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Home My WebLink AboutDIO 024Irna Pro'ect ~r~ler File Covea e J 9 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. I ~ ~ ~. ~-f- Order File Identifier Organizing (done) RES AN Color Items: ~Greyscale Items: ^ Poor Quality Originals: ^ Other: o-sided II I I II ll ll ll l ll 1 1 DIGITAL DATA Diskettes, No. ^ Other, No/Type: ae,~a~~=eaea iuiuuiuuiui OVERSIZED (Scannable) ^ Maps: Other Items Scannable by a Large Scanner ~~S' OVERSIZED (Non-Scannable) ^ Logs of various kinds: NOTES: BY: Maria Project Proofing BY: Mari Date: Date: f ~ `~/ Scanning Preparation x 30 = BY: Maria Date: ~/~ ~~~ Production Scanning ^ Other:: C7 /s/ I ~ ~ I IIIIIlIlll~lll lllll / /s/ ~~ _ + =TOTAL PAGES ~ ~ _~ (Count does not include cover sheet , ~ n /s/ IUlJ'L, IIIIIIIIIIIIIIIIIII Stage 1 Page Count from Scanned File: ~~- - (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: YES _ BY: Maria Date: f ~ ~~ 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. NO /s/ ~~ NO ,iiuuuuuuuu ReScanned BY: Maria Date: /s/ Comments about this file: o~a„«e~k=a ii~~u!iiiioiiii 10!612005 Orders File Cover Page.doc INDEX DISPOSAL INJECTION ORDER #24 Nicolai Creek Unit No. 5 1) February 22, 2002 2) March 22, 2002 3) September 27, 2004 4) --------------- Application for Disposal Injection Order Notice of Hearing, ad order for ADN affidavits of publication, mailing list Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells Internal note to file • ~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Aurora ) Gas, LLC for disposal of Class II ) oil field wastes by underground ) injection in the Tyonek Formation, ) Nicolai Creek Unit No. 5, Section ) 19, T11N, R12W, S. M. ) Disposal Injection Order No. 24 Nicolai Creek Field Nicolai Creek Unit No. 5 Well June 26, 2002 IT APPEARING THAT: 1. By correspondence dated February 22, 2002, and received by the Alaska Oil and Gas Conservation Commission ("AOGCC") on February 26, 2002, Aurora Gas, LLC ("Aurora") requested authorization for a disposal order to allow the underground injection of non-hazardous Class II oil field waste fluids into the Tyonek Formation within the Nicolai Creek Unit No. 5 ("NCU #5") well bore. The NCU #5 well is located in the Nicolai Creek Field, Kenai Peninsula Borough, Alaska. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on March 22, 2002 in accordance with 20 AAC 25.540. 3. The Commission did not receive any protest or a request for a public hearing. FINDINGS: 1. Aurora is the operator of the Nicolai Creek Unit. There are no other operators within a one-quarter mile radius of the proposed disposal injection well. 2. The NCU #5 well is a vertical well within Federal lease AA-8426, which is administered by the Bureau of Land Management. Cook Inlet Region Inc. is the surface owner. 3. Aurora proposes to conduct disposal operations in the NCU #5 well between 2000' and 2550' measured depth ("MD"). Disposal Injection Order Nicolai Creek Unit No. 5 June 26, 2002 Page 2 of 6 4. There are no wells within aone-half mile radius of the NCU #5 well. 5. There are no recorded domestic water supply. wells within 5 miles of the proposed injection site. The nearest drinking water supply source is Markley's Spring, an artesian spring located in the NW %4 of Section 27, T11N, R12W, S.M., which is over 2 '/2 miles southeast of NCU #5. The closest known water well is a 120-foot deep utility water well located at the Nicolai Creek Unit No. 3 ("NCU #3") well site, about 3,230 feet to the east of the NCU #5 well. 6. The proposed disposal interval in the NCU #5 extends from 2000' to 2550' MD and true vertical depth ("TVD"), and is composed of Tyonek Formation sediments. The name Tyonek Formation is used to identify the disposal zone described in this order. 7. The lithologies in the proposed disposal zone consist of permeable very. fine to coarse-grained sandstones and conglomerates interbedded with clays and siltstones. 8. Wire line log analytical techniques, which comply with EPA recommended methods as described in "Survey of Methods to Determine Total Dissolved Solids Concentrations," (KEDA Project No. 30-956), were used to characterize formation water salinity in the NCU #5 well. Well log analysis indicates formation salinities within the proposed disposal interval are 10,000 ppm or greater. 9. Laboratory analysis of a produced water sample from equivalent or shallower sands in offset well NCU #3 yielded a value of 10,500 ppm, which confirms the well log analytical results. 10. Approximately 140 net vertical feet of sandstone are present in the proposed disposal interval. 11. The main confining zone is 80'of siltstone and mudstone located between the depths of 1840' and 1925' MD and TVD, which will prevent upward migration of injected fluids into overlying non-exempt aquifers. 12. The proposed disposal zone is confined below by over 50 net vertical feet of siltstone and approximately 90 net vertical feet of clay that lie between the depths of 2780' and 3120' MD and TVD. 13. The NCU #5 well was drilled to a depth of 8578' MD and TVD. The well was completed with 30" structural conductor from surface to a depth of 34' MD, 16" surface casing from surface to a depth of 308' MD, 10-3/4" casing from surface to 2628' MD, and 9 7/8" open hole from 2628' to 8578' MD. The original well bore was abandoned on March 7, 1972 with cement plugs in the 9 7/8" hole from 7215' to 7000' MD, 6718' to 6500' MD, 4151' to 3950' MD, 3314' to 3050' MD, 2756' to 2500'MD (into 10-3/4" casing), and at surface with a 25 sack cement plug. .. ,~~~ Disposal Injection Order Nicolai Creek Unit No. 5 June 26, 2002 Page 3 of 6 14. Aurora proposes to re-enter NCU #5, drill out the surface plug and clean out the 10-3/a" casing to a depth of 2500' MD. The well will be completed with 2 7/8" tubing and a packer at approximately 2250' MD. Perforations will be added between 2325' and 2345' MD. 15. The 10-3/4", 40.5 pound per foot ("ppf'), casing meets the requirements of AAC 252.412. 16. Aurora will test the mechanical integrity of the NCU #5 well in accordance with the requirements of 20 AAC 25.412 The surface plug will be drilled out, the casing will be cleaned, flushed, and pressure tested to 1500 psi for 30 minutes. A USIT logging tool or equivalent will be utilized to evaluate the integrity of the cement within the well bore. After running the completion packer and tubing, the casing/tubing annulus will be pressure tested to 1500 psi for 30 minutes. Pressure on the tubing/casing annulus will be monitored each day during injection operations to ensure continued mechanical integrity of the completion. 17. The disposal waste stream will consist of produced water, drilling, completion and workover fluids, drill cuttings, rig wash, mud slurries, and other Class II fluids and solids. The composition of the waste stream and constituent volumes will vary depending on drilling, workover, stimulation and maintenance activity. 18. Aurora proposes that the average daily injection volume will range from 350 to about 1,000 barrels per day (BPD") at rates ranging up to a maximum of 5 barrels per minute ("BPM"). The daily volume would depend on the number of producing wells, drilling activity and well work conducted annually. 19. At the proposed injection rates, Aurora estimates maximum surface injection pressure of 1500 pounds per square inch ("psi") under normal operating conditions. 20. A step rate test will be done after perforating the disposal interval to establish injection rate and pressure characteristics of the formation. 21. The workover, drilling and production programs are estimated to generate a maximum of 372,500 barrels of oilfield waste per year. Up to 3,725,000 barrels of waste maybe disposed over the anticipated 10-year life of the project. 22. Aurora expects fractures will be created as the disposal zone begins to plug with injected solids and waste. Fractures (or disaggregation of the clogged pores and rock matrix) provide pathways to transport waste fluids to undamaged storage volume within the disposal zone. 23. Aurora submitted fracture-model analysis results of four different fracture scenarios. The results showed that during expected operations, injected wastes would not breach the confining layers between 1840' and 1985' MD and TVD. Disposal Injection Order ~ Page 4 of 6 Nicolai Creek Unit No. 5 June 26, 2002 24. The injection pump will be continuously manned during injection operations at the NCU #5 well. The annulus pressure of the NCU #3 well will be checked and recorded prior to and after each injection cycle. CONCLUSIONS: 1. The application requirements of 20 AAC 25.252(c) have been met. 2. There are no wells within aone-half mile radius of the NCU #5 well. There are no recorded domestic water supply wells within 5 miles of the NCU #5. The nearest domestic water supply, Markley's Spring, is a surface water source that is located over 2 1/2 miles southeast of the NCU #5. 3. Waste fluids will be contained within appropriate receiving intervals by the confining lithology in the Tyonek Formation, cement isolation of the well bore and operating conditions. 4. Disposal injection operations in the NCU #5 well will be conducted at rates and pressures below those estimated to fracture the confining zone. 5. Evaluation of operational performance data and surveillance data will reasonably assure there is no fracturing of the confining zone. 6. Surveillance of disposal material, daily monitoring of operational parameters, and demonstration of mechanical integrity will reasonably ensure continued mechanical integrity of the well and that waste fluids are contained within the disposal interval. 7. Disposal injection of Class II wastes into well NCU #5 will not cause waste, jeopardize correlative rights, or impair ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT: RULE 1: Authorized Infection Strata for Disposal Injection of authorized fluids for purposes of underground disposal of oil field wastes is permitted into the Tyonek Formation between 2000' and 2550' MD in the NCU #5 well, in the Nicolai Creek Unit. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. RULE 2: Authorized Fluids Fluids authorized for injection in the NCU #5 well are: 1. produced water 2. drilling, completion and workover fluids ~~~, Disposal Injection Order Nicolai Creek Unit No. 5 June 26, 2002 Page 5 of 6 3. drilling mud 4. Norm scale 5. tank bottoms 6. rig wash 7. precipitation accumulating within containment areas 8. other fluids suitable for disposal in a Class II well and approved by the commission on a case-by-case basis. RULE 3: Demonstration of Tubing/Casing Annulus Mechanical Integrity In addition to the requirements of 20 AAC 25.252 (d), mechanical integrity of the disposal well must be demonstrated at least once every two years. RULE 4: Maximum Infection Pressure Disposal injection operations must be conducted at rates and pressures below those estimated to fracture the confining zone between 1840' and 1925' MD. The Commission may implement specific maximum injection rates and pressures by administrative action following a review of injection test data and evaluation of surveillance reports. RULE 5: Surveillance Operating parameters including disposal rate, disposal pressure, annulus pressures, step rate test results and volume of fluids and solids pumped must be monitored and reported according to requirements of 20 AAC 25.432(1). Operator will obtain a baseline temperature log and a baseline step rate test prior to initial injection. An initial report of operations must be provided after one month of injection. An annual report for the calendar year evaluating the performance of the disposal operation, including an annual MIT and step rate test, must be submitted by July 1 of each year. RULE 6: Notification of Improper Class II Infection The operator must immediately notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operators' responsibility. RULE 7: Administrative Action Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. r~ a} ;. Disposal Injection Order ~ Page 6 of 6 Nicolai Creek Unit No. 5 June 26, 2002 RULE 8: Other Conditions Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless specifically superseded by Commission order. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order may result in the revocation or suspension of this authorization. DONE at Anchorage, Alaska and dated June 26, 2002. ,~ ~'~:~ ~ ®~ ~~ Cammy Oe hsli Taylor, Ch ' Alaska Oil and s Conservation Commission Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e, 10th day after the application for rehearing was filed). ._ (. ' • ~ 4~''~Z NY PUBLIC LIBRARY DIV E, GRAND OFFICE OF THE GOVERNOR, ARENT FOX KINTNER PLOTKIN KAHN, CENTRAL STATION JOHN KATZ STE 518 LIBRARY P O BOX 2221 444 N CAPITOL NW WASHINGTON SO BLDG NEW YORK, NY 10163-2221 WASHINGTON, DC 20001 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 US MIN MGMT SERV, CHIEF OCS LIBRARY OF CONGRESS, STATE U S DEPT OF ENERGY, STATS & INFO DOCUMENT SECTION PHYLLIS MARTIN MS E1823 381 ELDEN ST MS 4022 EXCH & GIFT DIV 1000 INDEPENDENCE SW HERNDON, VA 20170-4817 10 FIRST ST SE WASHINGTON, DC 20585 WASHINGTON, DC 20540 TECHSYS CORP, US GEOLOGICAL SURVEY, LIBRARY DPC, BRANDY KERNS NATIONAL CTR MS 950 DANIEL DONKEL PO BOX 8485 RESTON, VA 22092 2121 NORTH BAYSHORE DR #616 GATHERSBURG, MD 20898 MIAMI, FL 33137 SD DEPT OF ENV & NATRL BP EXPLORATION (ALASKA), INC., ILLINOIS STATE GEOL SURV, LIBRARY RESOURCES, OIL & GAS PROGRAM LIBRARY/INFO CTR 469 NATURAL RESOURCES BLDG 2050 W MAIN STE #1 P O BOX 87703 615 E PEABODY DR RAPID CITY, SD 57702 CHICAGO, iL 60680-0703 CHAMPAIGN, IL 61820 LINDA HALL LIBRARY, SERIALS DEPT UNIV OF ARKANSAS, SERIALS DEPT 5109 CHERRY ST ALFRED JAMES III UNIV LIBRARIES KANSAS CITY, MO 64110-2498 107 N MARKET STE 1000 FAYETTEVILLE, AR 72701 WICHITA, KS 67202-1811 IOGCC, OIL & GAS JOURNAL, P O BOX 53127 R E MCMILLEN CONSULT GEOL LAURA BELL OKLAHOMA CITY, OK 73152-3127 202E 16TH ST P O BOX 1260 OWASSO, OK 74055-4905 TULSA, OK 74101 US DEPT OF ENERGY, ENERGY DEGOLYER & MACNAUGHTON, BAPI RAJU INFORMATION ADMINISTRATION MIDCONTINENT DIVISION 335 PINYON LN MIR YOUSUFUDDIN ONE ENERGY SO, STE 400 COPPELL, TX 75019 1999 BRYAN STREET STE 1110 4925 GREENVILLE AVE DALLAS, TX 75201-6801 DALLAS, TX 75206-4083 STANDARD AMERICAN OIL CO, XTO ENERGY, SHELL WESTERN E&P INC, AL GRIFFITH MARY JONES G.S. NADY P O BOX 370 810 HOUSTON ST STE 2000 P O BOX 576 GRANBURY, TX 76048 FORT WORTH, TX 76102-6298 HOUSTON, TX 77001-0574 H J GRUY, PURVIN & GERTZ INC, LIBRARY , ROBERT RASOR 2150 TEXAS COMMERCE TWR RAY TYSON 333 CLAY STREET SUITE 3850 600 TRAVIS ST 2016 MAIN #1415 HOUSTON, TX 77002 HOUSTON, TX 77002-2979 HOUSTON, TX 77002-8844 CHEVRON, OIL & GAS JOURNAL, PETRAL CONSULTING CO, PAUL WALKER BOB WILLIAMS DANIEL L LIPPE 1301 MCKINNEY RM 1750 1700 W LOOP SOUTH STE 1000 9800 RICHMOND STE 505 HOUSTON, TX 77010 HOUSTON, TX 77027 HOUSTON, TX 77042 AURORA GAS, GAFFNEY, CLINE & ASSOC., INC., MARATHON OIL COMPANY, G. SCOTT PFOFF LIBRARY WILLIAM R HOLTON, JR. 10333 RICHMOND AVENUE, STE 710 1360 POST OAK BLVD., STE 2500 5555 SAN FELIPE STREET SUITE 2511 HOUSTON, TX 77042 HOUSTON, TX 77056 HOUSTON, TX 77056-2799 UNOCAL, REVENUE ACCOUNTING EXXON EXPLORATION CO., MARK ALEXANDER P O BOX 4531 T E ALFORD 7502 ALCOMITA HOUSTON, TX 77210-4531 P O BOX 4778 HOUSTON, TX 77083 HOUSTON, TX 77210-4778 EXXON EXPLOR CO, TEXACO EXPLORATION & CHEVRON USA INC., ALASKA DIVISION LAND/REGULATORY AFFAIRS RM 301 PRODUCTION INC, ATTN: CORRY WOOLINGTON P O BOX 4778 CORRY WOOLINGTON P O BOX 1635 HOUSTON, TX 77210-4778 PO BOX 36366 HOUSTON, TX 77251 HOUSTON, TX 77236 PETR INFO, PHILLIPS PETROLEUM COMPANY, WORLD OIL, DAVID PHILLIPS W ALLEN HUCKABAY DONNA WILLIAMS P O BOX 1702 PO BOX 1967 P O BOX 2608 HOUSTON, TX 77251-1702 HOUSTON, TX 77251-1967 HOUSTON, TX 77252 EXXONMOBIL PRODUCTION PENNZOIL E&P, CHEVRON CHEM CO, LIBRARY & INFO COMPANY, WILL D MCCROCKLIN CTR J W KIKER ROOM 2086 P O BOX 2967 P O BOX 2100 P O BOX 2180 HOUSTON, TX 77252-2967 HOUSTON, TX 77252-9987 HOUSTON, TX 77252-2180 MARATHON OIL COMPANY, ACE PETROLEUM COMPANY, , NORMA L. CALVERT ANDREW C CLIFFORD WATTY STRICKLAND P O BOX 3128, Ste 3915 PO BOX 79593 2803 SANCTUARY CV HOUSTON, TX 77253-3128 HOUSTON, TX 77279-9593 KATY, TX 77450-8510 TESORO PETR CORP, INTL OIL SCOUTS, LOIS DOWNS JIM WHITE MASON MAP SERV INC 300 CONCORD PLAZA DRIVE 4614 BOHILL P O BOX 338 SAN ANTONIO, TX 78216-6999 SAN ANTONIO, TX 78217 AUSTIN, TX 78767 XTO ENERGY, BABCOCK & BROWN ENERGY, INC., , DOUG SCHULTZE 350 INTERLOCKEN BLVD STE 290 ROBERT G GRAVELY 3000 N GARFIELD SUITE 175 BROOMFIELD, CO 80021 7681 S KIT CARSON DR MIDLAND, TX 79705 LITTLETON, CO 80122 US GEOLOGICAL SURVEY, LIBRARY DIANE SUCHOMEL GEORGE G NAUGHT JR BOX 25046 MS 914 10507D W MAPLEWOOD DR P O BOX 13557 DENVER, CO 80225-0046 LITTLETON, CO 80127 DENVER, CO 80201 C & R INDUSTRIES, INC.,, NRG ASSOC, KURT SALTSGAVER JERRY HODGDEN GEOL RICHARD NEHRING 7500 W MISSISSIPPI AVE STE C4 408 18TH ST P O BOX 1655 LAKEWOOD, CO 80226-4541 GOLDEN, CO 80401 COLORADO SPRINGS, CO 80901- 1655 _. .. ~ , --- ~ a_ ~~L ~ RUBICON PETROLEUM, LLC, PLAYER GAS CO., BRUCE I CLARDY JOHN A LEVORSEN GARY PLAYER SIX PINE ROAD 200 N 3RD ST #1202 1671 WEST 546 S COLORADO SPRINGS, CO 80906 BOISE, ID 83702 CEDER CITY, UT 84720 US GEOLOGICAL SURVEY, LIBRARY MUNGER OIL INFOR SERV INC, BABSON & SHEPPARD, 2255 N GEMINI DR P O BOX 45738 JOHN F BERGOUIST FLAGSTAFF, AZ 86001-1698 LOS ANGELES, CA 90045-0738 P O BOX 8279 VIKING STN LONG BEACH, CA 90808-0279 , ORO NEGRO, INC., US GEOLOGICAL SURVEY, ANTONIO MADRID 9321 MELVIN AVE KEN BIRD P O BOX 94625 NORTHRIDGE, CA 91324-2410 345 MIDDLEFIELD RD MS 999 PASADENA, CA 91109 MENLO PARK, CA 94025 SHIELDS LIBRARY, GOVT DOCS DEPT ECONOMIC INSIGHT INC, UNIV OF CALIF H L WANGENHEIM SAM VAN VACTOR DAVIS, CA 95616 5430 SAWMILL RD SP 11 P O BOX 683 PARADISE, CA 95969-5969 PORTLAND, OR 97207 US EPA REGION 10, MARPLES BUSINESS NEWSLETTER, STATE PIPELINE OFFICE, LIBRARY THOR CUTLER OW-137 MICHAEL J PARKS KATE MUNSON 1200 SIXTH AVE 117 W MERCER ST STE 200 411 W 4TH AVE, STE 2 SEATTLE, WA 98101 SEATTLE, WA 98119-3960 ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, DEPT OF REVENUE, , 1026 W. 4th Ave, Ste 201 BEVERLY MAROUART DUSTY RHODES ANCHORAGE, AK 99501 550 W 7TH AV STE 570 229 WHITNEY RD ANCHORAGE, AK 99501 ANCHORAGE, AK 99501 GUESS & RUDD, DEPT OF REVENUE, OIL & GAS AUDIT FOREST OIL, GEORGE LYLE DENISE HAWES JIM ARLINGTON 510 L ST, STE 700 550 W 7TH AV STE 570 310 K STREET STE 700 ANCHORAGE, AK 99501 ANCHORAGE, AK 99501 ANCHORAGE, AK 99501 FAIRWEATHER, DEPT OF REVENUE, AURORA GAS, DUANE VAAGEN CHUCK LOGSTON J. EDWARD JONES 715 L STREET STE 7 550 W 7TH AVE, SUITE 500 1029 W 3RD AVE, STE 220 ANCHORAGE, AK 99501 ANCHORAGE, AK 99501 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DEPT OF REVENUE, , DIV OF ENVIRONMENTAL HEALTH DAN DICKINSON, DIRECTOR CAMMY TAYLOR JANICE ADAIR 550 W 7TH AVE, SUITE 500 1333 W 11TH AVE 555 CORDOVA STREET ANCHORAGE, AK 99501 ANCHORAGE, AK 99501 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, PRESTON GATES ELLIS LLP, LIBRARY ALASKA DEPT OF LAW, DIV OF AIR & WATER QUALITY 420 L ST STE 400 ROBERT E MINTZ ASST ATTY GEN TOM CHAPPLE ANCHORAGE, AK 99501-1937 1031 W 4TH AV STE 200 555 CORDOVA STREET ANCHORAGE, AK 99501-1994 ANCHORAGE, AK 99501 .. ,,. ._ ,` `~ `3.`j ' - .