'll ask you to ~- to -- to talk about the gas 18 reinjection. 19 MR. CHANCEY: Well, the -- the water will be 20 reinjected into the Tertiary and Cretaceous sands initially. 21 If it -- we so deem that it's appropriate to put the water back 22 into the Lisburne, we'll come back to the Commission and ask for 23 the necessary type of work to be done to -- for a secondary 24 recovery project if -- in the event we went to a waterflood. 25 The gas will be reinjected into the Lisburne. R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AV~_NUI.:. 272 7515 -51- 1 MR. SMITH: Okay. And along this same line -- 2 well, I think it's actually on page 25 where it comes up, or where 3 it carne to mind. Going backwards here a minute. Would you tell 4 us why you're reinjecting the gas on the offshore island rather 5 than on one of the onshore locations? 6 MR. CHANCEY: I would also like to answer that one, 7 Mr. Commissioner. 8 MR. SMITH: Okay, Don. 9 MR. CHANCEY: Our present understanding of the 10 areal extent of the Lisburne gas cap includes an area both onshore 11 and offshore. And we believe at this point that it is -- will be 12 necessary to inject gas into a large area of the gas cap, which ( 13 will mean that we will start onshore but soon move to include 14 also offshore injection of gas to hit all of the gas cap. 15 MR. SMITH: And again I'll go backwards again. 16 I skipped a couple of my on page 23, Don, you spoke about the 17 well test system and the facilities there. Would you elaborate a 18 little bit about the testing facilities? How many are available, 19 how it's done and .....? 20 MR. BEACH: Okay. Briefly, what you have is a 21 test system at each drill site. 22 MR. SMITH: So that's six of them. 23 MR. BEACH: Yeah, so you have six of those in this 24 initial development area. So you have six of those sytems, one 25 at each -- one at each drill site. Now, any individual well can R &. R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVI::NUc._ 272 7515 -52- 1 be routed into the test system and tested for whatever length of 2 time is appropriate to test that well, and we've set some minimum~. :3 MR. SMITH: Okay. That's -- how are the -- the 4 oil, gas and water -- are they metered at that point or is it a 5 reading from a tank or what kind of .....? 6 MR. BEACH: Yeah. What we have there is a three- 7 phase separator, the test separator and the three-phase separator, 8 the oil, water and the gas, each leg of the three-phase separator 9 being metered independently. Those metered coolants then are -- 10 are logged continuously during the duration of the test. 11 MR. SMITH: Okay. Do you know yet what kind of 12 meters will be used, for instance, for the oil? 1:~ MR. BEACH: Well, we're anticipating that we'll 14 use turbine meters for the -- the gas and -- I'm sorry, turbine 15 meters 16 Danyer 17 gas. 18 for the oil, and, for -- for instance, a Daniel (ph) senior orifice meter for the -~ for the -- for the MR. SMITH: Okay. If you'll bear .with me a 19 second, I've about lost my place here switching back and forth. 20 On page 27, Don, you concerning the automatic gas detection 21 system, with respect to the H2S monitoring and -- and design 22 criteria, did you also consider and do you plan to adhere to 23 API RP-55, that is, American Petroleum Institute Recommended 24 Practices Number 55, for conducting oil and gas production 25 operations involving hydrogen sulfide? R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AVE.NUl::. 2727515 -53- 1 MR. BEACH: Yes, as a matter of fact a complete 2 list of all the things that we've been -- that we considered in 3 corning up with our H2S criteria, I don't have one prepared, but 4 -- with us, but we do have that. One of those criteria was the 5 one you've referenced. 6 MR. SMITH: Okay. Let me see, my next question 7 was for Dan Chancey I think on page 30. Don, the -- I understand 8 the reason you need chemical inhibitors in the -- and -- and that 9 you you've shown the valve in the tubing string there, but 10 please explain to me the operation of injection of chemical 11 inhibitors through downhole valves installed in the tubing? Just 12 how is this accomplished? 13 MR. CHATTERTON: With gas lift? 14 MR. SMITH: Especially with gas lift involved 15 and. . . . . 16 MR. CHANCEY: Okay. Let me answer -- answer your 17 fir- -- second question I think. If we have a well on gas lift, 18 that probably will not require this kind of service, because the 19 gas is going to be warm and we do not expect the problem, so we 20 planned thi s this method with the well not on gas lift. 21 MR. SMITH: 22 string that ...... 2:3 MR. BREEDEN: 24 MR. SMITH: 25 Okay. Okay. And even then is there another Perhaps I could help there. Do you just inject down the anulus? R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W, 3RD AVE-NUl 2727515 -54- 1 MR. BREEDEN: We'll have a -- for this particular 2 paraffin inhibitor, we'll have an injection valve just below the 3 safety valve with a separate small diameter 4 MR. SMITH: Okay. 5 MR. BREEDEN: ...... control line type line. 6 MR. SMITH: Okay. Okay. On page 34, Don, about 7 the -- with regard to the pressure surveys, the initial static 8 survey there, please explain what you consider to be an extended 9 period for a shut-in bottomhole pressure measurement, and -- or 10 can you define the term "extended period"? 11 MR. CHANCEY: At present I cannot define the term 12 "extended period". As you know, we have taken several extended 13 pressure buildups during the two-month phase -- two-month 14 production test phase of our evaluation, and these have extended 15 for greater than 30 days. We do expect that when the field is 16 -- we will have to evaluate that as we begin gathering data to 17 see what is an appropriate time period. 18 MR. SMITH: So really your proposal here is not 19 specific as to -- as to the type of -- of pressure test or -- or 20 how it's to be conducted at this time? 21 MR. CHANCEY: That's correct. 22 MR. SMITH: Well, I'm having to by-pass some of 23 my questions here. Well, I might ask you, will follow up 24 pressures after the well the field comes on production, will 25 follow-up pressure tests in your opinion be more or less important R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 . 277-0573 509 W. 3RD AVENUE 277·8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVE'. NUc. 272 7515 -55- 1 than the initial pressures? 2 MR. CHANCEY: Our program at this point is 3 centered around the initial pressures of -- of the wells. I woule 4 like to point out that we will continue a drilling program after 5 the field starts up, so we will continue to be getting initial 6 pressures throughout the field from the new wells which are 7 drilled after the field starts up, and we believe this is a very 8 important part of the pressure monitoring program we're presenting. 9 MR. SMITH: Okay. And that'll continue through -- 10 will that redrilling phase in -- with new fresh initial pressures 11 carry you through the implementation of VOR? Do you anticipate 12 that? 13 MR. CHANCEY: We don't know exactly when we will 14 be able to commit to VOR or secondary recovery at this time. We 15 estimate that we will have enough data from the field either 16 through full field production or various production tests to be 17 able to evaluate secondary recovery within a couple of years 18 after the start up of full field. We do plan at this time to 19 have an active drilling program for at least two years after full 20 field start up. 21 MR. SMITH: Okay. You recommended a minimum of 22 one pressure per -- pressure test per drill site, which -- per 23 year, which is six tests per year. And that's, of course, the 24 way I understand it, in addition to the initial pressures that 25 you'll be gaining while you're drilling wells. If you just got R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 31~D AVENUe. 272 7515 1 2 :3 4 5 6 7 8 9 10 11 12 ( 13 14 15 16 17 18 -56- when it gets down to the point of where it's just -- there are no initial new wells being drilled and it -- do you think six pressure tests from this reservoir in this large of an area is would really be adequate? MR. CHANCEY: At first, yes, we -- we will be taking more than six tests during the drilling program. Your statement is correct. But after several years of taking this kind of data, I believe we'll be in lot better position to be able to answer your appropriate questions as to how long the test period should be and how many tests will become necessary, because we will begin to get trends as to what -- how the reservoir is performing under as the field begins to produce, and these thus, we'll be able to better address these questions as the drilling program begins to tail off. MR. SMITH: Well, I -- I agree that initially six are enough. I think reconsideration of the program later is the -- the real key to it. MR. TATE: Lonnie, I might add -- Leland -- 19 Leland Tate. The six that are there are -- are the minimum 20 that we'll take. I -- I feel almost certain that -- that there 21 will be substantially more tests than that run during that time 22 period just for for other reservoir purposes, so -- the 23 problem we have is interpreting pressure build-ups and 24 extrapolating that into the -- to the absolute reservoir pressure. 25 And as we get more experience, we -- we probably will know more R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W, 3RD AVE-NUl_ 272 7515 -57- 1 about how to answer your question better as far as how many are 2 actually required. ;3 MR. SMITH: Okay. Don, with regard to the well 4 testing paragraph there, I'd already asked Don Beach about the 5 well test equipment, please elaborate on the minimum number of 6 well tests your design permits for accurate determination of that 7 oil, water and gas? 8 MR. CHANCEY: We'll be submitting a minimum of 9 one test every six months to the Commission: We'll be taking 10 several more tests in that six-month period per well for our own 11 understanding of the reservoir mechanisms. We .... 12 MR. SMITH: And, well, you mentioned the -- only 13 -- you -- only using -- basing the test on a four-hour time 14 interval and that being adequate. What justification do you have 15 of that being an adequate test from this reservoir? 16 MR. CHANCEY: We believe four hours under normal 17 operations in other words, the test may last longer than four 18 hours, but we require that that four hours be representative of 19 that well, and the precedent has been set by the other reservoir 20 which is in the Prudhoe Bay Unit also for four~hour tests. 21 MR. SMITH: Well, I'm -- I'm a little concerned 22 that you're -- you have designed around a four-hour test and then 23 we'll get all of these two or 300 wells out there and you can't 24 test them but four hours or less, and -- and you might need more. 25 What provision is there for -- for that situation, where you need R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 w. 3RD AVl:.NUl:. 272 7515 7 8 9 10 11 12 ( 13 14 15 16 17 18 19 20 21 22 23 24 25 -58- 1 a longer test and -- have you -- have you -- do you have more 2 equipment in and time available than you'll be utilizing or . .... ;3 MR. CHANCEY: Yes, we do. 4 MR. SMITH: ..... at what point will that be a 5 push? 6 MR. CHANCEY: It -- I do not believe that that that that case will occur, Mr. Commissioner, because with one test separator per pad, we will have a lot of time for tests in excess of four hours, and we will have time for more than one test every six months, and we will be utilizing those test facilities extensively, so we'll be taking far more than -- than just that minimum number of -- of tests, and it -- it will be in our best interest to do so. MR. SMITH: Well, since oil production reporting and allocation is necessary on a monthly basis, why shouldn't well tests be verified by a new test each month? Why semi- annually? MR. TATE: Don, may I -- may I help? Lonnie, the system -- the system that's been designed here is very similar to the Prudhoe Bay system, and the -- the reporting semi-annual is -- is just a normal GOR test that we would report to the Commission. With 30 wells per well site, even if you took a 24- hour test on each well each day, you'd get every well tested every month, and in fact we'll probably test, if we use four-hour tests, then you'd test what, all the wells four times every month R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 1007 W 3RD AV!:.NUE:. 272 7515 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 -59- 1 or six times every month, whatever it would be. Actually what 2 we're doing is we're running -- we're putting the wells in the 3 test separator, allowing them to stabilize, and using then four 4 or six or eight, whatever period of time is -- is appropriate, we 5 think four is okay, to -- to get a stabilized production rate off 6 of that well and then -- and then we're using that number to 7 allocate production. And we may have three or four or five of 8 those tests during a month on -- on a well if it's changing, 9 particularly in flow characteristic, to allocate that production. 10 It's been been very successful in our other operations. As -- as 11 you probably remember, early on we had some problem with the 12 allocation factors, that is, test to production, but now they run 13 more than 99% most of the time in a production test. So we 14 think wi th with one test separator per 30 wells, we'll be able 15 to be very accurate with our testing and with our allocation 16 system. 17 MR. SMITH: Okay. Thank you. That's -- that's 18 all I have right now. 19 MR. CHATTERTON: Have you got any more ...... 20 MR. SMITH: I've got ..... 21 MR. CHATTERTON: ..... through there or .....? 22 MR. SMITH: I've been through it. 23 MR. CHATTERTON: You're -- you're through? 24, MR. SMITH: Yeah. Unless I think of something 25 while you're doing it. R & R COURT REPORTERS 1 810 N STREET SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3fW AVENUI:::. 2727515 -60- 1 MR. CHATTERTON: Okay. Real fine. Thank you. 2 Linda, you thought you were going to get off, didn't you? 3 Well, I'll follow the same format that Commissioner Smith did 4 and -- and try and run through the prefiled testimony and ask my 5 questions. And, Linda, you were the first to testify, so you're 6 the first place where I may have a -- some questions. 7 One is on page four, in the third paragraph, you referred 8 to the Lisburne -- you state, "The Lisburne Reservoir is bounded 9 on the north by the Prudhoe Bay fault." I always have problems 10 with nomenclature. Have you ever heard of a Nyakuk (ph) Fault? 11 MS. OKLAND: We don't use that terminology 12 in-house. We call it the Prudhoe Bay Fault. It -- I have been ( 13 informed that other companies call it that. 14 MR. CHATTERTON: It's.... 15 MS. OKLAND: I do not know, 16 MR. CHATTERTON: ..... It's the same ..... 17 MS. OKLAND: ..... first hand what they refer 18 to..... 19 MR. CHATTERTON: Would you ..... 20 MS. OKLAND: ...... when they use that term. 21 MR. CHATTERTON: ..... think from what -- your 22 knowledge, do you believe it's the same structural feature? 23 MS. OKLAND: It's a major north -- east/west 24 trending fault complex. It is not a single fault. What we call 25 the Prudhoe Bay Fault is not one fault. I do not know if their R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572. .. 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3Fm AVENUE 272 7515 -61- usage is identical to ours, but it certainly applies to at least 2 some portion of that complex. :3 MR. CHATTERTON: It's generally speaking -- your 4 Prudhoe Bay Fault is generally speaking a high displacement fault 5 striking east -- west and east, north of your Phase One 6 development area? 7 MS. OKLAND: That is correct. 8 MR. CHATTERTON: Okay. Very good. All right. 9 And it extends easterly from your Phase One development area, 10 the the Prudhoe Bay Fault as 11 MS. OKLAND: It extends beyond ..... 12 MR. CHATTERTON: you define it? 1:3 MS. OKLAND: ..... our development area, yes. 14 MR. CHATTERTON: Thank you. You further state in 15 that same sentence that the Lisburne Reservoir is bounded on the 16 northeast by a major cretaceous unconformity. Is that bounding 17 due solely to an unconformity, or is it possible that there might 18 be some structural feature that might control it, like a fault, 19 as the Prudhoe Bay Fault does to -- as you say, to the north? 20 MS. OKLAND: Within our development area, we are 21 really only dealing with the unconformity. There is a -- the 22 Nicholson Fault, of course, cuts the Lisburne further to the east. 23 That's beyond our development area. 24 MR. CHATTERTON: And this Nicholson Fault that 25 you -- Nicholson Fault or Nicholson Bay Fault, whichever, it's R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVI".NUI:. 