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DIO 013
Image Project Qrder File ~c~ver Page XHVZE This page identifies those items that were not scanned during the initial production scanning .phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. -~ ~ Order File Identifier Organizing (done) RES AN Color Items: ^ Greyscale Items: ^ Poor Quality Originals: ^ Other: Two-sided IIIII~IIIIIIIIIIIII DIGITAL DATA ^ Diskettes, No. ^ Other, No/Type: o ~„~a~~eeeea iiumiiuiuiiii OVERSIZED (Scannable) ^ Maps: Other Items Scannable by ~ ~ , a Large Scanner ~ ~>;~ S i ~ 1:i~ ~ ~~ OVERSIZED (Non-Scannable) ^ Logs of various kinds: NOTES BY: / Maria Project Proofing BY: Date: ~ l , Scanning Preparation x 30 = BY: Maria Date: ~ Production Scanning /s/ / / + =TOTAL PAGES ~ ~ (lam (Count does not include cover sheet) /s/ III II~IIIIIIN VIII Stage 1 Page Count from Scanned File: ~~J ~ / (Count does include cover heat) Page Count Matches Number in -Scanning-Pre aration: L~ YES NO BY: Maria Date: ~ ~ ~ ~ /s/ ~. Stage 7 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. III II'III VIII II III ReScanned III IIIIIIIIIII VIII BY: Maria Date: /s/ Comments about this file: Date: ^ Other:: !s/ a ,«e~,~ uiuumuuiim 10/6/2005 orders Fire Cover Page.doc ~ • North Trading Bay Unit Well S-4 1. October 22, 1996 Inter-office memo re: Annular disposal of work over and produced fluid, Spark Platform, Trading Bay Field 2. June 24, 1997 Marathon's Application for Injection Spark Platform well S-4 3. July 29, 1997 Marathon's Application for Injection Spark Platform well S-4 4. July 28, 1997 Marathon's Ltr re: Request for Class II Disposal Well North Trading Bay Unit Spark Well S-4 5. July 31, 1997 Notice of Hearing and Affidavit of Publication 6. May 8, 1998 Ltr from Marathons re: Spark S-rd 7. May 12, 1998 Ltr from Marathons re: Spark S-rd 7. October 9, 1998 Marathon's ltr re: amendment to DIO 13 Well S-4 Spark Platform North Trading Bay 8. February 19, 1999 Alaska Individual Well Production 9. August 24, 2001 Platform Inspection 10. June 23, 2003 UIV File Review 11. September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells 12. ---------------------- Report on Disposal Injection Operations Spark Platform 13. August 1, 2008 NTBU UIC Report Disposal Injection Order 13 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: THE APPLICATION OF MARATHON )Disposal Injection Order No. 13 OIL COMPANY (Marathon) for ) underground disposal of Class II oil field )North Trading Bay Unit well S-4 wastes by injection through the annulus )North Trading Bay Unit of the North Trading Bay Unit well S-4. ) September 12, 1997 IT APPEARING THAT: 1. By letter dated July 28, 1997, Marathon requested authorization from the Alaska Oil and Gas Conservation Commission ("AOGCC") to dispose Class IT oil field waste fluids by underground injection through the annulus of the North Trading Bay Unit well S-4, located on the Spark Platform. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on July 1, 1997. 3. The Commission did not receive protest or a request for a public hearing. FINDINGS: Marathon is the operator of the North Trading Bay Unit. There are no other operators within aone-quarter mile radius of the proposed disposal injection project. 2. Marathon is the only working interest owner within the North Trading Bay Unit. 3. Marathon proposes disposal injection through the 9 5/8" x 13.3/8" annulus in the North Trading Bay Unit S-4 well ("NTBU S-4"). The annulus of NTBU S-4 is open to the Tertiary Tyonek Formation from 2132' measured depth ("MD") to 7045'MD. 4. Marathon ran open hole logs in NTBU S-4 from 2132' MD to total depth ("TD"). The operator derived lithologic information above 2132' MD using logs from the NTBU S-1 well, which was logged from 450' MD to TD. NTBU S-1 is within 250' of NTBU S-4 through interval between 450' MD and 2135' MD. The Tyonek Formation in North Trading Bay Unit is composed of an alternating sequence of fluvial deposits including sandstone with minor conglomeratic intervals, siltstone, shale and coal. The 9 5/8" x 13 3/8" annulus of NTBU S-4 is in contact with approximately 600 feet of porous and permeable sandstone capable of serving as a receiving zone for the disposed fluids. Disposal Injection Order ~''~13 ~ Page 2 September 12, 1997 6. A net thickness of 180 feet of confining zone lithologies is present in the NTBU S-1 well between 980' MD and 1908' MD. 7. Well NTBU S-4 was constructed with 13 3/8", 61 lb/ft, J-55 casing set to Z 132' MD and cemented to surface; and 9 5/8", 471b/ft, N-80 casing set to 10744' MD and cemented to 7045' MD. 8. There is no serviceable tubing or packer in the NTBU S-4 well, nor in any other well on the platform that may be capable of being used as an injection well. These wells have all been killed with mud to leave them in a more secure condition. 9. The U. S. Environmental Protection Agency ("EPA") has exempted the portion of aquifers beneath Cook Inlet described by aone-quarter mile area beyond and lying directly below the Trading Bay Field (40 C.F.R. § 147.102). I0. North Trading Bay Unit is within the geographical area known as the Trading Bay Field. 11. The Commission may authorize less stringent requirements for a well or project if injection does not occur into, through or above a freshwater source or non-exempt aquifer (20 AAC 25.450). 12. The mechanical integrity of NTBU S-4 cannot be established through the procedures prescribed in 20 AAC 25.412 because the well is not equipped with serviceable tubing or packer. 13. Annulus pressure monitoring, as described in 40 CFR § 146.8(b)(3), can be used to verify mechanical integrity of the casing above the injection zone in NTBU S-4. 14. Injectant will consist of Class II waste fluids associated with the production of the NTBU S-2rd well and from any workover operations within that well. These fluids will primarily consist of produced water with salinities ranging from 5,000 to 15,000 parts per million, and completion fluids composed of three to six percent KCL brine with various additives. 15. NTBU S-2rd currently is produced only when there is a demand for gas, normally during the winter. 16. Marathon anticipates the average daily disposal volume will be less than 5 barrels, with a maximum daily volume over the life of the project of 300 barrels. 17. The total volume of disposal fluid estimated for the life of the project is 200,000 barrels. 18. Marathon estimates that the average surface injection pressure will be 700 psig, with a maximum surface injection pressure of 1000 psig. Disposal Injection Order iv~!13 ~ Page 3 September 12, 1997 19. Third party evaluation of the proposed disposal injection operation by a hydraulic fracturing stimulation contractor indicates that the maximum daily volume of 300 barrels injected at 1000 psig will be incapable of fracturing the lithologies adjacent to the NTBU S-4 well. - 20. The injection zone formation waters are largely equivalent in salinity to the produced formation waters. Typical salinities determined using standard analytical techniques are 5,000 to 15,000 parts per million for these fluids. 21. Operational reports of cementing procedures indicate NTBU S-4 and all wells within a one-quarter mile radius of the subject well are competently cemented and are unlikely to serve as migration conduits for disposal fluids. 22. The Commission has previously approved the annular disposal of oil field waste fluids in the NTBU S-4 well under the authority of 20 AAC 25.080. That approval expired March 31, 1997. CONCLUSIONS: 1. The requirements of 20 AAC 25.252 have been met. 2. Waste fluids authorized for disposal under this order in NTBU S-4 will consist exclusively of Class II waste generated from workover and production operations of the NTBU S-2rd well. 3. Permeable strata that can be reasonably expected to contain the total volume of disposal fluids anticipated for this project are in contact with the 9 5/8" x 13 3/8" annulus in NTBU S-4. 4. Movement of waste fluids will be confined within appropriate receiving intervals by confining lithology, cement isolation of the NTBU S-4 9 5/8" x 13 3/8" annulus and operating parameters. 5. Fracturing of the disposal receiving zones is unlikely under the proposed operating parameters. 6. Monitoring of disposal rates and pressures will ensure fluids are contained within the disposal interval. Changes in these parameters may be an indication that fluid is escaping beyond the authorized disposal interval. 7. Disposal injection in NTBU S-4 will not occur into, through, or above anon-exempt freshwater aquifer, and will not result in an increased risk of movement of fluids into a freshwater source. 