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CO 393
Conservation Order Cover Page XHVZE This page is required for administrative purposes in managing the Scanning process. It marks the extent of scanning and identifies certain actions that have been taken. Please insure that it' retains it's current location in this file. '~_~_,~ Conservation Order Category Identifier Organizing RESCAN ~ Color items: [] Grayscale items: [] Poor Quality Originals: [] Other: NOTES: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED (Scannable with large plotter/scanner) Maps: [] Other items OVERSIZED (Not suitable for plotter/scanner, may work with 'log' scanner) [] Logs of various kinds [] Other BY; ROBI~ Scanning Preparation TOTAL PAGES BY: ROBI~ Production Scanning Stage I PAGE COUNT FROM SCANNED DOCUMENT: ~ PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: ..~ YES .,, NO BY: Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: YES ~ NO (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION I~ REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALS OR COLOR IMAGES) General Notes or Comments about this Document: 5/21103 ConservOrdCvrPg,wpd STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re: THE APPLICATION OF STEWART PETROLEUM COMPANY for an order granting an exception to spacing requirements of Title20 AAC 25.055 to provide for the drilling of the West McArthur River Unit No. I-1 enhanced oil recovery water injection well. ) Conservation Order No. 393 ) ) ) Stewart Petroleum Company ) West McArthur River Unit No. I-1 ) ) ) ) April 10, 1997 IT APPEARING THAT: 1. Stewart Petroleum Company submitted an application dated March 10, 1997 requesting exception to 20 AAC 25.055(a) (3) to allow drilling the West McArthur River Unit I-1 enhanced oil recovery service well to a location that is closer than 500 feet to a drilling unit boundary. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on March 21, 1997 pursuant to 20 AAC 25.540. 3. A petition was recieved from an interested party with concerns related to the proposed enhanced oil recovery operations at West McArthur River Unit. No substantive protests were recieved from an affected owner who may be harmed if the requested spacing exception is issued. FINDINGS: 1. The Stewart Petroleum Company West McArthur River Unit I-1 well as proposed will be a deviated hole drilled from a surface location 1953' from the west line (FWL) and 3233' from the north..line (FNL) of Section 16, T8N, R14W, Seward Meridian (SM), the proposed top of the injection interval is 2400' FWL and 600' FNL of Section 15, T8N, R14W, SM and the proposed bottom hole location is 2765' FWL and 328' FNL of Section 15, T8N, R14W, SM. Conservation Order ~,~ )3 .,. April 10, 1997 Page 2 2 Offset owner Union Oil Company of California has been duly notified. 3. An exception to 20 AAC 25.055(a) (3) is necessary to allow drilling of this well. CONCLUSION: Granting a spacing exception to allow drilling of the Stewart Petroleum Company West McArthur River Unit I-1 well as proposed will not result in waste nor jeopardize correlative rights. NOW, THEREFORE, IT IS ORDERED: Stewart Petroleum Company's application for exception to 20 AAC 25.055 for the purpose of drilling the West McArthur River Unit I-1 well is approved as proposed. DONE at Anchorage, A1 '~' David W. gohnsL~n,~ Alas~onservati on__sion Mary Marsh~n~ Commissioner AlaskaOil anh'~Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). Stewart Petroleum Company 4700 Business Park Blvd., Suite #13 Anchorage, Alaska 99503 (907) 563-5775 · FAX (907) 563-4060 April 8, 1997 Mr. Dan Johnson P. O. Box 191004 Anchorage, AK 99519 Re: WMRU Reservoir Maintenance Plan Dear Dan: To confirm our conversation of today, I met with the Schlumberger people on Friday. As a result of that meeting, I asked them to modify the draft proposal to include economic analysis in the WMRU reservoir study and to provide us with details of baseline input data necessary in order to provide reasonably reliable conclusions with respect to WMRU pressure maintenance Plan. We will then assemble the data or figure out how to obtain it. I intend to initiate this work only if the proposed Force Energy sale falls through. If that happens, we will proceed with Schlumberger. Very truly yours, 'Steven L. Hartung, President SLH:nl DAN R. JOHNSON P.O. Box 191004 Anchorage, AK 99519 (907) 245-1486/275-3600-Pager April 9, 1997 Mr. David W. Johnston Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Petition of concerns related to Stewart Petroleum Company proposed waterflood operation. Dear Mr. Johnston: I had a conversation over the phone on Tuesday, April 8, 1997 with Mr. Steve Hartung, CEO for Stewart Petroleum Company, regarding West McArthur River Unit proposed pressure maintenance plan. Mr. Hartung intbrmed me that if the proposed sale of the WMRU to Force Energy falls through, that he would proceed with a reservoir study by Schlumberger before drilling the pressure maintenance well. I asked Mr. Hartung if he would confirm this information to me in a letter, He replied that he would. For the following reason I, Mr. Dan R. Johnson, would like to withdraw my Petition of concerns relating to Stewart Petroleum Company's proposed waterflood operation. A copy of the letter from Mr. Hartung is attached. I would like to apologize to the Alaska Oil and Gas Conservation Commission should this have caused any inconvenience to anyone. Sincerely: Dan R. Johnson Working Interest Owner CC. Steve Hartlung RECEiVeD A~R 9 199'/' Alaska Oil .&aa ~ ~;ons.' .Gflmllli~iu' E. rik L~Roy P.C. 1016 W. 6th A~e. Sl, c 420 (907) 2T7-2006 iL[D Edk LeRoy, P.C. 1016 W. 6th Ave., Ste 420 Anchorage, AK 99501 (907) 277-2006 Attorney for Debtor CLERK U.S. BANKP~UPTC'¥ THE UNITED STATES BANKRUPTCY COURT FOR THE DISTRICT OF ALASKA In ce: STEWART PETROLEUM CO., Debtor. ) STEWART PETROLEUM CO. ) ) Plaintiff, ) ) ) CO-OWNERS OF LEASES ADL 359111, ADL 35911~ ADL 384403, ADL 384404, ADL 381216, ADL 381012,) ADL 381030, ADL 387023; ASSOCIATION ) OF WORKING INTEREST OWNERS; ) JOHN DOE 1-10; JANE DOE 1-10; ) POLAR BEAR INVESTMENTS, L.L.C.; HOWARD ) THOMAS; 90-2 CORPORATION; ALEUT ) CORPORATION; JEFF ALLEN; ATWOOD ) CHILDREN'S TRUST; SANDRA ATWOOD; ) BERNARD TREVELYN, LTD.; PAUL BAER; ) WILLIAM M. BANKSTON #5816034218047; ) JESSE C. BELL; THOMAS P. BERRY; GRAHAM ) BIDDLE; CRAIG BIEBER; JIM BISHOP; THERESE ) BOVEY; GLENN S. BOVEY; SARA D. BREAKER; ) MADELYN BRINGMANN; GEORGE BRINGMANN; ) GREGORY S. BURGESS; BURGESS FAMILY ) TRUST; KATHRYN BURGESS; JEFFREY BURGESS~ W. DON BURROWS; JANE V .BURROWS; ) GERALD R. CALEY; CEDAR CLIFF RANCH; ) DELYNN CHAMBERS; GLEN CHAMBERS; ) HARRIET WEAGEL CHANCELLOR; THEO M. ) CHENIER; KAREN L .CHESLER; LEON F. CHESLER;I JEFF CHESLER; CINDY CHESLER; CIRCA 84; ) MELANIE A. CLARK; D. CRAIG CLARK; BONEE ) CLARK; NELL CODER; KENT L CODER; COIL, INC; ) COOK INLET INVESTMENT TRUST; KATHLEEN ) COTTINGHAM; PETER S. CROSSON; GLENN P. ) CURTIS; RAY W. DAHL; HELENE M. DAHL; ) LILIANE DAMMOND; DAVID C. DAUM; ) RICHARD E. DAUM; NANCY K. DAVIS; PERRY T. ) Section 363(h) Complaint Page I Bankruptcy Case No. Ag6-00795-DMD Chapter 11 Bancap No. 97-3029 [Bankruptcy Electronic Docketing Reference Number] Adversary Case No. Ag6-00795-002-DMD COMPLAINT TO TRANSFER INTEREST OF CO-OWNER UNDER 11 U.S.C. 353(h) 9 1997 Oil .& Gas Cons. DAVIS; JOHN J .DICK; MARLENE L. DICK; DOUPE' ) FAMILY TRUST; RONALD C. DOUPE'; THOMAS W.) DOUPE'; LINDA DOUPE'; ANN C. DOWNER; ) WILLIAM V. DOWNER; B. L. DUNBAR; ) RUTHANNE DUNBAR; WILLIAM J. DUNBAR; JOHN ) EBISU; RANDALL H. ELEDGE; SHARON F. ) ELEDGE; CAROLE A. ELKINS; RICHARD ENBERG; ) STEVE FITZHUGH; CAROL FONTAINE; NAOMI J. ) FRYE TRUST, U/T/A; DAVID A. GIBSON; CAROL H.) GIBSON; PAUL GIBSON; EDITH GIBSON; ) WAYNE GILMORE; THE T&V G TRUST; MICHAEL ) GOENS; ALLYSON GOENS; GEORGE E. GOERIG; ) GEORGE GRAHAM; THERESA GRAHAM; PAULINE) HALKETT; DAVID HALL; JOHN E. HAXBY; ) MARY L. HAXBY; MONIKA HAZlOT; DAVID ) HAZIOT; KARL G. HOENACK; PEGGY B. HORNE; ) EDWARD HUNTLEY; NANCY HUNTLEY; ) MARGARET IBBOTSON; LARRY IHLEN; SANDRA ) IHLEN; LARRY IVERSON; MABEL A. JAEGER ) LIVING TRUST; DAN R. JOHNSON; DOUGLAS F. ) JONES; ROBERT E. JONES; DARLA K. JONES; ) LEWIS KEADING; LUCILLE KEADING; JAMES T. ) KEARNS; ALFRED O. KEHL; JAMES L. KOTHE; ) HANS KRUGER; SELVlA KRUGER; LAB ) PROPERTIES, INC.; MARC LANGLAND; WALLACE ) LAUTERBACH; LINDA LEARY; NANCY LESKO; ) BILL LEWIS; JULIE LEWIS; WILLIAM R. LEWIS; ) LAURIE S. LEWIS; RICHARD N. LUCU; LOIS T. ) MAEMORI; PETER MAHER; WILLIAM MALEY; ) DENNIS MALONEY; DEBBIE MALONEY; ) MICHAEL R. MARINELLI; BERNARD L. MARSH; ) WILLIAM H. MCDONALD; JOHN C. MCDONALD; ) MAX MEDEMA; DAWN MEDEMA; MEDEMA ) FAMILY TRUST; DAN MELLON; MICHAEL S. ) MELUM; LANA MELUM; JERRY A. MILLER; ) HENRY S. MINICH; JERRY W. MOORE; JAMES D. ) MORGAN; KEITH MORTENSEN; ANNA N. ) MORTENSEN; MOSLEY ENTERPRISES; BRIAN S. ) MYHRE; SUE M. MYHRE; GREGORY MYHRE; ) DEBORAH. MYHRE; PHILIP E. MYHRE; EMMA J. ) MYHRE; ROGER P. MYHRE; GARY P. NELSON; ) JOSEPH L. NEWHOUSE; NORCAP, L.L.C.; NUGGE~ NEVADA, INC.; L. E. OSBOURNE; DEBRA ANN ) OSBOURNE; DOUBLAS OSHLO; JAMES E. OWEN; ) WILSON OWENS; TENNYS B. OWENS; STEPHEN ~. STEWART; C. L. PARKIN; TIMOTHY P. PAYNE; ) LESLIE M. PAYNE; CLAIR PEASE; AMELIA ) PENROSE; JAMES PERRY; DONNA PERRY; ) SHERRON G. PERRY; ROBERT L. PERSONS; ) DEANNA L. PERSONS; STEVE PETERSON; MARK ) Section 363(h) Complaint Page 2 APR 9 ]997 Oil .& 6a$ Cons. Anc~ioragoi, Erik LeRoy P.C. 1016 W. 6~h Ave. St~ 420 (90'0 277-2006 PFEFFER; POLARIS FUND, L.P.; FRANK RAMOS JFJl; LINDA RASMUSSEN; CHARLES L. REDMOND; ) EVELYN M. REID; ESTATE OF WILLIAM D. ) RENFRO; MICHAEL C. RENFRO; DALE H. ) RICHARDSON; KRIS H. RICHARDSON; JACK ) RICHARDSON; HELEN RICHARDSON; LUTHER ) DEAN RlCKERSON; ROYCE G. ROBERTS; JAMES ~ ROSE; WHITNEY M. ROSE; ALYSON J. ROSE; ) DAVID L. ROSEN; ROSS PRODUCTION ) COMPANY-DIC; ROSS PRODUCTION CO #1; ROSS) PRODUCTION CO #2; ROSS PRODUCTION CO t~L3;) MARK ROWLEY; LEANNE ROWLEY; MITCHELL L ) RUCKER; BEVERLY F. RUCKER; HENRY RUST; ) ANTONIO SALADINO; SASUMI, INC.; SARAH A. ) SCHIERHORN; CAROLE J. SCHNEIDER; JOHN S. ) SEAMAN; DOROTHY MILLIKEN SELMAN ) REVOCABLE TRUST; CHARLES HENRY SELMAN ) REVOCABLE TRUST; NICK SEMENIUK; DAVID C. ) SHARP; MAGDALENA E. SHARP; C. D. SHARP; ) BUDDY R. SHEARER; ANITA L. SHEARER; ) DONALD F. SHEEHAN; JEANNE T. SHEEHAN; ) DONNA SHEEHAN; DALE SHEETS; MARLENE ) SHEETS; FRANK L. SHOGRIN; KARL SKOMP; ) SNOW CACHE INVESTMENTS, GEN. PTNERSHIP; ) JOCELYN T. SOURANT; NICHOLAS SOURANT; ) SPIELMAN FAMILY TRUST; T. A. SPIELMAN; ) JOSHUA STETSON; D. R. STEWART; STEWART ) PETROLEUM COMPANY; ROBERT W .STINSON; ) LOUANN K. STINSON TRUST; DOUGLAS F. ) STRANDBERG; O. E. SUMPTER; EDWARD A. ) SWICKLE; T&R; TEN OIL TWO; EVELYN IONA ) THON; JEFFREY V. THON; TRISTAN LOUISE ) THON; JAMES L. THURMAN; LETA THURMAN; ) THURMAN OIL & MINING, INC.; REBECCA ) KAREN TISCHER; VIRGINIA B. TRACY; BRYCE ) TWlTCHELL; BARBARA J. TWlTCHELL; JERRY E. ) URLING REVOCABLE TRUST; GRACE P. VALLEE; ) W. O. VALLEE; VlKTORIA LTD. PARTNERSHIP; ) DENNIS C. VINCENT; MARY F. VINCENT; ) STEPHEN R. VOGLER; ROBERT VON WEAGEL; ) CHRIS VON IMHOF; STANLEY WALTERS; ) NEREIDA WALTERS; RAY M. WATERS; EDGAR ) WEAGEL; DONNA MARIA WEAGEL; ROBERT L. ) WEST; TAMMY WESTE; PAUL D. WHITE; ) GEORGE L. WHYEL; ROSALIE A. WHYEL; PAUL ) WICHOREK; CHARLOTTE WINSLETT; JACK T. ) WIRKKALA; GEORGIA BURY WOODSON ) REVOCABLE TRUST; JOHN H. WOOLERY; ) MICHAEL J. YORKE; WILLIAM D. ARTUS; JOHN ) BLOCKER; JOHN BLOCKER TRUSTEE; CABOT ) Section 363(h) Complaint Page 3 Erik LeRoy P.C. 1016 W. 6th Av~. Ste 420 (907) 2~-2oo6 CHRISTIANSON; ENCAP ENERGY, LC; ESCOPETA) OIL & GAS CORP.; ESCOPETA PRODUCTION ALASKA, INC.; JOHN POPE; CATHRYN ROBERTS; Defendants. Comes now Stewart Petroleum Co. (Plaintiff) and files its complaint against the Co-Owners (Defendants) identified in Exhibit "A' attached hereto and made a part hereof for all purposes, and plead as follows: 1. Plaintiff is the Debtor-in-Possession against whom an involuntary bankruptcy petition was filed on September 13, 1996, and by final Order of the Court entered on January 24, 1997, order for relief in bankruptcy was duly entered. 2. At the time of the filing of such bankruptcy proceeding, the Debtor was the owner of an undivided interest in certain oil, gas and mineral leases ("Leases") described in Exhibit "B" attached hereto and made a part hereof for all purposes. 3. At the time of the filing of such bankruptcy proceeding, the Defendants herein owned undivided interests in such leases as described in Exhibit A. 4. Existing between the Plaintiff and the Defendants at the time of the filing of such bankruptcy proceeding were vadous forms of agreements consisting of Division Orders, Participation Agreements, Carded Working Interest Agreements and Overriding Royalty Agreements applicable between Plaintiff and vadous Defendants each defining the Co-Owner relationship between the Plaintiff and each Defendant. 5. The Plaintiff has received a contractual offer from a credit worthy buyer, Forcenergy, Inc., and has applied to the bankruptcy Court for authority to sell its interest, free and clear of liens and encumbrances to Forcenergy. A summary of such contract is attached as Attachment "C". 6. The Plaintiff would show the Court that the purchase pdce being paid by Forcenergy for the entirety of such property is significantly greater than a smaller unit of such property would bdng on the market place in that by virtue of the sale of 100 percent of the working interest burdened by no greater than a 25% royalty interest, leaving a net revenue interest of 75%, the purchaser will be able to undertake the Section 363(h) Complaint Page 4 , . . 10. 11. 12. 13. 14. 15. expensive and dsky work overs and refits of the subject property in order to maximize its potential recovery and will further be assured of having the status of operator. A lesser interest would jeopardize the willingness of the purchaser to undertake the expensive and dsky work overs and threaten the purchaser's ability to preserve its status as operator. Because of the difficulty in operating the subject property, the expensive and necessary renovation and refitting of the vadous wells and the necessity to predict control of operations, a partition in kind of the interest in the Leases among the various Co-Owners is impractical and will result in severe diminution in value if it is attempted. The interest owned by the Plaintiff in the subject property at this time cannot guaranty a continuing control of operation and Forcenergy has, in its contract, demonstrated its perceived damages if less than 100 percent of the interest in the subject Leases is not conveyed. The benefit to the estate of this sale free and clear of the interest of the co-owners significantly outweighs any detriment, if any, to a Co-Owner. The Co-Owners are receiving monetary benefits by virtues of the ability of the Plaintiff to sell its interest in,the Leases at the same time the Co-Owners' interests are sold. By selling Forcenergy an interest in the leases which includes both the Plaintiff's interests and the interests of Co-Owners, Forcenergy is willing to pay a significantly higher pdce. The subject properties are in need of significant renovation and refit and no prudent operator will undertake such expenditures unless it is assured that it will continue to control operations and that it owns a significantly large enough interest in the Leases to justify the dsk that it undertakes. The Leases being sold are not used in the production, transmission or distribution of the sale of electdc or natural or synthetic gas for heat, light or power. By separate adversary proceedings, A-96-00795-003-DMD, and A-96-00795-004-DMD, Plaintiff has filed Complaints against vadous owners of undivided interest in the Leases whose Assignments were within one year of, or 90 days of, the filing of this bankruptcy proceeding. Section 363(h) Complaint Page 5 CE VED A?R 9 199'/ A/as~ Oil..& Gas Cons..C,o.m~issto' Anch'orag{l Erik l_,cRoy P.C. 1016 w. ~ Ave. St~ 420 (~7) 277-2OO6 16. The defendants in those adversary proceeding are named in this adversary proceeding for the purpose, in this adversary proceeding, of obtaining a judgment in this adversary proceeding under Section 363(h) to have the sale of the Plaintiff's and the Co-Owners interests in the Leases to Forcenergy concluded free of any and all claims of the Defendants, without waiving Plaintiff's claims against such Defendants in such other adversary proceedings. WHEREFORE, Plaintiff requests that, after Defendants being duly served, and after final hearing thereon, the subject Leases be sold free and clear of the undivided interest of the Co-Owners and that from gross proceeds, from the sale of the Leases, after deducting all necessary and reasonable costs and expenses of closing, be divided in proportion to the ownership between the Plaintiff and the Defendants as to the property held in common between the parties, and for such other and further relief to which Plaintiff may show itself justly entitled. Dated March 31, 1997. Edk LeRoy, P.C. Attorney for Debtor 4,¢R 9 1997 Alaska Oil & GasCons. Anchorage Section 363(71) Complaint Page 6 I nves~r's Participation in W. I. as of 07/24/96 Revised 3/26/97 Name 90-2 Corporation Aleut Corp Allen, Jeff Atwood, Sandra Atwood, Burton IV Atwood, Letitia Atwood, Robed Baer, Paul Bankston IRA Bell, Jesse Bennett, Connie Bernard Trevelyan Berry, Thomas Biddle, Graham Bieber, Craig Bishop, Jim Bovey, Glenn Breaker, Sara Bringmann, George Burgess, Jason Burgess, Jeff Burgess, Greg Burgess (L.A.B.) Burrows, W. Don Burrows, Jane Caley, Gerald Cedar Cliff Ranch Chambers, Delynne Chambers, Glen Chancellor, Harriet Chenier, Theo Chesler, Jeff Chesler, Leon Circa 84 Clark, D. Clark, Melanie Clinton (COIL) Coder, Kent Coder, Nell Cook Inlet Investment Cottingham, Kathleen Crosson, Peter Curtis, Glenn Dahl, Helene W.i.% WMR #lA 0.20000 0.25000 0.10000 0.30000 0.1~00 0.05000 0.05000 0.10000 0.15000 0.84000 4.72000 2.72000 5.50000 0.80000 0.12500 0.10000 0.90000 0.05000 0.10000 0.1 0000 0.10000 0.05000 0.02500 2.72000 0.10000 0.10000 0.30000 0.03750 W.I. % WMR #2 0.20000 7.50000 0.12500 1.00000 0.20000 0.20000 0.20000 0.25000 0.20000 0.10000 0.10000 0.05'0-0'0--- 0.20000 0.1 00OO 0.1 0000 0.15000 0.04000 2.12000 0.12O00 0.90000 0.80000 0.10000 0.20000 0.200O0 0.30000 0.05000 0.10000 0.05000 0.30000 0.10000 0.05000 0.05000 0.12000 0.20000 0.10000 0.50000 O. 10000 O. 1 0000 0.02500 W.l.% WMR #3 0.20000 7.50000 0.1250O 0.10000 0.30000 0.1 0000 0.10000 0.20000 0.10000 0.10000 0.15000 0.14000 2.32000 0.32000 2.00000 0.12500 0.30000 0.50000 0.05000 0.10000 0.05000 0.30000 0.10000 0.05000 0.05000 0.32000 0.5~00 O.O25OO O.O75O0 W.I.% WMR//1 Exhibit A, page 1 Dahl, Ray Dammond, Liliane Daum, David Daum, Richard Davis, Nancy Davis, Perry Dick, John Doupe, Linda Doupe, Ronald Doupe, Thomas Doupe, Woodrow Downer, Ann Downer, William Dunbar, Wm Dunbar, B L Ebisu, John Eledge, Sharon Eledge, Randall Elkins, Carole Enberg, Richard First InterBank Fitzhugh, Steve Fontaine,Carol Frye, Naomi Gibson, David Gibson, Edith Gibson, Paul Gilmore, Wayne Glimspe, Mary (Swickle) Goeddertz, Terrell Goens, Michael Goerig, George Graham, George Halkett, Pauline Hall, David Haxby, John Haxby, Mary Haziot, Monika Haziot, David Hoenack, Karl Hopkins, Kristine Horne, Peggy Huntley, Edward Ibbotson, Margaret Ihlen, Larry Iverson, Larry Johnson, Dan Jones, Douglas Jones, Robed Keading, Lewis Kearns, J am es 0.23330 0.05000 O. 10000 1.20000 0.20000 0.02500 0.10000 0.1 0000 0.20000 0.10000 0.10000 0.20000 0.05000 0.05000 0.30000 0.20000 0.15000 0.1 0000 0.05000 0.07500 0.05000 0.20000 0.05000 0.15000 0.05000 0.1 0000 0.1 0000 0.1 0000 0.025'00 0.1 0000 0.05000 O. 1 0000 0.20000 0.20000 0.30000 O. 1 0000 0.40000 0.07500 0.23330 0.1 0000 0.1 000O 0.22500 0.30000 1.20000 0.20000 0.05000 0.20000 O. 10000 0.20000 0.10000 0.1 0000 0.25000 0.25000 0.20000 0.05000 0.05000 0.20000 0.50000 0.200"0'0-- 0.1 0000 0.20000 o.100¢ 0.27506 · 0.05000 0.05000 o.o5oo( 0.0750~) 0.10000 o.5ooo0 0.1000~ 0.10006 0.05006 0.20000 0.20000 0.20000 , , .. , , 0.2000b , 0.20000 0.1 0000 0.40000 0.40000 0.30000 0.1 0000 0.50000 O. 1 0000 0.23330 0.1 0000 0.25000 0.30000 1.20000 0.20000 O.O25O0 0.20000 0.20000 0.20000 0.1 0000 0.25000 0.25000 0.20000 0.1 0000 0.30000 0.10000 0.30000 O. 1 0000 O. 1 0000 0.1 0000 0.05000 0.05000 0.05000 O. 1 5000 0.10000 0.20000 0.20000 O. 10000 0.15000 0.1 0000 0.1 0000 0.12500 0.02500 0.10000 0.05000 0.20000 0.40000 0.30000 0.1 0000 0.40000 0.07500 Exhibit A, Page 2 Kehl, Alfred Kothe, James Kruger, Hans & Silvia Langland, Marc Lauterbach, Wallace Leary, Linda Lesko, Nancy Lewis, Bill and Julie Lewis, William and Laurie Lucu, Richard Mabel A. Jaeger L T Maher, Peter Maley, William Maloney, Dennis Marinelli, Michael Marsh, Ben McDonald, John McDonald, Wm. Medema Family Trust Medema (Escrow Perry) Medema (Escrow Max) Uedema, Max Mellon, Dan Melum, Michael Miller, Jerry Minich, Henry S Moore, Jerry Morgan, James Mortensen, L. Keith Moseley Enterprises Myhre, Brian Myhre, Gregory Myhre, Philip Uyhre, Roger Nelson, Gary Newhouse, Joseph Norcap, Ltd Nugget Nevada Osborne, L. E. Oshlo, Doug Owen, James Owens, Tennys Owens, Wilson Parkin, C. L. Payne, Timothy Pease, Claire Penrose, Amelia Perry, Donna Perry, Sherron Persons, Robert Peterson, Steve Pfeifer, Mark Polaris 0.20000 0.40000 0.30000 0.10000 0.05000 0.01880 0.10000 0.05000 0.40000 10.00000 1.00000 1.00000 1.00000 0.10000 0.10000 0.30000 0.15000 0.03750 0.1 0000 0.21670 0.05000 0.10000 0.03750 0.40000 3.10000 O. 1 0000 0.05000 0.10000 0.1 0000 0.05000 0.15000 0.05000 1.00000 0.60000 0.80000 0.25000 0.50000 0.50000 0.30000 0.20000'''r''-' 0.05000 0.10000 0.1 O000 0.1 O000 O. 1 O000 0.05000 0.02500 0.1 0000 0.40000 0.22500 0.22500 11.82500 1.00000 2.00000 0.10000 0.1000..0 0.1000O 0.2O000 0.10000 0.70000 O. 15000 0.14166 0.26668 0.31670 0.1166(~ 0.1 0000 0.05000 0.4OO00 6.10000 O. 1 0000 0.1000(~ 0.10000 0.10000 O.lo0Ob 0.05000 0.05000 0.30000 0.05000 1.00000 0.8O000 1.30000 O. 10000 0.10000 0.5O000 0.20000 0.1 0000 0.30000 0.30000 O. 1 0000 O. 12500 O. 1 0000 O. 1 0000 0.05000 0.01880 0.05000 0.20000 0.40000 0.22500 0.22500 10.00000 1.00000 1.00000 1.00000 0.10000 0.20000 0.05000 O. 10000 0.40000 0.70000 0.1 5000 0.O3750 O. 15000 0.21670 0.05000 0.03750 0.40000 2.1 0000 0.10000 0.05000 O. 1 0000 0.1 0000 O. 10000 0.05000 0.25000 0.05000 1.00000 0.60000 0.80000 0.25000 0.5OO00 Exhibit A, Page 3 Ramos, Frank Rasmussen Redmond, Charles Reid, Evelyn Renfro, Mike Renfro, Wm. Richardson, Jack Richardson, Dale Richardson, Kris Rickerson,Luther Robeds, Royce Rose, James or Whitney Rose, James or Alyson Ross #1 Ross #2 Ross #3 Ross DIC Rowley, Mark Rucker, Mitchell Rust, Henry Saladino, Antonio Sansumi, Inc. Schierhorn, Sarah Schneider, Carole Seaman, John Selman, Charles Selman, Dorothy Semeniuk, Nick Sharp, C. D. Sharp, David Shearer, Buddy Sheehan, Donald Sheehan, Donna Sheehan, Donna Marie Sheehan, Jeanne Sheets, Dale Shogrin, F. L. Skomp, Karl Snow Cache Investments Sourant, Jocelyn Sourant, Nicholas Spielman Family Trust Spielman, Lois Spielman, T. A. Stetson, Joshua Stewart, Steve Stewart, D. R. Stinson, Louann Stinson, Robert O. 1 0000 0.60000 11.00000 0.20000 0.20000 0.30000 0.07500 0.10000 0.20000 0.40000 0.40000 0.05000 0.02500 0.35000 0.05000 0.30000 0.20000 0.03750 0.05000 O. 1 0000 0.05000 0.15000 O. 10000 0.20000 .... 0.20O00 0.10000 0.4OO00 0.10000 0.10000 0.10000 0.50O00 0.10000 4.00000 4.68750 0.50000 0.20000 0.10000 0.10~0-~--- 0.30000 0.1 0000 o.100o6 0.25000 0.3750~ 0.3750(~ 0.20000 0.10000 0.20000' 0.1 0000 0.20000 0.05000 o.o5o0o 0.1 0000 0.40000 0.05O00 0.10000 0.45O00 O. 15OOO 0.40000 0.30000 0.1 0000 0.12500 0.05000 0.20000 0.05000 O. 1 0000 O. 1 0000 0.05000 0.40000 0.40000 0.1 0000 O. 1 0000 0.20000 13.36370 0.50000 0.30000 0.30000 0.1 0000 0.10000 0.07500 0.10000 0.20000 0.4OO00 0.20000 O. 1 0000 0.05000 0.40000 0.05000 O. 10000 0.30000 0.20000 0.40000 O. 1 0000 0.03750 O. 12500 0.05000 O. 1 0000 Exhibit A, Page 4 Stra. ndberg, Doug Sumpter, O.E. Swickle, Edward T&R Tenoil Two Thomas, Howard Thon, Evelyn Thon, Jeffery Thon, Tristan Tischer, Rebecca Tracy,' Virginia Thurman, James Thurman Oil & Mining Twitchell, Bryce Urling, Jerry Vallee, Grace Vallee, Wm. Viktoria Ptnrship Vincent, Dennis Vogler, Steve Von I mHof, Chris Walters, Stanley Waters, Ray Weagel, Donna Weagel, Ed Weagel, Robed Von West, Robed Weste, Tammy White, Paul Whyel, George Wichorek, Paul Winslett, Charlotte Wirkkala, Jack Woodson, Georgia Woolery, John Yorke, Michael Stewart Petroleum 0.20000 0.02500 0.02500 0.60000 0.4000O 0.20000 0.05000 0.35000 0.05000 3.25000 0.40000 0.02500 0.1 0000 0.25000 0.10000 0.03750 0.20000 0.05000 0.05000 0.20000 0.05000 1.00000 0.05000 0.10000 0.05000 72.28130 27.71870 0.50000 0.1 0000 0.40000 .... 0.40000 0.20000 0.05000 0.70000 0.05000 0.05000 0.05000 6.00000 0.10000 0.40000 0.10000 0.20000 0.20000 0.05000 0.10~0-0---- 0.20000 0.05000 0.05000 0.05000 0.40000 0.05000 0.50000 0.2000(i .,. 0.05000 ., 0.05O00 0.1000(~ 0.10o00 0.05000 0.10000 86.36250 13.63750 0.30000 O. 10000 0.60000 0.40000 0.20000 0.60000 0.05000 6.00000 0.40000 0.12500 0.06250 O. 1 000O 0.03750 0.20000 0.05000 0.05000 0.1 0000 0.20000 0.05000 0.50000 O.05000 0.10000 O.O5OOO 77.59500 22.405 100.00000 100.00000 100.00000 Artus, Wm. Battley, Kenneth Blocker, John R. Blocker, Trustee, John R., Christianson, Cabot Encap Energy, LLC Escopeta Oil & Gas Escopeta Alaska Production Pope, John Roberts, Cathryn Bennett, Connie Blocker Polar Bear 0.37195 0.78125 2.20000 3.00000 0.1~75 0.25000 1.00000 1.00000 0.0~40 0.0~40 .6 0.036* *disputed 0.00372 0.78125 2.20000 3.00000 0.14875 0.25000 1.00000 1.00000 0.04840 0.04840 .6 0.036 0.00372 0.78125 2.20000 3.00000 O. 14875 0.25000 1.00000 1.00000 0.04840 0.04840 .6 0.036 RE'¢EIV D 1.89000 Exhibit A, Page 5 West McArthur River Unit Cape Starichkof West Trading Bay South McArthur South Trading Bay Exhibit B Leases Lease Numbers ADL 359111 ADL 359112 ADL 3 84403 ADL 384404 ADL 381216 ADL 381012 ADL 381030 SPC and Co-Owner Interest being sold 100% working interest 100% working interest 33.3% working interest 33.3% working interest 33.3% working interest 33.3% working interest 33.3% working interest West Redoubt Shoal ADL 387023 100% working interest Exhibit C Forcencrgy Contract Summary The proposed contract between the Debtor and Fore. energy is found as an exhibit to the Debtor's Second Amended Disclosure Statement dated March 31, 1997, and is summarized here: . . . . . . . 10. 11. Assets Forcenergy acquires from SPC: a. 100% of the WMRU working interests 33% of the working interest of non-producing Cook Inlet leases other than West Redoubt Shoal 100% of the working interest of West Redoubt Shoal Price paid for assets acquired: $23,250,000.00 Minimum title to be transferred on June 5, 1997: 75% of the working interest in the WMRU. Price penalty for delivering less than minimum title to WMRU: Working Net Revenue Interest Interest Purchase Price Delivered 100% 75% 23,250,000 95% 71.25% 22,050,000 90% 67.5% 18,350,000 85% 63.75% 17,295,000 80% 60.0% 16,260,000 75% 56.25% 15,225,000 Closing shall occur on or before June 5, 1997. SPC may transfer the minimum 75% of working interest on June 5, 1997 and the remainder of the 100% of the working interest in WMRU on or before Decxanber 31, 1997 without penalty. SPC will retain overriding royalty with respect to each Non-Producing Leases, except for the two Non-Producing Leases affecting Cape Starichkof Area, equal to 2.5%, proportionately reduced to the interest therein conveyed by SPC to Foreenergy. SPC will retain overriding royalty in Cape Starichkof Area equal to 4.0%, proportionately reduced to the interest conveyed by SPC to Forcenergy. SPC shall receive a 2% ovemding royalty to that portion of WMRU Lease determined to be a discovery well. SPC shall receive as overriding royalty equal to 50% of any discovery royalty reduction is non-WMRU leases other than Starichkof. SPC shall receive a 4% proportionately reduced royalty to that portion of Starichkof Leases determined to be a discovery well. If the Starichkof leases produce more than 50,000,000 barrel of oil, SPC will receive additional ovemding royalties. F_zik LeRoy P.C. AUomcy 1016 W. 6th Ave. Stc 420 Anchorage, AK 99501 (907) 277-2006 Erik LeRoy, P.C. 1016 W. 6th Ave., Ste 420 Anchorage, AK 99501 (907) 277-2006 Attorney for Debtor MAP, CLERK IN THE UNITED STATES BANKRUPTCY COL~;~qBANKRUPTCY COURT. - DEPUTY CL~.PJ~" FOR THE DISTRICT OF ALASKA In re: STEWART PETROLEUM CO., Debtor. Case No. A96-00795-DMD DEBTOR IN POSSESSION'S MOTION TO SELL PROPERTY FREE & CLEAR OF ANY INTEREST IN SUCH PROPERTY PURSUANT TO 11 U.S.C. 363(f)with MEMORANDUM MOTION The Debtor in Possession, through Steven Hartung its President, and undersigned counsel, moves this court for an order permitting the sale to Forcenergy, Inc. of the estate's interest in the West McArthur River leases, ADL 359111 and ADL 359112, and the estate's interest' in the Non-Producing Leases, ADL 384403, ADL 384404, ADL 381216, ADL 381012, ADL 381030 and ADL 387023, free and clear of the interests of unrecorded working interest and any claims or liens against the property under 11. U.S.C. 363(0. This Motion is supported by the following Memorandum in Support. MEMORANDUM IN SUPPORT F orcenergy, Inc. has offered to purchase 100% of the working interest in the West Mc. Arthur River Unit and West Redoubt Shoal leases and 33.3% of the working intereSt in the other Cook Inlet non-producing leases for $23,250,000.00. A proposed contract between the Debtor and Forcenergy is appended to the March 31, 1997 Second Amended Disclosure Statement. The specific interests Forcenergy has offered to acquired are described in Section 36309 Motion and Memorandum page 1 ~ OJ[ & 6as ~oas. ~~ Erik LeRoy P.C. 1016W. 6th Ave. Ste 420 (907) 277-2006 Exhibit A to this Memorandum. Forcenergy's offer is contingent upon the Debtor conveying at closing on June 5, 1997, a minimum of 75% of the working interest in the WMRU leases. By separate adversary actions, the Debtor seeks to sell both the recorded and unrecorded working interests in the leases described in Exhibit A. Under 11 AAC 82.615 et. seq. an assignment of an State of Alaska oil and gas lease is not effective against the State of Alaska until it is approved by the Department of Natural Resources. Under AS 40.17.080 et. seq., to be effective against a bona fide purchaser, a conveyance of a lease must be recorded in the property records in the recording district in which it is located. As of the September 13, 1996 petition date, the Debtor retained recorded title to 57.20125% of the working interest in the WMRU leases. (Summary of the Department of Natural Resources Assignments and Anchorage Recording Office recordation attached as Exhibit B.) As of July 24, 1996, the Debtor had executed DNR Lease Assignments conveying to more than 200 individuals and corporations between 72% and 87% of the working interests in West Mc. Arthur River Unit Wells No. lA, 2 & 3. ( Investor Participation in working interest attached as Exhibit C.) In addition to these assignments, by July 24, 1996, the Debtor had transferred the following additional Polar Bear John Blocker BattleyGroup Pope/Roberts Escopeta Oil Escopeta Production Encap interests: Consequently, by July 24, 1996, the in WMRU. 3.6% ORRI 11.2% working interest 1.0195% working interest 0.0968% working interest 1% working interest 1% working interest 0.25% working interest 18.1663% Debtor had transferred almost all of the working interests However, as of the petition date, based upon the records of the DNR and the Anchorage Recording Office, the Debtor held approximately 56% of the working interest of the Section 363~ Motion and Memorandum page 2 ~ LeRoy P.C. 1016 W. 6th Ave. Ste 420 Anchorage, AK 99501 (907) 2T'/-2006 WMRU. The remaining 44% of working interests which the debtor had transferred to his investors were unassigned at DNR and unrecorded in the books of the Anchorage Recording Office. These interests appear on Exhibit C to this Memorandum. Under 11 U.S.C. 363(0, after notice and hearing, the The trustee may sell property under subsection(b) or (c) of this section free and clear of any interest in such property of an entity other than the estate, only if - (1) applicable nonbankruptcy law permits sale of such property free and clear of such interest; (2) such entity consents; (3) such interest is a lien and the price at which such property is to be sold is greater than the aggregate value of all liens on such property; (4) such interest is in bona fide dispute; or (5) such entity could be compelled, in a legal or equitable proceeding, to accept a money satisfaction of such interest. The Debtor has moved for an order authorizing the sale of all of its interests in the leases described in Exhibit A free and clear of all liens, claims and interests, including any claims for successor liability, whether or not related to environmental matters, state trespass, nuisance, negligence, strict liability and other tort claims of any kind, and free and clear of ali environmental liabilities under applicable federal, state and local statutes, regulations, ordinances, rules, orders or other applicable law. Such relief is available under either 363(0(4) or (0(5). The unassigned and unrecorded working interests are subject to bona fide dispute under Section 363(0(4). Unrecorded transfers or real property interests can be avoided under 11 USC 5~.d(a) In re Probasco, 839 F.2d 1352 (9"' Cir. 1988). An unrecorded working interest in an oil lease is no different and can be avoided under 11 USC 544. In re Cascade Oil, 65 BR 35(Bkrtcy D. Kan. 1986)("The trustee or as is in this case the debtor in possession, pursuant to its status as bona fide purchaser under section 544(a)(3) is entitled to avoid the Section 363(f) Motion and Memorandum page 3 APR 9 1997 Alaska .0/1 .