272 7515 -62- 1 basically a northwest/southeast trending or striking fault with 2 major displacement? a MS. OKLAND: Yes, I believe it's -- well, perhaps 4 not. Is it shown on the structure map? It doesn't go that far. 5 MR. CHATTERTON: It doesn't show -- yes, it does. 6 It shows .... 7 MS. OKLAND: Okay. It doesn't go -- yes, it does. 8 MR. CHATTERTON: on your 9 MS. OKLAND: It -- it is on there. 10 MR. CHATTERTON: ..... Exhibit Two 11 MS. OKLAND: Exhibit Four. 12 MR. CHATTERTON: ..... I'm speaking of that line la that strikes right down through Sag Delta Three on your Exhibit 14 Two? 15 MS. OKLAND: I don't know. I'm looking at Exhibit 16 Four. It does show on Exhibit Four. 17 MR. CHATTERTON: All right. We'll go to Exhibit 18 Four. Yeah, I see it there, too. The same place. All right. 19 Either one, but you have Exhibit Four. That line where you have 20 up -- a "U" on one side and a "0" on the other. side, and striking 21 northwesterly/southeasterly. Is it possible -- you are aware 22 that you did attach some proposed rules here and you chose to 23 define the Lisburne Pool as that interval equivalent to the 24 measured depths in Prudhoe Bay State Number One, extending from 25 drill depths of 89- -- 8790 to 10,440 as .... R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3F·m AVE.NUE 272 7515 4 5 6 7 8 9 10 11 12 ( 1:3 14 -63- MS. OKLAND: Um-hm. 2 MR. CHATTERTON: the vertical limits of the 3 Lisburne Pool? MS. OKLAND: Yes. MR. CHATTERTON: All right. Would it be -- would it be conceivable that that Nicholson Fault might have a bearing on the closure, if you'd like, or be a boundary to the Lisburne Pool if you take that entire vertical section and expand beyond your Phase One development area? MS. OKLAND: Well, in my testimony I also referred to the uncertainties that we have within the Lisburne below -- really below 9300 subsea. There are a lot of uncertainties, and I really -- almost anything is conceivable, but I am not able to answer your questions at this point with what we know. 15 MR. CHATTERTON: Would you think it might be 16 possible? 17 MS. OKLAND: I'm a little confused. I guess -- 18 we're a little 19 MR. CHATTERTON: My -- my ..... 20 MS. OKLAND: ..... confused on· what you're 21 MR. CHATTERTON: . . . . maybe I can 22 MS. OKLAND: ..... you're driving at there? 23 MR. CHAT'rERTON: ...... rephrase my question, 24 because -- and to me, I'm sorry to dwell on this, but I think 25 this is going to be very important in the Commission's R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W 3RD AVENUE 2727515 -64- 1 deliberations. You -- you're asking for a pool definition, the 2 vertical extent of it from the top of the Wahoo as you call it, 3 whether it is true stratigraphic or whether it is eroded top, to 4 the base of the Alapah, as defined by a log 1n Prudhoe Bay State 5 Number One. Now, I'm sure that you have on occasions found that 6 there is indications of hydrocarbons throughout that entire 7 section. I'm very sure you've ..... 8 MR. CHANCEY: Yeah. 9 MR. CHATTERTON: determined that in your -- 10 I'm asking if that is defined as the Lisburne Pool, as you go to 11 the northeast, is the boundary of the pool not only controlled by 12 a cretaceous unconformity, but also possibly or probably, which- ( 13 ever term you wish to use, by the Nicholson Bay Fault? 14 MS. OKLAND: I think that's possible, certainly. 15 MR. CHATTERTON: You'll go with "possible". How 16 about probable? If you think I'm trying to lead you, .... 17 MS. OKLAND: Even probable. 18 MR. CHATTERTON: ..... you're right. 19 MS. OKLAND: I think you're correct. 20 MR. CHATTERTON: Okay. It's a good que- -- it's 21 a good guess anyway. Okay. Very good. 22 One other quick thing, and this is sort of a Mickey Mouse 23 one, but on your Exhibit Two, could you tell me what the -- what 24 the triangles and the circles represent? That's not my question, 25 but carrying forth. I \ R & R COURT REPORTERS 1 810 N STREET SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 31~D AVENUI::. 272 7515 -65- 1 MS. OKLAND: They were meant to indicate a 2 difference between partial and complete penetrations. :3 MR. CHATTERTON: Very good. And which -- and 4 which being which? I know, the 5 MS. OKLAND: I'd have to look. 6 MR. CHATTERTON: ..... triangle is complete. ... 7 MR. CHANCEY: The triangle's .... 8 MS. OKLAND: Triangle must 9 MR. CHATTERTON: ..... The triangle 10 MS. OKLAND: ..... be complete ...... 11 MR. CHATTERTON: ..... is complete. Okay. 12 MS. OKLAND: ...... penetration. 13 MR. CHATTERTON: Thank you very much. I'm not 14 through yet, so 15 MS. OKLAND: Oh, gee. 16 MR. CHATTERTON: All right. We'll go to page 17 five or your testimony, and we're into, well, the -- the 18 paragraph at the bottom of the page, and I will quote. Referring 19 to Wahoo and Alapah, and you're referring to "Shaly, silty beds 20 are fairly continuous, and are useful for correlation. However, 21 they do not," and I emphasize, "constitute effective field-wide 22 barriers to fluid movement, because they are thin, of variable 23 permeability, and are breached by fractures." 24 Now, that "they do not" coupled with the "breached by 25 fractures," are you in effect saying that there can be pressure R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVl'.NUl 272 7515 -66- 1 communication ln a vertical direction between varlOUS strata? 2 MS. OKLAND: We believe this is possible. We 3 don't have enough data to know in all portions of the field 4 whether this is occurring 5 MR. CHATTERTON: True. 6 MS. OKLAND: ..... or not. 7 MR. CHATTERTON: And -- and would you like to re- 8 -- you -- you said the word "possible," would -- would you 9 would you go so far as to say "probable"? 10 MR. CHANCEY: Based on the data known (ph). 11 MS. OKLAND: As far as I know now, I would say 12 probable. 13 MR. CHATTERTON: Thank you. I refer you to -- I'w 14 on page six and under the heading "structure" and I refer you 15 to ...... 16 MR. WILLIAMS: Mr. -- Mr. Chairman, could -- I 17 don't mean to interrupt your questions, but I think we may have a 18 little bit of elaboration on that one point 19 MR. CHATTERTON: Fine. MR. WILLIAMS: if you dOr;l't mind? MR. CHATTERTON: I'd love to hear it. Sorry. 20 21 22 MR. CHANCEY: When you specifically ask about 23 pressure communication, since the field is not on production, I 24 don't think we have enough data right now to make that conclusion. 25 MR. CHATTERTON: Right. The perhaps the word R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVE.NUI:. 272 7515 -67- "pressure" that I chose was -- was wrong. Shall -- shall I just 2 drop "communication" and say -- drop the verb "pressure" and say :3 "communication"? 4 MR. CHANCEY: I think pressure is the best way 5 to -- to isolate or to define communication, ..... 6 MR. CHATTERTON: Right. 7 MR. CHANCEY: ..... so I think the best way is to 8 actually observe it by pressure communication. 9 MR. CHATTERTON: Right. And we didn't say it did 10 exist, we said it probably existed. 11 MR. CHANCEY: Possibly existed. 12 MR. WILLIAMS: Yeah, I think ..... ( 13 MR. CHATTERTON: Well, she ..... 14 MR. WILLIAMS: ..... that's what 15 MS. OKLAND: "Possibly" is a 16 MR. WILLIAMS: ..... what we want to clarify is 17 the.... 18 MS. OKLAND: ..... good word, yeah. 19 MR. WILLIAMS: .... is the "probably" and the 20 "possibly" . 21 MR. CHATTERTON: I think she did clarify that. 22 I thought that the .... 23 MR. WILLIAMS: Yeah. 24 MR. CHATTERTON: record would show -- I 25 think it will show that she said it was probable. R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 w. 3RD AVENUl~ 2727515 -68- 1 MR. WILLIAMS: Yeah. That's ..... 2 MS. OKLAND: That's a personal opinion, however. ;3 MR. CHATTERTON: Understood. Okay. That's all I 4 have, too. All right. Fine. I understand what you're saying. 5 Very good. And why you're saying it, too. Okay. 6 On page six and under the heading "structure," you refer 7 to Exhibit Four, and -- and Exhibit Four -- Keith, you don't have 8 to put it back on. I think we're all aware of it. Exhibit Four, 9 you -- you title it "Top Lisburne Structure Map". You have 10 testified that it is drawn upon the top of the Lisburne. Is it 11 truly a structure map? Is it representative of structure or 1S 12 it representative of an unconformity? ,( 13 MS. OKLAND: It depends on where you are. In 14 some cases it is ..... 15 MR. CHATTERTON: As we get .... 16 MS. OKLAND: ..... an unconformity that is the 17 top 0 f ..... 18 MR. CHATTERTON: Where the ..... 19 MS. OKLAND: ..... the Lisburne. 20 MR. CHATTERTON: ...... unconformity is being 21 effective -- is is affecting the common depth points on your 22 Exhibit Four, then it ceases to become a structure map, is that 23 correct? It becomes more of a . . . . 24 MS. OKLAND: It might be more clear to say simply 25 say it is a top Lisburne map. "Structure" is intended to imply -( R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 w. 3RD AVENUl 272 7515 -69- 1 that it is showing you the subsurface top of ..... 2 MR. CHATTERTON: Right. :3 MS. OKLAND: ..... the Lisburne. 4 MR. CHATTERTON: The -- the -- the comparison of 5 your -- your map -- well, fine. I I think we both understand 6 it, but what -- what brought it to my attention was when I 7 compared your Exhibit Four with your Exhibit Six, which is an 8 east/west cross section running from West Beach State Number Two 9 through Gull Island State Number Two to Sag Delta State Number 10 Five, if you look at your Exhibit Four you would say that Sag 11 Delta State Five is roughly 200 feet structurally lower than Gull 12 Island State Number Two. ...... 13 MS. OKLAND: That is reflecting ...... 14 MR. CHATTERTON: ...... Yet on your cross 15 MS. OKLAND: ...... the truncation. 16 MR. CHATTERTON: ...... section you will see that 17 the Alapah is much lower structurally in Gull Island State Number 18 Two than it is in Sag Delta Number Five. That's the question 19 about is it truly a structure map? 20 MS. OKLAND: In the area of the truncation, no. 21 MR. CHATTERTON: All right. Thank you very much. 22 We're still on page -- okay. That takes page seven faulting 23 to the north -- and again, on page seven where you have 24 development limits, you say the Permo-Triassic -- "The trapping 25 mechanism in the Lisburne ... is provided by faulting to the R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3f",0 AVE.NUE. 272 7515 t -70- 1 north and truncation to the east." And we now have your personal 2 opinion that it's possible it could be truncation and faulting? :~ MS. OKLAND: Yes. 4 MR. CHATTERTON: Thank you. Okay. I -- On page 5 eight you refer to the field rules. I am not -- and -- and I'm -- 6 I'm -- my memory's -- I've lost as to whether you who testifiec 7 to the fact that -- it will come up, never mind. Never mind. 8 Okay. Okay. Thank you very, very much, Linda. 9 Don, you're the next one on place -- on tap. And would 10 you refer to Exhibit Number Seven? And you show -- on that there 11 is a heavy -- I'd better get my Exhibit Number Seven. All right. 12 That's okay. I've got it. You have a sort of a heavy dashed ( 13 line depicted on that. Now, is that the limits of the Phase -- 14 is -- of the Phase One development area, or is what's depicted on 15 Exhibit Nine the Phase One development area? 16 MR. CHANCEY: What is depicted on Exhibit Nine is 17 the Phase One deyelopment area. 18 MR. CHATTERTON: Okay. What is the line, that 19 heavy dashed line on Exhibit Seven supposed to represent? 20 MR. CHANCEY: That represents where we believe 21 the top of the Lisburne structure hits the 9300-foot contour. 22 MR. CHATTERTON: All right. Is -- is that also 23 representing what you were requesting for the -- upon the -- when 24 -- when we void -- or revoke, if we do revoke, Conservation Order 25 83-C, is that the limits of what you would like the new Prudhoe -- \, R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W 3RD AVE.NU~.. 272 '7515 -71- 1 new Lisburne pool rules to be? Is that the boundary of the pool 2 rules area? ;3 MR. CHANCEY: That's correct. 4 MR. CHATTERTON: Okay. As I remember Conservation 5 Order 83-C, it appears that it would expand the westerly 6 boundary of 83-C to encompass additional lands, and it would 7 appear that tract -- that it contracts the easterly boundary of 8 the old limits line of 83-C, contracts it in a westerly 9 and re-establishes it further to the west. That was you did 10 that only to encompass just your 9300? That was the purpose for 11 doing that? 12 MR. CHANCEY: That is correct. 1:3 MR. CHATTERTON: Do you have any real objection 14 if it's not contracted ..... 15 MR. CHANCEY: I have no objection ..... 16 MR. CHATTERTON: .... on the eastern .....? 17 MR. CHANCEY: ..... no, Commissioner. 18 MR. CHATTERTON: Okay. Despite maybe a little 19 confusion in in the direct testimony, you really refer to 20 Exhibit Nine as and the six drill sites as the primary, what 21 we call the Phase One development area? 22 MR. CHANCEY: That is correct. 23 MR. CHATTERTON: Okay. Thank you. I think we 24 kicked around the -- let's see. That lets you off the hook for a 25 moment, Don. R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVl:.NUf'_ 272 7515 -72- 1 Don Breeden, I think we kicked you around enough on this 2 situation and -- and what -- what you're looking in basic, you're 3 basically your testimony dealing with drilling and well design 4 is directed toward the -- what we now establish as the primary 5 development area, the six drill sites, is that correct? 6 MR. BREEDEN: Yes, sir. 7 MR. CHATTERTON: Very good. Okay. We might have 8 a new ballgame if we went out with drill site XYZ out in the 9 westerly portion of the Prudhoe Bay Unit, we might have a 10 different ballgame? 11 MR. BREEDEN: I think we might ask geology to look 12 into that. 13 MR. CHATTERTON: Right. Okay. What -- you -- 14 you were quiet -- Don, you were quiet on your wirelie (ph) logging 15 plans for -- for the wells. Are you going to run conventional 16 logs from surface to TD on every well, or what are your plans? 17 MR. BREEDEN: I think Don Chancey would be better 18 to address that one. 19 MR. CHATTERTON: Okay. Don Chancey? 20 MR. CHANCEY: We do not plan to run conventional 21 well logs from surface to TD on every well. We plan to follow 22 the existing rules which are are set forth within the Prudhoe 2:3 Bay Uni t. 24 MR. CHATTERTON: All right. Then that would be 25 in essence that you would log below the surface of a string of R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 ,. 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 w. 3f~D AVENUe_ 272 7515 1 2 ;3 4 5 6 7 8 9 10 11 12 ( 13 14 15 16 17 18 19 20 21 22 23 24 25 ,'I \ -73- surface casing, potentially set at 5,000 feet and you would not have on every well a log above 5,000 feet, is that right? MR. CHANCEY: We will not have a log on every well above 5,000 feet, that's correct. MR. CHATTERTON: Okay. But you will have a log above 5,000 feet on at least one well per drill site? MR. CHANCEY: Per drill site, yes, sir. MR. TATE: Yes. MR. CHATTERTON: Thank you. Now, Don Breeden, back to you. You -- you -- and I'm in the last sentence of the well, the first big paragraph on page 17, which reads, "This is a neces- -- a necessary precaution," referring to the depth of the surface casing -- of -- of the surface casing, "since the next section of hole will be drilled through the drawndown Permo- Triassic gas cap," and I guess you mean "pressure" drawn- -- drawndown? MR. BREEDEN: Yes, sir. MR. CHATTERTON: Do you feel that you have any problem between the drawndown pressure support in the Permo- Triassic gas cap and the amount of mud density that it will support? Do you believe it will support a sufficient mud density to over-balance any Putt River sands that might exist? MR. BREEDEN: Yes, we feel it will at this time. MR. CHATTERTON: Would you have to do any pretreatment of the mud for anything like that? Do you think R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 .. 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVE:.NUf:_ 272 7515 -74- 1 that it -- it'll support a -- a mud density that's sufficient to 2 control the Putt River sands, but not lose it into the Permo- 3 Triassic? 