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CO 423
INDEX CONSERVATION ORDER NO. 423 Milne Point Field 1) December 11, 1997 BP Exploration Exhibits 2) December 23, 1997 Notice of Public Hearing, Affidavit of Publication 3) February 24, 1998 BP Exploration MPU 1998 Plan of Development 4) February 25, 1998 Transcript, sign in sheet and exhibits 5) April 17, 2018 Administrative Approval Milne Point Well MP C-46 6) ------------------- Email CONSERVATION ORDER NO. 423 ~ ~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION :.3001 Porcupine Drive Anchorage Alaska 99501-3192 Re: THE APPLICATION OF BP ) EXPLORATION (ALASKA) INC. to ) present testimony for classification of a new ) pool and the establishment of pool rules for ) development of the Sag River oil pool in the ) Milne Point Unit. ) Conservation Order No. 423 Milne Point Field Milne Point Unit Sag River oil pool May 6, 1998 IT APPEARING THAT: 1. By letter dated December 5, 1997, BP Exploration (Alaska) Inc. ("BPX") requested a public hearing to present testimony to define the Sag River oil pool in the Milne Point Unit and establish pool rules for development and production of the reservoir. 2. The Commission published notice of public hearing in the Anchorage Daily News on December 23, 1997. 3. A hearing concerning the matter of the applicant's request was convened in conformance with 20 AAC 25.540 at the Commission's offices, 3001 Porcupine Drive, Anchorage, Alaska 99501 at 9:00 am on January 27, 1998. FINDINGS: 1. The vertical limits of the Sag River oil pool maybe defined in the Milne Point Unit A-O1 ("MPA-O1") well between the measured depths of 8810 feet to 8884 feet, which appears to contain. a typical and representative stratigraphic section of the reservoir 2. The MPA-O1 well is located near Kavearak Point in Section 23, Township 13 North, Range 10 East, Umiat Meridian. 3. The portion of the pool that BPX proposes to develop is within the Milne Point Unit. 4. BPX evaluated five Sag River wells within the proposed project area with either conventional core or rotary sidewall cores and borehole geophysical data and an additional six Sag River wells with borehole geophysical data only. 5. BPX integrated petrophysical information with an extensive seismic grid throughout the proposed project area to develop more complete knowledge of the reservoir. 6. The Sag River Formation is late Triassic to early Jurassic in age and consists primarily of thin marine shelf sand intervals throughout the central portion of the North Slope. Conservation Order IV~ 23 May 6, 1998 Page 2 7. BPX has subdivided the Sag River Formation within the Milne Point Unit into four laterally extensive sub-zones, A through D. The zones are fairly uniform in thickness and have similar reservoir properties. - ~ ~- 8. Zone A is the basal 'Sag River sandstone unit, which uncomformably overlies the Shublik Formation. The interval in the proposed project area is composed almost entirely of non- reservoir sandstone, with porosity to 18%, permeability to 1.2 millidarcies, and an average gross thickness of about 16 feet. 9. Zone B is the primary Sag River reservoir interval, with porosity to 21%, permeability to 23 millidarcies, and an average gross thickness of 30 feet. 10. Zone C is the uppermost Sag River Formation sandstone interval. Zone C is generally non- reservoir with porosity to 17%, permeability to 2.9 millidarcies and an average gross thickness of 10 feet. 11. Zone D is non-reservoir siltstone and shale at the top of the Sag River Formation; its average gross thickness is about 21 feet. 12. The combination of moderate to good porosity and poor permeability observed in zones A through C are the result of two processes, bioturbation and diagensis. 13. Core data shows extensive carbonate cementation and greater grain densities in Zones A and C. 14. BPX estimates Sag River net pay to range from 9 to 18 feet and permeability-thickness to range from 30 to 68 millidarcy-feet within the proposed project area. 15. The trapping mechanism observed in the Sag River oil pool is predominately structural, consisting of three-way anticlinal closures sealed against the downthrown side of faults, with throws generally greater than 50 feet. 16. An orthogonal fault pattern segments the oil column into three known equilibration regions throughout the project area. The known oil-water contacts are at 9150 feet, 9050 feet, and 8950 feet subsea. 17. Flexibility in well placement will be needed because of the area's structural complexity and complex faulting. 18. The Ivishak, Shublik and Lisburne Formations, which are productive elsewhere on the North Slope, have not been shown to contain more than residual hydrocarbon saturation in the proposed project area. The Ivishak Formation contains high water saturation even when encountered in fault blocks above the Sag River oil-water contacts. 19. BPX used permeability values on the order often times those observed in core data to realize accurate simulation of well performance in the Sag River Formation 20. Core and borehole geophysical data show extensive fracturing within the Sag River Formation. Conservation Order N'T'423 May 6, 1998 Page 3 21. BPX estimates the original oil-in-place (OOIP) at 62 MM STB oil and the reservoir area about SSOO acres based upon seismic and.log data. •- - -- 22. Sag River crude oil properties are: gravity 39.2° API, solution gas-oil ratio 974 SCF/STB, formation volume factor 1.56 RB/STB, viscosity .277 centipoise, gas gravity .8, and bubble point pressure 3513 psi. 23. BPX recorded an initial reservoir pressure of 4425 psi and a temperature of 235° F at 8750 feet subsea datum. 24. BPX estimates primary recovery at about 15% of OOIP assuming solution gas drive with some limited aquifer pressure support. 25. Some form of gas or water injection, or a combination of both, will be needed to obtain maximum ultimate recovery. Full field model studies by BPX indicates as much as 38% of OOlP maybe recovered depending on the timing and type of pressure maintenance project implemented. 26. The current development plan proposed by BPX will require 25 wells, with 16 producers and 9 injection wells. 27. BPX plans on surface commingling Sag River production with Kuparuk River and Schrader Bluff production for processing at existing Milne Point surface facilities. Production from each pool will be determined by using production tests in a common test separation facility. BPX proposes to apply a single allocation factor for all pools in the MPU production system. 28. BPX has no plans to commingle the separate pools within any wellbore in the Milne Point Unit. 29. BPX will use electric submersible pumps (ESP) for primary artificial lift. ESP wells will not utilize packers or subsurface safety valves as part of their completion. 30. BPX proposes to measure reservoir pressure annually in newly drilled and existing wells. 31. Enhanced recovery injection will use gas from the Sag River oil pool, and may require additional make up gas from the Kuparuk River and Schrader Bluff pools. High-pressure gas lines may be added to allow gas injection into the Sag River oil pool. 32. BPX plans on using alternative completions methods such as different liners types, open hole completion, multi-laterals, horizontal wellbores and combinations of the above to optimize drainage and improve recovery. CONCLUSIONS: Pool rules for the initial development of the Sag River oil pool are appropriate at this time. 2. Initial development of the Sag River oil pool will occur on leases participating in the Milne Conservation Order 1423 ~ Page 4 May 6, 1998 Point Unit. 3.. The eastern.and northern productive.limits of.the Sag River intervaLwithin he Milne Point Unit vicinity have not been delineated. 4. Well spacing units of 40 acres will allow the operator sufficient flexibility to locate wells to accommodate geologic, stratigraphic and structural factors throughout the project area. 5. Alternative completion practices will allow flexibility and enable the operator to optimize drainage and maximize ultimate recovery. 6. Early implementation of an enhanced recovery operation to support reservoir pressure will preserve reservoir energy and enhance ultimate recovery. 7. Sag River production will be allocated using exiting test facilities and methods applied to the Kuparuk River and Schrader Bluff pools. 8. Reservoir pressure will be measured at injection and production wells using standard industry practices on a regular basis to manage production and monitor reservoir performance. 9. Exception from the gas-oil-ratio limitations of 20 AAC 25,240 is appropriate provided a pressure maintenance project starts within six months of the start of regular production. NOW, THEREFORE, IT IS ORDERED THAT the rules hereinafter set forth, in addition to statewide requirements under 20 AAC 25 apply to the following affected area referred to in this order. Umiat Meridian T12N R11E Sections 2, 3, l 1. T13N R11E Sections 18, 19, 29, 30, 31, 32 T13N R10E Sections 2, 3, 4, 5, 6, 9, 10, 11, 12, 13, 14, 15, 22, 23, 24, 25, 36 T14N R10E Sections 29, 30, 31, 32, 34, 35 T14N R9E Sections 25, 36 Rule 1 Field and Pool Name The field is the Milne Point River Field. Hydrocarbons underlying the affected area within the Sag River Formation constitute a single oil and gas reservoir called the Sag River oil pool. Rule 2 Pool Definition The Sag River oil pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 8810 feet and 8884 feet in the Milne Point Unit No. A-01 well. Conservation Order 23 ~ - Page 5 May 6, 1998 Rule 3 Spacing_Units Nominal spacing units within the pool will be 40 acres. 'The pool shall not be opened in any well closer than 500 feet to an external boundary where ownership changes. Rule 4 Casing and Cementing Practices a.) Conductor casing shall be set at least 75 feet below ground level and cemented to surface. b.) Surface casing shall be set at least 500 feet below the permafrost and cemented to the surface. Rule 5 Completion Practices The following alternative completion methods are allowed: a.) Liners, to include but not limited to slotted, pre-drilled, pre-packed and sintered, or a combination thereof, landed inside of cased hole and which may be gravel or frac packed. b.) Open-hole completions provided that the casing is set not more than 100 feet above the uppermost oil bearing zone. c.) Multi-lateral completions, in which more than one branch of the wellbore is completed in the Sag River oil pool, connected to a single common wellbore with production gathered and routed through common production tubing to the surface. d.) Injection into the Schrader Bluff, Kuparuk and/or the Sag River pools using a common wellbore with packers and down-hole flow control devices to regulate injection into each interval. e.) The Commission may approve other completion methods upon application. Rule 6 Well Completions Production or injection wells may be completed with tapered casing provided a sealbore, packer, or other isolation device is positioned not more than 200 feet above the top of the productive interval. Rule 7 Automatic Shut-in Equipment a.) All wells capable of unassisted flow of hydrocarbons must be equipped with afail-safe automatic surface safety valve. b.) Injection wells must be equipped with a double check valve arrangement. c.) Surface safety valves must be tested at six-month intervals. Rule 8 Common Production Facilities and Surface Comminalin~ a.) Production from the Sag River oil pool may be commingled with production from the Kuparuk River and Schrader Bluff oil pools in surface facilities prior to custody transfer. b.) Each producing Sag River well must be tested a minimum of two times per month. c.) The Commission may require more frequent or longer tests if the allocation quality Conservation Order N~:'423 May 6, 1998 deteriorates. Page 6 d.) The operator shall submit a monthly file(s) containing daily allocation data and daily test data or agency surveillance and evaluation. Rule 9 Reservoir Pressure Monitoring a.) Prior to regular production or injection an initial pressure survey must be taken in each well. b.) At least one bottom-hole pressure survey per four producing or injecting governmental section shall be measured annually. No less than four reservoir pressures will be measured annually. Bottom-hole surveys in paragraph (a) may fulfill the minimum requirement. c.) The reservoir pressure datum will be 8750 feet subsea. d.) Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or extrapolated from surface, pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, representative ESP pressure measurements, and open-hole formation tests. e.) Data and results from pressure surveys must be reported quarterly on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412 but must be available to the Commission upon request. f.) Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (e} of this rule. Rule 10 Gas-Oil Ratio Exem tion Wells producing from the Sag River oil pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply. Rule 11 Pressure Maintenance Project A pressure maintenance project must be initiated within six months after the start of regular production from the Sag River oil pool. Rule 12 Reservoir Surveillance 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 implementation and reservoir management summary including engineering and geotechnical parameters. b.) Voidage balance by month of produced fluids and injected fluids and cumulative status. c.) Analysis of reservoir pressure surveys within the pool. d.) Results and where appropriate, analysis of production and injection log surveys, tracer surveys and observation well surveys. e.) Review of pool allocation factors over the prior year. £) Future development plans. Conservation Order N~'~423 May 6, 1998 Rule 13 Production Anomalies Page 7 In the event of..oil production,capacity.proration at or from.-the Milne Point.Unit facilities, all commingled reservoirs produced through the Milne Point Unit facilities will be prorated by an equivalent percentage of oil production, unless this will result in surface or subsurface equipment damage. Rule 14 Administrative Action Upon proper application, 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, and is based on sound engineering principles. DONE at Anchorage, Alaska and dated I\ '~ ~~' J ` '"r~r '~ ~~ ,. ~. - i ~ L ~_ ' f a +4 ' -~,. r Commissioner 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 ofthe 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 ofthe 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). • • CORRECTION CONSERVATION ORDER N0.423 ISSUED MAY 6. 1998 May 12, 1998 Page 4 Should read: Rule 1 Field and Pool Name The field is the Milne Point Field. Hydrocarbons underlying the affected area within the Sag River Formation constitute a single oil and gas reservoir called the Sag River oil pool. • • 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 ) e 1 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 jip .- Daniel T. Sear o , r., Commissioner, Chair • • . Oil. 4 : . s Conservation Commission ofr o‘A oil 44 r 0 rman, Coer 0, 104 ' - :- a Oil , , • 4 a Conserva ion Commission . 0 i' I f 4. z ' ��'' Cat y P. : oerst- r, Commissioner � r i,'N O' 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(6), "[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'; 'caunderwood'; 'Chris Gay'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber; 'ddonkel @cfl.rr.com'; 'Deborah J. Jones'; De!bridge, 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 Lambet; '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; 'trmjr1; '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'; 'Cara 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.colombie @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 @a►aska.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); Pasqua!, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.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 Samlamthcv Fi/shev 14 l aisi Oa' a L Ga' Con -earva ,o v Ca Boni (907)793 -1223 (907)276 -7542 (fay.) 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 Ct. 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 V\\ Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Reqts from Order Revised Rule - "Well safety valve systems" (2) Comment fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265( "In wells (excludin dis injectors) must be equipped with(i) a double check valve 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 h 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 25.265(h)(5) ) 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 . 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(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 (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; 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 25.265(m) N deactivated SVS was replaced with requirement to maintain a deactivated SVS; si m 9 ( ) tag on well when not manned fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(x); 25.265(b); 25.265(d)( "Injection wells (excludin dis 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 25.265(a); 25.265(b); 25.265(d)( "Injection wells (excludin dis injectors) must be equipped with(i) a double check valve 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 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 th nt es the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require wells (excludin disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.265(b); 25.265(d)( 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 h . 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 th le check valve es the requirements of a sing." 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 Milne Point Unit Milne Point Readopted 25.265(d) dictates which wells require SSSV; 477 5 yes injection well require SSSV or injection valve below permafrost test 25.265(a); 25.265(b); 25.265(d); N/A Schrader Bluff 25.265(h)(5) replaces SSSV nipple requirement for all wells every 6 months fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Borealis 471 3 yes injection well require SSSV below permafrost; test every 6 months 25.265(h)(5) N/A replaces SSSV nipple requirement for all wells Northstar Northstar 458A 4 no fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500• 25.265(b); ); 25.265(d)(1) "The minim setting depth for a tubing conveyed subsurface safety valve is 500 feet." Existing pool rule established a minimum setting depth for the 25.265(a) ft minimum setting depth for SSSV ; 25.265 b 9 9 Y y SSSV Prudhoe Ba Unit Aurora 457B 3 yes 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; Y 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 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 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 25.265(h)(5) 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 all wells - fail -safe auto SSV and SCSSV; SSSV may be installed above or below 25.26.� ,- (a); 25.265(b); 25.265(d)(1) "The setting depth of a required subsurface safety valve must be located in the tubing either Existing pool rule established alternate SSSV setting depth; ; 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 wells require CO 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 25.265(h)(5) 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 . a ; .265 b 25.265(h)(5); deactivated SVS was replaced with requirement to maintain a 25265 25 Kuparuk River Unit; O Kuparuk 432D 5 yes prescribed by Commission; CO 432D.009 modifies Rule 5(b) - LPP N/A tag on well when not manned; administrative approval CO 25 m Milne Point Unit may be defeated on W. Sak injectors w /surface pressure <500psi w/ 25.265(m) 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 UnitlFieid Pool Conservation Rule Rescind Rule? Existing Order Requirement New Regulation Provisions Order (1) g Revised Rule - "Well safety valve systems" (2) Comment q Addressing Reqts from Order 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 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 25.265(h)(5) SCSSV satisfies the requirements of a single check valve" SSSV requirement for MI injectors Milne Point Sag fail -safe auto SSV; injection wells require double check valve; test In j q PP Check valve requirements for injectors are not covered by Milne Point Unit 423 7 no 25.265 ( a ) ; 25.265 ( b ) 25.265(h)(5) ; ection wells must bee ui equipped with a double check valve arrangement." readopted regulation River every 6 months fail -safe auto SSV; gas /MI injectors require SSV and single check valve and SSSV landing nipple; injection require ( ni le; water injection wells re (i) double "Injection 1 wells (excluding disposal injectors) equipped with(i) a double check valve Check valve requirements for injectors are not covered by dis osal injectors ) must be a ui ed with readopted lation; readoted 25.265d5 d include Kuparuk River Unit Kuparuk regu p ( )( ) oes not West Sak 406B 6 no 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 4066.001 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 quirement for MI injectors; administrative approval CO d injectors w /surface pressure <500psi w/ notice when defeated and defeated on West Sak water injectors with surface injection pressure less than 500psi" 4068.001 remains effective [re:defeating the LPS when surface placed back in service injection pressure for West Sak water injector is <500psij 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 Prudhoe Bay Unit North Prudhoe 345 4 yes deactivated; maintain list of wells w /deactivated SVS; test as 25.265(a); 25.265(b); 25 N/A Requirement to maintain a wellhead sign and list of wells with 2 5.265 m 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 Prudhoe Bay Unit Prudhoe 341E 5 yes be maintained and tested as part of SVS; sign on well if SV 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; deactivated; maintain list of wells w /deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for all wells prescribed by Commission Prudhoe Bay Unit Niakuk 329A 5 yes fail -safe auto SSV and SCSSV; maintain list of wells w/ removed o 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; deactivated SVS; sign on wellhead 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells Prudhoe Bay Unit Pt. McIntyre 317B 8 yes 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; routine well ops w/o notice 25.265(j); 25.265(m) replaces SSSV nipple requirement for all wells Prudhoe Bay Unit West Beach 311 B 6 yes fail -safe auto SSV; sign on w 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; w /deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV nipple 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 Prudhoe Bay Unit Lisburne 207A 7 yes fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wel 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with y w /deactivated SVS; test as prescribed by Commission 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a tag on well when not manned Prudhoe Bay Unit Prudhoe - Kuparuk 98A 5 es suitable automatic safety valve installed below base of permafrost t Readopted 25.265(d) dictates which wells require SSSV; y prevent uncontrolled flow 25.265(d) N/A replaces SSSV nipple requirement for all wells Statewide N/A N/A N/A yes Commission policy dictating SVS performance testing AOGCC Policy- SVS Failures; issued by order of the y requirements 25.265(h): 25.265(n); 25.265(0) N/A Commission 3/30/1994 (signed by Commission Chairman 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 THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 423.001 Mr. Paul Chan Senior Operations Engineer Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket Number: CO -18-011 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alciska.gov Request for administrative approval to amend Rule 10 Gas -Oil Ratio (GOR) Exemption of Conservation Order No. 423 (CO 423) to allow the production of well Milne Point C-46 (PTD 217-052) at a GOR more than twice the initial GOR in absence of an ongoing EOR injection project. Milne Point Field Milne Point Unit Sag River Oil Pool Dear Mr. Chan: By letter dated April 17, 2018, Hilcorp Alaska, LLC (Hilcorp) requested administrative approval to amend Rule 10 of CO 423 to authorize production from the Milne Point C-46 (MP C-46) well with a GOR in excess of twice the initial GOR without an ongoing EOR injection projection in the Sag River Oil Pool (SROP) as is currently required by Rule 10. In accordance with Rule 14 of CO 423, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request to allow continued production from the MP C-46 well. Rule 10 Gas -Oil Ratio Exemption of CO 423 currently states: "Wells producing from the Sag River oil pool are exempt from the gas -oil -ratio limits of 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply." 1 ' CO 423 was issued on May 6, 1998. On November 7, 1999, new regulations governing GOR limitations came into effect and changed the ordering of this regulation such that the citations in the current rule do not match up with the proper corresponding part of the new regulation. The correct current citations to replace those in the current Rule 10 are 20 AAC 25.240(a) and 20 AAC 25.240(b)(1) respectively. CO 423.001 August 7, 2018 Page 2 of 3 The SROP began regular production in May 1995 and began water injection in July 2002. Water injection ceased in October 2012. The initial GOR of the SROP was 974 SCF/STB. Producing a well with a GOR more than twice the initial GOR (in this case the limit is 1,948 SCF/STB) for the pool is prohibited without an order from the AOGCC authorizing such production. Prior to commencing and subsequent to ceasing water injection the pool -wide GOR did not exceed the limit established by 20 AAC 25.240(a). Ceasing water injection has not negatively impacted recovery from the SROP. In fact, recovery from the SROP has increased substantially in recent years due to drilling and workover activities performed by Hilcorp since it became the operator of the Milne Point Unit (MPU). One of the wells that Hilcorp drilled was the MP C-46 well completed in July 2017 and brought on production in August of that year. The MP C-46 well came on production with a GOR higher than the pool - wide average and increased steadily until February 2018 at which time the well was shut in because of the GOR limitation due to the lack of EOR injection occurring in the SROP. The higher initial and rapidly increasing GOR coupled with a rapid decrease in the bottomhole pressure at the MP C-46 location have changed Hilcorp's view of reservoir connectivity in the SROP. When the MP C-46 well was completed Hilcorp believed the bottomhole location would be in communication with the remainder of the SROP. The current interpretation is that the portion of the SROP where the MP C-46 well is located is more compartmentalized than previously thought, there's not strong communication with the remainder of the pool, and the rapid pressure drop indicates the compartment that the MP C-46 well is completed in is small with limited reserves. Because the small compartment that the MP C-46 well is in is not well connected to the rest of the SROP, resuming EOR injection elsewhere in the pool will not have a beneficial effect on production at the well. Because ceasing injection activities had no substantial effect on recovery from the SROP, EOR injection for MP C-46 will not benefit the rest of the SROP. And the compartment the well is located in is not large enough to justify drilling and completing an injector in that fault block. Rule 14 of CO 423 allows the AOGCC to amend the order administratively if the change does not promote waste or jeopardize correlative rights and is based on sound engineering judgment. As discussed above, EOR injection to support the MP C-46 well is not viable; so allowing the well to resume production at a producing GOR that exceeds the GOR limit will not cause waste. In fact, waste would only be caused if this well was prohibited from producing further because of the reserves that would be stranded. The well is located within a defined pool within the MPU and thus correlative rights are protected. Producing the MP C-46 well at a GOR that exceeds the limits established by 20 AAC 25.240(a) is a sound engineering decision because it is the only viable way to produce the well and not strand reserves. Additionally, and on its own motion, the AOGCC is amending Rule 14 of CO 423 to reflect the circumstances under which CO 423 can be amended by way of administrative approval. Now, therefore it is ordered that Rules 10 and 14 of CO 423 are amended to read as follows CO 423.001 August 7, 2018 Page 3 of 3 Rule 10 Gas -Oil Ratio Exemption Wells producing from the Sag River oil pool are exempt from the gas -oil ratio limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b)(1) apply. Additionally, the Milne Point C-46 well (PTD 217-052) is exempt from the gas -oil ratio limitations of 20 AAC 25.240(a) regardless of whether the provisions of 20 AAC 25.240(b)(1) apply. Rule 14 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission my 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. DONE at Anchorage, Alaska and dated August 7, 2018. H ollis S. French Cathy P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner 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 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. rHE STATE 01ALASKA (,OVFiRNOR BILL NVALRFR Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 423.001 Mr. Paul Chan Senior Operations Engineer Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket Number: CO -18-011 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative approval to amend Rule 10 Gas -Oil Ratio (GOR) Exemption of Conservation Order No. 423 (CO 423) to allow the production of well Milne Point C-46 (PTD 217-052) at a GOR more than twice the initial GOR in absence of an ongoing EOR injection project. Milne Point Field Milne Point Unit Sag River Oil Pool Dear Mr. Chan: By letter dated April 17, 2018, Hilcorp Alaska, LLC (Hilcorp) requested administrative approval to amend Rule 10 of CO 423 to authorize production from the Milne Point C-46 (MP C-46) well with a GOR in excess of twice the initial GOR without an ongoing EOR injection projection in the Sag River Oil Pool (SROP) as is currently required by Rule 10. In accordance with Rule 14 of CO 423, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request to allow continued production from the MP C-46 well. Rule 10 Gas -Oil Ratio Exemption of CO 423 currently states: "Wells producing from the Sag River oil pool are exempt from the gas -oil -ratio limits of 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply." t 1 CO 423 was issued on May 6, 1998. On November 7, 1999, new regulations governing GOR limitations came into effect and changed the ordering of this regulation such that the citations in the current rule do not match up with the proper corresponding part of the new regulation. The correct current citations to replace those in the current Rule 10 are 20 AAC 25.240(a) and 20 AAC 25.240(b)(1) respectively. CO 423.001 August 7, 2018 Page 2 of 3 The SROP began regular production in May 1995 and began water injection in July 2002. Water injection ceased in October 2012. The initial GOR of the SROP was 974 SCF/STB. Producing a well with a GOR more than twice the initial GOR (in this case the limit is 1,948 SCF/STB) for the pool is prohibited without an order from the AOGCC authorizing such production. Prior to commencing and subsequent to ceasing water injection the pool -wide GOR did not exceed the limit established by 20 AAC 25.240(a). Ceasing water injection has not negatively impacted recovery from the SROP. In fact, recovery from the SROP has increased substantially in recent years due to drilling and workover activities performed by Hilcorp since it became the operator of the Milne Point Unit (MPU). One of the wells that Hilcorp drilled was the MP C-46 well completed in July 2017 and brought on production in August of that year. The MP C-46 well came on production with a GOR higher than the pool - wide average and increased steadily until February 2018 at which time the well was shut in because of the GOR limitation due to the lack of EOR injection occurring in the SROP. The higher initial and rapidly increasing GOR coupled with a rapid decrease in the bottomhole pressure at the MP C-46 location have changed Hilcorp's view of reservoir connectivity in the SROP. When the MP C-46 well was completed Hilcorp believed the bottomhole location would be in communication with the remainder of the SROP. The current interpretation is that the portion of the SROP where the MP C-46 well is located is more compartmentalized than previously thought, there's not strong communication with the remainder of the pool, and the rapid pressure drop indicates the compartment that the MP C-46 well is completed in is small with limited reserves. Because the small compartment that the MP C-46 well is in is not well connected to the rest of the SROP, resuming EOR injection elsewhere in the pool will not have a beneficial effect on production at the well. Because ceasing injection activities had no substantial effect on recovery from the SROP, EOR injection for MP C-46 will not benefit the rest of the SROP. And the compartment the well is located in is not large enough to justify drilling and completing an injector in that fault block. Rule 14 of CO 423 allows the AOGCC to amend the order administratively if the change does not promote waste or jeopardize correlative rights and is based on sound engineering judgment. As discussed above, EOR injection to support the MP C-46 well is not viable; so allowing the well to resume production at a producing GOR that exceeds the GOR limit will not cause waste. In fact, waste would only be caused if this well was prohibited from producing further because of the reserves that would be stranded. The well is located within a defined pool within the MPU and thus correlative rights are protected. Producing the MP C-46 well at a GOR that exceeds the limits established by 20 AAC 25.240(a) is a sound engineering decision because it is the only viable way to produce the well and not strand reserves. Additionally, and on its own motion, the AOGCC is amending Rule 14 of CO 423 to reflect the circumstances under which CO 423 can be amended by way of administrative approval. Now, therefore it is ordered that Rules 10 and 14 of CO 423 are amended to read as follows. CO 423.001 August 7, 2018 Page 3 of 3 Rule 10 Gas -Oil Ratio Exemption Wells producing from the Sag River oil pool are exempt from the gas -oil ratio limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b)(1) apply. Additionally, the Milne Point C-46 well (PTD 217-052) is exempt from the gas -oil ratio limitations of 20 AAC 25.240(a) regardless of whether the provisions of 20 AAC 25.240(b)(1) apply. Rule 14 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission my 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. DONE at Anchorage, Alaska and dated August 7, 2018. //signature on file// Hollis S. French Chair, Commissioner //signature on file// Cathy P. Foerster Commissioner AND //signature on file// Daniel T. Seamount, Jr. 