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CO 275
Image Project Order File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. G ~ Order File Identifier Organizing (done> RESCAN ^ Color Items:. ^ Greyscale Items: ^ Poor Quality Originals: ^ Other: NOTES: BY: Maria Project Proofing BY: Maria Scanning Preparation BY: Maria ,.o,den uumimiiuui DIGITAL DATA ^ Diskettes, No. ^ Other, No/Type: Date: Date: x30= Date: ~ /' ae.~a„~ee~ea iuuiuiiiiiui OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: ^ Other:: /s/ /s/ + =TOTAL PAGES (Count does not include cover /s/ P~^~~"_^~__~ 9 III!Illlllllllllil Stage 7 Page Count from Scanned File: ~© (Count does include cover eet) Page Count Matches Number in Scanning Preparation: YES NO BY: Maria Date: ~ ~' /O /s/ f Sfage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. III II II II VIII II III ReScanned II I II II II V III I I III BY: Maria Date: /s/ Comments about this file: Quality Checked III II~III IIIIIII III 10/6/2005 Orders File Cover Page.doc ~ • INDEX CONSERVATION ORDER N0.275 Sag Delta North 1) January 11, 1991 BP request for hearing to establish pool rules for Sag Delta North 2) February 6, 1991 Notice of Public Hearing 3) February 28, 1991 BP request to temporarily inject water into Sag Delta #9 4) March 12, 1991 Transcript of Hearing 5) November 20, 2008 BP Exploration (Alaska), Inc. request for surface commingling of production (co 275-001) CONSERVATION ORDER NO. 275 ~ ~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re : THE APPLICATION OF BP ) EXPLORATION (ALASKA) ) INC. for classification of new ) oil pools and prescribing pool ) rules for development in the ) Duck Island Unit of the ) Endicott Field . ) IT APPEARING THAT: Conservation Order No. 275 Endicott Field Ivishak Oil Pool Alapah Oil Pool April 24, 1991 1. BP Exploration (Alaska) Inc. submitted an application dated January 11, 1991 requesting a public hearing for the establishment of pool rules for the development and exploitation of the Sag Delta North oil accumulation. 2. Notice of public hearing to be held March 12, 1991 was published in the Anchorage Daily News and the Anchorage Times on February 6, 1991. 3. A hearing covering the matter of the applicant's request was held in conformance with 20 AAC 25.540 at the office of the Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501 at 9:00 a. m. on March 12, 1991. 4. Members on the staff of BP Exploration (Alaska) Inc. presented testimony including exhibits. The hearing record was closed at the end of the public hearing. FINDINGS 1. Hydrocarbons are trapped in the Ivishak Formation, a member of the Sadlerochit Group, and the Alapah Formation, a member of the Lisburne Group within Tracts 13 and 15 of the Duck Island Unit. Conservation Orde~75 April 24, 1991 Page 2 2. The Ivishak and Alapah oil accumulations appear to be separate based on pressure measurements and oil gravities . Oil gravity is 25° API in the Ivishak compared to 28° to 29° API in the Alapah. 3. The accumulations encompass an area of approximately 380 acres and are characterized by wells Sag Delta No . 9 (SD-9) , Sag Delta North No . 1 (SNO-1) , Sag Delta North No . 2 (SNO- 2) , and Sag Delta North No . 3 (SNO-3) . 4. The vertical limits of the pools may be defined by the accumulations in the BP Exploration SD-9 well which appears to be a typical and representative well. 5. Well control and 3-D seismic coverage are adequate to reasonably define the areal limits of the accumulations . 6. The pools are bounded to the south by a major fault and there appear to be numerous smaller faults within the accumulations . 7. The base of the Ivishak light oil column appears to be planar and occurs at 10,112 feet measured depth in the SNO-2 well . It is underlain by a tar mat, which separates an aquifer from the oil column. Data show the tar mat will transmit pressure but appears to be immobile . 8. The Alapah appears to have multiple oil/water contacts based on petrophysical calculations . 9. Volumetric calculations of original oil in place indicate approximately 14 million stock tank barrels (STB) in the Ivishak and approximately 3.7 million STB in the Alapah. 10. Initial Ivishak reservoir pressure is 4825 psig and temperature is 212°F at 10,000 feet true vertical depth. 11. Reservoir performance testing began at SD-9 on July 31, 1989 to gather data for development and depletion planning. Wells SNO-3, SNO-1 and SNO-2 were drilled and put on production in September 1990, November 1990, and December 1990, respectively. 12. The SD-9 well watered out in February, 1991, after producing approximately 1.5 million STB of oil. Conservation Orde~75 April 24, 1991 Page 3 13. SD-9 was converted to water injection in March 1991. 14. The SNO-1, SNO-2 and SNO-3 wells are currently on production. 15. At least two well tests per month per well are being conducted for allocation purposes . 16. Development of the Ivishak and Alapah accumulations is predicated on facilities sharing and commingling production with the Endicott Oil Pool production located on the Main Production Island (MPI) . 17. Primary depletion mechanisms indicated by test performance are solution gas drive and partial water drive in the Ivishak sands . Primary recovery is estimated to be 30$ of original oil in place . 18. Predictive studies indicate waterflooding the Ivishak reservoir will increase recoveries to 35-44$ of original oil in place. 19. An Alapah zone was tested in SNO-3 and rapidly depleted during a test period of 24 days . Total recovery is estimated to be 200, 000 STB from the Alapah. 20. Commingling Alapah and Ivishak production within the same wellbore will be a way to capture Alapah reserves which would not be developed separately. 21. The SNO-1, SNO-2 and SNO-3 wells were completed such that the Alapah and Ivishak intervals can be isolated from each other. 22. Drilling units of 40 acres will be adequate to efficiently develop the small, irregularly shaped and faulted blocks making up the Ivishak and Alapah accumulations . 23. No evidence for a gas cap in either pool has been indicated. 24. A Sag Delta North Participating Area has been established by the owner/operator which encompasses the Ivishak and Alapah oil accumulations and has been submitted to the Department of Natural Resources for approval. Conservation Orde~75 April 24, 1991 Page 4 25. Wells drilled from the Main Production Island (MPI) of the Duck Island Unit, Endicott Field, are not required to have conductor casing (C0216) . 26 . A waiver of the diverter system required by 20 AAC 25.035 (b) (1) has been granted for all Duck Island Unit, Endicott Field wells . 27. Waivers of the requirements for formation leak-off tests below structural and intermediate casing have been granted all Duck Island Unit, Endicott Field wells . CONCLUSIONS 1. Establishing pool rules for the hydrocarbon accumulations in the Ivishak and Alapah formations occurring within the boundaries of the Duck Island Unit, Endicott Field, is appropriate. 2. Forty(40)-acre drilling units provide necessary flexibility to locate wells for efficient development of the irregular shaped and faulted Ivishak and Alapah oil accumulations . 3. Surface commingling of production from the Ivishak and Alapah accumulations with production from the Endicott Oil Pool is necessary. 4. Downhole commingling of production from the Ivishak and Alapah accumulations is necessary and will allow recovery of reserves in the Alapah which might otherwise not be produced . 5. A full scale waterflood in the Ivishak accumulation to replace voidage will increase ultimate recovery. NOW, THEREFORE IT IS ORDERED THAT the rules hereinafter set forth apply to the following described area of the Duck Island Unit, Endicott Field, referred to in this order as the affected area: UMIAT MERIDIAN T12N R16E Section 25: NE4 Section 24: All state lands within the EZ Conservation Orde~75 April 24, 1991 Page 5 T12N R17E Rule 1 Section 19: All state lands Section 20: All state lands Section 29: All state lands Section 30: NZ FIELD AND POOL NAME. • within the N z The hydrocarbons contained within the Ivishak and Alapah Formations constitute reservoirs named the Ivishak Oil Pool and Alapah Oil Pool respectively. Their development areas are within the Duck Island Unit, Endicott Field . Rule 2 POOL DEFINITION. The Ivishak Oil Pool is defined as the accumulation of hydrocarbons that are common to and which correlate with the accumulation in the BP Exploration Sag Delta No . 9 well between the measured depths of 12069 and 12314 feet. The Alapah Oil Pool is defined as the accumulation of hydrocarbons that are common to and which correlate with the accumulation in the BP Exploration Sag Delta No. 9 well between the measured depths of 12418 and 12992 feet. Rule 3 WELL SPACING . (a) Nominal 40-acre drilling units are established for the pool within the affected area. Each drilling unit shall conform to quarter- governmental sections as projected . No more than one well may be drilled into and produced from each drilling unit. The pool may not be opened in a well closer than 1000 feet to any well opened to a common pool. Neither pool shall be opened in any well closer than 500 feet to the exterior boundary of the affected area. (b) The Commission may administratively approve modifications to well spacing when justified . Rule 4 CASING AND- CEMENTING REQUIREMENTS a) Surface casing, to provide for proper anchorage, for preventing uncontrolled flow and to protect the well from the effects of permafrost thaw-subsidence or freeze-back loadings, shall be set at least 500 measured feet below the base of the ice-bearing Conservation Orde~75 • April 24, 1991 Page 6 permafrost. Sufficient cement shall be used to fill the annulus behind the casing to at least the mud line. (b) Alternate means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze-back may be administratively approved by the Commission upon application and presentation of data which show the alternatives are appropriate, based upon accepted engineering principles . (c) Conductor casing is not required. (d) Formation leak-off tests are not required below structural and intermediate casing. Rule 5 DIVERTER SYSTEM A diverter system is not required on the structural casing. Rule 6 COMPLETION PRACTICES a) Wells completed for production or injection in the Sag Delta North Participating Area may utilize casing strings or liners cemented through the productive intervals and perforated, slotted liners, screen wrapped liners or open hole methods, or combination thereof . The Commission may administratively approve alternate completion methods where appropriate. b) Wells completed with the ability to have both Ivishak and Alapah Pools open to the same wellbore must have a means of isolating one from the other to prevent crossflow. Means to isolate the zones may include but are not limited to packer tailpipe assemblies, through tubing bridge plugs, cement squeezing, and cement plugging. The Commission may administratively approve alternate isolation methods where appropriate . Rule 7 PRESSURE SURVEYS a) Prior to regular production, a pressure survey shall be taken on each well. b) The datum for all pressure surveys is 10,000 feet subsea. Conservation OrdeY'~75 April 24, 1991 Page 7 c) A minimum of one bottom-hole pressure survey per producing governmental section shall be run annually. The survey in part (a} of this rule may be used to fulfill the minimum requirements. d) Pressure survey, as used in this rule may mean a static bottom- hole pressure survey, pressure transient survey, or open hole pressure tests such as repeat formation tests and drill stem pressure tests. e) Data from all pressure surveys shall be filed with the Commission on Form 10-412 within 45 days after the survey is taken. Rule 8 POOL-WIDE WATERFLOOD PROJECT a) A waterflood project is approved for the Ivishak Pool. b) Wells SD-9 and SNO-4 are approved as water injection wells in the Ivishak Pool . c} The Commission may approve additional wells as water injectors upon written application. d) Annual fluid withdrawal from the Ivishak Pool shall not exceed annual fluid injection by more than 10~. Rule 9 GAS-OIL RATIO EXEMPTION Wells producing from the Ivishak and Alapah Oil Pools are exempt from the gas-oil ratio limits set forth in 20 AAC 25.240(b} . Rule 10 COMMON PRODUCTION FACILITIES AND COMMINGLING a) Production from the Ivishak Pool and Alapah Pool may be commingled in the wellbore . Appropriate production logs shall be run to determine proper allocation of produced fluids with results reported to the Commission. b) Production from the Ivishak Pool and Alapah Pool may be commingled on the surface with production from the Endicott Oil Pool prior to custody transfer. Conservation. Ordei'~75 • April 24, 1991 Page 8 c) Each producing well completed in the Ivishak and/or Alapah Pool shall be tested at least twice a month for a minimum of four hours at a stabilized flow rate. d) 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 10b of the actual LACT metered volume. e) The operator shall provide the Commission with a well test and '~ allocation report at the end of each calendar year. The report will consist of a thorough analysis of all surveillance data relative to f ~, the well test system and the resulting allocation factors . Rule 11 GAS OFFTAKE a) Gas produced from the Sag Delta North Participating Area may be utilized as fuel in the Endicott Field facilities . b) Gas produced from the Sag Delta North Participating Area not utilized as fuel will be injected into the Endicott Pool gas cap . Rule 12 ADMINISTRATIVE ACTION On its own motion or upon written request, the Commission may administratively amend this order so long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles . DONE at Anchorage, Alaska and dated April 24, 1991. OIL ,~.~~ Ord n~ 0 1~ ~~ ~~ Alaska it a G o nervation Commission -'` ,~~ y~ Lonnie C . Smith; Coaalmissioner Alaska Oil and Gas Conservation Commission Russell A. Douglass, C missioner Alaska Oil and Gas Conservation Commission • L1itt~-7~ OIL CO1~13iaRQATIOI~T COMI~IISSIOI~T SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501.3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. CO 202.043 (Endicott Oil Pool, Endicott Field) ADMINISTRATIVE APPROVAL NO. CO 275.001 (Alapah and Ivishak Oil Pools, Endicott Field) ADMINISTRATIVE APPROVAL NO. CO 449.001 (Eider Oil Pool, Endicott Field) Mr. R. L. Skillern Senior Landman BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Surface Commingling of Production from Proposed Endicott Field Well 2-30B/ME-O1 with Production from Defined Endicott Field Oil Pools Dear Mr. Skillern: The Alaska Oil and Gas Conservation Commission (Commission) received your letter, dated November 20, 2008, requesting approval to commingle production on the surface from the proposed Endicott Field Well 2-30B/ME-O1 with production from the Eider, Ivishak, Alapah, and Endicott Oil Pools (i. e., "defined Endicott Field oil pools"). The Commission GRANTS your request subject to certain conditions as listed below. Proposed Well 2-30B/ME-O1 is on lease ADL 34633 (Tract 13), which is within the Endicott Field, but is not part of any defined Endicott Field oil pool. Based on seismic information, proposed Well 2-30B/ME- O1 production will not drain those oil pools. BP Exploration (Alaska) Inc. (BPXA) has requested that Well 2-30B/ME-O1 be allocated on a daily basis using the same methodology employed for wells in the Eider Oil Pool. Well 2-30B/ME-O1 allocated production will be based upon a minimum of two well tests per month. BPXA proposes that the allocation factor be fixed at 1.0 (i.e., it will not be adjusted for discrepancies between measurements of total Endicott Field oil production derived from well tests and from the Lease Automated Custody Transfer (LACY) meter). The Commission grants BPXA's request to commingle production on the surface from the proposed Endicott Field Well 2-30B/ME-O1 with production from the defined Endicott Field oil pools prior to custody transfer. This approval is conditioned upon the following: 1. Unless the Commission otherwise requires, production from Well 2-30B/ME-O1 will be determined through well tests conducted at least twice per month at a stabilized flow rate lasting more than four hours. 2. Unless the Commission otherwise requires, production from We112-30B/ME-01 will be allocated on a daily basis using the same methodology employed for wells in the Eider Oil Pool, with a meter allocation factor fixed at 1.0. 3. The operator shall provide the Commission with a written well test and allocation report at the end of • Mr. L. R. Skillern January 22, 2009 Page 2 of 2 each calendar year. 4. Within one year after the start of production from Well 2-30B/ME-O1, the operator shall (1) provide the Commission a written report with all reasonably available evidence regarding whether the well is in communication with any defined Endicott Field oil pools, and (2) apply to the Commission to include the well within an already defined Endicott Field pool or within a new Endicott Field pool. 5. Unless notice and a public hearing are required, upon proper application or its own motion, the Commission may administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. ENTERED at Anchorage, Alaska, and dated January 2 , 2009. i3:' J _, ~ ~~~ s~ ,~,_.,. Daniel T. Seamount, Jr., Chair ~~~ ~ ~ 6 , ~ y', Y 'rJ~ - + ~ .~`...... ~ ~~s .~s~' • Cathy P. oerster, 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 Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsid- eration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for re- consideration 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. Fail- ure 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 af- ter 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 oth- erwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on ap- peal 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. Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Wertheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket BeII Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 ~~/~y(~ ~ q ~ t~G~j~ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, January 23, 2009 11:30 AM Subject: co202-043, co275-001 and co449-001 Endicott Attachments: co202-043, co275-001, co449-001.pdf BCC:Aleutians East Borough; Anna Raff; Barbara F Fullmer; bbritch; Bill Walker; Brad McKim; Brandon Gagnon; Brian Gillespie; Brit Lively; Bruce Webb; buonoje; Cammy Taylor; Cande.Brandow; carol smyth; Cary Carrigan; caunderwood@marathonoil.com; Charles O'Donnell; Chris Gay; Cliff Posey; Dan Bross; dapa; Daryl J. Kleppin; David Brown; David Gorney; David Hall; David House; David L Boelens; David Steingreaber; ddonkel; Deborah Jones; doug_schultze; Eric Lidji ;Evan Harness; eyancy; foms2@mtaonline.net; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gregg Nady; gspfoff; Hank Alford; Harry Engel; Havelock, Brian E (DNR); jah; James Scherr; Janet D. Platt; jejones; Jerry McCutcheon; Jim Arlington; Jim White; Jim Winegarner; Joe Nicks; John Garing; John S. Haworth; John Spain; John Tower; John W Katz; johnny.aiken@north-slope.org; Jon Goltz; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; keelson@petroleumnews.com; Krissell Crandall; Kristin Dirks; Laura Silliphant; Lynnda Kahn; mail=akpratts@acsalaska.net; mail=fours@mtaonline.net; Marilyn Crockett; Mark Dalton; Mark Hanley; Mark Kovac; Mark P. Worcester; Marguerite kremer; Matt Rader; Melanie Brown; Mike Bill; Mike Jacobs; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Nick W. Glover; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; Patty Alfaro; Paul Decker; Paul Winslow; Pierce, Sandra M (DNR); Randall Kanady; Randy L. Skillern; rcrotty; Rice, Cody J (DNR); rmclean; Rob McWhorter ; rob.g.dragnich@exxonmobil.com; Robert Campbell; Robert Fowler; Robert Province; Roger Belman; Rudy Brueggeman; Scott Cranswick; Shannon Donnelly; Sharmaine Copeland; Sondra Stewman; Sonja Frankllin; Stan Porhola; stanekj; Steve Lambert; Steve Moothart; Steven R. Rossberg; tablerk; Tamera Sheffield; Temple Davidson; Terrie Hubble; Tim Lawlor; Todd Durkee; Tony Hopfinger; trmjrl; Von Gemmingen, Scott E (DOR); Walter Featherly; Walter Quay; Wayne Rancier; Aaron Gluzman; Dale Hoffman; Fridiric Grenier; Gary Orr; Joe Longo; Lamont Frazer; Marc Kuck; Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; Sandra Lemke; Scott Nash; Steve Virant; Tom Gennings; Willem Vollenbrock; William Van Dyke; Woolf, Wendy C (DNR); Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:co202-043, co275-001, co449-OOl.pdf; Jody J. Colombie Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 1/23/2009 `'~Td 1 • R, L. Skillern Senior Landman -Alaska November 20th, 2008 Mr. Kevin Banks, Acting Director Division of Oil & Gas State of Alaska, Dept. of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, AK 99501-3560 Mr. John Norman Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Request for Surface Commingling of Production for Well 2-30 B/M E-01 Gentlemen, BP Exploration ;Alaskal Inc. 900 East Benson Boulevard PO Box ?96612 Anchorage, AK 99519-6612 (907) 564-5111 Phone: 1907) 564-5567 Fax: 1907)564-4264 Email SkilleRL~bp.com Web: www.bp.com ~- ~:_. .. In accordance with 20 AAC 25.215, BP as Operator of the Duck Island Unit and sole Working Interest Owner o lease A L 34633 ract 13) hereb re uests ermission for surface commingling of production p Y q from Well 2-30B/ME-01 with production from the .Eider, Sag Delta North, and Endicott Oil Pools. The Operator proposes the following methodology for tracking production from Well 2-30B/ME-01. • Production from Well 2-30B/ME-01 will be allocated on a daily basis using the same methodology employed for wells in the Eider Oil Pool (Conservation Order No. 449) and will be tracked through BP's production tracking system. Allocations will be based on well tests as described below. • vVeii 2-306/NIE-01 will be tested a minimum of two times per month during periods when the well is on production. The meter allocation factor for Well 2-30B/ME-01 will be fixed at 1.0 • Allocated data will be reported monthly to the DNR using form 10-405 as required by 20 AAC 25.230. This methodology for • Mr. Kevin Banks, Acting Director Division of Oil & Gas Mr. John Norman Alaska Oil and Gas Conservation Commission November 20t", 2008 Page 2 • allocation and reporting will continue until final determination of the Producing Area for Well 2-30B/ME-01. Should you have any questions, please contact John Garing at (907) 564-5167. Sincerely, 1 :~ ~; .~~ #~ R.L. Skillern cc: John Garing Endicott Files ~+ It ~J U 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 L • ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING MARCH 12, 1991, 9:00 O'CLOCK A.M. TRANSCRIPT OF PROCEEDINGS HELD AT THE OFFICES OF THE ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA ~~ ~,. ~..~it #~ GaS ~,' ~ChOCu;~. R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. SRD AVENUE 1007 W. 9RD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8548 272-7815 272-8022 ANCHORAGE. ALASKA 99501 • • ~J 1 2 3 4 5 6 8 9 10 11 12 13 14 15 16 17 ~! 18 19 20 21 22 23 24 25 ~~ ~~ 2 P R O C E E D I N G S CHAIRMAN JOHNSTON: The time is approximately 9:04. The date is March 12, 1991. The location is the offices of the Alaska Oil and Gas Conservation Commission, located at 3001 Porcupine Drive, Anchorage, Alaska. I'd like to begin by introducing the head table. My name is David Johnston, I'm chairman of the Commission. To my right is Commissioner Russ Douglass; to my left is Commissioner Lonnie Smith; to the far left is Lou Kehler of R & R Court Reporters, who will be making the transcript of these ~, proceedings. At this time I'd like to ask Commissioner Russ Douglass to read into the public record the notice that was provided for this meeting. COMMISSIONER DOUGLASS: Notice of Public Hearing, State of Alaska, Alaska Oil and Gas Conservation Commission: regarding the application of BP Exploration (Alaska) Incorporated, for a public hearing to present testimony for classification of a new oil pool and prescribing pool rules for its development in the Duck Island Unit of the Endicott Field. Notice is hereby given that BP Exploration (Alaska) Incorporated has petitioned the Alaska Oil and Gas Conservation Commission, under 20 AAC 25.520, to hold a public hearing to present testimony for classification and prescribing of pool rules for the development of a new oil pool in the Endicott R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 9RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8543 272-7515 272.3022 ANCHORAGE. ALASKA 99501 • • ~~ ~ _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 3 Field; the development areas located in Tracts 13 and 15 of the Duck Island Unit, and has been generally referred to as the Sag Delta North accumulation. A hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska, 99501, at 9:00 a.m. on March 12, 1991, in conformance with 20 AAC 25.540. All interested persons and parties are invited to present testimony. Russell A. Douglass, Commissioner, Alaska Oil and Gas Conservation Commission. Published February 6, 1991. CHAIRMAN JOHNSTON: Thank you. The proceedings will be held in accordance with our regulations governing hearings; specifically those regulations are 20 AAC 25.540. Those regulations provide that the Commission will take sworn testimony or unsworn statements in the deliberations of the Commission. Greater weight, of course, will be given to sworn testimony. As you come to the front table to present your testimony we ask that you state your name and who you .represent. Those people wishing to be considered expert witnesses will be requested to state their qualifications. The Commission will then consider those qualifications and rule as to whether we would consider you an expert witness in these matters. R & R COURT REPORTERS 8f0 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8543 272.7518 272-3022 ANCHORAGE. ALASKA 99501 • • r ~~ 1 2 ~~ 3 4 5 6 7 8 9 l0 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 4 The order of testimony: We'll have the applicant going first, followed by others wishing to testify. With Commission approval the applicant may cross examine those other witnesses. At the conclusion of the sworn testimony, unsworn oral statements or written comments may be accepted. .From time to time the Commission will be asking questions of the people providing testimony. Members of the audience will not be permitted to ask questions directly, however, if you do have a question, we ask that you write it down, indicate who the question should be directed to, and then if you would pass it forward to the head table here, the Commission will take a look at those questions and if, in our opinion, we consider it helpful, the Commission will then ask that question. A written transcript of the proceedings will be prepared and will be made a part of the public record. At this time I'd like to ask Russ Douglass to swear in those people that are providing testimony. COMMISSIONER DOUGLASS: All those who are going to be presenting testimony, if you'd stand, please, and raise your right hand. (Oath administered) MR. JOHNSON: I do. MR. POLICKY: I do. MR. HELLMAN: I do. COMMISSIONER DOUGLASS: Let the record show that R & R COURT REPORTERS 8f0 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8543 272-7515 272-3022 ANCHORAGE. ALASKA 99501 • • ~~ ~_~ 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 I~ 19 20 21 22 23 24 25 ~~ 5 Sam Johnson, Bruce Policky and Herman Hellman are duly sworn in and will be presenting testimony for us today. You may be seated. CHAIRMAN JOHNSTON: At this time, I'd like to ask Mr. Hellman as to who would be initiating the introduction to your testimony? MR. HELLMAN: Mr. Policky will do the introduction.. CHAIRMAN JOHNSTON: Mr. Policky, if you'd like to start your testimony. MR. POLICKY: Do you want me to go into qualifications right now? CHAIRMAN JOHNSTON: If you wish to be considered an expert witness, we'd like you to state your name and who you represent and your qualifications. MR. POLICKY: My name is Bruce Policky. I graduated from the University of Wyoming in 1978 with a bachelor of science degree in petroleum engineering. I worked for approximately four years for Amerada Hess before hiring on with Sohio Alaska Petroleum Company in 1982. I've been employed with Sohio and later BP Exploration. Since 1982 I've held positions in Alaska at Kuparuk, Prudhoe Bay, Endicott and Sag Delta North areas. I'm currently manager of Reservoir and Production Engineering for the Endicott Reservoir. CHAIRMAN JOHNSTON: One moment, please. (Pause) The. Commission will recognize you as a expert witness in these R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 8RD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8548 272.7515 272-8022 ANCHORAGE. ALASKA 99501 • • ~_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 6 matters before us today. Please proceed. MR. POLZCKY: Okay. I'll introduce into the record now our written testimony. Mr. Chairman, members of the Commission, ladies and gentlemen, my name is Bruce J. Policky. I'm manager of Endicott Reservoir and Production Engineering for BP Exploration. The purpose of this hearing is to provide testimony in support of the establishment of pool rules for the Duck Island Unit, Ivishak and Alapah accumulations. We are officially requesting that these accumulations be called the Sag Delta North Ivishak Pool and the Sag Delta North Alapah Pool. The boundaries of both pools a re encompassed by the proposed Sag Delta North Participating Area for the Sag Delta North Reservoir pursuant to the Duck Island Unit Agreement and are all within the geographic boundaries of the state of Alaska and are, therefore, subject to the jurisdiction of the Alaska Oil and Gas Conservation Commission. The testimony will enable the Commission to establish pool rules applicable to both pools, which will allow economic development of the resources within the Sag Delta North Field. A production test has been underway with the authorization of the Commission since July 31, 1989. Currently there are. three wells that are producing; one well is injecting water, and a fifth well is being drilled. BP Exploration requests the Commission to approve R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 2770572 277-8543 272.7515 2723022 ANCHORAGE, ALASKA 99501 • • ~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 • 7 several concepts which are considered necessary for economic development of the pool. These are: 1) Well spacing of 40 acres to allow well placement for maximum oil recovery; 2) initiation of water injection for enhanced oil recovery; 3 ) surface commingling of production from the Sag Delta North Ivishak and Alapah Pools with the Endicott Pool; 4) and down hole commingling of the Alapah Pool with the Ivishak Pool to allow for maximizing economic recovery from the Alapah Pool. BP Exploration will make the presentation of the testimony on behalf of the other Working Interest Owners, which include Cook Inlet Region Incorporated, Nana Region Incorporated, and Doyon Limited. Within the testimony we will discuss our present understanding of the reservoir description, reservoir performance history, prediction of future reservoir performance, and the plan of field development. At this time I'll introduce Sam Johnson, who will carry through on the reservoir description. MR. JOHNSON: Thank you. Mr. Chairman, members of the Alaska Oil and Gas Conservation Commission, ladies and gentlemen, I'm Samuel R. Johnson. I will be presenting the features of the Sag Delta North Reservoir Description on behalf of BP and the other Working Interest Owners. R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 9RD AVENUE 1195 W. 8TH AVENUE 277-0572 277-8549 272-7515 272.9022 ANCHORAGE. ALASKA 99501 • • ~~ ~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 8 MR. HELLMAN: Do you want to state your qualifications? MR. JOHNSON: Yes. I have received a bachelor's. of science degree in geology in 1978 from the University of Utah, and I have 13 years' industry experience. During the last 2- 1/2 years I've been involved with the Endicott development, and most recently with the Sag Delta North Field. My current position is Lead Geologist in Reservoir Description. CHAIRMAN JOHNSTON: The Commission will recognize you as an expert witness in the matters pending before us today. MR. JOHNSON: My testimony will begin with a brief geographic description of Sag Delta North Field, continue with the stratigraphy, petrophysical properties, structural setting, and then I'll conclude with the estimation of oil in place. COMMISSIONER SMITH: Should we be labeling these as exhibits? CHAIRMAN JOHNSTON: This is Exhibit Number 1, and they're all included in this package, is that correct, Sam? MR. JOHNSON: That's correct. The exhibits are in the package. COMMISSIONER SMITH: Well, the exhibits are listed then. I'll watch them; they'll be the official exhibits as you have them labeled, unless there's some discrepancy on it. I'll try to watch that. CHAIRMAN JOHNSTON: As you go through your testimony and as you refer to each exhibit would you indicate or briefly R & R COURT REPORTERS B10 N STREET, SUITE 101 509 W. 8RD AVENUE 1007 W. 8RD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8548 272-7515 272-3022 ANCHORAGE, ALASKA 99501 ~ ~ ~_J 1 2 3 4 5 6 7 8 9 10 it 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ~~ • 9 describe what that exhibit is and indicate the exhibit number as you proceed with your testimony? MR. JOHNSON: Okay, that would be possible. Exhibit 1 is a location map for the Sag Delta North Field showing the extent of the exploitable hydrocarbon bearing zones, the bounding faults here, and the relationship to the Endicott Field and to the existing shoreline. All the wells of the Sag Delta North Field are drilled from the main production island out into ~~ the accumulation. Also shown on this map is the existing -- or the proposed participating area of the Sag Delta North Field, shown in the heavy line. The Sag Delta North Field underlies state and federal leases located offshore, and it is adjacent to the northernmost section of the Endicott Field, which contains hydrocarbons in the Kekiktuk Formation, limited in this fault and the Niakuk fault. The Sag Delta North Field contains hydrocarbons reservoired in the Triassic Ivishak Formation and the Carboniferous Alapah Formations, and the area encompasses approximately 380 acres. The delineation of the Sag Delta North Field is based on four wells; the Sag Delta Number 9, 2-38 SN-01, 1-17/SN-02 and the 2-32/SN-03. The data from the well logs were used to determine the petrophysical properties. We also incorporated Repeat Formation Tests, or RFTs and there are some cores available from the Sag Delta Number 9. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277.8543 272-7515 272.3022 ANCHORAGE, ALASKA 89501 • • r~ ~~ 1 2 ' 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 i 23 24 25 r~ ~~ 10 I would like to introduce Exhibit 2, which is the typed log for the Sag Delta North Field, based on the Sag Delta Number 9 Well. This shows the two oil pools that are proposed; the Alapah Oil Pool encompassing the Alapah porosity zones of the Lisburne group and the Ivishak Oil Pool encompassing correlatable sandstones within the Ivishak. This exhibit shows the stratigraphic zonation that we are proposing using here. The Ivishak sand has been broken into an Upper Sand and a Lower Sand, separated by a middle shale. The Lower Sand has been further subdivided into an A and a B, based on different petrophysical properties. For instance the decreasing porosity associated with that zone. Ivishak conformably overlies the Kavik Formation. The Kavik unconformably overlies the Alapah porosity zones, which we have identified four correlatable porosity zones within the Alapah. And the basis of that correlation is a persistent gamma marker at the base of Zone 1. Exhibit 3 summarizes the stratigraphy and reservoir zonations, deposition environments and dominant lithology. We start at the base of the section in the Lisburne and the Alapah group, consists primarily of dolomites and limestones, and there's a series of cyclical shallowing upward intertidal shoals as reflected in the decreasing gamma ray count at the top of each cycle. The Lisburne is unconformably overlain by the mudstones of the Kavik Formation, which is interpreted as a marine shale. The silisiclastic progradation of the Lower A R & R COURT REPORTERS 810 N STREET, SUITE f01 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8543 272-7515 272-3022 ANCHORAGE. ALASKA 99501 • • 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 ~ ~ ~~ 11 member of the Ivishak prograded out into the Kavik seas so we've interpreted the Lower Sand as marine shore face or in very shallow water. There's a sharp break between the Lower A and the Lower B. It is cored, it's a sharp break and the B possibly represents a fluvial distributary channel that's cut into the shoreface sand. Overlying the B member is middle shale, it's primarily of mudstone. It does contain some silt stone. We don't have core of this upper part of the section, so the interpretation of this environment is somewhat speculative, but the mudstone is persistent in all the wells drilled to date, suggesting that possibly it's regional and may represent another marine incursion, similar to the Kavik. It may, although, be a A fill or flood plain shale, more of a fluvial environment. The upper sand that overlies the marine mudstone, again, is speculative but possibly represents another marine incursion or shorefaced sand. If this is a marine shale, if not, it's another channel. There are an increase in some cherts and pebbles in the upper sand from cuttings, suggesting a fluvial environment. Exhibit 4 is a structure map. It's mapped on top of the Lower Sand of the Ivishak. Lower Sand is the primary section of the reservoir here. Contour interval at 20 feet and scale, in the testimony of 1" to 1,000'. The primary bounding fault is this fault down to the south here that separates Sag North from the Endicott Pool. What's also interesting to note is R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 9RD AVENUE 1195 W. 8TH AVENUE 277-OS72 277-8549 272-7515 272.9022 ANCHORAGE. ALASKA 99501 ~ J 1 2 3 4 5 6 7 8 9 10 11 12 13 14 IS 16 17 18 19 20 21 22 23 24 25 r ~ L~ • • 12 basically an anticlinal feature that plunges to the north with dip off the .flanks to the east and west. There's also offset of the structural crest along -- as we cross in each fault block, so that there's probably been some strike slip motion along these faults. The eastern limb or the zeature is Lne limit of the Ivishak as it is truncated by the lower cretaceous unconformity. I'd like to show a cross section; two of the existing wells from the Sag Delta Number 9 up to the crestal wells, SN- 03 and SN-O1, then off to the flank well here. So, Exhibit 5 is a structurally hung cross section through the Sag Delta North Field. The shales provide the trap for the hydrocarbon accumulation with the HRZ shales as a cretaceous forming the cap for the Ivishak, and the Kavik shales provided in the cap for the Alapah. The structure beneath the LCU is independent of its surface, and it's a truncated unconformity, and we can see gunk coming from .the Sag Delta Number 9 that the upper sand is truncated by that unconformity as going to the Sag Delta North Number 2 to the upper sand as truncated, as we get up on the anticlinal crust. As we go down into this incline these sands pick up again. The top of the Alapah part of the base of the Kavik is also an unconformity, however, this unconformity has been folded. So if a folded angular unconformity that controls the amount of section in the Alapah Porosity Zones, we do see R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277.0572 277-8543 272-7515 272-3022 ANCHORAGE, ALASKA 99501 ~~ ~~ 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 W • • 13 truncation going up the anticline. As we get to the crest probably this truncation will persist off to the east. I'd also like to note on Exhibit 2 is the base of the light oil column for the Ivishak was defined in the Sag Delta North Number 2 well at 10,112 feet. We're assuming that's a plainer contact, and with Sag Delta North Number 9 just missing the exploration well. Oil water contacts in the Alapah, we've found three so far, more depending on petrophysical considerations. And this is a much more complicated section. Just to come back to the base Ivishak light oil, we do have a immobile tar mat here, however, running RFTs in Sag Delta North Number 2 we did find depleted -- less than original reservoir pressures in the aquifer beneath that tar mat, so there appears to be some communication across that zone. Exhibit 6 is a petrophysical summary of the primary hydrocarbon bearing zones of the Sag Delta North Reservoir. The Upper Sand, Lower Sand, A and B, are contained in the Ivishak Pool, and the Alapah Porosity Zones in the Alapah Pool. The net to gross values is the amount of possible pay within the sandbearing sections, and included for the entire sand. The values given are average values, and then in parentheses we have the ranges of those values. Starting with the Upper Sand, let me just point out that since we have correlated these as sand, these values tend to be R & R COURT REPORTERS 8f0 N STREET. SUITE 101 S09 W. 9RD AVENUE 1007 W. 3RD AVENUE 1185 W. 8TH AVENUE 277.0572 277-8548 272-7515 272-3022 ANCHORAGE. ALASKA 99501 r ~ ~~ 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 • • 14 fairly high, but the Upper Sand, .83, with a range of .7 to .96 or almost 1, it has a little bit lower porosity than the other zones at 17.5 with a range of 16 to 19%. Oil saturations range from close to 68% -- or average about 68% and range from 71.4 to 64%. The Lower Sand B is the best section in the Sag Delta. North Reservoir. We have .81 net to gross with a range of .7 to almost 9. We have very good average porosities of over 22% with a range from 19 to over 25%. Oil saturations in the light oil column average about 70%, range from 66 up to 70%. The Lower A Sand has a little higher net to gross than B, it has intermediate porosities between Lower, and the Lower B and the Upper Sand ranges from 19 to 23. We have a little bit higher water saturation, therefore a decreased oil saturation with average around 64 and ranging from 59 up to 68, almost 70%. The Alapah Porosity Zones are based on a little different parameters since the dolomites and carbonates have about a .86 net to gross, and again these are -- you know, we have correlated the porosity zones, so we tend to high grade these. We have quite a range of net to gross values; from .2 up to 1. Porosities average about 17.5% and range from 11 up to 24%. And we see 75% average oil saturation with range from 60 to 88%. I just might note that the evaluation of carbonates can be quite speculative, so that these numbers aren't as anchored as the numbers that we're using for the Ivishak. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 8RD AVENUE 1007 W. 8RD AVENUE 1185 W. 8TH AVENUE 277.0572 277-8548 272.7515 272-8022 ANCHORAGE. ALASKA 99501 • • ~.J 1 2 ~ 3 4 5 6 7 8 9 to li 12 13 14 15 16 17 18 19 20 21 22 23 24 25 15 Multiplying the net to gross times porosity times water saturation times acre feet and dividing by formation volume factor is the number that we have used to calculate the stock original oil in place. Exhibit 7 summarizes the distribution of the stock tank original oil in place or STOOIP by reservoir sections. Again, the Upper or Lower Sand A and B are the Ivishak Pool with the Alapah Pool separate there. I'd like to note that the bulk of the accumulation is contained in the Lower Sand B. There's a significant quantity in the Upper Sand of 4.7 million barrels at 27$. The Lower Sand A contains 2.8 million barrels; 16$ of the total accumulation. I'm currently estimating 3.7 million barrels in the Alapah, which represents about 27$ of the total accumulation. I'd like to point out here that the oil contained in the Alapah has a much higher API gravity than the Ivishak sandstones. Also it has different oil water contents, and the ~', Alapah -- the wells we have encountered below average or below the original reservoir pressure in the Ivishak, we've encountered original reservoir pressures in the Alapah, so supporting the fact that we have two separate pools out here that are not in communication with one another. Exhibit 8 is the areal distribution of the hydrocarbon bearing Ivishak sandstones that make up the Ivishak Pool. Starting at the base of the section, the Lower Sand is the dark line. It encompasses pretty much the central core of the R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 8RD AVENUE 1007 W. SRD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8548 272-7515 272-8022 ANCHORAGE. ALASKA 99501 r-~ ~~ 1 2 3 4 5 6 7 8 9 10 I 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 r ~ ~J • • 16 anticlinal area. The position of this line is controlled by 10112', base light oil content. The Lower Sand B, the dash line, is controlled to the north and to the west by the oil water contact and also up into this area to the east. This is where the truncation of the LCU occurs; the sand is truncated. The Upper Sand, the dot-dash line is controlled to the west by the oil water contact, and the western line here is where it's truncated by the LCU. As we move off the crest of the anticline we do pick up another section of the Upper Sand in the light oil column in fault blocks to the south. Exhibit 9 shows the distribution of the Alapah porosity zones, hydrocarbon bearing sections. You have four porosity zones. It's kind of busy, but the western portion of all these lines and to the north are primarily controlled by oil water contacts. There are numerous oil water contacts but we've applied averages to the zones. And to the eastern line of these zones is controlled by the pre-Kavik unconformity as the -- you know, the unfolded unconformity. So this is actually an erosional surface here with an oil water contact bearing surface here. That is, they're all basically contained and underly the Ivishak's accumulation. Uncertainties, you know, associated with the volumetrics include variations in the oil water contact are not being plainer and variations in reservoir properties as we move off to the east, which we're, you know, evaluating with the last well we .plan to drill, the 5N-04, or as we have R & R COURT REPORTERS 8f0 N STREET, SUITE 101 509 W. SRD AVENUE 1007 W. SRD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8548 272-7515 272-3022 ANCHORAGE, ALASKA 99501 • • ~~ ~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 • currently planned. 17 That concludes my portion of the testimony. I'd like to introduce Herman Hellman, who will wrap up the reservoir description section and carry on with the engineering aspects of Sag Delta North. CHAIRMAN JOHNSTON: Before you proceed, does the Commission have any questions of Mr. Johnson? COMMISSIONER SMITH: No, not at this time. CHAIRMAN JOHNSTON: I notice on your Exhibit 8 that a portion -- I guess it's the Lower B Sands appears to abut the boundary between state and federal acreage. I believe this is the disputed acreage that's part of the ..... MR. JOHNSON: Uh-huh (affirmative). CHAIRMAN JOHNSTON: ..... Dinkum Sands litigation. What is your control to the north there over the areal distribution; im other words, what kind of data points do you have? MR. JOHNSON: Well, this field is interpreted. from the Endicott 3-D Survey. So you have structural control out of at least two; the lease line and a little bit beyond, so we have pretty good structural control, based on the seismic. To the extent of the -- actually it's the Upper Sands' hydrocarbon bearing sections to the north here. You know, this line is pretty near our ability to drill out that far. We're almost to our limit as being able to drill a well out there, and in addition, there's this fault here that may separate and may not R & R COURT REPORTERS 810 N STREET, SUITE f01 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8548 272-7515 272.8022 ANCHORAGE. ALASKA 99501 • • ~~ ~~ J 1 2 3 4 5 6 7 8 9 to 11 12 ., ii 14 15 16 17 18 19 20 21 22 23 24 25 ~ ~ 18 communicate this pool with the central portion of the accumulation. CHAIRMAN JOHNSTON: On Exhibit 1, I see that you have what appears to be one wel l proposed to the far north . What kind of information do you hope to gain by drilling that well? MR. JOHNSON: .Well, that well is contingent upon SN-04, which is drilling here, and if we have very optimistic results i from this well, it may mean that we could push this contact out a little bit and have this well as an injector, keeping this well as the producer. But as we see it now, we really don't think this is a viable well, and will take a real upside in the SN-04 well, too. It could make that a possibility. CHAIRMAN JOHNSTON: You don't see the areal distribution of the pool shifting to the north after you acquire information from that well? MR. JOHNSON: No. CHAIRMAN JOHNSTON: Okay, thank you. MR. HELLMAN: My name is Herman L. Hellman. I have a bachelor of science degree in aerospace engineering from the University of Texas in 1966. I have 25 years of experience in the petroleum industry, working in various aspects of reservoir development and resource studies in south Texas, UK, Norwegian North Sea sectors and Alaska. I've been employed by BP since November of 1982, working on Alaskan field development, and I've been working on Sag Delta North since the original exploration R & R COURT REPORTERS 8f0 N STREET. SUITE lOt 509 W. 3RD AVENUE 1007 W. 8RD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8548 272-7515 272-3022 ANCHORAGE. ALASKA 99501 ~~ ~_~ 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 ~ ~ • • 19 tests or delineation tests in March of 1989. CHAIRMAN JOHNSTON: Lonnie? COMMISSIONER SMITH: Fine. CHAIRMAN JOHNSTON: The Commission will recognize you as an expert witness in these matters. MR. HELLMAN: My testimony will consist of completion of the reservoir description section; an overview of the past reservoir performance; -- I feel a bit constrained here, like I'm on a leash -- review of the reservoir studies describing the depletion mechanisms; discussion of performance predictions, surveillance plans and other development issues. To begin the testimony I'd like to complete the reservoir description section with a discussion of permeability, relative permeability and fluid properties. The discovery. well, which is 5-3-$D-09, commonly referred to as Sag Delta 9, is the only well in the field that has been cored. There was a conventional core taken in that well in the Lower A Sand in the Lower B of the Ivishak formation and also the Alapah formation.. Permeability, this was cored in December of 1981 when the well was originally drilled. Permeability in the Ivishak ranges from about two millidarcies to over 600 millidarcies. The arithmetic average of that is about 124 millidarcies. The Alapah permeabilities are generally less than 5 millidarcies except in a couple of 5' streaks where permeabilities range in the 100 to 200 millidarcy range. The permeability data that we used in our. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8543 272.7515 272.3022 ANCHORAGE. ALASKA 99501 • 20 1 reservoir simulation model will be shown in a later exhibit. There is not any relative. permeability data available 2 3 for the Sag Delta North Ivishak or the Alapah sands -- Alapah 4 carbonate. Pseudo oil water and gas oil relative permeabilities 5 that were developed for the Endicott 3-A sand were used in our 6 modelling. In those the oil water endpoints were adjusted to ~ Ivishak initial water saturations of 25$ in the light oil column g and 40~ in a transition zone with a residual oil to water of g 20~. And the gas oil curves were also used; they were adjusted l0 to a residual gas of 35$. 11 Surface separator samples were collected on Sag Delta 12 9 shortly after the well was put on production and a laboratory 13 analysis of that oil yielded a bubble paint of 3,912 psi and 14 initial GOR of 672. We utilized that data to begin with in our 15 i reservoir modeling for a history match. We were not able to 16 obtain a history match in our reservoir simulation studies. 