4 5 some 6 7 Don. 8 MR. BREEDEN: Yes, I believe it will. We may do pretreatment if indicated with lost circulation material. MR. CHATTERTON: Okay. Thank you. Thank you, Let's see. Okay. Ron, I guess it's your turn now, if I can ask you 9 refer you to page 26 of your testimony, and the middle 10 paragraph first there. I'll tell you what, I'm not going to 11 bother you -- what I'm going to ask you, and I won't -- don't 12 want to take everyone's time for this, but I want to catch you a 13 little bit later. I will be interested in -- and maybe after we 14 break off here, you will be able to write on Exhibits -- Exhibit 15 15 is the flow diagram of the Lisburne production center, write 16 on there some pressure, such as discharge pressures for the 17 compressors that you have there, and also if you have, I will be 18 asking you not only the -- the pressures along the flow train, 19 but also potentially a temperature as you best are designing for, 20 and I will also be asking you as to the volume~ you anticipate 21 that will be discharged, the -- the liquids that will be dichargeé 22 from the depropanizer, 23 MR. BEACH: Okay. 24 MR. CHATTERTON: and whether you're going to 25 meter them or not. R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 w. 3RD AVENUe. 2727515 -75- 1 MR. BEACH: All right. 2 MR. CHATTERTON: Okay. And I will put that on :3 Exhibit 1 5. It will be part of the public record. Okay. But 4 I don't want to take the detailed time to run through it right 5 now. 6 Don Chancey, what -- do -- do you happen to know what the 7 cloud point is of this crude? Wax crystallizàtion poibt 8 temperature-wise? I'm looking at your page 30, at the bottom of it. 9 10 MR. CHANCEY: The crystallization point is 11 varies with both pressure and temperature. 12 MR. CHATTERTON: Um-hm. 13 MR. CHANCEY: We have done some -- some additional 14 work, and -- oh, excuse me, it also varies with GOR, so 15 MR. CHATTERTON: Okay. I've seen that happen. 16 MR. CHANCEY: ..... so I would then have to give 17 you a range. 18 MR. CHATTERTON: All right. Fine. It's not a 19 quick deal like some products like diesel oils are? 20 MR. CHANCEY: That's correct. 21 MR. CHATTERTON: Okay. Okay. Leland, I'm not 22 going to let you out either. In your opinion, do you feel that 23 the limits of the Lisburne pool as you are requesting that it be 24 defined that the limits have been established for that pool as to 25 the limits of ability to produce hydrocarbons in paying R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AVE.NUt: 272 7515 1 2 3 4 5 6 7 8 9 10 11 12 ( 13 14 15 16 17 18 19 20 21 22 23 24 25 -76- quantities? MR. TATE: Based on the -- the information that we have from the 27 or so wells that have been drilled, the -- the minus 9300-foot subsea elevation should pretty much include any -- that area should pretty much include any of the, what we consider economically developable areas. That's not to say that, you know, how discontinuous the Lis- -- not "discontinuous," but varying the Lisburne is. It might be different in some areas. MR. CHATTERTON: Um-hm. MR. TATE: Outside that area, and you might actually -- you know, there might actually be some developable area out there, but we don't have wells to prove that right now. So I think MR. CHATTERTON: Understood. MR. TATE: I think the area that we've included encompasses and -- and is proven up by most of the by the wells that we have, so the answer is I -- I think it it's pretty -- it's a pretty good estimate of the -- of the economically developable area. MR. CHATTERTON: Right. But it is possible that -- taking this long 2,000 feet of vertical interval, it is possible that there might be areas of that pool that are capable of producing in paying quantities beyond -- outside of your 9300- foot contour? MR. TATE: I -- I think I would have to say it's R Be R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 1007 W. 3Fm AVE.NUl: 272 7515 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 -77- possible, yes. 2 MR. CHATTERTON: All right. I'll accept possible. 3 Would you think that -- that say a well that on a short-term test 4 produced say 7,800 barrels a day rate might be a well in paying -- 5 capable of producing in paying quantities? 6 MR. TATE: 7,800? 7 MR. CHATTERTON: Yes, sir. 8 MR. WILLIAMS: Seven to 800 or 7,800? 9 MR. CHATTERTON: 78 hundreds. Seven thousand 10 MR. WILLIAMS: Seven thousand ...... 11 MR. CHATTERTON: ..... eight hundred. 12 MR. WILLIAMS: .... eight hundred? 13 MR. TATE: Well, I don't -- it's a function of 14 how big the pool is. If you didn't -- if you didn't deplete it 15 in 30 days, it probably would be. I ..... 16 MR. CHATTERTON: It would be suggestive? 17 MR. TATE: It would 18 MR. CHATTERTON: Right? MR. TATE: definitely be suggestive. MR. CHATTERTON: Okay. Thank you. You -- You 19 20 21 you testified, Leland, that you are in negotiations with the 22 other principal -- apparent principal working interests with 23 Lisburne production in establishing a participating area, which I 24 think some state agency requires would have to be established 25 prior to -- to going on full field production so to speak, and R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 2727515 { -78- 1 you say -- you indicate that's going to be completed by '86, is 2 that correct? :3 MR. TATE: Yes, sir, it -- that's certainly our 4 intent. We're -- this is one of those where you don't have all 5 the information you'd like to have, so the equity -- a proper 6 equity for all peop- -- for all 7 MR. CHATTERTON: Understood. 8 MR. TATE: ...... parties is difficult to 9 establish, and 10 MR. CHATTERTON: Okay. 11 MR. TATE: ...... and we're just in the early 12 stages of trying to develop that. But we -- we're hopeful that I' \ 13 we'll be able to to get a participating area formed in -- in 14 '86. 15 MR. CHATTERTON: Okay. You had -- at this point 16 in time, you would have no plans to do step-out drilling beyond 17 your Phase One development area, you yourselves, Phase One 18 development area to try and establish pool limits? 19 MR. TATE: They're -- they're -- not outside the 20 development area. I think -- you're -- you're talking about ARCO 21 now? 22 MR. CHATTERTON: I'm talking -- yes, right. 23 MR. TATE: ARCO 24 MR. CHATTERTON: ARCO 25 MR. TATE: we -- we don't have any plans R & R COURT REPORTERS 1 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 w. 3rm AVENU~_ 277-0572 - 277-0573 277-8543 272 7515 ANCHORAGE, ALASKA 99501 ,~ -79- 1 right now to move outside that -- that Phase One area. 2 MR. CHATTERTON: Okay. 3 MR. TATE: Let me -- let me restate that. The 4 Phase One area is the area included in those six drill sites. We 5 will probably do some testing around the -- around the near edges 6 of that to -- to look and see about the -- the marginal 7 thicknesses, to see if that might be econ- -- economic. 8 MR. CHATTERTON: Okay. 9 MR. TATE: But -- but not major step outs. 10 MR. CHATTERTON: Okay. 11 MR. TATE: We're not looking at that. 12 MR. CHATTERTON: Once there has been an initial 13 participating area established, I presume it could be established 14 in the -- there is a mechanism that's -- within the Prudhoe Bay 15 Unit agreement and/or the Prudhoe Bay Unit operating agreement to 16 establish participating areas and also to expand them. I do 17 believe that is the case? 18 MR. TATE: Yes, sir, that's right. And . . . . 19 MR. CHATTERTON: Right. 20 MR. TATE: ...... and tract operations. Even if 21 a participating area is formed, tract operations are allowed 22 within the -- within the agreement, so any -- any individual owner 23 could continue to drill either within the initial area or outside 24 that area to further prove up his acreage. 25 MR. CHATTERTON: Right. And if he indeed then R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W 3RD AVE.NUt-_ 272 7515 -80- 1 did prove a well capable of producing in paying quantities, I 2 think the mechanism within the Prudhoe Bay Unit also provides for 3 the cost equalization, the production equalization, and the 4 expansion of the initial participating area? 5 MR. TATE: Yes. 6 MR. CHATTERTON: Okay. What would you do, 7 Leland, if this pool extended beyond the Prudhoe Bay Unit 8 boundaries, what would you what would happen then? 9 MR. TATE: Well, the -- the Lisburne is a part 10 of the Prudhoe Bay Unit. It's just -- it will be another 11 participating area, so I would assume what would occur, and, 12 steve, you can help me here, but ..... 13 MR. WILLIAMS: Yeah, I'm -- I will. 14 MR. TATE: ..... I would assume what would occur 15 is the -- the -- is the -- the unit boundary would be expanded. 16 MR. WILLIAMS: Yeah, I don't think there's 17 anything that we would do if -- right -- right now at the present 18 time, if the field rules area extended as they do in 83-C well 19 beyond the eastern edge of the Prudhoe Bay Unit. I don't think 20 anything is required. 21 MR. CHATTERTON: Um-hm. 22 MR. WILLIAMS: If that answers your question? 23 MR. CHATTERTON: Not -- not quite, Steve. I I 24 think I -- and -- and maybe, Leland, rather than directly to you, 25 whomever would like to reply to it, if we take as a possible, R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AV~~NU[ 272 7515 -81- using Linda's term, that the par- -- the limits of the Lisburne 2 -- the -- the paying quantities limits, if you like, of the 3 Lisburne Pool may extend beyond your primary development area, 4 may extend to the northeast even possibly so far as the Nicholson 5 Bay Fault, if we say that is the case as we -- and some of those 6 lands up there were for some reason or other no longer within the 7 Prudhoe Bay Unit, this is where my question comes: What type of 8 a mechanism would you use to expand -- or would there be a 9 mechanism in place to provide for the tract drilling and the 10 expansion of a participating area up there even though it's 11 beyond what might become the boundary of the Prudhoe Bay Unit? 12 MR. WILLIAMS: I -- I think that there -- there 13 -- there are a number of questions in -- in your question 14 statement. 15 MR. CHATTERTON: Is a number. 16 MR. WILLIAMS: The -- the existing Prudhoe Bay 17 Unit, which we're all familiar, and the Prudhoe Bay Unit Operating 18 Agreement does contain provisions which allow expansions of 19 partici- -- which allow the formation of a participating area, 20 allow expansions of that participating area, based on -- on 21 reservoir basis and -- and drilling activity and people proving 22 up their acreage. Allow people the opportunity to prove up that 23 acreage as Leland noted through tract operations. 24 For areas that are outside the Prudhoe Bay Unit, there 25 are provisions in the Unit Agreement right now which allow R & R COURT REPORTERS 1 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 272 7515 ANCHORAGE, ALASKA 99501 -82- 1 expansions of the Prudhoe Bay Unit area to include reservoirs 2 which lay both within and without the Prudhoe Bay Unit, so that I 3 believe the intent was that the reservoir would be operated under 4 the Prudhoe Bay Unit. 5 If, for instance, and -- and certainly your question has 6 a number of -- of hypothesis to it, and an awful lot of 7 possibilities and an awful lot of conjecture, and the base 8 best data available is going to dictate what is going to happen. 9 For instance, your example on a well that produced 7,800 barrels 10 a day, I'm not a reservoir engineer or a geologist, but I think 11 a well that produced 7,800 barrels a day over a three-day period 12 of time or a one-day period of time, does not necessarily mean 13 that it's the same pool or within the same field or in 14 communication or in the same participating area as one that may 15 exist. I think the data is going to have to show that. It's not 16 a given to begin with. 17 There are also in my view provisions in the statutes of 18 the State of Alaska and in the conservation statutes with the 19 Commission that allow types of cooperative development to ensure 20 that -- that the reservoir's -- maximum oil recovery occurs from 21 reservoirs even if those reservoirs overlay two grassroots units 22 if you will. 23 So I think that tho- -- there -- there -- there are 24 provisions which would allow that to happen if all of the 25 possibilities and all the ifs that you indicate would occur. R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 w. 3F~D AVENUE 272 7515 { -83- 1 MR. CHATTERTON: All right. Understood. 2 MR. WILLIAMS: I I hope that was responsive. 3 MR. CHATTERTON: We appreciate the direction from 4 you, Steve. We do recognize you're not under oath. 5 I think that that is about where I -- you did include 6 in the and I think I mentioned it before, some proposed rules. 7 We mayor may not ..... 8 MR. WILLIAMS: Right. 9 MR. CHATTERTON: follow that. We do 10 appreciate your -- your interest in in being helpful to us, 11 and we'll try and comply as best we can. 12 For -- is there anything else to come before -- before us 13 at this time? I -- I've -- Lonnie, do you have ..... 14 MR. SMITH: I have -- I have another ..... 15 MR. CHATTERTON: ...... further questions? 16 MR. SMITH: ..... I have another question here 17 that occurred to me. Your -- you've testified to the fact that 18 the Lisburne production facilities' equipment, the nominal design 19 is to handle 100,000 per day of oil. What rate do you expect to 20 start up with in 1986? 21 MR. TATE: Want me to try that one? 22 MR. BREEDEN: Yeah, go ahead. 23 MR. TATE: If we had all the wells drilled, we 24 could probably tell you. We've -- we've estimated the -- the 25 well production rate somewhere between 1,000 and -- and 2,000 R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272 7515 -84- 1 barrels per day per well, and we would certainly intend to have 2 enough wells drilled to fill that production facility if it's at :3 all possible. 4 We have designed the facility such that -- and -- and 5 tried to eliminate as many bottlenecks as we can. The nominal 6 design IS 100. We hope -- we're hopefull to be able to produce 7 more than that given that the wells perform a little better than 8 we thought, and that the facility performs a little better than 9 we thought. So the answer, Lonnie, is somewhere between probably 10 80 and 100 and, you know, something above 100 depending on how 11 the wells perform. So I can't quite give you that upper limit. 12 MR. SMITH: Okay. 1:3 MR. TATE: It -- it -- it will be a function of 14 how we do. 15 MR. SMITH: 16 kind of a minimum? 17 MR. TATE: 18 be our minimum, yeah. We Well, really the 100,000 barrel is I would -- I would say that that would obviously we'll ramp up in production. 19 We won't start out the first day at 100,000 barrels a day. It 20 will take some time to get all the wells flowing and the normal 21 operational problems worked out of the new facility, but not too 22 long after we get started up, I would hope that we are at or 23 above that that level. 24 MR. SMITH: Okay. Well, maybe someone can give me 25 an idea of what this design equipment -- what you expect it R & R COURT REPORTERS 1 810 N STREET. SUITE 101 277-0572 277-0573 509 W. 3RD AVENUE 277·8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE.. 272 7515 -85- 1 could handle maximum on a -- on a daily on-going basis? 2 MR. BEACH: We anticipate that we would be able 3 to reach 125,000 barrels a day with this equipment. 4 MR. TATE: At -- at different times in the life, 5 the -- the capability of the facility will be limited by 6 different things. As you get later in life, the gas/oil ratio 7 will have come up, and you may be limited by your gas handling 8 capacity, whereas early in life you may be limited by your liquid 9 handling capacity. And just looking back at Prudhoe experience, 10 the facilities we built have been able to handle more than we 11 designed them for, and so we're -- we are optomistic that we'll 12 be able to handle more than the nominal design. 13 MR. CHATTERTON: And I might fall back to a 14 question about the modeling, and have -- with regards to rates, 15 well rates, and recoveries, is there -- did you do any modeling 16 having to do with the sensitivity to recoveries? 17 MR. CHANCEY: We ran our model at two different 18 field rates: at the nominal 100,000 barrel per day, and we also 19 ran it at a 160,000 barrel per day, and we did not see any 20 change in the ultimate recovery of oil between those two cases. 21 MR. SMITH: Okay. That's -- that's all they can 22 MR. CHATTERTON: Okay. All right. Is -- is 23 there anything else to ..... 24 MR. WILLIAMS: I was going to suggest, 25 Mr. Chairman, if I may that -- that you asked Mr. Beach to -- to R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 - 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W 3,,<0 AVENUe. 272 7515 -86- 1 write on Exhibit 15, on the flow diagram? 