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Home My WebLink AboutAIO 013 A , ) Imag.!prOject Order File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. A:J:.o 0 13 A Order File Identifier Organizing (done) 1IIIIII111111111111 D Two-sided RESCAN DIGITAL DATA o Color Items: D Greyscale Items: D Diskettes, No. D Other, No/Type: D Poor Quality Originals: o Other: NOTES: BY: ~ Date I / /20 IDS- Date: 1/ /30/0$ Project Proofing BY: ~ Scanning Preparation BY: C Maria ') x 30 = + Date: 11/10/Ó:5" Production Scanning Stage 1 Page Count from Scanned File: _ /:; .3 o Rescan Needed 1111111111111111111 OVERSIZED (Scannable) o Maps: D Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) o Logs of various kinds: o Other:: /s/ /11P 1111111111111111111 /s/ V/II P = TOTAL PAGES S':;2.. (Count does not include cover shr)ìt~ /5/ y tf If - 1111111111111111111 (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES BY: ~ Date: II /3C/ OS Stage 1 If NO in stage 1 page(s) discrepancies were found: YES BY: Maria Date: Scanning is complete at this point unless rescanning is required. ReScanned BY: Maria Date: Comments about this file: NO /s/ vvrP NO /5/ 1111111111111111111 I 1-1111111111 /5/ Quality Checked 1111111111111111111 10/6/2005 Orders File Cover Page.doc • • INDEX AREA INJECTION ORDER #13A Swanson River Field 1) October 2, 1995 Unocal's Application for AIO Swanson River Field 2) October 19, 1995 Unocal's Clarification of Request for Hemlock Pool Expansion 3) October 26, 1998 AOGCC's ltr re: Swanson River Pipeline Freeze Protection 4) April 13, 2000 Internal Memo re: Unocal's request to inject nonhazardous ethylene glycol waste into Class II wells 5) April 13, 2000 e -mail re: ethylene glycol and flush water disposal i 6) June 28, 2001 Ltr from Oil Risk to Unocal 7) June 30, 2001 Ltr from Unocal to DEC 8) August 24. 2001 Ltr to Unocal to AOGCC re: Determination of Acceptability of Class II Injection of Contaminated 9) September 27, 2004 Public Notice to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells 10) May 13, 2010 Unocal's request for Admin Approval (AIO 13A.001) Area Injection Order #13A ') STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: THE REQUEST OF UNION OIL ) COMPANY OF CALIFORNIA to ) amend Area Injection Order # 13 for ) Swanson River Field ) Area Injection Order No. 13A Swanson River Field March 16, 1987 (original order) First Amendment: December 5, 1995 IT APPEARING THAT: 1. The Commission issued Area Injection Order No. 13 for the Swanson River Field on March 16, 1987 2. Union Oil Company of California Inc. ("UNOCAL") became sole operator of the Swanson River Field on December 15, 1992. 3. By letters dated October 2, 1995, and October 19, 1995 UNOCAL requested expansion of the Swanson River Field, Hemlock Oil Pool, to include the G zone of the Tyonek Formation and the lower portion of the Hemlock Formation and appropriate revisions to Area Injection Order 13 to include the expanded pool. FINDINGS: 1. AS 31 generally, and AS 31.05.030(h) and 20 AAC 25.460 specifically, provide the Commission with the authority to issue an order governing underground injection operations on an area basis. An order permitting the underground injection of fluids on an area basis, rather than for each injection well individually, provides for efficiencies in the administration and surveillance of underground fluid injection operations. 2. Swanson River Field constitutes a compact "project area" which can readily be described by governmental subdivision. UNOCAL is the sole operator of underground injection activities in this area for the Swanson River Field. 3. All aquifers below 1700 feet within the Swanson River Field boundary, and one- quarter (1;4) mile beyond, are exempted under 40 CFR 147. 1 02(b )( 1 )(i) for Class II injection activities. . t:p "1 ')O[) /I, 5Ct,~N,NEL .JUN t,1 li r~ - ,', Area Injection Order No. .I.JA March 16, 1987, First Amendment December 1, 1995) Page 2 ') J 4. Adequate confining strata are present below 1700 feet in the Swanson River Field to prevent upward movement of waste fluid from injection zones into non-exempt fresh water sources. 5. The vertical limits for injection of fluids into the Hemlock formation for enhanced oil recovery may be defined in the Soldotna Creek Unit well SCU 41-4, Swanson River Field. 6. The vertical limits for injection of non-hazardous oil field liquids into the Sterling formation may be defined in the Swanson River Unit well SRU 32-33, Swanson River Field. 7. The strata into which fluids are to be injected will accept fluids at injection pressures which are less than the fracture pressure of the injection strata and their confining formations. 8. To ensure that fluids injected are confined to injection strata, the mechanical integrity of injection wells will be demonstrated periodically and monitored routinely for disclosure of possible abnormalities in operating conditions. ~ 9. Injection wells existing on the date of this order were constructed and completed in accordance with Commission regulations. NOW, THEREFORE, IT IS ORDERED THAT the rules hereinafter set forth govern Class II underground injection operations in the Swanson River Field as described in Rule 2 of Conservation Order No. 123 A. Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, non-hazardous fluids may be injected for the purposes of pressure maintenance and enhanced oil recovery into strata defined as those strata which correlate with strata found in the Soldotna Creek Unit well SCU 41-4 between the measured depths of 10,085 feet and 10,815 feet. Rule 2: Authorized Injection Strata for Disposal Within the affected area non-hazardous oil field fluids may be injected for the purpose of disposal into strata defined as those strata which correlate with strata found in the Swanson River Unit well SRU 32-33 between the measured depths of2,100 feet and 3,460 feet. ~u ··..t; \ II\: n:1 i.') t~ ')[-\LI.r 8CANh~;,I... d~.)n'J (...' (" C. ,', Area Injection Order Nu. J.'1A March 16, 1987, First Amendment December 1, 1995) Page 3 Rule 3: Fluid Injection Wells The underground injection of fluids must be: 1) through a well permitted by the Commission for drilling as a service well; 2) through a well approved by the Commission for conversion to a service well for injection; or 3) through a well approved by the Commission that existed as a service well for injection purposes on the date of this order. Rule 4: Monitoring the Tubing/Casing Annulus Pressures The tubing/casing annulus pressure of each injection well must be checked weekly to ensure there is no leakage, and that it does not exceed a pressure which will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 5: Reporting the Tubing/Casing Annulus Pressure Variations Tubing/casing annulus pressure variations of more than 200 psi between consecutive pressure readings made when injecting under steady state conditions of fluid temperature, rate, and pressure must be reported to the Commission on the first working day following the observation. Rule 6: Demonstration of Tubing/Casing Annulus Mechanical Integrity A schedule must be developed and approved with the Commission which ensures that the tubing/casing annulus for each injection well is pressure tested prior to initiating injection and at least once every four years thereafter. A test surface pressure of 1500 psi, or 0.25 psi/ft multiplied by the vertical depth of the packer whichever is greater; but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength. The test pressure must be held on the tubing/casing annulus for 30 minutes with no more than a 10% decline and must be stable at the end of the test period. As an alternative, with Commission approval, injection wells may be surveyed using an EP A sanctioned logging device every second year. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure testing or logging. Rule 7: Well Integrity Failure Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation and obtain approval of a plan for corrective action. ..- . .. II ~M (.) ~ì 2D \I.,:: ~"r-I~\NN¡¡-~,: JU¡\J (.. I·' .- ' -r..;} '.....IJ "~~ I~", IJ c....... - ~., ') Area Injection Order No. IJA March 16, 1987, First Amendment December 1, 1995) Page 4 Rule 8: Plugging and Abandonment of Fluid Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission. Rule 9: Administrative Relief Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Commission's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into an underground source of drinking water. DONE at Anchorage Alaska, and dated March 16, 1987, first amendment December 5, 1995 ~ 1)(~ ~ David W .~hñSion, Chai~man Alaska Oil and Gas Conservation Commission ·t¿/~· ð~ TJk~ Babcock, Commissioner Alaska Oil and Gas Conservation Commission 1. Da~d N~Îimmi~Sioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or nex1 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 ftom the date the Commission refuses the application or mails (or othetwise distributes) an order upon rehearing, both being the fmal order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by inaction of the Conunission, the 30-day period for appeal to Superior Court runs ftom the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). , ~-, ' ~ ~, "' ~~ ,) í') l- u :~~C.f\\'H\\E:!..' "a)i'¿ {, N I__U " • • ijj\ ft a a SEAN PARNELL, GOVERNOR ALASKA OIL OIL AND 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL Area Injection Order 13A.001 Mr. Dave Whitacre Union Oil Company of California P.O. Box 196247 Anchorage, AK 99519 -6247 RE: Area Injection Order 13A Request for Administrative Approval Rule 2: Authorized Injection Strata for Disposal Swanson River Field Dear Mr. Whitacre: In accordance with Rule 9 of Area Injection Order ( "AIO ") 13A.000, the Alaska Oil and Gas Conservation Commission (Commission) hereby GRANTS Union Oil Company of California's (Unocal) request for administrative approval revising the authorized injection strata for injection disposal of Class II oil field wastes to the strata that are common to, and correlative with, strata between the measured depths (MD) of 1,745 feet and 3,460 feet in Swanson River Unit (SRU) well No. 32 -33 (SRU 32 -33). FINDINGS 1. Within the Swanson River Field, all aquifers deeper than 1,700 feet below ground surface are exempted per 40 CFR 147.102 (b)(1)(i). 2. Strata receiving Class II injected waste materials are sandstones assigned to the "B- series" of the Pliocene -aged Sterling formation. These stacked, fluvial sandstone strata are typically 10- to 50 -feet thick, rich in volcanic rock fragments, fine -to coarse - grained, fairly to moderately sorted, and display little detrital or authigenic matrix. Well -log correlations indicate local continuity of the sandstone strata is good. 3. Upper confinement for injected waste is provided by a 30- to 50 -foot thick interval of interbedded layers of claystone and siltstone with minor sandstone that lies between 1,695 feet and 1,745 feet MD in SRU 32 -33 (see Figure 1, below). This confining interval is present on well logs and appears to be continuous for a radius of 1 /2 mile around the active SRU 31 -33WD and SRU 32 -33WD disposal wells. 