8. Annulus pressure monitoring is an acceptable technique to demonstrate mechanical integrity for this well. Disposal Injection Order i~'!13 September 12, 1997 Page 4 9. Low disposal volumes and unique conditions associated with the facility location, reservoir producing age, and producing characteristics of well NTBU S-2rd do not justify drilling a dedicated disposal well nor equipping an existing well on the Spark Platform with a serviceable tubing and packer. - 10. The cost of equipping the NTBU S-4 well with a serviceable tubing and packer outweigh the benefit derived from producing the NTBU S-2rd well. 11. Disposal injection operations in NTBU S-4 will not cause waste nor jeopardize correlative rights, and will likely result in greater ultimate recovery from the North Trading Bay Unit. NOW, THEREFORE, IT IS ORDERED THAT: Rule 1 Authorized Injection Strata for DisRosal. Class II oil field fluids may be injected into the NTBU S-4 well in conformance with Alaska Administrative Code, Title 20, Chapter 25, for the purpose of disposal into strata which is common to and correlates with the Tyonek Formation between 1908' - 7045' MD. Rule 2 Demonstration of Tubing/Casing_Annulus Mechanical Integrity The operator shall confirm mechanical integrity by analyzing the recorded daily disposal rates and pressures to determine that for a given rate, the pressure has not varied by more than 25%. Rule 3 Well Integrity Failure Whenever disposal rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of the casing above the shoe, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action and obtain Commission approval to continue injection. Rule 4 Operational Criteria Average daily disposal rates shall not exceed 5 bbls/day, and maximum disposal rates shall not exceed 300 bbls/day. Maximum disposal injection surface pressure in NTBU S-4 shall not exceed 1,000 psi. Rule 5 Surveillance Operating parameters including disposal rate, disposal pressure, annulus pressure and fluid volume must be monitored and reported according to the requirements, where applicable, of 20 AAC 25.080 and 20 AAC 25.432. An annual report evaluating the performance of the disposal operation will be submitted on or about July 1 each year. Disposal Injection Order"~!'13 September 12, 1997 Page 5 Rule 6 Administrative Action Upon request, the Commission may administratively revise-and reissue this order upon proper showing that any changes are based on sound engineering practices and will not allow waste fluids to escape from the disposal zone. Robert N. Christenson, P.E., 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). DONE at Anchorage, Alaska and dated September 12, 1997. r ALASFiA OIL A1~TD GAS COI~TSERQATIOI~T COMMISSIOIQ TONY KNOWLlS, CaOVERNOR 3001 PORCUPINE DRNE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX:. (907) 275-7542 ADMINISTRATIVE APPROVAL DIO NO. 13.2 Re: Amendment to Rule ~ of Disposal Injection Order (DIO) No. 13 W. C. Barron Marathon Oil Company P O Bos 196168 Anchorage, AK 99519-6168 Dear Mr. Barron: This is in response your written request dated October 9, 1998, to make permanent the conditions allowed in DIO 13.1, approved May 15, 1998. DIO 13.1 amended Rule 4 "Operational Criteria" of DIO 13 to allow disposal of higher annual volumes of disposal fluids. We evaluated the data you submitted in your September 23 report, which provided information on disposal operations from April through August of 1998. Therefore as provided by "Rule 6 Administrative Relief' Rule ~ is amended as follows: Rule 4 Operational Criteria Average daily disposal rates shall not exceed 200 bbls/d and maximum disposal rates shall not exceed 300 bbls/d. Maximum disposal injection surface pressure in NTBU S-4 shall not exceed 1000 psi. This approval is based upon well S-4 serving as a backup disposal. welt to well S-5. Should well S-4 become the primary disposal well, the Commission reserves the right to reconsider this decision. DO'_~'E in Anchorage, Alaska this day February 26, 1999. J ~;Q/tih~~' - - Robert N. Christenson, P.E. Camille Oechsli David V~ Johnston Chairman Commissioner Commissi~ • \\SERVERV\_COMMOMAADIO'13-2 DOC ~ r TONY KNOWLES, GOVERNOR ALASBiA OIL A1~TD GA5 COI~TSERQATIOI~T COATMIS5IOI~T 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 ADMINISTRATIVE APPROVAL Di0 No, 13.1 Re: Amendment to Rule 4 of Disposal Injection Order (DIO) No. 13 W. G Barron Marathon Oil Company P O Box 196168 Anchorage, AK 99519-6168 Dear Mr. Barron: Pursuant to your written request dated May 8, 1998, for an amendment to Rule 4 "Operational Criteria" of DIO 13 to allow disposal of higher annual volumes of disposal fluids, we evaluated the data you submitted and that which we had in our files. Therefore as provided by "Rule 6 Administrative Relief' Rule 4 is amended, for a period not exceeding six months, as follows: Rule 4 Operational Criteria Average daily disposal rates shall not exceed 200 bbls/d and maximum disposal rates shall not exceed 300 bbls/d. Maximum disposal injection surface pressure in NTBU S-4 shall not exceed 1000 psi. At the end of the six month period. the Commission will evaluate the need to retain the amended rule or continue with the original rule. We request that you submit a record of injection volumes and pressures, and address the economic and technical considerations of equipping NTBU #4 with tubing and packer should injection remain at the higher volumes. This information should be submitted no later than five months from the date of this administrative approval David W. Chairman Robert N.ZThri Commissioner Cammy 0 hsli Commissioner .DONE in Anchorage, Alaska this day May 15, 1998. X13 NTBU UIC Report Regg, James B (DOA) r-] L From: Schoffmann, A B (Ben} [abschoffmann@marathonoil.com] Sent: Friday, August 01, 2008 11:07 AM To: Regg, James B (DOA) Cc: Ibele, Lyndon; Turkington, Jeffrey A.; Schoffmann, A B (Ben) Subject: NTBU UIC Report • ~r Page 1 of 1 Jim, Thanks for the call on the referenced report for wells S-4 and S-5 on the Spark platform. Please be advised that S-4 is indeed a Class II injection well with a completion variance as we confirmed in our conversation. We will submit a corrected annual report to clarify that issue shortly. Also, we have yet to conduct our MIT on S-5. It is currently shut-in and will remains so until we have performed the MIT. At present, we don't have enough fluids to conduct the test on board, but once we have collected a '~ sufficient volume, we will be providing notice to you so AOGCC can withness the test. Jeff Turkington is our Production Supervisor for this area and will be contacting you soon for this test. Regards, gew Ben Schoffmann Operations Manager Marathon Oil Company work: 907-565-3035 cell: 907-748-3589 fax: 907-565-3076 ZERO Incidents. Our greatest purpose -Our deepest passion 8/4/2008 '.~12 ..r Alaska Asset Team Marathon MAM ®Alaska Production LLC May 28, 2010 P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 fce,P~l ~- Inad.~8~ (=ld RE~ElVED JUN 0 2 201 Daniel T. Seamount, Jr., Commission Chair Alaska Od E~#~ar Cer>~. Commission Alaska Oil & Gas Conservation Commission An~her~ge Attn: Jim Regg 333 W. 7th Avenue, Suite 100 ~ ~~ - d 3 Anchorage, AK 99501 n,~ ~~ Reference: Report on Disposal Injection Operations Well S-4, Spark Platform, North Trading Bay Unit Well S-4 on the Spark platform of the North Trading Bay Unit is governed by Disposal Injection Order (DIO) No. 13, approved September 12, 1997. This report covers the final disposal injection operations for S-4 from January 1, 2009 until September 12, 2009, when the well was plugged and abandoned. S-4 has been shut-in for most of the reporting period. The only injection during 2009 was in July for a total of 1175 barrels, injected at a maximum pressure of 900 psi. Attached please find an injection monitoring report and chart showing daily injected volume and maximum injection pressure on the annulus. Please contact me with any questions at 907-565-3043. Sincerely, i Tiffany Stebbins Compliance Representative cc: M. D. Dammeyer Well file Houston file r # Marathon Alaska Production LLC Spark Platform, well # S-4 S-4 Injection Monitorin Sheet Max Injection Pressure Daily Injection Date on Annulus (psi) Volume (bbls) 7/7/09 300 200.0 7/14/09 225 115.0 7/15/09 225 150.0 7/19/09 300 45.0 7/20/09 300 21.2 7/21 /09 300 224.5 7/23/09 300 229.0 7/24/09 200 15.3 7/25/09 900 148.0 7/30/09 900 27.0 Total Injected lr~lu~re (dbls) 1175.0 Page 2 of 2 1000 ~ 900 800 700 -- 600 ~-- 500 - 400 - 300 200 100 0 0 T T Daily Injection Volume __- (bbls) - -~- Max Injection Pressure, _ __ on Annulus (psi) 0 0 0 T T T N M ~ ~~ I ~, ~: ~~~ 0 0 0 0 0 T T T T T u7 n M Marathon MARATHON Oil Company April 16, 2009 • Alaska Asset Team P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 t t~~G Daniel T. Seamount, Jr., Commission Chair Alaska Oil & Gas Conservation Commission i~~~~ -~ ~~~' ° ~ ~~~-~i~si~ Attn: Jim Regg ~rr~i~or=~~~ 333 W. 7t" Avenue, Suite 100 Anchorage, AK 99501 Reference: Report on Disposal Injection Operations Well S-4, Spark Platform, North Trading Bay Unit This well is governed by Disposal Injection Order (DIO) No. 13. There have been no disposal injection operations for the period of January 1, 2007 through December 31, 2008 for well S-4 on the Spark platform of the North Trading Bay Unit. S-4 has been designated a backup disposal well to S-5. S-5 came online September 3, 1998; and disposal into S-4 ceased. Marathon is currently in the process of preparing procedures for abandonment of this wellbore in 2009. Please contact me with -any questions at 907-565-3043 or tastebbins@ marathonoil.com. Sincerely, ~~~~ Tiffany Stebbins Compliance Representative cc: B. Schoffmann Well file Houston file i~ • Alaska As• Team M O i C~a~npany MARATHON August 4, 2008 (Revision to June 23, 2008) Tom Maunder AOGCC 333 West 7th Ave, Suite 100 Anchorage, AK 99501 PO BOX 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 rvI~ ~ ~# 5 2i~~8 ~I. , ~.:~ ~ ~ ~ _ ._~:~i Reference: Report on Disposal Injection Operations 2007 Well S-4 and S-5, Spark Platform, North Trading Bay Unit Dear Mr. Maunder: This annual report of disposal operations covers the period of January 1, 2007 through December 31, 2007 forwells S-4 and S-5 on the Spark platform of the North Trading Bay Unit. Disposal via well S-4 is governed by Disposal Injection Order (DIO) No. 13 for the North Trading Bay Unit (approved September 17, 1997), and disposal well S-5 is governed by DIO No. 15 approved August 31, 1998. Attached are three plots showing injection volume, injection pressure and casing pressure for Well S-5 in the calendar year 2007. The last mechanical integrity test for S-5 was conducted on July 13tH 2004. The next such test is expected to be performed within two months, with appropriate notice provided to the AOGCC. In the interim, no disposal/injection activities will be performed. S-4 is a Class II injection well with a completion variance and mechanical integrity is determined by monitoring of injection rates and pressures only. For the report period, there were no fluids injected into either well; thus all injection rates and tubing pressures for both wells were zero. Spark production has been shut in since 2005 due to liquids loading in the sole gas producing well, S-2rd. A minor anomaly was noted in the recorded data for the S-5 casing pressure (see attached graph), however since the pressure is very low and there was no injection activity during this period, no action was deemed necessary. Sincerely, ~~~ ~ A. B. Schoffmann Operations Manager Marathon Oil Company Enclosures Q:\Spark\Wells\Regulatory\2007 Annual Injection Report for S-4 and S-5\Spark #4 and #5 Annual Inj Rept - 080408 revision.doc ~~ a~ a~ E ~ 0 0 > > c c 0 0 U U U U .