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 fine shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be en oneous. 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.mon the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: To: Tuesday, August 07, 2018 3:27 PM Bell, Abby E (DOA); Bixby, Brian D (DOA); Boyer, David L (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Earl, Adam G (DOA); Erickson, Tamara K (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Laubenstein, Lou (DOA); Loepp, Victoria T (DOA); Martin, Teddy J (DOA); McLeod, Austin (DOA); Mcphee, Megan S (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Rixse, Melvin G (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWeIIIntegrityCoordinator; Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer; Barbara Kruk; bbritch; bbohrer@ap.org; Ben Boettger, Bill Bredar; Bob Shavelson; Bonnie Bailey; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cody Gauer; Cody Terrell; Colleen Miller; Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Pascal; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Morris; George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Greg Kvokov; Gretchen Stoddard; gspfoff; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington (arlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt; Jim White 6im4thgn@gmail.com); Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); Jon Goltz; Joshua Stephen; Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick; Michael Schoetz; Mike Morgan; MJ Loveland; Motteram, Luke A; Mueller, Marta R (DNR); Nathaniel Herz; knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Tirpack; Robert Warthen; Ryan Gross; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Spuhler, les J (DNR); Stephanie Klemmer; Stephen Hennigan; Stephen Ratcliff; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer; Teresa Imm; Terry Caetano; Tim Mayers; Todd Durkee; Tom Maloney; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vern Johnson; Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Casey Sullivan; Corey Munk; Don Shaw; Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Matt Armstrong; Melonnie Amundson; Franger, lames M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Scott Pins; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke; Zachary Shulman Subject: CO 423.001 Hilcorp Attachments: CO 423.001.pdf Re: Docket Number: CO -18-011 Request for administrative approval to amend Rule 10 Gas -Oil Ratio (GOR) Exemption of Conservation Order No. 423 (CO 423) to allow the production of well Milne Point C-46 (PTT) 217-052) at a GOR more than twice the initial GOR in absence of an ongoing EOR injection project. Milne Point Field Milne Point Unit Sag River Oil Pool As a courtesy I am emailing the attached Administrative Approval. Please remember to sign up for AOGCC Notices and Orders immediately. Effective immediately the AOGCC will be using a listsery to send all Public Notices. This includes items such as Public Hearing Notices and AOGCC Orders. If you or your organization would like to continue to receive Public Notices from AOGCC please sign up at this link: httv://Iist.state.ak.us/main anilistinfo/aogccMublic notices. Thank you, Jody J. Colombie AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7°i Avenue Anchorage, Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 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 Jody Colombie at 907.793.1221 or jody.colombieOalaska.¢ov. 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. Box 60868 Fairbanks, AK 99706 A J From: Sent: Roby, David S (DOA) To: Thursday, May 10, 2018 9:55 AM French, Hollis (DOA); Foerster, Catherine P (DOA); Seamount, Dan TD Cc: (LAW) Subject: Colombie, Jody 1 (DOA) (Oq)%Ballantine, Tab A RE: GOR Waiver for the MPU C-46 well We already have information regarding reserves in the application they submitted. Dave Roby (907)793-1232 CONFIDENT/gL/ryNOTIC� This e-mail message, including any attachments, The unauthorized NOTrevICE: This of Alaska and is for the sole use contains inform Please delete it, use or disclosure of such information use Of the intended recipients , information from the Alaska Oil and (9071793.1 without first saving or forwardin () �t maY contain confidential and as Conservation 232 or wave robe@ g it, and• sot the violate state w federal law. If you are an /or privileged ahsk°ti that the AOGCC is aware unintended recipient information. Of the mistake in sending it to p of this e-mail, From: French, You, Contact Dave Roby at Sent: Thursda Hollis (DOA) Y May 10, 2018 9:45 AM To: Foerster, Catherine P (DOA) <cathy.foerster (DOA) <rster, am hent@ alaska. <Cat @alaska.gov>; Roby, Cc: Colombie, Jody g Ballantine<jod, Tab A Y David S (DOA) <dave.roby@alaska. ov>; Subject: RE: GOR Waiver for the MPU C 4Y-COlomb16 well (LAW) <tab.ballantine@alaska.gov> g Seamount, Dan T @elaska.gov> I guess I would also lean towards a hearing. We could ask a few questions about the articulate the points that Dave brings up about the block being too small to su Potential for waste, just to make Hilcorp From: Foerster, Catherine P (DOA) pPort an injector, etc. Sent: hUrsday, May 10, 2018 9:31 AM To: Roby, David S <danseamount (pOA) <dave.robv(caala��>; French, Hollis (DOA) < alaska. ov>; Ballantine, Tab A ) hollis.french CC: Colombie, JO J (DOA) < (LAW) < alaska. ov>; kdy- olombieCilalaska >tab.ballantine alaska. ov> Seamount, Dan T (DOA) Subject: RE: GOR Waiver for the MPU C-46 well missing something, let me know and I'll take a firmer stand. I can go either way. It sounds like we already know the answer; so I wonder what purpose the hearing would serve. If I'm -rom: Roby, David S (DOA) lent: Wednesday, May 09, 2018 4:44 PM 'o: French, Hollis (DOA) <holils.french (DOA) <cathv foerster(a�alaska alaska. ov>; Seamount, Dan T c: Colombie, Jody °V>% Ballantine, Tab A (DOA) <dan.seamount alaska. ov>; Foerster, Catherine Ibject: GOR Waiver(foOAhecolombiefa�ala a (LAW) <tab.ballantine alaska. ov> MPU C-46 well ov> corp has submitted an application for a permanent GOR waiver for the recently completed MPU C-46 well, which produces m the Sag River Formation. There are pool rules for the Sag River that do contain a GOR waiver but that waiver er Is contingent on ongoing EOR injection which ceased in 2012 and they have no plans to resume EOR injection any time soon. There's only a handful of wells producing from the Sag now and all but the C-46 are below the GOR limitation in the regs. The C-46 well is located in a small isolated fault block that's not big enough to justify an injection well and the one existing injection well in the Sag is not in a location where it would do any good for any of the producers so returning it to service is not prudent. Hilcorp has asked that we consider their application administratively. The admin approval clause in the pool rules states: Upon proper application, 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, and is based on sound engineering principles. So, theoretically, if we determine that waste will not occur (which is a gray area since without pressure support some oil would be left behind as the C-46 is produced but leaving behind some of something still recovers more oil than recovering all of nothing) we do have the authority to administratively amend the GOR waiver in the pool rules. However, I lean towards holding a hearing on this matter since by regulation GOR waivers that are not associated with an EOR project or data gathering require a hearing. Thoughts? Dave Roby Sr. Reservoir Engineer Alaska Oil and Gas Conservation Commission (907)793-1232 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 Dave Roby at (907)793-1232 or dave.robv@alasko.00v. 9 Hilcorp Alaska, LLC April 17", 2018 Hollis S. French, Chair Alaska Oil and Gas Conservation Commission 333 West 7"' Avenue, Suite 100 Anchorage, Alaska 99501 RE: Milne Point Well MP C-46 (PTD 217-052) Request for Administrative Approval to CO 423 Dear Commissioner French, Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Paul Chan Senior Operations Engineer (907)777-8333 APR 17 2018 At®GCC Hilcorp Alaska, LLC ("Hilcorp"), as Operator of the Milne Point Unit, requests Administrative Action of Conservation Order No. 423 as per Rule 14 to exceed the Gas - Oil ratio limitations of 20 AAC 25.240 (a). Background The MP C-46 well targeted the western updip edge of a faulted area in the Sag River formation. The well was placed on the western edge of a faulted area with the intent to add injection support on the eastern down dip edge of the fault block at a later date. After fracture stimulating the well, production rates from the well did not match with the original estimated drainage area and Hilcorp proceeded to re -work the geophysical interpretation of the area. Modeling The following work products are complete: • Computer Modelling Group's (CMG) reservoir model built to forecast rate and cumulative oil production ("Original Field Study") • Performed two sets of pressure buildup (PBU) tests (the first was done 21 days after initial production and the second PBU was completed six months later). The data was analyzed using IHS Well Test software to estimate reservoir pressure, permeability and skin. • Calculated tank size using MBAL material balance software using P*/Pi data from PBU analysis. Geologist re -mapped area from seismic data independently of original field study. Updated "Original Field Study" CMG model to perform history match. Conclusions • First pressure transient analysis (PTA) estimated reservoir pressure to be 3,129 psi after 21 days of production. • Second PTA estimated reservoir pressure to be at 2,600 psi after six months of production. • MBAL estimates tank size at 1.3-1.4 MMBO using the pressures from the PTA. • New geologist mapped tank size estimated at 1.22 MMBO • Reduced oil in place due to faulting and smaller area from new geologist mapping. • CMG history match forecasts 200 MBO recovery due to the small drainage area. • An offset injection well is uneconomic due to small reservoir volume. • The best option to develop this isolated fault block would be under solution gas drive, which should not affect the rest of the reservoir due to compartmentalization. Request Waiver of the Gas -oil ratio limitations on 20 AAC 25.240 (a) and allow the well to be produced by solution gas drive. Please do not hesitate to contact Paul Chan at 907-777-8333 should you have any questions regarding this application. Sincerely, W ( L_ Paul Chan, Senior Operations Engineer HILCORP ALASKA, LLC Attachments: MP C-46 Original Field Study MP C-46 Production to Date MP C-46 First PBU Analysis MP C-46 Fault Mapping Update MP C-46 Modeling Update MP C-46 Second PBU Analysis M1 a C-46 Sag_C-48_C-46inj_no_frac.irf Time (Date) Oil Rate SC Sag_C-46_L-55 no_frac.irF ---------------Cumulative Oil SC Sag_C-46_L-55_no_frac.irf Oil Rale SC C-46 history.fhf Cumulative Oil SC C-46 history.fhf • Primary Recovery: -Cum oil = 0.82 MMBO by 2040 -00IP(P50)=-6.0 MMBO Confidential 10000 100 t0 Cureale<Iw Geo Prod0e11am 195.2 P1140-- 011 PradPallani 59.2 Mbbl -- Water ProdutWnt 131 Mbbl -- Gas InjeaOani .0 Mrld -- Water Sn)edfane .0 Mbbl r'onfidential P Within 3 months of production the oil rate dropped from 1200 BOPD to 300 BOPD m' -- Uj History P i (syn) 3834.2 p5l(aJ kh 48.1021 md.ft Xt 225.174 ft 00 p`m,na 3128.0 psi(a) h 35.000 n X, 2000.000 ft - 0 CUM, 14.66 Mbbi k 1.3743md Ye 2000.000ft 1417.21 Mstb s< 2.388 X„, 1000.00oft 000IPm,�� i s -5.569 Y,,, 500.000 ft .5 m' s, -5.762 = 3000___ a -10 V � 2500 x i 2000 -—`--- —fes- _ • Paan — Pmoaa -20 w• 1500 —4e„ — qw -25 1000 - - - - -. % Error 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 Pf if Time (h) 2.00 0.00 • Both initial(Pi) and flowing pressures(Pf) were matched by varying the size of the tank • Results showed that tank size was around 1/4th the original estimation —1.4 MMBO • P* and Pi was used in MBAL • MBAL pressure match gave —1.3 MMBO Confidential • New Geo/GP Interpretation o�\ 75 F 1 u� • Pressure buildup analysis -1.4 MMBO and gave P* used for MBAL • C-46 MBAL analysis -1.3 MMBO based on production data and P* • Geo/GP new fault interpretation: Confidential -1.22 MMBO Production Date Field History File Production Date Field History File C-46 C-46 history.fhf C-46 C-46 hlstory.fhf Time (Date) 0 C Rme SO GCS ry 0 GumuWlivv OA SC G4C6 h.V M1INmyM OX RMa SG Sp C-08 Lbs �ro peaM ""CumubMn Op S'V Sep_G� Lp5 p hRM Oa Rale SG baa��CAO emspyreCCYonM --CMmA•M OI SC Sag G-0e_mMILpN1vIiM.H • Red: Old fault block interpretation history match and prediction: -OOIP: 6.0 MMBO and 820 MBO recovery by 2040 • Blue: New fault block interpretation history match and forecast: -OOIP: 1.4 MMBO and 200 MBO recovery by 2022 2020 2025 2030 2035 2040 Time (Date) 0 00".Wca helay.M 0 OMnulaNe ON SC CnB Iaalpy.M Op RMeu Sap G<6 L55 m rtac.M ............ SSG Sp GCB 665 re Irx.M W Rao Sc Sap c<6 imallyreEKllon M ------CumulMNeg5G 5e0_CA9 ama�_peEictiomel Confidential 9� 3500 3000 2500 R a 2000 m a 1500 1000 500 History o 900 800 -5 700 C -10 600 m a 91 --500 -15 400 � Z n -20 200 -25 _...___ --30 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000 4200 4400 4600 4800 5000 _ 9 Time (h) C-1 0 !.00 1.60 Estimated average reservoir pressure was obtained from recent shut in (1/27/18-4/11/18) —2.5 month=2600 psi P* 2746 psi. law- E MIE9, ONE IIIIIIII■■■I���� o 900 800 -5 700 C -10 600 m a 91 --500 -15 400 � Z n -20 200 -25 _...___ --30 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000 4200 4400 4600 4800 5000 _ 9 Time (h) C-1 0 !.00 1.60 Estimated average reservoir pressure was obtained from recent shut in (1/27/18-4/11/18) —2.5 month=2600 psi P* 2746 psi. 3,800. - __.-----._----- -------- -----'. 3,800 - -- - -- ---------- - - - 3,750 3,750 History :Tank Pressure History Tank Pressure -.- _i 3,]00 3,]00 Pi=3834 ✓-Simulation:TankPressure 3,650 Pi=3834 ✓ Simulatiln.TankPressure 3,650 3,600- -- ------ - 3,600 ._.. - . ...... 3,550psi -- 3,550 psi 3,500 3,500 3,450 3,450 - 3,400 .............................. 3,400 -- '-...._.------------------------ ..._.------------ .-_____.__....._____._._-.: Q, 3,350 - : a 3,350 - 3,300 3 3,300 ' 3,250 - 3,250 y 3, 50 P*=3129psi - -- - 3; 50 - P*=3129psi t° 3,100- F 3,100 3,050 3,050 - . 3,000: ---. __._..«_ -------------------------------- . - ----- ----- --- - 2,950 _________ 3,000 . .2,950 =850 Pres=2600 psi 2,850 Pres=2600 psi 2,801 - - ---- ---------- ------..._ 2,800 ------------------- 2,750 ------- --- 2,750 _ 2,750 2,701- ! 2,700 2,650 2,650 2,600 - _______________ 2,600. ------------- .----------------------- __--___------------ _________._...___.._-_ 8/13/2017 10/1212017 12/11/2017 2/912D1a 4/10/2018 8/13/2017 10/12/2017 12/11/2017 2/9/2018 4/10/2018 Time (date m/d/'y) Time (date Md/y) • MBAL tank pressure versus actual pressure for MBAL tank pressure versus actual pressure for the the original (6.0 MMBO tank size estimation) original (1.4 MMBO tank size estimation) Confidential ~4 • 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ~.~ • ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING In Re: SAG RIVER POOL, MILNE POINT UNIT TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska February 25, 1998 9:00 o'clock a.m. APPEARANCES• Commissioners: MR. DAVID W. JOHNSTON, CHAIRMAN MR. WILLIAM N. CHRISTENSON BP Exploration (Alaska): ~ ~ ~ ~ ~M1 ~°4~. a ~,. _~~4~ ,. `r,1Yv ~, E L I T E C O II R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 MS. MARSHA DAVIS MR. ROBERT HUNTER MR. PETER BURKE MR. PETER RICHARDS MR. JAMES ROBERTSON MR. BILL HILL 2 1 P R O C E E D I N G S 2 (On record - 9:01 a.m.) 3 CHAIRMAN JOHNSTON: I'd like to call this hearing to 4 order, please. The time is a couple minutes after 9:00 in the 5 morning. The date is February 25, 1998, and we are located at 6 the offices of the Alaska Oil & Gas Conservation Commission on 7 3001 Porcupine Drive, Anchorage, Alaska. To begin I'd like to 8 introduce the head table. My name is David Johnston, I'm 9 chairman of the commission; and to my right is Commissioner Bob 10 Christenson. Laurel Earl, of Elite Court Reporting, will be 11 making a transcript of these proceedings. If you wish to 12 receive a copy of the transcript, we'd ask that you contact 13 Elite Court Reporting directly for that transcript. 14 The purpose of these proceedings is to consider an 15 application by BP Exploration to establish pool rules for the 16 Sag River Pool in the Milne Point Unit. The commission 17 published notice of the hearing on December 23, 1997 and again 18 on January 21, 1998. The second notice essentially .rescheduled 19 the hearing from a date in January to today's date. Both 20 notices were published in the Anchorage Daily News, and I'd 21 like to enter those into the public record at this time with 22 marking the December 23 notice as exhibit -- as AOGCC Exhibit i I 23 1, and the January 21, 1998 notice AOGCC Exhibit 2. ~, 24 These proceedings will be conducted in accordance with 25 commission regulations governing public hearings. Those are E L I T E C OUR T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 3 1 specifically 20 AAC 25.544. Briefly, those regulations allow 2 us to take sworn testimony or oral statements, although greater 3 weight will be given by the commission to sworn testimony. We 4 would ask the witness to, as they approach the commission, 5 state your name and who you represent, and if you wish to be 6 .considered an expert witness in the matter we would ask that 7 you state your qualifications, as the commission would rule as 8 to whether we would consider you an expert witness in the 9 matter before us. Members of the audience will not be 10 permitted to ask questions directly of the person testifying, 11 although if you do have questions, we'd ask that you write them 12 down on a piece of paper and then forward it to the front here 13 and we'll take a look at the question. If we feel it is 14 germane to the topic we will ask those questions ourselves. 15 So with that I'd like to invite BP Exploration. I 16 believe Marsha Davis is the kind of kick-off person for the 17 applicant. 18 MS. DAVIS: I like kick-off. In my Olympics waning 19 moments, I'm a little more sport. I'll be providing the 20 introduction for BP Exploration. My name is Marsha Davis, I'm 21 an attorney for BP Exploration Alaska. Inc., the operator of 22 Milne Point Unit. BP is presenting testimony today on behalf 23 of itself, as a working interest owner and unit operator, as 24 well as on behalf of OXY USA Inc., the other working interest 25 owner in Milne. E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 4 1 This hearing has been scheduled in .accordance with 2 20 AAC 25.520 and 20 AAC 25.540 in order to consider evidence 3 relevant to the establishment of pool rules for the Milne Point 4 Unit Sag River resource. This testimony includes operating and ' 5 technical data concerning the currently geological and 6 reservoir properties as well as proposed plans and timing for 7 reservoir development. This testimony will enable the 8 commission to establish rules allowing economical development 9 of Sag River resources which will prevent waste, protect fresh 10 water and protect correlative rights. 11 Our testimony today is divided into four primary 12 disciplines: geology, reservoir, facilities engineering, and 13 drilling and completions engineering. Robert Hunter will 14 present testimony relating to the geology of the Sag River. 15 Peter Burke will present the reservoir information. Peter 16 Richards will present the surface facilities testimony, and 17 James Robertson and Bill Hill will present the drilling and 18 completions testimony. Each of these witnesses will state his 19 education and experience which we believe qualify him as an 20 expert. Each of the witnesses is prepared to respond to 21 questions concerning the testimony and related exhibits. 22 Some of the materials presented today are confidential, 23 and we request that such information be kept confidential, 24 pursuant to Alaska Statute 31.06.035(d) and 20 AAC 25.537. We 25 will identify which sections of the testimony we consider E L I T E C O U R T R E P O R T IN G 4051 Eas 995 t 20th Avenue #65 Anchorage Alaska 08 907.333.0364 5 1 confidential at the time it is to be presented and request that 2 the public be excluded from that portion of the hearing. 3 Our witnesses will be presenting sworn testimony and 4 wish to be qualified as experts today. 5 CHAIRMAN JOHNSTON: Just a brief question. On your 6 application you have proposed testimony dated December 1997,. 7 but more recently we received testimony dated February 1998. 8 MS. DAVIS: The 1998 testimony will be considered to be 9 the actual testimony for the day. 10 CHAIRMAN JOHNSTON: Okay. And I'd also like to 11 indicate a letter that we got from OXY USA, addressed to the 12 commission, and apparently it's by Michael Gooding for Ed Beham 13 (ph)? 14 MS. DAVIS: Yes. 15 CHAIRMAN JOHNSTON: And basically it indicates OXY's 16 full support of the BP efforts to define the Sag River Pool and 17 indicates their support for development in the accumulation. 18 I'd like to enter this as an AOGCC Exhibit 3. 19 MS. DAVIS: For the audience I have six public copies, 20 so if I can ask BP folks not to take them and for folks that 21 are maybe in a group who wants a copy, I could -- BP can share ~, 22 between them if you'd like to reference them. 23 CHAIRMAN JOHNSTON: Okay. If you would please identify I 24 yourself for the record. 25 MR. HUNTER: My name is Robert Hunter. I work for BP E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 6 1 in Alaska. 2 CHAIRMAN JOHNSTON: And do you wish to offer sworn 3 testimony? 4 MR. HUNTER: Yes, I do. 5 CHAIRMAN JOHNSTON: If you'd raise your right hand, 6 please. 7 (Oath administered) 8 MR. HUNTER: Yes, I do. 9 CHAIRMAN JOHNSTON: Thank you. And consider yourself 10 sworn. 11 MR. HUNTER: Thank you. 12 CHAIRMAN JOHNSTON: And do you wish to be considered an 13 expert witness? 14 MR. HUNTER: Yes, I do. 15 CHAIRMAN JOHNSTON: If you'd state your qualifications. 16 MR. HUNTER: I'm a senior geologist working satellite 17 development opportunities in the Western North Slope Department 18 of BP Exploration Alaska. I received a bachelor of arts degree 19 in geology from the University of Montana in 1984, and a master 20 of science degree in geology from the University of Wyoming in 21 1986. I have been with BP and its affiliates for the past 12 22 .years. I've worked the subsurface of the North Slope over the 23 past nine years in Prudhoe, Lisburne, Pt. McIntyre, Niakuk, 24 Kuparuk, and Milne Point developments. My testimony provides 25 geologic justification to the commission supporting BP's E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 7 1 proposed Sag River Pool limits. 2 CHAIRMAN JOHNSTON: Do you have any objections? 3 COMMISSIONER CHRISTENSON: I have no objections. i 4 CHAIRMAN JOHNSTON: Thank you. Mr. Hunter, the 5 commission will accept you as an expert witness in this matter. 6 MR. HUNTER: Thank you. I'd like to give a general 7 overview first. 8 CHAIRMAN JOHNSTON: Can everybody in the audience hear 9 us back there? If at any time there's any difficulty, if 10 you'd raise your hand then we'll try and get the witness to 11 speak up if that becomes a problem. 12 MR. HUNTER: The proposed Sag River Pool area is 13 located in the Milne Point area near the coastline of Simpson 14 Lagoon on the Western North Slope. That's in this area right 15 up here. The Sag River Pool would include the stratigraphic 16 interval which is defined by the MPA-01 type log from 8810 to 17 8884 feet in measured depth, and that's in this interval here 18 to here. 19 CHAIRMAN JOHNSTON: So are you including part of the 20 Shublik as part of the Sag River Pool? 21 MR. HUNTER: No, we are not. And that's within -- do I 22 need to disconnect this -- is this a portable unit? 23 REPORTER: Put that on your belt and go ahead and walk 24 where you need to. 25 MR. HUNTER: How far can I go? E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 8 1 REPORTER: Quite a bit. 2 MR. HUNTER: It's within the mapped area of the oil 3 accumulation which is on Exhibit 2, and what's on the overhead 4 here is Exhibit 1. This is the mapped area of the accumulation 5 on this map back here. Marsha Davis has also made copies of 6 this map. Exhibit 2 also illustrates the Milne Point Unit 7 location and the outlying area of the proposed Sag River Pool 8 Rules. Working interests in each. of the leases are held 9 uniformly by BP at 91.19 and OXY at 8.81. 10 Chevron discovered oil in the Sag River formation in 11 this area in the Kavearak Point 32-25 well in 1969. That's 12 this well right here. And this discovery was confirmed by 13 Conoco in their MPA-O1 well in 1980 at A-1 in this location 14 right -- right here. 15 CHAIRMAN JOHNSTON: So that you can place it a little 16 bit more accurately on the map, would you just trace the 17 outline of the unit boundary there for us? 18 MR. HUNTER: Let's see if we have that on that map. 19 Yes. 20 CHAIRMAN JOHNSTON: Yeah, I thought that's where it is. 21 MR. HUNTER: It's this boundary right here. 22 CHAIRMAN JOHNSTON: Great. Thank you. 23 MR. HUNTER: I'm glad I had it on the map. Okay. The 24 Sag River is one of many potential satellite opportunities 25 which are in the Kuparuk area of the North Slope. And just far E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 9 1 background here to show where the Sag River is 2 stratigraphically on the North Slope, it's this thin formation, 3 the sands in this area on the stratigraphic chart. 4 BP acquired working interest in the Milne Point leases 5 from Conoco and Chevron and succeeded Conoco as unit operator 6 effective January 1, 1994. In 1995, BP drilled the first 7 dedicated Sag River well, MPE-13, to assess productivity of 8 this relatively poorly developed reservoir. 9 This slide I have up here now is for illustration 10 purposes and shows the Kavearak 32-25 discovery well drilled in 11 1969. And this Sag River discovery was confirmed in 1980 by 12 the MPA-01 well, and then confirmed again by MPC-1, MPB-1 and 13 then it took almost 25 years from discovery to the first real 14 appraisal test that BP undertook in 1994 with the MPA-13 well. 15 This is very significant because that 25 years between 16 discovery and appraisal indicates the marginal productivity of 17 this particular formation, and one of the things that BP will 18 be struggling with in proposing the development of the Sag 19 River Pool. 20 Okay. Since..... 21 CHAIRMAN JOHNSTON: Can you generally locate those 22 wells on the map over there? 23 MR. HUNTER: Yes. (Pause} Kavearak 32-25 is right 24 here, MP18-O1 which was drilled off the structure and did not 25 discover oil in the Sag River and is down structure on the i E L I T E C OUR T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 10 1 flank here. MPA-O1 is here. Now MPE-13 is a high angle well 2 and extends from a point near MPA-01 to the -- in the beginning 3 of the high angle section to the end of the high angle section 4 to the northwest. MPB-O1 is also located on the flank of the 5 structure, but did also -- the logs look like it encountered 6 some hydrocarbons in the Sag River. MPC-Ol is up to the 7 northwest. MPL-O1 is off a structure on a separate fault 8 block. Cascade-O1, which was BP's discovery well, down in this 9 area shows the Sag River accumulation down at the southeast on 10 the structure. I already showed where MPE-13 was, and MPC-23 11 is in this area here which was also one of BP's appraisal 12 wells, which I'll discuss in a moment. F-33 is the 13 northwestern-most appraisal well. MK-33 is the 14 southeastern-most appraisal well. So the wells are very widely 15 spaced within the Milne Point Unit. This area, I think, has 16 recently been added to the Milne Point Unit, and they are very 17 far apart. 18 CHAIRMAN JOHNSTON: But it appears that the wells 19 pretty well cover the -- at least the portion of the reservoir 20 that you deem productive? 21 MR. HUNTER: That's correct. The appraisal wells are 22 all located on the crest of the structure. 23 Since we drilled E-13, BP has drilled 13 additional 24 widely spaced Sag River wells: the C-23 and F-33 in 1995, and 25 K-33 in 1997. The marginal productivity from these wells EZ I TTs COURT R.EPOR T I NG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 11 • • • 1 2 311 4~ 5 6,1 7 81 9 10 lli 12 13 14 15 16 17 18 19 20 21 22 23 24 25 dictates caution in the development program. Therefore, BP will proceed with a synergistic development of Sag River with Kuparuk and Schrader Bluff opportunities where possible. Additionally, radically de-scoped well options are being evaluated. Do you need any clarification on radically de-scoped wells? CHAIRMAN JOHNSTON: Please. MR. HUNTER: A radically de-scoped well is a borehole such as a slimhole or a sidetrack borehole which does not cost near as much as a dedicated borehole to the Sag River, and so it's a way to ensure that drilling a Sag River well can be economic with the expected productivity from that well. In order to economically develop the Sag River Pool, BP will need to first demonstrate that certain technical operations are feasible with respect to this pool. First, BP is planning to test a pressure support mechanism by,initiating gas injection in a planned sidetrack near the existing Sag '1 River well, C-23. Would you like me to locate that on the map? CHAIRMAN JOHNSTON: Please. MR. HUNTER: The C-12 sidetrack is near the C-23 borehole downstructure to the northeast. It's about 3500 feet away from the C-23 borehole. Here's a blow-up copy of that where that is located. E L I T E C O Q R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 ~' 12 1 If pressure support is demonstrated to be technically 2 and economically feasible, BP will consider implementing 3 additional injection patterns. The ability to utilize 40-acre 4 spacing will enhance the success of such a program. Finally, 5 the economic feasibility of any development is contingent upon 6 the Sag River Pools' use of existing infrastructure an the 7 ability to commingle production in the shared facilities. 