& Gas Cons. Cp.[itilliS.s.toi' Anc~orage~ Erik LeRoy P.C. 1016 W. 6th Aw. Stc 420 (~) 2~-2006 assignments to the "investors"... all of which were unrecorded on the date the petition for relief was filed."); In re Lynn Jones, 77 BR 541, ,544 (Bkrtcy N.D. Tex 1987); In re Bethel Resources 79 BR 717, 721 (Bkrtcy S.D. Ohio 1987). To be a bona fide dispute under section 363(f)(4) the dispute does not have to be the subject on a concurrent adversary action. In re Collins 180 BR 447, 452 (Bkrtcy ED VA); In re Octagon Roofinq, 123 BR 583, 590 (Bkrtcy ND III 1991). All that is needed to approve a sale under section 363(0(4) is that there is an objective basis for a dispute. See In re Gerwer, 898 F.2d 730 (9~ Cir. 1990). Unrecorded working interests have not suggested any reason so far in this bankruptcy why the issue of whether their interests are or are not avoidable is not a bona fide dispute.~ The Debtor believes that a sale of the WMRU leases to Forcenergy, Inc. is in the best interests of the Debtor, its creditors and all working interests. As explained in the Seconded Amended Disclosure Statement, the risks of operating the WMRU field are substantial and the price Forcenergy has offered is reasonable when all projections for the WMRU leases are appropriately risk adjusted. Consequently, the Debtor requests that an order be entered selling the interests described above to Forcenergy, Inc. free and clear of the interests of unrecorded working interests, all liens, claims and interests, including any claims for successor liability, whether or not related to environmental matters, state trespass, nuisance, negligence, strict liability and other tort claims of any kind, and free and clear of all environmental liabilities under applicable federal, state and local statutes, regulations, ordinances, rules, orders or other applicable law. Dated March 31, 1997. Erik LeRoy, P.C. ~ The sale could also be confirmed under section 363(0(5) because unassigned and unrecorded working interests could be compelled to accept money satisfaction because they can be compelled to accept treatment under a plan of reorganization. See In re Grand Slam, 178 BR 460, 462 (D. E.D. Mich 1995). Section 36309 Motion and Memorandum page 4 Exhibit A Leases Lease Numbers SPC and Co-Owner Interest being sold West McArthur River Unit ADL 359111 ADL 359112 100% working interest 100% working interest Cape Starichkof ADL 384403 ADL 384404 33.3% working interest 33.3% working interest West Trading Bay ADL 381216 33.3% working interest South McArthur ADL 381012 33.3% working interest South Trading Bay ADL 381030 33.3% working interest West Redoubt Shoal ADL 387023 100% working interest APR 9 1997 FILING AND RECORDING ANALYSIS OF ORRi CWi & WI AT WMRU Assi~lnmentRecorded ~lross Interest net Interestcharacter 100 State -12.5 -12.51 ORRI Wagner -5 -51 ORRI Stewart 06/19191 -7.5 -7.5 Ssang. 06/21/91 06/21/91 -50 Blocker 03~20/95 03/20/95 -6 -5.25 CWI Artus 04/13/95 03/30195 -0.37195 -0.325456 CWI Battley 04/13195 03/30195 -0.78125 -0.683594 CWI Cabot 04/13195 03/30/95 -0.14875 -0.130156 CWI Cohn 06/05/95 06122195 -1.8 -1.8 ORRI Fayez 06~05~95 06/22195; -1.8 -1.8 ORRI Blocker 06~08~95 06~08~95 -1.2 0.875 CWl Pope 06~08~95 -0.0484 -0.04235 OWl Roberts 06~08~95 -0.0484 -0.04235 OWl Ssang 08115~95 50 -12.19875 -9.198906 Potential Sec. 548 transfers EO & G 09~06~95 09~25~95 -1 -0.875 OWl EP 09~06~95 09~25~95 -1 -0.875 OWl Blocker 11/02/95 01104196 -3 -2.625 OWl Blocker 11/02/95 11/01/95 -1 -0.875 OWl Encap 01/04/96 01/12/96 -0.25 -0,21875 CWl Med. Tr 03/26/96 -04/03/96 -10 -8.75 WI Medema 03/26/96 04/03/96 -2 -1,75 WI Perry 03/26/96 04/03/96 -2 -1,75 WI -20,25 -17,71875 potential Sec 547 transfers Cotting 08/28/96 -0.033333 -0.029164 WI Soumnt 08/28/96 -0,36667 -0.320836 WI Sourant 08/28/961 -0.13333 -0.116664 WI Thomas 08/28/96 -0,2 -0.175 WI Strandbg 08/28/96 -0.33333 -0.291664 WI Owens -08/29/96 -0.1 -0.0875 WI Renfro 09/03/96 -0.36667 -0.320836 WI Renfro 09/0::)/96 -0.06667 ._-0.058336 WI Thurrnan 09/04196 -5.08333 -4.447914 WI Nugget 09113196 -3.66667 -3.208336 WI -10.35 -9.05625 Investor's Participation in V~. ~. as of 07/24/96 Revised 3/26/97 Name 90-2 Corporation Aleut Corp Allen, Jeff Atwood, Sandra Atwood, Burton IV Atwood, Letitia Atwood, Robert Baer, Paul Bankston IRA Bell, Jesse Bennett, Connie Bernard Trevelyan Berry, Thomas Biddle, Graham Bieber, Craig Bishop, Jim Bovey, Glenn Breaker, Sara Bringmann, George Burgess, Jason Burgess, Jeff Burgess, Greg Burgess (L.A.B.) Burrows, W. Don Burrows, Jane Caley, Gerald Cedar Cliff Ranch Chambers, Delynne Chambers, Glen Chancellor, Harriet Chenier, Theo Chesler, Jeff Chesler, Leon Circa 84 Clark, D. Clark, Melanie Clinton (COIL) Coder, Kent Coder, Nell Cook Inlet Investment Cottingham, Kathleen Crosson, Peter Curtis, Glenn Dahl, Helene Dahl, Ray Dammond, Liliane Daum, David Daum, Richard W.l.% WMR #lA 0.20000 0.25000 0.10000 0.30000 0.10000 0.05000 0.05000 0.10000 0.15000 0.84000 4.72000 2.72000 5.50000 0.80000 0.12500 0.10000 0.90000 0.05000 0.10000 0.10000 0.10000 0.05000 0.02500 2.72O00 0.10000 0.10000 0.30000 O.O3750 0.23330 0.05000 Exhibit C, page 1 W.l.% WMR #2 0.20000 7.50000 0.12500 1.00000 0.20000 0.20000 0.20000 O.250OO O.2OO00 0.40O00 0.10000 0.10000 0.05000 0.20000 0.10000 0.10000 0.15000 0,04000 2.12000 0.12000 0.90000 0.80000 0.1000O 0.20000 0.20000 0.30000 0.05000 0.10000 O.O5O00 0.30000 0.10000 0.05000 0.05000 0.12000 0.20000 0.10000 0.50000 0.10000 0.10000 0.02500 0.23330 0.10000 0.10000 0.22500 W.l.% WMR #3 0.20000 7.50000 0.12500 0.10000 0.30000 0.10000 0.10000 0.20000 0.10000 0.10000 0.15000 0.14000 2.32000 0.32000 2.00000 0.12500 0.30000 0.50000 0.05000 0.10000 0.05000 0.30000 0.10000 0.05000 0.05000 0.32000 0.50000 0.02500 0.07500 0.23330 0.10000 0.25000 Davis, Nancy Davis, Perry Dick, John Doupe, Linda Doupe, Ronald Doupe, Thomas Doupe, Woodrow Downer, Ann Downer, William Dunbar, Wm Dunbar, B L Ebisu, John Eledge, Sharon Eledge, Randall Elkins, Carole Enberg, Richard First InterBank Fitzhugh, Steve Fontaine,Oarol Frye, Naomi Gibson, David Gibson, Edith Gibson, Paul Gilmore, Wayne Goeddertz, Terrell Goens, Michael Goerig, GeOrge Graham, George Halkett, Pauline Hall, David Haxby, John Haxby, Mary Haziot, Monika Haziot, David Hoenack, Karl Hopkins, Kristine Horne, Peggy Huntley, Edward Ibbotson, Margaret Ihlen, Larry Iverson, Larry Johnson, Dan 0.10000 1.20000 O.2OO0O 0.02500 O.1O0OO 0.10000 0.20000 0.10000 0.10000 0.20000 0.05000 0.05000 0.30000 0.20000 0.15000 0.10000 0.05000 0.07500 0.05000 0.20000 0.05000 0.15000 0.05000 0.10000 0.10000 0.10000 0.02500 0.10000 0.05000 0.10000 0.20000 0.20000 Jones, Douglas 0.30000 Jones, Robed 0.10000 Keading, Lewis 0.40000 Kearns, James 0.07500 Kehl, Alfred 0.20000 Kothe, James Kruger, Hans & Silvia 0.40000 Langland, Marc 0.30000 Lauterbach, Wallace 0.10000 Leary, Linda Lesko, Nancy 0.~ .00 1.20000 0.20000 0.05000 0.20000 0.10000 0.20000 0.10000 0.10000 0.25000 0.25000 0.20000 0.05000 0.05000 0.20000 0.50000 0.20000 0.10000 0.20000 0.10000 0.27500 0.05000 0.05000 0.05000 0.10000 0.50000 0.10000 0.10000 0.05000 0.20000 0.20000 0.20000 0.20000 0.20000 0.10000 0.40000 O.4OO00 O.30000 0.10000 0.50000 0.10000 0.50000 0.30000 0.20000 0.05000 0.10000 0.30000 1.20000 O.200OO O.O2500 0.20000 0.2OO0O 0.20000 0.10000 0.25000 O.25O00 0.20000 0.10000 0.30000 0.10000 0.30000 0.10000 0.10000 0.10000 0.05000 0.05000 0.05000 0.10000 0.20000 0.20000 0.10000 0.15000 0.10000 0.10000 0.12500 0.02500 0.10000 0.05000 0.20000 0.40000 0.3O000 0.10000 0.40O00 0.07500 0.20000 0.10000 0.30000 R 0.12500 Pfi 9 1 t ooo Exhibit C, page 2 Alaska Oil & 6as Cons. Comm'tsstu' Anchorage Lewis, Bill and Julie Lewis, William and Laurie Lucu, Richard Mabel A. Jaeger L T Maher, Peter Maley, William Maloney, Dennis Marinelli, Michael Marsh, Ben McDonald, John McDonald, Wm. Medema Family Trust Medema (Escrow Perry) Medema (Escrow Max) Medema, Max Mellon, Dan Melum, Michael Miller, Jerry Minich, Henry S Moore, Jerry Morgan, James Mortensen, L. Keith Moseley Enterprises Myhre, Brian Myhre, Gregory Myhre, Philip Myhre, Roger Nelson, Gary Newhouse, Joseph Norcap, Ltd Nugget Nevada Osborne, L. E. Oshlo, Doug Owen, James Owens, Tennys Owens, Wilson P arkin, C. L. Payne, Timothy Pease, Claire Penrose, Amelia Perry, Donna Perry, Sherron Persons, Robert Peterson, Steve Pfeifer, M ark Polaris Ramos, Frank Rasmussen Redmond, Charles Reid, Evelyn Renfro, Mike Renfro, Wm. Richardson, Jack Richardson, Dale 0.05000 0.01880 0.10000 0.05000 0.400O0 10.00000 1.00000 1.00000 1.00000 0.10000 0.10000 0.30000 0.15000 0.03750 0.10000 0.21670 0.05000 0.10000 0.03750 0.40000 3.10000 0.10000 0.05000 0.10000 0.10000 0.05000 0.15000 0.05000 1.00000 0.60000 0.80000 0.25000 0.50000 0.10000 0.60000 Exhibit C, page 3 0.~ ,00 0.10000 0.10000 0.05000 0.02500 0.10000 0.400OO 0.22500 0.22500 11.82500 1.00000 2.00000 0.10000 0.10000 0.1000O 0.20000 0.10000 0.700OO 0.15000 0.14166 0.26668 0.31670 0.11666 0.10000 0.05000 0.40000 6.10000 0.10000 0.10000 0.10000 0.10000 0.10000 0.05000 0.05000 0.30000 0.05000 1.00000 0.80000 1.30000 0.10000 0.10000 0.50000 0.15000 0.10000 0.20000 0.20000 0.10000 O.4OOOO 0.10000 0.10000 0.05000 0.01880 0.05000 0.20000 0.40000 0.22500 0.22500 0.00000 1.00000 1.00000 1.00000 0.10000 0.20000 0.05000 0.10000 0.4000O 0.70000 0.15000 0.03750 0.15000 0.21670 0.05000 0.03750 0.40000 2.10000 0.10000 0.050OO 0.10000 0.10000 0.10000 0.05000 O.25000 0.05000 1.00000 0.60000 0.80000 0.25000 0.50000 0.10000 0.05000 0.40000 0.40000 0.10000 Richardson, Kris Rickerson,Luther Roberts, Royce Rose, James or Whitney Rose, James or Alyson Ross #1 Ross #2 Ross #3 Ross DIC Rowley, Mark Rucker, Mitchell Rust, Henry Saladino, Antonio Sansumi, Inc. Schierhorn, Sarah Schneider, Carole Seaman, John Selman, Charles Selman, Dorothy Semeniuk, Nick Sharp, C. D. Sharp, David Shearer, Buddy Sheehan, Donald Sheehan, Donna Sheehan, Donna Marie Sheehan, Jeanne Sheets, Dale Shogrin, F. L. Skomp, Karl Snow Cache Investments Sourant, Jocelyn Sourant, Nicholas Spielman Family Trust Spielman, Lois Spielman, T. A. Stetson, Joshua Stewart, Steve Stewart, D. R. Stinson, Louann Stinson, Robert Strandberg, Doug Sumpter, O.E. Swickle, Edward T&R Tenoil Two Thomas, Howard Thon, Evelyn Thon, Jeffery Thon, Tristan Tischer, Rebecca Tracy, Virginia Thurman, James 11.00000 0.20000 0.20000 0.3O000 0.07500 0.10000 0.20000 0.40000 0.4OO0O 0.05000 0.O25O0 0.35000 0.05000 0.30000 0.20000 0.03750 0.05000 0.10000 0.05000 0.20000 0.02500 0.02500 0.60000 0.40000 0.20000 0.05000 0.35000 O.O5OO0 3.25000 Exhibit C, page 4 o.i"i' .oo 0.10000 0.50000 0.10000 4.00000 4.68750 0.50000 0.20000 0.10000 0.10000 0.30000 0.10000 0.10000 0.25000 0.37500 0.37500 0.20000 0.10000 0.20000 0.10000 0.20000 0.05000 0.05000 0.10000 0.40000 0.05000 0.10O0O 0.45000 0.15000 0.40000 0.30000 0.10000 0.12500 0.05000 0.20000 0.05000 0.10000 0.50000 0.10000 0.07500 0.40000 0.40000 0.20000 0.05000 0.70000 0.05000 0.05000 0.05000 0.10000 0.20000 13.36370 0.5O0O0 0.30000 0.30000 0.10000 0.10000 0.07500 0.10000 0.20000 0.40000 0.20000 O.1OOOO 0.05000 O.4O000 0.05000 0.10000 0.30000 0.20000 0.40000 0.10000 0.03750 0.1250O 0.05000 0.10000 0.30000 0.10000 0.15000 0.60000 0.40000 0.20000 0.60000 0.05000 1997 4laska Oil & GasCons. Anch'orage. Thurman Oil & Mining Twitchell, Bryce Urling, Jerry Vallee, Grace Vallee, Wm. Viktoria Ptnrship Vincent, Dennis Vogler, Steve Von ImHof, Chris Walters, Stanley Waters, Ray Weagel, Donna Weagel, Ed Weagel, Robert Von West, Robed Weste, Tam my White, Paul Whyel, George Wichorek, Paul Winslett, Charlotte Wirkkala, Jack Woodson, Georgia Woolery, John Yorke, Michael Stewart Petroleum Bennett, Connie 1.89 in Well 1 0.40000 0.02500 0.10000 0.25000 0.10000 0.03750 0.20000 0.05000 0.05000 0.20000 0.05000 1.00000 0.05000 0.10O0O 0.05000 72.28130 27.71870 100.00000 6.~ .00 0.10O0O 0.40O00 0.10OOO 0.20000 0.20000 0.05000 0.10000 0.20000 0.05000 0.05000 0.05000 0.40000 0.05000 0.50000 0.20000 0.05000 · 0.05000 0.10000 0.10000 0.05000 0.10000 86.36250 13.63750 100.00000 6.00000 0.40000 0.12500 0.06250 0.10000 0.03750 0.20000 0.05000 0.0500O 0.10000 0.20000 0.05000 0.50000 0.05000 0.10000 0.05000 77.59500 22.405 100.00000 Exhibit C, page 5 Dan R. Johnson P.O. Box 191004 Anchorage, AK 99519 (907) 245-1486/275-3600-Pager April 7, 1997 David W. Johnston Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Petition of concerns related to Stewart Petroleum Company proposed waterflood operation. Dear Mr. Johnston: I have been an investor in the Stewart Petroleum Company since November 1, 1989 in the development of the "West McArthur River Unit Project" located in the Cook Inlet Basin of Alaska. I have.a working int~est ownership i~ tl~ t~e~ producing wells of the West McArthur River Unit, .x~lls. #I';:#2~ .& IL3,, and~have~l~ia*ll~ i~oice for my proportionate share for the proposed water~od/pressure I haveii~tta~d8. let~.'.*r ~ted.~tU~eh ~: 199~ I submitted to Mr. Steve Hartung, CEO, for Stew ''''~: Peti~ i':i"~"' '~ =' ~"" =~"~ ~ W: tl!,.:~ues09~] and.:co~n~q'egarding the proposed pressure maintenance ~i .: ~,:J .... '~ . >.- ..... plan, ~'tong _~tnfor,~txon!~,ni~e ~ategll~ _~easibflity Study of West McArthur River Umt. ?" :::r [u ~.) r' 0'] ::J "' mm -< :.. .. ....} .~ ~ . . I attended a~ie~,'ng:with ~mn~ on~3vfiir~ 25, 1997 m response to my quesuons and tone'ns reOrmg hie ~rop4"~je~i~res~[ure~,~,,ir~nance plan Mr. Hartung gave mca copy of a memo i!6f correspondence from Mr. ~. ltefl~_e~ regarding the pressure maintenance of West McArthur River Unkl I will be out of town from April 12, 1997 until May 2,1997. Ifa public hearing is held on the matter on April 22,199?, would there be an opportunity for me to attend the hearing telephonically or, is there a possibility the hearing could be reschedule so I could attend in person. If you have any questions please contact me before I leave town on April 12,1997. Sincerely: Dan R Johnson Working Interest Owner RECEIVED AP~ O7 1991 Alaska Oil & Gas Cons. Commission Armhorage Dan R. Johnson P.O. Box 191004 Anchorage, AK 99519 (907) 275-3600 March 5, 1997 Mr. Steve Hartung, CEO Stewart Petroleum Company 4700 Business Park Blvd., Suite #13 Anchorage, Alaska 99503 RECEIVED Alaska 0il & Gas Cons. Commission Anchorage Re: West McArthur River Field Unit Proposed Pressure Maintenance Plan. Dear Mr. Hartung: I am writing in response to questions and concerns regarding the proposed pressure maintenance plan of the West McArthur River Field in the Cook Inlet Basin of Alaska. I have attached a letter dated February 12, 1997 with questions from an individual who was previously involved with the Stewart Petroleum proposed pressure maintenance plan of the West McArthur River Field. In addition, I have attached a letter dated January 11,1996 sent to Mr. Stewart with questions and concerns regarding the proposed pressure maintenance plan. I have worked on the North Slope at Prudhoe Bay with the Petroleum Engineer Group tbr British Petroleum Exploration Inc., and am familiar with water flood operation along with problem associated with secondary recovery methods. I felt it was necessary to discuss the potential concerns of the proposed pressure maintenance plan, with other working interest' owners that have a large amount invested in the West McArthur River Field, as I do. It was decided that the questions and concerns warrant research, and since I had a working relationship with people that have the experience and expertise in the reservoir engineering field, I took on the task The following Proposed Work Plans and Water Flood Feasibility Study of West McArthur River Unit were based on 300 pages of Well file data, along with the fact of insufficient core samples and the lack of fluid analyses information fi'om the (WMRU). A special cores analyses (SCAL) and fluid analyses (PVT) would have to be obtained from the neighboring McArthur River Unit. 1.) Orbis Engineering, Inc., Denver, Colorado, reservoir engineering firm with the expertise and experience in oil and gas property evaluation. Orbis proposes a 5 step work plan to complete a reservoir study to optimize. The estimated cost of completing steps 1-4 would cost $16,500 and take 7-9 weeks to complete. The cost associated with step 5, should it be necessary, is estimated to be an additional $7,000-18,000 depending upon the number of scenarios and details required. A copy of the Orbis Engineering Proposed Work Plan is attached. t. 2.) GeoQuest-A Division of Schlumberger Canada Limited Reservoir Technologies. GeoQuest estimates that a total of 19 man days of engineering and technician time will be required to collect and review the initial data, construct the simulation model, history match the GOR, watercut and pressure histories, setup and run a total of six tbrecast cases, and to document the results. The total cost for the engineering study, including travel, is expected to be approximately $23,400. A copy of GeoQuest the Proposal to conduct a Water Flood Feasibility Study is attached. I have attached additional information on two other companies with the expertise and experience in oil and gas property evaluation (1 .) ALLEN & CROUCH Petroleum Engineers, Casper, Wyoming (2.) CAWLEY, GILLESPIES & ASSOCIATES, Inc. Petroleum Consulants, Fort Worth, Texas. The President of the company, Mr. Richard F. Strickland, mentioned to me that they had recently reviewed the West McArthur Field for a potential investor. In summary: The pressure is declining at West McAthur River Field and will need a waterflood design to maintain pressure to provide optimum production and enhanced oil recovery..This is also needed to stay in compliance with the State of Alaska's pressure maintenance management of a reservoir. Those issues are not in dispute, but rather the potential concerns and questions attached with the (WMRU) proposed pressure maintenance plan, are the issues of incremental recovery factor, efficiency due to an unbalanced nature of the project with one injector and three producers, concerns of premature breakthrough of water, injection rates, pressure performance of the water flood, process hcility water handing capabilities, and time factor of the secondary oil recovery before the economic limit is reached, are of concern. To construct a water tlood simulation model of the West McAthur reservoir would help assist in evaluating the reservoir performance and to predict future oil, gas, and water rates and recovery factors. The simulation model is only a tool to analyze the reservoir, but due to the critical future and life of the West McArthur River field, I would hope that Stewart Petroleum uses every tool available in the best interest of all parties involved. I would appreciate hearing from you as soon as possible regarding this matter. Sincerely: Dan R. Johnson Working Interest Owner CC: Ray Dahl, Working Interest Owner James L. Thurman, Working Interest Owner Armand Spielman, Working Interest Owner Kenneth W. Battley, Managing Agent Paul White, Stewart Petroleum RECEIVED Alaska Oil & Gas Cons. Commission Amhorage TO: Dan Johnson The following are my questions on the WMRU proposed pressure maintenance plan. 1) incremental secondary reserves will be impacted by the sweep effic, iency (think of it as the top view of the water sweeping a swath of oil from the injector to the producer). The McA~hur River Field has a full-blown peripheral w-aterflood pattern with injectors ail around the outside of the field. The WMRU plan will only have one injector and three producers. This has to be mucfq more inefficient and the incremental recovery factor should De much less. Primary recovery will only be 7.:3% of the oil in place so secondary recovery should De only an incremental fraction of this, pemaps 1/3 at best or 2.4% of the OOIP which is only 1.$MMBO. Huddleston says there will be an equal amount of proved secondary reserves as primary and this is not possible with a one well injection program. 2) in addition, I don't see how the Huddleston report can add on probable secondary oil of another 14.6% of the oil in place without ddiling more injectors and more producers. The Hudctleston report is operating off OOIP of 54 MMBO. This is not dgtlt because the 3 proclucers at WMRU have only developed the Stewart leases which is about 1/2 of the entire oil in the field. The remainder is net subject to secondary recovery or primary recovery. That is one mason why the primary recovery factor of 7.3% is so iow, it is 7.3% of too big of a number. Since only a part of the field has been developecl, only that same part of the field can be expected to gain benefit from the secondary recovery project. 1 think that is where Huddleston threw in some probable waterflood oil of an additional 14.6%. That would bring the total up to 30% which doesn't look too unrealistic to Mc, Arthur River Un~s 50% recovery but the big field developed the entire enchilada and ~q~IRU has only developed at}out 1/2 of its field. It is unrealistic to expect one injector to increase the field's oil production rate. It will hopefully decrease the decline but there is no way that the rate will ever see 95,000 BOPM again as the Huddleston report states. Wetl No. 2 (the prodsucer closest to the injector) will hopefully see some benefit pretty quickly and may even increase in oil production. But the other two wells will still be declining which will more than offset any gain to be seen in No. 2. Then as No. 2 waters out, the other two wells may see some leveling off from their decline but that will be more than offset by No. 2 falling in oil production and increasing c~rastically in water production. Overall, the oil rate will keep declining, it just hopefully won't decline as fast, This is due to ttle unbalanced nature of the project with one injector and 3 producers. It would be interesting to ask an engineering firm if this unbalanced t~e of waterflood could even possibly be the wrong thing to cio even if it was at no cost due to the risk of premature breakthrough of water. The injected water may make a beeline to the pressure sink of Well No. 2, No. 1 and No. 3 and water them out so quickly that them is' minimal secondary oil recovered before the economic limit is reached. RECEIVED Alaska Oil &.Gas Cons. C0rnmission Anchorage I am very concerned that there will not be anyone in charge of this project that knows anything about running an oil field let alone a waterflood project. Would you invest any adctitional 1'honey in the WMI~U project? That is what you are proposing by spending $3MM on the injection well. There wig be aJso be additional operating costs and complications keeping the waterftood going, if you don't have someone in charge that knows what they are .doing and has the autho~ and trust to spenct money where it needs to be 5peril then the waterflood will be a fiasco. Them is an oil boom going on and I thL'~l( everyone needs to maize that them is plenty of work out there for contractors and Knowledgeable oit people. Why would anyone go to work for someone who didn't pay their 13'tls, has questionable management and is run by a bunch of lawyem, wiqen they can work for Unocal, ARCO, BP, AnodeS, Forcenergy, otc? Sorry that I sound so negative, but that is how 1 feel. I i<now everyone is desperate to try to improve things, but you have to make sure you aren't making a bad situat~3n wOl:se. January ~t' I996 RE: WEST MCARTHUR RIVER 51ELD Cook Inlet Basin, Alaska Mr, Bill Stewart Stewart Pe~:oleum Company Denali Towers North, Suite 13~ 2550 Denali Street Anchorage, Alaska 99503 Dear Mr. Stewart: RECEIVED f. daska Oil & GaS Con~. Commissibn A~horage We acknowledge receipt of your undated letter set-ting' forth your recommendation to commence a pressure maintenance program in the West McArthur River Field, Cook Inlet Basin. As you know, JKG L.A., Inc. (subsidiary of Petroleum, Inc.), Petroleum, Inc., and Muffin, Lnc. own an interest in ail three wells in this field. While we recognize the potential need for repre~uring, we have a number of questions concerns relative to the manner in which you propose rd accomplish this. We are also concerned as to.why you propose to move at such a f,xst .~0. Our questions a_nd concerns are as follows: (1) It appears that the waterftood program you propose will systematically water out each well as the oil. front is shoved to the Northeast. The program would cause well 2A to water out first followed by IA. The #3 well would then be the only long lived producing well. Is this correct? (2) If the #3 well is the only producing well left, how does your proposed Watefflood program benefit all panic!pan? as you inctieated in your letter? (3) If the 2A well Waters out first, how does an owner with an interest in only this well benefit? ~4) Why would the owner in the early watered out wells even consider your program knowing their well will soon water out with the oil 'recovered essentially by the owners under the #3 well? (5) If the lA well is deemed to be non-commercial after sidetracked, could this well be an injector point? (6) Have you conducted a study that indicates your proposed program will (1) insure a greater ultimate recovery of oil/gas; and (2) protect the correlative rights of ali parties owning an interest in the various proration units? Mr. Bill Stewart January 11., 1996 Page Two (7) As set out ha your letter, the "Field Production Facilities" provision of hhe Participation Agreements provides that the costs for a water injection-well or wells shall be allocated evenly to the weil(s) producing or capable of producing and shall be borne by the participants in such welt or wells on ~¢ basis of ownership therein. Said provision also provides' that the non-consent provisions (subsequent wells) of tZe Operating Agreement are not applicable to water injection we'lis. Do you believe '~s provision precludes owners from participating in decisions relative to the what, when, where and how of a pressure maintenance program? (8) Do you plan to obtain ".input" or. accept~ce .from the Non-Operators as to the program you propose? .. · , We believe that the Non-Operators have the righ/., per ~aticle VII D.3. of ~e Operating Agreement, to participate in deciding what .type of pressure 'maintenance prograra is necessary, as well as when the program should be initiated. Said Article VII D.3. provides ti.at the Operator shall not undertake any single prc..jec[ estimated to require an expenditure in excess of $50,!)00 _withgut. the consent of ~. . (9) Do you plan to unitize the acreage currendy set up for the 3 wells and prepare a uvJfization agreement? (10) ff you do not unitize this acreage, how do you plan to hap. die the following: (a) day-to-day operations of the injection program, (b) billing of costs incurred after the ±r,Atial program costs, (c) allocation of revenue. (11) I.t' you do not unitize, how do you plan to comply with the Alaska Oil and Gas Conservation Commission's requirements for repressuring, unitization, allocation of urki.'t' production, etc.? ' (12) Normally, an engb~eefing'committee (e~stablished 'from the working interest owners) determines Lbo parameters of a waterftood proj~.ct taking into ac¢om~t the current production, feet of pay, cumulative production, remaining .reserves, etc. Tract participation percentages would be detenv, ined based on the collective decision of this comminee. Az Operators Committee (also established from the working in. teres, t owners) would prepare the applicable agreement, obtain acceptance of same by alt owners and then submit same to the Commission for their approval. Do you plan to establish either ~ engineering committee or an operators committee? .',,TE MA I I',ITEHAI',IC':.E P. 4-'6 Mr. Bill S~¢wan ~anuary 11,199~ Page Three As you can see, we have a number of problems with your repressure recommendation. need your response to the above questions ancot concerns before we cma respond to your AFB. We are aware that you haven't responded to Petroleum, Inc.'s letter dated August 3, 1995 wherein they had asked for answers on many questions concerning operating cos~ and other operational matters. Petroleum, Inc. is most interested in receiving your response. Your very early response ro r. his letter as well as Petroleum, Inc.'s lemr of August 3, 1995 is requested. Please direct your reply to the attention of each of the owners who are co- authors to this letter. JKG LA, INC. P~.TP, OLELrM, P{C. MURF~W, h-NC. E-,, . ,"/' Robert C Hearon David L. M~ .' }ohn K. G~'ey . "5' President Vice P~idenr President ORBIS ENGINEERING, INCORPORATED February 18, 1997 Mr. Dan R. Johnson P.O. Box 191004 Anchorage, AK 99519 Dear Mr. Johnson, Orbis Engineering, Inc. has reviewed the data package that you have provided regarding a potential pressure maintenance program in the West McArthur River Field. Based upon the available data, Orbis was able to develop a list of potential concerns with the proposed pressure maintenance program. In addition to the list of potential concerns with the program as described, a work plan and cost estimate for completing a reservoir study to better understand and optimize a pressure maintenance program was developed. Potential concerns with proposed pressure maintenance program: · An attempt to keep the reservoir net voidage rate (oil, gas, & water produced = water injected) equal to zero using a single injection source might result in rapid water channeling through the most permeable zones. This would result in a large portion (often times the largest from a hydrocarbon pore volume standpoint) of the reservoir volume being unswept and reserves left behind. Reservoir heterogeneity might result in very poor waterflood sweep efficiency. Waterflood reserves are directly related to sweep efficiency. Sweep efficiency has a vertical component as well as an areal one. Injecting water into a single well with a large degree of permeability variation up and down the wellbore leads us to believe that the value obtained for sweep efficiency would not be very high. · Permeability variation within each wellbore could result in the majority of injected water flowing through a single perforated interval, while only small fractions of injected water are left available to sweep less permeable zones. To increase the severity of this problem, the zones with less permeability are the ones which will have exhibited the lowest recoveries and have the most oil remaining to be recovered. This principle is illustrated by the lack of producing rate during the flow test on the West McArthur River #1 Well. · Treating permeability variation as if the system behaved like a uniform system with permeability equal to the geometric mean is an optimistic way to treat the problem. In fields with serious heterogeneity issues, a layered model should be used. If it is determined not to use a layered model, at the very least a model incorporating the Dykstra-Parsons permeability variation coefficient should be used to handle vertical permeability variation. · A pressure maintenance program should not be initiated without first identifying similar stratigraphic intervals between wells in the field. An understanding of these stratigraphic intervals would allow a better feel to be developed for potential channeling problems. o In one of the reports that you provided, the validity of a material balance analysis is questioned due to the lack of accurate gas production data. If the average reservoir pressure is still above the bubble point pressure, the lack of gas production data might not significantly effect the analysis. A good material balance analysis would help to confirm volumetric estimates of original oil in place (which would be more applicable to the study area that the total field volumetrics) and might provide a better understanding of the percent contribution of various reservoir drive mechanisms including- oil expansion and partial water drive energy. ORBIS ENGINEERING, INCORPORATED · 1801 BROADWAY. SUITE 1120 · DENVER, COLORADO 80202. U,S,A.. TELEPHONE [303) 295-0066 · TELEFAX [303) 295-0065 · Comparing a one well pressure maintenance program at West McArthur River with the success exhibited by the McArthur River Field waterflood is not a good analogy. The one well program at West McArthur River is more comparable to a pilot test in the McArthur River Field. Pilot tests often times are less successful than the full scale waterfloods that follow them due to the poor areal sweep efficiency associated with smaller pattern sizes with limited numbers of injectors. · On a proj. ect scale, the waterflood at the McArthur River Field (the analogy referred to in the documents) has been a success. However, some individual patterns within the field may have experienced premature water breakthrough due to channeling. The McArthur River Field is large enough to handle premature water breakthrough in a small number of its many patterns, however if water was to break through prematurely in the proposed WMRF program, the entire field would become uneconomic. To address these concerns and try to develop the most economical maimer in which to increase production from the WMRF, additional understanding of the reservoir is required. Orbis proposes the following steps to complete a reservoir study to optimize recovery from the WMRF. Proposed Work Plan: 1. Complete a brief review of the history and problems associated with the analogous McArthur River Field waterflood project. 