2 MR. CHATTERTON: Yes. 3 MR. WILLIAMS: I believe the Commission may want 4 to keep the record open for a short period of time after this 5 hearing. We could take Exhibit 15 and -- and provide a response 6 to your questions on that during the period the record's held 7 open if you will, rather than after today -- or do it either 8 way you'd like? 9 MR. CHATTERTON: I -- I appreciate that offer. I 10 would much prefer it that way, Steve. And on that point, for not 11 just that reason, but -- but for selfish reasons and time 12 constraint reasons, I would like to keep the order open and 13 and we'll keep this record open until 4:30 p.m. on Monday, 14 December 12th -- or December the 10th. And as I said, it may be 15 purely for Commission selfish reasons. It I realize it may 16 you -- you are planning a well to drill in a well here very 17 shortly. But from what I know of of it now, I believe that 18 can be done and under existing 83-C rules -- maybe not 83-C rules, 19 but they certainly can be done under existing statewide rules. 20 MR. WILLIAMS: Statewide rules. 21 MR. CHANCEY: Yes, sir. 22 MR. CHATTERTON: And we we might revoke in 23 part 83-C. We'll figure out some way that we can accommodate 24 that. 25 MR. CHANCEY: Yes, sir, we do plan to -- to spud (\ R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277,0572 277-0573 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W 3RD AVlNU[ 272 7515 t -87- 1 a well within the next month or two, ...... 2 MR. CHATTERTON: Right. If it's within ..... 3 MR. CHANCEY: ...... which would make (ph) 4 statewide ...... 5 MR. CHATTERTON: ...... the next month, we .... 6 MR. CHANCEY: ..... regulations. 7 MR. CHATTERTON: ..... might have a problem. If 8 it's two months, we have no problem, because we must have the 9 order out within 30 days following the closing of the hearing. 10 MR. CHANCEY: Yes, we -- we do anticipate to have 11 a well spud by the end of the year. MR. CHATTERTON: Okay. Well, with -- and under 12 13 statewide regs, why, we can handle that as -- as you plan it. 14 I guess if there's nothing else, why, we'll close this at 15 approximately 11:30 a.m., and I guess, Meredith, we're off the 16 record. Thank you one and all. 17 (END OF PROCEEDINGS) 18 19 20 21 22 23 24 25 I \ R & R COURT REPORTERS 1 810 N STREET, SUITE 101 277-0572 277-0573 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 w. 3RD AVENUrc 272 751::; 21 22 23 S E A L 24 25 i 1 " \~ 1 C E R T I F I C A T E UNITED STATES OF AMERICA SSe STATE OF ALASKA I, Meredith L. Downing, Notary Public In and for the State of Alaska, residing at Anchorage, Alaska, and electronic 2 3 4 5 6 reporter for R & R Court Reporters, Inc., do hereby certi fy: That the annexed and foregoing transcript of public hearing was taken before me on the 29th day of November, 1984, beginning at the hour of 9: 00 A.M., at the Greater Anchorage Area Borough Assembly Chambers, 3500 Tudor Road, Anchorage, Alaska, pursuant to notice. That the wi tnesses, before testifying, were duly sworr to testify to the truth, the whole truth and nothing but the truth. 7 8 9 10 11 12 13 That this transcript as heretofore annexed is a true and correc transcription of the testimony of the witnesses, taken by me electronically and thereafter transcribed by me. That the original transcript has been retained by me for the purpose of filing the same wi th the Alaska Oil and Gas Conservation Commission, Anchorage, Alaska. I am not a relati ve or employee or attorney or counsel of any of the parties, nor am I financially interested in this action. 14 15 16 17 18 19 IN WITNESS WHEREOF, I have hereunto set my hand anc affixed my seal this 13th day of December, 1984. 20 :~,' ..". i<'t,,¡pi/IJ ..-.~ ","'" Jf' .1" '. '" ' . I,' -" ¡i" 'Ji.' ',,' , ' :,'''' .."p" , , .., " ~1~ I'¡..''¡; ,~.~I'" \'!I'-'\' , ".( .,' ;õ'¡, ':.., . '. ~ ""(., ";:tll,,*,""fr~ " :,1, , -:,."".' -/:" . ,f Notary Public n and for ,Alaska My Commission expire's: 5/3/86 R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 1007 W. 3RD AVE:.NUf~ 277·0572 . 277·0573 277·8543 272 7515 ANCHORAGE, ALASKA 99501 () Ffì ê -e Caf} ." " LISBURNE FIELD RULES TESTIMONY Mr. Chairmari-; -- Members of the Alaska Oil and Gas Conservation Commission (Commission), Ladies and Gentlemen: My name is Stephen M. Williams, and I am an attorney with ARCO Alaska, Inc. , (ARC a) the Operator for the Eastern Operating Area of the Prudhoe Bay Unit. ARCa, Exxon Corporation (Exxon) , and Sohio Alaska Petroleum Company (Sohio), are all owners of leases which overlay the Lisburne Reservoir. The owners have requested this public hearing before the Commission, pursuant to the provisions of 20 AAC 25.520, to consider the adoption of fip.ld rules for development of the Lisburne ail Pool. The application' for field rules was filed in November, 1984. Prefiled testimony was also delivered to the Commission on November 26, 1984. Confidential meetings were held with the Commission on October 30, 1984 to review ARCa/Exxon reservoir interpretation and on November 8, 1984, to review Sohio reservoir interpretation. ARCO requests that the application and prefiled testimony be made part of the public record. These documents support th~ application for field rules for the Lisburne Oil Pool. Several representatives of ARCO will present testimony today. Our testimony will provide a geological description of the Lisburne Reservoir, a reservoir analysis, discussion of reservoir development plans, a description of the facilities necessary for development of the Lisburne Reservoir, a discussion of. well design, and finally, a Fld Rulesdc2 1 <, { summary of the testimony and discussion of the proposed field rules for the Lisburne Oil Pool. Our intent is to emphasize the key points· and provide updated information to the Commission: .--gained through the delineation and testing activities conducted by the owners over the last several years. Afterwards, the Owners request that a panel be formed at the conclusion of testimony to provide a forum from which the Commission may ask questions on specific matters provided in the testimony. It appears that original field rules were adopted for the Prudhoe Bay Lisburne Oil Pool in Conservation Order No. 83-C. This Order was adopted January 12, 1970. The Commission is requested to revoke Conservation Order No. 83-C, and adopt revised field rules for the Lisburne Oil Poo 1 . Information gained over past years has provided valuable operational information, and sets forth the need to modify these rules. We have proposed a revised set of Field Rules for your consideration. These proposed Rules are contained in Appendix 1 . The following witnesses will testify today: Linda Okland will provide the geological testimony; Fld Rulesdc2 2 ( Don Chancey will provide the reservoir analysis testimony and the well operations testimony; Don Breedèft-will provide the drilling testimony; Ron Beach will provide the facilities description; and Leland E. Tate will provide a summary of the testimony. Each of the witnesses has included in their pre-filed testimony a biographic.al summary setting forth their respecti ve qualifications. We request that the wi tnesses be sworn in at this time. Linda Okland will begin the testimony today with the geological description of the Lisburne Reservoir. Fld Rulesdc2 3 '~ f GEOLOGY INTRODUCTION - .-- My name is Linda Okland. I am a senior geologist wi th ARCO Alaska, Inc. I received a Master of Arts degree in geology from the University of North Dakota in 1978, and I have been employed as a petroleum geologist by ARCO since 1978. I worked in Midland, Texas for two years before coming to Alaska in 1980. I have been working on the Lisburne Reservoir since January, 1982. My testimony today will include a geologic description of the Lisburne Reservoir. Oil was discovered in the Lisburne Reservoir with the drilling of the Prudhoe Bay State No. 1 well in 1968. Exhibit 1 is a map of a portion of the Arctic Slope of Alaska in the vicinity of the discovery well. The Lisburne Reservoir is bounded on the north by the Prudhoe Bay Fault, on the northeast by a major cretaceous unconformity and by gentle dip to the south and southwest. The area for which Lisburne Field Rules are proposed is outlined on Exhibit 2. It coincides generally with the northeastern portion of the Prudhoe Bay Unit. To date, 27 wells have penetrated the Lisburne within the area outlined. These wells are highlighted on the map. Four of the wells indicated are north of the Prudhoe Bay Fault. Of the Fld Rulesdc2 4 ~ remaining wells, 13 produced oil or oil and gas on test in the Lisburne Reservoir. One well produced water and two were apparently tight. _ Five wells which penetrated less than 100 feet of the-- .Lisburne Reservoir, and one well in which the Lisburne was severely truncated, were not tested in the Lisburne interval. The Lisburne section of one well was lost due to stuck pipe before it could be tested. STRATIGRAPHY The Lisburne Group underlies the Sadlerochit Group. The Lisburne Group is subdivided into the Wahoo and Alapah Formations, each of which is typically about 1000 feet thick in the Prudhoe Bay area. Exhibit 3 is a portion of the log from Prudhoe Bay State No.1. The top of the Lisburne Group occurs at a measur~d depth of 8790 feet, and the base at 10440 feet measured depth. The Wahoo-Alapah boundary is at approximately 9500 feet measured depth. Both Wahoo and Alapah consist predominantly of shallow marine limestone and dolomite, with lesser amounts of shale, silt, sand, and chert. Shaly or silty beds are fairly continuous, and are useful for correlation. However, they do not constitute effective field-wide barriers to fluid movement because they are thin, of variable permeability, and are breached by fractures. Dolomi te and chert are irregular in their distribution. Dolomite is a relatively minor component of the upper Wahoo, but becomes more prevalent lower in the section. A thick, shaly, dolomitic interval occurs at the base Fld Rulesdc2 5 of the Wahoo. This interval stratigraphically separates- the Wahoo from the Alapah. Porosity ·~.in'·· the Lisburne post-depositional in nature, interaction of factors, leaching, and dolomitization. Reservoir is predominantly and is controlled by a complex including depositional facies, Na tural fractures are abundant throughout the Lisburne Reservoir. Many of the fractures are partially to completely filled with calcite cement, but unmineralized fractures are also present. The fractures are predominantly vertical or near vertical, with no strong directional trend. Storage capacity in the fractures is small, but their contribution to permeability is significant. STRUCTURE Exhibit 4 is a structure map on the top of the Wahoo Formation, with a contour interval of 200 feet. The Lisburne Reservoir is bounded on the north by a major east-west trending fault complex. Closure is created by faulting on the north, by truncation on the west, and by dip of 135 feet per mile to the south and east. Exhibit 5 is a north-south cross-section from ARCa/Exxon Gull Island State No. 2 to ARCa/Exxon Sag River State No.1. The vertical exaggeration is approximately 44:1. This cross-section and the east-west cross-section which follows Fld Rulesdc2 6 show the general structure and correlations in the upper part of the Wahoo. As illustrated in this cross-section, Lisburne sediments dip to the south gently, away from the fault. Within the boundà~i~s of the proposed Field Rules Area, the top of the Lisburne Reservoir occurs at depths ranging from 8300 feet subsea in the north to about 9300 feet subsea in the southwest. Exhibit 6 is an east-west cross-section from ARCO/Exxon West Beach State No. 2 to Sohio Sag Delta State No.5. The vertical exaggeration on this cross-section is approximately 40:1. This cross-section shows that the Lisburne Reservoir is truncated to the east by a major Cretaceous unconformity. In this area, the Lisburne Reservoir is overlain by impermeable Cretaceous shale. The truncation begins just to the east of the Sohio Sag Delta No. 6 well, and is shown by a heavy wavy line on the structure map. A lighter wavy line indicates where the Wahoo has been removed and truncation of the Alapah begins. East of this line Wahoo is not present. On the west, the Lisburne Reservoir is partially truncated by a smaller unconformity of probable Permian age. DEVELOPMENT LIMITS The trapping mechanism in the Lisburne, as, in the Permo-Triassic Reservoir, is provided by faulting to the north and truncation to the east. The downdip limits of the reservoir are determined by low proven oil saturation at approximately 9300 feet subsea. This contact is gradational. Fld Rulesdc2 7 ~I~ lit The areal limits of the proposed Field Rules Area were selected to enclose all potentially commercial portions of the Lisburne Reservoir. A ga& cap is present in the area, with a gas-oil contact es~ímated at 8600 feet subsea. Above 9300 feet subsea, sediments of the Lisburne formations are oil-stained where porous. Reservoir quality is determined by porosity development. Despite considerable variations in porosity, there appears to be good lateral communication among porous zones both above and below 9300 feet subsea. Oil-stained rock also occurs below 9300 feet subsea. We do not know, at th1.s time, the extent or continuity of oil in this part of the section. Uncertainty still exists in the sustained producibility of oil in the Alapah and the Wahoo below 9300 feet subsea. Present development plans are limi ted to 9300 feet subsea and above. If producible oil is established below this depth in the future, however, we anticipate that it could only be commercially developed in conjunction with the shallower Lisburne oil. Therefore, we request that one set of Field Rules be granted for the entire Lisburne Reservoir within our proposed development area. As drilling proceeds, we will conduct tests of the Lisburne interval below 9300 feet subsea, and if viably producible, these intervals will be included in our development plans. This concludes my prepared testimony. Donald K. Chancey will now present the reservoir analysis testimony. Fld Rulesdc2 ,8 RESERVOIR ANALYSIS INTRODUCTION - My name is Donald K. Chancey. I received a Bachelor of Science in Engineering in 1975 from The University of Texas. Following graduation, I went to work for ARCO as a Petroleum Engin~er. In 1982, I moved to Alaska and I have been working on the Lisburne Reservoir since that time. I am a member of the Society of Petroleum Engineers and a Registered Professional Engineer in the State of Texas. My testimony' today will include a description of the Lisburne Reservoir, a summary of reservoir performance studies, and comments on well spacing. Oil and Gas in Place Exhibit 7 is a map of the proposed Phase I development area for the Lisburne Reservoir. The area outlined for development was determined by well logs, core data, production tests, and reservoir analysis. Within the proposed development area, ARCO estimates stock tank barrels of original oil-in-place with 500 standard cubic feet of free gas in place. 