4. Lower confinement for injected waste is provided by a 115 -foot thick interval that lies between about 3,460 feet and 3,575 feet MD in SRU 32 -33. This interval contains an aggregate thickness of about 55 feet of interbedded claystone, siltstone and coal that will provide an effective bottom seal for the injected fluids. This confining interval appears to be continuous for a radius of 1 /2 mile around SRU 31 -33WD and SRU 32 -33WD. • • AIO 13A.001 February 17, 2011 Page 2 of 4 150 MV 50 J.2 OHMM X1001.85 G/C3 26C TVOSS> a0.S1Sh0 rsxlu( CIJS) J.2 Of ROM 20000. .. -- _ T VD DTCPI0T1 <MD 1600 1°00 -1400 -n Confining 1700 1,00 °° Interval 1800 1.00 -1600 __ -1700 1900 1 son C 2000 .000 - 1600 2100 2100 -1000 _ -2000 2200 2200 Perforated Intervals in 2300 z3oo -210° SRU 31 33 W and 2400 2400 -2200 SRU 32-33W D -2300 2500 2500 m Revised _200 Disposal 2600 2600 Interval -2600 2700 2700 :::: ze00 -2600 23 °° = -2000 3000 00.0 . _ 3100 3100 f zs°o 3000 3200 0200 -3100 3300 3300 3400 0.0 -3200 --.. 3 3300 Confining 350o 3500 Interval z - - - 3600 3600 -3400 =� =c -r== Figure 1. SRU 32 -33 Well Log • AIO 13A.001 February 17, 2011 Page 3 of 4 5. To date, approximately 62.3 million barrels of Class II wastes have been injected into wells SRU 21 -33WD, SRU 31 -33WD, SRU 32 -33WD, and SRU 41 -33WD. Wells SRU 21 -33WD and SRU 41 -33WD have been properly plugged and abandoned, but during disposal injection operations these two wells received 2.7 and 3.7 million barrels of waste, respectively. Wells SRU 31 -33WD and SRU 32 -33WD are active injection wells that have received 32.7 and 23.2 million barrels of waste, respectively. 6. The cumulative injected Class II waste volume is estimated to extend radially about 800 feet from SRU 31 -33WD and about 650 feet from SRU 32- 33WD.' Waste volumes injected into SRU 31 -33WD and SRU 32 -33WD are likely in communication with each other. 7. Rule 2 of AIOs No. 13 and 13A defines the authorized injection strata as "...those strata which correlate with strata found in well SRU 32 -33 between the measured depths of 2,100 feet and 3,460 feet." The injection strata were defined in accordance with descriptions provided by ARCO Alaska, Inc., operator for the SRU at the time of the original application. 8. Upper confining intervals for the Sterling injection sands are not precisely defined in the original application for AIO 13. The depth of 1,700 feet is referenced in that application and in AIO 13 as being the upper limit for confinement. 9. On May 13, 2010, Unocal requested the Commission revise AIO 13 to conform to the well logs. 10. The Alaska Department of Natural Resources' MapGuide Water Rights GIS System (http: / /magellan.dnr. state .ak.us /dnrwater /default.cfn) shows 10 shallow water wells recorded in the SRU area; the deepest is 262 feet below ground level. All wells are registered to Unocal and dedicated to supporting oil and gas activities; no other registered water wells are within 6 miles of the SRU. 11. Active disposal injection wells SRU 31 -33WD and SRU 32 -33WD recently passed standard mechanical integrity tests. CONCLUSIONS 1. The proposed, revised injection strata that are equivalent to strata between 1,745 and 3,460 feet MD in well SRU 32 -33 are sufficiently thick and laterally continuous and have sufficient reservoir properties to accept additional injected Class II waste fluids. 1 This estimate is based on the temperature- log - determined waste depths of 1,970 feet MD in 1989 and 1,800 feet MD in 2010, assuming uniform filling of the 170 -foot thick interval at 8.1 feet per year, an average porosity of 21.5 %, and piston -like displacement of native formation fluids. 2 ARCO Alaska, Inc., 1987, Swanson River Unit, Area Injection Order Application for AIO 13. Attachment G -2 is hand - annotated with the injection interval between 2,100 feet and 2,422 feet MD. Attachment G -2 is described on page 12 as "an electric log showing the water injection zones in a typical water injection well." However, page 11 states: "Injection within the Sterling is limited to water wet sandstones within the Sterling B series (as recognized by Chevron Stratigraphy) from 2,100' to 3,500'." AIO 13A expanded the definition of the underlying Hemlock Pool, but it did not alter the definition for the Sterling injection sands or address the associated Sterling confining intervals. 3 ARCO Alaska, Inc.. 1987. cited above. Subsection 2, states in part: "Even if the immediate confining zone failed, there are several confining zones between the injection interval and 1700'." Finding 4 of AIOs 13 and 13A states: "Adequate confining strata are present below 1700 feet in the Swanson River Field to prevent upward movement of waste fluid from injection zones into non - exempt fresh water sources." AIO 13A.001 February 17, 2011 Page 4 of 4 2. The upper and lower confining intervals designated in the SRU 32 -33 well, confirmed on the well logs submitted in support of the original application, are sufficiently thick and laterally continuous to contain injected waste fluids. 3. There is no evidence that injected waste fluids have migrated or will migrate upward beyond the upper confining layer into non - exempt strata. Underground sources of drinking water will not be affected. 4. The active disposal injection wells have demonstrated mechanical integrity. 5. Revising the authorized injection strata will not promote waste or jeopardize correlative rights, is consistent with the well logs submitted in support of the original application, is based on sound engineering and geoscience principles, and will not result in an increase risk of fluid movement into fresh water. NOW, THEREFORE, IT IS ORDERED THAT the rule governing Class II underground injection operations in the Swanson River Field as described in Rule 2 of Area Injection Order No. 13A be revised as follows: Rule 2 Authorized Injection Strata for Disposal (Revised AIO 13A.001) Within the affected area non - hazardous oil field fluids may be injected for the purpose of disposal into strata defined as those strata that are common to, and correlate with, strata f. - well SRU 32 -33 between the measured depths of 1,745 feet and 3,460 feet. 04 DONE at Anchorage, Alaska and dated February 17, 2011. . • Daniel T. Seamount, Jr. No P . n Cath P. Foerster Chair omm • s' . er Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, February 18, 2011 9:18 AM To: '(foms2 @mtaonline.net)'; '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWeIIIntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fulimer'; 'bbritch'; 'Becky Bohrer'; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Gillespie'; 'Brian Havelock'; 'Bruce Webb'; 'caunderwood'; 'Chris Gay'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber; 'ddonkel @cfl.rr.com'; Delbridge, Rena E (LAA); 'Dennis Steffy'; 'Elizabeth Bluemink'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jeffery B. Jones'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Rudy Brueggeman'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothat; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; 'Valenzuela, Mariam '; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); Yereth Rosen; 'Aaron Gluzman'; Ben Greene; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; 'Dale Hoffman'; David Lenig; 'Gary Orr; 'Jason Bergerson'; 'Joe Longo'; 'Lara Coates'; Marc Kuck; 'Mary Aschoff; 'Matt Gill'; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; 'Ryan Daniel'; 'Sandra Lemke'; Talib Syed; 'Tiffany Stebbins'; 'Wayne Wooster; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Matt Herrera; Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: AIO13A -001 (Swanson River Field) Attachments: aio13A- 001.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Richard Neahring k Wedman Jerry Hod den Mar We Y 9 NRG Associates Hodgden Oil Company Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil Tools P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Barrow, AK 99723 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 \\D')\`" 0 I. • Chevron Paul Winslow Chevron North America %O. Petroleum Engineer Advisor Exploration and Production MidContinent/Alaska P.O. Box 196247 Anchorage, 99519-6247 Tel el 907 7 7 263 7629 Fax 907 263 7828 CEN Email: PWinslow @chevron.com MAY : 7 011 May 13, 2010 Commissioner Dan Seamount, Chairman Alaska Oil and Gas Conservation Commission 333 W 7th Ave # 100 Anchorage, Alaska 99501 -3509 AREA INJECTION ORDER NO. 13A REQUEST FOR ADMINISTRATIVE APPROVAL REGARDING RULE 2: AUTHORIZED INJECTION STRATA FOR DISPOSAL SWANSON RIVER FIELD Dear Chair Seamount: Union Oil Company of California ( "Union ") requests administrative approval under Rule 9: Administrative Relief of Area Injection Order No. 13A to amend Rule 2: Authorized Injection Strata for Disposal in Swanson River Field. Rule 2 currently authorizes the disposal of non - hazardous oil field fluids into strata which correlates between the measured depths of 2,100 feet and 3,460 feet in the Swanson River Unit v well SRU 32 -33. Union believes that the 3,460 foot depth provides adequate basal confinement of injected fluids but, based on well log interpretation, does not believe the 2,100 foot depth provides confinement from upward migration of injected fluids. The current top of authorized injection strata (2,100 feet MD) is in the middle of a permeable Upper 4 Sterling sandstone, and in Union's interpretation, does not offer vertical confinement of injected fluids in the current water disposal wells. Therefore, Union proposes the top of the authorized injection strata be amended to 1,745 feet MD/TVD ( -1,558 feet TVDSS) as correlated in the Swanson River Unit well SRU 32 -33. To support this request, Union submits the following information and documentation as attachments: 1. Well Log of SRU 32 -33 (1,600 feet — 2,200 feet MD) (attached), A 2. SRU 32A -33 Well Schematic (Equivalent to SRU 32 -33 at Rule 2 disposal depths), and 3. Upper Sterling cross section showing the % mile radius regional extent of the upward confining interval. The proposed amended top depth of 1,745 feet MD /TVD is based on three criteria. First, the proposed injection strata depth remains distinctly below the top of the exempted aquifers which, per 40 CFR 147.102(b)(1)(i) for Class 11 injection activities, is at a depth of 1,700 feet. Second, the