8 CHAIRMAN JOHNSTON: So do you think the results of 9 testing in MPC-23 would be representative for the entire 10 accumulation? 11 MR. HUNTER: Yes, I do. 12 CHAIRMAN JOHNSTON: Thank you. 13 MR. HUNTER: Thank you. 14 MS. DAVIS: At this point we would identify the next 15 piece of testimony would be confidential (indiscernible - away I 16 from microphone) reservoir information that is confidential 17 relative to some of the well information that's not ublic P 18 data. At this point we would request this section be held 19 confidential. 20 CHAIRMAN JOHNSTON: And how long do you anticipate the 21 testimony to take place, the confidential portion? 22 MS. DAVIS: About 15 minutes. 23 CHAIRMAN JOHNSTON: About 15 minutes, okay. And you 24 would like only BP personnel present and staff from the AOGCC? 25 MS. DAVIS: Correct. E L I T E C O U R T R EP O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 13 1 CHAIRMAN JOHNSTON: Okay. 2 MS. DAVIS: If there is someone from DNR that would be 3 acceptable. 4 CHAIRMAN JOHNSTON: What about DOR? 5 MS. DAVIS: I'm not sure about DOR. I'm trying to 6 think. I know DNR has confidentiality but I'm not sure about 7 DOR because -- do they customarily sit in on them? 8 CHAIRMAN JOHNSTON: We've had confidential sessions 9 before where there has been no objection from the applicant 10 having a DOR representative sit in. 11 MS. DAVIS: Okay. If a DOR representative is here and 12 they would be able to hold this portion confidential, that 13 would be fine. 14 CHAIRMAN JOHNSTON: Then at this time I would like to 15 ask that the public members step outside in order to allow the 16 commission to consider confidential testimony. And if the BP 17 representative would identify and make sure that the people 18 remain are authorized representatives from BP, then we can 19 proceed. 20 (Off record - 9:21 a.m) 21 (The confidential portion not transcribed) 22 (On record - 9:48 a.m.) 23 CHAIRMAN JOHNSTON: I'd like to go back on record, and 24 for the record I'd like to recap what took place during the 25 break. The commission took a break to discuss whether the E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 14 1 information that we were hearing was in fact confidential. The 2 commission determined that in fact the information that we were 3 hearing was information that we: commonly put into the public 4 record. We talked to BP about our concern, BP agreed that in 5 fact this information should be: on the public record. So what 6 we decided to do is back-up anct start the hearing over again in 7 public session with the information that had been earlier 8 referred to as confidential. So we're kind of backing up and 9 starting over with where we asl+:ed the public members of the 10 audience to leave the room. So you will not miss anything. 11 MR. HUNTER: Could we z:ewind the tape? 12 MS. DAVIS: No. 13 MR. HUNTER: The stratigraphy of the Sag River consists 14 primarily of thin marine shelf sandstone packages deposited 15 throughout the Prudhoe Bay area on the North Slope of Alaska, 16 as documented in the public record by Barnes in 1987. In 1971 17 the North Slope Stratigraphic (:ommittee said that the Sag River 18 formation as the sandstone intesrval which underlies the 19 Jurassic Kingak shale and over]Lies the Triassic Shublik 20 formation in this area here. 7Che sands are extensively 21 bioturbated which has mixed the: originally deposited sands, 22 silts, and muds, and forms a reslatively poor reservoir quality 23 sandstone. In the proposed pool area, the Sag River formation 24 is divided in the study into four zones, from bottom to top, 25 zone A, B, C, and D, and this :zonation scheme was originally E L I T E C OUR T R E P O R T I N G 4051 East 20th Avenue #65. Anchorage Alaska 99508 i 907.333.0364 ~! 15 1 proposed regionally by Gardner in 1987. Each zone boundary 2 likely represents a chronostratigraphic surface and is commonly 3 i marked by an increase in bioturbation, shaliness, and 4 phosphorite and glauconite concentrations. The Sag River 5 formation averages about 77 feet in thickness in the proposed 6 pool area. And the net pay ranges from 9 to 18 feet thick. 7 And the Sag River formation permeability-thickness ranges from 8 30 to 68 millidarcy-feet. The net pay is shown on this map 9 here which also -- which shows the Sag River net pay throughout 10 the region and not just on the area which contains oil on this 11 fault block here. And the Sag River permeability thickness on ', 12 this map in Exhibit 4 also shows the net permeability thickness 13 throughout the region and not just on the fault block which 14 contains the hydrocarbons. 15 Zone A is the basal Sag River sandstone unit which 16 unconformably overlies the Shublik formation. That's this zone 17 right here. It's almost entirely tight, non-reservoir ', 18 sandstone in the area. Porosities develop up to 18~ and 19 permeability is to 1.2 millidarcies. The average gross 20 thickness of zone A is about 16 feet. 21 Zone B is the primary Sag River interval, right here, 22 and you can see that porosities are better developed in zone B, 23 and the resistivity response is also a little bit better in 24 zone B. Resistivities in the Sag River are commonly suppressed 25 due to glauconite and the tightness of the formation. And ~, ~ ELI TE COURT REPORTI NG 4051 East ZOth Avenue #65 Anchorage Alaska. 99508 907.333.0364 16 • 1 the -- so it's a very subtle reservoir. Zone B is the primary 2 Sag River interval and it develops porosity up to 21~ and 3 permeability to 23 millidarcies as measured from cores taken in 4 the area. The thickness of zone B averages about 30 feet. 5 Zone C is the uppermost Sag River sandstone in the 6 proposed pool area, and that's this zone right here. It's 7 still a sand, but as you can see the porosity has dropped 8 dramatically, and it's mostly non-reservoir sand. Porosities 9 develop up to 17~ and permeability is up 2.9 millidarcies. The 10 average gross thickness of zone C is about 10 feet. 11 Zone D, which is the uppermost Sag, is a non-reservoir 12 siltstone and shale at the top of the formation. There's a 13 prominent shift in sonic and resistivity logs which occurs at 14 the contact between the base of the Kingak and the top of the 15 Sag in Sag zone D. The average gross thickness of zone D is 21 16 feet, and the structure map and velocity field shown in 17 Exhibit 2 were constructed to conform to the zone C rather than 18 zone D because zone D is the top of the reservoir sand in the 19 Sag River. 20 Now within the proposed pool area, the Sag River has 21 been mapped structurally here using the Milne Paint and 22 Northwest Eileen seismic surveys. The regional structure on 23 the top of the Sag is dominated by many northwest to southeast 24 trending faults such as this one here which forms the trap for 25 this hydrocarbon accumulation. There are additional faults E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 17 • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • i trending north-south, east-west which segment and complicate this structural trap. All the fault sets appear to post date deposition of the Sag River interval, and the throws range from 20 feet to in excess of 200 feet. This fault here is, the throw is in excess of 200 feet, with the greater throws associated with that northwest to southeast trending fault. The segmentation of structural closures is supported by the oil-water contacts inferred from existing well penetrations, and this leads to three equilibration regions, which I'll discuss here in a minute. The depths of the Sag River in the area range from up in the northwest 8500 feet subsea to 9500 subsea in the southeast. The depth structure at the top of Sag River merges j existing well control which penetrate the Sag with an interpretation of the average seismic velocity which does account for the thinning of the permafrost in the -- along the coastline in the barrier island region. As we drill additional wells in this region into the Kuparuk we're also getting more control over the permafrost thinning in that area. The trapping mechanism of the Sag River is primarily structural as demonstrated by the fault trap here. There's a possibility that it might be stratigraphic. I have a slight component to it because of the tightness of the formation. There are faults with vertical displacements as low as 50 feet which could subdivide and separate the Sag River zones and E L I T E C OUR T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 18 1 cause different reservoir segments with different oil-water 2 contacts. 3 As I mentioned before, there are three blocks that 4 we've identified in the area with different oil-water contacts, 5 and these are 9150 feet in the southeast, as demonstrated by 6 K-33 and Cascade-O1 penetrations and production. In the 7 central area, E-13 and C-23, the oil-water contact and closure 8 is 9050 feet. In the northwest the oil-water contact inferred 9 from closure is 8950 feet. These oil-water contacts are based 10 on structural closure and well productivity or well 11 productivity or well tests. And they appear to step up from 12 9150 to 9050 to 8950 from southeast to northwest. 13 The Shublik does not develop into a reservoir in the 14 proposed pool area. And neither the Eileen, Ivishak or 15 Lisburne formations are known to contain more than residual 16 hydrocarbons in the proposed pool area. The Eileen and the 17 Ivishak formations contain high water saturations even where 18 they're penetrated above the depths of the Sag River oil-water 19 contacts. There are three wells which penetrate the Eileen and, 20 the Ivishak above the Sag River oil-water contacts, and those 21 are MPA-01, the pilot hole next to that for MPE-13, and 22 I MPC-23 -- C-23 in this area here. So the Ivishak is wet in 23 those areas. ~ 24 The name of the Sag River Pool, as I discussed before, 25 as proposed for this interval between the base of the Kingak ~' , ELI TE CO UR T REPOR T I NG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 19 • 2 3 4 5 6 7 8 9 • • 10 11 12 13 14 15 16 17 18 19 20 21' 22 23~' 24 I 25 and the top of the 5hublik, covering zones A, B, C, and D of the Sag River. I'll go a little bit into some of the information that we have for reservoir description. In the Milne Point Unit we have five wells that contain either core or rotary sidewall cores within the Sag interval. We do have full core in the Kavearak 32-25 well, in MPB-Ol off the periphery of the structure here, MPC-O1 up to the northwest, and MPL-01 off the trap that we've identified here. We have sidewall cores in Cascade-01. There are six additional wells which have recorded logs over the interval, and these include MP18-O1, MPA-01, MPE-13, MPC-23, MPF-33 to the northwest, and MPK-33 to the southeast. Porosity data from the cored wells were used to model porosity in the non-cored wells. There was core data available, for the Sag River A, B, and C zones. The B zone is demonstrated in this exhibit here, demonstrates the highest quality reservoir and sands. So the core densities, which are greater in the C and the A zones seen in the log here, likely indicate more carbonate cementations. Core porosities in the B interval range from 8 to 21~ with a mean of 16~. Core porosities in the A and the C zones on either side of the B range from 2 to 19~, with a mean of 12~ in the gross interval. Permeabilities from the core data were used to predict permeability in the non-cored wells. The permeabilities range E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 20 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 from nothing to 23 millidarcies for all the available core data. Zone B, the arithmetic permeability is 2.7 millidarcies, that's as an average, whereas in zone A and C average .4 millidarcies. We've used a criteria of 1 millidarcy permeability, either predicted or core, to determine net pay for wells above the oil-water contact. And that net pay is seen here in Exhibit 3. Inside the structural cores are seen in Exhibit 2. The net pay in greater than 1 millidarcy rock usually occurs where we have greater than 15~ porosity as a rule of thumb. Average water saturations in the net pay calculated intervals from log analysis range from 45 - 57~. The zone B primary reservoir average porosity in the net pay is 18~ with an average permeability of 2.8 millidarcies in the net pay. Zone A and C average porosities where they develop in the net pay are 16~ with permeabilities of 1.2 and 2.1 millidarcies respectively. The core, log and model derived porosities, permeabilities, net-to-gross and water saturations were all input into the reservoir model, which we will discuss later in the testimony, for zones A, B and C of the Sag River. The permeabilities in that reservoir model were adjusted up by a constant to match the well history. CHAIRMAN JOHNSTON: Why was that necessary to adjust your permeabilities by this constant? E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 21 • • 1 2 3 4' 5' 61 7 8 9 10 11~ 12 13 14 15' 16 17 18 19 20 21 22 23 24 25 MR. HUNTER: Because the well performance is better than the reservoir properties which we have input into the reservoir simulator. The primary reason for that is likely that the fracture contribution from the tight sands accounts for some of that increased productivity. CHAIRMAN JOHNSTON: So you see fracture porosity being a significant contributor to the productivity of the..... MR. HUNTER: Initially, yes. CHAIRMAN JOHNSTON: Initially. MR. HUNTER: Yes. CHAIRMAN JOHNSTON: Would that be -- apply equally to all the zones or would it play more important in say the tighter A and C? MR. HUNTER: In care I've seen more fractures in zone A, especially where it comes off the Shublik, the tight Shublik carbons, and there are definitely more fractures in zone A. I would anticipate that those -- some of those fractures would extend into zone B, although I've not observed as many fractures in core in zone B. CHAIRMAN JOHNSTON: And what was the constant that you used? MR. HUNTER: Peter will discuss that in his testimony, but -- do you recall what that was, Peter? MR. BURKE: Yes, it was 10-fold (indiscernible) around I the wells. ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • ~ 22 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 I 181 19 20 21i 22 23 ~ 24' 25 CHAIRMAN JOHNSTON: And so you see the reservoir as fairly uniform across this entire area; is that right? MR. HUNTER: Yes, I do. CHAIRMAN JOHNSTON: So pretty much the same properties li throughout. You wouldn't expect any wide variations from north,, to south, you don't see any localized effect from longshore currents or any sort of turbidites or that sort of thing associated with this accumulation? MR. HUNTER: No, I do not. The individual zones A, B, C, and D are very correlable throughout the field area from all' the wells I've seen on this exhibit here, and the reservoir properties do not change dramatically within the reservoir interval in the hydrocarbon -- in the area that contains hydrocarbons. There are differences in the primary reservoir interval, zone B, which occur in the areas where we do not have live hydrocarbons in that zone. Markedly, that is demonstrated by a tighter density response where that sand is in the water zone. You'll see that where the B zone goes into the water in B-1 in MP18-Ol and in MPL-01 as well. But within the wells that contain hydrocarbons the petrophysical properties are remarkably similar. CHAIRMAN JOHNSTON: Okay. How about do you anticipate any localized effect from the faulting? Is that going to complicate the development? I MR. HUNTER: Absolutely. We've seen -- Peter will talk Fs'L I TE COOR T REPOR T I NG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 i 23 1 about this a little bit in his testimony, but we have seen in 2 the high angle well, MPE-13, we did crass a fault in that well. 3 The production from that well, we have a great deal of water 4 associated with the oil. We believe that that water is coming 5 from a fault and that the water is coming from the Ivishak, 6 it's coming up the fault in through the interval that is in the 7 Sag River in that high angle well. Because the Sag River is 8 entirely on the crest of the structure well above the oil-water 9 contact. We shouldn't be getting any water from the Sag River 10 in that well. That's an indication of the openness of the 11 fault -- potential fault conductivity in this area. You can 12 see on this structure map where this fault has some bends 13 associated with it, and those bends in that fault might open up 14 local areas of -- pull apart or compression which could locally 15 open up certain faults and C10Se other faults depending upon 16 how that major bounding fault bends. And that as well as 17 regional stress is definitely a concern, especially in an area 18 where we're talking about gas injection. So we're trying to do 19 our best to account for that and to look for areas which are 20 less complicated by faulting, but realizing that the faults, 21 that we need to use them to our advantage where we can..... 22 CHAIRMAN JOHNSTON: Right. 23 MR. HUNTER: .....and account for that. 24 CHAIRMAN JOHNSTON: Thank you. 25 MR. HUNTER: Uh-huh. .ELI TE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 24 i • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN JOHNSTON: And if you would state your name for the record, please? MR. BURKE: My name is Peter Burke. CHAIRMAN JOHNSTON: And do you wish to be sworn? MR. BURKE: Yes, I do. CHAIRMAN JOHNSTON: Please raise your right hand. (Oath administered) MR. BURKE: I do. CHAIRMAN JOHNSTON: Thank you. Consider yourself sworn. And do you wish to be considered an expert? MR. BURKE: Yes, I do. CHAIRMAN JOHNSTON: State your qualifications. MR. BURKE: I'm the resident engineer for the Sag River development. I studied petroleum reservoir engineering to i i master's level at Landon University in the United Kingdom, and ~I i have 25 years of experience with BP Exploration and Amoco. I ~ started work on the Sag River development in March of '97, and i have directed the reservoir performance simulation work done by ~I I an external consultant. CHAIRMAN JOHNSTON: Any objection? COMMISSIONER CHRISTENSON: No objection. CHAIRMAN JOHNSTON: Thank you. We'll consider you an expert witness in this matter. Please proceed. MR. BURKE: My section of the testimony begins with describing the oil-in-place. The estimated oil-in-place for E L I T E C O U R T R E P O R T I N G 4052 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • r 25 • 2 3 4 5 6 7 8 9 10 11 12 13 i 14 15 16 17 18 19 20 21 22 23 24 25 the Sag River interval in the proposed pool area is 61.7 ~I million stock tank barrels as calculated from the recently constructed reservoir model. The northwest area contains 9.7 million barrels and is being produced by F-33. There are 49.1 million barrels in the central area of the pool, which is now being produced by E-13 and C-23. There are 2.9 million barrels in the southeast area, which is being produced by K-33. The productive volume in the model is constrained by rock and fluid properties, the net pay thickness of the sand, the oil-water contacts, as defined earlier, and by the major sealing faults. The results are as follows: The northwest area of 1300 acres, 9.7 million barrels; the central area, 6800 acres and 41.9 million barrels; and the southeast area contains 2.9 million barrels in 400 acres. The total acreage of 8500 acres and 61.7 million barrels. The fluid property analysis has been carried out in the sample from the C-23 well. The principal characteristics of the sample are as follows: The average crude gravity is 39.2 API; the bubble point pressure was determined at 3513 psi; solution GOR was 974 stock tank cubic feet per barrel; the oil formation volume factor as initial conditions is 1.56 reservoir barrels per stack tank barrel; the oil viscosity was .277 centipoid at initial conditions; and separator gas gravity is .8. E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 26 • 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • i The measured initial reservoir pressure and temperature were 4425 psi and 235° Fahrenheit at a datum of 8750 feet subsea. This portion of the testimony will include further discussion of the reservoir performance, development and management of the Sag River Pool. The potential performance of the Sag River reservoir was investigated using a three-dimensional, black oil reservoir mode. This model was used to guide the decisions relating to 'i the optimum reservoir management of the Sag River Pool. There are many aspects of the reservoir which are still unknown, including the degree of areal continuity across the reservoir, fracture density and conductivity in the vertical and horizontal directions, anisotropy in the reservoir properties, observed performance under water and/or gas injection, the aquifer strength, the fault transmissibility and the oil-water contact in undrilled fault blocks. Therefore, the development plan requires flexibility to accommodate any required adjustments in the operations due to unexpected reservoir conditions. Although gas injection is the currently preferred development strategy for the field, the actual reservoir parameters may point toward the ultimate recovery scheme being a waterflood or a water alternating gas, WAG, injection plan. The primary recovery mechanisms for full development of E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 27 • 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18' 19 20 21 22 23 24 25 ~_J the field are fluid expansion and aquifer pressure support. There is no gas cap as the reservoir was initially 912 psi under-saturated with an initial pressure of 4425 compared to the bubble point of 3513 psi. Estimated recovery under primary depletion of normal development is 15~ of the original oil-in-place, rising to 38~ with an immiscible gas flood scheme. The proposed pool area Sag River reservoir, zones A, B and C,were modeled using Landmark's VIP simulation program. A VIP is a three-dimensional, multi-phase simulator with black oil and compositional options. A black-oil treatment was used for the Sag River Pool study. A full-field model was built to investigate various development plans and recovery processes for the field. The model area, including the grid configuration, is shown in ~ Exhibit 5. And in Exhibit 5 that my colleague has just put up, we see an area which represents a structural surface which is now being gridded. The model cell size is 419 feet by 419 feet for an area of around four acres for each grid cell, seven model layers have been included. The overall dimensions of the grid are 198 cells by 54 cells in the X and Y directions, and with seven layers we have a total of just under 75,000 cells. The reservoir description used in the full field model included the seismic structural definition and the layering interpretation described in the Geology and Reservoir E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 28 • 2 3 41 5~~ 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20~ i 21i 22 23 24 25 ~~ Description sections. The Sag A and C layers were represented with one layer each while the thicker B layer reservoir sandstone was subdivided into two layers, each averaging 15 feet in thickness. Average model layer properties for the main Sag interval net pay in Layer B are 18~ porosity and 8 millidarcies. The net pay in the Sag A and C layers have average porosities of 16 and 17g and average permeabilities from 1 to 2 millidarcies. Three different oil-water contacts are used in the model for the Sag River interval, as described in the Geology section. The Shublik, Eileen, and Ivishak formations are also included in the model. It is believed that the water production in E-13A is coming from a fault conductive to the Ivishak interval. Both the Eileen and Ivishak have been given porosity, permeability, and high water saturations in the model. The Shublik is treated as a non-porous shale. A six-well pattern model was also built for a preliminary sensitivity analysis of well density and injection options. The pattern model used the same layering scheme as the full field model and represented the central area around the well C-23. PVT properties and oil-in-place used in the simulation study were given in the previous Reservoir Oil-In-Place and Fluids section. Relative permeability was based on that developed in the Sag River modeling used in the Prudhoe Bay Unit, and no relative permeability curves are available from E L I T E C OUR T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • ' 2 3 4 5 '~ 6 7 8 9 10 11 12 13 14 I~ ' 15 16 III 17 i 18 I ' 19 20' 21 22 23 24 25 r~ ~J • • 29 the core taken in the Sag wells that we have in our unit. The adjacent aquifer was modeled as a fixed pore volume of columns of cells attached directly to .the oil zone below the oil-water contact. The aquifer volume is around seven times L that of the oil zone. Following the initial construction, the full field model was history matched with the four producing wells to help assure valid forecast results. Adjustments were made primarily to the Sag River layer permeability, increasing from an average of 2.7 to 8 millidarcies in the B zone, and to the fault conductivity near the E-13 well. Following the history match, the full field model was set-up to forecast the future performance of the reservoir under various operational scenarios. In these cases all wells were placed on bottomhole pressure control with a minimum flowing bottomhole pressure of 1500 pounds for the producers and a maximum bottomhole injection pressure of 5500 pounds. To approximate the enhanced productivity/injectivity from stimulation, all proposed wells were assigned negative skin factors and increased permeability in the model cell containing the well. The forecast cases included gas injection with varying well spacing, waterflooding, and horizontal wellbores. For each case well locations were selected based on the productive areas, according to the desired well density and pattern E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 i 30 1 configuration. New wells were added to the model in a staged 2 fashion to approximate a probable drilling schedule. 3 Each of the forecast cases was run 20 years to 2018. 4 In all cases, voidage was approximately replaced, i.e., 5 constant reservoir pressure was maintained, by injecting either l 6 make-up gas, in addition to the produced gas from the reservoir ~~ 7 or sufficient injection water. Initial results indicate that li 8 the estimated o timum ratio for roducers to in'ectors is it P P J 9 between 2:1 and 1.5:1, and this was used in selecting the well ~, 10 locations and service for each forecast. 11 In summary, gas injection gave the best recovery of the' 12 options analyzed. Waterflooding does provide a significant ~, 13 improvement in the recovery aver primary depletion. Horizontal 14 wells contribute to additional production over conventional 15 well development, however, their application is not universally 16 applicable across field due to the reservoir constraints and/or' 17 economics. In all cases, down-dip wells benefit from pressure 18 support from Sag River aquifer. Full field modeling recovery 19 results are shown in the following table. 20 The table shows primary, waterflood, and gas injection 21 cases with varying spaces between 160 and 320 acres per well.. 22 And -- should I read out each of these lines in detail? 23 CHAIRMAN JOHNSTON: I don't think. that is necessary 24 since it's before us, sir. 25 MR. BURKE: The planned well spacing figure for each ELI TE COUR ~' REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 31 • 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • i ` case was used to locate wells in the fully developed up-dip, central area of the model. The effective spacing value was calculated by dividing the estimated productive area above the oil-water contact by the total number of wells. Additional model work is planned with alternative completion techniques and different operating scenarios. As development of the field progresses, the new data received will be used to update the model and, if necessary, revise the development plan for optimum recovery operations. Producing wells will be completed in the Sag River C, B an A sand intervals with fracture stimulations. Sources for the injected gas will be produced gas from the Sag River Pool and make-up gas from other sources in the area, including Kuparuk and Schrader Bluff. At a minimum, voidage will be replaced with the reservoir pressure being maintained at or near 4,300 psi. Since gas injection, with associated gas breakthrough and production, the recommended method of pressure support, gas-oil ratios at the producer wells will be expected to exceed limits set forth in 20 AAC 25.240{b), and an exception to this ~ rule is requested. Based on modeling,. immiscible gas injection is indicated to be the preferred recovery process for the Sag River development with recoveries in the 32 to 40~ range. Water-alternating-gas, WAG, or simultaneous water and gas E L I T E C OUR T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 32 J • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 injection, using miscible or immiscible gas, are considered ~I possible future recovery mechanisms for the Sag River reservoir' along. with alternative completion techniques such as horizontal or multi-lateral wellbores. Forty acre spacing is requested in order to allow for flexibility in developing the field. The planned spacing is 320 acres per well, but reservoir conditions may require optional well location configurations. Estimated recovery from the field under gas injection is 20 million barrels, with the majority of the production coming from the wells in the central area. The 1995-'97 four we:Ll Sag River appraisal program was valuable in determining well productivities and reservoir characteristics. The performance of the E-13 horizontal well has indicated that a fault in the wellbore is conductive and extends below, and possibly above, the producing horizon. The producing are to the southeast is limited due to the oil-water contact. The C-23 and F-33 vertical wells appear to be representative of typical behavior for the field. These wells had initial rates around a thousand barrels a day, in F-33, to 2000 barrels a day in C-23, but declined sharply to two to 400 barrels a day within a year. As of November 1997, cumulative production from the Sag River Pool was around 785,000 barrels of oil. The commission has copies of the Milne Point Unit Review of the 1997 Plan of Exploration, Development and E Z I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 33 • 2 3 4 5 6 7 8 9 10 ~ 11 12 i 13 I' ~ 14 ' 15 16 17 18 19 I' 20 21 ~, 22 23 24 ' 25 ~~ Operations, and the Milne Point 1998 Plan of Exploration, Development and Operations that were filed with and approved by the Department of Natural Resources. These were filed with the commission for informational purposes pursuant to AOGCC regulation 20 AAC 25.527(ay. The plans below outline a full Sag River development should Sag River development become economically viable. The plans show the most efficient development of the Sag River reservoir as demonstrated from the reservoir model. Initial pressure in the Sag River reservoir is about 900 psi above the bubble point pressure. To date there have been no reservoir pressure support measures implemented. Therefore, BP is currently planning in 1998 to drill a sidetrack, pre-produce it, and then initiate immiscible gas injection as part of Phase 1 drilling and completion if the project can be demonstrated to be economically viable. Although only gas injection and waterflooding scenarios have been analyzed to date, water-alternating-gas injection using miscible or immiscible gas is considered to be a possible future recovery method for the Sag River reservoir. If further study indicates that this would yield a more favorable recovery and is economically viable, then the development plan would be revised to conform to those results. Horizontal wells and/or multi-laterals will also be considered and, if provided viable, implemented in the future. E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 34 1 The recommended full development plan at this time 2 contains a total of 25 wells, four existing wells with 20 to 22 3 additional wells, with 16 producers and nine injectors. 