3 billion billion The average porosity of the productive interval is approximately ten percent, determined from logs and core data where available. Fld Rulesdc2 9 In-Place Saturations Two methods of calculating water saturation have been evaluated by ARca and Exxon. _The first method involves the conventional analysis of~eìèctric well logs calibrated to oil base cores. The second method utilizes water saturation data obtained from several oil base cores to calculate a Buckley-Leverett J-function. This J-function provides a correlation of water saturations with formation permeabili ty, porosity, and height above the water-oil contact. Water saturations at any point in a well profile can be determined by use of the J-function. The various methods yield an average water saturations of 20-40 percent within the developable oil column. Fluid Properties Initially, reservoir pressure in the Lisburne formation averages about 4,490 pounds per square inch at 8900'55 datum with a reservoir temperature of 183°F. The oil gravity averages 27° API. The oil formation volume factor averages 1.385 reservoir barrels per stock tank barrel, and the solution gas-oil ratio is 830 cubic feet per barrel as measured in a bottomhole sample taken from West Bay State No. 1 on March 1, 1982. In-place Lisburne crude is saturated and has a viscosity of 0.7 centipoise. Reservoir Performance The primary recovery mechanism in the Lisburne Reservoir is thought to be predominantly solution gas drive with some additional benefit provided by gas cap expansion. There is a possibility that gravity drainage may increase oil recovery. If the natural fracture Fld Rulesdc2 10 {\ pattern is vertically extensive, reservoir boundaries could be- crossed and a natural flow path for segregation of oil and gas provided. -- Produced gas, after deduction for field fuel, will be initially reinjected into the Lisburne. Gas will primarily be injected into the Lisburne gas cap, but perhaps also down dip to help minimize regional pressure gradients. This will maintain a higher reservoir pressure and increase recovery. Although some water production has been seen in drillstem tests, little water has been produced during the production, tests. We do not expect to have strong aqui fer support. Recovery is estimated to be in the range of 7% to 22% of original oil in place with primary depletion and gas reinjection. Several reservoir simulators have been built by Lisburne owners to model the Lisburne formation. I will describe ARCa' s modeling efforts. Ini tially, a single well model was buil t to match the nine month production test at West Bay State No.1. The model consisted of 15 radial cells with increasing radii around the well bore. Well logs and some cores provided the basis for 15 layers to r~present the Upper Wahoo. This model was matched to the production test history and the results were applied to the construction of a 2-D strip model. As shown in Exhibit 8 , a north-south cross-section was drawn through West Beach State No.2, West Bay State No.1, South Point State No. 1 and Sag River State No.1. From this cross-section a strip model with 60 cells in the north-south direction and 18 layers covering the Upper Wahoo was built. There is one cell in the east-west direction with the width Fld Rulesdc2 11 f that cell varying to approximate the original oil-in~place.. Although there is only limited production data from which to match the model, the moctels indicate that individual wells may show a substantial~decline, but infill drilling will maintain total field withdrawal rates. Sp-veral wells have shown a tendency to go to high gas-oil ratios in a short period of time. The model also indicated that our recovery could be increased if the field is drilled on 160 acre spacing rather than 320 acre spacing. Natural flow tests have been conducted on several wells indicating a tight matrix with permeabilities ranging from 0.1 to 2 millidarcies. These permeabilities have been confirmed by routine core analysis. However, history matches with the single well simulator indicate that higher permeabilities were required to support the rates between 1000 and 2000 barrels per day that were seen during the two-month production test in each of five wells. Near-well stimulation was also required. At least part of the observed near-well stimulation and the enhanced matrix permeability are attributed to the natural fracture system. Acidizing or hvdraulic fracturing cleans up wellbor~ damage and enhances the natural fracture productivity. To date, we have performed 76 drillstem tests, 40 in the Wahoo and 36 in the Alapah. Short term flow tests, usually of two months duration, were run in the Lisburne intervals of West Bay State No. 1, South Point State No.1, Pingut State No.1, South Bay State No. 1, and Sag Del ta No.6. From these short term tests, we have confirmed that the Lisburne Reservoir is capable of producing at Fld Rulesdc2 12 well rates in the 1000-2000 barrels of oil per day range. Thesé earlier tests provided only hints of potential operational and GOR problems. - Reservoir Development Plans In mid-December of this year, development of the Lisburne Reservoir will commence with the drilling of 320 acre spaced wells on drillsi te L2 as shown on Exhibi t 9. Current plans call for 160 acre well spacing during Phase I primary development but other spacing will, be evaluated as addi tional production occurs. Drilling will take place from six drillsites. Drilling of 320 acre spacing wells will be completed during the third quarter of 1987 and infill drilling to 160 acre spacing will be completed in 1989. The ultimate' planned well count could reach 210 wells on 160-acre spacing. While we have provided manifolding for up to 20 gas injectors at LGI and L6, four gas injectors will be completed in time for the late 1986 start-up. Pending results of initial dp.velopment, further Primary Development could develop the edge regions of the reservoir during the time period from 1990 through 1992 as shown on Exhibit 10. Up to four rigs will be utilized during this development program. While drilling will be a major activity during the next seven years, several other development activities will also be vigorously pursued. Because of the long lead times required for secondary and enhanced oil recovery projects, the time period prior to start-up of the Lisburne Production Facility in late 1986 is extremely Fld Rulesdc2 13 important. Major efforts will be made during this time to"obtai~ the data required to evaluate the best ultimate recovery plan for the Lisburne Resër~oir. Information must be obtained on formation producing "..1 --characteristics, recovery mechanisms, flow characteristics, formation continuity, fluid compatibility, and reservoir limits. One of the first tests is planned to begin in early 1985. South Point State No. 1 may be placed on a long term production test to determine extended production characteristics such as oil rate, bottomhole pressure, GaR, and water production. It is anticipated that the test will last until field start-up. This information will be used to confirm equipment design assumptions and to provide early production data for computer model simulations. ARCO, Exxon. and Sohio are presently designing a five well interference test to be conducted from drillsite L2 durinq mid-1985. One 80 acre well will be needed which will require an exception to the field rules requested today. The purpose of this test is to determine effective vertical and horizontal reservoir permeabilities, directional permeability trends, and zonal isolation. Another part of this test will be a limited drainage area test to obtain early information on how the reservoir fracture and matrix systems produce under finite reservoir conditions. This information will assist in our understanding of the reservoir performance during primary and secondary recovery. Fld Rulesdc2 ·14 ~- It Other tests may be conducted as prudent to obtain the information- required to select an appropriate secondary/enhanced recovery method. Upon completion of limi ted drainage tests and pending continued ·po£~tive results from laboratory studies, a pilot waterflood test is planned. Satisfactory pilot water flood performance could lead to a commitment to a full field waterflood project. Gas injectivity tests may be conducted and tests will be made to determine the extent of gas cap communication with the oil column. The current goal is to gather enough information to permit commitment to a full field secondary/EaR project by early 1989. This concludes my testimony on Reservoir Analysis and I would now like to introduce Don Breeden who will speak on Drilling and Well Design. Fld Rulesdc2 15 ,I·· \\ DRILLING AND WELL DESIGN My name is~ðon-·Breeden. I am a Senior Drilling Engineer for ARCO. I am a 1973 graduate of Montana State University with a Bachelor of Science degree in Mechanical Engineering. I have ten years of oil and gas industry experience, with nine of those years in drilling and workovers. I was hired by ARCO Alaska's drilling department in 1979 and have since worked about equal times as a drilling engineer and drilling foreman. I have worked on the Lisburne Reservoir since October" 1983, initially as a rig supervisor on South Bay State No. 1 and since March, as a drilling engineer. My testimony includes a brief description of drilling and well design for the Lisburne Reservoir. As with other North Slope oilfields, we will directionally drill the Lisburne wells from centrally located gravel pads. Drilling procedures and well design for the Lisburne Reservoir will be very similar to those now used in the Prudhoe Bay Field. The casing program is the same, except that the casing will be set deeper, as appropriate for the Lisburne. As shown on Exhibit 11, a 20 inch conductor casing will be set 75 to 80 feet below pad level and cemented to surface using the "PolesetR" method. This is the primary cementing method used by ARca on the Prudhoe Bay Unit conductors. It has sufficient strength, provides some added insulating qualities, and has reduced Fld Rulesdc2 16 (' ( or eliminated the incidence of conductors settling while drilling surface holes. After the conductor has been set, a drilling rig will be moved in and a diverter system will be installed on the conductor. This system will include an annular preventer and two diverter lines vented in different directions. The system will be set to automatically open the valves on the diverter lines if the annular preventer is closed. A 17~ inch hole will be drilled to a depth between 4000 and 5000 feet True Vertical Depth (TVD) where 13-3/8 inch surface casing will be set and cemented back to surface. This increased setting depth will provide added kick tolerance. This is a necessary precaution, since the next section of hole will be drilled through the drawndown Permo-Triassic gas cap, before sp.tting intermediate casing. The casing head and a 5000 psi blowout preventer stack will be installed and tested, consistent with Commission requirements. A 12~ inch hole will be drilled below surface casing into the shale between the Sadlerochit and the Lisburne. An intermediate string of 9-5/8 inch casing will be set near the top of the Lisburne and will be cemented to provide at least 500 feet of coverage over the Sag River sand, or the Put River sand, if present. The 9-5/8 inch by 13-3/8 inch annulus will be left temporarily uncemented so that it can be used for injection of excess drilling fluids. That annulus will then be filled wi th cement and "arctic pack" to a point below the base of the permafrost. Fld Rulesdc2 17 ,{ ( An 8~ inch hole will be drilled through the Lisburne production interval. After logging, a 7 inch production liner will be set and cemented. - The casing program I have just described is planned for the early development wells. Other completion methods and casing programs will be considered as our knowledge of the reservoir and drilling conditions grows. Alternative completion methods are a major area of interest. Slotted liners, screen liners, and open-hole completions have been used wi th good results in other carbonate reservoirs around the world. With' some refinements in drilling technology, high angle drain holes may also prove to be beneficial to efficient reservoir drainage. The possibility of running two weights and grades of surface casing will also be evaluated early in the development. Generally, the loads due to permafrost thaw-subsidence and freezeback are significantly greater than the loads imposed while drilling. A combination string of surface casing could be run with the accepted permafrost design casing through the permafrost interval and the lighter weight and grade casing below the permafrost. The sui tabili ty of the surface casing for permafrost service on the drilling island will be verified. An overall reduction of casing sizes will also be considered. The stated casing program includes the contingency to set a 7-5/8 inch Fld Rulesdc2 '18 { drilling liner across the Sadlerochit and a 5 inch liner through the Lisburne production interval if required by hole conditions. If that contingency does not occur, there may be strong economic incentive to. 'reduce hole and casing sizes. A final point on the casing program is that it is designed for hydrogen sulfide (H2S) service, as are the completion equipment, tubing, and wellhead equipment. H2S first appeared during testing of Pingut State No.1. During that test, the, concentration stabilized at about 1400 ppm. Sag Delta No. 6 contained a comparatively low concentration of about 25 ppm. The other Lisburne wells showed only trace amounts of 10 ppm or less. Production test history indicates the high concentrations of H2S are cGnfined to the area around Pingut State No.1. We will follow safe drilling practices, keeping in mind the affects of this gas on both people and equipment. To insure personnel safety, we will continuously monitor for the presence of H28. A readily available supply of H2S scavenger, such as zinc carbonate, will be maintained to treat the entire mud system, if needed. Emergency operating and remedial procedures will be drawn up and posted and a supply of personnel protective equipment will be kept at the well site. All personnel on the rig will be informed of the dangers of H2S, and all rig site supervisors will be trained for operations in an H2S environment. Fld Rulesdc2 '19 ,~ i These practices will be followed throughout the Lisburne' development until drilling history proves they are not required. In addition, on àl~wells drilled into the area of Pingut State No. 1, we will 'fol1-ow the recommendations in API RP49 "Safe Drilling of Wells Containing Hydrogen Sulfide". The nature of the wells to be drilled requires the use of grade G-105 drill pipe. Some of the high angle and long departure wells may require grade S-135 drill pipe. These materials are susceptible to sulfide stress cracking, but can be used safely under the controlled conditions recommended in Section 8, "Drill Stem Corrosion and Sulfide Stress Cracking", of API RP7G, "Drill Stem Design and Operating Limits". We will follow those guidelines, as appropriate. This concludes my testimony. facilities description. Ron Beach will now present the Fld Rulesdc2 20 ~ FACILITIES DESCRIPTION INTRODUCTION' -- My name is L. Ron Beach and I am the Lisburne Facilities Planning Engineering Supervisor responsible to ARCO Alaska, Inc. for the integrity and workability of the Lisburne Production Facilities. I am a 1974 graduate of the Colorado School of Mines wi th a Bachelor of Science degree in Chemical and Petroleum Refining Engineering. ¡ have been involved in the design, construction, maintenance, or operation of hydrocarbon processing facilities for the past ten ýears. I have been an employee of Atlantic Richfield since 1980 whereupon I was first a senior process design engineer for coal gasification and synthetic fuel systems. After that, I was a project manager responsible for designing and constructing oil and gas processing facilities, both on platforms in the Gulf of Mexico and on land. Presently, I am the Facility Planning Engineering Supervisor for the Lisburne project. My testimony today will include a description of the Lisburne Facilities. Fld Rulesdc2 21 \ The Lisburne Development area is located within the Prudhoe Bay uni t northeast of the Trans Alaska Pipeline System (TAPS) Pump Station No. 1. Th~ development will have five onshore drill sites, one offshorê"drilling island, one pad for gas injection only (LGI) , one Lisburne Production Center (LPC) , interconnecting roads and flowlines and a 6 mile, 16 inch diameter oil sales pipeline from the LPC to TAPS Pump Station 1 as shown on Exhibit 12. ONSHORE DRILL SITES The development plan for' the onshore drill sites includes four drill sites sk.irting the shoreline of Prudhoe Bay with a fifth drill site some 3 miles inland to the southeast near the west bank of the Sag River. The five drill sites are Ll, L2, L3, L4, and L5. Drill site Ll will have slots for 32 wells, while the remaining onshore dril·l sites will each contain slots for 36 wells in two rows on 60 foot centers. From the wellhead, production flowlines are connected to three-phase (oil, gas & water) production and test headers, one production and one test header per row of wells as shown in Exhibit 13. The two production headers are joined outside the drill site module just upstream of the drill site emergency shut down valves as are the two test headers. The production header and the test header are then routed to separate coils in an indirect-fired drill site heater where the fluids are heated to 140 OF to improve the flow characteristics between the drill si te and the LPC. All external lines between the individual well wing valves and the heater inlet flanges will be insulated. Fld Rulesdc2 22 '~ The great majority of Lisburne production wells are expected to be' naturally-flowing. Should some wells require artificial lift, high pressure gas is av~ilable at the drillsites. Headers, laterals and chokes for -4a~-'lift will be installed as necessary. All well control and testing functions at the drill sites will be performed manually by a drill site operator with the exception of the well safety shut-in systems (which are automatic) and the drill site emergency shut down system which can either be triggered manually or automatically by certain out of limit conditions. Data gathering at the drill site will be both a manual and automë.tic function. The Lisburne Data Gathering System will continuously monitor