17 I'd like to introduce here Exhibit 10, which is the lg Ivishak fluid properties with which we were able to obtain a 19 reservoir simulation match. These properties are very similar 20 to the Endicott field fluid properties. The bubble point that 21 was used was 4825, which is near initial reservoir pressure of 22 4825. Although no gas cap is present in the Ivishak reservoir, 23 we believe that the bubble point is very near the initial 24 reservoir pressure. And that was necessary in order to be able 2g to get a match in our reservoir simulation. So, once again, R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1185 W. 8TH AVENUE 277-0572 277.8543 272-7515 272.3022 ANCHORAGE. ALASKA 99501 • • 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 r ~J 21 these are the fluid properties that were utilized in our reservoir simulation model. We feel this is the best technical example or representation of the Ivishak fluid properties. No laboratory analysis of the Alapah crude has been obtained. The API gravity was measured in the 28 to 29 degree range on the tests that were conducted on Sag North 03 well. And, again, this indicates the difference in the crude between the Ivishak and the Alapah. I'll continue with a discussion of the past performance of the reservoir during the test period, starting out with Exhibit Number 11. Exhibit 11 is a plot of the production history of well 5-3 Sag Delta 9. Plotted on the left axis is the production in barrels per day and the gas oil ratio in standard cubic feet per barrel. On the right-hand side is the water cut in percent. The well began producing the last day of July, 1989. It began producing at solution GOR, essentially no water rates in about -- just around 2,000 barrels per day. In November of 1989 -- or September and October of 1989, the water cut began to increase slightly and the rates were increased at that time up to about 3,500 barrels per day. Water cuts continued increasing on a fairly steady increase until about July of 1990 when the Upper Sand in the well was completed. All the previous production had been from the Lower Sand. The Upper Sand was perforated, began producing oil. This affected the water cut, R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. SRD AVENUE 1007 W. 8RD AVENUE 1185 W. 8TH AVENUE 277.0572 277-8548 272.7515 272-8022 ANCHORAGE, ALASKA 99501 • • ~_J 1 2 3 4 5 6 7 8 9 10 11 12 I! 13 14 15 16 17 18 19 20 21 22 23 '' 24 25 r ~ ~~ 22 so obviously the water cuts went down and the Upper Sand was dry oil. The well continued to produce at around the 3,000 barrels a day range with fairly constant gas oil ratios and increasing water cuts until February of 1991 when the well watered out at 90 plus percent water cut. In March the well was converted to water injection. Based on the temporary permit that was obtained from the AOGCC the well has been injecting water since March 1. As far as reservoir pressure is concerned, relating to the Ivishak reservoir, I'll discuss that later when I talk about-the reservoir modelling aspects. Well, 2-32/SN-03 was drilled and completed in September of 1990, and originally we began producing this well from the Alapah. Exhibit 12, which I'm showing now, is a plot of oil and GOR from a test of the Alapah into a test separator. What's plotted is the rates versus a 30-minute period for 2-1/2 days. So we have test data here every 30 minutes. As you can see, the well originally produced about 35 to 3,800 barrels of oil per day and then very rapidly declined over the 2-1/2-day period to about 800 barrels per day. GORs began down fairly lower in the six to 700 range, and by the end of the test period were up about 5,800, indicating a pressure depletion and fairly typical flow in a fractured carbonate. Over a 24-day test period when the well was producing, the well produced 12,360 barrels of oil, and during this- time the reservoir pressure declined from original pressure, which was about 4,900 psi, to 3,370 psi after R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 8RD AVENUE 1T35 W. 8TH AVENUE 277-0572 277.8548 272-7515 272.3022 ANCHORAGE, ALASKA 99501 • • ~_..J 2 3 4 SI 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ~~ 23 a three-day shut-in. At that time we set a plug in a WD isolation packer between the Alapah and the Ivishak isolating the Alapah and we then perforated the Ivishak. Exhibit 13 is a plot of the Ivishak production from the SN-03 well. This was completed in the Ivishak Lower Sand. The well is produced at about 1,500 barrels a day from November,. when it was initially brought on until the current February average production. Water cuts have been minimal, GORs have trended upward but are now trending downward. 2-38/SN-01 was the next well that was put on production. It was placed on production in November of 1990 at about 4,000 barrels a day. This well was completed in the Ivishak Lower Sand. I'm showing Exhibit 14, which is a plot of the Ivishak production from SN-O1. Production, about 4,040 barrels a day initially in the range of four to 5, 000 over the period that we've been producing the well. GORs near solution, trending upward slightly, now coming down again a bit. Water cuts essentially zero till December when they began to increase slightly. About a 13$ water cut in February. The latest tests on the well has it at about a 16~ water cut. Recently we restricted this well rate to 1,500 barrels a day to better balance our boardage replacement, and I'll discuss that a little bit later, when I get into the reservoir modelling aspects. The last well drilled was Sag Delta North 2. It began producing in December of 1990. Exhibit 15 is a plot of R & R COURT REPORTERS 810 N STREET, SUITE f01 509 W. 3RD AVENUE 1007 W. SRD AVENUE 1185 W. 8TH AVENUE 277-OS72 277-8548 272-7515 272-8022 ANCHORAGE. ALASKA 99501 • • ~_~ 1 2 3 4 5 6 7 8 9 10 ~, T1 12 13 14 15 16 17 18 19 20 21 22 23 24 25 r ~~ 24 production versus time. This well began producing around 3,000 barrels a day. It-has been producing in the three to 4,000 barrel a day range for the last two months. Water cuts, up to about 5%, GORs at or near solution GOR. Exhibit 16 is a plot versus time of production, water cut and GOR for the entire Sag Delta North Field. This includes a small volume that was also produced from the Alapah, as well as the Ivishak. Notice the water cuts increasing into the middle of 1990. At that time the Upper Sand in Sag Delta 9 was added, decreasing the water cuts. Then as the other wells came on, the water cuts continued to decrease with increased oil production. Gas to oil ratios have been relatively constant, at or near solution GOR. Oil rates peaked out above 12,000 barrels a day -- I believe that was in December, with rates declining slightly since then, with our current depletion plan, that I'll discuss later, and a restriction of the one well to 1,500 barrels a day. Current production rates are in the seven to 8,000-barrel a day range. During the test and delineation phase of the development, wells were drilled to targets that are within seismicly defined fault blocks, as you saw from Mr. Johnson's testimony. This allowed us to determine reservoir continuity. As a result of this orderly delineation and with exceptions to Alaska Administrative Code 20 AAC 25.055, wells were drilled on somewhat less than 80-acre spacing when you review the entire R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 8RD AVENUE 1007 W. SRD AVENUE 1185 W. 8TH AVENUE 277.OS72 277-8548 272-7515 272-8022 ANCHORAGE. ALASKA 99501 • • ~~ ~_J 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 ~~ ~J 25 reservoir development. This has provided for well placement flexibility and proper reservoir drainage. So BP is requesting that 40-acre spacing be granted in the Pool Rules to continue this flexibility for future development of the reservoir. This concludes my testimony regarding historical reservoir performance, and now I'll move on to the reservoir simulation study and our depletion planning. A full field reservoir simulation model was developed for the Ivishak Pool, Ivishak Reservoir. We used this to study the performance and to develop a depletion plan for the field to maximize economic recovery. The VIP-EXECUTIVE reservoir simulator was used to perform this study. Exhibit 17 shows the grid system that was utilized overlaid over a map of the Lower Oil Sand, which is present in the oil column. This is a 26 by 42 grid block system. It is encompassed by 200' by 200' grids within the oil bearing portion of the reservoir, slightly larger grids in the outside area representing the aquifer. .Exhibit 18 is a type log of the Sag Delta North Ivishak . It shows the layering and the porosity permeability values which were used in our reservoir simulation model. The .model was split into the three major sands; the Upper Sand and the Lower Sand, A and B member. Each of triese sanas ana memoers w~r~ divided to three layers. The bottom layer was represented by a 10' layer, which allowed us to more accurately model the water R & R COURT REPORTERS 8f0 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8543 272.7515 272-3022 ANCHORAGE. ALASKA 99501 • • r~ ~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 r 1 ~J 26 movement through the reservoir. The upper part of the sand was split into two equal layers, the remaining part above the 10', for a total of nine layers within the full field model. Porosity values used within the sands varied areally. Porosity 16 to 18~ in the Upper Sand; 200, 300 millidarcy permeability; the Lower Sand B member, 19 to 22~ porosity, up to 350 millidarcies' permeability; and the Lower Sand A went to 220 porosity, 90 to 350 millidarcies. Reservoir performance in a reservoir simulation model is history matched by providing for the simulator the oil production from the field and then using the simulator during the production history phase. to match gas oil ratio, water cut performance, and reservoir pressure performance. Once these parameters are matched, then we feel that we have an acceptable reservoir simulator, which is history matched and can be used for future predictions. Exhibit 19 is a plot of the reservoir pressure history and the pressure history match that was obtained. in the modelling of the Ivishak Reservoir. What is plotted here is reservoir pressure on the left-hand axis. On the bottom axis are days from field start, and about 550 days represents January, 1991, to put this in perspective. The .solid symbols represent actual field measured pressures. The red symbol is the pressure in the Lower Sand, the blue square is the pressure in the Upper Sand measured at Sag Delta North Number 2, and the R & R COURT REPORTERS. 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277.0572 277-8543 272-7515 272-3022 ANCHORAGE. ALASKA 99501 ~1 ~_~ 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 ~ ~ ~~ 27 black diamond is the pressure measured in the Upper Sand in Well Number 9. The hollow symbols connected by lines represent the reservoir simulator predicted pressures for the Lower Sand B member, the Lower Sand A member, the Upper Sand in Sag 9 and the Upper Sand in Sag 2 -- Sag Delta North 2. We're able to measure pressures from the reservoir simulator for both the Lower Sand B and the Lower Sand A, whereas in the field we can actually measure those pressures because the sands are in communication in the well bores. So what we have here then is a match of our measured pressures versus our reservoir simulator pressures. Looxing zirsL aL Lne Lower Sand, that's these lines through here, you see we have a fairly close history match through this time period. We're a little bit high, compared to this static pressure here, taken in SN-01, but this well was -- we don't believe this well was completely built up at the time. There was only a 15-minute stop made at the time when the pressure was still building, so there's indications that that pressure is slightly low. We've also matched the pressure in Sag 9 in the Upper Sand. Remember, that sand was completed later in the field life after the well was producing for a while. So that pressure was at initial pressure until it was completed. We matched this point then with production. That's a somewhat isolated sand within that particular fault block, so the pressure falls off very rapidly there. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8543 272.7515 272-3022 ANCHORAGE. ALASKA 99501 • • n ~~ 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 28 The Upper Sand is also completed in Sag North 2. We also got a good pressure match on that, matching this point that was measured when the well was brought on production, and then declining after that in the predictive phase. Exhibit 20 is a plot of the production data, both measured and simulated during the history match phase. Again, the horizontal axis are the days from field start-up with oil rated GOR plotted on the left-hand side, water cut plotted on the right-hand side. The solid symbols represent Sag Delta 9 oil production, Sag Delta 9 gas oil ratio. The .hollow symbol here represents the Sag Delta 9 water cut. Sag Delta 9 is the well that makes up the predominance of the reservoir history as a result of it being the only well that was producing during most of the time. So really all we're trying to match here is the Sag Delta 9 performance. Since we put in the actual production data the model data matches that accurately, of course, when we're trying to predict the gas oil ratio and the water cut trends. The gas oil ration has been at or near solution GOR. We get a little fluctuation in this part in time and also in the water cut plot as a result of adding the Upper Sand in Sag Delta 9. But the trends are very well matched. We're back down to the proper GORs here, and the upper trend here is reflected as Sag Delta 9 waters out. This performance was really expected at Sag Delta 9. The lower part of the sand is resting right at the base. of R & R COURT REPORTERS 810 N STREET, SUITE f01 509 W. 8RD AVENUE 1007 W. 8RD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8549 272-7515 272.3022 ANCHORAGE. ALASKA 98501 L_ ~ 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 • • 29 the light oil column, so we always anticipated that Sag Delta 9 would water out very rapidly, and it did after about a year and a half to two years of production. Predictive cases were undertaken to determine the production plan which would maximize economic recovery. Water injection is considered to be the most practical approach to enhance recovery in this field. There are no gas caps present. Gas injection was not considered. Because there are no gas caps, there's no need to store gas in this reservoir because gas can be stored in the Endicott Pool, which shares facilities with this field, as well as a large portion of the gas produced here. can also be utilized as fuel in the Endicott facilities. A primary depletion case was run to provide a basis for determining the benefits of water injection. We also invested various waterflood alternatives, including first the conversion of Sag 9 to water injection, the addition of the Sag North 4 Well, which, as Mr. Johnson pointed out earlier, is the well that's currently drilling. That well is being drilled primarily as a water injector. And we also looked at cases to optimize water injection volume and offtake rates to maximize economic recovery. Exhibit 21 is a table showing the recoverable oil -- is there a problem with the numbers there? COMMISSIONER SMITH: I think that said 20. MR. HELLMAN: This says 20, but I believe it is ..... R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8548 272-7515 272.3022 ANCHORAGE. ALASKA 98501 2 3 4 5 6 7 8 9 l0 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ~~ ~J • • COMMISSIONER SMITH: 21 in the book. 30 MR. HELLMAN: I believe it is actually Exhibit 21. It's 21 in the written testimony. This is a table indicating the recovery from the various sand members, the Lower Sand A member, the Lower Sand B member, and the Upper Sand for two cases; the depletion case and our range of waterflood cases. As you can see, recoveries zor aepiez.ion case aLG relatively high for depletion, a range of 27 to 39$. This is because we're not dealing here just with normal solution gas drive. There is a somewhat active aquifer that is providing pressure support to the reservoir. The aquifer extends off out to the west of the accumulation, and as a result some water influx is occurring, as evidenced by the watering out of Sag Delta 9 and some of the pressure maintenance that we've seen, and as a result we're seeing some relatively high recoveries for a depletion case. But there is oil to be gained by conducting a waterflood. With our waterflood cases you can see that our recovery factors then did range up into the 42 to 47$ range, so there was a significant increase by injecting water. As you'll see when I show the pressure plots, we would be increasing pressure within the reservoir. So through optimization of our waterflood, proper placement of wells, we feel that we can approach this upper range of recoveries for the waterflood case. Exhibit 22, which I'm showing at this time, is a Sag Delta North Production Performance Plot with production rates R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8543 272-7515 272.3022 ANCHORAGE. ALASKA 99801 • . ~~ 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 u 31 and reservoir pressure plotted against time. It includes the production history period from 1989 to the present time. It includes the reservoir pressure history, and it includes the predictions that we saw on the previous graph, as far as recovery is concerned, of a depletion case and the range that could be expected from a waterflood case. What we can see from this is that without waterflood the reservoir pressure would continue to deplete out into the 1995 time period and decline from original pressure, which was about 4,900 psi down to a pressure of about 28 -- 2,700 psi. However, with our waterflood plan, we will be begin injecting water, as we already have in Sag 9, the reservoir pressure will increase and we'll be back up near original pressure in 1992 -- near the end of 1992.. In this optimum case the Sag Delta 9 and Sag North 4 are both used as water injection wells. The rate in Sag Nortn 1 is constrained to 1,500 barrels a day to better balance reservoir voidage, and we're injecting in the range of five to 6,000 barrels a day above the water offtake requirements. So we're re-injecting all produced water and then injecting five to 6,000 barrels a day of additional water to rebuild the pressure in the reservoir. I think this shows the benefits of waterflood over natural depletion, both here and in the previous graph, considerable additional reserves as a result of waterflood implementation. R & R