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Home My WebLink AboutCO 345INDEX CONSERVATION ORDER NO. 345 1. August 17, 1994 2. August 26, 1994 3. October 5, 1994 4. October 10, 1994 5. October 19, 1994 6. October 25, 1994 7. October 27, 1994 8. December 30, 1994 9. February 20, 2020 10. February 24, 2020 11. May 21, 2020 12. ----------------- Draft Pool Rules Held Confidential Notice of Public Hearing, Affidavit of Publication Hearing Transcript Letter from DNR re: Proposed Pool Rules Notice of Public Hearing, Affidavit of Publication Letter to DNR re: Pool Rules Memo to DOG re: Nov. 3, 1994 Meeting Application for the Formation of the North Prudhoe Bay Participating Area BPXA's request for Amin Approval for Conforming PBU Greater Pt. McIntyre Area Satellite Pool Rules for Consistency (CO 345.002) BPXA Request to amend CO 492 rule 3(a) and 6(a) (co345.003) Notice of Hearing and mailing Emails STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501 -3192 Re: The Application of ARCO Alaska, Inc. ) Conservation Order No. 345 to present testimony for classification of ) a new oil pool and to prescribe pool rules ) Prudhoe Bay Field for development of the North Prudhoe ) North Prudhoe Bay Oil Pool Bay accumulation in the Prudhoe Bay ) Field. ) December 16, 1994 IT APPEARING THAT: 1. By letter dated August 18, 1994, ARCO Alaska, Inc. requested a public hearing to present testimony for establishing pool rules for development and operations in the North Prudhoe Bay oil accumulation, located in T12N, R14E, Umiat Meridian. 2. Notice of public hearing to be held on October 5, 1994 was published on August 26, 1994. 3. A hearing concerning the matter of the applicant's request was held in conformance with 20 AAC 25.540 at the Commission offices, 3001 Porcupine Drive, Anchorage, Alaska 99501 at 9:00 a.m. October 5, 1994. The hearing record remained open until the close of business October 19, 1994. FINDINGS 1. ARCO Alaska, Inc. drilled the North Prudhoe Bay State (NPBS) No. 1 well to a depth of 9610 feet TVD in 1970. The well is located in Sec. 23, T12N, R14E, U.M. 2. The NPBS No. 1 well encountered 42.5 feet of hydrocarbon charged sandstone in the Sag River Formation and 46 net feet in the Ivishak Formation; oil was tested up to 9200 feet subsea and gas down to 9135 feet subsea. 3. The NPBS No. 1 well produced 2,727 barrels of oil per day from the Ivishak Formation and 3.6 million cubic feet of gas and 132 barrels of condensate daily from the Sag River Formation during drillstem testing. 4. The NPBS No. 1 well was plugged and abandoned in 1985. 5. Initial reservoir pressure in the NPBS No. 1 well was 4,600 psi at a datum of 9245 feet subsea in 1970. 6. ARCO Alaska, Inc. drilled the NPBS No. 3 well to a depth of 9447 feet TVD in 1993. The well is located in Sec. 25, T12N, R14E, U.M. 7. The NPBS No. 3 well encountered hydrocarbons within intervals stratigraphically equivalent to the hydrocarbon bearing intervals in the NPBS No. 1 well. f Conservation Order 345 • Page 2 December 16, 1994 8. ARCO began a long -term production test of the NPBS No. 3 well on October 13, 1993. As of September 30, 1994, the well had produced 948,000 barrels of oil; 258,000 barrels of water and 2.9 billion cubic feet of gas. 9. Reservoir pressure in the NPBS No. 3 well, at a datum of 9,245 feet subsea, has declined from an initial 3,922 psi to 3803 psi in June, 1994. 10. Oil from the NPBS No. 3 well has an API gravity of 35 degrees, a bubble point of 3,870 psi, a solution gas-oil ratio of 923 standard cubic feet per stock tank barrel, a sulfur content of 0.4% and a formation volume factor of 1.48 reservoir barrels per stock tank barrel. 11. ARCO estimates the oil -water contact in NPBS No. 3 at 9280 feet subsea. 12. The North Prudhoe Bay oil accumulation is located north of the Prudhoe Oil Pool and south of the Point McIntyre Field. The North Prudhoe Bay accumulation is bounded on the north and south by two regional faults, the Prudhoe Bay fault and the Pt. McIntyre Fault. 13. Oil within the Prudhoe Oil Pool has an API gravity of about 29 degrees and a sulfur content of 1.0 %. The oil -water contact in the Prudhoe Oil Pool is approximately 9000 feet subsea. 14. No gas -oil contact can be identified in either NPBS No. 1 or No. 3. 15. Five conventional cores were taken in the NPBS No. 1 well in the basal Shublik and upper Ivishak intervals. These cores were used to calibrate open hole log responses from both the NPBS No. 1 and No. 3 wells. 16. Reservoir characteristics derived from log analysis of the NPBS No. 3 well are listed below: Ivishak Shublik Sag River Average Porosity 19.6% 14.8% 18.7% Permeability, and 590 Not Tested Not Tested Gross Interval Thickness* 42 77 78 Feet of Net Pay 20 12 50 Net to Gross Ratio 0.48 0.17 0.64 Water Saturation, % Pore Vol. 38% 33% 36% *above estimated oil -water contact 17. ARCO's estimate of total original in place hydrocarbons is 12 million stock tank barrels of oil and 31 billion standard cubic feet of gas. 18. Production from the NPBS No. 3 well is commingled at the surface with production from the West Beach Oil Pool in a six -inch diameter multiphase production line running from the West Beach pad to Lisburne Drill Site L1. 19. No facilities for water or gas injection or gas lift currently exist at the West Beach Pad. Conservation Order 345 • • Page 3 December 16, 1994 20. Production records show that NPBS No. 3 oil production declined from an initial 6000 bbl/day oil in October, 1993 to about 2100 bbl/day in August, 1994. Gas rate decreased from a peak of 15.9 MMSCF/D in December, 1993, to 7.4 MMSCF/D in August, 1994. Water production began immediately following initial production and increased to about 1500 bbl/day in August, 1994 21. Cased hole logs in NPBS No. 3 well indicate gas entering at the top of the perforations from a source above the Ivishak Formation. 22. ARCO perforated a gas bearing interval in the Sag River Formation to help produce liquids from the Ivishak Formation in the NPBS No. 3 well. 23. ARCO has not yet formulated a long term development plan for the North Prudhoe Bay oil accumulation, and stated that additional reservoir data is needed before an appropriate long- term depletion plan can be developed. 24. To continue production from the NPBS No. 3 well, ARCO requested a permanent exemption from the gas -oil ratio limitation set forth in 20 AAC 25.240(c). 25. The primary recovery mechanism anticipated by ARCO is solution gas drive, possibly supplemented by gas cap expansion. Based upon pressure and production information, ARCO believes that water drive may also be a factor in primary recovery. 26. ARCO has equipped the NPBS #3 well with a fail -safe automatic surface and subsurface safety valve (SSV and SSSV). ARCO plans to equip other wells in a similar manner, if drilled and capable of unassisted flow to the surface. 27. ARCO proposes to use well tests as a basis for allocating production. 28. ARCO has upgraded metering equipment and facilities, established equipment maintenance schedules, and provided personnel training at the LPC to enhance allocation. 29. ARCO has developed detailed procedures for allocating production between producing pools. Testing procedures previously approved by the Commission (C.O. 311, 317 & 329) cover test frequency, test separator utilization, test stabilization periods, well and field history record keeping, NGL allocation procedures, records maintenance, reporting requirement and metering installation standards. 30. ARCO proposes to test the NPBS No. 3 well at least two times per month. 31. The pool rules area requested by ARCO includes portions of ADL 28297 and ADL 34624. The mineral interest ownership for each lease is ARCO 50% and Exxon 50 %. ARCO states that there is currently a royalty interest that is different between the two leases. 32. ARCO has submitted a participating area application to the Department of Natural Resources for North Prudhoe Bay reservoir. ARCO's participating area application includes only a portion of ADL 28267. ARCO states that this application, once approved, will Conservation Order 345 • • Page 4 December 16, 1994 integrate the interests of the mineral interest owners and the royalty owner for the area contemplated for development in the North Prudhoe Bay area. 33. DNR has not yet approved the participating area agreement for the North Prudhoe Bay reservoir. 34. Permafrost is known to exist to a depth of 1600 feet to 1800 feet in the North Prudhoe Bay area. 35. The North Prudhoe Bay accumulation is included entirely within the affected area of Area Injection Order No. 4A. 36. AIO No. 4A concludes that no underground sources of drinking water exist within its affected area. CONCLUSIONS 1. Commercially exploitable hydrocarbons exists as one pool within the Ivishak, Sag River and Shublik Formations in the North Prudhoe Bay area. 2. The North Prudhoe Bay oil accumulation is a separate and distinct pool within the Prudhoe Bay Field. 3. The North Prudhoe Bay Oil Pool is capable of regular production. 4. Development plans for the North Prudhoe Bay Oil Pool, including additional drilling and enhanced oil recovery plans, are uncertain at this time because of sparse well control, structural complexity, uncertain volume of original oil in place and reservoir drive mechanisms. 5. Continued production from the NPBS No. 3 well, reservoir pressure measurements and reservoir modeling may provide additional information useful for resolving uncertainties related to original oil in place and reservoir drive mechanisms in the North Prudhoe Bay oil accumulation. 6. Periodic review of the operator's development plans is appropriate to ensure that operations are being conducted to optimize recovery and prevent waste. 7. The North Prudhoe Bay Oil Pool includes a gas cap of indeterminate size. 8. The solution gas-oil ratio within the NPBS No. 3 well is being masked by production of gas from the gas cap. 9. An exemption from the gas-oil ratio limitation set forth in 20 AAC 25.240(c) is required before regular production of the NPBS No. 3 can commence. Conservation Order 345 • Page 5 December 16, 1994 10. Long -term exception to gas-oil -ratio limit in 20 AAC 25.240(c) is not appropriate at this time because produced gas is not being returned to the reservoir and no additional recovery project is currently planned. 11. Pool rules are appropriate to define the conditions for gathering additional production and reservoir data necessary to support a long -term depletion plan for the North Prudhoe Bay Oil Pool. 12. The North Prudhoe Bay Oil Pool cannot support stand alone facilities, and surface commingling of production for processing in the LPC is necessary to maximize recovery. 13. Production allocation procedures developed for other pools that are commingled and processed at the LPC are suitable for allocating North Prudhoe Bay production. Periodic reviews are appropriate to evaluate allocation methodology and revise procedures if warranted. 14. Surface commingling of North Prudhoe Bay production with Lisburne, Niakuk, Pt. McIntyre, Stump Island and West Beach production will not cause waste nor jeopardize correlative rights. 15. The installation of surface or subsurface safety valves on wells could prevent an uncontrolled release of hydrocarbons. 16. Precautions regarding sulfide corrosion and stress cracking are warranted. 17. The mineral interest owners and the state royalty owner have not yet integrated their interests in the portion of the North Prudhoe Bay Oil Pool contemplated for development. 18. No underground sources of drinking water are known to exist in the North Prudhoe Bay area. 19. Subject to the rules below and statewide requirements, production from the North Prudhoe Bay reservoir may occur in a manner that will protect freshwater, prevent waste, protect correlative rights, and provide for the maximum ultimate recovery of oil and gas that is prudent. NOW, THEREFORE, IT IS ORDERED THAT the rules hereinafter set forth, in addition to state -wide requirements under 20 AAC 25, apply to the following affected area referred to in this order: Umiat Meridian T12N, R14E Section 22 All Section 23 SW 1/4 Conservation Order 345 . • Page 6 December 16, 1994 Rule 1 Field and Pool Name The field is the Prudhoe Bay Field. Hydrocarbons underlying the affected area and contained within the Sag River, Shublik and Ivishak Formations constitute a single associated gas and oil reservoir called the North Prudhoe Bay Oil Pool. Rule 2 Pool Definition The North Prudhoe Bay Oil Pool is defined as the accumulation of oil and gas that correlates with the interval between 9105 feet and 9568 feet measured depth in the North Prudhoe Bay State #1 well. Rule 3 Drilling and Production Equipment Drilling and production equipment must meet the requirements of API RP 7G, Section 8, "Drillstem Corrosion and Sulfide Stress Cracking," current edition. Rule 4 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 and shutting down any artificial lift system where an over pressure of equipment may occur. 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 well head 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 Commission inspection 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 is in proper working condition. Rule 5 Surface Commingling and Common Facilities a. Production from the North Prudhoe Bay Oil Pool may be commingled on the surface with production from other pools for processing at the LPC 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. Conservation Order 345 • S Page 7 December 16, 1994 2. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. 3. Sum the TMP volume for all wells in all pools. 4. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP) 5. Calculate each well's actual monthly production (AMP) volume as: AMP = TMP x Allocation Factor 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. At a minimum, 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. e. Optimum test duration and stabilization time will be determined on a well -by -well basis by the operator or, in its discretion, by the Commission. f. Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on -line water cut measurement devices approved by the Commission. g. API gravity will be determined for each producing 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. i. The allocation process for the North Prudhoe Bay Oil Pool will be reviewed with the Commission in conjunction with scheduled LPC allocation review. Rule 6 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. Rule 7 Reservoir Pressure Monitoring a. Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure. b. Until a secondary recovery project is approved and implemented, a minimum of one bottom- hole pressure survey per producing governmental section shall be obtained annually. Conservation Order 345 • • Page 8 December 16, 1994 c. The datum for all surveys is 9245' TVDss. d. Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom - hole pressure after the well has been shut in for an extended period. e. The pressure surveys will be reported to the Commission on form 10 -412, Reservoir Pressure Report. All data necessary for complete analysis of each survey need not be submitted with the form 10 -412, but must be submitted upon request. f. Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with part 'e' of this rule. Rule 8 North Prudhoe Bay Oil Pool Annual Reservoir Report. A surveillance report will be required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: a. Progress of enhanced recovery project(s) implementation and reservoir management summary, including engineering and geotechnical parameters. b. Voidage balance by month of produced fluids and injected fluids. c. Analysis of reservoir pressure surveys within the pool. d. Results and, where appropriate, analysis of production logging surveys, tracer surveys and observation well surveys. e. Results of any special monitoring. f. Future development plans. Rule 9 Gas-Oil Ratio Exemption Wells producing from the North Prudhoe Bay Oil Pool are exempt from the gas -oil ratio limit set forth in 20 AAC 25.240 (c) for a period of one year from the date of these pool rules. The operator must show cause and justify a continuance of the exemption before the end of one year of regular production. Rule 10 Integration of Interests Within 30 days of the date of this order, the operator will submit to the Commission a copy of an agreement validly integrating the interests of all persons owning interests in the affected property in the pool or portion of the pool for which development is contemplated. In the absence of an agreement, the Commission will hold a public hearing in accordance with 20 AAC 25.540 and issue an order creating a participating area which integrates the interests of all persons owning an interest in the pool or portion of the pool. Conservation Order 345 110 Page 9 December 16, 1994 Rule 11 Administrative Action Upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights or compromise ultimate recovery, and is based on sound engineering principles. DONE at Anchorage, Alaska and dated December 16, 1994. m !gip David W. Johnston, C . an Alaska Oil . • Gas Cons- ation Commission A Ott Ar Y q ' T4 f?' Russell A. Douglass, Commij oner O . Alaska Oil and Gas Conservation Commission • M rjON Co, � kerman Babcock, Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30 day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: AN ORDER rescinding those rules within ) Docket Number: CO -10 -21 existing Conservation Orders relating to ) Other Order No. 66 well safety valve systems. ) ) Statewide, Alaska January 11, 2011 IT APPEARING THAT: 1. On October 13, 2010 the Alaska Oil and Gas Conservation Commission (AOGCC or Commission) formally adopted new regulations relating to well safety valve systems, at 20 AAC 25.265. 2. The newly adopted well safety valve system regulations underwent final review by the Regulations Section of the Alaska Attorney General's Office and were forwarded to the Alaska Lieutenant Governor's Office on October 28, 2010. 3. The new regulations were signed by the Lieutenant Governor and took legal effect on December 3, 2010. 4. To ensure consistency with the new regulations, the AOGCC, on its own motion, proposed to rescind part or all of the outdated rules within existing Commission Orders relating to well safety valve systems. 5. On November 4, 2010, pursuant to 20 AAC 25.540, the Commission published in the Alaska Daily News notice of opportunity for public hearing on December 6, 2010. 6. The Commission received written comments in response to its public notice, and held a public hearing on December 7, 2010. 7. Oral testimony and written comments were provided at the December 7, 2010 hearing. FINDINGS: 1. Well safety valve systems are regulated under newly- adopted 20 AAC 25.265, which consolidates the requirements previously established in legacy documents, policies, and statewide guidelines relating to safety valve systems. 2. Thirty -four existing Commission Orders contain rules governing well safety valve systems. Twenty of those Orders contain broad regulatory requirements for safety valve systems that are now covered by the newly- adopted regulations. The remaining fourteen Orders include field- or pool- specific safety valve system requirements. Other Order 66 • • Page 2 Statewide, AK January 11, 2011 3. Within existing Commission Orders are rules unrelated to well safety valve systems; these rules will continue in effect, unmodified. 4. Existing Commission Orders containing individual rules relating to well safety valve systems are enumerated in the attached Table. CONCLUSIONS: 1. Eliminating redundant requirements and standardizing wording for those field - and pool - specific safety valve system requirements deemed appropriate to retain will improve regulatory clarity. 2. Twenty existing Commission Orders that include rules relating to well safety valve systems are rendered unnecessary, and can be replaced by newly- adopted 20 AAC 25.265. As more fully set forth in the attached Table, those Orders are Conservation Orders 98A, 207A, 300, 311B, 317B, 329A, 341E, 345, 402B, 432D, 452, 457B, 471, 477, 484A, 505B, 553, 559, 570, and a Commission unnumbered Order signed March 30, 1994 (policy dictating SVS performance testing requirements). 3. Fourteen existing Commission Orders include field- or pool - specific safety valve system requirements that the Commission considers appropriate for retention. Wording for the same safety valve system requirements existing in different Commission Orders has been standardized. As more fully set forth in the attached Table, those Orders are Conservation Orders 406B, 423, 430A, 435A, 443B, 449, 456A, 458A, 562, 563, 569, 596, 597, and 605. NOW, THEREFORE, IT IS ORDERED THAT individual rules in thirty-four existing Commission Orders that relate to well safety valve systems are hereby rescinded or revised as enumerated in the Table. Remaining rules unrelated to safety valve systems within affected Commission Orders remain in effect, unmodified. DONE at Anchorage, Alaska, and dated - ary 11, 2011 AO , _Iii1101199' Aili Daniel T. Se. r ou , r., Commissioner, Chair p . j i 4 _ it . I :. s Conservation Commission {� s ie rman, Coer a Oil , . • a Conserva ion Commission ' ' fi r - .. � 4 . , Cat y P. toerst-r, Commissioner Alaska • it and Gas Conservation Commission Other Order 66 • • Page 3 Statewide, AK January 11, 2011 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Tuesday, January 11, 2011 4:08 PM To: Ballantine, Tab A (LAW); '(foms2 @mtaonline.net)'; '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator'; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer; 'Bill Penrose'; 'Bill Walker'; 'Bowen Roberts'; 'Brad McKim'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'carol smyth'; '• 'Chris 'Crandall, Krissel►'; 'D Lawrence' 'dapa'; 'Daryl Posey; Cranda , caunderwood Chris Ga C p rY l J. 'caunderwood'; Gay'; Y, Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber ,. , 'ddonkel @cfl.rr.com'; 'Deborah J. Jones'; Delbridge, Rena E (LAA); 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Michael Dammeyer'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; 'rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; 'Valenzuela, Mariam '; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; 'Dale Hoffman'; 'David Lenig'; 'Gary Orr'; 'Jason Bergerson'; 'Joe Longo'; 'Lara Coates'; 'Marc Kuck'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Richard Garrard'; 'Sandra Lemke'; 'Talib Syed'; 'Tiffany Stebbins'; 'Wayne Wooster'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Brooks, Phoebe L (DOA) (phoebe. brooks @alaska.gov);. Colombie, Jody J (DOA) (jody.co►ombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @ alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Johnson, Elaine M (DOA) (elaine.johnson @ alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk @alaska.gov); Pasqual, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) Qim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA) (dan.seamount @alaska.gov); Shartzer, Christine R (DOA) Subject: Other 66 Safety Valve Systems Attachments: other66.pdf SaAVumilth v 7 r A tous-ccv O 2/ at Co yo-e- rvatw-ry C o-vvwr i avv (907)793 -1223 (907)276 -7542 (faw) 1 • • • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton President 408 18 Street 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil Tools P.O. Box 58055 P.O. Box 93330 795 E. 94 a. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson P.O. Box 69 US Geological Survey 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Unit/Field Pool Conservation Rule Rescind Rule? Existing Order Requirement New Regulation Provisions Revised Rule - "Well safety valve systems" (2) Comment Order (1) Addressing Reqts from Order fail -safe auto SSV and SCSSV; injection wells (except disposal) require wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.265(b); 25.265(d)(2)( Check valve requirements for injectors are not covered by Colville River Unit Qannik 605 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25 arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.2659(b); 25.265(d)(1); Check valve requirements for injectors are not covered by Oooguruk Oooguruk - Nuiqsut 597 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(1); "Injection wells (excludin disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Oooguruk Oooguruk - Kuparuk 596 6 no (1) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d)(2)(F); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit Raven 570 5 yes sign on wellhead NIA deactivated SVS was replaced with requirement to maintain a deactivated SVS; si 25.265 m 9 ( ) tag on well when not manned fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "Injection wells (excludin disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Fiord 569 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.265(b); 25.265(d)(2)( Check valve requirements for injectors are not covered by Colville River Unit Nanuq - Kuparuk 563 6 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(x); 25.265(b); 25.265(d)(2)(H); "Injection wells (excludin disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Nanuq 562 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve" Prudhoe Ba Unit Put River 559 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Deep Creek Unit Happy Valley 553 3 yes SSV or SSSV 25.265(a) N/A Prudhoe Ba Unit Orion 505B 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Prudhoe Ba Unit Polaris 484A 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI r - Milne Point - 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; Milne Point Unit Schrader Bluff 477 5 yes injection well require SSSV or injection valve below permafrost; test 25.265(h)(5) N/A replaces SSSV nipple requirement for all wells every 6 months Prudhoe Ba Unit Borealis 471 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y injection well require SSSV below permafrost; test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500 y Existing pool rule established a minimum setting depth for the Northstar Northstar 458A 4 no ft minimum setting depth for SSSV 25.265(a); a ) ; 25.265 ( b ) 25.265 ( d )( 1 ) "The minimum setti ng depth for a tubing conveyed subsurface safet y valve is 500 feet." SSSV fail -safe auto SSV; SSSV landing nipple below permafrost; test every 6 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Aurora 457B 3 yes months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(a); 25.265(b); 25.265(d); "Injection wets (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Meltwater 456A 5 no valve and SSSV landing nipple; water injection wells require (1) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors fail -safe auto SSV (all injectors and producers capable of unassisted 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Midnight Sun 452 6 yes flow to surface); test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for at wells fail -safe auto SSV and SCSSV; SSSV may be installed above or below "The setting depth of a required subsurface safety valve must be located in the tubing either Existing pool rule established alternate SSSV setting depth; 25.265(a); 25.265(b); 25.265(d)(1); Duck Island Unit Eider 449 7 no permafrost; injection wells require double check valve; LPS trip above or below permafrost. Injection wells must be equipped with a double check valve check valve requirements for injectors are not covered by pressure; test every 6 months 25 arrangement." readopted regulation fail -safe auto SSV and SCSSV (producers and gas injectors); water "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Colville River Unit Alpine 443B 5 no injection wells require (i) double check valve, or (ii) single check valve 25.265(a); 25.265(b); 25.265(d)(2)(H) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or Check valve requirements for injectors are not covered by and SSV SCSSV satisfies the requirements of a single check valve." readopted regulation fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tabasco 435A 6 no valve and SSSV landing nipple; water injection welts require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS Requirement to maintain a wellhead sign and list of wells with deactivated; maintain list of wells w /deactivated SVS; test as 25.265(a); b 25.265 h 5 deactivated SVS was replaced with requirement to maintain a 25.265 Ku aruk River Unit; 25 . 265 (b); O( ); p Kuparuk 432D 5 yes prescribed by Commission; CO 432D.009 modifies Rule 5(b) - LPP 25.265(m) N/A tag on well when not manned; administrative approval CO 25 . Milne Point Unit may be defeated on W. Sak injectors w /surface pressure <500psi w/ 432D.009 remains effective [re:defeating the LPS when surface notice when defeated and placed back in service injection pressure for West Sak water injector is <500psi] Page 1 of 2 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Revised Rule - "Well safety valves stems' (2) Comment UnitlField Pool Order (1) Rule Rescind Rule . Existing Order Requirement Addressing Reqts from Order y systems" ( ) fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(x); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve" SSSV requirement for MI injectors Milne Point - Sag 423 7 n fail -safe auto SSV; injection wells require double check valve; test j Check valve requirements for injectors are not covered by Milne Point Unit every 6 months 25.265(a); a ) ; 25.265 ( b ) ; 25.265(h)(5) h )( 5 ) In ection wells must be equipped with a double check valve arrangement " readopted regulation River fail -safe auto SSV; gas /MI injectors require SSV and single check Check valve requirements for injectors are not covered by valve and SSSV landing nipple; water injection wells require (i) double "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve readopted regulation; readopted 25.265(d)(5) does not include Kuparuk River Unit Kuparuk -West Sak 406B 6 n check valve, or (ii) single check valve and SSV; test every 6 months; 25.265(a); 25.265(b); 25.265(d); arrangement or (ii) a single check valve and a SSV. A subsurface- controlled injection valve or SSSV requirement for MI injectors; administrative approval CO p P CO 406B.001 modifies Rule 6(e) - LPP may be defeated on W. Sak 25.265(h)(5) SCSSV satisfies the requirements of a single check valve. The Low Pressure Pilot may be 4068.001 remains effective [re:defeating the LPS when surface injectors w /surface pressure <500psi w/ notice when defeated and defeated on West Sak water injectors with surface injection pressure less than 500psi." injection pressure for West Sak water injector is <500psi] placed back in service fail -safe auto SSV and SCSSV; LPS trip pressure; readily accessible Badami Badami 402B 6 yes control unit; SSSV below permafrost; NTE 210days between tests; 25.265(a); 25.265(b); 25.265(h); N/A submit test results electronically within 14days; SVS defeated /removed 25.265(m) ) only if well SI or pad continuously manned fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit North Prudhoe 345 4 yes deactivated; maintain list of wells w /deactivated SVS; test as 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a prescribed by Commission tag on well when not manned fail -safe auto SSV (S /D well and artificial lift); if SSSV installed it must be maintained and tested as part of SVS; sign on well if SVS 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Prudhoe 341E 5 yes deactivated; maintain list of wells w /deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for at wells prescribed by Commission fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Niakuk 329A 5 yes deactivated SVS; sign on wellhead 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; SSSV may be rermoved as part of 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Pt. McIntyre 317B 8 yes routine well ops w/o notice 25.265(j); 25.265(m) replaces SSSV nipple requirement for all wells fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; nipple Prudhoe Bay Unit West Beach 311B 6 yes w /deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV pP requirement for all wells West Fork West Fork (Sterling 300 5 yes fail -safe auto SVS on each production tubing 25.265(a); 25.265(b) N/A A &B) fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with N/A Prudhoe Bay Unit Lisburne 207A 7 yes w/deactivated SVS; test as prescribed by Commission 25.265(m) deactivated SVS was replaced with requirement to maintain a tag on well when not manned suitable automatic safety valve installed below base of permafrost to 25.265 d N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Prudhoe - Kuparuk 98A 5 yes prevent uncontrolled flow () replaces SSSV nipple requirement for all wells AOGCC Policy - SVS Failures; issued by order of the Commission policy dictating SVS performance testing Statewide N/A N/A N/A yes 25.265(h); 25.265(n); 25.265(o) N/A Commission 3/30/1994 (signed by Commission Chairman requirements Dave Johnson) Footnotes (1) No SVS rules found in Injection Orders (2) New title for Revised Rule; "N /A" means entire pool rule to be rescinded Page 2 of 2 Public Hearing Record And Backup Information available in Other 66 2 tii • fl • ni FRANK H. MURKOWSKI, � GOVERNOR ALASKA. �7 OIL AND GAS r 333 W. 7T" AVENUE, SUITE 100 CONSERVATION COMMISSIONT I ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (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. sCANNE AUG 0 S 2003 • 1 July 29, 2003 Page 2 of 2 Accordingly, Conservation Orders No. 207, 311B, 329A, 341D, 345, 452, 457A, 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 operator's notification to the AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. DATED at Anchorage, Alaska and dated July 29, 2003. _ , <-------- 9 _ � ' r / ,/ / e ; _ (--___ rah ' in ! D. ' e T. Seamount, Jr. - an • y Ruedric Chair Commissioner Commissioner BY ORDER OF THE COMMISSION V' \ \ � ,\ I , ,N a � 77 � 1 14 ',- t L. l --1',.. � 1 -; ' G t rk i4 i 1 0�'co�fi rl-IE STA:rE o ALASKA GOVERNOR MICHAEL J. DUNI-FAVY Ms. Katrina Garner Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 207D.001 CONSERVATION ORDER NO. 311B.003 CONSERVATION ORDER NO. 317B.003 CONSERVATION ORDER NO. 329B.005 CONSERVATION ORDER NO. 345.002 CONSERVATION ORDER NO. 362A.006 CONSERVATION ORDER NO. 570.010 PBU Area Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Re: Docket Number: CO -20-003 Request for Administrative Approval for Conforming Prudhoe Bay Unit (PBU) Greater Point McIntyre Area Satellite Pool Rules for Consistency Prudhoe Bay Unit Lisburne Oil Pool — Conservation Order (CO) 207D West Beach Oil Pool — CO 311B Pt. McIntyre and Stump Island Oil Pools — CO 317B Niakuk Oil Pool — CO 329B North Prudhoe Bay Oil Pool — CO 345 Greater Point McIntyre Area — CO 362A Raven Oil Pool — CO 570 Dear Ms. Garner: By letter dated February 20, 2020, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to amend the pool rules in the above referenced orders to bring conformity and consistency to the rules governing operations in the pools in the Greater Point McIntyre Area (GPMA), to make operations more efficient, and to make compliance oversight for the Alaska Oil and Gas Conservation Commission (AOGCC) simpler. There are several requests that apply broadly across multiple GPMA pools. These are as follows. COs 20713.001, 31 1B.003,317B.003, 32913.005, 345.002, 362A.006,570.010 April 3, 2020 Page 2 of 12 Well Spacing Requirements: Currently, the Lisburne Oil Pool (LOP) has an interwell spacing requirement of one well per government quarter section and no pay opened within 1,000 feet of another well. The West Beach Oil Pool (WBOP) has an interwell spacing requirement of one well per 160 acres until circumstances warrant the AOGCC changing it. The Pt. McIntyre Oil Pool (PMOP) has a spacing requirement of one well per 40 acres with no pay open within 500 feet of another well. The Niakuk Oil Pool (NOP) gives the AOGCC the authority to approve the drilling of any well that is at least 500 feet from the affected area boundary and does not have open pay within 1,000 feet of another well. The Raven Oil Pool (ROP) has an interwell spacing requirement of 20 acres with no pay open within 500 feet of the affected area external boundary. BPXA requests that the interwell spacing requirements be eliminated and that the only spacing requirement be a 500 -foot offset from property lines where the landowner is not the same on both sides of the line. At the time the spacing requirements in these pool rules were imposed wells were being drilled nearly vertically. Because modern horizontal and multi -lateral wells are now being utilized to develop pools, BPXA needs flexibility to drill wells as dictated by the geology and reservoir models in order to maximize recovery. Standardizing the spacing requirements by eliminating interwell spacing requirements while retaining property offset requirements will result in improved recovery while protecting correlative rights. Pressure Survey Requirements: BPXA requests that the pressure survey requirements be modified so that compliance with regulatory oversight becomes simpler and data is collected in a meaningful manner. Currently, the Lisburne Oil Pool (LOP) requires at least one pressure survey be taken each year from each producing drillsite and that the results be submitted monthly, while the West Beach Oil Pool (WBOP), Pt. McIntyre Oil Pool (PMOP), and Niakuk Oil Pool (NOP) require one pressure survey per producing governmental section per year and results submitted quarterly. North Prudhoe Bay Oil Pool (NPBOP) requires one pressure survey per producing governmental section but doesn't specify when the results need to be reported, and Raven Oil Pool (ROP) requires one pressure survey per reservoir compartment where production wells exist and specifies the results are to be reported in the annual reservoir surveillance report. The inconsistency in where pressure surveys need to be collected and how the results are to be reported makes it more difficult for the operator to stay in compliance without yielding any benefit that could not be obtained by more uniform collection and reporting requirements. Moreover, after decades of development and reporting, the pools in the PBU are well understood and have sophisticated reservoir models. At this point, monitoring of reservoir pressure is important for proper reservoir development and targeted pressure surveys would provide the most useful information for reservoir development purposes. Presenting the results of the reservoir pressure surveys from the prior year in the annual reservoir surveillance report and proposing a plan for collection of reservoir pressure surveys in the coming year as part of the annual reservoir surveillance report will give the AOGCC an opportunity to review the data and ensure the proposed plans are adequate. This is consistent with how the other pools in the PBU are managed. COs 207D.001, 31113.003, 317B.003, 32913.005, 345.002,362A.006, 570.010 April 3, 2020 Page 3 of 12 Well Testing: The GPMA pools have inconsistent well testing requirements that include quarterly allocation process reviews, monthly allocation reports, determining water volumes by API approved methods or an on-line water cut meter, monthly or annual API gravities for each well depending on the pool, gas samples collected yearly from each non -gas lifted producer, a minimum of two well tests per well, and twice monthly well tests. BPXA requests to eliminate the quarterly allocation process reviews and monthly allocation reports and proposes instead to provide an allocation factor report as part of the annual surveillance report as is done elsewhere in the PBU. BPXA also requests eliminating the water volume calculation, API gravity, and gas sampling requirements since at this point, recovery methods in these pools are unchanging and render this data of little benefit. Finally, BPXA requests to eliminate the requirement to test each producing well at least twice each month and instead require a minimum of one test per month per well. This request is consistent with how the rest of the PBU is managed and allows BPXA to maximize its well testing resources by testing the wells with stable production less frequently and testing the wells with less stable production more frequently to improve the overall allocation of production. Additionally, BPXA makes several requests that apply only to a single pool. These include the following. LOP Gas Oil Ratio (GOR) Testing Requirement: The LOP requires a GOR test on each producer within 90 to 120 days of commencement of regular production and then semiannually thereafter. The monthly well testing requirements for allocation purposes will provide adequate information as to the producing GOR of the wells so as to render the current rule unnecessary. LOP Gas Cap Water Injection (GCWI) Project: BPXA proposes to remove the 20,000 BWPD injection rate limit and raise the injection pressure limit from 0.55 psi/ft to 0.85 psi/ft. When the LOP GCWI was initially approved it was thought that the water injection rate and pressure must be constrained to prevent parting the LOP matrix to prevent premature water breakthrough. After several years of operation, such strict limits on injection rates and pressure do not appear to be necessary and the GCWI project will still function as planned if injection rates are constrained to 0.85 psi/ft. PMOP Enhanced Oil Recovery (EOR) Project Report: BPXA requests elimination of the annual EOR project report for the PMOP because miscible injectant for this pool is now being supplied by PBU Central Gas Facility and not from the Lisburne Production Center. As such, a PMOP EOR project specific report is no longer needed as the MI composition is the same as elsewhere in the PBU. Conclusions: Each of the affected COs contain an administrative action rule that allows the AOGCC to administratively amend the orders provided the proposed change does not promote waste, jeopardize correlative rights, is based on sound engineering and geoscience principles, and will COs 207D.001, 311B.003, 317B.003, 329B.