~ .~ ~~ Y Y L L '' ^Q^ rr~^^. VJ VJ • ^, N ~ +_+ ~ ~C O ~ ~ ~ O m V ~ G1 .~ '~ ~ c~ L V7 ~ ~ C O ~ Z N ~ y L . ~O d ~' _a ~C Y N i O ~ ~. ~ N ~ 12/27/2007 11 /27/2007 10/28/2007 9/28/2007 8/29/2007 7/30/2007 d 6/30/2007 p 5/31 /2007 5/ 1 /2007 4/1/2007 3/2/2007 1 /31 /2007 -I I ~ I I ! I ^ 1/1/2007 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o ~ o adMB `aw jon uoi;oafu~ N Q:\Spark\W ells\Regulatory\2007 Annual Injection Report for S-4 and S-5\Spark #4 and #5 Annual Inj Rept - 080408 revision.doc ~~ ~~ ~~ L L ~ ~ m a~ ^L ^L LL LL C O O J-+ y-+ U U a~ a~ c 'c Y Y L L Q Q ~~ • ^ ~~ 12/27/2007 11 /27/2007 10/28/2007 9/28/2007 L ~ d~+ N •- N C ~ ~ a ca =m 0 r ~ V C ~~ C ca L 1 =, N ~ ~ O ~ Z ca N ~ N ~ ~+ ~ ~ ~a ea i O fl. ~ ~ _N O 8/29/2007 7/30/2007 d ..+ 6/30/2007 0 5/31 /2007 5/1 /2007 4/1 /2007 3/2/2007 1 /31 /2007 1/1/2007 0 0 0 0 0 0 0 0 0 0 0 °o a°o con v° ~ °o 00o coo ~ ~ c~' ~ ~ ~ Bisd a~nssaad uoi;~afu~ Q:\Spark\W ells\Regulatory\2007 Annual Injection Report for S-4 and S-5\Spark #4 and #5 Annual Inj Rept - 080408 revision.doc ~~ a~ a~ L L ~ ~ ~ ~ a~ a~ ^L L I..L .~ .~ U U ~~ ~~ ~~ L L ,,^Q^ ''^Q^. vJ vJ • ^ 12/27/2007 11 /27/2007 10/28/2007 9/28/2007 L N ~ ~ ~ L a ~a a, m C ~ .y C c~ U ~ ``L 1 r N 'C ~ C O ~ Z ~ ' ~ ~ N L W _a ~ Y (/~ L O ~ C. ~- N N ~~ 8/29/2007 7/30/2007 N a+ 6/30/2007 5/31 /2007 5/1 /2007 4/ 1 /2007 3/2/2007 1 /31 /2007 ~I ,-~~--~-I-~!T~-I-~~r-C 1 / 1 /2007 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o~ o~ o~ o~ o~ o~ o~ o~ o~ o~ O ~ O O O ti~ O O u7 ~~~ M M N N ~ ~ r 6isd `a~nssa~d Buise~ Q:\Spark\W ells\Regulatory\2007 Annual Injection Report for S-4 and S-5\Spark #4 and #5 Annual Inj Rept - 080408 revision.doc w ~. • Alaska7~set Team - U.S. Production Operations M Marathon ~ ~""; ~`~ ~°n Q ~ ~ ~~:{ MARATHON Oil Company ~ ~ '~ ~§ ~ ~ ~ ~'~ ~' ~~"' .~, ~~, 1t1;> r~x s.,~~ _.~~~ June 23, 2008 Tom Maunder AOGCC 333 West 7th Ave, Suite 100 Anchorage, AK 99501 P.O.Box196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 Reference: Report on Disposal Injection Operations 2007 Well S-4 and S-5, Spark Platform, North Trading Bay Unit Dear Mr. Maunder: This annual report of disposal operations covers the period of January 1, 2007 through December 31, 2007 for wells S-4 and S-5 on the Spark platform of the North Trading Bay Unit. Disposal via well S- 4 is governed by Disposal Injection Order (DIO) No. 13 for the North Trading Bay Unit (approved September 17, 1997), and disposal well S-5 is governed by DIO No. 15 approved August 31, 1998. Attached are three plots showing ini~ction volume, injection pressure and casing pressure for this well in the calendar year 2007. The last mechanical integrity test for S-5 was conducted on July 13tH 2004 and the next such test is due by July 13tH 2008. (S-4 is completed as an annular injector and mechanical integrity is determined by monitoring of injection rates and pressures only.) For the report period, there were no fluids injected into either well; thus all injection rates and tubing pressures for both wells were zero. Spark production has been shut in since 2005 due to liquids loading in the sole gas producing well, S-2rd. A minor anomaly was noted in the recorded data for the S-5 casing pressure (see attached graph), however since the pressure is very low and there was no injection activity during this period, no action was deemed necessary. Sincerely, . ~C~•--- A. B. Schoffmann Operations Manager Marathon OiI Company L:\Spark\Wells\Regulatory\Spark #4 and #5 Annual Inj Rept - 05-2007 final.doc Enclosures Disposal Wells S-4 and S-5 Injection Volume Spark Platform -North Trading Bay Unit 800 700 600 D a ~ 500 00 ti E 0400 c 0 :. ~ 300 ._ 200 100 0 N O O v • Spark #4 Injection Volume ^ Spark #5 Injection Volume • w ~ v, cn rn ~ a0 co ~ 1 ~ N ~ ~ 1 O O (NO ONO O N N ~ N N N ~ ~ ~ ~ ~ 00 J V N O O O N N N N N ~ ~ ~ O O O O O O O O O N N N v v v v O O J ~ ~ O O O J ~l ~1 Date 2000 1800 1600 1400 rn .y a X1200 L 7 N N i 1000 a c 0 800 d .~ 600 400 200 0 N O O V Disposal Wells S-4 and S-5 Injection Pressure Spark Platform -North Trading Bay Unit • Spark #4 Injection Pressure ^ Spark #5 Injection Pressure ~ 1 ~J w ~ cn cn rn V oo c~ j N 1 1 1 O O O O N N N N N N ~ ~ ~ ~ ~ N O O O N N N N N ~ ~ ~ O O O O O O O O O N N N O V V V O O O O O O O O V V V V V V O O O Date 1000 950 - ------- 900 _ _ - - - 850 _ - -- 800 750 - 700 650 N Q' 600 -- ti 3 550 (!1 y 500 L a 450 -_ a~ y 400 --...- __-- U 350 . _ _ --- 300 - - 250 - - 200 150 -- 100 50 - ---- - 0 1 ~ W N O N O O 00 O V Disposal Wells S-4 and S-5 Casing Pressure Spark Platform -North Trading Bay Unit • Spark #4 Casing Pressure ^ Spark #5 Casing Pressure - II fi -- 4 -- -- ---~ - .I ~ ~ .1 ~ ~ W W W N N ~ ~ N N N ~ O OO CEO ~ N N N ~ V V O O O O O O O O O O V J ~I V V O O O Date • Alaska Asset Team M Marathon ~,~~~~~~ PO BOX 196168 MARATHON ~1~ COI'npany Anchorage, AK 99519-6168 ,j~~ 0 2 207 Telephone 907/561-5311 Fax 907/565-3076 Alaska Oil ~ Gas Cons. CQmmissiatt Anchorage June 28, 2007 Tom Maunder AOGCC - 333 West 7t" Ave, Suite 100 Anchorage, AK 99501 Reference: 2006 Annual Report of Disposal Injection Operations Well S-4 and S-5, Spark Platform, North Trading Bay Unit Dear Mr. Maunder: This annual report of disposal operations covers the period of January 1, 2006 through December 31, 2006 for wells S-4 and S-5 on the Spark platform of the North Trading Bay Unit. Disposal via well S-4 is governed by Disposal Injection Order (D10) No. 13 for the North Trading Bay Unit (approved September 17, 1997), and disposal well S-5 is governed by DIO No. 15 approved August 31, 1998. During the report period, there were no production activities on the Spark platform. The only producing gas well, S-2rd, was shut-in for the entire period due to liquid loading. Therefore, there were no fluids produced or injected during the report period. All rates and pressures for the two Spark injection disposal wells were "zero" as indicated on the attached plots for calendar year 2006. The last mechanical integrity test for S-5 was conducted on July 13th 2004 and the next such test is due by July 13th 2008. Well S-4 is not equipped with a serviceable tubing or packer, and therefore mechanical integrity is established by alternative means as set forth in DIO-13. Sincerely, ~ .S~ . B. Schoffmann Operations Superintendent Marathon Oil Company Enclosures Disposal Well S-4 Casing Pressure Spark Platform -North Trading Bay Unit 2000 ._...__...._,_..._~.._-- --._...__,_.__ ~, 1800 ~ -. __.. __. 1600 - - -. ,.. 1400 rn .% °-I 200 d 41000 a` m H 800 m U 600 400 200 0 • ~ Spark #4 Casing Pressure ~ -~ (.mil P N (~ m ~ W ~ O N ' N N N Q Q ~ ~ ~ J J °m oo° 8i i~ 8i rn °m ~i rn rn °o g °o rn rn rn Date Disposal Well S-5 Casing Pressure Spark Platform -North Trading Bay Unit ~ Spark N5 Casing Pressure • • r Disposal Well S-4 Injection Volume Spark Platform -North Trading Bay Unit • Spark #4 Injection Volume CVV 704 644 O a 3500 m ti E 0400 c 0 4300 'c ~ (J A (\ (\ O~ \ 00 (p ' ' W ~ ~ ' (J (J fJ N N ~ ' N pN N N pp p~ ~ ~ O m J J O ~ ~ QOi m 01 O~ OOi ~ OOi O S O O) Of 01 Date Disposal Well S-5 Injection Volume Spark Platform -North Trading Bay Unit - ~~~ Spark #S Injection Volume 200 100 0 800 700 600 a 3500 a0 ai E x400 c 0 4300 c 200 100 0 ~ ~ (~ A N m J W (O ' ~ N ~ -~ W (J (J N N ~ ' N N `~?+ N O ~ N O ~ N O ~ O in ~ O ~ ~ O ~ ~ O ~ ~ O in m N 8 J N 8 J N 8 m m Date • •, ~ ~~ ~ Disposal Well S-4 Injection Pressure Spark Platform -North Trading Bay Unit • Spark #4 Injection Pressure cuuu 1800 1600 1400 m .~ a 1200 n m X1000 a c 0 '~ 800 d 'c 600 400 200 0 cvvv 1800 1600 1400 m .