2. Review the WMRF geology including- identification of various stratigraphic intervals, confirm the structure analysis, confirm porosity height distribution. 3. Run a material balance model on the available data to confirm Original Oil in Place and better understand reservoir drive mechanisms. 4. Develop a simple reservoir simulation model to estimate time to water breakthrough and reservoir sweep efficiency for the proposed pressure maintenance program 5. Estimate recovery and calculate economics for various water injection scenarios to optimize oil recovery and project economics. It is estimated that the cost of completing steps I-4 in the above work plan would cost approximately $16,500 and take 7-9 weeks. The cost'associated with step 5, should it be necessary, is estimated to be an additional $7,000-18,000 depending upon the number of scenarios and detail required. Orbis appreciates the opportunity to provide you with this work proposal. Your project appears to be one with a great deal of potential, and we would welcome the opportunity to help you increase recovery from the field. If you have any questions, please do not hesitate to contact us. Regards, M.P. Cleary ~' Keith Engler President / Petroleum Engineer Orbis Engineering, Inc. Orbis Engineering, Inc. r,,Jaska 0ii & (la~, Cons. hnch0ra~e Schlumberger - GeoQuest A Division of Schlumberger Technologies Corooration 500 W. International Airtoorl Road Anchorage, Alaska 99518 - 1199 (907) 562-7669 (Bus.) (907) 563-3309 (Fax) March 3.1997 Mr. Dan Johnson PO Box 191004 Anchorage, Alaska, 99519 Attached to this cover letter is a detailed proposal to conduct a water flood feasibility study on the West McArthur River Unit prepared by Mr. Warren Griswold of our Reservoir Technologies Group. The proposal is based on a limited data set supplied to Mr. Griswold and outlined in his opening paragraphs. The local GeoQuest office here in Anchorage has had the opportunity to work in detail with the Stewart log data and is well prepared to aid in any data collection which may be required for the study. In particular, correlation work and FMS facies analysis performed by our geologist Mr. Ted Bornemann could be used to provide detailed mapping as discussed in the "Geological Mapping" section of the proposal. As the available pressure data is somewhat limited we would recommend that a pressure build-up test be conducted on at least one of the wells before the simulation work is undertaken. Please feel free to contact Mr. Griswold or myself with any questions or comments you may have. Regards, Rob North /~ f'ff f' / Alaska Center Manager GeoQuest Interpretation & Computing Services RECEIVED March 3, 1997 Mr. Dan Johnson c/o GeoQuest ICS, Alaska 500 W. International Airport Rd. Anchorage, Alaska, USA 99515 Dear Mr. Johnson: Re~ Proposal to Conduct a Water Flood FeasibiliW Study on the West McArthur River Unit As requested by Mr. Rob North of GeoQuest (Anchorage), the Reservoir Technologies Group of GeoQuest (Calgary.), A Division of Schlumberger Canada Limited (GeoQuest) has prepared an outline of their proposed course of action and cost and time estimates to conduct a reservoir simulation study on Stewart Petroleum's interests in the West McArthur River Unit. The following estimate is based on limited information obtained during telephone conversations with Mr. North and a brief synopsis of the pertinent data and may be subject to revision as additional information becomes available. As we understand it, the primary objectives of this study are to evaluate the feasibility of water injection into the unit and to determine the optimum number of injectors and their location to provide the most efficient sweep of the hydrocarbon reserves. Secondary objectives could evaluate the potential of infill drilling with vertical (deviated) wells and/or horizontal wellbores, investigate the impact of surface facility and downhole constraints on the oil recovery., and to examine alternative depletion strategies. GeoQuest believes that all of the study objectives can be accurately and reliably achieved through the use of reservoir simulation. The West McArthur River Unit has been described to us as a closed anticlinal structure that has been faulted off of the much larger McArthur River Unit located to the northeast. The fault separating the two units is currently interpreted as sealing. The remainder of the anticline is bounded by a downdip, non-active waterleg. The structure incorporates a hydrocarbon bearing area of approximately 2000 acres. Three on-shore wells have been directionally drilled into the off-shore anticline, all of which have penetrated the producing horizon near the crest of the structure. Current well spacing is approximately 60 acres. One of these wells was abandoned after a short period of production and was subsequently redrilled in a more favourable position. Geologically, the reservoir consists of a series of hydraulically isolated sand/shale sequences which range in thickness between 10 and 120 feet. Four of the six identifiable sand units, however, range between 30 and 50 feet. The three lower sand units are expected to be water bearing. Porosities are in the order of 7 to 18 percent, with permeabilities in the range of 10 to 300 md. Water saturations are estimated to be between 20 and 40 percent. The 29° APl reservoir oil was discovered in 1991 at an initial pressure of approximately 4300 psia. While the reservoir is still well above the saturation pressure and is not in any immediate danger of falling below the bubble point (estimated to be approximately 931 psia) the reservoir had declined in pressure to 3000 psia by 1995. Watercuts at all three producing wells range between 30 and 50 percent. The mechanism of this water production is not currently known to GeoQuest at this time. Data Collection Prior to the construction of the simulation model, GeoQuest would collect data from Stewart Petroleum's well files to obtain copies of log data, conventional fluid and core analyses, wellbore configuration and completion specifics, workover histories, and any pressure surveys that have been performed to date. Details of the surface separator conditions and any constraining production limits are also required. It is currently anticipated that special core analyses (SCAL) and fluid analyses (PVT) are not available for this Unit and would have to be obtained from the neighboring McArthur River Unit. Production data for the four wells would have to be provided in an ASCII digital file. Production Analyst (PA) format would be preferable although any fixed data format is acceptable. Data Review Fluid property analyses would be entered into PI'Ti, GeoQuest's interactive equation-of-state based PVT package to review and verify the laboratory experiments performed on these fluid samples and to evaluate their consistency. Within PVTi these data can be calibrated to reflect the historical surface separator conditions and then a suitable PVT data set for the ECLIPSE simulator to be prepared. Relative permeability and capillary, pressure data measurements would be analyzed using $CALi, GeoQuest's interactive special core analysis program. Within SCALi, these data can be qualitatively reviewed, smoothed, normalized, and averaged. The program can also be used to automatically assign on a grid cell basis, a relative permeability curve or endpoint values for scaling as a function of depth, thickness, porosity, permeability, or lithology. Finally, tables and arrays of these data will be generated that can be directly imported into ECLIPSE. Production data would be loaded into SCHEDULE for evaluation, quality control checks, and preparation of the "schedule" section of the ECLIPSE data set. Well and group hierarchies can be defined in SCHEDULE as well as the calculation of the well connection factors. This latter feature is particularly useful if wellbore trajectories are not vertical or if a layer is partially completed (i.e., perforated interval is shorter than the layer thickness). Timestep periods, used for production averaging, can be automatically adjusted to accommodate major well or field events. Grid System A regular Cartesian grid system will be developed that incorporates the entire hydrocarbon bearing area with a series of uniform grid cells. Additional grid cells located in the downdip water bearing regions of the reservoir would be somewhat larger in size. It is currently anticipated that the interior grid system will be designed to allow infill drilling down to 40-acre spacing. With a minimum grid spacing of nine grid cells per well. the average grid cell dimensions should be approximately 440 feet on a side, or 4.4 acres in area. To minimize the number of grid cells, the primary axis of the grid should be oriented in a southwest to northeast direction. This orientation would also be conducive to the possibility of preferential flow along the perpendicular, secondary axis. To fully cover the entire simulation area, it is currently anticipated that the model would require approximately 55 grid cells along the length of the reservoir and 25 grid cells along the width for a total of 1375 areal grid cells in a single layer. Geological Mapping If the individual reservoir units are hydraulically isolated, with no chance of channeling behind the casing, then simulation of the water bearing layers is not required. However, since the source of the historical water production is not currently known, then at least one wet layer should be included in the simulation to allow some alternative methods of water production in the simulator. At this time, it is our understanding that only the upper three reservoir units are hydrocarbon bearing. Therefore, geological maps for the top four reservoir units should be mapped. A quick review of the type logs shows that the Bench 2 unit is of considerable thickness over most of the pool. This unit would need to be further subdivided into approximately five layers for the simulator. The remaining two hydrocarbon bearing units are both approximately 35 feet thick and should be subdivided into two layers each to model gravity segregation and the resulting under/over running of water and gas. This secondary layering could and should be based on stratigraphy if it is present and correlatable. If not, then geological maps can be prepared for each unit as a total and then GRID can subdivide each layer automatically based on equal or proportionate layering. GRID is GeoQuest's soft~vare package that transforms sophisticated geological models into an appropriate model for simulation. The suite of geological maps provided must contain the structure on the top of the porosity of Bench 1. To define the tops and bottoms of each subsequent layer, either gross thickness maps of each modeled unit can be used or, alternatively, a structure map for the top of porosity for each subsequent unit as well as the bottom of structure of the Bench 4 could be provided. If the net-to-gross ratio is not 1.0 then either maps of net porous sand (no Sw cutoff) or net-to-gross ratio must be provided for each unit. Maps of porosity distribution are also required for each unit. To provide the permeability distributions to the simulator either maps of horizontal permeability must be generated or a porosity/permeability transform must be supplied. This latter method would define the permeability distribution as a function of porosity. The brief reservoir characterization write-up that Mr. Rob North provided indicated that the Hemlock formation is characterized by two reservoir facies: sand and conglomerate. The conglomerate facies is apparently of poorer reservoir quality. Since the facies type could influence the porosity and permeability distribution, the facies type should also be mapped for reference. There are several alternative methods that can be utilized to generate the required data which should be discussed with your geologist prior to preparing the above suite of maps. It is expected that Stewart Petroleum will provide geological maps in a digital CPS format which can be directly imported into GRID. Hard copy contour maps can be utilized here, but they would require approximately two days of technician time to digitize them. This would be an additional cost over and above the cost and time estimate quoted at the end of this proposal. By superimposing the grid system onto each map, GRID will automatically sample the data at the intersecting grid cell comers. This process creates a comerpoint grid which rigorously conforms the three-dimensional aspects of the grid system to the top and bottom of structure. These data will then be exported into an ECLIPSE compatible data file. Preparation of the geological maps are also not included in the scope of this cost/time estimate. Should geological and petrophysical interpretation be required they can be provided by GeoQuest through Mr. Rob North. History. Match Typically, individual well oil production data (averaged on a producing day basis) is specified to the simulator. During the history match, the model will be required to calculate the corresponding gas and water rates according to the saturation and pressure dependent mobilities. The reservoir parameters will be iteratively adjusted until a satisfactory match of the calculated and observed watercut, gas-oil-ratio, and pressure data are achieved. At this time, the history match process appears to be relatively uncomplicated since the number of wells and the length of the history is limited. However, preliminary observations in the production and pressure histories may have some impact. Water production is quite high considering no communication with the lower water bearing layers is thought to exist. This may be easily explained once the structure maps have been prepared or it could involve extended history matching to test various alternatives. The elevated gas-oil ratios (GOR's) are also questionable since the reservoir pressure is significantly higher than the estimated bubble point. This could be indicating either measurement errors in the gas production, or possibly high drawdown in the near wellbore area due to high production rates. Lastly, a quick review of the pressure data suggests that the West McArthur River Unit might be influenced by some external source of pressure support. The pressure decline should be more or less linear since the reservoir is above the saturation pressure. However, recent pressure measurements indicates that the field pressure has leveled off. This trend might indicate that a large active aquifer is associated with the oil zone or that there is some communication with the main McArthur River Unit. Through the history match process all of these scenarios can be tested. Performance Forecasts Once an adequate history match is achieved, the model will be converted to forecast mode. This will be accomplished by adjusting the well productivities so that the calculated rates and bottomhole pressure data are consistent with actual producing conditions. A base forecast case with no changes to the current operating conditions will be run to compare the relative performances of all other forecast cases. This base case will be followed by up to five additional forecast cases, each utilizing a different production and/or injection well configuration (including the possibility of infill wells) or to investigate various voidage replacement ratios. Each subsequent forecast case will be directed towards optimizing the waterflood to maximize and accelerate the recovery, of hydrocarbons from this pool. Additional performance forecast cases can be run at Stewart Petroleum's request for an additional cost. Economics A thorough economic evaluation of each forecast performance may be necessary to determine the optimum development scenario. It is anticipated that Stewart Petroleum will undertake the economic evaluation and is therefore not included within the scope of this study. GeoQuest will provide production and injection forecasts in tabular form for economic analysis. Reporting A summary of the data, assumptions, and procedures used to obtain the history match and the relative comparisons of any and all forecast cases would be presented in a concise report. GeoQuest expects that intermediate results would be discussed with Stewart Petroleum at key study intervals for comments and/or recommendatiOns. Time and Costs GeoQuest estimates that a total of 19 mandays of engineering and technician time will be required to collect and review the initial data, construct the simulation model, history match the GOR, watercut and pressure histories, set up and run a total of six forecast cases, and to document the results. The above timing and following cost estimates assume that a meeting with Stewart Petroleum would be conducted in Anchorage prior to and following the simulation study. Data collection would be performed during the initial trip to Anchorage. The total cost for the engineering study, including travel, is expected to be approximately $23,400. GeoQuest expects that the approach described above is consistent with Stewart Petroleum's objectives. If you have any questions or comments, please contact me by telephone at (403) 263-3030 or e-mail at wgriswold~calgary.geoquest, slb.com. Yours very truly, GeoQuest- A Division of Schlumberger Canada Limited Reservoir Technologies Group Warren A. Griswold, RET Senior Petroleum Consultant /wag 302 fORT WORTH CLUB BUILDING .306 WEST SEVENTH STREET fORT WORTH. TEX^S 76~02-49e7 (817) 336-2461 FAX (617) 877-37:~8 CAWLEY, GILLESPIE ~, ASSOCIATES, INC. PETROLEUM CONSULTANTS 2ND ?LOOR 13 SHORTS GAI~DENS COVENT GARDEN LONDON WC2H 9at (0171) 240-4999 Fax (0171) 240-3666 February 14, 1997 Mr. Dan R. Johnson P.O. Box 191004 Anchorage, AK 99519 Dear Mr. Johnson: Thank you for your phone call and inquiry concerning our capabilities in regards to analysis of waterfloods. For your review I have enclosed several items including a general description of our capabilities and brief write-ups from various waterflood studies that we have done. As I mentioned in our previous conversation, we have recently reviewed the West McCarthy Field for a potential investor. I would be happy to discuss our capabilities with you further at your convenience. Sincerely, / / / / ./u,. e- i ,/'Z, c ~- ' .... Richard F. Strickland, Ph.D., P.E. President Ca~vley, Gillespie and Associates, Inc. Petroleum Consultants 302 Fort Worth Club Building 306 West Seventh Street Fort \Vorth, Texas 76102-4987 Telephone (817) 336-2461 Fax (817) 87'7-3728 RECEIVED f-laska 0il & Ga~ Cons. Commission Anchorage 1160 Dairy Ashford. Suite 130 Houston, Texas 77079-3010 Telephone (713) 557-8030 Fax (712,) 597-$035 Engineering and Geoloo~v The detailed assessment of producing reservoirs is one of the principal businesses of Cawley, Gillespie & Associates, Inc. CG&A's field studies are used by governmental agencies, major oil companies and independents alike to maximize oil and gas recovery. Our experience with full-field, three-dimensional, three-pk, ase resep~oir simulation has included over 1,550 field studies during the last several years. We have studied reservoirs as large'as the 15,000 well Panhandle Field (Texas) and as small as single well fields, as complex as multi-component solvent based EOR projects and as simple as single phase dry gas reservoirs. Various techniques have been used, including evaluation of production performance, volumetric and material balance calculations, and reservoir modeling, depending on the amount and quality of data available and the purpose of d:e studies. Complete geological evaluation of fields has included depos~tional environment studies along with detailed log evaluation and correlation, reservoir zonation, core examination, thin sections and SEM studies. CG&A's work is frequently used in contested administrative and legal proceedings. Reser~'e Certification - With diversified experience in oil and gas producing properties throughout North gznerica and around the globe, CG&A's proficient team or' rese,woir engineers, development geologists and economists integrate geologicai, geoptLysica!, engineering and economic data to produce high quality reserve estimates and economic forecasts. CG&A has formally published over 5000 hydrocarbon reset', e evaluations since CG&A first melded talents in 1961. The generated data have been used by over 550 firms includina~ international oil companies, independent producers, and !ea~.~.";"q,.:= 'e'nanc~al' or~oanizations; CG&A's rese~,e ar.d economic reports have been ,-.c¢,p:,.d bv oil and szas lending institutions worldwide. .,Many of these evaluations are integral to merger and acquisition proceedings. CG&A has evaluated over two billion US dollars of potcntia! interests in the past three years alone. Primary, secondary and enhanced resep:es t',ax'e all constituted CG&A reports. CG&A analyses have also accommodated various production scenarios, specified operational expenditures and price projections. Where required, resep,'e classifications used in published reports confbrm to the criteria of' the Securities and Exchange Commission and the guidelines of the Society of Petroleum Engineers. In addition to the traditional deterministic approach, CG&A is adept in the application of probabilistic methods. The procedure applied to reserve evaluation depends on the quantity and quality of the data available and the characteristics of the reservoir. The principal methodologies are production performance, material balance, volumetric, simulation and analogy. Generally, a superior availability of reliable data leads to a narrowing of estimates in a probabilistic sense and a greater confidence in the calcula.ted reserves. CG&A's familiarity with large multi-well oil and gas reservoirs is particularly relevant to many international oil and gas ventures. CG&A pro~'essiona!s offer a global experience base having worked with production sharing contracts throughout Australia, Europe and Mexico. Additionally, CG&A is afforded ready access to international financial institutions through our full service office in London, UK. Reservoir Engineering - CG&A has engineering tools available to simulate individual well or full field reservoirs with all types of fluid systems including black oil, dry gas, retrograde gases, compositional, and coalbed methane, to analyze transient well tests, to evaluate well logs, to create computerized geological maps, to perform equity determination studies, and to perform economic forecasting. We utilize state of the art technology to accomplish field studies tl'~rough ex-tensive computer facilities and -specialized sot~ware programs designed for reservoir characterization, log analysis, reservoir simulation, deliverability and economic forecasting. The software used for processing input data, conducting numerical simulations, and summarizing the model's output has been written largely by CG&A personnel. In addition to our in-house sol'ware, we utilize numerous packages from the major oil and gas sof~ware vendors. Geoscience Evaluations - Geological capabilities cover all phases of petroleum geology including basin studies, prospect evaluation, wellsite evaluation and comprehensive reservoir characterization. The reservoir characterization capabilities include detailed core descriptions, including fracture identification and depositional environment interpretation, thin sections with mineral identification and pore description, log analysis, reservoir zonation using sequence stratigraphic concepts and geostatistical techniques including neural netv,:ork li~hofacies identificatsion for quantification and population o£ reser','oir models. Extensive geological computing capabilities are utilized to enhance the quantification and e~lciency of complex reservoir characterization Problems. Geophysical capabilities include two and three-dimensional seismic interpretation, prospect evaluation, regional basin studies and detailed field evaluation. CG&A's seismic toolbox includes the utilization of seismic wavelet attributes to determine lateral and vertical stratigraphic changes within the geological section, the identification of hydrocarbon indicators, the interpretation of seismic data to develop geologic maps; the interpretation of seismic lines and coordination or' the final construction of structure maps, and the use of ship-towed magnetometers and side scan sonar for location of subsea wellheads. Steps in a Typical Integrated Field Study CG&A generally performs the following projects during the course of an integrated field study: Evaluation of existing well logs and core data - CG&A evaluates existing well logs to develop gross and net thickness maps, structure maps, an accurate awareness of the continuity of individual reservoirs, and a knowledge of the quality of the fields. CG&A gathers and evaluates core data to properly construct accurate reservoir descriptions and characterizations. Identification of reservoir flow units is accomplished by several techniques including neural network lithofacies identification. If necessary, a depositional environment model is developed. · Construction of a geologic model - CG&A will typically build the geologic model in three steps, 1) construction of the geologic framework (e.g. structure, faults, depositional environment), 2) deterministic or stochastic facies modeling, and 3) deterministic or stochastic petrophysical modeling. Conditional simulation is applied to complex reservoirs in an effort to capture the heterogeneity. Three dimensional very fine gridded conditional simulations delineate permeability distributions that better represent the calculated heterogeneity, match the available core data, and m6del the geologic characterization. CG&A uses conditional simulation to significantly enhance reservoir management capabilities. The resulting distributions are applied to a three-dimensional fluid flow simulation to better manage the current and future production of the reservoir, predict future injection requirements and delineate the fluid flow through the formation. · Development of a production data base - CG&A develops a production data base that includes sustained oil, gas, and water rates, test data, reservoir pressure data, flowing pressure data, and produced oil, gas, and water compositions for the pertinent wells. · PVT characterization of fluids - CG&A utilizes a highly effective equation of state package to apply the Peng-Robinson (PR) or the Soave-Redlich-Kwong (SKK) equation of state to properly characterize reservoir fluids. This capability allows most types of calculations involving mixtures with two or three hydrocarbon phases and provides a basis for related simulations. We are able to generate two and three phase boundaries on various types of diagrams, characterize the heaw fractions of the oil, select pseudo-components, improve the density prediction from the PR or SKK equation of state by using the volume translation technique of Peneloux et al, match the saturation pressure by adjusting the interaction coefficients, attain viscosity predictions, and perform regression analysis to match experimental data of various descriptions. · Well simulation history matching - CG&A performs indMdual well simulation history matching in order to refine the process of reservoir description, identify {' {' near wellbore performance characteristics, interpret injection/falloff tests, and develop sensitivity curves for various reservoir characteristics. Construction of simulation models - CG&A utilizes areal or three-dimensional simulation models in order to investigate all phases of reservoir performance and to predict future oil, gas and water rates and recovery factors. Below is a partial list of Cawley, Gillespie & Associates, Inc. 