COURT REPORTERS 610 N STREET, SUITE 101 508 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277.8543 272-7515 272-3022 ANCHORAGE. ALASKA 99501 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 r~ L~ • • 32 Exhibit 23 is a summation of our depletion plan. We would implement a full field waterflood. We've converted Sag 9 to water injection, drilled Sag North 4 as a water injection well, balanced our injection for optimal recovery, repressure the reservoir, and not inject gas into this reservoir. BP requests that waterflood implementation be authorized within the pool rules, based on the recovery benefits that can be gained, as I've demonstrated. Attachment 1, which is attached to this testimony, is the application that we made for temporary injection for Sag Delta 9. This includes all the information that was required by Alaska Administrative Code 20 AAC 25.402. We also would request that as a result of the pressure maintenance project, which we are implementing, that an exemption for the gas oil ratio limit is set forth in 20 AAC 25.240(b) be granted. Based on the geologic and reservoir data that's available, it's apparent that wells completed with the Alapah reservoir will drain very small areas of the reservoir. They also will capture a little oil, based on the performance that we saw in the Sag North 3 Well. Our estimate is that only about 200,000 barrels can be recovered from the entire Alapah Pool. That's from the 3.7 million barrels -- I believe was the number that Mr. Johnson showed earlier. Additional drilling or dual completion of existing wells to develop the Alapah cannot be economically justified. Capturing the Alapah reserves from the R & R COURT REPORTERS 810 N STREET, SUITE f01 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8543 272-7515 272-3022 ANCHORAGE. ALASKA 99501 r~ L J 1 2 3 4 5 6 7 8 9 to 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • • 33 existing wells would provide a means for producing otherwise uneconomic reserves. In addition, the Alapah Pool will produce at high GORs relative to the Endicott Pool and the Ivishak Pool. Since all production from the Sag Delta North Reservoir shares facilities with the Endicott Pool with the Endicott. Field, there is a concern about gas handling capability. The gas capacity or the gas handling equipment will be full at Endicott from about 1993 till the end of field life, and as a result, in order to maximize oil production there will be a prioritization of wells on a GOR basis so that higher GOR wells will be constrained or shut in so that oil can be maximized. As a result of this, in the period prior to 1993, before the gas facilities are loaded, high GOR oil wells can be produced and. additional oil can be captured as a result of that. So this is another benefit to being able to comingle the Alapah with the Ivishak and perhaps produce some higher GOR early on, prior to facility loading. So in order to economically produce these reserves, BP requests that down hole commingling between the Alapah Pool and the Ivishak Pool be permitted. We don't believe that this will create waste, as this Alapah oil would not be produced under other circumstances. As far as our surveillance plans go for these pools, reservoir pressures will be measured on each well prior to regular production. Repeat formation testers are run on most wells while we log the wells, if our hole conditions permit. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 8RD AVENUE 1007 W. SRD AVENUE i1S5 W 8TH AVENUE 277-0572 277-8548 272-7515 272-3022 ANCHORAGE. ALASKA 99501 ~~ 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 u • 34 These provide much additional information -- useful information in addition to a static pressure after the well has been completed. So we would prefer at least one pressure we measured in each producing government section every year reported to the Commission. We also like the capability of using these repeat formation testers to provide the initial reservoir pressure. We would plan to run production logs. These could include flow meters, temperature logs, other industry proven downhole performance tools. Alapah reservoir contributions could also be determined, and if there were any cross-flow going on between the pools, that could be identified and steps could be taken, as I'll discuss in a moment, to eliminate that. Rate data will also be measured and reported. All fluids, injection rates, well head pressures will be measured and reported as normal, as we normally do for Endicott Field, reported by well. The Sag Delta North Pool casing and cementing requirements are identical to the Endicott Pool requirements. Wells that are drilled to the Ivishak reservoir encounter the exact same formations going down through the Ivishak as we do in our Endicott Field, drilling down to the Kekiktuk. In both fields, the Ivishak and the Kekiktuk lie just below the lower cretaceous unconformity. It would be recommended that we adopt something similar to the Endicott Pool Rule 4, as far as casing and cementing requirements, and this is shown in Exhibit 24. This is a R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8543 272-7515 272-3022 ANCHORAGE, ALASKA 99501 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 ~I 21 22 23 24 25 r ~ • 35 slightly modified Rule 4 from the Endicott Pool Rules relating to surface casing ties, which are currently being utilized and have been approved. Exhibit 25 shows a typical well bore configuration for a Sag Delta North well. All of the wells that have been completed in Sag Delta North have been completed in this manner. A WD packer has been set normally between the Ivishak Pool and. the Alapah Pool. This will allow us to gather reservoir pressure data utilizing this WD packer. If the Alapah is perforated, we can gather isolated pressure data, and if there were to be any indication of cross-flow and reserves oils from one zone to the other, a plug or two could be set in this WD packer to isolate the Alapah from the Ivishak. The development and continued production of the Sag Delta North Pool is dependent upon utilizing the Endicott facilities, which already exist for production of the Ivishak/Alapah oil. This would require commingling of Sag Delta North and Endicott crude .prior to processing and metering. Sag Delta North production would be allocated on the basis of test separator measurements of oil and gas. Water volumes W111 be determined by centrifugation of the mixed oil water samples. Each Sag Delta North well would be tested a minimum of four hours at a stabilized flow rate twice monthly. This method of allocation for royalty and tax purposes has been approved by all relevant State of Alaska agencies and also by the owners of both R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8549 272-7515 272-8022 ANCHORAGE. ALASKA 99501 • • ~~ ~_ J 2 3 4 ', 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 • 21 22 23 24 25 36 the Endicott and Sag Delta North Fields. This concludes my testimony in support of pool rules for the Sag Delta North Ivishak and Alapah Pools. This testimony has included results of laboratory analysis, model. studies, practical reservoir management considerations and operational and economic requirements. It is based on our .present understanding of these two pools. We hope that this testimony will provide the Alaska Oil and Gas Conservation Commission to draft pool rules which will satisfy the requirements of the Commission and the Working Interest Owners. We also believe that any flexibility to modify these rules administratively would be beneficial to accommodate any changes which may result from a better understanding of the reservoir as the field development progresses. CHAIRMAN JOHNSTON: Thank you very much, Mr. Hellman. Do you have any questions? CHAIRMAN DOUGLASS: Not at this time. CHAIRMAN JOHNSTON: Lonnie? COMMISSIONER SMITH: Herman, there's one thing. On page 7 you mentioned about the surface separator sample from Sag Delta 9. Would you explain a little bit why that pressure is so different than what you used in your study, ... MR. HELLMAN: Yes. COMMISSIONER SMITH: ..... your history matching? MR. HELLMAN: I don't know the exact reason why it was R & R COURT REPORTERS 8f0 N STREET, SUITE f01 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277.0572 277-8548 272-7513 272.3022 ANCHORAGE. ALASKA 99501 • • 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 37 different. There are two explanations that I think are technically logical, both of which would involve the loss of gas or misunderstanding of how much gas was actually present in the sample. Either somehow when the sample was taken some gas was lost, although it was taken under very careful conditions, There could have been some metering problems at the time. which did not allow us to accurately measure the GOR. Another possibility is that because the bottom hole pressure of the .' reservoir had depleted somewhat, the well was flowing at the time and some gas was obviously lost going into solution -- or into saturation of the reservoir; there was a gas deficiency in the oil that was being produced. But the net result is that in order to get a depressed bubble point like that there has to be a gas deficiency in the oil sampling. COMMISSIONER SMITH: Did any subsequent pressures in , that interval confirm the higher pressure -- initial pressure, or is it all reservoir simulations? MR. HELLMAN: Well, it's all reservoir simulations. There's been no additional fluid samples taken. The initial reservoir pressure is well known. That was measured on RFT tests when Sag 9 Well was originally drilled, and also when Sag 9 Well was completed. COMMISSIONER SMITH: Fine. CHAIRMAN JOHNSTON: Mr. Hellman, what are your plans for allocating production between the Alapah and the Ivishak? R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8543 272-7515 2723022 ANCHORAGE. ALASKA 99501 • ~~ ~~ 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 I 19 20 21 22 23 24 25 38 MR. HELLMAN: We have no plans to allocate. production between the two, the reason being that within the Sag Delta North Participating Area, which is proposed and being formed, the Alapah, the Ivishak are considered one entity, as far as the participating areas concerned. So the equity shares and the tract allocations will be identical for the two pools. CHAIRMAN JOHNSTON: And for purposes of reservoir surveillance you feel that the pressure monitoring program will give you an adequate determination? MR. HELLMAN: The pressure monitoring program as well as there will be production wells running from time to time to determine what fluids are going, but there will be no direct attempt to maintain an allocation and a measurement of the volumes on a monthly basis or anything like that. We will take spot checks to see what's going on. CHAIRMAN JOHNSTON: Your current waterflood plans call for two wells being drilled, I believe. Do you have any evidence to suggest that the faults that we see crossing this area are sealing faults? MR. HELLMAN: We know that -- well, first our waterflood plans as they are right now really only require the drilling of one well. Sag 9 has been converted. We're planning on drilling Sag North 4. The 5 Well that was shown on the earlier maps is not planned unless conditions change considerably from what we presented. The reservoir pressure data that we gathered as we R & R COURT REPORTERS 8f0 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1185 W. 8TH AVENUE 277-0572 277.8548 272-7515 272-3022 ANCHORAGE, ALASKA 99501 ~~ i 2 3 4 5 6 7 8 9 10 11 12 • ~i 14 15 16 17 18 19 20 21 22 i 23 24 25 • 39 drilled the wells, both from initial statics and also from RFTs indicated that there is generally good communication across these faults. There is not juxtaposition from sand to sand completely across .the faults because the faults do have some fairly large throws on them. But somewhere along the faults there is communication from the sand to the other sand because the reservoir pressures are very common across the -- particularly the Lower Sand. This was seen in original measure pressures. CHAIRMAN JOHNSTON: You indicated that at least on one of the wells, I believe, that you felt that a rate restriction would be appropriate at 1,500 barrels per day. Do you feel that II this type of rate restriction would apply to the entire pool? MR. HELLMAN: Well, the rate restriction does apply to the entire pool in that in restricting .that particular well to 1,500 barrels a day we're restricting the pool .rate, and that allows us to offset voidage with variant planned injection. We're injecting about 8,000 barrels a day into the Sag 9 Well, and our current offtake is around 8, 000 barrels a day. However, the Sag North 2 Well is not really receiving pressure support from Sag 9 Well because the Sag North 2 Well is completed in the Upper Sand. And based on the measurements that we have -- we believe in our reservoir simulation, we believe there's enough natural influx to provide pressure support for that well, and _ we'll continue to monitor that with reservoir pressure data. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 8RD AVENUE ~ 1007 W. 8RD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8548 272.7515 272.8022 ANCHORAGE. ALASKA 99501 ~~ ~~ 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~~ • • 40 But we feel that the restriction we made on Sag North 1 is sufficient to bring us into balance from a voidage replacement standpoint. CHAIRMAN JOHNSTON: So what kind of restriction would that mean for the entire reservoir? MR. HELLMAN: That would bring the entire reservoir down to where we are right now, which is about 8,000 to 8,500 barrels a day is what it's producing at currently. CHAIRMAN JOHNSTON: I have some concerns about the areal extent of the pool extending beyond the boundary of the -- or the disputed boundary between state and federal acreage. How much of the reservoir, in your opinion, would extend into that area? MR. HELLMAN: There's a possibility that there is a small volume of oil that would extend over there. It lies in the Upper Sand. It could well be isolated by that fault. The is juxtaposition on that fault. The reservoir is very thin; it's a thin column of oil, 10, 15 feet thick underlain by water. It would not be exploitable from the Endicott Island in that it's pretty much at the limit of our drilling capabilities. We drilled a well at Endicott that's about that length, but it was quite costly and very troublesome. We certainly couldn't -- nobody could drive for five or 10 feet of oil in that area. Also in our simulation studies, we did include some oil out there, and there was no drainage of oil from that area. It was R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277-8548 272-7515 272-3022 ANCHORAGE. ALASKA 99501 r~ ~~ 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 • • 41 all isolated by the fault, so it didn't even provide a pressure support for the volume studies. CHAIRMAN JOHNSTON: At your maximum reach how far would you be away from that boundary? MR. HELLMAN: I believe at the maximum reach we could come just about to the lease line, would be about as close as we'd come. It would be very difficult if impossible to drill past that lease line. COMMISSIONER SMITH: I have another question here. Herman, in relation to your previous answers there about the rate of seven to 8,000 barrels a day, do you expect it to continue at that sort of rate even after the re-pressurization from Number 9? MR. HELLMAN: No, I don't. If I could refer back to COMMISSIONER SMITH: Right. MR. HELLMAN: ..... this exhibit -- and I don't remember the number. COMMISSIONER SMITH: Yes, I understand. MR. HELLMAN: But that particular exhibit indicates the decline that we see. This is a result -- even though pressure is increasing the water cuts are continuing to qo up on the wells, the capability of the wells to flow is declining somewhat, so the rates will continue to drop off. COMMISSIONER SMITH: And this simulation was a planned R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1185 W. 8TH AVENUE 277-0572 277.8543 272.7515 272-3022 ANCHORAGE. ALASKA 99501 • • r~ L~ 1 2 3 4 5 6 7 8 9 10 I1 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ~_~ 42 injection in Number 4 as well? it MR. HELLMAN: This has injection in both wells, and it II also included gas lift to maximize recovery from the reservoir. COMMISSIONER SMITH: But it was the same zone in both wells, same pool? MR. HELLMAN: Yes. REPORTER: That was Exhibit 22. MR. HELLMAN: 22, okay. COMMISSIONER SMITH: Well, as I recall, to summarize your reservoir data, there's definitely two different pools that are separated from your data, but there are very similar characteristics in pressure and reservoir characteristics being close together; is that correct? MR. HELLMAN: That's correct. The pools are separate, as witnessed by the variation in oil water .contacts. The pressure data -- we're on a normal pressure gradient so there's a normal hydrostatic gradient, so the pressure data would probably indicate a fairly uniform gradient between the two pools with depth. But there are significantly different oil water contacts between the two pools, and also a difference in the crude gravity between the two. pools. It's definitely a different type of crude . But they are very close . They are only about 100 feet apart -- I believe 100 to 200 feet separates them in the shell barrier. COMMISSIONER SMITH: Obviously you don't consider it a R & R COURT REPORTERS 8f0 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE .1135 W. 8TH AVENUE 277.OS72 277.8548 272-7515 272-3022 ANCHORAGE. ALASKA 99501 • r~ ~_~ 1 2 3 4 5 6 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I • 43 problem to comingle them and produce them together in any way. MR. HELLMAN: We don't consider it a