~ a 41200 m M X1000 a c 0 '~ 800 u 'c 600 400 200 0 ~ ~ W A N N O> J Oo (p ~ (J N ~ ~ W !J fJ N N ~ pN N N N pO O\ N mm m pJ V ~1 O ~ OOi m O O ~ m O O O O m m ~ ~ ~ Date Disposal Well S-5 Injection Pressure Spark Platform -North Trading Bay Unit ^ Spark #5 Injection Pressure ~ -• W A (~ N O~ V W f0 \ pp O> W O N p O -\` m ~ p O W O (J ~ (J p O N ~ N ~ ~ 0 W O ~ pJ J O m m ~ rn O rn rn Dete M Marathon MARATHON Oil Company June 13, 2006 JUN 1 4 2006 Winton Aubert Alaska Oii & Gas Cons. Commission AOGCC Anchorage 333 West 7th Ave Suite 100 Anchorage, AK 99501 Reference: Report on Disposal Injection Operations Well S-4 and S-5, Spark Platform, North Trading Bay Unit Dear Mr. Aubert: This annual report of disposal operations covers the period of January 1, 2005 through December 31, 2005 for wells S-4 and S-5 on the Spark platform of the North Trading Bay Unit. Disposal via well S-4 is governed by Disposal Injection Order (DIO) No. 13 for the North Trading Bay Unit (approved September 17, 1997), and disposal via well S-5 is governed by DIO No. 15 approved August 31, 1998. Attached are two plots showing injection volume and injection pressure for wells S-4 and S- 5.Injection into well S-5 began on September 3, 1998. Because well S-4 is designated as a backup disposal well for S-5, injection into S-4 ceased when injection began in S-5. The S-2RD gas producer was flowed from mid-November 2004 until it was shut in mid- September 2005 due to liquid loading problems. Injection of the produced fluid from the S- 2RD well was injected solely into the S-5 well. All injection into S-5 was below the DIO operating limits of 1000 bbls/day and 3000 psi surface disposal pressure. A workover of S- ZRD is currently under evaluation. If this workover is implemented and is successful, injection operations will recommence in S-5 with S-4 as the backup. Sincerely, ~`" -` A: B. Schoffmann Operations Manager Alaska ~et Team P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 L:\Spark\Wells\Regulatory\Spark 4 and 5 Annual Inj Rept - 06-2006.doc Enclosures Disposal Wells S-4 and S-5 Injection Pressure Spark Platform -North Trading Bay Unit 2,000 1,800 1,600 1,400 .N 1,200 1,000 a 0 800 a~ .~ 600 400 200 0 ^ S-5 • S-4 ^ ~~~ ~~ ^ ~~^ ~ ^ ^• ti ^ ^ ~ ^ ^ ^ ~ ^^ ~ ^ ^ ^ ^ ^ ^^^ ^ ^ ^^ ^ ^ ^ ^ ^ ^ ^ ^ ^ ~ ^ ^ ^ ^ ^ ^ ^ ^ ^ ^ ^ ^ ^ ^ ^ ^ ^ ^ ^ ^ .~a~o~ .~a~oh ~a~oh PQ~oh ~a~oh ~a~oh ,~°~~~ .~~`Oh .P°~'o~ ~eQ~h O4~Oh ~oJOh peGoh 800 700 600 0 ~ 500 m E c 400 0 a 300 .~ 200 100 0 Disposal Wells S-4 and S-5 Injection Volume Spark Platform -North Trading Bay Unit • S•4 • S-5 • • • • _ - -. •~~• • ~ ~ ~ ~• • ~ ~ • • • ~ ~ -_ _ - ~ ~ • • ~~ ~.,~~oh ~.'a~oh ~~~oh ~.P~~O~ ~a~oh ~a~oh ,~~oh o~J`o~ PJ~oh ~eQoh oG~Oh ~oJph Oevph • M Marathon MARATHON Oil Company October 12, 2001 Ms. Wendy Mahan Alaska Oil & Gas Conservation Commission 3001 Porcupine Dr. Anchorage, AK 99501-3192 Alaska Domestic reduction P.O.Box196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Reference: Report on Disposal Injection Operations Well S-4 and S-5, Spark Platform, Worth Trading Bay Unit d` Dear Ms. Mahan: ~.---~ '~~~'1 _^~ -~t...i pro - ~5 This annual report of disposal operations covers the period of June 1, 1999 through June 30, 2001 for wells S-4 and S-5 on the Spark platform of the North Trading Bay Unit. Disposal via well S-4 is governed by Disposal Injection Order (DIO) No. 13 for the North Trading Bay Unit (approved September 17, 1997), and disposal via well S-5 is governed by DIO No. 15 approved August 31, 1998. Due to an oversight the report due on or about July 1, 2000 was not submitted, therefore this report covers a two year period. Attached are four plots showing injection volume and injection pressure for wells S-4 and S-5. Injection into well S-5 began on September 3, 1998. Since well S-4 is designated as a backup disposal well for S-5, injection into S-4 largely ceased when injection began in S-5. As shown from the attached graphs, injection into S-5 from June 1999 through June 2000 was within the conditions of the disposal injection order. Little injection has taken place since July 2000 due to problems with the sole producing well, S-2RD. A workover of S-2RD is currently under evaluation. If this workover is implemented and is successful, injection operations will recommence in S-5 with S-4 as the backup. Sincerely, ,~ `~-°~ ~____~, W.C. Barron Operations Superintendent N:\DRLG\SPARK\S-4\Spark 4 and 5 Annual Inj Rept - 10-2001.doc Enclosures ~,,~ ~~ ~., a; ; ;,. A subsidiary of USX Corporation Disposal Wells S-4 and S-5 Injection Volume Spark Platform -North Trading Bay Unit 900 800 700 a 600 c 500 E 0 c 400 ~= 300 200 100 0~ • • • ------- s ~ ,,. ---- ~ ~~-.~ -t-------------------_ ~ - - t~i~ ---------------------s- ~ ~ • _. ,K s ~~ ~~ ~~ ~~ ~~ ~~ ~~ ~~ OO OO OO OO OO O~ -~'~J~• ~`'~~` "~~~~`• ~QP~~ `L°'ye~• ~~O~ti ti~~~J• ti~~e4• ~1•,a~• ti`0~,0• ti~~a~• ~`O'PQ~• ti`O~a~• ~y,~~~• t s Disposal Wells S-4 and S-5 Injection Volume Spark Platform -North Trading Bay Unit 1 - • S-5 ----- 0. -------------------------- 0.7 a 3 ~ 0.6 a~ -------------------------------------- ~ 0.5 ~--------------------------------------------- °> o ~~ •- 0.4 ------------ ---- --------------------------------------------------------------------------------------------------------------- ., 0.3 '~ --------------------------------------- ---------- --------------------------------------------- ------------------ --------------------------- ----------------------------------------- 0.2 '- -------------------------------------------------------------- 0.1 ' ----------------------------------------- ---- ----------------- - 0 00 00 00 00 00 00 00 O~ O~ O~ O~ O~ O~ ~.,J~ ~~.,0~, ~OPO~ ryO~eQ. ~OOG~ ~O~oJ. `LO~eG• ry1.,a~. ~0~~. 'L~~a`. 'L1P~`. ry1~a~. ryO.,JO. t Disposal Wells S-4 and S-5 Injection Rates Spark Platform -North Trading Bay Unit 1600 ~ 1400 1200 ~ 1000 a ~ 800 --------------------- 0 '~ 600 - ----------------- . 400 ------- ------ 200 0 ----- • . • --s- Z • ~ • . •• • . ~~ ~ -~ ------------ j---------i`--~----~-~--------~--~.--- --- ---- •t •: ~ . s .~ •s • . • ~ S-4 ~ S-5 -- • ~ ~ • - ---------- I--- --------------- --------- ----------- ------------ t ~i • t ~i~ -------------------------------------------- ~~ ~~~~ • i • • . . ~ ~.,J~, ~.,~~, ~~.,J`, ~oPJ~ 'L°'~e~, ~~oG~, ~~~o~, `L~~~G, ~1.,a~, ~~~~. 'L1~a`. '1`OP~`• ry~~a~ ~~.,J~. t s Disposal Wells S-4 and S-5 Injection Rates Spark Platform -North Trading Bay Unit 120 • S-4 ~' • S-5 -------------------------------------------------------------- N • 80 ------------- ----------------------------------------------------------- .~ ~ = a ~ ~ ----------------------------------------- o !, ~ °' ~~ ~ --------------- i I 20 -------------------------- i 0 00 00 OO OO OO OO OO O~ O~ O~ O~ O~ O~ ~.,J`. ~~.,0`, ~OPJ~ `L°'ye~, ~OOG,~ 'LO~o,, `LO~eG, ~1.'aO, `LrO~e~• ~~~a`. 'L1P~`. ~1~a~. ~O,,J,~. r~ i -~ • Marathon MARATNON Oil Company ~~~~ Y ~~ ~~V~ '" ~~. ~~~~ September 23, 1998 Alaska Oil ~ Gas Cons. Comnirssion Anchorage Ms. Wendy Mahan Alaska Oil & vas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99513-7599 Reference: Report on Disposal Injection Operations Well S-4, Spark Platform, North Trading Bay Unit Dear Ms. Mahan: ~~o ~ i3 Disposal Injection Order (DIO) No. 13 for the North Trading Bay Unit well S-4 requires that Marathon submit an annual report of disposal operations on or about July 1. This report covers the period from the start of continuous injection in well S-4 in September 1997 to September 1, 1998. Next year's report will be prepared for the period of September 1, 1998 to July 1, 1999, and will be submitted in July 1999. Approval to inject produced fluids from well S-2rd into the annulus of well S-4 was granted on September 12, 1997, and continuous production from well S-2rd began on September 27, 1997. Initially, injection in well S-4 was into the annulus of the 95iR° and 133~A" casing s±rings. Infectivity via this annulus was poor however, and in November 1997 Marathon obtained sundry approval (#397-196) to inject into the annulus of the 4'/Z" tubing and 93/8" casing. Perforations were added (see wellbore schematic) to facilitate injection into the high-quality disposal zones. This operation was successful in improving injection into well S-4. In May 1998, water production from well S-2rd increased greatly. Marathon asked to increase the daily average injection allowable from 5 BWPD to 200 BWPD on May 8. This request was granted by the AOGCC on May 15 for a six-month period. The attached graph shows injection volumes and pressure into well S-4 since May 1998. In general, water injection into well S-4 has been sufficient to produce well S-2rd at a minimum rate. The graph shows that injection pressure tends to gradually climb in well A subsidiary of USX Corporation Environmentally aware for the long run. Alaskn Dourest oduction P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 9071561-5311 t • Report on Disposal Injection Operations Well S-4, North Trading Bay Unit September 21, 1998 Page 2 S-4, which is due to the buildup of trapped gas in the annulus. Note the drastic reduction in injection pressure on July 1 after bleeding off trapped gas pressure from the annulus. The annular pressure measurements prior to August 1998 shown in the attached graph are occasionally high due to incorrect placement of the annular pressure transducer upstream of a choke. When the separator dumped fluid, the pressure transducer briefly. sensed separator pressure instead of true injection wellhead pressure. The pressure transducer was moved directly onto the wellhead in August 1998, which eliminated the pressure "spikes" seen in previous months. Ignoring these spikes, the graphical trend clearly indicates that the AOGCC wellhead injection pressure limitation of 1,000 psig was never exceeded. A misunderstanding by Marathon operating personnel led to the AOGCC injection volume limitation being exceeded for four days in August 1998. The Marathon person on duty thought that the maximum allowable daily injection volume was 400 BWPD when in fact only 300 BWPD was allowed. Actual injected water volumes exceeded the allowable by less than 100 BWPD for these four days. Marathon supervisory personnel took corrective measures as soon as they became aware of the problem, and since then the maximum daily injection volume has not been exceeded. Marathon personnel monitor injection volumes into well S-4 continuously, and shut-in when the 300 BWPD limit is reached. Sincerely, J. ~a~~( EilerQ~~ Pro~d~tion Engineer JGE/ms M:\WP\OPNS98UGE923. Enclosures Disposal Well S-4 Spark Platform, NTBU .y Q ~' a~ N L a c m ,~ c 1,400 1,200 1,000 800 600 400 200 500 450 400 350 300 m E 0 250 L m w 200 ~ .