the flowing status, pressures, and temperatures ·of the producing wells at the drill sites. This data will be under a drill site operator's supervision via his moni taring station wi thin the drill si te module. Wells on test will have continuous monitoring of pressures, temperatures and flows (oil/gas/water) off each leg of the test separator. The rate of production from each well will be regulated by manually adjusted chokes. Normally the flow from the wells is routed to the production header and advances to the LPC for processing. Any individual well may be routed to the test header by manual operation of divert valves at a manifold skid located near the wellhead. Usually, only one well will be on test at each drill site at any given time. Fld Rulesdc2 -23 ~; OFFSHORE DRILLING ISLAND The sixth drilling location in the Lisburne Development Area is a proposed gravel island within the confines of Prudhoe Bay approximately·-13000 ft. offshore and connected to the shoreline by a gravel causeway as depicted in Exhibit 12. While the processing scheme for the production from this location is the same as that for the five onshore drill sites previously described, some significant differences exist which are enumerated here. First, there are slots for 40 wells on the island, of which 32 are to be producers and 8 are gas injectors similar to those on the Lisburne Gas Injection (LGI) pad which will be described later. These wells are in two rows, as onshore, but on 10 foot centers to minimize island size. This closer wellhead spacing was chosen to minimize potential environmental impacts at this location and to reduce investment. To prevent degradation of the island structure due to wave and/or ice action, partial slope protection may be installed at the time of the island's construction. The proposed causeway to shore will not be slope protected but be buil t with a 1: 7 vertical to horizontal slope as this is a more cost effective approach for this 2~ mile long structure. The production line from the island, the gas inj ection line to the island and the power cable to the island will be buried in the causeway to prevent damage by any natural or accidental occurrence. Fld Rulesdc2 '24 1,( GAS INJECTION The produced gas, in excess of that consumed as fuel, will be reinjected into "the Lisburne gas cap. This is accomplished at DS-L6 locat-èd-- -offshore in the northern part of the reservoir as well as from the onshore pad DS-LGI. Two gas injection locations are required in order to distribute the injected gas over the entire gas cap. INTERCONNECTING ROADS AND FLOWLINES Du~ to the proximi ty of the Lisburne Development Area to the existing Permo~Triassic facilities, the maximum practical use will be made of the existing roads and pipeline construction pads. New access roads and pipeline construction pads will only be built in those areas where new pipeline right-of-ways are being established. All roads and pads will be constructed from locally mined gravel. Production flows to the LPC from the drill sites through a system of partially trunked flowlines as shown on Exhibit 12. The reinjection gas line to L6 (and LGI) uses the same pipeline route as the flowlines from Ll. Drill sites Ll, L2 and L6 take fuel gas off this line. The reinjection gas line branches at DS-Ll before going into the causeway or on to LGI. As with the production lines, either branch can be shut in without affecting the flow of gas to the second destination. Should down dip injection be necessary, provisions have been made to allow for this injection at each of the drillsites with some facility modification. Fld Rulesdc2 25 it LISBURNE PRODUCTION CENTER The Lisburne development requires the installation of an independ~n1: prodùc-tion facili ty since the existing Permo-Triassic flow stati6~~~làck the capacity to handle in the near term all the oil and gas currently planned to be produced from the Lisburne Reservoir. The plot plan of the Lisburne Production Center (LPC) is shown in Exhibit 14. The Lisburne Production Center (LPC) separates the crude feed stream into oil, gas and water as depicted in Exhibit 15, the overall process flow diagram. Nominal design rates for the LPC are 100 MBD of oil, 10 MBD of water and 600 ~MSCFD of natural gas. The crude oil is' processed to TAPS specifications and pumped to the pipeline while the gas and produced water are separated and reinjected into the Lisburne and Tertiary or Cretaceous sands. The crude feed streams enter the LPC and are manifolded into a single header. The crude proceeds to the high pressure separator. Free gas and water are separated in this vessel. Oil then flows to the Interstage Crude Heater where its temperature is raised. Liberated gas is separated and the oil is gravity fed to a pair of electrostatic treaters where it is dewatered to the TAPS specification. The separated water is combined with the free water from the high pressure separator and pumped into a disposal well located at the LPC pad. Oil from the treaters is then further flashed and the remaining solution gas is liberated. The oil is cooled, metered and pumped to TAPS Pump Station #1. Fld Rulesdc2 26 ') ) The gas is compressed and dehydrated by contact with triethylenê glycol (TEG) to a water dew point of -40°F at 500 pound per square inch gauge. The gas is compressed to injection pressure in two trains, eà-bö.·'·· train using a gas turbine driven centrifugal compressor system. The first stage of compression raises the gas pressure to approximately 1500 pounds per square inch gauge at which point approximately 10% of the stream is removed for use as plant fuel. The remaining gas then proceeds to the second stage of compression which increases the pressure to 4700 pounds per square inch gauge and routing into the gas reinjection line. Five horizontal process safety flare tips, three high pressure and two low pressure, will be installed at the flare pit to the north of the LPC. Because the flare volumes will not exceed pilot and purge gas quantities of 1 million cubic feet per day other than in cases of emergency or operational necessity, the flare is not designed for smokeless operation. The three high pressure flare tips are identical and each is capable of handling 50% of the high pressure relief. Each low pressure flare tip is capable of handling 100% of the low pressure relief. Interconnecting piping and sufficient spacing will be provided to allow the isolation of anyone high pressure or low pressure tip so that it can be taken out of service without compromising plant safety. The automatic gas detection system at all Lisburne facilities will include hydrogen sulfide (H2S) monitoring due to the presence of the substance in parts of the reservoir. This system provides a safe and effective means of dealing with the presence of H2S. The Fld Rulesdc2 27 Lisburne Production Center design criteria for H2S- has considered all relevant industry, state, local and federal regulations and has incorporated industry experience and good engineering practice to ensure peršònnel, environmental and equipment safety. As with other North Slope facilities, the Lisburne Production Center will be provided with a fire and gas safety system including automatic hydrocarbon gas detection, halon deluge system and a firewater system. Fire and gas alarms will trigger operator response for initiation of the emergency shut down system. The Lisburne Production Center utilities include circulating process heating and cooling systems, a fourteen megawatt power plant with appropriate spare capacity; a plant and instrument air system; a heating and ventilating system; and direct fired heaters for utility, life support and back up process heat. Other support facilities include a data acquisition system (that will be microwave linked to the Prudhoe Bay Uni t communications center), local and central control rooms, maintenance facilities, and warehousing space. Major maintenance shops are currently planned to be shared wi th the existing PBU facili ties. Living quarters will be built in the proximity of the existing Prudhoe Bay Operations Center. These facilities will require between 80 and 100 North Slope assigned personnel per shift (or approximately 180 people total) for operation, maint8nance and on-site engineering. These numbers do not include drilling or workover rig crews, contract maintenance personnel, construction crews, or Anchorage based staff support. FId Rulesdc2 .28 ') ) This concludes my testimony today regarding Lisburne facili ties.' D. K. Chancey will" now discuss Well Operations. -- Fld Rulesdc2 . 29 ) WELL OPERATIONS INTRODUCTION - My testimony today will touch on two topics. First, I will describe our typical well design and the alternatives for well completions that are being investigated. Then, I will present our field wide reservoir surveillance plans. Phase I - Well Design and Completions Exhibit 16 is a simplified wellbore diagram which illustrates the design of a typical Lisburne completion. We have selected a 7 inch, K-55 production liner. You will notice we plan to run 2-7/8 inch or 3-1/2 inch tubing with 5 or 6 gas lift mandrels supplied with dummy valves. This completion scheme will give us the freedom to artificially lift if it becomes necessary. The number of mandrels will provide the flexibility needed due to fluctuations in gas lift supply pressure, well productivity, and produced water-oil ratio. Paraffin deposi tion has been seen in tubing and flowlines during the two month tests of several Lisburne wells. Several alternatives are under consideration for controlling this paraffin deposition. The method which we currently plan to employ will call for the injection of chemical inhibitors through downhole valves installed in the tubing. Other possibilities that continue to be investigated are insulated tubing to maintain the temperature of the fluid stream above the wax crystallization point, gelled packer Fld Rulesdc2 30 ) ) fluids and-periodic tubing washes with hot oil or piraffin solvents to remove :W._,'deposits that form despite preventive measures. Subsurface'~-Sa"féty Valves In the interest of operating the Lisburne Reservoir in a similar manner as other Prudhoe Bay Unit reservoirs, subsurface safety valves will be installed in all wells capable of natural flow. Completion Techniques Drillstem testing has indicated that the unstimulated Lisburne flow capacity is lo~, and in fact, the Lisburne intervals will often not flow prior to some form of stimulation. The testing demonstrated that the reservoir was tight with an average unstimulated permeability of less than two millidarcies. One explanation for the low unstimulated flow capacity is formation damaged during drilling operations. This hypothesis is supported by the severe fluid loss observed in two wells when initially drilling the reservoir and after acidization. What we have seen prior to well stimulation is essentially a matrix only response. Comparing the permeabilities both before and after stimulation indicates that there is a 10-20 fold improvement in conductivi ty between purely matrix flow and composite fracture and matrix flow in the Lisburne Reservoir. A second explanation for the flow improvement is that the acid cleans up the partially calcite filled fractures. Therefore, in our efforts to improve Lisburne flow efficiencies, we are looking into three areas of well completion. These areas are: 1) drilling fluids, 2) stimulation methods, and 3) alternate completions, each of which will be discussed below. Fld Rulesdc2 31 ) ) Drilling Fluids In attempting to minimize skin damage from drilling and to improve . our ability to in.terpret open hole logs, various types of mud systems inéi.uding oil base , salt water base, and fresh water base systems have been tried. No decision on optimum mud system has been made, but we plan to continue trying different mud syste~s to evaluate the effect they have on drilling and producing Lisburne wells. Stimulation Methods We are in a very early stage of defining the most effective stimulation method. Our approach is designed to provide maximum flexibility. - We will acidize, test the zone with regard to productivity, and possibly perform an acid fracture or a propped fracture treatment. Alternative Completions Alternative completion designs may offer opportunities to minimize flow obstructions around the wellbore. One of the configurations that merits study is open hole completions. Although no open hole completions have been performed in Lisburne wells to date, the method has been successfully employed worldwide in other carbonate reservoirs and in sandstone reservoirs on the North Slope. Several open hole tests have been performed in the Lisburne Reservoir. No excessive formation sloughing was observed during these tests, nor were problems setting pipe experienced following the test. Therefore, we do not anticipate any problems with hole sloughing in an extended production period using open hole completions. Fld Rulesdc2 32 ) With a naturally fractured reservoir it may be appropriate ~o onlý perforate',:t.he bottom of the commercial oil zone in producing wells. This wouldminimiz~ gas coning and cycling if gravity drainage is a dominant rese·rvoir drive mechanism. It might also eliminate the need for a costly workover program to remove perforations producing predominantly gas. Other completion schemes such as lateral drainholes may be worth testing during the development of the Lisburne Reservoir as another means to overcome the low well flow efficiencies encountered thus far. Reservoir Surveillance Program As has been noted earlier, data will be required to monitor reservoir performance, define reservoir properties, and provide the basis for effective reservoir management. I will now outline our plan for obtaining this data. This information is categorized into two areas. The areas a.re bottom-hole pressure measurements, and well testing. Bottom-Hole Pressure Measurements For prudent reservoir management, it will be important to maintain an updated isobar map of bottom-hole pressures. These pressures will be reported at the common subsea datum elevation of 8,900-feet. An initial static reservoir pressure will be measured in each well prior to significant production. This will be done by either a Fld Rulesdc2 33 ) pressure build-up test or by simply measuring the bottom hole- pressure after thè well has been shut-in for an extended period. The initial statiC- pressure surveys will be used to update the pressure isoéar map during the development Because of the extended pressure buildup periods accurate pressure measurements, for economic prefer flexibility in obtaining follow-up pressures. At least one well per drillsite will have a representative pressure taken annually following field start-up. The pressure surveys will be filed with the Commission annually. drilling program. required to obtain reasons we would Well Testing A critical aspect of any reservoir surveillance and management program is accurate production data. Production volumes from each well will be 'measured on a semi~annual basis under normal operating conditions for a minimum four-hour period. Four-hour test periods have proven sufficient in other reservoirs with similar well rates to give representative data. The test will determine oil, gas, and water rates, oil gravity, oil basic sediment and water content, and flowing temperature and pressure at the choke. More frequent tests will be taken as required for proper production allocation between wells and prudent reservoir surveillance and operational decisions. The test results will be filed with the Commission semi-annually. Production Logs Some production logs will be run in selected Lisburne wells and this data will be provided to the Commission. However, surveys will not be run on a routine basis in all wells because it is Fld Rulesdc2 '34 doubtful they will be of technical value in performance monitoring of this reservoir-. Since the Lisburne is a naturally fractured reservoir, product~on surveys in the wellbore will not necessarily indicate th:e-"-:_ proper quanti ty of fluid being produced from individual porous intervals within the Reservoir. In addition, we plan to hydraulically fracture many of the Lisburne wells to increase productivity. The induced fracture will obscure fluid origin and cause uncertainty in any results derived from production logs. Relatively low well production rates in the 7 inch liners and free gas influx further complicates interpretation of production logs. Gas-Oil and Oil-Water Contact Monitoring Logs run to date have not been able to distinguish gas/oil or oil/water co~tacts. The