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 4 of 12 not increase the risk of fluid movement into freshwater. All of BPXA's requested changes comply with these requirements. The proposals to consolidate the rules across the GPMA pools, eliminate or modify the GOR testing and GCWI project rules in the LOP, and eliminating the requirement for an unnecessary EOR project report for the PMOP will simplify operations for BPXA, make uniform the compliance requirements, and will not impact ultimate recovery. Eliminating interwell spacing requirements, while maintaining a minimum offset distance from property lines where ownership changes, will maximize ultimate recovery while also protecting correlative rights. The only proposed change that could potentially have an impact on fluid movement into fresh water is the elimination of the water injection rate limitation and increasing the water injection pressure limitation for the LOP GCWI. However, since the proposed injection pressure limit is below the fracture gradient of the confining interval this will ensure the LOP GCWI injection remains in the LOP. The proposed changes can be made administratively. Finally, on its own motion, the AOGCC is revising the administrative action rules, where necessary, to be consistent and uniform with the language currently used by the AOGCC for these rules. Now, therefore, it is ordered that the subject conservation orders are amended as shown below Lisburne Oil Pool — Conservation Order No. 207D Rule 3. WELL SPACING There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 9 GAS -OIL RATIO TESTS (Rescinded] Rule 10. PRESSURE SURVEYS a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Lisburne Oil Pool Reservoir Surveillance Report by June 15th of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Lisburne Oil Pool Reservoir Surveillance Report by June 151 of each year on Form 10- 412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,900 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. COs 207D.001, 31113.003, 31713.003, 32913.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 5 of 12 Rule 16. GAS -CAP WATER INJECTION PROJECT a. Water injection is authorized into Well L5-29 only and is limited to perforations within the upper Wahoo Formation (Zone 6) between the measured depths of 13,585' and 13,634'; and b. Injection pressures must be maintained below 0.85 psi/ft. West Beach Oil Pool— Conservation Order No. 311B Rule 3 Well Spacing There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 7 Common Facilities and Surface Commingling a. Production from the West Beach Pool may be commingled on the surface with production from other pools prior to custody transfer. b. 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 AOGCC. C. Each producing well will be tested at least once each month. Wells that have been shut-in and cannot meet the once -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. d. Optimum test duration and stabilization time will be determined on a well -by -well basis by the operator. Rule 9 Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual West Beach Oil Pool Reservoir Surveillance Report by June 15`h of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual West Beach Oil Pool Reservoir Surveillance Report by June 15"' of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut- in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be COs 20713.001, 31113.003, 31713.003, 32913.005, 345.002,362A.006,570.010 April 3, 2020 Page 6 of 12 permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. Pt. McIntyre and Stump Island Oil Pools — Conservation Order No. 317B Rule 4 Well Spacing There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 10 Surface Commingling and Common Facilities a. Production from the Pt. McIntyre and Stump Island Oil Pools may be commingled at the surface with production from other pools for processing at the Lisburne Production Center ("LPC") and production from the Pt. McIntyre Oil Pool Drillsite PM2 may be commingled at the surface with production from other pools for processing at the Prudhoe Bay Unit IPA Gathering Center 1 ("GCI"), prior to custody transfer. b. Daily production from all wells will be based on empirical well performance curves derived from 3-phase flow equations and production well test data, and will he a function of flowing tubing pressure and gas -lift rate. The method is described within the "Prudhoe Bay Unit (PBU) Western Satellite Production Metering Plan — Policies and Procedures Document" dated August 1, 2002. c. Each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operation conditions must be utilized for well testing. d. Optimum test duration and stabilization time will be determined on a well by well basis by the operator. e. Wells will use the associated process facility allocation factor for oil, gas, and water. Pt. McIntyre wells that flow to both GC 1 and LPC in the same month will use a prorated (GC 1 and LPC) well allocation factor for oil, gas, and water. f. Natural gas liquids ("NGLs") processed at the LPC 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 AOGCC. COs 207D.001, 31113.003, 3176.003, 32913.005, 345.002, 362A,006,570.010 April 3, 2020 Page 7 of 12 g. NGLs attributable to the PM2 to GCI gas stream and recovered at the CGF will be allocated by calculating the amount of separator off -gas, excluding gas lift gas, attributable to Pt. McIntyre wells producing into GC -1. The percentage of total separator off -gas delivered to the CGF, that is Pt. McIntyre formation gas, multiplied by the total NGL recovery at CGF, yields the amount of NGLs to be allocated to Pt. McIntyre. h. Allocation data and well test data will be supplied to the AOGCC via the Annual Reservoir Surveillance Report. Rule 12 Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Pt. McIntyre Oil Pool Reservoir Surveillance Report by June 151i of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Pt. McIntyre Oil Pool Reservoir Surveillance Report by June 151i of each year on Form 10- 412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 14 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. Rule 16 Pt McIntyre Oil Pool Enhanced Oil Recovery Proiect Injection of miscible injectant for enhanced recovery operations is approved for the Pt. McIntyre Pool. COs 207D.001, 31113.003, 317B.003, 32913.005, 345.002, 362A.006,570.010 April 3, 2020 Page 8 of 12 Niakuk Oil Pool — Conservation Order No. 329B Rule 3 Well Spacing There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 6 Surface Commingling and Common Facilities a. Production from the Niakuk oil pool may be commingled on the surface with production from other pools for processing at the LPC 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 AOGCC via the Annual Reservoir Surveillance Report. i. Conduct well tests to determine production rates for each well. ii. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. iii. 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 c. NGL's 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 AOGCC. I Each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -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 time will be determined on a well by well basis by the operator. Rule 8 Reservoir Pressure Monitorin a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Niakuk Oil Pool Reservoir Surveillance Report by June 151 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. COs 207D.001, 311B.003, 31713.003, 329B.005, 345.002,362A.006, 570.010 April 3, 2020 Page 9 of 12 b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Niakuk Oil Pool Reservoir Surveillance Report by June 15`h of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 12 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. North Prudhoe Bay Oil Pool — Conservation Order No. 345 Rule 5 Surface Commingling and Common Facilities a. Production from the North Prudhoe Bay Oil Pool may be commingled on the surface with production from other pools for processing at the LPC 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 AOGCC via the Annual Reservoir Surveillance Report. 1. Conduct well tests to determine production rates for each well. 2. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. 3. Sum the TMP volume for all wells in all pools. 4. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP). 5. Calculate each well's actual monthly production (AMP) volume as: AMP = TMP x Allocation Factor 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 AOGCC. COs 207D.001, 31113.003, 31713.003, 32913.005, 345.002,362A.006,570.010 April 3, 2020 Page 10 of 12 d. At a minimum, each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -monthly test frequency must be tested within five days of startup. e. Optimum test duration and stabilization time will be determined on a well -by - well basis by the operator or, in its discretion, by the AOGCC. Rule 7 Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual North Prudhoe Bay Oil Pool Reservoir Surveillance Report by June 15th of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual North Prudhoe Bay Oil Pool Reservoir Surveillance Report by June 15th of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. COs 207D.001, 31113.003, 317B.003, 329B.005, 345.002,362A.006, 570.010 April 3, 2020 Page 11 of 12 Greater Pt. McIntyre Area — Conservation Order No. 362A.005 Rule 1: Lisburne Production Facilities Produced fluids from the Lisburne Oil Pool, West Beach Oil Pool, North Prudhoe Bay Oil Pool, Niakuk Oil Pool, Pt. McIntyre Oil Pool, Stump Island Oil Pool, and Raven Oil Pool may continue to be commingled on the surface for processing at the Lisburne Production Center. Production from each pool may be assigned on the basis of at least once monthly well tests using procedures described in individual conservation orders for those pools or in this order. The AOGCC may approve a different test frequency for individual wells upon application. Raven Oil Pool — Conservation Order No. 570 Rule 3: Well Spacin¢ There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 6• Common Production Facilities and Surface Comminaline a. Production from the Raven Oil Pool may be commingled on the surface with production from other pools for processing at the LPC 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 AOGCC via the Annual Reservoir Surveillance Report. Conduct well tests to determine production rates for each well. ii. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. iii. 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). Calculate each well's actual monthly production (AMP) volume as: AMP = TMP x Allocation Factor c. NGL's 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 AOGCC. d. Each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -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 time will be determined on a well by well basis by the operator. COs 20713.001,311B.003,317B.003,329B.005,345.002,362A.006,570.010 April 3, 2020 Page 12 of 12 Rule 7• Reservoir Pressure Monitoring a. C. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Raven Oil Pool Reservoir Surveillance Report by June 15tb of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. Data from the surveys required in (a) of this rule shall be submitted with the Annual North Raven Oil Pool Reservoir Surveillance Report by June 15th of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 9,850 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. DONE at Anchorage, Alaska and dated April 3, 2020. Jeremy M. Price Jeremy M. Price Chair, Commissioner Daniel T. Seamount, Jr. Daniel T. Seamount, Jr Commissioner Digital Jessie L. Je sta Chmielowski Dae 2v` 13:56:53 -gaga Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. 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That" r F" nfnae ingrt on Yedwr nen m.. a, I the "-_- 1L1 no ParMen onNmelryenpnmeYmn Yreyued.. Prod.bnenana reswmemlMurna[CNIhe10 mNlm tlreymOneogrn rnPonO to ywmF oryNtr mn .gimme rebNe mawgmem. Nd env a Ymn IIIHE STATE ofi-1 1 V 1 -- GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVALS CONSERVATION ORDER NO. 83A.001 CONSERVATION ORDER NO. 207D.002 CONSERVATION ORDER NO. 311B.004 CONSERVATION ORDER NO. 31711.004 CONSERVATION ORDER NO. 329A.002 CONSERVATION ORDER NO. 3411.002 CONSERVATION ORDER NO. 345.003 CONSERVATION ORDER NO. 452.005 CONSERVATION ORDER NO. 457B.007 CONSERVATION ORDER NO. 471.010 CONSERVATION ORDER NO. 484A.005 CONSERVATION ORDER NO. 50513.003 CONSERVATION ORDER NO. 559A.002 CONSERVATION ORDER NO. 570.011 Mr. Oliver Sternicki Well Integrity Engineer Hilcorp North Slope LLC P. O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Numbers: CO -20-004 and CO -20-008 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w oogcc.alasko.gov Request to amend normal operating limit for inner annulus pressure for non Lisburne development area wells from 2,000 psig to 2,100 psig and to add an administrative approval clause to Conservation Order No. 492 Prudhoe Bay Unit All Oil Pools Dear Mr. Sternicki: By application dated February 24, 2020, Hilcorp North Slope, LLCI (HNS) applied to modify Conservation Order No. 492 (CO 492) to raise the inner annulus (IA) normal operating limit (NOL) reporting threshold from 2,000 psig to 2,100 psig for all wells not processed through the Lisburne Processing Center (LPC)'. CO 492 was issued on June 26, 2003 and applied to all pools in the The February 24, 2020, application was submitted by BP Exploration (Alaska) Inc. (BPXA) as operator of the Prudhoe Bay Unit (PBU) but effective on July 1, 2020, BPXA came under new ownership and was renamed HNS. HNS is currently the operator of the PBU. z The ]A NOL for wells processed through the LPC is currently set at 2,500 psig. HNS is not seeking to modify this at this time. COs 83A.001, 207D.002, 311B.004, 317B.003, 329A.002, 3411.002, 345.003, 452.005, 457B.006, 471.009, 484A.005, 505B.003, 559A.002, & 570.011 October 1, 2020 Page 2 of 4 Prudhoe Bay Unit (PBU). The order established rules for dealing with sustained casing pressure for all producers in the PBU. Some, but not all, of the pools in the PBU area have incorporated the rules found in CO 492 directly into its pool rules. CO 492 itself did not contain provisions to allow it the be administratively amended, so providing public notice and opportunity to comment was required in order to amend the order. As such CO 492 will be amended separately and this letter will amend the individual pool rules for the PBU area oil pools. Due to operational changes over time in the PBU, namely increases in the gas lift header pressures, the 2,000 psig NOL for the IA that requires notification to the Alaska Oil and Gas Conservation Commission (AOGCC) when it is exceeded is triggering numerous notifications. These notifications do not on their own require any corrective action to be taken, but simply are a reporting burden on the operator and the AOGCC. Increasing the NOL from 2,000 to 2,100 would decrease the frequency of these notifications. Currently, the NOL for the IA for wells processed through the LPC is 2,500 psig. Exceeding the 2,500 psig NOL triggers a reporting requirement, but does not, standing alone, require corrective action. Another limit that is currently in place, and is not being changed by this action, is a pressure limitation of 45% of the casing's burst pressure rating. Exceeding the 45% pressure limitation requires that corrective action to be taken. Increasing the reporting threshold from 2,000 psig to 2,100 psig for the wells that are not processed at the LPC will eliminate many unnecessary notifications for wells where notification was triggered by the gas lift system pressure instead of an actual problem with the well that might indicate loss of containment. Increasing the IA NOL from 2,000 psig to 2,100 psig for production wells that are not processed at the LPC is based on sound engineering and geoscience principles. Now therefore it is ordered that the text below shall replace the text in the specified rules in the following orders: Conservation Order Oil Pool 207D Lisburne 457B Aurora 484A Polaris 505B Schrader Bluff 559A Put River 570 Raven Rules being replaced 15 11 and 123 11 11 10 12 I In the current CO 457B, the pool rules for the Aurora Oil Pool, Rule 11 contains paragraphs a. through f. of the annular pressure rules and Rule 12 contains the definitions in paragraph g. of the annular pressure rules. Paragraph g. is a part of the revised Annular Pressure of Production Wells shown here and thus Rule 12 in CO 457B is being eliminated. COs 83A.001, 207D.002,31 I B.004,317B.003, 329A.002, 3411.002, 345.003, 452.005,457B.006, 471.009, 484A.005,505B.003,559A.002, & 570.011 October 1, 2020 Page 3 of 4 And be added as the new rule indicated in the following orders: Conservation Order Oil Pool Added rule 83A Kuparuk River 9 31113 West Beach 14 317B Pt McIntyre and Stump Island 17 329A Niakuk 13 341I Prudhoe Oil Pool 22 345 North Prudhoe Bay 12 452 Midnight Sun 15 471 Borealis I 1 Annular Pressure of Production Wells a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each production well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each production well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for Commission inspection. c. The operator shall notify the Commission within three working days after the operator identifies a well as having (1) sustained inner annulus pressure that exceeds 2500 psig for wells processed through the Lisburne Processing Center and 2100 psig for all other production wells, or (2) sustained outer annulus pressure that exceeds 1000 psig. d. The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any production well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The operator shall give the Commission notice consistent with the requirements of Industry Guidance Bulleting 10-01 A of the testing schedule to allow the Commission to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a production well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the Commission within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10- 403) a proposal for corrective action. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. COs 83A.001, 207D.002, 31 1B.004, 317B.003, 329A.002, 3411.002, 345.003, 452.005, 457B.006, 471.009, 484A.005, 505B.003, 559A.002, & 570.011 October 1, 2020 Page 4 of 4 f Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the Commission under (c) of this rule, unless the Commission prescribes a different limit. g. For purposes of this rule, 1. "inner annulus" means the space in a well between tubing and production casing; 2. "outer annulus" means the space in a well between production casing and surface casing; 3. "sustained pressure" means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) is not pressure that has been applied intentionally. DONE at Anchorage, Alaska and dated October 1, 2020. Jeremy J ent,M Price by Date: 20201001 M. Price 131vaear00' Jeremy M. Price Chair, Commissioner Daniel T. Denied r xamoumdc. 5eamount, Jr. 02'."e20a 001 Daniel T. Seamount, Jr. Commissioner Je$512 L. Digitally signed by Jessie L Chmielowski Chmielowski 111:2020.1001 12:22:07-08'00' Jessie L. Chmielowski Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days atter the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 12 J From: Rixse, Melvin G (CED) Sent: Wednesday, June 10, 2020 2:27 PM To: Sternicki, Oliver R Cc: Colombie, Jody J (CED) Subject: FW: June 25 hearing to amend 4 CO's Attachments: CO -20-008 Public Hearing Notice.pdf, RE: CO -20-008 This is a clarification email to BPXA, Oliver Sternicki, that the AOGCC interpretation of any development well going through Lisburne Production Center, whether on gas lift or natural flow, will be allowed 2500 psig sustained inner annulus pressure before reporting is required. CO -20-008 as written should be fine. We will then administratively amend the COs per the notice. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231) or (Melvin. Rlxsera) a l aska Pov). cc. Jody Colombie From: Colombie, Jody J (CED) Sent: Wednesday, June 10, 2020 8:59 AM To: Chmielowski, Jessie L C (CED) <Jessie.chmielowskiPalaska.eov> Cc: Rixse, Melvin G (CED) <melvin.rixse(@alaska ¢ov> Subject: RE: June 25 hearing to amend 4 CO's No one has requested a hearing Mel: Do you vote to vacate? Jody From: Chmielowski, Jessie L C (CED) <iessie.chmielowski(@alaska eov> Sent: Wednesday, June 10, 2020 8:57 AM To: Colombie, Jody J (CED) <jody.colombie@alaska eov> Cc: Rixse, Melvin G (CED) <melvin.rixsePalaska.gov> Subject: June 25 hearing to amend 4 CO's Hi Jody, Were there any requests to hold the hearing that's scheduled for June 25? Wondering if we can vacate and administratively amend the CO's? Co; imbie, Jody J (CED) From: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Sent: Tuesday, June 2, 2020 3:43 PM To: Rixse, Melvin G (CED) Cc: Lau, Jack Subject: RE: CO -20-008 Mel, I was doing some work on the NOL increase and noticed something that might need slightly more clarification. The operator shall notify the AOGCC within three working days after the operator identifies a dm-elopment well as having (a) sustained inner annulus pressure that exceeds 2500 psig for wells with supplied gas lift pressure from the Lisburne Processing Center and 2100 psig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig. The issue is that this wording could be interpreted as just applying to the gas lifted produces at LPC and excludes the natural flow producers at that facility and in the GPMA area. There are currently 69 wells this applies to. This part should read: ...for wells with supplied gas lift pressure from the Lisburne Processing Center or wells processed through the Lisburne Processing Center... Let me know what you think, OliveerAStternicki V Yo g��V�� Sr. Well Integrity Engineer BP Exploration Alaska Cell: 1 (907) 350 0759 oliver.sternickiCai7bp.com From: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Sent: Friday, May 15, 20204:31 PM To: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Subject: FW: CO -20-008 From: Colombie, Jody 1 (CED) <iodv.colombie_@alaska.aov> Sent: Friday, May 15, 2020 3:16 PM To: AOGCC_Public_Notices <AOGCC Public Notices PIist state ak us> Subject: [AOGCC_Public_Notices) CO -20-008 Docket Number: CO -20-008 Prudhoe Bay Field, All Pools .1odv.1 Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7'� Avenue Anchorage, AK 99501 (907) 793-1221 Direct (907) 2 76- 7542 Fax List Name: AOGCC Public Notices@?Iist state ak us You subscribed as: ryan.danielCoft.com Unsubscribe at: http://Iist.state ak.us/mailman/options/aogcc public notices/ryan daniel%40bp com STATE OF ALASKA ADVERTISINGNOTICE ORDER TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVITOFPUBAIDVERTTMENN'T.ATTACHED COPY OF ADVERTISING ORDER NUMBER AO -08-20-024 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O.AGENCY 5/152020 PHONE: 907 279-1433 333 West 71h Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: 907 276-7542 TO PUBLISHER: Anchorage Daily News, LLC SPECIAL INSTRUCTIONS: PO Box 140147 Anchors a Alaska 99514-0174 TYPE OF ADVERTISEMENT: FV_ LEGAL I— DISPLAY r CLASSIFIED 'fir OTHER (Specify below) DESCRIPTION PRICE CO -20-008 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBMIT INVOICE SHOWING ADVENDSING ORDER NO., CERTIFIED AFFNAVIT OF PUBLICATIO Al TO: AOGCC 333 West 7th AvenueTotal Anchors e, Alaska 99501 Pae 1 of 1 of All Pages $ REF 1 Tye Number Amount Date Comments I PvN IVCO21795 2 AD AO -08-20-024 3 a FIN AMOUNT SY AcL Tem late PGM LCR Object FY DIST LIQ t 20 AOGCC 3046 20 2 3 4 5 Title: Purchasing Authority's Signature Telephone Number IF;ri ceiving agency name must appearon all invoices and documents relatingto this purchase. egisteredfor tax free transactions underChapter32, IRS code. Registraaonnumber92-73-0006K. Items are for the exclusive use of the slateand DISTRIBUTION: Division Fiscal/Original AO Copies: Publisher (faxed), Division Fiscal, Receiving Form: 02-901 Revised: 5/21/2020 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: CO -20-008 Prudhoe Bay Field, All Pools BP Exploration Alaska, Inc., by application received February 24, 2020, requests the Alaska Oil and Gas Conservation Commission (AOGCC) revise Rule 3 of Conservation Orders 317, 505, 559 and 570 to include the following language: The operator shall notify the AOGCC within three working days after the operator identifies a development well as having (a) sustained inner annulus pressure that exceeds 2500 psig for wells with supplied gas lift pressure from the Lisburne Processing Center and 2100 psig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig. In addition, on its own motion AOGCC proposes to add the language that "unless notice and public hearing are otherwise required, upon proper application the AOGCC may administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater." The AOGCC has tentatively scheduled a public hearing on this application for June 25, 2020, at 10:00 a.m. at 333 West 7' Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on June 5, 2020. Due to health mandates issued as a result of the covid-19 virus, if a hearing is requested, the hearing will be held telephonically. Those desiring to participate or be present at the hearing should call 1-800-315-6338 and, when instructed to do so, enter the code 14331. Because the hearing will start at 10:00 a.m., the phone lines will be available starting at 9:45 am. Depending on call volume, those calling in may need to make repeated attempts before getting through. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1221 after June 7, 2020. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7`s Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on June 22, 2020, except that, if a hearing is held, comments must be received no later than the conclusion of the June 25, 2020 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at (907) 793-1221, no later than June 20, 2020. Jertmy M. Price Chair, Commissioner Bernie Karl K&K,Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 3 BP Exploration (Alaska) Inc., Attn: Well Integrity Coordinator, PRB-20 ,. Post Office Box 196612(40 Anchorage, Alaska 99519-6612 February 24, 2020 Mr. Jeremy Price Alaska Oil and Gas Conservation Commission 333 West 71h Avenue Anchorage, Alaska 99501 Subject: Request to amend Conservation Order No. 492 rule 3(a) and 6(a). Dear Mr. Price, BP Exploration (Alaska) Inc. requests an amendment to Conservation Order No. 492 rule 3(a) and 6(a) such that current notification and pressure limits are changed from 2000psi to 2100 psi for wells not processed through the Lisburne Processing Center. Current maximum gas lift header pressure in the Prudhoe Bay field for wells not processed through the Lisburne Processing Center regularly exceeds 2000psi. The field - wide IA (Inner Annulus) NOL (Normal Operating Limit) is set at 2000 psi for non -Lisburne development wells, excluding jet pump wells. Beginning in 2015 BPXA began installation of wireless digital annulus pressure gauges on all wells, this was completed in late 2019. Due to the increased accuracy of the annulus pressure readings and realtime monitoring/alerting capability, board operators are now very frequently responding to false alerts of IA NOL excursions on gas lifted wells due to gas lift header pressure exceeding 2000 psi, not sustained casing pressure as intended. BPXA requests that rule 3(a) and 6(a) be changed from 2000psi to 2100 psi (excluding jet pumps) for wells not processed through the Lisburne Processing Center to help minimize b>�d and well pad operators responding to false alerts. If you have any questions, please call me at 564-5430. Sincerely, Ryan Daniel BPXA Well Integrity Team Lead Attachments: Technical Justification Technical Justification for Conservation Order No. 492 Amendment February 24, 2020 History and Status: Gas lift header pressure at many of the drill sites and pads in the Prudhoe Bay field (excluding wells processed through the Lisburne Process Center) regularly exceeds the 2000 psi IA NOL set for development wells. Gas lift compressor outlet pressures are commonly set at 2100 psi. Historical gas lift pressures can be seen in Figure 1 & 2 for reference. The legacy IA NOL value of 2000 psi was set to remain compliant with Conservation Order No. 492 rule 3(a) and 6(a). Prior to the installation and monitoring of wireless annulus pressure gauges this was not as large of a problem due to one IA pressure read being recorded via mechanical gauge daily per well. If a pressure read exceeded the 2000 psi NOL it was reported to Well Integrity and evaluated to determine if the excursion was SCP or not. Currently all wells in the Prudhoe Bay field have the inner annulus pressures monitored in real-time by either the EOA or WOA production center board operators. The board operators are notified with an alert when the IA pressure of a well exceeds the set NOL value of 2000 psi. This ensures a timely notification and response to any potential excursion event. With the utilization of the wireless annulus pressure gauge alerting it has become an ongoing problem where wells supplied with gas lift pressure are regularly setting off alerts due to the gas lift supply pressure exceeding the 2000 psi NOL and not due to SCP as intended. This excessive alerting has the potential to desensitize workers to possible hazardous occurrences. Increasing IA NOL from 2000 psi to 2100 psi for development wells would eliminate the majority of these false NOL excursion alerts and allow resources to be more focused on response and evaluation of probable SCP events. This increase of 100 psi to the IA NOL is well within the design parameters of development wells across the Prudhoe Bay field. All development wells are included in this request in an effort to reduce the complexity of the IA NOL change. While non gas lifted wells are not subject to the same false alerts there is an increased risk of operating the field with IA NOLs varying for different types of wells. The use of gas lift on development wells, including natural flow producers, is continually changing, some require gas lift for kick off purposes only while others need constant gas lift. Gas lift usage may also change as a well ages depending on depletion or may change due to well work such as add perf/ reperf interventions. The tracking of these dynamic changes would be very difficult and the continual changing of NOL between 2000 psi and 2100 psi for individual wells in multiple data and control systems would greatly increase the complexity and management of NOLs across the field. This inconsistency in IA NOLs would be difficult for field personnel to continually keep track of and would reduce their effectiveness in identification of potential SCP events and would potentially result in misreporting of excursions. The IA NOL increase would not reduce the ability to identify SCP excursions in non -gas lifted wells. BPXA currently monitors development wells for minimum tubing by IA differential pressure thresholds as an indicator of communication. In addition to this SITP of non - gas lifted wells is in excess of 2100 psi, which if seen on the IA would indicate a loss of tubing integrity and would flag as SCP. Based on this it is requested to increase the IA NOL for all development wells (excluding jet pump wells and those processed through the Lisburn Processing Center) to 2100 psi. Figure 1- EOA DS Gas Lift Header Pressure EOA Gas Lift Pressure 9/1UID16 3/U10{4 OW., U9/t05 9/iyN115 13/3)/2015 1/6/2016 2AW=6 Figure 2- WOA Pad Gas Lift Header Pressure WOA Gas Lift Pressure —DID: —DSM i --DIK —DS OS —DS Dv —MC9 Ds u —os la — Dsn —a Pte —SP.a —DPte Nwa —arta —LPA —MP.O —NFH PPN R Nd —SPM --owe v wa V PM .PW we P.. SE 3o Exploration (Alaska) Inc 900 East Benson Boulevand P.O. Boz 196612 Anchorage, Alaska 99519-6612 (907) 551-511.1 February 20, 2020 Via USPS and Electronic Delivery Jeremy Price Commission Chair Alaska Oil and Gas Conservation Commission 333 West P Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Administrative Approval Conforming PBU GPMA Pool Rules for Consistency Amendments to Conservation Orders: 207C, Rules 3, 9c, IOa-f,l6c; CO 317B Rules 4, 10b,d, 10g, 10h, 10i, IOj, 12a -f, 16b; CO 329A Rules 3, 6b,d, f -j, 8a -f, e; CO 311B Rules 3, 7b, d, f -k; 9a -f; CO 345 Rules 5b,d,f-i, 7a -f; CO 362A.005 Rule 1; CO 570 (Corrected) Rule 3; AA No. 570.002; CO 570.004 Rule 6 b, d, f -i; , l Of governing the development and operation of the Lisburne, Pt. McIntyre, Niakuk, West Beach, North Prudhoe, and Raven Oil Pools Dear Chair Price, Aj BP Exploration (Alaska) Inc. (BPXA), as the operator of the Prudhoe Bay Unit (PBU), respectfully requests that the commission administratively approve amendments described in this application to the referenced Conservation Orders. Each of these pools is in the Greater Pt. McIntyre Area (GPMA) in the PBU. This administrative relief is sought under Rule 17 of CO 207C and its equivalents in the other referenced Conservation Orders. The amendments are proposed with the goal of bringing more efficiency to the management of these reservoirs through achieving as much rule consistency as possible, while still honoring the unique aspects of each pool. More consistent rules will also result in easier monitoring of compliance for the Commission. The proposed changes are in line with recent Commission - approved changes to CO 341F (January, 2018) for the Prudhoe Oil Pool and for changes made to COs 452, 457B, 471, 484A, 505B for the Aurora, Borealis, Orion, Polaris and Midnight Sun Oil Pools (May 29, 2019). With the GPMA Plan Year running April 1 — March 31, BPXA RECEIVED FEB 2 1 2020 AOGCC respectfully requests adjudication by April 1, 2020 in order that the entire next plan year may be under the new regulations. In overview*, BPXA seeks simplification and consistency for the following: Well Spacing. l3PXA proposes there should be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area, unless the owner and landowner are the same on both sides of the line. This is consistent with the language for the Prudhoe Oil Pool except for the "same landowner" clause which represents an improvement to the POP rule. Pressure Data 10-412 Report. BPXA proposes to eliminate the monthly (Lisburne) to quarterly (Pt. McIntrye, Niakuk, West Beach) to unspecified (N Prudhoe and Raven) reporting requirement by allowing the operator to annually nominate in the ASR (or if no ASR is required to annually report) the number and approximate locations of pressure surveys, with the AOGCC having 30 days to register an issue; if none is raised the proposed number will take effect. The pressure data report would be included in the ASR with that report replacing Lisburne's requirement for an annual meeting to review pressure monitoring requirements and to discuss plans for reservoir management. All data necessary for analysis of each survey need not be submitted with the report but must be available to the commission upon request. This is the current regulation for the POP. It is proposed to remove the requirement to determine water volumes, annual API gravity, and annual gas samples from each non -gas lifted producing well in the Surface Commingling and Common Facilities rules as our reservoir recovery mechanisms are not changing. The need for data of this kind on such a frequency is not justified. If the operator were to change the recovery mechanism then it might be prudent to monitor each well in such a manner but barring that, BPXA does not see this data guiding reservoir management decisions. Allocation Process Reviews. BPXA proposes to formally eliminate this requirement. Instead, this requirement can be replaced with an Allocation Factor report in the Annual Surveillance Report (ASR). Well Test data Report. BPXA proposes to formally eliminate this requirement for all GPMA pools that currently have it and replace it with the Allocation Factor report in the ASR, as provided for other BP operated pools in AOGCC Administrative Approval (AA) (Docket # CO -15-013) dated 1/7/16. That AA waived the requirement to submit monthly reports of daily allocation and test data for a number of PBU pools. It covered some but not all of the GPMA Pools. Well Test Frequency. BPXA proposes to go from two to one per month for the GPMA pools. This will be in alignment with the other PBU pools. *Items that pertain solely to individual pools are: proposed elimination of the Lisburne Oil Pool Gas -Oil Ratio Test requirement, proposed upward revision of Injection Gradient and elimination of injection rate limit for the Lisburne Gas Cap Water Injection Project, and proposed elimination of the Pt. McIntyre Oil Pool EOR Project performance report. Rationale behind these "one-off' items is provided in Table 1, a spreadsheet containing all the proposed changes across the six GPMA pools. 2 The specific requests are detailed on an individual pool basis below using the convention of brackets [ ] for deletions of existing order words; use of underline denotes proposed new text. Only those rules and paragraphs within rules that have proposed changes are included below. Lisburne Oil Pool Conservation Order 207C Rule WELL SPACING (Source: CO 207) There shall be no restrictions as to well spacing except that no IThe well spacing unit shall be one producing well per governmental quarter section. No] pay shall 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 9 GAS -0I1. 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 minimum 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 submitted in January and July of each year.] Rule 10 PRESSURE SURVEYS 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. 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, temperature, and well conditions to allow for a complete analysis of the pressure survey. 0 The operator shall schedule an annual meeting with the Commission to review the pressure monitoring program and discuss future plans for reservoir management.] 3 a. year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Lisburne Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10-412 Data submitted shall include rate pressure time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,900 true vertical feet subsea. Transient pressure surveys obtained by a shut-in buildup test an injection well pressure fall-off test, a multirate test or an interference test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoringtechnigues, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 16 CAC -CAP WATER INJECTION PROJECT [b The Well L5-29 injection rate is limited to 20,000 barrels of water injected per day;] c.Injection pressures must be maintained below 0.85 psi/ft. Pt. McIntyre Oil Pool Conservation Order 317B Rule 4 Well Spacing There shall be no restrictions as to well spacing except that no [The spacing unit shall be one producing well per 40 acres or quarter -quarter governmental section. No] pay shall be opened in a well closer than 500 feet to the boundary of the affected area. Rule 10 Surface Commingling and Common Facilities 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 [quarterly in both computer file and report formats.] via the Annual Reservoir Surveillance Report. No changes to the remainder of b (sub paragraphs). d. Each producing well will be tested at least [twice] once each month. Wells that have been shut in and cannot meet the [twice] once 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 The operator shall submit a review of pool production allocation factors and 12 issues over the prior year with the annual reservoir surveillance report and retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years Data shall be presented on a monthly basis, reported annually in the ASR. [I Of) API gravity will be determined for each producing well annually by an API/MPMS approved method. 