~ O 150 100 50 0 ,~~' ,~~' ~~~' ~~~' ~a~' ~~~' ~,~~' ~~~' 'J~' ~Jt~' ~JO' ,JO' ,JO' ,J~~~,,J~'~,J~~~,,J~~~',J~~ ,,J~~~',J~~ ~ 4i ~ J~ ~ ~ ~Q. • North Trading Bay Unit Spark Platform, Well S-4 Marathon Oil Co., Alaska Region Water Disposal Via 4-1/2" x 9-5/8" Annulus 11/28/97 SCSSV -Otis ball Valve (c~ 269' 13-3/8", 61#, J-55, BTC Casing @ 2132' Tubing: 4-1/2", 12.6#, N-80, Batt. 4" Camco KBM Gas Lift Mandrels (all dummied) 2489' 4715' 6531' 7909' 8694' 8231' 9798' Fish: 2l' x 1-11/16" w/ 3.789" gauge ring (11/23/97) 3-1/2", 9.2#, N-80, Butt. Tubing 10093' - 10341' Plugged Perforations G-1 10126' - 10138' (4 spt) G-2 10149' - 10213' (4 spt) G-3/4/5 10226' - 10337' (4 spf) P1uQaed Perforations H-I/2U 10356' - 10476' (4 spt) H-2L/3 10484' - 10553' (4 spt) H-3 10561' - 10592' (4 spt) _ ~ _ , J _ ~, TD = 10770' Tubing - Casin~Perfs 4594' - 4624' DIL 4654' - 4684' DIL 5428' - 5438' DIL X523' - 5543' DIL 5937 - 5967 DIL Tubing Restriction Aroung GLM @ 9231' Tubing Bridge Plug L 9245' Otis "XO" Sliding Sleeve @ 10057 ID = 3.813" Baker Retrieva-D Packer L 10341' Crossover (4-1/2" x 3-1/2") @ 10093' Portco "X" Nipple (n~ 10308' ID = 2.750" Portco "X" Nipple @ 10341' ID = 2.750" Baker Retrieva-D Packer @ 10341' Otis "Q" Nipple @ 10364' ID = 2.635" 9-5/8", 47#, N-80, BTC Casing @ 10744' Last Rev.: JGE, 12/29/97 ~~~ • • ~,a' ~~ ~~ r i ~' ,~ j ! ' z~ 1 ~+ ', ~ / ~ ~ ; a~ FRANK H. MURKOWSKI, GOVERNOR ~~ ~~ OIL ~D ~ !r{ 333 W. 7"' AVENUE, SUITE 100 COR~~RQ~~Ois CO~`II~7SIOR r ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing 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. i N • • 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 Injection 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 O eratin 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 l 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 • • Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrit " Confinement" River Unit AIO 16 - Kuparuk River Unit; Tarn Oil Pool 6 7 10 AIO 17 - Badami Unit 5 6 g 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; Midnight 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 Injection 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 C7 • Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Inte rity" Confinement" DIO 11 -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 D 1 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 Stora a 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 Recover In'ection Orders EIO 1 -Prudhoe Bay Unit; Prudhoe Bay Field, Schrader No rule No rule 8 Bluff Formation Well V-105 i Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" EIO 2 -Redoubt Unit; RU-6 5 8 9 - -- - Public Notices • i <scott.cranswick@mms.gov>, Brad McKixr~ <mckimbsCBP.com> Please find the attached Notice and Attachment for the proposed amendment. of underground injection orders and the Publo Notice Happy Valley #10. ..Jody Colombie Content-Type: application/msword ;Mechanical Integrity praposal.doc' Content-Encoding: basz64 Content~Type: application/tnsword Mechanical Integrity of Wells Notice.doc Content-Encoding:. base64 Content-Type: applicatiorv'msword FIappyv'alleyl0_~IearingNotice.doc Content-Encoding: base64 ~, 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 Content-Type: application/msword Mechanical Integrity of Wells Notice.doc i Content-Encoding: base64 ......... ....... . __ . Content-Type: application/msword Ad Order form.doc Content-Encoding: base64 1 of 1 9/29/2004 1:10 PM 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 Wertheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Kelly Vafadez 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 [F'wd: Re+ Consistent Wording for Injection ~s -Well Integrity ... Subject: [Fwd: Re: Consistent Wording for Injection Orders - Frorn:7ohn Norman <jahn_norman@admin.state.ak.us> Date: Fri, O1 Oct 2004 11:09:26 -0800 To: Jody J CoIombie <jody colombie@admin.state.ak.us> 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 regg(aadmin.state.ak.us CC:dan seamount a,admin.state.ak.us, john norman~c~,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 re~g~;admin.state,ak.us> 8/25/2004 3:15:06 PM »> Rob -Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...] to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions 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 reQn(aadmin.state.ak.us> 8/I7/2004 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 1 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injectiot~ers -Well Integrity ... i - 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 1 Alaska Oil & Gas Conservation Commission 2 of 2 10/2/2004 4:07 PM ;[iF'wd: Re; Consistent Wording for Injection ~s -Well Integrity ... Subject: [Fwd: Re:_Consistent Wording for Injection Orders - V~ell Integrity (Revised}1 From: John Norman <john_norman@admin.state.ak.us> Date.: Fri, O1 Oct 2004 11:08:5 -0800 To: Jody J Colombie <jody colombi@adrnin.state.ak.us> please print all and put in file for me to review just prior to hearing on these amendments. thanx ------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders -Well Integrity (Revised) Date:Thu, 19 Aug 2004 1:46:31 -0800 From:Rob Mintz <robert mintz~,law.state.ak.us> To:dan seamount(a,admin.state.ak.us, _jim re~g(ccadrnin.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. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim regg~ admin.stateak.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 Injection~rs -Well Integrity ... ~ e _ - 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 Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement The tubing, casing and packer of an injection well must demonstrate integrity during operation. The operator must immediately notify the Commission and submit a plan of corrective action on 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 every four years thereafter (except at least once every two years in the case of a slurry i_n~ection well}, and. before returning a well to sen~ice following a-€tc-r a workover affecting mechanical integrity, ~..~,, ;:* ,;,,~.;* .,11,,,... ~ ., r ~. ~ ~ . *~ °~-. •*; ~A v 1 ~ } V CLl ~T i Y 11 tTnless an alternate means is approved by the Commission mechanical integrity must be de~x~onstrated by a tubing pressure test using a ~ ?v~l-surface pressure ofn~e 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that mshows stabilizing pressure that does^~ not change more than 10°$- ercent during a 30 minute period. -~y .. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement Except as otherwise provided in this rule Tthe tubing, casing and packer of an injection well must d ~t~~~rnaintain integrity during operation. «%henever any pressure communication, leakage or lack of intection_zone isolation is indicated by injection rate. operating pressure observation, test, survey, log, or other evidence the operator nshall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval, ipae";icr .'t~ .'tin" °" ,'' ~ °';,"~ ~°~~ .'., The operator shall shut in the well if so directed by the Commission. The o~crator shall shut in the well without awaiting a response from the Commission if continued operation would be unsafe or would threaten contamination of freshwater `~ ""''° ~ ~'~ ' " ~ ' '.:: ' d Until,corrective action is successfully completed, Aa monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. „[Fwd: 1,Ze [Fwd: AOGCC Proposed WI Lan for Injectors]] i Subiect: [Fwd: Re: [Fwd: AOGCC Proposed WI Language for Injectors]] From: Winton Hubert <winton aubert@admin.state.ak.us> Date: Thu, 28 Oct 2004 09:4$c53 -0800 To: Jady J Colornbie <jody_colombie@adminstate.ak.us> 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: <41812422.8060604@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 <Enge1HR@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 Lame 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:j Sent: Wednesday, September 29, Subject: Public Notices dy colombieQadmin.state.ak.us 2004 1:01 PM Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal.ZIP» «Mechanical Integrity of Wells Notice.doc » 2 of 3 10/28/2004 11:09 AM X10 rt~ r A i UIC File Review Date: June 23, 2003 Subject: Unocal N. Trading Bay Unit (NTBU) Spark Platform Well S-4 (Waste Disposal) PTD #: 169-034 • Orders: CO 69, 74, I08 (pressure maintenance-11/18/71) and 225 DIfl 13 Reviewers: Tom Maunder, P.E. Initiating Action: Intent to perform MIT on Spark S-5 Review Summary-Well File 1. This well was drilled in June 1969. 13-3/8" @ 2132', w/ 1000 sx Class G w/10% gel followed by 400 sx Class G tail 9-5/8" @ 10744', 1050 sx Class G. 2. Well was suspended pending completion as a water injector. 3. Well was completed in multiple zones for injection in early May 1972 and placed in service. Injection ceased in January 1981. 4. The platform was "sold" to Marathon prior to the end of 1991 when Marathon proposed to SI the well. The well was SI long term effective February 25, 1992. 