~~. r!.,.. . GAFO, GREENPEACE DEPT OF NATURAL RESOURCES, DIV DEPT OF REVENUE, OIL &GAS AUDIT PAMELA MILLER OF OIL &GAS FRANK PARR 125 CHRISTENSEN DR. #2 TIM RYHERD 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-2101 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3540 ANCHORAGE, AK 99501-3510 DEPT OF NATURAL RESOURCES, DIV DEPT OF NATURAL RESOURCES, DIV DEPT OF NATURAL RESOURCES, DIV OF OIL&GAS OF OIL&GAS OIL&GAS JIM STOUFFER JULIE HOULE WILLIAM VAN DYKE 550 W 7TH AVE, SUITE 800 550 W 7TH AVE, SUITE 800 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 ANCHORAGE, AK 99501-3560 ANCHORAGE, AK 99501-3560 DNR, DIV OF OIL &GAS DEPT OF NATURAL RESOURCES, DIV ALASKA JOURNAL OF COMMERCE, JAMES B HAYNES NATURAL RESRCE OF OIL &GAS ED BENNETT MGR BRUCE WEBB 2000 INTL AIRPORT W #A10 550 W 7TH AVE, SUITE 800 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99502 ANCHORAGE, AK 99501-3560 ANCHORAGE, AK 99501-3560 AK JOURNAL OF COMMERCE, OIL & YUKON PACIFIC CORP, BAKER OIL TOOLS, ALASKA AREA INDUSTRY NEWS 1400 W BENSON BLVD STE 525 MGR ROSE RAGSDALE ANCHORAGE, AK 99503 4710 BUS PK BLVD STE 36 2000 INTL AIRPORT RD W #A10 ANCHORAGE, AK 99503 ANCHORAGE, AK 99502 ANADARKO, HDR ALASKA INC, N-I TUBULARS INC, MARK HANLEY MARK DALTON 3301 C Street Ste 209 3201 C STREET STE 603 2525 C ST STE 305 ANCHORAGE, AK 99503 ANCHORAGE, AK 99503 ANCHORAGE, AK 99503 ALASKA OIL &GAS ASSOC, ANADRILL-SCHLUMBERGER, FINK ENVIRONMENTAL CONSULTING, JUDY BRADY 3940 ARCTIC BLVD #300 INC., 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-5711 THOMAS FINK, PHD ANCHORAGE, AK 99503-2035 6359 COLLATE DR. ANCHORAGE, AK 99504-3305 US BUREAU OF LAND MNGMNT, ARLEN EHM GEOL CONSLTNT JAMES E EASON ANCHORAGE DIST OFC 2420 FOXHALL DR 8611 LEEPER CIRCLE DICK POLAND ANCHORAGE, AK 99504-3342 ANCHORAGE, AK 99504-4209 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 BUREAU OF LAND MANAGEMENT, AMERICA/CANADIAN STRATIGRPH CO, US BUREAU OF LAND MNGMNT, GREG NOBLE RON BROCKWAY ANCHORAGE DIST OFC 6881 ABBOTT LOOP ROAD 4800 KUPREANOF PETER J DITTON ANCHORAGE, AK 99507 ANCHORAGE, AK 99507 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 US BLM AK DIST OFC, GEOLOGIST UOA/ ANCHORAGE, INST OF SOCIAL ARTHUR BANET THOMAS R MARSHALL JR & ECON RESEARCH 949 EAST 36TH AVE STE 308 1569 BIRCHWOOD ST TERESA HULL ANCHORAGE, AK 99508 ANCHORAGE, AK 99508 3211 PROVIDENCE DR ANCHORAGE, AK 99508 VECO ALASKA INC., TRADING BAY ENERGY CORP, ROSE RAGSDALE CHUCK O'DONNELL PAUL CRAIG 3320 EAST 41ST AVENUE 949 EAST 36TH AVENUE 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 ANCHORAGE, AK 99508 ANCHORAGE, AK 99508 } , {. , .. ~., - US MIN MGMT SERV, US MIN MGMT SERV, AK OCS US MIN MGMT SERV, RESOURCE RICHARD PRENTKI REGIONAL DIR STUDIES AK OCS REGN 949E 36TH AV 949E 36TH AV RM 110 KIRK W SHERWOOD ANCHORAGE, AK 99508-4302 ANCHORAGE, AK 99508-4302 949E 36TH AV RM 603 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, REGIONAL SUPRVISOR, FIELD GORDON J. SEVERSON FRANK MILLER .OPERATION, MMS 3201 WESTMAR CIR 949E 36TH AV STE 603 ALASKA OCS REGION ANCHORAGE, AK 99508-4336 ANCHORAGE, AK 99508-4363 949E 36TH AV STE 308 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, RESOURCE US MIN MGMT SERV, LIBRARY , EVAL 949E 36TH AV RM 603 JOHN MILLER JIM SCHERR ANCHORAGE, AK 99508-4363 3445 FORDHAM DR 949E 36TH AV RM 603 ANCHORAGE, AK 99508-4555 ANCHORAGE, AK 99508-4363 USGS -ALASKA SECTION, LIBRARY CIRI, LAND DEPT PHILLIPS ALASKA INC., LAND 4200 UNIVERSITY DR P O BOX 93330 MANAGER ANCHORAGE, AK 99508-4667 ANCHORAGE, AK 99509-3330 JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 PHILLIPS ALASKA INC., PHILLIPS ALASKA INC., LAND DEPT PHILLIPS ALASKA INC., MARK MAJOR ATO 1968 JAMES WINEGARNER STEVE BENZLER ATO 1404 P O BOX 100360 P O BOX 10036 P O BOX 100360 ANCHORAGE, AK 99510-0360 ANCHORAGE, AK 99510-0360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA INC., LEGAL DEPT PHILLIPS ALASKA INC., PETROLEUM INFO CORP, MARK P WORCESTER JOANN GRUBER ATO 712 KRISTEN NELSON P O BOX 100360 P O BOX 100360 P O BOX 102278 ANCHORAGE, AK 99510-0360 ANCHORAGE, AK 99510-0360 ANCHORAGE, AK 99510-2278 PHILLIPS ALASKA INC., KUP CENTRAL ALYESKA PIPELINE SERV CO, ALYESKA PIPELINE SERV CO, LEGAL WELLS ST TSTNG PERRY A MARKLEY DEPT WELL ENG TECH NSK 69 1835 S BRAGAW - MS 575 1835 S BRAGAW P O BOX 196105 ANCHORAGE, AK 99512 ANCHORAGE, AK 99512-0099 ANCHORAGE, AK 99510-6105 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR DAVID W. JOHNSTON LINDA BERG MICHAEL CAREY 320 MARINER DR. 4210 FRONTIER LANE P O BOX 149001 ANCHORAGE, AK 99515 ANCHORAGE, AK 99516 ANCHORAGE, AK 99514 JWL ENGINEERING, NORTHERN CONSULTING GROUP, , JEFF LIPSCOMB ROBERT BRITCH, P.E. GERALD GANOPOLE CONSULT GEOL 9921 MAIN TREE DR. 2454 TELEQUANA DR. 2536 ARLINGTON ANCHORAGE, AK 99516-6510 ANCHORAGE, AK 99517 ANCHORAGE, AK 99517-1303 ASRG , CONRAD BAGNE DAVID CUSATO ARMAND SPIELMAN 301 ARCTIC SLOPE AV STE 300 600 W 76TH AV #508 651 HILANDER CIRCLE ANCHORAGE, AK 99518 ANCHORAGE, AK 99518 ANCHORAGE, AK 99518 ..fir, • • HALLIBURTON ENERGY SERV, TESORO ALASKA COMPANY, OPSTAD & ASSOC, MARK WEDMAN PO BOX 196272 ERIK A OPSTAD PROF GEOL 6900 ARCTIC BLVD ANCHORAGE, AK 99519 P O BOX 190754 ANCHORAGE, AK 99518-2146 ANCHORAGE, AK 99519 ENSTAR NATURAL GAS CO, MARATHON OIL COMPANY, JACK O HAKKILA PRESIDENT OPERATIONS SUPT P O BOX 190083 TONY IZZO W.C. BARRON ANCHORAGE, AK 99519-0083 P O BOX 190288 P O BOX 196168 ANCHORAGE, AK 99519-0288 ANCHORAGE, AK 99519-6168 MARATHON OIL COMPANY, LAND UNOCAL, UNOCAL, BROCK RIDDLE P O BOX 196247 KEVIN TABLER P O BOX 196168 ANCHORAGE, AK 99519-6247 P O BOX 196247 ANCHORAGE, AK 99519-6168 ANCHORAGE, AK 99519-6247 EXXONMOBIL PRODUCTION BP EXPLORATION (ALASKA), INC., BP EXPLORATION (ALASKA) INC, COMPANY, MARK BERLINGER MB 8-1 PETE ZSELECZKY LAND MGR MARK P EVANS PO BOX 196612 P O BOX 196612 PO BOX 196601 ANCHORAGE, AK 99519-6612 ANCHORAGE, AK 99519-6612 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA) INC, INFO BP EXPLORATION (ALASKA) INC, BP EXPLORATION (ALASKA) INC, RESOURCE CTR MB 3-2 MR. DAVIS, ESQ SUE MILLER P O BOX 196612 P O BOX 196612 MB 13-5 P O BOX 196612 M/S LR2-3 ANCHORAGE, AK 99519-6612 ANCHORAGE, AK 99519-6612 ANCHORAGE, AK 99519-6612 AMSI/VALLEE CO INC, PINNACLE, , WILLIAM O VALLEE PRES STEVE TYLER L G POST O&G LAND MGMT CONSULT PO BOX 243086 20231 REVERE CIRCLE 10510 Constitution Circle ANCHORAGE, AK 99524-3086 EAGLE RIVER, AK 99577 EAGLE RIVER, AK 99577 D A PLATT & ASSOC, DEPT OF NATURAL RESOURCES, 9852 LITTLE DIOMEDE CIR JAMES RODERICK DGGS EAGLE RIVER, AK 99577 PO BOX 770471 JOHN REEDER EAGLE RIVER, AK 99577-0471 P O BOX 772805 EAGLE RIVER, AK 99577-2805 COOK INLET KEEPER, PHILLIPS PETROLEUM CO, ALASKA , BOB SHAVELSON OPERATIONS MANAGER RON DOLCHOK PO BOX 3269 J W KONST P O BOX 83 HOMER, AK 99603 P O DRAWER 66 KENAI, AK 99611 KENAI, AK 99611 DOCUMENT SERVICE CO, KENAI PENINSULA BOROUGH, , JOHN PARKER ECONOMIC DEVEL DISTR NANCY LORD P O BOX 1468 STAN STEADMAN PO BOX 558 KENAI, AK 99611-1468 P O BOX 3029 HOMER, AK 99623 KENAI, AK 99611-3029 BELOWICH, , PENNY VADLA MICHAEL A BELOWICH JAMES GIBBS P O BOX 467 1125 SNOW HILL AVE P O BOX 1597 NINILCHIK, AK 99639 WASILLA, AK 99654-5751 SOLDOTNA, AK 99669 ;' (~ ~ ~~ ~' 1 PACE, KENAI NATL WILDLIFE REFUGE, VALDEZ PIONEER, SHEILA DICKSON REFUGE MGR P O BOX 367 P O BOX 2018 P O BOX 2139 VALDEZ, AK 99686 SOLDOTNA, AK 99669 SOLDOTNA, AK 99669-2139 ALYESKA PIPELINE SERVICE CO, VALDEZ VANGUARD, EDITOR EVERGREEN WELL SERVICE CO., VALDEZ CORP AFFAIRS P O BOX 98 JOHN TANIGAWA SANDY MCCLINTOCK VALDEZ, AK 99686-0098 PO BOX 871845 P O BOX 300 MS/701 WASILLA, AK 99687 VALDEZ, AK 99686 UNIV OF ALASKA FAIRBANKS, PETR COOK AND HAUGEBERG, NICK STEPOVICH DEVEL LAB JAMES DIERINGER, JR. 543 2ND AVE DR V A KAMATH 119 NORTH CUSHMAN, STE 300 FAIRBANKS, AK 99701 427 DUCKERING FAIRBANKS, AK 99701 FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, , RICK WAGNER KATE RIPLEY C BURGLIN P O BOX 60868 P O BOX 70710 P O BOX 131 FAIRBANKS, AK 99706 FAIRBANKS, AK 99707 FAIRBANKS, AK 99707 DEPT OF NATURAL RESOURCES, DIV K&K RECYCL INC, ASRC, OF LAND P O BOX 58055 BILL THOMAS REG MGR NORTHERN REGION FAIRBANKS, AK 99711 P O BOX 129 3700 AIRPORT WAY BARROW, AK 99723 FAIRBANKS, AK 99709-4699 UNIV OF ALASKA FBX, PETR DEVEL UNIVERSITY OF ALASKA FBKS, PETR RICHARD FINEBERG LAB DEVEL LAB P O BOX 416 SHIRISH PATIL DR AKANNI LAWAL ESTER, AK 99725 437 DICKERING P O BOX 755880 FAIRBANKS, AK 99775 FAIRBANKS, AK 99775-5880 DEPT OF ENVIRON CONSERV SPAR, SENATOR LOREN LEMAN CHRIS PACE STATE CAPITOL RM 113 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1182 JUNEAU, AK 99801-1795 (~uAne, Uaaa~en , ~~irw¢a~he-~ ~Ld ~on~j, (~,u,rarQ Cgs 1 ~,~~~ ~; ` ~'.::~ ~ 4 A~~) i • Xv 4 r ~ ~ e R ~'R ~{ ', ,~ .. _. 1 G r~ ~ / ~~ d(r~ ~~J ~ 55 ~' ~~ h~v~c ~- ~ ~ .. CAS c~ C--~Cs~S~, ~ ~ ~t~: ` ~ ~ ~~ ~~~. v~ ~ d~'_ ~~~~ r ~/ -~ ~ e P ~~ ~ c ~ ~ `~°~ 3 ; c ,, ~K'1 2 of 2 f/~T1~. 3-PM ~3 • • j ti /. I +~~ i 1 , ;,''r~~; ~ j ~ ~ ',, i ~ ~ ~~~ ~. ~~~ ,~~ ~~,~ ~+- ~+ ~~ FRANK H. MURKOWSKI, GOVERNOR I ~~~~ ~~~~ss ~t~T~ /'t~~+ f ~/[>•-7~ OIL oisi~+l~+t]r~a7 ?+ 333 W. 7"' AVENUE, SUITE 100 COI~TSERVATIOI~T COhiI~IISSIOI~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 ' FAX (907) 27&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 mechanical 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 no 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 of 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 Form 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 isolation. • • 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. Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" Area In'ection Orders AIO 1 -Duck Island Unit 6 7 9 AIO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, Ugnu, West Sak 6 ~ 9 Fields AIO 3 -Prudhoe Bay Unit; Western Operating Area 6 ~ 9 AIO 4C -Prudhoe Bay Unit; Eastern Operating Area 6 ~ 9 AIO 5 -Trading Bay Unit; McArthur River Field 6 6 9 AIO 6 -Granite Point Field; Northern Portion 6 ~ 9 AIO 7 -Middle Ground Shoal; Northern Portion 6 ~ 9 AIO 8 -Middle Ground Shoal; Southern Portion 6 ~ 9 AIO 9 -Middle Ground Shoal; Central Portion 6 ~ 9 AIO 1 OB -Milne Point Unit; Schrader Bluff, Sag River, 4 5 8 Kuparuk River Pools AIO 11 -Granite Point Field; Southern Portion 5 6 8 AIO 12 -Trading Bay Field; Southern Portion 5 6 8 AIO 13A -Swanson River Unit 6 ~ 9 AIO 14A -Prudhoe Bay Unit; Niakuk Oil Pool 4 5 8 AIO 15 -West McArthur 5 6 9 • L Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" River Unit AIO 16 - Kuparuk River Unit; Tarn Oil Pool 6 7 10 AIO 17 - Badami Unit 5 6 8 AIO 18A -Colville River Unit; Alpine Oil Pool 6 7 11 AIO 19 -Duck Island Unit; Eider Oil Pool 5 6 9 AIO 20 -Prudhoe Bay Unit; Midni ht Sun Oil Pool 5 6 9 AIO 21 - Kuparuk River Unit; Meltwater Oil Pool 4 No rule 6 AIO 22C -Prudhoe Bay Unit; Aurora Oil Pool 5 No rule 8 AIO 23 - Northstar Unit 5 6 9 AIO 24 -Prudhoe Bay Unit; Borealis Oil Pool 5 No rule 9 AIO 25 -Prudhoe Bay Unit; Polaris Oil Pool 6 g 13 AIO 26 -Prudhoe Bay Unit; Orion Oil Pool 6 No rule 13 Dis osal In'ection Orders DIO 1 -Kenai Unit; KU WD-1 No rule No rule No rule DIO 2 -Kenai Unit; KU 14- 4 No rule No rule No rule DIO 3 -Beluga River Gas Field; BR WD-1 No rule No rule No rule DIO 4 -Beaver Creek Unit; BC-2 No rule No rule No rule DIO 5 -Barrow Gas Field; South Barrow #5 No rule No rule No rule DIO 6 -Lewis River Gas Field; WD-1 No rule No rule 3 DIO 7 -West McArthur River Unit; WMRU D-1 2 3 5 DIO 8 -Beaver Creek Unit; BC-3 2 3 5 DIO 9 -Kenai Unit; KU 11- 17 2 3 4 DIO 10 -Granite Point Field; GP 44-11 2 3 5 • Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" DIO 1 I -Kenai Unit; KU 24-7 2 3 4 DIO 12 - Badami Unit; WD- l, WD-2 2 3 5 DIO 13 -North Trading Bay Unit; S-4 2 3 6 DIO 14 -Houston Gas Field; Well #3 2 3 5 DIO 15 -North Trading Bay Unit; S-5 2 3 Rule not numbered DIO 16 -West McArthur River Unit; WMRU 4D 2 3 5 DIO 17 -North Cook Inlet Unit; NCIU A-12 2 3 6 DIO 19 -Granite Point Field; W. Granite Point State 3 4 6 17587 #3 DIO 20 -Pioneer Unit; Well 1702-15DA WDW 3 4 6 DIO 21 - Flaxman Island; Alaska State A-2 3 4 7 DIO 22 -Redoubt Unit; RU D1 3 No rule 6 DIO 23 -Ivan River Unit; IRU 14-31 No rule No rule 6 DIO 24 - Nicolai Creek Unit; NCU #5 Order expired DIO 25 -Sterling Unit; SU 43-9 3 4 7 DIO 26 - Kustatan Field; KF 1 3 4 7 Storage Injection Orders SIO 1 -Prudhoe Bay Unit, Point McIntyre Field #6 No rule No rule No rule SIO 2A- Swanson River Unit; KGSF #1 2 No rule 6 SIO 3 -Swanson River Unit; KGSF #2 2 No rule 7 Enhanced Reeove In'ection Orders EIO 1 -Prudhoe Bay Unit; Prudhoe Bay Field, Schrader No rule No rule 8 Bluff Formation Well V-105 • Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" EIO 2 -Redoubt Unit; RU-6 5 g g 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF AO-02 514016 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEEBOTTf3M FOR INVOICEADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7th Avenue, Suite 100 ° Anchorage, AK 99501 PHONE Pc "' 907-793-1221 07 79 1 1 T Journal of Commerce 0 301 Arctic Slope Ave #350 Anchorage, AK 99518 ~ ~ - DATES ADVERTISEMENT REQC[RED: October 3, 2004 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWY. SPECIAL INSTRCCTIONS: AFFIDAVIT OF PUBLICATION United states of America State of ss division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she 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, REMINDER INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED W ITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE Notary public for state of My commission expires Public Notices ~ • Subject: Public Notices From: Jody Colombie <jody colombie@admin.state.ak,us> Date: Wed, 29 Sep 2004 13:01:04 -0800 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, AngeIa Webb <ange_webb@admin.state.ak,us>, Robert E Mintz <rober-t mintz(~~?la~~.state.ak.us%, Christine Hansen <e.hansen@iogce.state.ok.us>, Ten-ie Hobble <nubblctl~u%bp.com>, Sondra Stedman <StewmaSD@BP.com>, Scott & Cammy Taylor cstaylar@alaska.net~, stanekj <stanekj@unocal.com>, ecalaw <ecolaw@trustees.org>, roseragsdale <roseragsdale@gci.net>, trmjrl ~trmjrl@aol.com>, jbriddle <jbriddle@marathonoil.com>, roekliill =rockhill (l;aoga.org>, shaneg <shaneg@evergreengas;corn>, jdarington <jdarlington a?forestoil.com=, nelson <knelson@petroleumnews.corri>, cboddy <eboddy@usibelli.com>, 1V1ark Dalton <mark.daiton@hdi'inc.com>, Shannon Dannelly <shannon.donnellv(~i~conocophillps.com ~, "Mark P. Worcester" <markp.worcester@conocophilt'ips.com>, "Jerry G: Dethlels" <ferry.c.dethlefs@eonacaphillips_eom>, Bob <bob@inletkeeper.org>, «-d~ ~ wd~•r~t.dnr.state.ak.rts>, tjr <tjr@dnr:state.ak.u;==-, bbritch <bbritch@alaska.net>, tnjnelson <mjnelson/apur<<inger-tz.com>, Charles O'Donnell``<chafles.o'donnell{a?veco.corn>, "Randy L. Skillern" °'SkilleRL@BP.eom> "Deborah J. 3ones°<JonesD6@BP.co~>, "Paul G. Hyatt" <hy~ttpg~a BP.com=, *'Ste~-en,R. Rassberg" <RossbeRS@BP.com>, Lois <lois@nletkeeper.org>, Dan Bross <kuacne~~~s(a;;kuac.org>, Gordon Pospisil <Po,spisG~a BP.eom>, ":Francis S. Sommer" <SammerF~«BP.com=~ ~Tikel Schultz <Mikel.Schultz@BP.cc>m>, '*Nick W. Glover" <GloverNW~ci BP.com>. "Daryl J. Kleppin" <KleppiDE@BP.com'~, "Janet D. Platt" <PlattJD@BP.c~m>, "Rosanne ?vI. 3acobserl" <JacobsRM@BP.com=, ddonkel <ddonkel@cfl.rr.com?, E:ollins !Mount ~collins moon@rcvcnue.state.ak.us>, mckay <mekay~a gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, bocastwf <bocastwf~`L~p.com>, Charles Barker . <barker@usgs.gov>, doug_sehtritze <doug Schultze@xtoener~.com=>, Hank Alford <hankalford@exxonmobil.com==, Mark Kovac <yesnol~?gc'i.net>, gspfoff <gspfoff@aurorapower.com>, :Gregg Nady <gregg:nad@~helLcom>, Fred Steece <fred.steece@state.sd.us>, rerotty <rcrotty@ch2m:com->, jcjoncs ~ jejoncti~iaurorapower.eorn>, dapa <dapa~}a alaska.net>, jroderick <jroderck@gei.net>, eyane_y =eyanc~-c~iseal-tite.net=, "Ja1n~s M: Ruud" <fames.m.ruudreicono~ophillips.cotn>, Brit Lively <mapalaska(aak.net~, fah <jah@dnr.state.ak.us=-, Kurt 1~ O1san <kurt alson@legis~tate.~ik.us= , buonoje <:_liuonoj~ ~z;bp.com>, Mark Hanley.<mark hanley@ariadarko.corn>, Loren lemon <for.-enleman~~lgav.state.ak.us >, Julie Houle-<jute_houle@dnrstate.ak.us@ John W Katz <jwkatz@sso.org ~, Suzan. J Hill <suzan hill@dec.state.ak.us>, tablerk <tablerk@unocal.com>, Brady <brady~c_iaoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpogp <bpvpp@borough.kenai.ak.us=-, Jim White <jimwhit@satx.r>•.com>;~"Johns. H~~rorth"'<john.s.ha~orti~ici~ex~onrnobil.com>, marry <marry@rkindustrial.com>, ghammons <glramrnar3s@aol.com>, rmclean <rmclean~a pobox.alaska.net=, mkm72Ci0 <mkm72(3f_l!i~'aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, Davicl L Boelens <dbc>elens(u~aurorapo~~-er.com=>, Todd Durkee <TDURKEE@KMG.com= .Gary Schultz -'g~ry_schultz(~dnr.state.ak.us>, Wa~me Ranvier <RANGIER@getro-~anada.ca>,Bitl tiLiller <Bill Miller. ~ !xtoalaska.com>. Brandon Gagnon <bgagrion@brenalati~~.con>>, Paul Winslow <pmwir~slow@forestoil.com= ,Garry Carron <eatro~:gr@~p.com==, Sharlnain~; Copeland <copelasv@b~.com>, Suzanna Allexan <sallexan@helmenergy.com- ,Kristin Dirks <kristirt d':irks(a dnr.state.ak.us>, ltaynell Zeman <kjzema@?marathonoil.conv, John Tower <John.To~~•ericceia.doe.go~>, Bill Fowler <Bili_Fowler@anadarkoCOM>, Vaughn Swartz '~~aughn.s~~-artz~rbccm.com=>, Scott Cranswick 1 of 2 9/29/2004 1:10 PM Public Notices ~ • <scott.cranswick@mrr~ .gov>, Brad McI~i~ <mckimbs@BP.com> Please find the attached Notice and Attachment for the proposed amendinent of underground injection orders and the Public Notice Happy,VaZley #lo. Jody Colombie ' Content-Type: appiication,!msword ;Mechanical Integrity proposal.doc ' Content-Encoding: base64 _ ___ Content-Type: appiication;'msword .Mechanical Integrity of Wells Notice.doc ' Content-Encodin : base64 g II Content-Type: applicatian/msword HappyValleyl0 HearingNotice.doc Content-Encoding: base54 Public Notice . • Subject: Public Notice From: Jody Colombie <jody Colombie@admin.state:ak.us> Date: Wed, 29 Sep 2004 12:55:26 -0800 To: legal@alaskaj ournal.com Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie ':Mechanical Integrity of Wells Notice.doc Content-Type: application/msword Content-Encoding: base64 _ __ _. .Content-Type: application/msword Ad Order form.doc- Content-Encoding: base64 1 of 1 9/29/2004 1:10 PM d' Citgo Petroleum Corporation Mary Jones David McCaleb PO Box 3758 XTO Energy, Inc. IHS Energy Group Tulsa, OK 74136 Cartography GEPS 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Kelly Valadez Robert Gravely George Vaught, Jr. Tesoro Refining and Marketing Co. 7681 South Kit Carson Drive PO Box 13557 Supply & Distribution Littleton, CO 80122 Denver, CO 80201-3557 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Richard Neahring John Levorsen Hodgden Oil Company NRG Associates 200 North 3rd Street, #1202 408 18th Street President Boise, ID 83702 Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Kay Munger Samuel Van Vactor Michael Parks Munger Oil Information Service, Inc Economic Insight Inc. Marple's Business Newsletter PO Box 45738 3004 SW First Ave. 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Portland, OR 97201 Seattle, WA 98119-3960 Mark Wedman Schlumberger David Cusato Halliburton Drilling and Measurements 200 West 34th PMB 411 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503. Anchorage, AK 99502 Anchorage, AK 99503 Baker Oil Tools Ciri Jill Schneider 4730 Business Park Blvd., #44 Land Department US Geological Survey Anchorage, AK 99503 PO Box 93330 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 Williams Thomas North Slope Borough Arctic Slope Regional Corporation PO Box 69 Land Department Barrow, AK 99723 PO Box 129 Barrow, AK 99723 ,[Fwd: Re: Consistent Wording for Injection O~- Well Integrity ... Subject: [Fwd: Re: Consistent Wording for Injection Orders - From John Norman <jolu~_norman@admin.state.alc.us> Date:. Fri, Ol Oct 2004 11:09:26 -0800 To: Jody J Colombie <jody colombie@admin_state.ak.tas> more Well Integrity (Revised)] ------- 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 mintz(cLlaw.state.ak.us> To:jim reggna,admin.state.ak.us CC:dan seamount ~r,admin.state.ak.us, john norman(u,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(ciadmin.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 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 redlines on the second document attached. »> James Regg <jim reQg~admin.state.ak.us> 8/17/2004 4:33:52 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 al( 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 1 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injecti~rders -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, EOR, 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. Norman <John Norman(a~admin.state.us> '! Commissioner i Alaska Oil & Gas Conservation Commission 2 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection Or~- Well Integrity ... Subject: [Fwd: Re: Consistent Wording for Trajection Orders -Well Integrity (Revised}] From: John Norman <john_norman@admin.state.ak.us? Date.: Fri, Ol Oct ?004 11:08:5 -0800 To Jody J Calombe <jody_colombie a~adminatate.ak.us> please print all and put in file for me to review just prior to hearing on these amendments. thanx ------- Original Message -------- Subjeet:Re: Consistent Wording for Injection Orders -Well Integrity (Revised) Date:Thu, 19 Aug 2004 1:46:31 -0800 From:Rob Mintz <robert mintz~,law.state.ak.us> To:dan seamount(a,admin.state.ak.us, jim reggnaadmin.state.ak.us, john normannaadmin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. $ased 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> 8/17/2004 4:33:52 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 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, EOR, 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 1 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injecti~ders -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~a,admin.state.us> ~~' Commissioner ?' Alaska Oil & Gas Conservation Commission __ _ __ _._. ___.._. Content-Type: application/msword Injection Order language - questions.doc Content-Encoding: base64 __ __ Content-Type: application/msword '' ';Injection Orders language edits.doc Content-Encoding: base64 2 of 2 10/2/2004 4:07 PM • • Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubin /g 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 Inte rity 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 Form 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 e~°erv four years thereafter (e~ccept at least once every two years in the case of a slurry injection wel{} anal. before returning a well to sen~ice following a-#tcr• a workover affecting mechanical integrity, ~.~~' ut l~~„* „~,..~ ,,,r;,;_~ ,; .T,. .~,:~, .*~ ~~- .*~ ~ r ', ~' ~ _ tTnless an alternate means is approved by the Commission mechanical integrity must be demonstrated by a tubing pressure test using, a ~ ?v~l-surface pressure ofn~~ 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that t~~-shows stabilizing pressure that does^~y not change more than 10°=i3-percent during a 30 minute period. -4~ .. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Inte rity Failure and Confinement Except as «ther~vise provided in this rule Tthe tubing, casing and packer of an injection well must demons~~te maintain integrity during operation. ~~'henever andpressure communication, leakage or lack of injection zone isolations indicated by infection rate, operating pressure obset-~~ation, test, survey log, or other evidence the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval_ ` ~ .- ~. The operator shall shut in the well if so directed by the Commission. The operator steal l shut in the well without awaiting a response from the Commission if continued operation would be unsafe or would threaten contamination of freshwaterT.f t"~~„ .., ~.,, t"°~ * *,. ~ ~~~~, ~* .,*~ f' +•~ ~~- iu ~.u~ ~~„ `~"""""°°'"°' '" " " ~' ' " ~ ' '~ * ~ r ~' Until~correctiye action is successfully com feted, Aa 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 Languor Injectors]] Subieet: [Fwd: Re: [Fwd: AOGCC Proposed WI Language for Injectors]] From: Winton Hubert <winton aubert@admin.state.ak.us> Date: Thu, 28 Oct 2004 09:48:53 -0&OQ To: Jady J Colambie <jolly_calombie@aclmin.state.akus> 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 Hubert <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 Hubert wrote: FYI. -------- Original Message -------- Subject: AOGCC Proposed WI Language for Injectors Date: Tue, 19 Oct 2004 13:49:33 -0800 From: Engel, Harry R <EngelHR@BP.com> To: winton aubert@admin.state.ak.us 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* ** 1 of 3 10/28/2004 11:09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI L~ge for Injectors)] return'_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 MITIA 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 help/wordsmithing: "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 A; Digert, Scott A; Denis, John R (ANC); Miller, Mike E; 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 We11s Notice.doc » 2 of 3 10/28/2004 11:09 AM 6174 STATE OF ALASKA ~ NOTICE TO PUBLISHER ~ ADVERTISING ORDER NO. ADVERTISING ORDER INV UST BE IN TRIPLICATE SHOWING ADVERTISING ORDER °RTIFIED AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO-02214030 SEE 80TTOM FOR INVOICE DRESS P R AOGCC 333 W 7th Ave, Ste 100 AGENCY CONTACT Jod Colombie DATE OF A.O. March 19 2002 ° M Anchorage, AK 99501 PHONE PCN ~ REQUIRED: o Anchorage Daily News P O Box 149001 Anchorage, AK 99514 March 2282002 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account #STOF0330 Advertisement to be published was e-mailed Type of Advertisement X Legal ^ Display ^ Classified ^Other (Specify) SEE ATTACHED PUBLIC HEARING SEND INVOICE IN TRIPLICATE TO AOGCC, 333 W. 7th Ave., Suite 100 Anchors e AK 99501 PAGE ~ of z PAGes TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 A>t~ 02910 3 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LID ~ O1 02140100 73540 2 3 REQUISITIONED BY: DIVISION APPROVAL: 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving Ao.FRM ~?', ~ ~ _ ,.' _ . _ • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Nicolai Creek Unit -Disposal Injection Order Aurora Gas, LLC. by letter dated February 22, 2002 has requested an order authorizing the injection of Class II fluids in the Nicolai Creek Unit No. 5 well located at Granite Point, Alaska. The requested order would allow disposal of oilfield wastes in the Nicolai Creek Unit No 5 well located in Sec. 19, T11N, R12W, Seward Meridian. The Commission has tentatively set a public hearing on this application for May 7, 2002 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 5:00 pm on April 10, 2002. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please ca11793-1221. In addition, a person may submit written comments regarding this application to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 5:00 pm on April 22, 2002, except that if the Commission decides to hold a public hearing, written comments must be received no later than 5:00 pm on May 7, 2002. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before April 17, 2002. ~~h ~~~ ~ Cammy O~chsli Taylor, Chair Oil and Gas Conservation Commission Published March 22, 2002 ADN AO #02214030 A' E ~ F ~11~,,7 ,, Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 AD # DATE PO 350158 03/22/2002 02214030 3~22~2002 PRICE OTHER OTHER GRAND ACCOUNT PER DAY CHARGES CHARGES #2 TOTAL STOF0330 $137.00 $0.00 $0.00 $137.00 $137.00 $0.00 $0.00 $137.00 STATE OF ALASKA THIRD JUDICIAL DISTRICT Lorene Solivan, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was grin*.ed in an office maintained at the aloresaic-1 place of publication of said newspaper. That fh~ anrlexed is a copy of an advertisement as it was published in regular issues (and clot in supplemental. form) of said newspaper on the above dates and that such newspaper was regularl distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individua Signe Subscribed and sworn to me before this date: 3 --a z -o Z Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: l' 7- D to % ~~tctrrtrrrr,.F ~ ~. R r~ . ~ .. ' 1 v ~(1~L ~' - -~ .'~~ ~~~.~ _®- J'°J~~~n ~pi„~s~,,~~'~ >l)91.1 Notice: of Public Hearing STATE OF ALASKA Alaska Oil and Gas_ Conservation Commission Re:Nieolai Creek Unit -Disposal Infection Order Aurora Gas, LLC. by letTeC dated February 22, 2007. has requested an order authorizing the infection of` Class II fluids in the Nicolai Creek Unit No.S,welt located at Granite Point, Alaskd. The requested order would allow disposal of oilfield wastes in the Nicolai Creek Unit No 5 well lOCoted in Se'c. 19, T11 N, R12W> Seward Meridian. The Commission has Tentdtively set a public hear- ins on This application for May 7, 2002 at 9:00 am at. The Alaska Oil and Gas Conservation Commission at $33 West 7th Avenue, Suitg 100,":Anchorage, Alaska 99501. A Rerson may request that the Yenta- lively scheduled hearing be held by filing a writ- ten request with The Commission no later Than 5:00 am on April 10, 2002. If a Yequest far a hearing is noftimely filed, the Commission will consider the issudnce of an order without a hedging. To learn if the Commission will hold the Public hearing, Please call 793-7221.. Irraddition, a person may submit wriTTedcom- ments regarding This application to the Alaska Oil. and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaskp 99507. WriT- ten commentsmusf be received no later than 5:D11 pm on April 22,2002, except that if the Commis- sion decides to hold_a public hearing, written ` comments must be received no later than 5:00 nm qn MaY. 7; 2002. ~ ' If you are a person with a disabilitYwho may need a special modification in order to comment or to- attend the public hearing, please contact Jody Co- lombie aT 793-1221 before April 17, 2002. 'Cammy Oechsli Taylor, Chair + `Oil and Gas Conservation Commission Published: March 22, 2002 ~~~~~~® MAR 2 ~ 2002 ~IIdtC~C011s.~ <, , , STATE OF ALASKA ~ NOTICE TO PUBLISHER ~ ADVERTISING ORDER NO. ADVERTISING INV . UST BE IN TRIPLICATE SHOWING ADVERTISING ORDER ERTIFIED ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF AO-OZ2 ~ 4030 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7~' Avenue, Suite 100 ° Anchorage AK 99501 PHONE PcN M , DATE ADVERTISEMENT REQUIRED: o Anchorage Daily News March 22, 2002 P O Box 149001 Anchorage AK 99S 14 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS , ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account #STOF0330 AFFIDAVIT OF PUBLICATION United states of America REMINDER State of Ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE division. THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION Before me, the undersigned, a notary public this day personally appeared MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she 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 2002, and thereafter for consecutive days, the last publication appearing on the day of .2002, 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 2002, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER Legal Notices Subject: Legal Notices Date: Tue, 19 Mar 2002 15:31:25 -0900 From: Jody Colombie <Jody_colombie@admin.state.ak.us> To: lsolivan@adn.com Lorene: I am e-mailing you three ad orders at the same time. Please send confirmation that you have received and processed these. Jody Name: lAd Order form.doc lAd Order form.doc Type: WINWORD File (application/msword) Encoding: base64 Name: 2Ad Order form.doc 2Ad Order form.doc Type: WINWORD File (application/msword) Encoding: base64 Name: 3Ad Order form.doc 3Ad Order form.doc Type: WINWORD File (application/msword) EncodinE: base64 Name: NoticeAnchorPointJ.doc NoticeAnchorPointJ.doc Type: WIl~1WORD File (application/msword) Encoding: base64 Name: NoticeSwansonRiverStorage.doc NoticeSwansonRiverStoraae.doc Type: WINWORD File (application/msword) Encoding: base64 Name: NoticeNicolaiCreek.doc NoticeNicolaiCreek.doc Type: WIl~TWOIZD File (application/msword) Encoding: base64 =~ ~ .s. .. 1 of 1 3/19/02 3:31 PM Re: Legal Notices Subject: Re: Legal Notices Date: 20 Mar 2002 09:43:07 -0900 From: Lorene Solivan <lsolivan@adn.com> To: Jody Colombie <jody_colombie@admin.state.ak.us> Thank you Jody, all is good to go with these three ads. They will publish on the 22n Lorene 257-4296 On Tuesday, March 19, 2002, Jody Colombie <jody_colombieQadmin.state.ak.us> wrote: >Lorene: >I am e-mailing you three ad orders at the same time.. Please send >confirmation that you have received and processed these. >Jody ~, ., ,.n _ ,., ~_, 1 of 1 3/20/02 10:38 AM • • NY PUBLIC LIBRARY DIV E, GRAND OFFICE OF THE GOVERNOR, ARENT FOX KINTNER PLOTKIN KAHN, CENTRAL STATION JOHN KATZ STE 518 LIBRARY P O BOX 2221 444 N CAPITOL NW WASHINGTON SO BLDG NEW YORK, NY 10163-2221 WASHINGTON, DC 20001 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 US MIN MGMT SERV, CHIEF OCS LIBRARY OF CONGRESS, STATE U S DEPT OF ENERGY, STATS & INFO DOCUMENT SECTION PHYLLIS MARTIN MS E1823 381 ELDEN ST MS 4022 EXCH & GIFT DIV 1000 INDEPENDENCE SW HERNDON, VA 20170-4817 10 FIRST ST SE WASHINGTON, DC 20585 WASHINGTON, DC 20540 TECHSYS CORP, US GEOLOGICAL SURVEY, LIBRARY DPC, BRANDY KERNS NATIONAL CTR MS 950 DANIEL DONKEL PO BOX 8485 RESTON, VA 22092 2121 NORTH BAYSHORE DR #616 GATHERSBURG, MD 20898 MIAMI, FL 33137 SD DEPT OF ENV & NATRL AMOCO CORP 2002A, LIBRARY/INFO ILLINOIS STATE GEOL SURV, LIBRARY RESOURCES, OIL & GAS PROGRAM CTR 469 NATURAL RESOURCES BLDG 2050 W MAIN STE #1 P O BOX 87703 615 E PEABODY DR RAPID CITY, SD 57702 CHICAGO, IL 60680-0703 CHAMPAIGN, IL 61820 LINDA HALL LIBRARY, SERIALS DEPT UNIV OF ARKANSAS, SERIALS DEPT 5109 CHERRY ST ALFRED JAMES III UNIV LIBRARIES KANSAS CITY, MO 64110-2498 107 N MARKET STE 1000 FAYETTEVILLE, AR 72701 WICHITA, KS 67202-1811 IOGCC, OIL & GAS JOURNAL, P O BOX 53127 R E MCMILLEN CONSULT GEOL LAURA BELL OKLAHOMA CITY, OK 73152-3127 202E 16TH ST P O BOX 1260 OWASSO, OK 74055-4905 TULSA, OK 74101 US DEPT OF ENERGY, ENERGY DEGOLYER & MACNAUGHTON, BAPI RAJU INFORMATION ADMINISTRATION MIDCONTINENT DIVISION 335 PINYON LN MIR YOUSUFUDDIN ONE ENERGY SO, STE 400 COPPELL, TX 75019 1999 BRYAN STREET STE 1110 4925 GREENVILLE AVE DALLAS, TX 75201-6801 DALLAS, TX 75206-4083 STANDARD AMERICAN OIL CO, XTO ENERGY, SHELL WESTERN E&P INC, AL GRIFFITH MARY JONES G.S. NADY P O BOX 370 810 HOUSTON ST STE 2000 P O BOX 576 GRANBURY, TX 76048 FORT WORTH, TX 76102-6298 HOUSTON, TX 77001-0574 H J GRUY, PURVIN & GERTZ INC, LIBRARY , ROBERT RASOR 2150 TEXAS COMMERCE TWR RAY TYSON 333 CLAY STREET SUITE 3850 600 TRAVIS ST 2016 MAIN #1415 HOUSTON, TX 77002 HOUSTON, TX 77002-2979 HOUSTON, TX 77002-8844 CHEVRON, OIL & GAS JOURNAL, PETRAL CONSULTING CO, PAUL WALKER BOB WILLIAMS DANIEL L LIPPE 1301 MCKINNEY RM 1750 1700 W LOOP SOUTH STE 1000 9800 RICHMOND STE 505 HOUSTON, TX 77010 HOUSTON, TX 77027 HOUSTON, TX 77042 • • AURORA GAS, GAFFNEY, CLINE & ASSOC., INC., , G. SCOTT PFOFF LIBRARY MARK ALEXANDER 10333 RICHMOND AVENUE, STE 710 1360 POST.OAK BLVD., STE 2500 7502 ALCOMITA HOUSTON, TX 77042 HOUSTON, TX 77056 HOUSTON, TX 77083 MARATHON OIL CO, UNOCAL, REVENUE ACCOUNTING EXXON EXPLORATION CO., GEORGE ROTHSCHILD JR RM 2537 P O BOX 4531 T E ALFORD P O BOX 4813 HOUSTON, TX 77210-4531 P O BOX 4778 HOUSTON, TX 77210 HOUSTON, TX 77210-4778 EXXON EXPLOR CO, TEXACO EXPLORATION & CHEVRON USA INC., ALASKA DIVISION LAND/REGULATORY AFFAIRS RM 301 PRODUCTION INC, ATTN: CORRY WOOLINGTON P O BOX 4778 CORRY WOOLINGTON P O BOX 1635 HOUSTON, TX 77210-4778 PO BOX 36366 HOUSTON, TX 77251 HOUSTON, TX 77236 PETR INFO, PHILLIPS PETROLEUM COMPANY, WORLD OIL, DAVID PHILLIPS W ALLEN HUCKABAY DONNA WILLIAMS P O BOX 1702 PO BOX 1967 P O BOX 2608 HOUSTON, TX 77251-1702 HOUSTON, TX 77251-1967 HOUSTON, TX 77252 EXXONMOBIL PRODUCTION EXXONMOBIL PRODUCTION PENNZOIL E&P, COMPANY, COMPANY, WILL D MCCROCKLIN GARY M ROBERTS RM 3039 J W KIKER ROOM 2086 P O BOX 2967 P O BOX 2180 P O BOX 2180 HOUSTON, TX 77252-2967 HOUSTON, TX 77252-2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO MARATHON, ACE PETROLEUM COMPANY, CTR Ms. Norma L. Calvert ANDREW C CLIFFORD P O BOX 2100 P O BOX 3128, Ste 3915 PO BOX 79593 HOUSTON, TX 77252-9987 HOUSTON, TX 77253-3128 HOUSTON, TX 77279-9593 TESORO PETR CORP, , WATTY STRICKLAND LOTS DOWNS JIM WHITE 2803 SANCTUARY CV 300 CONCORD PLAZA DRIVE 4614 BOHILL KATY, TX 77450-8510 SAN ANTONIO, TX 78216-6999 SAN ANTONIO, TX 78217 INTL OIL SCOUTS, XTO ENERGY, BABCOCK & BROWN ENERGY, INC., MASON MAP SERV INC DOUG SCHULTZE 350 INTERLOCKEN BLVD STE 290 P O BOX 338 3000 N GARFIELD SUITE 175 BROOMFIELD, CO 80021 AUSTIN, TX 78767 MIDLAND, TX 79705 ROBERT G GRAVELY DIANE SUCHOMEL GEORGE G NAUGHT JR 7681 S KIT CARSON DR 10507D W MAPLEWOOD DR P O BOX 13557 LITTLETON, CO 80122 LITTLETON, CO 80127 DENVER, CO 80201 EVERGREEN WELL SERVICE CO., US GEOLOGICAL SURVEY, LIBRARY C & R INDUSTRIES, INC.,, JOHN TANIGAWA BOX 25046 MS 914 KURT SALTSGAVER 1401 17TH ST STE 1200 DENVER, CO 80225-0046 7500 W MISSISSIPPI AVE STE C4 DENVER, CO 80202 LAKEWOOD, CO 80226-4541 ~ Yom, , ± ... ~ w~ gyp} fl f. . J L. ~ ~ • • JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, ID 83702 MUNGER OIL INFOR SERV INC, P O BOX 45738 LOS ANGELES, CA 90045-0738 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA NRG ASSOC, RUBICON PETROLEUM, LLC, RICHARD NEHRING BRUCE I CLARDY P O BOX 1655 SIX PINE ROAD COLORADO SPRINGS, CO 80901- COLORADO SPRINGS, CO 80906 1655 ' TAHOMA RESOURCES, US GEOLOGICAL SURVEY, LIBRARY GARY PLAYER 2255 N GEMINI DR 1671 WEST 546 S FLAGSTAFF, AZ 86001-1698 CEDER CITY, UT 84720 BABSON & SHEPPARD, JOHN F BERGQUIST P O BOX 8279 VIKING STN LONG BEACH, CA 90808-0279 US GEOLOGICAL SURVEY, KEN BIRD 91324-2410 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 ECONOMIC INSIGHT INC, SAM VAN VACTOR P O BOX 683 PORTLAND, OR 97207 ANTONIO MADRID P O BOX 94625 PASADENA, CA 91109 SHIELDS LIBRARY, GOVT DOGS DEPT UNIV OF CALIF DAVIS, CA 95616 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE, WA 98101 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 GUESS & RUDD, DUSTY RHODES GEORGE LYLE 229 WHITNEY RD 510 L ST, STE 700 ANCHORAGE, AK 99501 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM GRAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 AURORA GAS, J. EDWARD JONES 1029 W 3RD AVE, STE 220 ANCHORAGE, AK 99501 FOREST OIL, JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET ANCHORAGE, AK 99501 PRESTON GATES ELLIS LLP, LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 DEPT OF REVENUE, BEVERLY MAROUART 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCKLOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 rr~fy~~9 .., ..~ ~> ~J „_ t_ ~ • GAFO, GREENPEACE DEPT OF NATURAL RESOURCES, DIV DEPT OF REVENUE, OIL & GAS AUDIT PAMELA MILLER OF OIL & GAS FRANK PARR 125 CHRISTENSEN DR. #2 TIM RYHERD 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-2101 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3540 ANCHORAGE, AK 99501-3510 DEPT OF NATURAL RESOURCES, DIV DEPT OF NATURAL RESOURCES, DIV DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS OIL & GAS OF OIL & GAS BRUCE WEBB WILLIAM VAN DYKE JIM STOUFFER 550 W 7TH AVE, SUITE 800 550 W 7TH AVE, SUITE 800 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 ANCHORAGE, AK 99501-3560 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DEPT OF NATURAL RESOURCES, DIV DNR, DIV OF OIL & GAS 550 W 7TH AVE, SUITE 1200 OF OIL & GAS JAMES B HAYNES NATURAL RESRCE ANCHORAGE, AK 99501-3560 JULIE HOULE MGR 550 W 7TH AVE, SUITE 800 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 ANCHORAGE, AK 99501-3560 ALASKA JOURNAL OF COMMERCE, AK JOURNAL OF COMMERCE, OIL & BRISTOL ENVIR AND ENG SERVICE, ED BENNETT INDUSTRY NEWS MIKE TORPY 2000 INTL AIRPORT W #A10 ROSE RAGSDALE 2000 W. INTL AIRPORT RD #C-1 ANCHORAGE, AK 99502 2000 INTL AIRPORT RD W #A10 ANCHORAGE, AK 99502-1116 ANCHORAGE, AK 99502 N-I TUBULARS INC, HDR ALASKA INC, BAKER OIL TOOLS, ALASKA AREA 3301 C Street Ste 209 MARK DALTON MGR ANCHORAGE, AK 99503 2525 C ST STE 305 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 ANCHORAGE, AK 99503 YUKON PACIFIC CORP, ANADARKO, ALASKA OIL & GAS ASSOC, 1400 W BENSON BLVD STE 525 MARK HANLEY JUDY BRADY ANCHORAGE, AK 99503 3201 C STREET STE 603 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503 ANCHORAGE, AK 99503-2035 ANADRILL-SCHLUMBERGER, FINK ENVIRONMENTAL CONSULTING, , 3940 ARCTIC BLVD #300 INC., ARLEN EHM GEOL CONSLTNT ANCHORAGE, AK 99503-5711 THOMAS FINK, PHD 2420 FOXHALL DR 6359 COLLATE DR. ANCHORAGE, AK 99504-3342 ANCHORAGE, AK 99504-3305 US BUREAU OF LAND MNGMNT, US BUREAU OF LAND MNGMNT, JAMES E EASON ANCHORAGE DIST OFC ANCHORAGE DIST OFC 8611 LEEPER CIRCLE DICK POLAND PETER J DITTON ANCHORAGE, AK 99504-4209 6881 ABBOTT LOOP RD 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 ANCHORAGE, AK 99507 AMERICA/CANADIAN STRATIGRPH CO, BUREAU OF LAND MANAGEMENT, US BLM AK DIST OFC, GEOLOGIST RON BROCKWAY GREG NOBLE ARTHUR BANET 4800 KUPREANOF 6881 ABBOTT LOOP ROAD 949 EAST 36TH AVE STE 308 ANCHORAGE, AK 99507 ANCHORAGE, AK 99507 ANCHORAGE, AK 99508 UOA/ ANCHORAGE, INST OF SOCIAL VECO ALASKA INC., THOMAS R MARSHALL JR & ECON RESEARCH CHUCK O'DONNELL 1569 BIRCHWOOD ST TERESA HULL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 3211 PROVIDENCE DR ANCHORAGE, AK 99508 ANCHORAGE, AK 99508 c ~ a #i~ __ ~ _. u~ • • TRADING BAY ENERGY CORP, US MIN MGMT SERV, RESOURCE US MIN MGMT SERV, AK OCS PAUL CRAIG STUDIES AK OCS REGN REGIONAL DIR 5432 NORTHERN LIGHTS BLVD KIRK W SHERWOOD 949E 36TH AV RM 110 ANCHORAGE, AK 99508 949E 36TH AV RM 603 ANCHORAGE, AK 99508-4302 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, US MIN MGMT SERV, RESOURCE RICHARD PRENTKI GORDON J. SEVERSON EVAL 949E 36TH AV 3201 WESTMAR CIR JIM SCHERR ANCHORAGE, AK 99508-4302 ANCHORAGE, AK 99508-4336 949E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, LIBRARY US MIN MGMT SERV, REGIONAL SUPRVISOR, FIELD 949E 36TH AV RM 603 FRANK MILLER OPERATNS, MMS ANCHORAGE, AK 99508-4363 949E 36TH AV STE 603 ALASKA OCS REGION ANCHORAGE, AK 99508-4363 949E 36TH AV STE 308 ANCHORAGE, AK 99508-4363 USGS -ALASKA SECTION, LIBRARY CIRI, LAND DEPT JOHN MILLER 4200 UNIVERSITY DR P O BOX 93330 3445 FORDHAM DR ANCHORAGE, AK 99508-4667 ANCHORAGE, AK 99509-3330 ANCHORAGE, AK 99508-4555 PHILLIPS ALASKA, LAND MANAGER ANCHORAGE TIMES, PHILLIPS ALASKA, JIM RUUD BERT TARRANT MARK MAJOR ATO 1968 P.O. BOX 100360 P O BOX 100040 P O BOX 100360 ANCHORAGE, AK 99510 ANCHORAGE, AK 99510-0040 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LAND DEPT PHILLIPS ALASKA, PHILLIPS ALASKA, LEGAL DEPT JAMES WINEGARNER STEVE BENZLER ATO 1404 MARK P WORCESTER P O BOX 10036 P O BOX 100360 P O BOX 100360 ANCHORAGE, AK 99510-0360 ANCHORAGE, AK 99510-0360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, PETROLEUM INFO CORP, PHILLIPS ALASKA, KUP CENTRAL JOANN GRUBER ATO 712 KRISTEN NELSON WELLS ST TSTNG P O BOX 100360 P O BOX 102278 WELL ENG TECH NSK 69 ANCHORAGE, AK 99510-0360 ANCHORAGE, AK 99510-2278 P O BOX 196105 ANCHORAGE, AK 99510-6105 ALYESKA PIPELINE SERV CO, ALYESKA PIPELINE SERV CO, LEGAL ANCHORAGE DAILY NEWS, PERRY A MARKLEY DEPT .EDITORIAL PG EDTR 1835 S BRAGAW - MS 575 1835 S BRAGAW MICHAEL CAREY ANCHORAGE, AK 99512 ANCHORAGE, AK 99512-0099 P O BOX 149001 ANCHORAGE, AK 99514 , JWL ENGINEERING, NORTHERN CONSULTING GROUP, DAVID W. JOHNSTON JEFF LIPSCOMB ROBERT BRITCH, P.E. 320 MARINER DR. 9921 MAIN TREE DR. 2454 TELEQUANA DR. ANCHORAGE, AK 99515 ANCHORAGE, AK 99516-6510 ANCHORAGE, AK 99517 GERALD GANOPOLE CONSULT GEOL DAVID CUSATO ARMAND SPIELMAN 2536 ARLINGTON 600 W 76TH AV #508 651 HILANDER CIRCLE ANCHORAGE, AK 99517-1303 ANCHORAGE, AK 99518 ANCHORAGE, AK 99518 ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 OPSTAD & ASSOC, ERIK A OPSTAD PROF GEOL P O BOX 190754 ANCHORAGE, AK 99519 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON P O BOX 196168 ANCHORAGE, AK 99519-6168 HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 JACK O HAKKILA P O BOX 190083 ANCHORAGE, AK 99519-0083 MARATHON OIL CO, LAND BROCK RIDDLE P O BOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, EXXONMOBIL PRODUCTION KEVIN TABLER COMPANY, P O BOX 196247 MARK P EVANS ANCHORAGE, AK 99519-6247 PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA) INC, PETE ZSELECZKY LAND MGR POBOX196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, INFO RESOURCE CTR MB 3-2 P O BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, SUE MILLER P O BOX 196612 M/S LR2-3 ANCHORAGE, AK 99519-6612 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER P O BOX 772805 EAGLE RIVER, AK 99577-2805 AMSI/VALLEE CO INC, WILLIAM O VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 COOK INLET KEEPER, BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 TESORO ALASKA COMPANY, PO BOX 196272 ANCHORAGE, AK 99519 ENSTAR NATURAL GAS CO, PRESIDENT TONYIZZO P O BOX 190288 ANCHORAGE, AK 99519-0288 UNOCAL, P O BOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, MR. DAVIS, ESQ P O BOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 RON DOLCHOK P O BOX 83 KENAI, AK 99611 PHILLIPS PETROLEUM CO, ALASKA DOCUMENT SERVICE CO, KENAI PENINSULA BOROUGH, OPERATIONS MANAGER JOHN PARKER ECONOMIC DEVEL DISTR J W KONST P O BOX 1468 STAN STEADMAN P O DRAWER 66 KENAI, AK 99611-1468 P O BOX 3029 KENAI, AK 99611 KENAI, AK 99611-3029 BELOWICH, NANCY LORD PENNY VADLA MICHAEL A BELOWICH PO BOX 558 P O BOX 467 1125 SNOW HILL AVE HOMER, AK 99623 NINILCHIK, AK 99639 WASILLA, AK 99654-5751 u • ~ PACE, KENAI NATL WILDLIFE REFUGE, SHEILA DICKSON JAMES GIBBS REFUGE MGR P O BOX 2018 P O BOX 1597 P O BOX 2139 SOLDOTNA, AK 99669 SOLDOTNA, AK 99669 SOLDOTNA, AK 99669-2139 VALDEZ PIONEER, ALYESKA PIPELINE SERVICE CO, VALDEZ VANGUARD, EDITOR P O BOX 367 VALDEZ CORP AFFAIRS P O BOX 98 VALDEZ, AK 99686 SANDY MCCLINTOCK VALDEZ, AK 99686-0098 P O BOX 300 MS/701 VALDEZ, AK 99686 UNIV OF ALASKA FAIRBANKS, PETR COOK AND HAUGEBERG, DEVEL LAB NICK STEPOVICH JAMES DIERINGER, JR. DR V A KAMATH 543 2ND AVE 119 NORTH CUSHMAN, STE 300 427 DUCKERING FAIRBANKS, AK 99701 FAIRBANKS, AK 99701 FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, , RICK WAGNER KATE RIPLEY C BURGLIN P O BOX 60868 P O BOX 70710 P O BOX 131 FAIRBANKS, AK 99706 FAIRBANKS, AK 99707 FAIRBANKS, AK 99707 DEPT OF NATURAL RESOURCES, DIV K&K RECYCL INC, ASRC, OF LAND P O BOX 58055 BILL THOMAS REG MGR NORTHERN REGION FAIRBANKS, AK 99711 P O BOX 129 3700 AIRPORT WAY BARROW, AK 99723 FAIRBANKS, AK 99709-4699 UNIV OF ALASKA FBX, PETR DEVEL UNIVERSITY OF ALASKA FBKS, PETR RICHARD FINEBERG LAB DEVEL LAB P O BOX 416 SHIRISH PATIL DR AKANNI LAWAL ESTER, AK 99725 437 DICKERING P O BOX 755880 FAIRBANKS, AK 99775 FAIRBANKS, AK 99775-5880 DEPT OF ENVIRON CONSERV SPAR, SENATOR LOREN LEMAN CHRIS PACE STATE CAPITOL RM 113 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1182 JUNEAU, AK 99801-1795 ~~ ~ • ,Aur{o~ra Gas, LLC RECEIVED ~=EE3 Z 6 2002 February 22, 2002 Ms. Cammy Oechsli Taylor, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Disposal Injection Order Approval Dear Ms. Taylor, Alaska Oil ~ Cas Cans. ~ammiss(Olt slr~c~~flrag~ Aurora Gas LLC hereby applies for approval of its plan to discharge non-hazardous Class II oilfield wastes in the Nicolai Creek Unit No. S wellbore. This injection well is required to support ongoing and future development plans on the Northwest side of the Cook Inlet, onshore, Granite Point area. The Application for Permit to Drill, and the Application for Sundry Approvals, are being submitted under separate covers. The well is currently permanently abandoned as depicted in Attachment I. Aurora intends to re-enter the NCU #5 wellbore, evaluate the mechanical integrity of same and perforate the interval from 2325 to 2345 feet MD. After a variable rate infectivity test and a leak offtest are performed, the well will be completed with a tubing packer set at 2250 feet, and 2 7/8 inch tubing run back to surface for injection below the packer through the perforations. The proposed injection zone is a loosely cemented unconsolidated conglomerate / siltstone in the Tyonek Formation. An initial onsite injection facility is being designed to dispose of waste at a rate of 1 barrel /minute. This will be sufficient during the initial phase of field redevelopment Aurora has planned. This figure will vary seasonally and throughout the life of the well as more prospects are developed and. more wells come on Line. Injection of finely ground drill solids is being planned for the summer months only, when temporary storage and grinding facilities can be mobilized to the site to handle drilling wastes. For future development considerations, Aurora is seeking approval for a maximum injection rate of S barrels /minute. Fracture and injection modeling indicate that over a project Iife of 10 years, this rate will have minimal impact on the surrounding areal lithology. Fluids to be disposed of include produced NaCI brine from nearby wells, workover and completion fluids used during field development procedures and drilling fluids from well drilling operations. These fluids are characterized more extensively in the attached Application for Disposal Injection Order document. ~. _ . ~ L_ • Ms. Taylor Page 2 Furthermore, the attached "Application for Disposal Injection Order" document addresses all requirements and regulations as set forth in the Alaska Administrative Code, Title 20 -Chapter 25, as they pertain to Disposal Injection Orders. If you have any questions or require additional information, please contact me at (713)977-5799, or Duane Vaagen at (907)258-3446. Sincerely, AURORA GAS, LLC . Jones Executive Vice President /Production Manager Enclosures cc: Duane Vaagen Andy Clifford ?: ~: , • Aurora Gas LLC Anchorage, Alaska APLICATION FOR UNDERGROUND DISPOSAL OF OILFIELD WASTES NICOLAI CREEK UNIT REDEVELOPMENT NICOLAI CREEK UNIT No. 5 GRANITE POINT, ALASKA 3anuary 2t~02 Aurora Gas, LLC • Table of Contents • Page 1.0 Property Description and Plat [20 AAC 25.252(c)(1)]__________________ „_,1-1 2.0 List of Operators and Surface Owners [20 AAC 25.252(c)(2)],,,,,,,,,,,,,,, „_,,,,,,,,,,r „ 2-1 3.0 Affidavit [20 AAC 25.252(c)(3)]„______________________ 3-1 4.0 Geologic Information [20 AAC 25.252(c)(4),,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ........ ,,,,,,,..__4-1 ...... 4.1 Tyonek Sandstone .. ,,,_„_,,,__-,,,,4-1 4.2 Injection Zones ............................................................................ ..............4-1 4.3 Confining Layers--------------------------------------------------------------------------- ------------•-.._4-1 5.0 Well Logs [20 AAC 25.252(c)(5)] ............................... ....... .................5-1 6.0 Casing and Cementing pragram[20 AAC 25.252(c)(6)],____.._.:_____..____._.___ _......_...____,_.6-1 7.0 Fluids to be Injected [20 AAC 25.252(c)(7)],,,,,,___„_,,,_-„ ......................... ,,,,,,,,,,,,7-1 ..... 8.0 Injection Pressure [20 AAC 25.252(c)(8)1__________________.. ,,,,8-1 9.0 Fracture Information [20 AAC 25.252(c)(9)J ........................................... .................9-1 10.0 Formation Water Analysis [20 AAC 25.252(c)(10)],,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,:,„,10-1 11.0 Freshwater Aquifer Exemption [20 AAC 25.252(c)(11),,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,11-1 12.0 Mechanical Condition of Well [20 AAC 25.252(c12)]._____,_,____.,_,__.,_.___,__ „__.._.._._,,,12-1 13.0 Mechanical Integrity of Disposal Nell [20 AAC 25.252(d)],,,, ,,,,,,,,, ,,, ,,,,,,,,,,,,,,,13-1 14.0 Summary of Areal Considerations for Disposal Well,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, 14-1 List of Figures Figure 1-1 Surface Location Property Plat,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,„1-2 Figure 1-2 Sundry Notice, As-Built Well Location Information,,______________ _________ 1-3 Figure 1-3 Lease Boundary Map, ..................................•-,,........... ,,,, l-4 Figure 2-1 Map 1, of Local Area and Current Developments,,,,,,,,,,,,,,,,,,,„ _,,,,,_,2-1 Figure 2-2 Map 2, of Local Area with Scale and Local Communities,,,,,,, ,,,,,,,,,2-2 Figure 2-3 Location ofNearby Wells_,_, _--_,____,_ ...w_..._~_~__~_._~.r_______----_ .__,___._2-3 Figure 6-1 Present Condition Nicolai Creek Unit No. 5,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,6-2 Figure 6-2 Planned Completion Diagram Nicolai Creek Unit No. 5-_________ -_„_____6-3 Figure 12-1 Completion Diagram of Nicolai Creek Unit No. 3 ,,,,,,,,,,,,,,,,,, ,,,,,,,12-2 List of Ezhibits Exhibit 3-1 Affidavit of Mr. Ed Jones ,,,,,,,,,,3-2 Exhibit 4-1 Lithology of Injection Interval NCU #5,_____________ _________„_____ _„__, ,____,_4-2 Exhibit 9-1 Injection Scenario I 9-3 Exhibit 9-2 Injection Scenario 2_„ ......................................~___...._ _._...: ......._ 9-4 Exhibit 9-3 Injection Scenario 3 ,,,,,,,,,,,,,,,,,,, ........................................... ,,,,,,,,,,,,,,9-17 Exhibit 9-4 Injection Scenario 4,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,„9-26 Exhibit 10-1 Formation Water, Total Dissolved Solids Analysis_____ _______ __ _______„ 10-2 Exhibit 10-2 Offset Well Correlation „,,,,,,,,,,,,,,,,,,, 10-3 Exhibit 14-1 Plat Map Markley Spring Location.,, ,,,,,,,,,,,,,, ,,,,,,,,,,,,14-3 NCU No. 5 Disposal Inje ction Order i ~3`~;i;l v'r ~'~ __ ._ List of Tables Table 6-1 Casing and Cement Detail Summary,,,,,,,,,,,,,,,,,,,, 6-1 List of Attachments Nicolai Creek Unit No. 5 Well Logs (Exhibit 5-1) NCU No. 5 Disposal Injection Order ,. ~. , ~.__, ~as~~,sl" • 1.0 Property Description and Plat [20 AAC 25.252(c)(1)] Nicolai Creek Unit No. 5 (NCU #5) is an abandoned well located on Federal lease number FEDA 034161, which is owned 100% by Aurora Gas LLC. This lease, located onshore, adjacent to Trading Bay on the northwest side of Cook Inlet, is comprised of 2260 acres. Surface rights are owned by Cook Inlet Region Incorporated (GIRT). NCU #5 was drilled as a vertical hole, tested, plugged and abandoned in .1.97.2.: There. are na other lease holders within.one-half mile of NCU #5. Figure 1-1 is a copy of the original surveyors report. Figure 1-2, is a Sundry notice filed with the AOGCC depicting the actual "as-built" coordinates and finished pad elevation. The actual lease boundary lines are depicted in Figure 1-3. Location information for the NCU #5 well is as follows. Nicolai Creek No. 1 Lease Number: FEDA 034161 Surface Location:.. 2183' SNL, 1.622' WEL, Sec....19, T1 lN,_R12W S.M Bottom Hole Location: Same Measured Depth: 8578' True Vertical Depth: Same NCU No. 5 Disposal Injecrion Order 1-1 • it`d " PR3W~R.12W. I I I I ~ I' I ~2 i 7 i I 1 I 8 ! 9 ! IO I I } ! , 1 + i I I I I i 9 i - ---^---- I I ~ I 1 i4 ~ 13 ~ I8 1 i I ' ~ 17 l 16 ~ 15 I ! 1____~- I ~ - - - - + ~~ ~ _ --~--+------±~--__--_- ! I a ~ ~ 21 I 1 I z3 I 24 ~ 9 ~` I -T'"S9"' NtKOLA! CREEK UNIT N0.5 1 ' ~ I I LAL ~ 61°gi 51.76;, I I I ~ LONG = 151 28_1.31 I I I L----. .-._I ^-- r~-~~--- -~-~ I X= 239,859 I ~ 1--- Y-2.571, 7IC __~. __...__._-.-{ ~ ) I I APPROX.GRDU LEV.IZSFT. 1 { , 26 I 25 I 3C i j I 29 { 2$ I 27 I ~ i I I I I I _ I I I I r------,-___- I , , i I 35 i 36 ~ 31 I I I I r ~ 32 I 33 I 34 j ~ ~ ~ I I i T I i N L i ~ ._._ _.. _. _... ...,.s - . ~._._. ~ .._ ~ ...~__..1. T. tON.~ I SCAIE~ 1° = I MILE CERTIFICATE OF SURVEYOR I hereby certify that I am properly registered and I icensed to practice land surveying in the State of Alasko and that this plot represents a locotion survey made by me or under my supervision, and thot oll dimensions and other detoils are correct, Date "~ SURVEYOR.~~- r L f ` , ~. it ~Ar,~KC,z ~f . ,,. NIKQLAI CREEK UNIT N0,5 Survgyeb fbr T~xACO ANC. Surveyed Dy F M. LINDSEY 8 ASSOC. LAND d HYDROGRAPHIC SURVEYORS 02Wesi Northern Lights Boulevord Box 4-081 iCADrbee Alb4kb Figure 1-1 NCU No. 5 Disposal Injection Order 1-2 ._.` _ . .. I _~ ~. • Farm P-3 Submie "Intmtwni In 17iPlirmte 2EV.. 9-7D~@~ & "SUnseyurnt Reports" !n Dupll®tr V • • • • ~ v• • •y ...,.. • S. API NUMF3iiCAL CODE OIL AND GAS CONSERVATION COMMITTEE 3-20036 @- I.F.AS£ DESIGNATION Al.'D SERiAI, ND. SUNDRY N071CE5 AND REPORTS ON WELLS (DO rwt uee tmr form for nropPSals to a,al ur to a¢epen or p1uL bark to a dittkrenl rrserwu A - 034161 Use "AYf LICATI(JN FOR PEftMC'I=' for such propusuls.l 1. PLL 4eR W LLL ~ WL1.4 OTft6[ ~ 7. iF IND[A1J, ALLOTTEE OR TFDBE NAME T NA:YtE OF OPERATOR H UNIT FARDI OR LEASE NAME TEXACO Inc. Nicolai Creek Unit 3. ADDRESS OF OPERATOR 9. WELL NO. P. 0. Box 4-1579, Anchorage, Alaska 99509 5 4. LOCATIUti (>F WELI. I@. F~1S) h'VD POOL, OR WILDCAT At s..rf~<r Wildcat 1622' W/E, 2128' S/N line, Sec. 19, T11N, R12W, g'SEC., T, R., M.. t6011'OM l1OLa S.M. OR,IECT1VEi Sec. 19,T11N,R12W,S.M. I"5, ELEV AT:ONS iShow wheth¢r DF, RT. GR, ete. t2. PERMIT ND. 88' Rotary Table (75' Grd, Level) X 71-30 ., Check /lppropriate Box To In~cate Naturo of Nbtic®~ Report, or Vlteer vats xortcL M txrsnrtox ro: ettseeersxT as-oss or: TL;T We26[ eft 1'T-OFP ';_ -('LL OR LLTLR C,(Lt•1p. ~_. sr LSLR RH CST-01P r- LLPLiR1x0 WLLL rR, CSt'LL TRL~T YLLTfPLb COM-I.CTL I PAeCT(fR[ TRi~iYLNT ~~_Y~ ALSLR1x9 C~RINO RHOOT OR •ClDtrg •RI NDOF• i RBOOTIt/O Ort aCIDtLSRC~ .(e~YOgvM LNr• ' RC-ASR Vr LLL [HLrOL PLANS I tOtht 1 .~'y,~ $yrye•.~'-jTO~.Qr't ; x:. '19TL: Report reLn1N M multlptL romDletlon on Well ~ t>thrrl CompletlPn a[ ReromDle[loa Seport Lad LgH [arm.i :5. Pt:et'RIRr. f•R!t PfiRCp PR CONPLLTLD OPLR.sT 10\L !: Cltn rl[ e[L [e Rl~ prrtiD-ut dtt[11 s. end ~It'P ptrtlIItIIt dl[PL. 10SiDdlpg eetimlted dett Ot Ltl[tlDg LII)' pzoPOSCd wpr14 The subject wellsite location has been completed and a final "as built" survey was made on January 24 and 25, 1972. The survey indicates the following: Location: 1622~W/E 2183' S/N, Sec. 19, T11N R12W, Seward Meridian or Lat. = 61b01'S1.21" and Long. = 151b26'01.92" or X = 239,830 and Y = 2,571,656 using Alaska State Plane Coordinate System, Zone 4. Elevation 88' Rotary Table f ~ u) t~ ~ (~ ~ `u l~ j f l j or 89' Kelly Bushing ,JAS ;~ 1 t~~r or 75' Ground Level Straight Line Distance to Nicolai Creek Unit #3 = 3266•.,r~a~~'-- 4 BIONSD _.~ / t ~ n c ann (T6U LDLLe for State o®ee nsel AFPSOYED Slf COND3TlONti OF APPSO4~2„ IF 6hi7: 2IT1'.t DATt Sea lnstructioiu On Reverse Side NCU No. 5 Disposal Injection Order T3TLt Field Foreman Dart 1/28/72 Figure 1-2 1-3 .. ~' ... L.fir, AUR ~ 00°0 i736 AC. ~~ ~¢ - - - - - AA-8426 1 AURORA GAS -1009` ~ t' ~~(;Q~ s~i°~' OkE I liiP ,TR,, GREEK T MILE A~i.~3279 UNR _ _ AURORA GAS -1009: 181,x3 AC. . HiP ADL-17688 r TR 4 , . ~, _ ~ v , ~ .... . - - - - .ss. _ x _ .... .'a AUR~pA GAS • 1 - x 196.52 AC. t18P 1T I~OL 585 ~ N L ~ ~ ~ , G ~ 5 s ARCO - 5091 3 AURORA GAS -5096 ,.'°`^ 5620 AC. NiP r _ _ ADL-17585... t4 N ,; AURORA oAS - loox f p :~'" P W ,q I Aa~<17595 R ~2 W NICOLA! CREEK ~~~$~.~ ,..o .. c. n . ~ j1 ' , ...~~.. R~visoC $4Warrbe~ 8, 2000 H -t2 W Figure 1-3 NCU No. 5 Disposal Injection Order I-4 r rr . • 2.0 List of Operators and Surface Owners [20 AAC 25.252(c)(2)] The operator of Federal Lease number FEDA 034161, where NCU #5 is located, is: Aurora Gas LLC 10333 Richmond Ave. Ste 710 Houston, TX 77042 The surface owner for the lease is Cook Inlet Region Incorporated (GIRT). There are no other surface owners or operators within aone-half mile radius of the surface location of the NCU #5 disposal well. Figures 2-1 and 2-2 show proximity of nearby oil and gas properties and developments. Figure 2-3, a structure map of the Nicolai Creek Operating Unit, indicates the location of the only known well's in the immediate vicinity of NCU #5, none of which are within '/2 mile. Cook Inlet Activity Map Legend O Vnit Boundary ® GN f1e1011ccumulation Gas Fle~dlAeeumulmen So/a Yad wMs .. F/'eeeaW l~ctive WMs t1 RalMrm __.:: Pipafnu • PraduclOn ceMtiy ~-__.. ^~ /.~~~ ..~~~/.~ Map A-E Figure 2-1 NCU No. 5 Disposal Injection Order ~~~~~~ JUL ~ 120t 1( T~ y 2-1 • • COOK INLET OIL & GAS MAP Units ~i Oil Ffeld /Accumulation ~ Gas Field/Accumulation * No StateMlnerals .tmer r~ Platform Oil Pipeline -- Tesoro Products Line -- Gas Pipeline -- - Military Products Line Production Facility o s ~o ~s m nun L.WS River UnN! Lak. UrYt Pretty Cra.k UNt~ BNUpa Rlver ran Rlver UrW n HORAGS North Cook INst Ur.t MoquaeArM* Nlcolal C Ka~oe* ~Grenfte Fbint , Norm trading B a y UnN ~ 3,r ( . ~ ~~ ~Hwfh M/dtlh Qround ~ ~ m i ~G lradir p ay U rll ~~Blrch Nlli Urdt* une (MCArMUr RNer Fold) Mldd/e Ground W. McArttrr River lln South Middle ~M°^s°^ River uw* ~ /Swanson RNer Ntest FoMwds JJ Soldotna Creek Urit* ~~v „ m s~ ~Beawr Cresk lkt * Ndst Fork'lj Dritt Rlwr ~ening UnK Terminal Gmery Loop U Karel UrYt oHotm Falls Gesk Q) ~~ T A North fork Unlt GO P q ~ 1i11~f Of /~~IISkC7 Figure 2-2 NCU No. 5 Disposal Injection Order 2-2 • N~c CI's~l[ #3 NCU #5~ ?rl i 411 H I klll IIII - I II I i i #~ I ~ ~ 19 '' 1'0 ~ ~I I I' I 11~ ~~ii li ' . , 4g ~.a,: F, I ~ `~I ii ~IIi~ '; ;.qi 3 NCU #1 . Coast 4 ii I 'i II~~ t~~~ ~;; ;t„ I ..;.; U #Z :; 1 ,F;II I N U 1-A ~ ` ' NCU #4 j{ey jz Proved Gab 32 ~~~ ~ Fauli Existing Wcll Near Top Tyo~aek Depth (, Plxcn-ed Well Figure 2-3 NCU No. 5 Disposal Injection Order 2-3 ~ ~ 3.0 Affidavit [20 AAC 25.252(c)(3)] The affidavit of Mr. Ed Jones, Executive Vice President and Production Manager, Aurora Gas LLC, is attached as Exhibit 3-1. NCU No. 5 Disposat Injection Order 3-1 ,_ f. _ -- ~, _ ~, ~ ~I EXHIBIT 3-1 AFFIDAVIT OF Mr. ED JONES EXECUTIVE VICE PRESIDENT AND PRODUCTION MANAGER AURORA GAS LLC State of Alaska.. Second Judicial District I, Ed Jones, declare and affirm that I have ~e.rsonal knowledge of the matters set forth in this affidavit, and that on the 2~~1 day of f ~~ i 2002, the following surface owner was provided a copy of this permit application by pl cing said copy in the United States mail with postage prepaid and certified at Anchorage, Alaska. Attn: Candace Beery Land Manager Cook Inlet Region Incorporated 2525. "G" Street,: Suite 500 P.O. Box 93330 Anchorage, AK 99509-3330 There are no other surface owners or operators within a one half mile radius of the Nicolai Creek # 5 well, being considered for use as an injector. 1 Ed ~ es Subscribed ands before me this ZS'''~" day of 2002. Notary Public in and r the State of Alaska NCU No. S disposal Injection ('rder t .ni.RSiN "-';SF.MN "rtnNt?hM:R n 1 M1Y "-N4"> is M ~ ~..~. .y~.:Y ^. C`/ I".~ `..~1. .. . R9 • ~_:~ ., ,,x,.~.S1.~-------..... 3-Z _ - ~! --_ ,'~~; 4.0 Geologic Information [20 AAC 25.252(2)(4)] This section includes information on the nature and distribution of the sediments in the proposed injection zone and of the confining zones which bound it. 4.1 Tyonek Sandstone The injection zone is contained within the Tyonek formation. This formation is comprised of numerous channel and floodplain sands and conglomerates with silt, clay and coal beds throughout. The boundary with the overlying Beluga Formation is difficult to determine with accuracy due to the gradational nature of the contact; however, Aurora Gas has estimated the contact between the two formations to be 1,743 feet MD (1,655 feet TVD subsea) in Nicolai Creek Unit #5 well, corresponding with 1,610 feet MD (1394 feet TVD subsea) in the Nicolai Creek Unit #3 well. 4.2 Injection Zones For the purposes of this application, all formation depths are referenced to the #5 well. The proposed injection zones are present between the depths of 2000' and 2550' as recorded on the logs of the Texaco Nicolai Creek Unit #5 well. The initial perforating and injecting will take place in the interval from 2325' - 2345'. The lithologies at these depths are primarily sandstones, conglomerates and siltstones with minor coal beds interbedded with shales. The sandstones and conglomerates are poorly cemented with expected, good intergranular porosity. On the logs, these zones appear to exhibit good properties for fluid injection. A reasonable estimate of porosity for these unconsolidated zones is 24 - 28%, with permeabilities of 50 - 100 millidarcies based on equivalent sands within the Nicolai Creek Unit #3 well, which is approximately 3230' to the east of NCU #5. Perforations are not planned above 2000' in the Nicolai Creek Unit #5 disposal well. The proposed injection zones located between 2000' and 2350' will be selectively perforated starting at the deepest available zone. Approximately 20' of perforations should be sufficient at the bottom of this interval for the planned injection operations. If additional perforations are needed at a later time, they will be made in the next available unperforated zone above those previously perforated. 4.3 Confining Layers The interval being considered for Class II non-hazardous injection activities is from 2000' - 2350' MD. There are several zones of shale and siltstone in the Nicolai Creek Unit #5 well above the proposed disposal zones. The main confining zones are located between the depths of 1480' and 1600'. These nonporous and nonpermeable shale and siltstone layers will form an effective upper seal and prevent the upward migration of injected fluids. Numerous layers of shale and siltstone are also present at depths greater than 2550' below the proposed injection zone. Examples of these are present at depths of 2780' - 2850' and from 3060' - 3 i 20'. These nonporous and nonpermeable layers wilLbe NCU No. 5 Disposal Injection Order 4-1 _... ~_ • effective barriers to downward migration of the injected fluids. Attached Exhibit 4-1 details the lithology above, through and below the intended injection interval. Exhibit 4-1 Lithology of Nicolai Creek Unit No. 5 Nicolai Cr eek Unit # 5 De th, ft. Litholo Notes 1305-1315 Coal 1315-1330 3 0 3 0 Siltstone l Sh 1 -1 4 3 1340-1380 a e Sandstone ~. 1380-1390 Coal 1390-1395 Shale 1395-1405 :~ Sandstone ;1f40514~~~; 1425-1450 11~t+a Sandstone 1450.1460 Coal 1460-1480 Sandstone "* 1480-1490 Shale 1490-1500 Siltstone 1500-1535 Shale 1535-1540 Siltstone 1540-1555 Coal 1555-1585 Shale 1585-1595 Coat 1595-1605 Siltstone 1605-1610 Coal 1610-1625 Shale 1625-1645 Sandstone 1660-1695 I Sandstone 1705-1745 I Sandstone 1780-1820 1820 1840 Sandstone l C - 1840-1925 oa Shale 1925-1960 Coal 1960-1985 Shale 1985-2020 Sandstone 2025-2030 Sandstone 2030-2045 Coal 2045-2070 Shale 2095-2130 ~ Sandstone ~ ' NCU No. 5 Disposal Injection Order 4-2 i • Exhibit 4-1 Continued.... 2130-2155 Shale 2155-2170 Siltstone 2170-2190 Coal 2190-2200 Siltstone 2200-2210 Shale 2210-2220 Siltstone 2220-2295 Shale 2295-2345 Siltstone 2345-2355 Coal 2355-2375 Shale 2375-2410 Siltstone * 2410-2420 Coal 2420-2435 Shale 2435-2485 Siltstone * 2485-2495 Coal 2495-2550 Siltstone Notes: Correlates with gas pay in NCU#3 * well ** Gas show on mudlog NCU No. 5 Disposal Injection Order 4-3 UL 01200 i • 5.0 Well Logs [20 AAC 25.252(c)(5)] Well logs showing the spontaneous potential (SP), resistivity, conductivity, interval transit time (Borehole Compensated Sonic) as well as actual on-site geologic observations (mud logs) for the interval being considered for injection are enclosed with this application. Copies of these logs can also be found in the archives at the Alaska Oil and Gas Conservation Commission. (See Attached Documents, Exhibit 5-1). NOU No. 5 Disposal Injection Order 5-1 6.0 Casing and Cementing Program [20 AAC 25.252(c)(6)) At present the well is plugged and abandoned (Figure 6-1). Records indicate that the interval being considered for injection is cased with 10 3/4" 40.5 lb/ft J-55 casing, which was cemented back to surface with good cement returns observed at that time. The proposed final casing, cement and completion configuration of Nicolai Creek Unit No. 5 is detailed in Figure 6-2. The proposed re-entry plan calls for drilling out the surface cement plug, cleaning out old mud in the wellbore and running a USIT, cement evaluation log from surface to PBTD at 2500' MD. If necessary, the casing will be perforated and cement will be squeezed into any interval where the casing/cement interface is deemed mechanically insufficient to offer a quality seal. After the casing/cement integrity has been confirmed and the casing has been pressure tested to 1500 psi, the well will be perforated for injection operations. Table 6-1 depicts the casing and cement program used when NCU #5 was originally drilled. Table 6-1 CBrrent Casing anal Cement Detail SummaFy Aurora Gas LLC Nicolai Creek Unit No. 5 Disposal Well Hole Casing Casing Depth Depth Float Size Size Description Shoe (RKB) Top Length Equipment Cement Vol Driven 30" Structural 34' Surface 34' None None 20" 16" 75# J-55 308' Surface 304.44' None Class "G" 600 SX 15" 10 3/<" 40.5 # J-55 2628' Surface 2634.00' None Class "G" 1440 SX NCU No. 5 Disposal Injection Order 6-i Proposed X~ Present Condition 25 Sack Cement plug at Surface 30" (.5"Wall Structural Conductor) Driven to 34' 16", 75# J-55 308' M D Drilling Mud 10 314", 40.5# J-5E 2628'MD(2628' TV Cemented w/ 14 sks Class G to surface Drilling I Drilling I Drilling Drilling Drilling N n u Nicolai Creek No. 5 Nicolai Creek Field Size Wt. Grde Thrd Depth Sks/Cmt CONDUCTOR 30" 34' SURFACE 16" 75# J-55 308' 600 Sks INTERMEDIATE 10 314" 40.5 # J-55 s~~ s 2628' 1440 Sks LINER PRODUCTION TUBING D: 71-03 I: 283-20036 ud Date: Feb. 2, 1972 to Abandoned: March 7, 1972 ~v. (RKB) 89.00' (Ground Elevation 75' depths are RKB measured depths. 30 Sack Class G Plug 756' - 2500' M D 5 Sack Class G Plug 14' - 3050' M D iSack Class G Plug i1' - 3950' M D Figure 6-1 115 Sack Class G Plug 6718' - 6500' M D t5 Sack Class G Plug r215' - 7000' M D 9 718" Hole toTD 8578' M D (8578' TV D) NCU No. 5 Disposal Injection Order DRAWING NOT TO SCALE Nicolai Creek No. 5 FAIRWEATHERE&P SERVICES INC. Rev. 01Pcond / DM! 05-Nov-01 6-2 9Jl`d9'UB~~~GJ c&~d~ ~~ ~ ~V`~~ • Proposed Present Condition 2 7l8"Tubing For Injection 30" (.5" Wall Structural Conductor) Driven to 34' 16", 75# J-55 308' M D Cemented W/600 ; Class G to Surface NaCl2 / KCIp InTbg annulus Class II Dlspo. Fluids 103!4", 40.5# J-55 2628'MD(2626' TVI Cemented w/ 144 sks Class G to surface Drilling ~ Drilllni Nicolai Creek No. 5 Nicolai Creek Field Size Wt. Grde Thrd Depth Sks/Cmt CONDUCTOR 30" 34' SURFACE 16" 75# J-55 308' 600 Sks INTERMEDIATE 10 3/4" 40.5 # J-55 a~ s~ 2628' 1440 Sks LINER PRODUCTION TUBING 2 7/8" 6.5 # L-80 8 Rd 2250' PTD: 71-03 API: 283-20036 Spud Date: Feb. 2, 1972 Date Abandoned: March 7, 1972 Elev. (RKB) 89.00' (Ground Elevation 75' All depths are RKB measured depths. 