4 Development well spacing will be up to 32 acres, consistent 5 with the model study results. Directionally drilled vertical 6 wells are planned for each phase of development at this time. 7 Future drilling could include the use of less conventional 8 wells such as horizontal or multi-lateral wells. A map with 9 the proposed development plan is shown in Exhibit 6, which has 10 just been put up. Proposed injection wells are annotated with 11 an "I" following the well name. 12 Current Phase 1 development plans for the Sag River 13 reservoir at Milne Point consist of at least one well drilled 14 to offset C-23 well and possibly two to four additional 15 penetrations. These wells may be sidetracks or deepenings of 16 current wells in the central area. If surface facility 17 constraints permit, an additional delineation well may be 18 drilled from F-Pad to the northwest. The actual performance of 19 the C-23 area wells will direct the future pool development. 20 In Phases 2 and 3, two subsequent wells are -- two 21 subsequent phases are included in the current development plan. 22 Phase 2 will add 14 additional wells with seven producers and 23 seven injectors. F-33 may be converted to injection. Three 24 producers will be added in Phase 3. Again, this schedule is 25 subject to revision as performance from the new wells dictates. E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue X65 Anchorage Alaska 99508 907.333.0364 • • 35 • 2 3 4 5 6 7 8 9 10 11 12 13 14 15 1& 17 1$ 19 20 21 22 23 24 25 • Depending on reservoir description and performance, select areas may require well spacing other than 320 acres. This may be determined by .faulting, areal changes in permeabilities, or fracture conductivity, which result in different than expected performance. Therefore, a 40-acre well spacing is requested to allow flexibility in placement of wells to maximize recovery from the Sag River reservoir. In summary, I'd like to say that what we have done is study on a very limited database in the appraisal package we have. We've constructed this reservoir model and we've looked at what may be development plans. We are doing this work to make sure the target that we have in mind from the Sag reservoir is a viable, economic target as our appraisal strategy moves forward. And these results that I've given you illustrate the work to date and the work is continuing. CHAIRMAN JOHNSTON: So the decision to do a waterflood or miscible WAG would be dependent on the results of production and additional drilling; is that what I'm hearing? MR. BURKE: That's correct. Yes, at the moment we are planning to investigate pressures of wells by gas injection, and the results of that pilot will dictate a lot about what happens in the future as to their economic viability. The other piece of our learning at the moment is to live with the current production wells and just see how well we can maintain production even at the level we have today, and you'll hear E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 • Anchorage Alaska 99508 907.333.0364 • 36 ., 1 2 3 4 5 6 7 8 9 10 11 12 13~ 14 15 I 16 17 more about that later in the presentation. CHAIRMAN JOHNSTON: With your plan for maintaining ~, pressure support with gas injection is that to maintain an existing reservoir pressure or do you expect decreasing pressure over time? MR. BURKE: I think in the area we've chosen because we've chosen to support an existing well, there is always a pressure sink in the area, and at the moment I think we wouldn't be able to re-pressure the reduced pressure level we 'have. We'd simply be looking to see the effects on pressure ', and speed of break through -- and post-break through performance. I don't think we're looking to re-pressure that area. If we'd gone to a virgin area then we could've lived II with original reservoir pressure and see if we'd maintained it. ~~ But for economic results we'd like to use one existing well and I~ one new well. i CHAIRMAN JOHNSTON: And are you seeing any aquifer 18 ~~ support? 19 i 201' 21' 22 231 24 25 MR. BURKE: I think we`re too far away from the aquifer ~ to see that, also of course the effective pulse in between we would not know whether we were not seeing it of whether it was I (faulted out in the areas we were looking at. So, I think, i ~I we're simply too far away to see the effects of an aquifer at ~ the moment. CHAIRMAN JOHNSTON: In terms of Phase 2 and 3, am I to E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 9950& 907.333.0364 • • 37 • • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 231 24 25 II understand that these are phases that may be pursued or there are phases that BP is planning to pursue? MR. BURKE: Phases 2 and 3 at the moment are conceptual from the model and clearly we'd have to have some success in Phase 1 to consider implementing those onward phases. A lot depends on Phase 1. CHAIRMAN JOHNSTON: Are those phases -- are the number of wells that are being proposed. in each phase, are those equally distributed across the entire pool or would it be concentrated in say this core area? MR. BURKE: No, they are distributed across the pool. There is variation in the distribution only to accommodate the fault pattern in the shape of the contacts. CHAIRMAN JOHNSTON: And the 40 acre spacing is being requested to essentially accommodate the .faulting primarily? MR. BURKE: Right. That's correct. CHAIRMAN JOHNSTON: No further questions. MR. CHRISTENSON: No questions. CHAIRMAN JOHNSTON: Thank you very much. (Pause) We're ready for our next witness. If you would please state your name for the record? MR. RICHARDS: Peter Richards. CHAIRMAN JOHNSTON: And do you wish to be sworn today? MR. RICHARDS: Yes. CHAIRMAN JOHNSTON: Would you please raise your right E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 38 J 1 2 3 4 5 6 7 8'i 9 10 11 12 13 14 15 16 17 18 '' 19 20''~ 21 22 23' 24 25i hand . (Oath administered) MR. RICHARDS: I do. CHAIRMAN JOHNSTON: Thank you. Consider yourself sworn. I assume you wish to be considered an expert? MR. RICHARDS: Yes. CHAIRMAN JOHNSTON: State your qualifications. MR. RICHARDS: I am the Development Studies Team Leader from Milne Point Unit, responsible far facilities development studies. I received a bachelor of engineering degree in chemical engineering from Imperial College, London, in 1983, and achieved chartered engineer status in 1990. I've worked for BP for 14 years in development, project and operational roles in the UK, Norway, Colombia, and now for the last nearly two years in Alaska. CHAIRMAN JOHNSTON: Thank you. The commission will consider you an expert witness in this matter. Please proceed. MR. RICHARDS: The Sag River reservoir underlies the Kuparuk and Schrader Bluff reservoirs within the Milne Point Unit. Sag River fluids are presently commingled with Kuparuk and Schrader bluff fluids at the pads and produced into the common MPU facilities. Economic development is contingent upon utilization of the MPU infrastructure and facilities which will also minimize future and environmental impacts. MPU roads -- pads and road system would be used to E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 39 1 support Sag River drillin and construction and future g 2 operations. 3 Sag River pipelines needs for multiphase production 4 would be provided by essentially existing flow line systems. 5 High pressure gas injection lines may be needed for Sag River 6 gas injection if gas injection becomes a viable enhanced 7 reservoir recovery process. Sag River development will use 8 primarily existing pipelines, flow lines that are already in 9 place. ' 10 Similarly, Sag River development will utilize MPU power 11 lines and on pad electrical equipment. Production wells will 12 use electrical submersible pumps for lift will require some 13 additional on-pad transformers and drives which will be 14 accommodated through minor expansion on existing pad 15 facilities. 16 The base assumption for Sag River facility development 17 is daily operation which requires minimal regular operator 18 presence in line with present operating practice. All data 19 gathering and routine operations are to be accomplished 20 remotely from the CFP (sic) andjor any pad control room. 21 Routine operations defined as well testing using 22 existing pad well testing facilities, well test divert valving, 23 emergency shutdown, production control, injection gas flow ' 24 metering if required as part of future operation, production 25 pressure monitoring -- I think that is. i E L I T E C OUR T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 40 1 Manual operations are defined as wellbore freeze. 2 protection, chemical injection, injection choke valve 3 actuation. 4 Well control and testing functions are performed 5 remotely using the control system. Well production rate is 6 generally controlled using variable speed drives for the 7 downhole electrical submersible pumps, or if you have gas, gas 8 lift, using gas injection rates for gas lift wells. Testing 9 takes place by a simple divert valve system redirecting the 10 flow from the production header to the test header and is 11 controlled remotely. 12 Emergency shutdown systems meet API-RP 14C requirements' 13 and BP specifications for safety systems. All production, 14 test, and injection piping on-site will be designed to be able ' 15 to contain wellhead shut-in pressure up to the emergency 16 shut-down valves. 17 Production wells can be shut down due to over or under 18 pressure with pressure switches. Additionally, these wells can'' 19 be shut-off remotely through the control system. 20 Injection wells flow reversal, due to a surface system 21 leak or depressurizing is stopped by the use of a low pressure 22 switch, ESD valve and check valve at the well. Additionally, 23 these wells can be shut-off remotely through the control 24 system. I 25 Basically we're saying we're using a lot of the ~, E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 41 1~ 2 3' 4 5 6 7 9 • • 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 existing infrastructure and .the existing systems which are in place to develop any additional Sag River development. CHAIRMAN JOHNSTON: So in terms of the test facilities, I assume those are the same test facilities that you are currently testing the Schrader Bluff production with? MR. RICHARDS: Yes, it will be primarily the Kuparuk ~ wells. Yeah, and possibly the Schrader Bluff wells also. CHAIRMAN JOHNSTON: Thank you. MR. RICHARDS: Okay. CHAIRMAN JOHNSTON: Okay, the next witness, please state your name for the record. MR. ROBERTSON: My name is James Robertson. CHAIRMAN JOHNSTON: And do you wish to be sworn today? MR. ROBERTSON: Yes, sir. CHAIRMAN JOHNSTON: If you'd raise your right hand, please. (Oath administered) MR. ROBERTSON: Yes, sir. CHAIRMAN JOHNSTON: Thank you. Consider yourself sworn. Do you wish to be considered an expert witness? MR. ROBERTSON: Yes, sir. CHAIRMAN JOHNSTON: Would you please state your qualifications. MR. ROBERTSON: Okay. I began working on drilling rigs in 1977. Between '77 and '82 I've worked on rigs as a E L I T E C O O R T R E P O R T I N G 4052 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 42 1! 2 3i 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 I 24 25 i roustabout, roughneck, motorman or derrickman, and during that time frame I worked on rigs in the Gulf of Mexico, onshore Texas, Idaho, Wyoming, Utah, Alaska's Cook Inlet, and Alaska's North Slope. In 1982 I began pursuing a petroleum engineering degree. In '88 I graduated from the University of Alaska, Fairbanks, with a BS in petroleum engineering. In 1988 I was hired by ARCO Alaska as a drilling engineer, and since 1988 I've worked as a workover and completions engineer, a drilling engineer or a company representative for either ARCO or BP Shared Services Drilling Department. And I've worked in the Prudhoe Bay, Kuparuk, Milne and Pt. McIntyre fields aver the last 10 years, and the last three years have been dedicated solely to working in Milne Point either as a drilling engineer or as a company representative. CHAIRMAN JOHNSTON: Thank you. We will consider you an expert witness in this matter. Please proceed. MR. ROBERTSON: Let's see, this portion of the testimony will include a description of Sag River well designs, completion designs and a reservoir surveillance plan. The drilling section will include a brief description of our drilling, casing, and cementing programs for the Sag River Pool. And this will be followed by a discussion of typical completion designs, safety systems and reservoir surveillance plans. Under Directional Drilling, our surveys will be by MWD, E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333•D364 • 43 • 2 3 4 5 6 7 8 9 • 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 measurement while drilling, or a gyro. The initial development logging suite planned for Sag River reservoir interval includes resistivity and gamma ray logs. And these logs, we'll get them from LWD, while we're drilling. Annular Injection. The surface casing by intermediate or production casing annulus on Sag River wells will be available for annular injection when approved by AOGCC in the Form 10-401 Permit to Drill. Under Casing and Cementing. The Sag River Pool casing and cementing requirements are generally consistent with AOGCC Regulation 20 ACC 25.030, requiring that casing and cementing programs meet the following criteria: 1) Provide adequate protection of all fresh water.. zones. 2) Prevent fluid migration between strata. 3) Provide protection from pressures and forces that may be encountered, including pressure and forces due to thaw subsidence and freezeback within the permafrost interval. Surface casing will be either shallow set or deep set. Shallow set surface casing is to be defined as surface casing set above the Schrader Bluff sands. And deep set surface casing is -- surface casing will set below the Schrader Bluff sands. The maximum surface casing setting depth is to be based on sound engineering principles and approved by the AOGCG in E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 44 • ~J • 1 2 3 4 51 61 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 251 our Permit to Drill. Our conductor casing is set 80 feet to provide anchorage and support for the rig diverter assembly. On surface casing cementing volumes, the surface casing cement volume will be determined in order to fill any rathole below the surface casing shoe as well as the entire annular volume from the casing shoe to surface. Excess volumes will be, determined based on historical data which have enabled cement li i to reach surface. Intermediate and/or production casing strings will be cemented with a volume of cement such that the top of cement is a minimum of 500 feet measured depth above any hydrocarbon bearing zone plus a minimum of 30~ excess. I! i It is proposed that the Sag River casing and cementing rules be written as specified in 20 ACC 25.030 and in accordance with the current Kuparuk Field rules as follows: 1) For proper anchorage and to divert an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface and cement will be pumped to fill the annulus behind he casing to surface. 2) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze-back, a string of surface casing will be set at least 500 feet measured depth below the base of 'the permafrost section. E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 45 • 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 ~ 18 19 20~ 21i 22 231, i 24 251I'~ r~ 3) To prevent well failure due to permafrost action, the operator shall install surface casing including connections, with sufficient strength and flexibility to prevent failure. To be approved for use as surface casing, the commission shall evidence that the proposed casing and '~ connections meet the above requirement. Other means for ' maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze-back, based on sound engineering principles, may be approved by the commission upon application. 4) It is proposed that the commission approve a ruling allowing the following alternative completion methods: a) liners to include, but not limited to slotted, pre-drilled, pre-packed, and sintered liners, or combination thereof, landed inside of cased hole and which may be frac/gravel packed; b) open hold completions provided that the casing is set not more than 50 feet above the uppermost oil bearing zone. Open hole completions may subsequently be .completed with liners, to include but not limited to slotted, pre-drilled, '~ pre-packed, and sintered liners, of combination thereof, and I'~i may be frac/gravel packed; c) horizontal completion with liners, to include but not limited to slotted, pre-drilled, pre-packed,. and sintered liners, or combination thereof, landed inside the horizontal E Z I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 46 • 11 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 extension and which may be frac/gravel packed; I d} multi-lateral type completions in which more than ~I one wellbore penetration in the Sag River Pool is completed in II I a single well, with production gathered and routed back to a I central wellbore; e) deepening or sidetracking existing wellbores to the Sag River reservoir; f) injection into the Schrader Bluff, Kuparuk, and/or I Sag River formation using a common wellbore and using packers j I and downhole flow control devices to regulate flow into each reservoir interval. The commission may approve other completion methods j I upon application and presentation of data which shows the I alternatives are based on sound engineering principles. Then finally with respect to drilling fluids. A spud ~I mud will be used to drill the surface hole. And a low solids, II non-dispersed mud system will be used to drill the reservoir Ii interval. ~, That pretty much sums up the drilling part of it. CHAIRMAN JOHNSTON: Thank you. In your experiences in drilling in this area have you encountered gas hydrates? MR. ROBERTSON: Oh yes, sir. We've encountered hydrates on several pads, and we've actually conquered the problem. I mean we've, over time, learned that we can -- we use a cold mixed water as possible for our muds. We usually ELI TE CDURT REPDRTIIVG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 47 ' • 1 2 3 4 5 6 7 8 9 10 11 12 13 . 14 15 16 17 18 19 20 21 22 23 24 25 use a smaller motor -- downhole motor which doesn't get as hot.l We minimize circulation rates and circulation times in those intervals, and then the biggest thing that we've done here lately is there's a product that's called lecithin, and it's actually a food product. They use it in making beer a lot, and so I'm intimately familiar with it, but what we've done is we've been able to weight up a little bit above the hydrate zone, add about a 2$ concentration of this lecithin, drill the hydrate zone and we barely even see them anymore, it will perk a little bit, and once we get below them they don`t bother us any more. CHAIRMAN JOHNSTON: Is that so. MR. ROBERTSON: Yeah, we've come a long way with hydrates. CHAIRMAN JOHNSTON: At what depth have you encountered the hydrates? MR. ROBERTSON: They're usually just below the base of the permafrost, right at this -- I would say between 2000 to 2500 feet TVD. CHAIRMAN JOHNSTON: And then once you get them behind cement you have no further problems with them at all? MR. ROBERTSON: No, sir. And we drilled probably 15 wells this summer on G & H pad where all those pads had hydrates, and without incident. So we're real happy with what we've done with hydrates. E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage AZaska 99508 907.333.0364 • 48 • ~i 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN JOHNSTON: Thank you. (Pause) State your name for the record, please. MR. HILL: Bill Hill. CHAIRMAN JOHN5TON: And I assume you wish to be sworn? MR. HILL: I do. CHAIRMAN JOHNSTON: Raise your right hand, please. (Oath administered) MR. HILL: I do. CHAIRMAN JOHNSTON: Thank you. Consider yourself sworn. And do you wish to be considered an expert? MR. HILL: Yes, please. CHAIRMAN JOHNSTON: State your qualifications, please. MR. HILL: I'm the lead production engineer with BP's Western North Slope Asset. I received a bachelor of science in petroleum engineering from the Royal School of mines, Imperial College, London University in June 1984. I have been employed by BP Exploration since August 1984 as a production engineer and have worked in the UK sector and in Alaska. My core skills are production engineering and completion engineering, both of which have been developed in an office and field environment. I've been in Alaska far about seven years. CHAIRMAN JOHNSTON: Thank you. The commission will consider you an expert in this matter. Please proceed. MR. HILL: Okay. I'll pick up the documentation here at Tubing/Casing Annulus Mechanical Integrity. Since the Sag I, E L I T E C O U R T R E P O R T I N G 4052 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 49 • 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19~ 20 II 21~i i 22 231 24 25 River injection wells will have an annulus with packer as part o their design, BPX will have the capability to pressure test the tubing/casing annulus to periodically check and verify the i i well's mechanical integrity. ~~ The Sag River production wells, however, will have an ~I electric submersible pump, ESP, suspended at the end of the I'~ tubing string with no packer present in the well, as is current ~I practice in the MPU ESP wells completed in the Kuparuk and III Schrader Bluff pools. This prevents testing of the I~ tubing-casing annulus to verify mechanical integrity as there I', will be open perforations in the reservoir interval. However, prior to perforating operations, the casing will be pressure tested to verify casing mechanical integrity. The Sag River production and injection trees are designed for the operating conditions expected at Sag River. The injection wells will also be equipped with check valves which allow injection down to the well, but block the well from flowing back at surface. Producers and injectors will be equipped with automatic pilot-operated surface safety valves which can be actuated from a remote position. Wellheads and trees will employ appropriate seal technology to minimize leaks and associated spills. Production wells will be designed to commingle production of all Sag River member sands. We anticipate profile modification and control of thief zones will be ELI T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage A.Zaska 99508 907.333.0364 • • 50 • 2 3 4 5 6 7 8 9 10 11 12 13 M 14 15 16 17 18 19 20 21 22 23 24 25 • primarily managed by controlling fluid injection in offset injection wells. Sag River production wells with an ESP and which do not require subsurface safety valves may be completed without a packer assembly as allowed by AOGCC Conservation Order Number 390. Artificial lift will be required in Sag River producers. Initial completions will utilize electrical submersible pumps or gas lift. Over time, the life cycle performance of these lift systems will be compared to alternative artificial lift methods. Artificial lift techniques may be modified if economics warrant. Electric submersible pumps have a finite life and require replacement when the unit has failed. Normal ESP changeout operations entail pulling the failed ESP, re-running tubing and a new EP, and putting the well back on production. In the past two years there have been approximately 120 rig operations at MPU where a significant portion of these rig workovers were to replace failed ESPs. ESP changeouts have taken as little as 44 hours from rig acceptance to rig release. We recommend that since the only modification to the wellbore is the replacement of the artificial lift unit, ESP, that Forms 10-403 and 10-404 not be required for routing E5P changeouts. The Sag River development area is largely coincident with the Kuparuk reservoir development and will rely on the E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 51 • 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 r ~J same operating infrastructure. Consistent with statewide AOGGC regulations, 20 AAC 25.265, and standard practices at MPU, subsurface safety valves, 5SSVs, will not be used in the Sag River development. Sag River wellheads. will be specifically designed to accommodate the ESP systems required to lift the Sag River fluids. Surface safety valves, SSVs, are included in wellhead equipment designs in a wing valve position. These devices will be activated by high and low pressure sensing equipment and are designed to isolate well fluids upstream of the SSV should pressure limits be exceeded. Where ESPs are employed, the sensing devices will de-energize the ESP concurrent with closing the SSV. Because periodic testing of the SSV will require pump shutdowns which are considered detrimental to ESP life span, we recommend testing the SSVs annually by reducing the speed of the ESP prior to the SSV test. Fracture stimulations of the low permeability Sag River formation will be required to achieve commercial flow rates in this reservoir. Horizontal wells can also be used to increase the productivity of the reservoir. Selection of the appropriate completion will be based on commercial and reservoir description considerations. Okay. Going to the Reservoir Surveillance Program here. As a result of the low density of wells currently E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 52 • • 1 2 3 4 5 6 71~ 8 9' 10 11' 12 13' 14 15' 16 17' 18 19 201~~ 21 22 231 24 25 completed in the Sag River, there are still many unknowns related to the flow characteristics areal continuity across the reservoir. These issues can only be resolved through actual I well development. Thus, a reservoir surveillance program will assist in the development and understanding of the Sag River. Pressures will be reported at a common datum of 8750 feet TVD subsea. Initial static pressure surveys are proposed in each production and injection will upon completion. On an annual basis, a minimum of one pressure measurement per lease, or four square section area -- four section area, across the field is recommended. Allowable pressure survey techniques should include wireline RFT measurements, pressure build-ups with bottomhole pressure measurements, ESP pressure measurements, injector surface pressure fall-offs and static bottomhole pressure surveys following extended shut-in periods. Pressure survey data would be reported to the AOGCC monthly. We anticipate that artificial lift equipment will preclude the use of surveillance logging techniques in producing wells. Surveillance logging will be used to monitor i injector profile distributions. We propose that a minimum of one injection survey or injection zone split determination be conducted per year per lease or four section area. Surveillance log data would be submitted quarterly. The existing well testing equipment at Milne Point Unit will be utilized to determine production rates from the Sag EL I TE CO UR T REPOR TIIdG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 53 • 1 2 River formation. Production will be commingled at surface and wells tested at least twice a month, utilizing a well test 3 4 5 6 7 methodology approved by the AOGCC. We recommend that optimum test duration at stabilized rates be determined by the unit operator in accordance with industry standard practices on a well by well basis. Production allocation methods currently in place for 8 g 10 11 12 13 14 15 16 I 17 18 19 20 ~ 21 22 23 24 ~ 25 r ~ ~~ the Kuparuk and Schrader Bluff formations will also be utilized) for the Sag River reservoir. A single production allocation factor based on a comparison of theoretical production with metered production volumes will be applied equally to the Kuparuk, Schrader Bluff, and Sag River formation production. Production data will be submitted monthly. In the event of production proration at or from Milne Point facilities, all commingled reservoirs processed through the Milne Point facilities will be produced to minimize adverse affects to surface or subsurface equipment. 'I And that concludes my testimony. CHAIRMAN JOHNSTON: Tn your production of the Sag River to date have you seen any evidence that the Sag River is able to flow to the surface water column? MR. HILL: No, it -- it's perhaps taken a very short period of flowing to surface, days, but it will quickly deplete and decline and requires artificial lift. CHAIRMAN JOHNSTON: Okay. And in terms of monitoring E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 54 51 6~ 7 81~, 91 10~ 11~ 12' 13 14 15' 16 17 18 19 20 21 22 23 z4 25 ~ the casing integrity, I see that you're proposing to test it 'before you run the ESP. MR. HILL: Before (indiscernible) absolutely. i CHAIRMAN JOHNSTON: Right. Do you have any proposals to monitor the casing over time in terms of determining whether you are maintaining integrity of the casing or..... MR. HILL: Our best go there is with the ESP lift. If the performance of the well is not in accordance with the III operating characteristics of the pump, clearly fluid is being ~ lost somewhere and that would raise suspicions and necessitate a workover or some diagnostic work to find the leak. Just by virtue of having that pump in the ground is a very goad indication of what should be happening at surface. In terms of pressure testing, no, we don't have anything formally documented in terms of doing perhaps a mechanical integrity test during the workover but that opportunity would be available typically on a two-year basis if they felt appropriate. CHAIRMAN JOHNSTON: If you saw some erratic performance in the ESP that would not necessarily indicate loss of casing integrity? MR. HILL: No, not necessarily. CHAIRMAN JOHNSTON: But it would be something that you'd want to trace down to figure out what that problem is? MR. HILL: Yes. EL I TE CO URT REPORT I NG 4051 East 20th Avenue #65 Anchorage A.iaska 99508 907.333.0364 • • 55 I • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN JOHNSTON: Presumably that would entail pulling the ESP, and once you pulled the ESP then you could run a pressure test after you put a packer in there? MR. HILL: Definitely. The key point now, as you say, is you have to pull the completion out of the ground,..... CHAIRMAN JOHNSTON: Right. MR. HILL: .....the tubing and ESP, part of the completion, out of the ground to ascertain what was going on in the casing, yes. We're fortunate that. we don't have much in the way a corrosion problem at Milne Point. Our C02 levels are very low and we don't have any H2S, so completion integrity has been very, very good over the years. CHAIRMAN JOHNSTON: So do I see a proposal here to run your production string all the way up to the surface? MR. HILL: The production tubing? CHAIRMAN JOHNSTON: See, you're going to have surface casing down to right around the Sag -- Schrader Bluff..... MR. HILL: Schrader Bluff, that's right, and then long string the 7 inch casing through the Sag River. CHAIRMAN JOHNSTON: And a long string and that will go from surface to TD? MR. HILL: That's correct, provided we were going to hydraulically fracture the well. It's quite possible that if we were to put in an open hole completion we would want to perhaps top set the reservoir and then drill out and lay in a E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 56 1~ 2 3 4 5 6 71 8 • • 9 101, 11 12 i 131 14' 15 16 17 18 19 20 21 22 23 24 25 liner of some description to enable us to drill the Sag River with a non-damaging mud and preserve as much formation permeability as we could, assuming we weren't going to frac the well. CHAIRMAN JOHNSTON: And then within the production string you'll run the ESP with the tubing? MR. HILL: That's correct. CHAIRMAN JOHNSTON: So you'll have at least two layers of protection uphole? MR. HILL: Yes. Yes, that's right. Yeah. I've got a..... (Off record comments) MR. HILL: Okay, here we have a current Sag River completion, in fact well MPU-Charli- 23, C-23. And as you can see, it's very straight-forward production completion with the ESP hung off the 2~/a inch tubing. This gas-lift mandrill up there, for interest, that enables us to commingle gas that has flowed up the annulus, if you like, and is commingled essentially just below surface because that is an effective method of achieving that and getting it to surface. It promotes run-life on the ESP as well not having to take some of the gas through the pump itself. And you can see your 7 inch casing running down to your perforations. Those perforations are hydraulically fractured, fracture half-length of about 150 feet, 24-40 propent. And then we have the surface casing down E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 57 2 3 4 5 6 7 8 9 • • 10 11 12 13 14 15 16 17 18 19 20~ 21 22 23 24 25 to just below the Schrader Bluff. So that is our current completion as it stands at the moment. As you know, we do have one well which is a horizontal well, E-13, where the reservoir was top set with a 7 inch casing. We drilled that with 6 inch assemblies instead of 4~ inch slotted liner in there. So that's how it stands. I hope that answers your question. CHAIRMAN JOHNSTON: Thank you. Are we getting toward the end of the testimony then? MS. DAVTS: That is all of our testimony of the ~, (indiscernible - away from microphone) proposed rules. CHAIRMAN JOHNSTON: Okay. What I'd like to do then is take a short break, maybe 10 minutes, and then come back and try and wrap this thing up. (Off record - 11:03 a.m.j (On record - 11:25 a.m.) CHAIRMAN JOHNSTON: I'd like to go back on record, please. We have a few questions for BP. In terms of .your possible future plans for EOR, whether it be miscible WAG or immiscible WAG, what are some of the drivers on that? We've seen proposals elsewhere across the slope for a pretty new development that really does not have any wells or very little information where the operator comes forward with a fairly aggressive miscible flood right from the getgo, and we're wondering why the difference here at Sag River. And if we ELI T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 58 1 could get the person answering to come up and speak with the 2 microphone? 