5. In September 1996, Marathon submitted a sundry application to dispose of up 35000 bbls of produced water from well S-2 (168-050) via the 13-3/8" x 9-5/8" annulus. Marathon proposed to dispose of any produced water directly from the separator with surface pressures of up to 1000 psi. Marathon's plans were to produce S-2 on during times of high demand (October -March). 6. Marathon provided further information in on October 15, where in their letter they attempted to justify their choice of annular disposal. Their points were limited disposal volume likely and no other really viable options. 7. Blair wrote an analysis and recommendation to the Commissioners on October 22. In that document he separated the potential wastes into completion fluid/filtrate (eligible for annular disposal and produced water (not eligible for annular disposal). 8. Sundry 396-187 was approved October 25, 1996. The sundry specifically states "Approve annular disposal of completion fluids and filtrate for 90 days after production begins." A report of annular disposal was required. 9. On February 11, 1997, Marathon requested an extension of 396-187 through the end of March to accommodate the planned production period. In the application it was indicated that disposal volumes had been low, on the order of 1 to 2 bpd with a pumping pressure below 200 psi. 10. Sundry 397-026 was approved February 12, 1997. No specific requirements are noted on the sundry other than a report of disposal. 11. In early November 1997, Marathon proposed to perforate the tubing and 9-5/8" casing in multiple intervals between 4594' and 5697'. Although it is not stated, fluids would then be pumped down the 9-5/8" x 4-1/2" annulus rather than the OA. 12. The 404 filed in mid December 1997 indicates that Marathon was disposing of 7 bwpd at 735 psi. M:\UIC File Reviews\030623-ntbuS-4-file-review.doc . r s 13. Marathon submitted the first annual report of operations required by DIO 13 on September 23, 1998. Of note in the report is the substantial increase of produced water from S-02. In May 1998, water production increased from 5 to 200 bwpd. 14. Marathon subsequently submitted an operations report in early October 2001. Spark well S-OS was approved for disposal injection in September 1998. Following that approval, 5-04 has been in back up status. Review Summary-DIO 13 1. On June 26, 1997, Marathon submitted an application for a Disposal Injection Order (DIO) to allow disposal of the produced water from S-02 into the OA of S-04. Marathon erroneously applied for a Class II authorization. 2. On July 29, 1997, Marathon submitted a revised application that more completely described the applicability of annular disposal in this case. 3. On July 31, 1997, a hearing notice was published. The notice included a statement that this DIO would require an exception to the regulation requiring an injection well to be completed with tubing and a packer. 4. DIO 13 was issued September 12, 1997. The ordered specified in Rule 4 that the average daily disposal rate could not exceed 5 bbUday with the maximum disposal rate not exceeding 300 bbUday. Rule 2 authorized pressure monitoring for demonstrating mechanical integrity. 5. In early May 1998, the water production from S-02 dramatically increased. Marathon applied for a revision of the average daily disposal rate to 200 bbUday. This was granted May 15, 1998. There is no information in the DIO file regarding point 11 reviewed in the well file regarding perforating the tubing and 9-5/8" casing and changing the disposal path to the 9-5/8" x 4-1/2" annulus. Conclusions 1. At this time Marathon has no immediate plans for 5-04 other than to likely keep it available to backup S-O5. 2. The DIO allows disposal of water produced with natural gas via disposal in the OA. Such an approval for production waste is likely unique in Alaska. 3. The well is presently configured with perforations through the 4-1/2" tubing and 9-5/8" casing that eliminates the need to dispose of fluids via the OA. 4. The disposal perforations in the wellbore are within the approved interval as specified in the DIO. Recommendations 1. No immediate action is necessary on well 5-04 or DIO 13. 2. As time allows, the DIO should probably be "cleaned up" to better reflect the present configuration of the well and the injection path. ~~~~~ Tom Maunder, PE Sr. Petroleum Engineer M:\UIC File Reviews\030623-ntbuS-4-file-review.doc onqr#-1 MLIWMA ~ ~ MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Julie Heusser, DATE: August 24, 2001 Commissioner THRU: Tom Maunder, '~, ~' ' t"" P. I. Supervisor S~~~o,~ FROM: Jeff Jones, SUBJECT: Platform (nspections Petroleum Inspector Spark /Spur- Platforms North Trading Bay Unit Trading Bay ST Friday Au~fust 24, 2001: I traveled to Marathon Oil Co.'s Spark and Spur Platforms and performed Semi-annual Platform Inspections. Marathon operator Mark Sutton accompanied me on the inspections. and was very helpful. On our arrival he restored power to both platforms following an electrical system failure that occurred on the previous day. I inspected all wells on the Spark and Spur Platforms and found them properly shut in, with no problems noted. There is no production from either platform at this time. These platforms have not been manned for several years and in places are showing signs of'deterioration. Summary: I performed semi-annual platform inspections at Marathon's Spark and Spur Platforms in the North Trading Bay Unit. 18 Wells inspected; no production. Attachment: NON-CONFIDENTIAL PLT INSP TBU Spark-Spur 10-24-01 JJ.doc ~8 .~, ° ALASKA INDIVIDUAL WELL PRODUCTION AS OF 02/19/99 WELL-NAME: N TRADING BAY UNIT S-04 API: 733-2fl184-04 LEASE: ADL0035431 OPERATOR: MARATHON OIL CO FIELD/POOL: TRADING BAY, G-NE/HEMLOCK-NE SALES CD - 82 ACCT GRP - 004 FINAL STATUS: DEV SUSP CURRENT STATUS: SER WDSPL ** ENHANCED RECOVERY ** 1972 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 8 21 7 12 31 30 29 29 30 25 30 29 OIL WTR 7,042 19,596 3,575 22,706 45,833 47,713 32,295 31,806 56,287 170,180 244,623 231,219 GAS 1972 TOTALS OIL WATER 912,875 GAS CUM OIL CUM WATER 912,875 CUM GAS 1973 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 30 16 20 30 24 9 28 21 30 31 29 31 OIL WTR 205,825 88,088 147,532 211,928 183,582 64,627 262,416 172,418 250,615 246,290 219,893 235,388 GAS 1973 TOTALS OIL WATER 2,288,602 GAS CUM OIL CUM WATER 3,201,477 CUM GAS 1974 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 31 28 31 26 31 30 31 30 30 31 21 16 OIL WTR 230,380 204,212 221,526 177,446 218,243 210,685 215,877 212,135 210,014 199,916 121,508 75,629 GAS 1974 TOTALS OIL WATER 2,297,571 GAS CUM OIL CUM WATER 5,499,048 CUM GAS 1975 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 30 28 13 28 31 30 30 31 30 31 27 31 OIL WTR 67,082 142,680 72,414 153,230 169,280 158,952 155,130 162,889 149,775 147,850 112,867 169,818 GAS 1975 TOTALS OIL WATER 1,661,967 GAS CUM OIL CUM WATER 7,161,015 CUM GAS 1976 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 31 29 31 30 31 29 31 31 30 30 30 31 OIL WTR 145,881 133,631 135,449 141,110 138,793 133,946 142,570 141,896 134,517 133,066 123,889 121,773 GAS 1976 TOTALS OIL WATER 1,626,521 GAS CUM OIL CUM WATER 8,787,536 CUM GAS 1977 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 31 26 31 30 21 23 16 10 10 29 30 6 OIL WTR 119,450 103,700 108,550 105,490 76,840 108,680 70,892 35,888 43,950 129,517 119,933 14,470 GAS 1977 TOTALS OIL WATER 1,037,360 GAS CUM OIL CUM WATER 9,824,896 CUM GAS ' ALASKA INDIVIDUAL WELL PRODUCTION AS OF 02/19/99 1978 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 13 28 31 29 31 30 31 27 28 31 30 31 OIL WTR 64,960 126,588 136,500 117,428 137,350 128,730 128,230 103,300 117,550 119,800 111,250 115,125 GAS 1978 TOTALS OIL WATER 1,406,811 GAS CUM OIL CUM WATER 11,231,707 CUM GAS 1979 JAN FEB MAR APR MAY JUN JUL 'AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 31 28 30 30 31 30 31 31 30 30 30 30 OIL WTR 116,010 101,560 107,721 111,600 114,940 108,100 118,670 116,740 102,940 100,960 106,930 99,890 GAS 1979 TOTALS OIL WATER 1,306,061 GAS CUM OIL CUM WATER 12,537,768 CUM GAS 1980 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR 2NJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 28 3 9 9 19 30 31 31 30 29 21 1 OIL WTR 78,880 7,946 26,390 35,670 75,080 109,490 104,450 104,590 104,240 91,440 61,000 260 GAS 1980 TOTALS OIL WATER 799,436 GAS CUM OIL CUM WATER 13,337,204 CUM GAS 1981 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT SHUT-IN WTR INJT SHUT-N SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN DAYS 7 8 8 OIL WTR 15,183 GAS 1981 TOTALS OIL WATER 15,183 GAS CUM OIL CUM WATER 13,352,387 CUM GAS FIELD/POOL: TRADING BAY, UNDEFINED SALES CD - 82 ACCT GRP - 004 FINAL STATUS: DEV SUSP CURRENT STATUS: SER WDSPL ** DISPOSAL PROJECT ** 1997 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH OTHER OTHER OTHER OTHER 4 13 1 17 DAYS OIL 32 55 12 232 WTR GAS 1997 TOTALS OIL WATER 331 GAS CUM OIL CUM WATER 331 CUM GAS 1998 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH OTHER OTHER OTHER SHUT-IN OTHER OTHER OTHER OTHER OTHER SHUT-IN SHUT-IN SHUT-IN DAYS 16 18 2 30 10 17 10 30 OIL WTR 157 29 36 4,683 882 3,369 2,595 743 GAS 1998 TOTALS OIL WATER 12,494 GAS CUM OIL CUM WATER 12,825 CUM GAS '~ ALASKA INDIVIDUAL WELL PRODUCTION AS OF 02/19/99 WELL-NAME: N TRADIDTG BAY UET2T .5-05 APIA: ?33-2Q1S6-OD LEASE: ADL0018776 OPERATOR: MARATHON OIL CO FIELD/POOL: TRADING BAY, G-NE/HEMLOCK-NE