proposed depth corresponds to the top of a permeable Upper Sterling sandstone and the base of what appears to be an adequate confining strata, 45 feet thick. Third, Union interprets this confining strata to be present in all wellbores within a %2 mile radius of our current water disposal wells, as demonstrated in Attachment 3. Rule 2 currently reads: "Within the affected area non - hazardous oil field fluids may be injected for the purpose of disposal into strata defined as those strata which correlate with strata found in the Swanson River Unit well SRU 32 -33 between the measured depths of 2,100 feet and 3,460 feet." Under Rule 9: MidContinent /Alaska Chevron North America Exploration and Production www.chevron.com • Commissioner Dan Seamount, Chairman Alaska Oil and Gas Conservation Commission May 13, 2010 Page 2 Administrative Relief, Union suggests the following language be used to amend Rule 2: "...in the Swanson River Unit well SRU 32 -33 between the measured depths of 1,745 feet and 3,460 feet." Union believes that the proposed amendment to Rule 2 would adequately prevent the upward movement of waste fluid from the injection zones into non - exempt fresh water sources. If you have any questions or would like to review any additional information, please contact myself (907/263 -7629) or Kevin Eastham (907/263 -7959) at your earliest convenience. Thank you for your consideration in this matter. Sincerely, Paul M. Winslow Petroleum Engineer Advisor Attachments I I MidContinent /Alaska Chevron North America Exploration and Production www.chevron.com • • ' evro SRU 32A -33 � . , .. � � �. ell SRU 32A -33 • '.`%..../... Actual Wellbore Schemat t d t Completed d 7/05/08 /15/91 RKB: 201.6' KB / GL: 172' AMSL KB -THF: 29.6' KB Casing and Tubing Detail ....1 ,___.) 1 2 L Size Type Wt/ Grade Top Btm CONN 1 ID Cement / Other 22 ' @ 22" Structural - Surface 45' - Cemented 45' 54.5 #, J -55 Surface 1,023' 600sxs 116# (stage 1), 13 -3/8" Surface DV Collar 1,023' 1,025' 8RD / 12.615" 600sxs 116# (stage 2), DV Collar I 1 54.5 #, J -55 1,025' 2,555' 64 sx 116# (top job) 1 29 #, N -80 Surface 364' BTC / 6.184" 26 #, N -80 364' 1,282' BTC / 6.276" 4 N. 23 #, N -80 1,282' 4,687' BTC / 6.366" 13-3/8" 5 r � 3 26 #, N -80 4,687' 6,225' BTC / 6.276" 650sxs 116# (stage 1), @ 555' 7" Surface 29 #, N -80 6,225' 7,916' BTC / 6.184" 750sxs 116# (stage 2) 26 #, P -110 7,916' 8,036' 8RD / 6.276" DV Collar 8,036' 8,038' 8RD / 6.276" 26 #, P -110 8,038' 8,701' 8RD ! 6.276" 5" Liner 18 #, N -80 8,379' 10,566' FL4S / 4.276" 70 bbl 15.6 ppg 1 cal° TOC - 4 2 -7/8" Liner 6.5 #, N -80 9,499' 11,386' 8RD -Mod / 2.441" 18 bbl 15.8 ppg 6,175' Tubing s 2 -7/8" Prod 6.5 #, N -80 Surface 8,910' 8RD -Mod / 2.441" Cplg OD = 3.668" 2 -3/8" Prod 4.7 #, N -80 8,910' 9,499' 8RD -Mod /1.995" Cplg OD = 3.063" 6 Production String Jewelry Detail # Depth (RKB) Length ID OD Item 1 29.6' 1.9' 2.992" 4.500" Tubing Hanger, 3 -1/2" 7 2 31.5' ? 2.441" 4.500" X -Over 3 -1/2" x 2 -7/8" DV Collar GLM, Camco Model MMGP 2 -7/8" x 1 -1/2" 8,036' 1 I 3 4,021' ? 2.441" 5.500" (Drift = 2.347 ") [Gaslift valve installed] 4 6,193' ? 2.441" 5.500" GLM, Camco Model MMGP 2 -7/8" x 1 -1/2" (Drift = 2.347 ") [Gaslift valve installed] 5 6,712' 15' 0.875" 2.441" Tubing patch, set 7/5/08 CBL TOC G- stop /packoff /spacer /packoff/AD -2 stop 8,355 GLM, Camco Model MMGP 2 -7/8" x 1 -1/2" TOL at X Z 8 6 7,281' 2 2.441" 5.500" (Drift = 2.347 ") [Gaslift valve installed] 8,379' GLM, Camco Model MMGP 2 -7/8" x 1 -1/2" 7" windowat , 9 7 8,359' . 2.441" 5 (Drift = 2.347 ") [Gaslift valve installed] 8,701' 8 8,379' ? 4.250" 6.276" Liner top x 10 9 8,818' 2 2.313" 3.668" Sliding Sleeve, 2.313" Min ID 10 8,878' 2 2.313" 3.668" X- Profile, 2.313" Min ID 11 11 8,910' 2 1.960" 3.668" X -Over 2 -7/8" 8RD -Mod B x 2 -3/8" 8RD -Mod P 12 12 8,962' ? 1.995" 3.870" GLM, TMPDX Teledyne 2 -3/8" x 1" (1.901" Drift) 13 9,466' ? 1.995" 3.870" GLM, TMPDX Teledyne 2 -3/8" x 1" (1.901" Drift) 13 14 9,499' 2 2 2 Baker E -22 Anchor Seal Assembly TOL at . ' ' 14 15 9,499' 4.33' ? ? Liner Top Packer, Baker SC-1L Packer 9,499' 1s 16 10,890' - - 1.75" Teledyne Bridge Plug ,� 17 11,319' Landing Collar 18 11,386' 10.0' - - FISH: 10' BHC /AC logging tool L I. � 5" @ 10566' Perforation Data G ZONE TOP BTM Spf Comments G 10,698' 10,724' 4,4,4 Perf (11/12/03), (3/27/01), (2/25/01) H -1 10,800' 10,820' 4,4 Perf (12/05/95), (5/10/91) H-1 H -2 10,835' 10,854' 4,4 Perf (12/05/95), (4/28/91) H -2 ° H -3,H -4 10,900' 10,912' 1 Perf (4/23/91) Tag Fill 10,863' SLM 16 7/02/08 \ H-3/H4 I ' 17 2 -7/8" @ 11,386' 18 TD = 11,396' PBTD = 11,319' Directional Data: max hole angle = 34.0° at 11,000' MD SRU 32A -33 Actual WBD 7- 05- 08.doc Updated by STP 3 -30 -10 , • • evro anso SRU 31 -33WD ,, SR 414 4.0/ st Co a .' Actual Wellbore Schematic 4,1 „0 � FMB= 1W KB /GL 165' AMSL KB -11F = 19.02' I`^ 1 I 10-8/4' Casing and Tubing Detail Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 10 -3/4” Conductor - Surface 90' - Driven 7" Surface 29 #, K -55 Surface 2,461' 8RD / 6.059" 800 sx / Cmt to surface 5 -1/2" Protective 17 #, N -80 _ Surface 2,015' BTC / 4.892" _ 100 sx / Cmt to surface 20 #, N -80 8RD / 4.778" (Drift of 5 -1/2" 20# = 4.653 ") Tubing 2 -7/8" j Production 6.5#, N -80 J Surface ) 1,923' 1 8RD / 2.441" 1 Cplg OD = 3.668" Production String Jewelry Detail Depth (RKB) Length ID OD Item 1 19' 0.50' 2.441" 3.668" Tubing Hanger, 2 -7/8" (8RD suspension threads) 2 1,917' 5.92' 2.375" 3.000" G -22 Tubing Locator Seal Assembly (5.13' seals) 3 1,917' 2.12' 3.000" 4.437" Packer, Baker F -1 (set hydraulically 9/22/85) 4 1,923' 0.60' 2.441" 2.875" Tubing Tail, 1 /2 Mule Shoe 2 5 2,413' 2.0' - - [FISH] Bridge Plug, Baker Model N -1 (tag 9/22/85) 6 2,413' - - - [FISH] Packer, Baker Model F -1 (tag 9/22/85) ' owl : = • • 4 Perforation Data ZONE TOP BTM SPF Condition Sterling 2,100' 2,140' 4,4 2 -1/8" WL (8/21/89) / 4" H.S.C. (1/2" EH), (8/25/81) Sterling 2,162' 2,242' 4,4 2 -1/8" WL (8/21/89) / 4" H.S.C. (1/2" EH), (8/25/81) San" Sterling 2,256' 2,284' 4,4 2 -1/8" WL (8/21/89) / 4" H.S.C. (1/2" EH), (8/25/81) X2,019 ` Sterling 2,313' 2,383' 4,4 2 -1/8" WL (8/21/89) / 4" H.S.C. (1/2" EH), (8/25/81) Top of Fill - -- $089'RKB• .� (Tag w/ . -'� 2.25" bailer 4115 /10) Staring I ,a PBTD 2413'RKB ;' 5 (Tag 9/22/85] b � t -- Ob. - d: - 6 7" Ld 2,461' TD 2,461' PBTD= 2,413' Directional Data: max hole angle = 0.5 at 2,450' MD SRU 31 -33WD WBD 6- 04- 10.doc Updated by STP 4 -15 -10 Chevron I Well: 1SRU 31 -33•wd 1 Field: Swanson • River • 104 -15 -2010 Pressure (psia) 500 600 700 800 900 1000 1100 1200 1300 1400 1500 0 I 100 Sk. 200 Pressure-Temperature Profile \ 300 - -- 1. RIH vs POOH Overlay 2. Well Shut -In � 400 - 1 500 600 '1 ■ 700 \ i ' 800 - CO 1 Y 900 4 d 1000 / 4 1100 - - CL r C) 1200 CI 1300 / 1400 — 1500 - 1600 _ - 1700 = — 1800 .., 1i00 1900 ,/ 2000 - 2100 ■ 45 50 55 60 65 70 75 80 85 90 95 Temperature (Deg. F) - Pressure — Perfs X PKR • 10 3/4" 7" - 2 7/8" POOH Pressure —Temperature POOH Temp Report date: 5/17/2010 '9a • • (Chevron 1 Well: 1SRU 31 -33wd 1 Field:1Swanson River 107 -27 -2010 Pressure (psis) 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1000 ; � MBMI WAWA 1100 ■I�� __I_ l - Pressure- Temperature Profile _ ; 1 Going in hole to 2069 Overlay Inn MIN �k ' 2. Well Shut In ' li 1200 ax - i a , ---- t 1300 ' • 1400 • 4 in , Y 1500 -. `J 0 d 1600 i 1700 — j � � klin - IIIIIA NO 1800 1 k _, - 1900 _ µ X J — 2000 i __.1 - - - ' --...' - -- t , 2100 � 1 ` ! i 50 55 60 65 70 75 80 85 90 95 100 L , Temperature (Deg. F) - Perfs x PKR 10 3!4" -7" 2 7/8" -�--- -51/2" 1st Pass Temp ---- 7 -25 -10 Temp 30 min Pass Temp 1 hr Pass Temp 2 hr Pass Temp 4 -15 -10 Temp Report date: 8/2/2010 Page 1 of 1 • • Maunder, Thomas E (DOA) From: Saltmarsh, Arthur C (DOA) Sent: Thursday, December 02, 2010 8:07 AM To: Maunder, Thomas E (DOA) Subject: SRU 32 -33 Attachments: SRU 32 -33 Disposal Zone Log.pdf; Findings_AIO13A.001.docx; Presentation1.pptx Hey Tom, i is II of injection are the logs and the findings /conclusions. Following s a tally o the � ection zone reservoir and porosity. I've also listed the additional confining layers deeper in the section. I've only included the reservoir sands covered by the injection order. Total reservoir sands: 1424' Average Porosity (range): 15 -28% Additional confining zones: 10' (2820') coal followed by 90' sand; 14' (2920') coal followed by 36' and 68' sand; 35' claystone (3010') followed by 162', 130', 33', and 57' sands; 15' claystone (3460' bottom of injection interval). There doesn't appear to be any shallower confining layers of significance. You should be able to copy and paste the Power Point slides of the Togs into the doc. 12/2/2010 5 R u 3? - 33 385 FEET v 3 TO 7 v :( ,la '31(5 W(44j2A4f ) L4.) .„)(IP QCDTC 260 us/ft 60 QCSP -70 mV 0 OCRHOB 1.65 g/cm3 2.65 Feet MD TVDSS OCRD OCNP1 1 ohm 100 0.6 unitlPss 0 0 CN1 : 0 ;f1 to - . - 4 • a • . - I.; : . " , CD m • CO I f • ■-• - 00 #9 ) ) ((ù,'<,"', ír,J :.' ' f,rl':~\, ~,',' :r.... ',',.,I,ï," ,,~ ')" '\ '\ " 'I F "', 'I)"~ 'j' i.....J. \, ~: ': :,; ,1,~'\ '! :1:, {:Q., L iJw ~ ~ (~u' '\I! '¡::1 ',I¡:,·,:,I.,','~ :W~:, 'i \.'. : ' J .... :,1.-, ;11, n /,'")"\ ('0') /,\\ I ,I i~' I' -,!...) / :Q \ '!i / £J\\<:~\,:¡ '" ,\.1 ,I~I"\" ClJi,' :'..J ".J:t-..J LJì...J '\..:.:!.J :ì1\ j", ' !,1J1"" "\ ! " '. LJìj / ;' ;¡ ! 1 / / ,/ FRANK H. MURKOWSKI, GOVERNOR A."/A.~&A. OIL Alft) GAS CONSERVATION COJDIISSION 333 W. ]fH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing m~chanical integrity of wells in all existing area injection orders, storage injection orders, enhanced recovery injection orders, and disposal injection orders. There are numerous different versions of wording used for each of the rules that create confusion and inconsistent implementation of well integrity requirements for injection wells when pressure communication or leakage is indicated. In several injection orders, there are 110 rules addressing requirements for notification and well disposition when a well integrity failure is identified. Wording used for the administrative approval rule in injection orders is similarly inconsistent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and before returning a well to service following a workover affecting mechanical integrity. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth 9f the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Fonn 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone iso lation. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. The following table identifies the specific rules affected by the rewrite. Injection Order "Demonstration of Mechanical Integrity" Affected Rules "Well Integrity Failure and Confinement" "Administrative Action" Area Ioj ection Orders AIO 1 - Duck Island Unit AIO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, Ugnu, West Sak Fields AIO 3 - Prudhoe Bay Unit; Western Operating Area AIO 4C - Prudhoe Bay Unit; Eastern Operating Area AIO 5 - Trading Bay Unit; McArthur River Field AIO 6 - Granite Point Field; Northern Portion AIO 7 - Middle Ground Shoal; Northern Portion AIO 8 - Middle Ground Shoal; Southern Portion AIO 9 - Middle Ground Shoal; Central Portion AIO lOB - Milne Point Unit; Schrader Bluff, Sag River, Kuparuk River Pools AIO 11 - Granite Point Field; Southern Portion AIO 12 - Trading Bay Field; Southern Portion AIO 13A - Swanson River Unit AIO 14A - Prudhoe Bay Unit; Niakuk Oil Pool AIO 15 - West McArthur 6 7 9 6 7 -9 6 7 9 6 7 9 6 6 9 6 7 9 6 7 9 6 7 9 6 7 9 4 5 8 5 6 8 5 6 8 6 7 9 4 5 8 5 6 9 ,) Affected Rules "Demonstration of "Well Integrity "Administrati ve Injection Order Mechanical Failure and Action" Integrity" Confinement" River Unit AIO 16 - Kuparuk River 6 7 10 Unit; Tarn Oil Pool 6 8 AIO 17 - Badami Unit 5 AIO 18A - Colville River 6 7 11 Unit; Alpine Oil Pool AIO 19 - Duck Island Unit; 5 6 9 Eider Oil Pool AIO 20 - Prudhoe Bay Unit; 5 6 9 Midnight Sun Oil Pool AIO 21 - Kuparuk River 4 No rule 6 Unit; Meltwater Oil Pool AIO 22C - Prudhoe Bay 5 No rule 8 Unit; Aurora Oil Pool 6 9 AIO 23 - Northstar Unit 5 AIO 24 - Prudhoe Bay Unit; 5 No rule 9 Borealis Oil Pool AIO 25 - Prudhoe Bay Unit; 6 8 13 Polaris Oil Pool AIO 26 - Prudhoe Bay Unit; 6 No rule 13 Orion Oil Pool Disposal Injection Orders DID 1 - Kenai Unit; KU No rule No rule No rule WD-l DID 2 - Kenai Unit; KU 14- No rule No rule No rule 4 DIO 3 - Beluga River Gas No rule No rule No rule Field; BR WD-1 DIO 4 - Beaver Creek Unit; No rule No rule No rule BC-2 DIO 5 - Barrow Gas Field; No rule No rule No rule South Barrow #5 DID 6 - Lewis River Gas No rule No rule 3 Field; WD-l DIO 7 - West McArthur 2 3 5 River Unit; WMRU D-l DID 8 - Beaver Creek Unit; 2 3 5 BC-3 DIO 9 - Kenai Unit; KU 11- 2 3 4 17 DID 10 - Granite Point 2 3 5 Field; GP 44-11 Affected Rules "Demonstration of "Well Integrity "Administrati ve Injection Order Mechanical Failure and Action" Integrity" Confinement" DIO II - Kenai Unit; KU 2 3 4 24-7 DIO 12 - Badami Unit; VVD- 2 3 5 1, WD- 2 DIO 13 - North Trading Bay 2 3 6 Unit; S-4 DIO 14 - Houston Gas 2 3 5 Field; Well #3 DIO 15 - North Trading Bay 2 3 Rule not numbered Unit; S-5 DIO 16 - West McArthur 2 3 5 River Unit; WMRU 4D DIO 17 - North Cook Inlet 2 3 6 Unit; NCro A-12 DIO 19 - Granite Point 4 6 Field; W. Granite Point State 3 17587 #3 DIO 20 - Pioneer Unit; Well 3 4 6 1702-15DA WDW DID 21 - Flaxman Island; 3 4 7 Alaska State A-2 DID 22 - Redoubt Unit; RU 3 No rule 6 Dl DID 23 - Ivan River Unit; No rule No rule 6 IRU 14-31 DID 24 - Nicolai Creek Order expired Unit; NCD #5 DIO 25 - Sterling Unit; SU 3 4 7 43-9 DIO 26 - Kustatan Field; 3 4 7 KFl Storage Injection Orders SIO 1 - Prudhoe Bay Unit, No rule No rule No rule Point McIntyre Field #6 SIO 2A- Swanson River 2 No rule 6 Unit; KGSF #1 SIO 3 - Swanson River Unit; 2 No rule 7 KGSF #2 Enhanced Recovery Injection Orders EIO 1 - Prudhoe Bay Unit; No rule 8 Prudhoe Bay Field, Schrader No rule Bluff Formation Well V-I05 Injection Order EID 2 - Redoubt Unit; RU-6 ') "Demonstration 0 f Mechanical Integrity" 5 ) Affected Rules "Well Integrity Failure and Confinement" 8 "Administrative Action" 9 I 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO,. CERTIFIED AO-02514016 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F R o M AOGCC 333 West th Avenue, Suite 100 Anchorage,AJ( 99501 907-793-1221 AGENCY CONTACT DATE OF A.O. lody Colombie September 7.7, 7.004 PHONE PC~ (907) 793 -17.7.] DATES ADVERTISEMENT REQUIRED: T o Journal of Commerce 301 Arctic Slope Ave #350 Anchorage, AJ( 99518 October 3,2004 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN_ SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that helshe is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for _ consecutive days, the last publication appearing on the _ day of , 2004, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2004, Notary public for state of My commission expires 9/29/2004 1: LO PM 10f2 Subject: Public Notices From: Jady Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 29 Sep2004 13:01:04 -0800 To: undisclosed~recipients:; , BeC: Cynthia, ß'MC'iver, <bre~m,'civer@, a~il1.state.ak.us>,~gèla,',', Web.b <angie _ webb@adnt,ìn.state~~.us> ,.Robert '~ Mintz' <robert_~iIltz.@law .statè~ak~us> ;'Christine " H~sen <ç..h~~en@iogcc.st(tte.9k~us>~'·TerrieHubÞle <hubbletl@bp..c'om>,S:ond;i-a StewIDan <Stewma$D@BP.coìn>, Scott &'Carßn¡y Tayl~r <stayl~r@alásk~.~et>,:'~tatJ;ekj <stanekj.@uno'6al.com>,'ecolaw <ecolaw@trustees.ôrg>, roser~gsdale <roseragsØale@gcLnet>, trmjrl <trmjr l@aol.cOm>, jbrid~Ie:<jbri4dle@marathqIloiLco~>, ,roèldíill <rockhil1@aoga.org>, shaneg <Sb.&1eg@~v~r-gre:eIígás.com>" jdarlington<jdärlíngton@~Ç>rest~H~~oJ)l>,:,n~lsoJ;1 " <ki1elsQt1@petroleumnews.com>" cbod~y ,<cboddY@l1sibelli.cotØ>,"¥ark 'DaItpn , <mark.dalt()n@hdtinc.cQm>, . Shannon DOnnelly <shannon.(ionnelly@conocophillips.co$>:. "'MarkP. . -, , ... -, . , " ','. , '."'1;,' . ' t·· WÓrcest~t" <mark.p~Worces~er@¢on,ocophillips.c9m>, "le,rryC., Dethlefs", ... ",. ,,'~ ~. ..... <jerry.c.dethlefs@conocophiilips.com>, .Bob <bob@inletkeeper.org>,w~v <",<.lv@dpr.stªte.ák. us>, tjr. <tjr@dnr~state.ak~ US>, .bbritch <~b-ritch@alaska.net> ,mjnelson <mjµelson(@pµrvmgertz.cQm>, Charles O'Donnell,<charles.o'donneIl@veco.cQm>, "RandyL.· Skillèm" <Skil!eR+@BP .co~>, "Deborah J. Jones" <JonesD6@BP.còni.>,"PaulG.Hy~tt" <hyattPg@BP.com>, nSteven R. Rossberg" <R,ossbeRS@BP .com>, ·Lois '<lois@inletkeeper.org> ,.DEttl ;Bross:~kua~news@kuac~org>, Gordon ' Po~pisil <Posl?isG@BP.coDJ>,. n.Fr~ci$ s. SOnunêf~t<Sö'~e~FS@l1P~com>,Mik:~l Sçhultz <MikeLSchultz@BP.com>, "NickW.Glover" <GlpverNW@BP..com>, '''Daryl]. K1êpp,in" <IÇteppiDE@ßP.com>, "J;met D. Pl~tt"<~.lattJD@BP .com>,nR~sanneM. Jaco.bsen" <JacohsRM@BP.com>, ddonke~ <ddonk~l@cfl.1T.co~>,ColüµS Mòunt , <collfus _ motmt@revenu~.state.ak.us>,mckay <mckay@gci.nét>, B~baraF Fullmer <barbara.,f.:fu11me.r@c.onocophillips~com>~' bocastwf <boc'(lStwf@bp.'com>, Cru~rles: Barker·. . <barker@usg~.gov>,doug_schuhze <doµg~schultze@Xtoenergy.c()m>,Hætk·Aiford .. : .,' <hank.alford@exxornnobil.com>,MarkKovac <yes~o l@gci.net:>;gspfoff. <gspfoff@aurorapower,.com>,Gregg Na<iY <gregq;.nady@sheU.c()m>,Fre~ 'St~eçe , <fred.steec~@state.sd. US>, rcrotty <r,crotty@ch2m.'com>,jcjQnes <jèj.ones@aurorapower.com>,dapa <dapa@al~ska~net>, jroØerick ,<j~<?de.rick@gci.n~t>, e~cY'<ey~çY@s.ea,I.~it~.,n~?-, ~rJames M. Ruud" <J~es.m.ruud@conócopbiHip~.~òm>', J3rit ~~vely <ni~PttlaSk~(@*...iet:>,.j.ah· . <jah@dnr.state~ak.us> ,Kurt E Ols'on '<kurt _ olsori@l~glS.st~te'.ak~us>,' buöpojê<buonqje@bp.com>, Mark Hanley <mark _ hanley@anadarko.com>, loren _lema!?- <lóre~~le$éUl@gòv.state.ak. u~>, Julie Houle <julie_holÛe@dDr..state'.ak~us>, John W Katz<jwkatz@sso.org>, Sùz~ JHill ' <suZan _ hill@dec.state.ak.us>, tablerk <tablerk@~oca1.com>,. Braqy <brady@~ga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpópp <bpopp@botough~kenai.ak.us>, Jim;~~e' , ..., . . <jimwhite@satx~lT.êom>, "John S.Haworth"' <jo1m~s:.haworth@exxorip:iobitèom>, inarty, <m.arty@r~in~ustria1.çöm>,:gbammöns <gþ~tIl~@~~lçoIJl~~,r.mël~~ <ni1cl~an@pobox~alaska.net>, mkm 7:200 <IDkm 7200@at>.Lcö~> ;,~µari,Gillespi~ , <itbmg@ü~ataSka.edu>; Dávid L,B.o~lens'.<dbQeleII;S@~µrorapø\yêi:~com>; Todø. pw;kee <TDURKEE@~G'~com.>~, Ga..ry Sc'~ultz" <gary _ schuhz@dDr~s~&*~us> ~ ,W(iy.ne.:R,ancier <RANCIER,@petro.c3Ilada~ca~" -Bill¥iller <Bilt. Millet@xto*l.~a."9Q~ ~ ~~~49*'~9agDon <bgagp:on@brenalaw.~òm>, 'P~lWi~slow <priíWinS~QW@îorestp~J:.8ÒIn>" <¥íY"Cat,ton .., <catrongr@bp.com>, Shannaine, Copeland <copelasv@bp.øo~>, ~uzanne AUexan <sa;llexan@helii1eÌ1ergy~com>, Kristin Dirks, <krisiin~dirks@Qnr:state.ak.. us>, KayneU Zeman <lcjzemarl@l11arâthonó~l.c6in>, Jóht1Tow~r <Johri.Tower@~i~4oe~goY~"i3i11 F~wler . . <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@ibccm,~còm>~Scott Cr~wi(:lç ) ) Public Notices Public Notices <sçottcfanswick@rnl1ls..gpv>, .BradMcKirn<rnC]{imbs@B:p.co1)1> ¿f9(ÎY .. . ... ... , " ... ..' .."... "::;, ~ . , " .. .. . ." ", ," . , " ~ ".. :'¡ , : ' , .' '.' : : . " . .' ",: ;':, " " , ". , " , . - ,: - - . :. , ,- . . , -" ""':, ,. : , - .. . .. 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Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie Content-Type: applicationlmsword Content-Encoding: base64 'Mechanical Integrity of Wells .. '~"-'.""'.""~'."'-"'" Content-Type: application/msword Ad Order form.doc Content-Encoding: base64 1 of 1 9/29/2004 1: 10 PM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street. Ste 2000 Ft. Worth, TX 76102-6298 /lja¡!¿:d I{//;h~ David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Com pany 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambe/l Street #400 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 ~,[Fwd: Re: Consistent Wording for Injectionþrs - Well Integrity... ) S. :ubject:' [Fwd: Re:· C{)nsistel1tW ötgil].gf'qr ~j,~c~iôn.Ord¢r~ -W~llm.t¢gritY<~.'.".~vis~d", )] F...'. ".,..r".',.,....,.·,Ð. .,', 'œ.',.,.'.· "':. J"""O,'.' hn N,orm.., '.,",an.,.·'" ",,'.,<."', ,J. ~O,.·..,·.'.hn.,/,', .,11,·'.0,':. nn.,,·..", ,',". an.' .'.,'.@.·.,,'·..·,'·,::.a,','·'drrt.in.,'~.tate.ak".,.'·".us. > ,"'" '",....' '.', """'.' .., " "¡ , IJ.te:Fri,OlOct 2004;'11:ó9:26+080(} ,"'" " ",.:'" ',' To: Jody J Colombie <jody _ colombie@adt.TIin.state.ak.us> more -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Wed, 25 Aug 2004 16:49:40 -0800 From:Rob Mintz <robert rnintz@law.state.ak.us> To:jim regg(Cl}admin.state.ak.us CC:dan seamount@admin.state.ak.us, john norm.an@admin.state.ak.us Jim, looks good, but I still think maybe it would be good to include the following sentence or something like it in the well integrity and confinement rule: "The operator shall shut in the well if so directed by the Commission." My thinking is that otherwise, an operator might argue that the Commission can only require the well to be shut in by going through an enforcement action, issuing an order after notice and opportunity for hearing, or meeting the strict requirements for an emergency order under the regulations. The proposed language makes clear that it is a condition of the authorization to inject, that the operator must shut in the well if directed by the Commission after a notification of loss of integrity, etc. »> James Regg <jim regg@admin.state.ak.us> 8/25/2004 3: 15:06 PM »> Rob - Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...] to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions abQut the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim regg~admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sf. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing I of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent vVording for Injection .=rs - Well Integrity ... - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EaR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions - adopts" Administrative Actions" title (earlier rules used" Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Nonnan <John Norman@admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission 20f2 10/2/2004 4:07 PM JFwd: Re: Consistent Wording for Injection ( }s - Well Integrity... ) .~~bject: [Fwd: Re:ConsistentW ordingfor IrijectipnO~4èr$ ~ ..W¢'n~tégrity(l{evis¢d)] ~r~l1l: John Norman <johrï_normanC$admiIl~state.al(,µs> . Date: Fri, 01 Oct 2004 11: 08: 5 5 ...0800 ~¥~';',~9ª~....jr·.·:~'9t~~~~'~¡'§.,~~~1#8~~~Þî.¢@~~~~~t~t~~~.!~~ij'$*.··.···.:.·..···..··.········· please print all and put in file for me to review just prior to hearing on these amendments. thanx -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Thu, 19 Aug 2004 15:46:31 -0800 From:Rob Mintz <robert mintz@law.state.ak.us> To:dan seamount~admin.state.ak.us, jim regg@admin.state.ak.us, john norman@admin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as red lines on the second document attached. »> James Regg <jim regg@admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing - specific to Ala 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EaR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions lof2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for Injection ~rs - Well Integrity ... - adopts" Administrative Actions" title (earlier rules used" Administrative Relief"); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg · John K. Norman <John Norman@admin.state.us> Commissioner : Alaska Oil & Gas Conservation Commission Content-Type: applicationlmsword Injection Order language - questions.doc Content-Encoding: base64 Content-Type: applicationJrnsword Injection Orders language edits. doc Content-Encoding: base64 20f2 10/2/2004 4:07 PM J ) Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement The tubing, casing and packer of an injection well must demonstrate integrity during operation. The operator must immediately notify the Commission and submit a plan of corrective action on F onn 10-403 for Commission approval whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, or log. If there is no threat to freshwater, injection may continue until the Commission requires the well to be shut in or secured. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection \vell), and before returnin,g a v\I'ell to service fol1o\ving afte.F a workover affecting mechanical integrity, and at least once every 4 years \vhile actively injecting. For slurry injection wells, the tubing/casing ¡mnulus tnust be tè:sted t(x mechanical integrity èvery 2 years. Unless an alternate 1TIeanS is approved by the COlnnlissìon. rnechanìcal integrity Hlust be demonstrated by a tubin.g pressure test using a +fie- M±+-surface pressure OfD1ust be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that fB-HSt-show~ stabilizing pressure that doesand lnay not change more than 10%- percent during a 30 minute period. -Any altenlate illcans of dem.onstrating Incchanìcal integrity must be approved by the COlnnlission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement Except as otherwise prov'ided in this rule, +!he tubing, casing and packer of an injection well must demonstrate lnaintain integrity during operation. \Vhenever anv pressure conlffiunication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log. or other evidence. t+he operator HH.tS-f-shaJI immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval.:. \vhenever any pressure cOffilnurlÍcation, leakage or lack of injection zone isolation is indicated by injection rate. operating pressure observation, test, survey, or log. The operator shall shut in the \vell if so directed bv the COl11111ission. The operator shall shut in the \-veU without awaitin,g a response Üom the COillInissi.on if continued operation would be w1safe or would threaten contamination of fresh waterIf there is no threat to freshwater, injection lnay continue until the C0l111nission requires the v;ell to be shut in or secured. Until corrective action is successfully completed, Àª monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. .[Fwd: Re: [Fwd: AOGCC Proposed WI Lan~ k for Injectors]] ) StllJ,Jecf: [Fwd: Re: [Fwd: AOGCC.Proposed WI Language for Injectors]] ~rºmJWitlton .Aubert.·<wiriton_aubert@adrnin.state.éÙ(;us> ~~~~~"~~_~(lii~~_~~#J~~"ii' .::,",.;,' This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: Re: [Fwd: AOGCC Proposed WI Language for Injectors] Date: Thu, 28 Oct 2004 09:41:55 -0800 From: James Regg <jim regg@admin.state.ak.us> Organization: State of Alaska To: Winton Aubert <winton aubert@admin.state.ak.us> References: <41812422.8080604@admin.state.ak.us> These should be provided to Jody as part of public review record Jim Winton Aubert wrote: FYI. -------- Original Message -------- AOGCC Proposed WI Language for Tue, 19 Oct 2004 13:49:33 -0800 Engel, Harry R <EngeIHR@BP.com> winton aubert@admin.state.ak.us Injectors Subject: Date: From: To: Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven; Engel, Harry R; Cismoski, Doug A; NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.; Reeves, Donald F; Dube, Anna T; NSU, ADW Well Integrity Engineer *Subject: * AOGCC Proposed WI Language for Injectors Hi Guys. John McMullen sent this to us, it's an order proposed by the AOGCC to replace the well integrity related language in the current Area Injection Orders. Listed below are comments, not sure who is coordinating getting these in front of Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few comments, but could live with the current proposed language. Note the proposed public hearing date is November 4. The following language does not reflect what the slope AOGCC inspectors are currently requiring us to do: "The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and * before* ** lof3 10/28/2004 11 :09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI Lanl è for Injectors)] returnj_ng a well to service following a workover affecting mechanical integrity." After a workover, the slope AOGCC inspectors want the well warmed up and on stable injection, then we conduct the AOGCC witnessed MITIA. This language requires the AOGCC witnessed MITrA before starting injection, which we are doing on the rig after the tubing is run. Just trying to keep language consistent with the field practice. If "after" was substituted for "before", it would reflect current AOGCC practices. It would be helpful if the following language required reporting by the "next working day" rather than "immediately", due to weekends, holidays, etc. We like to confer with the APE and get a plan finalized, this may prevent us from doing all the investigating we like to do before talking with the AOGCC. "Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall * immediately*_** notify the Commission" This section could use some helpjwordsmithing: "A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation." Report content requirements are clear, but it's a little unclear what triggers a well to be included on this monthly report. Is it wells that have been reported to the AOGCC, are currently on-line and are going through the Administrative Action process? A proposed re-write would be: "All active injection wells with well integrity failure or lack of injection zone isolation shall have the following information reported monthly to the Commission: daily tubing and casing annuli pressures, daily injection rates." Requirements for the period between when a well failure is reported and when an administrative action is approved are unclear. This document states "the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403". If we don't plan to do any corrective action, but to pursue an AA, does a 10-403 need to be submitted? The AOGCC has stated they don't consider an AA as "corrective action". Let me know if you have any questions. Joe -----Original Message----- From: Kleppin, Daryl J Sent: Wednesday, September 29, 2004 1:37 PM To: Townsend, Monte Ai Digert, Scott A¡ Denis, John R (ANC) ¡ Miller, Mike Ei McMullen, John C Subject: FW: Public Notices FYI -----Original Message----- From: Jody Colombie [ mailto:jody colombie@admin.state.ak.us Sent: Wednesday, September 29, 2004 1:01 PM Subject: Public Notices Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal. ZIP» «Mechanical Integrity of Wells Notice.doc» 2 of3 10/28/2004 11:09 AM #8 /i/.' ð 3 ) '\- -) Unocal Alast,a ñesources Union Oil Company of California 260 Caviar Street Kenai, Alaska 99611 Telephone (907) 283-7505 Alaska Oil & Gas Cons. Commission Anchorage RECEIVED AUG 2 7 2001 UNOCAL@> August 24, 2001 Ms. Cammy Taylor Commissioner Alaska Oil and Gas Conservation Commission 333 W. Seventh Avenue Suite 100 Anchorage 99501 ~\\)\-S~ RE: Request for Determination of Acceptability of Class II Injection of Contaminated Groundwater at Swanson River Field Dear Ms. Taylor, Background Sometime prior to 1988, a release of new xylene product occurred at the Swanson River field P&S Yard from a bulk product storage tank. The actual quantity of xylene released is unknown, but the resulting contamination to the soils and groundwater beneath the site was extensive. In 1991 a groundwater collection system was installed down gradient of the spill site. The collection system was designed to intercept and collect the contaminated groundwater preventing it from reaching an adjacent down gradient wetland area. After the installation of the interception trench several remediation technologies were tested on the impacted soils and underlying groundwater. The technology chosen for treating the soils was land farming. Excavated material was land farmed for two years eventually leading to the construction of six treatment ponds that cascade down through the site. The logic was that after the soils were treated the ponds would polish off any residual xylene. Unfortunately this effort was not completely successful and we are still faced with managing the contaminated groundwater. The remediation of this site is continuing and we are working closely with the U.S. Fish and Wildlife Service and the Alaska Department of Environmental Conservation. Groundwater Treatment System Groundwater is collected in the interception system continuously, all year long. During past years, all the collected groundwater was pumped to an air-sparging tank, treated, and discharged onsite in a percolation cell. This past June we began bypassing the air- . n.J <>¡¡ 0'1) ') n fill Cf("!