3 MR. BURKf;: My name is Peter Burke. I guess at this 4 stage we -- one of the drivers would be the fractured nature of 5 the reservoir and how that showed up in well performance -- 6 continued well performance or the performance of the pilot. I 7 think in other reservoirs where we -- where BP has been a 8 partner anyway, including the Tom (ph) reservoir, for example, 9 we haven't seen a.ny evidence of fractures there and it's nat a 10 concern. But we would have a concern about putting injectant 11 in a reservoir which has a -- certainly is very faulted. 12 Whether I would say faulted and fractured, our thoughts are 13 that it is quite fractured. And to put injectant which has a 14 strong alternative economic value across a whole series of 15 reservoirs -- now Schrader, Kuparuk itself, we would want to 16 see that weren't entering into what could be a wasteful process 17 of recirculating and possibly losing injectant. 18 CHAIRMAN JOHNSTON: So your bootstrapping effect in the 19 -- in this particular reservoir..... 20 MR. BURKE:: In this particular..... 21 CHAIRMAN :TOHNSTON: .....or may not be as great as say 22 to the south..... 23 MR. BURKE: That's right. 24 CHAIRMAN ~fOHNSTON: .....and primarily because of the 25 fractured nature of..... E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 59 • • 1 2 3 4 51 61 71 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25i MR. BURKE: Yes. I mean it's a strong concern from us 'i in one, we'd want to see more evidence of and continued performance monitoring that, especially with a pilot. If we had that -- we had very rapid breakthrough that we thought was attributable to faulting, I mean it would certainly be a driver against the injectant. We might find alternative uses for the injectant which are much more viable. CHAIRMAN JOHNSTON: And you'll only be able to gauge the fractured nature or the problems associated with the fractured nature of the pool based upon additional drilling and performance of those wells? ~i MR. BURKE: Right. It's the most positive. I mean you can infer things from other sources including the size, but I ~I ~i mean the most positive evidence would be the performance 'I between an injector and produce it there. CHAIRMAN JOHNSTON: We11, haw long do you think it will) take for BP to more fully explore the feasibility of MI; are we talking a year, two years or five or six years? j MR. BURKE: Well, our plans at the moment are to proceed with the design of the C-12 sidetrack to support C-23 '' area. And we wouldn't really get much injection performance. underway until the end of '99, I would think. So, I mean, it's that kind of time scale really to see whether we should pursue that in Phase 2. CHAIRMAN JOHNSTON: So it's several years out you might E L I T E C OUR T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 60 1 2 3 4 • I~ 5 6 7 8 91 10 11 12 13 14 15 16 17 18 19 20 21 22 23 I 24 25 be prepared to sit down with the commission again and further explore the feasibility of say an MI flood? ~, MR. BURKE: Right. That's -- I'd say that's based on doing the Phase 1 work that we've talked about of having to II compete for our places on the drilling rig schedule and then toj pre-produce the area and to flange up and inject gas in a significant enough period. So it is, as you say, several years before we would..... CHAIRMAN JOHNSTON: And if you were to go eventually to a MI flood, where would be your source of MI? CHAIRMAN JOHNSTON: I guess sources of MI just haven't been fully defined yet. I mean we're looking at MI elsewhere in our operations and we have to consider MI -- MI not only being hydrocarbon, of course it could be C02 -- C02/NGL mix. I mean we're considering those kind of options right across our three main reservoirs at this moment. CHAIRMAN JOHNSTON: In terms of your gas support that you're proposing, where is the gas coming from? II MR. BURKE: The gas at the moment can came from j produced gas from our current operations which, of course, will' be a mixture of Schrader Bluff and Kuparuk and Sag. CHAIRMAN JOHNSTON: Right. MR. BURKE: Commingled gas. We would simply -- we have high pressure gas available at that particular well pad. The source is already available to us at the site.. E L I T E C D U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907 •333 •0364 • 61 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN JOHNSTON: In terms of the areal extent of the West Sag accumulation principally to the southeast in the Cascade area does the reservoir appear to extend into the Prudhoe Bay Unit? MR. BURKE: I guess I would ask my colleague -- I'll hand him the mic -- to answer on geological grounds. CHAIRMAN JOHNSTON: Very good. MR. BURKE: I have no reservoir engineering comments to make on that. ~ CHAIRMAN JOHNSTON: Thank you.. MR. HUNTER: My name is Bob Hunter. The question, as I'~ ~i understand it, was what is the areal extent of the Sag River reservoir in the southeastern portion of the area? CHAIRMAN JOHNSTON: Right. And does it extend into the I Prudhoe Bay Unit? MR. HUNTER: Okay. My short answer to that question would be that we do not believe the specific hydrocarbon associated with K-33 and the Cascade-O1 penetrations extends into the Prudhoe Bay area. We believe it is a defined oil-water contact, it's difficult to see on this map, but you can see closure at a level of 9150 that is also associated with some of these faults, and that it is confined within the map that is shown here in Exhibit 2. CHAIRMAN JOHNSTON: Now is that the -- I'm noticing on that exhibit a red outline around the Cascade well. What does E L I T E C O U R T R Ts PORT I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 62 ., 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that red outline indicate? MR. HUNTER: This red outline indicates it's. done, I believe, on the basis of 40 acre tracts, but it is in the area around that 9150 closure in the Cascade area, and this is the area that we would specifically come to the DNR for discussion about the -- not the pool rules, but the..... MS. DAVIS: PA. MR. HUNTER: .....PA. And that -- you'll also see a red area around the central area here, and also in the area to the northwest. CHAIRMAN JOHNSTON: So that's the proposed participating area boundary for the Sag River? MR. HUNTER: That's correct, although we have not formally proposed that. CHAIRMAN JOHNSTON: Okay. And has the unit boundary been expanded now to include that Cascade portion? MR. HUNTER: I believe it has. Is that correct, Marsha? MS. DAVI5: Yes, it has. CHAIRMAN JOHNSTON: It has. MS. DAVIS: It arrived at its decision in December. CHAIRMAN JOHNSTON: So now that portion is included within the unit boundary? MS. DAVIS: Correct. CHAIRMAN JOHNSTON: So this map needs to be amended to E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • 63 • 2 3 4 5 6 i 7 8 • I~ 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 reflect the unit boundary extending to the southeast? MR. HUNTER: Yes, it does. CHAIRMAN JOHNSTON: Any other questions? MR. CHRISTENSON: No. CHAIRMAN JOHNSTON: Okay. It looks like we have no further questions for BP at this time. I guess there's one matter that we do need to clarify relative to the earlier confidential portion. Because we decided that the information that we were hearing was not confidential and decided to proceed with a public session, I do not see any need to have the transcript reflect or have the portion that we kind of convened for the public to be typed up at all since the same information verbatim was presented in public sessions, so I think it would be better just to keep a clean record to indicate a public process from the beginning of the hearing to the end of the hearing and so there's no need for our court reporter to type up that small section in there where we were dealing with supposedly confidential information. REPORTER: Thank you. CHAIRMAN JOHNSTON: Okay. Any other comments from the applicant then? MS. DAVIS: No. CHAIRMAN JOHNSTON: Is there anybody in the audience that wishes to make a statement or appear before the commission? I guess with that I don't see any reason to keep E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • • 64 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the record open, so I'd like to adjourn this hearing and thank you for your participation. (Off record - 11:37 a.m.) END OF PROCEEDINGS E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 r~ L J • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • • C E R T I F I C A T E UNITED STATES OF AMERICA) )ss. STATE OF ALASKA ) I, Laurel L. Earl, Notary Public in and for the State of Alaska, and Reporter for Elite Court Reporting, do hereby certify: That the foregoing Alaska Oil & Gas Conservation Commission Hearing Re: Sag River Pool, Milne Point Unit was taken before me on the 25th day of February 1998, commencing at the hour of 9:00 o'clock a.m., at the offices of Alaska Oil & Gas Conservation Commission, 3001 Porcupine Street, Anchorage, Alaska; That the hearing was transcribed by myself to the best of my knowledge and ability. IN WITNESS WHEREOF, I have hereto set my hand and affixed my seal this 11th day of March 1998. Notary Public in and for Alaska OFfiCIAI SEAL STATE OF ALASKA NOTARY PUBLIC I.AIlR~L L. /EARL q ~} ~1y Comm. expires:...1.1.:..~.+..`3..~' :rtnxvtitKCabvaxtt+naNnwt; wwlttiw~tu~a:-tmrov E L I T E C O U R T R E P O R T I N G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 • MILNE POINT UNIT TESTIMONY FOR SAG RIVER POOL RULES February, 1998 c ~.-~.~c,..~,~ ~~~ • ~+ • TABLE OF CONTENTS I. INTRODUCTION II. GEOLOGY AND RESERVOIR DESCRIPTION III. RESERVOIR OIL-IN-PLACE AND FLUIDS IV. RESERVOIR DEVELOPMENT V. FACILITIES VI. WELL DRILLING AND COMPLETION OPERATIONS VII. PROPOSED SAG RIVER POOL RULES VIII. LIST OF EXHIBITS XI. REFERENCES Page 1 2 7 8 15 17 24 29 29 u • ~ Milne Point Unit Sag River Pool. Rules Testimony February 25, 1998 1. Introduction My name is Marcia Davis. I am an attorney for BP Exploration (Alaska) Inc., the operator of the Milne Point Unit. BP is presenting testimony today on behalf of itself, as a working interest owner and unit operator, and OXY USA, Inc., the other working interest owner in the Milne Point Unit. This hearing has been scheduled in accordance with 20 AAC 25.520 and 20 AAC 25.540 in order to consider evidence relevant to the establishment of pool rules for the Milne Point Unit Sag River resources. This testimony includes operating and technical data concerning the currently understood geological and reservoir properties as well as proposed plans and timing for reservoir development. This testimony will enable the Commission to establish rules allowing economical development of Sag River resources which will prevent waste, protect freshwater and protect correlative rights. Testimony is divided into four ,primary disciplines: geology, reservoir, facilities engineering and drilling and completions engineering. Robert Hunter will present testimony related to the geology of the Sag River, Peter Burke will present the reservoir testimony, Peter Richards will present the surface facilities testimony, and James Robertson and Bill Hilt will present the drilling and completions testimony. Each of these witnesses will state his education and experience which we believe qualify him as an expert. Each of the witnesses is prepared to respond to questions concerning the testimony and related exhibits. Some of the materials to be presented today are confidential, and we request that such information be kept confidential pursuant to AS 31.05.035(d) and 20 AAC 25.537. We will identify which sections of the testimony we consider confidential at the time it is to be presented request that the public be excluded from this portion of the hearing. Our witnesses will be presenting sworn testimony and wish to be qualified as experts. • CONFIDENTIAL -1- • t Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 II. Geology and Reservoir Description Introductions My name is Robert Hunter. I am a senior geologist working satellite development opportunities in the Western North Slope department of BP Exploration (Alaska). I received a Bachelor of Arts degree in geology from the University of Montana in 1984 and a Master of Science degree in geology from the University of Wyoming in 1986. I have been with BP and its affiliates for the past 12 years. I have worked the subsurface of the North Slope over the past nine years in Prudhoe, Lisburne, Pt McIntyre, Niakuk, Kuparuk, and Milne Point developments. My testimony provides geologic justification to the Commission supporting BP's proposed Sag River Pool limits. My name is Peter Burke. I am the reservoir engineer for Sag River development. 1 studied petroleum reservoir engineering to Master's level at London (UK) University and have over 25 years industry experience with BP Exploration and Amoco. I started work on the Sag River development in March of 1997 and have directed the reservoir performance simulation work conducted by an external consultant. . General Overview The proposed Sag River Pool area is located in the Milne Point Unit area near the coastline of Simpson Lagoon on the Western North Slope. This Sag River Pool would include the stratigraphic interval defined by the MPA-01 type log from 8810 to 8884 feet measured depth (Exhibit 1) within the mapped area of the oil accumulation (Exhibit 2). Exhibit 2 also illustrates the Milne Point Unit location and outline and the area of t_he proposed Sag River pool rules. Working interests in each of the leases are held uniformly by BP at 91.19% and OXY USA Inc. at 8.81 %. Chevron discovered oil in the Sag River formation in this area in the Kavearak Point 32-25 well in 1969. This discovery was confirmed by Conoco in their MPA-01 well in 1980. BP acquired working interest in the Milne Point Unit leases from Conoco and Chevron and succeeded Conoco as unit operator effective January 1, 1994. In 1995, BP drilled the first dedicated Sag River well (MPE-13) to assess productivity of this relatively poorly developed reservoir. Since that time, BP has drilled three additional widely spaced Sag River appraisal wells: MPC-23 and MPF-33 in 1996, and MPK-33 in 1.997. The marginal productivity from these wells dictates caution in the development CONFIDENTIAL -2- • s Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • program. Therefore, BP will proceed with a synergistic development of Sag River with Kuparuk and Schrader Bluff opportunities where possible. Additionally, radically de- scoped well options are being evaluated. In order to economically develop the Sag River Pool, BP will need to demonstrate that certain technical operations are feasible with respect to this pool. First, BP is planning to test a pressure support mechanism by initiating gas injection in a planned sidetrack near the existing Sag River well, MPC-23. If pressure support is demonstrated to be technically and economically feasible, BP will consider implementing additional injection patterns. The ability to utilize 40-acre spacing will enhance the success of such a program. Finally, the economic feasibility of any development is contingent upon the _ Sag River Pools' use of existing infrastructure and the ability to commingle production in the shared facilities. Request Confidential session (AS 31.05.035(d) and 20 AAC 25.537) StratigraphX • The late Triassic to early Jurassic Sag River formation consists primarily of thin marine shelf sand packages deposited throughout the Prudhoe Bay area on the North Slope of Alaska (Barnes, 1987). The North Slope Stratigraphic Committee (1971) designated the Sag River formation as the sandstone interval underlying the Jurassic Kingak shale and overlying the Triassic Shublik formation in the subsurface of the Prudhoe Bay region. The sands are extensively bioturbated which has mixed the originally deposited sands, silts, and muds, forming a relatively poor reservoir quality sandstone. In the proposed pool area, the Sag River formation is divided into four zones named A,-B, C, and D from bottom to top (Exhibit 1). This zonation scheme was originally proposed regionally by Gardner (1987). Each zone boundary likely represents a chronostratigraphic surface and is commonly marked by an increase in bioturbation, shaliness, and phosphorite and glauconite concentrations (Gardner, 1987). The Sag River formation averages 77 feet in thickness in the proposed pool area. The Sag River formation net pay ranges from 9 to 18 feet thick (Exhibit 3). The Sag River formation permeability-thickness ranges from 30 to 68 millidarcy-feet (Exhibit 4). Zone A is the basal Sag River sandstone unit unconformably overlying the Shublik formation (Exhibit 1). Zone A is almost entirely tight, non-reservoir sandstone in the proposed pool area. Porosities develop up to 18% and permeability up to 1.2 millidarcies (md). The average gross thickness of zone A is 16 feet. CONFIDENTIAL -3- s~ Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Zone B is the primary Sag River reservoir interval in the proposed pool area. Zone B develops porosity up to 21 % and permeability up to 23 and as measured from cores taken in the area. The average gross thickness of zone B is 30 feet. Zone C is the uppermost Sag River sandstone in the proposed pool area. Zone C is tight, non-reservoir sandstone. Porosities develop up to 17% and permeability to 2.9 md. The average gross thickness of zone C is 10 feet. Zone D is non-reservoir siltstone and shale at the top of the Sag River formation. A prominent shift in sonic and resistivity logs occurs at the contact between the base Kingak and the top Sag River formation (Exhibit 1). The average gross thickness of _ zone D is 21 feet. The structure map (Exhibit 2) and velocity field were constructed to conform to the top of zone C since zone D is not a reservoir. Structure Within the proposed pool area, the top Sag River has been mapped using three- dimensional seismic data from the Milne Point and Northwest Eileen seismic surveys. • The regional structure on the top of the Sag River is dominated by a number of northwest-southeast trending faults which support three-way anticlinal closures in the footwall of these faults. Additional faults trending north-south and east-west segment and complicate these closures. All fault sets appear to post date deposition of the Sag River interval. Throws range from 20 feet to in excess of 200 feet, with the greater throws associated with the NW-SE trending faults (throwing down to the southwest). The segmentation of the structural closures is supported by oil-water contacts inferred from existing well penetrations, leading to three equilibration regions as discussed below. The Sag River depths in this region range from 8,500 feet to 9,500 feet true vertical depth subsea (TVDss) (Exhibit 2). The depth structure at the top Sag River merges existing Sag River well control with an interpretation of average seismic velocity which accounts for regional thinning of the permafrost interval. Thinning of the permafrost interval leads to a velocity gradient which roughly parallels the present day shoreline and barrier island trends. As development drilling provides additional velocity control this model can be further refined. Trapping_Mechanisms • The trapping mechanism of the Sag River is predominately structural but maybe a combination of structural and stratigraphic. Faults with vertical displacements as low CONFIDENTIAL -4- • ~ Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • as 50 feet appear to trap oil and might segment the reservoir into blocks with different oil/water contacts. Controls over Oil Distribution Three regional blocks with separate oil/water contacts (OWC's) have been identified in the proposed pool area (Exhibit 2). Three OWC's are currently recognized; these contacts are: 9150 feet TVDss in the southeast area near MPK-33, 9050 feet TVDss in the central area near MPE-13 and MPC-23, and 8950 feet TVDss in the northwest area near MPF-33. These OWC's are based on mapped structural closure and observed well productivity or well tests. The OWC's, therefore, appear to step up to the northwest. The Shublik formation does not develop into a reservoir in the proposed pool area. Neither the Eileen, Ivishak, or Lisburne formations are known to contain more than residual hydrocarbons within the proposed pool area. The Eileen and Ivishak formations contain high water saturations even where penetrated above the depths of the Sag River OWC's. Three wells penetrate the Eileen and Ivishak above the Sag • River OWC's: MPA-01, MPE-13 pilot hole, and MPC-23. Proposed Pool Name and Boundaries The name Sag River Pool is proposed for oil accumulations in the MPA-01 type log from 8810 to 8884 feet measured depth (Exhibit 1) and the mapped area of the oil accumulation (Exhibit 2). This would include Sag River zones A through D which have been correlated throughout the proposed pool area. Reservoir Description This section will summarize the reservoir properties of the Sag River reservoir in the proposed pool area. The formulated description was utilized in the reservoir simulation study, which provided data on the field volumetrics and original oil-in-place and on the recovery processes. In MPU five wells contain either core or rotary sidewall cores in the Sag interval (full core in Kavereak 32-25, MPB-01, MPC-01, and MPL-01, and sidewall cores in Cascade-01 ). Six additional wells have recorded logs over the interval in the proposed pool area (MP18-01, MPA-01, MPE-13, MPC-23, MPF-33, and MPK-33). U CONFIDENTIAL -5- • s~ Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Reservoir Properties Gross Interval Porosity data from the cored wells were used to model porosity in the non-cored wells. Core data was available for the Sag A, B and C zones. The B zone contains the highest quality sands. The core grain densities which are greater in the C and A zones likely indicate more carbonate cementation. Core porosities in the B interval range from 8-21 % with a mean of 16%. Core porosities in the A and C zones range from 2-19% with a mean of 12%. Permeabilities from the core data were used to predict permeability in the non-cored wells. The permeabilities range from 0-23 and for the available core data. Zone B arithmetic average permeability was 2.7 and whereas Zone A and C average 0.4 md. A criteria of greater than 1 and permeability (predicted or core) is used to determine net pay for wells above the OWC (Exhibits 3 and 4). The net pay in rock with permeabilities greater than 1 and usually occurs in rock of greater than 15% porosity. Net Pay Interval Average water saturations in the net pay calculated intervals from log analysis range from 45-57%. Zone B average porosity is 18% with an average permeability of 2.8 and in the net pay. Zones A and C average porosities are 16% with average permeabilities of 1.2 and 2.1 md, respectively in the net pay. Core, log and log model derived porosities, permeabilities, net-to-gross and water saturations were input into the reservoir model fior zones A, B and C. Permeabilities in the reservoir model were adjusted upwards by a constant to match well history. CONFIDENTIAL -6- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 III. Reservoir Oit-In-Place and Fluids Original Oil-in-Place (OOIP) The estimated OOIP for the Sag River interval in the proposed pool area is 61.7 million stock tank barrels (MMSTBO) as calculated from the recently constructed reservoir model. The northwest area contains 9.7 MMSTBO and is being produced by MPF-33. There are 49.1 MMSTBO in the central area of the pool, which is now being produced by MPE-13 and MPC-23. There are 2.9 MMSTBO in the southeast area, which is being produced by MPK-33. The productive volume in the model is constrained by rock and fluid properties, the net pay thickness of the sand, the oil-water contacts as defined earlier, and by the major sealing faults. The results are as follows: Estimated Area OOIP Region in Model Acres SMMSTBO~ Northwest Area 1,300 9.7 Central Area 6,800 49.1 Southeast Area 400 2.9 TOTAL 8,500 61.7 Reservoir Fluids and PVT Properties A fluid property analysis has been performed on a sample from the MPC-23 well. The principal characteristics of the sample are as follows: Average Crude Oil Gravity 39.2 deg API Bubble Point Pressure 3513 psia Solution Gas-Oil Ratio (Separator) 974 scf/stb Oil Formation Volume Factor (Initial Conditions) 1.56 rb/stb Oil Viscosity (Initial Conditions) 0.277 cP Gas Gravity (Separator) 0.8038 (Air=1.0) The measured initial reservoir pressure and temperature were 4425 psia and 235 degrees F at a datum of 8750 feet TVDss. CONFIDENTIAL -~- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 IV. Reservoir Development Introduction This portion of the testimony will include a discussion of reservoir performance, development and management of the Sag River Pool. The potential performance of the Sag River reservoir was investigated using athree-dimensional, black oil reservoir model. This model was used to guide the decisions related to the optimum development and reservoir management of the Sag River Pool. Reservoir Uncertainties There are many aspects of the reservoir which are still unknown including the degree of areal continuity across the reservoir, fracture density and conductivity in the vertical and horizontal directions, anisotropy in the reservoir properties, observed performance under water and/or gas injection, aquifer strength, fault transmissibility and OWC in undrilled fault blocks. Therefore, the development plan requires flexibility to accommodate any required adjustments in the operations due to unexpected reservoir conditions. Although gas injection is the currently preferred development strategy for the field, the actual reservoir parameters may point toward the ultimate recovery scheme being a waterflood or a water alternating gas (WAG) injection plan. Recove Mechanisms The primary recovery mechanisms for full development of the field are fluid expansion and aquifer pressure support. There is no gas cap as the reservoir was initially 912 psi undersaturated with a pressure of 4425 psia, compared with the bubble point of 3513 psia. Estimated recovery under primary depletion with normal development is 15% of the original-oil-in-place (OOIP), rising to 38% with an immiscible gas flood scheme. RESERVOIR MODEL STUDY Model Assumptions The proposed pool area Sag River reservoir, zones A, B and C were modeled using Landmark's VIP simulation program. VIP is athree-dimensional, multi-phase simulator with black oil and compositional options. A black-oil treatment was used for the Sag River Pool study. CONFIDENTIAL -g- • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 A full-field model (FFM) was built to investigate various development plans and recovery processes for the field. The model area including the grid configuration is shown in Exhibit 5. The model cell size is 419 feet by 419 feet for an area of four acres, with seven model layers. Overall dimensions of the grid are 198 cells by 54 cells with seven layers for a total of 74,844 cells. The reservoir description used in the FFM included the seismic structural definition and the layering interpretation described in the Geology and Reservoir Description sections. The Sag A and C layers were represented with one layer each while the thicker B layer reservoir sandstone was subdivided into two layers, each averaging 15 feet in thickness. Average model layer properties for the main Sag interval net pay in Layer B, are 18% porosity and 8 millidarcies (md) permeability. The net pay in the Sag A and C layers have average porosities of 16% to 17% and average permeabilities from 1 to 2 md. Three different OWCs are used in the model for the Sag River interval, as described in the Geology section. The Shublik, Eileen, and Ivishak formations are also included in the model. It is believed that the water production in the MPE-13A well is coming from a fault conductive to the Ivishak interval. Both the Eileen and Ivishak have been given porosity, permeability, and high water saturations in the model. The Shublik is treated as anon-porous shale. A six well pattern model was also built for a preliminary sensitivity analysis of well density and injection options. The pattern model used the same layering scheme as the FFM and represented the central area around the MPC-23 well. PVT properties and oil-in-place used in the simulation study were given in the previous Reservoir Oil-In-Place and Fluids section. Relative permeability was based on that developed for the Sag River modeling in Prudhoe Bay Unit. l The adjacent aquifer was modeled as a fixed pore volume of columns of cells attached directly to the oil zone below the OWC. The aquifer volume is around seven times that of the oil zone. Model Forecasting Following the initial construction, the FFM was history matched with the four producing wells to help assure valid forecast results. Adjustments were made primarily to the Sag River layer permeability (increased from an average of 2.7 to 8 and in the B zone) and to the fault conductivity near the MPE-13 well. • CONFIDENTIAL -9- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Following the history match, the FFM was set-up to forecast the future performance of the reservoir under various operational scenarios. In these cases all wells were placed on bottom hole pressure control with a minimum flowing pressure of 1,500 psig for the producers and a maximum bottom hole injection pressure of 5,500 psig (or 0.62 psi/ft). To approximate the enhanced productivity/injectivity from stimulation, all proposed wells were assigned negative skin factors and increased permeability in the model cell containing the well. The forecast cases included gas injection with varying well spacing, waterflooding, and horizontal wellbores. For each case, well locations were selected based on the productive areas, according to the desired well density and pattern configuration. New wells were added to the model in a staged fashion to approximate a probable drilling schedule. Model Results Each of the forecast cases was run to 1 January 2018. In all cases, voidage was approximately replaced (i.e., constant reservoir pressure was maintained) by injecting • either make-up gas in addition to the produced gas from the reservoir or sufficient injection water. Initial results indicate that the estimated optimum ratio for producers to injectors (P:I) ratio is between 2:1 and 1.5:1, and this was used in selecting the well locations and service for each forecast. In summary, gas injection gave the best recovery of