combination of low reservoir porosity and low formation water salinity place the standard neutron tools outside their design range for formation evaluation, and therefore, cased hole neutron logs will not be run on a routine basis to moni tor fluid contacts. Some experimental tools may be run in selected Lisburne wells to evaluate our abili ty to moni tor fluid contacts and these logs will be provided to the Commission. There are no cased hole logging tools available today which have been shown to be able to monitor fluid contacts under the Lisburne Reservoir conditions. We will continue to evaluate new logging tools and analysis techniques as they evolve. This concludes my testimony today. I would now like to introduce L. E. Tate who will summarize our testimony. Fld Rulesdc2 35 ) ) SUMMARY OF TESTIMONY Mr. Chairman";-·-'"inembers of the Alaska Oil and Gas Conservation Commission~ ladies and gentlemen. My name is Leland E. Tate. I am Vice President of Engineering and Extension Exploration for ARca Alaska, Inc. I received a Bachelor of Science Degree in Petroleum Engineering from Texas Tech University in 1970. I have worked in Alaska for ARca for the past nine years. I have direct responsibility for Lisburne Design and Development. As discussed today, ARca and the other owners have been evaluating the Lisburne Reservoir for some time. The data and information gained to date has allowed the owners to commit the full field development of the Lisburne. However, even with this commitment, the parties still need to acquire additional data and information to optimize production techniques and maximize oil recovery. The development of the Lisburne poses some unique problems. This reservoir has different geological characteristics from other reservoirs discovered on the North Slope and will provide challenges to both the owners and the Commission. The owners are committed to operation. The facilities are efficient manner and provide employees and the environment. a safe and environmentally sound designed to operate in a safe and built-in protection to both our Fld Rulesdc2 36 ) ') The reservoir data program will provide valuable information and- data concerning the Lisburne for orderly and efficient reservoir development. . - The drilling program will meet or exceed the requirements noted in Commission regulations and utilize valuable information gained from previous drilling activity. The development of the Lisburne Reservoir provides opportunities for both the owners and the State of Alaska. ARca and the other owners look fo~ward to meeting the development challenges with you and bringing into production another major field on the North Slope. The three owners are currently negotiating to establish a Lisburne Participating Area within the Prudhoe Bay Unit prior to start-up of full field production. We anticipate that these agreements will be completed in early 1986. We thank you for the opportunity to provide this testimony today and are now available to address any questions you may have. Fld Rulesdc2 37 ) PROPOSED LISBURNE FIELD RULES The rules wh.ieh·. follow pertain to the following areas: T10N, R14E, U.M. Sections 1,2,11, and 12 TI1N, R16E, U.M. 1,2,3,4,5,6,7,8,9,10,11,12, 13,14,15,16,17,18,19,20,21, 22,23,24,27,28,29,30,31,32, 33, and 34 TI0N, R15E, U.M. 1,2,3,4,5,6,7,8,9,10, 11, and 12 T12N, R13E, U.M. Sections 35 and 36 TI0N, R16E, U.M. 3,4,5,6,7,8,9, and 10 TI2N, R14E, U.M. Sections 22,23,24,25,26,27, 28,31,32,33,34,35 and 36 T11N, R13E, U.M. Sections 1,2,3,4,8,9,10,11,12 13,14,15,16,17,21,22,23,24 and 25 TI2N, RI5E, U.M. Sections 19,20,21,22,23,24, 25,26,27,28,29,30,31,32,33, 34,35 and 36 T11N, R14E, U.M. All Sections TI2N, RI6E, U.M. Sections 25,26,27,28,29,30, 31,32,33,34,35 and 36 T 11 N, R 15 E, U '. M . All Sections Fld rulesdc2 38 ) Rule No.1: Name of Field The name of the fie1.d is Prudhoe Bay Field. Rule No.2: Definition of Pool The Lisburne Pool is defined as the accumulation of hydrocarbons that is common to and correlates with accumulations found in the Atlantic Richfield-Humble Prudhoe Bay State No. 1 well between the measured depths 8790 feet and 10440 feet MD. These depths are referenced to' the Kelly bushing elevation and are depths as measured by the Schlumberger Compensated Formation Density log, Run 5, dated March 9, 1968 and Run 6 , dated Apri 1 14, 1968 . Upon application, the commission can administratively approve changes in the pool rule affected area. Rule 3: Well Spacing In the affected area, the following rules shall apply: a) no pay shall be opened in a well closer than 1000 feet to any pay opened in anQther well in the Lisburne Oil Pool or be nearer than 500 feet to the boundary of the affected area; and b) not more than one well may be drilled to the Lisburne on any government quarter section; c) wells with closer spacing than described in 3a) or 3b) may be approved administratively upon application. Fld rulesdc2 39 ) Rule 4: Casing and Cementing a) Casinq and cementing requirements are as specified in 20 AAC 25.030. CASING AND CEMENTING, except as modified below. "- b) 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. High density modified polyurethane foam, such as PolesetR or other material administratively approved by the Commission, may also be used as a cementing material. c) A string of surface casing shall be set at least 500 measured feet below the base of the permafrost section, but not below 5000 feet true vertical depth. Sufficient cement shall be used to' fill the annulus behind the casing to the surface. d) The surface casing in contact with the permafrost, including connections, shall have minimum axial strain properties required to prevent damage due to permafrost thaw and freezeback. 1) The only types and grades of casing with threaded connections that shall be used in Lisburne Oil Pool development drilling and have been approved for use in other North Slope Fields as surface casing in the permafrost are the following: A. 13-3/8", 72 lb/ft., L-80 Buttress Fld rulesdc2 40 ) B. 13-3/8", 72 Ib/ft., C,;.¡::::]':.·3;i:-0318" , 68 Ib 1ft. , "''I D ,,'."',':'. 1 0 3'1 4-" ':'::."I~!,"'(:"'" . - _, ) N-80 Buttress MN-80 Buttress 45.5 Ib/ft., K-55 Buttress E..--.i_-:Hl~.3/4n,· 45.5 lb/ft., HF-ERW Arctic Grade, J-55 Buttress F. 9-5/8", 36 lb/ft., 9-5/8", 40 lb 1ft. , 9-5/8", 36 lb/ft. , J-55 Buttress G. H. I. 9-5/8", 40 lb/ft., J,-55 Buttress J. 9-5/8", 47 lb/ft., K-55 Buttress K-55 Buttress HF-ERW Arctic Grade, HF-ERW Arctic Grade, L-80 Buttress 2) The Commission may administratively approve other types and. grades of surface casing for use in the permafrost interval upon a showing that the proposed casing and connection can meet the load requirements of permafrost thaw-subsidence and freeze back. This evidence shall consist of one of the following. A. full scale tensile and compressive tests B. finite element model studies; or, Commission c. other types of axial strain data acceptable to the 3) Sound engineering practice shall govern the selection of surface casing to be run in the string above the conductor casing shoe and below the permafrost interval. Fld rulesdc2 41 ') ) e) Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze back may be å~inistratively approved by the Commission. - - ._.. f) The Commission may approve alternative completion methods (to 20 AAC 25.030 (b) (4) and (5) ) based upon application for Permit to Drill (Form 10-401). 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 last casing string is set not more than 100 feet above the productive zone. 3) high angle drain holes. Rule 5: Blowout Prevention Equipment a) The blowout prevention equipment and its use shall be in accordance with 20 AAC 25.035 BLOWOUT PREVENTION EQUIPMENT. Rule 6: Hydrogen Sulfide a) Where applicable, operator shall comply wi th 20 MC 25.065 HYDROGEN SULFIDE, except as modified below: Fld rulesdc2 42 ) ') 1) High strength drill pipe shall be used according to the. requi,r,ements of API RP 7G (Section 8) "Drill Stern Design and Operáting Limits (Drill Stern Corrosion and Sulfide St·r~·as. . Cracking) " . Rule 7: Automatic Shut-in Equipment All wells which are capable of unassisted flow of hydrocarbons, will be equipped with a fail-safe automatic subsurface safety valve (SSSV) . This valve will be in the tubing string located no shallower than the base of the permafrost and must be capable of preventing an uncontrolled flow. Rule 8: Gas Venting or Flaring a) The daily average volume of 1000 MCF/day is permitted for safety flare in the Lisburne Production Center. b) Safety flare volumes for additional facilities may be approved administratively upon application. c) Safety flare volumes administratively. may be increased or decreased d) Flare volumes for planned activities such as initial start-up or commissioning new equipment may be approved administratively. Fld rulesdc2 ·43 ) ,) Ru 1 e 9: Gas-Oil Ratio Tests Between days after regular production and each six months the·r~a.f-t·er" a gas-oil ratio test shall be taken on each producing well. The test shall be of at least four 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, semi-annually. Rule 10: Pressure Surveys a) A static bottom hole pressure survey shall be taken on each well prior to regular production. b) Within ~ year following complAtion of development drilling program and after start of significant production, a pressure survey shall be taken from one well on every drillsite every 12 months. c) Data from the surveys required in this rule shall be filed with the Commission annually. Reservoir Pressure Report, Form 10-412 shall be utilized for all surveys with attachments 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. Fld rulesdc2 ,44 45 Fld rulesdc2 Conservation Order No. 83C is hereby cancelled. Order Cancelled Rule 12: commission, will be returned to the Lisburne Oil Pool. operations or. administratively approved for other purposes by the upper limit if all produced gas, except quantities used in lease The gas-oil ratio on individual wells will not be subject to an Maximum Gas-Oil Ratio Rule 11: prescribed in (d) of this rule. techniques, tests, or surveys shall also be submitted as e) Result~ .and data from any special reservoir pressure monitoring subsea. d) The Lisburne Pool pressure datum plane shall be 8900 feet ) ) l.'.. ,- . '. C ,,_ f). 8/\3 CONSER\f,\ ¡ :~=;;.~ (~'C):/,ì'JtSS!ON EXHIBIT 1 Co J-c7 C~:F¡c;t: espy , -, BEAUFORT SEA ~ kUPARUk RIVER UNIT LISBURNE / . ~ c( ~ "I o 5 a.. Mf LEr 407984006 R 0 -..,/ EXHIBIT 2 ----, r----' I + + ~----------------I BE/lUFORT e eMIAdIe a2 SE/l 0tLL IS.ST.a' NINdJc-ar - - - - - - - - - --. .8EI'CH ST .ai\ \ 'NINl.U< a,A I + + --...---....-- + +A II.BEACH ST.a. & 91'0. on. TA -S I . . . 31 36 3' TERM NELL .., 36 ooeOlLL IS.Sf .e2~ ~ 0 SIlO. DELTA o. . : L~ , 'Ji. DS-L6 DS dl ~. DELTA ., . . 1C-07 N.ø.~Y ST.I .--, . DS-Ll PRUDHOE BIlY ~ I t-- .+ + + + + £.8I'Y ST.-. I I J... PMØŒ Bit' ST .., . .' ., I I I «, ~ ~ ...~ ~ IN ~ J__ ~ ~ ~ i so-{H g-fA· + + + ... - ~ + ...... ...' "' -œ-L3 , "- "'- I ""9ft m .I'A. ~ PU" .R.27-11-1I4 2-S 4- . e . + + 4.-- + + + + + 31 3i 11 35 31 . 6 + + + + + + + + + + DELTA ST..t . ~ ~ ~ ...:" ~ ,tb ~' ~ ~ ~ -~,\j + ... + + ... + + + + + + + + <c, ,C) ,,() ~ ,0~G· ~ "- "- "'- ~ A + ., "- + + + + + + + + + + + + 3tI 3\ 36 3& 3L 36 31 38 LISBURNE . FIELD + + + + + + + + + RULES AREA + + + + + + + + + 407984005 ( TMK, CI.N.""L..z.a.T }TIORAtaHIC ..CTIQN ..ND" 'j...NC. '-QQ "-"wDHa. ... v fll...a, ..L...8ec A ·Ge a T e~oo' " " " " " 775' 1300' 725' 3000' . uK IK J ,~ ~ '-, ~ N....e GUBIK FU, LITMOlOGY' ..-. .. - - - -'- .- . - . -. - - '- - ' SAGAVANIRI< TOI< " FM. " " '" 'A' '.~~~' =?-: --= . 'B' '-- LISBURNE GP, , - - .... . I ~ " . . . "- M " ENDICOTT GP o OLoe~ I T I( I~" j AlA.. O...Ã7 ,.. BASEMENT I".OT TO SCALE] EXHIBIT 3 . alt. T~ IoI.U.... ,A,~__... J-- ~-') v~. \ , ',' , . . ~ ~._.:..._..-.., ~ Z 0 = c a Z \ .:F a: 0 Z .... ~ Q. ~. . . } g : c . ~ :~/~.....~::: 110O - tIOO - IODOO _ lO'DO- 10_- ,~- 10M0- ,__ ......au.lo OI'T", :~~ . .'. ....~..\. ~-~ ...,....:.... . . . . . . . . . ~ . . . .. . .. - .. ~1 f~)~ ~ , , . ;-p':',\V' " " ). . ): <\>: .., .¿" .'., '. . , ~ . ;.1....-(~ , " ~-;~ r , "~-:'-'-~(( ~~)¡~ ,, ...~, ). ,....) . '... aT t· I ~:<~~ , t , , . . ... ... - ~ '-';"'i-~-~-; '~~. (.':.../.....-J ,1 _ 1_ 1- 1;.::.>..,:, :'~ . . - ,~~ z 2 Z' Þ- ~ C Q. I ~ o en .... ~ : en f ~ ~ 2 c 'e' ~ -... COLVILLE ::II GP. '0' ¡ HIGHL Y RADIOACTIve ZONE . ! KUPARUK ~IVER FM. 1- - -, ~owEA CAE T4CEOuS S"'''I,E VIIIIT 1 t KINGAK FM. _. f SAG RI\'. FM." L SHUBLIK FM~f ~~. ~~ " ., ,-. ~.. ',. . "-... SADLEROCHIT IVIS"''''' 5S'''' ::..,.....,~.~~ P ,I GP I(AYI. S"'''I.E'''' ~ EC..OOI( A 1=''', J.... I ' . :: ~ _ : $ ~""A"I IT~I"'.....I... EXHIBIT 4 T TOP LISBURNE STRUCTURE MAP --~~--~------~----~----~-~ I I I PRUDHOE BAY UNIT ~----------------- - )} J/ '\' \ C.I. · 200' 5 MI LES D -------------~ I I I "'----_.1 r------", w. BEACH STATE #2 -~ ~j GUll IS.'" STATE #2 .... -8600' '\J E. BAY· ~ STATE #1 I I ''''8 8~, , -9CJ$J I SAG RIVER .. STATE #1 - -9200 t ~; t -9400 ' t:!.n I AAAI'V'\~ ) N-S STRUCTURAL CROSS SECTION QULL. J SLAND EXHIBIT 5 .' 511nE -2 N 1:1 S ...... . 8400 - ::i:; :. -MOO 8450 - - 1M50 EAST BAY esoo - STATE *1 - 9500 ¿-- øsso - r - 8550 QR 8BOO - ,~ - 8800 .-so - ,. - 8850 ~ 8700 - - 8700 81'50 - ( - 8750 ~ 8SOO - ~ - 8800 IIISO - - 8850 8900 - ~ -8900 89SO - s=. - 8950 SAG RIVER 9000 - <-- STATE -1 - 9000 9050 - ~ - 9050 GR .."..100 9100 - - 9100 9150 - ~ - !U50 I 9200 - ~-: ~ - 9200 92SO - .. T - 9250 .. ~. ~ 9::JOO - ~ - 9300 93SO - f - 9350 ~ ~ 9400 - L.. - 9400 .. 9450 - ~ - 9"50 9500 - l .. 9500 9550 - ; - - 9550 ~ .,. 9600 - ~ - 9600 \"" 96SO - ~ - 9650 9100 - - 9700 9?50 - F - 9750 9800 - - !IeOO 9850 - l. - 8e5O 0 2 ~ 9900 - I \ - "DO 99!50 - SCALE IN Þ4ILES >. - 9950 2 ??oo - - 10000 ~! U81r'1 WEST BEACH STATE -2 W E 1300 - QULl ISLAND - 8300 STATE -2 I35Q - - B350 QR . . . . - I- .400 - ~~ - 8400 -;r 8450 - (" .I"t. _ - 9450 1500 - SAG DELTA - 8500 STATE -5 8550 - "- - 8550 t!" QR 8800 - }- ...... - 8600 - 8650 - ~ _.~~~ - 8650 8700 - - 8700 :t= 87!iO - ~ >-- - 87'50 110O - ~ ~ ~ - 9BOO -= I8SO - ~ ~ ~, . - 8SSO >- 8900 - ~ .~ - 8SOO 1950 - ~ - 8950 .. 9000 - > - 9000 ~ '- !)OI;O - ~ :- ~ - 9050 9100 - "- - 9100 ~ ~ it 9150 - --- ~~- ~~ - 9150 1200 - """'- ~ - !1200 9250 - """"'- . . ~ - 92SO 9:J00 - """"'- ~:~- ~ - 9300 5350 - - S350 .,...... 1400 - -~ 9450 - 0 1 2 - S450 I ,,- I SCALE IN HILES :. EXHIBIT 8 W-E STRUCTURAL CROSS SECTION ') ) EXHIBIT 7 "Iv", Or-9 8., r ~ ... + PRUDHOE BAY UNIT '\ ID.L IS. NIAKUK \ tSLANOS + + + & al 38 31 PRUDHOE OilY - r-------"\ ,,,.. 6 - t-- + + ... + I I ~---, I ~ Cc, ,~ ~ .f- - ~ q. of- + + ... ... +- ~ ...' ,.... '" .... t ' - ~ I ... + ...-- + + + + + 31 38 31 36 3J , . B Ii ... + + ... + + + + 6 4- ~ <c- ...'!J ~ ....Iò '-" q. ~ ~ + . + ~ + + + + ... +- + <.:, ...() ...0 "', ...t;) ~ '\ '" " q.. ft' - I of ~ (Ã- ,C) '\ + + + + :r + PRU~HO£ ;AY + + + ... . 31 ~ UNIT 36 31 . 11 3S LISBURNE FIELD I + + + + + + + + ... RULES ARER + + + + + + + + + . 407~R4004 - 8200 5 - 8400 ~ 11 13 - 8600 - 8800 - 9000 - 9200 - 9400 - 9600 EXHIBIT 8 8200 - ---- 4 - -.:- -- -7 8400 - --:::=r- - --- . 0 =-=- -~ 13 16 19 22 25 --=----~ --_--28 31 - -- ~-===~-----34 37 -==-~ ----~=------==-==------ 40 43 --- -~ ~ -- ~ -=--=--=- --- -- --------- -------~ ---==-----::===- _--16 9 -- ------------- ~ ~ ~ ---- - - 4 52 - -~ ---=::::.~-----= = --=.- --:::::==---__-55_ ~-~-=-----------=--- ------ -----60 -- -=----:::::: -- -- -- ---=- ~-- I - - - :::::..-.---- - -- - ---=--- 3 9200- -- - = == - =---- ~- 5 17 -- --~ _ _ _ -= 7 -- - ~----- -- - ---------- - -~=- ---=-~ 9 --======---=== 119400- --------==-- 13 -==~ 15 17 9600 - 8600 - _ 8800 - 9000 - ~' 2-D Strip Model LISBURNE DEVELOPMENT HELLS \ w W <:t U1 112N TllN DaS o a S a I. S96 ACRES 30 L2-6 11 13 I JI 601 / ACRE >l =3 9 I --r 4972' 1 ~ 2 15 DaSa L2 604 ACRES -4994'- W W <:t U1 - - a:: a:: 607 ACRES 36 31 591 ACRES ~ 36~ TI~ ~_ f2 ..3' 'r~l1t 593 ~ ACRES @ £ EXISTING HELLS INJECTION HELLS PLANNED HELLS ~ I:XHIts..1 " DDS L5 5BB ACRES 320 ---- 160 RCRE RCRE SPACING SPRCING x w w LJ) (D 0: 0: \ 3 10 )( & -4BI>I'- 5 A ........ ........ 22 29 ): 11 )( 24 K 19 x... ""- T12N ""'- TllN :x 29 I I * 33 - 36 >r 7 - DaSa L5 22 ;X ./ * 4 2 ¥ -4928'- 6 .,. / / / 599 ACRES 13 ,. ~ 15 )( / 25 \ I ~ 32 28 DaS L3 604 I\CRES ){ 34 21 21 30 5000' L...... DaS -4994'- w W :0:. U1 (D 31;; ér 5000' I L4 o ~ I SCALE IN FEET I 607 ACRES 36 31 JULY 29.1984 -' ~ Þ: 18 FAP 6010~~~12 LISBURNE DEVELOPMENT PLAN EXHIBIT 10 I ! PHA$E 1 PHASE 2 F I COMMENCE FIELD DEVELOPMENT DRILLINQ STARTUP NELL ~ ð. ~ ð. ~ ~ DRILLING aHll T COMPLETE COtA..ETE 320 ACRE 160 ACRE HELLS HELLS DETAIL FIELD FACILITIES DESIGN FABRICATE STARTUP ~ lJ. ð ~ ~ COMM I T SEALIFT SEALIFT DRILLSITES LPC INTERFERENCE TEST PILOT NATERFLOOD DRILLING INTERFERENCE ~ ~ ~ START START TEST .. . I . SECONDARY/ EOR . I. 1984 1985 1986 PILOT NftTERFLOOD 1987 1988 6 COM'LETE EVALUATION CCM4IT ð~ START DRILLIMe 1989 1990 ~' '-'" SEAL J FT LPS ~ð6 STMT LPS INJECTION STARTlP 1991 1992 An'700.olnn'7 / TYP T}:AL LISBURNE WF'~ EXHIBIT 11 ... .. CONDUCTOR 20· H-40.. 