problem; we consider it to be the only method that we're going to get any recovery at all from the Alapah zone. There's just not sufficient reserves there to justify the cost of drilling wells to it, making dual completions; there would just be no other way to recover it. COMMISSIONER SMITH: Fine. CHAIRMAN JOHNSTON: Do you have any plans for doing any FOR operations in the Alapah? MR. HELLMAN: In the Alapah? No, we don't. We don't believe there would be sufficient reserves there. CHAIRMAN JOHNSTON: How many more wells do you anticipate drilling into the reservoir? MR. HELLMAN: If the well that we're currently drilling, Sag North 04, comes in as anticipated., there's a very high likelihood that will be the last well we would drill. Were we to see something quite different with more oil, then we would reassess our development plan and there might be an additional well justified. COMMISSIONER SMITH: Herman, do you recall the cumulative produced from Number 9? MR. HELLMAN: I believe it was 1.5 million barrels. COMMISSIONER SMITH: 1.5 million barrels before it watered out? R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 8RD AVENUE 1007 W. 8RD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8548 272-7515 272-8022 - ANCHORAGE. ALASKA 99501 r ~~ 1 2 3 4 5 6 7I 8' 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • • 44 MR. HELLMAN: I believe that's correct. It is in the testimony. COMMISSIONER SMITH: Okay. MR. HELLMAN: I think it is 1.5 million barrels though. COMMISSIONER SMITH: You don't expect this to be representative of the other wells though; with the plans you have you expect to recover a total of about 17 million. Is that what I remember? MR. HELLMAN: No, that was the oil in place. The total recoverable is -going to be about 6-1/2, I believe, at the maximum. COMMISSIONER SMITH: Okay. MR. HELLMAN: So we would expect something on that order per well recoverable. It's going to be something around a 1.5 million barrels to 2 million barrels probably. COMMISSIONER SMITH: Fine. I don't have anything further. CHAIRMAN JOHNSTON: Any more questions? COMMISSIONER SMITH: Do you want to take a break and see if there are questions from the audience? CHAIRMAN JOHNSTON: Yes. I think at this particular time I'd like to take a short recess, 10 minutes. The time is approximately 10:24. Thank you. (Off record - 10:24 a.m.) (On record - 10:34 a.m.) R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 8RD AVENUE 1007 W. SRD AVENUE 1185 W. 8TH AVENUE 277-0572 277-8548 272.7515 272-3022 ANCHORAGE. ALASKA 99501 • • 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 • • 45 CHAIRMAN JOHNSTON: The. time is approximately 10:34. We had just concluded hearing the testimony of Mr. Herman Hellman. He had responded to a few questions that the Commission had. At this time the Commission has no further questions of the applicant. I would like to ask if there are any members of the audience that would like to make any oral statements or provide any written comments at this time. (Pause) There being none, are there any questions from the audience that have been written down? (Pause) There being none, I would like to note that the time is approximately 10:35. This hearing is now adjourned. Thank you. (Off record - 10:35 a.m.) * * * * * * * * * * * * * END OF PROCEEDING * * * * * * * * * * * * * R & R COURT REPORTERS 8f0 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 1135 W. 8TH AVENUE 277-0572 277.8543 272.7515 272-9022 ANCHORAGE. ALASKA 99501 r~ L~ 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 ~I 21 ~' 22 23 24 25 r L_~ • C E R T I F I C A T • 46 I, Laurel "Lou" Kehler, Reporter for R & R Court Reporters, Inc., do hereby certify: THAT the foregoing pages numbered 02 through 45 contain a full, true and correct proceedings. in the Alaska Oil and Gas Conservation Commission Public Hearing, transcribed by me to the best of my knowledge and ability from the cassette tape identified as follows: Tape 16126 Logs 0254 - 2991 DATED at Anchorage, Alaska this 20th day of March, 1991. SIGNED AND CERTIFIED TO BY: REPORTER Notary Public in and for Alaska My commission expires 10/20/94 R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 9RD AVENUE 1007 W. 9RD AVENUE 1185 W. 8TH AVENUE 277-0572 - 277.8548 272-7515 272.9022 ANCHORAGE. ALASKA 99501 ~ r' • :~ :~ h f.7~-,.~ ,. .: ., 510 CE~T~- NORTI~ TESTIMONY F©R ~~~~ .~ POt~L RULES M,~RCI~ 12 19.91 ,,~ ..~ . ,~. .~ ~._ ~~ y_ ~. ^: `~ ~ .~ -~ y RE~~I' MAR 2 21991 Afasica OiI & Gas Cons. GQm~tssl~ ~~~: ~ncfioraga~ • '• • TABLE OF CONTENTS SECTION 1. Introduction 2. Reservoir Description 3. Reservoir Pertormance 4. Surveillance Pians 5. Well Planning 5. Facility Utilization 6. Conclusion • PAGE 1 2 6' 11 11 12 12 i~ • I~ . In r n r. Chairman, Members of the Commission, Ladies and Gentlemen, my name i .Bruce J. Policky ,Manager, Endicott Reservoir and Production Engineering or BP Exploration (Alaska).The purpose of this hearing is to provide testimony in support of establishment of pool rules for the Duck Island Unit Ivishak and lapah accumulations. We are officially requesting that these accumulations be ailed the Sag Delta North Ivishak Pool and the Sag Delta North Alapah Pool. he boundaries of both Pools are encompassed by the proposed Sag Delta orth Participating Area for the Sag Delta North Reservoir pursuant to the Duck stand Unit Agreement and are all within the geographic boundaries of the State f Alaska and are .therefore subject to the jurisdiction of the Alaska Oil and Gas onservation Commission. he testimony will enable the Commission to establish pool rules applicable to nth Pools which will allow economic development of the resources within the ag Delta North Field. A production test has been underway with the ~thorization of the Commission since July 31,1989. Currently 3 wells are ~oducing, one well is injecting water and a fifth well is being drilled.. BP xploration requests the Commission to approve several concepts which are ~nsidered necessary for economic development of the Pool. These are: 1) Well spacing of 40 acres to allow well placement for maximum oil recovery. 2) Initiation of water injection for enhanced oil recovery. 3) Surface commingling of production from the. Sag Delta North Ivishak and Alapah Pools with the Endicott Pool 4} Down hole commingling of the Alapah Pool with the Ivishak Poo! to allow for maximizing economic recovery fromthe Alapah Pool, i• 1 i ~ BP Exploration will make the presentation of the testimony on behalf of the other Working Interest Owners which include Cook Inlet Region, Incorporated, Nana Regional Corporation and Doyon Limited. Within the testimony, we will discuss our present understanding of the reservoir description, reservoir performance history, predictions of future reservoir pertormance and the plan of field development. Mr. Chairman,.members of the Alaska Oil and Gas Conservation Commission, ladies and gentleman, my name is Samuel R. Johnson and I will be presenting testimony on features of the reservoir description of the.. Sag Delta North Field on behalf of BP Exploration (Alaska) and the other Sag Delta North working interest owners. I have received a Bachelor of Science in Geology from the. University of Utah in 1978.. I have 13 years industry experience and for the last two and one half years have been working development of the Endicott Field. I am .currently lead geologist in reservoir description and recently, have been responsible for geological analysis of the Sag Delta North Field. My testimony will begin with a brief geographic description of the Sag Delta North Field, continue with a review, of the stratigraphy petrophysical properties, structural. setting and conclude with the volumetric estimates of the hydrocarbons in place.. Exhibit 1 is a location map for the Sag Delta North Field showing the .extent of the exploitable hydrocarbon. bearing reservoir, bounding faults, and existing wells. used for field delineation. Relationship. to the Endicott Field and the proposed participation area outline for which the field rules for the Sag Delta North Reservoir would apply are also shown. The Sag Delta North Field underlies state leases located several miles offshore. The field is adjacent to the northern most limit of the hydrocarbon bearing Kekiktuk Formation. of the Endicott Field. The Sag Delta North Field, a truncated anticlinal structure feature, contains hydrocarbons reservoired in the 2 s • Triassic Ivishak Formation and the Carboniferous Alapah Formation. Hydrocarbon bearing zones encompass approximately 380 acres. The delineation of the Sag Delta North Reservoir is based on four wells: 5-03/SD-09, 2-38/SN-01, 1-17/SN-02 and 2-32/SN-03. The data from these wells consist of well logs used to determine petrophysical parameters, Repeat Formation Tests (RFT's), and core analysis from a portion of the reservoir from the SD-09 well. Structural control and fault identification are based on the interpretation of the Endicott 3D seismic survey. Alapah .Formation contains four correlatable dolomitic porosity zones.. A persistent gamma ray marker at the base of Alapah porosity Zone 1 provides the basis for the correlation. .The interpreted depositional environments and dominant lithologies are summarized on Exhibit 3. The interpretations are based. upon core descriptions for the Alapah Formations and the Lower sand of the Ivishak. .Log character is used to interpret the Middle shale and Upper sand of the Ivishak. The shallowing upward carbonate cycles within the Alapah are reflected in the decreasing gamma count in each cycle. The porosity zones are.. usually- confined to the upper section of each cycle. These carbonate cycles are unconformably overlain by the marine shales of the Kavik Formation. The Ivishak Oil Pool's hydrocarbons are reservoired in correlatable sandstones .within the Ivishak. The Alapah Oil Pool's hydrocarbons are reservoired in correlatable porosity zones within carbonates in the Alapah Formation.. Exhibit. 2 illustrates the formation and zonal nomenclature based on the SD-09 well logs. The Ivishak Formation has been subdivided into an Upper sand, Middle shale and Lower sand. This zonation persists throughout the Sag Delta North Field.. The Lower sand of the Ivishak Formation has been further subdivided into an A and B member, this subdivision. is based upon differing petrophysical properties. Lithology changes are marked at the contacts of the Kavik Formation with the underlying carbonates and the overlying sandstones. The ~ • • I• 'rogradation of a siiisiclastic shoreline into the Kavik seas deposited the Lower sandstone of the Ivishak Formation. The Lower sandstone shows minor nterfingering with the Kavik. Shale laminae in the Lower sandstone rapidly iecrease upward reflecting the higher energy. deposition in the shoreface system. The higher porosity and less shaley "B" member of the Lower sand nay have been deposited by distributary or fluvial channels. The. depositional -nvironment of the overlying Middle shale and the Upper sand is somewhat speculative due to the absence of core material. The Middle shale is present in tll of the. wells and while relatively closely spaced, is none the less persistent. the contact between the Upper sand with the Middle shale appears gradational ~r interfingering and therefore may reflect a similar depositional environment as he Lower sand. However, minor amounts of pebble-sized grains and higher percentages of chert grains occur in sample cuttings in the Upper sand perhaps eflecting a fluvial environment. ag Delta North reservoir's limits are defined by faults and. the truncation of the reservoir by unconformities. Exhibit 4, a structure map on top of the Lower sand member of the Ivishak, illustrates the field bounding fault(s). The southern most ault, a splay of the Niakuk, separates Sag Delta North from the Endicott Field. here appears to .have been strike slip movement along the faults as evidenced by the offset off the anticlinal crest. The eastern limb of the anticline is truncated by a lower Cretaceous unconformity. Progressively. older sediments of the Ivishak and Alapah are truncated to the east. Shales deposited upon regional unconformities provide the trap for the hydrocarbons. Correlations based on the Sag Delta North well control show truncation of sediments beneath the Kavik shales and the HRZ shales as shown in the cross section Exhibit 5. Regional correlations form the basis for the unconformity. at the base of the Sfiublik. The upper sand. member is truncated by a lower Cretaceous unconformity. in the wells SN-03 and. SN-01. In addition, the Alapah Porosity Zone 4 and the overlying carbonates are truncated by a pre-Kavik unconformity. This surface was subsequently folded and faulted during the. tectonic event(s) which produced the anticlinal. structure. 4 • • C7 Petrophysical parameters have been calculated from log derived values for each of the hydrocarbon bearing sequences. A summary ofi these values are shown in Exhibit 6. Algorithms used for the calculations follow practices established for the Ivishak reservoir at the nearby Prudhoe Bay Field and for the Lisburne reservoir at the Lisburne Field. Applying porosity and gamma ray cutoffs to each hydrocarbon zone yield net to gross values. Average porosity and water saturation values are then calculated for the net pay for each interval. iividual well averages and averages of well porosity, net to gross and 1 - Sw ire multiplied to acre-ft and then divided by formation volume factor to timate oil in place. The acre-ft calculations were based on isopachs of net y above the base light oiL A common oil water contact was used for the shak Oil Pool. SN-02 defines the base of light oif in the Ivishak at 10112' >VSS. An immobile tar mat separates the light oil from the aquifer. RFT assures indicate pressure communication between .the Ivishak's light oil lumn and the aquifer beneath the tar mat. Unique oil water contacts were used for each porosity zone in the. Alapah Oil Pool. Oil water contacts in the Alapah porosity zones have. been .encountered at 10177, 10223' AND 10309' TVDSS. RFT data from 5N-02, the third development well drilled., indicated original formation pressures in the Alapah porosity zones in contrast to below original reservoir pressures within the lvishak's aquifer and light oil column. In addition, the oil reservoired in the Alapah has a higher API gravity than oil reservoired in the Ivishak. These data support the division of the Sag Delta North Reservoir into two separate pools. I• The distribution of stock tank original oil in place (STOOIP) by zone are shown on Exhibit 7. The areal extent of the hydrocarbon bearing Ivishak sandstones, the Ivishak Oil Pool, is shown on Exhibit 8. Primary controls of the Ivishak Oil.. Pool's areal extent are the subsea position of the base light oil and the pre-HRZ unconformity. .The areal extent of the hydrocarbon bearing Alapah. porosity. zones, the Alapah Oil Pool, are shown on Exhibit 9. `Primary controls of the Alapah Oil Pool's areal extent`are the oil water contacts and the pre-Kavik unconformity. Uncertainties in the estimates .include; non-planar oil water 5 • • contact or variations by fiault block, variability in the thickness of the tar mat, and reservoir quality away from well control. This concludes my portion of the testimony. The following testimony by Herman Hellman will cover the reservoir engineering aspects and expected performance. 3. Reservoir Performance Mr. Chairman,. Members of the Alaska Oil and Gas Conservation Commission, ladies. and gentlemen, my name is Herman L. Hellman .and I will be presenting testimony-on the reservoir engineering and development. considerations for the Sag Delta North reservoir on behalf of BP Exploration and the other Working Interest Owners. I received a Bachelor of Science in Aerospace Engineering from the University of Texas in 1966. I have 25 years of petroleum industry experience relating to field development and reservoir engineering studies. I have been .employed by BP Exploration since November 1982 working on development of Alaskan oil fields. I have been assigned to the Sag. Delta North Field since the discovery weN test in March 1989. My testimony will consist of: the completion of the reservoir description; an overview of past reservoir performance; review of the reservoir studies describing the depletion mechanisms; discussion of performance predictions,. surveillance plans and other development issues. To begin my testimony l will complete our reservoir description with a discussion of permeability, relative permeability and fluid properties. The discovery well, SD-09 is the only well in the field that has been cored. The lower sand A and B of the Ivishak formation and the Alapah formation were conventionally cored in December 1981. Permeability ir; the Ivishak. ranges from about 2 and to over. 600 and with an arithmetic average of 124 md. Alapah permeabilities are generally less than 5 and except for a couple of 5 foot streaks with permeabilities of 100 to 200 md. Permeability data used in reservoir simulation studies will be shown later. • 6 • • • • • ~etative permeability data is not available for the Sag Delta North .Ivishak or ~lapah. Pseudo oil water and gas oil relative permeability data developed for he Endicott Subzone 3A was used for Ivishak reservoir modelling studies The ail water endpoints were adjusted to Ivishak initial water saturations of 25% in he light oil column and 40% in the oil-water transition zone and a residual oil to eater of 20%. Gas oil curves were adjusted to a residual to gas. of 35%°. urtace separator samples were collected from SD-09 and laboratory analysis fielded an oil bubble point of 3912 psi and initial solution GOR of 672 scf/bbl. Je were not able to obtain a history match in reservoir simulation studies using pis data. The data shown in Exhibit 10, which is similar to Endicott fluid data ave the best match in reservoir model history matching. Although no gas cap is resent the bubble point is very. near original pressure. No laboratory analysis f the. Alapah crude has been obtained. API gravity was measured at 280.290 wring the testing of SN-03 and indicates that the crude is different from the ~ishak crude. I will continue my testimony with a discussion of the past pertormance of the reservoir during the test period. Exhibit 11 is a .plot. of the oil production, water gut and GOR vs time for the Ivishak reservoir. Well SD-09 was brought on production in July 1989 at an oil rate of about 2000 b/d, a GOR of about 700 scf/bbl and no water. The well was initially completed in the Lower Sand B member. The .well began producing small volumes of water in November 1989. In July 1990 the Upper Sand was perforated. The well continued. to produce. with increasing water cuts. and relatively stable GOR until the well watered out in February 1991. The well was. converted to-water injection on March 2 under a temporary injection order and is .injecting 7000 - 8000 bwpd. SD-09 produced about 1.5 mmstb of oil prior to watering out. The bottom of the Ivishak sand in the well is located at the oil water contact and its water cut performance is as expected. Reservoir pressure performance will be discussed later in my testimony concerning reservoir modelling. 