the options analyzed. Waterflooding does provide a significant improvement in the recovery over primary depletion. Horizontal wells contribute to additional production over conventional vertical well development, however, their application is not universally applicable across field due to reservoir constraints and/or economics. In all cases, down-dip wells benefit from pressure support from Sag River aquifer. FFM recovery results are shown in the following table. CONFIDENTIAL -lo- • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • • Planned Effective Number Oil Recovery Weil Spacing Well Spacing of Wells Production Factor Case acres (acres) (Prod/Inj/Tota~ (MMSTBO) % OOIP Primary i 60 15 Waterflood 160 217 27/12/39 18.7 30 Gas Inj 160 217 27/12/39 23.5 38 Gas Inj 200 273 22/9/31 22.0 36 Gas Inj 320 338 16/9/25 19.8 32 Gas Inj 200 256 22/11/33 23.4 38 Utilizing Horizontal Wells * Results from using six well pattern model. The planned well spacing figure for each case was used to locate wells in the fully developed, up-dip, central area of the model. The effective spacing value was calculated by dividing the estimated productive area above the OWC by the total number of wells. Additional model work is planned with alternative completion techniques and different operating scenarios. As development of the field progresses, the new data received will be used to update the model and, if necessary, revise the development plan fore optimum recovery operations. RESERVOIR MANAGEMENT STRATEGIES Producing wells will be completed in the Sag River C, B and A Sand intervals (as shown in attached type log, Exhibit 1) with fracture stimulations. ~~ Sources for the injected gas will be produced gas from the Sag River Pool and make-up gas from other sources in the area, including Kuparuk and Schrader Bluff. At a minimum, voidage will be replaced with the reservoir pressure being maintained at or near 4,300 psia. CONFIDENTIAL -11- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Since gas injection, with associated gas breakthrough and production, is the recommended method of pressure support, gas-oil ratios at the producer wells will exceed limits set forth in 20 AAC 25.240(b) and an exception to this rule is requested. RESERVOIR DEVELOPMENT CONCLUSIONS Based on modeling, immiscible gas injection is indicated to be the preferred recovery process for the Sag River development with recoveries in the 32% to 40% range. Water-alternating-gas (WAG) or simultaneous water and gas injection, using miscible or immiscible gas, are considered possible future recovery mechanisms for the Sag River reservoir along with alternative completion techniques such as horizontal or multi-lateral _ wellbores. Forty acre spacing is requested in order to allow for flexibilitydeveloping the field. The planned spacing is 320 acres per well, but reservoir conditions may require optional well location configurations. Estimated recovery from the field under gas injection is 20 MMSTBO, with the majority of the production coming from the wells in the central area. END CONFIDENTIAL SECTION RESERVOIR PERFORMANCE Appraisal Phase Performance The 1995-1997, four well Sag River appraisal program was valuable in determining well productivities and reservoir characteristics. The performance of the MPE-13 horizontal well has indicated that a fault in the wellbore is conductive and extends below, and possibly above, the producing horizon. The producing area to the southeast is limited due to the oil-water-contact (OWC). The MPC-23 and MPF-33 vertical wells appear to be representative of typical behavior for the field. These wells had initial rates around 1000 bopd (MPF-33) to 2000 bopd (MPC-23) but declined sharply to 200-400 bopd within a year. As of November, 1997, cumulative production from the Sag River Pool is around 785,000 barrels of oil. DEVELOPMENT PLANS The Commission has copies of the Milne Point Unit Review of the 1997 Plan of Exploration, Development and Operations, and the Milne Point Unit 1998 Plan of Exploration, Development and Operations that were filed with and approved by the Department of Natural Resources. These were filed with the Commission for informational purposes pursuant to AOGCC regulation 20 AAC 25.517(a). CONFIDENTIAL -12- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 CJ The plans below outline a full Sag River development should Sag River development become economically viable. These plans show the most efficient development of the Sag River reservoir as demonstrated from the reservoir model. Initial reservoir pressure in the Sag River reservoir is about 900 psi above the bubble point pressure. To date, there have been no reservoir pressure support measures implemented. Therefore, BP is currently planning in 1998 to drill a sidetrack, pre- produce it, and then initiate immiscible gas injection as part of Phase 1 drilling and completion if the project can be demonstrated to be economically viable. . Although only gas injection and waterflooding scenarios have been analyzed to date, water-alternating-gas (WAG) injection using miscible or immiscible gas is considered to be a possible future recovery method for the Sag River reservoir. If further study indicates that this would yield a more favorable recovery and is economically viable, then the development plan would be revised to conform to those results. Horizontal wells and/or multi-laterals will also be considered and, if proved economically viable, implemented in the future. The recommended full development plan at this time contains a total of 25 wells (four existing wells with 20 to 22 additional wells) with 16 producers and nine injectors. Development well spacing will be up to 320 acres, consistent with the model study results. Directionally drilled vertical wells are planned for each phase of development at this time. Future drilling could include the use of less conventional wellbores, such as horizontal or multi-lateral wells. A map with the proposed development plan is shown in Exhibit 6. Proposed injection wells are annotated with an "I" following the well name.. Phase 1 - 1998 Current phase 1 development plans for the Sag River reservoir at Milne Point consist of at least one well drilled to offset the MPC-23 well and possibly two to four additional penetrations. These wells may be sidetracks or deepenings of current wells in the central area (Exhibit 2). If surface facility constraints permit, an additional delineation well may be drilled from F-Pad to the northwest. The actual performance of the MPC-23 area wells will direct the future pool development. CONFIDENTIAL -13- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Phases 2 and 3 Two subsequent phases are included in the current development plan. Phase 2 will add 14 additional wells with seven producers and seven injectors. MPF-33 may be converted to injection. Three producers will be added in Phase 3. Again, this schedule is subject to revision as performance from the new wells dictates. Well Spacing Depending on reservoir description and performance, select areas may require well spacing other than 320 acres. This may be determined by faulting, areal changes in permeabilities, or fracture conductivity, which result indifferent than expected performance. Therefore, a 40 acre well spacing is requested to allow flexibility in placement of wells to maximize recovery from the Sag River oil reservoir. U CONFIDENTIAL -14- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 V. Faciiities Introduction My name is Peter Richards. I am the Development Studies Team Leader for Milne Point Unit responsible for facilities development studies. I received a Bachelor of Engineering degree in Chemical Engineering from Imperial College, London in 1983 and achieved Chartered Engineer status in 1990. I have worked for BP Exploration for 14 years in Development, Project and Operational roles in the UK, Norway, Colombia and now Alaska. General Overview The Sag River reservoir underlies the Kuparuk reservoir and Schrader Bluff reservoir within the Milne Point Unit (MPU). Sag River fluids will be commingled with Kuparuk and Schrader Bluff fluids at the pads and produced into the MPU facilities. Economical development is contingent upon utilization of the MPU infrastructure and facilities which will also minimize environmental impacts. Pads and Roads The MPU pads and road system will be used to support Sag River drilling, construction, and operations. Pipelines Sag River pipeline needs are for multiphase production. High pressure gas injection lines may be needed for Sag River gas injection if gas injection becomes a viable enhanced reservoir recovery process. Sag River development will use MPU pipelines. Power Lines Sag River development will utilize MPU power lines and on pad electrical equipment. Production wells that will use Electrical Submersible Pumps (ESP's) for lift will require on pad transformers and drives which will be accommodated through minor expansion of on pad facilities. • CONFIDENTIAL -1s- • ~ Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Facilities The base assumption for Sag River facility development is daily operation which requires minimal regular operator presence in line with present operating practice. All data gathering and routine operations are to be accomplished remotely from the CPF and/or any pad control room. Routine operations are defined as: 1. Well testing using existing pad .well testing facilities 2. Well test divert valuing 3. Emergency shutdown 4. Production control (ESP control) 5. Injection gas flow metering (possible future operation) 6. Production pressure metering Manual operations are defined as: 1. Weli bore freeze protection 2. Chemical injection . 3. Injection choke valve actuation Well control and testing functions are performed remotely using the control system. Well production rate is generally controlled using variable speed drive (VSD) controls for the wells with down hole ESP's or gas lift injection rates for gas lift wells. Testing takes place by a simple divert valve system redirecting the flow from the production header to the test header and is controlled remotely. Emergency Shutdown Emergency shutdown systems meet API-RP 14C requirements and BPX specifications for safety systems. All production, test, and injection piping on-site will be designed to be able to contain well head shut-in pressure up to the emergency shut down (ESD) valves. Production wells can be shut down due to over or under pressure with pressure switches. Additionally, these wells can be shut off remotely through the control system. Injection wells flow reversal, due to a surface system leak or depressurizing, is stopped by the use of a low pressure switch, ESD valve and check valve at the well. • Additionally, these wells can be shut off remotely through the control system. CONFIDENTIAL -16- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • VI. Well Operations Introduction My name is Bill Hill. I am the Lead Production Engineer for BP's Western North Slope Asset. I received a Bachelor of Science in Petroleum Engineering from the Royal School of Mines, Imperial College, London University in June 1984. I have been employed by BP Exploration since August 1984 as a Production Engineer and have worked in the UK Sector and in Alaska. My core skills are Production Engineering and Completion Engineering both of which have been developed in an office and 'field' environment. My name is James Robertson. I began working on drilling rigs in 1977. Between 1977 and 1982 I worked on drilling rigs as a roustabout, roughneck, motorman, or derrickman. During that time frame I worked on rigs in the Gulf of Mexico, onshore Texas, Idaho, Wyoming, Utah, Alaska's Cook Inlet and Alaska's North Slope. In 1982 I began pursuing a degree in Petroleum Engineering. In 1988 I graduated from the University of Alaska, Fairbanks with a B. S. Petroleum Engineering. In 1988 I was hired • by ARCO Alaska Inc. as a Drilling Engineer. Since 1988 I have worked as a workover and completions engineer, drilling engineer or Company Representative for either ARCO or BP's Shared Services Drilling. I have worked in the Prudhoe Bay, Kuparuk, Milne Point, and Point McIntyre fields over the past 10 years. General Overview This portion of the testimony will include a description of Sag River well designs, completion designs and a reservoir surveillance plan. The drilling section will include a brief description of our drilling, casing, and cementing programs for the Sag River Pool. This will be followed by a discussion of typical completion designs, safety systems and reservoir surveillance plans. Directional Drilling Directional surveys will be by MWD or gyro. • CONFIDENTIAL -17- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Logging Operations The initial development logging suite planned for Sag River reservoir interval includes resistivity and gamma ray logs. These logs will be obtained from logging-while-drilling tools positioned in the drilling bottom hole assembly. Annular Injection The surface casing by intermediate/production casing annulus on Sag River wells will be available for annular injection when approved by the AOGCC in Form 10-401 Permit to Drill. Casing and Cementing The Sag River Pool casing and cementing requirements are generally consistent with AOGCC Regulation 20 ACC 25.030, requiring that casing and cementing programs meet the following criteria: 1) Provide adequate protection of all fresh water zones. 2 Prevent fluid mi ration between strata. g 3) Provide protection from pressures and forces that may be encountered, including pressure and forces due to thaw subsidence and freezeback within the permafrost interval. Surface casing will either be shallow set or deep set. Shallow set surface casing will be defined as surface casing set above the Schrader Bluff Sands. Deep Set surface casing will be defined as casing set below the Schrader Bluff Sands. Maximum surface casing setting depth is to be based on sound engineering principles and approved by the AOGCC in the Permit To Drill. Conductor casing is set. at ~Q° t~r`provide anchorage and support for the rig diverter assembly. Surface casing cement volume will be determined in order to fill any rathole below the surface casing shoe as well as the entire annular volume from the casing shoe to surface. Excess volumes will be determined based on historical data which have • enabled cement to reach surface. CONFIDENTIAL -18- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Intermediate and/or production casing strings will be cemented with a volume of cement such that the top of cement is a minimum of 500 feet measured depth above any hydrocarbon bearing zone plus a minimum of 30% excess. It is proposed that the Sag River casing and cementing rules be written as specified in 20 ACC 25.030 and in accordance with the current Kuparuk River Field rules as follows: 1) For proper anchorage and to divert an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface and cement will be pumped to fill the annulus behind the casing to surface. 2) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze-back, a string of surface casing will be set at least 500 feet measured depth (MD) below the base of the permafrost section. 3) To prevent well failure due to permafrost action, the operator shall install surface casing including connections, with sufficient strength and flexibility to prevent • failure. To be approved for use as surface casing, the Commission shall evidence that the proposed casing and connections meet the above requirement. Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze-back, based on sound engineering principles, may be approved by the Commission upon application. 4) It is proposed that the Commission approve a ruling allowing the following alternative completion methods: a) liners, to include but not limited to slotted, pre-drilled, pre-packed, and sintered liners, or combination thereof, landed inside of cased hole and which may be frac/gravel packed. b) open hole completions provided that the casing is set not more than 50 feet above the uppermost oil bearing zone. Open hole completions may subsequently be completed with liners, to include but not limited to slotted, pre- drilled, pre-packed, and sintered liners, or combination thereof, and may be frac/gravel packed. c) horizontal completion with liners, to include but not limited to slotted, pre- • drilled, pre-packed, and sintered liners, or combination thereof, landed inside the horizontal extension and which may be frac/gravel packed. CONFIDENTIAL -19- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • d) multi-lateral type completions in which more than one wellbore penetration in the Sag River Pool is completed in a single well, with production gathered and routed back to a central wellbore. e) deepening or sidetracking existing wellbores to the Sag River reservoir. f) injection into the Schrader Bluff, Kuparuk, and/or Sag River formation using a common wellbore and using packers and downhole flow control devices to regulate flow into each reservoir interval. The Commission may approve other completion methods upon application and presentation of data which shows the alternatives are based on sound engineering principles. Drilling Fluids A spud mud will be used to drill the surface hole. A low solids non-dispersed mud system will be used to drill the reservoir interval. Tubing./Casing Annulus Mechanical Integrity Since the Sag River injection wells will have an annulus with packer as part of their design, BPX will have the capability to pressure test the tubing /casing annulus to periodically check and verify the well's mechanical integrity. The Sag River production wells however, will have an electric submersible pump (ESP) suspended at the end of the tubing string with no packer present in the well as is current practice in the MPU ESP wells completed in the Kuparuk and Schrader Bluff pools. This prevents testing of the tubing-casing annulus to verify mechanical integrity as there will be open perforations in the reservoir interval. However, prior to perforating operations, the casing will be pressure tested to verify casing mechanical integrity. Wellhead and Production Tree Design The Sag River production and injection trees are designed for the operating conditions expected at Sag River. The injection wells will also be equipped with check valves which allow injection down the well, but block the well from flowing back at surface. • CONFIDENTIAL -20- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Producers and injectors will be equipped with automatic pilot-operated surface safety valves which can be actuated from a remote position. Wellheads and treeswill employ appropriate seal technology to minimize leaks and associated spills. Well Design and Completions Production wells will be designed to commingle production of all Sag River member sands. We anticipate profile modification and control of thief zones will be primarily managed by controlling fluid injection in offset injection wells. Sag River production wells with an ESP and which do not require SSSV may be completed without a packer assembly as allowed by AOGCC Conservation Order Number 390. Artificial lift will be required in Sag River producers. Initial completions will utilize electric submersible pumps or gas lift. Over time, the life cycle performance of these lift systems will be compared to alternative artificial lift methods. Artificial lift techniques may be modified if economics warrant. ESP changeouts Electric submersible pumps have a finite life and require replacement when the unit has failed. Normal ESP changeout operations entail pulling the failed ESP, re-running tubing and a new ESP, and putting the well back on production. In the past two years, there have been approximately 120 rig operations at MPU where a significant portion of these rig workovers were to replace failed ESP's. ESP changeouts have taken as little as 44 hours from rig acceptance to rig release. We recommend that since the orily modification to the wellbore is the replacement of the artificial lift unit (ESP), that Forms 10-403 and 10-404 not be required for routine ESP changeouts. Subsurface Safety Valves The Sag River development area is largely coincident with the Kuparuk reservoir development and will rely on the same operating infrastructure. Consistent with statewide AOGCC regulations (20 AAC 25.265) and standard practices at MPU, sub- surface safety valves (SSSV's) will not be used in the Sag River development. n ~J CONFIDENTIAL -21- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Surface Safety Valves Sag River wellheads will be specifically designed to accommodate the ESP systems required to lift the Sag River fluids. Surface safety valves (SSV's) are included in wellhead equipment designs in a "wing" valve position. These devices will be activated by high and low pressure sensing equipment and are designed to isolate well fluids upstream of the SSV should pressure limits be exceeded. Where ESP's are employed, the sensing devices will de-energize the ESP concurrent with closing the SSV. Because periodic testing of the SSV will require pump shutdowns which are considered detrimental to ESP life span, we recommend testing the SSV's annually by reducing the speed of the ESP prior to the SSV test. Stimulation Methods Fracture stimulations of the low permeability Sag River formation will be required to achieve commercial flow rates in this reservoir. Horizontal wells can also be used to increase the productivity of the reservoir. Selection of the appropriate completion will • be based on commercial and reservoir description considerations. RESERVOIR SURVEILLANCE PROGRAM As a result of the low density of wells currently completed in the Sag River, there are still many unknowns related to the flow characteristics and areal continuity across the reservoir. These issues can only be resolved through actual well development. Thus a reservoir surveillance program will assist in the development of the Sag River. Reservoir Pressure Measurements Pressures will be reported at a common datum of 8,750 feet TVDss. Initial static pressure surveys are proposed in each production and injection well upon completion. On an annual basis, a minimum of one pressure measurement per lease (or four- section area) across the field is recommended. Allowable pressure survey techniques should include wireline RFT measurements, pressure buildups with bottomhole pressure measurement, ESP pressure measurements, injector surface pressure falloffs and static bottom hole pressure surveys following extended shut in periods. Pressure survey data would be reported to AOGCC monthly. • CONFIDENTIAL -22- • ~ Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Surveillance Logs We anticipate that artificial lift equipment will preclude the use of surveillance logging techniques in producing wells. Surveillance logging will be used to monitor injector profile distributions. We propose that a minimum of one injection survey or injection zone split determination be conducted per year, per lease or four section area. Surveillance log data would be submitted quarterly. Production Allocations and Well Testing The existing well testing equipment at Milne Point Unit will be utilized to determine production rates from the Sag River formation. Production will be commingled at surface and wells tested at least twice a month utilizing a well test methodology approved by the AOGCC . We recommend that optimum test duration at stabilized rates be determined by the Unit Operator in accordance with industry standard practices on a well by well basis. Production allocation methods currently in place for the Kuparuk and Schrader Bluff formations will also be utilized for the Sag River reservoir. A single production i allocation factor based on a comparison of theoretical production with LACT metered production volumes will be applied equally to the Kuparuk, Schrader Bluff, and Sag River formation production. Production data will be submitted monthly. Production Anomalies In the event of production proration at or from Milne Point facilities, all commingled reservoirs processed through Milne Point facilities will be produced to minimize adverse affects to surface or subsurface equipment. C~ CONFIDENTIAL -23- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 VII. Proposed Sag River Field Pool Rules This concludes our technical presentation. Please ask any questions pertaining to the previous discussion. For your convenience and consideration, we propose the following pool rules be adopted for the Sag River pool. The rules hereinafter set forth apply to the following described area of the proposed Sag River pool (Exhibit 2): Umiat Meridian T12N, R11 E Sections 2, 3, 11 T13N, R11 E Sections 18, 19, 29, 30, 32 T13N, R10E Sections 2, 3, 4, 5, 6, 9, 10, 11, 12, 13, 14, 15, 22, 23, 24, 25, 36 • T14N, R10E Sections 29, 30, 31, 32, 34, 35 T14N, R9E Sections 25, 36 Rule 1. Field and Pool Name The field is the Milne Point Field and the pool is the Sag River Oil Pool. Rule 2. Poo! Definition The Sag River Oil Pool is defined as the accumulations of oil and gas in the Sag River formation which occur in the stratigraphic positions which correlate with the MPA-01 type log from 8810 to 8884 feet measured depth (Exhibit 1). Rule 3. Well Spacing Nominal 40 acre drilling units are established for the pool within the affected area. Each drilling unit shall conform to ahalf-half-quarter governmental section as projected. The pool shall not be opened in any well closer than 500 feet to the exterior boundary • of the affected area without a spacing exception or Pool area modification. CONFIDENTIAL -24- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Rule 4. Casing and Cementing The Sag River casing and cementing rules are written as specified in 20 ACC 25.030 and in accordance with the current Milne Point Field rules as follows: 1) For proper anchorage and to divert an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface and cement will be pumped to fill the annulus behind the casing to surface. 2) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze-back, a string of surface casing will be set at least 500 feet MD (measured depth) below the base of the permafrost section. Cement shall be pumped to fill the annulus behind the casing to surface. 3) To prevent well failure due to permafrost action, the operator shall install surface casing including connections, with sufficient strength and flexibility to prevent failure. To be approved for use as surface casing, the Commission shall evidence that the proposed casing and connections meet the above requirement. Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze-back, based on sound engineering principles, may be approved by the Commission upon application. Rule 5. Completion Practices The following alternative completion methods are allowed: a) liners, to include but not limited to slotted, pre-drilled, pre-packed, and sintered liners, or combination thereof, landed inside of cased hole and which may be frac/gravel packed. b) open hole completions provided that the casing is set not more than 50 feet above the uppermost oil bearing zone. Open hole completions may subsequently be completed with liners, to include but not limited to slotted, pre- drilled, pre-packed, and sintered liners, or combination thereof, and may be frac/gravel packed. CONFIDENTIAL -25- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 c) horizontal completion with liners, to include but not limited to slotted, pre- . drilled, pre-packed, and sintered liners, or combination thereof, landed inside the horizontal extension and which may be frac/gravel packed. d) multi-lateral type completions in which more than one wellbore penetration in the Sag River Pool is completed in a single well, with production gathered and routed back to a central wellbore. e) deepening or sidetracking existing wellbores to the Sag River reservoir. f) injection into the Schrader Bluff, Kuparuk, and/or Sag River formation using a common wellbore and installing packers and downhole flow control devices to regulate flow into each interval. The Commission may approve other completion methods upon application and presentation of data which shows the alternatives are based on sound engineering principles. • Rule 6. Automatic Shut in Equipment All wells which are producing hydrocarbons must be equipped with afail-safe automatic surface safety valve shut-in system able to simultaneously shut in the wellhead and shut in the artificial lift equipment if present. The SSV will be tested annually. Rule 7. Common Facilities and Surface Commingling a. Production from the Sag River Oil Pool may be commingled on the surface with production from the Kuparuk River Oil Pool and the Schrader Bluff Oil Pool, Milne Point Unit, prior to custody transfer. b. Each producing well shall be tested at least twice a month utilizing a well test methodology approved by the AOGCC. Optimum test duration at stabilized rates will be determined in accordance with standard industry practices by the Unit Operator on a well by well basis. The Unit Operator will use its best efforts to obtain valid well tests at uniform time intervals. c. The Commission may require more frequent or longer well tests if the summation of the calculated monthly production volume for all pools is not within 10% of the actual LACT metered volume. CONFIDENTIAL -26- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Rule 8. Production Anomalies In the event of production proration at or from Milne Point facilities, all commingled reservoirs processed through Milne Point facilities will be produced to minimize adverse affects to surface or subsurface equipment. Rule 9. Reservoir Pressure Monitorincl a. Prior to regular production a pressure survey shall be taken on each well to determine reservoir pressure. b. A minimum of one bottomhole pressure survey per lease or four section area 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 8,750 feet subsea. d. Pressure survey means a static bottomhole pressure survey, pressure buildup • test, multiple flow rate test, repeat formation tester, drill stem test, pressure fall- off test, ESP pressure measurement, or bottom hole pressures calculated from well head pressure in an injector. e. Data from pressure surveys required in this rule shall be filed with the Commission monthly. Commission from 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 made available to the Commission upon request. f. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted in accordance with part (e) of this rule. Rule 10. Filing Form 10-403 and 10-404 Exemption ESP producing wells are exempt from filing AOGCC forms 10-403 and 10-404 during a ESP changeout unless the casing is altered or the well is stimulated. Rule 11. Gas-Oil Ratio Exemption • Wells producing from the Sag River Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). CONFIDENTIAL -27- • l~ Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 • Rule 12. Administrative Relief Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Commission that the changes do not promote waste, jeopardize correlative rights, and are based on sound engineering principles. • • CONFIDENTIAL -2s- ~ • • • • Milne Point Unit Sag. River Pool Rules Testimony February 25, 1998 VIII. List of Exhibits Exhibit 1: MPA-01 Sag River Type Log Exhibit 2: Top Sag River Structure Map -Areal extent of Sag River Pool Exhibit 3: Sag River Net Pay Map Exhibit 4: Sag River Permeability * Thickness Map Exhibit 5: Full Field Model Area and Grid Configuration Exhibit 6: Proposed Development Plan Map in Full Field Model IX. References Barnes, David A., 1987, Reservoir quality in the Sag River formation, Prudhoe Bay field, Alaska: depositional environment and diagenesis IN Alaskan North Slope Geology Vol. 1, Ed. By Irv Tailleur and Paul Weimer, publ. by Pacific Section, Society of Economic Paleontologists and Mineralogists and the Alaska Geological Society. Gardner, Michael H., 1987, Sag River formation stratigraphic relationships and reservoir characterization, Prudhoe Bay region, ARCO internal report. North Slope stratigraphic Committee, 1971, West to east stratigraphic correlation section, Point Barrow-Ignek Valley, North Slope, Alaska: North Slope stratigraphic Committee, Anchorage, Alaska. CONFIDENTIAL -29- • ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING SAG RIVER-MILNE POINT UNIT Pool Rules February 25,1998 9:00 AM SIGN IN PLEASE NAME -COMPANY PHONE DO YOU PLAN TO TESTIFY? (PLEASE PRINT) YES NO ~~~~€~ Qwz~ ne 57~~ 4~~0 ~/ $©b 1~un+er .1~~' Shy-ys s3 / l~ev~~,~,x /~~z Z~S~~~34 rr~ `I rsn .564 - ~l6 ~'~ ~-, ._.