91. 5# SET (I 80' CEMENT TO SURFACE .. .. SURFACE 13-3/S8 L-SO.. 72# STC SET @ 4000' .. .. INTER~DIATE 9-5/S- L-SO.. 47# BTC SET NEAR TOP OF LISBURNE f f LISBURNE INTERVAL , .. PRODUCTION LINER 7- L-80.. 29# STC '\ J 407984002 REV. -"-~,,,- EXHIBIT 12 DS-L6 -- ~ Prudhoe Bay ·~,0< ~\... c¡Ù\' ) 2 ROWS OF 18 WELL HEADS~ ON 60' CENTERS. ~ ~. HEATER & TEST J)¡ - I SEPARATOR PAD FLARE PIT EXHIBIT 13 ~ ~ · "- · · · · · · · · '0 J- .. o o N · · · I 1 75' .1 I · · · · · · · · · · · · · · · · · · "", ~ .. o 00 q- ..... D.5. L-2 PLAN VIEW ( TYPICFL . 40'798400 . AI 2006A4002 P€V.O JCN I I PARKING ¡AREA I I LISBURNE PRODUCTION CENTER P~OT·PLAN "-T.!. j OFFICESI MAINTENANCE BLDG ~ ~ ~ FIREWATER :1 ~ ENTRANCE I x X X X CONTROL ROOM ~~~~~~~~~~~~~========: 'I II II ;1 II II LJ WA TER DISPO:"~L WE~L PO'I'IER ::;;;:- GEr--ERA TI ON r 01 STAr£)BY GEr-Æ:RA TOR TRAt-ß- FOR '-ER S UTILITIES ~ ~~ :) I ~N\[\!iJI" Y'\ i, ¡.: .NWV'fI DE"YDRATION~LJ REINJECTION COMPRESSION j\:,.-., - I I n, ...._'(" I I ",' ~ . I I i I I I I' I 1._, I \ I I \ (FUTURE) 1 \ \ \/\¡\/\^/~j\^/ \ . I « I \ ,\ ' '\ I I\/VV\/ý\/V L.____J j~rr;- 13°00'00 Z' ~ ~ ~ Q. l3 ) IN...ET MANIFOLD r- STV/IP CQt.f)RESSION ::::= -~ :::=-~ ~ - 0::::::::: :;:::; -~ OIL PRODUCTION ,.. -.0 Q ~ I I I OIL /'2/ SHIPPING L PÆOH 0 SLOP 0 OIL ~ 1 1 1 / ....' T T ~ :1 ...~ ~ ....~j ~- M ~-DIESEL ,) 1 1 ~~ I' T T T "'" ~ 0 ~U DEPROPt.NIZER PLANT \^^^I /\/\/\/\ ~ ~ ~ -- ~~~~===========_. EXHBrr 14 . ~ ') ) LOW STAGE ~ R~ J I<LJECTI ON .!CC) Co..f'RESSOR A ~ ~ INTERCoa..ER V HIGH STAGE .. suCiJON V !CIW8B£R lOW HIGH 5TAGE ST AGE REJNJECTION SUCTJON Co..f'RESSOR SCRUBBER - ~ JT VALVE -( - . --(X) He . .~ r---.. TEG +- TEG C(WTACTOR RfS I DUE TEG ~ GAS ~ SCRIÆBER ~ ~OOr- r COtÐ ( HI GH PRESSU~ SLUG CATCHER IP COfof'RESSOR RES I DUE GAS COOL ER i CPUDE FROM DRILLSITES + REFERENCE DW«>S: ~ I~I DATE EXHIBIT 15 aloo AFTERCOQER .. ) FUEL GAS SCRuBBER + COtÐ ~ Ie> SUCTION SCRuBB~R . I H ex=:> ~ r IP COOLER I COtÐ WATER TO I_ DISPOSAL I IIfYJ~JOPð I GAS TO I R=: I flLlECTJ ON t a .. rl ---- STy Co..f'RESSOR t .( FUEL GA.S .. ( I- a. .r . f ) ( I ELECTROSTAlIC ~ , TREATERS I I I I I I 1111' 10« "fI.oca _ _ . IIlIlII,d lID lOT KALI """to Jt..Jr£. I 984 ~I /~:"'~ NTS I. . e PROPAfo£ __ CH:LLE"fj PROPAt£ - ~ .. ~~ 11 \, \----¡ ( . ~ .( ) .. . c ) DEPROPANIZ£R EC(N)MJZER DRUM IoEG ,0 DEPPOPANI Z£R FEED HEATER . t DEPROPANJ ZER FEED FLASH DRuM V DEPROPANIZER c~~~ ---1 CC) ~. . . ï"'1 DEPROPANIZER "" I OFFGAS ----.. COIoPRESSOR . C)- DEP~iER REFLUX .. DRUM r--"¡ I I I " / ~ REFR!GERA'lT I / X" I MAI(E -uP U!IItT I DEPROPANIZER ~ r--., " / X / " L__.I ~ REBOILER - ~ Pt.IIIP . -- ) g'..~ &I:-.. a.£G ,0 CRUDE OIL CRUDE OIL BOOSTER PUJ,p AFTERCDOC.ER IAA- _ SCAU: 'ca ~'UOÆ::I IN.> ~ .... ) ~G ø- CRUDE INTERSTAG[ HEATER ~ ISTV s:~ - ............. SCRuBBER , ~ ----l ex:::> ~ -............._ r STV COQER ~ '\ COfÐ 11 (, " \ TREATER )~ "-IoU ~aozDo ~1oL' UTI fa; _ .AD Ioú 7('13984001 b 0;THE RIoCJtÐ.. / DEPROPANIZER I REBOILER ----- ~ ~uDE OIL', ..' ~ ,':"0 PIPEUt£! CRuDE OIL SHIPPING Puf,f> ~[Rl©@ ~O@~[k~Q O!ñ)@a ~ .. . - J" A - - -. . - . 'Ð: . . . ...,... ,....1.1 ---- LISBURNE PRODUCTION CENTER OVERALL ?P.OC~SS FLOW ,,..,. ~.. I cr: I C ,,... .dI _, ~.. _ ~, ',:r ! '\ TYP ~)CAL LISBURNE Wr~~ EXHIBIT 18 - - ,. .. ~nNnl J~TnR 20" H-40... 91.5- CSA 80' CEMENT TO SURFACE SUBSURFACE SAFETY VALVE '0 CHEMICAL INJECTION VALVE SET AT :t: 2000' 10 ,. .. SURFACE 13-3/8" L-80... 72. BTC CSA APPRO X 4000' CEMENT TO SURFACE 2-7/8U... 6.5.... L-80 PLASTIC COATED TUBING 5-8 GASLIFT MANDRELS IN TUBING STRING - - - - 2-7/8" PACKER SET ~200' ABOVE LISBURNE ~~- INT~RMFnIATE 9-5/8" L-80... 47tt BTC .. .. - - ~ ( LISBURNE INTERVAL \ ! PRODUCTION I INFR 7U L-80... 29- BTC .07984003 RO #3 02-001A(Rev.10/79) It: was brought out by Sohl0 tha,t even though the facies of tbe individual carbona.te ZOIles between. the shales may vary· across the Prudhoe areé!, porosi.ty zones tend to persist laterally. Though it is also recognized tbat isolated local water pockets may exist, porosity in general continues from well to well rather than occurring only in small separat.e isolated pods. F<racturing at: 8.n average spa.cing of approximately three feet provides vertical pe,nl'}eability across the shales. A sec()nd significant poin.t illustrated at the Sohio presentation ~las the apparent high productivity potential for the Alapah (Lower Lisburne) across the northeastern portion of the a.rea above the (-10,000) oil/water contact. In illustrating this point, Sohio utilizes the data provided by the Sag Delta No. 1 (33-12-16) and the Sag Delta No.. 6 'Wells. One number tha.t I happened to note was that the Sag Delta #6 had up to 90' of net effective pay in the As a m,atteI" of interest, Sahia refers to the continuous sha.le ms.rking the top Alapah as tbe "Green Shale". Also, f"ro¡a what I could tf~ll, Sohio picks the. \vahoo/Alapah contact at the same point tha.t we do here at the Commissi.on. In view of the subject mee,ting c}ccurring during your recent pe.rsonal leave. I wish to bring to your attention t.wo part1,cular geologic i,tems presente,d by Sohio f1t the meeting that bave poten.t.ial bearing on establishi,ngslttisfa.cto:t';r field rules. Number one, it wa.s quite apparent front Sohi.o· s discussion a.nd illustrative cross .sectiot'ts that numeI'ous valid stratigra.phic ma:r'kersexist. through the entire Lisburne section. Not only do many of the luajor 10...·20 foot shales correla,te among the. wells, but marlY of the thin , less than 10 foot thick shales also correlate amol1g adjaceut wells. Sohlo accordingly subdivide.s the Lisburne into num.ercuscorrel£itive zones. November 8, 1984 Sohio Lisburne Heeting-.".·. Geologic Highlights SUBJECT: Bat'ry Kugler J L~ ~ Commissioner -p--- ~ . . . . /7..",.,~· wi 111. am Van Ai eli ¿'···Z~Øif1 SeniorPetrolew:n G~logist FROM: TELEPHONE NO: THRU: ALASKA OIL Al~D GAS CONSERVATION COHNISSION C,: 8:1' 1 D Ie B:-rI. A L Lonnit~ c. Smítñ~~;.,'lY')~·'···" . ~. . . -. DATE: NOVetl1ber 23. 1984 Commissione,r ¡~ð B.2g.8 FILE NO: TO: Cd 20'7 Stalè of Alaska MEMORA,~DUM -h'^- (, '~-J Al.a.pa.h. The principal illustration tha.t Sahia used to illustrate the producti-ve potential of the northeast area was a net effective porosity/foota.ge map of the total l,i.sburne. The domi,nant feature of th,is map was the northwest-southeast trending thick that crosses the Sag Delta ¿~:rea getleral1y in ,the area where the top of the L:Lsburne is truncated by the pre-cretaceous unconformity. It i.s evident from Sohio,' s presentation that the L.isburne accumu.- léltion appea.rs to occur i1:ì one pool. The gas/oil contact is at a.ppt"oximately' -8,600' S5 and the oil water contact is at approxi- ma,tely -10,000' SSe Reserve.s are estiutated to be 6.8 to 9.0 bil1io11 :BOIP with rt1,Co,very estimat.ed to be 1.9 billi,cfn BO t.hrough prima?, and water injection recovery. cc: L1Íarry Kugler Russ Dougliis'S MEMORAI\JÒUMCo.\:.EI-~ate 'of Alaska cð2dÎ ALASKA OIL AHDGAS CONSERVATIO~~ C011HISSION TO: LonnieC. Smith Commission.e'r DATE: November 20, 1984 A.le.6 FILE NO: TELEPHONE NO: FROM: ""\) Russell A. Douglass ".,Y Petroleum Reservoi,r El1gineer SUBJECT: Summary of Lisburne 1:feetings with ¡'ield Owners. As you are aware. the Comm.issionmet with owners of the Lishurne Pool to discussreserv,oir descript1011. ARCO/Exxon met ,,1th us Octobe,r30. 1981t and Sohio met with us on NovemberS. 1964. Atta.chedis a summa.ry data sheet.. None of the pa.rties have trouble with a single 1)001 designation. They agree it is hard to S8.}" one way or the other if the pools are in cODmlunication. There is also agreement on. the extent of th.e initial development area (9300 t contou't'). Iui"tie,lly only the ~lahoo will be exploit,ed. Hajority of their wo'rk has beel"'!. analyzing \/,a,hoo tests, coreS,t logs t etc. AR,CO tf~mpers their ,estimates with a ±15% ran,ge of error.. All of the owners agree there are still a lc)t of unsl1swe:re(l questions.. ARCO/E)tXon have modeled the 1>lest Bay State long term p:rodu.cti.011, test an.d hav,e ex,panded to cross-section worle on the field. S.obia has modeled the test also but dl')es not feel they hEnn.~ sufficient data. toe).!pand to a cr()t~s-section or full field modeling effort.. Sollio 'Eloted on-going studies concerning 'W'etta.bility, fra.cture/matrix description, COR behavior, pressure depende.tlCe, of k, frefl water conta(~t:, relative permeability and capillary- pres- su:r.'es.. The ta.ble Bumtnarizes most of the pertinent reservoir elata. Geology wise they seem to be, in. agreement on the major definiti.on. The separation of iJahoo (Upper) and Alapah (Lower) is agreed upon. Host of the subsections in the \-lahoo are a.lso the same. Exxon see,ms to have more subsections but the boundaries of the ARCO sections correspond with those of L~on. OZ·001A(Rev. 10/79) VARIABLE Gas-Oil contact (GOC) Oil-water contact (OWC) Reservoir pressure datum Reservoir temperature Average 0 (percent) Matrix perm (md) Composite perm (md) Avg Connate Sw(%) Cutoff 0 (%) 001P (to 9300'ss) Wahoo MMSTBO OGIP - gas cap (BCF) so In gas total Oil recovery factor Production rates COMPARISON OF OPERATOR DATA - LISBUIDiE RESERVOIR ARC 0 Exxon 8600 8586 9147 9300 9150 (water free) 9330 (oil free) 4490 8900'ss 183°F no datum 8900'ss 11 0.5-2 10-30 15-30 5 2971 547 10.5 5 2573· 455 14.7% 200-3000 B/D/well 12.1% Sohio 8600 9300-10000'ss 4276 @ 8600'ss 180°F no datum 8.5-11.6 0.01-2 15-30 ~ 5 3407 600-800 12.1% .~/ 1200-2500 BOPD/well #2 November 15, 1984 .~ Î, J:.;!,--··-'·\."C..,(..ì..!\,ÞM . ,'., ~~ ' " . ·---;;-:17'4./,' ~-"\ cor~~~, / I",'" ~\ f~\"·'~iÜ~. ',t.'.:.::~.'\.G,' " ,. , ·J¿'-\'1 [\\\("d3- ~ ,.. '?l\:2ENO=\ '~.'\' ',' ~Á. ',r :.:.~ (, è...;.",, .t!-~ ~ c.· .---.-' ·\-.yt-~~.;,',.f.~.': ~" A...."..-ï ---'\" '; \¿;~~~~( = .-- \ ST;~ T@3'YFC..__i .....-. \ ('1"1\1 Tf:C I~__,\,~-__:~,..-._-- I f-tÖt\iFER: __--J _0 .....~""_.. .-.- FILS----;' Commission ~. ~1 \"(;~:~ i ARCO Alaska, In \ Post Office ..;;,dx 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 Mr. C. V. Chatterton State of Alaska Alaska Oil and Gas Conservation 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Chatterton: ARCO Alaska, Inc. on behalf of itself and Exxon Corporation, request i.n accordance to the provisions of 20 ACC 25.520, that the Alaska Oil and Gas Conservation Commission consider the adoption of field rules for the development of the Lisburne Oil Pool. We understand that the hearing to consider these proposed field rules will be held on November 29, 1984 at 9:00 a.m. at the Municipal Assembly Chambers, 3500 Tudor Road. Several representatives of ARCO will be present at the hearing to provide supporting testimony for these rules. The testimony will provide a geological description of the Lisburne reservoir, a reservoir analysis, a description of the facilities necessary for development of the Lisburne Reservoir, a discussion of well operations and drilling activity for the Lisburne Reservoir, and a summary of the testimony and a discussion of the proposed field rules for the Lisburne Oil Pool. If you have any questions or comments concerning this matter, please call me at 265-6330. I would be happy to drop by and discuss this matter with you at your convenience. A copy of this request has been provided to the Prudhoe Bay Unit Working Interest Owners, and other interested parties. Best regards, ~-, {}f(,' --.- , 'Q / ' ;- K. Ch~nc .' RECElVED DKC/KTP/dy ttl/~\i 1 6 1984 ,, \I .. ~ ~ C<:rn'l¡\SS¡Or. A.\aska on & Gas Cons. \ ì Anchorage ARCO Alaska, Inc. is a Subsidiary 01 AtlanlicRichlieldCompany 1 11-2ktp #1 ( Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of ARCO ALASKA, INC. for a conservation order redefining the pool rules for the Lisburne Oil Pool in the Prudhoe Bay Field. Notice is hereby given that ARCO Alaska., Inc. has requested the Alaska Oil and Gas Conservation Commission to hold a public hearing in order to present testimony to redefine the Lisburne Oil Pool rules for the development and exploitation of this pool in the Prudhoe Bay Field. The public hearing will be held at 9:00 AM Thursday, November 29, 1984 in the Municipality of Anchorage Assembly Room, 3500 East Tudor Road, Anchorage, Alaska. All interested persons and parties are invited to give testimony. ~ ¡J. d¡£{~ Harry W. Kugler Commissioner Alaska Oil & Gas Conservation Commission ')" H t: ¡..,:;.) C ~ D h' ^ G t: rr T I:: Ã ;',: C I:-ì n R Ä.l: t" rd., ;J. S ,,~ A ¡~ ~j S 1 (I - 0 Ij tl (} p .. U . 13 (ì i 4, l) t- h lJ U tï (I F 1) u fj C f C ~\ . 1 J C: þ.~, C·TL &. c;Ì'>,~ Ci,)"5Sì-<,RVL\II,)I': C(JiV;,j 3 0 Ü 1 PC; R C U ¡.; 1 ',I ~.. l} H i V L A~CHGRAGE. ^~ 99~Ol I) ~ (.¡ ¡J À S I i~i .\; U H S .. ;3 t. II) G f) U L Y S ~; ¡,} R 'I).. A C r. C'., pel (,.¡ G J J L Ä "1 C', t~ C L ,~, RES: T H A. T S H ~: r s 1~ H F iJ ~ . GAL C [. F R ¡':. C f r H r.~ ANCHORAGE ITMFS. Ä DAlwY ~¿WSP~P~R P U l:'; L T SHE-I.> 1 /Ii T H ¡:,; T [I j'i (\: f1 F' i~ ~'~ C H (j RAG E: lW THE THlkO JUOJCIAL DIViSION, STATF üF 4LASKA. A~0 THAT fh~ (,~ ~:f lr J. C E~, () F~' .. ,. . .. . . . IIIIt . ... . _ . .. . . . .. . II1! . .. . . . . A COpy OF WHICH IS HER~TO AYîACH€D, \1\1 À S Pi !J B L¡ I S¡,·~; 8: ü IN..................... '" . . . . .. . . OF THE A~CHnPAG~ TIMES. 8 E: G I [\1 ¡~ '[11,1 G () ............................... II E: (,~ c~ J.' f\l (; (J '~\i .. ,. . .. . .. . . . . . . . oil¡ .. . . .. . .. ,. . .. . . .. THE SIZE OF ThIS AD AS............. SIG'\\E~O............... .. 'I. H EF R ICE: (,I ~ I· T HIS AD IS................... $ Alj-OB 5543 1 ISSUF~S 1 ()/26/8l!, 1()/:26/84 41 LII\IE:S ~/ ? $ ". arL:t~~~~~,~ 12.30 'I'li~~AO ivÜ fir<l~ IS............................... 1.917026 SUb SC¡:..~ 1 f: E: [) A Nil S I"! U;:,:, r·: TO BgFORE ME THIS....................... 26 DAY OF DCT.1984 NOTARY t'Uhl,JC O~ ì'Hf, S'fATE, OF' Ar,ASKA ~.a~ ¡r.;! y C [} r~\M ]., S 5 I (] i'i F K P I H E S .. . .. .. .. .. .. .. .. .. · .. · '.. · 5 -/-f"b --~-~~~~~~~~--~~~~~ .} , ,/' -{_:::. ';;' C , - N,Q, .1'ICEO. F~,",'t1,.I. C . I· .R'Ule,·' ~IAT-: "OFA¡.\ .~I~À "'~~~,),'. ."",' " ....()..~J;!:II. P,'~I'.',.;,I , . I , ' cop ,n',...O:O.~, 5;¡yon '. ' Ré:1iilt,o. pp¡'lcation ¡Of,IA. ',A, 'C.O I ' A'LA~fIV., .1 NC., for acør:aser· \(otlc;.n 'order' redeflnlJi\; \ tl'!e . ~Ol. ',~.' ,.le..s.. for. t"h, e. LIS. bu..r,'.I:If.QI.t ,:K',. . 'I':,'I~ the prudho~~ØY I i'~ì,''1>:I: '. "'.' '.... I I., eN ' 'ils .'. here.bV:9Iven.tha.t ,I " ~~ '~~~~&~ÕI,:~~,¿3~ . '.' G:òh1ml$SI1i/il1ìl),fC) 'hearing 'In"ô~(!erto ~~.'.r, ~i.~.J..'.,','.~,.tI.~.;;~.'et.'. :.,1,1'1, e..~ pool In the Pr_e : ':'~, ' i -- 09' , <6 { AMERADA HESS CORPORATION Attn: R. W. Mullins P. O. Box 2040 Tulsa, OK 74101 AMOCO PRODUCTION CO.,U.S.A. Attn: J. C. Burnside Amoco Building 17th and Broadway Denver, CO 80202 BP ALASKA EXPLORATION INC. Attn: G. Knowles One Maritime Plaza, Ste.500 San Francisco, CA 94111 BURGLIN BROTHERS, INC. Attn: Cliff Burglin P. O. Box 131 Fairbanks, AK 99707 CHEVRON U.S.A., INC. Attn: T. A. Edmondson P. O. Box 8200 Concord, CA 94520 COOK INLET REGION, INC. Attn: Geo. Kriste P. O. Box 4-N Anchorage, AK 99509 DOYON, LTD. Attn: M. Thompson 201 First Avenue Fairbanks, AK 99701 EXXON CO. U.S.A. Attn: K. T. Koonce P. O. Box 2180 Houston, TX 77001 GEOPOLE INC. Attn: Brian Brundien 509 W. 7th Avenue Anchorage, AK 99501 GETTY OIL CO. Attn: R. J. Hamilton 1515 Arapahoe Street Three Park Central Denver, CO 80202 INTERESTED PARTY LIST LOUISIANA LAND EXPLORATION CO. Attn: R. J. Chebul 1675 Broadway, Ste. 2100 Denver, CO 80202 MARATHON OIL CO. Attn: C. A. Dowden P. O. Box 102380 Anchorage, AK 99510 MOBIL OIL CORPORATION Attn: W. J. Clauser P. O. Box 5444, Terminal Annex Denver, CO 80217 NANA DEVELOPMENT CO. Attn: W. L. Hensley 4706 Harding Drive Anchorage, AK 99503 PHILLIPS PETROLEUM CO. Attn: J. K. Fetters 8055 E. Tufts Avenue Parkway Denver, CO 80237 SEALASKA CORPORATION Attn: R. Stitt 1 Sealaska Plaza Juneau, AK 99801 SHELL WESTERN E&P INC. Attn: T. F. Hart P. O. Box 576 Houston, TX 77001 SOHIO ALASKA PETROLEUM CO. Attn: R. A. Flohr 50 Fremont Street San Francisco, CA 94105 TEXACO, U.S.A. Attn: B. D. Whiteley 550 W. 7th Avenue, Ste. 1320 Anchorage, AK 99501 UNION OIL CO. Attn: G. A. Graham P. O. Box 1700 Los Angeles, CA 90051 RECE\VEO NOV 1 619\\4- " 0·, & Gas Cons. Commission Alas~a i Anchorage