'engineering and geologic capabilities: Numerical Simulation Black Oil Compositional Three dimensional Dual Porosity Coalbed methane Probabilistic (Monte Carlo) Regression analysis and automatic histor).' matching PVT Characterization SRK and PR equations of state Regression analysis Heavy. fraction characterization Petrophysics Thin section Mineral identification Pore description Log analysis (conventional and neural network) Geologic Modeling and Geostatistics Depositional environment studies Sequence stratography Fracture identification Spatial analysis Deterministic and stochastic petrophysical modeling Deterministic and stochastic lithofacies modeling Reservoir zonation using sequence stratigraphic concepts Geophysics Two and three-dimensional seismic interpretation Prospect evaluation Regional basin studies Porosity determination Determination of lateral mid vertical stratigraphic changes Identification of hydrocarbon indicators Construction of structural maps Pressure Transient Test Analysis Single and dual porosity Hydraulic fracture characterization Drawdox~. buildup and interference tests Automated Dpe cur~'e matching T.xpe cur~'e generation Analytical simulation Probabilistic Methods Monte Carlo simulation Decision tree analysis Latin H.xper Cube analvsis So,ware Computer Modelling Group (CMG) family of reser~'oir simulators Landmark VIP family of reservoir simulators CG&A's in-house farnilv of reservoir simulators CMG's Equation of State Package for fluid characterization Terra Sciences for log analysis Landmark Z-map for computer mapping Data Explorer for three-dimensional 54sualization ARIES for decline curve analysis and reserve and economic forecasting PanSvstem by Edinburgh Petroleum Services (EPS) for pressure transient test analysis Geostatistical and conditional simulation sol,rare Three-dimensional visualization of simulation and geology Equation-of-state surface facilities simulation Boffin's svstemwide nodal analysis Oilwat and Gaswat material balance programs by Boffin Ward System Group. Inc. NeuralShell 2 neural network so~vare The attached pages are examples of some of the field studies completed by CG&A. A brief narrative is provided to explain the graphics. Also included is a brief write-up summary of some of the integrated field studies CG&A has performed in the past. Neuhoff(Buda Woodbine) Field. Texas 1985-present We conducted a reservoir en~nee~g and geolo~cal field study of a comple~ h/ghly faulted oil reservoir located beneath the overhang of a salt dome. Completed projects have included full-field simulation, the determination of the initial oil and gas in place, prediction of primary and expected secondary recover, desi~ of the water inje~ion pro,am and development of a plan of depletion for the purposes of unitization. We are currently mon/toring the waterflood project which began in the Fall of 1987. · Simulation Sof[xvare: CG&A In-house developed 2-D · Personnel Responsible: · Reservoir Type Data: · Client Contact: CG&A In-house developed 3-D Robert D. Ravnaas Dr. Richard F. Strickland Michael A. Fox Single porosity, 14 wells Black-Oil, Solution Gas Combination sandstone and limestone Waterflood project Energy Production Company, Mr. Joe Vaughan (214) 692-8581 Schneider (Buda) Field. Wood County. Texas 1988-present This project identified and mapped three geologic facies combined with full field simulation. The purpose of this work was to develop a plan of depletion and design a waterflood project. The permeabilities and porosities in the interwetl areas were represented by a model combining kriging and fractal distribution. The model honors both the heterogeneity, suggested by well data and the geological description of the reservoir (technique developed by Petroleum Engineering Department, University of Texas). Waterflooding was initiated in October, 1991. We are currently history matching the production and pressure performance of the waterflood. · Simulation Software: CG&A In-house developed 2-D Personnel Responsible: Reservoir Type Data: · Client Contact: CG&A In-house developed 3-D INfEX, Computer Modelling Group Robert D. Ravnaas Dr. Richard F. Strickland Sam French Michael A. Fox SingleJDual porosity, 6 wells Black-Oil, Solution Gas Carbonate Reef limestone Watefflood project Energy Production Company, Mr. Joe Vaughan (214) 692-8581 SPE 2397O Three-Dimensional Conditional Simulation of Schneider (Buda) Field, Wood County, Texas R.D. Ravnaas* and R.F. Strickland,' Cawley, Gillespie & Assocs.; L.W. Lake,' U. of Texas; A.P. Yang,' Texaco E&P Technology Div.; Mohammad Malik, U. of Texas; D.R. Prezbindowski, International Petrology Research; and Tom Mairs, Consulting Geologist °SPE Members SPE Copyright 1992. Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 1992 SPE Permian Basin Oil and Gas Recovery Conference held in Midland, Texas, March 18-20, 1992. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are sublect to correction by the author(s). The mater~al, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, ~ts officers, or members. Papers presented at SPE meetings are sublect to publication review 13y Editorial Committees of the Society o! Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copiecl. The abstract should contain consptcuous acKnowmdgment o! where and by whom the paper is presented, Write Librarian Manager, SPE, P.O. Box 833836, Rlcharclson, TX 75083-3836. Telex, 730989 SPEDAL. Abstrnct Introduction A three dimensional conditional simulation model, integrating a cOmprehensive data base coupled with engineering, geological, and petrological studies, has significantly enhanced reservoir management capabilities in the Schneider (Buda) Field. Presented are the results of a series of conditional simulations of the Schneider (Buda) Field. The Schneider (Buda) Field is developed in a Buda reef complex. Porosity types change significantly between reservoir facies. A three dimensional conditional simula- tion generated using only well control points did not adequately characterize the reservoir. An intermediate two dimensional conditional simulation using additional assumptions was then generated to refine and control the final three dimensional conditional simulation. The resulting three dimensional conditional simulation delin- eates permeability distributions that better: 1) represent the calculated heterogeneity, 2) match the available core data, and 3) model the geolo~c characterization, including the defined facies. The resulting distributions have been applied to a three dimensional fluid flow simulation to better predict fluid movement through the reservoir. References and figures at end of paper The Schneider (Buda) Field is located in Wood County, Texas, approximately 100 miles east of Dallas near the town of Hainesville (Figure 1). Production is from Cretaceous reefal Buda Limestone discovered under the overhang of the Hainesville salt dome (Figure 2). Bounded by faults to the east and west, the updip limit is the sat: dome, and the downdip limit is a tar mat/water contact. Originally a depletion drive black oil reservoir, it was undersaturated at discovery. The field was discovered by the Dan Peacock No. 1 well flowing 1,008 BOPD with a 1,000 psi flowing tubing pressure from perforations au 9,400 feet on March 4, 1988 (Figure 3). The field was unitized and a water injection project initiated in October 1990, with three producing wells and one injection well. Production/Injection History Production began in the Schneider (Buda) Field ir March, 1988, with the discovery well, the Peacock No. ! Four wells have been drilled in the field with the discover~ well converted to injection in October, 1990. As of Augus 31, 1991, cumulative production from the field was 1,28t MSTB with recent production rates averaging a total o 1,500 BOPD for the current three producing wells (Figun 4). Cumulative water injection as of August 31, I991, wa: 313 2, SPE 23970 Three ~' nensional Conditional Simulation of Scl{' :der (Buda) Field 687 MSTB with recent injection rates in the Peacock No. 1 averaging 2,400 B WIPD. The cumulative injection/ withdrawal ratio since October, 1990, is 1.3. Pressure History The original reservoir pressure at -9,022 feet subsea was 4,090 psia (Figure 5). This black oil reservoir was undersamrated by 765 psi with an original bubble point pressure of 3,325 psia. Bottomhole pressures were taken when each well was initially completed and then on a regular, quarterly basis. The reservoir pressure fell quickly until the bubble point pressure was reached in early 1989. Production rates were voluntarily restricted to 300 BOPD per well to preserve reservoir energy until thc field was unitized and water injection initiated. A relatively inexpensive but useful interference test was conducted when injection began in October, 1991. The Peacock No. 1, Jones No. 2, and Jones No. 3 STH wells have extremely high flow capacity and reach average reservoir pressure in less than 24 hours of shut-in. Base- line static pressures were obtained in all three wells with Amerada gauges just prior to injection in the Peacock No 1. The pressures were in close agreement and averaged 2,910 psia. Thereafter, on a weekly basis, the wells were shut-in overnight and bottomhole static pressures were obtained. Pressure response due to injection was measured on both the Jones No. 2 and Jones No. 3 STH after two weeks of injection. Pressures were recorded weekly for several months. This pressure information has proven invaluable to properly match the interwell reservoir flow capacity in the fluid flow simulator. were calculated from differential liberation and separator tests for input to the black oil simulator. The original oil formation volume factor was 1.305 RB/STB corrected to field separator conditions. The original solution gas/oil ratio was 565 SCF/STB, and the oil viscosity was 0.93 cp. Stock tank oil gravity is approximately 26 degrees APl. Core AcquisitionJPetrophvsical Properties Every well in thc reservoir was conventionally cored for a total of 445 feet of core material. Full diameter whole core analysis was performed on the cores taken from the heart of the reef, the Jones No. 2 and Jones No. 3 STH. Kmax, K90 and Kvert were measured. Plug analysis was performed on the Peacock No. 1 and the SASI Ranch No. 1. Full diameter analysis was performed on selected intervals in the reef debris facies of the Peacock. Helium was used for all porosity measurements. The net pay arithmetic average core permeability is 65 md. Inspection of the core plus knowledge of the size of the rugs typically present in reef facies suggest that even the whole core measured permeabilities are lower than true, in-sim perme- abilities. Pressure transient tests and history matching of the injection interference pressures confirm this observa- tion. A full suite of open hole well logs was run in every well, including neutron, density, and sonic logs. Equations were developed relating core porosity to the porosity log readings to estimate porosity in intervals of missing core data. Average net pay perosities vary from well to well from a high in the Peacock of 15.7 percent to a low in the SASI Ranch of 10.0. Fluid Properties A bottomholc fluid sample was obtained during the completion of the Peacock No. 1. Bottomhole tempera- tures have been recorded in thc Peacock along with other wells in thc Hainesville Dome area. Thc temperature gradient is typical of the area~ and the temperature at the reservoir datum of -9,022 feet subsca is estimated to be 215 degrees F. The bubble point pressure was calculated to be 3,325 psia at 215 degrees F. Thc subsequent pres- sure history from the field demonstrated good agreement with the predicted bubble point, as indicated by the pressure-cumulative production plot leveling off as pres- sures fell ~low 3,325 psia. Combination fluid properties'''2 Numerous special core tests were conducted, including steady state water-oil relative permeability, .waterflood displacement, unsteady state gas/oil relative permeability, air-brine drainage centrifuge capillary pressure, brine-oil imbibition centrifuge capillary pressure, and centrifuge gas-oil relative permeability. Electrical properties (m and n tests) plus formation compressibility were measured. As expected, rock compressibility was greater in the reefal and reef debris facies than in the grainstone shoal. Geological and PetroloKical Studies All core material from thc four wells (SASI Ranch, Peacock, Jones 2 and Jones 3 STH) were studied from thc 314 SPE 23970 Rav~-~, Stricldand, Lake, Yang. Malik, Prezbi:~ 'owski, and Maim Schneider Field in order to establish controls on reservoir :velopment. Detailed descriptions of the cores were prepared noting lithology, sedimentary structures, porosity, grain types and petrophysical signature. A detailed petrographic study was also carried out using transmitted light and scanning electron microscopy. The purposes of this study were to: 1) document the type, size and distribu- tion of porosity in the Schneider Field; 2) determine the origin of the porosity, its relationship to deposifional facies, and controls on reservoir heterogeneity, and 3) develop a reservoir model that will allow the reliable projection of reservoir quality beyond the well bore (Figure 6). Geological Reservoir Model The Schneider Field reservoir is developed in a Buda (Lower Cretaceous) marine reef complex limestone. This reef complex grew on the south flank of a paleotopogra- phic high formed during an early stage of salt movement. Salt movement (diapifism) has been demonstrated to be a control for reef and grainstone shoal distribution in the East Texas Basin.4 Reefal organisms provide the source for skeletal grains within the shoal complex. Lithofacies distribution indicates that the present Buda structure 'enerally represents an exaggerated model of paleodepositional topography. The development of higher energy reef, reef apron carbonate sands and fore-reef/shoal debris facies on the deeper water carbonate mudstones and wackestones documents a shallowing upwards sequence. Subaerial exposure terminated the development of Schnei- der reef complex and enhanced reservoir quality by meteoric water leaching. Four major limestone lithofacies are recognized in the Schneider reef complex. The productive reservoir lithofacies are: reef debris, reef, and shoaling grainstone apron (Figures 7, 8, and 9). The fourth lithofacies, a pre- reef limestone, is not considered productive. 'These lithofacies developed in a vertical and off-structure direc- tion. Reservoir porosity distribution is controlled by depo- sitional facies, early diagenesis and bitumen distribution. Three major types of porosity (affecting reservoir char- acteristics) are present in the Schneider Field: 1) skel- moldic ~rosi~' (formed shortly after deposition by selec- tive dissolution of skeletal grains, particularly corals); 2) primary interparticle porosity (formed at the time of depo- sition); and 3) micro-fracture porosity (formed during burial and associated with stresses generated during salt movement). Porosity types change and reservoir quality decreases down section and down dip. So]id hydrocarbons (bitumen) also seriously degrade the reservoir quality in the lower portions of the Schneider Field. Overall degradation of reservoir quality by porosity plugging bitumen increases with depth, creating an asphalt seal at or near the oil/water contact. This asphalt seal is analogous to what is found in the nearby Hawk/ns Field? Bitumen and pyro-bitumens can form by a number of different processes,a so the distribution of the bitumen within the reservoir offers clues to its origin. The occur- rence of the solid hydrocarbon in the lower portion of the reservoir and in association with the major fault to the west indicates that water washing may be responsible for its development. Additional data is required to confirm this interpretation. Reservoir Lithofacies Pre-reef Limestones - This non-reservoir quality lithofacies is present in the base of the cored Buda Formation (Figure 10F). The importance of this lithofacies increases in a down dip direction. Skeletal wackestone is the dominate limestone lithology and interfingers with the overlying packstone-grainstones of the reef debris lithofacies. Skeletal grains include foraminifera, pelecypod, gastropod, echinoid and coral fragments. Stylolites and micro-frac- tures are common. These mud dominated carbonate sediments were deposited in a Iow energy (below wave base) marine environment. Porosity is poorly developed because of the abundance of carbonate mud and the common occurrence of bitumen filling moldic pores. Reef Debris - This lithofacies is composed of a coarsening upwards sequence of nonsorted to poorly sorted packstones and grainstones interfingered with the mud dominated wackestones of the pm-reef facies (Figures 10C and 10D). Skeletal fragments consisting of large randomly oriented corals and stromatoporoids dominate the sediment. Other skeletal grains include mollusk (including Inoceramus), coral and echinoid fragments. This lithofacies interfingers with the basinward and underlying pre-reef limestones and up-dip reef facies. Deposition of this lithofacies occurred to the front of the reef complex facies. Storm and gravity transport of 315 4 SPE 23970 Dimensional Conditional Simulation of( ~meider (Buda) Field reef derived sediments into deeper water, basinward of the reef, is responsible for deposition. Continued reef devel- opment used the proximal reef debris deposits as a base for further basinward growth leading to an interfmgering of the two lithofacies. Reef debris deposits are common and have been documented in recent and ancient carbonate systems.9 Porosity consists of early secondary grain moldic and primary pores. Reservoir quality is variable and tends to decrease with increasing carbonate mud matrix content. Permeability measurements may provide an inaccurate measure of the flow characteristics within this facies because of the presence of randomly oriented, very large skeletal components. These partially leached skeletal components and the surrounding lithified carbonate muds can exceed the size of the core sample. Permeability measurements can be misleading when single grains are larger than the core diameter. Reef Facies - This lithofacies is characterized by thick coral/stromatoporoid boundstones with a patch quilt distri- bution of discontinuous wackestone, packstone and grain- stone units (Figures 10A and 10B). In addition to coral, skeletal components include echinoid, mollusk (pelecypod and gastropod), stromatoporoid, algae and foraminifera. Carbonate mud matrix is commonly present having been deposited in the baffled areas between coral stromatoporoid colonies. Lithification of the mud matrix and the early leaching of the skeletal components (corals. stroma- toporoids and mollusk) resulted in large vuggy and tubular pore spaces. Coral and stromatoporoid colonization and prolific growth on the south flank of the Hainesville paleotopographic high formed the main reef complex. Current, wave and biological erosion of the reef complex were the sources of the sediments for the basinward shoaling grainstones and reef debris lithofacies. Subaerial exposure terminated reef development. Porosity consists of early secondary and primary pores. The large size and volumetric importance of leached skeletal components and sheltered pore primary pore spaces within this facies accounts for its overall excellent reservoir quality. Shoaling Grainsmne Apron - This lithofacies consists of skeletal grain.stones developed to the front of the main patch reef complex by wave and current reworking of reef sediments (Figure 10E). Skeletal grains include broken and rounded fragments of mollusk, coral, stromatoporoid a'- echinoid fragments. The lithofacies thins and interfmg~,. with underlying reef debris limestones and the down-dip pre-reef limestones. Harbour and Mathis~° document a relationship between rudist reefal development and carbon- ate grainstone shoal development in Black Lake Field of central Louisiana. Reef and reef-derived skeletal grains- tone facies have been documented for the Lower Creta- ceous James Reef (Fairway Field) of East Texas. ~ In each of these systems, reefal organisms served as the grain source for the carbonate sands. Porosity consists of secondary grain moldic and primary interparticle pore spaces. The energy of the depositional environment and the degree of early meteoric leaching controlled porosity development. Deposition down-dip occurred in lower energy marine environments (deeper water), which resulted in thinner grainstone beds and poorer sorting characteristics that rapidly reduced reser- voir quality. Conditional Simulation There are several methods used to incorporate geological reservoir model in the development of peru. ability and porosity distributions for input to fluid flow simulators.'2'x6 Traditional contouring, whether by hand or computer mapping packages, of permeabilities and po- rosities, often understates the true heterogeneity of the reservoir. Hand contouring relies on the experience of the individual in mapping interwell properties. Most popular computer mapping packages use mathematical rules for interpolation without regard to the spatial statistics of the property. Since these types of contouring reflect only large scale variation, they do not account for fine scale property variation. In fluid displacement processes, one conse- quence of this reduction in modeled heterogeneity is to predict sweep efficiencies that are too high, giving optimis- tic forecasts. When adequate data is available, application of geo- statistical techniques defines the spatial relationsl,fips of the property. ,?.25 Given the spatial relationships (autocovariance models), maps created by kriging can be constructed. Kriging gives the optimal (minimum variance) estimate of the property at every location. However, kriged maps, by themselves, also smooth the distribution, understating true heterogeneity. An enhancement 316 SPE 23970 5 Rav~~ ~, Strickland, Lake, Yang, MalLk, Prezbf~ owski, and Maim "riging, referred to as "conditional simulation" has been ~evised to help account for fine scale property variations and maintain the actual heterogeneity of the reservoir.~9~:7 Conditional simulation is the process of constructing unsmoothed realizations, using geostatistical techniques, that honor the data at well control points (conditional). The steps in conditional simulation are: 1. Define an autocovariance model(s) based on the data obtained from the reservoir. 2. Krige a surface through the actual well control data. . Construct an unconditional realization using the autocovariance model. This realization does not honor data values at control point locations, but does simulate both large and fine scale variability that is similar to the actual distribution defined by the autocovariance model. . Krige a surface through the values obtained from the unconditional realization in step 3 using only those values at the actual well locations. . Subtract the kriged surface from the unconditional realization to obtain a residual field. This residu- al contains only small scale variations and, since the kriged surface uses the values at the control points, the residual at these locations is zero. Add the residual from step 5 to the kriged surface of step 2. The resulting realization honors the well control points with heterogeneity comparable to the data obtained from the reservoir. Application of Conditional Simulation There are five basic steps to prepare for the condition- al simulation procedure described above. See Yang2s for more information. Determine Probability Distribution Most methods for testing probability distributions are for independent data and may not be suitable for data with strong spatial correlation. Because of this, visual inspec- tion of '.[ne probability density function, pelf (or h/stogram) determines the proper type of distribution. The pdf is chosen because it offers both easy identification of symme- try and the presence of multiple peaks. For the Schneider (Buda) Field, the pdf of the loga- rithm of permeability for each facies in the reservoir can best be approximated by normal distributions (the perme- ability is log normally distributed). The three reservoir facies show variations in the mean and variance. However, there is sufficient overlap on the pdf for the three facies so that the differences in the mean and variance are adequate- ly reflected from the conditioning of the well data (step 2 above). Variogram A variogram is used to identify an autocovariance model. Log permeabilities were used because of greater precision and the observed log normal pdf. The variograms for each of the facies were linear and exhibited large fluctuations. Large fluctuations of the vafiogram indicate long-range spatial correlation because correlation reduces precision (increases fluctuations). A straight-line fit to the variogram implies a fractal model that does not level off as happens, for example, in a spherica/ model. Fractal models mathematically describe the complex shapes found in nature and have been used in a wide Variety of geostatistical applications.26m;zg'~a R/S Plot The slope of the rescaled range (R/S) plot2s2~26 is used to determine the fractal exponent H of the fractal model. Even if the fractal model is not used, it is advisable to make an R/S plot to check the presence of long range correlation. Because the variogram is more precise when the separation distance is small, and the R/S plot is more preciSe when it is large, the R/S plot is more reliable in inferring long range correlation than the variogram which tends to under-estimate long range correlation. There is no distinctive difference among t/ne R/S plots of individual facies or wells in the Schneider (Buda) Field. Analysis of the plots results in an H= 0.85 for log perme- ability. 317 6 ThrU"' ~imensional Conditional Simulation of !{ acider (Buda) Field SPE 23970 Autocovariance Model Combining our observation of the pall vafiogram, and the R/S plot, the following approximate autocovariance model was used for all the facies: N C(h) -2 VzH(2H-I) hzte-2 Arithmetic averaging occurs when p= 1; when p= -1 the procedure results in harmonic averaging. This is an approximation to the fractional Gaussian noise autocovariance function. Once H is known, Vt is adjusted to make the function, Equation (1), fit the experimental autocovariance calculated from the core data. Variance of the Difference between the Wells The variograms and the R/S plots described above establish the autocovariance model in the vertical direction. For the horizontal direction, there is not enough data to calculate the variogram or the R/S ploL By assuming a fractal model, the same fractal exponent H, estimated from the vertical direction, is used for the horizontal direction. The only unknown in Equation (1) is the magnitude of V1. The variance of the difference between two wells is one point on the horizontal variogram and allows calculation of VI. From an analysis of all well pairs we can obtain Vt for the model in the horizontal direction. The method used to determine p for our work pre- serves the coefficient of variation, CV, of the permeabilities. CV is defined as the standard deviation divided by the mean. The CV is chosen as the criterion for two masons. First, it is a dimensionless parameter which directly affects dispersion and other fluid flow charac- teristics. Second, when all permeability values are multi- plied by a constant, the coefficient of variation is un- changed. This allows the effective permeability to be defined to achieve the same pressure drop as the original permeability before averaging and at the same time maintain the same degree of heterogeneity. Application of this method requires assuming seve' values of p and then calculating the CV of the reduce. averaged data set. The value of p that produces a reducecl data set CV equal to the original data set CV is then chosen. For the Schneider Field a value of p= -0.2 was used for log permeability. In the Schneider Field the average interwell variance is about thc same as the maximum separation value for the vertical variogram. These manipulations indicate that the autocovariance function in Equation (1) applies for all directions, but in the horizontal directions h is stretched by a factor equal to the field dimensions divided by the vertical extent. Averaging From about 150 core samples in a well, only six layers are to be simulated. We must therefore average six groups of approximately 25 samples stacked vertically to reduce the 150 point data set to six points in each well. There are various classical methods of averaging permeabilities such as arithmetic, geometric, and harmonic averaging?7'~9 Power averaging~° encompasses all methods with its transformation exponent p ranging from -1 to +1. Three Dimensional Permeability Model A 40 by 21 by 6 layer grid system was constructed to represent the field (Figure 11). This system size provided a balance between the detail needed for reservoir descrip- tion and computer limitations of storage and speed. An initial ~rce dimensional conditional simulation was per- formed using only thc data from the four wells (Figure 12). This model did honor the control points with comparable heterogeneity suggested by the averaged core data but did not adequately model the geological model described by the petrologist and the geologist. The four spatial control points are not sufficient to cause the mathematical process of conditional simulation to match the symmetry of the reefal dcpositional framework. Specifically, the permeabilities should degrade away from the reefal core area near the Jones 2 and Jones 3 S: 318 SPE 23970 Rav~...,-% Stricldand, Lake, Yang, Malik, Prez~: 4owski, and Mairs to thc east, southeast, south, and southwest. This is xhibited in the easterly direction by the poorer quality rock in the SASI Ranch. Sufficient well control is not available in the other directions to confirm the degree of permeability degradation suggested by the depositional environment and geological model. This problem was solved by defining a vertical surface that would be expect- ed to contain' rock quality similar to the SASI Ranch. A two dimensional conditional simulation along this surface would produce a field that can be input as control points in a final three dimensional conditional simulation. Two Dimensional Conditional Model by full diameter, whole core analysis. The match was achieved by multiplying the permeabilities in these facies by a scaling factor. The technique of power averaging the measured core permeabilities by preserving the CV enables scaling the permeabilities to match pressure history, while keeping the same degree of reservoir heterogeneity. The information produced by the fluid flow simulation is now being used to manage the current and future production of the reservoir, predict future injection require- ments, and delineate the fluid flow through the formation. Conclusions The SASI Ranch is the only well to intersect the edge 1. of the reservoir. It exhibits the poorer rock quality that the geologic model predicts toward the eastern and southern edges of the field. To better match the geologic model in the three dimensional simulation, a 48 by 6 vertical, two 2. dimensional conditional simulation was constructed to represent the surface of poorer quality rock at the edge of the reservoir. The areal extent of the two dimensional surface is shown in Figure 11. Duplicating the SASI Ranch data at three additional points in the conditional 3. 