SALES CD - 82 ACCT GRP - 004 FINAL STATUS: DEV 1-OIL CURRENT STATUS: SER WDSPL ** OIL PRODUCTION ** 1969 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT DAYS 30 16 23 30 31 30 31 OIL 32,799 8,191 57,280 91,804 95,294 74,056 76,562 WTR 34,666 12,222 664 452 325 668 1,057 GAS 7,217 2,747 13,516 22,181 22,680 18,169 17,036 1969 TOTALS OIL 435,986 WATER 50,054 GAS 103,546 CUM OIL 435,986 CUM WATER 50,054 CUM GAS 103,546 1970 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT DAYS 31 28 31 30 31 30 31 31 30 31 30 31 OIL 71,662 61,440 55,915 55,938 50,730 44,993 37,542 33,072 35,052 33,124 26,457 23,100 WTR 1,656 3,714 8,727 6,255 8,955 11,528 13,634 13,114 13,920 16,117 21,776 26,342 GAS 19,669 17,137 15,217 11,124 10,972 10,741 10,639 8,855 7,957 6,214 4,242 4,366 1970 TOTALS OIL 529,025 WATER 145,738 GAS 127,133 CUM OIL 965,011 CUM WATER 195,792 CUM GAS 230,679 1971 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT DAYS 31 28 30 30 31 21 31 31 30 31 30 31 OIL 24,532 22,216 15,404 9,815 14,051 5,325 6,323 11,880 10,240 10,011 7,696 7,970 WTR 21,668 22,394 27,148 30,744 21,077 15,395 26,511 27,340 20,630 20,017 16,474 17,263 GAS 2,989 2,537 1,877 902 1,541 637 614 1,347 899 905 670 734 1971 TOTALS OIL 145,463 WATER 266,661 GAS 15,652 CUM OIL 1,110,474 CUM WATER 462,453 CUM GAS 246,331 1972 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT DAYS 31 29 31 30 31 30 31 31 30 31 30 31 OIL 8,163 9,415 12,361 13,641 20,991 23,055 24,693 27,679 26,531 25,264 21,919 21,033 WTR 27,584 26,528 28,037 27,812 33,409 29,025 29,912 32,527 29,787 29,108 29,350 31,395 GAS 721 785 1,073 1,767 3,750 4,131 4,661 5,720 5,129 5,011 5,001 5,050 1972 TOTALS OIL 234,745 WATER 354,474 GAS 42,799 CUM OIL 1,345,219 CUM WATER 816,927 CUM GAS 289,130 1973 JAN FEB MAR APR MAY JUN JUL AUG SEP. OCT NOV DEC METH GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT DAYS 31 28 31 30 30 25 29 31 30 31 30 31 OIL 22,660 19,661 19,221 18,462 18,163 8,703 18,.928 18,602 16,014 15,514 15,148 14,121 WTR 32,779 29,447 34,238 35,750 31,943 25,195 39,608 43,550 39,400 43,726 45,678 49,884 GAS 6,445 5,373 5,569 5,651 4,990 2,607 4,997 5,070 4,177 3,984 3,659 3,128 1973 TOTALS OIL 205,197 WATER 451,198 GAS 55,650 CUM OIL 1,550,416 CUM WATER 1,268,125 CUM GAS 344,780 1974 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT GAS LIFT DAYS 31 28 31 30 31 30 31 31 30 31 30 10 OIL 14,128 12,417 13,560 11,743 10,591 9,777 9,238 7,842 6,564 6,654 5,889 1,529 WTR 51,379 44,027 52,754 46,917 52,802 49,765 57,038 47,540 40,875 41,025 41,870 13,800 GAS 2,985 2,622 2,842 2,440 2,243 2,181 2,030 1,950 1,675 1,580 1,500 400 1974 TOTALS OIL 109,932 WATER 539,792 GAS 24,448 CUM OIL 1,660,348 CUM WATER 1,807,917 CUM GAS 369,228 FIELD/POOL: TRADING BAY, G-NE/HEMLOCK-NE SALES CD - 82 ACCT GRP - 004 FINAL STATUS: DEV 1-OIL CURRENT STATUS: SER WDSPL ** ENHANCED RECOVERY ** ALASKA INDIVIDUAL WELL PRODUCTION AS OF 02/19/99 1974 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC WTR INJT METH 6 DAYS OIL 52,026 WTR GAS 1974 TOTALS OIL WATER 52,026 GAS CUM OIL CUM WATER 52,026 CUM GAS 1975 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 30 28 13 28 31 30 30 31 30 31 27 15 OIL WTR 292,757 258,903 118,847 271,480 313,805 350,298 311,994 341,650 315,178 342,742 278,792 150,881 GAS 1975 TOTALS OIL WATER 3,347,327 GAS CUM OIL CUM WATER 3,399,353 CUM GAS 1976 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 31 29 31 12 31 29 31 31 30 30 30 31 OIL WTR 314,453 309,073 318,666 98,535 189,130 187,639 196,160 194,182 173,552 180,326 177,034 188,153 GAS 1976 TOTALS OIL WATER 2,526,903 GAS CUM OIL CUM WATER 5,926,256 CUM GAS 1977 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 31 26 31 30 21 23 16 10 10 29 30 6 OIL WTR 186,805 152,990 182,810 147,350 77,004 116,580 79,341 41,709 53,620 175,881 182,299 19,640 GAS 1977 TOTALS OIL WATER 1,416,029 GAS CUM OIL CUM WATER 7,342,285 CUM GAS 1978 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 13 28 31 29 31 30 31 27 28 31 30 31 OIL WTR 86,690. 178,970 207,230 175,330 200,230 189,340 191,380 159,280 169,810 191,910 189,420 200,052 GAS 1978 TOTALS OIL WATER 2,139,642 GAS CUM OIL CUM WATER 9,481,927 CUM GAS 1979 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 31 28 30 30 31 30 31 31 30 30 30 30 OIL WTR 207,580 185,320 196,590 200,140 211,020 194,950 199,530 198,880 199,490 207,760 212,440 221,510 GAS 1979 TOTALS OIL WATER 2,435,210 GAS CUM OIL CUM WATER 11,917,137 CUM GAS 1980 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT WTR INJT DAYS 28 3 9 9 19 30 31 31 30 29 30 31 OIL WTR 170,790 12,406 42,740 54,590 127,370 211,570 192,130 194,920 197,780 200,750 119,280 102,420 GAS 1980 TOTALS OIL WATER 1,626,746 GAS CUM OIL CUM WATER 13,543,883 CUM GAS • .- ALASKA INDIVIDUAL WELL PRODUCTION AS OF 02/19/99 1981 JAN FEB MAR APR IN HUT MAY SHUT-IN JUN SHUT-IN JUL SHUT-IN AUG SHUT-IN SEP SHUT-2N OCT SHUT-IN NOV SHUT-IN DEC SHUT-IN METH WTR INJT WTR INJT WTR INJT - S DAYS 31 21 8 OIL WTR 88,949 68,975 22,720 GAS 1981 TOTALS OIL WATER 180,644 GAS CUM OIL CUM WATER 13,724,527 CUM GAS 1982 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC METH SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN SHUT-IN DAYS OIL WTR GAS WATER GAS CUM OIL CUM WATER 13,724,527 CUM GAS 1982 TOTALS OIL 1998 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV WTR INJT DEC WTR INJT METH 1 1 DAYS OIL 7 90 WTR GAS 1998 TOTALS OIL WATER 97 GAS CUM OIL CUM WATER 13,724,624 CUM GAS FIELD/POOL: TRAD ING BAY, UNDEFINED SALES CD - 82 ACCT GRP - 004 ** FINAL STATUS: DEV 1-OIL CURRENT STATUS: SER WDSPL ** DISPOSAL PROJECT 1998 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC OTHER OTHER OTHER METH 30 21 1 DAYS OIL 10,420 6,436 7 WTR GAS 1998 TOTALS OIL WATER 16,863 GAS CUM OIL CUM WATER 16,863 CUM GAS • • ~ 7 Alask~n Domestic roduction M Marathon MARATHON Oil Company May 12, 1998 Mr. Blair Wondzeii Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Reference: Spark Well S-4 Injection Dear Mr. Wondzell: P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 At the present disposal rates, Marathon Oil Company will exceed our permitted annual injection in Spark Platform Well S-4 at the North Trading Bay Unit as of tomorrow afternoon,. Wednesday, May 13, 1998. Therefore, to avoid shutting in Well S-2rd and potentially harming its production, Marathon requests expedited approval by noon tomorrow of our request for increased water injection into Well S-4. Thank you far your prompt attention to this matter. If you have any questions, please call Gary Eller at 564-6315. Sincerely, T~ ~\ ~ W. C. Barron Operations Superintendent JGE/nrs M'1WP10PNS98WGE512 -~1a~ ' `~a-de U~'~`~-~ Qfl~ro`~t ~iC `~ 1S t~~8 A subsidiary of USX Corporation Environmentally aware for the long run. 7332017201:500 • • ~o ab yi as 7332017201:500 S-02RD Days Gas Water Cum On Rate Rate Gas Prod (PD) (PD) Prod Date ------- Mcf/d ---- bbl/d - -- -- MMcf ------- --- --- 19960101 ---------- 0 ---- -- - * ------ * 0 19960201 0 * * 0 19960301 0 * * 0 19960401 0 * * 0 19960501 0 * * 0 19960601 0 * * 0 19960701 0 * * 0 19960801 0 * * 0 19960901 0 * * 0 1001 0 * * 0 1101 0 * * 0 61201 9 2467 0 22 19970101 20 5295 0 128 19970201 18 3561 0 192 19970301 31 3160 0 290 19970401 0 * * 290 19970501 0 * * 290 19970601 0 * * 290 19970701 0 * * 290 19970801 0 * * 290 19970901 4 9103 0 327 19971001 13 5155 0 394 19971101 2 2600 0 399 19971201 17 7886 0 533 19980101 16 8211 0 664 19980201 19 3981 0 740 19980301 2 5659 0 751 f ; M Marathon MARATHON Oil Company October 9, 1998 Alaska Domestic , duction P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 ~~r~~~ i9~, Mr. Blair Wondzell ~11aI~IraOii&GasCons.Commissiar Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive AfaehoragE Anchorage, Alaska 99513-7599 Reference: Amendment to Disposal Injection Order (DIO) No. 13 Well S-4, Spark Platform, North Trading Bay Unit Dear Mr. Wondzell On May 15, 1998, the AOGCC granted an amendment to rule 4 of Disposal Injection Order (DIO) No. 13 for the North Trading Bay Unit (NTBU) well S-4. The amendment increased the maximum average daily disposal rate in the annulus of well S-4 from 5 bbls per day to 200 bbls per day. The maximum disposal rate of 300 bbls per day and maximum injection pressure of 1,000 psi were unchanged from the original order. The AOGCC also requested that Marathon submit a report by October 15 assessing the economic and technical considerations of equipping well S-4 with tubing and packer should injection remain at the higher volumes. Marathon requests that the 200 bbl/day average disposal allowance for well S-4 be made permanent. A report dated September 23 regarding injection into wefi S-4 was recently sent to Ms. Wendy Mahan of the AOGCC. This report affirms that increasing the disposal allowable to 200 bbls/day in well S-4 has not led to any undesirable consequences. Injection pressure into well S-4 has stayed below the 1,000 psig limit. The recent successful conversion of well S-5 to disposal means that well S-4 will now serve as a backup disposal well, but full injection capability needs to be maintained in well S-4. Well S-2rd continues to produce water in excess of 100 bbls/day. Recovery of NTBU gas reserves is dependent on being able to dispose of adequate volumes of water. I estimate that equipping well S-4 with tubing and a packer would cost roughly $1.4 million. It would require reactivation of the Spark platform rig, pulling the 4'/" tubing, abandoning the existing perforations, rerunning the injection tubing and packer, and A subsidiary of USX Corporation Environmentally aware for the long run. '. • • Report on Disposal Injection Operations Well S-4, North Trading Bay Unit October 9, 1998 Page 2 deactivating the rig. Significant expense would be required simply to make the unmanned Spark platform suitable again for continuous human habitation. Seeing that well S-5 is currently able to dispose of all of Marathon's produced water adequately, and since well S-4 is able to dispose of the water in its existing state if required, there is no current economic justification for equipping well S-4 with tubing and packer. Sincerely, ~~ ~~ J. Gary Eller Production Engineer JGE/nrs N:~DRLG~SPARK~.S-41AC{'aCC98A.WPD ~~ SENT BY~Marathon Oil Company 5- 8-98 1~24PM ; ~~~ Marathon ~MRNTNON J Oil Company Anchorage-~ 907 276 7542:# 1/10 -~°'g ~' 9` Alaska Ragion ~ ~ J~~ ~~, ~ Domestic Production J ~ jc ~~ ~ ~ -F6 - ~~(y'" P,t7, pox 196168 Anchorage, AK 99519-6168 ( (~ ~r- y u ~`~ Telephone 967/561-531 ~ ~~,e!