__-. ~Y~s~f-~, Nelstr,-, PiY/-~ a.~8.36 as ~ r~s -or6~---Tc~ov~ ~L~~-~ o ~~ 3` y~ C 3 ~ - 07 ~ OXY `~ Edward J. Belun, Jr. _ Asset Team Leader Heavy Oi! Team - Western Region OXY USA Inc. P.O. Box 50250, Midland, TX 79710-0250 Phone (915)685-5673 Fax: (91 S) 685-5931 E:Mail Ed Behm 0 .COm - ~-- Xy._.__.._ September 10, 1997 Alaska Oil. and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Attention: Mr. Dave Johnston, Chairman Reference: Milne Point Unit -Sag River Pool Dear Chairman Johnston: Sincerely ~~ OXY USA Inc., with its partner and operator BP Exploration (Alaska) tnc. has worked to fully develop the Milne Point Unit. OXY USA Inc. is in full support of the Sag River Pool rules proposal as submitted by BP Ea~ploration. Please accept this letter as full support of the effort by BP Exploration to define the Sag River Pool and establish parameters for development. We look forward to your support of the requested Pool Rules by BP Exploration and the development of the Sag River Reservoir w~fllin flee Milne Point Unit. If OXY can be of any assistance, please do not hesitate to call me at (915) 685-5646. EJB:MDG/esm xc: Mr: Randy Burnett Ed Behm (by Michael D. Gooding) Asset Team Leader Heavy Oil Team Western Region DECEIVED Alaska Oi{ ~, ~~~ ~~'~,,.~. ~,c,i>~:~~it~siolt R;~ilturagis l An Occidental Oil and Gas company boy ~c~`3 BP EXPLORATfON December 5, 1997 David Johnston Commissioner Alaska Oil and Gas Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Johnston, ~~- BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Attached is BP Exploration's Pool Rules testimony for the proposed Sag River Pool in the Milne Point Unit area. Please review this testimony and the related exhibits in preparation for the Sag River Pool Rules testimony with the commission. Please let us know if we can further clarify any sections of this testimony. We look forward to scheduling a time fot the testimony with the commission. Thank you for your time and yo r staff's suggestions for improving this testimony. ~~.. Bruce Policky Exploitation Manager, Western North Slope ~~~ 'A1aslt~ Did & Gas Cans. Cc~m~missian Ant;trnr~~e ~3 February 24, 1998 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: Milne Point Unit 1998 Plan of Develo meet Dear Sirs: ~~~~ ~~ n ~ ~ ,~;.~ P ~~ ~"~ i ~ Enclosed for your files is-the Milne Point Unit Review of the 1997 Plan of Exploration, Development and Operations, and the Milne Point Unit 1998 Plan of Exploration, Development and Operations that were filed with and approved4by the Department of Natural Resources. Pursuant to AOGCC regulation 20 AAC 25.517(a), we are filing this-with the Commission for informational purposes. Should you or your staff have any questions, please contact me at 564-5472. Sincerely, ~. ~.' -~- Thomas E. Niswander~ MPU Commercial Manager cc: Marcia Davis, BPXA Gary Benson, BPXA Mike Gooding, OXY • • Milne Point Unit Review of 16'h Plan of Exploration, Development and Operations for Calendar Year 1997 Year to date production has averaged 51.6 MBOPD. Later this year the 40t'' and last well in the original Northwest Milne project (F-Pad) and the first well of the new 20 slot F-Pad expansion will be drilled. The final wells of the original Cascade project (K-Pad) were drilled this year and local source water injection at K-Pad will begin in October. Three wells have been drilled from F and L pad into the northeastern portion of ADL388235 (lease acquired from ARCO in 1996), this area will be included in the 10th Milne Point PA expansion. An additional Sag River well was drilled at K-pad to further evaluate Sag River development potential. Minor modifications to increase Central Processing Facility capacity from 65 to 75 mbd will be complete by year end. Work, by a joint BP and Contractor conceptual design team, continues to mature a sanction case for Schrader Bluff development consisting of R&D, field testing and conceptual engineering. Sixteen wells will be drilled to the Schrader Bluff this year to evaluate potential well completion designs. A new 3D seismic data set covering north Milne was acquired earlier this year and a second survey extending the 3D coverage further to the north may be shot in September. Work is underway on the 10th Milne Point Kuparuk and Schrader Bluff PA expansion and the Sag River Pool Rules, Area Injection Order and PA. To date in 1997, the following drilling has occurred: Kuparuk Reservoir: K Pad: MPK-06, MPK-18Ai, MPK-21i and MPK-43Ai F Pad: MPF-54, MPF-49i, MPF-42i, MPF-73, MPF-57, MPF-65, MPF-50, MPF-05, MPF-26i, MPF-41i and MPF-09 G Pad: MPG-12 E Pad: MPE-19, MPE-18 and MPE-14 L Pad: MPL-32, MPL-34i, MPL-35, MPL-33i, MPL-39, MPL-20 (suspended) and MPL-36 (in progress) Sag River Reservoir: K Pad: MPK-33 Schrader Bluff Reservoir: G Pad: MPG-09i, MPG-11, MPG-13i, MPG-15 and MPG-10 H Pad: MPH-14, MPH-10, MPH-11i, MPH-09 and MPH-12 (in progress) For the remainder of 1997 and contingent on drilling results, more drilling is planned at the following pads: F, H, J, E and C pads for Kuparuk development drilling. H, I and J pads for Schrader Bluff development drilling. September 30, 1997 • Milne Point Unit 17~h Plan of Exploration, Development and Operations for Calendar Year 1998 Drilling activities currently planned, but not yet sanctioned, for 1998 include the further development of Northwest Milne Kuparuk reservoir from the new 20 slot F-Pad expansion, the appraisal and development of a number of smaller Kuparuk fault blocks in the southern and southwestern areas of the field and 8 Schrader Bluff wells. Lessons learned from the 1997 and 1998 Schrader Bluff drilling programs will be incorporated into our evaluation during 1998 of the next phases of Schrader Bluff development. The four existing Sag River test wells will be monitored to assess Sag River development potential and additional wells are planned to test a Sag River injection strategy. Normal workover operations will continue and reservoir, waterflood and IWAG performance will continue to be optimized. FOR studies will be progressed in 1998 to support possible future sanctions of FOR projects in both the Kuparuk and Schrader Bluff resen~oirs. Options for gas debottlenecking of the CFP are currently being evaluated for possible sanction in 1998. Conceptual engineering for a possible expansion of CFP capacity from 75 to 100 mbd is progressing and will be completed in 1998. Expansion of MPU facilities beyond its current nominal 75 mbd capacity is contingent on having an economically attractive and sanctioned major expansion of the Schrader Bluff development. An approximate 2 rig year program (34 wells) is planned for the Kuparuk, Schrader Bluff and Sag River reservoirs in 1998. Development is planned on F, L, C, E, G, H, and J pads. There are also two Schrader Bluff appraisal wells planned for next year, which will possibly be drilled off the Prudhoe Texaco #1 exploration gravel pad. Plans include drilling several horizontal producers and injectors and several extended reach wells with departures greater than 19,000 feet. The decision to drill the wells in next years program will be contingent upon economic viability, product prices and the ability to compete for capital funds. Any wells drilled outside the currently defined MPU PA boundaries are planned for immediate hook up and production or injection as Tract or Lease Operations until such time as PA creation or expansions are approved. Long Range Plans The Milne Point Unit will continue to be explcred, appraised. and developed. Reservoirs. will continue to be managed in ways which will ensure the maximum economic development of the resource. Information from reservoir surveillance, geologic data and drilling technology along with economic viability will continue to determine the pace and direction of development for Milne Point's reservoirs. t f MILNE POINT UNIT TESTIMONY FOR SAG RIVER POOL RULES February, 1998 Pte.: ~~'(g ~Z ~~ ~e ~- • • TABLE OF CONTENTS I. INTRODUCTION II. GEOLOGY AND RESERVOIR DESCRIPTION III. RESERVOIR OIL-IN-PLACE AND FLUIDS tV. RESERVOIR DEVELOPMENT V. FACILITIES VI. WELL DRILLING AND COMPLETION OPERATIONS VII. PROPOSED SAG RIVER POOL RULES VIII. LIST OF EXHIBITS XI. REFERENCES Page 1 2 7 8 15 17 24 29 29 • Milne Point Unit Sag River Pool. Rules Testimony February 25, 1998 I. Introduction My name is Marcia Davis. I am an attorney for BP Exploration (Alaska) Inc., the operator of the Milne Point Unit. BP is presenting testimony today on behalf of itself, as a working interest owner and unit operator, and OXY USA, Inc., the other working interest owner in the Milne Point Unit. This hearing has been scheduled in accordance with 20 AAC 25.520 and 20 AAC 25.540 in order to consider evidence relevant to the establishment of pool rules for the Milne Point Unit Sag River resources. This testimony includes operating and technical data concerning the currently understood geological and reservoir properties as well as proposed plans and timing for reservoir development. This testimony will enable the Commission to establish rules allowing economical development of Sag River resources which will prevent waste, protect freshwater and protect correlative rights. Testimony is divided into four primary disciplines: geology, reservoir, facilities engineering and drilling and completions engineering. Robert Hunter will present testimony related to the geology of the Sag River, Peter Burke will present the reservoir testimony, Peter Richards will present the surface facilities testimony, and James Robertson and Bill Hilly will present the drilling and completions testimony. Each of these witnesses will state his education and experience which we believe qualify him as an expert. Each of the witnesses is prepared to respond to questions concerning the testimony and related exhibits. Some of the materials to be presented today are confidential, and we request that such information be kept confidential pursuant to AS 31.05.035(d) and 20 AAC 25.537. We will identify which sections of the testimony we consider confidential at the time it is to be presented request that the public be excluded from this portion of the hearing. Our witnesses will be presenting sworn testimony and wish to be qualified as experts. L -1- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 II. Geology and Reservoir Description Introductions My name is Robert Hunter. I am a senior geologist working satellite development opportunities in the Western North Slope department of BP Exploration (Alaska). I received a Bachelor of Arts degree in geology from the University of Montana in 1984 and a Master of Science degree in geology from the University of Wyoming in 1986. I have been with BP and its affiliates for the past 12 years. I have worked the subsurface of the North Slope over the past nine years in Prudhoe, Lisburne, Pt McIntyre, Niakuk, Kuparuk, and Milne Point developments. My testimony provides geologic justification to the Commission supporting BP's proposed Sag River Pool limits. My name is Peter Burke. I am the reservoir engineer for Sag River development. I studied petroleum reservoir engineering to Master's level at London (UK) University and have over 25 -years industry experience with BP Exploration and Amoco. I started work on the Sag River development in March of 1997 and have directed the reservoir performance simulation work conducted by an external consultant. General Overview The proposed Sag River Pool area is located in the Milne Point Unit area near the coastline of Simpson Lagoon on the Western North Slope. This Sag River Pool would include the stratigraphic interval defined by the MPA-01 type log from 8810 to 8884 feet measured depth (Exhibit 1) within the mapped area of the oil accumulation (Exhibit 2). Exhibit 2 also illustrates the Milne Point Unit location and outline and the area of t_he proposed Sag River pool rules. Working interests in each of the leases are held uniformly by BP at 91.19% and OXY USA Inc. at 8.81 %. Chevron discovered oil in the Sag River formation in this area in the Kavearak Point 32-25 well in 1969. This discovery was confirmed by Conoco in their MPA-01 well in 1980. BP acquired working interest in the Milne Point Unit leases from Conoco and Chevron and succeeded Conoco as unit operator effective January 1, 1994. In 1995, BP drilled the first dedicated Sag River well (MPE-13) to assess productivity of this relatively poorly developed reservoir. Since that time, BP has drilled three additional widely spaced Sag River appraisal wells: MPC-23 and MPF-33 in 1996, and MPK-33 in 1997. The marginal productivity from these wells dictates caution in the development rae~~ r _2. • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 program. Therefore, BP will proceed with a synergistic development of Sag River with Kuparuk and Schrader Bluff opportunities where possible. Additionally, radically de- scoped well options are being evaluated. In order to economically develop the Sag River Pool, BP will need to demonstrate that certain technical operations are feasible with respect to this pool. First, BP is planning to test a pressure support mechanism by initiating gas injection in a planned sidetrack near the existing Sag River well, MPC-23. If pressure support is demonstrated to be technically and economically feasible, BP will consider implementing additional injection patterns. The ability to utilize 40-acre spacing will enhance the success of such a program. Finally, the economic feasibility of any development is contingent upon the _ Sag River Pools' use of existing infrastructure and the ability to commingle production in the shared facilities. Request Confidential session (AS 31.05.035(d) and 20 AAC 25.537) Stratigraphx The late Triassic to early Jurassic Sag River formation consists primarily of thin marine shelf sand packages deposited throughout the Prudhoe Bay area on the North Slope of Alaska (Barnes, 1987). The North Slope Stratigraphic Committee (1971) designated the Sag River formation as the sandstone interval underlying the Jurassic Kingak shale and overlying the Triassic Shublik formation in the subsurface of the Prudhoe Bay region. The sands are extensively bioturbated which has mixed the originally deposited sands, silts, and muds, forming a relatively poor reservoir quality sandstone. In the proposed pool area, the Sag River formation is divided into four zones named A,-B, C, and D from bottom to top (Exhibit 1). This zonation scheme was originally proposed regionally by Gardner (1987). Each zone boundary likely represents a chronostratigraphic surface and is commonly marked by an increase in bioturbation, shaliness, and phosphorite and glauconite concentrations (Gardner, 1987). The Sag River formation averages 77 feet in thickness in the proposed pool area. The Sag River formation net pay ranges from 9 to 18 feet thick (Exhibit 3). The Sag River formation permeability-thickness ranges from 30 to 68 millidarcy-feet (Exhibit 4). Zone A is the basal Sag River sandstone unit unconformably overlying the Shublik formation (Exhibit 1). Zone A is almost entirely tight, non-reservoir sandstone in the proposed pool area. Porosities develop up to 18% and permeability up to 1.2 millidarcies (md). The average gross thickness of zone A is 16 feet. -3- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Zone B is the primary Sag River reservoir interval in the proposed pool area. Zone B develops porosity up to 21% and permeability up to 23 and as measured from cores taken in the area. The average gross thickness of zone B is 30 feet. Zone C is the uppermost Sag River sandstone in the proposed pool area. Zone C is tight, non-reservoir sandstone. Porosities develop up to 17% and permeability to 2.9 md. The average gross thickness of zone C is 10 feet. Zone D is non-reservoir siltstone and shale at the top of the Sag River formation. A prominent shift in sonic and resistivity logs occurs at the contact between the base Kingak and the top Sag River formation (Exhibit 1). The average gross thickness of zone D is 21 feet. The structure map (Exhibit 2) and velocity field were constructed to conform to the top of zone C since zone D is not a reservoir. Structure Within the proposed pool area, the top Sag River has been mapped using three- dimensional seismic data from the Milne Point and Northwest Eileen seismic surveys. The regional structure on the top of the Sag River is dominated by a number of northwest-southeast trending faults which support three-way anticlinal closures in the footwall of these faults. Additional faults trending north-south and east-west segment and complicate these closures. All fault sets appear to post date deposition of the Sag River interval. Throws range from 20 feet to in excess of 200 feet, with the greater throws associated with the NW-SE trending faults (throwing down to the southwest). The segmentation of the structural closures is supported by oil-water contacts inferred from existing well penetrations, leading to three equilibration regions as discussed below. The Sag River depths in this region range from 8,500 feet to 9,500 feet true vertical depth subsea (TVDss) (Exhibit 2). The depth structure at the top Sag River merges existing Sag River well control with an interpretation of average seismic velocity which accounts for regional thinning of the permafrost interval. Thinning of the permafrost interval leads to a velocity gradient which roughly parallels the present day shoreline and barrier island trends. As development drilling provides additional velocity control this model can be further refined. Trapping Mechanisms The trapping mechanism of the Sag River is predominately structural but may be a combination of structural and stratigraphic. Faults with vertical displacements as low C'~!!''I. -4- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 as 50 feet appear to trap oil and might segment the reservoir into blocks with different oil/water contacts. Controls over Oil Distribution Three regional blocks with separate oil/water contacts (OWC's) have been identified in the proposed pool area (Exhibit 2). Three OWC's are currently recognized; these contacts are: 9150 feet TVDss in the southeast area near MPK-33, 9050 feet TVDss in the central area near MPE-13 and MPC-23, and 8950 feet TVDss in the northwest area near MPF-33. These OWC's are based on mapped structural closure and observed well productivity or well tests. The OWC's, therefore, appear to step up to the northwest. The Shublik formation does not develop into a reservoir in the proposed pool area. Neither the Eileen, Ivishak, or Lisburne formations are known to contain more than residual hydrocarbons within the proposed pool area. The Eileen and Ivishak formations contain high water saturations even where penetrated above the depths of the Sag River OWC's. Three wells penetrate the Eileen and Ivishak above the Sag River OWC's: MPA-01, MPE-13 pilot hole, and MPC-23. Proposed Pool Name and Boundaries The name Sag River Pool is proposed for oil accumulations in the MPA-01 type log from 8810 to 8884 feet measured depth (Exhibit 1) and the mapped area of the oil accumulation (Exhibit 2). This would include Sag River zones A through D which have been correlated throughout the proposed pool area. Reservoir Description This section will summarize the reservoir properties of the Sag River reservoir in the proposed pool area. The formulated description was utilized in the reservoir simulation study, which provided data on the field volumetcics and original oil-in-place and on the recovery processes. In MPU five wells contain either core or rotary sidewall cores in the Sag interval (full core in Kavereak 32-25, MPB-01, MPC-01, and MPL-01, and sidewall cores in Cascade-01). Six additional wells have recorded logs over the interval in the proposed pool area (MP18-01, MPA-01, MPE-13, MPC-23, MPF-33, and MPK-33). -5- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Reservoir Properties Gross Interval Porosity data from the cored wells were used to model porosity in the non-cored wells. Core data was available for the Sag A, B and C zones. The B zone contains the highest quality sands. The core grain densities which are greater in the C and A zones likely indicate more carbonate cementation. Core porosities in the B interval range from 8-21 % with a mean of 16%. Core porosities in the A and C zones range from 2-19°I° with a mean of 12%. Permeabilities from the core data were used to predict permeability in the non-cored wells. The permeabilities range from 0-23 and for the available core data. Zone B arithmetic average permeability was 2.7 and whereas Zone A and C average 0.4 md. A criteria of greater than 1 and permeability (predicted or core) is used to determine net pay for wells above the OWC (Exhibits 3 and 4). The net pay in rock with permeabilities greater than 1 and usually occurs in rock of greater than 15% porosity. Net Pay Interval Average water saturations in the net pay calculated intervals from log analysis range from 45-57%. Zone B average porosity is 18% with an average permeability of 2.8 and in the net pay. Zones A and C average porosities are 16% with average permeabilities of 1.2 and 2.1 md, respectively in the net pay. Core, log and log model derived porosities, permeabilities, net-to-gross and water saturations were input into the reservoir model for zones A, 6 and C. Permeabilities in the reservoir model were adjusted upwards by a constant to match well history. L -6- ~ • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 III. Reservoir Oil-In-Place and Fluids Original Oil-in-Place (OOIP) The estimated OOIP for the Sag River interval in the proposed pool area is 61.7 million stock tank barrels (MMSTBO) as calculated from the recently constructed reservoir model. The northwest area contains 9.7 MMSTBO and is being produced by MPF-33. There are 49.1 MMSTBO in the central area of the pool, which is now being produced by MPE-13 and MPC-23. There are 2.9 MMSTBO in the southeast area, which is being produced by MPK-33. The productive volume in the model is constrained by rock and fluid properties, the net pay thickness of the sand, the oil-water contacts as defined earlier, and by the major sealing faults. The results are as follows: Estimated Area OOIP Region in Model Acres (MMSTBO) Northwest Area 1,300 9.7 Central Area 6,800 49.1 Southeast Area 400 2.9 TOTAL 8,500 61.7 Reservoir Fluids and PVT Properties A fluid property analysis has been performed on a sample from the MPC-23 well. The principal characteristics of the sample are as follows: Average Crude Oil Gravity 39.2 deg API Bubble Point Pressure 3513 psia Solution Gas-Oil Ratio (Separator) 974 scf/stb Oil Formation Volume Factor (Initial Conditions) 1.56 rb/stb Oil Viscosity (Initial Conditions) 0.277 cP Gas Gravity (Separator) 0.8038 (Air=1.0) The measured initial reservoir pressure and temperature were 4425 psia and 235 degrees F at a datum of 8750 feet TVDss. L -7- i Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 IV. Reservoir Development Introduction This portion of the testimony will include a discussion of reservoir performance, development and management of the Sag River Pool. The potential performance of the Sag River reservoir was investigated using athree-dimensional, black oil reservoir model. This model was used to guide the decisions related to the optimum development and reservoir management of the Sag River Pool. Reservoir Uncertainties There are many aspects of the reservoir which are still- unknown including the degree of areal continuity across the reservoir, fracture density and conductivity in the vertical and horizontal directions, anisotropy in the reservoir properties, observed performance under water and/or gas injection, aquifer strength, fault transmissibility and OWC in undrilled fault blocks. Therefore, the development plan requires flexibility to accommodate any required adjustments in the operations due to unexpected reservoir conditions. Although gas injection is the currently preferred development strategy for the field, the actual reservoir parameters may point toward the ultimate recovery scheme being a waterflood or a water alternating gas (WAG) injection plan. Recovery Mechanisms The primary recovery mechanisms for full development of the field are fluid expansion and aquifer pressure support. There is no gas cap as the reservoir was initially 912 psi undersaturated with a pressure of 4425 psia, compared with-the bubble point of 3513 psia. Estimated recovery under primary depletion with normal development is i 5% of the original-oil-in-place (OOIP), rising to 38% with an immiscible gas flood scheme. RESERVOIR MODEL STUDY Model Assumptions The proposed pool area Sag River reservoir, zones A, B and C were modeled using Landmark's VIP simulation program. VIP is athree-dimensional, multi-phase simulator with black oil and compositional options. A black-oil treatment was used for the Sag River Pool study. 'g_ • Milne Point Unit Sag River Pool Rules Testimony February 2S, 1998 A full-field model (FFM) was built to investigate various development plans and recovery processes for the field. The model area including the grid configuration is shown in Exhibit 5. The model cell size is 419 feet by 419 feet for an area of four acres, with seven model layers. Overall dimensions of the grid are 198 cells by 54 cells with seven layers for a total of 74,844 cells. The reservoir description used in the FFM included the seismic structural definition and the layering interpretation described in the Geology and Reservoir Description sections. The Sag A and C layers were represented with one layer each while the thicker B layer reservoir sandstone was subdivided into two layers, each averaging 15 feet in thickness. Average model layer properties for the main Sag interval net pay in Layer _ B, are 18% porosity and 8 millidarcies (md) permeability. The net pay in the Sag A and C layers have average porosities of 16% to 17% and average permeabilities from 1 to 2 md. Three different OWCs are used in the model for the Sag River interval, as described in the Geology section. The Shublik, Eileen, and Ivishak formations are also included in the model. It is believed that the water production in the MPE-13A well is coming from a fault conductive to the Ivishak interval. Both the Eileen and Ivishak have been given porosity, permeability, and high water saturations in the model. The Shublik is treated as anon-porous shale. A six well pattern model was also built for a preliminary sensitivity analysis of well density and injection options. The pattern model used the same layering scheme as the FFM and represented the central area around the MPC-23 well. PVT properties and oil-in-place used in the simulation study were given in the previous Reservoir Oil-In-Place and Fluids section. Relative permeability was based on that developed for the Sag River modeling in Prudhoe Bay Unit. The adjacent aquifer was modeled as a fixed pore volume of columns of cells attached directly to the oil zone below the OWC. The aquifer volume is around seven times that of the oil zone. Model Forecasting Following the initial construction, the FFM was history matched with the four producing wells to help assure valid forecast results. Adjustments were made primarily to the Sag River layer permeability (increased from an average of 2.7 to 8 and in the B zone) and to the fault conductivity near the MPE-13 well. -9- f ~ Milne Point Unit Sag River Pool Rules Testimony February 25, 199$ Following the history match, the FFM was set-up to forecast the future performance of the reservoir under various operational scenarios. In these cases all wells were placed on bottom hole pressure control with a minimum flowing pressure of 1,500 psig for the producers and a maximum bottom hole injection pressure of 5,500 psig (or 0.62 psi/ft). To approximate the enhanced productivity/injectivity from stimulation, all proposed wells were assigned negative skin factors and increased permeability in the model cell containing the well. The forecast cases included gas injection with varying well spacing, waterflooding, and horizontal wellbores. For each case, well locations were selected based on the productive areas, according to the desired well density and pattern configuration. New wells were added to the model in a staged fashion to approximate a probable drilling schedule. Model Results Each of the forecast cases was run to 1 January 2018. In all cases, voidage was approximately replaced (i.e., constant reservoir pressure was maintained) by injecting either make-up gas in addition to the produced gas from the reservoir or sufficient injection water. Initial results indicate that the estimated optimum ratio for producers to injectors (P:I) ratio is between 2:1 and 1.5:1, and this was used in selecting the well locations and service for each forecast. In summary, gas injection gave the best recovery of the options analyzed. Waterflooding does provide a significant improvement in the recovery over primary depletion. Horizontal wells contribute to additional production over conventional vertical well development, however, their application is not universally applicable across field due to reservoir constraints and/or economics. In all cases, down-dip wells benefit from pressure support from Sag River aquifer. FFM recovery results are shown in the following table. L -lo- Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Planned Effective Number Oil Recovery Well Spacing Well Spacing of Wells Production Factor Case acres (acres (Prod/InjlTotal) (MMSTBO) % OOIP Primary 160 15 Waterflood 160 217 27/12/39 18.7 30 Gas Inj 160 217 27/12/39 23.5 38 Gas Inj 200 273 22/9/31 22.0 36 _ Gas Inj 320 338 16/9/25 19.8 32 Gas Inj 200 256 22/11/33 23.4 38 Utilizing Horizontal Wells * Results from using six w ell pattern model. The planned well spacing figure for each case was used to locate wells in the fully developed, up-dip, central area of the model. The effective spacing value was calculated by dividing the estimated productive area above the OWC by the total number of wells. Additional model work is planned with alternative completion techniques and different operating scenarios. As development of the field progresses, the new data received will be used to update the model and, if necessary, revise the development plan for optimum recovery operations. RESERVOIR MANAGEMENT STRATEGIES Producing wells will be completed in the Sag River C, B and A Sand intervals (as shown in attached type log, Exhibit 1) with fracture stimulations. Sources for the injected gas will be produced gas from the Sag River Pool and make-up gas from other sources in the area, including Kuparuk and Schrader Bluff. At a minimum, voidage will be replaced with the reservoir pressure being maintained at or near 4,300 psia. -11- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Since gas injection, with associated gas breakthrough and production, is the recommended method of pressure support, gas-oil ratios at the producer wells will exceed limits set forth in 20 AAC 25.240(b) and an exception to this rule is requested RESERVOIR DEVELOPMENT CONCLUSIONS Based on modeling, immiscible gas injection is indicated to be the preferred recovery process for the Sag River development with recoveries in the 32% to 40% range. Water-alternating-gas (WAG) or simultaneous water and gas injection, using miscible or immiscible gas, are considered possible future recovery mechanisms for the Sag River reservoir along with alternative completion techniques such as horizontal or multi-lateral wellbores. Forty acre spacing is requested in order to allow for flexibility developing the field. The planned spacing is 320 acres per well, but reservoir conditions may require optional well location configurations. Estimated recovery from the field under gas injection is 20 MMSTBO, with the majority of the production coming from the wells in the central area. END CONFIDENTIAL SECTION RESERVOIR PERFORMANCE Appraisal Phase Performance The 1995-1997, four well Sag River appraisal program was valuable in determining well productivities and reservoir characteristics. The performance of the MPE-13 horizontal well has indicated that a fault in the wellbore is conductive and extends below, and possibly above, the