7 f. • • Well 2-32/SN-03 was drilled and completed in September 1990 and began producing from the Alapah reservoir porosity zone 3 in October. Exhibit 12 shows the well production rate at 30 minute increments for 2.5 days while flowing to the test separator. The wells oil rate declined from 3300 bopd to 800 bopd while the GOR increased from 600 scf/bbl to 5800 scf/bbl. During a 24 day test the well produced 12,360 barrels of oil and the reservoir pressure declined from an original pressure of about 4900 psi to 3370 psi measured after a shut in of 3 days. A plug was then set in an isolation packer and the well was completed in the Ivishak Lower Sand. As shown in Exhibit 13 the well has since been producing at 1100 to 1700 bopd with minimal water.. - 2-38/SN-01 was drilled and placed on production in November 1990 producing from the Ivishak Lower Sand. As can be seen in Exhibit 14 the well has been producing 4000 to 5000 bopd and the water cut has gradually increased. The most recent production test indicated a 16% water cut.. Recently the well rate was restricted to 1500 bopd as part of our depletion plan which I will discuss later. Well 1-17/SN-02 is the last well drilled and it began production in December 1990 from the Lower Sand A member and the Upper Sand. As seen in Exhibit 15 this well is producing about 5000 bopd with a 6% watercut and low GOR. Exhibit 16 is a plot showing total Sag Delta North oil production, water cut and GOR during the test period. Through February 1991 2.5 mmstb have been. produced. Note the oil rate reduction in March due to the SN-01 rate reduction. During the test and delineation phase of the development, wells were drilled to targets within seismicly defined fault blocks. This allowed determination of reservoir continuity. As a result of this orderly delineation with exceptions. to Alaska Administrative Code 20 AAC 25.055, wells were drilled on less than 80 acre spacing when viewing the entire reservoir development. This has. provided well placement flexibility and proper reservoir drainage. BP requests that 40 acre spacing be granted in the Pool Rules to continue this flexibility to develop the reservoir. 8 • ~ n U This concludes my testimony regarding the historical .reservoir performance and I will now move on to the reservoir simulation study and the depletion plan. A fullfield reservoir simulation model was developed to study the performance and to develop a depletion plan for the field to maximize economic recovery. The VIP-EXECUTIVE reservoir simulator was used to .perform the study. i• i• A 26 by 42 grid block system was used to model the Ivishak formation. Exhibit 17 shows the grid system superimposed on the net pay map of the Lower Sand. Grid blocks within the oil column are 200' by 200' with larger blocks. representing the aquifer. Exhibit 18 is a type log of the Ivishak sand indicating the layering and the range of porosity and permeability used in the model. Each of the Upper,Lower Sand A and Lower Sand B members were divided into 3 layers. The bottom layer of each member was 10' thick with the remainder divided equally between the 2 upper layers. The 10' thick bottom layer provided for more accurate modelling of the waterfront advance. Reservoir performance was history matched by providing the model with oil production data and matching model predicted reservoir pressure, water production and GOR performance with actual field performance. Exhibit 19 is a .plot of the reservoir simulator. derived pressures and actual field measured .pressures vs. days since field startup. January 1, 1991: is represented by 550 days in this exhibit. The filled symbols represent measured pressures and the connected unfilled symbols reflect simulator predicted pressures. Reservoir pressure in both the Upper and Lower Sands have been matched. Exhibit 20 is a plot of simulator generated oil, GOR and watercut and actual data vs days since production start. The majority of the reservoir history is SD-09 production. Symbols labeled as S9 represent actual measured data from SD-09 and the symbols labeled with an "M" represent .model data. This plot shows a good match for this well. Other wells early pertormance was also 9 • • • • • invited. by the model but they are not presented here because the data is very. Predictive runs. were then undertaken. to determine the production plan which would maximize economic recovery. Water injection is considered to be the most practical approach to enhanced recovery. Gas injection was not considered due to the lack of initial gas caps and no need to store gas in the reservoir because gas can be used as fuel and injected into the Endicott pool A primary depletion case was run to provide a basis for determining the .benefits of water injection. Waterflood alternatives investigated included conversion of SD-09 to water. injection, the drilling of SN-04 as an additional water injector and cases to optimize water injection volumes and offtake rates. Exhibit 21 is a table showing the recoverable oil and recovery factors for .primary depletion and waterflood. The preferred depletion plan requires water injection into SD-09 and drilling SN-04 as a water injection well. Well SN-01 is constrained to 1500 bopd to better balance voidage and 5000 - 6000 b/d of water is injected in addition to returning produced water. This plan will result in recoveries on the high side of the waterflood range shown in Exhibit 21. Oil rates and reservoir pressure response as a result of this plan .are shown in Exhibit 22. Oil rates. decline as water cuts increase. but reservoir pressure is restored to near original in 1992. The benefits of waterflood over natural depletion are seen in thin plot. Exhibit 23 summarizes the preferred. Ivishak depletion plan. BP .requests that waterflood implementation be authorized within the pool rules based on the recovery benefits to be gained. Attachment 1 to this testimony is the. application for .temporary injection authority for SD-09 which includes all information required by Alaska Administrative.Code 20 AAC 25.402. BP also requests, as a result of the pressure maintenance project proposed, an exemption to the gas-oil ratio limit as set forth in 20 AAC 25.240(b). Based on the geologic and .reservoir data available,. it is apparent that wells completed. within the Alapah .reservoir will drain very. small areas around the 10 • '• i• • • well and capture little oil. BP estimates only about 200 mstb could be recovered from the entire Alapah pool Additional drilling or dual completions in existing wells to develop the Alapah only can not be economically justified. Capturing Alapah reserves from the. existing wells provides a means of producing otherwise uneconomic reserves. In addition the Alapah Pool will produce at high GOR's relative to the Endicott Pool and Ivishak Pool. Gas processing facilities at Endicott will be full from about 1993 until near the end of field life and high GOR oil will be restricted in order to maximize oil throughput. As a result early production of the Alapah will benefit recovery. In order to economically produce these reserves BP is .requesting that down hole commingling between the Alapah Pool and the Ivishak Pool be permitted. This will not create waste as the Alapah would not be produced otherwise. d determined and any. crossflow between pools can be identified. Rate data including producing rates of .all fluids, injection rates, and well. head pressures will also be measured and recorded. and reported by well Reservoir pressures will be measured on each well prior to regular pro uction. Repeat formation testers are run .while logging most wells if hole conditions permit. These provide much useful information and can be used to provide pressure prior to production. At least one pressure will be measured in each producing government section every year and reported to the Commission. Production logs which may. include flowmeters, temperature logs or other industry proven downhole diagnostic tools wiH be run to determine reservoir performance parameters. Alapah reservoir contributions can also be 5. Well. Planning The Sag Delta North Pool casing and cementing requirements are identical to the. Endicott Pool requirements. Wells drilled to the Ivishak reservoir encounter the exact same formations prior to entering the pay zone as the Endicott wells. It 11 • • • • i• is recommended that Endicott Pool Rule 4 or similar be adopted for the Casing and Cementing Requirements .with modification as shown in Exhibit 24. Exhibit 25 shows a typical well configuration for Sag Delta North. A WD packer has been placed in all producing wells between the Alapah and the Ivishak to allow individual pressure surveys and to provide isolation of the Alapah if required. Crossflow if occuring can be eliminated by placing retrievable plugs in the isolation packers. 6. Facility Utilization Development and continued production of the Sag Delta. North Pool is dependent upon utilizing the existing production and injection facilities of the Endicott Field. This requires commingling of Sag Delta North and Endicott .crude prior to processing and metering. Sag Delta North production will be allocated on the basis of test separator measurements of oil and gas. Water volumes will be determined by centrifugation of separator samples. Each Sag .Delta North well will be tested at least twice. monthly for a minimum of 4 hours at a stabilized flow rate. This method of allocation for royalty and tax purposes has .been approved by all relevant State of Alaska agencies and by the owners of both the Endicott and Sag Delta North Pools. 7. Conclusion -This concludes testimony in support of pool rules for the Sag Delta North. Ivishak and Alapah Pools. The testimony has included results of laboratory analysis, model studies, practical reservoir .management considerations and operational and economic requirements.. It has been. based on our present knowledge of the reservoir. We hope that the testimony. provided today will allow the Alaska Oil and Gas Conservation Commission to draft pool rules which satisfy the requirements of the Commission and the Working Interest Owners. Flexibility to modify the pool rules administratively would be beneficial to accommodate any changes which. 12 may result from a better understanding of the reservoir as the field development progresses. [7 i• • ~~ • SAG DELTA NORTH 7~ Q 4'' r :` ~~~' ~,, ~- 3~Z$Z ~ ` ' 0~ P I, ~aJ~ti 0 ~' '~~`6~~.a~J~ ~ O aL ~ 0 P O . O O .o 0 0 (M.n., Q 0 ~~; o ~ o . ~ o . o o ~ . ~. .o. o .. , __ .~ o _ a O ndlcott Wells 1 mile O ag De1ta North Wells .~ ~ ~f ~; ~, roposed Sag Deita North Wells ., ~~ ~~ ~~~ I_ISr~uRl~r Alapalt Alapah Porosity Zones - N W 1~ -- ~ - v~, .-f: ~i ~ - - - - !_ _I_l_ __- _ - ~_--._ i-~--1-I- -- - - -~ - _ _I_ s I i . ~ --- Kavik u SADI_EROCIIIT Ivfshak ~ lower middle upper o0 sand shale sand r y ~ a~ T. `-~i ~ oNl N i i ~ N N U ~ +p ~ N O N p yNj _.___ O O O O O ~ W lJ O O OQQ !~ O N N ~ Q t ~ - ~-- - .I S - - -- -_ .. .. ~'~_~ Y -- ---- - --- - - .--1....--~--_-- ----- - --- - _~._-_. lr. t, .. -; ..- =i=.rte=-._.~? 1-1-! !--lu_~_ _ ----- --- - (If-_ _I_--_ _ _ ~ -1-!- -1-~ - I - - ~- I I I_ I~t ~ _{ - I- -- i~ , ~ ~ ,, ;~~~' ;~ ~ ;~~~ I ~~ - lad -~- r~ _ ; , ,~ .:._ ._ X Alapah Oll Pool - a r-r ~~ «• ONp O O O O O b ~ b ~ O O Il~llr~~l~l Ivishak Oil Pool _'l~LLLL~I! -~ • N T _-1 ~t ~ t I'. a ~ • ~-- - ,y - ~ ~- ~ - - ~ : ~ w o _ 3 , e ~ O p ~ cu ~ ~ ~ - O (fI Z O _ _ _ ~ Ji _ ~ ~~ ~.. _ ~ : - 3 Q [D ' _ __ _ - - - -~ ~ ~ I; ~ W ,~~ I . - _ __ _ _~ ~ ~ ~ ~ m _ _- -- =~ -i- - -_ ~ I = s s - yl - - -{ _ ~ - • r SAG DELTA NORTH FIELD STRATIGRAPHY AND RESERVOIR ZONATION UPPER SAND MIDDLE SHALE IVISHAK "B"MEMBER LOWER SAND "A"MEMBER KAVIK PRIMARILY SANDSTONE MINOR SILTSTONE OR MUDSTONE MUDSTONE WITH MINOR SILTSTONE PRIMARILY SANDSTONE WITH MINOR MUDSTONE SANDSTONE MUDSTONE MARINE LISBURNE ALAPAH DOLOMITES AND LIMESTONES CYCLICAL SHALLOWING UPWARD INTERTIDAL SHOALS EXHIBIT 3 • FLUVIAL OR DISTRIBUTARY CHANNEL OR POSSIBLY SHOREFACE FLOODPLAIN, BAYFILL OR .VERY SHALLOW MARINE MARINE UPPER SHOREFACE OR FLUVIAUDISTRIBUTARY CHANNEL MARINE SHOREFACE VERY SHALLOW WATER • • ~~ .'y~ ~\ \ \'dJ ~.ri> ~~ ~ ~'i~ ~~\\ i0d J ~~~ ~ V i O ~. ., \ ~~\ dy~J \ ~O 5. ~ ~ `~ S ~~ ~~ < , ~ `~~~ ~~~ \ ~~sao'~ /~J~ ~~ ~ (/ \ ~~\\\\ 09~\ ~0. ~ O > \ ~ O /Q ~ h, ,~~~~~~efo roe o Y ' ~ `~~~.~~ ~~~a \~ ~o'~c ~~\~ ~;~ ~~ ~;~ ~~ ~, • r SAG DELTA NORTH STRUCTURE MAP ON THE IVISHAK LOWER SAND CONTOUR INTERVAL = 20 FEET SCALE: 1 "= 1000' _. -d Op~4 0 ~ :- ryq~ ~~ap~ p S ° j ~ ~~:. ~NO ~ ° ~d $ (j \ ~ ° U ~J r0 ~8 i \ \ \ Line of cross section. (EXHIBIT 5) EXHIBIT 4 Go t '' o l ~~~, o~„ `,fit ~. U~11 ~~~ ~\~ ~ ~+ • • ~~ ~ t _~ r t - ;. A•• ~ Ii . n:i~.'. 1 ' ,t ~~lra..y}• ra! ~ !: 'l ~~ !Sts _u. r- ~ ~ >•j , ::i 1 ,~ If') •. ~~+ R r ~ ~.wN 1 ~ J11 r ' :: .. ~ d:' :: ~ ~ z rt. ^s ~ I~ I t n ~ L a 1 uttltirttrrttt t ~~ +,:r•:1•+. •ttt ;fit to +i. • ~ rr Ir r•tn• r r rltr ~ r. , r y,lt r .I,il a.~:i:. .... ...._. ...~ tt 1 ~ t. :.:...,..... ,t ..:.. , ...: .- v =}u fjr • t r turn nt r•tr. ~:f::n.t,m. ..r.;p......t..,..~4.: ul s"t~rt r r n.+r•r nrf..},.{.. n ~.....t.u~ (A Q r: ..:' ' .~ ...~ t n a nln! n dry ~ 'y - W .. ..:.. ...».. ....... ... _.... _. ...... .... ... .:. .: .•.. ......:.. :..... Q ...,..,...•.. ...... ... f= Sy -- - ~ O~(~, W O ~~~• 0~~~ ~~Q J~~ l QP`r~o ~. ~O ,~P QLp' ........ ...... ....I...s::::: ... ::r:::.:::r:: ::.• ::f ::r::s.~:: :::::::....:: ..r.: ... :f:..:::~:.::.:::.......::: ............ ::t : ~:s - a =~~ - - - =~4i - _ - - - a - - - - - _ - - - - - - - - - -- _ a> ..... .. - - - - -:, N :~~' •t ..3::: ' R ~: :1:: ~::~... Q ............. ....: . ....... ~ :: :' - ::l: fit:: ::t:' 1~ it + ~ :,lf + F t I sit i+ f !+ ! d `' 44 f f ! f~ f t f 1 1. o f 1 ifntii'c v J ~ innureuun~r unnaenr a t ~ +wrnw• •. . 'nnnm a nfnnnnnni ~ ft• _ : W '~ ~••- •• »•• I~fltilltllll 11 Olltllur7f qll_ iltt llC IBII~~ tilt .~=: ~ittflM1 J '~~ arri!!lgeet!!!I tale , t t t n t;t um r t - » •• = ::•::::~::_: _ Q ~ L a. ummmteiilt uttnnnt~iuun nt mi}atnr in udnnit im rounna:;~::,~,tenmrm ummmuu:~nPmi~~~nnu~ duunnnutu~rugpnmm~n°mrun+u~+rf,r/r~~ ~ Z N Z _ »I ..~.~~ _ :~ ........:.rte : _ _ » _ - »~ ~ _ _ ._ .i.--- ~ _.. ... .._ _. ». •••~ .. .. - ... Q~ W ... s.. ' ''~^^ f ~ V+ ' Q t. ~ :..:: .. _ ai i^..iL + .. .:.i:.~;•Ee. cc:. ..6.ws...,. .... ,. ::::::: 2Ec •: :;, ....---••tf:a.t~..ri r_e%~'Ii'='fa'E*ie'::2eyice a ~,,, T J T~ W = 1"' rR Q o ~, z Q N J ~ LL! _ O F- ~ ~ a° NZ ~~ ~J ' ~ ~ ' ZaH 71dHSfA1 711AV~i o ~ 0 0 °o syldap easgns o f I ~ 3Ndfi85tl I • • SAG DELTA. NORTH PETROPHYSICAL SUMMARY .ZONE NET TO GROSS POROSITY 1- S w Upper Sand .83 (.7 to .96) 17.5 (16.1 to 19) 67.8 (71.4 to 64.2) " " 66 9 t 71 3 76 3 i Lower Sand B .81 (.72 to .89) 22.3. (19.5 to 25.6) . o . ( . ) Lower Sand "A" .98 (.92 to 1) 20.7 (19.2 to 23.3) 64.4 (59 to 68.9) Alapah Porosity Zones .86 (.42 to 1) 17.4. (11.1 to 24.7) 75.2 (59.1 to 88.2) EXPLANATION: AVERAGE VALUE (RANGE) values. for net to gross and porosity include the hydroc arbon and water columns 1-Sw values for hydrocarbon column only EXHIBIT 6 • SAG DELTA NORTH FIELD DISTRIBUTION OF STOCK TANK ORIGINAL OIL IN PLACE '~ STOOIP i (million. barrels) PERCENT UPPER SAND 4.7 27% LOWER SAND „ B„ 6.5 37%° LOWER SAND „ A., 2.8 16% i ALAPAH 3.7 ~ 20% 17.7 100% EXHIBIT 7 • AREAL DISTRIBUTION OF HYDROCARBON BEARING IVISHAK SANDSTONES OF THE IVISHAK OIL POOL SCALE 1"=1000' • • • AREAL DISTRIBUTION OF HYDROCARBON BEARING ALAPAH POROSITY ZONES Srni E ~~~_~ppp~ . • • SAG DELTA NORTH IVISHAK FLUID PROPERT • INITIAL .RESERVOIR PRESSURE (10000' SS) • OIL BUBBLE POINT • RESERVOIR TEMPERATURE • PRODUCED OIL GRAVITY • RESERVOIR OIL VISCOSITY • .SOLUTION GOR • OIL .FORMATION VOLUME FACTOR • GAS FORMATION VOLUME FACTOR • 4825 PSIG 4825 PSIG 212° F 25° API 1 CP 778 SCF/STB 1.35 RB/STB 0.00065 RB/SCF •. • EXHIBIT 10 • • EXHIBIT 1• 5-03/S D-09 5000 4500 4000 P R ~ G 3500 ~ D R U 3000 C S ~ C 2500 F ~ N ~ 2000 B B B ~ 1500 / ~ 1000 500 0 Jul-89 Sep-89 Nov- 00.0 90.0 80.0 70.0 60.0 50.0. ~N A T 40.0 E R 30.0 C 20.0 U T 10.0 0.0 89 Jan-90 Mar-90 May-90 Jul-90 Sep-90 Nov-90 Jan-91 i- PRODUCTION ~ GOR -~- WATER CUT t • • - 8 -CHOKE Exhibit 12 Sa ®elta North. --~ -PREs ---~E-GOR ~ ~N_03 Ala ah Test --~}--TEMP Well 2 3 / p sooo ~ , 1.0 0 0 -- s o 0 0 ?~ '~ m i m v N 4000 V ... ~ v O ~' ~ 3000 °~ 1 0 0 .