9ng Packer !250' M D erforatlons 325' - 2345' M D 30 Sack Class G Plug 756' - 2500' M D 5 Sack Class G Plug 14' - 3050' M D i Sack Class G Plug i1' - 3950' M D Figure 6-2 Drilling Drilling Drillin4 NCU No. 5 Disposal Injection Order 115 Sack Class G Plug 6718' - 6500' M D Sack Class G Plug 15' - 7000' M D y .rd" Hole toTD 8578' M D (8578' N D) DRAWING NOT TO SCALE Nicolai Creek No. 5 FAIRWEATHER E&P SERVICES INC. Rev. 01 Proposed / DHV 05-Nov-01 6-3 c~~a~~~~~% ~~~ ~ ~. ~tl~~ ~ ~ 7.0 Fluids to be Injected [20 AAC 25.252(c)(7)] Nicolai Creek Unit No. 5 is intended to be used for disposal of general non-hazardous Class II oilfield wastes generated in the production, drilling and workover of wells on the west side of the Cook Inlet. Produced fluids will primarily be sodium chloride formation water. Completion and workover fluids will be composed of potassium and/or sodium chloride type brines, cement, bentonite and/or polymer viscosity enhancing agents and some formation fluids. The drilling waste will contain bentonite or polymer for viscosity control, potassium and sodium chloride, cement, fresh water, and finely ground drill solids obtained in the course of drilling. All materials to be injected will be non-hazardous Class II materials only. The average density of produced and workover fluids are estimated at 9.0 - 9.5 ppg. Drilling waste will be ground to 50 mesh size or smaller, with the final blended slurry density estimated to be between 9.0 - 11.5 ppg with solids content limited to 20 % by weight. Bentonite or polymer viscosifiers will be used as necessary to maintain proper slurry viscosity thereby reducing the potential of well plugging while injecting the drill solids. For the disposal injection order application, permission is being requested to dispose of non- hazardous Class II oil-field waste at a maximum, intermittent rate of 5 bpm, or 7200 bbls/day maximum, based on the following scenarios. The surface injection facilities are currently being designed to accommodate disposal of well fluids at a continuous rate of 1 bbUmin, year-round. Upon completion of the Nicolai Creek Unit redevelopment, initial injection rates will be on the order of 350 - 450 bbUday of produced formation water which when disposed of at a rate of 1 bbUmin., would entail injecting for 7.5 hours per day. As new wells are drilled and other prospects are developed, the drilling waste, work-over fluids and produced formation fluids generated will be added to the injection stream. This will cause fluctuations in the injection rates as well as the amount injected per day as the waste stream increases or decreases. The following, while very optimistic, are conceivable maximum injection rates and amounts that could occur over the planned 10 year service life of Nicolai Creek Unit No. 5, during the course of field redevelopment and satellite project development. Production Fluids: 20 producing gas wells, each producing 50 bbls /day brine. 50 bbls/day X 20 wells X 365 production days / year = 365,000 bbls /year total. Therefore, 50 bbls/day/well X 20 wells = 1000 bbl /day brine. At 1 bbl /minute, injection would last 16.7 hours /day. Drilling and Workover Fluids: 5 Well procedures /year, each generating a total of 1500 bbls waste /well. 5 wells X 1500 bbls / well X 1 year = 7500 bbls /year total. With short term seasonal injection of drill solids at 5 bbl /minute, material would be injected for a period of 25 hours /year. This seasonal volume could be higher if more aggressive development plans are initiated. NCU No. 5 Disposal Injection Order 7-I _: ,: . . ..~ ~>.~~>r • The above calculations indicate the need to dispose of 372,500 bbls waste /year, or 1020 bbls / day. If injection was sustained at the above indicated rate for 10 years straight, a total of 3,725,000 bbls would be disposed of over the anticipated life of the project. At this time it is anticipated that produced fluids and workover fluids will be injected on a year round basis as needed. Disposal of any drilling waste or solids containing workover fluid is anticipated to be handled during the summer months only, when temporary solids holding and grinding facilities can be mobilized to the site for operations. To make developing the gas potential in the nearby area as economically attractive as possible, Aurora would like to minimize on-site equipment rental costs by injecting at as high a rate as possible, not to exceed 5 bpm when disposing of drilling and workover generated wastes. It should be pointed out that it will be necessary to periodically shut the injection facility down for maintenance and repair. This will cause a backlog of waste materials to be disposed of. The option to increase the rate as necessary to prevent an excessive amount of waste fluids in storage is necessary. The fluids to be disposed of do not need any special consideration with respect to injection zone compatibility. The primary injection fluid will be sodium chloride, brine which is native to and will be produced from, the Tyonek formation it is being injected back into. Other fluids will be brines of various composition, most likely potassium chloride used in the make-up of workover and drilling fluids, There are no known reactive characteristics of the formation to these fluids at this time. NCU No. 5 Disposal Injection Order 72 ti~F t, ` yf"o i ,7 `), ~~ 8.0 Injection Pressure [20 AAC 25.252(c)(8)] The surface pressure will not be allowed to exceed the maximum test pressure of 1500 psi. This equates to a down hole pressure of 2905 psi across the lower perforations, or 2995 psi at the PBTD of 2500' MD. The maximum surface pressures calculated during injection and fracture modeling (see Sec 9.0, Fracture Information) approached 863 psi, for a downhole pressure across the perforations of 1856 psi. This pressure was calculated while pumping pure 10.0 ppg brine (to simulate produced well fluids) and exceeded the pressures observed modeling the high rate /high density disposal (4-5 bpm / 15 ppg) slurries due to the effect of the increased hydrostatic head induced by the high density fluids. This analysis assumes a negligible friction loss between surface and the packer at 2250' MD. Four injection and frac scenarios were modeled and Section 9.0 contains information on the pressures, rates and slurry densities referenced herein. After perforating the well, Aurora Gas LLC will perform a step rate injection test to establish injection rates and pressures. The step rate test will be incrementally increased to pump rates approximately 100 % in excess of the maximum anticipated. pumping rates for waste disposal.. Pressure falloff data will also be collected. NCUNo. 5 Disposal Injection Order 8-1 i5 ~E`i ~.. ~ yr . _ .. 1_l . _ ~ . ~ ~ 9.0 Fracture Information [20 AAC 25.252(c)(9}] Injection disposal of produced well, workover, completion and drilling fluids and solids (as described in Section 7.0) is expected to create vertical fracture(s) in the disposal formation. To better understand the subsurface dynamics of the displaced fluids and materials, computer fracture and injection modeling was performed. The primary purpose of the modeling is to show that the fluids and materials injected will be contained by the boundaries offered by the impermeable shales and siltstone beds discussed in section 4.3 of this application, and that the areal effect will be negligible. Secondary considerations were to investigate potential injection pressures, both surface and subsurface. The model has been run for the following four injection scenarios. 1.0 Injection of 15 ppg fluid at 4 barrels per minute for 10 continuous days, then stopping injection for 1 day, followed by repetition of the 10 day pumping period, until 245,000 total barrels of fluid and 42,005,6001bs of 100 mesh sand are injected. 2.0 Injection of 10 ppg brine at 1 barrel per minute for 365 days resulting in 526,143 total barrels of fluid injected. 3.0 Injection of 13 ppg fluid at 1 barrel per minute for 355 days resulting in 511,666 total barrels of fluid and 56,713,7001bs of 100 mesh sand are injected. 4.0 Injection of 15 ppg fluid at 5 barrels per minute for 5 days resulting in 36,026 barrels of fluid and 6,166,3001bs of 100 mesh sand are injected. In all four modeled cases,. the fractures were constrained by the bounding shales and siltstones described in section 4.3. All modeling runs can be considered as extreme and unlikely as the mechanical limitations of the surface equipment and fluid volumes actually injected will likely never approach those used for the modeling. Complete details of the parameters used and the results obtained can be viewed in Exhibits 9-1, 9-2, 9-3 and 9-4. Injection Scenario 1 was designed to investigate injection of a high solids content (15 ppg) fluid at a high rate (4 bpm) for an extended time (40 days), to simulate the disposal of a large amount of drill solids that would accumulate with an aggressive drilling schedule. The following parameters were used: Injection material consisted of 10 ppg brine with proppant added at a rate of 5 ppg (100 mesh sand for simulating drill solids). The slurry was injected at 4 bbl / minute for 40 days at 10 day intervals with 24 hours off between each interval (see Exhibit 9-1 for details and summary of results). The total volume of fluid injected is 245,274 bbls of brine, and total solids injected were 42,005,6001bs of sand. At this rate, which is totally unrealistic in terms of volume and pumping schedule, a fracture was initiated which propagated radially outward 449 feet and extended vertically from 2,330 to 1,779 feet. Modeling showed that the fracture would break through one of the bounding shale sequences from 1840~tQ 1925 feet. It did not however, penetrate the primary bounding shale interval from NCU No. 5 Disposal Injection Order 9-1 ~. 9 . ~ • • 1480 to 1600 feet. It should be emphasized that this rate is unrealistically high because under even the most optimistic of development schemes, there would be an insufficient volume of fluid of this density to dispose of to sustain such a rate. See details and results in Exhibit 1. Scenario 2 was designed to investigate the results of long term, 24-hour/day injection. The following guidelines were used: The fluid injected was straight 10 ppg brine. The brine was injected at 1 bpm for a total of 365 days with no break in injection (see Exhibit 9-2 for details and summary of results). The total volume of fluid injected is 526,143 bbl of brine. At this rate, which exceeds volumetric design considerations, simulation showed the induced fracture propagated radially outward 527 feet and extended vertically from 2420 to 2069 feet. Under this scenario, the fracture did not penetrate the bounding shale located at 1925 feet. Again, this rate exceeds the anticipated maximum injection as outlined in the aforementioned injection volumes under even the most optimistic of development plans. Scenario 3 investigated the results of year-round injection of an injection material consisting of 10 ppg brine blended with proppant added at a rate of 3 ppg disposed of at a rate of 1 bpm (see Exhibit 9-3 for details and summary of results). The slurry was injected at 1 bpm for a total of 355 days. The total volume of brine injected is 511,666 bbls, and the total solids injected were 56,713,7001bs of 100 mesh sand. At this rate, the induced fracture propagated radially outward 507 feet and extended vertically from 2330 to 1934 feet. The fracture did not penetrate the bounding shale located at 1925 feet and again, this rate far exceeds the maximum yearly anticipated injection volume as outlined above. Scenario 4 was designed to investigate a worst case injection program assuming a high density (15 ppg) fluid and high flow rate of 5 bpm for short duration (5 days). This is necessary as temporary surface grind and inject facilities will be brought to the site to handle the drill solids during the summer months only. In the interest of economics, and to make developing the gas potential in the nearby area as attractive as possible, Aurora would like to minimize on-site equipment rental costs by injecting at as high a rate as possible, not to exceed 5 bpm during the summer solids grind and inject procedure. In this example, slurry was injected at a rate of 5 bpm using a 10 ppg brine and a proppant concentration of 5 ppg (15 ppg slurry) for 7200 minutes (5 days). The total volume of slurry injected is 36,026 bbls, and the total solids injected equaled 6,166,300 lbs of proppant (see Exhibit 9-4 for details and summary of results).. At this rate, the induced fracture propagated radially outward only 299 feet and extended vertically from 2420 to 2026 feet. Using this model, the fracture did not penetrate the bounding shale located at 1925 feet. Under even the most optimistic of development plans, this rate exceeds the yearly anticipated solids injection volumes proposed by a factor in excess of 4 and it clearly shows one would be able to inject for short term periods, a 15 ppg slurry at a rate of 5 bpm. The maximum density fluid predicted for any disposal into the NCU #5 disposal well is on the order of 11.0 - 11.5 ppg. The modeling revealed that because of the high inherent permeability of the sandstones (50 md), that when the fracture gets large, there is sufficient surface area for all injected fluids to leak off at a rate equal to or faster than the actual injection rate. NCU No. 5 Disposal Injection Order 9-2 • Exhibit 9-1 FracproPT10.0 Hydraulic Fracture Analysis Date: December 20, 2001 WeIF Name.. Nicola Creek #5 Location: Formation: Job Date: 12/19/2001.02:51.;41 PM Filename: Nicolai Creek Run 1 Fracture Geometry Summary Fracture Half-Len th ft 449 Pro ed Half-Len th ft 0 otal Fracture Hei ht ft 551 otal Pro ed Hei ht ft 0 De th to Fracture to ft 1779 Max. Fracture Width in 1.11 De th to Fracture Bottom ft 2330 v .Fracture Wid#h in 0.58 Equivalent Number of Multiple Fracs 1.0 vg. Proppant Concentration (Ib/ft2 0.00 Fracture Slu Efficient 0.03 All values reported are for a single fracture Model has run until 65626.00 min Fracture Conductivity Summary Dimensionless Conductivity 0.00 Ref. Formation Permeabiiity mD 50.0 Proppant Damage Factor 0.50 Proppant Permeabilit mD 20000 All values reported are for a single fracture Fracture Pressure Summary Model Net Pressure si -93 BH Fracture Closure Stress si 1856 Observed Net Pressure si 0 Closure Stress Gradient si/ft 0.797 H drostatic Head si 1463 Surface Pressure si 549 Averages reported during Main Frac NCU No. 5 Disposal Injection Order 9-3 ,: 4s,, . _ _ .. • • Operations Summary otal Clean Fluid Pumped 245274 otal Proppant Pumped 42005.6 bbls klbs Total Slurry Pumped (bbls) 245274 otal Proppant in Fracture 0.0 klbs Pad Volume (bbls) 0 vg. Hydraulic Horsepower 63 h Pad Fraction (°1°) 0 Max. Hydraulic Horsepower 72 h Main Fluid 10# BRINE Main Proppant 100-Mesh Averages reported during Main Frac NCIJ No. 5 Disposal Injection Order ~'~ • Concentration of Pro ppant in Fracture {Ib/ft2) S#age # Length ft Uppe~Ht ft LowerHt ft Upper Conc 1b1ftZ Lower Conc Iblft' 1 Has Leaked Off 3 Has Leaked Off 5 Has Leaked O ff 7 449.0 275.4 275.4 0.00 0.00 7 447.8 275.4 273.9 0.00 0.00 7 446.1 275.4 271.$ 0.00 0.00 7 444.0 273.5 271.1 0.00 0.00 7 442.5 271.7 271.1 0.00 0.00 7 440.7 269.4 271.1 0.00 0.00 7 439.1 267.5 271.1 0.00 0.00 7 438.0 266.1 271.1 0.00 0.00 7 435.8 263.4 271.1 0.00 0.00 7 435.1 262.6 271.1 0.00 0.00 7 432.6 259.5 271.1 0.00 0.00 7 431.4 258.0 271.1 0.00 0.00 7 429.0 255.0 271.1 0.00 0.00 7 427.6 253.4 271.1 0.00 0.00 7 426.6 252.2 271.1 0.00 0.00 7 425.1 250.3 271.1 0.00 0.00 7 423.6 248.5 271.1 0..00 0.00 7 422.5 247.1 271.1 0.00 0.00 7 420.9 245.1 271.1 0.00 0.00 7 419.4 243.2 271.1 o.oa o.oo 7 41$.2 241.9 271.1 0.0o O.Oo 7 416.5 239.7 271.1 0.00 0.00 7 414.7 237.6 271.1 0.00 0.00 7 413.4 236.0 271.1 0.00 0.00 7 411.5 233.7 271.1 0.00 0.00 7 410.2 232.0 271.1 0.00 0.00 7 408.1 229.5 271.1 0..00 0.00 7 406.7 227.7 271.1 0.00 0.00 7 404.6 225.1 271.1 0.00 0.00 7 402.3 222.3 271.1 0.00 0.00 7 400.7 220.4 271.1 0.00 0.00 7 398.3 217.4 271.1 0.00 0.00 7 396.6 215.4 271.1 0.00 0.00 7 394.1 212.3 271.1 0.00 0.00 7 392.2 210.0 271.1 0.00 0.00 7 389.7 206.9 271.1 0.00 0.00 7 387.8 204.5 271.1 0.00 0.00 7 385.2 201.3 271.1 0.00 0.00 7 383.1 198.8 271.1 0.00 0.00 7 381.1 196.3 271.1 0.00 0.00 • • Concentration of Pro ppant in Fracture (Ib/ft2) Stage # Length ft UpperHt ft LowerHt ft Upper Conc Ib/ftz Lower Conc Ib/ft2 7 378.2 192.8 271.1 0.00 0.00 7 376.1 190.2 271.1 0.00 0.00 7 373.9 '! 87.5 271.1 0.00 0.00 7 370.9 183.9 271.1 0.00 0.00 7 368.6 ~ 81.0 271.1 0..00 0.00 7 365.5 177.2 271.1 0.00 0..00 7 363.0 174.2 271.1 0.00 0.00 7 360.5 171.1 271.1 0.00 0.00 7 357.3 167.1 271.1 0.00 0.00 7 354.7 163.9 271.1 0.00 0.00 7 351.9 160.5 271.1 0.00 0.00 7 348.3 156.1 271.1 0.00 0.00 7 345.3 152.5 271.1 0.00 0.00 7 342.4 148.9 271..1 0.00 0.00 7 339.4 145.2 271.1 0.00 0.00 7 335.6 140.5 271.1 fl.00 0.00 7 332.4 136.5 271.1 0.00 0.00 7 329.0 132.4 271.1 0.00 0.00 7 325.4 128.0 271.1 0.00 0.00 7 321.7 123.5 271.1 0.00 0.00 7 318.0 118.9 271.1 0.00 0.00 7 313.4 113.3 271.1 0.00 0.00 7 309.3 108.3 271.1 0.00 0.00 7 305.0 103.0 271.1 0.00 0.00 7 300.9 97.9 271.1 0.00 0.00 7 295.1 90.8 271.1 0.00 0.00 7 288.1 82.2 271.1 0.00 0.00 7 281.2 73.$ 271.1 0.00 0.00 7 272.8 63.5 271.1 0.00 0.00 7 262.6 51.0 271.1 0.00 0.00 7 251.9 37.8 271.1 0.00 0.00 7 237.2 19.8 271.1 0.00 0.00 7 198.4 7.5 235.9 0.00 0.00 7 135.2 2.2 163.6 0.00 0.00 7 68.7 0.0 84.3 0.00 0.00 NCUNo. ~ Disposal Injecrion Order ~-6 ~__ ~' . _~ - _ ~_ C • Fracture Conductivity (mD•ftj Stage # Length ft UpperHt ft LowerHt ft Upper Cond mD•ft Lower Cond mD•ft 1 Has Leaked Off 3 Has Leaked Off 5 Has Leaked O ff 7 449.0 275.4 275.4 0.00 0.00 7 447.8 275.4 273,9 0.00 0.00 7 446.1 275.4 271.8 0.00 0.00 7 444.0 273.5 271.1 0.00 0.00 7 442.5 271.7 271.1 0.00 0.00 7 440.7 269.4 271.1 0.00 0.00 7 439.1 267.5 271.1 0.00 0.00 7 438.0 266.1 271.1 ~ 0.00 0.00 7 435.8 263.4 271.1 0.00 0.00 7 435.1 2.62.6 271.1 0.00 0.00 7 432.6 259.5 271.1 0.00 0.00 7 431.4 258.0 271.1 OA4 0.00 7 429.0 255.0 271.1 0.00 0.00 7 427.6 253.4 271.1 0.00 0.00 7 426.6 252.2 271.1 0.00 0.00 7 425.1 250.3 271.1 0.00 0.00 7 423.6 248.5 271.1 0.00 0.00 7 422,5 247.1 271.1 0.00 0.00 7 420.9 245.1 271.1 0.00 0.00 7 419.4 243.2 271.1 0.00 0.00 7 418.2 241.9 271.1 0.00 0.00 7 416.5 239.7 271.1 0.00 0.00 7 414.7 237.6 271.1 0.00 0.00 7 413.4 236.0 271.1 0.00 0.00 7 411.5 233.7 271.1 0.00 0.00 7 410.2 232.0 271..1 0.00 0.00 7 408.1 229.5 271.1 0.00 0.00 7 406.7 227.7 271.1 0.00 0.00 7 404.6 225.1 271.1 0.00 0.00 7 402.3 222.3 271.1 0.00 0.00 7 400.7 220.4 271.1 0.00 0.00 7 398.3 217.4 271.1 0.00 0.00 7 396.6 215.4 271.1 0.00 0.00 7 394.1 212.3 271.1 0.00 0.00 7 392.2 210.0 271.1 0.00 0.00 7 3$9.7 206.9 271.1 0.00 0.00 7 387.8 204.5 271.1 4.00 0.00 7 385.2 201.3 271.1 4.00 4.44 7 383.1 198.8 271.1 0.04 0.00 ,r,~~ • Fracture Conductivity (mD•ft) Stage # Length ft UpperHt ft LowerHt ft Upper Cond mD~ft Lower Cond mD~ft 7 381.1 196.3 271.1 0.00 0.00 7 378.2 192.8 271.1 0.00 0.00 7 376.1 190.2 271.1 0.00 0.00 7 373.9 187.5 271.1 0.00 0.00 7 370.9 183.9 271.1 0.00 0.00 7 368.6 181.0 271.1 0.00 0.00 7 365.5 177.2 271.1 0.00 0.00 7 363.0 174.2 271.1 0.00 0.00 7 360.5 171.1 271.1 0.00 0.00 7 357.3 167.1 271.1 0.00 0.00 7 354.7 163.9 271.1 0.00 0.00 7 351.9 160.5 271.1 0.00 0.00 7 348.3 156.1 271.1 0.00 0.00 7 345.3 152.5 271.1 0.00 0.00 7 342.4 148.9 271.1 0.00 0.00 7 339.4 145.2 271.1 0.00 0.00 7 335.6 140.5 271.1 0.00 0.00 7 332.4 136.5 271.1 0.00 0.00 7 329.0 132.4 271.1 0.00 0.00 7 325.4 128.0 271.1 0.00 0.00 7 321.7 123.5 271.1 0.00 0.00 7 318.0 118.9 271.1 0.00 0.00 7 313.4 113.3 271.1 0.00 0.00 7 309.3 108.3 271.1 0.00 0.00 7 305.0 103.0 271.1 0.00 0.00 7 300.9 97.9 271.1 0.00 0.00 7 295.1 90.8 271.1 0.00 0.00 7 288.1 82.2 271.1 0.00 0.00 7 281.2 73.8 271.1 0.00 0.00 7 272.8 63.5 271.1 0.00 0.00 7 262.6 51.0 271.1 0.00 0.00 7 251.9 37.8 271.1 0.00 0.00 7 237.2 19.8 271.1 0.00, 0.00 7 198.4 7.5 235.9 0.00 0.00 7 135.2 2.2 163.6 0.00 0.00 7 68.7 0.0 84.3 0.00 0.00 NCU No. 5 Disposal Injection Order 9_g i~~~ ~ .' lI. 1. . ~~,+.~ ,. ~~. ~ ._.. ~ .m L ,.. (v~~..~ Treatment Schedule Stage # Elapsed Time min.sec Fluid Type Clean Volume bbls Prop Conc. Stage Prop. kfbs Slurry Rate b m Proppant Type ellbore Fluid 10# BRINE 75.3 1 10:da s 10# BRINE 0000.0 5.00 10500.0 4.00 100-Mesh 2 11:da s SHUT-IN 0.0 0.00 0.0 0.00 3 22:da s 10# BRINE 50000.0 5.00 10500.0 4.00 100-Mesh 4 23:da SHUT-IN 0.0 0.00 0.0 0.00 5 33:da s 10# BRINE 50000.0 5.00 10500.0 4.00 100-Mesh 6 34:da s SHUT-IN 0.0 o.oa 0.0 0.00 7 45:da s 10# BRINE 50000A 5.00 10500.0 4.00 100-Mesh Scheduled clean vol (bbls) 199999.98 Scheduled sand tots! (klbs) 42000.00 Scheduled slurry vol (bbls) 245223.36 NCU No. ~ Disposal Injection Order 9-~ ~~r s, "` ~.r`.. _.. c_ti~ . • All Fluid info is at a reservoir temperature of 1.50.0 (°F) All Viscosities at Shear Rate of 511 (1/sec) Fluid Parameters ----• Fluid Name 1tr# BRINE Initial Rheolo iscosit 1.72 n' 1.000 k' 3.59Oe-05 Rheology ~ 4.0 hours iscosit 1.72 n' 1.000 k' 3.59Oe-05 Gel Density 1.18 purt Loss 0.0 all Buildin 0.0 Flowrate #1 10..00 Fric Press #1 648.0 Flowrate #2 20.00 t=ric Press #2 2259.7 Flowrate #3 0.00 Fric Press #3 7834.7 B Fric Mult 1.000 • Wellbore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction Multiplier. Viscosity is displayed in (cp) K' is displayed in (lbf•s^n1ft2) Gel Density is displayed as (sg) Spurt Loss is displayed in (gal/ft2) Wall Building is displayed in (ft/min%) Friction pressure is displayed in (psi/1000 ft) Flowrate is displayed in (bpm) Friction is displayed for longest weilbore segment NCU No. 5 Disposal Injection Order 9-10 ~)jiyr~ ;, v 1N - .. r .