'imulation achieved better control of the model and provided a closer match to the geologic data. Final Three Dimensional Conditional Simulation The two dimensional conditional simulation permeabil- ity values were then used, along with three additional existing well control points, to produce a final three dimensional conditional simulation (Figure 13). In general, higher permeabilities are located in the reef core, with lower permeabilities to east and south. The final simulated model matched the predicted geological model of the field. To our knowledge, this is the first three dimensional conditional simulation that incorporates such geologic detail. Fluid Flow Simulation A fluid flow simulation was then generated to predict the movement of fluids through the reservoir. As predicted from the petrological study, history matching the interfer- ence test pressures required increasing the permeabilities in both the reef and reef debris facies. The in-situ reservoir scale permeabilities in these facies is greater than measured Improved reservoir management results from a com- prehensive data acquisition program coupled with engineering, geological, and petrological studies. Successful three dimensional conditional simulation requires the incorporation of a detailed geological reservoir model that reliably projects reservoir facies beyond the wellbore. The Schneider Field is developed in a Buda reef com- plex. Three reservoir facies have been identified: reef, reef debris, and shoaling grainstone apron. . The petrological study predicted that both the reef and reef debris facies in-situ permeabilities would be greater than measured by full diameter whole core analysis. This observation was confirmed by subse- quent fluid flow simulation history matching. , Power averaging permeabilities, preserving the CV of the original distribution, enables history, match/ng of pressure drops without reducing the heterogeneity of the reservoir model. Nomenclature BOPD BWIPD C(h) CV h H Barrels of oil per day Barrels of water injected per day Autocovariance function of separation h Coefficient of variation, the mean divid- ed by the standard deviationTM Separation (lag) distance Fractal exponent 319 ,8 SPE 23970 Thre~' 'mensional Conditional Simulation of S{. :ider (Buda) Field K90 Kvert MSTB N P RB R/S Plot SC1= STB STH Permeability measured 90 degrees to 5. direction of maximum value Permeability measured in direction of maximum value Permeability measured in vertical direc- 6. tion Thousands of stock tank barrels Number of observations to be power averaged 7. Power averaging exponent Probability density function Reservoir barrels Rescaled range plot26''~''~ 8. Standard cubic feet Stock tank barrels Side-track hole Variogram value at h=l Acknowledgements We thank Energy Production Corporation for permission to publish this work. We would also like to thank Michael Fox, Sam French, and Bob Meade for their help on this project. We also acknowledge the Enhanced Oil Recovery Research Program of the Center for Petroleum and Geosystems Engineering at The University of Texas. Larry W. Lake holds a Shell Distinguished Chair. References Nichols, E.A.: "Geothermal Gradients in Midcontinent and Gulf Coast Oil Fields," Trans. AIME (1947) 170, 44-50. . Amyx, Bass, and Whiting, Petroleum Reservoir Engi- neering, McGraw-Hill Book Company, New York City (1960). 3. McCain, Jr. William D. The Properties of Petroleum Fluid. s, 2nd Edition, PennWelI Books, Tulsa, (1990). . Lomando, A.J., "Aptian Depositional Patterns Influ- enced by Salt Tectonics, Central East Texas Basin," (Abstract) AAPG, (1980), v. 73, no. 3, 382. Barker, C., "Organic Geochemistry in Petrolear. Exploration," AAPG, Continuing Education Course Note Series No. 10, (1980). Wencllandt, E.A, Shelby, T.H. Jr., and Bell, J.S., "Hawkins Field, Wood County, Texas," AAPG Bull. (Nov. 1946)v. 30, no. 11, 1830-1856. Lee, W.J. et al, "A Mathematical Model of the Haw- kins Woodbine Reservoir," JPT (Dec. 1977) 1545- 1549. King, R.L., and Lee, W.J., "An Engineering Study of the Hawkins (Woodbine) Field," JPT (Feb. 1976) 123- 128. 9. Flugel, E., Microfacies Analysis of Limestones, Sprin- ger-Verlag, New York City (1982). 10. Harbour, J.L., and Mathis, R.L., "Sedimentation, Diagenesis, and Porosity Evolution of Carbonate Sands in the Black Lake Field of Central Louisiana," Carbonate Sands - A Core Workshop, Harris, P.M. (ed.), SEPM core workshop No. 5 (1984) 306-333. 11. Achauer, C.W., "Facies, Morphology, and Major Reservoir Controls in the Lower Cretaceous James Reef, Fairway Field, East Texas," Carbonate Petro- leum Reservoirs, Roehl, P.O. and Choquett, P.W. (eds.), Springer-Verlag, New York City (1985). 12. Lake, L.W., and Carroll, H.B. Jr. (eds.), Reservoir Characterization, Academic Press, Orlando (1986). 13. Lake, L.W., Carroll, H.B. Jr., and Wesson, T.C. (eds.), Reservoir Characterization II, Academic Press, San Diego (1991). 14. Van De Graaff, W.J.E., and Ealey, P.J., "Geological Modeling for Simulation Studies", AAPG Bull., v. 73, no. 11 (November, 1989) 1436-1444. 15. Johnson, C.R., and Jones, T.A., "Putting Geology into Reservoir Simulations: A Three-Dimensional Modeling Approach," paper SPE 18321 presented at the 1988 Annual Technical Conference, Houston, Texas, Oct. 2- 5. 320 SPE 23970 Rayne', Stricldand, Lake, Yang, Mai[k, Prezbiq,,~'~wski, and Maim 16. 17. 18. 19. Testerman, J.D., "A Statistical Reservoir Zonation Technique", Trans., AIME (1962) 225, 88%893. Davis, John C., Statistics and Data Analysis in Geolo- gy, John Wiley & Sons, New York City (1973). Cressie, Noel, Statistics for Spatial Data, John Wiley & Sore, New York City (1991). $oumel, A.G., and Huijbregts, Ch.J., Mining Geostati- stics, Academic Press (1978). 28. 29. 30. Yang, A.P., "Stochastic Heterogeneity and Disper- sion,'' PhD dissertation, The University of Texas Deparnnent of Petroleum Engineering (1990). Mandelbrot, B.B., The Fractal Geometry of Nature, Freeman, New York City (1983). Emanuel, A.S., Alameda, G.K., Behrens, R.A., and Hewett, T.A., "Reservoir Performance Prediction Methods Based on Fractal Geostatistics," SPERE (Aug. 1989) 311-318. 20. 21. Isaaks, E.H., and Srivasmva, R.M., Applied Geostatistics, Oxford University Press (1989). Ripley, Brian D., Spatial Statistics, John Wiley & Sons, New York City (1981). 31. Matthews, J.L., Emanuel, A.S., and Edwards, K.A., "A Modeling Study of the Mitsue Stage 1 Miscible Flood Using Fractal Geometries," paper SPE 18327 present- ed at the 1988 Annual Technical Conference, Houston, Oct 2-5. 22. 23. 24. 25. 26. 27. Kelkar, Mohan, "Introduction to Geostatisfics," Tutori- al Paper, Third International Reservoir Characteriza- tion Technical Conference, Tulsa, Nov. 3-5, 1991. Kim, Young C., Introductory Geostatistics and Mine Planning, Course Notes, University of Arizona Depart- ment of Mining and Geological Engineering (1990). De Costa e Silva, A.J., "A New Approach to the Characterization of Reservoir Heterogeneity Based on the Geomathematical Model and Kfiging Technique," paper SPE 14275 presented at the 1985 Annual Technical Conference, Las Vegas, Sept. 22-25. Chopra, A.K., Severson, C.D., and Carhart, S.R., "Evaluation of Geostatistical Techniques for Reservoir Characterization," paper SPE 20734 presented at the 1990 Annual Technical Conference, New Orleans, Sept. 23-26. Hewett, T.A., "Fractal Distributions of Reservoir Heterogeneity and Their Influence on Fluid Trans- port,'' paper SPE 15386 presented at the 1986 SPE Annual Technical Conference and Exhibition, New Orleans, Oct. 5-8. Hewett, T.A., and Behrens, R.A., "Conditional Simu- lation of Reservoir Heterogeneity with Fractals," SPERE (Sept. 1990) 217-225. 32. Crane, S.D., and Tubman, K.M., "Reservoir Variability and Modeling with Fractals," paper SPE 20606 presented at the SPE 1990 Annual Technical Confer- ence, New Orleans, Sept. 23-26. 33. Aasum, Y., Kelkar, M.G., and Gupta, S.P., "An Application of Geostatistics and Fmctal Geometry for Reservoir Characterization," SPEFE (March 1991) I 1- 19. 34. Perez, G., and Chopin, A.K., "Evaluation of Fmctal Models to Describe Reservoir Heterogeneity and Performance," paper SPE 22694 presented at the 1991 SPE Annual Technical Conference, Dallas, Oct. 6-9. 35. Mandelbrot, B.B., and Van Ness, J.W., "Fractional Brownian Motions, Fractional Noises, and Applica- tions,'' SIAM Rev., Oct. 1968, 10, 4, 422-437. 36. Mandelbrot, B.B., and Wallis, J.R., "Robusmess of the Rescaled Range R/S in the Measurement of Noncyclic Long Run Sta. tistical Dependence", Water Resources Research, Oct. 1969. 37. Law, J., "Statistical Approach to the Interstitial Heter- ogeneity of Sand Reservoirs," Trans. AIME (1944) 155, 202-222. 38. Warren, J.E., and Price, H.S., "Flow in Heterogeneous Porous Media," Trans. AIME (1961) 222, 153-169. 321 10 SPE 2397£ Th{ Dimensional Conditional Simulation of{ ~-meider (Buda) Ficld 39. Jensen, J.L., Hinkley, D.V., and Lake, L.W., "A Statistical Study of Reservoir Permeability: Distribu- tions, Correlations, and Averages," SPERE (Dec. 1987), 461-468. 40. Joumel, A.G., Deutsch, C., and Desbarats, A.J., "Power Averaging for Block Effective Permeability," paper SPE 15128 presented at the 1986 SPE California Regional Meeting, Oakland, Apr. 2-4. WINNS~ORO )UITMAN SCHNEIDE. R I:*IF-LD · DAI.LAS ~X~ARKANA AUSTIN · WOOD COUNTY 0 5 'lO CORPUS Figure 1 - Location of Schneider (Buda) Field. SCHNEIDER (BUDA) FIELD Figure 2 - Rendered View of Hainesviile Salt Dome and Schneider (Buda) Field Reservoir. 322 WESLEY TOLLETT A-575 EPCO Jones No. 1 12,450' -8565 ~1~ oBRIT]SH AMERICAN 1t,.,9o' Weisenhunt No. ! BRITISH AMERICAN Weisenhunt Ne.B- I 10,023' -9022 Un. Peacock No. 13,075' / / I/ I i I i I I Jones OH SL JO N LAMON$ I Scale in Feet Figure 3 - Structure Map of Schneider (Buda) Field on Top of Buda Formation. ,f I 10(1 - I0 1987 TIME (YEAR) I000 O 1000 0 Figure 4 - Production/Injection History Graph of Schneider (Buda) Field. 4500 I ~ .... ~ 40OO 35OO 3OOO 25O0 JONES NO. 2 (UNIT NO. 3) JONES NO. 3 STH (UNIT NO. 4)I PEACOCK NO. 1 (UNIT NO. 1 UNIT NO, 1 WI BEGIN INJECTION~~~<~ - ! 1988 1989 1990 1991 131::~[S,~UI::~ AT SL~SF_A DATUM TIME (YEAR) Figure 5 - Pressure History Graph of Schneider (Buda) Field. 324 LEGEND · REEF FACIES [] REEF DEBRIS FACIES [~ SHOALING GRAINSTONE APRON = :1 Figure 6 - Fence Diagram of Schneider (Buda) Reservoir. Figure 7 - Rendering of Reef Debris Facies. 325 REEF ~REEF DEBRIS FACIES Figure 8 - Rendering of Reel ancl Reef Del~-is Facies. ~,SHOALING GRAINS TONE APRON Figure 9 - Rendering of all Three Facies: Reef. Reef De~'~s. an0 Shoaling Grainstone Aoroa. 326 Figure 10 - Core Slab Photographs of the Four Lithofacies Present in the Schneider Field. ! ql ~4 lei :a3 :a.~ :als :all :am 30 37' ,40 I 2 3 4 5 6 7 $ 9 ;011121314 1516 1718192021 ! , , ; I I - EXISTING WELLS [] - WA'I~R 2-D VERTICAL CONDITIONAL SIMUf..~TION Figure 11 - Schematic of Three Dimensional Conditional Simulation Grid. 327 Vertical Scale Compressed Layer 1 Layer 3 Layer 5 Layer 2 Layer 4. ....... ~:.: ::.,', ...... -.._ ~og,o tc 3,150 Ft. Figure 12 - First Three Dimensional Permeability Distribution. Vertical Scale Compressed · '~ ,. Layer 1 Layer 3 Layer 5 Layer 2 Layer 4 Layer 6 ~- 3.150 Ft. .I Figure 13 - Final Three Dimensional Permeability Distribution. 328 Endicott Field. Arctic Ocean. Alaska 1995-present CG&A provided consulting services for British Petroleum Exploration's Endicott Asset Group in Anchorage, Alaska. The Endicott Field is located offshore the North Slope of Alaska. Original oil-in-place is estimated to be 1.1 billion STBO with a cumulative oil production of over 300 million STBO. CGA's services involved two separate simulation projects. The first project involved building a partial field model of the upper subzones of the Endicott field to evaluate a proposed enhanced oil recovery, project. We developed a modified black oil model with representation of the target zones by first tuning model parameters with sequential fine grid models which were then upscaled to the final partial field model. The model was history matched at the individual well level and optimized waterflood and WAG cases were developed. The final results will be used to justify implementing the EOR project and to evaluate the infill drilling of several wells in the upper subzones. The second project involved work on a full field simulation model of the Endicott Field which had been developed by British Petroleum. The model had approximately 50,000 active grid cells. Our services involved evaluating the model to identi~ areas for improvement. We instituted a new methodology of well management and replaced the hydraulic tables with an enhanced method of estimating pressure drops in the tubing that occur with multiphase flow. We also improved on the history match and then evaluated the incremental production rates and reserves associated with various facility upgrades. We also performed sensitivities to changing water injection patterns to determine the effect on incremental oil recovery. Our work will be used to justify the investments associated with the upgrades. · Simulation Software: · Personnel Responsible: Reservoir Type Data: · Client Contact: Western Atlas VIP-Exec Richard A. )alexander Sam W. French Kekiktuk Formation: Multistory fluvial sandstones separated by thick areally extensive shales and sealin~partially sealing intra-reservoir faults 130+ wells Modified black oil model (Todd/Longstaff) BP Exploration (Alaska), Inc., Mr. Dave Szabo (907) 564-4788 BP Exploration (Alaska), Inc., Mr. Mark Weggeland (907) 564-5351 North Belrid.?,e Diatomite Field. Kern County. California 1995 The productive formation of the Belfidge Field is a low permeability (one to ten millidarcies), high porosity (40 to 60%) diatomaceous earth reservoir approximately 1500 feet thick. The pore structure consists of friable and compressible diatoms :vhich are responsible for the high porosity but lo~v permeability. We have performed extensive reservoir engineering and geological studies of this major oil occurrence. The average well spacing is typically less than one acre. Our'work has consisted of detailed log analysis and mapping, neural network predictions of core porosity and permeability, geostatistical modeling of rock characterization, estimated ori~nal oil and gas in place, predicted the primary performance from ex/sting wells, evaluated the potential for infill drilling, predicted expected recovery, simulation of the primary performance and the expected waterflood potential, and the economics associated with each of these development strategies. · Shnulation Software: CG&AIn-house developed 2-D · Personnel Responsible: · Reservoir Type Data: · Client Contact: CG&A In-house developed 3-D VIP-Exec, Dual PhL/K Neural Networking Geostatistics Data Explorer Visualization Richard A. Alexander Dual porosity., 75+ wells Black-Oil, Solution Gas Diatomaceous Waterflood project Crutcher-Tufts Corporation, Mr. Ed James (504) 581-9327 Lost Hills Field. Kern County. California 1995 The productive formation of the Lost Hills Field is vet similar to the Belridge Field described above. Our ongoing work has consists of detailed log analysis and mapping, neural network predictions of core porosity and permeability, geostatistical modeling cf rock characterization, estimated ori~nal oil and gas in place, predicted the primary performance from e,,dsting wells, evaluated the potential for infill drilling, predicted expected recovery, simulation of the primary performance and the expected waterflood potential, and the economics associated with each of these development strategies. · Simulation Sof~vare: · Personnel Responsible: · Reservoir Type Data: · Client Contact: CG&A In-house developed 2-D VIP-Exec, Dual Phi/K Neural Networking and Geostatistics Data Explorer Visualization Richard A. Alexander Dual porosity, 75+ wells Black-Oil, Solution Gas Diatomaceous Waterfiood project Bakersfield Ener~~ Resources, Mr. Bob Shore (805) 399-4270 South Lake Arthur Field. Vermilion Parish. Louisiana 1993 - present CG&A has performed several studies during the evaluation of the South Lake Arthur Field. The projects consist of a geologic review, volumetric estimates, material balance P/Z analysis, full field performance modeling, estimates of ultimate recovery, single well modeling of producing deliverability, and scheduling of future rates. The reservoir is found in the faulted Mio~'p formation and the special core analysis indicated high formation compressibilities ( 60 microsips). A limited water influx was modeled and the ultimate height of the water table was predicted. · Simulation So,rare: CG&A In-house developed 2-D · Personnel Responsible: · Reservoir Type Data: · Client Contact: IMEX, Computer Modelling Group CG&A Automatic History Matching Dr. Richard F. Stricldand Robert D. Ravnaas Richard A. Alexander bfichael A_ Fox Single porosity, 20 wells Gas High Compressibility Sandstone Depletion v~dth partial water drive Enervest, Mr. John Walker (713) 659-3500 Belrid~e Diatomate Field. Kern Countv~ California 1977-present The productive formation of the Belridge Field is a low permeability (one to ten md.), hi~ porosity (40 to 60%) diatomaceous earth reservoir approximately 1500 feet thick. The pore structure consists of friable and compressible diatoms which are responsible for the high porosity but Iow permeability. We have performed extensive reservoir engineering and geological studies of this major oil occurrence. The average well spacing is typically less than one acre. Our work has consisted of detailed log analysis and mapping, estimated original oil and gas in place, predicted the primary performance from existing wells, evaluated the potential for irtfill drilling, predicted expected recovery, simulation of the primary performance and the expected water-flood potential, and the economics associated with each of these development Simulation Sofb, vare: strate~es. · Personnel Responsible: Reservoir T~e Data: · Client Contact' CG&A In-house developed 2-D CG&A In-house developed 3-D Richard A. Alexander Dr. Richard F. Strickland Dual porosity, 75+ wells Black-Oil, Solution Gas Diatomaceous Waterflood project Bakersfield Ener~, Resources, Mr. Bob Shore (805) 399-4270 Anschutz Ranch East. Utah 1986-1988 This reservoir has over 40 producing gas condensate wills completed throughout a I000 foot pay section. Initial liquid yields were near 300 Bbls of condensate per MMSCF of gas. A major reservoir engineering field study was conducted to determine ownership (equity.), expected fieldwide production rates, indMdual well deliverability, and the state of the fluid as it existed in the reservoir and at the surface. Also several single-well model studies were conducted to verify that sampling procedures correctly defined the reservoir fluid. · Simulation Software: Integrated Technolo~es VIP Compositional · Personnel Responsible: · Reservoir Type Data: · Client Contact: CG&A In-house developed 2-D Richard A. Alexander Dr. Richard F. Stricldand Robert D. Ravnaas Dual porosity, 25+ wells Near Critical Retrograde Gas Eolian Sandstone Nqtrogen Injection M_idcon Corporation, Mr. Jerome ~Mrowca (313) 691-2735 Bryan (Woodbine) Field. Texas 1984-1989 A complete reservoir engineering and geological study was conducted to determine initial oil in place, the expected recovery by primary depletion, the potential for secondary recovery, and the present value economics for each of the plans of depletion. Future primary and secondary performance predictions for each of the 105 wells were accomplished by areal reservoir simulation studies. The results were used as a guide in designing the most profitable and efficient waterflood pattern for the unit. This relatively thin (7 it.), high permeability (200-2000 md) sandstone reservoir covers over 15,000 acres. Wells responding to water injection have produced at rates in excess of 1,000 BPD. The field is currently in the latter stages of decline after a successful implementation of the waterflood which increased unit rates from 4,500 BPD to 22,000 BPD. · Sin~ulation Soft-ware: · Personnel Responsible: · Reservoir Type Data: · Client Contact: CG&A In-house developed 3-D Dr. Richard F. Strickland Single porosit?', 105 wells Black-Oil, Solution Cras with original gas cap Sandstone Waterflood with Gas cap injection B.W.O.C., Inc., Mr. Gary Trover (409) 776-0121 MEMO TO: February 24,1997 STEVE HARTUNG FROM: WALTER WELLS RE: OR.BIS ENGINEERING, INC. CORRESPONDENCE of FEBRUARY 18, 1997 (TO) DAN R. JOHNSON .(I~) PRESSURE MAINTENANCE- WMRU Per your request I have reviewed the above captioned correspondence of 2-18-97 and summarize as follows: PART I OF THEIR LETTER ADDRESSES POTENTIAL CONCERNS WITH THE PROPOSED PRESSURE MAINTENANCE PROGRAM: I have numbered these items no's 1 through 8 for reference and comment individually: ITEM NO. 1: Each geologist 0Warthen, Saltmarsh & Wells) plus the consulting engineering firms that have reported on the reservoirs, recoveries, structure, reserves and/or cash flow and the effect of installation or non-installation of the pressure maintenance program as presently implemented are aware of the potential channeling they describe and the consequences thereof. Bo This is a fact well recognized, however, the only practical way to effect pressure maintenance at WMRU is through reentry and utilization of the proposed well. It is well positioned as to flank location and the cased-hole reentry aspect makes it very cost effective. C, Multiple injection wells would be preferable; however, that would be cost prohibitive. De In order to avoid channeling, the injections rates and pressure will be kept low. RECEIVED ITEMS NO. 2, 3 & 4 A. Reservoir heterogeneity and permeability variations between and within individual reservoirs (benches) are recognized phenomena of the Hemlock reservoirs. These items simply state the problems; there is no easy solution. (see "Summary Comments") ITEM NO. 5 A. Logs, including various open-hole log suites plus mud (sample) logs have all been examined. I'm not aware of any disagreement as to well-to-well correlations within WMRU. There is, in fact, a rather high degree of lateral continuity between Hemlock sections in this entire general area. ITEM NO. 6 A, At least 3 volumetric estimates have been made to dat~, all by extremely capable individuals. It is agreed that there is a probable mix of reservoir drive mechanisms at WMRU. ITEMS NO 7 & 8 A. No direct comparison has been made of the proposed WMRU-PM program with the large McArthur River Field waterflood. In point of fact, the same percentage recoveries of OOIP are not suggested. B, Note that recoveries at McArthur River will approach 50-'52% of OO!p; this is possible because (at least in part), of the opportunities for multiple injection wells. There is no such opportunity at WMRU; that is why the Huddleston & Co., report of 1-1-97 specifically addresses this point and projects a recovery of 30%. Note that in this report a risk adjusted case is also provided. SUMMARY COMMENTS In general the Orbis letter address facts which are well recognized and that have been considered in all previous reserve estimates and subsurface studies. The facts are that WMRU cannot support a multiple injection well program; the one- well program may not be ideal but it will certainly provide pressure support and enhance recoveries. This program has always been proposed as the most economical way to maximize recoveries at the lowest practical cost. R ~ C ~ ~ V ~ D ESCOPETA PRODUCTION ALASKA, INC. ANCHORAGE, ALASKA An. cYtorage The material balance study referred to is a means for estimating the volume of the reservoir. At least two reservoir studies have been made incorporating net sand (reservoir) mapping; also certain data desirable for material balance calculations is not available, specifically: core data, gas analysis and original and current oil analysis. You will never be able to obtain core data; if you want a material balance report, Huddleston & Co. can run one in about a week (I would estimate) after they receive oil & gas analyses. If you wish additional clarification or have further questions as a result of reading this or the Orbis Engineering letter, that you contact directly those who have already made rather exhaustive studies of the subsurface geology and reservoir aspects (i.e. OOIP estimates, recoveries, etc.) of WMRU, Mr. Robert Warthen and Huddleston & Co. They should be able to provide you with a very timely and capable response. Let me know if I can help you further in this regard. CS tTmmD P .T tOZSO S OnOO ST AAPG (CPG #3214) AIPG (CPG #6993) ALASKA (CPG #AA-307) FEBRUARY 24, 1997 ATTCH: Annotated copy of Orbis Engr. letter of 2-18-97. ESCOPETA PRODUCTION ALASKA, INC. ANCHORAGE, ALASKA RECEIVED h~chora.ge FEB 19 '9,' 08:~AM ~ebru~ t~, i~ Mt. Dan lt.. JoZmson P.O. Goz tgtO04 ~~, AX 9~$19 Au ,au~mpt u:) ~ tl~ ~~ 12~ voidMe taro (oil, ~ ~ ~1 Well ~~wells~~. ~~ reservoir su~y zo opOmize reoovcry from I. Co=~Io2 a brief.review of me tdsmry ,.d probJmns usociated wire ese ualosmu McArtbm. River 2. Review the W)43Un Seolosy inc]udi~- ~ or v~om su*miZ3:aph~ ~ ~ ~ ~s~ ~~ ~ve ~~. Orbis q,precims the~ to provide you witlt d)h work Fropmal. Your project ippeir8 robe one wi~ a tTeat deal o! potent, and we wmzld welcome tbe ~ to help ym incrnse ~ ~rcm Ltm fie~. Y~y~u b~ve Luy q~-dio~, p~eue do no~ be~lm~ m conza~ us. M.P. C~.,J~ Prelim 'SOCIETY OF PETRCL~"JM EI,IGIi~E---_.= OF AiS.~ 6200 ~.~crth Centrz! --'.?ressway D~!las, Texas 75206 THIS IS A P.=.:?R~:T --- SU.A~ECT TO COF.?.EC-.!Oi~ E 32 3 Early Reservo i r Model lng o f Trading Bay Uti it Hemlock Formation By W. H. E!liott. Jr. and C. J. Diver, Member-- A2..'.~, >:5razhon Oil Co. ~" Col)yri::hl ] 97 l A,,,,.ri('a,, it:..,titutc of 3li,,i,,~..%l(.tallurr.:i(-al. a,,,I l',.tr,,I,.,,,,, E,,~zin(.,.r.~. !,,'. This paper was prepared for the Southwest Alaska Section Regional Meeti~ng of the Society of Petroleum Engineers of AI~,~, to be held in Anchorage, Alaska, ~.~y 5-7, 1971. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous ack_nowledgment of where s.nd by whom the paper is presented. Fublication elsewhere after publication in the JOb~dL~ OF P~OL~-I~M TEC'-2~OLOGY or the SOCIETY OF PETROLEb~ ENG~,S JOUPJ,:AL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. ?nree copies of ~ny discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publicztion in one of ~he t~,,o SPE magazines. ABSTRACT With considerable foresight, the Working Interest Owners in ~he Trading Bay Unit approved the first performance prediction for the Hemlock reservoir before the first development well was spudded in the Unit. This study and subsequent ones have been made utilizing a high speed digi~ al computer and a program which simulates flow of one, two or three fluid phases in one, two or three dimensions within a reservoir model com- posed of several thousand grid cells. The fluid flow si~u~a~o~ has been described in published papers. The incentives which prompted the engineer- ing representatives to recommend expenditures for computer simulation and management to ap- prove the expenditures are outlined. In essence these incentives are proper reservoir management and effective utilization of reservoir energy (either natural or induced) to (1) sustain a high field producing rate, (2) increase the re- c6very from the reservoir, and (3) minimize in- vestments, particularly by drilling only the re- quired wells. The objectives and major results of ~he important performance predictions and pressure history matches :hat have been made are reviewed. References and illustrations aa end of paper. A number of problems typical of preliminary studies have been encountered, and additional problems will occur in the future. The problems involve simulating fluid flow in the reservoir, in the well bores and at ~he surface. Thus far, adequate solutions to the various problems have been obtained and the s~udies have been success- fully completed. It is concluded :ha: early simulations of historical performance and early performance predictions can be advantageous and profitable. However, engineers should carefully outline all objectives, review :he five ingredien~s of an effective application of simulation models as outlined and proceed to recommend a study that may cost tens of ~housands of dollars only if economically Justified. iNTRODUCTION The Trading Bay Uni: encompasses :he Ho_Arthur River Field which is located in the Cook In!e: about 75 miles southwest of Anchorage, Alaska. ~'he primary producing horizon, :he Hem- lock formation, is approximately 500 fee~ ~hick. It was discovered in 1965, by Union Oil Company of California and Marathon Oil Company. By the end of :!:e 1966 drilling season, a total of eleven '*'elis had been drilled from barges, with- in · ,'hat was :o become the Uni~ boundary, by four 'p~ra[ors representing nine major companies. ;hey essentially defined the oil-wa:er contact :nd provided considerable rock and fluid data. .".ney cost $1 million to $1.5 million each. Five .f ti~e eleven wells produced oil from the 'ormation. Structural interpretation, completed :evelopmen: wells and platform locations are il- _us:rated by Figure 1. On Januar~ 1, 1971, the :umulattve oil recovered from the Hemlock forma- tion was nearly 88 million barrels and the oil :roducing rate was approximately 100,000 barrels :er day. Pressure maintenance was underway with :'~u-aulative water injected amounting to approxi- tamely 51 million barrels from three pla:forms _nto peripheral wells. The organizational meeting of the Eng lng & Planning Group for the Trading Bay Unit -~eld in Los Angeles, California, on February 15, 1967 prior to State approval of the Unit. Durin :his meeting, it was concluded that the economic incentives justified the use of a fluid flow sLmulator and Marathon's was chosen. A forecast .~f primary depletion was made and the report was :utopia:ed in June 1967. ~' TRADING BAY UNIT Hn.tLOCK FO~?"\TION SPE 3243 determination of t]~e optimum size and the opti- mum time for installation of pressure mainten- ance equip:em:, (4) the selection of proper in- Jection and produczion well locations for im- proved recovury and producing re:e, and (5) appropriate selection and si=lng of production equipment from :ublng and artificial lift equi men: to pipe line charge pumps. These are com- plex problems involving not only reservoir be- havior, but also well bore hydraulics, :he in- stallation and performance of equipment, subma- rine pipe lines, a common carrier pipe line on shore, a tanker loading terminal, :he optimum scheduling of tankers, etc. The model s~udies have attemp~%d to account for equipment capaci- ties, including the capacity of the common car- rier pipe line; but tanker schedules and other considerations were intentionally omitted. Seven additional simulator studies have followed. A producing ra~e study during January 1968 compared the feasibilities of water injec- tion and gas injection. Reservoir descriptions from two pressure history matches were prepared iuring July and October 1968; and a prediction ~f water flood performance with several varia- tions was made during January and February 1969. 