\ \1\,~NE;-¡' 'I J ~J hI (. {, '-' ".,', \,.;')J"-~~Ir~' '\!I... \:1..,". <. '\ \ -) -) TO: Cammy Taylor AOGCC -2- August 24, 2001 sparging tank, pumping the groundwater directly into the first of the six ponds through a series of sprinklers. Although this treatment method is working very well it will not work during the winter months. This winter the groundwater will again be treated through the air sparging system. Future Remediation As mentioned above, remediation of the site is continuing. Future plans will require additional excavation and land farming of contaminated soil. The existing pond system will be destroyed in this process. Water management has been difficult in the past as all the water had to be managed through the treatment system while excavation and construction of the ponds occurred. This includes both groundwater and storm water contacting the potentially xylene contaminated soil. On August 23,2001, we met with the USF&WS and ADEC to discuss future plans. We will be gathering additional data from the site this fall and using that information to prepare a plan for the next step in the remediation effort, which we will begin next spring. Request The existing air sparging system is not capable of handling all of the groundwater at this time and is maintenance intensive due to iron fouling, which generates a waste which is typically shipped to an industrial waste landfill. The only way we can effectively treat the water with the air sparging system is by reducing the flow rate at which we remove the contaminated groundwater from the ground, which compromises our ability to meet our environmental objectives. If we could ultimately pump this water into our Class II Injection Well we could easily manage all the water from the collection system. Likewise if we were allowed to dispose of the groundwater and storm water collected during construction activities this would make our remediation efforts more effective. If the contaminated groundwater were introduced into the oil/water separation equipment of our production system then any xylene that partitioned to the oil phase would be recovered for crude oil sales. Xylene is a normal constituent of crude oil. We respectfully request permission to process the contaminated groundwater and storm water collected from the P&S Yard remediation site through our production system with subsequent injection of the water phase into the Class II Injection Well. , G (('¡ <)Df\:,'1 ,..' b"'-'"\ ~~ ~l'\:\ >~ /¡ { . L .1 e:' C" l~~ ~¡~ ~\~ t:. L) <...; I,) b \1 [; ", - f~" 'a ~_ 1,.,(. \,0 ') ') TO: Cammy Taylor AOGCC -3- August 24, 2001 Groundwater Characteristics During the past few years the concentration of xylene in the groundwater collected in the interception system range between 20 and 60 mg/L (see attached letter to Alan Kukla). Water that is currently in the ponds is much cleaner and is non-detect in most of the ponds (see attached table). A graph and table are also attached which show groundwater flow rate and total gallons pumped this summer. The average flow rate over this past summer is 8 gpm. There will be periods of time when the flow rate is significantly higher. The addition of this water to the system will have no impact on operations. Thank you for your consideration of this request. If you have any questions or need any additional information, please contact John Hammelman at (907) 283-5507 or Laura Hammond at (907) 283-5508. Sincerely, Za~+ Advising Environmental Scientist Sl;j\NNE,(¡ ,JUN 2 2 2Q[,~~ #7 ') ) Ul:1ocal A~~",ka Resources Union Oil Company of California 260 Caviar Street Kenai, Alaska 99611 Telephone (907) 283-7505 UNOCAL8 June 30, 2001 Alan Kukla State of Alaska Department Environmental Conservation 555 Cordova Street- Anchorage, Alaska 99501 Re: P&S Yard Monitoring Report 110 - Permit No. 9623-DB002 Dear Mr. Kukla: '~ ' Attached is the May 2001 monthly monitoring report for the Swanson River Field P&S Yard groundwater remediation project. If you have any questions or need any additional information, please don't hesitate to contact me at (907) 283-5507. Sincerely, 9t14..~ John Hammelman CERTIF1ED MAIL cc: J. Frates, USFWS - Soldotna U. Kelmser, Chevron B. Fisk, USBLM D. Seagren, ADEC- Soldotna J. Stout,USFWS, Anchorage File - SRFlRemediation/P&S Yard GW Monitoring U i{\' ? .., 200/1 ..J~)!J C',' /-.} . I~", #6 ~f/~~/¿~~l ~f:~~ 9072433754 OILRISK CONSULTANTS PAGE 02 ",) ) ) OilRisk Consu~nts 3527 North Point Drive }uachorage,Aùaska 99515 phone 907..248..0058 fax 907-243.·3754 JW1e 28, 2001 Unocal Corporation 260 Caviar Street Kenai, AI< 99611-7769 Attn: Mr. John .Haminelman Subject: May, 2001 monitoring results for the P & S Yard groundwater treatment system, ADEC Wastewater Disposal PennitNo. 9623-DB002 .Dear John: This letter provides the May) 2001 monitoring results for the P & S Yard' groundwater' treatment system at Swanson River Field. Monthly maintenance and sampling was perfo~ed on May 21 by David Brailey of OïiRisk. Monitoring results are listed in Table 1 and are graphed below; hardcopjes of the May, 20011aboratolyreport are attached, . , Figure 1. Influent Monitoring Results (Recent) " , '80,000 l ~ 120,000.- ð å T otilt BTEX QClnccn....tion S.polnl ""lining ave,øGø ¿ o ! i 60.000- o u iií tñ 4Q,OQO - ð. ð , A o ' I ~",-. . I . . . . . J . . . . . I . . . . . I . . . . I't . . . . . I . . . . . I . . . . . I, .0' . . . I ',~ÆI96 W197 12181Ø7 M198 1218¡'g8 8n1V9 1~J!IS 6/6¡gD 1~/.!ItoØ 6/GIOf FigUre 2. IntJuent Monitoring Results (Long Term) 250.000 - c¿ 2GO,OOO - CI :1. g ¡ 150.000 - ~ 8 ð 100,000 - U ~ Z CD A I'. A TOlal åTex coñcen,-;anon I ~ I\IMIng aYa1'B1iI1I . A o . . ~'-~r'~ . 12/7/93 1217194 12/7¡5 tlJ6lØ6 ~ 12J5JOO ~I(" i\ r,~!, ' ~ --, ~ v~.o-d ',~ ~,~ /;.... I' Jill' M q (:) ()OO' 7 I.......",...:' ',," L I¡ ~ (, '~1 t... J .~. ) OILRISK CONSULTANTS '\ ) PAGE 03 ~ ~{/~~/~~~l ~(:b~ 9072433754 \ Mr. John Hammelman JW1e 28, 2001 Page: 2 , Table 1. May, 2001 Monitoring Results ~ & S Yard Groundwater Treatment System ·I"'~-""'. ~-. . . Sample Date Benzene, Toluene, Ethyl- Xylen~, Flow Rate, µgIL µWL benzene µgIL gpd Inf1v..~nt 5/21/01 ND(200) ND(200) 1,400 4r9OO 55- ~ VÞ_··N"_-.~~~~I\-. .. April 27 to Effluent 5/21/01 ND(l) 3.30 48 190 May 21 . .. ¿,. ..N_ -~" "__ ..,... Effluent limt (pennit NO. S 500 480 200 36,000 9623.:.DB002) .... ·~__'-i._'--.''''_. Approximately 1,327 gallons o,fwater were treated betWeen ~Fil27 and May 21, 2001) at an average daily flow rate of 55 gallons per day (gpd). Effluent BTEX concentrations were below the permit 1imits shown on Table 1. '~ ' Thank you for the opp,?rtunity'to'provide these services. Please can should you have any questions. Sincerely, ~¿.~ David E. Brailey - ) OilRisk Consultants Attachments: Analytica Alaska, Inc., laboratory report dated June 14, 2001 SCAN~\H~ c' · ,. I ,rUl\:;: 2 20Cl<~ I I I 0 8/11/01 8/4/01 7/28/01 7/21/01 7/14/01 7/7/01 6/30/01 6/23/01 6/16/01 6/9/01 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I o ~t) - 200000 4 - ef', \c1 ' ~ ~-7 ;Z 2: rn c C;....., r" Z "-' /' -4l c: L - 0 E 12 - 6. - 600000 co c.. 0> C> Q) Q) 0> ........, - - co co c.. L- E ~ ~ :::s 0 6- c.. LL 8 - - 400000 - co ......, 0 I- - 800000 16 6. 1000000 . 20 - < - , . f\ e:_-i¡ {,:('l\\i\.~~\~~::r' rUM C\ ';' ':! i' '.::.)' (~,l).i 1.\ ~ "\' ,I "'t! tk:~ t: c_ L. ~,~ ~~.) ~ '1 (- . Date Datenum meter flow rate 6/6/01 14:24 37048.60 330 6/6/01 14:33 37048.61 455 12.54 6/6/01 15:05 37048.63 975 16.49 6/7/01 12:20 37049.51 11500 8.26 6/8/01 7:30 37050.31 23000 10.00 6/11/01 6:37 37053.28 75310 12.26 6/11/01 19:40 37053.82 81920 8.44 6/14/01 14:35 37056.61 118296 9.06 6/22/01 8:45 37064.36 205730 7.83 6/26/01 23:08 37068.96 249740 6.65 7/6/01 7:11 37078.30 338270 6.59 7/11/01 14:50 37083.62 390823 6.86 7/1 3/01 16: 15 37085.68 412367 7.27 7/20/01 15:37 37092.65 486910 7.42 7/25/01 16:15 37097.68 555780 9.52 7/30/01 16:28 37102.69 641425 11.87 8/9/01 19:10 37112.80, 8"15450 11.95 8.82 .~ . ') ') \, ", .. -) ) P&S Yard Pond Water Concentrations, Summer 2001 Pond Date Benzene, Toluene, Ethyl- Xylenes, Sample mg/L mg/L benzene mg/L 5/21/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) ND(0.003) Pond 6 6/14/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) ND(0.003) 6/26/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) ND(0.003) 7/20/01 pending pending pending pending 5/21/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) ND(0.003) Pond 5 6/14/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) ND(0.003) 6/26/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) ND(0.003) 7/20/01 pending pending pending pending 5/21/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) 0.0036 Pond 4 6/14/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) ND(0.003) 6/26/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) ND(0.003) 7/20/01 pending pending pending pending 5/21/01 ND(0.001 ) ND(0.001 ) 0.0025 0.066 Pond 3 6/14/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) ND(0.003) 6/26/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) ND(0.003) 7/20/01 pending pending pending pending 5/21/01 ND(0.001 ) 0.02 0.13 0.64 Pond 2 6/14/01 ND(0.001 ) ND(0.001 ) 0.0021 0.038 6/26/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) 0.0069 7/20/01 pending pending pending pending 5/21/01 ND(0.001 ) ND(0.001 ) ND(0.001 ) ND(0.003) Pond 1 6/14/01 ND(0.002) 0.0049 0.068 0.48 6/26/01 ND(0.002) 0.0029 0.022 0.17 7/20/01 pending pending pending pending ~ t', t:o,;~,!!' ......".l--..l~,H\~bC[i ,~~JM {"<, (. ~ $ ffl:.r'1'!, r \j l.. ...- ow ~ ~ ~ #5 '~ [F'~d: ethylene:glycol and flush water disposal] ';, ) ) Subject: [Fwd: ethylene glycol and flush water disposal] Date: Thu, 13 Apr 2000 15 :41 :57 -0800 From: Wendy Mahan <Wendy_Mahan@admin.state.ak.us> Organization: doa-aogcc To: Camille Oechsli <cammy _ oechsli@admin.state.ak.us> Cammy, I accidentally left you off of this email. ..., ",.".., ",......................,,,..........,,...... ...,..,.,........"......",......."