~-.n ~ _ .... L_ f-... ~r • Leakoff Parameters • Reservoir type Gas Filtrate to reservoir fluid perm. ratio, Kp/KI 10 .Reservoir pore pressure (psi) 1014 Initial fracturing pressure (psi) 2356 Reservoir fluid compressibility (1 /psi) 9.87e-004 Cold filtrate viscosity (cp) 1.00 Hot filtrate viscosity (cp) 1.00 Cold reservoir viscosity (cp) 0.03 Hot reservoir viscosity (cp) OA3 Porosity 0.10 Gas Leakoff Percentage 100.00 Reservoir Parameters Reservoir temperature (°F) Depth to center of Perfs (ft) Perforated interval (ft) Initial frac depth (ft) 150.00 2330 20 2330 Layer Parame#ers Layer # Top of zone ft Stress (psi) Top of zone ft Young's modulus si Poisson's ratio Top of zone ft Total Ct (ft/min'/:) PoreFluid perm. and 1 0.0 1124 0,0 6.Oe+006 0.25 0.0 O.000e+000 O.OOe+000 2 1405.0 1203 1405.0 1.4e+006 0.33 1405.0 O.000e+000 O.OOe+000 3 1425.0 1078 1425.0 1.7e+006 0.31 1425.0 O.000e+000 O.OOe+000 4 1450.0 1164 1450.0 4.4e+005 0.39 1450.0 O.000e+000 O.OOe+000 5 1460.0 1103 1460.0 1.7e+006 0:31 1460.0 3.728e-002 S.OOe+001 6 1480.0 1262 1480.0 1.4e+006 0.33 1480.0 O.OODe+000 O.OOe+000 7 1490.0 1196 1490,0 4.4e+005 0.39 1490.0 O.000e+000 O.ODe+000 8 1500.0 1290 1500.0 1.4e+006 0.33 1504.0 3.728e-002 5.OOe+001 9 1535.0 1230 1535.0 4.4e+005 0.39 1535.0 O.000e+000 O.OOe+000 10 1540.0 123$ 1540.0 4.4e+00 0.39 1540.0 3.728e-002 5.OOe+001 11 1555.0 1335 1555.0 1.4e+006 0.33 1555.0 O.000e+000 O.OOe+000 12 1585.0 1272 1585.0 4.4e+005 0.39 1585.0 3.728e-002 5.DOe+001 13 1595.0 1280 1595,0 4.4e+005 0.39 1595.0 O.000e+000 O.OOe+000 14 1605.0 1286 1605..0 4.4e+005 0.39 1605.0 O.000e+000 O.OOe+000 15 1610.0 1375 1610.0 1.4e+006 0.33 1610.0 O.000e+000 O.OOe+000 16 1625.0 1226 1625.0 1.7e+006 0.31 1625.0 3.728e-002 S.OOe+001 17 1645.0 1322 1645.0 4.4e+00 D.39 1645.0 O.OOOe+D00 OAOe+000. 18 1660.D 1258 1660.0 1.7e+006 D.31 1660.0 3.728e-002 S.OOe+001 19 1695.0 1360 1695.0 4.4e+005 0.39 1695.0 O.OOOe+000 O.OOe+000 20 1705.0 1294 1705.0 1.7e+006 0.31 1705.0 3.728e-002 S.OOe+001 21 1745.0 1404 1745.0 4.4e+005 0.39 1745.0 O.000e+000 O.OOe+000 22 1765.0 1507 1765.0 1.4e+006 0.33 1765.0 O.000e+000 O.OOe+000 23 17$0.0 1350 1780,0 1.7e+006 0.31 1780.0 3.728e-002 5.OOe+001 24 1820.0 1464 1820.0 4.4e+00 0.39 1820.0 O.OOOe+D00 0.40e+000 .,, -. ,. _. . __ ,_ _ . _ G.:.~,. ~ ~ Layer Parameters Layer # Top of zone ft Stress (psi) Top of zone ft Young's modulus si Poisson's ratio Top of zone ft Total Ct {ftlmin'/2} PoreFluid perm. and 25 1840.0 1600 1840.0 1.4e+006 0.33 1840.0 O.OOOe+000 a.00e+000 26 1925.0 1554 1925.0 4.4e+005 0.39 1925.0 O.000e+000 OAOe+000 27 1960.0 1677 1960.0 1.4e+006 0.33 1960.0 O.000e+000 O.OOe+000 28 1985.0 1502 1985.0 1.7e+006 0.31 1985.0 3.728e-002 5.OOe+001 29 2020.0 1618 2020.0 4.4e+005 0.39 2020.0 O.000e+000 O.OOe+000 30 2025.0 1521 2025.0 1.7e+006 0.31 2025.0 3.728e-002 S.OOe+001 31 2030.0 1630 2030.0 4.4e+005 0.39 2030.0 O.000e+000 O.OOe+000 32 2045.0 1749 2045.0 1.4e+006 0.33 2045.0 O.000e+000 O.OOe+000 33 2070.0 1666 2070.0 4.4e+00 0.39 2070.0 O.000e+000 O.OOe+000 34 2095.0 1584 2095.0 1.7e+006 0.31 2095.0 3.72$e-002 5.OOe+001 35 2130.0 1821 2130.0 1.4e+006 0.33 2130.0 O.OOOe+000 O.OOe+000 36 2155.0 1730 2155.0 4.4e+005 0.39 2155.0 O.000e+000 O.OOe+000 37 2170.0 1744 2170.0 4.4e+005 0.39 2170.0 O.000e+000 O.OOe+000 38 2190.0 1756 2190.0 4.4e+005 0.39 2190.0 O.000e+000 O.OOe+000 39 2200.0 1874 2200.0 1.4e+006 0.33 2200.0 O.OOOe+000 O.OOe+000 40 2210.0 1772 2210.0 4.4e+005 0.39 2210.0 O.OOOe+000 O.OOe+000 41 2220.0 1919 2220.0 1.4e+006 0.33 2220.0 O.000e+000 O.OOe+000 42 2295.0 1856 2295.0 4.4e+00 0.39 2295.0 O.000e+000 O.OOe+000 43 2345.0 1880 2345.0 4.4e+005 0.39 2345.0 O.000e+000 O.OOe+000 44 2355.0 2010 2355.0 1.4e+006 0.33 2355.0 O.000e+000 O.OOe+000 45 2375.0 1914 2375.0 4.4e+005 0.39 2375.0 3.728e-002 S.OOe+001 46 2410.0 1932 2410.0 4.4e+005 0.39 2410.0 O.000e+000 O.OOe+000 47 2420.0 2063 2420.0 1.4e+006 0.33 2420.0 O.OOOe+000 O.OOe+000 48 2435.0 1968 2435.0 4.4e+005 0.39 2435.0 O.000e+000 O.OOe+000 49 2485.0 1992 2485.0 4.4e+005 0.39 2485.0 O.OOOe+000 O.OOe+000 50 2495.0 1996 2495.0 4.4e+005 0.39 2495.0 O.000e+000 O.OOe+000 NGUNo. 5 Disposal Injection Order 9-IZ G: r~~H. ~ ,___.~ eJ 1~ ~ ' • Litholo gy Parameters Layer # Top of zone ft Lithology Top of zone ft Fracture Toughness si•in'fs Top of zone ft Tip Effects Factor 1 0.0 Overburde n 0.0 1000 0.0 1.00 2 1405.0 Shale 1405.0 2000 1405.0 1.00 3 1425.0 Sandstone 1425.0 1000 1425.0 1.00 4 1450.0 oal 1450.0 500 1450.0 1.00 5 1460.0 Sandstone 1460.0 1000 1460.0 1.00 6 14$0.0 Shale 1480.0 2000 1480.0 1.00 7 1490.0 iltstone 1490.0 1000 1490.0 1.00 8 1500.0 Shale 1500.0 2000 1500.0 1.00 9 1535.0 Siltstone 1535.0 1000 1535.0 1.00 10 1540.0 Coal 1540.0 500 1540.0 1.00 11 1555.0 Shale 1555.0 2000 1555.0 1.00 12 1585.0 Coal 1585.0 500 1585.0 1.00 13 1595.0 iltstone 1595.0 1000 1595.0 1.00 14 1605.0 Coal 1605.0 500 1605.0 1.00 15 1610.0 Shale 1610.0 2000 1610.0 1.00 16 1625.0 Sandstone 1625.0 1000 1625.0 1.00 17 1645.0 Coal 1645.0 500 1645.0 1.00 18 1660.0 Sandstone 1660.0 1000 1660.0 1.00 19 1695.0 Coal 1695.0 500 1695.0 1.00 20 1705.0 Sandstone 1705.0 1000 1705.0 1.00 21 1745.0 Coal 1745.0 500 1745.0 1.00 22 1765.0 Shale 1765.0 2000 1765.0 1.00 23 1780.0 andstone 1780.0 1000 1780.0 1.00 24 1820.0 oal 1820.0 500 1820.0 1.00 25 1840.0 Shale 1840.0 2000 1840.0 1.00 26 1925.0 Coal 1925.0 500 1925.0 1.00 27 1960.0 Shale 1960.0 2000 1960.0 1.00 28 1985.0 Sandstone 1985.0 1000 1985.0 1.00 29 2020.0 oal 2020.0 500 2020.0 1.00 30 2025.0 Sandstone 2025.0 1000 2025.0 1.00 31 2030.0 oal 2030.0 500 2030.0 1.00 32 2045.0 hale 2045.0 2000 2045.0 1.00 33 2070.0 Siltstone 2070.0 1000 2070.0 1.Ob 34 2095.0 Sandstone 2095.0 1000 2095.0 1.00 35 2130.0 Shale 2130.0 2000 2130.0 1.00 36 2155.0 Siltstone 2155.0 1000 2155.0 1.00 37 2170.0 Coal 2170.0 500 2170.0 1.00 38 2190.0 iltstone 2190.0 1000 2190.0 1.00 39 2200.0 Shale 2200.0 2000 2200.0 1.00 40 2210.0 Siltstone 2210.0 1000 2210.0 1.00 41 2220.0 Shale 2220.0 2000 2220.0 1.00 ~.. ~ U_ ~ _ l.'. _ _ • Litholo gy Parameters Layer # Top of zone ft Lithology Top of zone ft Fracture Toughness si•in'/z Top of zone ft Tip 1=ffects Factor 42 2295.0 Siltstone 2295.0 1000 2295.0 1.00 43 2345.0 Coal 2345.0 500 2345.0 1.00 44 2355.0 Shale 2355.0 2000 2355.0 1.00 45 2375.0 Siltstone 2375.0 1000 2375.0 1.00 46 2410.0 Coal 2410.0 500 2410.0 1.00 47 2420.0 Shale 2420.0 2000 2420.0 1.00 48 2435.0 Siltstone 2435.0 1000 2435.0 1.00 49 2485.0 Coal 2485.0 500 2485.0 1.00 50 2495.0 Siltstone 2495.0 1040 2495.0 1.00 Wellbore Configuration Segment Length ft Segment Type Tubing ID (in) Tubing OD (in) Casing ID (in) 1650 ubin 2.441 0.000 0.000 670 Casin 0.000 OA00 10.050 Tubular Goods are defined to the TOP of the deepest set of pertorations that are being modeled. Frac #1 0 of Perfs - TVD ft 2320 Bot of Perfs - TVD ft 2340 Pert Diameter in 0.500 of Perfs 20 NCU No. 5 Disposal Injection Order 9-14 s.`-~ - r1 F;~,~n • . ~ • ,_.. ~: ~ ~~ ~ 8 ~ ~ ~ ~ ~ ~ 8 ~ i ~w °_ ~ ~ ----- --- ~~ se. ~ T j8 ~ V _T y O + v '~ ~ ~ ~ O O v O O O O ~ ~ ~~ ~ g ~ ~ L ~ NCU No. 5 Disposal Injection Order ~ ~ ~~A~~l~l~ JUL fJ ~ ZOD~ 9-15 Exhibit 9-Z FracproPT10.0 Hydraulic Fracture Analysis Date: December 26, 2001 Wellname: Nicolai Greek #5 Location: Formatting: Job Date: 12/99!2001 02:51:41 PM Filename: Nicolai Creek Run 2 Fracture Geometry Summary Fracture Half-Len th ft 527 Pro ed Half-Len th ft 0 Total Fracture Hei ht ft 351 otal Pro ed Hei ht ft 0 De th to Fracture To ft 2069 Max. Fracture Width in 1.27 De th to Fracture Bottom ft 2420 v .Fracture Wid#h in 0.65 Equivalent Number of Multiple Fracs 1.0 vg. Proppant Concentration (lb/ft2 0.00 Fracture Slur Efficiency 0.01 All values reported are for a single fracture Model has run until 525000.00 min Fracture Conductivity Summary Dimensionless Conductivity 0.00 Ref. Formation Permeability mD 50.0 Proppant Dama a Factor 0.50 Proppant Permeabili mD 116000 All values reported are for a single fracture Fracture Pressure Summary Model Net Pressure si 80 BH Fracture Closure Stress si 1856 Observed Net Pressure si 0 Closure Stress Gradient si/ft 0.797 H drostatic Head si 1091 Surface Pressure si 863 Averages reported during Main Frac NCU No. 5 Disposal Injection Order 9-16 • • Frac#ure Geometry Summary otal Clean Fluid Pumped 526143 otal Proppant Pumped 0.0 bbls klbs otal Slurry Pumped (bbls) 526143 otal Proppant in Fracture 0.0 klbs Pad Volume (bbls) 0 vg. Hydraulic Horsepower 21 h Pad Fraction (%) 0 Max. Hydraulic Horsepower 21 h Main Fluid 10# BRINE Main Proppant Brad -2040 Averages reported during Main Frac NCII No. S Disposal Injection Order 9-17 ~. • • Concentration of Proppant in Fracture (Ib/ft2) Stage # Length ft UpperHt ft LowerHt ft Upper Conc Ib/ft2 LowerConc Ibift2 1 526.9 175.5 175.5 0.00 0.00 1 524.2 173.8 175.5 0.00 0.00 1 520.5 171.3 175.5 0.00 0.00 1 517.1 169.0 175.5 0.00 0.00 1 514.4 167.2 175.5 0.00 0.00 1 511.9 165.6 175.5 0.00 0.00 1 509.1 163.7 175.5 0.00 0.00 1 507.0 162.3 175.5 0.00 0.00 1 503.3 159.8 175.5 0.00 0.00 1 501.0 158.3 175.5 0.00 0.00 1 499.1 157.1 175.5 0.00 0.00 1 495.4 154.6 175.5 0.00 0.00 1 493.2 153.1 175.5 0.00 0.00 1 490.1 151.0 175.5 0.00 0.00 1 487.5 149.3 175.5 0.00 0.00 1 484.1 147.0 175.5 0.00 0.00 1 481.0 144.9 175.5 0.00 0.00 1 477.8 142.8 175.5 0.00 0.00 1 473.8 140.1 175.5 0.00 0.00 1 470.3 137.8 175.5 0.00 0.00 1 467.1 135.7 175.5 0.00 0.00 1 465.1 134.4 175.5 0.00 0.00 1 462.0 132.3 175.5 0.00 0.00 1 460.0 130.9 175.5 0.00 0.00 1 456.7 128.8 175.5 0.00 0.00 1 453.3 126.5 175.5 0.00 0.00 1 449.0 123.6 175.5 0.00 0.00 1 447.5 122.6 175.5 0.00 0.00 1 445.2 121.1 175.5 0.00 0.00 1 443.6 120.1 175.5 0.00 0.00 1 441.3 118.5 175.5 0.00 0.00 1 438.8 116.9 175.5 0.00 0.00 1 437.2 115.7 175.5 0.00 0.00 1 434.6 114.1 175.5 0.00 0.00 1 432.8 112.9 175.5 0.00 0.00 1 430.1 111.1 175.5 0.00 o.aa 1 428.1 109.7 175.5 0.00 0.00 1 425.3 107.8 175.5 0.00 0.00 1 423.2 106.5 175.5 0.00 0.00 1 420.3 104.5 175.5 0.00 0.00 1 418.1 103.1 175.5 0.00 0.00 1 415.0 101.0 175.5 0.00 0.00 ~.. ~ ~; 'jts~i `~ • • Concentration of Proppant in Fracture (Ib/ft2) Stage # Length ft UpperHt ft LowerHt ft Upper Conc 1blftY Lower Conc Ib/ft' 1 412.7 99.5 175.5 0.00 0.00 1 409.6 97.4 175.5 0.00 0.00 1 407.2 95.8 175.5 0.00 0.00 1 403.9 93.6 175.5 0.00 0.00 1 401.5 92.0 175.5 0.00 0.00 1 399.0 90.3 175.5 0.00 O.OQ 1 395.6 88.1 175.5 0.00 0.00 1 393.1 86.4 175.5 0.00 0.00 1 389.5 84.0 175.5 OAO 0.00 1 387.0 82.3 175.5 0.00 0.00 1 383.3 79.8 175.5 0.00 0.00 1 380.5 78.0 175.5 0.00 0.00 1 377.6 76.1 175.5 0.00 0.00 1 373.6 73.4 175.5 0.00 0.00 1 370.7 71.4 175.5 0.00 0.00 1 367.5 69.4 175.5 0.00 0.00 1 363.1 66.4 175.5 0.00 0.00 1 360.0 64.3 175.5 0.00 0.00 1 356.6 62.1 175.5 0.00 0.00 1 353.0 59.7 175.5 0.00 0.00 1 348.2 56.5 175.5 0.00 0.00 1 344.2 53.8 175.5 0.00 0.00 1 340.0 51.0 175.5 0.00 0.00 1 334.5 47.3 175.5 0.00 0.00 1 328.8 43.5 175.5 0.00 0.00 1 320.0 37.7 175.5 0.00 0.00 1 309.8 30.9 175.5 0.00 0.00 1 297.2 22.5 175.5 0.00 0.00 1 279.4 10.6 175.5 0.00 0.00 1 249.0 0.0 165.9 0.00 0.00 1 204.5 0.0 136.3 0.00 0.00 1 152.7 0.0 101.7 0.00 0.00 1 82.2 0.0 54.8 0.00 0.00 NCU No. 5 Disposal Injection Order 9-19 ~~;~~ <, ~..~:t i • LeakoffParameters Reservoir type Gas Filtrate to reservoir fluid perm. ratio, Kp/KI 10 Reservoir pore pressure (psi) 1014 Initial fracturing pressure (psi) 2356 Reservoirfluid compressibility (1/psi) 9.87e-004 Coid filtrate viscosity (cp) 1.00 Hot filtrate viscosity (cp) 1.00 Cold reservoir viscosity (cp) 0.03 Hot reservoir viscosi#y (cp) 0.03 Porosity 0.10 Gas Leakoff Percentage 100.00 Reservoir Parameters Reservoir temperature (°F) Depth to center of Perfs (ft) Perforated interval (ft) Initial frac depth (ft) 150.00 2330 20 2330 Layer Parameters layer # Top of zone ft Stress (psij Top of zone ft Young's modulus si Poisson's ratio Top of zone ft Total Ct (fttmin'/2) PoreFluid perm. and 1 0.0 1192 0.0 6.Oe+006 0.25 0.0 O.OOOe+000 O.OOe+000 2 1490.0 1196 1490.0 4.4e+005 0.39 1490.0 O.000e+000 O.OOe+000 3 1500.0 1290 1500.0 1.4e+006 0.33 1500.0 3.728e-002 S.OOe+001 4 1535.0 1230 1535.0 4.4e+005 0.39 1535.0 O.000e+000 O.OOe+000 5 1540.0 1238 1540.0 4.4e+005 0.39 1540.0 3.728e-002 5.OOe+001 6 1555.0 1335 1555.0 1.4e+006 0.33 1555.0 O.000e+000 O.OOe+000 7 1585.0 1272 1585.0 4.4e+00 0.39 1585.0 3.728e-002 S.OOe+001 8 1595.0 1280 1595.0 4.4e+005 0.39 1595.0 O.000e+000 O.OOe+000 9 1605.0 1286 1605.0 4.4e+005 0.39 1605.0 O.000e+000 O.OOe+000 10 1610.0 1375 1610.0 1.4e+006 0.33 1610.0 O.OOOe+000 O.OOe+000 11 1625.0 1226 1625.0 1.7e+006 0.31 1625.0 3.728e-002 5.OOe+001 12 1645.0 1322 1645.0 4.4e+005 0.39 1645.0 O.000e+000 O.OOe+000 13 1660.0 1258 1660.0 1.7e+006 0.31 1660.0 3.728e-002 5.OOe+001 14 1695.0 1360 1695.0 4.4e+005 0.39 1695.0 O.000e+000 O.OOe+000 15 1705.0 1294 1705.0 1.7e+006 0.31 1705.0 3.728e-002 S.OOe+001 16 1745.0 1404 1745.0 4.4e+00 0.39 1745.0 O.000e+000 O.OOe+000 17 1765.0 1507 1765.0 1.4e+006 0.33 1765.0 O.OOOe+000 O.OOe+000 18 1780.0 1350 1780.0 1.7e+006 0.31 1780.0 3.728e-002 S.OOe+001 19 1820.0 1464 1820.0 4.4e+005 0.39 1$20.0 O.000e+000 O.OOe+000 20 1840.0 1600 1840.0 1.4e+006 0.33 1840.0 O.000e+000 O.OOe+000 21 1925.0 1554 1925.0 4.4e+005 0.39 1925.0 O.000e+000 O.OOe+000 22 1960.0 1677 1960.0 1.4e+006 0.33 1960.0 O.000e+000 O.OOe+000 23 1985.0 1502 1985.0 1.7e+006 0.31 1985.0 3.72$e-002 5.OOe+001 24 2020.0 1618 2020.0 4.4e+005 0.39 2020.0 O.000e+000 O.OOe+000 ...~ , u ~ _ ~ ~_ ~'.. ~._ `~ • • Layer Parameters Layer# Top of zone ft Stress (psi) Top of zone ft Young's modulus si Poisson's ratio Top of zone ft Total Ct (ft/min'h) PoreFluid perm. and 25 2025.0 1521 2025.0 1.7e+006 0.31 2025.0 3.728e-002 S.OOe+001 26 2030.0 1630 2030.0 4.4e+005 0.39 2030.0 O.OOOe+000 O.OOe+000 27 2045.0 1749 2045.0 1.4e+006 0.33 2045.0 O.000e+000 O.OOe+000 28 2070.0 1666 2070.0 4.4e+005 0.39 2070.0 O.000e+000 O.OOe+000 29 2095.0 1584 2095.0 1.7e+006 0.31 2095.0 3.728e-002 5.OOe+001 30 2130.0 1821 2130.0 1.4e+006 0.33 2130.0 O.000e+000 O.OOe+000 31 2155.0 1730 2155.0 4.4e+005 0.39 2155.0 O.000e+000 O.OOe+000 32 2170.0 1744 2170.0 4.4e+005 0.39 2170.0 O.000e+000 O.OOe+000 33 2190.0 1756 2190.0 4.4e+005 0.39 2190.0 O.000e+000 O.OOe+000 34 2200.0 1874 2200.0 1.4e+006 0.33 2200.0 O.000e+000 O.OOe+000 35 2210.0 1772 2210.0 4.4e+005 0.39 2210.0 O.000e+000 O.OOe+000 36 2220.0 1919 2220.0 1.4e+006 0.33 2220.0 O.000e+000 O.OOe+000 37 2295.0 1856 2295.0 4.4e+005 0.39 2295.0 O.000e+000 O.OOe+000 38 2345.0 1880 2345.0 4.4e+005 0.39 2345.0 O.000e+000 O.OOe+000 39 2355.0 2010 2355.0 1.4e+006 0.33 2355.0 O.000e+000 O.OOe+000 40 2375.0 1914 2375.0 4.4e+005 0.39 2375.0 3.728e-002 5.OOe+001 41 2410.0 1932 2410.0 4.4e+005 0.39 2410.0 O.000e+000 O.OOe+000 42 2420.0 2057 2420.0 1.4e+006 0.33 2420.0 O.000e+000 OAOe+000 NCU No. 5 Disposal Injection Order 9-21 ... ~ r f'f`r,.r. __ _ ~, r ~ ~': .. , • Litholo gy Parameters Layer # Top of zone ft Lithology Top of zone ft Fracture Toughness si•in'/: Top of zone ft Tip Effects Factor 1 0.0 verburde n 0.0 1000 0.0 1.00 2 1490.0 Siltstone 1490.0 1000 1490.0 1.00 3 1500.0 Shale 1500.0 2000 1500.0 1.00 4 1535.0 Siltstone 1535.0 1000 1535.0 1.00 5 1540.0 Coal 1540.0 500 1540.0 1.00 6 1555.0 hale 1555.0 2000 1555.0 1.00 7 1585.0 oal 1585.0 500 1585.0 1.00 8 1595.0 Siltstone 1595.0 1000 1595.0 1.00 9 1605.0 Coal 1605.0 500 1605.0 1.00 10 1610.0 Shale 1610.0 2000 1610.0 1.00 11 1625.0 Sandstone 1625.0 1000 1625.0 1.00 12 1645.0 Coal 1645.0 500 1645.0 1.00 13 1660.0 Sandstone 1660.0 1000 1660.0 1.00 14 1695.0 Coal 1695.0 500 1695.0 1.00 15 1705.0 Sandstone 1705.0 1000 1705.0 1.00 16 1745.0 Caal 1745.0 500 1745.0 1.00 17 1765.0 Shale 1765.0 2000 1765.0 1.00 18 1780.0 Sandstone 1780.0 1000 1780.0 1.00 19 1820.0 Coal 1820.0 500 1820.0 1.00 20 1840.0 Shale 1840.0 2000 1840.0 1.00 21 1925.0 Coal 1925.0 500 1925.0 1.00 22 1960.0 Shale 1960.0 2000 1960.0 1.00 23 1985.0 andstone 1985.0 1000 1985.0 1.00 24 2020.0 oal 2020.0 500 2020.0 1.00 25 2025.0 Sandstone 2025.0 1000 2025.0 1.00 26 2030.0 Coal 2030.0 500 2030.0 1.00 27 2045.0 Shale 2045.0 2000 2045.0 1.00 28 2070.0 Siltstone 2070.0 1000 2070.0 1.00 29 2095.0 Sandstone 2095.0 1000 2095.0 1.00 30 2130.0 Shale 2130.0 2000 2130.0 1.00 31 2155.0 Siltstone 2155.0 1000 2155.0 1.00 32 2170.0 Coal 2170.0 500 2170.0 1.00 33 2190.0 Siltstone 2190.0 1000 2190.0 1.00 34 2200.0 Shale 2200.0 2000 2200.0 1.00 35 2210.0 Siltstone 2210.0 1000 2210.0 1.00 36 2220.0 Shale 2220.0 2000 2220.0 1.00 37 2295.0 Siltstone 2295.0 1000 2295.0 1.00 38 2345.0 Coal 2345.0 500 2345.0 1.00 39 2355.0 Shale 2355.0 2000 2355.0 1.00 40 2375.0 Siltstone 2375.0 1000 2375.0 1.00 • C~ Litholo gy Parameters Layer # Tap of zone ft Lithology Top of zone ft Fracture Toughness si•in'/Z Top of zone ft Tip Effects Factor 41 2410.0 Coal 2410.0 500 2410.0 1.00 42 2420.0 Shafe 2420.0 2000 2420.0 1.00 Model Parameters Fracture Growth Parameters (FracproPT 3D Model) Crack Opening Coefficient 0.8500000 Rock Deformation Coefficient 00001000 Channel Flow Coefficient 1.0000000 Tip Radius Fraction 0.0100000 Tip Effects Sole Volume (bb!) 100.00 Fluid Radial Weighting Exponent set to default of Rock Deformation Coeff / 10. Proppant Model Parameters Minimum Proppant Concentration (Ib/ft^2) Minimum Proppant Diameter (in) Volume Fraction of Proppant in Slurry Proppant Drag Effect Exponent Proppant Radial Weighting Exponent Proppant Convection Coefficient Proppant Settling Coefficien# Quadratic Backfill Model Quadratic Backfill Coefficient Stop Model on Screenout Initial Leakoff Area Coeff Closure Leakoff Area Coeff Minimum Fracture Height Near Wellbore Friction Exponent NCUNo. 5 Disposal Injection Order 0.20 0.008 0.60 8.0 0.2500 10.00 1.00 ON 0.50 ON 1.00 OA3 OFF 0.50 ~r 9-23 Proppant Data Pro ant Name Brad 2040 Cost $/Ib .070 Bulk Dens Ibm/fts 96.20 Packed Porosit 0.418 pecific Gravity s .65 urbuience Coeff a 1.54 urbulence Coeff b 1.23 Diame#er in .024 Perm 0 psi D 32.0 Perm @ 2000 psi D 232.0 Perm @ 4000 psi (D) 103A Perm @ 6000 psi D 54.00 Perm @ 8000 psi D 29.00 Perm @ 10000 psi D 15.00 Perm @ 12000 psi D 8.00 Perm @ 14000 psi D 4.00 Perm @ 16000 psi D .00 Perm @ 18000 psi D 1.000 NCU No. 5 Disposal Injection Order .... ., ~ .. ~ .., _ ~ ~, t,..... -. I-24 NCU No. 5 Disposal Injection Order 9-25 ?4llll~lt g-~ • FracproPT9 0.0 Hydraulic Fracture Analysis Date: December 27, 2001 t~ellname: Nicolai Greek #5 Location: Formatting: Job Da#e: 1211912001 02:51:41 PM Filename: Nicolai Creek-Run 3 Fracture Geometry Summary Fracture Half-Len th ft 507 Pro ed Half-Len th ft 0 otal Fracture Hei ht ft 396 otal Pro ed Hei ht ft 0 De th to Fracture To ft 1934 Max. Fracture Width in 0.90 Depth to Fracture Bottom ft 2330 v . Ft~acture Width in 0.47 Equivalent Number of Multiple Fracs 1.0 vg. Proppant Concentration (Ib/ft2) 0.00 Fracture Slur Efficienc 0.00 All values reported are for a single fracture Model has run until 511060.00 min Fracture Conductivity Summary Dimensionless Conductivity 0.00 Ref. Formation Permeability mD 50.0 Pro pant Dama a Factor 0.50 Proppant Permeabilit mD 20000 All values reported are for a single fracture Fracture Pressure Summary Model Net Pressure si -34 BH Fracture Closure Stress si 1856 Observed Net Pressure si 0 Closure Stress Gradient si/ft 0.797 H drostatic Head si 1280 Surface Pressure si 562 Averages reported during Main Frac NCU No. 5 Disposal Injection Order 9-26 ~ _ i . ~ i Fracture Geometry Summary Total Clean Fluid Pumped 511666 otal Proppant Pumped 56713.7 bbls klbs Total Slurry Pumped (bbls) 511666 otal Proppant in Fracture 0.0 klbs Pad Volume (bbls) 0 vg. Hydraulic Horsepower 17 h Pad Fraction (%) 0 Max. Hydraulic Horsepower 17 h Main Fluid 10# BRINE Main Proppant 100-Mesh Averages reported during Main Frac NCU No. 5 Disposal Injection Order 9-27 ~~ • Concentration of Proppant in Fracture (Ib/ft2) Stage # Length ft UpperHt ft LowerHt ft Upper Conc Ib/ftz Lower Conc Ib/ftZ 1 506.9 197.8 197.8 0.00 0.00 1 501.9 193.9 197.8 0.00 0.00 1 500.3 192.6 197.8 0.00 0.00 1 498.5 191.3 197.8 0.00 0.00 1 496.0 189.3 197.8 0.00 0.00 1 494.0 187.$ 197.8 0.00 0.00 1 493.5 187.3 197.8 0.00 0.00 1 491.2 185.6 197.8 0.00 0.00 1 489.4 184.2 197.8 0.00 0.00 1 488.3 183.3 197.8 0.00 0.00 1 485.9 181.4 197.8 0.00 0.00 1 483.9 179.9 197.8 0.00 0.00 1 482.6 178.8 197.8 0.00 0.00 1 481.3 177.$ 197.$ 0.00 0.00 1 479.1 176.1 197.8 0.00 0.00 1 477.6 175.0 197.8 0.00 0.00 1 475.9 173.6 197.8 0.00 0.00 1 474.5 172.5 197.8 0.00 0.00 1 472.2 170.7 197.8 0.00 0.00 1 470.5 169.4 197.8 0.00 0.00 1 467.5 167.1 197.8 0.00 0.00 1 465.8 165.7 197.8 0.00 0.00 1 463.8 164.2 197.8 0.00 0.00 1 461.4 162.3 197.8 0.00 0.00 1 460.7 161.8 197.8 0.00 0.00 1 459.2 160.6 197.8 0.00 0.00 1 457.6 159.4 197.8 0.00 0.00 1 456.0 15$.1 197.8. 0.00 0.00 1 454.8 157.2 197.8 0.00 0.00 1 452.6 155.4 197.8 0.00 0.00 1 450.9 154.1 197.8 0.00 0.00 1 448.3 152.1 197.8 0.00 0.00 1 446.5 150.7 197.8 0,00 0.00 1 444.0 148.7 197.8 0.00 0.00 1 441.4 146.7 197.8 0.00 0.00 1 439.4 145.1 197.8 0.00 0.00 1 436.6 142.9 197.8 0.00 0.00 1 434.5 141.3 197.8 0.00 0.00 1 431.6 139.1 197.8 0.00 0.00 1 429.2 137.2 197.8 0.00 0.00 1 426.8 135.3 197.8 0.00 0.00 1 423.7 132.9 197.8 0.00 0.00 r. , ~ :~ ~ ~s 't • Concentration of Proppant in Fracture {Ib/ft2) Stage # Length ft UpperHt ft LowerHt ft Upper Conc Ib/ft2 Lower Conc Ib/ft2 1 421.4 131.1 197.8 0.00 0.00 1 41$.3 128.6 197.8 0.00 0.00 1 415.8 126.7 197.8 0.00 0.00 1 412.5 124.1 197.8 0.00 0.00 1 410.0 122.2 197.8 0.00 0.00 1 407.4 120.1 197.8 0.00 0.00 1 4Q3.