7he third pressure history match was completed lay 1969. During 3uly, August and October 1969, ~ two-part study to select locations for addi- :ional water injection wells was completed. A ~ourth reservoir description by pressure history ~atching was completed during February 1970 and ;everal predictions were made of performance ,*arious wells conver~ed ~o injection. The fluid flow simulator used in these ~:udies solves the three-phase flow equations in ;ne, %wo and three dimensions, including all :mown sources of energy. }~ost of the work has :eon done, however, in two dimensions without :apillary forces to lower costs. The simulator :as a variety of engineering-oriented options. iNCENTIVES FOR MODEL STUDIES OBJECTIVES ~D RESULTS OF HODEL STUDIES Another author5 has wisely stated that a sufficient and effective application of a simu- lated model contains the following ingredients: (1) a question of economic importance, (2) ade- quate descrip~ions of all related systems with accuracy emphasized only for :hose items which strongly influence importan~ answers, (3) a strong dependence of the answers upon momequtl- ibrium, time dependent, spatial distributions pressure and/or fluid saturations (:he conven- ~ional material balance calcula~ions are mean- ingless), an~ (4) the least sophisticated ma ma:leal model or fluid flow simulator which adequately answer the questions. An'effective study also has a fifth ingredient, which is ing. The recommendations resulting from the simulation must be in the hands of management in time for appropriate action. The objectives and results of some of the studies which have been made will illustrate the application of some of these precepts, par- ticularly ~iming. They will also support the proposition that, although many problems will be encountered and the resu!~s may be imperfect early performance predictions and an early analysi.~ of bcl~ovior u.~;ing tl~u api)ropria~e simu- lation model can be economically beneficial. Study :;o. 1 - Primary Depletion Prediction June 1967 The major incentive which prompts a corpo- :etlon ~o spend money is, of course, profit. 7ha~ incentive was inherent in the Trading Bay 7ni:. A large potential for profitably increas- .ng oil recovery exists because of ~he under- ;a~ura%ed nature of the Hemlock crude, and :he ;ize of ~ha reservoir. Opportunities for im- proved economics included: (1) elimination of ~ecessary wells to save capital investment, (2) ~n early determination of the mos: profitable ~e:hod for maintaining pressure, (3) an early The Major decisions to build offshore plat- forms, lay submarine pipe lines, construct pro- duc:ion facilities onshore and participate in a contr..on cart!ur pipe line wi~!~ a tanker loading dock were .-.:~de competitively before a Unit existed. !'.:waver, wt~en the Unit was formed, managemen~ considered it importan% to compile all available data and prepare a consolidated depletion s~udy with :he fol!owin'~,)~~~ PE 3243 !. Develop a producing race forecast for primary depletion. 2. Prepare an economic analysis includ- ink c~im:~Lc~ capiLn! rcqt~ir('mcnL~, expenses and cash flow bafere federal taxes. 3. Develop any addi~io'nal information which may be useful in planning equipment installations, e[c., and for budget purposes. Analysis of the oil recovered during the drill stem test of the discovery well showed the! solution gas-oil ra~io was approximately 300 cubic feet per barrel and compressibility was very low (8.41 x 10-6 vol./vol.-psi). A few simple calculations indicated ~hat producing re=es per well would decline rapidly as =he reservoir pressure declined from the initial pressure (4265 psia) to the bubble point (1787 psia) and tha~ oil recovery would be less than 10% of the oil in place when the bubble point was reached by pressure depletion. Fixed operating costs would be high, therefore pro- ducing rates at the economic limit would be high and recovery below ~he bubble point was expected to be very low. These es=images were confirmed by =he model study. Figure 2 illustrates a significant pre- diction made in =he first study, that a sharp production decline Would occur before drilling was completed due to the rapid pressure decline. At the time of the study, no development wells had been drilled and the basic assumptions re- flected =he then current belief tha~ neither artificial lif~ equipmen~ nor injection equip- men~ should be ins~alled on the crowded pla=- forms until some drilling equipmen~ was removed. Also reflected were the expec=a~ions =ha= =he m~a~imu~du~r well would be 15_QJ~ BO~Y-~'~that deve~loDme~ should be on 80__a_~r_e~_ $~cing. Subsequent events proved all of these a~o be zncorrec~. But in spi=e of these inaccuracies the study provided reasonably Tl~e urgen~ need to investigate artificial requiremen'.s and =heir effect upon well spacing and crude oil production and ~ransporca=ion fa- cilities · -'as mos= apparent. Therefore, during Nov~.ml)cr 1967, :~ K:~ lifL :~Lt~dy w:,:~ m:~du i~ wt,icl~ well produczivi~ies were ~horough!y evalua[ed u~i!izing reservoir pressures predicted by [he first computer simulation. This study led to the conclusion :hat tl~e productivity of the wells would be much higher than previously estimated and that 4-1/2 inch tubing should be run in the wells instead of smaller tubing. I: was further concluded ~ha: gas lift compressors should be in-j stalled during 1968 in ~he 2000-4000 HP range and that studies were urgently needed on well spacing and production and transportation fa- cilities. Wells were equipped with 4-1/2 inch ~ubing. A 3000 HP compressor was installed on the Dolly Varden platform during late 1968 and another one during 1969. A 4400 HP compressor installation was placed on the Grayling Platform during 1969 and two 2000 HP compressors replaced the original 750 HP gas lift compressor on the King Salmon Platform. Reservoir Descriptions by Pressure History Matchin~ Figure 3 illustrates s:ructural interpretation of the reservoir which occurred between early 1967, before any develop- ment wells were drilled, and late 1970. Nearly all of the changes were forccas'~ by three pres- sure history matches, which is significan~ be- cause, for each of ~he ~hree matching studies made, the oil produced amounted to only approxi- mately 0.7%, 1.5% and 3% respectively of ~he oil ini~ially in place. The model was sensitive volume ci~anges because the oil compressibility was low. ~q~at appear to be small s~ruc~ural changes caused large volume changes due to the ~htckness of the forma:ion. The objectives of the pressure history ma:c~ ing simulations were: sound economic guidance and focused attention on ~he problems which required immediate engineer- ing attention. Early application of artificial lift and pressure maintenance could elevate and smoo~h ~he produc~ion curve. It was therefore recom- mended that compressor equipment be ordered for all platforms as soon as possible. These in- stallations would require considerable redesign work and modifications on the platforms. I~ was recommended tha~ studies begin immediately of ar~ificla! lift requirements and pressure main- =chance schemes. Also recommended were a wa=er Injec=ivi=y test and careful planning of ~he.de- ve!opmen= well drilling program to minimize the drilling of unnecessary wells and ~o maximize the reservoir information obtained. 1. To improve t:he estimate of oil in place. 2. To escima:e the magnitude and areal dis=ribucion of the aquifer drive. 3. To improve ~he escima:es of reservoir volume and cransmissibili:y in par- ~icular areas. . 4. To de~ermine ~he average reservoir pressure during history as a runt- :ion of time and cumulative oil recovery. The his:ory matches indicazed' ~ha~ :he aquifer was e~:panding but at llmi:ed ra~es and not in all areas. They also indica~ed decreasing ~.ransmissibi!ity down-dip, especially low trans-i missibility along the east flank of ~he south ina!f of the field and at the south tip, and a tigh~ s~reak (possibly a minor fault) just east _~f weii G-lO and west of wells D-ii and D-5 '-'hich probably extends to the south end of ~-he fieid as a major fault. EARJ_Y RESERVOIR NODELii;G OF TRADING BAY UNIT HE2.ILOCK FC-'~~' ~ICN SPE 3243 Immoszng Real N¢chanical Limits History matching in two dimensions (2-D) has been adequate because only pressure was being matched. However in the future, it is expected tha~ three-dimensional simulation will be re- quired to match pressure and water cut. PROBLEMS .~ND SOLUTIONS Calculating Well Producing Rates For the first study (June 1967), producing rates were calculated using the simple P.I. equation, an expected specific productivity in- dex of 0.0014 bbls./day-psi-ft, and the ex- pected net feet of oil sand az each location. The best wells (400 feet of oil pay) were per- mi[tad to produce only 1500 barrels of oil per day based on observed producing rates during drill stem tests. Four months after the report was distributed, =he first development well was completed and tasted 4489 barrels of oil per day It was obvious that the initial productivity in- dices should be defined more accurately. After =he first study, the simple produc:iv- ity index equation for calculating producing rate was replaced by several polynomial equa- tions. The polynomials were obtained by surface fits on data from a large number of gas lift calculations (pressure profiles). Each polynom- ial equat%on describes the liquid producing rate as a function of reservoir pressure and pro- ductivity index for a particular tubing size and gas/liquid ratio. The program selects the prop- er equation for the tubing in the well and the appropriate gas/liquid ratio, depending upon whether the well is flowing or gas-lifting. This technique calculates the producing rate more accurately =hen the simple productivity index equation because i= utilizes a unique ~i:uttJt:lnuott~ Solution of tl~e productivity Index equation and the complex aqua=ions which describ~ fluid flow through the tubing. By assigning the proper initial indices to :he wells and allowing the indices to vary with pressure and saturation, acceptable producing ra~es usually were forecast. Measured indices were not always assigned because the gas lift calculations and resulting polynomials assumed ver:iaai wells, gas lift from the bot:om of the =eils and no water cut. To improve on :he solu- tion to this probiem, gas lift calculation mc:t~ods are being improved and the feasibility of making a separate artificial lift calculation for each well in each time step is being invest- igated. The total field producing rate is a function of many variables. Even if the individual well producing capac!k!cs ara aucura~cly calculated, the total field producing ra~a is not defined until the effects of all of :he mechanical restraints from the well heads to ~he markets are defined. In addition, predicted well ra~es are a function of the predicted reservoir pres- sure at each well. These pressures vary in a pressure maintenance projec: with the capacities of ~he injection wells, the injection pumps and the treating equipment. All of these mechanical l~mits are a part of the model. The procedures selected calcula:a the maximum production or in- jection ra~es as con,roi!ed by the wells. These volu~.es are then summed; the sums compared to the various applicable limits; and the individu- al well rates reduced proportionately if neces- sary. The economic effects of making expensive equipment installations affecting one or more of the variables were evaluated by this technique. To do so requires that ~he effect of an install- ation on production be defined wi~h reasonable accuracy. Only the more significant changes are. evaluated, including such installations as a 3000 }LP compressor for lif~, the installation of 40,000 barrels per day of water injection capa- city on a platform or its expansion to 80,000 BWPD. In addition to the large amount of reservoir data supplied to tl~e cumpuker, ~l,u fluid flow simulator will currently accept 115 inpu~ vari- ables relating to fluid flow in the well bores and through surface equipment. Included in these variables are such items as field oil production limits, field gas production limits, individual platform oil production limits, plat- form liquid production limits, platform artifi- cial lift limits, water injection iimi~s, gas injection limits and ~he times to change various limits. In order to analyze the performance predict- t,d by tl~e t'~,~::l,ut,.r, a well rCl>,~r~ I.~ prinLc'd am illus~ratud by Figures 4 a~d 5, wl~ich arc par~s of ~he same page. I= includes ~he well ~ime, its location in the reservoir ma=rix, 17 colons of production and reservoir da~a related ~o ~he well and a col~n labeled "Q" Se=. In ~he "Q" Set column, le~=er-n~ber code groups are used ~o define wha~ has happened to :he well in each ~ime s~ep as a resul~ of ~he 115 inpu~ variables which control flow outside ~he reservoir. The number in ~he code specifies :he ~ubing size while :he let:ars designate nine conditions for ~he well and 12 reasons for ~he condition. Wi~h t~is information and ~c information on platform and field production and injection ra~es, lg is possible ~o de:ermine a great deal about :he effect of equipment insta!la~ions and additional S~E '3243 - wells and whether or not tke production con- trois are working as planned. Two-Dimensional Simulation of 3-D Fluid Flow Designers of fluid flow simu!aaors have proposed various mathematical methods for simu- lating three-dimensional fluid flow in two di- mensions. The designers claim only that such methods are simple approximations of the true fluid flow. The method used in the Hemlock studies has been described in the literature.4 As the au- thors stated, "Gravity and elevation are rigor- ous in tl~e two-dimensional study. However, nobilities and treatment of segrega;ed phases become non-rigorous." W. H. ELLIOTT, JR. and C. ~.~ DIVER To c~scribe the review, selection and ap- plication of the relative permeability data is beyond the scope of this paper. Very briefly, the Group e!ec:ed no: to employ the full capa- b!lity of tl,~. ~.l:,,ul~[or in wl, lcl~ nine ro~k r~- gions can be defined. In ~l~e 2-b work, one sa~ of relative permeabi!i:y curves was assigned ~o the reservoir and one se~ ~o the well cells. This was done ~o compensate for ~he large cell size selected wherein a cell represents a 20 acre block of ~he reservoir. In the 3-D work, the Group has decided ~o use one set of rela~iv< pe~cab!li~y cu~es for rock having less [han 100 mi!lidarcy permeablli~y and another se~ for rock above 100 millidarcy. Both the hardware and the software being The permeability to oil near each well was determined from pressure buildup data. It was converted ~o absolute permeability using the oil relative permeability curve and initial satura- tions. A contour map of these absolute permea- used are fully capable of 3-D simulation. How- bilities was then prepared for digitizing and ever to reduce costs, the Engineering & Planning input. In this manner, the absolute permeabili- Group elected to model in 2-D for the studies ties supplied =o the model were rela~ed to the made to date. The Group recognized thac some error was introduced, but believes the results have been sufficient to satisfy the original quirements. In order to selec~ ~he proper alternative oil permeabilities measured by the pressure suz-veys. Fortunately, this is a wa~er injection projec~ and most of the studies are performed above the bubble point. Therefore, three-phase offered by the simulator for the treatment of relative permeability data generally are not a phase segregation and the calcula~ion of mobili- determining factor. ties, 3-D runs were made on a segmen~ of the reservoir during December 1968. Then, 2-D runs RESULTS were made on the identical segment. The various methods for calculating mobilities were applied The application of fluid flow s~nula~ors tc with and without capillary pressure. This work various problems, particularly in pressure main- was done after an extensive examination of core tenance projects, appears to be increasing. da~a and well logs. This has been adequate, but This =rend will continue if confidence in the ~he au=hors hold the opinion =ha= future model- ing work will require full 3-D simulation for matching water cuts and more accurately pre- dicting ultimate recovery. Relative Permeability resul[s can be gained and maintained. A comparison of actual production perform- ance with the performance predicted by a simu- lator may increase or decrease the confidence a person has in a simulator. Figures 6 through 8 present comparisons which hopefully will in- Probably the most difficul~ rock property crease confidence. In the figures, actual to define is relative permeability. A consider-! monthly average oil producing rate (B/D) is able amount of money, manpower and materials represented by ~t~e solid line and the predic:ed been expended in an effor~ to adequately define the relative permeabllities ~o oil, water and gas. Data have been obtained from more ~han 20 samples. Some of the samples were run a~ reservoir conditions and some a~ room c mon:hly average rate by ~he dashed line. Thc oil rate predicted in the June 1967 study, as sl~own In Figure 6, was very much in error on ~he low side. This was :lie result of For water relative permeabi!i~ies, wa~er pro- underestimating ~he well capacities. The error duced from the aquifer was used in some measure- during 1968 ranges between +100% and +240% of ments wi~tle sodium chloride brine (not racom- the predicted rate and decreases ~o approxi- mended) was used in others. Comparisons were made between measurements using reservoir crude and those wi~h mineral oil. Bo~h sand and con- glomerate smmples were run. l.[ost of ~he tests were on plugs under rasgored staze conditions; however, some whole core da~a were obtained and several fresh samples were run. ma.~e!y -'352 during '1970. The June 1968 predicuion, illustrated in Figure 7, '.'as very close for ~hree months; :hen it exi:ibi:ed a sudden departure from real life. The initial departure amounted to approximately -30% of the predicted mon".h!y re:as but di- minisl~es ~o a range of +3% to -13% during 1970. , EARLY RESERVOI. R M. ODELI:;G OF !' TRADIr;G BaY UNIT HE.~0. OCK FOr VrlON SPE 3243 Yhe predicted annual production for 1970 was benefits tha{. ~ay be derived from -2~.!y 5% high. The initial departure resulted from a forecast of 100,000 BOPD rates caused by assuming compressors would be available by Sap- -amber to supply gas for ar".ificial lift. They Zid not actually materialize un~il early 1969. ~ne other source of error was the assigr---~--ent of a specific productivity index to all wells of 0.015, excep~ where this was inaonsis~en~ wi~h the reservoir mo~el permeabilities. Actual pro- ~uctivity indices proved to be lower, ~herefore well rates were generally computed :oo high. As migh~ be expected, the ability to fore- cast producing rates improved as experience was gained. Figure 8 shows that the monthly oil rates forecasted i:~ the January 1969 study are reasonably close. The largest differences oc- aurred immediately afte~ the study was completed and amount to approximately -18% of the predict- ed rate during the first three months of 1969. During this time, production was curtailed due ~o impaired shipping ability resulting from a tanker strike and severe ice conditions. During 1970, the actual monthly rates vary from 88% to 112% of the predicted rates. For the year, ac- tual productioh is .only 2.5% less than predicted. In the October 1969 forecast, the modeled wa=er injection ra.~es were reduced to more near- ly equal actual injection rates. Time has prov- en this forecas~ of oil rates to be low by 12% for the year. The February 1970 pressure history matching showed that the' active aquifer has continued to increase in size; and the larg- er aquifer is compensating to some degree for ~he lower injection rates. An improvement in opera=lng efficiency has also contributed ~o the higher producing ra=es. All forecasts were based upon 857: efficiency to accoun= for rig · moves, mechanical failures, cons=ruction, ship- ping delays, and other assorted down time. It appears a~ this time that the total field oil producing rate can be forecast with less than ±3% error in the annual production for a~ least two years if reasonably good estimates are available of =he well productivity indices and equipment capacities and if =he aquifer ef- fects are correctly modeled. I= has no~ been possible as ye~ to check the accuracy of long range forecas=s. CONCLUSIONS 1. Early simulations of actual performance (history ma~ching) can be beneficial if the matarlal balance error in ~he simulator can be held to an e.xtremely low tolerance and if :he reservoir being modeled is sensitive to volume and transmissibi!i=y changes. 2. The u~ili~y of a reservoir simulation study should be judged not only on the basis of rate prediction accuracy, bu~ also on o~her 3. Reservoir descriptions can be developed which =ay ~e of considerable value in selecting well ioca:lons and in designing prussure main- tenancc projects. 4. Early performance predictions may em- phasize probit:ns wl~ich had no~ been apparen~ and suggest so!u~lons which will improve economics. The information developed can be useful in jus- tifying equipment installations. 5. Early predictions of performance are particularly beneficial where it is suspected that injection should begin at an early date. 6. A!ti~ough predic:ions made using a fluid flow simulator may not be entirely correct, the results will be much more accurate than ~hose obtained by any other method, provided a rea- sonably good description of the reservoir has been supplied. 7. Experience with a large fluid flow simulator has demonstrated tha~ a reservoir engineer wino knows the field operation should be present to assess the results when critical com- puter runs are made. He should know the source and accuracy of all input da~a and be capable of Judging wi~utl~ur or no~ the output is reasonable. 8. The modeling personnel responsible for the operation of the simulator should know it intimately and be capable of explaining its operation so that it is not a "black box" to the user. ACK;;OW LI!DL;:-!~';T S The participants in ~he Trading Bay Unl~ are: Union Oil Company of California (0para,or and Sub-operator), Marathon Oil Company (Sub- operator), A~lan~ic Richfield Company (Sub- operator), Pan ~nerican Petroleum Corporation, Phillips Petroleum Company, Skel!y Oil Company and Standard Oil Company of California, Western Operations, Incorporated. The auditors appreciate ~he efforts of all ~hose who have made publishing ~his paper possi- ble. REFEREi;CES 1. Brei~enbach, E. A., Thurnau, D. H. and van Pool!ch, I1. K.: "I,~uniscible Fluid Flow Sim- ulator,'' Socluty of Fu~roluum kn~in~ers of A~IE Sy.~:posium in Dallas, 'Ca.;as (April 22- 23, 19683, Preprin~ i;o. SPE 2019. 2. Brei;enbach, E. A., T!,urnau, D. H. and van Pool!on, Ii. K.: "The Fluid Flow Simulation Equations," Socie".y of Petroleum Engineers of AI:.?- Symposium in Dallas, Texas (April 22-23, i968), Preprint No. SPE 2020. 3. Brei'~e::bach, E. A., Thurnau, D. H. and van .o-'e- 5~43 , ' Poollen, H. K.:"Solution' of the Immiscible Flui~ Flow Simulation Equations," Society of Petroleum Engineers Journal (June 1969), 155. 4. Breicenbach, E. A., Thurnau, D. H. and van Poollen, H. K.: "Treatment of Individual Wells and Grids in Reservoir Modeling," S. 9ciety W. H. ELLIOTT, JR and C. J. DIVER of Pec .eum Engineers Journal (December 1968) 341. 5. Coa~s, K. H.: "Use and Misuse of Reservoir Simulation Models," Socie=y of Petro eum Engineers of AIHE Symposium in Liberal, Kansas (:;ovember 14-15, 1968), Preprint No. SPE 2367. q- I + + I I I INJEC?IO# WELl,, I I / I / / / ' ' 197'0 / / ------ 1967 / // ,~=,~--- ~l,g M P~T ,. , 90 - _J'DRILLING TO BE COMPLETED, ~ RTIFICIAL LIFT INSTALLED m° 80 , - o° 70 ~ ~0 0 - ~ I ,,, I I I ,, ; I , I RECEIVED A!aska Oil & Gas Cons. Corr~missb~ Anchora,ge X[LL REPORT 1RAUIflG 6A¥ PR[OlCllOfl RUII 1069-2 ltllS NELL R[PORI i$ fOR TIlE TIF[ STIP EIIUING AT 2.37534 YEARS OR 861.00000 UAYS FROH BEGINtiIIIG OF -ISTORY TIH£ STEP ~ 29 0ALE: 3/I/10 ~£LL STN. HOU[ PEN. flAHL 140. ! J L FT. ,.- IK O 4 23 t- ?K O 12 30 l.. 3~ 0 6 24 K- 4K O IZ 26 ~- SK O 16 30 ~- 6~ 0 8 34 trRACFLr..,"d NUtlOER 4 OIL O0000000000000bO0000000C, C, O0000000000 CALC. Ct, H. U.U. PN£S. PRES. CALC. FLOg FLOW 5AIH. NLLL EXTR. P.I. 8/U ~SlB PSi PSi T.F. 318 L4 3381 3181 .b3Z 2775 2828 3.3 212 L[4 5Jl 1569 .502 ?9~4 Z961 2.2 210 LF4 1041 bll .514 ~73 2909 4.~ ]36 LF4 525 1421 .4gl E195 2U03 $.6 311 L4 2353 22]9 .$51 Z102 2170 3.4 390 14 0 29 .5ZO 330~ 3242 6.9 Ill 14 0 lb .539 34~3 3129 3.4 Fl~., ~, - ~ei! report {'art A, t)'pica! prediction r--'.. G A S N A I E R GGGGGGGGGGGGGGGGGGGGG b'did~ttRNbl~41~ CALC. ChH. CALC. CALC.CUM. CALC. TOlL FLOW FUN GOR SATH. FLOg FLOg ~OR LIFT HCF/D lt~lCF CF/B 8/O HST8 U/6 B/O 1055 992 312 .000 0 0 O.O 3381 166 489 312 .000 938 514 1.8 1468 321 214 312 .OOO 1306 247 1.2 2353 164 443 31Z .000 1853 850 3.6 2318 734 699 31Z .000 981 34S 0.4 3340 0 9 .000 -13132-3016 13132 0 6 .000 -b620 -~41 -b6ZO Fig. 5 - ~ell report Pert B, typtcil prediction run. I10 I00 90 80 7O 60 ,°I 40 ~0 ~0 I0 0 [ I [ ~ i I i i i ill i i [ ] i i i'[ ! [ i'1 i i'] ll ] 1 i 1 i"11 i i i ~,-~----PREDICTED JUNE '67 JF~v//// i dNID [ JIF iUlA IkII J I J IAi~ IOINIOg JIF lUiA lulJ I J IA I$1oINIOI j IF I~IA lu l J I j I A IS IoIN Io 1968 j 1969 I 1970 ¥IK. ') - Comparison 01' June~ X'kF/, preiJcted utth actual oti prol=¢~.=K rate, O m O O O I U 0 O: .J I10 I00 90 8o 70 60 50 40 ~ I [ I I I'1 I I I I [ I I I I I I i !'! I i i"l i i il i i i i i i i il PREDICTED dUNE '68 ~ -~---A. CT UAL .'-t~. '/ - 'c-eeri"-m~ o:' .'~.-.e, t-.'-.~, rre.~'.::e.t '.'itl a~".t_ jti productr.~ rate. RESEARCH CENTER.LIBRARY ~J. TS PRESEI,;-.A.-IDN iS ~jBJEC-. TO CCRF.r-CTiO~: SPE 5530 Performance of the Hemlock Reservoir- Mc Arthur River Fi eld MF. Ni' DELIVERY SERVICE ~r · . ............ X~MOIICO~-~VJ' Diver, ,'.:ara.~kon Oil Co., J. W HarT, -'-~-~.*4-~ =~chfie!d Co, ~.d g. A. .M,~ 801~ Union Oil Co. of California, Me=bets one (~0~) 79&~1 (341) ©Copyright 1975 American Institute of .h, Iining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 5Oth Annual Fall Meet±ng of the Society of Uetroleum Engineers of ~IME, to be held in Dallas, Texas, Sept. g~-Oc~, l, 1975. Mermission uo copy is restricted to an abstrac~ of not more than ~OO words. Illustrations may no~ ~e copied. The abstract should contain conspicuous acknowledg~en~ of where and by whom the paper is presented. ?ublicat!on elsewhere after publication in ~he JOURnaL O~ ~ETROLEUN TEC}~OLO~Y or the SOCIETY OF PETBOLEb~ ENG!~._-nS JOURnaL is usually grouted upon request ~o ~he Editor cf the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of a~.y discussion should be sen~ to the Scciety of Petroleum Engineers office. Such discussions may be presented a~ the zbove meeting and, '*Ith the paper, may be considered for publication in one of the =~c SPE m~gazines. ABSTRACT The pressure maintenance program by water injection in the Hemlock Reservoir of the McArthur River Field - Cook Inlet, Alaska - has been extremely successful. This is one of the largest offshore water injection projects in ,North America. Constant engineering study ~nd surveillance coupled with an aggressive att'itude on the part of the owners has resulted in a program which will maximize productivity and ultimate recovery from the reservoir. iNTRODUCTION The McArtnur River Field is located about 70 miles southwest of Anchorage, Alaska, in Cook inlet (Fig. 1). The field was discovered in 1965 by the Union-Marathon Grayling Well No. l-A. The field outline was suOsequently delineated by ten additional exploratory wells drilled by four operators over a period of two years. Current production is IS4,000 BOPD from 49 wells which have been drilled from three platforms. Initial oil-in-place was in excess cf one billion barrels and cumulative pro- ~uction through June 1975 was about 250 mi! lion barrels. R-:~'erences aro illustrations a.c end of paper. The field was unitized as the Trading Bay Unit in August 1967 before development drilling operations had commenced. A unique feature of the Unit Agreement provided for equity redeter- minations at specified intervals. This was a necessary and desirable vehicle to encourage unitization prior to development drilling and recognize subsequent data derived from develop- merit drilling. Union Oil Company of California is Unit Operator with Union, Marathon Oil Company and Atlantic Richfield Company as Sub- operators for the three drilling and production platforms. The fi eld has been effectively engineered through the Unit Engineering & Plan- ning Group which was formed in 1967 and has taken an active and continuing part in reservoir management throughout the life of the field. Engineering guidance led to the early installa- tion of pressure maintenance facilities and to the installation and subsequent expansion of artificial !ift on board the platforms. Engi- neering eva,uation of the field-wide injection pressure maintenance project has been contin- uous since its inception and engineering study led to the introducti,on in 1973 of an extremely successful infill drilling program which is still in progress. FIELD DESCRIPTION The McArthur River Structure as shown in ~ig. 2 is uncompilcated and composed of two PE~' RI.~AHCE OF THE HEMLOCK RE~ERVOZR J' .ARTHUR RIVER FIELD anticlines with an intervening syncline forming one' major structural trap. Apprcximately 900 feet of closure exists on this structure. A crestal apex of tb, e major anticline occurs in Sec. 28, TgN, R13W. The dominant axis trends NIOOW. Flank dims in the field vary from 6o - 80 on the east and up to 200 on the west. The major Trading Bay Fault establishes the northwest limit of the McArthur River structural trap. This fault is a large thrust fault with possible lateral northeast move- ment of the separate up-thrown Trading Bay Field area. A normal fault striking N96ow occurs in the southwest part of the structure in beds above the Hemlock Formation. The sediments in McArthur River Field are comprised of several hundred feet of Recent to Quaternary fluvio-glacial gravels and clays underlain by about 10,500 feet of non-marine Tertiary Kenai Group sediments comprised of lenticular, often discontinuous, units of sandstone, conglomerate, siltstones and clay- stones. These Tertiary sediments are under- lain unconformably by an unknown thickness of Lower Jurassic Talkeetna Formation volcanics and metasediments. Part of the lower Unit of the Kenai Group, the Hemlock Formation, Oligocene in age, is a clayey to sandy, pebble to boulder conglomerate, interbedded with pebbly sandstone', minor siltstone and occasional coal. The Hemlock Formation in this field has a gross thickness of approximately 500 feet. There are six main intervals or layers ~eparated by immemvious ~iltstoneEwhich exist ~_,-6'Ve__r. ~hm en~i~ -trJct~]~e. A typical log illustrating this layering is shown in Fig. 3. The quantity of mixed silt and clay varies with lithology averaging about 12 percent in the sandstones and about 16 percent in the conglomerates. Net effective section varies from 300 to 425 feet in thickness. Perme- ability measurements vary with lithology and structural position but average~ on the crest of the structure degra~ 25 md. on the flanks. Several core samples wer~ subjected to 2500 psi frame pressure and porosity value corrections applied to the remainder of the core values. The predom- inately sand samples have an average porosity of approximately ~ percent while the more conglomeratic, samDl~ average 9.5 percent. ~----.