..,.............,......,. Subject: ethylene glycol and flush water disposal Date: Thu, 13 Apr 2000 15:40:45 -0800 From: Wendy Mahan <Wendy_Mahan@admin.state.ak.us> Organization: doa-aogcc To: lhammond@unocal.com, Robert Christenson <robert_christenson@admin.state.ak.us>, Dan Seamount <dan _ seamount@admin.state.ak.us> Laura, Unocal has requested to dispose of 6-10,000 gallons of ethylene glycol and flush water generated in the Swanson River Field (SRF) into two Class II disposal wells, 31-33WD and 32-33WD. According to my previous conversations with you, there are 12 1000 Btu heaters at well pads or tank settings at SRF. The heaters heat flow lines (oil out) or gas lift lines (gas down) to wellheads at oil producing wells. The heaters are natural gas fired and provide a heated ethylene glycol bath surrounding the flowlines. The glycol bath is necessary to reduce hydrate formation/freezing in the flowlines. The heater systems currently hold approximately 3,000 gallons of nonhazardous ethylene glycol. An additional 3-6,000 gallons of water will be necessary to flush the lines once the glycol is drained. Unocal originally planned to send the ethylene glycol portion of the waste to a commercial facility for recycling but was told that the glycol had degraded to the point that it was no longer usable. The only Class I disposal wells in Alaska are located on the North Slope. Transporting the waste for disposal on the North Slope would create an additional spill risk as well as unnecessary air pollution and fuel usage. Unocal could also store the waste indefinitely and use it for make-up water when drilling activities resume. Storing the waste indefinitely while awaiting disposal also creates an additional spill risk. The Commissioners discussed the situation and determined that Class II injection of this nonhazardous "associated" waste is the most environmentally beneficial solution. Please feel free to call me if you have any further questions, Wendy Mahan Natural Resource Manager . 9 C\) 011")\"'" ,..,' nt\\~, r f,.! (., s,(;r\'NNtJ. d U~\\ {..'I . - I of I 4113/004:09 PM #4 ) MEMORANDUM STATE OF ALASKA TO: Well Files 31-33WD (80-114) and 32-33WD (80-115) FROM: Wendy Mahan DATE: Apri/13, 2000 RE: Unocal request to inject nonhazardous ethylene glycol waste into Class" wel/(s) at Swanson River Field !\ \C) \~ {\ I spoke to Laura Hammond on April 1 oth, 11th and 13th regarding Unocal's request to dispose of 6-10,000 gallons of ethylene glycol and flush water generated in the Swanson River Field (SRF). According to Laura, there are 12 1000 Btu heaters at well pads or tank settings at SRF. The heaters heat flow lines (oil out) or gas lift lines (gas down) to wellheads at oil producing wells. The heaters are natural gas fired and provide a heated ethylene glycol bath surrounding the flowlines. The glycol bath is necessary to reduce hydrate formation/freezing in the flowlines. The heater systems currently hold approximately 3,000 gallons of nonhazardous ethylene glycol. An additional 3-6,000 gallons of water must be used to flush the lines once the glycol is drained. Unocal originally planned to send the ethylene glycol portion of the waste to a commercial facility for recycling but was told that the glycol had degraded to the point that it was no longer usable. The only Class I disposal wells in Alaska are located on the North Slope. Transporting the waste for disposal on the North Slope would create an additional spill risk as well as unnecessary air pollution and fuel usage. Unocal could also store the waste indefinitely and use it for make-up water when drilling activities resume. Storing the waste indefinitely while awaiting disposal also creates an additional spill risk. The Commission authorized the Class II injection of this "associated" waste as the most environmentally beneficial solution. I notified Laura of the Commissioners decision on April 13, 2000. ,., ("f \"~1·,ç:rl JUN 2, 2· '/\':' 0'~. '~,'~, 'te.~,l,. . #3 · .__,..-1wJL...,_~. .,' ...~...,__.:..~~_.......'".A ''t ) ) ïONYKNOWLES.GOVERNOR ALASIiA OIL i~ GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE. ALASKA 99501 -3192 PHONE: (907) 279-1433 FAA: (907) 276-7542 October 26. 1998 Larry Greenstein Unocal Corporation Agricultural Products P.O. Box 196247 Anchorage. AK 99) 19-6247 ~\O \~C\ Re: Swanson River Pipeline Freeze Protection Dear Mr. Greenstein: This letter is in addition to e-rnail correspondence dated October 14 and 23. 1998 regarding the classification of 111ethanol used to freeze protect a pipeline in the Swanson River field. According to UnocaL several options are under consideration for disposal of produced water generated in the Swanson River tield. One of the options would entail freeze protecting a pipeline to the Class II disposal well with approximately 35 barrels of methanol in order to íàcilitate transportation and disposal of the produced water. The methanol used would be new product. for the sole purpose of keeping t1uids from tì'eezing in the pipeline. Jonathan \VilliaIns of EP A Region 10 concurs \vith our interpretation that as long as the tluid is not a listed hazardous \vaste. 111ethanol mixed in the pipeline with produced \vater and used for facilitating disposal of the produced water would beCOlue a Class II waste. Please call if you have any additional questions or concen1S. Sincerely. l \J ..1U~,:", \ \ \ 'v \ ðv'--- \ - Wendy Mahan Natural Resource:' lanager A ttachll1ent Cc: Laura Hanunond. Cnocal Jonathan \\ïllian1s. EPA Region 10 Grover Panee. EPA Region 10 ..... 1'\1.","" i~-J,.· ""]N oj ') jOD.~ ~:~~t,.i 'i.~ '\ \ \! J:: \..! "J ~, ,{, ,{,J Lr . ..,---....".- ....... , . "" .~..~~.. ............,.............u.,.a..-.....,.''''- _ ...........:..:...._~_ .RE: ~.:v~son River pipeline freeze protect t1uids-r "¡'{jRePlY ,) Subject: RE: Swanson River pipeline freeze protect tluids-reply -Reply Date: Mon~ 26 Oct 1998 08:58:53 -0800 From: "Greenstein. Larry P" <greensteinlp@,unocal.com> To: Wendy _MahanrfY,admin.state.ak.us. Ihammond@,unocal.com. "'lONA THAN \VILLlAMS'" <WILLIAMS.JONA THAN@,epamail.epa.gov.> CC: P ARTEE.GROVER@,epamail.epa.gov ~~anks f~~ ~he follow-up! ~~~s ~se of methanol as 2£ the Swanson Piver ~~jec~~c~ ~ells is bu~ one of .::::onsideri:-.g. f~eeze ;~c~ectlon ~~e op~~c~s we are - - -- ::-.e :hank YG~ again fer ::::-egula~l~ns. c ~ ear lr.l.g any possible misinterpreta~~c~ of the :::"'arry > ---------- > From: > Sen t : To: JONATHAN WILL;_~~S[SMTP:WILLIAMS.JONATHAN@epamail.epa.gov; Friday, October 23, 1998 1:02 PM ~'lendy _ Mahan@ad..rnin. sea ce. ak. us; lhammond@unocal. com > Cc: ?~TEE.GROVER@epamail.epa.gov; Greenstein, ~arry ? '> Subjec:: Swanson River _'C:'peline freeze protecc fJ..uicis-reply -_=:epJ..~' .'> ~, ~"h.anks ::::;r th.e confirmacic:: e-mail Wendy.Since~¡e.veci::::::eeverych.in:; > over c::e phone, let r:¡e quick.3..y summarize things tc be sure chat ;'Je're :5i':'':'' > talking about the same thing. > > The UlC regs narrowly constrain injection into Class lID wells to chose > fluids ;.¡hich have been "broughc to the surface in ccnnect:':'cn with ~ ~aturai qas scorage operatio~s, or conventionl Ol~ or nacural gas " produceion and may 1=e commi::q.3..ed with waste waters from gas plants ;.¡h. i cn ¿¡ re an in tegra J.. _:::a rt: 0:: _';:]roducc ion opera t ions, unless those :va cer s .c' are c i ¿¡ s s i fie d a s a .~ a z a r d 0 u s ¡.¡ a s tat the t im e 0 f i:: j e c c Lo n. " > > Additi::;ns co ehe prcduced wacer stream needed to allow i~jeccion (SO , c~at ~roduction can oent':'nue), such as a biocides, etc. are considered _~ ~e OK. 3ut mixing .:.:-: scur:: :,:.~ich hasn't been "broughc to =.~e surface" :·:icÌ: :.~e produced ;·:acer s.:..-::;:i~- ::; dispose of ic is not ~~.. , ~ ~ .. u:: ~e~ s tandi..."'J. g ~:: -:.. ,"" - -- --............. '-' :~e ~roduced wacer ~:ream :-:eeds 'Co ha ve :.~e :reeze ~roceceane. =- _~ a c -- , :.~e r"orma cion 'lIa eer is nee s :;':::ply ~einç: . . -:-.:::. ,.-, ~~ -- ..... -'" is a ::'':'2posa':'' screa::'. :::::r s:;:::e:.~ing which :·¡asn' t:: "~rouah: __ :.:e s:Jrfa'~e" , '. ~urlng pre8~ce.:.o~. " ,» We!:ci~' Mahan <01endy_:-Iaha.-:}a.i..'TIin.seace.ak.us.> 2:/2.,;/95 > 1...'5: 13[0::-::' »> > __7onachan ftVilliams ':"2':C :::e a -.-oicemail message yes[erda~: :,::'r:h EPA' s conc¡;::rence chac ::reeze ~ro=ec=ing the Swanso.1 Ri','er 'Ci;::;eli.-:e as ::- r ope 2 e ci wi c.:: I:: e c h a:-: 0 J.. i sa.:: c e p tab 1 e . ~he methanel, preci:.:.ced ¡·¡a r:er , :~ixc~=e :~ill be C~ass :: a~~ 25 such, you're free == ji52~se of :h.e Cl:::5S II~ well. é/C:;' need a::yr::-:'i:::; else, ~., -''''' !ne a shouc. SL;;\~\~ \\! if.. LI St r;'.) ') q n\ j~\.I} (} () c.~L......'.J 1 l)¡' 1 10/26/98 8:22 .~ #2 ~.~~ . '\ ooT-;19-95 THU 18:57 ,1 ) UNOCAL ASSET GAS GRP ) FAX NO. 9072637874 P.Ol/02 Unocal Corporation ' ...) 011 & Gas Operations 909 West 9th Avenue. P.'-'. b~X 196247 Anchora9Q, Ata~ka 99519.&241 Telephone (907) 276-7600 UNOCAL8 ) .-~ ~ :;""-r A·· " .' I "; October 19, 1995 Alaska RE~';;JED OCT 2 0 1995 AiaskaOil & Gas Cons. Conunission Anchoraga Mr. Bob Crandall Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Crandall: Re: Swanson Riv~r Field, State· of Alaska Clarification of Request For Hemlock Pool Expansion In support of Unocal's request in our Jetter of October 2, 1995 for the expansion of the Hemlock Oil Pool at Swanson River Field, I would like to clarify our justification for including the lower sands of the Hemlock Formation in this proposed expansion. The lower Hemlock Formation is defined as the interval between the depths of 10,585 feet and 10,815 feet (measured depth) in the Sotdotna Creek Unit 41-4 well. This interval is comprised of five sands, referred to as the H11 through H15 benches, and interlayered ·mudstones. These sands extend beneath the ·entire Soldotna Creek and Swanson River Units, however they are believed to be productive only along the crest of the structure In the Soldotna Creek Unit. In December, 1994 production was established from the H11 bench in the SCU 41A-8 well at an initial rate of 171 SOPD. By July, 1995 production had dropped to 91 SOPD. The lowermost H10 bench was perforated on July 14, 1995 and total oil production increased to 149 BOPD. The most recent test on this well indicates that it is producing at a rate of 113 SOPO. Oil recovered from the H11 bench in SCU 41 A~8 has an API gravity of 26 degrees, which is lower than the 37 degree API oil initially produced from the upper Hemlock. initial gas-oil ratios from the H11 were 1100-1500 SCFfSTB which is higher than the ~'" . , it,1i CJ¡ ~~ 2Dfìt, <:;-'.,!\ ... '. t", ~\,\\r\.¡.'. \~~."' H f~~ (, (~ _ . '- i ~vr~, '" \)þ.!,., ~" '" · l! . '~OCT ;:-19-95 THU 18: 57 UNOCAL ASSET GAS GRP ') FAX NO. 9072637874 ") P. 02/02 .