10g) Gas samples will be taken and analyzed for composition from each non -gas lifted producing well yearly. 10h) Quarterly allocation process reviews will be held with the Commission. 10i) This rule may be revised or rewritten after an evaluation period of at least one year.] Ia. Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure. b. A minimum of one bottom hole pressure survey per producing governmental section shall be run annually. The surveys in part a. of this rule may be used to fulfill the minimum requirements c. The datum for all surveys is 8800' TVDss. d. Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom hole pressure after the well has been shut in for an extended period. e. The pressure surveys will be reported to the Commission quarterly. Commission form 10-412, Reservoir Pressure Report, shall be used to report results from these surveys. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted upon request. f. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys also shall be submitted in accordance with part e. of this rule.] year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b Data from the surveys required in (a) of this rule shall be submitted with the Annual Pt. McIntyre Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10- 412 Data submitted shall include rate pressuretime depths temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea Transient pressure surveys obtained by a shut- in buildup test an injection well pressure fall-off test a multirate test, or an interference 5 test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for water injection wells Other quantitative methods may be administratively approved by the AOGCC. c Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 16 Pt. McIntyre Oil Pool Enhanced Oil Recovery Project [b. An annual report must be submitted to the Commission detailing performance of the PMOP Enhanced Oil Recovery Project and outlining compositional information for the current miscible injectant necessary to maintain miscibility under anticipated reservoir conditions. The report should be submitted in conjunction with the PMOP Annual Reservoir Report.] Niakuk Oil Pool Conservation Order 329 Rule 3 Well Spacing [Upon application ofthe operator, the Commission may administratively approve the drilling of any well to a bottom hole location greater than 500 lineal feet from the external boundary of the affected area. No well bore may be open to the Niakuk oil pool within 500 feet of the external boundary of the affected area nor within 1000 feet of another well capable of producing from thesamepool.] There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area. Rule 6 Surface Commin¢dng and Common Facilities 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.] via the Annual Reservoir Surveillance Report. No changes to the remainder of b (sub paragraphs). d.Each producing well will be tested at least [twice] once each month. Wells that have been shut in and cannot meet the [twice] once 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. [f.Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission. g.API gravity will be determined for each producing well annually by an API/MPMS approved method. h.Gas samples will be taken and analyzed for composition from each non gas lifted R producing well yearly. i.Quarterly allocation process reviews will be held with the Commission. j.This rule may be revised or rewritten after an evaluation period of at least one year.] Rule 8 Reservoir Pressure Monitoring a. [Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure. b. A minimum of one bottom hole pressure survey per producing governmental section shall be obtained annually. The surveys in part'a' of this rule may be used to fulfill the minimum requirements. c. The datum for all surveys is 9200' TVDss. d. Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom hole pressure after the well has been shut in for an extended period. e. The pressure surveys will be reported to the Commission quarterly on form 10-412, Reservoir Pressure Report. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted upon request. f Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with part'e' of this rule.] This pan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b Data from the surveys required in (a) of this rule shall be submitted with the Annual Niakuk Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10-412. Data submitted shall include rate pressure time depths temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea Transient pressure surveys obtained by a shut- in buildup test an injection well pressure fall-off test a multirate test, or an interference test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for water injection wells Other quantitative methods may be administratively approved by the AOGCC. VA c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. West Beach Oil Pool Conservation Order 311B Rule 3 Well Spacin¢ There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area. [Statewide 160 -acre drilling units are in effect until such time as data or circumstances warrant the Commission to approve a change.] Rule 7 Common Facilities and Surface Commingling [(b) Production from each pool will be determined by the following well test allocation method. Allocation data and well test data will be supplied to the Commission monthly in both computer file and report formats.] (d) Each producing well will be tested at least [twice] once each month. Wells that have been shut-in and cannot meet the [twice]once-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. [(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 producing West Beach well monthly. (h) Gas samples will be taken for each non -gas lifted producing well yearly. (i) Quarterly allocation process reviews will be held with the Commission. 0) Prior to installing separate test facilities (if required by future development) at West Beach, Commission approval of the facilities must be obtained. (k) This rule may be revised or rewritten after an evaluation period of at least one year.] Rule 9 Reservoir Pressure Monitorine [(a) Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure. (b)A minimum of one bottom -hole pressure survey per producing governmental section shall be run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements. (c)The datum for all surveys is 8,800' TVD SS. (d)Pressure survey will be a pressure buildup, pressure falloff, RFT, or static bottom -hole pressure after the well has been shut in for an extended period. (e)The pressure surveys will be reported to the Commission quarterly. Commission form 10-412, Reservoir Pressure Report, shall be used to report results from these surveys. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted on request. (f)Results and data from any special reservoir pressure monitoring techniques, tests, or surveys also shall be submitted in accordance with part (e) of this rule.] a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual West Beach Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10- 412 Data submitted shall include rate pressure time depths temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea Transient pressure surveys obtained by a shut- in buildup test an injection well pressure fall-off test a multirate test, or an interference test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for water iniection wells Other quantitative methods may be administratively gproved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques tests or surveys shall also be submitted as prescribed in (b) of this rule. North Prudhoe Bay Oil Pool Conservation Order 345 Rule 5 Surface Commingling and Common Facilities (b) Production from each well will be determined by the following well test allocation methodology. Allocation data and well test datawill be supplied to the Commission via the Annual Reservoir Surveillance Report. [monthly in bothcomputer file and report formats.] No changes to the remainder of b (sub paragraphs). (d) At a minimum, each producing well will be tested at least once [twice] each month. Wells that have been shut in and cannot meet the once [twice] monthly test frequency must be tested within five days of startup. [(f) Water volumes will be determined by APIIMPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission. (g) API gravity will be determined for each producing 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. (i) The allocation process for the North Prudhoe Bay Oil Pool will be reviewed with the Commission in conjunction with scheduled LPC allocation review.] Rule 7 Reservoir Pressure Monitoring [7a) Prior to regular production, a pressure survey shall be taken on each well to determine the reserv0lr pressure. 7b) Until a secondary recovery project is approved and implemented, a minimum of one bottom- hole pressure survey per producing governmental section shall be obtained annually. 7c) The datum for all surveys is 9245' TVDss 7d) Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom- hole pressure after the well has been shut in for an extended period. 7e) The pressure surveys will be reported to the Commission on form 10-412, Reservoir Pressure Report. All data necessary for complete analysis of each survey need not be submitted with the form 10-412, but must be submitted upon request. 7f) Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with parte' of this rule.] year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b Data from the surveys required in (a) of this rule shall be submitted with the Annual North Prudhoe Bay Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10-412 Data submitted shall include rate pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 9245 true vertical feet subsea. Transient pressure surveys obtained by a shut-in buildup test an injection well pressure fall-off test, a multirate test, or an interference test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c Results and data from any special reservoir pressure monitoringtechniques, echniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Raven Oil Pool Conservation Order 570 Rule 3: Well Spacing [To allow for close proximity of wells in separate fault blocks, spacing within the pool will be a minimum of 20 acres. The ROP shall not be opened in any well closer than 500 feet to the external property lines where ownership or landownership changes.] 10 There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area. Rule 10: Annual Reservoir Surveillance Report [f. By August 1 of each year, the Operator shall schedule and conduct a technical review meeting with the AOGCC to discuss the report contents and to review items that may require action within the coming year by the AOGCC. The AOGCC may conduct audits of technical data and analyses used in support of the surveillance conclusions and reservoir depletion plans.] Rule 6: Common Production Facilities and Surface Commingling c. All wells must be tested a minimum of [twice] once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. Wells that have been shut in and cannot meet the [twice] once 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. d. [The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation.] Allocation data and well test data will be supplied to the Commission via the Annual Reservoir Surveillance Report. [f.Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission. g.API gravity will be determined for each producing 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. i.Quarterly allocation process reviews will be held with the Commission.] Rule 7: Reservoir Pressure Monitoring a. [Prior to regular production or injection, an initial pressure survey must be taken in each well. b. A minimum of one pressure survey will be taken annually in each of the ROP reservoir compartments where production wells exist. C. The reservoir pressure datum will be 9,850' feet true vertical depth subsea. d. Pressure surveys may consist of stabilized static pressure measurements (bottom - hole or extrapolated from surface), pressure fall-off tests, pressure build-up tests, multirate tests, drill stem tests, and open -hole formation tests. e. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the AOGCC upon request. f. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule.] 11 a.An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Raven Oil Pool Reservoir Surveillance Report by June 15th of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b.Data from the surveys required in (a) of this rule shall be submitted with the Annual Raven Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10-412. Data submitted shall include rate pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 9,850' true vertical feet subsea. Transient ressure surveys obtained by a shut- in buildup test an injection well pressure fall-off test a multirate test or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water iniection wells Other quantitative methods may be administratively approved by the AOGCC. c.Results and data from M special reservoir pressure monitoringtechniques, chniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. If you have any questions regarding this request, please contact Bill Bredar at 564-5348 or through email at William.bredar@bp.com. Sincerely, q� Katrina Garner PBU Area Manager Cc: J. Schultz, CPAI J. Farr, ExxonMobil Alaska, Production Inc. D. White, Chevron USA D. Sturgis, ExxonMobil Alaska, Production Inc. E. Reinhold, CPAI D. Roby, AOGCC 12 r 8 I ' - 411 ,;(5-Mier- COMM COMM .� RES ENG rr SR ENG 4 SR ENG ENG ASST 1 ENG ASST SR GEOd GEOL A GEOL ASS Ir STAT TECH 1 ' STAT TE FILE 1 PRUDHOE BAY UNIT APPLICATION FOR THE FORMATION OF THE NORTH PRUDHOE BAY PARTICIPATING AREA RECEIVED JAN 1 0 1995 DECISION AND FINDINGS OF THE COMMISSIONER Alaska Oil & Gas Cons. Commission ALASKA DEPARTMENT OF NATURAL RESOURCES Anchorao Romo 0.G. SIEKKINEN TRQ Shrell JAN 4 1995 Doer DECEMBER 30, 1994 Candor © Greater PG Maw la v ao dP liP PRUDHOE BAY UNIT RECEIVED FORMATION OF THE NORTH JAN 1 0 1995 PRUDHOE BAY PARTICIPATING AREA Alaska Oil & Gas Cons. Commission Anchor • I. INTRODUCTION AND BACKGROUND This matter concerns the formation of the North Prudhoe Bay Participating Area (NPBPA) to be located within the current boundary of the Prudhoe Bay Unit (PBU) and what lands should be included in the proposed NPBPA. Pursuant to Paragraph (d) of the Amended Application for the Proposed Pt. McIntyre Participating Area Prudhoe Bay Unit Expansion (Amended Application), dated October 13, 1993, the North Prudhoe Bay State (NPBS) Acreage (Attachment 1) was granted a deferral of contraction from the PBU. ARCO Alaska, Inc (ARCO) and the Exxon Corporation (Exxon) were required by the terms of the Amended Application to submit an application to form a NPBS Acreage Participating Area by September 30, 1994. If the application was not filed by September 30, 1994, the NPBS Acreage would automatically contract out of the PBU as of that date. ARCO, on behalf of itself and Exxon, applied to form the NPBPA within a portion of the NPBS Acreage on August 18, 1994. The acreage proposed for inclusion in the NPBPA overlies an oil reservoir known as the "North Prudhoe Bay Reservoir ". An oil and gas "unit" is comprised of a group of leases which cover all or part of one or more potential or known reservoirs and which are subject to a "unit agreement." The "unit agreement" is the instrument which is typically executed by those with an interest in the leases, including the royalty owner, and which specifies how unit operations will be conducted, and how costs and benefits will be allocated among the various leases. A second agreement called a "unit operating agreement" controls the relationship between parties which share the costs of unit development. Unitization generally allows a potential or known reservoir to be more efficiently explored, developed, or produced than on a lease by lease basis. A "participating area" (PA) is usually limited to that part of the unit area which has been shown to be productive of oil or gas in "paying quantities" from a given reservoir. A PA may consist of less, but not more, area than the unit area. If the unit area encompasses more than one reservoir, a separate PA must generally be established for each delineated reservoir. Additionally, if the same reservoir contains both oil and gas, separate PAs may be established to distinguish between the oil rim and the gas cap. For example, the PBU currently consists of six PAs overlying several reservoirs all located within the PBU area: the oil rim and gas gap PAs (collectively the initial participating areas or IPAs) for the Prudhoe Bay or Permo- Triassic Reservoir; the Lisburne PA for the Lisburne Reservoir; the West Beach PA for the West Beach Reservoir; the Pt. McIntyre PA for the Pt. McIntyre and Stump Island Reservoirs; and the Niakuk PA for the Niakuk Reservoir. The boundaries of PAs can be revised as more wells are drilled and more data are obtained. The regulations governing unitization expressly provide for the expansion and contraction of a PA. Only those parties who own interests within the designated PA will share in the costs of production and revenues from the sale of the oil or gas from the PA. 1 p t dP The Division concludes that ARCO's application to form the NPBPA (as amended on October 14, 1994) should be granted. It further concludes that the NPBPA should be limited to the area proposed by ARCO (October 14, 1994 letter) because only that area has been shown to be "reasonably known to be underlain by hydrocarbons and known or reasonably estimated...to be capable of producing or contributing to production of hydrocarbons in paying quantities." 11 AAC 83.351(a) (emphasis added). If additional data are obtained or submitted in the future which confirm that revision of the PA area is appropriate, the boundaries of the NPBPA may be revised. II. APPLICATION FOR THE FORMATION OF THE NORTH PRUDHOE BAY PARTICIPATING AREA ARCO's NPBPA application was submitted pursuant to 11 AAC 83.351 and Section 5.3 of the PBU Agreement. The application included: a proposed plan of development and operations; a tract participation schedule for the leases in the proposed PA; geological and geophysical data supporting the proposed PA; a proposed methodology for allocating production from all the producing reservoirs that will share the Lisburne Production Center (LPC); and a copy of the NPB Special Provisions to the PBU Operating Agreement that was submitted on December 6, 1994. Additional geological and geophysical information was submitted on September 15 and September 19, 1994. ARCO requested that the Division approve the NPBPA effective September 30, 1994. The acreage proposed for the NPBPA encompasses the NPB Reservoir which includes the Ivishak Formation, the Shublik Formation, and Sag River Sandstone. The NPB Reservoir contains hydrocarbons and is purported to be capable of producing hydrocarbons in paying quantities. The NPB Reservoir is referenced on Attachment 4 of the NPBPA application. In the August 18, 1994 application, portions of two leases were originally proposed for inclusion in the NPBPA (ADLs 28297 and 34624). At the request of the Division of Oil and Gas and with the concurrence of both ARCO and Exxon, the application was modified on October 14, 1994 to delete ADL 34624 from the proposed NPBPA. A map of the NPBPA and the tract participation schedule for the NPBPA are listed as Attachment 2 and Attachment 3, respectively. ADL 28297 reserves a 12.5% royalty share to the state. A reduction of the royalty rate from 12.5% to a discovery royalty rate of 5 percent for all production from the lease was granted on March 6, 1991. The royalty reduction was granted for ADL 28297 because the Pt. McIntyre accumulation was discovered by the drilling of the Pt. McIntyre No. 3 well on that lease. The discovery royalty rate is effective for the period April 1, 1988 through March 31, 1998. III. GEOLOGICAL AND ENGINEERING CHARACTERISTICS DATA IN SUPPORT OF THE APPLICATION The proposed NPBPA lies entirely within the boundaries of the PBU. The NPBPA Reservoir encompasses the Ivishak Formation, the Shublik, and the Sag River Sandstone which are the same stratigraphic intervals as the major productive intervals in the Prudhoe Bay Reservoir. ARCO estimates that the reservoir contains between 1.8 and 2.4 million barrels of recoverable reserves. 2 • • ARCO provided geological, petrophysical and well information to support its proposed NPBPA. These data include geologic logs of the North Prudhoe Bay State No. 1 and No. 3 wells, and structure and gross hydrocarbon isochore maps of the Ivishak Formation. Only two wells have penetrated the NPB Reservoir within the proposed NPBPA boundary. ARCO and the Division staff discussed additional, significant data, and structural interpretations of the Reservoir. These discussions reviewed pertinent confidential information including proprietary ARCO 3 -D seismic data, well logs from the two wells, core and core descriptions from the North Prudhoe Bay State No. 1 Well, interpreted structure maps, isochore maps, geological cross - sections of the NPB Reservoir, and volumetric calculations of the hydrocarbons in -place within the proposed NPBPA. The data and interpretations are discussed later in this Decision and Findings. IV. DISCUSSION OF THE PARTICIPATING AREA DECISION CRITERIA 11 AAC 83.351(a) provides that a PA may include `only land reasonably known to be underlain by hydrocarbons and known or reasonably estimated, through use of geological, geophysical, or engineering data to be capable of producing or contributing to the production of hydrocarbons in paying quantities." "Paying quantities" means: quantities sufficient to yield a return in excess of operating costs, even if drilling and equipment costs may never be repaid and the undertaking as a whole may ultimately result in a loss; quantities are insufficient to yield a return in excess of operating costs unless those quantities, not considering the costs of transportation and marketing, will produce sufficient revenue to induce a prudent operator to produce those quantities. 11 AAC 83.395(4). A PA application must be evaluated under these standards, as well as those of 11 AAC 83.303. Under 11 AAC 83.303, a proposed PA will be approved if the commissioner finds that the PA is necessary or advisable to protect the public interest. To make such a finding, the commissioner must determine that the proposed PA will: (1) conserve natural resources; (2) prevent economic and physical waste; and (3) protect all parties of interest, including the state. In evaluating the above criteria, the commissioner will consider: (1) the environmental costs and benefits; (2) the geological and engineering characteristics of the potential hydrocarbon accumulation or reservoir proposed for inclusion in the PA; (3) prior exploration activities in the proposed PA; (4) the applicant's plans for exploration or development of the proposed PA; (5) the economic costs and benefits to the state; and (6) any other relevant factors (including mitigation measures) the commissioner determines necessary or advisable to protect the public interest. The following evaluates the NPBPA under these criteria and considerations. (A) Conservation of Natural Resources The formation of oil and gas units and PAs within unit areas to develop hydrocarbon - bearing reservoirs generally conserves hydrocarbons. A single PA will provide for more efficient, integrated development of the NPB Reservoir. A comprehensive operating agreement and plan of development governing that production will help avoid duplicative development efforts. 3 1 f As mentioned in section III. of this Decision and Findings, the NPB Reservoir and the proposed NPBPA lie entirely within the boundaries of the PBU. The production of the hydrocarbon liquids from the NPBPA through existing production and processing facilities, specifically the Lisburne Production Center (LPC), generally reduces the incremental environmental impact of the additional production. Using the existing facilities, gravel pads, and infrastructure eliminates the need for new stand -alone facilities for the new PA. Small hydrocarbon accumulations, like the NPB Reservoir which is estimated at this time to contain only 12 million barrels of oil -in- place, would likely be non - developable without the lower cost structure resulting from a more complete utilization of existing facilities. Forming the NPBPA will maximize oil and gas recovery, while minimizing negative impacts on other resources within the area. (B) Prevention of Economic and Physical Waste Generally, forming a PA facilitates the equitable division of costs and allocation of hydrocarbon shares, and provides for a diligent development plan which maximizes physical and economic benefit from a reservoir. Further, the formation of the PA and facility sharing opportunities may allow economically marginal hydrocarbon accumulations to be developed. The LPC owners have negotiated agreements among themselves to share the existing production capacity of the Lisburne facilities and the PBU infrastructure. Using these facilities and the infrastructure eliminates the need to construct stand -alone facilities to process the relatively small volume of recoverable hydrocarbons in the NPBPA. The state has participated in attempts to reduce the need for additional major processing facilities and thus to minimize any additional surface impacts and costs. The state has agreed to allow commingled production through the existing LPC and has worked to provide for a well test -based production allocation methodology for current and future reservoirs sharing the LPC. The adoption of that methodology is subject to periodic review and reconsideration to assure that the state's royalty and tax interests are protected. Further, facility consolidation will save capital and promote better reservoir management through future pressure maintenance and enhanced recovery procedures. A long term development plan for the reservoir has not been approved to date. In combination, these factors in the short term allow the NPB Reservoir to be developed and produced in the best interest of all parties. (C) Protection of All Parties Forming separate PAs seeks to protect the economic interests of all working interest owners of the reservoirs in the PAs, as well as the royalty owner. By combining interests and operating under the terms of a unit agreement and unit operating agreement, such as the PBU Agreement and PBU Operating Agreement, as amended to account for any special PA provisions, the owners may be assured that costs and revenues will be fairly allocated based on specific ownership interests. Because hydrocarbon recovery will be maximized and additional production -based revenue will be derived from NPBPA production, the state's economic interest is furthered. Additional recovery of hydrocarbons, however, in and of itself may not always be determinative of the state's best interest. Production must occur under suitable terms and conditions to assure that 4 the economic interests of both the working interest owners and the state, as the royalty owner, are protected. It has been the state's consistent policy of opening the renegotiation of some specific terms of the original lease contracts at the time of unitization decisions. Although not required here, amendments to an existing unit agreement or oil and gas lease may be necessary to protect the state's interest. In particular, amendments may be necessary where an application seeks to include leases which are not already within unit boundaries or leases, which contain different terms and conditions, or which through their commitment to an existing unit agreement, by virtue of the terms of that agreement, its operating agreement or applicable settlement agreements, would prejudice the state's economic interests. The proposed production allocation methodology further protects the interest of all parties by allocating production between the reservoirs that produce through the LPC. This methodology intends to accurately and fairly allocate production. It may be revised if it does not meet those goals. Also, within the PBU, gas from one PA may be reinjected or stored in another PA. A gas disposition/reserves volume accounting procedure accounts for and tracks gas that is either produced, used, sold, reinjected or stored. In reviewing the above criteria, the following factors were considered: (1) The Environmental Costs and Benefits As discussed in section IV.A., the sharing of some of the existing facilities eliminates duplication and reduces the surface area altered by development. The development of the NPB Reservoir will not significantly alter the existing gravel pads, roads or surface facilities. Further, no significant additional impacts to nearshore habitat or biological resources are anticipated because the additional NPBPA production will share the existing PBU facilities. (2) The Geological and Engineering Characteristics of the Reservoir and Previous Exploration and Development Activities of the Proposed Participating Area There are two major faults in the North Prudhoe Bay area, the Prudhoe Bay Fault and the Pt. McIntyre Fault. Both are east/west trending, down -to- the -north normal faults with approximately 1000 feet of throw at the Ivishak level. The area between these two major faults is the location of the NPB accumulation. Oil and gas in the NPB area was first encountered by the NPB State #1 Well in 1970. The well encountered hydrocarbons in the Sag River and Ivishak Formations. A drill stem test of the Sag River Formation recovered 3.6 MM SCFD of gas and 132 STBD of condensate, while a drill step test of the Ivishak Formation recovered oil at a rate of 2727 STBD. Although the tested intervals in the NPBS #1 well are the same intervals that contain the a majority of the reserves in the Prudhoe Bay Field, the proposed NPB Reservoir is a separate accumulation based on its higher oil gravity, 35 API vs. 28 API, and an oil/water contact at -9289 feet SS, approximately 300 feet deeper than the oil/water contact in the Prudhoe Bay Field. Following the acquisition of 3 -D seismic data in 1990, the NPB State #3 Well was drilled from the West Beach Drill Site in 1993. That well encountered hydrocarbons in the Sag River, Shublik, and Ivishak Formations and has produced over 850,000 STB of oil from the Ivishak 5 Formation as a Tract Operation in the PBU since October 14, 1994. While the NPBS #3 Well has been certified as capable of production in paying quantities by the ADNR and continues to produce from the Ivishak Formation, the NPBS #1 Well has been plugged and abandoned. (3) The Applicant's Plan for Exploration or Development of the Participating Area For the NPB Reservoir, primary recovery with aquifer support is expected to yield 15 -20 percent of the original oil in place. ARCO states that further development plans for the NPB Reservoir are uncertain at this time. Immediate plans are to continue producing the NPBS #3 Well and the Reservoir through the permanent production line from the West Beach Drill Site to the LPC. All produced NPB Reservoir gas will be injected into the Lisburne reservoir since no gas injection facilities are available at the West Beach Drill Site. Given the current level of uncertainty regarding reservoir size and performance (amount of aquifer support), fluid handling capacity limitations at the LPC, and economic conditions, the initially proposed plan of development is consistent with prudent reservoir management practices. However, the Division is concerned that only one well, NPBS #3, may be inadequate to recover oil from the entire area proposed for the NPBPA. The initial plan is adequate for the next year while reservoir performance data is gathered and evaluated. As a condition of approval of the Plan of Development for the NPBPA, the Division will require ARCO, as NPBPA Operator, to address enhanced recovery possibilities and the desirability of drilling additional wells in the PA in future plans of development (POD). Specifically, in the POD for 1996, ARCO should address the issue of whether or not additional wells are justified in the PA, and how ARCO expects to maintain and enhance the physical recovery from the NPBPA. (4) The Economic Costs and Benefits to the State As discussed in Article IV (C) above, increased production and revenues, in and of themselves and without consideration of other relevant factors, may not always be in the state's best interest. Here, however, the gain in economic benefits outweighs any perceived costs to the state. Economic benefits accrue to the state because approval of the NPBPA promotes the ultimate physical recovery of hydrocarbons from the NPB Reservoir and the PBU. Any administrative burdens associated with the new PA are far outweighed by the value of additional royalty and tax benefits derived from the NPBPA production. See section V. below for a further discussion of relevant economic costs and benefits factors. (5) Any other relevant factors (including mitigation measures) the commissioner determines necessary or advisable to protect the public interest The factors are discussed in Article V below. V. OTHER ISSUES PERTINENT TO THE NPB PARTICIPATING AREA APPLICATION In a letter dated January 13, 1993 to ARCO, the division noted a number of concerns related to the application to form the West Beach Participating Area (WBPA) within the PBU. Some of 6 the issues addressed in that letter are pertinent to this application to form the NPBPA. The attached letters (Attachment 5) dated January 13, 1993 and March 1, 1993 set forth the issues and the agreements between the parties in the WBPA regarding the royalty issues. These same agreements between the parties regarding the WBPA shall apply to the NPBPA. The Division incorporates the following from Section V. of the Decision and Findings of the Commissioner, Alaska Department of Natural Resources 'regarding the Application for the Formation of the WBPA, dated April 2, 1993, into this Decision and Findings regarding the formation of the NPBPA. A meeting was held between ARCO and division staff on February 23, 1993 to discuss the concerns raised in the January 13, 1993 letter. Prior to the February 23, 1993 meeting, ARCO submitted a written response, dated January 25, 1993, to the state's concerns with the West Beach Participating Area application. In addition, ARCO submitted another letter, dated March 1, 1993, regarding ARCO and Exxon's understanding of the outcome of each of these issues as a result of the February 23rd meeting. Except for use of ARCO's and Exxon's initially proposed gas disposition and reserve debit report, Item 3 of the March 1, 1993 letter, the division agrees with ARCO's and Exxon's understanding of the outcome of the West Beach Participating Area issues as expressed in ARCO's March 1, 1993 letter. Regarding the gas disposition and gas reserves debit report, the modified report included as Attachment 2 is acceptable to the division for gas volume accounting purposes. A copy of the Match 1, 1993 letter is appended to this Decision and Finding as Attachment 3. The referenced Attachment 2 and Attachment 3 of the WBPA Decision and Findings will be Attachment 4 and 5 to this NPBPA Decision and Findings. Finally, per the Amended Application, any of the NPBS Acreage that is not included within a participating area by December 31, 1994, automatically contracts out of the PBU on that date. If additional data supportive of a request for expansion are obtained in the future, ARCO and Exxon may apply to expand the NPBPA to include such acreage. VI. FINDINGS AND DECISION Considering the facts discussed in this document and the administrative record, I hereby make findings and impose conditions as follows: 1. The proposed PA, the NPBPA, meets the requirements of 11 AAC 83.303. 2. The available geological, and engineering data submitted demonstrate that the proposed participating area acreage is known to be underlain by hydrocarbons and known or reasonably estimated to be capable of production or contributing to production in sufficient quantities to justify the formation of the NPBPA within the PBU. 7 3. The geological and engineering data supporting the PA justify the inclusion of the proposed tract within the NPBPA at this time. The entire PA is wholly contained within the boundaries of the current PBU. Under the terms of the applicable regulations governing formation and operation of oil and gas units (11 AAC 83.301 - 11 AAC 83.395) and the terms and conditions under which these lands were leased from the state, the following lands are to be included in the NPBPA: • T.12.N., R.14.E., U.M., Sec. 22 (ADL 28297 (Tract 8)). 4. Pursuant to Paragraph (d) of the Amended Application for the Proposed Pt. McIntyre Participating Area Prudhoe Bay Unit Expansion, dated October 13, 1993, North Prudhoe Bay State Acreage not included within the NPBPA automatically contract out of the PBU. The following NPBS Acreage contracts out of the PBU as of December 31, 1994: T.12.N., R.14.E., U.M., Sec. 23: S /2, S /2NE /4, and SE /4NW /4 (ADL 34624 (Tract 7)). Within forty -five (45) days of the date of this Decision and Findings, ARCO shall submit to the Division updated Exhibits A and B to the PBU Agreement reflecting the revised PBU Area. 5. The PBU Agreement and the Alaska statutes and regulations governing oil and gas units provide for further expansions of a PA in the future as warranted by additional information and findings. Therefore, the public interest and the correlative rights of all parties, including the state, are protected. 6. Formation of the PA equitably divides costs and allocates produced hydrocarbons, and sets forth an initial development plan designed to maximize physical and economic recovery from the NPB Reservoir within the approved PA. 7. The production of NPBPA hydrocarbon liquids through the existing production and processing facilities within the PBU reduces the environmental impact of the additional production. Utilization of existing facilities will avoid unnecessary duplication of development efforts on and beneath the surface. 8. As of this time, the proposed well test allocation methodology is acceptable for royalty allocation purposes and for allocating the commingled gas and hydrocarbon liquids production among the NPBPA, the West Beach Participating Area, the Niakuk Participating Area, the Pt. McIntyre Participating Area and the Lisburne PA as those streams are processed through the LPC. The LPC Operator, ARCO, shall provide the Division with the monthly production allocation reports and well test data for the wells producing through the LPC by the 20th of the following month. The Division reserves the right to request any information it deems pertinent to the review of those reports. 8 • f The monthly allocation report shall include a monthly oil, gas, and water allocation factor to be applied uniformly to the respective commingled production streams, a summary of monthly allocation by well, a summary of the allocated volumes of oil, hydrocarbon liquids, gas and water by participating area, oil gravity of the combined stream, and specific well test data for all tests which have been conducted. 9. The Division reserves the right to review the well test allocations to insure compliance with the methodology prescribed in this decision. Such review may include, but is not limited to, inspection of facilities, equipment, well test data, and separator back - pressure adjustments. 10. During the first year in which commingled production from the NPBPA is allocated, reviews of the allocation methodology will be scheduled with the Division. Following its review, the Division, in its sole discretion, may require revision of the allocation procedure. Subsequent reviews may be requested by either the Division or the operator. Following any subsequent review, the allocation procedure may be revised with the written consent of, or upon the written direction of, the Division in its sole discretion. 11. To account for the gas produced from each participating area, the gas volume disposition and gas reserves debited from or credited to each PA using the shared LPC, the NPBPA operator shall submit a monthly gas disposition and reserves debit report using the form indicated in Attachment 4. The gas disposition report shall be submitted with the monthly production allocation reports. As with the other PAs sharing the LPC, the Division approves a fuel gas allocation methodology which allocates flare and fuel gas in proportion to the NPBPA's share of total produced gas through the LPC. 12. The field cost allowance for the state's royalty share of oil produced from the approved NPBPA shall be governed by the 1980 Prudhoe Bay Settlement Agreement. Whether the state bears any deductions of any kind whatsoever (whether called allowances, deductions or fees) for the state's royalty share of "NGLs" and dry gas, and if so, the amount of those deductions, shall be subject to the final resolution of the ANS Royalty Litigation. 