~.we~ghted porosity ~s estimated I_~-to b--~qJ~.~)~ercent. Original water satura- .'~tion esti'~ates vary from 35 - 40 percent. The Hemlock produces a 35o API paraf- finic crude. At original reservoir condi- tions of temperature and pressure, the solution GOR was 309 cubic feet per barrel ~.~-:~'t-t,ing in a formation volume factor of 1.186.~ Viscosity of the saturated crude SPE 553~ at reservoir temperature of 185OF. is I cp. The bubble ~oint has been measured at 1790 psia or nearly 2500 psia less than the original reservoir pressure indicating the highly under- saturated condition of the system. Laboratory data shows no variation of crude analysis either vertically or horizontally throughout the field. The interstitial water has a salinity of approximately 24,000 ppm and contains practi- cally no barium or strontium. At reservoir conditions this water has a viscosity of 0,35 cp EARLY PERFORMANCE The field has been developed from :hree platforms with two drilling rigs on each of the platforms. These platforms have operated suc- cessfully in the harsh Cook Inlet environment where tides fluctuate by up to 35 feet, currents run as high as 8 knots and ice floes can form up to 4 feet thick. They have withstood a 5.9 magnitude earthquake in 1968 centered only 60 miles away. Development drilling operations conmenced in the last half of 1967. Analysis of the drill stem test data from the explora- tory wells provided some clue as to what should be expected. However, it was not until the first development well was completed that the true quality of the field was fully appreciated. The first wells were drilled on the crest of the field so these early wells for the most part encountered a full section of pay above the oil-water contact. The combination of thick- ness, permeability and favorable viscosity resulted in PI's in the range of 5 to 10 and ini~n r~t~ uF ~p This high rate of production was a s. urprise, since wells._jd~iher fields in the Cook Inlet completed prior to 1968 were pro- ducing _at"'~-¥erage rates in the 1 ,~500 BOPD range. -"- -- Within eight months' the field rate increas- ed to 70,000 BOPD {Fig. 4). Platform produc- tion faciliteis became fully loaded almost immediately requiring rapid expansion of flow lines and headers, separation equipment, and shipping facilities. Reservoir pressure de- clined rapidly due to the under saturated crude and the lack of any substantial natural water drive. The declining reservoir pres- sure required the installation of artificial lift equipment earlier than had been anticipated leading to further platform construction activity during the development drilling phase. As a result of the high withdrawal rates and rapidly declini, ng pressure, engineering studies were instituted to cope with the attendant problems. To maintain producing rates, artificial lift methods had to be designed; and to combat the pressure drop, some means of pressure maintenance was necessary. SPE 5S30' i" J. Diver, J. W. Hart, G. A. Gra.~ ARTIFICIAL LIFT Although initial wells produced at rates in excess of 5,OOO BOPD, the rapidly declining bottom hole pressure required that artificial lift be installed very early in order to main- tain productivity. Several alternate methods of lift were considered but .it was apparent that gas lift was best suited, at least for some initial period. The low formation gas-oil ratio (300:1), the deep lift (9,000'+), and the high volume of mostly clean oil production repre- sented an almost ideal condition for gas lift. Other methods of lift have been studied period- ically but it appears at this time that gas lift is still the most efficient lifting mechanism and will continue to be for the fore- seeable future. Expansion of the gas compres- sion facilities on board the platforms is still taking place. Depending on platform produced fluid rate, compression horsepower varies from 7,500 to 13,500. PRESSURE MAINTENANCE ~' Reservoir performance of other fields~ Cook In-~et Basin inc~icatec~ insufficient voidage fe_~cement by na:ura! aquifer expansion.' A primary depletion stucly on McArthur R~'r, prior to the start of development drilling, indicated that without water influx oil recovery would be quite low, producing rates would de- cline rapidly, and the fi eld life would be extended over a long time. This study and other early studies have been described previously.1 The results of the primary depletion study led directly into a comprehensive study of the alternatives for pressure maintenance. This work effort was accelerated by the completion of the first development wells in late 1967 at the 8,000 BOPD oil rates. A comprehensive program for reservoir pressure data gathering was implemented from the outset and these data confirmed the anticipated rapid pressure de- cline. This data showed that in February 1968, only three months after initial production, a pressure drop of 200 psi had taken place in the major portion of the field. In January 1968, the Engineering & Plan- ning Group completed the first of a series of pressure maintenance evaluation studies. This first study recommended that design of water flood facilities co~nce immediately for all three platforms and that a well be drilled on the periphery of the reservoir in order to conduct water injection tests. A month later the group completed an investigation of gas injection as another means of pressure maintenance. The volume of gas required exceed- ed any known available supply and it was con- cluded that water injection was the only feasi- ble method to employ. These recommendations were rapidly implemented and in_~jy 1968~er ~nAiectivity te%t ~n W~ll K-6__c~bora be in_jet~c:.d-i-Frto--t~~~i r ~-~ thout detri- mental~f-Fe'E'ts. ~n ~,,h~e~zent tests~ inj~c,'ion fa_res up to 30,00~r_~Zab!!she~. aY surface pressures of 3,.O0.0...to.j~SOCL.os.i.. Ln_.~J~is w~.q-e---l'9-6~-, ~mmediately following the successful injection test, water injection plants were ordered for the three platforms. Having decided on water injection as the means for pressure maintenance, the next engineering problem was the selection of a pattern. Five-spot and inverted nine-spot patterns were studied. However, a major dis- advantage was the requirement to convert several high productivity wells on the crest of the structure which would have resulted in a sub- stantial reduction in field rate. As an a~_ternative i~ wa~ decided to start out inject- !ng fn~~er_tphe~al wails_ nfLthe in'~ePte~l of._~lank.__ioje~i~.p_o. Even though individual w~ inje~t-i'~ities were somewhat less on the average than those in the test well, su~t water wa~ ip~iected to cause a pressure response~in one exceg_.t.i_op~_~.]] wa.ize, r_.j_~ection to _d~l_te--b~ _1~]~i'_~-._~.~0 wells located on the'~~ry of the fi el d. In early 1969, full scale water injection commenced (Fig. 4). Construction of the plants continued through 1969 and by mid-1970, the total injection rate was 120,000 BWPD, about the volume required to replace voidage. After expansion and modification of the plants, total injection reached 170,000 BPD in 1971 and has been maintained at this level. Because of the large volume of water required, the only reasonable water source was Cook Inlet, a very dirty, glacial silt laden body of water. The water is deaerated in a vacuum or stripping tower. All platforms utilize upflow sand filters with upstream injection of a flocculating agent. This type filter has been used for industrial purposes along the Mississippi River, but this was the first time they were used for an oil field water treatment plant. On two platforms diatomaceous earth filters are employed to reduce the_.solids content to less than 1 ppm. w a.~,t~p~ a ~,±s ._by.. ga S,._t,,,u...r..b.!._~ ~dr_i_v_e.~ centrifugal pumps operating at pressures from_m~__ w'~'l'T~-Ts-"tti'~"~-o~'thern part of the reservoir was not as high as the wells on the north flank so the higher pressures are required on the southern-most platform. 4 SPE 5530 PERFORICAN~'" OF THE HEMLOCK RESERVOIR - MCARTHi~."". RIVER FIELD In late 1969, before balance between in- jection and production was achieved, the field- wide average pressure was calculated to be 2,850 psi representing a pressure drop of about 1,400 psi. Cumulative production at this time was 53.5 million barrels of oil. Measured pressures revealed even lower pressures in the south- central portion of the field as shown in Fig. 5. Pressures as low as 2,400 psi were measured in this area. The low injection rates in the east and southern flank wells were insufficient to offset the large withdrawal rates of the crestal wells. This prompted studies to evaluate a modification of the injection pattern to achieve more injection if the rate could not be in- creased in the existing wells. Two significant problems with the water flood project were recognized, (1) a lack of sufficient injection rate, and (2) unacceptable vertical distribution of the injected fluid. To deal with this, a major injection well stimulation program was undertaken. The objective was to achieve improv- ed vertical water distribution through large volume mud-acid stimulation treatments of the injection wells while at the same time gaining a substantial increase in overall injection rates. The procedure for these stimulation treatments has been detailed in another paper.2 Results were good in some wells. Profile improvement did result in increased injection rates. However, the full effects were not realized until facility expansions were com- pleted on the platforms. During this time, casing parted in an injection well near the low pressure area and it was recommended the well be redrilled to a somewhat in-field location. This was an attempt to locate the well in a more permeable section of the reservoir closer to the low pressure area. The success of this decision was confirmed when the new well was completed at an initial injection rate of 16,000 BPD, a 9,000 BPD increase from the original well. A near ideal injection profile was achieved in this interior well after acidizing. The nearly simultaneous events of success- ful workovers and relocation of a key injection well resulted in a more uniform vertical and areal distribution of injected water. tially if at all effective. The conversion of one producer and the relocation of one injector are currently under study as a means of solving this problem. In 1974, a flank well that was producing a low fluid rase with a high water cut was redrilled to a new bottom hole location only 100 feet away from the original hole. The purpose of this was two-fold. We wanted to see if we could re-establish con~nercial production in a watered out well by redrilling. Because of the heterogeneous nature of the reservoir, the possibility of bypassing large volumes of oll in less permeable zones was of major concern. Secondarily, we wanted to evaluate the extent to which the reservior had been flooded verti- cally in this part of the field. After we began injecting volumes substan- tially in excess of reservoir voidage in 1971, the pressure decline throughout the field was reversed. The pressure distribution in January t973 is illustrated in Fig. 6. Since that time the average pressure has been steadily increas- ing. The low pressure area in the south- central portion of the field still remains. This is felt to be a result of the lack of reservoir continuity or minor faulting along this flank of the field. ' ~ ' ~%ection ~nto one or two wells on :he west flank is only par- Our primary objective was only partially successful. The well produced only 1,O00 BOPD with less than 5 percent water cut from the redrilled completion. However, the.new logs indicated much better vertical sweep than we had anticipated. Most of the lower sand sections appeared to have been swept by the injected water. Log analysis indicated some 150 feet of reservoir with water saturation changes of about 25 to 30 percent Approximately 35 feet of more shaley interval indicated about 0 - l0 percent change in water saturation. Vertical conformance from this data is estimated at 80 percent. Ju) wa_ter floodi~q h.~j._~ional ..... . Pri to full implementation of the flood sure~~; , pres was declining throughout the reservoir with'~m~ ~~ corresponding steep decline rate for the ind vidual producing wells. Success of the water flood project is attributed to several factors- 1. The vertical conformance of water in- jected into the reservoir appears to be excep- tionally good. 2. Displacement efficiency is high. 3. Pressure transmissibility over long distances across the reservoir has been good. 4. Pressure has been maintained above the bubble point throughout the reservoir. 5. There is an absence of significant "thief" zones common to many water injection projects. PRODUCTION WELL STiMULAT~ON Two workover techniques have been employed to restore productivity in the field. To-date three successful matrix acid stim- ulations have been performed resulting in pro- ductivity increases of ~wo to three fold. 'One job failed as a result of the acid breaking by the primary cement and stimulating a water bearing interval. C. J. Diver, J. W. Hart, G. A. G(: am INFILL DRILLING Reperforating under drawd~wn conditions has proven to be a satisfactory technique for stim- ulation. A drop in productivity was first measured as a reduction of transmissibility on pressure buildup analysis. Later, production logs indicated sections of the well not con- tributing any fluid, it was these intervals which were initially reperforated with marked success. It is surmised that some fines in the matrix plug existing perforations as a re_sult of the movement of large quantities of fluid into the well bores. With cumula- tive fluid production from 4 to ll million barrels per well, only a minor amount of solid material per barrel can result in significant quantities of solids being transported. This productivity loss is the subject of consid- erable study at the present time. RECOMPLETIONS The common problem of the proper water cut at which to shutin producing wells in a peripheral injection project is present in a unique form in the Mr_Arthur River Hemlock. ~Because of a rather flat oil-~. water contact, t~ areal ~xten{ ol~ the lower ~ers l s~onSid~rabi_v l__e_ss _tha~ in t,hq ~up; P~.- water encroachment and high injection rates in these lower layers have caused water production to occur there first. With the beginning of water production, we have observed an abnormal decline in well productivity. This decline is in excess of that attributable to less effective gas lift and saturation changes in the water pro- ductive layers. Production log data showed in many instances a marked drop in oil rate from the water-free sand members. Therefore, we had two reasons for eliminating these water producing intervals in the lower structure wells; (1} retaining reservoir energy for up-structure withdrawal points and (2) pre- vent loss of recovery by restoring produc- tivity to the water-free layers. Simple cement squeezes below a retainer where the primary cement job was suspect or setting a bridge plug have both been successful in eliminating the water production. By shut- ting off this water production, we have successfully restored the oil producing rate from upper layers in nine such wells. The water cut at which these plug-backs are performed is more a function of the drop in upper layer productivity than other con- siderations. In late 1971 and continuing through 1972, a decline in production rate was appar- ent as shovm on Fig. 7.~he field_was _ developed~on essentially 160-a.cr.e s~a~cingL Early studies had indicateO that there might be areas of the reservoir left unswept with- out additional drilling. To evaluate this potential and attempt to restore production rate, in 1973 the first infill wells were drilled on 80-acre spacing. These wells were completed with a different technique than that originally employed in the field. In the initial drilling phase, perforating either through tubing or with casing guns, was accomplished by shooting the entire interval to be opened and then placing the~ well on production. Beqinninq in 1973~. th_~"-~ we~lls have been perf6rated through ~bi'ng { unoer dr~wdown cohb~t~ons, intervals which are ind~u:C:d from' open hole log analysis to have poorest rock properties are per- forated first and "cleaned up." A dif- ferential pressure of approximately 1,O00 psi is maintained while perforating these intervals. The better rock is not shot until production has been established from these lower quality intervals. As a result, we have been able to establish good rates of production from layers that were apparently not producing from the earlier wells. While successful economically, these wells did not achieve the reservoir control we felt would be necessary to maximize ultimate recovery. In 1974, we modified the program so that the new wells were perforated in only the~_________~ lower sand members where we had nearly re- stored original reservoir pressure. The~ first well in this modified program was ~ drilled in an area offsetting wells which had had these layers cement squeezed to shut off water production as discussed under workovers. This well was completed for an initial rate of 6,000 BOPD flowing. It has produced a total of just over 2,000,000 barrels in 12 months and is currently producing 4,000 BOPD with a 24 percent water cut. Two more wells were drilled in 197~ and were completed in the same manner with similar results. As shown in Fig 7, there is a substan- tial increase in oil rate resulting from this drilling program over that established by the decline which started in 1971. Field rates are at or near all time highs. We expect the average production for 1975 to exceed lO0,O00 BPD for the first time in the field's history, Through June 1975 cumulative oil production from the infill wells amounts to over 12 million barrels and the current pro- duction rate from these wells is nearly 40,000 barrels per day. Additional locations remain to be drilled and the plan is to complete the current pro- gram in i976. RECOVERY PERFORi" 'CE OF THE .HEMLOCK RESERVOIR - MCA~' 'UR RIVER FIELD SPE 553( 2. Pressure response to injection has been measured with injection wells drilled up to a mile from the nearest producer and over ~vo miles from the crest of the field. Fig. 8 demonstrates the effect on .recov- ery by the various worXover and drilling schemes employed in McArthur River Field. The displacement of the curve toward higher ultimate recovery at the same WOR shows the benefits derived. The slope of the WOR versus cumulative base curve estab- lished in 1970 has remained constant with each procedure employed. In 1971 and 1972 the major effort was on workovers and recompletions. Starting in 1973 and continuing again in 1974 the infill drilling program has drastically displaced the curve. Because of these successes we expect to recover an additional 50 to 80 million bar- rels of oil. By proper layer management, even with a relatively limited number of wells, we have been able to recover over 50 percent of the ultimate reserves at a water cut only now up to 17 percent. Recovery through June 1975 is some 248.4 million barrels. Cumulative injection totals 308 million barrels or approximately 20 percent of the pore volume. CONCLUSIONS 1. Pressure maintenance early in the life of the field has served to stabilize producing rates. A unitized operation with an engineering committee working essentially full time in the early development provided a means for rapid response to the highly accel erated pressure decl i ne. 3. The field has and is performing remarkably close to theoretical analysis. 4. In a layered reservoir with limited wells careful planning of completion intervals will result in additional recovery. ACKNOWLEDGEMENTS The authors wish to thank the manage- merits of Marathon Oil Company, Union Oil Company of California, and Atlantic Richfield Company for permission to publish this paper. Thanks are also due the many technical people in the owner company organizations who have been involved in Trading Bay Unit Engineering studies. REFERENCES 1. Elliott, W. H. Jr., and Diver, C. J.: "Early Reservoir Modeling of Trading Bay Unit Hemlock Formation," Society of Petroleum Engineers of AIME Southwest Alaska Section Regional Meeting, Anchorage, Alaska, May 5-7, 1971, Preprint No. SPE 3243. 2. Wieland, D. R., and Vinson, M. E.: "Engineered H-Cl-HF Treatments Provide Successful Stimulation in Cook Inlet," Society of Petroleum Engineers of AIME Annual Fall Meeting, San Antonio, Texas, Oct. 8-11, 1972. Preprint No. SPE 4120'. Fig. i - McArthur River Field location-Cock Inlet, Alaska. · · · / r~rma~.cn, June 1975, Fig. 2 - Top of Hemlock -- ~ I,IcArthur River Field. H~ ul.~CIC LOG Fig. 3 - C-eneralized geologic section and t.~Te log - McArthur River Field. ~180 '0 o ~00' ~ GO 30 [ o 20 ~_ I.- ,o~ o a~ ?i&. a _ ?.~oduct&:n and ir,.'ection River Field. I ,f Fig. ;, - Reservo4. r pressure map-,..'anuar'.' A/ l I Fig. ? - ~_ffec: cf Lnfi!l drL!ilng pre- gram, McAt%hut R&':er P~.e!d. Fi&. : Reser':o'.r pressure 1~9691,9701 ~97~ 119'z21 ~J?311g?41 .2 .I .08 0 0 .04 .0:~ .010 50 IOO ~ 200 250 CUMULATIVE OIL PRODUCED MILLIONS BARRELS Fi~. ~ - Change cf wa:er-ctl r~tic vs reco'.'ery %~:k ':arlcus p.-'o6rs'::s: "^ ' ~"- Field. ....A.: .... ~i';er VARDEN · m · m_cb R£CE V :D I .l' INJECTION WELL · WELL DRILLED OR REDRll I =.'3 SINCE 1973 Fig. 1. S:[.ucture contour map. top of Hemlock for~.atior~. R ervoir ,,, ~TERLING FM HEMLOCK ! WEST Management at McArthur River by J e'.TE' Diver, D:,'; ....... R. se,-roh' E ,,~7; ,,ee,'. .llarnt ho,t 0il Co.: J. %V. Hart, So.,';..q ',:..k(z Dist,';c! E ,,rji /,eer. Ath, ,,t ic RichJTehl 0ii Co.; and G. A. Graham, D:.~tr:ct £',,gi,,ee,'. L',,io. 0;1 Co. of Caf(for, rift: A,:c~ o r,39e. Alaska ~/~c.A.~.hu.r River field is located about 70 miles southwest of Anchorage, Alazka. The discovery well, Union-EIarathon Grayling l-A, was drilled in 1965. The ~ekt outline was subsequently delineated by 10 add~o.,,.al exploratory wells drilled by four operators over ape. riod of two years. Tr.e Trading Bay unit which includes McA.rthur River field was fo~Tned in August 19~7, before de- velopment drilling operations had commenced. A uni¢;,;e feature of the unit agreement provided for equi~' r~etmminations at specified intervals. This en- cour'ag.~:l unitization p,ior to development by reeog- nizL't.g subsequent data derived from development drilEng. Union 0il Co. of Califo,'nia is unit operator : ,;.~ 'ith Un[on. 3Ia~,-tthon Oil Co., and Atlantic Richfield · PRODUCING Wi~,~~?(o'Oll g~t Gag CO~S. Commtss,u~j. - S 5U~J~mtOt~ for the t~'ee drilling and produc- Anchorage ~ fion pla~o~s. Field Description 'I-ne 5[cAa'thur River structure is uncomplicated and composed o£ two anticlines with an intervening syn- dine forming one major structural trap (Fig. 1). Ap- proxLma~ely 900 ft of closure exists on this structure. 'Cue Hemlock formation has a gross thickness of ap- pro.x~.~ately 500 ft. 01igocene in age, it is a elayey to sandy', uebble to boulder conglomerate interbedded with ?bbly sandstone, minor siltstone, and occasional c~al. There are six main intervals or layers separated by Lm...-~:rvious s{ltstones which exist over the entire strut'.ute. A typicoal log illustrating this layering is sho:~.m in Fig. 2. Volumetric calcu~atio~ of in-plac~ t(,tal sUtrhttv over 1 billion hbl ,Xtate:-!-,) hal- arlt.-~ c::lClllar, lO/15 t]lt~.'~ VQYllletl tills lltl~_..~r F,:dlowing is a summary of pertinent rock and fluid HEMLOCK LOG WELL D-1 Fig. 2. Typic'al Hemlock lng 3hox~ing six main iuterxals. proF--": les: Porosity', % 7-16 10.5average Pe.~n. eabilit;-, mil 10-200 90 average N=t pay, Ct 300-425 E: HT. (leg F 185 Coz,mate water, % 3244 35 average Water salinity, ppm 2.1.000 (Cotttinued on palIe ~0) PETROLEUM ENGINEER, DECEMBER, 1976 Reser,'eir' Manager~ent V,'ate,- viscosity, cp 0.35 Crude g~-avity, deg API 35 Crude viscosity, cp. orig. 1.19 Solution ratio, cu ~.rbbl 309 FVF, bblYobl, orig. 1.186 Original pressure, psi 4250 ( - 9350 Satm-ation pressure, psi '1790 Early Performance From discovery in 1965 until the fi~.t well was spudded in 1967 a unit had been formed, an onshore production facility eonsu'ueted, a pipeline and loading term.inal built, and three platforms constructed and installed in the Inlet. These platforms have operated sueeessful!y in the harsh Cook Inlet environment where tides fluctuate by up to 35 ft, currents run as high as 8 'knots, and ice flows mn form up to 4 ft thick. They have ~-ithstoo¢l a 5.9 magnitude earthquake centered only 60 miles away. Field rate increased to 70,000 b/d eight montks after completion of the initial well (Fig. 3). Platform pro¢lue- tion facilities became fully loaded almost immediately requiring rapid expansion of flow lines and headers, separation equipment, and shipping facilities. Reser- voir pressure declined rapidly due to unde~attu-ated etude and lack of any substantial nattu-al water drive. =Mthough initial wells produced at rates in excess of 8000 b/d, rapidly declining bottomhole pressure re-' quired artificial lift ve~' early in order to maintain productivity. This resuited in major construction ti~-ity at the same time full scale drilling activity was under,vas'. ~eve,-al alternate methods of lift were con- si¢lered, but gas lLft was the most practical solution. Pressure Maintenance A primary field depletion study utilizing rock and fluid proi~-ti=s from exploratory wells was completed prior to tee s~a~ of development drilling. This study indicated that without water influx oil recovery would be quite low. pressm'es would drop ye%-rapidly with an attendant drop in producing rates, and the field life would be ex:ended over a long period of time unless a large number of wells were drilled. ReservoE' pressm'e data confirmed the anticipated rapid p:'essm'e decline and by February 1968, only three months after initial production, a pressure drop of 200 psi was measm'ed in the major portion of the field. Results of the pNma~T depletion study led direetly into a comprehensive study of alternatives for pres- sure maintenance. In January 1968, the engineering and planning group completed the first of a series of pressm-e maintenance evaluation studies. This study recommended that design o£ wate,'flood facilities commence immediately for all three platforms and that a well be d,5tled on the periphery of the reservoir to conduct, water injection tests. These recommendations we,'e rapklly implemented and, in May I9'38. a water injeetivity test in well K-6 on the north periphe~T of the field confirmed laboratory data that filtered Cook Inlet water could be injected into the re.=e~-voir without det,'imental effects. On sub- sequent tests injection rates up to 30,000 bid were established at sm'face pressm'es of 3000 to 3500 psi in 200 180 160 140 120 100 80 60 40 20 20 O 0 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 Flg. 3. McArthur River perg'orrrmnt~ eur~'e. 40 PETROLEUM ENGINEER, DECEMBER, 1gTE Shan-R' )d Va r- E-Tee VALVES offer flexibility of des~jn to match your syst"~m Shah-Rod dampers are In service in many corrosive and high temperature applica- tions. Service conditlons can fluids be either gas or water ~, with pressures of vacuum to 12§ lb. WOG and temperatures from cryogenic to /":!~..:' 2000 + ' F. Sizes from 4" to 144". Other sizes upon request. Shah-Rod engine-sres select ', the most compat- ':: ible materials or "· .., coatings for services as described above to supply the industry with a damper that is maintenance free for many years. For more information call or write todayl inc. P.O.Box 455, Huron, Ohio 44839 Phone [419] 5,NI,-2066 Telex 980-~4 / Circle 229 on Reader Se~ic~ Card S.ve m. oney replacing pressure guuges: Ask for GAUGES INTERNATIONAL For new equipment ~ or for replacement m ask for GAUGES INTERNATIONAL pressure gauges. You'll get the accuracy and dependability your crew wants in mud systems, BOP accumulator units, flowing wellheads, gathering lines or pipelines. GAUGES INTERNATIONAL gives you a choice of brand new or rebuilt Models 6 and 7' gauges. Check with your oilfield supply store and see how GAUGES INTER- NATIONAL saves you money either way. If you go the gauge-exchange route, you may turn in OTECO Types O or A (or Cameron Types D or F') as well as Gl Models 6 and 7. You'll get Gl Models 6 or 7 completely rebuilt and tested to new specifications. IMMEDIATELY AVAILABLE GAUGES INTIRNATIONAI., INC P.O. Box 1849. Houston. TX 77001 Phone (713) 869-4671 42 Circle 230 on Reader Service Card this we~. In June 1968, immediately following the ' successful injection test. water injection plants were ordered for the three platforms. Having decided on water injection for pressure maintenance, the next engineering problem was the selection of a pattern. Five-spot anti inverted nine- spot patterns were studied. A major disadvantage of pattern injection, however, was the need to convert several high pro¢luctivity wells on the crest of the structure wl~ich woultl h:tve substanti;tlly reduced fiekl production rates. As an alternative, it was de- cided to star~ out injecting into the peripheral wells of the inverted nine-spot pattern to evaluate the effec- tiveness of flank injection. This plan provided the flex- ibility of reve~ing to a pattern if required. In early 1969, full scale water injection commenced (Fig. 3). Construction of the plants continued through 1969. and by mi¢1-1970 the total injection rate was 120.(~)0 b/ti, about the volume required to replace vokl- age. To;al injection capacity reached 170,000 b/d in 1971 anti has been maintab~ed at this level. Cent~'ifug:tl pumps (IHven by ~z:ts turbines pump water :tt pressures from 3000 to 4500 psi. Injectivity into fl;ink wells in the southe~'n part of the reservoir was not ,-ts high as wells (,n the n,n'~h flank so higher pressures are re(lui~d on the southern-most platform. PETROLEUM ENGINEER, DECEMBER, 1976 )pe],~t~ ph~oph~e~ were der(~ ~ed w~ch ~o','e . ,anted bhrou~h to various other ope~t[oc~ ~eld. )Ie ~n<t ~ con~en~ionM econo~c ~)'s~ letez~.ine p>~enc~ pro6~. In ~d~don. pot~.q~ loss )[ not doL~ ~e proposed project ~ meas~ed :he cost of t~e project to dete~qe ~ction, or dei~)'ed action In ~e ~ o[wa~er ~jeccion, i~ <<~ reco~ major e~o~c ~ were ~~ced wel~ ~d i~t~llin~ eq~pmenc ~thout complete in- Co~nt~on on incU~iciual ~U cha~eHsti~ or even know~ ~e to~ ~eolo~e sec~ ~o w~c5 water wo~d ~ ~j~. ~ w~ me~ed a~r~t ~n eve~ water ~d s~'e~ an ~mosc ce~ loss ~ re~ve~' ~d ~te. ~ a res~. l& ~jection we~ were d~ed ~nd ~m- plet~ prior co ~<~Ua~on of ~~on eq~pmen~ on the p~o~. lnje~i~icy tes~ were not conduct~ these we~, ~d ~e wells the~elves wo~d ~mve had litde v~ue ~ the pm~m been a ~H~e. In~osc ~s ~ Cook I~e~, ~e ~e to ~iti~ p~ducdon. In 3Ie.~h~ ~iver, ve~' ~f L,'.jecti,,n x~-$~' .chi¥\'e~l in sli~htl',' more th;~n years. ~4"I~e 1~9. before b~l~nc~ b~t~e~n i~jecti~n ~nd production ',~ as achie','e<l, fiel(1-~vi(!e z~','e~:ge pressure ~'~< calc..a..] ' ~,1 to b~ 255g p~i, r~l~resen:inz, a pressure (lmu of ab.,u: 1400 psi. Cu~:~ul;~dve c~'~<l¢ t,roduction tb~ tLm¢ ~ as ~?,EU0.000 bbl. P:'essu:'es as low ~ 2400 psi were measured in the south-cent:~! portion of the field (Fi~. 4). T~o si~~nt prpblems with the wate~ood oroj- ~ were a lack of s~ficient.in~ection rate and ~tabid v¢~i~ dist~bUtion of injected fluid. To deal w~ ~~~-tG ~mprove ve~ water dis~n t~U'~ I~'e'~~' mud-acid s~imulation ~reat- .