~ Mr. Bob Crandall AOGCC Page No.2 )'~/.f~· original upper Hemlock solution GOR of 375 SCF/STB but much lower than the current average upper Hemlock GOR of 65,000 SCF/STB. Initial pressure in the H11 bench was 5331 psia which is similar to original upper Hemlock pressure of 5.580 psis. Lithologically, the lower Hemlock is very similar to the upper Hemlock. Both intervals appear to have been deposited by a braided stream system. The average porosity of the lower Hemlock ;s approximately 16%, slightly less than the 18% average porosity of the upper Hem1ock. Core and mudlog data indicate that both the upper and lower benches are comprised of fine to medium grained sand and conglomerate. Because it is difficult to interpret Jogs from the lower Hemlock benches. the exact depth of the oillwater contact remains poorly defined; however, it is believed to be close to the oillwater contact depth of -10,570 feet (subsea) recognized in the H10 bench. This oil/water contact will limit the productive area of the lower Hemlock sands to the crest of the structure. Average net sand thickness of the total lower Hemlock sand interval is approximately 100 feet while the thickness of the producing H11 bench averages only 10 feet. As a result of the limited area extent and thickness of the H11 bench, recoverable reserves in this one sand are expected to be approximately 700,000 STB. If additional sands in the lower Hemlock are proven to be productive this figure will increase. Recoverable reserves would also increase if gas were injected into the lower Hemlock for pressure maintenance; therefore, we also request that Area Injection Order No. 13 be modified to include the lower Hemlock interval as defined above. Thank you for your consideration of this request. and if you have any additional questions please give me a call at 263-7837. D - . :- ',." J t D \'" t.. '- \.- OC1 2. 0 \99S '\ o. Gas Cons. Cj).mmi~\9.n "\'.1~~~\\~ , ,y ~--\ 'ê1\c\iQ~9! ' Sincerely, Erik P. Graven Advanced Development Geologist cc: M.T. Morell K.A. Tabler c~" i',k~H\P;:n n i\\í 0~ 2; 200( G~v!"d'(, ,",,'Of. ~HJ!\i I" ' - #1 Unocal Corporation Oil & Gas Operations . , \ 909 West 9th Avenue, P. /196247 Anchorage, Alaska 99519-6<:::47 '1 ./ J)'~' -'1. ~ . (t' ¡t,J ~ loJ ~t.( ~ -y-> UNO CALI> ... October 2, 1995 Kevin A. Tabler Land Manager Alaska Business Unit ....., , 't, .' Mr. Bob Crandall Alaska Oil and Gas Conservation Committee 3001 Porcupine Drive Anchorage, Alaska 99501 .. .. ,:,;¡'.q ~ " IÌ C ......, (ì " .. (\ a ~- \.1 V L:. I'~. 'ì I ."o./...,\"J Alaska Oil & Gas Cons. Commission Anchorage Swanson River Unit State of Alaska Request For Hemlock Pool Expansion Dear Mr. Crandall: Pursuant to prior discussions with the Alaska Oil and Gas Conservation Commission and the Department of Interior, Bureau of land Management (BlM), Union Oil Company of California, (Unocal) (Operator of the Swanson River Unit), requests Administrative Approval under Rule 7 of Conservation Order 123 to redefine the definition of Hemlock Oil Pool (Rule 3) to include the Tyonek G Zone formation. Inasmuch as the two horizons are an extension of the same accumulation and geologically part of the same pool, future development of the Tyonek G Zone formation will be consistent with the management and development of the Hemlock Oil Pool and therefore it's appropriate to expand the Pool Definition of Rule 3 to include the interval 10,085 feet to 10,815 feet. Correlations of the expanded intervals can be extrapolated into the Standard Oil Company of California, Soldotna Creek Unit 41-4 well but are more readily identifiable in wells 43-4 (10,168' -10,920') and 41A-8 (10,116' -10,880'). As a conservation matter, reserves accessed, commingled and produced through existing wellbores will maximize production in the Unit and are reserves that economically would not otherwise be obtained if drilled on a grass roots basis. Additionally, at some point, an enhanced oil recovery program in the Tyonek G Zone is envisioned if economically viable. An immiscible gas injection program for pressure maintenance similiar to that conducted in the Hemlock would be employed utilizing the same wellbores consistent with existing Pool Rules. Early and very rough preliminary estimates of original oil in place indicate It··t" l' '^,t:;"~E~"" '~~f:l.TI~")) ~'\, 20 r ~)Îò:.;9b"'~Ô·l1 ~\1 - LI d d I\¡ {,. ¡;. _.' o!'~ Mr. Bob Crandall ) SWR-Hemlock Pool Expansion Page3 ) The "G1" interval has not yet been proven to be productive, however wireline logs and mudlogs indicate the presence of oil in this sand. Net sand thickness reaches a maximum of 32 feet in SCU 34-4 and thins to the northwest. Average pay thicknesses are estimated at 20'. Areal extent and oil-water contacts The "G2" sand extends across the entire Soldotna Creek Unit. North of the SRU 41-33 and SRU 21 A-34 wells the "G2JJ sand thins, and it pinches out entirely south of the SRU 314-27 well. This stratigraphic boundary forms the northern limit of the reservoir. The down-dip extent of the "G2" oil-water contact has not yet been identified, however mudlog shows indicate that it is similar to, or shallower than, the oil-water contact in the upper Hemlock sands. It is important to note that the oil-water contacts, and thus the areal extents, vary for different sands within the existing Hemlock pool. It is doubtful therefore that the "G" zone sands will have oil-water contacts that are identical to any single Hemlock sand, yet these "G" zone oil-water contacts are exp~cted to fall within the range exhibited by the various Hemlock sands. The "G1" sand pinches out along northeast-southwest trending line that passes near the SCU 341-4, SCU 314-4, and SCU 41A-8 wells. This stratigraphic boundary forms the northwestern limit of the "G1" reservoir. Like the "G2" sand, the oil-water contact and resulting areal extent for the "G1JJ sand has not yet been identified, however it is expected to fall within the range exhibited by the Hemlock sands. Porosity and Permeabilitv The average core permeability in the Tyonek "G" zone at Swanson River Field is 189 md. This is very similar to Hemlock permeabilities which generally range from 50-500 md. Log porosities in the "G" zone are also very similar to those in the Hemlock, averaging approximately 18%. Fluid Properties and Reservoir Pressure The fluid properties and the reservoir pressure in the Tyonek "G2" sand are almost identical to that originally found in the Hemlock in the Soldotna Creek Unit fault block. The API gravity and initial solution GOR from the "G2" sand in SCU 34-4 was 37.7 degrees API and 370 SCFlbbl respectively. This compares to initial values of 37 degrees API and 375 SCFlbbl for the Hemlock in the Soldotna Creek Unit fault block. The initial bottom hole pressure measured in SCU 34-4 was 5540 psig which is almost identical to the initial pressure of 5580 psig for the Hemlock in the Soldotna Creek Unit fault block. ~. ¡/\ ¡ 'Ii 'i~¡"-~'" PJM (¡)) ') l)orv¡ ~~;à~~ß\.I~'\1EG v I\, \J fe, ,.J L ~>t Mr. Bob Crandall ) SWR-Hemlock Pool Expansion Page2 ) approximately 15 MMSTS ~xist in the Tyonek G Zone. This estimate will be revised as information from additional wells and production history is analyzed. Recovery factors are very uncertain at this point. Due to the potential enhanced oil recovery program, we further request that the Area Injection Order No. 13 for Swanson River Field be modified to include the Tyonek G Zone. Further to our request and in support of our application, I have enclosed copies of correspondence between BlM and Unocal evidencing 8lM's encouragement and support for our proposed request. The following is provided as geologic and engineering support of this application: Geoloaic and Reservoir Justification The first documented test of Tyonek "G" zone oil production in the Swanson River Field occurred in August, 1974 from SRU 32-33. After running segregation packers, Chevron perforated and produced thé Tyonek "GB zone through a sliding sleeve. Well test records show Tyonek "G" zone production as high as 467 80PO, but by late 1976 production had declined to 42 8CPD. In 1977, SRU 32-33 was shut-in and did not produce again from the Tyonek "G" zone. In 1987, ARCO redrilled the well as SRU 32A-33 and completed it in the Hemlock only. In March 1995, Unocal perforated a stratigraphically equivalent unit, herein designated the "G2" sand, in SCU 34-4, resulting in approximately 300 SCPO production. Subsequently, the G2 sand has been perforated and produced in the following wells: SCU 12A-4, SCU 321-9, and SCU 323-4. Definition of intervals The Tyonek "G" zone is defined as the lithostratigraphic unit lying immediately above the Hemlock Formation and below the subsea depths of -10,050 feet in the SCU 34-4 well and -10,075 feet in the SCU 13-9 well. Two sandstone intervals are recognized within the "G" zone: the upper sandstone is designated as the "G1" sand and the lower sandstone is designated as the "G2" sand. Pay thickness Net pay thickness in the ClG2" sand varies from 15 feet in SCU 13-9 to 75 feet in SCU 23-4, with an average pay thickness across the Soldotna Creek Unit of approximately 40'. ~' '., l !i\.f' D-·~,·~ JHN .r. ~) 2000 ~C~\6~1\\5t:L)'~ur' I~ ,<, ~ i} r' I J\¥. Bob Crandall SWR-Hemlock Pool Expansion Page4 ) , We trust that the foregoing" supports our request for Administrative Approval and Area Injection modification for the requested action and that the Commission will approve same. Please contact the undersigned at (907) 263-7600 should you have additional questions. Enclosures Very truly yours, I '"""' j j J! '-j )l-t.t li...'_~~/~{..'t.6h /L J' Kevin A. Tabler r~, "'"' ~ ' , , t': D r-.ï..........· nrT n ,1 100:~ \,i \.1 ...' "·I~ , ...J ',J y ~~i2ska UU & Gas Cans. Commission Þ.f1Cnof2ge I,' ,¡ ~-"";I""J',~ ~¡, ~E~'¡'" ¡¡ 11\1 C)) 2 20['~ v'L..f!.'"\'\\~ ...,~, ~. ~J!\! t.. <J'''!' \' n , \: \' \, j I ',~:II ,.~A~ ~~^~$ ~Ä\/'^~ , .'L.'SH.., OIL .'NI) G.'S / (~()NSElt"I.\TION C()~I~IISSIC)N / ~1aI'Ch 12~ 1992 I _\' ~ 1\ , I , . , ~ ~ I ' . , . ~ MlTER J. HICKEL. GOVERNOR 30CU PORCuPtNe ORM: ANCHORAGE. ALASKA 9iSOt·3,i2 PHONE: (90'1) 2N-t433 TELECOPV: (901) 216-15-42 Geoffrey L_ Upson ARCa Alaska Inc_ P.O. Box 100360 Anchorage, Alaska 99510-0360 Ä\\J \~~ Re: Swanson River Field--UIC Class II Dìsposa! Dear l\tr. Upson: As pan of its ground water relnediation progralß for Swanson River Filed (SRF), ARCa Alaska Inc. (AAI) in Nove-mber 1991 requested COlnlnission approval to dispose of ground water contatninated with crude oil and produced water in SRF Class II wells. AAI proposes to recover ground water contaminated by spilled crude oil, produced water and associated downhole chen1Ìcals by cut off trench or extraction wells. The fluid will be treated at the produced water treaunent facilities at the 1-33 Tank Fann. Any free hydrocarbon fraction will be recovered and recycled, while the aqueous fraction is proposcd to be disposed of in a Class II well. '111e Comrl1ission has consulted with EPA in this matter and has detennined that the fluids proposed for disposal as described in your sublnittal are Class II fluids, and Inay be disposed by underground injection in a Class II well. If you have any question concerning this Inatter, please call me at 279-1433. I would also like to apologize for the long delay in our reply, but ùte consultation with EPA çouplcd with ongoing Commission activities delayed our response. ~ ~ LJaVll1 \V:Jö.Qnston \ Chainnan ~ cc: Don Fritz, DEC Harold Scou, EPA Joe Dygas, BL~t Dan Doshier, USF\VS Evcrt Robinson-\Vilson, USFWS ;? 2 ~~D ['/).