13. Regarding the production allocated from the NPBPA and the state's taking of any royalty oil in -kind from the NPBPA, it continues to be the state's position that it has only nominated the taking of royalty oil in kind and has never nominated gas for in -kind taking. 14. Diligent exploration and delineation of the NPB Reservoir underlying the approved participating area is to be conducted by ARCO and Exxon under the PBU plans of development and operation approved by the state. 9 . _ • III 15. The initial plan of development for the NPBPA meets the requirements of 11 AAC 83.303 and 11 AAC 83.343 while reservoir performance data are gathered and evaluated from the NPBS #3 Well. The plan is approved for a period of one year from the effective date of this Decision and Finding subject to the terms and conditions of section IV.(3). Future plans must be submitted in accordance with 11 AAC 83.343 and are also subject to the terms and conditions of section IV.(3) of this Decision and Findings. . 16. The State and the Applicants have agreed to change the requested effective date of the NPBPA. Approval of the NPBPA within the PBU is effective January 1, 1995. For these reasons and subject to the conditions and limitations noted, I hereby approve the North Prudhoe Bay Participating Area within the Prudhoe Bay Unit. i I J s E. Eason, Director Date Division of Oil and Gas For: Marty Rutherford, Acting Commissioner Alaska Department of Natural Resources Attachments: Delegation of Authority Attachment 1: NPBS Acreage Map Attachment 2: NPBPA Tracts Attachment 3: Tract Allocation Schedule Attachment 4: Example Gas Disposition and Reserve Debit Report Attachment 5: Correspondence dated January 13, 1993 and March 1, 1993 PBU.NPBPA.Appv.txt 10 DELEGATION OF AUTHORITY With respect to the Application to Form the North Prudhoe Bay Participating Area within the Prudhoe Bay Unit, I hereby delegate to the Director of the Division of Oil and Gas my authority under 11 AAC 83.343 to Approve/Deny Plans of Development, my authority under 11 AAC 83.351 to Approve/Deny Participating Areas, and my authority under 11 AAC 83.371 to Approve/Deny Allocation of Cost and Production Formulas. Dated: I 2. `k`1- Anchorage, Alaska Marty Rutherford, Acting Co'q ssioner Alaska Department of Natural Resources N N Expansion Acreage and Slivers _ 0 Excluded Acreage ® Contracted Acreage ® Expansion Acreage EXX 34822 8PX 365548 WBPA A/E 34623 Tract 116 Tract 117 Slivers ri NPBS Acreage Expansion Area + Slivers = PMPA Slivers are only part of the Expansion Acreage Contracted Acreage f i , ..,__,.................1..„...„.._.... .... .... . ,•••••••••••••• ••••••••••••••4 ►••••••*••• ■ t►•••1'•••••••••••••• ■-�-- w • : PBS f3., oA li OV :• : •. : •_ �•.•�•.S.: +. : �i�: �i1 4:1 :• :••••••• :••• :••• :•• :•• :• � �Ii. �/ ••••••••••••••• • ••••••••••••• ♦• Lease Lines ---�► 7 �!'r , .,� 5 ' • • • • • • • • • • • • • • • • • • • • • • • • • • • •1 Tract 115 �tt a � 1 1 0 e •� ,f Tract 8 �� Tract 1111111 tact 8 I �• C ♦ • • • • • • • • • • • • • • • •� . A/E 28298. A/E 28297 A.V. `. 3'�i'e�'�' 6a. A �y • • • • • • • •1 A / E 34624 NE 34 1 �i�`►�' •i i i a i a a ..1 ' '1" 1 111111111111111111111111111111111111111111 • Tract 27 Tract 28 Tract 29 Tract 30 NE 28300 NE 28301 ` j NE 34628 A/E 34629 - _ A- X-4------ ■ ..J Tract 8ARCO - Exxon Tract 7ARCO - Exxon • ■ 28297 34624 ■ Proposed North Prudhoe BayParticipating Area Boun Lou, N IMINNMENNIMEMMINNI ■ ■I PBU Boundry mir.mt Ns • • ■ NPB 3 • NPB 1 Se1on 2 Section 23 ■NPB2 • Abel St #1 )\ ��, Tract 27ARCO - Tract 28ARCO - Exxon 28300 Exxon 28301 North Prudhoe Bay Proposed Participating Area � r •ATTACFiriENT 2 Tracts Within the North Prudhoe Bay Participating Area and North Prudhoe Bay Tract Participation Tract No. of ADL ADL Basic Lessee of Interest OIP Tract No. Description Acres No. Royalty Record Ownership MMSTB Participation To 8 T12N -R14E, Sec 22 I 640 I 28297 1/8* _ ARCO & I Exxon - 50% 12.1 I 100% * This lease is currently subject to the reduced Discovery Royalty rate. ATTACHMENT 3 .1AR 15 'O3 09 z4AM ARCO AK (L.SBURNE) P.2/3 • 111 11. SAMPLE AREA GAS DISPOSmON AND RESERVE DEBIT REPORT ARCO ALASKA, INC. VOLUMES ARE IN MCF AT 14.65 PSIA PRODUCTION MONTH uSBURNEPRODUCT= CENTER A Ai EFIX SOOT TOTAL OW P PERCENTAGES Lisburne • West Seam TOTAL HYDROCARBON LIQUIDS PRODUCED (SIB) Lisburne West Seam LPC SYSTEM SU MmARY TOTALS TOTAL SOG GAS PRODUCED LESS TOTAL FUEL GAS USED Pow generation fuel Lease suet LPC fuel Total LEES POWER GENERATION SALES LESS FLARE GAS Rare within AOGCC Allowable Excess Flan Subject to Tax Olga Flare Subj. to Tax/Pntty Total LESS NGLS (MCF equivalent) TOTALSOG RESERVE GAS DEBITS GAS PU TED PARDCIPATINGAREA SHAREBREAKOUTS TOTALSOG GAS PRODUCED Lisburne West Beach LESSTOTAL FUEL GAS USED Lisburne Power generation fuel Lease fuel LPC fuel LPA Total West Beach Power generation fuel Lean fuel LPC rum WBPA Total LESS PCAVERG NEPAT1ON SAL S U bum. West Beach PAGE 1 ATTACHMENT 4 nAR 15 '93 O9 :25AM ARCO AK (LISBURNE) P. S SAMPLE AREA GAS DISPOSRION AND RESERVE DEBIT REPORT ARCO ALAslA . INC. VOLUMES ARE IN MCF AT 14.65 PSIA PRODUCTION MONTH LISBUPNE PRODUCTION MITER AM EPX DOCCN TOTAL LESS RLAREGAS Lisburne Flare within AOGCC Allowable Excess Flare Subject to Tax Excess Flare Subj. to Tax/Pnity LPA Total West Beach Flan within AOGCC Allowabte Excess Rare Subject to Tax Emus Ran Subj. to TaxlPnity WBPA Total LESS NOLS (MCP equivalent) Lisburne Waal Beach TOTAL SOG RESERVEGAS DEBITS Lisburne Current month YTD IfO Waal Beach Current month YTD RD GAS AVALASLE FOR INJECTION Lisburn) Current month YTD ITD Weal Beach Current month YID TTD TOTAL ECG RESERVES *LRCM HID LPA RESERWIR From Lisburne Current month YTp From Waal Bench RECEIVED Current month I TD JAN 1 0 1995 ffD TOTAL SOGRESERV ES NUECTEDINTOWBPARESERVGIR F S ail Gas Cons. Commission From Llrburne Anchori Curran month YID RD From Well Beads Current month YTD ITO NOTE: Each participating area's apportioned share of fuel gat utilized in the LPC and nate gas in any month is based on Its apportioned share art total produced gas. PAGE 2 • WALTER J. HICKEL, GOVERNOR DEPT. OF NATURAL RESOURCES ANCHORAGE. LASKA 99510.7034 PHONE: (907) 762.2553 DIVISION OF OIL AND GAS (907) 762-2547 January 13, 1993 • ARCO Alaska, Inc. P.O.Box 100360 Anchorage, Alaska 99510 -0360 Attn: Keith Weiser Lisburne/Pt. McIntyre Subject: West Beach Participating Area Application Dear Mr. Weiser: A number of issues have been raised in the Division of Oil and Gas' review of the application for the formation of the West Beach Participating Area within the Prudhoe Bay Unit. The issues are attached to this letter. I suggest the State and ARCO meet to discuss these issues. Please call Bill Van Dyke or Mike Kotowski at your earliest convenience to arrange the meeting. If you have any questions on any of the items, please contact them at 762 -2547. Sincerely, • iir 07/01 es E. Eason ector Attachments cc: Gary E. Baker - Exxon Patrick Coughlin - ADOL Deborah Williams - Condon, Partnow & Sharrock PBU.WBRESP.Txt At tachment 5 • i Application for Formation of West Beach Participating Area Within the Prudhoe Bay Unit An initial review of the Application has raised the following concerns; the State and ARCO should meet to discuss them: 1. Generally, a participating area (PA) may include only land reasonably known to be underlain with hydrocarbons and reasonably estimated to be capable of contributing to production. 11 AAC 83.351(a) provides in pertinent part: The participating area may include only the land reasonably known to be underlain by hydrocarbons and known or reasonably estimated through the use of geological, geophysical, or engineering data to be capable of producing or contributing to production of hydrocarbons in paying quantities. Such a showing is usually established by a certification, in accordance with 11 AAC 83.361, that at least one well in the proposed participating area is capable of producing hydrocarbons in paying quantities. Yet, ARCO has not requested a paying quantities determination for any well within the proposed participating area. Until a paying quantities determination is made, the division lacks a reasonable basis for establishing a properly configured participating area for the West Beach Reservoir. ARCO has submitted the West Beach 4 type log, a top structure map of the Kuparuk Formation over the proposed West Beach Participating Area, a gross isopach map of the Kuparuk Formation over the proposed area, and a hydrocarbon pore -foot map of the Kuparuk Formation. The additional information necessary to make the paying quantities determination are: (a) Well test summaries and chronologies from the West Beach 4 Well and /or the West Beach 3B Well. The data should include test separator meter readings and tank straps during each flow period, surface well pressures, and any static and /or transient reservoir pressure data; (b) Cost data to show that the well test data indicate production volumes sufficient to yield a return in excess of operating costs. The cash flow analysis should include operating costs and processing costs per barrel of oil and the expected wellhead price. The calculations should represent a one year time period. 2. Based on the geological information contained in Attachments 6 410 (and 7 of Lhe participating area application, the division is concerned that portions of the proposed area do not meet the criteria set forth in 11 AAC 83.351(a). Of particular concern to us are Tract 5, Tract 7, and the SE /4 and NW /4 of Sec. 25 of Tract 28. Further, we are concerned with the proposal to include within the proposed participating area "any other producing reservoir from the surface to the base of the Kuparuk Formation which may be discovered within the boundaries of the West Beach Participating Area." ARCO needs to explain how the inclusion of these yet to be discovered or delineated lands meets the criteria of 11 AAC 83.351, 11 AAC 83.361, and 11 AAC 83.303. 3. The division will require accounting procedures to properly allocate Lisburne, Pt. McIntyre, and West Beach produced gas, gas used for fuel, flare, gas reinjected into the Lisburne gas cap or another participating area gas cap, and translucent liquid hydrocarbons (otherwise referred to as NGLs). The ARCO has proposed (1) an area gas disposition and reserves debit report for the three participating areas, and (2) a fuel gas utilization allocation based upon each PA's proportionate share of produced formation gas. In order to be consistent on this issue with what we approved in the Duck Island Unit for the Endicott and Sag Delta North Participating Areas, the division will require the following for the royalty free fuel and flare gas used for the benefit of each respective participating area in the operation of the Lisburne Production Center (LPC) or other participating area operations: The use of royalty free gas for the LPC operations (fuel and flare) must be apportioned among the three participating areas using the common production facilities. The basis for apportioning the fuel gas used in development and production operations during a month shall be each participating area's fraction of the total hydrocarbon liquids produced through the LPC that month. The basis for apportioning the flare gas in any month shall be each participating area's fraction of the total produced gas determined from well tests that month. The Alaska Oil and Gas Conservation Commission has authorized (or will authorize) the flare of a specific amount of gas for safety flare purposes. Any excess flare gas above the authorized amount is subject to a royalty payment. To properly account for the various monthly dispositions among any participating area using the shared Lisburne facilities, the division will require the attached gas disposition and reserves debit report. 2 r • 410 • 4. The division is concerned with the proposed production allocation methodology among Lisburne, Pt. McIntyre and West Beach. Currently, we do not have a problem with ARCO's proposed methodology because it's based on a minimum of two individual well tests during the month and is similar to what currently is approved for the Milne Point and Duck Island Units. However, at issue may be the appropriate allocation factor for the one production well West Beach Participating Area, and how we handle the so- called "wedge" effect. As long as there is only one producing well in the proposed West Beach Participating Area, a meter allocation factor different from one (1.0) appears inappropriate. With the one well producing well in the West Beach, the West Beach production volume should be determined using the well test data, and not subsequently adjusted using a meter allocation factor. Regarding the so- called "wedge" effect, a later well test reporting date and the use cf a well test obtained early in the next month may resolve this issue. This would permit the use of four well tests to allocate production for any given month. 5. We note the following with regard to the attachments /exhibits included with the application: - The Niakuk should be replaced with the West Beach in Exhibit 5. It is our understanding that the Niakuk will be produced at a later date. - In the Sample Production Allocation /Offtake Schedule, page 2, it continues to be the State's position that it has only nominated the taking of royalty oil in kind. If anything other than the State's nomination of oil is provided, the State will not pay more than the oil field cost allowance pending resolution of Severed Issues of the ANS Royalty Litigation. 6. The royalty -in -kind language in the Prudhoe Bay Unit Agreement, Article 6.4, is not acceptable for the West Beach and Point McIntyre areas. The division desires the flexibility to be able to nominate RIK oil and gas separately from the West Beach and Point McIntyre areas. At this time, a RIK nomination must be based on total unit oil or gas production - -not participating area by participating area. The division realizes that the ANS Settlements contain amended RIK language, however, we do not believe that the ANS settlement language is the language to apply either. We will propose new language to Article 6.4 at a later date. Furthermore, the division is proposing the attached amended language to Article 7.2 of the Prudhoe Bay Unit Agreement. The amended language addresses usage of royalty free fuel gas for 3 f participating area operations as well as the injection of Unitized Substances from one participating area into another participating area within the Prudhoe Bay Unit Area. 7. Because the leases proposed for inclusion in the West Beach Participating Area are entirely within the current Prudhoe Bay Unit Area, the division acknowledges that, unless amended now or at a later date, the field cost allowance for the State's royalty share of oil produced from the proposed West Beach Participating Area will be governed by the 1980 Royalty Settlement Agreement. However, the field cost allowances for the State's royalty share of "NGLs" and dry gas are part of the Severed Issues in the ANS Royalty Litigation. These field cost allowances are subject to the final resolution of this litigation. Prudhoe.WBPA.Response.Txt I I 4 Lisburne, Pt. McIntyre, and West Beach Gas DisposAion & Reserve Debit Report ADNR Revised Volumes are in MCF at 14.65 PSIA - calculations subjed to revision when finalized Month Year 11/17/92 Page 1 > BPXA EXXON : ':ARCO TOTAL USBURNE OWNERSHIP% 20 40 10.0000. 100.000 PT. MCINTYRE OWNERSHIP 00040,:; WEST BEACH OWNERSHIP x 5 0.0 0 00 50. Ii10000b Total Gas Produced SOG Gas Production LPA SOG Gas Production PMPA SOG Gas Production WBPA Total Hydrocarbon Liquids Produced HCL Production LPA MCI. Production PMPA MCI Production WBPA U, Less Fuel Gas Used /°'� E For Power Generation {�" u.'") cl For of . uses a e m Total Gas Fuel Used _ ._ r"' = ; . . S s Power Generation Sales wino. O � t6 ubject io Royally Payment) -- - -- -. _.. -- --- - -- C . PC Total Fuel Gas Used Q For Power Generation .--n ; For other uses _ __ Total LPCFuei Gas IPA Share of Fuel Gas Used For Power Generation For other uses r Total IPA Fuel Gas ' PMPA Share of Fuel Gas Used For Fower Generation For other uses _ Total PMPA Fuel Gas WBPA Share of Fuel Gas Used For Fower Generation For other uses Total WBPA Fuel Gas ess Flare Gas - -- AOGCC Authorized Flare (20 MC 25.235) Excess Flare Subject to Tax Exoc.ss Flare Subject to Tax and Penalty E xcess Flared in violation of AOGCC regs. Total Flare Gas LPA Share of Flare Gas AOGCC Authorized Flare (20 MC 25.235) Excess Flare Subject to Royalty Excess Flare Subject to Tax and Penalty Excess Flared in violation of AOGCC regs. LPA fail Gas PMPA Share of Flare Gas AOGCC Authorized Flare (20 MC 25.235) Excess Flare Subject to Royalty • Excess Flare Subject to Tax and Penalty Excess Flared in violation of AOGCC regs _ PMPA Total Flare Gas _- _ — __ -- IA/BA Share of Flare Gas AOGCC Authorized Flare (20 MC 25 235) Excess Flare Srbject to Royalty ' Excess Flare Subject to Tax and Penalty ' Excess Flared in violation of AOGCC regs. t aus BPXA EXXON ARCO TOTAL LISBURNE OWNERSHIP% 20.0000 40.0000 40.0000 100.0000 PT. MCINTYREOWNERSHIP<% • WEST REACH OWNERSHIP % 5000011 S0.0000 100.0000 Less NGLs (mot equivalent) LPA NGLs PMPA NGLs - WEIPA NGL's Gas Available for Minor Gas Sales LPA Share PMPA Shan WBPA Share Current Month VU) as of 9/1/92 (gas inj into LPA) ITO as of 9/1192 (gas inj. into IPA) Less Power Generation Sales (Subject to Royalty Payment) LPA Share PMPA Share WBPAShare Current Ai debited from inj into LPA Illince to Injection LPA Net Injection `ITO_ ITO -- - -- -- PMPA Net Injection vTD — — ITD —_ -- WOPA Net Injection V -- -- --- - - -- -- ITD I' 'tat IPA SOU Reserve Gas Debits Month YTD --- - - - - -� ITO I ^'�I P4rPA SOG Reserve Gas Debits Month YID ITp ill WRPA SOG Reserve Gas Debits Month VTD I ralal IPA SOG Reserves Injected into LPA Reservoir Month YID — lTD Total WB S; G Reserves Injected into LPA Reservoir Month V TD -- ITD 1 T rtal WRPA SOG Sold from LPA Reservoir Month YTD ITO rJOTE (I) Each PA's apportioned share of fuel gas utilized for the LPC is based upon its apportioned share of total produced liquid hydrocarbons. (2) Each PA's apportioned share of flare gas in any month is based on its apportioned share of total produced gas AGREEMENT TO AMEND THE PRUDHOE BAY UNIT AGREEMENT The Prudhoe Bay Unit Working interest Owners and the Department of Natural Resources, State of Alaska, hereby agree to amend the Prudhoe Bay Unit Agreement as follows.*: (1) Amend Article 7.2 as follows: Royalty Payments. No royalty, overriding royalty, production or other payments shall be payable on account of Unitized Substances used, unavoidably lost, stored or consumed in Unit Operations, including but not limited to, the injection thereof into any formation underlying the Unit Area, except as specified herein. For the Lisburne Particioatina Area, the Point McIntyre Participating Area, and the West Beach Participatina Area within the Prudhoe Bay Unit, no royalty, overridina royalty, production or other payments shall be _ payable on account of Unitized Substances used, 'unavoidably lost, stored or consumed in Unit Operations to the extent, and only to the extent, that the Unitized Substances are used in the Lisburne, Point McIntyre or West Beach Participatina Areas, respectively. More generally, it has been, and continues to be, the intent of the State of Alaska that this royalty exemption section ( .57.2) does not apply to Unitized Substances that are sold, includina transactions that result in any credits or debits amona the Working Interest Owners. If Unitized Substances from one oarticioatina area (that is, the contributina oarticioatina area) are in - iected into another oarticioatina area (that is, the recipient oarticioatina area), the Unitized Substances first withdrawn from the recipient oarticipatina area shall be considered to be the Unitized Substances from the contributina oarticioatina area until an amount equal to that transferred shall be so Produced. If Unitized Substances produced from a particular participatina area are used or consumed in the operation of any facility the use of which is not exclusively devoted to that Participatina Area's [UNIT] Operations, royalty, overriding royalty, production or other payments shall not be payable on the part of the Unitized Substances produced from that particular oarticioatina area used or consumed in the facility which fairly is apportionable on a use basis to that oarticioatina area's [THOSE UNIT] Operations being served by the facility. Wording to be added to the existing Prudhoe Bay Unit Agreement is underlined; wording to be deleted from the existing Prudhoe Bay Unit Agreement is capitalized and enclosed in brackets. 1 II! 411 This Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original, but all of which shall constitute on and the same instrument. Unit Operator ARCO Alaska Inc. Date: ARCO Alaska, Inc. By: PBUAMEND1.txt • ARCO Alaska. Inc. • Post Office dox .k60 ' ` Anchorage. Alaska 99510 -0360 r Teleohone 907 263 4275 Andrew O. Simon Manager Lisburne /Point McIntyre E1ECEIVED, March 1, 1993 t.;tR 2 1993 DI% OE 01 L as ifaAS Mr. James E. Eason Division of Oil and Gas Alaska Department of Natural Resources C C' / C (� P.O. Box 107034 C 1.� V L �.! Anchorage, Alaska 99510 -7034 JAN 10 1995 RE: West Beach Participating Area Meeting tkias iii .& Gas Cons. Commission Mchora Dear Mr. Eason: Our February 23 meeting to discuss the West Beach Participating Area (WBPA) issues raised by the DNR in its January 14 letter was very useful in allowing both parties to better understand each other's positions. A clear path forward for the approval of the WBPA appears to have been established. ARCO and Exxon's understanding of the outcome of each issue is noted below. 1. The issue of a paying quantities determination for the proposed (WBPA) was resolved. The DNR acknowledged that West Beach #3B, located within the proposed WBPA boundary, was certified as being capable of producing in paying quantities in February, 1977 and that data supplied for WB-4 established additional certification. 2. Concerning the proposed boundary of the WBPA, ARCO and Exxon agreed to present to members of the DNR technical staff geologic and geophysical data in support of Attachments 6 and 7 of the WBPA. This meeting is scheduled for March 1 at the DNR's office. In the WBPA application, ARCO and Exxon proposed to include within the WBPA "any other producing reservoirs from the surface to the base of the Kuparuk Formation which may be discovered within the boundaries of the West Beach Participating Area ". While this proposal was made to facilitate and encourage the development of any minor reservoirs that may be encountered while drilling the Kuparuk, which are by their nature vulnerable to additional costs, the DNR's alternative proposal to consider including any such reservoir in the WBPA at the time they are actually encountered is acceptable to ARCO and Exxon. Therefore the WBPA will be limited to the Kuparuk as referenced on Attachment 4 (type log) of the WBPA Application (attached). ARCO M.sa w�.... s - -► a MORO* a Cu.�sr ATTACHMENT 5 • Mr. James E. Eason • March 1, 1993 Page 2 3. Concerning the gas accounting procedures and fuel gas allocation, all parties agreed to the use of ARCO and Exxon's proposed gas disposition and reserve debit report, as well as a fuel gas allocation methodology which allocates flare and fuel gas in proportion to each participating area's share of total produced gas. 4. With regard to the proposed production allocation methodology, ARCO and Exxon agreed to submit to the DNR a "statement of intent" for the proposed production allocation methodology. Please find attached public testimony given to the State of Alaska Oil and Gas Conservation Commission during the January 13, 1993 Field Rules Hearing which we believe should satisfy this request. The DNR agreed that the "wedge effect" is no longer an issue assuming the operator is allowed to submit the allocated data by the 20th of the following month. 5a. With regard to the reference to Niakuk in Exhibit 5 of Attachment 8 to the WBPA, ARCO and Exxon agreed that in the actual allocation report Niakuk will be replaced by West Beach. 5b,6,7. Each of the remaining issues are tied to the ANS Royalty Litigation. All parties agreed that it is inappropriate to address these issues outside of the context of ANS Royalty Litigation., All parties agreed that the resolution reached in the ANS Royalty Litigation will apply to the WBPA. This letter outlines ARCO and Exxon's understanding of the DNR's position on these issues. If the DNR's position is different than noted above, please let me know as soon as possible so that any outstanding issue can be quickly resolved. Sincerely, A. D. Simon Manager Lisburne /Point McIntyre SMR:ADS:tg Attachments cc: G. Baker Exxon S. M. Bennett BPX W. D. Morgan Exxon J. Reeder BPX . ! • ATTACHMENT 4 :tom ..ovember 24. 1 West Beach Field :est 3each PA Aonli.ca: Type Log ARCO /Exxon West Beach #4 ) __ _, •- • Iso• 300. 2 2000. ' z -.,,, _ / i \+! 1 J • 301 CAP .A C flif1 +- i•� F. ISO. .2 2000.48. o �i['r SO4 GAPI r-- ILO oni1{ 4P0I PU MD NOSS (FT) (FT) 1 .III 1 y ._ � -_..�i tH = -.. .._- I • I I I I I. I 5700 I ��_ 1 j _i 1 -� i ! _ ...._ .._, e ms.._. . ... • . - - -.._ . r - • __ . _; _ -� -- Gamma Ray Shale (HRZ) 1 ' 1 ' ' 1 t -- ' ` II : i 1 ; 14,548' ( -8759' SSA 1 ' 1 1 1 -...._ HI'. I j l 1 I_ {4600 i I 1 1 8600 1 1 I I I I 1- t 1 I 1 I , I 1 I ME I: 1 1 1 ► 1 " " °' I _ 1 I ! I Kuparuk I! i _ f I 1 ,, I jam II I I . ____._-I 4700 I • I - 8900 _ I_ I I 1 j I I ' I � - I 1 1 AU 14766 aaaa06i a _l.._1._ ii ._1 a - aaaacaa 1 1 ' 1 `77-, .__r � I 1 , 14,781' ( -8950' SS) i I , {4601 , ' :mp. f I i 1 I —i 1 I I. ! King ak / 9000.4 =.4-...- 1! 1 1 1 I ^ I46a I ` I ,I [ 1 1 1 1 1 MI luveach ? u[ 1 ∎ i l i l i t l ---7 -f 1 1 1 ! - �- ; , i ' t - • • Public Testimony Given at the January 13, 1993 West Beach Field Rules Hearing VI. Production Allocation My name is Ronald Oba. I am an Engineering Director for ARCO Alaska, Inc., currently supervising the Lisburne /Point McIntyre Operations Engineering Group. I received a Bachelor of Science Degree in Mechanical Engineering in 1972 and a Master of Science Degree in Mechanics in 1974 from the University of Colorado. I have 19 years of experience in the petroleum industry working in the areas of production research, operations engineering, and reservoir engineering. I have been working in Alaska since 1984. My work efforts in Alaska have been directed towards the development of the Lisburne, Point McIntyre, and West Beach accumulations. In my testimony today, I will discuss the incentives for commingled production, the concept of well test based production allocation, and the details of production allocation activities for West Beach and all of the other fields which will be producing fluids for processing at the LPC. Successful implementation of commingled production from several producing fields is necessary for the development of small hydrocarbon accumulations on the North Slope. By the term commingled production, I mean the production of fluid streams from individual wells and separate fields which is combined prior to treatment at a common processing facility. At these common processing facilities, the oil, water, and gas are physically separated before measurement. Prior to any sales, the oil and gas streams are metered through standard custody transfer sales meters. Commingled production promotes North Slope resource development by enabling the Producers to reduce capital investments and per barrel operating costs via more complete utilization of existing facilities. Small hydrocarbon accumulations that would otherwise be non - developable resources, become economic reserves because of the lower cost structure resulting from commingled production. An integral part of a successful implementation of commingled production is the allocation of the produced fluids back to the originating field for revenue and reservoir management purposes. An analysis completed by ARCO indicates that the commingling of production from the Lisburne, Point McIntyre, Niakuk, and West Beach accumulations will result in the additional recovery of 100 -150 million barrels. One reason for this additional recovery is illustrated graphically in Exhibit VI -25. All facilities have a minimum physical throughput rate limit which is determined by the installed equipment. As shown in this exhibit, the commingling of production from multiple fields extends the useful life of each individual field by allowing each field to produce at lower rates while still satisfying the minimum production rate required by the facility. This extension of field life results in additional resource recovery. • • Owners to expand the LPC liquid handling system to more closely match forecasted commingled production rates. This plan will provide for a more effective utilization of all of the LPC equipment on the North Slope. Finally, the LPC is a relatively new facility. Commissioned in 1986, the LPC is one of the newest major facilities on the North Slope. It was designed and built as a standalone processing facility with state -of- the -art equipment. By standalone, we mean that the LPC does not rely on any other facility to completely process production. It has its own electrical power generation equipment and provides its own gas reinjection compression. This is a fairly unique processing facility on the North Slope as the initial design incorporated state -of- the -art corrosion- resistant duplex stainless steel to mitigate corrosion concerns. Additionally, throughout the short operating life of the LPC, significant modifications and upgrades have been made to maintain equipment quality. Over 57 million has been spent on upgrades to the major equipment, and almost $3 million was recently spent to upgrade the overall metering systems in preparation for anticipated commingled production. Details of these metering upgrades are discussed in Exhibit VI -32. As with any development of hydrocarbons, the quantification of produced oil, water, and gas volumes is important for both revenue accounting purposes and reservoir management activities under commingled production operations. However, when production from several fields is commingled prior to final processing and metering, separate direct measurements of the oil, water, and gas volumes at standard conditions for each producing field are not possible with existing metering technology. Thus, a production allocation methodology must be adopted. ARCO is requesting that the commingled production from West Beach and all of the other fields producing into the LPC be allocated with a well test based production allocation methodology. In general, the proposed well test based production allocation methodology focuses on individual well rates from each well producing into the commingled system. The production from an individual well is determined from a combination of periodic well tests and the producing history of that individual well. For example, as shown in Exhibit VI -27, knowing the rate at which a well produces oil, water, and gas and knowing the amount of time that well is on production, it is possible to calculate how much volume that well produced on a daily basis. Summing this calculated daily production volume for all wells in a commingled field provides an estimate of that field's daily production. Rarely does the sum of the calculated daily field production volumes for all commingled fields exactly equal the volume measured by the final custody transfer meters. Therefore, calculation of allocation factors is required to maintain a proper field split of the produced fluids. Exhibit VI -28 shows in equation form the general calculations used to determine the allocation factors. Variations in well producing rates are the main cause for the discrepancies between the calculated production volumes and the sales volumes. These rate variations result from a variety of causes ranging from natural well production decline to changing surface system conditions. A detailed 3 • Recognizing the need to reduce as much potential error as possible, the Lisburne Owners over the past year have invested nearly S3 million to upgrade the critical meters used for the allocation of production. The focus of these upgrades was the installation of state -of- the -art mass flow meters and online water cut metering at all drill site test separators. A mass flow meter calibration station has been constructed and installed at the LPC to allow for onsite calibration checks. This onsite station will allow for cost effective meter calibration and provide an opportunity for third party witnessing. Maintenance schedules have been established and operator training has been undertaken. All of this has been done to ensure accurate equipment is available for well testing. Additionally, well testing guidelines such as stabilization time, test duration, and testing frequency continue to be updated as existing well performances dictate. Similar guidelines will be established as commingled fields start production. As presented, both the State of Alaska as well as the Producers have a vested interest in commingled production and well test based production allocation. It is important that all parties have a firm understanding of the allocation process. It is with this in mind that ARCO fully supports efforts by the State of Alaska to designate a single lead agency to address metering and well test based production allocation issues for the State. We envision that as commingled production begins, all parties should play an active role in determining the appropriateness of the actions taken within the allocation process and should focus on ways to streamline the methodology while meeting the needs of all involved. It is via this partnership that the most efficient, accurate, and fair allocation of commingled production can be achieved. Specifically addressing West Beach development, ARCO is proposing that production be commingled prior to separation at the LPC and that oil, water, and gas production be allocated back to the producing fields by utilizing well test based production allocations. Exhibit VI -32 is a report describing the details of the proposed implementation of well test based production allocations for commingled production being processed through the LPC. In brief, the proposed implementation involves the following features: 1. Periodic production testing for all wells producing into the LPC. 2. Well test frequency will be maximized using all available test separator capacity at each drill site, within the constraints imposed by operating conditions. 3. The stabilization period and test period duration of each well test will be optimized by the Operator to obtain a representative test. 4. The Operator will attempt to obtain well tests at uniform intervals. 5. Well and field operating condition information required for the construction of a field production history will be maintained. 6. NGLs will be allocated based on gas volume produced and computer simulated process yields. 5 Rate vs. Time for Two Generic Fields With Separate Facilities and Two Generic Fields Commingled at a Single Facility with a 10,000 BOPD Minimum Rate Facility Limit 100000 i 90000 0 80000 Minumum Facility Rate — — [Shutin Commingled Fields A and Bl rrt 70000 k Q' 60000 in O 25 : m Shutin Field B, - m 50000 i 40000 IIIP 30000 -- Shutin Field Ai 20000 1414t11411111111 10000 • O j = . 1993 1998 2003 2008 2013 2018 2023 2028 January 13,1993 Well Tests and Event History for a Generic Well 2000 - :: h ' 1400 -- - Cri a 1200 -- X m N ix N p V : 600 .-- r • 400 .— WeII was Shutir - -0► 200 — ....... - .. 0 -- - - - - -- Time Theoretical Production • Well Tests lamiary 13, 1993 • • January 13, 1993 Lisburne /Point McIntyre/West Beach Allocation Methodology 1 . Conduct well tests to determine production rates for each well. Criteria for determining what wells to test: • Known well performance • Significant Events Pre and post well work tests Diagnostic work (i.e. temperature and pressure changes) Tests for engineering purposes • Date of last test 2. Review well tests for validity. • How does this well test compare with past well tests for this well • Was the stabilization period long enough • Was the test duration long enough • Did the flowing tubing pressure change significantly during the test • Did the lift gas rate change during the test 3. Review the significant events for each well. • Examine the event history for shutins, openings, gas lift gas changes and choke changes. • Examine the drill site operator shift change notes for why a well was shutin and other items of interest that might have an impact on the oil, water and gas rates of the wells. This includes, flowing tubing pressure and temperature trends, hot oiling, hot gassing, methanol treatments, LPC back pressure, field prorations, etc. 4. Calculate each well's theoretical monthly production by combining well test rates with significant events for that well. Allocating with no significant events: • Allocate from the beginning of one well test to the beginning of the next well test. Allocating with significant events: • Instead of extrapolating as a well is shutin or extrapolating for flush production when a well is brought online, it is assumed that the last well test rates are constant from the beginning of the last well test until the end of the event and that the current well test rates are constant from the end of the event until the beginning of the next well test or event. 5. Sum the theoretical monthly production volumes for all wells in all fields. Exhibit VI -29 e "A" WELL , ,,,( 50000 40000 - 0 - 30 0 0 20000 - 1111 d � i no( 0� �� f 1��► ' - - -- -- If' !�� •i /Ntftt• (t• UU�� l( a t• + ll�f I •w.-- l llIt-e.1 1/J• INNIMIMMINIMIIIIMMINIMIMINIMMI ,0 le (i ve« ll• l�ltf•0.�t�,�'�.. ► fpfiidl � t_I(Ufgf/ lt!!