$ 117.3 197.8 0.00 0.00 1 400.9 115.1 197.8 0.00 0.00 1 398.0 112.9 197.8 0.00 0.00 1 394.2 109.9 197.8 0.00 0.00 1 391.1 107.5 197.8 0.00 0.00 1 388.1 105.1 197.8 0.00 0.00 1 383.8 101.7 197.8 0.00 0.00 1 380.5 99.1 197.8 0.00 0.00 1 376.8 96.3 197.8 0.00 0.00 1 373.0 93.3 197.8 0.00 0.00 1 369.2 90.4 197.8 0.40 0.00 1 364.2 86.5 197.8 0.00 0.00 1 360.3 83.4 197.8 0.00 0.00 1 355.9 80.0 197.8 0.00 0.00 1 350.8 76.0 197.8 0.00 0.00 1 345.2 71.6 197.8 0.00 0.00 1 337.7 65.7 197.8 0.00 0.00 1 329.6 59.4 197.8 0.00 0.00 1 319.8 51.8 197.8 0.00 0.00 1 308.0 42.5 197.8 0.00 0.00 1 294.3 31.8 197.8 0.00 0.00 1 276.0 17.6 197.8 0.00 0.00 1 250.7 0.0 195.7 0.00 0.00 1 141.3 0.0 110.3 0.00 0.00 NCU No. 5 Disposal Injection Order ~~_>: F 9-24 • • LeakoffParameters Reservoir type Gas Filtrate to reservoir fluid perm. ratio, Kp/KI 10 Reservoir pore pressure (psi) 1014 Initial fracturing pressure (psi) 2356 Reservoir fluid compressibility (1/psi) 9.87e-004 Cold filtrate viscosity (cp) 1.00 Hot filtrate viscosity (cp) '1.00 Cold reservoir viscosity (cp) 0.03 Ho# reservoir viscosi#y {cp) 0.03 Porosity 0.10 Gas Leakoff Percentage 100.00 Reservoir Parameters Reservoir temperature (°F) Depth to center of Perfs {ft) Perforated interval (ft) Initial frac depth (ft) 150.00 .2330 20 2330 Layer Parameters Layer # Top of zone ft Stress (psi) lop of zone ft Young's modulus si Poisson's ratio Top of zone ft Total Ct (ft/min'/Z} PoreFluid perm. and 1 0.0 1232 0.0 6.Oe+006 0.25 0.0 O.OOOe+000 O.OOe+000 2 1540.0 1238 1540.0 4.4e+005 0.39 1540.0 3.728e-002 5.OOe+001 3 1555.0 1335 1555.0 1.4e+006 0.33 1555.0 O.000e+000 O.OOe+000 4 1585.0 1272 1585.0 4.4e+005 0.39 1585.0 3.728e-002 5.OOe+001 5 1595.0 1280 1595.0 4.4e+005 0.39 1595.0 O.000e+000 O.OOe+000 6 1605.0 1286 1605.0 4.4e+005 0.39 1605.0 O.000e+000 O.OOe+000 7 1610.0 1375 1610.0 1.4e+006 0.33 1610.0 O.OOOe+000 O.OOe+000 8 1625.0 1226 1625.0 1.7e+006 0.31 1625.0 3.728e-002 S.OOe+001 9 1645.0 1322 1645.0 4.4e+005 0.39 1645.0 O.000e+000 O.OOe+000 10 1660.0 1258 1660.0 1.7e+006 0.31 1660.0 ~.728e-002 S.OOe+001 11 1695.0 1360 1695.0 4.4e+005 0.39 1695.0 O.000e+000 O.OOe+000 12 1705.0 1294 1705.0 1.7e+006 0.31 1705.0 3.728e-002 S.OOe+001 13 1745.0 1404 1745.0 4.4e+005 0.39 1745.0 O.000e+000 O.OOe+000 14 1765.0 1507 1765.0 1.4e+006 0.33 1765.0 O.000e+000 O.OOe+000 15 1780.0 1350 1780.0 1.7e+006 0.31 1780.0 3.728e-002 5.OOe+001 16 1820.0 1464 1820.0 4.4e+005 0.39 1820.0 O.000e+000 O.OOe+000 17 1840.0 1600 1840.0 1.4e+006 0.33 1840.0 O.000e+000 O.OOe+000 18 1925,0 1554 1925.0 4.4e+005 0.39 1925.0 O.000e+000 O.OOe+000 19 1960.0 1677 1960.0 1.4e+006 0.33 1960.0 O.OOOe+000 OAOe+000 2p 1985.0 1502 1985.0 1.7e+006 0.31 1985.0 3.728e-002 5.OOe+001 21 2020.0 1618 2020.0 4.4e+005 0.39 2020.0 O.000e+000 O.OOe+000 22 2025.0 1521 2025.0 1.7e+006 0.31 2025.0 3.728e-002 S.OOe+001 23 2030.0 1630 2030,0 4.4e+005 0.39 2030.0 O.000e+000 O.OOe+000 `. __ ~' ' t. ~f ~, ,~ _ ~ . • Layer Parameters Layer # Top of zone ft Stress (psi) Top of zone ft Young's modulus si Poisson's ratio Top of zone ft Total Ct (ft/min'/z) PoreFluid perm. and 24 2045.0 1749 2045.0 1.4e+006 0.33 2045.0 O.000e+000 O.OOe+000 25 2070.0 1666 2070.0 4.4e+005 0.39 2070.0 O.000e+000 O.OOe+000 26 2095.0 1584 2095.0 1.7e+006 0.31 2095.0 3.728e-002 S.OOe+001 27 2130.0 1821 2130.0 1.4e+006 0.33 2130.0 O.000e+000 O.OOe+000 28 2155.0 1730 2155.0 4.4e+005 0.39 2155.0 O.000e+000 O.OOe+000 29 2170.0 1744 2170.0 4.4e+005 0.39 2170.0 O.000e+000 O.OOe+000 30 2190.0 1756 2190.0 4.4e+005 0.39 2190.0 O.000e+000 O.OOe+000 31 2200.0 1874 2200.0 1.4e+006 0.33 2200.0 O.000e+000 O.OOe+000 32 2210.0 1772 2210.0 4.4e+005 0.39 2210.0 O.000e+000 O.OOe+000 33 2220.0 1919 2220.0 1.4e+006 0.33 2220.0 O.000e+000 O.OOe+000 34 2295.0 1856 2295.0 4.4e+005 0.39 2295.0 O.000e+000 O.OOe+000 35 2345.0 1880 2345.0 4.4e+005 0.39 2345.0 O.000e+000 O.OOe+000 36 2355.0 2010 2355.0 1.4e+006 0.33 2355.0 O.000e+000 O.OOe+000 37 2375.0 1914 2375.0 4.4e+005 0.39 2375.0 3.728e-002 5.OOe+001 38 2410.0 1932 2410.0 4.4e+00 0.39 2410.0 O.000e+000 O.OOe+000 39 2420.0 2057 2420.0 1.4e+006 0.33 2420.0 O.000e+000 O.OOe+000 NCU No. 5 Disposal Injection Order 9-31 Litholo gy Parameters Layer # Top of zone ft Lithology Top of zone ft Fracture Toughness si•in'f: Top of zone ft Tip Effects Factor 1 0.0 Overburde n 0.0 1000 0.0 1.00 2 .1540.0 Coal 1540.0 500 1540.0 1.00 3 1555.0 Shale 1555.0 2000 1555.0 1.00 4 1585.0 Coal 1585.0 500 1585.0 1.00 5 1595.0 Siltstone 1595.0 1000 1595.0 1.00 6 1605.0 oa! 1605.0 500 1605.0 1.00 7 1610.0 Shale 1610.0 2000 1610.0 1.00 8 1625.0 Sandstone 1625.0 1000 1625.0 1.00 9 1645.0 Coal 1645.0 500 1645.0 1.00 10 1660.0 Sandstone 1660.0 1000 1660.0 1.00 11 1695.0 Coal 1695.0 500 1695.0 1.00 12 1705.0 Sandstone 1705.0 1000 1705.0 1.00 13 1745.0 Coal 1745.0 500 1745.0 1.00 14 1765.0 Shale 1765.0 2000 1765.0 1.00 15 1780.0 Sandstone 1780.0 1000 1780.0 1.00 16 1820.0 oal 1820.0 500 1820.0 1.00 17 1840.0 Shale 1840.0 2000 1840.0 1.00 18 1925.0 Coal 1925.0 500 1925.0 1.00 19 1960.0 Shale 1960.0 2000 1960.0 1.00 20 1985.0 Sandstone 1985.0 1000 1985.0 1.00 21 2020.0 Coai 2020.0 500 2020.0 1.00 22 2025.0 Sandstone 2025.0 1000 2025.0 1.00 23 2030.0 oal 2030.0 500 2030.0 1.00 24 2045.0 Shale 2045.0 2000 2045.0 1.00 25 2070.0 Siltstone 2070A 1000 2070.0 1.00 26 2095.0 Sandstone 2095.0 1000 2095.0 1.00 27 2130.0 Shale 2130.0 2000 2130.0 1.00 28 2155.0 Siltstone 2155.0 1000 2155.0 1.00 29 2170.0 Coal 2170.0 500 2170.0 1.00 30 2190.0 Siltstone 2190.0 1000 2190.0 1.00 31 2200.0 Shale 2200.0 2000 2200.0 1.00 32 2210.0 Siltstone 2210.0 1000 2210.0 1.00 33 2220.0 Shale 2220.0 2000 2220.0 1.00 34 2295.0 Siltstone 2295.0 1000 2295.0 1.00 35 2345.0 Coal 2345.0 500 2345.0 1.00 36 2355.0 Shale 2355.0 2000 2355.0 1.00 37 2375.0 Siltstone 2375.0 1000 2375.0 1.00 38 2410.0 Coal 2410.0 500 2410.0 1.00 39 2420.0 Shale 2420.0 2000 2420.0 1.00 1. ~- • Model Parameters • Fracture Growth Parameters (FracproPT 3D Model) Crack Opening Coefficient 0.8500000 Rock Deformation Coefficient 0.0001000 Channel Flow Coefficient 1.0000000 Tip Radius Fraction 0.0100000 Tip Effects Scale Volume (bbl) 100.00 Fluid Radial Weighting Exponent set to default of Rock Deformation Coeff ! 10. Proppant Model Parameters Minimum Proppant Concentration (Ib/ft^2) 0.20 Minimum Proppant Diameter (in) 0.008 Volume Fraction of Proppant in Slurry 0.60 Proppant Drag Effect Exponent 8.0 Proppant Radial Weighting Exponent 0.2500 Proppant Convection Coefficient 10.00 Proppant Settling Coefficient 1.00 Quadratic Backfill Model ON Quadratic Backfill Coefficient 0.50 Stop Model on Screenout ON Initial Leakoff Area Coeff 1.00 Closure Leakoff Area Coeff 0.03 Minimum Fracture Height OFF Near Wellbore Friction Exponent 0.50 NCU No. 5 Disposal Injection Order 9-33 ._ _. _,._ ~ ~_1 ,~., ~ _ { Prop pant Data Pro ant Name Brad -2040 100-Mesh Cost ($/Ib) 0.070 0.070 Bulk Dens tbmtft~ 6.20 115.8 Packed Porosit 0.418 0.300 Specific Gravity s 2.65 2.65 Turbulence Coeff a 1.54 1.39 Turbulence Coeff b 1.23 1.13 Diameter in 0.024 0.006 Perm 0 si D 32.0 0.00 Perm @ 2000 psi D 32.0 0.00 Perm @ 4000 psi D 103.0 40.00 Perm @ 6000 psi D 54.00 0.00 Perm @ 8000 psi D 9.00 0.00 Perm @ 10000 psi D 15.00 40.00 Perm @ 12000 psi D 8.00 0.00 Perm @ 14000 psi D .00 0.00 Perm @ 16000 psi D .00 0.0 Perm @ 18000 psi D 1.000 0.0 NCU No. S Disposal Injection Order • 9-34 • ~~ - - ~ , ~~ "1 ,1 '1 ~;t h I ~ ~ ~ a ~" i; it{[[[s` '• i n'1 : ~'.1 / ~ i A ~ ~ ~ ~ .? ~ ~~+ ~ O ~~ , I \ ~ * '~ w ~ ~r I J ~~1 ~l aa i~ 3 ~4 i ~e 3 iw W ~~ 4 C t L NCU No. 5 Disposal Injection Order 9-35 ~~A~N~~ ~~L ~ 12a1~ Exhibit 9-4 FracproPT10.0 Hydraulic Fracture Analysis Date: December 27, 2001 Wellname: Nicolai Creek #5 Location: Formatting: Job Da#e: 12/19/2001 02:51:41 PM Filename: Nicolai Creek Run 4 Fracture Geometry Summary Fracture Half-Len th ft 299 Pro ed Half-Len th ft 0 otal Fracture Hei ht ft 351 otai Pro ed Hei ht ft 0 Depth to Fracture Top ft 2069 Max. Fracture Width (in 1.12 Depth to Fracture Bottom ft) 2420 v .Fracture Width in 0.58 Equivalent Number of Multiple Fracs 1.0 vg. Proppant Concentration (Ib/ft2 0.00 Fracture Slur Efficient 0.04 All values reported are for a single fracture Model has run until 7200.00 min Fracture Conductivity Summary Dimensionless Conductivity 0.00 Ref. Formation Permeability mD 50.0 Pro pant Damage Factor 0.50 Pro pant Permeabilit mD 20000 All values reported are for a single fracture Fracture Pressure Summary Model Net Pressure si 83 BH Fracture Closure Stress si 1856 Observed Net Pressure si 0 Closure Stress Gradient si/ft 0.797 H drostatic Head (psi) 1383 Surface Pressure (psi) 928 Averages reported during Main Frac NCU No. 5 Disposal Injection Order 9-36 1 ~~ tf ~ ~ Fracture Geometry Summary otal Clean Fluid Pumped 36026 otal Proppant Pumped 6166.3 bbls klbs Total Slurry Pumped (bbls) 36026 otal Proppant in Fracture 0.0 klbs Pad Volume (bbls) 0 vg. Hydraulic Horsepower 114 h Pad Fraction (%) 0 Max. Hydraulic Horsepower 119. h Main Fluid 10# BRINE Main Pro ant 100-Mesh Averages reported during Main Frac Treatment Schedule Stage # Elapsed Time min.sec Fluid Type Clean Volume bbls Prop Conc. Stage Prop. klbs Slurry Rate b m Proppant Type elibore Fluid 10# BRINE 75.3 1 7200:00 10# BRINE 29361.0 5A0 6165.8 5.00 100-Mesh Scheduled clean vol (bbls) 29360.99 Scheduled sand total (klbs) 6165.81 Scheduled slurry vol (bbls) 36000.00 NCU No. 5 Disposal Injection Order 9-37 _" _. _.. Lti ~. . LeakoffParameters Reservoir type Gas Filtrate to reservoir fluid perm. ratio, Kp/KI 10 Reservoir pore pressure {psi) 1014 Initial fracturing pressure (psi) 2356 Reservoir fluid compressibility (1/psi) 9.87e-004 Cold filtrate viscosity (cp) 1.00 Hot filtrate viscosity (cp) 1.00 Cold reservoir viscosity (cp) 0.03 Ho# reservoir viscosity {cp) 0.03 Porosity 0.10 Gas Leakoff Percentage 100.00 Reservoir Parameters Reservoir temperature (°F) Depth to cen#er of Perfs (ft) Perforated interval (ft) Initial frac depth (ft) 150.00 2330 20 2330 Layer Parameters Layer # Top of zone ft Stress (psi) Top of zone ft Young's modulus si Poisson's ratio Top of zone ft Total Ct (ft/mn'/2) PoreFluid perm. and 1 oA 1192 0.0 6.Oe+006 0.25 0.0 o.ooae+ooo a.ooe+000 2 1490.0 1196 1490.0 4.4e+005 0.39 1490.0 O.000e+000 O.OOe+000 3 1500.0 1290 1500.0 1.4e+006 0.33 1500.0 3.728e-002 S.OOe+001 4 1535.0 1230 1535.0 4.4e+005 0.39 1535.0 O.000e+000 O.OOe+000 5 1540.0 1238 1540.0 4.4e+005 0.39 1540.0 3.728e-002 S.OOe+001 6 1555.0 1335 1555.0 1.4e+006 0.33 1555.0 O.000e+000 O.OOe+000 7 1585.0 1272 1585.0 4.4e+005 0.39 1585.0 3.728e-002 S.OOe+001 8 1595.0 1280 1595.0 4.4e+00 0.39 1595.0 O.000e+000 O.OOe+000 9 1605.0 1286 1605.0 4.4e+005 0.39 1605.0 O.000e+000 O.OOe+000 10 1610.0 1375 1610.0 1.4e+006 0.33 1610.0 O.000e+000 O.OOe+000 11 1625.0 1226 1625.0 1.7e+006 0.31 1625.0 3.728e-002 S.OOe+001 12 1645.0 1322 1645.0 4.4e+005 0.39 1645.0 O.000e+000 O.OOe+000 13 1660.0 1258 1660.0 1.7e+006 0.31 1660.0 3.72$e-002 5.OOe+001 14 1695.0 1360 1695.0 4.4e+005 0.39 1695.0 O.000e+000 O.OOe+000 15 1705.0 1294 1705.0 1.7e+006 0.31 1705.0 3.728e-002 S.OOe+001 16 1745.0 1404 1745.0 4.4e+005 0.39 1745.0 O.OOOe+000 O.OOe+000 17 1765.0 1507 1765.0 1.4e+006 0.33 1765.0 O.OOOe+000 O.OOe+000 18 1780.0 1350 1780.0 1.7e+006 0.31 1780.0 3.728e-002 5.OOe+001 19 1820.0 1464 1820.0 4.4e+005 0.39 1820.0 O.000e+000 O.OOe+000 20 1840.0 1600 1840.0 1.4e+006 0.33 1840.0 O.000e+000 O.OOe+000 21 1925.0 1554 1925.0 4.4e+005 0.39 1925.0 O.000e+000 O.OOe+000 22 1960.0 1677 1960.0 1.4e+006 0.33 1960.0 O.000e+000 O.OOe+000 23 1985.0 1502 1985,0 1.7e+006 0.31 1985.0 3.728e-002 S.OOe+001 <,- t, • Layer Parameters Layer# Top of zone ft Stress (psi) Top of zone ft Young's modulus si Poisson's ratio Top of zone ft Total Ct (ft/min'/a) PoreFtuid perm. and 24 2020.0 1618 2020.0 4.4e+005 0.39 2020.0 O.000e+000 O.OOe+000 25 2025.0 1521 2025.0 1.7e+006 0.31 2025.0 3.728e-002 5.OOe+001 26 2030.0 1630 2030.0 4.4e+005 0.39 2030.0 O.000e+000 O.OOe+000 27 2045.0 1749 2045.0 1.4e+006 0.33 2045.0 O.OOOe+000 O.OOe+000 28 2070.0 1666 2070.0 4.4e+005 0.39 2070.0 O.000e+000 O.OOe+000 29 2095.0 1584 2095.0 1.7e+006 0.31 2095.0 3.728e-002 5.OOe+001 30 2130.0 1821 2130.0 1.4e+006 0.33 2130.0 O.000e+000 O.OOe+000 31 2155.0 1730 2155.0 4.4e+005 0.39 2155.0 O.000e+000 O.OOe+000 32 2170.0 1744 2170.0 4.4e+005 0.39 2170.0 O.000e+000 O.OOe+000 33 2190.0 1756 2190.0 4.4e+005 0.39 2190.0 O.OOOe+000 O.OOe+000 34 2200.0 1874 2200.0 1.4e+006 0.33 2200.0 O.000e+000 O.OOe+000 35 2210.0 1772 2210.0 4.4e+005 0.39 2210.0 O.000e+000 O.OOe+000 36 2220.0 1919 2220.0 1.4e+006 0.33 2220.0 O.000e+000 O.OOe+000 37 2295.0 1856 2295.0 4.4e+005 0.39 2295.0 O.000e+000 O.OOe+000 38 2345.0 1880 2345.0 4.4e+005 0.39 2345.0 O.000e+000 O.OOe+000 39 2355.0 2010 2355.0 1.4e+006 0.33 2355.0 O.OOOe+000 O.OOe+000 40 2375.0 1914 2375.0 4.4e+005 0.39 2375.0 3.728e-002 S.OOe+001 41 2410.0 1932 2410.0 4.4e+005 0.39 2410.0 O.000e+000 O.OOe+000 42 2420.0 2057 2420.0 1.4e+006 0.33 2420.0 O.000e+000 O.OOe+000 NCli No. 5 Disposat Injection Order 9-39 ~.~ ~. ~~ ~~ . Litholo gy Parameters Layer # Top of zone ft Lithology Top of zone ft Fracture Toughness si•in'/2 Top of zone ft Tip Effects Factor 1 0.0 Overburde n 0.0 1000 0.0 1.00 2 1490.0 Siltstone 1490.0 1000 1490.0 1.00 3 1500.0 Shale 1500.0 2000 1500.0 1.00 4 1535.0 Siltstone 1535.0 1000 1535.0 1.00 5 1540.0 Coal 1540.0 500 1540.0 1.00 6 1555.0 Shale 1555.0 2000 1555A 1.00 7 1585.0 oal 1585.0 500 1585.0 1.00 8 1595.0 Siltstone 1595.0 1000 1595.0 1.00 9 1605.0 Coal 1605.0 500 1605.0 1.00 10 1610.0 Shale 1610.0 2000 1610.0 1.00 11 1625.0 Sandstone 1625.0 1000 1625.0 1.00 12 1645.0 Coal 1645.0 500 1645.0 1.00 13 1660.0 Sandstone 1660.0 1000 1660.0 1.00 14 1695.0 Coal 1695.0 500 1695.0 1.00 15 1705.0 Sandstone 1705.0 1000 4705.0 1.00 16 1745.0 Coal 1745.0 500 1745.0 1.00 17 1765.0 Shale 1765.0 2000 1765.0 1.00 18 1780.0 Sandstone 1780.0 1000 1780.0 1.00 19 1820.0 Coal 1820.0 500 1820.0 1.00 20 1840.0 Shale 1840.0 2000 1840.0 1.00 21 1925.0 Coal 1925.0 500 1925.0 1.00 22 1960.0 Shale 1960.0 2000 1960.0 1.00 23 1985A Sandstone 1985.0 1000 1985.0 1.00 24 2020.0 Coal 2020.0 500 2020.0 1.00 25 2025.0 Sandstone 2025.0 1000 2025.0 1.00 26 2030.0 Coal 2030.0 500 2030.0 1.00 27 2045..0 Shale 2045.0 2000 2045.0 1.00 28 2070.0 Siltstone 2070.0 1000 2070.0 1.00 29 2095.0 Sandstone 2095.0 1000 2095.0 1.00 30 2130.0 Shale 2130.0 2000 2130.0 1.00 31 2155.0 Siltstone 2155.0 1000 2155.0 1.00 32 2170.0 Coal 2170.0 500 2170.0 1.00 33 2190.0 Siltstone 2190.0 1000 2190.0 1.00 34 2200.0 Shale 2200.0 2000 2200.0 1.00 35 2210.0 Siltstone 2210.0 1000 2240.0 1.00 36 2220.0 Shale 2220.0 2000 2220.0 1.00 37 2295.0 Siltstone 2295.0 1000 2295.0 1.00 38 2345.0 Coal 2345.0 500 2345.0 1.00 39 2355.0 Shale 2355.0 2000 2355.0 1.00 40 2375.0 Siltstone 2375.0 1000 2375.0 1.00 r ~~ t Litholo gy Parameters Layer # Top of zone ft Lithology Top of zone ft fracture Toughness si-in'/: Top of zone ft Tip Effects Factor 41 2410.0 Coal 2410.0 500 2410.0 1.00 42 2420.0 Shale 2420.0 2000 2420.0 1.00 Model Parameters Fracture Growth Parameters (FracproPT 3D Model) Crack Opening Coefficient 0.8500000 Rock Deformation Coefficient 0.0001000 Channel Flow Coefficient 1.0000000 Tip Radius Fraction 0.0100000 Tip Effects Scale Voiume (bbl) 100.00 Fluid Radial Weighting Exponent set to default of Rock Deformation Coeff / 10. Proppant Model Parameters Minimum Proppant Concentration (Ib/ft^2) Minimum Proppant Diameter (in) Volume Fraction of Proppant in Slurry Proppant Drag Effect Exponent Proppant Radial Weighting Exponent Proppant Convection Coefficient Proppant Settling Coefficient Quadratic Backfill Model Quadratic Backfill Coefficient Stop Model on Screenout Initial Leakoff Area Coeff Closure Leakoff Area Coeff Minimum Fracture Height Near Wellbore Friction Exponent NCU No. ~ Disposal Injection Order 0.20 0.008 0.60 8.0 0.2500 10.00 1.00 ON 0.50 ON 1.00 0.03 OFF 0.50 .., 9-41 Prop pant Data Pro ant Name Brad -2040 100-Mesh Cost $/lb 0.070 0.070 Bulk Dens Ibm/ftg 96.20 115.8 Pecked Porosit 0.418 0.300 Specific Gravity s .65 .65 urbulence Coeff a 1.54 1.39 Turbulence Coeff b 1.23 1.13 Diameter in 0.024 0.006 Perm 0 psi D 32.0 0.00 Perm @ 2000 psi D 32.0 0.00 Perm @ 4000 psi D 103.0 0.00 Perm @ 6000 psi D 54.00 40.00 Perm @ 8000 psi D 9.00 0.00 Perm @ 10000 psi D 15.00 0.00 Perm @ 12000 psi (D) 8.00 0.00 Perm @ 14000 psi D 4.00 40.00 Perm @ 1&000 psi D .00 0.0 Perm @ 18000 psi D 1.000 0.0 NCU No. 5 Disposal Injection Order • ~~;:,, ;- 9-42 • • NCU No. 5 Disposal Injection Order 9-43 • • 10.0 Formation Water Analysis The physical properties of the formation fluids in the prospective injection zones in NCU #5 have been analyzed and detailed through three different methods. Log analysis of the NCU #5 well, log analysis and correlation of nearby offset well NCU #3 (Exhibit 10-1), and laboratory analysis of a produced water sample from NCU #3, taken from zones that correlate with those to be injected into in NCU #5 (Exhibit 10-2). Log analysis of NCU #S injection interval was performed by an independent party using both the SP and the Rwa interpretation method. Both are industry standard methods for determining natural formation water salinity. Based on the SP log analysis method for the injection interval from 2300' - 2350', the formation water Total Dissolved Solids (TDS) content is calculated to be 13,500 ppm. When the Rwa method is applied, it can be shown that using a formation porosity of 25% (current porosity estimates of the Beluga formation at this depth range from 24 - 28%), the formation water TDS content is calculated to be 10,500 ppm (Exhibit 10-1). While it is understood that formation water salinity determination through log analysis is an inferred number, it can be shown that the intervals to be injected into correlate with perforated producing intervals in the NCU #3 well which is 3230' to the east of NCU #3 (Figure 10-1 and Exhibit 5-1) Based on laboratory analysis of a sample of produced water from the aforementioned and identified correlative zone, the Total Dissolved Solids (TDS) of the formation water has been determined to be 10,500 ppm. The actual breakdown of identified components and results of the produced water analysis are presented in Exhibit 10-2. NCU #5 /NCU #3 Correlation Chart Marker NCU#5 NCU#3 Gas Pa ~ Salinities Sandstone 1985-2020 :1900-1940: yes 10,500 Sandstone 2095-2130 :2010-2030: yes ~ 10,500 Tblu 2190 2100 Sandstone :2065-2090 Siltstone 2295-2345 :2200-2240: yes : 10,500 Coal ~ 2258-2270 Siltstone 2375-2410 :2300-2330: yes 10,500 Coal Siltstone :2330-2340 : ; 2360-2378 yes 10,500 Figure 10-1 NCU No. 5 Disposal Injection Order 10-1 Exhibit 10-1 Nicolai Creek Unit No. 3 Produced Water Analysis And Cross Correlation to Nieolai Creek Unit No. 5 Injection Zones. NCU No. 5 Disposal Injection Order ~. ; . ~ a L'~ 10-2 • Analytica Alaska Southeast 5438 Shaune Drive Juneau, AK 99801 (907)780-6668 l=ax (907) 780-6670 AI~AL~T'I~A Environmental Laboratories 11/26/01 Fairweather E & P P.O. Box 103296 Anchorage, AK 99510-3246 Attn: Jeff Osborne Work Order #: J0110064 Date: 11/26/01 Work ID: Nicolai Creek Unit #3 Date Received: 10/23/01 Sampte tdentification Lab Sample Number Client Description .Lab Sample Number Client Description J0110064-01 Produced Water Enclosed are the analytical results for the submitted sample(s). Please review the CASE NARRATIVE for a discussion of any data. andlor quality control issues. Listings of data qualifiers, analytical codes, key dates, and QC relationships are provided at the end of the report. Sincerely, David Wetzel Project Manager "The Science of Analysis, The Art of Service" r -_ ,. _ ;~it~~~ ;, r Case Narrative Analytiea Alaska Southeast Work Order: J0110064 Samples were prepared and analyzed according to methods outlined in the following references: o Methods far Chemical Analysis of Water and Wastes, USEPA 600/4-79-020, March 1983. o Test Methods for Evaluating Solid Waste, USEPA SW~846, Third Edition, Revision 4, December 1996. Problems encountered with the analyses are discussed in the following narrative. i Cr, Cu, Pb, Mn, and Zn are present in a small amount in the laboratory method blank. This value is less than 1 /10 of any detected values in the samples, so the effect on the data is insignificant. {f 4 ~gF • Detailed Analytical Report Analytica Alaska Southeast Workorder (SDG): 70110064 Project: Nicolai Creek Unit #3 Client: Fairweather E & P Client Project Number: none Report Section: Client Sample Report Client sample Name:. produced Water Matrix: Aqueous Collection Date: 10/18/01 4:45:OOPM Lab Sample Number: 70110064-01B Analysis Date: 11!14!01 5:59:15PM Prep Date: 11/8/01 Instrument: Elan Analytical Method ID: SW6020 -ICPMS -ICPMS Total File Name: JQ11112009.es Prep Method ID: 3010A Dilution Factor: 5 Prep Batch Number; 70 1 1 1 1 2009 Report Basis: As Received Analyst Initials: SAW Anal to CASNo Result 1'IaPS Units ~ MIL Rerun #• Aluminum 7429-90-5 ND ug/L 25 3.4 1 Antimony 7440-36-0 ND ug/L 2.5 0.43 Arsenic 7440-38-2 5.13 ug/L 5.0 0.43 Barium 7440-39-3 3,910 ug/L 1.3 0.32 Beryllium 7440-41-7 ND ug/L 1.5 0.50 Cadmium 7440-43-9 ND ug/L 1.0 0.15 Chromium 7440-47-3 3.85 ug/L 0.50 0.15 Cobalt 7440-48-4 4A1 ug/L 0.50 0.15 Copper 7440.50-8 130 ug/L 2.5 0.85 Lead 7439-92-1 7.68 ug/L 0.75 0.19 Manganese 7439-96-5 2,130 ug/L 2.5 0.31 Molybdenum 7439-98-7 ND ug/L 5.0 0.75 Nickel 7440-02-0 37.9 ug/L 2.5 0.050 Selenium 7784-49-2 20.4 ug/L 5.0 1.5 Silver 7440-22-4 ND ug/L 1.8 0.55 Thallium 7440-28-0 ND ug/L 1.3 0.21 Vanadium 7440-62-2 66.5 ug/L 5.0 0.75 Zinc 7440-66-6 47.8 ug/L 5.0 0.80 Lab Sample Number: 70110064-O1B Analysis Date: 11/14/01 6:07:17PM Prep Date: 11/8/O1 Instrument: Elan Analytical Method ID: SW6020 -ICPM S -ICPMS Total File Name: J011112009.cs Prep Method ID: 3010A Dilution Factor: 100 Prep Batch Number: 7011112009 Report Basis: As Received Analyst Initials: SA Anal to CASNo Result wt's Units P L MDL Rerun #: Calcium 7440-70-2 406,000 ug(L 5,000 890 3 Iron 7439-89-6 85,500 ug/L 5,000 490 Magnesium 7439-96-5 225,000 ug/L 5,000 170 Potassium 7440-09-7 375,0(10 ug/L 5,000 630 Sodium 7440-23-5 3,870,000 ug/L 5,000 740 Page 3 of 9 .