-. ~ ~ Q E a~ F 2000 ~ N ... ,-: O a 1000 N N d i 10 °' 0 0 20 40 60 80 100 120 PERIOD (30 minute ) • • 2-32/SN-03 EXHIBIT 73 5000 4500 4000 P R O G 3500 D ~ U R 3000 C S ~ C 2500 O F nJ ~ 2000 B B B ~ 1500 D 1000 500 0 -^- PRODUCTION -~- GOR -~- WATER CUT 25.0 20.0 15.0 W A 10.0 T E R C 5.0 U T I, 0.0 Nov-90 Dec-90 Jan-91 Feb-91 ~ • 2-38/SN-01 6000 5000 P R G U O 4000 U R C S ~ C 3000 O F N ~ B g .2000 B ~ D 1000 0 -~ PRODUCTION ~- GOR • WATER CUT EXHIBIT 74 25.0 20.0 15.0 W A 10.0 T E R C 5.0 U • ~I T 0.0 Nov-90 Dec-90 Jan-91 Feb-91 • 1-17/SN-02 soon 5000 P R G D O 4000 U R C S ~ C 3000 O F N ~ B B 6 2000 / ~ D 1000 0 Jan-91 ~ PRODUCTION ~- GOR -~ WATER CUT • EXHIBIT 15 25.0 20.0 i 15.0 ' W A 10.0 T E R C 5.0 U T 0.0 Dec-90 Feb-91 OIL RATE STB/D GOR SCF/BBL ~i J ...L N .A C'1 OD O N •A O O O O O O O O O O O O O O O O O O O O O O JUL 89 SEP 89 NOV 89 ~ JAN 90 ~ ` _ i MAR 90 ~ MAY 90 ~ ~ m JUL 90 t / n O SEP 90 ~ ~ ~ NOV 90 ~ ~ m JAN 91 MAR 91 ~ o- iv ~ rn oo j o 0 0 0 0 0 WATER CUT • ~ • A ~ v ~ ~ v m m ~ ~ O D ~ Z ~ O D 70 Z -I C7 = m m x x m ~ f • • Can Il • ntact ... ra. .... _. .. .. Exhibit 17 n 12050 >'>>< sso0 ~- Model Data • Exhibit 18 Sag delta North Ivishak Log GAMMA RAY RESISTIVITY POROSITY 0.0 150 TVD MD 1 0 1000 40 0.0 12000 ,,~ .~ ~~•.. Porosity 16%-181° 12100-1- _; • ~ 'I B ~ ~~ OZ i U} i G3 0 -~I A 12150 ~= '~ ., :~ ~•. •, .~_; 12200 .,,.., 1 ~ 12300 ., ;~ .~ ., .~ '12350 ' ` Permeability 200 and - 300 and ..<>;<>H 1 aooo+ • • • Sag Delta North Pressure Match 4900 4800 4700 4600 4500 4400 4300 4200 4100 4000 3900 3800 3700 3600 3500 Exhibit 19 0.000 100.0 200.0 300.0 400.0 500.0 600.0 700.0 DAYS • • • r • Sag Deita North Exhibit 20 Sag Deita #9 History Match 4000 0.7 3500 0.6 3000 0.5 OC 2500 0.4 ~ v ~? 2000 L °' ~ ~ 0.3 . p 1500 0.2 1000 500.0 0.1 0.000 0 0.000 100.0 200.0 300.0 400.0 500..0 600.0 700.0 • s~~ DAYS SAG DELTA NORTH SIMULATION RECOVERY RESULTS DEPLETION WATERFLOOD MBBL REC % MBBL REC LOWER SAND A 1075 3 3 1000 - 1400 33 - 43 LOWER SAND B 2000 27 2800 -3500 39 - 47 UPPER SAND 1075 3 9 1100 - 1200 41 - 42 • EXHIBIT 21 • 13000 12000 11000 ,-. 0 10000 m N 9000 v, 8000 a~ 7000 c 6000 0 ~ 5000 0 4000 L °' 3000 2000 1000 0 • • 5000 4500 a m 4000 ~ a~ a L 3500 'o L m a~ 3000 2500 U • Sag Delta North EXn~a~t 22 Production Performance • • Saa Delta North Depletion Plan • Implement Full Field Waterflood Convert SD-09 to Water Injection Drill SN-04 as a Water Injector Exhibit 23 • Balance Injection for Optimal Recovery • Repressure Reservoir • No Gas reinjection • • • ~ • Conservation Or No. 202 Page 5 EXHIBIT 24 September 20, 1984 Rule 4 Casing and Cementinq~uirements a) Structural casing shall be set by driving or jetting to a sufficient depth below the mud line to ensure support of drilling fluid returns to the surface while drilling hole for a conductor string. b) Conductor casing to provide for proper anchorage shall be set at least 75 feet below the island surface and sufficient cement shall be used to fill the annulus behind the pipe to the island surface. Cement fill shall be verified by observation of cement returns. The cement may. be washed out or displaced to a depth not exceeding the depth of the structural casing shoe to facilitate casing removal upon well abandonment. 'I c) Surface casing, to provide for proper anchorage, for preventing ~ uncontrolled flow and to protect the well from the effects of permafrost thaw-subsidence or freeze back loadings, shall be set at least 500 measured feet below the base of the permafrost but not below 2700 feet true vertical depth: Sufficient cement shall be used to fill the annulus ~ behind the casing to at least the mud line. d) .Surface casing types and grades approved for use include: 1 } 13-3/8 inch, 72 pounds/foot, L-80 Buttress; !, 2) 13-3/8 inch, 68 pounds/foot, NT-80CYHE Buttress; j 3) 10-3/4 inch, 45.5 pounds/foot, K-55 Buttress; 4) 10-3/4 inch, 45.5 pounds/foot, HF-ERW Arctic Grade J-55 Buttress; 5) 9-5/8 inch, 47 pounds/foot, L-80 Buttress ~, 6) 9-5/8 inch, 47 pounds/foot, NT95HS NSCC 7) 9-5/8 inch, 47 pounds/foot, NT80S NSCC e) The commission may administratively approve additional types and grades of surface casing upon a showing that the proposed casing and connection can withstand the permafrost thaw-subsidence and freeze ..back loadings which may be experienced. Evidence submitted to the Commission shall include: 1) Full scale tension and compression testing; or 2) Finite element model studies, or '~, 3) Other types of axial strain data acceptable to the Commission. • ~I, f) Alternate means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze back may be administratively approved by the Commission upon application and presentation of data which show the alternatives and appropriate, based upon. accepted engineering principles. TREE: 41/16" /5000 psi /McEvoy /Baker Actuator WELLHEAD: 13-518' /5000 psi /FMC (CCL) ~. 13-3/8', 68#Itt, NT80 CYHE BUTT CSG 2541' NT80S XO to NT95HS 11041' • i• TOP OF T TIW LINER i308T 9-5/8', 47#Jft, NT95HS,~SCC , .13349' Ref. Log: DLL-GR {1029/90) SIZE SP INTERVAL S A US 3 318' 6 13394' -13486' OPEN R.T. 0.EV = 54.5 B.f. 0.EV =15.3' SSSV LANDING NIPPLE 1553' OTIS (3.813• LD.) W/SSSV IN MIN. LD. 2" 41/2',12.8#/ft, G80, TDS GLM's Otis , 1-112' 1300 SS Latch No TVDSS MD-BKB 7 3957 5125 6 6395' ~~' 5 7556' 1004,' 4 8243' 10980' 3 8815 11798' 2 g32T 12536' i 9671' 12999' 4-12" 'SWS"NIPPLE 13028' (Parker) (3.813' ID) RgM hand re- 13045 k+ase safety jnt 9-518' PACKER 13045 TIV1l (4.00' LD.) 412', 12.6#/ft 1-80,?AILPIPE 412" "SWS' NIPPLE (Parker} (3.813'ID) 1309T 412' SWS"NIPPLE ' (Parker) (3.813't0} 13118 412" WLEG 13131' MARKER JOINT 13~' T OTIS "WD' PACKER 13550' 412' 'X' NIPPLE 1355T (Otis) (3.813' 10) 412' 'XN" NIPPLE 13561' (Otis) (3.725" IDy 412' WLEG 13563' PBTD 13745 .,... T, 29#/(t, NT95HS .'w~: ~'. TKC 13831' Date By Comments ENDtCOTT WELL: 2-38/ SN-01 10/4190 PGS PROPOSED COMPLETKN API NO. 50-029-220 1120190 JLH INITIAL COMPLETION COMPLETION DIAGRAM BP EXPLORATION (ALASKA), INC EXHIBIT 25 • • • I AME ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING MARCH 12, 1991 BP EXPLORATION (ALASKA), INC. ENDICOTT FIELD, SAG DELTA NORTH ACCUMULATION SIGN IN PLEASE DO YOU PLAN TO COMPANY TESTIFY OR COMMENT? (PLPsAS ~~ '~ ~~ PRINT ) ~ ~/ ~~~so~ ~- CD - D - D~ F' ~ ~. ~,~is - A~Lc~ - Nd i~ e ~ ~.1~ '.~ ~cc~- ~ ~M s - - ND i 5- G/S D-- ~~1 S - a J,~, c,_ ~ ~ ~ - ~ r~ ~ - ~d ~r~~ ~~ ~ - ~ ~!~ , ~a l D-~f~ l-~ ~t - ~ '' ~r- ~ ~- ~- ~~ ~ o ~ o -- ~ D s ~~.~-~~ ~~° ,~~-,~ ~ w ooh Q~ No - f3P o v / - ~ 1 -~' • I I i I ~i NAME & ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING MARCH 12, 1991 BP EXPLORATION (ALASKA), INC. ENDICOTT FIELD, SAG DELTA NORTH ACCUMULATION SIGN IN PLEASE DO YOU PLAN TO COMPANY TESTIFY OR COMMENT? (PLEAS I ~I ~IM(~ PRINT) ~ 0 U ~Ti ~-~- /C ~~ s.~ ~ ~ac~ ~ c, ~1-S 5 G. O sv N ~ ~ si~i / T /~ d~ AVC ~/o /f n/ 3T ~ //11 /1'1 / 1< N ~ ~R ,BG/~//Z G~D~D~L t L - ''~ - II - ~3 ~ ~ ~' BP EJ(PLORATIQN BP Exploration (Alaska) Inc. 1 900 East Benson Boulevard P.O. Box 196612 '~, Anchorage, Alaska 99619-6612 ', (90~ 561-5111 February 28, .1991 David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Subject: Sag Delta North, Temporary Injection Authority Dear Mr. Johnston: • ' BP Exploration respectfully requests permission to temporarily inject water 'into well Sag Delta #9 in the Ivishak formation. This request is presented in ', order to gather information to provide for an early implementation of an ', enhanced hydrocarbon recovery project in the subject accumulation.. A pool rules hearing for the accumulation is scheduled for March 12, 1991 and full justification for the implementation of an enhanced hydrocarbon recovery project will be presented at that time. In the interim the following information as required by Alaska Administrative Code 20AAC 25.402 parts (c) to (h) Enhanced Recovery Operations is provided. (c) 1. A plat showing the location of the proposed injection well Sag Delta #9 is attached. The nearest production wells that penetrate the injection zone are Sag Delta North #1, #2, and #3, all of which are more than one-quarter miles from Sag Delta #9. • 2. There are no other operations within one-quarter mile of Sag Delta #9. 3. No affidavit required. 4. Approval is requested to inject seawater and/or produced water into the Ivishak formation in Sag Delta #9. 5. Sag Delta North Pool is at approximately 10,000 ft. subsea. 505AROW ~' • .- .- '; Mr.. D. W. i ohnston February ~8, 1991 • Page 2 6. The Ivishak formation has an approximate thickness of 92 ft. in the lower sand and 40 ft. in the upper sand. Injection interval is bounded at top by HRZ/Shlublik and bottom by Kavik shale. 7. Sag Delta #9 logs are on file with the AOGCC. 8. A well completion diagram is supplied for Sag Delta #9. Mechanical integrity test has been completed, see (d) below. • 9. Injection water will be seawater and/or produced water from Sag Delta North or Endicott. Maximum expected injection rate is 8000 bwpd. Formation water analyses are not currently available, but will be taken to evaluate water compatability. Based on injection performance history at Endicott water compatibility is not expected to be a problem. 10. Estimated average wellhead. injection pressure is 2500 psia, maximum 2700 psia. 11. Injection will take place into the .Ivishak at approximately 10,000 feet subsea. No fresh water strata are endangered. 12. An analysis of the formation water is not currently availabie.(see (c) (9)). 13. Not applicable. 14. Reservoir simulation shows an expected incremental increase in ultimate recovery of 0.8 to 1.0 MMstb of oil as a result of the proposed water injection into Sag Delta. #9. C~ (d) A copy of a mechanical integrity test performed on Sag Delta #9 on February 24, 1991, and witnessed by the AOGCC is provided. Pressures will be monitored in the casing/tubing annulus and reported on the monthly injection report (form 10-406). (e) The Commission will be notified of any casing/tubing pressures or changes that exceed those indicated. (f) As required by the Commission. (g) An application for Sundry Approval (Form 10-403) for the proposed change in Sag Delta #9 status is attached. SOSAROW Mr. D. W} Johnston ~~ 1=ebruaryl, 28, 1991 Page 3 ~i (h) There are no other wells that penetrate the injection zone within one- quarter mile of Sag Delta #9. Sincerely, /~i,~ B. J. Policky Manager, Endicott Reservoir and Production Engineering BJP/AROW/slk • , ~ __ I '~ i I,~cc: ~ B. J. Policky ~ H. L. Hellman N~- ` ' J. W. Dupree it A. R. O. Wood Sag Delta. 9 well file ',• ,~~ ~° ~ _, 33 i ~ 11 ~ ~ t,,., * r- .9 ~r. ,•~, t rv'+ A d ~ ~ ~ II . - 1 ~. ~ ' `: KB ~ 48.45 BF 13.8'. ~ "„_ '~' M . DEV. >< 45:26 . 4900' MD DIESEL TO 650' ' "`~- .~ i 13-3/$", 72#/ft, L-80,;8trs Csg i; . 2695' -~" 1 s • r,'J1 z ~4 ~• --,,-. _ '.TREE: 4-1/16" / 5000 psl / McEvoy WELLHEAD:. 13-5/8" / 5000 psl /FMC 3-1/2" SSSV LAND{NG NIPPLE OTIS (2.750" LD.) 1540' 3-1/2", 9.2#/it, L-80, TDS Tubing GLM's (McMURRY), (1-1/2", "RK") Latch Aln -/h ollo ~rar~nr. TOP,OF 7" LINER' 11288' 1 9-5/t~", 47#dt, L-80, BTRS. CSG. 11778' ,. NERFORATIN(i SUMMARY Ref. Log: CBT (3/25/89) CO. G SP INTERVAL SOS' 2.125" 4 12072 - 12119' SOS' 2.125" - 4 12127 -12136' SOS', 5"DPC. 4 12200' -.12210' ', 5" DPC 4 ' 12218' -12250' 5" DPC 5 12272' -12313' 3-1/2" SLID{NG SLEEVE ' CAMCO CB-1 11.186 (2.813" LD.) 3-1/2" 'X' NIPPLE ' PARKER. (2.750"'LD.) 11200 71W SBR (12' long) 11219' 9-5/8" PACKER ' TIW (HBBP) 11234 2-7/8", 6.5#/It, L-80, TAILPIPE 2-7/8"'X' NIPPLE ~ ' PARKER (2.313" LD.) 11281 2-7/8"'X' NIPPLE PARKER (2.313" LD.) 11313'. E--- 2-7/e" WLEG 11352' "~- 7" OTIS "WD" PKR 12145' W/ 2-7/8" "X" NIPPLES (2.313" f.D.) 4 BROKEN SLIPS FROM THE PERFORATING PACKER ON TOP .`-` '~-- 2-7/8" WLEG 12166' OF BRIDG PLUG -~ ' FRIDGE PUG SET AT 12262' 7",'29#/ft, L-80, BTRS. LINER ~' ' 3110' ~- CEMENT PLUG FROM , L~.,~." "..~~'~ .12660' - 13250' ,.. (^~www~w w w w fFp w wwwt w~w w w w www w w 6" PEN HOLE T.D. ~^w~" " w " w w ~w w w ~~. 14100' w w~w~w~w~~ Date ~ By Comments WELL 5-03 / SD-09 01/19Y88 FH PROPOSED COMPLETION API N0. 50-029-20639 o4/1s/ss JLH COMPLETION COMPLETION. DIAGRAM ' 7/22/9 JLH ADDED PERFORATIONS` __ BP EXPLC)RA`>•ION, INC. #6 3042' 3039' # 7072' 6099' #4 9325' 7780' #3 1031 T 8670' #2 10972' 9098' #1 1 094' 919 ' --__._ --- - --- _ -- --- sT~ -~s diK_ ~>E WELL i~AHE *p +t5 aN *I - ~tl TYPE OF 11NM1t.US FLUID ['KR TYD tD GSING SIZ~lxrlCEtADE TBQ SIZE tbEO .TEST PRESS TeC C5C PRESS Tli~iE TBG CSG PRESS TINE TtiC CSG 'PRESS TINE START T8G TIxE P CSG PRESS F '-- ©3 D,~saxx- 9.,~0 g U g P ~ ~Qub~ ~r=rrr'sCy~E, wE'w ~~.-t fj/~b.~c~~-~ ~ .~ -S~c~ 9 /~ ~~-~ ~rJ3~~1'~k' ~ ~ /~ a ~'~ 3 f vZ, o~ © 1.?So ~ /.?s'~ ~y~ j;L?f "' 1! y ~- ~~~a ~' NQiIS: KENTS: e 9iQi75s 3 i tIG i tiJECI' I ON FLU 10 PRODIiCE HATER INJ SALT 1rATER I NJ M15CIBlE iHJECTION rli.JE~'fIFtC ti0t 11t1E~1'ltiG {}s lrov OS/t0~9D~ !tl~iauJ1R FLUID a ~ 1 ESEL GLYCpt 5111.T bU1TER il4t 1 LLi NC rUD QTt'~R DT}~ti C~IENTc 3~"'3 4'D 1tELL TEST: [oittal ~^' ~-year lforkover .Explain, Na~cx x l TNESS s r MATURE (7.Jt~AHIf REP S K?tATtlRE ' ~- •~ 9 i ~ ~D ! r ` w ' r 3 ~, ? ~ m ~~~ --~ -~ ,. ~. --~ m r • off' u ~0 T' r ~,, R ra ,... • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ype of Reque~t: Abandon _ Suspend _ Operatlon Shutdown _ Re-enter suspended well Alter casing _ Repair well Plugging _ Time extension Stlmulate ~~ Change approved program ~ Pull tubing _ Variance _ Perforate _ Other x 2. Name of Dper for 5. Type of Well: 6. Datum elevation (DF or KB) BP Ex !oration laska Ina P ) Development x KBE=55 feet 3. Address Exploratory _ stratlgrephic_ 7. Unit or Property name P. O. Box 1966 2, Anchorage, Alaska 99519-6612 service- Duc>r' island Unit%Sag Delta 4. Location of wel at surface 8. Well number 336' SNL, 2230'1, WEL, Sea 36, T12N, R 16E 5-03/Sag Delta #9 At top of productive interval 9. Permit number 184' SNL, 299' WEL, Sea 25, T12N, R16E 81.117 At effective depth 10. API number 5276'SNL, 133 INEL, Sea 24, T12N, R16E 50- 029-20639 At total depth I 11. Field/Pool 486T SNL, 4891~,'WEL, Sec. 19, T12N, R17E Sag Delta North/Ivishak 12. Present well c ndition summary Total depth: !, measured 14100 feet Plugs (measured) Bridge plug set at 12262: ' !, true vertical 11728 BKB feet Cement plug from 12660' - 13250' Effective dept~t: measured 12660 feet Junk (measured) Slips from perforating packer on top of bridge ', true vertical 10486 BKB feet plug at 12262: Casing Length Size Cemented Measured depth True vertical depth .Structural BKB. BKB Conductor 200' 20" Driven 235' i8T Surface I, 2660' 13.3/8" 2246 c. f. Ars;tic Set /l 2695' 2647 , Intermediate 11743' 9-5/8" 1716 cf. Class G Production 130 c.f. Arctic Set l 11778' 9676' Liner ', 1822' 7" 976cf. C/assG 11288=13110' 9292'-10802' Perforation dejpth: measured 12072'- 12119; 12127- 12136; 12200'- 12210; 122 18=12250; 122 72=123 13'(plugged) i true vertical (Subsea) 9915' - 9953; 9960' - 9967, i 0020' - 10028; 10035' - 10061; 10079' - 10113' (P/u99~) Tubing (sine, grade, and measured depth) 3-1/2" 9.2#, L-80 tubing with 2-7/8" 6.5# tail pipe to i 1352: Packers and ~SSV (type and measured depth) 9-5/8" TIW packer at 11234; 7" WD packer at 12145; 3-1/2" SSSV at 1540: 13. Attachments Description summary of proposal _~ Detailed operations program BOP sketch 14. Estimated dal for commencing operation 15. Status of well classification as: March 1991 16. If proposal was verbally approved Oil x Gas Suspended Name of apprtpver Date approved Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Si ned 2 Title ReservoJr Development Coordinator Dated ,g FOR COMMISSION USE ONLY ditions of app val: Notify Commission so representative may witness Approval No. Plug integrity BOP Test Location clearance Mechanical Integrity Test Subsequent form required 10- Approved by orde ~ of the Commission Commissioner Date corm io-403 lieu Q6/15/88 SUBMIT IN TRIPLICATE North: • Well 5-03/Sag Delta #9 Service Designation 4 E Well 5-03/Sag Delta #9 will be converted from oil production service to water injection service starting approximately March 1 ~ i 991. • 505AROW 2 • Notice of Public Hearing • STATE OF ALASKA Alaska Oil and Gas Conservation Commission The application of BP Exploration (Alaska) Inc. for a public hearing to present testimony for classification of a new oil pool and prescribing pool rules for its development in the Duck Island Unit of the Endicott Field . Notice is hereby given that BP Exploration (Alaska) Inc. has petitioned the Alaska Oil and Gas Conservation Commission under 20 ~AC 25.520 to hold a public hearing to present testimony for classification and prescribing of pool rules for development of a new oil fool in the Endicott Field. The development area is located in Tracts 1~i3 and 15 of the Duck Island Unit and has been generally referred to al.s the Sag Delta North accumulation. I, A hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501 at 9:00 am cn March 12, 1991 in conformance with 20 AAC 25.540. All interested persons and parties .are invited to present testimony. ~ ~~, Russell A. Douglass Commissioner '' Alaska Oil and Gas Conservation Commission February 6, 1991 ~~ i BP EXPLORATION January 11,1991 David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Dear Mr. Johnston: BP Exploration respectfully requests the Alaska. Oil and Gas Conservation Commission to hold a public hearing for the establishment of pool rules for the development and exploitation of the Sag Delta North oil accumulation. The hearing can be conducted on March 12, 1991 as per previous discussions. The Sag Delta North oil accumulation is located in Tracts 13 and 15 of the Duck Island Unit. Please direct any questions regarding this request to Herman Hellman at (907) 564-4785. Sincerely, B. J. olicky BJP/HLH vi-rhiT 3-~".~.._a i -- -- FPVG ,s, Er'~[<a A ='~ ~.Ci ~~~Y~ • BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 14:: ~ ~ ~ .S CppS. ~Qf I~jj~.`: ~I -. ;.~~, ~~,~} ~Cag~ ~~d