• 5000 4000 3000 • e 2000 ! — i0 111111111111.0 - • k 400 1 W 300 ta. 200 t 49 1 g , 50 N1111114111111111•1111111111/111111111111 1. IIIIIIIIIIIIIIIIIIIIM i !'11Iffly f�1111t/IR7t1It7 I r A f, p. • 30 I ' i lil , ' i / 1 j r r , I' I r r r 1 • 1 r r' - � —r 1 r r r r PIT I! U ' i + r 1 r ' ►rl Il f i f l 11 k 20 � r ,1 r rr r r, r r , �f y , �` r ' r_ 1 ' ' o• I V ?1 1 i H � I ' 1( II' �� f f� l f `_ + 1 r - i b ti {�1 i =u i� III r �� t�� S.o Ii 1 1 2.0 1 Ill! 111 I 1 i( 87 88 89 90 91 92 -tom Oil rate (stb/D) __ " °"" Gas rate (mcf /D) •" - Water rate (bw /D) • . EXHIBIT VI -32 West Beach Field Rules Testimony Supporting Documentation Well Test Based Production Allocation ECONOMIC PERSPECTIVES Commingling of production will benefit the State of Alaska by preventing waste of the State's hydrocarbon resources by facilitating production of resources that would not be produced otherwise. West Beach is a good example of this, the reservoir size would not support a standalone facility so its resources would never be produced. Another reason that commingling prevents waste of the State's hydrocarbon resources is shown in Exhibit 1. All facilities have a minimum throughput rate that is determined by the turndown rates of the specific equipment installed in the facility. When that minimum throughput is reached then the facility and all of the fields producing into that facility will have to be shutdown. In the example shown in Exhibit 1, which assumes a minimum facility throughput of 10,000 BOPD, Field A is shut down in the year 2013 and Field B is shut down in the year 2007. However, the commingled fields are not shut down until the year 2026. Being able to produce each field to a lower facility limit allows more reserves to be produced. For Lisburne, West Beach, Point McIntyre and Niakuk the additional recovery is estimated to be 100 to 150 million barrels, of which the State of Alaska should receive 13 -20 million barrels of this oil in Royalty and Severance Taxes. Beyond the deferring the attainment of the physical minimum rate limits of a facility, commingled production also extends the economic life of a processing facility and the associated fields by spreading the daily operating costs over a larger number of barrels. Generally, the base operating costs for a facility are not directly proportional to rate, and thus the cost to process 20,000 BOPD is not twice the cost to process 10,000 BOPD. The cost to process 5,000 BOPD is more than half the cost to process 10,000 BOPD. Thus, commingled production allows two fields to produce at 10,000 BOPD production rates while benefiting from lower processing costs that separate fields would have to produce at 20,000 BOPD rates to obtain. The bottom line result is a prolonged economic field life for each commingled field and thus a greater recovery of the resources in place. Commingling of production allows oil from fields that could not support the capital investments required for their own standalone facility to be produced and additional oil to be produced due to the facility minimum throughput benefits and economic life extensions discussed previously. Implied with commingled production is the allocation of that production. Currently, there is no accepted technology available to directly measure the production from the individual commingled fields. Thus, a well test based production allocation method is proposed. The process of well test based production allocation is not new to operations on the North Slope. It has been used for years for the purposes of reservoir management in Lisburne and other fields with a range of allocation factors of 0.90 to 1.1, with 1.00 representing the ideal case where the theoretical and actual production volumes match. An evaluation of the impact that this historic range of allocation factors would have on the State of Alaska and the field Page 1 1/13/93 S for the • e allocation engineer to verify that all of the shut ins were recorded in the event history. If for some reason the LDGS goes down because of a communication failure, a shutdown to install new programs, an unexpected crash, etc., well testing will not be adversely affected. At the drill sites, data is collected by the Bailey process control system, and then that data is transferred to LDGS; so if the LDGS goes down, the Bailey is still collecting data. Once back on line, LDGS can continue with the well testing in place. LDGS is backed up with the following schedule: daily backups for one week, weekly backups for four weeks, and then a monthly backup. The monthly backup is taken after all of the production allocation for the month is completed and it contains the official results for that month. The month -end backup is kept offsite and is kept permanently. The monthly backup can be loaded onto an alternate system and all of the data for that month accessed. DETAILED PRODUCTION ALLOCATION PROCESS RECEIVED • Conduct well tests to determine production rates for each well. - JAN 1 0 1995 • Review well tests for validity. M Oil & Gas Cons. Commission • Review the significant events for each well. +4nchora • Using data from the following month will help to eliminate the "wedge" effect and improve production allocation accuracy. • Calculate each well's theoretical monthly production by combining well test rates with significant events for that well. • Sum the theoretical monthly production volumes for all wells in all fields. • Calculate an allocation factor which divides the "Total Sales" volume by the sum of the theoretical monthly production volumes for all wells in all fields. • Calculate each well's allocated monthly production volume by multiplying the theoretical production by the allocation factor. • Sum the allocated production volumes for each well in each field to determine the amount of production derived from each field. Once well tests are obtained, the allocation process begins. Exhibit 2 shows the methodology used in allocating production. The steps used in allocating production are straight forward and leave little room for subjectivity. The only steps that are open to subjective treatment are Steps 2 and 3, reviewing the well test for validity and Page 3 1 /13/93 Overall the ability to d•troactive adjustments after char es in the flowing conditions • � g g of wells have occurred allows the allocation engineer to handle a variety of situations. For example, if the LPC system pressure increased by a significant amount, causing the flow rates to change on all of the wells, aggressive testing of all the wells could be conducted at the higher pressure. By coupling these new test results with retroactive adjustments, accurate production allocations could be maintained for the period after the system pressure changed. In determining the theoretical monthly production from a well, all data is used. Specifically, well test data from the past months as well as data from the first part of the following month can be incorporated in the analysis. By using the data from the next month, the "wedge" effect can be reduced. Exhibit 5 illustrates this situation. During the month of October 1992, the "wedge" effect accounted for a 3% change in Lisburne's monthly oil allocation factor. Therefore, extension of the month -end closeout of all data will improve the allocation process. Thus, final allocated production rates will be reported by the 20th day of the following month. An example of additional supporting data to be reported is shown in Exhibit 6. After the theoretical volumes are determined for all of the wells by combining the well tests with the significant events, all of the theoretical monthly volumes are summed for all of the wells in all of the fields. An allocation factor is then calculated by dividing the known "Sales" volume by the sum of all of the wells theoretical monthly volumes. Each wells allocated monthly production is then calculated by multiplying that wells theoretical monthly volume by the allocation factor. The allocated monthly volumes for all of the wells in a field are then summed to determine that fields' monthly production. WELL TEST FREQUENCY • Frequency should be determined by well behavior —some require less frequent testing and others more frequent testing. • Well test selection is based on known well performance, significant events, and date of last well test. • Currently in Lisburne, test separator usage is 80% - 90 %. • Any minimum monthly well testing frequency requirement might not be met under certain circumstances (e.g., pipeline prorations, plant problems, and well failures). • West Beach development will initially be one well and will be tested at DS-L1. Therefore, there will be no significant impacts on well testing frequency at DS -L1 Accurate allocation of production between fields depends upon the ability of the operator to recreate the production rate history for each well producing into the common facility. One aspect of accurately simulating each well's production history is Page 5 1 /1 3/93 1 . operations. During the day there is one lead operator that roams the field and performs numerous tasks. There is a drill site operator at DS-L2, a drill site operator at DS-L4, a drill site operator that watches DS-L3 and DS-L5 together, and a drill site operator that watches DS -L1 and DS-LGI together. At night there are two operators: one for drill sites DS-L1, DS -LGI, and DS -L2, and another operator for drill sites DS -L3, DS -L4, and DS -L5. Drill site manning levels are expected to . be similar for future operations. Having the drill site operators spread out like this makes it difficult to achieve 100% utilization of available testing equipment. For example, the drill site operator could be busy doing remedial work on a well or at another drill site when a well test ends. It could be some time before he is able to manually divert another well to the test separator. However, even with one drill site operator covering several drill sites, Lisburne has been able to achieve test separator usage in the range of 80% - 90% (allocatable well testing usage in the range of 70% - 80 %) of total available equipment time. This relatively high percentage of allocable well tests is a result of the operators and the engineers ability to monitor wells thru LDGS as they are tested and respond to any anomalies. It is felt that even with the addition of more drill site operators, this equipment utilization cannot be significantly improved. An inherent problem with establishing any minimum testing frequency is that there are several scenarios that would cause the operator to not meet these requirements. Operation problems such as pipeline prorations, plant upsets, and mechanical well failures are unavoidable. Problems like these are usually unexpected and require the immediate shut in of wells. By establishing arbitrary well test frequencies, the operator will have increased difficulty in accurately predicting produced volumes during and after these upset conditions since valuable testing time could be wasted testing wells solely to meet frequency requirements. In the case of a mechanical well failure, the well might have to be shut in for safety reasons prior to meeting any minimum requirements. Current operations, as well as future operations, will require wells to be cycled in order to maximize total offtake. Currently, this is due to gas handling constraints. For example, in November 1992 Lisburne had two wells which tested higher than the permissible GOR; one well was online for 15 hours and the other for 8 hours. Both wells had only one test and were shut in for the majority of the month. It would be a waste of effort and a reduction of total offtake to bring these types of wells back into the system solely to meet arbitrary testing requirements. Initial development of West Beach calls for one well to be commingled at DS-L1. The one West Beach well combined with the ten currently producing DS-L1 wells will not present any well testing frequency problems. If more wells are necessary for full West Beach development, the option of an additional test separator at West Beach will be explored. It is currently estimated that the addition of test separation facilities and associated piping would cost the Owners approximately $10 million. Page 7 1 /13/93 • • guidelines are utiiizea as a starting point for weil testing duration and the actual well tests are monitored during and after the test to ensure representative flows are obtained. Well testing stabilization and duration times for West Beach and any other commingled fields will be examined after start -up. WELL TEST BACKPRESSURE ADJUSTMENTS • Testing wells in a test separator imposes an incremental backpressure on a well. This backpressure will cause the well to test at slightly different rates than the normal production rates. • The impact of the back pressure effect is determined by the productivity index of a well. • If there are large errors introduced by the backpressure effect, then the well test rates can be corrected. • It is anticipated that the backpressure effects for West Beach and Lisburne will be relatively small and that no adjustments will be necessary. During the execution of a well test, the production from a well is redirected from the normal production piping system into a test piping system. Generally, this change imposes an incremental backpressure of 0 -20 psi on the well as it is being tested and will result in the measurement of a production rate that is slightly different (lower) than the normal production rate. The magnitude of the incremental backpressure is determined by the size of the test equipment and flowlines and the relative amounts of oil, water, and gas being measured. The overall impact of this incremental backpressure is determined by the individual well's productivity index. Productivity index is defined as the change in well producing rate with a change in pressure. In the case where the combination of well productivity index and incremental backpressure exerted by the test separator are significant, the raw well test rates could be adjusted using the well's productivity index. The productivity index would be determined via additional well tests performed at several different backpressure conditions on a periodic basis, as dictated by changing well performance characteristics (such as GOR, water cut, or total fluid rate). A typical productivity index range for wells producing into the LPC will be on the order of less than one to five barrels per day per psi of pressure change. Due to the combination of small well productivity indices and small well test incremental backpressures, the current backpressure impacts in Lisburne are relatively small, and it is anticipated that the backpressure impact for West Beach will also be relatively small. No adjustments are anticipated. Other fields that are commingled into the LPC will be examined for backpressure impacts. As production histories are established, future backpressure adjustments may be made. Additionally, tests are currently underway to operationally reduce the magnitude of the backpressure when a well is in test. Page 9 1 /13/93 • The low and high pressure flare volumes are estimated by examining the plant conditions before, during, and after a flare event. Direct measurement of these flare volumes is not feasible since a very wide range in potential rates would need to be covered and varying amounts of liquid carryover would need to be handled. Attempts to improve the measurement of these flare gas volumes would significantly impair the primary safety relief functions of the flare systems. Since May 1991, the historical gas volumes involved in flare situations, including flare assist gas, has been less than 0.1% of the total gas processed at the LPC. While the five Lisburne drill site fuel gas meters and the flare assist gas meter were not upgraded, their accuracy is still ±2% and the volume of gas they measure less than 0.5% of the total produced gas processed by the Lisburne production system. No upgrades for these meters are planned since their impact on gas allocation is extremely small. It is anticipated that metering installations for any field whose production will be commingled for processing in the LPC will have to meet the same industry standards for metering that Lisburne currently meets, and where possible, installation of similar meters will be required. West Beach will initially be tested at DS-L1, so there will not be any new metering required to bring West Beach into the LPC. Concurrent with upgrading of the physical instrumentation used in the production allocation process, the Lisburne Maintenance Group has accepted the responsibility for meter calibration and maintenance. While the Prudhoe Bay Flow Measurement Group will continue to be available as a technical information resource, the primary responsibility will reside with Lisburne Operations. This group is developing a flow measurement manual that outlines everything relating to flow measurement including required training for personnel, calibration equipment, calibration frequency, and calibration procedures. Increased training for personnel includes several industry and internal courses including the International School of Hydrocarbon Measurement and the API - PETEX School of Liquid Measurement. Calibration frequency for all critical meters is currently planned on a monthly basis. However, this could change as more field performance data is received. To facilitate the calibration of the mass meters, a gravimetric proving skid has been installed at the LPC. A schematic is included as Exhibit 15. This gravimetric proving skid duplicates the same calibration procedures that the manufacturer uses to calibrate all of the mass meters that it produces. Having the gravimetric skid at the LPC allows us to more easily verify the accuracy of the mass meters and eliminates continually shipping meters back to the factory for calibration. Simply stated, the gravimetric skid works by pumping water from a holding tank, through the mass meter and onto a very accurate scale. The weight of the water on the scale is then compared to the weight of water measured by the mass flow meter. The resulting meter factor is then calculated. The weights used to calibrate the scales are certified by the National Institute of Standards and Testing and will be recertified with the State of Alaska Division of Weights and Measurements every two years. Page 11 1/13/93 1110 Unrecoverable oil inciudes spilled oil and oil that cannot be processed and is sent offsite for disposal. If the unrecoverable oil is due to a spill, then the volume can only be estimated. If the oil is taken to offsite for disposal, then the Slop Oil Tank level and the truck volumes are used to calculate the volume. Since LPC start-up, the unrecoverable oil volume has been insignificant. Load crude comes from Prudhoe Bay Flow Station No. 1 (metered at ±1 %) and is used in wells for remedial treatments such as hot oil jobs and stimulations. Load diesel (metered at ±0.5 %) comes from the Crude Oil Topping plant and is used as a remedial treatment fluid and to freeze- protect wells and flowlines. The total load crude and load diesel volumes are subtracted from the total sales volume at the end of each month. Individual field usage will be accounted for. Since October 1991, the load crude and diesel was less than 0.25% of the total oil processed by the LPC. The sum of the individual well tests from all fields provides the denominator for the numeric allocation factor equation shown in Exhibit 14. The test separator meters provide the cornerstone for these measurements. The test separator fluid measurement meters have been upgraded to Micro Motion mass flow meters (±0.2 %). The mass meter was tested against a turbine meter at DS-L2 prior to installing the mass meters at all of the drill sites. Exhibit 16 shows an overlay of the mass meter and turbine meter rates. Phase Dynamics microwave water cut meters (±0.5 to 1.0 %) provide online water production measurements and are supplemented by periodic shakeout sampling. The water cut meter performance was verified at DS-L2 prior to installing them at all of the drill sites. Working in combination, these two meters accurately measure the amount of oil and water produced during a well test. Thus, the oil allocation factor is derived from the calculation of an adjusted sales volume divided by the produced volume derived from the well testing program. WATER METERING AND ALLOCATION • The meter on the disposal well will soon be upgraded to an ultrasonic meter in order to provide more reliable, long -term, consistent service. • External water would include water from pit dewatering and exploratory water. • The test separator total liquids are measured with Micro Motion mass flow meters and the water cut is measured with Phase Dynamics water cut meters. • Well test shakeouts will supplement online water cut measurements. The calculation of the water allocation factor uses the actual disposed or injected volume and the sum of the individual well tests. The actual disposed or injected volume is corrected for the TAPS BS &W volume and the external water added to the slop oil tank volume. The actual numerical equation used in the allocation of water production is shown in Exhibit 14. Page 13 1/13/93 • The flare volumes are estimated and are historically quite small. • The five drill site fuel and the flare assist meters do not meet current industry standards for sales meters. However, these meters handle less than 0.5% of the total gas processed by the Lisburne production system. In the calculation of the gas allocation factor, there is not a single meter that provides a direct total produced gas measurement analogous to the oil "sales" meter. In Lisburne, there are currently 22 meters or calculated volumes that are used to perform the gas allocation. There are six gas injection meters, the LPC fuel meter, the five drill site fuel meters, the high and low pressure flare volumes, the NGL shrinkage volume, the five master gas lift meters, the flare assist meter and the IPA fuel meter. These critical meters and volumes are shown in the critical metering diagram. The actual numerical equation used in the allocation of gas production is shown in Exhibit 14. The five test separator gas meters, the LPC fuel meter, the six gas injection meters and the IPA fuel gas meter have recently been upgraded and meet current AGA -3 and API standard for orifice meters and are accurate to t0.5 %. These meters are responsible for measuring 99.5% of the produced gas processed by the Lisburne production system. It is currently anticipated that these meters will be calibrated monthly. However, as more field performance data is gathered, the timing of the calibrations might change. The NGL shrinkage volume is calculated by the same facility process simulator computer program that calculates the stabilized NGL volume. This will be discussed in detail in another section. The flare volumes are estimated by examining the plant conditions before, during, and after a flare event. Direct measurement of these flare volumes is not feasible since a very wide range in potential rates would need to be covered and varying amounts of liquid carryover would need to be handled. Attempts to improve the measurement of these flare gas volumes could significantly impair the primary safety relief functions of the flare systems. Since May 1991, the historical gas volumes involved in flare situations, including flare assist gas, has been less than 0.1% of the total gas processed at the LPC. Exhibits 18 and 19 show the number of flare events, the size of the flare events and the flare gas percentage of the total gas processed at LPC. The five Lisburne drill site fuel gas meters and the flare assist gas meter do not meet current industry standards for sales meters. These meters are flange fitting orifice meters with online pressure and temperature compensation. The accuracy of the drill site fuel and the flare assist meters is in the range of ±2 %. The volume of gas these meters measure is less than 0.5% of the total produced gas processed by the Lisburne production system. NGL MEASUREMENT • Field NGL volumes will be determined by the field's volume of produced gas and field NGL yield factors. Page 15 1/13/93 3. Calculate the LPC h riv and daily stabilized NGL andlnkage volumes: Hourly NGL(STB) = (Meter 660) x (SF) Houriy Shrinkage (MSCF) = (Meter 660) x (SF) x (SHF) Daily Total NGL (DTN) = Sum of hourly NGL volumes Daily Total Shrinkage (DTS) = Sum of hourly Shrinkage volumes Total rate to TAPS including NGLs *: 36,000 STB /D Total rate to TAPS without NGL plant *: 31,500 STB /D Stabilized NGLs blended with crude : (36,000 - 31,500) = 4,500 STB /D Total unstabilized NGL rate out of depropanizer *: 8,300 AB /D NGL SF: (4,500/8,300) = .5422 = 54.22% Actual hourly NGL rate blended with crude : (Meter 660) X (SF) Daily Total NGL volume (DTN) : Sum of hourly NGL volumes Total produced gas to injection without NGL plant *: 450,000 MSCFD Total produced gas to injection with NGL plant *: 442,000 MSCFD Equivalent NGL gas Volume *: (450,000-442,000) = 8,000 MSCFD SHF: (8,000/4500) = 1.77 MSCF /STB Actual hourly Shrinkage Volume : (Meter 660) X (SF) X (SHF) * Note: This value has been calculated by process simulator. NGL Volume Determination (Commingling Lisburne and West Beach) The Daily Total NGL (DTN) and Shrinkage (DTS) volumes will be calculated as they are currently when multiple fields are commingled into the LPC. However, in order to calculate the contribution of each field (Lisburne and West Beach) to the stabilized and unstabilized NGL volumes, it is necessary that the components making up each reservoir be labeled and tracked separately. Thus, the Lisburne methane component will be labeled as LISCi, the West Beach methane component as WBCI with the remaining components being similarly labeled (LISC2, LISC3, ..., WBC2, WBC3, ..., etc). In this way, the model is able to differentiate the makeup of each stream by component and the field that produced that component. From this data, NGL yield tables (Stabilized STB NGL /MMSCF produced gas) are developed for each field over the operating range of the LPC. These yield tables are used in combination with the current methodology to determine the volume of stabilized NGLs for each field. The following list shows the steps involved and how the methodology would apply for calculating the stabilized NGL volumes for a two field case (Lisburne and West Beach). The same approach will be used when additional fields are commingled. Current 1. Record hourly averages of pertinent plant operating conditions. 2. Calculate hourly SF and SHF based on operating conditions. 3. Calculate the LPC hourly and daily stabilized NGL and shrinkage volumes: Page 17 1/13/93 • • • External water will be subtracted from the water disposal_meter. • Exploration oil will be subtracted from the TAPS sales oil and will be credited to the exploration Owner(s). LPC fuel and flare gas will be divided among producing fields based upon the gas fraction produced through the LPC by each field. At the LPC, 86% of the fuel is used to run the gas compressors that handle the produced gas. Drill site fuel and flare gas will be divided among the fields producing into each. drill site based upon the gas fraction produced through that drill site. All of the drill site fuel is used to run the drill site heaters. The major reason for adding heat to the drill site fluid before it is sent to the LPC is the cooling caused by the entrained gas. The flare gas at the LPC and the drill sites will be divided among fields producing based upon the fraction of gas each field produced through that facility. RECEIVED JAN 1 0 1995 A skca Oil & Gas Cons. Commission Anchora Page 19 1/14/93 January 13, 1993 Lisburne /Point McIntyre/West Beach Allocation Methodology 1 . Conduct well tests to determine production rates for each well. Criteria for determining what wells to test: • Known well performance • Significant Events Pre and post well work tests Diagnostic work (i.e. temperature and pressure changes) Tests for engineering purposes • Date of last test 2. Review well tests for validity. • How does this well test compare with past well tests for this well • Was the stabilization period long enough • Was the test duration long enough • Did the flowing tubing pressure change significantly during the test • Did the lift gas rate change during the test 3. Review the significant events for each well. • Examine the event history for shutins, openings, gas lift gas changes and choke changes. • Examine the drill site operator shift change notes for why a well was shutin and other items of interest that might have an impact on the oil, water and gas rates of the wells. This includes, flowing tubing pressure and temperature trends, hot oiling, hot gassing, methanol treatments, LPC back pressure, field prorations, etc. 4. Calculate each well's theoretical monthly production by combining well test rates with significant events for that well. Allocating with no significant events: • Allocate from the beginning of one well test to the beginning of the next well test. Allocating with significant events: • Instead of extrapolating as a well is shutin or extrapolating for flush production when a well is brought online, it is assumed that the last well test rates are constant from the beginning of the last well test until the end of the event and that the current well test rates are constant from the end of the event until the beginning of the next well test or event. 5. Sum the theoretical monthly production volumes for all wells in all fields. Exhibit 2 Production Allocation - How a Typical Well is Handled 2000 1800 -- ... . 1600 1400 Q � CO 1200 tit 1000 M � CC _ 800 -- o 400 rr W 200 -- 0 Time Theoretical Production ■ Well Tests How Allocations Are Typically Handled: • Allocate from beginning of test to beginning of test January 13, 1993 The Month End "Wedge" Effect 1600 — -- - - - -- - - - -- _ NOTE: Have a minimum of 2 tests in the month but use a . minimum of 4 tests for allocations in that month. - 1 1 1400 -- 1 1 111 1 1 . 1 1 1 1 ~ 1 1 1200 -- ` 1 1 The Month End "Wedge" Effect 1 1 • - \ 1 1 Allocation drop 1 1 date to meet k o (Production Trend 1 1 a 1000 reporting ... m 1 1 a . N - 1 1 requirements U1 1 - ADOR 1 1 AOGCC cc 100 1 1 O - 1 1 1 1 • 1 1 • • - 1 1 600 -- 1 1 1 ▪ The "Wedge" effect is the error - -- 'Month End Boundaries'- ►t 1 1 400 — introduced in the allocation factor - - - - - 1 1 . caused by not being able to interpolate 1 1 . between well tests that cross the 1 1 - month end boundaries 1 1 200 ■■ t■ I r r r t 1 1 r r r r ■ r r' 1 ■ ■ r 1 ■ 1 1 1 1 1 ■ r ■ I ■ 1 1 ■ ■ I r r■ 1 4/1/92 4/11/92 4/21/92 5/1/92 5/11/92 5/21/92 5/31/92 6/10/92 6 /20/92 6/30/92 January 13, 1993 • . O• •t - I _ 0 I • � i 40000 30000 — - -- 20000 I II!P!II I - - - - - c , �icc • .�f� _ l( t ■ • to. list's . ... i 'i �� tte'l u tia�t r� urar li r a at«t � ra�wwi� if �.at •l S�:F:.�i,�ttc t rsa!ta�fc alca i ' in (arge` l (Mit tats 5 it _ • 4000 IT 3000 �• . r, 200 r ".� 300 � - - - __�__ fp 200 � le , ,.. ,,,. i. , 40 � % # lIYUt111�!111�1ai1�11f1 r • fr --- 1 1 -- 41/1 (�, ,� � l� I ,Ai L' 11 / . it ll 1 � , , X 14 1 I / 20 30 i '�l� • 1 M 'oil. / I Vin' f ! 1 I ■ __ ;I I I� ti � I i tort �i>tnaa� so we to i t ; 510 I II l; l 4.0 i t II 3.0 1 ' 2.0 ii ii t .0 91 92 87 89 90 f am,arn" 11 1993 nil rata Icth►rn -..0.- rac rata (m•fIf11 - Water rata (hw /nl Typical Well Test Stabilization 500.00 - 8000.00 r = [Total Liquid) 450.00 -- _ _ _ _ _ _ _ 7500.00 ,� 400.00 — _ - � - 7000.00 • F • . r C • a 350.00 - 6500.00 tri I • 30 0.00 -- 6000.00 0 a . Ph 1,.. - n► Gas O m f '' 3 250.00 550000 C r N 0 200.00 1^ r 5000.00 n TS 0 ...... . . 0 3150.00 .. s 4500.00 rte+ v r 1- 100.00 -- Water Cut } 4000.00 - . 50.00 — , 3500.00 . i \ :,..../..........„.........,___________ . . 0.00 _ • • w ' . . • . I . . ■ . ` . . . • I ■ • 3000.00 12/21/92 12/21/9216:44 12/21/92 17:56 12/21/92 19:08 12/21/92 20:20 January 13, 1993 Typical Well Test for a Slugging Well 500 4000 • - _ 450 - 9- 1 ........ I.- - ,...__ .._ _. *� 3000 I 400 - } � -• - -._ i.. 2000 6 m 350 ....1..... 1 ..+ 1000 0 o - m is 300 �. --_ _, •___..... 0 0 m - a 1 G1 C CC - 250 — - - -10 00 • Imi 3 ( Gasj (Oil I L ift Gas m 200 — 1 Water j -- -2000 a t - N. o - j r - 1 i 150 -- - -- -3000 ; ' • 5 4 - r - - i - 100 — ....... -- -4000 r r ■ 5o r 5000 { 1 i r 0 ..._ _. �. -6000 12/17/92 12/18/92 12/18/92 12/18/92 12/18/92 12/18/92 12/18/92 12/18/92 12/18/92 12/18/92 22:50 0:02 1:14 2:26 3:38 4:50 6:02 7:14 8:26 9:38 January 13, 1993 LISBURNE, POINT MCINTYRE AND WEST BEACH CRITICAL METERING DIAGRAM . I ® EXPLORATORY FLUIDS NGL & SHRINKAGE EXTERNAL WATER GAS (estimated) LISBURNE WELLS UNRECOVERABL OIL, HP & LP FLARE LPC FUEL I LOAD CRUDE (estimated) ted) DRILL SITE ARTIFICIAL LIFT I FUTURE i t LOAD DIESEL / 1 POINT WE • ® 1 S LISBURNE MCINTYRE BEACH I I I 'Otti'l IPA FUEL CD 41111) 4113) 1 .: CM m I LPC CD ga F EE w FLARE f,, ASSIST I A • LISBURNE POINT WEST W • MCINTYRE `EACH , ( DR ILL SITE FUEL I .'• ' T .a Separator ' CID TAPS (OIL + NGL'S) I FUTURE I LPC -01 ` ■ ( N i t i t WATER INJECTOR I I PT. MCINTYRE WELLS tzeiD CMD 4112) 43113) 1 I - set : "� USB URNE PT. M INTYRE WEST I— — — FUTURE BEAC fr GAS REINJECTION f 1 L 1 1 1 1 — ® —So' WEST WELLS January 13, 1993 • H I 01611RL INPUT 10 p 1 .ill © pI!R R1YiI•It[0H I C M O4IROL snits • O OIGITRL OUTRJT TO 011TR RO UISIT[0/ S Pr C0 ITROL Svs ,A1 e ■ A , It#IOG IIAIT To Ha • • • •. 0RIA RCiJItITION I CONTROL SrSTIJI . I. r RILOG OUTPUT TO K ' © a I T ROJIi1TION • ► carioca_ sorsicrt ORT11 1101JISITION I COAR f o S -© © 0 JII 01 MUM, BATCH W••( I CI 6 . BOB • 111IT01 MIK 1 m I.21/0 4 (XI) N • _ 1 ---- • j 1 01 1 0.. c 5 , 1 satz rt 4 . •� 2 I 2' • h•• 1 A I (n I I 0 ® =rm.wro I ril ,. 2' I eV .0.11•131 nIownoTION N't 4 VII ' 7 — i OS I FLEX JOINT — � o • SUMP TANK CIRCULATING PIMP IS 1P VARIABLE SPEED r F LEX JOINT 1 r IM1WI n AO REVISED I1 -18 -92 ® I a O R.... P S. T paoocP DRAWN CLINTON REF; 11ROo DATE; 7 -27 -92 SCALE; NTS January 13, 1993 i Lisburne Shakeout vs. Water Cut Meter Data 100.0 • • _ • 4 - 3 90 .0 •-. • ■ 1■ • ■ • • 80.0 [Slope - 0 Intercept - - 0.4239, R "2 - 0.97611 ■ as ■ 70.0 • • /r• v • F 60. - r • ti i ' • S. I-' 5 • .� 0 • • • V 0 • Y 40.0 N • � � � • ■ ... • • ; 30.0 —. - r • N • I l . 1- 20.0 i ...11-111- ,•. ■ . lb I • I ■ 10.0 -- . I ..._ • 0.0 • N , ■ ■ I I I T 1 ■ ■ , ■ ■ 1 ■ ' ■ ■ ■ 1 1 ■ 1 1 ■ 1 ■ 1 ■ ■ + ■ I ■ 1 + 1 ■ ■ 1 + • 1 1 ■ 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 100.0 Water Cut Meter Water Cut ( %) ■ All Drill Sites Ideal 45 Deg Line Least Squares Fit LAST UPDATE: 11/9/92 January 13, 1993 Total Flare Volumes and Total Flare Volume As A Percent of Total Produced Gas for Lisburne (5/91 -11 /92) . 42000 { {} - 0.35% - { ; ' . ✓ - T 36000 — , al ,. .. .. .... -- 0 3 0 % -' 0 i , . C _ ' — 0 .25% 3 30000 , A t ` D m 24000 — < -- 0.20% a. PA* I A* o ,y j y, •-+ > - .o E 18000 — _ B € . 0.15% o .. 13 u• ii _ y -t v �s3 O a. i r 4 C I- 12000 — 4 • , -1 g 0.1 % a < >; ;; z Y pe Wit : m ..• • G fA i � �. 0.05% 0 6000 -- j._ # r s s . 0• I i I I• I I I 1 ° 4' I . .N' I z . . I" i hv„ 1 .. l * l • • I , 1'4 _ 0.00% r- -- r- r Ir. r r- 1- N N N N N N N N N N N S S S S S e S S s s S s s S S S S Total Flan Volume • Monthly Flare Volume As a % of Total Flan Volume As a % of Produced Gas Produced Gas January 13, 1993 i P Percent Deviation vs Days Between Well Tests for High, Medium and Low Variance Wells 35.00 . % Deviation - Volume With Less Tests - Volume With All Tests The Low Variance Web is a Type A Well : and 30.00 ; Volume With All Tests The High Variance Well is a Type B Well 25.00 • 20.00 - o 0 i.-- 15.00 10.00 ; ■. • gl S 5.00 f- -...T - _. .■ •' " - Q + y 0. ® . ••- • • , v .• 11 - • • • • N at - 5.00 =- ' • ` ' "! �......,, • _ _ • i i . ■ — _ ■ • ■ r — _ r _ ■ — • •10.00 , . : • • ... . . .. ... -- __ ■ a r ■. .. s - 15.00 -. _ 1 ,1. 1 . 1 . • ■ t' •20.00 _ __ _ __ ... _ ' -25.00 -- pa N `s' rn • -30.00 11 - 3._. (-71 ... Ci ■ r -35.00 • n • 1 i 1 i v 0 10 20 30 40 50 60 70 80 Average Number of Days Between Well Tests • Low Low • Medium Medium • High High January 13,19931 7 OCT -27 -94 THU 11:55 DIV,OF OIL AND GAS FAX NO. 9075623852 P. 01/01 FROM AOGCC 410 6 -7542 OCT 2 8:53 No.001 P.01 Memorandum State of Alaska Oil and Gas Conservation Commission To: Sams Eason Date: October 27, 1994 Director, DOG Telephone; 279 -1433 Fax number: 276 -7542 r'rom: David W.10 Subject; Nov. 3, 1994 meeting Chaff Before finalizing our Nov. 3 meeting, the commission needs to determine if the meeting will have direct bearing on our deliberations concerning the N. budhos Day pool rules. If so, since we arc in adjudication, it may be necessary to invite the applicant to the meeting. Do you or your staff intend to offer Information or comments likely to influence our decision c.orircrning pool rules for N. Prudhoe Eay or do you intend only to share general thoughts and comments about management of the LPC and production from the Greater Point McIntyre arca? 7 Oy / 6 / gy v p-L., , 1 N o / 1 1 (. e , t „,j- ...c) (cC v 5S < s cn N P� . 5,0-Q-c . / 0 0 .1—v7 0:_c___Q.,6( , .1-...r// 1% CW-P 5 , ...„________ _________ _____,.._ --- ‘ - it ,-- ------,,,, /_>...----- (---.- 1 L-- , — 2 1--:>,-.'190-a ‘N ( f zi 21 at _ �" gash a 1\ crc`� °�a ' 41 10 Memorandum State of Alaska Oil and Gas Conservation Commission To: James Eason Date: October 27, 1994 Director, DOG Telephone: 279 -1433 Fax number: 276 -7542 From: David W. Jo n Subject: Nov. 3, 1994 meeting ChairMan Before finalizing our Nov. 3 meeting, the commission needs to determine if the meeting will have direct bearing on our deliberations concerning the N. Prudhoe Bay pool rules. If so, since we are in adjudication, it may be necessary to invite the applicant to the meeting. Do you or your staff intend to offer information or comments likely to influence our decision concerning pool rules for N. Prudhoe Bay or do you intend only to share general thoughts and comments about management of the LPC and production from the Greater Point McIntyre area? i I I 6/17: d 0 KL11\ WALTER J. NICKEL, GOVERNOR ALASKA OIL AND GAS soot PORCUPINE ORLYE CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3192 PHONE: (907)279 -1433 October 25, 1994 TELECOPY: (907)276 -75422 James E. Eason, Director Division of Oil and Gas Department of Natural Resources P.O. Box 107034 Anchorage, AK 99510 -7034 Dear Jim, Thank you for your October 10 letter concerning pool rules for North Prudhoe Bay. The commission agrees that insufficient information is available today to judge the adequacy of ARCO's long -term plan of development. The commission will require ARCO to submit annual updates and will continue to evaluate its plans for pool development to ensure that waste does not occur, correlative rights are protected and a greater ultimate recovery of oil and gas is realized. You are correct in noting that throughput at the LPC is at facility handling capacity. As you are aware, ARCO has steadily increased LPC oil capacity from its original 100,000 barrels per day to today's approximately 160,000 barrels per day. LPC oil throughput now significantly exceeds ARCO's original plan of between 135,000 to 140,000 barrels per day when surface commingling was first approved by Revenue, DNR and the commission during our deliberations on West Beach and Pt. McIntyre. While throughput limits exist, it is also clear that ARCO has enjoyed significant success de- bottlenecking the LPC to handle increased crude oil flow from Pt. McIntyre, West Beach, Niakuk and North Prudhoe Bay. It is also clear that ARCO and the other mineral interest owners have recognized that production limits would be reached, and that production from certain pools would be deferred. It has always been our understanding that production wells will compete for LPC processing space based on handling constraints at the time in question. Initially, the main constraint was expected to be gas handling capacity. Because of successful de- bottlenecking efforts and better than expected oil rates from the Pt. McIntyre pool, the main constraint presently is oil handling capacity. Oil throughput is now being optimized by balancing oil rate with GOR to keep the compressors fully loaded. Production conditions at the LPC will remain dynamic and will change day to day, and year to year, as fields are developed and reservoir management plans mature. Criteria for "who gets in the door first" should remain dependent on facility handling constraints and sound reservoir engineering decisions with the paramount goal of maximizing ultimate �,;� p10 Uh4 On re CYC1 r h =. • s recovery. The possibility exists, however, for this queuing arrangement to become distorted because of the differing royalty and tax rates in the Greater Point McIntyre area. To prevent production bias, strong commission oversight is needed. You pose an interesting question concerning the relationship between LPC capacity and reservoir and well management decisions at Lisburne, Pt. McIntyre, West Beach, Niakuk and North Prudhoe Bay, i.e., should NPBS #3 be worked over, should additional wells be drilled, or should high GOR Lisburne wells be returned to production? These same types of questions exist for any pool being developed where production handling and processing facilities are at or near capacity. However, these questions become problematic for the state and the mineral interest owner because of the differing royalty and severance tax rates for each pool in the Greater Point McIntyre area. If a common tax and royalty rate existed between each pool, I suspect your concerns for protecting correlative rights, preventing waste and conserving resource would disappear or, at least, be reduced solely to reservoir engineering matters and not economic perplexity. Has the state considered negotiating a common tax and royalty rate for the Greater Point McIntyre oil pools? Since individual pools are processed at a common production center, the individual pools could be managed as a common property. By removing tax and royalty distortions between pools, sound engineering principles could be applied as the sole basis for evaluation and development of each pool in the Greater Point McIntyre area. This idea may be an area worthy of commission inquiry. The commission looks forward to discussing your concerns and any proposals you may have with respect to the plan of operation and development for the LPC and Greater Point McIntyre area. I suggest we meet November 3, 1994 at 9:00 am in the commission's offices. 111 & 611111 1 1 g„,„,„„,. David . Johnston Chairma cc. Commissioner Noah 35 STATE OF ALASKA ADVERTISING ADVERTISING ORDER NO. ORDER AO- s { {. AGENCY CONTACT DATE OF A.O. F R PHONE 1. u z M j 4 (907) -, - -: " _ -r ti s ti d DATES ADVERTISEMENT REQUIRED: Y ) . 1 T i / 9f o Fir Publisllin Conlpany A 1,341 U U �± _ 7 •'=r - , t.ia= ? f , ' i, y L I SPECIAL INSTRUCTIONS: S H E R AFFIDAVIT OF PUBLICATION UNITED STATES OF AMERICA ` STATE OF aciDt. ;I(- 3`?.