producing horizon. The producing area to the southeast is limited due to the oil-water-contact (OWC). The MPC-23 and MPF-33 vertical wells appear to be representative of typical behavior for the field. These wells had initial rates around 1000 bopd (MPF-33) to 2000 bopd (MPC-23) but declined sharply to 200-400 bopd within a year. As of November, 1997, cumulative production from the Sag River Pool is around 785,000 barrels of oil. DEVELOPMENT PLANS The Commission has copies of the Milne Point Unit Review of the 1997 Plan of Exploration, Development and Operations, and the Milne Point Unit 1998 Plan of Exploration, Development and Operations that were filed with and approved by the Department of Natural Resources. These were filed with the Commission for informational purposes pursuant to AOGCC regulation 20 AAC 25.517(a). -#~t~~1~L -12- Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 The plans below outline a full Sag River development should Sag River development become economically viable. These plans show the most efficient development of the Sag River reservoir as demonstrated from the reservoir model. Initial reservoir pressure in the Sag River reservoir is about 900 psi above the bubble point pressure. To date, there have been no reservoir pressure support measures implemented. Therefore, BP is currently planning in 1998 to drill a sidetrack, pre- produce it, and then initiate immiscible gas injection as part of Phase 1 drilling and completion if the project can be demonstrated to be economically viable. . Although only gas injection and waterflooding scenarios have been analyzed to date, water-alternating-gas (WAG) injection using miscible or immiscible gas is considered to be a possible future recovery method for the Sag River reservoir. If further study indicates that this would yield a more favorable recovery and is economically viable, then the development plan would be revised to conform to those results. Horizontal wells and/or multi-laterals will also be considered and, if proved economically viable, implemented in the future. The recommended full development plan at this time contains a total of 25 wells (four existing wells with 20 to 22 additional wells) with 16 producers and nine injectors. Development well spacing will be up to 320 acres, consistent with the model study results. Directionally drilled vertical wells are planned for each phase of development at this time. Future drilling could include the use of less conventional wellbores, such as horizontal or multi-lateral wells. A map with the proposed development plan is shown in Exhibit 6. Proposed injection wells are annotated with an "I" following the well name. Phase 1 - 1998 Current phase 1 development plans for the Sag River reservoir at Milne Point consist of at least one well drilled to offset the MPC-23 well and possibly two to four additional penetrations. These wells may be sidetracks or deepenings of current wells in the central area (Exhibit 2). If surface facility constraints permit, an additional delineation well may be drilled from F-Pad to the northwest. The actual performance of the MPC-23 area wells will direct the future pool development. -13- • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Phases 2 and 3 Two subsequent phases are included in the current development plan. Phase 2 will add 14 additional wells with seven producers and seven injectors. MPF-33 may be converted to injection. Three producers will be added in Phase 3. Again, this schedule is subject to revision as performance from the new wells dictates. Well Spacing Depending on reservoir description and performance, select areas may require well spacing other than 320 acres. This may be determined by faulting, areal changes in permeabilities, or fracture conductivity, which result in different than expected performance. Therefore, a 40 acre well spacing is requested to allow flexibility in placement of wells to maximize recovery from the Sag River oil reservoir. _~q_ Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 V. Facilities Introduction My name is Peter Richards. I am the Development Studies Team Leader for Milne Point Unit responsible for facilities development studies. I received a Bachelor of Engineering degree in Chemical Engineering from Imperial College, London in 1983 and achieved Chartered Engineer status in 1990. I have worked for BP Exploration for 14 years in Development, Project and Operational roles in the UK, Norway, Colombia and now Alaska. General Overview The Sag River reservoir underlies the Kuparuk reservoir and Schrader Bluff reservoir within the Milne Point Unit (MPU). Sag River fluids will be commingled with Kuparuk and Schrader Bluff fluids at the pads and produced into the MPU facilities. Economical development is contingent upon utilization of the MPU infrastructure and facilities which will also minimize environmental impacts. Pads and Roads The MPU pads and road system will be used to support Sag River drilling, construction, and operations. Pipelines Sag River pipeline needs are for multiphase production. High pressure gas injection lines may be needed for Sag River gas injection if gas injection becomes a viable enhanced reservoir recovery process. Sag River development will use MPU pipelines. Power Lines Sag River development will utilize MPU power lines and on pad electrical equipment. Production wells that will use Electrical Submersible Pumps (ESP's) for lift will require on pad transformers and drives which will be accommodated through minor expansion of on pad facilities. -ls- • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Facilities The base assumption for Sag River facility development is daily operation which requires minimal regular operator presence in line with present operating practice. All data gathering and routine operations are to be accomplished remotely from the CPF and/or any pad control room. Routine operations are defined as: 1. Well testing using existing pad well testing facilities 2. Well test divert valuing 3. Emergency shutdown 4. Production control (ESP control) 5. Injection gas flow metering (possible future operation) 6. Production pressure metering Manual operations are defined as: 1. Well bore freeze protection 2. Chemical injection 3. Injection choke valve actuation Well control and testing functions are performed remotely using the control system. Well production rate is generally controlled using variable speed drive (VSD) controls for the wells with down hole ESP's or gas lift injection rates for gas lift wells. Testing takes place by a simple divert valve system redirecting the flow from the production header to the test header and is controlled remotely. Emergency Shutdown Emergency shutdown systems meet API-RP 14C requirements and BPX specifications for safety systems. All production, test, and injection piping on-site will be designed to be able to contain well head shut-in pressure up to the emergency shut down (ESD) valves. Production wells can be shut down due to over or under pressure with pressure switches. Additionally, these wells can be shut off remotely through the control system. Injection wells flow reversal, due to a surface system leak or depressurizing, is stopped by the use of a low pressure switch, ESD valve and check valve at the well. Additionally, these wells can be shut off remotely through the control system. -16- ~ ~ Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 VI. Well Operations Introduction My name is Bill Hill. I am the Lead Production Engineer for BP's Western North Slope Asset. I received a Bachelor of Science in Petroleum Engineering from the Royal School of Mines, Imperial College, London University in June 1984. I have been employed by BP Exploration since August 1984 as a Production Engineer and have worked in the UK Sector and in Alaska. My core skills are Production Engineering and Completion Engineering both of which have been developed in an office and 'field' environment. My name is James Robertson. I began working on drilling rigs in 1977. Between 1977 and 1982 1 worked on drilling rigs as a roustabout, roughneck, motorman, or derrickman. During that time frame I worked on rigs in the Gulf of Mexico, onshore Texas, Idaho, Wyoming, Utah, Alaska's Cook Inlet and Alaska's North Slope. In 1982 began pursuing a degree in Petroleum Engineering. In 1988 I graduated from the University of Alaska, Fairbanks with a B. S. Petroleum Engineering. In 1988 I was hired by ARCO Alaska Inca as a Drilling Engineer. Since 1988 I have worked as a workover and completions engineer, drilling engineer or Company Representative for either ARCO or BP's Shared Services Drilling. I have worked in the Prudhoe Bay, Kuparuk, Milne Point, and Point McIntyre fields over the past 10 years. General Overview This portion of the testimony will include a description of Sag River well designs, completion designs and a reservoir surveillance plan. The drilling section will include a brief description of our drilling, casing, and cementing programs for the Sag River Pool. This will be followed by a discussion of typical completion designs, safety systems and reservoir surveillance plans. Directional Drilling Directional surveys will be by MWD or gyro. -1~- • w Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Logging Operations The initial development logging suite planned for Sag River reservoir interval includes resistivity and gamma ray logs. These logs will be obtained from logging-while-drilling tools positioned in the drilling bottom hole assembly. Annular Injection The surface casing by intermediate/production casing annulus on Sag River wells will be available for annular injection when approved by the AOGCC in Form 10-401 Permit to Drill. Casing and Cementing The Sag River Pool casing and cementing requirements are generally consistent with AOGCC Regulation 20 ACC 25.030, requiring that casing and cementing programs meet the following criteria: 1) Provide adequate protection of all fresh water zones. 2) Prevent fluid migration between strata. 3) Provide protection from pressures and forces that may be encountered, including pressure and forces due to thaw subsidence and freezeback within the permafrost interval. Surface casing will either be shallow set or deep set. Shallow set surface casing will be defined as surface casing set above the Schrader Bluff Sands. Deep Set surface casing will be defined as casing set below the Schrader Bluff Sands. Maximum surface casing setting depth is to be based on sound engineering principles and approved by the AOGCC in the Permit To Drill. Conductor casing is set at 80 feet to provide anchorage and support for the rig diverter assembly. Surface casing cement volume will be determined in order to fill any rathole below the surface casing shoe as well as the entire annular volume from the casing shoe to surface. Excess volumes will be determined based on historical data which have enabled cement to reach surface. -18- s ~ Milne Poin[ Uni[ Sag River Pool Rules Testimony February 25, 1998 Intermediate and/or production casing strings will be cemented with a volume of cement such that the top of cement is a minimum of 500 feet measured depth above any hydrocarbon bearing zone plus a minimum of 30% excess. It is proposed that the Sag River casing and cementing rules be written as specified in 20 ACC 25.030 and in accordance with the current Kuparuk River Field rules as follows: 1) For proper anchorage and to divert an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface and cement will be pumped to fill the annulus behind the casing to surface. 2) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze-back, a string of surface casing will be set at least 500 feet measured depth (MD) below the base of the permafrost section. 3) To prevent well failure due to permafrost action, the operator shall install surface casing including connections, with sufficient strength and flexibility to prevent failure. To be approved for use as surface casing, the Commission shall evidence that the proposed casing and connections meet the above requirement. Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze-back, based on sound engineering principles, may be approved by the Commission upon application. 4) It is proposed that the Commission approve a ruling allowing the following alternative completion methods: a) liners, to include but not limited to slotted, pre-drilled, pre-packed, and sintered liners, or combination thereof, landed inside of cased hole and which may be frac/gravel packed. b) open hole completions provided that the casing is set not more than 50 feet above the uppermost oil bearing zone. Open hole completions may subsequently be completed with liners, to include but not limited to slotted, pre- drilled, pre-packed, and sintered liners, or combination thereof, and may be frac/gravel packed. c) horizontal completion with liners, to include but not limited to slotted, pre- drilled, pre-packed, and sintered liners, or combination thereof, landed inside the horizontal extension and which may be frac/gravel packed. -~i~~L -19- ~ ~ Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 d) multi-lateral type completions in which more than one wellbore penetration in the Sag River Pool is completed in a single well, with production gathered and routed back to a central wellbore. e) deepening or sidetracking existing wellbores to the Sag River reservoir. f) injection into the Schrader Bluff, Kuparuk, and/or Sag River formation using a common wellbore and using packers and downhole flow control devices to regulate flow into each reservoir interval. The Commission may approve other completion methods upon application and presentation of data which shows the alternatives are based on sound engineering principles. Drilling Fluids A spud mud will be used to drill the surface hole. A low solids non-dispersed mud system will be used to drill the reservoir interval. Tubing /Casing Annulus Mechanical Integrity Since the Sag River injection wells will have an annulus with packer as part of their design, BPX will have the capability to pressure test the tubing /casing annulus to periodically check and verify the we11's mechanical integrity. The Sag River production wells however, will have an electric submersible pump -(ESP) suspended at the end of the tubing string with no packer present in the well as is current practice in the MPU ESP wells completed in the Kuparuk and Schrader Bluff pools. This prevents testing of the tubing-casing annulus to verify mechanical integrity as there will be open perforations in the reservoir interval. However, prior to perforating operations, the casing will be pressure tested to verify casing mechanical integrity. Wellhead and Production Tree Design The Sag River production and injection trees are designed for the operating conditions expected at Sag River. The injection wells will also be equipped with check valves which allow injection down the well, but block the well from flowing back at surface. E~4L -20- Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Producers and injectors will be equipped with automatic pilot-operated surface safety valves which can be actuated from a remote position. Wellheads and trees will employ appropriate seal technology to minimize leaks and associated spills. Well Design and Completions Production wells will be designed to commingle production of all Sag River member sands. We anticipate profile modification and control of thief zones will be primarily managed by controlling fluid injection in offset injection wells. Sag River production wells with an ESP and which do not require SSSV may be completed without a packer assembly as allowed by AOGCC Conservation Order Number 390. Artificial lift will be required in Sag River producers. Initial completions will utilize electric submersible pumps or gas lift. Over time, the life cycle performance of these lift systems will be compared to alternative artificial lift methods. Artificial lift techniques may be modified if economics warrant. ESP Changeouts Electric submersible pumps have a finite life and require replacement when the unit has failed. Normal ESP changeout operations entail pulling the failed ESP, re-running tubing and a new ESP, and putting the well back on production. In the past two years, there have been approximately 120 rig operations at MPU where a significant portion of these rig workovers were to replace failed ESP's. ESP changeouts have taken as little as 44 hours from rig acceptance to rig release. We recommend that since the only modification to the wellbore is the replacement of the artificial lift unit (ESP), that Forms 10-403 and 10-404 not be required for routine ESP changeouts. Subsurface Safety Valves The Sag River development area is largely coincident with the Kuparuk reservoir development and will rely on the same operating infrastructure. Consistent with statewide AOGCC regulations (20 AAC 25.265) and standard practices at MPU, sub- surface safety valves (SSSV's) will not be used in the Sag River development. -21- • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Surface Safety Valves Sag River wellheads will be specifically designed to accommodate the ESP systems required to lift the Sag River fluids. Surface safety valves (SSV's) are included in wellhead equipment designs in a "wing" valve position. These devices will be activated by high and low pressure sensing equipment and are designed to isolate well fluids upstream of the SSV should pressure limits be exceeded. Where ESP's are employed, the sensing devices will de-energize the ESP concurrent with closing the SSV. Because periodic testing of the SSV will require pump shutdowns which are considered detrimental to ESP life span, we recommend testing the SSV's annually by reducing the speed of the ESP prior to the SSV test. Stimulation Methods Fracture stimulations of the low permeability Sag River formation will be required to achieve commercial flow rates in this reservoir. Horizontal wells can also be used to increase the productivity of the reservoir. Selection of the appropriate completion will be based on commercial and reservoir description considerations. RESERVOIR SURVEILLANCE PROGRAM As a result of the low density of wells currently completed in the Sag River, there are still many unknowns related to the flow characteristics and areal continuity across the reservoir. These issues can only be resolved through actual well development. Thus , a reservoir surveillance program will assist in the development of the Sag River. Reservoir Pressure Measurements Pressures will be reported at a common datum of 8,750 feet TVDss. Initial static pressure surveys are proposed in each production and injection well upon completion. On an annual basis, a minimum of one pressure measurement per lease (or four- section area) across the field is recommended. Allowable pressure survey techniques should include wireline RFT measurements, pressure buildups with bottomhole pressure measurement, ESP pressure measurements, injector surface pressure falloffs and static bottom hole pressure surveys following extended shut in periods. Pressure survey data would be reported to AOGCC monthly. ~' -zz- ~ ~ Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Surveillance Logs We anticipate that artificial lift equipment will preclude the use of surveillance logging techniques in producing wells. Surveillance logging will be used to monitor injector profile distributions. We propose that a minimum of one injection surveyor injection zone split determination be conducted per year, per lease or four section area. Surveillance log data would be submitted quarterly. Production Allocations and Well Testing The existing well testing equipment at Milne Point Unit will be utilized to determine production rates from the Sag River formation. Production will be commingled at surface and wells tested at least twice a month utilizing a well test methodology approved by the AOGCC . We recommend that optimum test duration at stabilized rates be determined by the Unit Operator in accordance with industry standard practices on a well by well basis. Production allocation methods currently in place for the Kuparuk and Schrader Bluff formations will also be utilized for the Sag River reservoir. A single production allocation factor based on a comparison of theoretical production with LACT metered production volumes will be applied equally to the Kuparuk, Schrader Bluff, and Sag River formation production. Production data will be submitted monthly. Production Anomalies In the event of production proration at or from Milne Point facilities, all commingled reservoirs processed through Milne Point facilities will be produced to minimize adverse affects to surface or subsurface equipment. C L -23- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 VII. Proposed Sag River Field Pool Rules This concludes our technical presentation. Please ask any questions pertaining to the previous discussion. For your convenience and consideration, we propose the following pool rules be adopted for the Sag River pool. The rules hereinafter set forth apply to the following described area of the proposed Sag River pool (Exhibit 2): Umiat Meridian T12N, R11 E Sections 2, 3, 11 T13N, R11 E Sections 18, 19, 29, 30, 32 T13N, R10E Sections 2, 3, 4, 5, 6, 9, 10, 11, 12, 13, 14, 15, 22, 23, 24, 25, 36 T14N, R10E Sections 29, 30, 31, 32, 34, 35 T14N, R9E Sections 25, 36 Rule 1. Field and Pool Name The field is the Milne Point Field and the pool is the Sag River Oil Pool. Rule 2. Pool Definition The Sag River Oil Pool is defined as the accumulations of oil and gas in the Sag River formation which occur in the stratigraphic positions which correlate with the MPA-01 type log from 8810 to 8884 feet measured depth (Exhibit 1). Rule 3. Well Spacing Nominal 40 acre drilling units are established for the pool within the affected area. Each drilling unit shall conform to ahalf-half-quarter governmental section as projected. The pool shall not be opened in any well closer than 500 feet to the exterior boundary of the affected area without a spacing exception or Pool area modification. -24- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Rule 4. Casing and Cementing The Sag River casing and cementing rules are written as specified in 20 ACC 25.030 and in accordance with the current Milne Point Field rules as follows: 1) For proper anchorage and to divert an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface and cement will be pumped to fill the annulus behind the casing to surface. 2) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze-back, a string of surface casing will be set at least 500 feet MD (measured depth) below the base of the permafrost section.. Cement shall be pumped to fill the annulus behind the casing to surface. 3) To prevent well fiailure due to permafrost action, the operator shall install surface casing including connections, with sufficient strength and flexibility to prevent failure. To be approved for use as surface casing, the Commission shall evidence that the proposed casing and connections meet the above requirement. Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze-back, based on sound engineering principles, may be approved by the Commission upon application. Rule 5. Completion Practices The following alternative completion methods are allowed: a) liners, to include but not limited to slotted, pre-drilled, pre-packed, and sintered liners, or combination thereof, landed inside of cased hole and which may be frac/gravel packed. b) open hole completions provided that the casing is set not more than 50 feet above the uppermost oil bearing zone. Open hole completions may subsequently be completed with liners, to include but not limited to slotted, pre- drilled, pre-packed, and sintered liners, or combination thereof, and may be frac/gravel packed. ___.. ~ -ZS- • • Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 c) horizontal completion with liners, to include but not limited to slotted, pre- drilled, pre-packed, and sintered liners, or combination thereof, landed inside the horizontal extension and which may be frac/gravel packed. d) multi-lateral type completions in which more than one wellbore penetration in the Sag River Pool is completed in a single well, with production gathered and routed back to a central wellbore. e) deepening or sidetracking existing wellbores to the Sag River reservoir. f) injection into the Schrader Bluff, Kuparuk, and/or Sag River formation using a common wellbore and installing packers and downhole flow control devices to regulate flow into each interval. The Commission may approve other completion methods upon application and presentation of data which shows the alternatives are based on sound engineering principles. Rule 6. Automatic Shut in Equipment All wells which are producing hydrocarbons must be equipped with afail-safe automatic surface safety valve shut-in system able to simultaneously shut in the wellhead and shut in the artificial lift equipment if present. The SSV will be tested annually. Rule 7. Common Facilities and Surface Comminalinp a. Production from the Sag River Oil Pool may be commingled on the surface with production from the Kuparuk River Oil Pool and the Schrader Bluff Oil Pool, Milne Point Unit, prior to custody transfer. b. Each producing well shall be tested at least twice a month utilizing a well test methodology approved by the AOGCC. Optimum test duration at stabilized rates will be determined in accordance with standard industry practices by the Unit Operator on a well by well basis. The Unit Operator will use its best efforts to obtain valid well tests at uniform time intervals. c. The Commission may require more frequent or longer well tests if the summation of the calculated monthly production volume for all pools is not within 10% of the actual LACT metered volume. -26- Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Rule 8. Production Anomalies In the event of production proration at or from Milne Point facilities, all commingled reservoirs processed through Milne Point facilities will be produced to minimize adverse affects to surface or subsurface equipment. Rule 9. Reservoir Pressure Monitoring a. Prior to regular production a pressure survey shall be taken on each well to determine reservoir pressure. b. A minimum of one bottomhole pressure survey per lease or four section area 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 8,750 feet subsea. d. Pressure survey means a static bottomhole pressure survey, pressure buildup test, multiple flow rate test, repeat formation tester, drill stem test, pressure fall- off test, ESP pressure measurement, or bottom hole pressures calculated from well head pressure in an injector. e. Data from pressure surveys required in this rule shall be filed with the Commission monthly. Commission from 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 made available to the Commission upon request. f. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted in accordance with part (e) of this rule. Rule i 0. Filing Form 10-403 and 10-404 Exemption ESP producing wells are exempt from filing AOGCC forms 10-403 and 10-404 during a ESP changeout unless the casing is altered or the well is stimulated. Rule 11. Gas-Oil Ratio Exemption Wells producing from the Sag River Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). -27- • i Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 Rule 12. Administrative Relief Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Commission that the changes do not promote waste, jeopardize correlative rights, and are based on sound engineering principles. L -2s- ~l Milne Point Unit Sag River Pool Rules Testimony February 25, 1998 VIII. List of Exhibits r Exhibit 1: MPA-01 Sag River Type Log Exhibit 2: Top Sag River Structure Map -Areal extent of Sag River Pool Exhibit 3: Sag River Net Pay Map Exhibit 4: Sag River Permeability * Thickness Map Exhibit 5: Full Field Model Area and Grid Configuration Exhibit 6: Proposed Development Plan Map in Full Field Model IX. References Barnes, David A., 1987, Reservoir quality in the Sag River formation, Prudhoe Bay field, Alaska: depositional environment and diagenesis iN Alaskan North Slope Geology Vol. 1, Ed. By Irv Tailleur and Paul Weimer, publ. by Pacific Section, Society of Economic Paleontologists and Mineralogists and the Alaska Geological Society. Gardner, Michael H., 1987, Sag River formation stratigraphic relationships and reservoir characterization, Prudhoe Bay region, ARCO internal report. North Slope stratigraphic Committee, 1971, West to east stratigraphic correlation section, Point Barrow-Ignek Valley, North Slope, Alaska: North Slope stratigraphic Committee, Anchorage, Alaska. C _~ L -29- #2 • • NOTICE OF DATE CHANGE OF PUBLIC HEARING STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Sag River Pool, Milne Point Unit NOTICE IS HEREBY GIVEN THAT the Alaska Oil and Gas Conservation has rescheduled the hearing set for January 27, 1998. The hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, AK on February 25, 1998 at 9:00 AM. Subject of the hearing is to present testimony for classification of and prescribing pool rules for the proposed Sag River Pool in the Milne Point Unit. If you are a person with modification in order to comment contact Diana Fleck at 793-1221 no a disability who may need special or to attend the public hearing, please later than Februarv 198. David W. J Chairman Published January 21, 1998 ADN A002814022 ~~ ~ « L ~ • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Sag River Pool, Milne Point Unit. Notice is hereby given that BPX by letter dated December 5, 1997, has petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 to hold a public hearing to present testimony for classification of and prescribing pool rules for the proposed Sag River Pool in the Milne Point Unit area. A hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, AK at 9:00 AM on January 27, 1998, 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 special modification in order to comment or to attend the public hearing, please contact Diana Fleck at 793-1221 no lat~r.xl~n Jax arv G David W. J Chairman Published December 23, 1997 ADN A002814016 on nR~GINAL ~-o~ CC ~ / Ad~~ 9294 STOF0330 POy~ 02314016 $44.40 AF F iD AVIT O F PLI B L ICATIO l~ STATE OF ALASKA, ) -CLIP - THIRD JUDICIAL DISTRICT. ) A~~.i.s.. Z, ,....G~ 1 k.i~.~ ............... being first duly sworn on oath deposes and says that he/she is an advertising representative Of Abtlte of puDttt Hem'irgg ST/lTE 0f ALASKA= the Anchorage Daily News, a Ata$It8 Oii and Gas" copservMiawcommis3ion daily newspaper. That said Re:' sap River Pooi, Milne newspaper has been approved Point by the Third ]Udlclal COUrt, Notic@ is hereby given ~ thpt'~ BPX by letter dated December Anchora e, Alaska, and it now ,¢i s, 1997, has netittdtlee ihe•Aias- ka Oil and Oas;COnservatian and has been ublished in the P cammi~idn dnaer za ;Aac to'Sp we t t s m r vi~ English language continually as a n ti on fo ~ assF fication of and prescribing' dail news a er in Anchora e, Y P P g pool rules tor. the rra~osea s«s River Poor in The Milne` Point Alaska, and it is now and during unit area. all said time was printed in an A hearing will be Field, «t me Alaska OH and Gds Conserva- Office maintained at the aforesaid lion commission, 3001 Po~-tu: D i Pi h : place of publication of said ne r ve, Anc ora4te, AiC at 9:0o AM an ,lanuarY-z7; 1998, newspaper. That the annexed is in conformance with 20 'AAC 2sseo. An interested :persons a copy of an advertisement as it and pdrffes are invjted to ~es- enrtestimonY. was published in regular issues If-voa are a cer;on w;tt, o and not in su lemental form of ~ PP ) disabiliiY wbo may need a special modHicafion in said news a er on P P order to comn,~tt ar to attend Yae Duna F 4 k f ee a# 1421 no< 7~ ~ 9~~ later tDan .ranuatr 20,1998. lsf4avid Johnston, j P r_ ~ ~ r PuD. Decem her 23,1997 1 and that such newspaper was regularly .distributed to its 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 ~ ~~~! Subscribed and sworn to before me this. day of ....... i ~~~.- Notary Public in and F the 54ite of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES i't'ti :'.~~r~r{SSi}:1 I^X',klrf't" ~ ~` *I Milne Point Unit Sag River Pool Rules Exhibits 1 through 6 December, 1997 ~~ , 1 e-e.. u~w1. .,caw c~~ ~~ ~ C. O - ~ dt3 N ~ ~~ f~ fTl ~1 «~ o ~s ~"~ ~ ~ '.."" ~ .r ~"~ ~ N E'~"~ fig, ~7•