~~ - . ~ t)~ treatment had not been tried on He~ock we~ ~ Cook Inlet. It ~volved acicliz~g ~ much as 1~ ~ of ~ction with dive~in~ m~tieH~l in st~es to ,:~.~.. achieve acid distribution. ~es~ts were ~ood i~ mo~ we~. ~m~le ~pmvement ~Iso resuked ~ incre~ecl ~jection ~tes. :.... · .. In 1~70. xveH D-24 was clHlled to replace injector D-10 which had s~ered p~ted easing and eould not be ~Ivaged. Bmed on the performance of well D-10, w~ dedd~ to lo~te well D-24 sHghtl>- upstruet~e in ,~... (Con~fnue~ on page NABORS DRILLING LIi ItTEQ DONALD A.. PARK CLAIR A. NABORS JAMES C. TAYLOR JOHN G. MONTGOMERY' The Board of Directors of Nabors Drilling Limited, Calgary, Alberta, takes pleasure in announcing the following executive appointments' Mr. Clair A. Nabors is appointed Chairman of the Board and Chief Execu- tive Officer. Mr. Nabors, very well known in the Canadian oil industry, has b=-',.,.,n President of the company since its inception in 1952. Mr. Donald A. Park is appointed President and a Director of Nabors Drilling Limited. He was previously Vice-President, Engineering. Mr. James C. Taylor is appointed President of the company's wholly-owned subsidiary, Nabors Alaska Drilling, Inc., headquartered in Anchor~¢e. He ,,,cas previously Vice-Presiden[ of Nabors Alaska. Mr. John G. Montgomery is appointed Vice-President Finance and Trea- surer of Nabors Drilling Limited. He was previously Treasurer. 44 Circle ZZ5 c~ Reader S-e.~ic-e Card PETROLEUM ENGINEER, DECEMBER, 1976 Rese~oir Maoagement i I '" KING " '/ '\ · · ~ / · , , ,- ~, .~ ~ ,, * .~ · .., / ,. ~'~./ / ,.;,,/.~ * / ." 'GRAYLING , ... ,,'.' // ~ '/ · ,,.,.~ -~ ~..' ~. I ,' , .," -- /~ ~ ' ~ ' I .,'//: ,, I ! ~.,... . // .' .' I I I UNITBO~I [ ~/· HE~LOCK PRODUCING WELL . ~~ ' //~ HEMLOC~ I~EC~ON WELl. "~ I~HE~LOCX CON~RTED , I INJE~ON WELL ~i~. 5. Rese~'o~ prussic, ~une [9T6. an attempt to encounter better rock quality and move the injection loc~tion. The new injector was completed for an imitbd rate of 16,000 b/d, a 9000 b/d increase over rh~t in well D-10. A nearly'perfect injection profile was achieved in this well after acidizing on completion. Pressure response to the increased injection rate as well ~s improved vertical distribution of injected water ~s apparent from the pressure map for 1976 (Fig. 5). The Iow pressutre area in the south-central portion of the field has shrunk considerably and pressure has increased by' about 600 psi as a result of these actions. The second measure of success of any such project is displacement efficiency. In this field, response has been measured by evaIuating open hoIe logs in wells which were original high rate producers and have been redrilled. One such well, K-4, was redrilled in 1974 in an attempt to make a successful oH completion from a well which had previously been watered out. It was suspected that only a small portion of the Hemlock interval had been flooded and that a high porosity section was responsible for the water production. The well was completed for 1000 b/d with less than a 5% water cut; however, new logs indicated much better vertical sweep than had been anticipated. Vertic=d conforms( in this pot'.ion of the reservoir is esti-' mated at SJ.c'¢. Additional drilling has confirmed an a]mosc u,~'orm s~veep in individual layers of the rock_ Th).s is ~.::ribuced to the di.~t;mce from injectors to profile~. Theor'.-.'.ic.',lly. the reservoLr has performed remark- ably well. Pe~ormance has been close to predictions made in January 1968. when only four welIs had been completed in t_he field. Thts unquestionably qu~!ifies the study as theoretical. Productivity decttne caused by two different mech- ard~ms bas been observed in man)' field wells. Onset of water production is accomparded with a drop in pro- ducfivi,.~.'. Thts is pa~iall¥ related to change in mobil- . ky and Ls not uncommon. Some wells not producing water have exhibited a decline in producti,~-ity, which Ls probably the result of the movement of particles in the formation. A drop in productivity is fn'st measured as a reduc- t. ion of transmissibility on pressure buildup analysis. Spkrmer and radioactive tracer surveys indicated sec- dona of the formation which were no longer contribut- ing any flu.id. It is surmise(! that formation fines plug e.xi~ting perforations as a result of the movement of large quantities of fluid into the well bores. Wi_j.tbjl2m.~ lative fluid production from 4~000,000 to 12,000,000. bbl/w_-eLl, o, nl.v a minor amount of solid material moved per bbl can result in. significant quantities of solids T~vo techniques h.-,ve been applied to the wells not pro¢lucin~z w.',ter in an nttempt to restore their pro- ducti~-ity. Larg:e volume, matrb~ acid stimulations have resulted in productjvit.v increases oftxvo to three tLmes. Depending on the amount of interv.~l to be t. reated, these jobs have required 20,000 to 30,000 gz]i of 1~-10 HC1-HF ackl. As in ~he injection wells, these~ were the 5_Pst producing well acklizations performed znl the Cook Inlet basin and were ~us~til:~ed on th-~as[si tried tecl"mlque. Another method used to restore pro-1 ductl~-lty is reperforatLng under drawdown condi- tions. ~n~s technique h:~ been used on ~ l~r~e number of wuUs with resuI~s vnrying from no jruzre~zse in prp- duc~ion to increases of over 1000 b/d. ~ The second t.vpe of productivity loss occuzs in those wells which start to produce some water. When this takes plnca two events can occur. The fiz's~ is a pre- cipka:Jon of barke which plugs the perforations and the second is interlayer Qow, either of which can result in re,lute(1 productivity. Other than slight ¢ttfferences caused by permea- bility effects, each of the layers has essentially a com- mon oLI-water contact at about 9~00 ft subsea~ Beca..use. ~.9_f flat clips on most flanks of the fi~this means a considerable difference in_~real covat-ag~:z[.oii!.~ien in the ~~--'ari0ds lay.e~, Early production profile data show that water encroachment, :~s a :'esult of aquifer movement and injection, occurre(l {n upstructure wells 48 PETROLEUM ENGINEER, DECEMBER, 197! .qeser::oir Man~geme.qt 0.01 ~ Z0__-7i __7_2._L.Z3 _7-1, ,'._75 '.7~_ 100 200 3,00 .... CUMULATIVE OIL PRODUCE,O, MILLION BBL Fig. 6. Water-oil ratio vs cumulative production. Hemloek-MeArthur River field. in the lower layers at early times. With the Neg-;n-i~.g of water production, an abnormal decline in well pro- duetivity has been rnea~ured and profile data iv..d_ica~e this drop in productivity was occurring in wat~-ffee inter,'als of the section. ~i~te.r producing inter~-aI~ w.~r-em%4~her pressure and capable of caus~mg wa:e""-'-'~ _~..~mb_ibi,tion i~? Water-f~e~e i~'~m: ~,o restore'~ pro4uc- tivit;- in '''{ ..... '";?.. _ ,.,f well a::(t protect against loss of rese~'.,-3.-, c-=ment sc:'.;eeze~< were performed on several ,,veL. T.-.i~ efSor-, i'.v_3 been successful anti production h~.s been r.-s~,'.,red ,'5't,m upper iaye:~ in nine such wells. In l:::e i:'71 a.".~t co::tinuir:.~ th:',~u.~}~ 1972, a decline in u.~d'-'c".!~ n rate wa.s :,ppa:'c-nt. The F_,_eld was origi- ~aES' de"e~.: ::-~ on 'o'~" , . c--ss=n:~,.: .160-ac:'e spacing.. Ear~ studies .-.at: :..'xuc:x~"~-'--'~te(t there m~ght be areas of the res- erx'otr ;et' -.:_~wept wit~oflt additibnalTlril tolTEC. ~'o e~_~,.m:e' .:.~ .~fend~l mud attempt to_ r_e.s_tore_ t.h_.e. ~..r_o: - . ; ..... 7';~ --' . .'7-. - · d~ .'-a ~. ~e ~ ~ un nl.~l~- ~t ere drilled m 19 ~3 on ~~. s ~cLn g. In ~ [~'-~-1' dri~ng phase, perforating, either gh.mug-h va~.tng or with e'a~ing guns, was aeeornplished by sho<xL-.g '~ eh.rive Hemlock inter,-al and placing ~e wen on =r~aduedon. Beginning in 1973 wells have been .e,=_ffo~zed th.rough tubing under drawdown con- dizions boa.:.~t on pe~orating results in older wells. Intert'a_% ~rKic~ indSeate the poorest rock properties fi-om o.r. en hole log analysis are perforated first and d~.=c4 ,ap. A diffe.,~ntial pressure of approximately 1000 psi is main-t~ihfid"-while perforating th'~'se i~.=-- ' ....................... The bezer rock N not perforated until production ~_~. been ~tablished from these lower quality inter- reis..-x.~ a. ~-?s,~t. gocd rates of production are estab- 15~hed ~-om .w!azively poor productivity layers. (Continued o~ pa~s ag) FLOAT EQUIPMENT · "FLOAT ' NOSE GUIDE SHOE .' BAFFLE PLATE · .. FLOAT NOSE Industrial Rubber's Float Nose is designed for economy In use on Iow-budget shallow holes. The nc~se and baffle plate are made of high strength aluminum ar~ easily drillable. The baffle plafe has an O-ring se,al immediately below the threads and an O-ring seal a~ a ball seat in the port opening. Customer furnLsh,es his own casing coupling. Available in sizes 4~" through 8~". GUIDE SHOE AND GUIDE NOSE Designed for economy in use on low--budget s,haJle-w holes, ~is equipment is available either as a full s.ho~ to make Ul3 on casing, or as a nose threaded to make up on customer's own casing coupling. Guide Sh<~ Guide Nose are made of high-strengt~ aluminum allo~ and are easily drtllable. Availatsle in sizes 2~" t~rou~h . BAFFLE PLATE The Baffle Plate is designed to be madeuD two joints of pipe and to serve as a landing for cement- ing plug. The plate is made of high streng~ aluminum alloy and is easily drillable. Available in .sizes through 8~" INSERT EQUIPMENT The same flapper-type valve as used in indus- trial Rubber's Flapper- Type Float Equipment is available as insert equip- ment. The same flapper valve and pumpout orifice as- sembly as used in Indus- trial Rubber's Automatic Fill-up Equipment is available as insert equip- ment. This insert unit is supplied with a tripping ball which seats on the pump-out orifice. A pres- sure cl -3~ psi shears the pin holding the orilice, trippir, g ~=_.11 and orifice fall downhole and the unit I:>~.~ operational as a flapper-type valve. Indus.--iai Rubber's Insert Flapper Valve and In- sert A~.~oc',atic F~il.-up Valve are available in sizes 4'~ thro,..~n 8~. O~l T~ D~s~on P. O. ~x ~, C~a~ma C~ey. Ok~a. 73109 3~ S. H~ O~a~ma Ci~. Okla. 73129 ~. ~5/~2-97~ 50 Circle ~ o. Reader Se, r~ic~ CaJ'd PETROLEUM ENGINEER, DECEMBER, 1976 Reservoir Msnager~ In 1974, the pro,'am ,.v~ mod- i.~ed so that new wells a.re per£ora- ted in on.].,,' the lov.'er sand membe:'s where or{~Lnal reservoLr pressure had been restored. The fimr. well in this modified proof, am. G-20. ,.vms drilled in an area offsetting wells in which layers tire and six had been cement squeezed to shut. o~ war. er production. This well was com- pleted from layers five and slx for an irdt. i~ flowi, ng rote of 6000 b/d. It has produced a total of over 3.3~?.'.6~X' bbi from :hese lavers and c'~-.en~]v D Droducin~ °'~0U b;d of oil v. [;k 2 50'.% water cut. Tv, r, m,,re v. ~l;s '.~ em d:dlied in 1974 an,! were com'z4e:ed in :he same mann.-" with Th~ dr,!ting program through 1975 z'esu~l b the high~.~: daily oH m:e imm the field shnce i:s ¢li~- cove.re.'. Two infill weLLs are being completed and this progrram is ex- THE GEOLOGRAPH MUD SENTRY CONSTANTLY MONITORS YOUR WELL'S MUD SYSTEM The Geolograph Mud Sentry instantly picks up any change in the variables of your well's mud system and alerts the crew with'visual and audio alarms. Three versions are available: the standard electro-pneumatic model, an all-electric model and an ail-pneumatic model for operations restricted by difficult electrical codes. Mud Sentry components may be stacked in a central location or placed in separate locations on the rig. Let us tell you more about the best mud-monitor- ing system avail-. - able! ' :'-'.-:: · .. ".-!.'-.':i '-" :.I '.'!4 THE GEOLOGRAPH CO. P.O. Box 2`5246 - Oklahoma City, Oklahoma 73125. (40~ ,5525~551 Cable Address: Geoiog; Telex Nc. 747-';29 petted to be f'mished this year. Re- serves from u'ells drilled in this prog~am now total over 35,000.000 hbl a:~d these wc. ll.~ currently pro- cluce approx~m:ely 45.000 bid. The drop in production rate for three months in 1976 was the resuk of an explosion on one of the plat- fut2ns. Productiun fi'om this plat- fora is expected to ret~ to nor- mal in the nero- furze. Fig. 6 demonstrates the effect on recovew by the various workover and drilling schemes employ~ in Mc.~thur River field. Displace- ment of the cum'e toward higher ultimate recovery at the same WOR cum~ative base eum'e esta~ l~hed ~ 1970 h~ rema~ed eon- stant with each procedure employed. Recovery of an additional 50,~0,000 to ~,000,000 bbl ofoil is expected. By proper layer man- agement, even with a relatively li- mited number of wells, reeovew of over 60% of the ultimate reserves at a cra-rent water cut of 22% h~ been achieved. Recovery through August 1976 is some 289,000,000 bbl of oil. Cumulative injection totals ' 375,000,000 bbl of water, or a~ proximately 22% of the pore volume. ~ Acknowledgements. The authors thank the managemen~ of .Marathon Oil Co., Union Oil Co. of California, and Atlantic Richfield Co. for p~rmission to publi.<h this paper. About the Authors Je~'mj Diver hv.~ u BS deffree i,, le,,,,, e~tgh, eeri,g f,'o,, Colorado School of Mi,es. He has bee, with .lion, tho, 2J yeor~, i,,chtdi,,g sere, gear., i,, Alaska. j. IV. Ha,~ g,'r,d,,ated fi'om Va,,der- hilt ,,.ith a ES d,gree i,, ~,,ec;,e~,,;cai r,,9;,,~e,'i,,9. H~ ;m.q bevu with Atilt,tic cite i,, A;qska. J. A. Gml, a,,, ,?ceiced h is BS i,, ,,,i,i,,g e,,gi,eeH,,g./}'n,,, the U,,i- ,',.,-.~ity ,g' Illi,,,,i.~ a,,d MS d~g,'ee A,Q.I;. He hns bee, with U,t[o, I1 gt'e~,'.x, i,,ctudi,,g.fi,,,r yearx i, Ala.qka. 52 Circle 232 on Reader Ser"~c~_ Card PETROLEUM ENGINEER. DECEMBER, 1976 WMRU Waterflood Response 22OO 2000 1800 1600 1400 1200 1000 80O 600 ........... j- ..........................; 2~97 2198 2199 2~00 - i ............ I .................... i ............... t '- ' F Waterflood B ~ ........ /No decline for 2 yrs, - .... i- - i .....,_ ..1 10%/yr decline i ~A~"' I. thereafter i .....I WaterfloodA _ l l O%/yr decline ...................... I : ............. I ........................... 2/01 2/02 2/03 2/04 2/05 Stewart Petroleum Company Denali Towers North, Suite 1300 2550 Dena[i Street. Anchorage. Alaska 99503 i ! Stewart Petroleum Company 4700 Business Park Blvd., Suite #13 Anchorage, Alaska 99503 (907) 563-5775 · FAX (907) 563-4060 March 10, 1997 Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Att n: Re: Mr. Robert 'P. Crandall, Senior Petroleum Geologist Application for Exemption to Provisions of 20 ACC 25.055 Drilling Units and Well Spacing Atasl,{a 0~t & Gas Cows, Comra88~, West McArthur River Unit ~-I ~c~o~age Mr. Crandall: Stewart Petroleum Company hereby makes application to the Alaska Oil and Gas Conservation Commission for an exemption to the drilling unit and spacing requirements of 20 ACC 25.055 as they pertain to the proposed bottomhole location of the West McArthur River Unit Well No. I-1. The proposed BHL for No. I-1 is: 2400' FWL and 600' FNL of Section 15, T8N, R14W, SM at the top of the Hemlock 2765' FWL and 328' FNL of Section 15, T8N, R14W, SM at TD An exception to 20 ACC 25.055 is required because the proposed wellbore will in the Hemlock formation will be closer than 500' to a quarter section line. All other spacing requirements will be met by the proposed BHL for WMRU No. !-1, i. e., the well is over 2500' from the nearest lease line and over 1000' from the nearest well in the same pool. The proposed WMRU #1-1 will be a water injection well which will improve the ultimate oil recovery from the WMR field. The proposed location has been determined to be the optimum location for this injection well. Attached is a map indicating the quarter sections offsetting the proposed WMRU #1-1 and a table describing the ownership of all offsetting quarter sections. This map shows the the BHL of the three existing wells at WMRU. Also attached is a map indicating the distances from quarter-section lines for the proposed top of Hemlock and TD of the WMRU #1-1. Since Unocal is an affected owner of an offsetting quarter section, a notification has been sent to them by certified mail and a copy is enclosed indicating the date of delivery to Unocal. The undersigned hereby verifies that he is acquainted with the facts surrounding this application for exemption and that the facts presented in this application including the attachments are true and correctly portray all pertinent and required data as defined in 20 ACC 25.055(a)(1) and (b). If there are any questions, please contact me at 563-5775. Paul D. White Operations Manager Stewart Petroleum Company cc: Steve Hartung, Stewart Petroleum Company Attachments: Map with Adjoining Quarter Sections to WMRU #1-1 Table of Offsetting Quarter Section Ownership Distance of Proposed Well to Qtr-Section Lines Copy of Notification of Offset Owner West McArthur River Unit No. !-1 Adjoining Quarter Sections TSN, R14W, Seward Meridian I W. McArthur River Unit ADL 17602 i Stewart Pet. Co. Unocal ADL 359I 11 II IIII II I III Section 3 Section 2 Section 4 ! vv~u#~ 'I I , I 1 ' Section 10 I ,' Section 9, , , , Section11, --,, ,I WM~u#=A i---~, -, ......... ,, ® ® .. , I I I I I I I I I I , I I I WMRU I I r,o~ose,, ,..,.~ , .. , .... I ~ I I I I I I I I I I I I I I ------L ............ I r '~ Section 15, I ~) ' , Section 16 I ~ I I I I I I I I I I ADL 359112 WMRU #1-1 Spacing Exception Quarter Section Ownership ~ ~ Unit Quarter ~ Description i Leasee i ADL .~. ........... -~(~-~ ...................... ~--~'§~-~-~ 4W--} Ref. ~ ........................ ~ 2 SE/4, Sec. 10 Stewa~ Petroleum Co. 359111 West McA~hur River Unit .................................................... ....................................................................................................................................................... 3 SE/4 Sec. 11 Uno~l 17602 5 SW/4 Sec. 14 Uno~l 17602 ........................................................................................................................................................................................... 6 SE/4, Sec. 15 Stewa~ Petroleum Co. 359111 West McA~hur River Unit 8 SE/4, Sec. 16 Stewa~ Petroleum Co. 359111 West McA~hur River Unit ..................................................................................................................................................................................................................................... , ., , No. I-! ~ TD . . . NWl4, Sec. 15 Stewad petroleum Cq.. 359111 W~s,t McA~hur River Unit West McArthur River Unit No. I-1 Distance to Quarter Section Lines T8N, R14W, Seward Meridian WMRU #1-1 Proposed Wellpath ,,~ ,Proposed #1-1 Top of Hemlock 600' S of Section Line 240' W of Qtr Section Line I Proposed #1-1 TD 328' $ of Section Line _,_ _ _ _1_2_5'_E_ _of_ _Qt_r_S_e_ctjo. n_ L_iQe_ _ _ Secti, )n 15 WELSPA. PPT Stewart Petroleum Company 4700 Business Park Blvd., Suite #13 Anchorage, Alaska 99503 (907) 563-5775 · FAX (907) 563-4060 March 10, 1997 Unocal Corporation 909 West 9th Ave. Anchorage, Alaska 99501 Attn: Mr. Kevin Tabler Re: Application for Exemption to Provisions of 20 ACC 25.055 Ddlling Units and Well Spacing West McArthur River Unit #1-1 Mr. Tabler: Stewart Petroleum Company hereby notifies Unocal Corporation that an application has been submitted to the Alaska Oil and Gas Conservation Commission for an exemption to the drilling unit and spacing requirements of 20 ACC 25.055 as they pertain to the proposed bottomhole location of the West McArthur River Unit Well No. I-1. If there are any questions, please contact me at 563-5775. Paul D. White Operations Manager Stewart Petroleum Company cc: Steve Hartung- Stewart Petroleum Company Attachments: Application for Exemption to Provisions of 20 West McArthur River Unit #1-1 (5 pages) flDNR/DIV OIL & GflS FflX NO, 016075630415 P, O1 · LEASE ADMINISTRATION 3601 C S~xeet, Suite 1398 Anchorage, Alaska 99503 State of Alaska DEPARTMENT OF NATURAL RESOURCES DIVISION OF OIL AND GAS (907)2694814 phone (907)563-0415 fax FAX TRANSMITTAL DEMVER TO: '~'~, ,0,~ '~~ TOTAL PAGES(including ~'ansmittal sheet): ~ COMMENTS: Fax Chat'ge $4.00 plus , copies x .25. Please remit this mnount ........ to: Department of Natural Resources Division of Management 3601 C Street, Suite 1230 Anchorage, AK 99503 Make check payable to: Department of Revenue. RECEIVED AlaSka Oil & Gas Cons. Commission Anchorage If you experience any problems receiving this fax, please call (907)269-8814 immediately. liAR-17-97 liON 15:32 RDNR/DIV OIL & GAS ADL 359111 and ADL 359112 NO, 016075630415 23-Sep-96 WORKING INTEREST ROYATY INTEREST NAMEJADDRES$ P, 02 60.80125 37.10109 10.00000 10.00000 8.200000 7,175000 5.083330 4,447914 3.666670 3-208336 3.000000 2.625000 2.000000 1,750000 2,000000 1,750000 1,000000 0.875000 1.000000 0.875000 Stewad; Peb'oleum CO 2550 Denali St Suite 1300 Anchorage, AK 99503 W. R, Stewart, President Medema Family Trust P.O. Box 4007 Homer, AK 99603 James & Millie Medema, Trustees John R, Blocker 50 Briar Hollow Dr. Suite 200 East Houston, TX 77027 Thru'man Oil & Mini~R Inc. 925 Aurora Dr. Fairbanks, AK 99709 NuRa¢~ Nevada lnc, 601 W. 5th Ave, Suite 700 Anchorage, AK 99501 John R, Blocker Trustee 50 Briar Hollow Dr. Suite 200 East Houston, TX 77027 Max Medema .,~,,. ..... 7150 Mountain Lake Circle Anchorage, AK 99516 Donna M, Perry 300 Front Street Fairbanks, AK 99701 Escopeta Oil & Gas Cor~orati 5005 Ftiverway Suite 100 Houston, TX 77056 F_.scopeta Production Alaska 5005 Rivorway Suite I00 Houston, TX 77056 RECEIVED,, Alaska 0il & Gas Cons. 8ommismon Anchorage Page I of 6 lIAR- 17-97 I'ION 15:32 WORKING INTEREST 0.781250 RDNR/D IV 01L 8, GRS -. ROYATY INTEREST 0.683594 FR× NO. 016075630415 NAM~ADDRESS Kenneth W. Battley 629 L Street Suite 201 Anchorage, AK 99501 P, 03 0.371950 0.325456 William D, Artus 629 L Street Suite 101 Anchorage, AK 99501 0.366670 0.445836 William D. Renfro Estate 3900 Arctic Blvd. Suite 304 Anchorage, AK 99503 0.366670 0.32O836 J'ocd.;/n $ourant 4890 San Juan Dr, Firday Harbor, WA 98250 0.333330 0.291664 Douglas F, Strandberg 816 Taft Street Port Townsend, WA 98368 0.250000 0.218750 Encap Energy L.L,C, 1100 Louisiana St. Suite 3I 50 Houston, TX 77002 0.200000 0.175000 Howard Thomas #2-602 701 Geneva Street St, Catharines, Ontario Canada L2N7H9 0.148750 0.130156 Cabot Christianson 911 W. 8th Ave. Suite 302 Anchorage, AK 99501 0.133330 0,100000 0.066670 0.116664 0.087500 0.058336 Nicholas Scurant 4627 Mil0 #C Huntington Beach, CA 92649 Tcrmys B. Owens 2211 Woodw0rth Circle Anchorage, AK 99517 Michael C. Reafro 3900 Arctic Blvd. Suite 304 Anchorage, AK 99503 RECEIVED t,!'*' I ~ ~' i:.;. , Alaska Oil & Gas Cons. 0omrniss~o~ Anchorage Page 2 of 6 7-97 NON 15: 3:9 ~DNR/D I V 01L & GAS WORKING INTEREST ROYATY INTEREST 0.048400 0,042350 0.048400 0,042350 0.033330 0.029164 12.50000 FAX NO, 016075630415 i , NAM~ADDRE$$ $ohn Pope 12800 Jeannie Rd Anchorage, AK 99516 Cathryn Roberts 12800 Jeannie Rd Anchorage, AK 99516 Kathleen Cottin~:ham 51 Park Lane Mailing Box 370 Tilbury, Ontario Canada NOP2LO Sale 40 P, 04 3.600000 Polar Bear investments, L.L, 800 Bering Dr. Suite 210 Houston, TX 77057 2.000000 1.000000 1.000000 1,o00000 1.000000 Richard E. Wagner P.O. Box 60868 Fairbanks, AK 99706 Charly E. Cole 406 Cushman St. Fairbanks, AK 99701 Euea Tekna Investluent$ 178 View Ave Fairbanks, AK 99712 Limestone Oil & Gas 4726-A Jacksboro Highway Wichita Falls, TX 76302 William G,S~oecker P.O, Box 1230 Fairbanks, AK 99707 0.562500 J'ames L. and Leta Thurman 925 Aurora Drive Fairbanks, AK 99709 Page 3 o! 6 ~R-17-97 NON 15:33 WORKING INTEREST hDNR/D I V 01L 8, ROYATY IN'I'EREST NO, 016075630415 i w___ NAME/ADDRESS P, 05 0.500000 0.500000 0.500000 0.437500 0.312500 0.250000 Robert Breeze Irrevocable Tr 520 Ocean View Drive Anchorage, AK 99515 Virginia Breeze, Trustee J'ohn M. Robinson 9333 Memorial Drive Suite 418 Houston, TX 77024 Frank L. Sho~rin P.O. Box 229 Hygiene, CO 80533 William R. Stewart 3530 W. 31st Avenue Anchorage, AK 66517 Rebecca L. Stewart 3530 W, 31 st Avenue Anchorage, AK 66517 P_..d~ar Paul Boyko 745 W, 4th Avenue Suite 500 Anchorage, AK 99501 0.250000 0,250000 0,250000 0.187500 0.125000 John K. Oarvey Revocable Tr 301 North Main Suite 860 Wichita, KS 67202 Polaris Fund, L.P. 400 Seapost Court Suite 250 Redwood City, CA 94063 Sensor Oil & Gas Inc, 5600 North May Avenue Suite 200 Oklahoma City, OK 73112 Lab Properties Inc, Po Box 410 Mercer Island, WA 98040 Iin Ku PJ~ee 31192h La Baya Drive Westlake Village, CA 91362 RECEIVED Alaska Oil & (~as Cons. ~nchoraO~ Page 4 of 6 I'1fiR-17-97 IvlON 15'33 WORKING INTEREST aDNR/DIV OIL & GaS ROYATY INTEREST 0.125000 0,125000 0.125000 0,125000 0.062500 0.062500 0.062500 FaX NO, 016075630415 NAME/ADDRESS · lmm i Stcwart F~fily Trust 550 W. 7th Avenue Suite 1800 Anchorage, AK 99501 William M. Bankston Trustee The Aleut Corporation 4000 Old Seward Highway Suite 300 Anchorage, AK 99503 The Audra l.addcn¢ Stewart 550 W. 7th Avenue Suite 1800 Anchorage, AK 99501 William M. Bankston Trustee The Rebecca L Stewart Trust 550 W. 7th Avenue Suite 1800 Anchorage, AK 99S01 William M. Bankston Trustee ,reft L, Bur.aess 6610 N. Oamino Padre isidoro Tucson, AZ 85718 Calderwood Rev.Trust 7900 Honeysuckle Drive Anchorage, AK 99502 Coil Inc. 5914-12th Ct NE Kirkland, WA 98033 P, 06 0.062500 0,062500 0.062500 0.031250 William H. Mcdonald 1524 Ship Avenue Anchorage, AK 99501 1524 Ship Avenue Anchorage, AK 99501 Yack ti. & Helen E. Rich~dsoalaska Oil & Gas Cons. 1911 Belair Drive Ancl, orage ('°m~iSston Anchorage, AK 99517 Gregory S, Bur~;ess 963 Banmoor Drive Tmy, MI 48064 Page 5 o f 6 7-97 ~ON 15:33 fiDNR/D IV 01L & WORKING INTEREST ROYATY INTEREST 0.031250 NO, 016075630415 NAME/ADDRESS Jason M. Burgess 3346 E. Torito Drive Phoenix, AZ 85044 P, 07 0.031250 0.031250 Walter Don Burrows 9701 Spring Hills Drive Anchorage, AK 99507 Robert L. & Deanna L. Perso Po Box 403 Girdwood, AK 99587 100.0000 100.0000 PENDING 1.200000 1.050000 0.966670 0.845836 0.666670 0.583336 0,125000 0.109375 0,125000 0.109375 Pe~y T. Davis 733W, 4th Avenue #822 Anchorage, AK 99501 Robert L, Fersons PO BOX 403 Girdwood, AK 99587 She~on G, Peny 715L ST.#7 Anchorage, AK 99501 Charles Selmaa 811 Dogwood Street Anchorage, AK 99501 Dorothy Selman 811 Dogwood Street Anchorage, AK 99501 3.083340 2.697923 ,~laska 0ii ~. Gas (;ohs. Commission Page 6 of 6 State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Notice of Public Hearing STATE OF ALASKA Alaska Oil & Gas Conservation Commission Re; The application of STEWART PETROLEUM COMPANY for exception to 20 AAC 25.055 to allow drilling the WEST McARTHUR RIVER UNIT No. I-1 water injection well. STEWART PETROLEUM COMPANY by letter dated March 10, 1997 has requested an exception to the provisions of 20 AAC 25.055(a)(3) for the drilling of an enhanced oil recovery service well in the West McArthur River Unit, in the Cook Inlet. The exception would allow Stewart Petroleum Company to directionally drill the West McAnhur River Unit No. I-1 water injection well to a bottom-hole location that is closer than 500 feet from a quarter section line. The proposed surface location is 1953' from the west line (FWL) and 3233' from the north line (FNL) of Section 16, T8N, R14W, Seward Meridian (SM), the proposed top of the injection interval is 2400' FWL and 600' FNL of Section 15, T8N, R14W, SM and the proposed bottom hole location is 2765' FWL and 328' FNL of Section 15, TSN, R14W, SM. The well as proposed will be open to the Hemlock Fm. within 500' of a spacing unit boundary in both the northeast and northwest quarters of Section 15. A person who may be harmed if the requested order is issued, or who has valid concerns related to waterflood operations and the maximization of ultimate recovery from the West McArthur River Unit, may file a written protest or petition prior to 4:00 PM April 7, 1997 with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on the matter. If the protest or petition is timely filed and raises a substantial and material issue within the Commission's statutory authority, a hearing on the matter will be held at the above address at 9:00 AM on April 22, 1997 in conformance with 20 AAC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, (907) 279-1433 after April 7, 1997. If no protest or petition is filed, the Commission will consider the issuance of the order without a hearing. If you are a person with a disability wtl~-'~y~~ a,~peeht~ tifieat~n in order to comment or to attend the p~ti~ql~~~se coI~D~iana l~d ~ at 279~1433 no later than April 11, 1997. Chairman Alaska Oil and Gas Conservation Commission Published March 21, 1997 AND AO2714028 ORIGINAL #3783 STOF0330 A0-02714027 $1o. .Ol AFFiDAViT STATE OF ALASKA, ) THIRD JUDICIAL DiSTil]CT. ) Eva M. Kaufmann being first duly sworn on oath deposes and says that he/she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on Marhh 19,1997 OF PUBLICATION I Noli~ of Public Hearing ~Petitlon Prior to 4'00 PM A Ii, 1~97b w,o~ ;L~' pril I .... _ ',_,,, me Alaska u.u ~u~ L , Oil · onservation Com- I STATE OF ALASKA /~)~s. ion, 3001 Porcupine Drive,] /1' ConservatlonAlaska Oil. commissiona,~l Gas ', Ii'men°race' Alaska 99501 request a he , and Iter If the ,,.,'.a.r_l?? on, the mat. |Re:, ,The application of Itl~elv fil~'~rr~__l~_tition is/ ;sm~W^RT PETROLEUM ~s,antio~ one matd, a%a~u~ ICONIPANY for exception to 20 /crucial to *~- .... sue [AAC'25.055 to allow clrilli~g the ........ = commission,s ISmn~tor¥ aUthority, a hear' IWEST McARTHUR RIVER J?? the matter, will, he hel'~ma~I. /UNIT NO. I-1 water inlectlon /'"!.' '1 a re. a,,:00 ami Ion April 17, 1997 in Coofor- I mance With 2O AAC 25,540. If a I,"'STEWART PETROLEUM Ihearing is to be held, interest. / I COM'P~NY by 'letter* clat~ led parties may confirm th~s by lMarch 10, 1997 has requested /C~lllng the Commlssion,s of- lan,'exception fo the provlslons /_lice, (907) 279-1433 after' Jar 20 AAC 25.055(a)(3) for the 1 1997 'April , . If no protest is f Idrllling. of an expk;ratory oil /~e .Commission wm .... !l.ed, |rec0very service well In the Iou!.a hea~n~'.r'ne oraer with./ /west McArthUr River Unit, In I~ne I'ssuan~ ~,.-~ "' .~uns~aer the 'Cook Inlet. ~ ~r You are a' parson with a .The. exception would allow ]dlsabllih, who may heecl a ! Stewart petroleum Company ~spaCial modification In order! to dlrectionally drill the West /to camm ,ent or to attend the/ McAr'thur River Unit No: 1,1 Lpublic hearing, please 'contact water Inlectlon well to a.. ;~iana Fleck at 279-1;433 no q April 10; 1997.' bottom.hole', location that Is rmter thma/. 'JOhnstOn closer than 500 ,feet from a ;/S/David 1 nuqrter section.line. The pro- lChairman . .:.i Gas ':.' ' . i~os~tt .~ur~ace' Ioccltlon Ls 1953' LAIOsR'a OiI ,:'rrbm the west line (FWL)~ and ' Conservation Commission 3233' from the north line ~~997 FNL) .of, Section 16, TSN, i :14W, Seward Meridian (SM),. ~e,'~'rOp6sed t6p of the Inlec-I ah'Inter, vails 2400' FWL ~nd I )0'".FNE 'of Section 15, TSN~I R14W,.;SM and the proposedl 'bOttom'i,hOle. location iS 2765' | .FWL a~d. 328' FNL of :sect on / '.15,' TSN, 'RlaW; SM. The well/ . as ~proposed Will. i~. 6~en: to the / HemlOc~k' pm...wlthln '500~ of a / .spacing unit boundary In both ! the....northeast., and northwest J '"qot~rters'of section,',]5. ':,' / I..,A'.pers0n WhOm ~y be harm- / leu~ If the reqUested, larder Is/ :Issued,,.. Or..;wh~;.~ha~. valld.,-:eah.. / :~rr~. re,oToa ~o ;.o~,'.-rf,e:,'.l ?."oro':ens aca "le c',~i-r zu ! .y .1! mar~ retire-; Iron'/ and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private indiViduals· '" ............ .... Third DN/islon. Anchorage, Alaska MY COMMISSION EXPIRES My Commission E~oires: ................ F~b/lI~rd' 872000 ..... 19 ......