-,,, ss 960 Public Hearing INVOICE MU )ST REFERENCE THE ADVER NOTICE of PUBLIC HEARING % � j iketVAD IVISION. A CERTIFIED STATE OF ALASKA ALASKA OIL AND cos F PUBLICATION BEFORE ME, THE UNDERSIGNED, A NOTARY PUBLIC THIS DAY MUST BE SU CONSERVATION COMMISSION , E. Re: The application of ARCO Alaska, - --^ Inc. and BP Exploration (Alaska) PERSONALLY APPEARED_ 1 ( { l 1 - ! LA V iU {WHO ATTA( tion Inc. to Order amend 173. Rule 5ofConserve- N H ERE. ARCO Alaska, Inc. and BP Exploration (Alaska) Inc. by letter BEING FIRST DULY SWORN, ACCORDING TO LAW, SAYS THAT dated September 14, 1994 have re- quested an amendment to Rule 5 of HE/SHE I S THE ' i � ` '\..c4.-7-7-t--1 Conservation Order 173. The amend O F ; _ •!'' ® mentwoufdi eliminate the subsurface safety valve requirement in the Ir y in R Kuparuk River oil pool, Kuparuk River PUBLISHED AT —44/ t. L1---- IN SAID DIVISION Reid, and require surface safetyvalves only on wells capable of unassisted / flow of hydrocarbons. AND STATE OF AND THAT THE Apersonwhomaybeharmedifthe requested order is issued may file a written protest prior to. 4 :00 p.m. ADVERTISEMENT, OF WHICH THE ANNEXED IS A TRUE COPY, WAS and Gas Conservation nse4wito Commission + and Gas Conservation Gommr� ion (hereinafter the Commission), 3001 PUBLI ED IN SAID PUBLICATION ON THE / Porcupine Drive, Anchorage, Alaska DAY OF 99501, and request a hearing on the J matter. if the protest is timely filed and Y 1�1 - raises a substantial and material issue io'� 19 " ,AND THEREAFTER FOR crucial to the Commision'sdetermina- tion, a hearing on the matter will be at the above address at 9:00 a.m. on CONSECUTIVE DAYS, THE LAST PUBLICATION APPEARING ON THE November 29, 1994 in conformance with 20 AAC 25.540.1f a hearing is to DAY OF be held, interested parties may con .._.4 1 THAT THE firm this by calling the Commission's office,(907) 279 -1433 after October 26, 1994. If no protest is filed, the RATE CHARGED THEREON IS NOT IN EXCESS OF THE RATE an ceof t h e o r d e consider the i ance of the order without a hearing. If you are a person with a disability CHAR D PRIVATE INDIVIDUA " . who may need aspecialmodification in order to comment or to attend the IA ,+ � public hearing, please contact liana 4 `tom r A Fleck at 279- 1433 no later than - November 25, 1994. RussellA. Douglass, Commissioner SUBSCRIBED AND SWORN TO BEFORE ME Alaska Oil and Gas Conservation Commission THIS DAY OF 00.-4-"4-t.x 1994f Ao02-5 14019 Published: October 19, 1994. NO RY PUBLIC FOR STATE OF ,QV 4.4.1.4.... _ MY COMMISSION EXPIRES 9%-s - 9s' 02 -901 (Rev. 6.85) PUBLISHER �� ALTER J. NICKEL, GOVERNOR DEPT. OF NATURAL RESOURCES P.O. BOX 107034 ANCHORAGE, ALASKA 99510 - 7034 PHONE (907) 762-2553 DIVISION OF OIL AND GAS October 10, 1994 David Johnston, Chairman RECEIVED Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive OCT 1 2 1994 Anchorage AK 99501 Alaska Oil & Gas Cons. Commission RE: North Prudhoe Bay Oil Pool -- Proposed Pool Rules Anchorag Dear Chairman Johnston: The following comments are submitted by the Division of Oil and Gas for the record regarding ARCO /Exxon's North Prudhoe Bay Oil Pool Rules request. 1. The proposed plan of development is adequate for the short term. It may or may not be adequate in the long term. As discussed at the pool rules hearing, additional data are needed in order to assess reservoir size and drive mechanisms and to develop a long term plan of development. Given the constraints discussed below, this data may not be available for several years. I recommend that the Commission limit its approval to an interim or short -term plan of development for the pool. This would assume that the adequacy of the proposed plan could be reviewed again in a year or two when more data are available. 2. The North Prudhoe Bay State #3 well (NPBS #3) produces through the Lisburne Production Center (LPC). All the Point McIntyre, Lisburne, West Beach and Niakuk wells also produce through that facility. It is my understanding that the LPC is producing at its maximum liquid and gas handling capacity. In order to produce the NPBS #3 well (which is now shut in) or to produce any newly drilled NPBS wells, an existing producing well in one of the other pools will have to be shut in or choked back. This allocation issue presents a dilemma to the LPC operator, the various combinations of working interest owners in the various pools, the royalty owner and to the Commission. There is no easy or clear choice concerning the level and timing of development for pools like West Beach and North Prudhoe Bay. As capacity becomes available in the LPC, should existing Lisburne wells be returned to production, additional wells be drilled at North Prudhoe Bay, West Beach, Point McIntyre or Niakuk or should the NPBS #3 well be worked over in hopes of returning it to production? 3. While economics should play a role in shaping the development plans for a pool, economics alone (either for a single project or as a comparison between multiple projects) should not be the sole consideration. Conservation of the resource, protection of correlative rights and prevention of waste also need to be considered. Sound engineering principles should be applied to the evaluation and development of this pool. Several promising O. 4 options and possibilities were discussed at the hearing. They should continue to be evaluated as more data becomes available. As a side note, many of the same options and possibilities as well as the same capacity constraint problems apply to the evaluation and development of the West Beach pool. Facility sharing at the LPC has worked so well that there now is a waiting line to get in. Unfortunately, there are no clear guidelines concerning who gets through the door first. We would be glad to explore this issue in more detail with the Commission and the effected lessees at your convenience. Thank you for holding the record open and allowing this opportunity to comment. Please contact Bill Van Dyke if you have specific questions concerning these comments. Sincerely, (tip J es E. Eason, irector cc: Commissioner Noah Commissioner Babcock Commissioner Douglas file: NPBS .-3 •CO 3! IMF 2 3 4 ALASKA OIL AND GAS CONSERVATION COMMISSION 5 PUBLIC HEARING OCTOBER 5, 1994, 9:00 O'CLOCK A.M. 6 7 TRANSCRIPT OF PROCEEDINGS 8 9 10 HELD AT THE ALASKA OIL AND GAS CONSERVATION COMMISSION 11 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 12 13 14 15 16 17 18 19 20 21 22 RECEIVED 23 OCT 2 4 1994 2 4 ylasxa u►1 & Gas Cons. Commission Anchors; 25 R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272-7515 ANCHORAGE, ALASKA 99501 S i 2 Ili/ 1 P R O C E E D I N G S 2 CHAIRMAN JOHNSTON: Good morning. I'd like to 3 call the meeting to order. I'd like to note the time is 4 approximately seven after nine o'clock in the morning. The 5 date is October 5, 1994. We are located in the Commission's 6 offices located at 3001 Porcupine Drive, Anchorage, Alaska. 7 To begin, my name is David Johnston, Chairman of the 8 Commission; to my left is Commissioner Tuckerman Babcock; to my 9 right is Commissioner Russ Douglass, and to our far right, over 10 here, is Penny Reagle, of R & R Court Reporters, who will be 11 making a transcript of these proceedings. For those people 12 that desire a transcript of the proceedings, we would request 13 that you contact R & R Court Reporters directly and obtain it • 14 from them. 15 At this time I'd like to request that Commissioner 16 Douglass read into the record the notice that was provided for 17 this hearing. 18 COMMISSIONER DOUGLASS: Notice of Public 19 Hearing, State of Alaska, Alaska Oil and Gas conservation 20 Commission; regarding the application of ARCO Alaska, Inc. for 21 a public hearing to present testimony for classification of a 22 new oil pool and prescribing pool rules for its development in 23 the Prudhoe Bay Unit of the Prudhoe Bay Field. 24 Notice is hereby given that ARCO Alaska, Inc. has 25 petitioned the Alaska Oil and Gas Conservation Commission, R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 3 1 under 20 AAC 25.520, to hold a public hearing to present 2 testimony for classification and prescribing pool rules for 3 development of a new oil pool in the Prudhoe Bay Unit. The 4 development area is located in the northeast portion of the 5 Prudhoe Bay Unit and is referred to as the North Prudhoe Bay 6 accumulation. 7 A hearing will be held at the Alaska Oil and Gas 8 Conservation Commission,3001 Porcupine Drive, Anchorage, Alaska 9 99501 at 9:00 a.m. on October 5, 1994, in conformance with 20 10 AAC 25.540. All interested persons and parties are invited to 11 present testimony. If you are a person with a disability who 12 may need a special accommodation, auxiliary aid or service, or 13 alternative communication format in order to comment on the • 14 proposed action, please contact Diana Fleck at 279 -1433 by 15 4:30 p.m., September 29,1994. 16 Signed, Russell A. Douglass, Commissioner, Alaska Oil and 17 Gas Conservation Commission. Published August 25, 1994. 18 CHAIRMAN JOHNSTON: Thank you. I think 19 everyone here pretty well understands Commission procedures for 20 hearings, but briefly, our procedures allow us to take sworn 21 testimony or unsworn statements. Greater weight, of course, 22 will be given to sworn testimony. If you wish to be considered 23 an expert witness in the matter before us, we'd ask that you 24 state your qualifications. The Commission will then rule as to 25 whether we would consider you as expert in this matter. • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 410 • 4 • 1 We'll have the applicant testify first, followed by 2 anybody else wishing to make testimony or a statement to the 3 Commission. In this particular case we'll not allow cross 4 examination of the applicant. Those people in the audience 5 that wish to ask a question of the applicant, we would ask that 6 you write your question on a piece of paper, forward it to the 7 front table here. We will take a look at it and if we feel it 8 germane, we will -- the Commission will then ask that question 9 of the applicant. 10 As I indicated earlier, we will be preparing a written 11 transcript. That is, again, available from R & R Court 12 Reporters. At this time I'd like to turn the table over to the 13 applicant. I believe Mark Worcester will provide introductory • 14 remarks. Mr. Worcester, we understand that the following 15 individuals, Sam Dennis, Mark Ireland, George Phillips, and 16 Andy Simon will be offering testimony; is that 17 MR. WORCESTER: That is correct. 18 CHAIRMAN JOHNSTON: correct? Perhaps at 19 this time we should swear those individuals in. 20 COMMISSIONER DOUGLASS: If you'd please rise 21 and raise your right hand. 22 (Oath administered) 23 IN UNISON: I do. 24 CHAIRMAN JOHNSTON: And if we could reflect in 25 the record that Sam Dennis, Mark Ireland, George Phillips, and 410 R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 5 1 Andy Simon have been properly sworn in. Mr. Worcester. 2 MR. WORCESTER: Mr. Chairman, Commissioners, 3 ladies and gentlemen, my name is Mark Worcester. I am a senior 4 attorney for ARCO Alaska, Inc., the operator of the North 5 Prudhoe Bay State Num- -- well, State Number 3 Tract Operation, 6 which we soon hope to be a participating area within the 7 Prudhoe Bay Unit. 8 This hearing has been scheduled in accordance with 9 20 AAC 25.520, and 20 AAC 25.540, in order to consider evidence 10 relevant to the establishment of rules for the development of 11 the North Prudhoe Bay Oil Pool. ARCO Alaska, Inc. is 12 presenting testimony today on behalf of both working interest 13 owners, itself, and Exxon Corporation. • 14 The testimony is divided into six parts: Testimony 15 related to geology of the pool will be presented by Sam Dennis; 16 Mark Ireland will describe the reservoir and plans for its 17 development; George Phillips will testify concerning the 18 surface facility and well operations that will be used to 19 develop the North Prudhoe Bay Oil Pool. He will then discuss 20 production allocation. Finally, Andy Simon will summarize and 21 conclude the testimony. 22 Each witness is prepared to respond to questions 23 concerning his testimony and related exhibits. For the 24 convenience of the Commission we have pre- submitted the text of 25 the testimony and copies of all exhibits. We have also R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 6 • 1 submitted a set of proposed rules for consideration by the 2 Commission. Unless the Commission has some question concerning 3 the legal issue or the procedures to be followed today, I am 4 prepared to turn the podium over to Mr. Dennis. 5 CHAIRMAN JOHNSTON: Just one question, 6 Mr. Worcester. Would you characterize ARCO's testimony today 7 as providing their plan of pool development to operate as 8 required by 20 AAC 25.517? 9 MR. WORCESTER: Well, 10 CHAIRMAN JOHNSTON: That would be on page 33. 11 MR. WORCESTER: I believe that you can consider 12 it to be such, yes. 13 CHAIRMAN JOHNSTON: And then in your opinion • 14 would this plan of development and operation, would it provide 15 for the prevention of waste, the protection of correlative 16 rights, and the maximum, ultimate recovery of oil and gas that 17 is prudent? 18 MR. WORCESTER: Given the fact that I'm an 19 attorney and not -- and just applying both legal standards, to 20 the best of my understanding as a lay person, I believe it does 21 satisfy those standards. 22 COMMISSIONER DOUGLASS: Thank you. 23 MR. WORCESTER: But as far as the technical 24 back -up, I think you should ask the people who are competent to 25 provide that information and with expert opinion. R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . . 7 1 CHAIRMAN JOHNSTON: Okay, thank you. And is 2 there an agreement integrating the interests of the mineral 3 interest owner? 4 MR. WORCESTER: All the tracks described in the 5 pool area are owned by ARCO and Exxon 50/50, so their interests 6 are consistent. There is currently a royalty interest that's 7 different between the two leases that are involved in the pool 8 operation. So -- and there is a participating area application 9 pending, and it's my understanding that there's been a request 10 made for the -- for ARCO and Exxon to limit the scope of that 11 request for participating are to the one tract that the current 12 well is on, and if that is done there will be an integration of 13 interest automatically as to that tract because the royalty • 14 interest and the Working Interest Owners will all be 15 coincident. My understanding is that DNR has indicated an 16 intent to grant the application for that. And if that's the 17 case, the area for which there would be the well planned and 18 production, there would be an integration of interests. The 19 pool area that's described in the application is somewhat 20 larger. 21 CHAIRMAN JOHNSTON: If we could request ARCO to 22 provide a copy of that agreement. When you do have everything 23 finalized that would be appropriate, and satisfy a condition of 24 the regulations. 25 MR. WORCESTER: Certainly we will keep the 411 R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 8 • 1 Commission updated on that. 2 CHAIRMAN JOHNSTON: Thank you. Any further 3 questions of Mr. Worcester? 4 COMMISSIONER DOUGLASS: Not at this time. 5 COMMISSIONER BABCOCK: None at this time. 6 CHAIRMAN JOHNSTON: Thank you. (Pause) And 7 before you proceed, Mr. Dennis, as you can hear, we may be 8 having our -- one of our frequent air shows in progress. So if 9 you would please speak up, I know it can be rather noisy, and 10 it may be somewhat difficult for the people in the back to hear 11 everything that's said, so we'd request that you try and 12 project your voice, if at all possible. 13 MR. DENNIS: All right. Mr. Chairman, • 14 Commissioner, ladies and gentlemen, my name is Sam Dennis. I 15 received a bachelor's of science degree in geophysical 16 engineering from the Colorado School of Mines in 1984, and have 17 been employed as an exploration geophysicist by ARCO since that 18 time. I have worked on various Alaska Projects for ARCO for 19 the last 10 years, including projects in the Bering Sea, the 20 Chukchi Sea, Cook Inlet, and the North Slope. For the last 21 2 -1/2 years I have been assigned to the Eastern Extension Group 22 which has responsibility for the North Prudhoe area. 23 My testimony today will cover the geological description 24 of the North Prudhoe Bay Oil Pool. 25 CHAIRMAN JOHNSTON: Okay. • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272-7515 ANCHORAGE, ALASKA 99501 • 9 • 1 (Commissioners confer in whispered tones) 2 CHAIRMAN JOHNSTON: Thank you, Mr. Dennis. We 3 will consider you an expert witness in this matter. 4 MR. DENNIS: To begin with, a general overview. 5 The North Prudhoe Bay Oil Pool is located north of the Prudhoe 6 Bay Field and immediately south of the Point McIntyre Field on 7 Alaska's North Slope. Exhibit II -1 shows the approximate 8 outline of the pool, which is located entirely within the 9 boundary of the Prudhoe Bay Unit. The oil and gas accumulation 10 at North Prudhoe Was first penetrated by the North Prudhoe Bay 11 State #1 Well in 1970. This well encountered 42.5 net feet of 12 hydrocarbon charged sandstone in the Sag River Formation, and 13 46 net feet of hydrocarbon charged sandstone in the Ivishak • 14 Formation. The well drill -stem tested gas and condensate from 15 the Sag River Formation at rates of 3.6 million cubic feet of 16 gas per day and 132 barrels of condensate per day. A separate 17 drill -stem test in the Ivishak produced oil at a rate of 2,727 18 barrels of oil per day. Although the tested intervals are the 19 same ones that contain the majority of the reserves in the 20 Prudhoe Bay Field, the North Prudhoe Pool can be documented as 21 a separate accumulation based on its significantly higher oil 22 gravity, 3 degrees versus 28 degrees, and an oil -water contact 23 at -9,280 subsea, approximately 300 feet deeper than the 24 oil -water contact in the Prudhoe Bay Field. 25 Following the acquisition of 3 -D seismic data in 1900, the • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274-8982 272 -7515 ANCHORAGE, ALASKA 99501 110 110 10 • 1 North Prudhoe area was re- evaluated and in 1993 North Prudhoe 2 Bay State #3 was drilled from the West Beach Drill Site into 3 the pool. This well encountered hydrocarbons in the Sag River, 4 Shublik and Ivishak formations and has produced approximately 5 948,000 barrels of oil from the Ivishak Formation to date. 6 Stratigraphy. The hydrocarbons in the North Prudhoe Bay 7 Pool occur primarily in the Ivishak Formation. The Ivishak in 8 this area consists of poorly sorted pebble conglomerates 9 COMMISSIONER BABCOCK: Excuse me, Mr. Dennis. 10 Did you say 948,000 barrels? The testimony that we have says 11 850,000. 12 MR. DENNIS: That's to date, it's 948,000. 13 That's outdated. 14 COMMISSIONER BABCOCK: Okay. All right. 15 MR. DENNIS: The Ivishak in this area consists 16 of poorly sorted pebble conglomerate and conglomeratic 17 sandstone interbedded with poorly to moderately sorted, very 18 fine to coarse - grained sandstones. Hydrocarbons also are 19 present in the Sag River and Shublik Formations, however the 20 producibility of these intervals is uncertain. 21 Exhibit II -2 is a type log for the pool from the North 22 Prudhoe Bay State #1 Well, and shows the electric log character 23 of the reservoir formations. The depth track displays subsea 24 data on the right and measured depth values on the left. Gamma 25 ray and spontaneous potential curves are displayed to the left • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 11 • 1 of the depth track and resistivity curves to the right of the 2 depth track. Density and sonic curve data are displayed in the 3 far right -hand track. As stratigraphic intervals are annotated 4 as is the interpreted oil -water contact at -9,280 feet subsea. 5 Five conventional cores were taken in the North Prudhoe 6 Bay State #1 Well in the basal Shublik and Ivishak, with a 7 total of 79.5 feet recovered. Core porosities over this 8 interval range from 15% to 26 %. Log calculations for the North 9 Prudhoe Bay State #3 Well indicate that the Ivishak has 20 feet 10 of net pay quality sandstone above the oil -water contact at 11 -9,280 feet subsea, with an average porosity of 20 %. 12 Structure. 13 CHAIRMAN JOHNSTON: Before you proceed there, • 14 Mr. Dennis, for purposes of defining the North Prudhoe Bay oil 15 accumulation, are you proposing the type log being the logs 16 from the #1 Well or the #3 Well? 17 MR. DENNIS: We would propose the #1 Well 18 primarily because it has a better sweep of logs and it's a 19 straight hole. 20 Structure. The North Prudhoe Bay Oil Pool is located in 21 an area of complex faulting as illustrated by the depth 22 structure map on the top of the Ivishak Formation, Exhibit 23 II -3. As shown on Exhibit II -3, there are two main fault 24 orientations in the area that intersect at a 90 degree angle. 25 The major faults in the North Prudhoe area are the Prudhoe Bay R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 12 1 Fault and the Point McIntyre Fault. Both are east -west 2 trending, down to the north normal faults with approximately 3 1,000 feet of throw at the Ivishak level. The area between 4 these two major faults is the location of the North Prudhoe Oil 5 Pool. As illustrated on the Ivishak structure map, the North 6 Prudhoe Pool is located on a horst block created by two 7 north /south trending normal faults. 8 The limits of the pool at North Prudhoe Bay are controlled 9 by two different structural elements. To the north, east and 10 west, different normal faults juxtapose Kingak Shale against 11 the reservoir interval, while to the south, structural dip 12 provides closure. 13 CHAIRMAN JOHNSTON: Before proceeding, do you • 14 point out on your display there the principal faults? 15 MR. DENNIS: Yes. This would be the Point 16 McIntyre fault here. The Prudhoe Bay fault that I referred to 17 would be off to the south end of the display here. The west 18 bounding fault on the accumulation would be this one, and the 19 east bounding fault would be this one. 20 Exhibit II -4 is a gross hydrocarbon isochore for the 21 Ivishak Formation for the North Prudhoe Bay Oil Pool. As 22 shown, the gross hydrocarbon column exceeds 160 feet in some 23 areas, with some portion of this hydrocarbon thickness being 24 gas. 25 CHAIRMAN JOHNSTON: Now, how did you arrive at • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 13 1 that thickness? 2 MR. DENNIS: Okay, this is a thickness from the 3 top of the Ivishak Formation to the oil -water contact at -9,280 4 feet subsea. 5 CHAIRMAN JOHNSTON: And that's principally from 6 interpretation of your 3 -D seismic? 7 MR. DENNIS: That's 3 -D seismic with the 8 available well control. 9 CHAIRMAN JOHNSTON: Right. 10 MR. DENNIS: At present, the exact position of 11 the gas -oil contact is unknown; the only constraints on the 12 gas -oil contact come from the North Prudhoe Bay State #1 well 13 where oil was tested up to -9,200 feet subsea and gas was • 14 tested down to -9,135 feet subsea. 15 Exhibit II -4 also shows the proposed North Prudhoe Bay 16 Pool Rules Area for which the North Prudhoe Bay Pool Rules will 17 apply. The Pool Rules Area covers 800 acres and includes all 18 of Section 22 and the Southwest Quarter of Section 23, Township 19 12 North, Range 14 East. 20 This concludes my testimony. I'd be happy to answer any 21 questions you might have at this time. 22 CHAIRMAN JOHNSTON: Would you take a little 23 time and describe the depositional environment that existed 24 when these logs were laid down? 25 MR. DENNIS: For the Ivishak Formation, as best R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 III • 14 • 1 we understand them, we would have what we refer to as a fan 2 delta with primarily deltaic sediments being deposited into a 3 marine environment, primarily consisting of sandstone, some 4 conglomerates. That would be for the Ivishak Formation. And 5 the Shublik and the Sag River Formation above that would be 6 shallow marine environments. On the Shublik would be -- 7 includes limestone and actually some sandstone. And then the 8 Sag River Formation includes primarily shallow marine 9 sandstone. 10 CHAIRMAN JOHNSTON: Okay. And the age of the 11 fault is relative to the depositional? 12 MR. DENNIS: Faulting is post- deposition of 13 all the rocks. IP 14 CHAIRMAN JOHNSTON: Okay, thank you, 15 Mr. Dennis. At this time we have no further questions. 16 (Pause) 17 MR. IRELAND: Good morning. My name is 18 Mark Ireland, and I work for ARCO Alaska, Incorporated. I'm 19 the director of the Development Support Group for the Greater 20 Point McIntyre area which includes responsibility for the North 21 Prudhoe Bay Reservoir. I received a BS and MS degrees in 22 petroleum and natural gas engineering from the Pennsylvania 23 State University in 1981 and 1983 respectively. I have 11 24 years of experience in the oil industry in various reservoir 25 engineering, operations engineering, and production operations 1 1 1 0 1 R & R C O U R T R E P O R T E R S 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . • 15 1 assignments in Plano, Texas; Dallas, Texas; LaFayette, 2 Louisiana; Houston, Texas; and since June of last year, the 3 Greater Point McIntyre area. 4 (Commissioners confer in whispered tones) 5 CHAIRMAN JOHNSTON: Thank you, Mr. Ireland. 6 We'll consider you an expert witness in this matter as well. 7 MR. IRELAND: Thank you. Reservoir 8 Description. To begin my testimony, I will discuss the 9 pertinent rock and fluid properties utilized in volumetric 10 calculations and recovery predictions for the North Prudhoe Bay 11 Reservoir. 12 As discussed in the preceding geologic testimony, core 13 data were obtained during the drilling in the North Prudhoe Bay • 14 State #1 in 1970, and these data confirm porosity values 15 calculated from logs. North Prudhoe Bay State #2 was not 16 cored. The net pay is estimated from openhole logs using a 17 porosity cut -off of 8 %, resulting in an average net -to -gross 18 ration of 42 %. In the North Prudhoe Bay State #3 well the Sag 19 River Formation contains 50 vertical feet of net pay in the 20 hydrocarbon column, the Shublik has 12 feet vertical of net 21 pay, and the Ivishak has 20 feet vertical of net pay above the 22 oil -water contact at -9,280 feet subsea. 23 The average porosity for the reservoir quality rock within g P Y q Y 24 the North Prudhoe Bay Pool ranges from 15 to 20% based on log 25 analysis calculations from the North Prudhoe Bay State #1 and • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 16 • 1 #3. The net pay in the Sag River Formation has an average 2 porosity of 19 %, the net pay in the shublik Formation averages 3 15% porosity; and the net pay in the Ivishak Formation has an 4 average porosity of 20 %. As previously discussed, the net pay 5 in the Sag River and Shublik Formations is believed to be gas 6 filled. 7 Permeability determined from well tests at North Prudhoe 8 Bay State #1 and #3 range from 350 to 840 millidarcies for the 9 Ivishak Formation. Water saturations determined from open -hole 10 logs range from 33% to 38 %. Exhibit III -5 is a table of the 11 average petrophysical properties for North Prudhoe Bay. 12 Fluid Properties. Reservoir pressure was determined for 13 both the North Prudhoe Bay State #1 and #3 using pressure • 14 transient analysis. The reservoir pressure measured in 1970 at 15 North Prudhoe Bay State #1 was 4,600 psi at -9,245 feet subsea. 16 The reservoir pressure measured 23 years later in 1993 at North 17 Prudhoe Bay State #3 was 3,922 psi at -9,245 feet subsea. This 18 pressure difference was unexpected and is not fully understood. 19 CHAIRMAN JOHNSTON: What's the pressure 20 currently today in the #3? 21 MR. IRELAND: Latest -- let's see. 3,800 22 pounds is our best estimate today. 23 CHAIRMAN JOHNSTON: 3,800 pounds as of today? 24 MR. IRELAND: YES. 25 CHAIRMAN JOHNSTON: Okay. On 1/24/94 you • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 410 17 • 1 reported it at 3,825. So what that tells me is that you had a 2 fairly rapid pressure decline here in the first year of 3 production, but for the last six months or so you haven't had 4 much of a pressure decline. 5 MR. IRELAND: Correct. We've seen a 6 stabilization in the pressure. 7 CHAIRMAN JOHNSTON: What would cause that? 8 MR. IRELAND: Potentially the water support 9 from lower in the Ivishak, we have 20 feet of net hydrocarbon 10 pay, but a substantial water column in the Ivishak below the 11 oil. 12 CHAIRMAN JOHNSTON: So you feel that you may 13 have water support in this reservoir? 14 MR. IRELAND: That would be one explanation. 15 CHAIRMAN JOHNSTON: And you concluded your 16 paragraph here, the pressure difference was unexpected and is 17 not fully understood. Could you speculate as to what may be 18 the cause for that pressure difference that you recorded over 19 those 23 years? 20 MR. IRELAND: One possible explanation would be 21 that perhaps through the aquifer there may be some 22 communication to the Prudhoe Bay accumulation or some other 23 source of pressure withdrawal. That would be the most obvious 24 answer that I can think of. 25 CHAIRMAN JOHNSTON: And are you fairly • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272-7515 ANCHORAGE, ALASKA 99501 • 18 1 confident that the measurement taken in the #1 in 1970 was an 2 accurate measurement? 3 MR. IRELAND: To the best of our knowledge. 4 CHAIRMAN JOHNSTON: Okay. Please continue. 5 MR. IRELAND: Fluid Properties -- no. Downhole 6 reservoir oil samples were collected from North Prudhoe Bay 7 State #3 and pressure - volume- temperature analysis was performed 8 on the samples. The collected oil samples have a measured 9 gravity of 35 degrees API, bubble -point of 3,870 psi, solution 10 GOR of 923 standard cubic feet per stock tank barrel, and a 11 formation volume factor of 1.48 reservoir barrels per stock 12 tank barrel. Water properties used for calculations are 13 estimated using standard correlations. Exhibit III -6 is a • 14 table of the fluid properties used in oil -in -place 15 calculations. 16 CHAIRMAN JOHNSTON: The properties that you're 17 reporting here, are these properties that have initial 18 conditions or conditions as they exist today? 19 MR. IRELAND: They should be valid for both. 20 The pressure has obviously declined, but 21 CHAIRMAN JOHNSTON: How about GOR? 22 MR. IRELAND: The solution gas relationship 23 should not be changed. If we are producing free gas, obviously 24 that is an impact as well, as we believe. 25 CHAIRMAN JOHNSTON: Do you know what your GOR • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 -0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 19 • 1 is today? 2 MR. IRELAND: Currently our last test -- let's 3 see, the very most recent one which wasn't included, our GOR 4 was just over 3,000 -- about 3,100. 5 CHAIRMAN JOHNSTON: 3,100. Again, on 3/24/94 6 you reported, I believe, 4,072 7 MR. IRELAND: Correct. 8 CHAIRMAN JOHNSTON: as a GOR. 9 MR. IRELAND: Yes, it's varied quite a bit. 10 We've had slugging problems in the well, both water, oil and 11 gas being produced, and has not been -- as you can see from the 12 list of the GORs, the oil rates, have not been a consistent, 13 smooth type of performance. 14 CHAIRMAN JOHNSTON: What was that GOR again? 15 MR. IRELAND: The -- on August 2 of '94, or the 16 most recent one, excuse me, August 19 of '94 was 2,881. 17 CHAIRMAN JOHNSTON: 2,891? 18 MR. IRELAND: 81. 19 CHAIRMAN JOHNSTON: 81. 20 MR. IRELAND: With an oil rate of 2,691 barrels 21 per day, and a water rate of 1,932 barrels per day. 22 CHAIRMAN JOHNSTON: Okay. 23 MR. IRELAND: Geochemical analysis of oil from 24 the North Prudhoe Bay State #3 was compared to similar data 25 from the IPA oil to show evidence of reservoir separation. R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . • 20 • 1 North Prudhoe Bay State #3 oil has a gravity of 35 degrees API 2 and 0.4% sulfur compared to IPA oils which have a gravity 3 around 29 degrees API and a sulfur content of around 1 %. The 4 North Prudhoe Bay State #3 oil is from a greater depth than the 5 IPA oil, yet has a higher API gravity and lower sulfur content. 6 This relationship is inconsistent with gravity segregation in a 7 well - connected reservoir. The oil -water contact in the North 8 Prudhoe Bay Oil Pool is also 200 feet lower than the oil -water 9 contact in the IPA. These data indicate that North Prudhoe Bay 10 and the IPA are separate oil pools. 11 CHAIRMAN JOHNSTON: Out of curiosity, what is 12 the API on the West Beach Well? 13 MR. IRELAND: Off -hand, I'm not sure. Let me • 14 check with -- 25. 15 CHAIRMAN JOHNSTON: 25 API. And would it have 16 a similarly low sulfur content or would it more compare with 17 the Prudhoe Bay Oil? 18 MR. IRELAND: I'm not sure if we've got that 19 information. 20 CHAIRMAN JOHNSTON: Thank you. 21 MR. IRELAND: Well Tests. Three drill -stem 22 tests were successfully carried out in North Prudhoe Bay State 23 #1. The first was a closed chamber test of the Ivishak 24 Formation recovering 23 barrels of oil. The second test 25 produced oil from the Ivishak and lower Shublik Formations at • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 21 1 the rate of 2,727 barrels of oil per day and established a 2 productivity index of 10 barrels of oil per day per psi, and a 3 permeability from 350 to 8,040 millidarcies. The third well 4 drill -stem test recovered gas and condensate from the Sag River 5 Formation at rates 3.6 million cubic -feet of gas per day and 6 132 barrels of condensate per day. 7 COMMISSIONER BABCOCK: Mr. Ireland, when were 8 those tests? 9 MR. IRELAND: That was in 1970. 10 COMMISSIONER BABCOCK: All three of them? 11 MR. IRELAND: Yes. 12 CHAIRMAN JOHNSTON: Now you have not done any 13 further testing in the #1 well since then, right? • 14 MR. IRELAND: Correct. 15 CHAIRMAN JOHNSTON: Okay. 16 MR. IRELAND: In the North Prudhoe Bay State 17 #3 only the top 20 feet of the Ivishak Formation was 18 perforated. The initial rate from this well was 9, 115 barrels 19 of oil per day and no water. The permeability as determined 20 from pressure transient analysis is 590 millidarcies. The 21 calculated productivity index was 8.5 barrels of oil per day 22 per psi. North Prudhoe Bay State #3 has been on production 23 since October 13, 1993, and during the last well test, the well 24 was -- I mentioned previously -- the very most recent well test 25 was producing approximately 2,691 barrels of oil per day, 1,932 R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 22 • 1 barrels of water per day at a GOR of 2,881. 2 CHAIRMAN JOHNSTON: Now, earlier Mr. Dennis 3 testified that, I believe, 940,000 barrels of oil had been 4 produced from the North Prudhoe Bay State #3 Well. Is that 5 since October 13, 1993? 6 MR. IRELAND: Yes. Yes, that's the cumulative 7 to date is those total numbers are 948,000 barrels of oil, 8 258,000 barrels of water, and 2.9 bcf of gas. 9 Exhibit III -7 is a summary of the well test information 10 for this well. 11 (Pause) 12 Hydrocarbons in Place. 13 CHAIRMAN JOHNSTON: The fluctuating rate of • 14 production, beginning say this year to the current date, is 15 that explained because of the operational nature of the -- or 16 is it explained by the nature of production up there in that 17 they have to shut down production in order to test the West 18 Beach and then you bring on the North Prudhoe Bay State or is 19 there some real problems producing this particular reservoir? 20 MR. IRELAND: I think it's more related to the 21 hydraulics in this well and problems with the -- you can see 22 the increasing water production with time. 23 Hydrocarbons in Place. Estimates of hydrocarbons -in -place 24 for the North Prudhoe Bay Pool reflect the well control, 25 structural interpretation, rock and fluid properties and rock • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274-8982 272 -7515 ANCHORAGE, ALASKA 99501 • 23 • 1 and fluid properties is outlined in previous testimony. This 2 data have been integrated into a fieldwide 3 hydrocarbons -in -place calculation. Because only two wells have 4 penetrated the reservoir and neither has shown a gas -oil 5 contact that can be identified by conventional log techniques, 6 the original oil -in -place is uncertain. However, the Sag River 7 was tested in the North Prudhoe Bay State #1 and produced only 8 gas and condensate. The Shublik has not been tested, but gas 9 production and production logs from the North Prudhoe Bay 10 State #3 indicate the Shublik contains gas. On this evidence, 11 we have assumed that the Sag River and Shublik Formations are 12 gas - filled. The result of this work reflects an estimated 13 original oil -in -place in the Ivishak Formation of 12 million • 14 stock tank barrels. The free gas volume if 31 billion standard 15 cubic feet. 16 Given the similarity of the oil produced, the test rates, 17 and the water -oil contacts in North Prudhoe Bay State #1 and 18 #3, it is reasonable to assume that they are part of the same 19 accumulation as mapped geologically. I will now review our 20 development plan. 21 CHAIRMAN JOHNSTON: Before you proceed with 22 your Development Plans, how did you arrive at the 12 million 23 stock tank barrels? In other words, what are the parameters 24 that you used to arrive at that figure? 25 MR. IRELAND: The -- utilizing the structural • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 24 • 1 information that Sam Dennis previously presented, basically 2 integrating the volume -- bulk volume of the net sand over the 3 Ivishak, and applying the parameters from Exhibit III -5 for 4 porosity, water saturation, and doing a volumetric calculation 5 on that basis. 6 CHAIRMAN JOHNSTON: In terms of your net 7 reservoir thickness what did you use as a number to represent 8 that net reservoir thickness in order to arrive at this volume? 9 MR. IRELAND: It was integrated over the map 10 that Sam showed previously. 11 CHAIRMAN JOHNSTON: So it would reflect 12 MR. IRELAND: Approximately 20 feet. 13 CHAIRMAN JOHNSTON: So that averages out at 20 4110 14 feet, realizing that you have an estimate in some portions of 15 the reservoir of 160 feet of pay? 16 MR. IRELAND: Well, some of that being -- most 17 of that being gas in some sections of the reservoir. I believe 18 the 160 included the Sag and Shublik; is that right? 19 MR. DENNIS: This is Sam Dennis. The way we 20 did it here was take that structure map, take the -- both 21 volumes of the Ivishak above the oil -water contact, and then we 22 assumed a gas oil - contact halfway between the gas down to and 23 the oil up to number, and that was, we felt, the best estimate 24 to get a volumetric to account for the gas, and then in that 25 volume that was calculated, we then applied the numbers that 1 R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 25 • 1 Mark's showing on the screen there. 2 CHAIRMAN JOHNSTON: You applied that evenly 3 across the areal distribution of 4 MR. DENNIS: Yes, for the porosity and the 5 water saturation end of formation volume factor. 6 CHAIRMAN JOHNSTON: Okay. Thank you. That was 7 what I was trying to understand. Now one other point of 8 confusion. In a report that we received I have written down 9 here March 29, '94, you referred to block 1, and block 1 10 through 3. Could you describe what you meant by block 1 and -- 11 I assume that you've broken the reservoir up into three 12 different blocks. 13 MR. IRELAND: I think maybe Sam could address • 14 that question. 15 MR. DENNIS: This is Sam Dennis again. 16 CHAIRMAN JOHNSTON: Why don't you come up and 17 use the microphone so we can make sure that we get you on the 18 transcript. 19 MR. DENNIS: In the original mapping after we 20 initially drilled this well, there's some belief that this 21 accumulation might extend further to the east than shown on the 22 current application. At that point we had broken into what we 23 called blocks 1, 2 and 3, and block 1 was the block that is now 24 being included for the pool rules. Subsequent work is -- as 25 we've worked this more and more, has cast some doubt on whether • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . • 26 • 1 this accumulation does extend further to the east into what we 2 had referred to as block 2 and 3, and so at the present time 3 when you -- what we are applying for is block 1 only. And 4 blocks 2 and 3 are -- there's a lot of doubt as to whether 5 those are included in this pool. 6 CHAIRMAN JOHNSTON: Okay. That same document 7 showed that at least at that time you felt that block 1 had a 8 range of hydrocarbon volumes, oil in place being anywhere from 9 11 to 24 million stock tank barrels, and 18 to 32 billion 10 standard cubic feet of gas. What has changed today for you to 11 be more conservative now in these estimates? 12 MR. DENNIS: I think the original volumes may 13 have included oil in place in the Shublik and Sag River • 14 Formations. The other thing, the change was increase in gas 15 production -- I mean it was more conservative as to where we 16 thought the gas -oil contact probably was. 17 CHAIRMAN JOHNSTON: Okay. But your information 18 in March doesn't indicate in what -- whether you considered the 19 Shublik or the Sag River in terms of your oil -in -place 20 calculation, but at that time did you feel that there was oil 21 in the Sag River in the Shublik? 