~ (' F 1 1. CJ Detailed Analytical Report Analytica Alaska Southeast Workorder (SDG): 70110064 Project: Nicolai Creek Unit #3 Client: Fairweather E & P Client Project Number: none Report Section: Clien t Sample Report Client sample Name: Prodaced Water Matrix: Aqueous Collection Date: 10/18/01 4:45:OOPM Lab Sample Number: 70110064-O1C Analysis Date: 11/5101 6:43:48PM Prep Date: 10/31/01 Instrument: Elan Analytical Method ID: 200.8 -Metals by ICP/MS - ICPMS Dissolved File Name: JQ ll03100Lcs Prep Method ID: 200.8-D Dilution Factor: 1 Prep Batch Number: 7011031001 Report $asis: As Received Analyst Initials: SAW Anal to CASNo Result F~QS Units ~ ~L Rerun #• Aluminum 7429-90-5 ND uglL 1.0 0.33 1 Antimony 7440-36-0 1.01 ug/L 0.10 0.027 Arsenic 7440-38-2 11.6 ug/L 0.15 0.044 Beryllium 7440-41-7 ND ug/L 0.15 0.045 Cadmium 7440-43-9 ND ug/L 0.20 0.062 Chromium 7440-47-3 1.16 ug/L 0.15 0.049 Cobalt 7440-48-4 4.08 ug/L 0.50 0.14 Copper 7440-50-8 9.80 ug(L 0.10 0.034 Lead 7439-42-1 ND ug/L 0.10 0.030 Molybdenum 7439-98-7 3.68 ug/L 0.50 0.13 Nickel 7440-02-0 29.2 ug/L 0.15 0.050 Selenium 7784-49-2 44.4 ug/L 0.50 0.14 Silver 7440-22-4 0.154 ug(L 0.10 0.028 Thallium 7g40.2g_0 ND ug/L 0.050 0.017 Vanadium 7440-62-2 25.7 ug/L 5.0 1.4 Zinc 7440-66-6 30.0 ug/L 0.25 0.084 Lab Sample Number: 70 1 1 0064-O1C Analysis Date: 11/5/O1 10:10:57PM Prep Date: 10/31/01 Instrument: Elan Analytical Method ID: 20Q.8 -Metals by ICP/Pv1S - ICPMS Dissolved File Name: JQ11031QQLcs Prep Method ID: 200.8-D Dilution Factor: 5 Prep Batch Number: 7011031001 Report Basis: As Received Analyst Initials: SA Anal to CASNo Result Flans Units >~ 1'~L Rerun #: Barium 7440-39-3 3,000 ug/L 1.3 0.41 2 Iran 7439-89-6 31,200 ug/L 250 75 Manganese 7439-96-5 1,890 ug/L 0.25 0.085 Lab Sample Number: 70110064-O1C Analysis Date: 11/5/01 10:15:04PM Prep Date: 10/31/01 Instrument: Elan Analytical Method ID: 200.8 -Metals b y ICP/MS - ICPMS Dissolved File Name: J011031001.cs Prep Method ID: 200.8-D Dilution Factor: 100 Prep Batch Number: 7011031001 Report Basis: As Received Analyst Initials: SA Anatyte C SNo Result FIaPS Units P L MDL Rerun #: Page 4 of 9 f ~~n,~ i .. , • i Detailed Analytical Report Analytica Alaska Southeast Workorder (SDGj: J0110064 Project: Nicolai Creek Unit #3 Client: Fairweather E & P Client Project Number: none Report Section: Client Sample Report cieQt sample Name: produced Water Matrix: Aqueous Collection Date: 10/18f01 4:45:OOPM Lab Sample Number: J0110064-O1C Analysis Date: 11/5/O1 10:15:04PM Prep Date: 10/31/01 Instrument: Elan Analytical Method ID: 200.8 _ Metals by ICP/MS - ICPMS Dissolved File Name: JOL1031001.es Prep Method ID: 200.8-D Dilution Factor: 100 Prep Batch Number: J011031001 Report Basis: As Received Analyst Initials: SA Anatvte CASNo Result Flans Units P L ~L Rerun #: Calcium 7440-?0-2 418,000 ug/L 25,000 5,800 3 Magnesium 7439-96-5 209,000 ug/L 50,000 12,000 Potassium 7440-09-7 319,000 ug/L 50,000 20,000 Sodium 7440-23-5 3,510,000 ug/L 50,000 13,000 Lab Sample Number: J0110064~O1A Analysis Date: 10/25/01 2:02:OOPM Prep Date: 10/23/01 Instrument: SCALE Analytical Method ID: 160.1 -Residue, Filterable, Gravimetric, Dried at 180C - File Name: Prep Method ID: 160.1 Dilution Factor: 1 Prep Batch Number: J011024010 Report Basis: As Received Analyst Initials: CT Arai to CASNo Result F1aPS Units ~ MDL Rerun #: Total Dissolved Solids 1Q500 mgfL 20 5.0 2 Page 5 of 9 Detailed Analytical Report Workorder (SDG): Project: Client: Client Project Number: 70110064 Nicolai Creek Unit #3 Fairweather E & P none Page 6 of 9 • Analytica Alaska Southeast ~~rn ' ~ , t' ~.f' ~; • • Detailed Analytical Report Analytica Alaska Southeast Workorder (SDG): 70110064 Project: Nicolai Creek Unit #3 Client: Fairweather E & P Client Project Number: none QC BATCH ASSOCIATIONS - BY METHOD BLANK Lab Project 1D: 6,351 Lab Project Number: 70110064 Test: 160.1 -Residue, Filterable, Gravimetric, Dried at 180C - (TDS) Prep Date: 10/23/01 Lab Method Blank Id; 7011024010-MB Prep Batch ID: 7011024010 Method: 160.1 -Residue, Filterable, Gravimetric, Dried at 180C - (TDS) This Method blank and sample preparation batch are associated with the following samples, spikes, and duplicates: SampleNum ClientSampleName DataFile AnalysisDate 70110050-O1A Batch QC 10/23/01 3:28:O1PM 70110064-O1A Produced Water 10/25/01 2:02:OOPM 7011024010-LCS LCS 10/23/01 3:28:OIPM 7011024010-LCSD LCSD 10/23/01 3:28:O1PM 70110050-OlA-DUP DUP 10/23101 3:28:O1PM Test: 200.8 -Metals by ICPMS -ICPMS Dissolved Prep Date: 10/31/01 Lab Method Blank Id: 7011031001-MB Prep Batch ID: 7011031001 Method: 200.8 -Metals by ICPMS -ICPMS Dissolved This Method blank and sample preparation batch are associated with the following samples, spikes, and duplicates: SampleNum ClientSamoleName DataFile AnalysisDate 70 1 1 0064-O1C Produced Water J011031001.csv 1115101 6:43:48PM 70 1 1 0064-O1C Produced Water J011031001.csv 11/5/O1 10:10:57PM 70110064-O1C Produced Water J011031001.csv 11/5/O1 10:15:04PM 70110077-07B Batch QC J01103100Lcsv 11/5/O1 6:10:49PM 7011031001-LCS LCS J011031001.csv 11/5/O1 5:29:56PM 7011031001-LCSD LCSD J011031001.csv 11/5101 5:34:04PM 70110077-07B-MS MS JO1I031001.csv 11/5/O1 6:14:56PM 70110077-07B-MSD MSD J011031001,csv 11/5/O1 6:19:03PM Page 7 of 9 - ~,: ,, {. , ._ ~.,,~.s • Detailed Analytical Report Analytica Alaska Southeast Workorder (SDG): 70110064 Project: Nicolai Creek Unit #3 Client: Fairweather E & P Client Project Number: none QC BATCH ASSOCIATIONS - BY METHOD BLANK Lab Project ID: 6,351 Lab Project Number: Jt)11QU64 Test: SW6020 -ICPMS -ICPMS Total Prep Da te: 11/8/01 Lab Method Blaak Id: 701 1 1 12009-MB Prep Batch ID: 70 1 1 1 1 2009 Method: SW6020 -ICPMS -ICPMS Total This Method blank and sample preparation batch are associated with the following samples, spikes, and duplicates: SampleNum ClientSampleName DataFile AnalysisDate 70110064-O1B Produced Water J011112009.csv 11/14/01 5:59:15PM 70 1 1 0064-OIB Produced Water J01 1 1 12009.csv 11/14/01 6:07:17PM 70110077-02B Batch QC J01 1 1 12009.csv 11/14/O1 1:52:SSPM 70 1 1 1 1 2009-LCS LCS 70 1 1 1 1 2009.csv 11/14/01 1:01:19PM 70 1 1 1 1 2004-LCSD LCSD J011112009.csv 11/14/01 1:05:21PM 70110077-02B-MS MS J011112009.csv 11/14/01 1:56:56PM 70110077-02B-MSD MSD J011112009_csv 11114/01 2:00:57PM DATA FLAGS AND DEFINITIONS Reporting Limit: Limit below which results are shown as "ND". This may be the PQL, MDL, or a value between. See the report conventions below. Result Field: ND =Not Detected at or above the Reporting Limit NA =Analyte not applicable (see Case Narrative for discussion) Qualifier Fields: LOW =Recovery is below Lower Control Limit HIGH =Recovery , RPD, or other parameter is above Upper Control Limit E =Reported concentration is above the instrument calibration upper range Organic Analysis Flags: B =Analyte was detected in the laboratory method blank J = Analyte was detected above MDL or Reporting Limit but below the Quant Limit (PQL) Inorganic Analysis Flags: J =Analyte was detected above the Reporting Limit but below the Quant Limit (PQL) W =Post digestion spike did not meet criteria S =Reported value determined by the Method of Standard Additions (MSA) Other Flags maybe applied. See Case Narrative for Description Page 8 of 9 ~ ~ r~ f r -. - _ ,i ~ a I"1 LJ Detailed Analytical Report Workorder (SDG): J0110064 Project: Nicolai Creek Unit #3 Client: Fairweather E & P Analytica Alaska Southeast :uenr rro,ec[ wumoer: uvuc REPORTING CONVENTIONS FOR THIS REPORT TestPkgName Basis # Sig Figs Reuorting Limit 160.1/160.1 (Aqueous) - (TDS) As Received 3 Report to PQL 200.8/200.8 (Aqueous} -ICPMS Dissolved As Received 3 Report to PQL 6020/3010A (Aqueous) -ICPMS Total As Received 3 Report to PQL Page 9 of 9 • Exhibit 10-2 Nicolai Creek Unit No. 5 Log Analysis and Total Dissolved Solids Determination And Cross Correlation with Nicolai Creek Unit No. 3 NCU No. 5 Disposal Injection Order ,;~,n r Ia-I1 C • Schwaler~ Formation Water Salinity Determination Nicolai Creek Unit 5 Company Field Well Date Logged Date Processed Reference Number API Number Log Analyst Fairweather E&P Services Nicolai Creek Nicolai Creek Unit 5 10-FEB-1972 23-NOV-2001 21487 50-283-20036-00 : Douglas Hupp, PE Alaska Data and Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, Alaska 99503 X907)273-1700 411 interpretations an opiniors based on infererx;es from electrical or otfrer measurements and we cannot, and do not guarantee the acarracy or correctness of any inter{aetationssnd gyve shall not, except in the case of gross or wi Ilful negligence on our part, be liable or responsible for am/ loss, cost, damages or expenses incurred or sustained by anyone resulting fmm arty interpretation made by any of orx officers, agents or erraoloyees. These interpretations are also subject tp clause 4 of our general tears ~ rxxxlitions as set out in our Curren price sdtedule. _ _ ~t1i,a • • Fairweather Log Date: 10-FEB-1972 Field: Nicolai Creek WeIL• Nicolai Creek unit 5 Introduction Fairweather E&P Services, Inc. (Fairweather) has asked Schlumberger to evaluate the salinity of the formation water on well Nicolai Creek Unit 5, which was drilled by Texaco in 1972. The intervals of interest are from 2300 ft to 2350 ft and 2500 ft to 2550 ft. The data available for this evaluation included Dual Induction - Laterolog, Gamma Ray, and Sonic well logging tools. In addition, Fairweather asked Schlumberger to discuss possible formation correlations between the Nicolai Creek Unit 3 and Nicolai Creek Unit 5 wells. Salinity Determination The salinity of the formation water (Rw- was determined by two techniques, SP interpretation and Rwa interpretation. Both techniques assume the fluid in the formation is water with no hydrocarbon. The charts used in this work are included in this report. SP Interpretation SP interpretation consisted of the following steps. 1. Determine temperature at the zone of interest (Tzone = 40 + 0.013 X Depth) 2. Determine Rmf attemperature of zone (Chart Gen-9) 3. Determine Rmfeq (Chart SP-2- 4. Determine SP deflection from shale baseline 5. Determine constant K (K = 61 + (0.133 x Temperature)) 6. Determine Rweq from formula SPdeflection = -k x log (Rmfeq/Rweq) 7. Determine Rw (Chart SP-2) 8. Determine salinity (Chart Gen-9) Zone 2300 ft to 2350 ft. 1. Temperature at zone = 70.2 °F 2. Rmf attemperature = 2.56 ohm-m 3. Rmfeq =1.2 ohm-m 4. SP deflection = -30 my 5. K = 70.3 6. Rweq = 0.45 7. Rw = 0.46 ohm-m 8. Salinity =13,500 ppm Zone 2500 ft to 2550 ft. 1. Temperature at zone = 72.8 °F 2. Rmf attemperature = 2.56 ohm-m 3. Rmfeq =1.2 ahm-m 4. SP deflection = -25 my 5. K = 70.3 6. Rweq = 0.53 7. Rw = 0.58 ohm-m 8. Salinity =11,000 ppm 4 r• F ~ ~~ r•', ... ._ .~- 'i... .. • Fairweather tog Date: 10-FE8-1972 Field: Nicolai Creek Well: Nicolai Creek Unit 5 Rwa Irrterpretation Rwa interpretation consists of the following steps. 1. Determine Rt from the DIL log 2. Determine Otlog from sonic log 3. Calculate porosity {~) from the sonic log {c~ = 0.67 x (Otlog - Otmatrix) / ©tlog) 4. Calculate Rwa (Rwa = cI~2 x Rt / 0.81- 5. Determine salinity (Chart Gen-9) The sonic measurement in this well is the largest source of uncertainty in the Rwa interpretation technique. Sonic measurements at shallow depths can be affected by poor compaction of the rock. If this is the case, the sonic porosity calculated from the equation in step 3 (above) may result in an optimistic (high) .interpreted porosity. A description of the Nicolai Creek Gas Field in the Oil and Gas Fields in the Cook Inlet Basin, Alaska, published by the Alaska Geological Society, 1975 indicated the porosity of the pay ranged from 25% to 35%. Salinity results are presented in this report are based on porosity from the Hunt-Raymer equation and assuming porosity = 25%. Porosity from Hunt-Raymer Equation Zone 2300 ft to 2350 ft. 1. Rt = 7.7 ohm-m 2. etlog =120 µsec/ft 3. ~ = 35.9% 4. Rwa =1.23 ohm-m 5. Salinity = 4900 ppm Porosity Assumed to be 25°k Zone 2300 ft to 2350 ft. 1. Rt = 7.7 ohm-m 2. atlog =120 µsec/ft 3. ~ =Assume 25% 4. Rwa = 0.59 ohm-m 5. Salinity =10,500 ppm Zone 2500 ft to 2550 ft. 1. 9t = 5.7 ohm-m 2. ~tlog =125 µsec/ft 3. ~= 37.2% 4. Rwa =1.22 ohm-m 5. Salinity = 4900 ppm Zone 2500 ft to 2550 ft. 1. Rt = 5.7 ohm-m 2.dtlog=125 µsec/ft 3. ~= Assume 25% 4. Rwa = 0.44 ohm-m 5. Salinity =14,000 ppm Correlation Comparison Fairweather asked Schlumberger to discuss the correlation between Nicolai Creek Unit 3 and Nicolai Creek Unit 5 wells. Zones of interest for correlation ranged from 1900 ft to 2330 ft in the Nicolai Creek Unit 3 well and 1985 ft to 2410 ft in the Nicolai Creek Unit 5 well. Cross well correlations are subjective, being based on logging curve similarities. Several factors, beyond the control of this analyst, affect the accuracy of this work including lithological changes, formation fluid differences, borehole mud salinity differences, and other geological variations. Similar log responses were noted as described in Table 1. ~~ .. ~ ,.. ' i _ '~ ~~~~~ Fairweather Log Date: 10-FE13-1972 Field: Nicolai Creek Weil: Nicalai Creek Unit 5 Table 1 Nicalai Greek Unit 5 Nicalai Creek Unit 3 Discussion 2550 ft 2500 ft Very sharp increase SP at the base of apparent sand. This suggests a possible errosional unconfarmity. 2375 ft to 2410 ft 2300 ft to 2330 ft Apparent fining upward sequence noted on SP. 2350 ft 2265 ft Increase resistivity spike noted on both logs. 2190 ft 2100 ft Increase resistivity spike noted on both logs. Summary Interpreted salinities based on SP and Rwa techniques range from 4900 ppm to 13,500 ppm for the upper zone and between 4900 ppm and 14,000 ppm for the lower zone. The SP and Rwa techniques show close agreement in salinity when the formation porosity is assumed to be 25%, ranging from 10,500 ppm to 14,000 ppm. If you have any questions regarding the formation water salinity calculations, please feel free to contact Douglas Hupp at (907- 273-1700. l~`~'~. t ~ F .__ • Resistivity of NaCI Solutions 8 s 5 4 3 2 1 0.8 ~ 0.6 E 0.5 0.4 0 0 0.3 O '~ 0.2 .~ .~ N 0.1 0.08 0.06 0.05 0.04 0.03 0.02 0.01 Conversion approximated by R2 = R1 [(T1 + 6.77)/(TZ+ 6.77)]°F or RZ = R1 [(T1 + 21.5)/(Tz+ 21.5))°C 10 a I ?oo 3pO ~0 moo` ~O, ~pO ~0` ~OOo ~?oo IgOO IjOO ?°oo X00 4°00 S°OO ~0 , °0 . ~D ~ ~ 0 ? pO ~ 0 4~ '~~O ~~ 0 30 ai 0 ao '°oo. "~D. 6p 1p °p° 8° O 'O ~p . 0 7? °p0 7 ~ °00 ~ '0p0 ~O ?p~~°0 ?g~ °O ?g~OOp °F 50 75 100 125 150 200 250 300 350 400 °O °C 10 20 30 40 50 60 70 80 90 100 120 140 160 180 200 I I I I I I 1 I I I I I I I I I 1 I Temperature (°F or °C) ~ Schlumberger V~~Ctl4./ , U L. l~ 1 ~V V'i Gen-9 ti m m v~ c 10 15 20 25 30 40 50 m rn C .~ v~ 100 `o E a 150 ~' c O 200 ip 250 m U 300 400 ~ 500 Z 1000 1500 zooo 2500 3000 4000 5000 10,000 15,000 zo,ooo 1-5 Gen ~ / 11 '1 ~1 • RW versus RWeq and Formation Temperature SP-2 (English) SP E E 0 m 0.05 E 0.001 0.002 0.005 0.01 O v m ~ 0.1 a smuy~ ~ 300°F - 200°F ~ _150°F - _100°F ' 75°F Saturation 0.02 0.2 0.5 1.0 \_I 0.005 0.01 0.02 0.03 0.05 0.1 0.2 0.3 0.5 1.0 RW or Rm, (ohm-m) These charts convert equivalent water resistivity, RWeQj from Chart SP-1 to actual water resistivity, RW. They may also be used to convert Rmf to Rmeey in saline muds. Use the solid lines for predominantly NaCI waters. The dashed lines are approximate for "average" fresh formation waters (where effects of salts other than NaCI become signifi- cant). The dashed portions may also be used for gyp-base mud filtrates. 2 3 4 5 F.'_runy~le: RW~ = 0.025 olun-m at 120°C From chart, RW = 0.031 ohm-m at 120°C Special procedures for muds containing Ca or Mg in solution are discussed in Reference 3. Lime-base muds usually have a negligible amount of Ca in solution; they may be treated as regular mud types. 2-s 11.0 Aquifer Exemption Order Class II waste disposal by injection is permitted regularly in aquifers with a Total Dissolved Solids (TDS) concentration greater than 10,000 PPM. TDS concentrations in the proposed injection zones, located between depths of 2000' - 2350' in the Nicolai Creek Unit No. 5 well, are estimated as being between 10,500 and 13,500 PPM based on log analysis and water analysis from offset well Nicolai Creek Unit No. 3. As detailed in the formation water description of section 10.0 of this application, it can be shown that the Total Dissolved Solids content of the formation that will be injected into exceeds the 3,000 - 10,000 ppm minimum TDS limit required for application of a Freshwater Aquifer Exemption. In view of the aforementioned results and in accordance with the rules laid out in [20 AAC 25.440(a)(2)] of the Regulations in the Alaska Administrative Code, no Freshwater Aquifer Exemption is necessary, so at this time none will be submitted. NCU No. 5 Disposal Injection Order 11-1 ~i.f r ~ 12.0 Mechanical Condition of Wells [20 AAC 25.252(c)(12)] There are no known wells, producing or abandoned, within one quarter mile of the Nicolai Creek Unit No. S. The closest well is Nicolai Creek Unit No. 3, a producing gas well operated by Aurora Gas. Figure 12-1 depicts the current completion configuration of producing gas well NCU #3. The well is 3,230' due east of Nicolai Creek Unit No. 5 (Figure 2-3). NCU No. 5 Disposal Injection Order 12-1 P F); a Proposed X~ Present Condition 31/1`2" Production Tubing Perforations 1900' - 1930' I TOL @ 1941' Pe rforatlons 2005' - 2032' M D Pe rforatlons 2201' - 2238' M D Perforations 2302' - 2328' M D Pe rforatlons 2360' - 2380' M D PBTD @ 2478' ~,'~ Drilling Mud Drilling Mud Drilling Mud BullPlug @ 2385' 20" Cemented W/720 Sks Baker Model DI @ 1803' MD Sliding Sleeve ' 9 518"47# Bakerwekl Screen @ 1900 -1931' Well has been Gravel Packed with 29,744 Ibs of gravel. ii 13 318" 54.5# ~,' WI 1770 Sks Cmt @ 2001' 3112" 9.2# Bakerwekt Screen 1933' - 2346' 7" 29# N-80 Liner @ 2522' Cement WI220 Sks Cmt 50 Sk CemeM Plug from 4915' to 5000' 50 Sk Cement Plug from -6890' to 7000' TD @ 8841' • Nicolai Creek No. 3 Nicolai Creek Field Size Wt. Grde Thrd Depth Sks/Cmt CONDUCTOR 20" 85# 282' 720 Sks SURFACE 3/8„ 54.5# .l-55 2001' 1770 Sks INTERMEDIATE 7" 29# N-80 2522' 220 Sks LINER PRODUCTION TUBING 3 1 /2" 9.2 # L-80 8-RD 2385' PTD: 167-007 (Packer API: 283-20003 Re-Entry Start Date: Dec 6, 2000 Date Re-Completed: Dec 25, 2000 Elev. (RKB) 16' (Ground Elevation 246' AMSL) @ 1812' All depths are RKB measured depths. Figure 12-1 DRAWING NOT TO SCALE Nicolai Creek No. 3 FAIRWEATHER E&P SERVICES INC. Rev. 01 Final / DM/ 18-Dec-01 NCU No. 5 Disposal Injection Order 12-2 13.0 Mechanical Integrity of Disposal Well [20 AAC 25.252(d)] The Nicolai Creek Unit No, 5 disposal well will undergo a series of mechanical integrity tests and evaluations during re-entry, recompletion and operation. Subsequent to drilling out the cement plug at surface, the casing will be cleaned and flushed to the top of the cement plug at 2550' and pressure tested to 1500 psi for 30 minutes. The cement job will then be evaluated with a USIT cement evaluation logging tool or equivalent. After running the completion packer and tubing, the casing/tubing annulus will also be pressure tested to 1,500 psi for 30 minutes. Mechanical integrity will be monitored daily during injection operations by recording the pressure on the tubing/casing annulus. NCU No. 5 Disposal Injection Order 13-1 .ti,,4 . ~ , _._ . 14.0 Areal Considerations for Disposal Injection Order With regard to Alaska Administrative Code [10 AAC 25.440 (a) parts (1) & (2)] extensive research of records at both Alaska Department of Natural Resources (DNR) and the United States Geological Society (USGS) did not reveal any "recorded" domestic water wells within 5 miles of the proposed injection site. The closest recorded domestic water supply is a freshwater surface flowing artesian spring known as Markley's Spring, recorded as being located in the NW '/4 of Sec. 27 (LAS 3400) or approximately 2 '/z miles distant in a south easterly direction (Exhibit 14-1). The closest known water well is a 120' deep utility water well located at Nicolai Creek Unit #3, which is 3230' distant to the east of NCU #5. Research also shows there are two known 200' deep drinking water wells located at the Ivan River Production pad which is over 25 miles away to the North East. The closest residence at this time is a camp used to house 2 production operators at the Granite Point Tank farm which is over 2 miles to the south east of NCU #S. Drinking wa#er for the camp is gathered at the aforementioned Markley's Spring. There is a housing facility at Shirleyville '(Granite Point area), which is closed at this time but is being considered for renovation and use by rig and construction crews while redeveloping the Nicolai Creek Unit Field. The Shirleyville facility is located approximately 2 '/2 miles to the south east of NCU #5, along the edge of the Cook Inlet, and potable water when required, is hauled in. The closest year round residential area is the village of Tyonek, which has a population of 193 people according to year 2000 census estimate. Tyonek is over 11 miles to the northeast of NCU #5, and the drinking water requirements for Tyonek are provided by a ga#hering system which intakes water from Second Lake, a freshwater lake 1 mile to the Northwest of Tyonek. The water is treated and held in a 175,000 gallon storage tank for local consumption. At this time, and for the foreseeable future because of its remote location,. climatic and local hydrology considerations, the area surrounding the Nicolai Creek Unit is not considered a desirable location for residential development or farming. The surface terrain is primarily water saturated peat moss. While heavily forested with birch, spruce and alders, there is no industry to support any residential development. The village of Tyonek is isolated and is accessible by air or boat only. There is no industry and the area primarily offers a subsistence type lifestyle with few opportunities for employment or growth. A small percentage of the local residents hold commercial fishing permits and some income is obtained through fishing charter operations. The nearest major developed area on the northwest side of the Cook Inlet is the community of Wasilla, which is approximately 65 miles to the northeast. The closest oil and gas producing property is the Granite Point field, offshore Granite Point and due east of Nicolai Creek, and the North Trading Bay Unit, southwest of Nicolai Creek Unit. Three nearby gas fields, the Anadarko Lone Creek, the Moquawkie, and the Albert Kaloa, are at this time suspended (See Figures 2-1 and 2-2). In summary, at this time there are no known water wells that exceed 200' in depth within miles of the proposed injection site. The natural fresh water drive offered by the glaciers and seasonal snow pack located at higher elevations combined with the hydrology of the surrounding area is NCU No. 5 Disposal Injection Order 14-1 • ~ such that there would be no reason to drill to the depth of the prospective injection zone at 2300' for drinking water. It would be cost prohibitive to drill, cost prohibitive to desalinate to drinking water standards and would afford no economic reason for doing so. One could argue also, that because of the numerous shallow gas sands and gas bearing coal beds in the area, it would technically be foolhardy to attempt to drill a freshwater well beyond the surface gravels, as the potential for disaster from a shallow gas blow-out increases dramatically as one drills deeper. NCU No. 5 Disposal Injection Order 14-2 ~ • Exhibit 14-1 Plat Map North Trading Bay Markley Spring Location NCU No. 5 Disposal lnjection Order 14-3 _, r s> r LEGEND TOWNSHIP 11N RANGE 12W OF THE SEWARD MERIDIAN, ALASKA WATER ESTATE ORAPIRC PIARMATRN QR.Y PBMCP ODCUAIm11P R@Mp 1110 OmlflAl. ARgID BA36 INFO RMATION --~"''~'.''~ mYDRODRAPHY BURVEY LP'DS _..._._..__.....__._ 81RAVbY LD7' LOrB - ~- - TDHTI9MPBH(77ON GRID - _ _ .- IN SRCI'IDN WM8 HIOFRIIAY ROAD ___________ ,-~-.- fig, RARR0,1D ~-~--~ SAL PON®t LRAR ~. ~ ~ 1----11--1 i--r~ Tffi18PNDNR IRAG PIPf9 1N0 - - - . A1RA0RTILAMWIq STRIP ~ m0RTL01ffAL CDgiRq. Q CbNIRA1. 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