22 MR. DENNIS: I think around the edges there are 23 almost certainly in places here that will be oil in the Sag 24 River. The question we've got is if it's there is it 25 producible. At this point we have no information that says it • R & R C O U R T R E P O R T E R S 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 27 1 is, and that's our major concern with the Sag River. 2 CHAIRMAN JOHNSTON: Okay. I have no further 3 questions at this time. Thank you. 4 MR. IRELAND: Development Plans. Drilling. 5 Any further development of the North Prudhoe Bay Pool is 6 uncertain at this time. Our immediate plans are to continue 7 producing North Prudhoe Bay State #3 through the permanent 8 production line from the West Beach pad to Lisburne Drill Site 9 L1. Initially, all produced gas will be injected into the 10 Lisburne reservoir since no gas injection facilities are 11 currently available at the West Beach pad. With continued 12 production data, we hope to refine our oil -in -place estimates 13 and evaluate further potential. Additional drilling is • 14 dependent on estimated reservoir size and economic conditions. 15 Off -Take Rate. Peak off -take rates may reach up to 10,000 16 barrels per day due to the high productivity of the Ivishak 17 sands if additional wells are drilled. 18 CHAIRMAN JOHNSTON: And how many wells would 19 that be? 20 MR. MARSHALL: Again, further development is 21 uncertain. The #3 well by itself came on initially at 9,000 22 barrels per day, so one additional well potentially could bring 23 the field rate up to 10,000 wells per day. 24 Well Spacing. The spacing requirements for North Prudhoe 25 Bay will be consistent with the statewide regulations • R & R C O U R T R E P O R T E R S 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 28 • 1 specifying 160 -acre drilling units. The Commission will be 2 approached if tighter spacing is necessary in the future. 3 This concludes my testimony. If there's no further 4 questions, George Phillips will not present a description of 5 the North Prudhoe Bay facilities. 6 COMMISSIONER DOUGLASS: Before you go, do you 7 have an estimate of your recovery factor? 8 MR. IRELAND: Probably looking at about 9 somewhere in the 15 to 20% range. 10 COMMISSIONER DOUGLASS: That's just primary 11 recovery, gas cap expansion. 12 MR. IRELAND: And whatever support we'll get 13 from aquifer expansion as well. • 14 CHAIRMAN JOHNSTON: At this time does ARCO have 15 any plans for an FOR program for the accumulation? 16 MR. IRELAND: No, we don't at this time. 17 CHAIRMAN JOHNSTON: Okay. What would those 18 plans hinge on? 19 MR. IRELAND: Essentially, we need to have a 20 larger oil -in -place target to go after, and more than likely 21 more favorable economic conditions, similar to the requirements 22 for further drilling. We would essentially need another well 23 in the field, more than likely. 24 CHAIRMAN JOHNSTON: Okay, so even though you're 25 requesting 160 -acre well spacing, you really do not envision • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . • 29 • 1 using 160 -acre well spacing; is that correct? 2 MR. IRELAND: In our most likely case, that's 3 correct. 4 CHAIRMAN JOHNSTON: Okay. Thank you. 5 MR. PHILLIPS: Good morning. My name is 6 George Phillips. I'm am currently working for ARCO Alaska, 7 Inc., as a team leader in the field of Operations Group for the 8 Greater Point McIntyre Engineering Department. I received a 9 bachelor of science degree in chemical engineering from 10 Oklahoma State University in 1977. I have 17 years of 11 experience in the petroleum industry working operations and 12 reservoir engineering in Texas, offshore in Louisiana, and 13 Alaska. I've been working in Alaska since 1984 and have been • 14 working Point McIntyre, West Beach and North Prudhoe 15 development since June 1992. 16 (Commissioners confer in whispered tones) 17 CHAIRMAN JOHNSTON: Thank you, Mr. Phillips. 18 We will consider you an expert witness in this matter. 19 MR. PHILLIPS: Thank you. 20 CHAIRMAN JOHNSTON: You may proceed. 21 MR. PHILLIPS: My testimony today will include 22 a brief description of the North Prudhoe Bay facilities, well 23 operations, and production allocation methodology. 24 General Overview. The North Prudhoe Bay accumulation is 25 part of the Prudhoe Bay Unit and will be operated under the 411) R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 30 410 1 Prudhoe Bay Operating Agreement. Current plans are to develop 2 North Prudhoe Bay from the West Beach pad. Existing facilities 3 include a drill site and the 6" production pipeline. North 4 Prudhoe Bay fluids will be commingled at surface with 5 West Beach fluids and produced into Lisburne Drill Li where it 6 will be commingled with Lisburne and Point McIntyre fluids 7 prior to processing at the existing LPC and subsequent shipment 8 to the Alyeska Pump Station Number 1. North Prudhoe Bay will 9 maximize use of the existing Initial Participating 10 Area /Lisburne Participating Area, the IPA /LPA, infrastructure. 11 This is shown on Exhibit 8. This will maximize the amount of 12 economic reserves and minimize environmental impacts. 13 Exhibit IV -9 is an area map showing the existing Lisburne • 14 Drill Site Li and West Beach facilities that will be utilized. 15 Initially one well, North Prudhoe Bay State #3, will be 16 produced via the existing 6" production pipeline. The initial 17 depletion plan calls for continuation of the long -term primary 18 production test of North Prudhoe Bay State #3. Information 19 gathered from this test, as well as information from the 20 ongoing test at West Beach #4 will be used to determine whether 21 secondary recovery methods will be necessary or viable for one 22 or both of these developments. 23 CHAIRMAN JOHNSTON: Given that statement, when 24 will you know whether a -- either this accumulation or the 25 West Beach accumulation is suitable for secondary recovery R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . . 31 • 1 methods? 2 MR. PHILLIPS: I really can't give you an 3 answer. It's an unknown question for us also. Basically we'll 4 continue to look at it, and it's depending on economic climate 5 and what we learn from that data. At this stage things don't 6 look good, but we're always positive. 7 CHAIRMAN JOHNSTON: And what are some of those 8 factors that do not look good? 9 MR. PHILLIPS: Right now the oil -in -place in 10 both projects don't tell us that we have enough to go out and 11 shoot for a larger development in the current economic prices. 12 Drill Sites, Pads and Roads. Our current plans are to 13 continue to develop the development of North Prudhoe Bay from • 14 the West Beach Pad. Sharing of existing infrastructure and the 15 associated economies of scale are necessary to justify 16 continued production and the potential for additional 17 development. The drill site location has been selected to take 18 advantage of existing gravel placement and the existing 19 facilities in place at West Beach. No gravel additions are 20 envisioned for development of either West Beach or North 21 Prudhoe Bay. 22 Pipelines. Production of the North Prudhoe Bay State #3. 23 Production from North Prudhoe Bay is commingled with West Beach 24 production and carried via the existing 6 ", multiphase 25 production line from the West Beach drill site to Lisburne • R & R C O U R T R E P O R T E R S 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 32 • 1 Drill Site L1. The production line travels parallel with the 2 West Dock road to Drill Site L1 and consists of approximately 3 10,300 of linear feet of 6" pipe. New vertical support 4 members, VSMs, in addition to existing Lisburne IPA VSMs were 5 used to install the 6" line. The VSMs were designed to 6 accommodate any further expansion of West Beach or North 7 Prudhoe Bay. 8 Long -term Production. In the event that additional West 9 Beach or North Prudhoe Bay wells are drilled, upgrades in 10 facilities may be required. A low end case, primary recovery 11 only, with no additional wells, would require -- would continue 12 to operate under the existing conditions. An intermediate case 13 could include additional wells, and would require either the • 14 installation of a second production /test line from the 15 West Beach pad to Drill Site L1 or the installation of 16 production metering. An upside case could require the 17 installation of a 12" production line, a 6: gas injection line, 18 conversion of the existing 6: production line for waterflood, 19 and installation of a test line or onsite production metering. 20 In all cases, the existing drill site layout and VSMs could 21 accommodate the new wells and additional flow lines. Some new 22 VSMs may be required for routing to a gas injection tie -in 23 point. 24 CHAIRMAN JOHNSTON: Before proceeding, you used 25 several general terms; a low end case, intermediate case and II • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 33 • 1 upside case. Can you give us some better feel for what those 2 cases may be? 3 MR. PHILLIPS: I can't at this time 'cause it's 4 -- it's basically exist as you are, can we go out and do 5 something more, and can we basically go out and justify going 6 to a full secondary recovery type operation. 7 CHAIRMAN JOHNSTON: And so those cases would be 8 in large part dependent upon the price of crude oil available 9 today, relative to price of 10 MR. PHILLIPS: The price of crude oil and the 11 size of the accumulation that we have. 12 CHAIRMAN JOHNSTON: And the size of the 13 accumulation. What effort -- how is that size of the 14 accumulation going to change? Is it through additional 15 drilling which will only be done in the event that oil prices 16 go up or -- how will ARCO make these decisions, I guess? 17 MR. PHILLIPS: A large part will be on price. 18 Again, as we get more information, we may refine our estimates. 19 At this stage though that's basically the two things we're 20 looking at. 21 CHAIRMAN JOHNSTON: So the upside case would 22 depend greatly on additional drilling which hinges on the price 23 of crude oil, and through additional drilling you may find a 24 larger target area than what is currently available to you? 25 MR. PHILLIPS: That's always a potential. R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . • 34 • 1 Drill Site Facilities and Operations. Production Testing 2 of North Prudhoe Bay State #3 or West Beach #4. Both North 3 Prudhoe Bay State #3 and West Beach #4 are commingled and 4 produced into the Lisburne Drill Site L1 facilities via the 6" 5 production line. All well control and testing functions at L1 6 are performed manually by an L1 operator, with the exception of 7 the well safety shut -in systems which are automatic. Data 8 gathering at L1 will be both a manual and automatic function. 9 The Lisburne Data Gathering System, LDGS, continuously monitors 10 the flowing status, pressure, and temperatures of the producing 11 wells at L1. This date will be under the drill site operator's 12 supervision through his monitoring station at L1. 13 Lisburne Production Center, LPC. No modifications to the 14 LPC are planned specifically for North Prudhoe Bay State #3. 15 However, facility modifications are planned for Point McIntyre. 16 These modifications focus on liquid handling expansion and 17 produced water handling expansion. The LPC was originally 18 built to process a nominal oil rate of 100,000 barrels of oil a 19 day and a gas rate of 440 million cubic feet a day, and a 20 produced water rate of 25,000 barrels a day. 21 Production from Lisburne, Point McIntyre, Niakuk, 22 West Beach and North Prudhoe Bay reservoirs is expected to 23 exceed existing LPC capacity long -term. The LPC will operate 24 with the intent of maximizing total production from the various 25 contributing fields. With the modifications and some • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 _ J . • 35 • 1 debottlenecking that has been done, the LPC is now expected to 2 process 150,000 barrels of oil a day and 200,000 barrels of 3 water a day. No modifications are planned at this time for the 4 LPC gas handling system. Currently as injection compression 5 capacity is 460 million cubic feet a day, based on a yearly 6 average. A produced gas stream is processed through the NGL 7 plant to recover NGLs upstream of the injection compressors. 8 The NGLS are then blended with oil up to a vapor pressure 9 specification and shipped to Pump Station Number 1. The NGL 10 plant can normally handle up to 460 million cubic feet a day. 11 Could I get some water, please? 12 CHAIRMAN JOHNSTON: We need to get a glass. 13 COMMISSIONER BABCOCK: Could we take a 14 five - minutes break? 15 CHAIRMAN JOHNSTON: Yes, I think that would be 16 appropriate. We'll take a five - minute break at this time and 17 get some glasses up here. Thank you. 18 (Off record) 19 (On record) 20 CHAIRMAN JOHNSTON: I'd like to go back on 21 record. We've just taken a short break and Mr. Phillips had 22 been testifying. Do you have any further testimony at this 23 time? 24 MR. PHILLIPS: Yes, I do. 25 CHAIRMAN JOHNSTON: Okay. R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 36 • 1 MR. PHILLIPS: At this stage I'd like to go 2 into the Well Operations part of my testimony. 3 Drilling and Well Design. Any additional North Prudhoe 4 Bay wells will be directionally drilled from a gravel pad 5 utilizing drilling procedures, well designs, and casing and 6 cementing programs similar to those currently used in other 7 North Slope fields or the proposed tubingless completions. 8 A 20" conductor casing will be set 75 feet below pad level 9 and cemented to surface. It may be necessary to drive or jet 10 the 30" structural casing to a sufficient depth below the pad 11 level to ensure support of drilling fluid returns to the 12 surface while drilling hole for the conductor casing. 13 Consideration will be given to driving or jetting the 20" • 14 conductor as an alternative setting method. A diverter system 15 compliant with the Commission requirements will be installed on 16 the conductor. 17 Surface holes will be drilled no deeper than 5,000' TVD, 18 true vertical depth. This setting depth provides sufficient 19 kick tolerance and allows the angle build portions of high 20 departure wells to be cased. No hydrocarbons have been 21 encountered to this depth in previous North Prudhoe Bay or West 22 Beach wells drilled from the West Beach pad. Cementing and 23 casing requirements similar to other North Slope fields should 24 be adopted for the North Prudhoe Bay. 25 The casing head and 5,000 psi blowout preventor stack will • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . . 37 • 1 be installed and tested consistent with Commission 2 requirements. Production holes will be drilled from surface 3 casing, through the Ivishak Formation, allowing enough rathole 4 to facilitate logging. Production casing will be set and 5 cemented. Intermediate casings and production liners will be 6 used to achieve specific completion objectives or to provide 7 sufficient contingency in mechanically more difficult wells 8 such as the high departure wells. 9 Well Design and Completions. Additional wells may be 10 justified dependent upon results from the long -term production 11 test, improved well designs including lower costs, and 12 encouraging economics of secondary recovery operations. 13 Additional wells will be high departure, ranging from 8,500 14 feet measured depth to 15,000 feet measured depth. Typical 15 completions could utilize 3 -1/2" tubing with potential for 16 4 -1/2" tubing in the higher productivity areas. In general, 17 North Prudhoe Bay wells will be utilized -- will either utilize 18 a slimhole, ultra slimhole design or potentially tubingless 19 completion, if accepted. 20 Let me go ahead and turn the overhead on. 21 Slimhole designs will consist of 10 -3/4" surface casing, 22 7 -5/8" production or intermediate casing with a 5 -1/2" liner 23 for the higher stepout wells. That overhead there is the one 24 without the 5 -1/2" liner, which is Exhibit V -10, and Exhibit 25 V -11 is the same style completion except we now have the 5 -1/2" R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 38 • 1 liner in there. Slimhole designs will accommodate both 3 -1/2" 2 and 4 -1/2" tubing. The ultra slimhole designs, which will be 3 Exhibit V -12, will consist of 9 -5/8" surface pipe, 7" 4 production string, and 3 -1/2" tubing. 5 Wells drilled at North Prudhoe Bay are expected to 6 penetrate from one of the three foll- -- from one to three of 7 the following zones: The Ivishak, Shublik, and Sag River, each 8 having the potential to contain hydrocarbons. All completions 9 are currently envisioned to be either a single packer, single 10 selective, or a tubingless completion depending on the number 11 of productive zones intersected. Multi -zone wells which have 12 selected single completions will have the capability to isolate 13 the zones via mandrels or ported sleeves. Again, these were • 14 shown V -10, 11, and 12. Additionally, I have included Exhibit 15 V -13, a schematic of our existing North Prudhoe State #3 Well. 16 And I'll comment, this one has been updated from the one 17 that's in the pre -file package to include the additional curves 18 that we've added to Sag. 19 CHAIRMAN JOHNSTON: The Sag appears there -- 20 shown as 13 there? 21 MR. PHILLIPS: Yes. The knot shown on the 22 schematic is separated interval where they're actually 23 separated from the Sadlerochit. 24 Approval is requested from the Commission to allow the 25 flexibility of running tubingless completions at North Prudhoe 1 1/ 1 R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 © • 39 • 1 Bay. Significant cost savings associated with tubingless 2 completions could provide the economic hurdle to justify 3 additional drilling and recovery of marginal reserves in this 4 field. One example of a tubingless completion for a producer 5 is shown in Exhibit V -14. If artificial lift is needed, it can 6 be accomplished by running -- let met get that up here -- it 7 can be accomplished by (sneezes) -- excuse me -- by running an 8 annular flow single point or multiple point coil tubing string 9 as shown in Exhibits V -15 -- here as a single point, and V -15 10 -- or excuse me, 16, as a multi - point. The annular flow design 11 would incorporate an annular surface (sic) safety valve, SSSV. 12 The completions can be safely designed for either injection or 13 production capability. The design includes a standard surface • 14 hole drilled to approximately 4,000 feet and cased with 9 -5/8" 15 casing. A 7 -7/8" or 8 -1/2" hole would be drilled to TD and 16 completed with 3 -1/2" tubing or 5 -1/2" -- or up to 5 -1/2" 17 tubing cemented in place. Profiles could be installed via 18 tubing or wireline. 19 CHAIRMAN JOHNSTON: You've just gone through a 20 fairly substantive discussion on possible wells to be drilled. 21 I have a sense that these are very speculative at this 22 juncture. 23 MR. PHILLIPS: That's correct. 24 CHAIRMAN JOHNSTON: That you want to be able to 25 have the flexibility to drill these wells in this configuration R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 40 • 1 in the event that ARCO decides to drill additional wells to the 2 accumulation. 3 MR. PHILLIPS: That's absolutely correct. It's 4 a -- again, getting back to the economic nature of the fields, 5 we're looking for ways to develop it, at the same time maintain 6 safe wells, and that's what we're looking at, tubingless 7 completions. 8 CHAIRMAN JOHNSTON: In terms of the tubingless 9 completion are the wells that would be drilled to the North 10 Prudhoe Bay State accumulation, would they be capable of 11 unassisted flow to the surface? 12 MR. PHILLIPS: Initially, yes. 13 CHAIRMAN JOHNSTON: Initially, yes. For how • 14 long a period would they be capable of unassisted flow? 15 MR. PHILLIPS: I don't have a good feel for 16 that. I can give you an example of our existing well 17 CHAIRMAN JOHNSTON: Please. 18 MR. PHILLIPS: right now. That well, 19 when w e first brought it on came on at high rates, 9 g g 9,000 , 20 barrels a day, and flung into our Subsequent system pressure. Subse Y. g Y P q 21 to that is that wells -- you were looking at the plot, the 22 rates were going down with the watercut coming up. That well 23 did load up and die. At that point we tried to flow that well 24 to a tank, and it would not flow to a tank at that condition. 25 That was when we then went ahead and added the purse to the • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 41 41/1 1 Sag. That well will now flow to a tank. We still have not got 2 it yet unloaded into the system. We haven't been able to get 3 it up to a point that where we can get into the 500 -pound 4 system pressure, but it will now flow to a tank, so float 5 atmospheric. So it's these wells -- as you get the higher 6 watercuts will load up and die on you. 7 CHAIRMAN JOHNSTON: The tubingless completion, 8 given the fact that these wells may be capable of unassisted 9 flow to the surface would require an exemption to Commission 10 regulation, specifically 20 AAC 25.200, Paragraph D. 11 MR. PHILLIPS: In terms of subsurface safety 12 valve? 13 CHAIRMAN JOHNSTON: No, in terms of -- it says • 14 all wells capable of unassisted flow must be completed with 15 downhole production equipment consisting of suitable tubing and 16 a packer. 17 MR. PHILLIPS: Yes. 18 CHAIRMAN JOHNSTON: All right. And the 19 significant cost savings associated with a tubingless 20 completion, could you elaborate on that a little bit more? 21 MR. PHILLIPS: We've looked at various types of 22 wells, and depending on whether you have to go to a cold tubing 23 lift string or not, the range of numbers that we've seen can be 24 as low as a savings of potentially zero if you made the wrong 25 mistake or actually more in some cases, but you could see 411 R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 42 • 1 savings in the range of 200,000 at the low end, up to a maximum 2 savings maybe of about a half million dollars at some of the 3 wells that we've looked at. 4 CHAIRMAN JOHNSTON: And do you describe what 5 may be the potential risk that would be associated with 6 tubingless completion? 7 MR. PHILLIPS: The risk that we see at this 8 stage is really -- like I said, in terms if you've made the 9 wrong decision in terms of cost that it's very similar to a 10 slimhole design where you're going to go ahead and drill your 11 production hole to TD and run casing as soon as that casing's 12 in place. Now you're doing the same thing and you're cementing 13 your tubing in place. Now the questions you run into is do you 14 get casing down or do you get tubing down, so you may get to a 15 point that you have to basically backup and go ahead and pull 16 that out and fall back into more of a slimhole type design. So 17 you end up basically spending more money. 18 CHAIRMAN JOHNSTON: Does ARCO consider this a 19 onshore development or an offshore development? 20 MR. PHILLIPS: We consider West Beach /North 21 Prudhoe onshore. 22 CHAIRMAN JOHNSTON: Onshore. So even though it 23 is onshore, you are -- and this is getting a little bit ahead 24 of us, since you're going into this here later on, but you did 25 mention it. Even though it is onshore you are desiring the R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274-8982 272 -7515 ANCHORAGE, ALASKA 99501 410 411 43 410 1 installation of subsurface safety valves? 2 MR. PHILLIPS: Yes, we're still recommending 3 ranks of service safety valves, consistent with our other 4 fields out in the greater Point Mac area and Prudhoe. 5 COMMISSIONER BABCOCK: Are you asking the 6 Commission to require you to do that or are you just stating 7 that that's your plan? 8 MR. PHILLIPS: It is our plan, and it's been 9 consistent with our field rules and the rest of the greater 10 Point Mac area to go ahead and have it as part of the field 11 rules. 12 CHAIRMAN JOHNSTON: We do have an application 13 pending with the Commission at this time for, I believe, the • 14 Kuparuk River that would request a removal of that requirement 15 for subsurface safety valves. I'm wondering why we would 16 consider the installation of subsurface safety valves in this 17 particular case and yet the removal in Kuparuk. Is there 18 anything different there that we should be aware of? 19 MR. PHILLIPS: Each field will be a little bit 20 different. I imagine we would want to look at that requirement 21 on a field by field basis. But at this stage we are 22 essentially a one well field, both West Beach and North 23 Prudhoe, both wells are there with subsurface safety valves. 24 We did not see it as an issue here. 25 CHAIRMAN JOHNSTON: Basically I'd note that • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 44 • 1 this requirement is consistent with the requirements that have 2 been imposed in additional fields elsewhere in the North Slope, 3 but that we have had just recently received an application for 4 removal of the subsurface safety valves in at least the Kuparuk 5 field, and the Commission has not made a decision in that 6 matter at this time. So please proceed. 7 MR. PHILLIPS: Subsurface Safety Valves. 8 Consistent with historic North Slope practice, a fail -safe 9 automatic subsurface safety valve, SSSV, will be run in all 10 wells capable of unassisted flow of hydrocarbons. Usually, 11 subsurface safety valves have been installed below the base of 12 the permafrost at approximately 2,000 feet measured depth and 13 both wireline and tubing retrievable valves have been • 14 successfully used on the North Slope. North Prudhoe Bay State 15 #3 has a tubing retrievable SSSV installed at 2,005' measured 16 depth. Approval is requested to allow the subsurface safety 17 valve installation depths of 300 feet or greater below ground 18 level. A shallower valve depth will allow greater well 19 planning flexibility without sacrificing well safety. 20 Advantages include less run time and better reliability in 21 wireline run valves, especially in the shallow kickoff /high 22 departure wells, less run time and quicker access in tubingless 23 completions potentially, and a cost savings on all completions 24 associated with less control line requirements. 25 Additionally, approval is requested for the temporary • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272-7515 ANCHORAGE, ALASKA 99501 i ! 45 • 1 removal of subsurface safety valves from individual wells for 2 routine well work operations or repair, not to exceed 30 days 3 30 days without specific notice to or authorization by the 4 Commission. This should minimize administrative burden for 5 both the Commission and the Operator. A list of all of 6 deactivated safety systems, associated dates, and reasons for 7 deactivation will be maintained and made available upon 8 request. We are also requesting that under special 9 circumstances the Commission be able to administratively 10 approve the waiver of subsurface safety valves on individual 11 wells to allow the use of innovative technology or as otherwise 12 justified. 13 Reservoir Surveillance Program. It is necessary to 14 acquire data in order to monitor reservoir performance, define 15 reservoir properties, allocate production between commingled 16 oil pools at the LPC, and provide the basis for effective 17 reservoir management. An isobar map of reservoir pressures 18 will be maintained with pressures reported at the common datum 19 elevation of 9,245' TVD subsea. Initial static reservoir 20 pressures will be measured at each well prior to regular 21 production and a minimum of one pressure survey will be taken 22 annually for each producing governmental section. This will be 23 done by either a pressure buildup, pressure falloff, Repeat 24 Formation Tester, RFT, or simply measuring the bottom -hole 25 pressure after the well has been shut in for an extended • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 46 • 1 period. All pressure surveys will be reported annually. 2 Production logs which may include flow meters, temperature 3 logs, or other industry - proven downhole diagnostic tools, may 4 be periodically run to help determine reservoir performance. 5 COMMISSIONER BABCOCK: What is the pressure in 6 #3? 7 MR. PHILLIPS: I believe Mark had that number 8 earlier as 3,800. 9 COMMISSIONER BABCOCK: And when was that test 10 of the 3,800? 11 MR. IRELAND: A few weeks ago, based on a 12 well 13 MR. PHILLIPS: Yeah, we've basically just • 14 verified that again based on -- the well's currently unable to 15 flow, and it's shut in and we can see that same fluid level, so 16 we've basically been able to verify we're in that same range, 17 beginning with the accuracy of the fluid level type 18 measurement. 19 COMMISSIONER BABCOCK: And what was it when you 20 started in #3? 21 MR. PHILLIPS: I'll go back to Mark's testimony 22 again. 23 MR. IRELAND: 3922. 24 MR. PHILLIPS: The numbers run together real 25 easy. • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 1 o 47 • 1 At this time I'd like to talk about our Production Allocation. 2 A General Overview. Since October 13, 1993 a long-term 3 production test of North Prudhoe Bay State #3 has been 4 underway. The fluids produced from this well have been 5 commingled with those from West Beach State 4 -- excuse me West 6 Beach #4, prior to processing at the LPC. A well test based 7 production allocation methodology has been utilized to 8 determine the production from each of these wells. This 9 identical methodology has received approval from the State of 10 Alaska for the commingled production from other fields 11 producing into the LPC and has been incorporated in the Field 12 Rules for the West Beach, Point McIntyre, and Niakuk Pools. 13 Details of this methodology were presented in a public hearing • 14 for each of these Pool Rules on January 3 -- 13, 1993, March 15 14, 1993, and October 28, 1993, respectively. Additionally, a 16 formal review of this production allocation methodology 17 occurred on February 1, 1994. It is my understanding that all 18 parties present at that review were satisfied with the 19 production allocation process to date. Another review of this 20 same process has been planned for October 13, 1994. 21 As discussed earlier, current plans are to continue 22 commingled production from North Prudhoe and West Beach into 23 the existing 6" production line to Lisburne Drill Site L1. The 24 Lisburne Data Gathering System, LDGA, will continuously monitor 25 the flowing status, pressures, and temperatures of the R & R C O U R T R E P O R T E R S 810 N STREET 1007 WEST THIRD AVENUE 277-0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 48 1 producing wells at the Lisburne Drill Site L1. This data will • 2 be under the drill site operator's supervision through his 3 monitoring station at the Lisburne Drill Site L1. Alternative 4 well shut -in periods will be required to ensure sufficient 5 purging of the single production line when obtaining 6 representative well test data. Wells on test will have 7 continuous monitoring of pressures, temperatures, and flow off 8 the liquid and gas lege of the test separator. The liquid leg 9 will have a continuous water cut analyzer and a mass flow 10 meter. The rate of production from each well will be 11 determined by at least two well tests per month. 12 Specifically addressing North Prudhoe Bay development, it 13 is not my intent to detail the exact production allocation 14 procedure since it is proposed that the Commission approve the 15 same procedure -- same production allocation methodology 16 consistent with all the other fields whose production is 17 commingled prior to processing at the LPC. In brief, the 18 proposed implementation involves the following features: 19 1. Periodic production testing for all wells producing 20 into the LPC. 21 2. Well test frequency will be maximized using all 22 available test separator capacity at each drill site, within 23 the constraints imposed by operating conditions. 24 3. The stabilization period and test period duration of 25 each well test will be optimized by the Operator to obtain a • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 ! ! 49 • 1 representative test. 2 4. The Operator will attempt to obtain well tests at 3 uniform intervals. 4 5. Well and field operating condition information 5 required for the construction of a field production history 6 will be maintained. 7 6. NGLs will be allocated based on gas volume produced 8 and computer simulated process yields. 9 7. Major test separator meters, major gas system meters, 10 and major water production meters will be installed and 11 maintained according to industry recommended practices or 12 standards. 13 8. The Operator will maintain records that permit • 14 verification of the satisfactory execution of the approved 15 production allocation methodologies. 16 9. The Operator will submit the Production and Injection 17 Report per 20 AAC 25.230 and 20 AAC 25.432 by the 20th of the 18 month following the reporting period. 19 10. The Operator's allocation activities will be reviewed 20 on a periodic basis. 21 11. Metering installations for any field whose production 22 will be commingled for processing in the LPC will have to meet 23 the same industry standards for metering that Lisburne 24 installations currently meet and, where possible, installation 25 of similar meters will be required. North Prudhoe Bay will • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274-8982 272 -7515 ANCHORAGE, ALASKA 99501 • 50 • 1 initially by tested at Lisburne Drill Site L1 so there will not 2 be any new metering required to bring North Prudhoe Bay into 3 the LPC. 4 In summary, we intend to treat all wells producing into 5 the LPC on a consistent basis. While not exact, the proposed 6 production allocation methodology provides for fair treatment 7 of all produced fluids. As we detailed in previous 8 testimonies, any potential misallocations associated with this 9 methodology are completely outweighed by the benefits derived 10 by all parties involved. 11 Thank you for your attention. 12 CHAIRMAN JOHNSTON: In terms of the commingling 13 of the West Beach #4 with the North Prudhoe Bay State #3, how 14 do you go about testing the production from each well? 15 MR. PHILLIPS: What we do is we'll alternately 16 shut -in one of the other wells and produce the remaining well 17 down the 6" line till we flush that line, and then we will go 18 ahead and put it in a test separator at L1. 19 CHAIRMAN JOHNSTON: What happens then if you 20 have -- or if you make the decision to drill an additional well 21 in one of these two reservoirs and you are then starting to 22 balance three wells and potentially four wells? 23 MR. PHILLIPS: We would either be balancing 24 three wells into that or at that point we'd be looking at 25 trying to delay a second test line at that point so we could R & R COURT REPORTERS 810 N STREET 1007 NEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 51 • 1 have a dedicated test line to the L1 facility, or possibly some 2 kind of other metering system out at the West Beach /North 3 Prudhoe area. 4 CHAIRMAN JOHNSTON: How long does a test 5 normally take? 6 MR. PHILLIPS: Those tests out at West 7 Beach /North Prudhoe, I've seen anywhere from a low of four to 8 six hours to a high of 24 hours. 9 CHAIRMAN JOHNSTON: And when you bring on -- so 10 in other words, when one of these wells is in test, the other 11 one is shut -in? 12 MR. PHILLIPS: Yes, sir. 13 CHAIRMAN JOHNSTON: And it could be shut -in for • 14 up to 24 hours; is that 15 MR. PHILLIPS: Or longer. 16 CHAIRMAN JOHNSTON: Longer. 17 MR. PHILLIPS: The stabilization period is part 18 of that time period also. 19 CHAIRMAN JOHNSTON: Right. 20 MR. PHILLIPS: Typically it's been in the -- 21 when we had both wells on a continuous type basis or 22 semi - continuous type basis you would see one well being shut -in 23 for three to four days. 24 CHAIRMAN JOHNSTON: When you shut a well in and 25 bring it back on do you see -- how would you characterize the R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 52 1 production profile as you bring the well back on? 2 MR. PHILLIPS: The well will very quickly 3 return to it's normal production characteristics. 4 CHAIRMAN JOHNSTON: Will you have a period of 5 flush production? 6 MR. PHILLIPS: There's always a very short 7 period of flush production. 8 CHAIRMAN JOHNSTON: And how long a period would 9 that be? 10 MR. PHILLIPS: Again, with the range of what 11 I've seen, and I have not looked at all the tests, but I would 12 say typically it's a very short period in a range of a couple 13 hours. • 14 CHAIRMAN JOHNSTON: But it is more oil that you 15 see than less oil? 16 MR. PHILLIPS: Yes. And again 17 CHAIRMAN JOHNSTON: Okay. And is that true for 18 both West Beach and 19 MR. PHILLIPS: Yes. And that is also again 20 tying back into these short shut -in periods. We've also gone 21 into West Beach, we've actually shut the well in for a period 22 of two weeks as part of trying to keep the GOR down. 23 CHAIRMAN JOHNSTON: Do you have any further 24 questions? Tuckerman? 25 COMMISSIONER BABCOCK: No. • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 i 53 • 1 CHAIRMAN JOHNSTON: Okay. Thank you. At this 2 time we have no further questions. 3 MR. PHILLIPS: Okay. Now I'd like to turn the 4 floor over to Andy Simon, who will summarize our testimony. 5 CHAIRMAN JOHNSTON: Thank you. 6 MR. SIMON: Mr. Chairman, members of the Alaska 7 Oil and Gas Conservation Commission, ladies and gentlemen, my 8 name is Andy Simon. I am manager of Lisburne /Point McIntyre 9 for ARCO Alaska, Inc. I received a Ph.D. in Petroleum 10 Engineering from the University of Missouri, Rolla, in 1980. I 11 have worked in Alaska for the last 14 years in both Prudhoe 12 and, more recently, Lisburne /Point McIntyre. IN my current 13 position, I am directly responsible for North Prudhoe Bay 14 development. 15 (Commissioners confer in whispered tones) 16 CHAIRMAN JOHNSTON: We will consider you an 17 expert witness in this matter, Mr. Simon. Please proceed. 18 MR. SIMON: As previously discussed today, oil 19 and gas were tested in the North Prudhoe Bay Reservoir in 1970. 20 A re- evaluation of this area led to the drilling of North 21 Prudhoe Bay State #3 in 1993, located approximately 3,300' 22 northwest of North Prudhoe Bay State #1. A long -term 23 production test to better understand the development potential 24 has been underway since October 13, 1993. At this time, our 25 development plans are uncertain. The plans we have presented • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 54 110 1 here today outline a program to continue to produce North 2 Prudhoe Bay State #3 through a permanent line from West Beach 3 to the Lisburne Drill Site L1. Pressure monitoring of this 4 well will continue to provide valuable information to optimize 5 our development plans for North Prudhoe Bay. We are requesting 6 pool rules at this time that provide flexibility to move ahead 7 with this initial development phase as well as to provide 8 sufficient flexibility to evaluate the range of development 9 options for the North Prudhoe Bay Reservoir. 10 The Owners are committed to a safe and environmentally 11 sound operation. The facilities are designed to operate in a 12 safe and efficient manner and will make maximum use of existing 13 IPA /LPA infrastructure to maximize economic reserves and 14 minimize environmental impacts. 15 Due to the uncertain nature of North Prudhoe Bay 16 development, we are requesting permission to remain on primary 17 production. Additionally, we are requesting permanent 18 exemption from 20 AAC 25.240, gas -oil limit of twice original 19 solution GOR. Removing this restriction will allow for maximum 20 recovery if the reservoir size is too small to justify further 21 development. 22 CHAIRMAN JOHNSTON: Before proceeding there, 23 Mr. Simon, what -- again, just for matters of clarification, 24 what is the original GOR? 25 MR. SIMON: I believe what we showed on Exhibit • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 55 410 1 III -6, we'd be saying the initial solution GOR would be 2 923 cubic feet per barrel. 3 CHAIRMAN JOHNSTON: 923. So twice that would 4 be 1,846, 1,50 or so, and you are well above that currently, 5 but you do have a temporary waiver of that 6 MR. SIMON: Yes, sir, from 7 CHAIRMAN JOHNSTON: while you're in test 8 production? 9 MR. SIMON: the Commission. 10 CHAIRMAN JOHNSTON: Why should the Commission 11 grant a permanent waiver? 12 MR. SIMON: I believe the reason we're asking 13 is in the event that the reservoir is too small to justify 411 14 further development this approach would maximize recovery from 15 the accumulation. 16 CHAIRMAN JOHNSTON: That's only because the 17 production would still continue 18 MR. SIMON: Yes, sir 19 CHAIRMAN JOHNSTON: basically. So what 20 you're saying is that without the permanent waiver of the GOR 21 limitation you would not be able to produce this well? 22 MR. SIMON: Yes, sir, the well would have to be 23 shut -in. 24 CHAIRMAN JOHNSTON: And at this time you cannot 25 justify returning the gas to the reservoir? • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 56 1 MR. SIMON: Yes, sir, that is correct. And as -- 2 George noted in fact we perforated the Sag in a deliberate 3 attempt to bring in additional gas to improve the well 4 hydraulics in an attempt to make it flow. 5 CHAIRMAN JOHNSTON: And you cannot at this time 6 justify an additional recovery project for the 7 MR. SIMON: Not at the present time, 8 Mr. Chairman. Our basic plan will be to continue to keep the 9 well on production and gain further pressure and water -oil 10 ratio behavior data to give us some further insights, I think, 11 into the fundamental drive mechanism and the oil in place. So 12 we'd still view this initial phase as continuing to gather 13 data, trying to gain insights into producing character of the • 14 reservoir, and this would just provide in the event that the 15 oil in place is insufficient to support either additional 16 drilling or application of a secondary recovery technique. 17 Then we would propose continuing to produce the reservoir under 18 primary. 19 COMMISSIONER DOUGLASS: So you consider this a 20 continuation of the testing that's been going on or 21 MR. SIMON: Yes, sir, our plan would be to 22 continue to gather data and understanding on the reservoir. At 23 the present time, as we see it, it's, you know, nominally a 24 12 million barrel in place reservoir with a rising watercut. 25 COMMISSIONER DOUGLASS: Well, you've • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 57 • 1 produced 2 MR. SIMON: 900 and 3 COMMISSIONER DOUGLASS: Going on a million 4 barrels. When would you expect to go on regular production 5 then? 6 MR. SIMON: I guess we'd be requesting that we 7 go on regular production with the approval of the pool rules. 8 CHAIRMAN JOHNSTON: But, again, for point of 9 clarification, regular production or your ability to continue 10 regular production would solely depend on the Commission's 11 waiver of the GOR limitation? 12 MR. SIMON: Yes, sir, because I believe -- I 13 don't remember the -- so it would be an extension of the 14 current exemption we have from the Commission, and we would be 15 asking to make that permanent. 16 CHAIRMAN JOHNSTON: Please proceed. 17 MR. SIMON: The drilling program will meet or 18 exceed all requirements specified in the Commission regulations 19 and will utilize valuable information gained from previous 20 drilling on the North Slope. To provide operational 21 flexibility, we are asking the Commission for approval to allow 22 the running of tubingless completions and the installation of 23 subsurface safety valves to a depth of 300 feet or greater. We 24 are also asking the Commission for approval to streamline the 25 approval process by allowing temporary removal of subsurface 410 R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 58 • 1 safety valves from individual wells for routine well work 2 operations or repair, not to exceed 30 days without specific 3 notice to or authorization by the Commission. 4 The reservoir surveillance program will provide valuable 5 information and data that will be continually incorporated into 6 our development planning and day -to -day operations. Special 7 emphasis will be placed on well testing due to the commingling 8 of West Beach and North Prudhoe Bay production at the Lisburne 9 Production Center. As George discussed earlier, flexibility of 10 test wells that require testing is key to obtaining proper 11 allocations. Initially, in order to build comfort and 12 confidence for all parties involved in the allocation process, 13 we are requesting a requirement of two well tests per month. • 14 This well test frequency should be discussed in future 15 allocation process reviews. 16 Well test information will be adjusted by individual 17 allocation factors for oil, gas and water. NGL production will 18 be based on gas production volumes and NGL process simulation. 19 All volumes will be reported to the Commission monthly. 20 The development of North Prudhoe Bay, with its wide range 21 of development opportunities and the sharing of existing 22 production facilities at the LPC, create many challenges for 23 both the Owners and the State of Alaska. We look forward to 24 working these challenges to develop an optimum depletion plan 25 for North Prudhoe Bay. We thank you for this opportunity to R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272-7515 ANCHORAGE, ALASKA 99501 . • 59 1 provide this testimony today, and are available to answer any 2 questions you may have. 3 COMMISSIONER BABCOCK: Mr. Simon, in the 4 participating area that you are attempting to gain approval for 5 from the Department of Natural Resources, does that include 6 what you identify here as all Section 22 and a quarter -- 7 southwest quarter of Section 23 or is it larger? 8 MR. SIMON: Our original application to the 9 Department of Natural Resources included theories -- you 10 referenced Section 23 and the southwestern Section of -- i 11 quarter section of 23? 12 COMMISSIONER BABCOCK: Uh -huh (affirmative). 13 MR. SIMON: The Department of Natural Resources 14 requested that we amend our application to remove the portion 15 of Section 23, and our intent would be to so do. 16 COMMISSIONER BABCOCK: And what impact on 17 ultimate recover would you estimate that might have? 18 MR. SIMON: I think the basic question is the 19 degree of communication of that horst block which North 20 Prudhoe 1 was drilled in with the accumulation in Section 22. 21 As I recall, the oil in place in that area with North Prudhoe 22 Bay 1 was drilled as relatively small. 23 CHAIRMAN JOHNSTON: What's the status on North 24 Prudhoe Bay 1? 25 MR. SIMON: I believe the well is temporarily • R & R C O U R T R E P O R T E R S 810 N STREET 1007 NEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . . 60 • 1 abandoned. 2 CHAIRMAN JOHNSTON: So whenever industry uses 3 that term I have to note that there's no such classification 4 within Commission regulations. I assume that means that there 5 are no downhole plugs in that particular well. 6 MR. PHILLIPS: Now as a clarification that well 7 has been PNA'd. 8 CHAIRMAN JOHNSTON: It has been PNA'd, okay. 9 Well, then that addresses my second question. I have no need 10 to ask that one. Any other? 11 COMMISSIONER BABCOCK: Then why was that 12 included in your initial application? 13 MR. SIMON: I think since we had a well 14 penetration into those three horizons with drill stem tests, 15 there's unquestionably hydrocarbons in them, and I think it's 16 unquestionably the same geologic members as we've seen in North 17 Prudhoe Bay State #3. 18 COMMISSIONER BABCOCK: Let me just clear up, 19 which well would you have the Commission identify as the 20 MR. SIMON: Dennis, I believe, identified North 21 Prudhoe Bay #1, the log, as being the type log for the 22 accumulation. I think it's a better sweep of logs then as a 23 straighthole. 24 CHAIRMAN JOHNSTON: But then the -- that log 25 would not be • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . • 61 1 COMMISSIONER BABCOCK: That's why -- that the 2 direction of my question. 3 CHAIRMAN JOHNSTON: Please proceed. 4 COMMISSIONER BABCOCK: Well, it's just -- it 5 seems that the well is the type of well that ought to be in the 6 pool. 7 MR. SIMON: We have requested the pool rule 8 area include this quarter section. 9 COMMISSIONER BABCOCK: But it may be that the 10 pressure is a different benefactor initially of 800 pounds, 11 which isn't entirely explained, and it's 23 years' difference, 12 but that's not very long in geologic time. So maybe that the 13 communication there is some deeper communication to water with 14 Prudhoe Bay, maybe not; maybe that these two are different 15 pockets as I think Mr. Dennis's geology showed there was a 16 fault cutting off the two. So it just makes me a little 17 uncomfortable to rely on #1 as the sample well, despite that 18 it's a straighthole and you have a better sweep of logs, and 19 I'd like you to just, from my perspective, consider what 20 additional information you could provide form #3 that would 21 make it a little easier to identify that as the typical well 22 for the pool, instead of #1. 23 MR. SIMON: We can certainly supply a type log 24 on North Prudhoe #3 annotated in the appropriate fashion. 25 COMMISSIONER BABCOCK: Well, I would like to • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 s • 62 1 see such a log as one of the exhibits. 2 CHAIRMAN JOHNSTON: Any additional? 3 COMMISSIONER BABCOCK: So you see no difficulty 4 -- no detrimental effect to ultimate recovery by not including 5 that part of Section 23 in the pool rules area? 6 MR. SIMON: No, sir. 7 COMMISSIONER BABCOCK: I mean in the 8 participating area. 9 MR. SIMON: No, sir. 10 COMMISSIONER BABCOCK: But you're still 11 recommending it's in the Pool Rules area? 12 MR. SIMON: Yes, sir. 13 CHAIRMAN JOHNSTON: Perhaps I'll ask a question • 14 while you're thumbing through there. And this is similar to 15 the question I initiated discussions with Mr. Worcester on -- 16 and he thought perhaps the technical members might be better 17 versed at response, and since you're the individual 18 summarizing, perhaps I'll address it to you. The plan of pool 19 development and operation must provide for several things, 20 among which is the maximum ultimate recover of oil and gas that 21 is prudent. In your opinion does this plan do that? 22 MR. SIMON: Yes, sir. And I think it provides 23 for an ongoing monitoring of data and reassessment of the plans 24 that are appropriate for this accumulation. 25 CHAIRMAN JOHNSTON: So you anticipate, even R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 411 • 63 1 though you're proposing no secondary or tertiary recovery 2 method, no returning of the gas to the pool, no real proposal 3 to drill additional wells as a plan that will maximize ultimate 4 recovery from oil and gas -- of oil and gas as prudent. Why do 5 you say that? 6 MR. SIMON: Well, I think with the information 7 we have gained with the size of the reservoir -- of course the 8 reservoir pressure appears to be stabilizing some, which 9 suggests some possibility of aquifer influx. I think from an 10 ultimate recovery standpoint certainly economic criteria come 11 into play there. I think as George alluded to, we're 12 endeavoring very hard to search for other means to either 13 expand technology or further reduce costs as it relates to • 14 drilling or facilities, for that matter. So challenges for us 15 are how can we safely drill wells at a reduced cost. For 16 example, how can we cost effectively and safely, for example, 17 get gas out to the West Beach drill site if that indeed proves 18 to make sense. So I think these are ongoing things. I think 19 the base plan we've outlined based on what we see as a single 20 well depletion is prudent. That is not to say that we 21 continually revisit that and search for other ways to 22 incorporate not only reservoir information but our development 23 knowledge into this. 24 CHAIRMAN JOHNSTON: Well, I certainly 25 appreciate the fact that West Beach and North Prudhoe Bay State • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 • 64 • 1 in similar type reservoirs are a bit different than the 2 grand -daddy up there, Prudhoe Bay, and I suspect in recognition 3 of that the Commission has to do things a little bit 4 differently. I am a little bit uncomfortable entertaining a 5 plan of development that supposedly maximizes ultimate recovery 6 when no FOR effort is being proposed and no additional wells 7 are really being proposed. 8 It's hard for me to make that jump that the maximum 9 ultimate recovery is being furthered by this plan. On the 10 other hand, I appreciate the difficulty that a small 11 accumulation like this does pose for development, and I think 12 what the Commission needs to do is to look at those elements 13 and try and work with the operator to the extent that we can. • 14 I would suggest that it would be appropriate for us to 15 frequently visit with the operator in terms of understanding 16 what is going on in North Prudhoe Bay State as well as the West 17 Beach, and ensure that in fact the operator is doing those 18 things that is prudent, and I think within the concept of 19 prudent, economics certainly enters into that. But I think 20 this Commission has to have a comfort level that you are doing 21 those things, that there is a serious effort to make the proper 22 investments in the -- in Alaskans' oil patch and that you're 23 not just putting a well in and being content to produce that 24 well without making other investments that may not make a -- as 25 high a rate of return. • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 65 • 1 Along those lines what kind of information can the ARCO 2 offer us that would say give us that comfort level in terms of 3 understanding that ARCO is in fact making the investments that 4 are appropriate for this particular oil accumulation? 5 MR. SIMON: Well, as you've referred to, 6 Mr. Chairman, I think we have a standing practice of 7 communicating with the Commission on not only reservoir 8 performance but what the implications are on plans of 9 development and the maximization of economic recovery. We 10 would certainly fully intend to continue doing that. Because, 11 I think as you can see from Sam's testimony, the geology in 12 this area is quite complicated and as we continue to gain data 13 on just the basic reservoir performance, I think our • 14 fundamental views from originally have changed somewhat 15 vis -a -vis the degree of, you know, the pressure performance is 16 flattening out some, water -oil ratios coming up. So I think 17 the Commission's comfort level would be raised by such a 18 process wherein updates on reservoir performance and the 19 implications on the plans were done on some kind of basis that 20 made sense. 21 CHAIRMAN JOHNSTON: Recently a report came out 22 who was sponsored by the Department of Commerce and Economic 23 Development and I don't recall the consulting firm at this 24 point that prepared that document. Are you familiar with that 25 study? It had to do with • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 66 • 1 COMMISSIONER BABCOCK: Gafney Kline. 2 CHAIRMAN JOHNSTON: Gafney and Kline, 3 that's right. 4 MR. SIMON: Yes, sir, I 5 CHAIRMAN JOHNSTON: Have you read that? 6 MR. SIMON: have seen it. 7 CHAIRMAN JOHNSTON: In terms of the information 8 provided in that do you think the State of Alaska should be 9 passive when it comes to developing or watching the operator 10 develop the oil patch or should we be a more active participant 11 in terms of looking at incentives and disincentives to 12 production. 13 MR. SIMON: Well, I think certainly if we look • 14 toward the trend of more marginal developments, I think some 15 things have happened with the state and the industry working in 16 concert. I think an example I would point to is our very 17 business unit where the ability for the state and the industry 18 collectively to develop a high comfort level in moving ahead 19 with commingled production, which if you look at the reservoirs 20 we deal with that I think all of -- well, certainly North 21 Prudhoe, Niakuk and West Beach, no way could remotely stand any 22 kind of independent development. And even I think something as 23 large as Point McIntyre would have been certainly marginal. So 24 I think in working that direction through that approach I think 25 more things as is towards the future will become more • R & R C O U R T R E P O R T E R S 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 67 • 1 important. I think if we had testified to the Commission that 2 approach will increase ultimate recovery out of that area 100 3 to 150 million barrels is somewhat unique. I'm not aware of 4 any place else that it's been done on this scale. 5 CHAIRMAN JOHNSTON: Would you care to comment 6 on the possibility of the state offering tax incentives, would 7 that be a proper role for the State of Alaska to consider? 8 MR. SIMON: Yes, I certainly think that any 9 type of a structure that could aid the phase of develops that 10 are more marginal certainly would be helpful for all parties 11 involved. 12 CHAIRMAN JOHNSTON: So you would say, if I 13 could characterize what you just said, that tax incentives • 14 might be appropriate for certain qualifying fields that may not 15 necessarily be appropriate for every field, but for certain 16 qualifying fields they might be? 17 MR. SIMON: Yes, sir. Well, I believe the 18 fundamental premise of consultants put forward was one of 19 attempting to shift how taxes were collected from a revenue 20 base to more to something that more recognized the volatility 21 in price and cost drivers in the future, just as a general 22 statement of philosophy. 23 CHAIRMAN JOHNSTON: Well, that's getting a 24 little bit far afield from North Prudhoe Bay State, 25 COMMISSIONER BABCOCK: Oh, just a little bit. • R & R COURT REPORTERS 810 N STREET 1007 NEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . . 68 1 CHAIRMAN JOHNSTON: but I was just 2 curious as to what your thoughts may be on that. It's one of 3 the first opportunities we've had to visit with industry since 4 that report has come out. So I thought I'd go a little far 5 afield here. Any 6 COMMISSIONER BABCOCK: I have a few questions. 7 CHAIRMAN JOHNSTON: Please. 8 COMMISSIONER BABCOCK: What was the Prudhoe Bay 9 pressure in 1970? 10 MR. SIMON: I believe the discovery pressure to 11 gas -oil contact was 4,335. 12 COMMISSIONER BABCOCK: 4,335. It seems to me 13 that the -- that's just as a matter of an explanation that the 14 ratio between North Prudhoe Bay #1 in 1970 and Prudhoe in 1970 15 is very close to being exactly what it is between #3 in Prudhoe 16 today, not as a percentage of the -- percentage but in the 17 total pounds per square inch difference; it's still about two 18 to 300. So that may point very strongly to some communication 19 at least from the level of water, even if your API and sulfur 20 indicate that it's a different oil pocket and the oil is not in 21 communication. But it may well be that this is a -- some sort 22 of finger of Prudhoe Bay, since it's at the same level. Is 23 West Beach at this depth? 24 MR. SIMON: West Beach is 25 COMMISSIONER BABCOCK: It's not, is it? • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272-7515 ANCHORAGE, ALASKA 99501 . 411 69 1 MR. SIMON: shallower. 2 COMMISSIONER BABCOCK: Yeah. So -- and I don't 3 know that that would change your -- change any part of your 4 development plan but just -- it's the public member on the 5 Commission looking at those ratios over time, it helps to 6 explain why there would be that difference. We may also be 7 able to -- since in Prudhoe your recovery -- oh, excuse me, 8 I'll backtrack for a minute. I want to ask a question: Is 9 there anyone here who believes that allowing primary recovery 10 to deplete this pool should not be allowed because it would 11 not, at this stage, given the economics that we are aware of, 12 contribute to maximum, ultimate recovery that is prudent? 13 (No audible response) • 14 COMMISSIONER BABCOCK: Okay. No takers on that 15 suggestion. In that case I would suggest that your testimony, 16 Mr. Simon, that it is -- in fact the most prudent maximum 17 recovery goes unchallenged. 18 CHAIRMAN JOHNSTON: Any further? 19 COMMISSIONER BABCOCK: No, those were the -- 20 and I don't know what impact would that have if in -- to your 21 development plans if in fact there was communication between 22 this pool and Prudhoe. 23 MR. SIMON: I guess nothing strikes me as being 24 readily apparent. And since clearly it is a geologically 25 isolated accumulation it's not being -- the oil certainly isn't • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 III 70 0 1 going any place. So it still requires a well or wells to 2 COMMISSIONER BABCOCK: Right. 3 MR. SIMON: extract. 4 COMMISSIONER BABCOCK: Right. 5 CHAIRMAN JOHNSTON: But presumably -- I mean if 6 I could follow along this line of speculation that 7 Commissioner Babcock raised, if this was an extension of the 8 Prudhoe Bay accumulation presumably then you would not have to 9 go through a well testing scenario, you'd just take that oil 10 and move it to the nearest flow station rather than taking it 11 over to the LPC. Would that change anything? 12 MR. SIMON: No, Mr. Chairman, because the most 13 efficient way is this -- North Prudhoe was piggy- backed off of • 14 West Beach which ties back in to Lisburne Drill Site L1. So 15 actually as far as North Slope facilities, it's the most direct 16 and cost effective access. 17 COMMISSIONER DOUGLASS: You'd be talking 18 another pipeline, wouldn't you, to go to a Prudhoe facility? 19 MR. SIMON: Yes, sir, and it would be some 20 considerable distance. 21 COMMISSIONER DOUGLASS: And if -- going further 22 on speculation, if indeed it is in communication then you're 23 deriving the benefits of the Prudhoe Bay enhanced oil recovery 24 program. 25 MR. SIMON: I guess I haven't seen any fil R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 71 1 geological evidence, and I'm not a geologist, so it's 2 relatively straight forward for me to say. 3 COMMISSIONER DOUGLASS: Well, that's why it's 4 qualified as very speculative, at least in my mind. 5 MR. SIMON: But it certainly doesn't seem that 6 there's any indication that the oil lags have any degree of 7 communication. I guess one can speculate as there's something 8 going on related back to the aquifer in Ivishak, but in that 9 whole area, I mean, I guess if one were to speculate, 10 conceivably is there something hooked into Lisburne, and it 11 might not even be the Prudhoe Bay accumulation. To me it just 12 seems that the source of the oil is compellingly different. I 13 mean a fingerprint is not a subtlety, and the task between • 14 North Prudhoe 1 and 3 were very consistent; much higher gravity 15 that you don't see anywhere in Prudhoe, and certainly isn't 16 consistent with either Lisburne or 17 CHAIRMAN JOHNSTON: Well, certain - 18 MR. SIMON: West Beach or Point McIntyre. 19 CHAIRMAN JOHNSTON: Certainly the API gravity 20 difference is compelling evidence to me that they're not 21 MR. SIMON: The same one. 22 CHAIRMAN JOHNSTON: part of the same, 23 right. 24 MR. SIMON: Yes, sir. 25 CHAIRMAN JOHNSTON: Additional? R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . . 72 1 COMMISSIONER BABCOCK: Nothing for me. 2 CHAIRMAN JOHNSTON: Any additional? 3 COMMISSIONER DOUGLASS: No. That's it, 4 thank you. 5 CHAIRMAN JOHNSTON: Okay. At this time, 6 Mr. Simon, we have no further questions of you. I'd like to 7 ask if there's any members of the audience that wish to come 8 forward and make any statements, comments -- we do have a 9 question here. Okay. 10 (Commissioners confer in whispered tones) 11 CHAIRMAN JOHNSTON: We have a series of 12 questions from the DNR representative, Mr. Bill VanDyke. At 13 this time perhaps we could ask Mr. Simon to take the hot seat 14 again, although we're only doing this because you're providing 15 the summary, and it may be appropriate to get another 16 individual up here who would answer the technical question. 17 Question one: Do material balance calculations indicate 18 reservoir size for oil and gas cap and aquifer? 19 MR. SIMON: Yes, sir. We've done material 20 balance calculations. I guess I would characterize it as you 21 always have an uncertainty as far as the drive mechanism. In 22 material balance you have to make an assumption of -- for 23 example, degree of aquifer influence. So, yes, we have done 24 material balance calculations, and you attempt to band it 25 within a reasonable assessment of parameters, mapped in with • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . • 73 1 the geology. 2 COMMISSIONER DOUGLASS: Are the results say 3 consistent with your volumetric calculations? 4 MR. SIMON: I believe -- yes, they are. 5 CHAIRMAN JOHNSTON: This is not a question from 6 Bill VanDyke, but just popped into my mind here as we are 7 talking. What additional work is ARCO proposing on doing in 8 order to get a handle on whether there is a active water drive 9 in the accumulation? 10 MR. SIMON: I think part of what would show at 11 continued well performance, the continuing monitoring of the 12 pressure and the water -oil ratio behavior will give you 13 insights. • 14 CHAIRMAN JOHNSTON: So if you see a 15 stabilization of pressure over the next say 12 months or so 16 would that be evidence supporting the concept of a active water 17 drive? 18 MR. SIMON: Yes, sir, it would to me. 19 CHAIRMAN JOHNSTON: And if you had an active 20 water drive would that change your depletion plan for the 21 accumulation? 22 MR. SIMON: Well, I think if you had an active 23 water driver certainly recovery factors associated with that 24 are substantially higher 25 CHAIRMAN JOHNSTON: Right. • R & R C O U R T R E P O R T E R S 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 . . 74 410 1 MR. SIMON: than anything related to 2 solution gas drive. 3 CHAIRMAN JOHNSTON: Certainly. 4 MR. SIMON: So the question will be from a well 5 hydraulic standpoint as being able to manage the water -oil 6 ratio and the production behavior. 7 CHAIRMAN JOHNSTON: So in such a scenario, if 8 you did have an active water drive and recovery went up 9 significantly would you then be -- would that be one of the 10 criteria that would fit a determination of drilling additional 11 wells or would the depletion be -- or could you deplete the 12 entire reservoir just with the one well? 13 MR. SIMON: Mr. Chairman, I think what you'd • 14 have to consider would be it's a fairly thin oil columns, about 15 20 feet, if I recall, and to what extent -- the question would 16 be how much water we can cycle through a single well, given we 17 do not have gas lift out there now. That poses a special set 18 of operational challenges. But I think that would be something 19 you would certainly want to keep in front of you and look 20 within that area of -- as George suggested, looking at 21 alternate ways of trying to drill wells more cost effectively 22 and, you know, certainly try to consider it as a way to get 23 obstructurally (ph) away from water. 24 CHAIRMAN JOHNSTON: Question number two from 25 Mr. VanDyke: Is the initial pressure in the North Prudhoe Bay • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 110 411 75 • 1 State #3 well consistent with the pressure in the Lisburne or 2 the Prudhoe Bay reservoir at the time the North Prudhoe Bay 3 State #3 well was drilled? 4 MR. SIMON: What's the -- let me phrase it, the 5 question: Was the pressure in the North Prudhoe Bay State #1 6 well consistent with the pressures of Lisburne, Prudhoe ..... 7 COMMISSIONER DOUGLASS: #3, not #1. 8 CHAIRMAN JOHNSTON: Yeah, the #3 well. 9 MR. SIMON: Oh, in the #3 well, not the #1 10 well. The #3 well. 11 CHAIRMAN JOHNSTON: Was it consistent with 12 pressure in the Lisburne -- in the Prudhoe Bay reservoir at the 13 time the North Prudhoe Bay State #3 well was drilled? • 14 MR. SIMON: I guess I'd ask for clarification. 15 What's the term "consistent" mean? 16 CHAIRMAN JOHNSTON: I was going to ask that, 17 too. 18 MR. SIMON: To different datums and 19 CHAIRMAN JOHNSTON: Perhaps Mr. VanDyke, if you 20 would clarify this question for us? 21 MR. VANDYKE: There's a different way to state 22 it -- this is Bill VanDyke with -- at a similar datum in the 23 Prudhoe Bay reservoir or the Lisburne reservoir what was the 24 pressure at the time the North Prudhoe Bay State well was 25 drilled? • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 76 • 1 (Pause - conferring in whispered tones) 2 MR. SIMON: I guess the question comes to mind, 3 all those fields have significant ranges of pressure in them. 4 I guess we would -- in our studied opinion of all the 5 information one wouldn't conclude that there's a direct 6 communication in any field right now. In other words, we're 7 struggling with this difference in pressure that we measured in 8 North Prudhoe in 1970, North Prudhoe 1 and Prudhoe 3. In other 9 words, I don't think you can uniquely characterize it in a 10 simplistic sense. 11 CHAIRMAN JOHNSTON: So what you're saying is 12 though potentially why you might possibly see the same pressure 13 in a well in say Prudhoe bay or over in Lisburne, that does not • 14 necessarily mean anything. 15 MR. SIMON: Yes, sir. I would be hesitant to 16 draw just on that single point. 17 CHAIRMAN JOHNSTON: Except there is a 18 coincidence there that you may have the same pressure. 19 MR. SIMON: Yes, sir. Yes, sir. 20 CHAIRMAN JOHNSTON: Okay. 21 COMMISSIONER DOUGLASS: So it would be ARCO's 22 position that essentially you cannot see any sort of 23 communication between this accumulation and the Lisburne or the 24 Prudhoe? 25 MR. SIMON: Let me confer with my geologist • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • • 77 • 1 for a second. 2 (Pause - conferring in whispering tones) 3 MR. SIMON: We do not see any compelling 4 geological reason that would show some logic of the supposition 5 that then when you put together with the pressure data would 6 suggest that. 7 COMMISSIONER BABCOCK: What was the oil -water 8 contact in #3? 9 MR. SIMON: It was 300 feet -- if I recall the 10 testimony, it was 300 feet deeper than the Prudhoe 11 accumulation. 12 COMMISSIONER BABCOCK: I mean as compared to 13 #1? • 14 MR. SIMON: I don't -- they're the same. 15 CHAIRMAN JOHNSTON: Question number three: Is 16 there an opportunity to drill from the Point McIntyre #1 drill 17 site or the injection well site at the base of the -- at the 18 base of West Dock? Would this reduce the cost of a new well? 19 MR. SIMON: I think that's something we've 20 looked at several times as what is the optimum surface location 21 to drill these wells from, and I think it relates back to a 22 view of what portion of the reservoir we would be trying to 23 reach. In other words, I guess the way I would simply answer 24 the question is I think we always kind of retest what is the 25 optimum way to try to get to a certain point. So, in other • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 78 • 1 words, we have not precluded that. 2 CHAIRMAN JOHNSTON: So it would be possible to 3 take one of the slots at the Point McIntyre #1 site and run a 4 well over to North Prudhoe Bay State? 5 MR. SIMON: I think there's always possible -- 6 you know, a number of different optimizations on drilling, but 7 the balance would then become, for example, our -- would we 8 actually need to add slots at Point McIntyre. 9 CHAIRMAN JOHNSTON: Yeah, what do you take away 10 from Point McIntyre 11 MR. SIMON: Yes, sir. 12 CHAIRMAN JOHNSTON: if you drill this 13 well, right. Okay. Would that in fact result in a cost • 14 reduction if you were able to utilize an existing slot? 15 MR. PHILLIPS: Depending again on the lo- -- 16 this is George Phillips again. Depending on the location we 17 would drill, we could reduce drilling costs from drilling from 18 Point Mac 1 to that bottom hole location where North Prudhoe 3 19 is from Point Mac 1. 20 CHAIRMAN JOHNSTON: Could you describe the 21 North Prudhoe Bay State #3 location right now; what does it 22 consist of? 23 MR. PHILLIPS: I was speaking of the bottom 24 hole location. So maybe actually look at the bottom hole 25 location on our physical map • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 • 79 • 1 CHAIRMAN JOHNSTON: Right. 2 MR. PHILLIPS: at XY -- Andy's got one -- 3 we could drill that, it's closer to Point Mac 1 than it is to 4 West Beach. 5 CHAIRMAN JOHNSTON: Okay, I see what you're 6 saying. Then the fourth question: Has ARCO /Exxon studied the 7 technical feasibility of water injection or gas injection? 8 Does either process result in increased recovery? 9 MR. SIMON: Yes, sir. We have on a screening 10 basis looked at various alternatives. I guess the question 11 would be in my mind is, as we referenced earlier, if you have 12 an active water drive, your base recovery factor is 13 substantially higher than if you were under some kind of more 14 typical solution gas drive mechanism, which then calls into 15 question the -- we may have a natural water flood in North 16 Prudhoe, and would be some question of what then would be a 17 target for enhanced oil recovery. 18 Yes, I think those are the types of things we always keep 19 in front of us to say if there a possibility to be able to do 20 those sorts of things. 21 CHAIRMAN JOHNSTON: But you have looked at -- 22 and run the numbers on a water injection project? 23 MR. SIMON: Under a set of assumptions that was 24 a significantly larger oil in place. 25 CHAIRMAN JOHNSTON: Right. I'm not asking 411 R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 . . 80 • 1 whether you determined whether it was economically viable or 2 not, I just want to know that you have in fact looked at that 3 option and you have then concluded after doing that that at 4 this time, given the nature of the accumulation and the 5 economics that exist today that it would not be economically 6 justified to do so. 7 MR. SIMON: Yes, sir. 8 CHAIRMAN JOHNSTON: Okay. And in terms of the 9 question, Part B here, does either process result in increased 10 recovery? How would you answer that? 11 MR. SIMON: I guess that I would -- I don't 12 really quite know how to answer it, because if you have a 13 strong, natural water drive, I wouldn't really expect much • 14 difference between that and a water flood, obviously. 15 CHAIRMAN JOHNSTON: Do you think within a 16 year's time you'll have a handle on whether you have an active 17 water drive? 18 MR. SIMON: Yes, sir, I would certainly think 19 so. 20 CHAIRMAN JOHNSTON: Any additional questions, 21 comments, statements? Do we need any additional information 22 from the applicant or shall we close the record? 23 COMMISSIONER BABCOCK: I'd like the 24 COMMISSIONER DOUGLASS: We did ask for that 25 integration of interests, but that was the only thing, as I 4 10 R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 ANCHORAGE, ALASKA 99501 111 • 81 • 1 understand it -- as I recall. 2 CHAIRMAN JOHNSTON: Well, perhaps we should 3 allow an additional two weeks for that information to come into 4 us and then we can close the record at that particular time and 5 move forward? 6 COMMISSIONER BABCOCK: That's fine. It would 7 also give anyone an opportunity to answer my other question, if 8 anyone cares to. 9 CHAIRMAN JOHNSTON: That's true. Okay. Why 10 don't we do that then. We'll hold the hearing record open for 11 a two -week period and that would be October the 19th. We'll 12 close the hearing record on October the 19th at close of 13 business. 14 COMMISSIONER BABCOCK: 4:30? 15 CHAIRMAN JOHNSTON: At 4:30. Without any 16 further business before the Commission, we stand in recess 17 until the 19th. Thank 18 COMMISSIONER BABCOCK: Mr. Chairman. 19 CHAIRMAN JOHNSTON: Yes. 20 COMMISSIONER BABCOCK: You mean to call back to 21 a public meeting or are we really in adjournment? 22 CHAIRMAN JOHNSTON: We would only call back in 23 the event that the additional information that was submitted to 24 us required further action on the part of the Commission. 25 COMMISSIONER BABCOCK: Thank you, okay. • R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274-8982 272 -7515 ANCHORAGE, ALASKA 99501 111 • 82 • 1 CHAIRMAN JOHNSTON: So if -- assuming there is 2 no further action on the 19th, the record will be closed on 3 that -- at that time. 4 COMMISSIONER BABCOCK: All right. 5 CHAIRMAN JOHNSTON: Thank you very much. 6 (Off record - 11:35 a.m.) 7 * * * * * * * * * * (END OF PROCEEDINGS) 8 * * * * * * * * * * * * 9 10 11 12 13 411/ 14 15 16 17 18 19 20 21 22 23 24 25 R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572 /Fax 274 -8982 272-7515 ANCHORAGE, ALASKA 99501 111 410 1 CERTIFICATE 2 UNITED STATES OF AMERICA) ss 3 STATE OF ALASKA 4 I, Laurel L. Kehler - Evenson, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and reporter 5 for R & R Court Reporters, Inc., do hereby certify: 6 THAT the annexed and foregoing Public Meeting of the Alaska Oil and Gas Conservation Commission, was taken before 7 Penny Reagle on the 5th day of October 1994, commencing at the hour of 9:00 o'clock a.m., at the offices of the Alaska Oil and 8 Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska, pursuant to Notice; 9 THAT this Transcript, as heretofore annexed, is a true and 10 correct transcription of the testimony given at said Public Meeting, taken by Penny Reagle and thereafter transcribed by 11 me; 12 THAT the original of the Transcript has been lodged with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine 13 Drive, Anchorage, Alaska; • 14 THAT I am not a relative, employee or attorney of any of the parties, nor am I financially interested in this action. 15 IN WITNESS WHEREOF, I have hereunto set my hand and 16 affixed my seal this 19th day of October 1994. 17 18 Ya-Wid ti Notary Public in and for Alaska 19 My commission expires: 10/20/94 20 21 22 RECEIVED 23 24 OCT 2 4 1994 plasm Uil & Gas Cons. Commission 25 ' Anchork a 1 1P R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277 - 0572 /Fax 274 -8982 272 -7515 1 ANCHORAGE, ALASKA 99501 42 41 41 •. Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of ARCO Alaska, Inc. for a public hearing to present testimony for classification of a new oil pool and prescribing pool rules for its development in the Prudhoe Bay Unit of the Prudhoe Bay Field. Notice is hereby given that ARCO Alaska, Inc. has petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 to hold a public hearing to present testimony for classification and prescribing pool rules for development of a new oil pool in the Prudhoe Bay Unit. The development area is located in the northeast portion of the Prudhoe Bay Unit and is referred to as the North Prudhoe Bay accumulation. A hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501 at 9:00 am on October 5, 1994 in conformance with 20 AAC 25.540. All interested persons and parties are invited to present testimony. If you are a person with a disability who may need a special accommodation, auxiliary aid or service, or alternative communication format in order to comment on the proposed action, please contact Diana Fleck at 279 -1433 by 4:30 pm, September 29, 1994. I I Russell A. Douglass Commissioner Alaska Oil and Gas Conservation Commission Published August 26, 1994 11853 STOF0330 02514003 $49.40 AFFIDAVIT OF PUBLICATION STATE OF ALASKA ) THIRD JUDICIAL DISTRICT ) Conservation SS. Re: The appUCatlen of ARCO Eva M Kaufmann being first duly Alaska, Inc. tar a.public hear- in9 to print testimony for sworn on oath deposes and says a pfd dal a„ry� pool Pool end that she is the Advertising ltsdeveinpme Prudhoe BaY Unit of the Prudhoe Nay Representative of the Anchorage Field. Daily News, a daily newspaper. A Notice Isaskahereby. that That said newspaper has been t the o,t a as appr by the Third Judicial oar I AAC 2SS20 �o hokl,a Court, Anchorage, Alaska, and it moray hfoorrrclassification r r a and nnw and has been l s� d in the prescribing pool rules for de- and been ptab.i.,he.. ii`i t, velopment of a new pil pool in English language continual) as a the Prudhoe Bay Unit. The g continually development area is located in daily newspaper in Anchorage, the 8a Unit and is re- Alaska, and it is now and during all fanned to as the North Prudhoe Bay accumulation. said time was printed in an office A hearing will be held at the Alaska Oil and Gas Conserve - Non Commission, 3001 Porcu- maintained at the aforesaid place of pine Drive, Anchorage, Alaska 99501 at 9:00 am on October S, publication of said newspaper. 1994 in catdormamce with 20 That the annexed is a copy of an AAC 25. ' All interested - py sons and parties art invited to advertisement as it was ublished present testimony. If you are a p person with a disability who • ! . in regular issues (and not in may need a special accomme- dation, auxiliary aid or ser - supplemental form) of said vice, or alternathre communi catibn format in order to comment on the proposed ac: newspap�r on: tion, please contact Diana Ugust 26 Fleck at 279 -1433 by 4:30 pm, September 29, 1994. ,1n9 4 /s/Russell A. Douglass 77 Commissioner, Alaska On and that such newspaper was and Gas ConservaNdn Commission regularly distributed to its Pub: A u tisL26 1994 subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. signed & C \ Eva M. Kaufm Classified Advertising 'ep. 257 -4296 Subscribed and sworn to before me this 24_ day of ...�� 1994 ' j/144(414, Notary Pu 'c in and for the State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES: My Commission Expires: October 14, 1997 19 *1 II' Draft Pool Rules 8/17/94 HELD CONFIDENTIAL