°' A~~ ~ ~~ FAX COVER LETTER ~1 DATE; ~ ~ ~. FROM: Name: ~/~ ~ l.:ocatlon/Extension: ~ ~ --~ fax No.: soy/5sa-sass A subsidiary of USX Corporation environmentally aware for th® long run. PLEASE DEI.IYER THE FOLLOWING TO: >f transmission is n~ complete, please call 90T/56i~311. SENT SY~Marathon Oil Company 5- 8-98 ; 1~25PM ; •, Marathon ~M o~ll coimlpany May 8, 1998 Mr. Blair Wondzell Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99513-7599 Reference: Spark S-2rd Dear Mr. Wondzell: Anchorage 907 276 7542;# 2/10 Alaska~ggion Domestic f'roduc8on P.0.13ox 196168 Anchorage, AK 99519-6168 TelephonA 807/561-5311 Marathon Oil Company requests that Rule ~ of Disposal Injecc~ion Order No. 13 for welt S-4 in the NTBU be revised to allow for annual average daily disposal rates of 200 bbls/day. The increase in water production from well S-2rd following perforating was unexpected, and the existing allowable disposal rate of 5 bbls/day is inadequate to produce well S-2rd effectively. The attached report by Gary Eller shows that: • The Sal disposal well is easily handling the increased water volumes. Increasing the allowable disposal rate to 200 bbls/day will not allow fluids to escape from the disposal zone. • Without increasing the disposal rate in well S-4, it is likely that reserve recovery from well S-2rd will be greatly diminished. • It is likely that water production from well S-2rd will continue to decrease if the well ~~ is continuously produced. ~ '~" ""'~~~ ~``'~" ~~ ~`~ There is low probability of success and nominal ono IC justifica~n attempt g o~- remedial squeeze work in well S-2rd. T ~,~ ~ ~o ~~ , ~~„ ,~.-~ e~-• At current production rates, well S-2rd will have to be s~within seven days to keep from exceeding the 5 bbl/day average disposal allowable. Crossflow of water during a sfiut-in will be detrimental to the producibility of well S-2rd. Since any shut-in of well S-2rd threatens the recovery of reserves from that weA, Marathon requests that this matter be acted upon quickly by the Oil 8~ Gas Commission. Sincerely, W. C. Barron ~~ Operations Superint ndent ~ ~ 1~~8 ~~ AY ,so~mrs MiwP1bPNS98WGE68 Attachments ~& A subsidiary of USJ~ Corporation Environmentally aware for the long run. 5ENT BY~Marathon Oil Compan 5- 8-98 1~25PM • Anchorage 907 276 7542;# 3/10 1NTRA COMPANY CORRESPONDEI~TCE TO: W.C. Barron Ok~CE: SUBJECT: Anchorage, Alaska Spark S-2rd Water Production DATE: May 6, 998 l~ttoM: J.G. Etter OFFICE: Anchorage, Well S-2rd in the NTBU has shown a large increase in water production since being returned to production May 1, 1998. The likely source is one of the seven sand bodies that were perforated for production in late Novennber1997. The annular disposal well 5~4 has had na difficulty keeping up with the increase in water production, However, the AOGCC disposal limitation of S bbls/day threatens reserve recovery its well S-2rd. T recommend that we ask the AOGCC to increase the allowed average annual injection volume to 200 bbls/day. The test of May 4 showed that well S-2rd made 104 bbl of water and 3,619 MCF in 24 hours. The well has produced nearly 700 bbl ofwater since being returned to production on May 1. Compare this with it's average rate oft bbls/day and 4,038 MCFD in mid l~ebruary when the well was last produced consistently. The most plausible scenario for the increased water is that during March and April, while S-2rd was shut-in, water crossflowed from one of the newly opened sands into a partially depleted, high permeability sand. This is supported by the generally impruving water ratio as the well continues to produce. As this high permeability sand unloads, it's likely that produced water volumes will continue to drop. But in the future it will be necessary to kecp well S-2rd online as nnxch as possible to assist the well in cleaning up and to prevent water from accumulating again. The annular disposal well S-4 has had no difficulty keeping up with the increase in water production. Current injection pressure is approximately 4fi0 prig, and shut-in pressure on the disposal wait. was approxirnately.224 psig before well S-2rd was brought back .online. The allowable disposal volume in well S-4 should be increased immediately, or production from welt S-2rd will be threatened. AOGCC .Disposal Injection Order No. 13 stipulates that the average daily disposal rate shall not exceed 5 bbls/day, which equates to 1,82.1 bbls/year. As of May 7, we have disposed of 915 bbls in welt S-4 in 1998. Unless the AOGCC's order is changed, the injection limitation on well S-4 will soon cause us to have to shut-in well S-2rd. This will likely have a detrimental elI`ect on the ultimate recovery of gas reserves from well S-2rd because of flooding-out of productive zones and tinuting producing time. o k. I do not recommend asking for an increase in the current allowed 300 bblslday maximum injection rate. That will assure that we do not hydraulically fracture out of zone, as per the findings in Disposal Order No. 13. 5FJNT BY~Marathon Oil Company ; 5- 8-98 1~26PM Anchorage-~ 907 276 7542;# 4/10 r ~ ~. i ~i Spark S-2rd Water Prodactivn May 7, 1998 Page 2 Remedial action to reduce the amount of produced water from well S-2rd will be difficult and expensive, and is possibly not economically justifiable. The well is completed with 2~/e" tubing inside 7", 29 ppf casing_ The first step would be to determine which sand(s) is producing the water, which could be a tricky evaluation given that crossflow into gas productive zones is probable. Shutting offthe water source would entail mobilizing 1 ~/2" coil tubing and performing a cement or gel squeeze. It's likely that a squeeae will have to be performed more than Dace given the number of open sands and likelihood of crossflow in the wellbore. Adding greatly to the complexity and cost of the operation is the condition of the Spark Platform itself, which has no facilities to store completion fluid, no fresh water source, minimal crew facilities, etc. I would use $300,000 to $400,000 as a first-look estimate for the cost of shutting offthe water in well S-2rd. Conclasions & Recommcndativns ]i. All indications to date show that the disposal well is handling the increased water volumes just fine. The injection pressure is where we expect it to be given recent injection history. There is no reason to believe that an increase in water disposal volumes in the annulus of well S-4 will cause future problems. 2. 1 expect tlm produced watdr volumes will contirnue to fhll if we consistently produce vvdll S-2rd. 3. Remedial action to shut offthe water in well S-2rd will be expensive and difficult to perform, and economic incentive is low. 4. Without increatsing the ailawable injection rate in well S-4 or shutting offer source of water, the rex~very of reserves from wdl S-2rd witt be greatly dim~iahcc~l. 5. 1 recommend that we ask the AOGCC to increase the annual average pet~'tsslble inje~cetion volume from 5 bblslday to 200 bbls/day. i would leave the peak permissible injection rate at its current 300 bbls/day maximum. 6, If approval is given to inject more water, I recommend that we keep well S-2rd online continually to prevent water accumulation in high perm sands. Attachments c, Lyndon Ibele r~~Y o ~ i998 o~~ SENT SY~Marathon O11 Company 5- 8-98 1~26PM Anchorage-' 907 276 7542;# 5/10 pp ~~wwnga'~uazuo~ ~~~~ O O O O 4 ~ O p O O ~ ~ d M M N O ~ © ~ N r r ~ O) N '` a Q N C O t! N ~a ~ ~ ~n o ~f e~- N c c~ c a M N r Op O © o o o $ ~ o N O o0 cq d' N T 'le- 3~W `e~~a ss9 SENT BY~Marathon Oil Company ; 5- 8-98 1~27PM ; Anchorage-~ 907 276 7542;# 6/10 Spark Well S-2rd 1998 Gas Water Production Well s-2rd, Spark Platform, NTBU Oas Water Water Ratio Oate MCF 1'b! bbl/MMCF 1-Jan-9$ 4,816 1.3 028 2-Jan-98 9,980 8 0.60 3-Jan-98 11,385 17 1.49 4•Jan-88 11,148 17 1.52 5-Jan-98 11,281 5 0,44 B-Jan-98 7,462 1 0.13 7-Jan-98 30 0.5 18.67 8-Jan-98 816 0.5 0,81 9-Jan-88 1,529 0.5 0.33 10-Jan-98 1,598 0.5 0,31 11-Jan-98 1,745 0.5 0.29 12tilan-98 668 0.4 0.60 13•Jan-98 225 0.2 0.89 14-Jan-98 298 0.2 0.87 15-Jan-98 0 0 - 1 B-Jan-98 150 0 _ 17-Jan-98 3,240 0 18-Jan-A8 0 0 - 19-Jan-98 5,348 p _ 20-Jan-98 5,770 0 _ 21,1an-98 10,800 0 _ 22-Jan-98 5,748 9.1 1.58 23~1an-98 8,780 16.3 2,40 24-.tan-98 6,224 /9 3.05 25-Jan-98 5,230 8 1.53 28-Jan-98 2,x13 L5 0.62 27-Jan•9$ 5,929 10,2 1.72 28-Jen-98 7,534 32,8 d.33 28-Jan-98 4,130 4 0.97 30-Jan-98 6,117 4 0.65 31-Jan-98 3,632 2 0.55 1-Feb-98 3,700 2 0,54 2-Feb-98 1,588 0 _ 3-Feb-98 1,897 0 4-Feb-9a 1,920 2 1.oa 5-Feb-98 1,944 2 1.03 6-Feb.eB 2,237 1 0.45 7•Feb-98 5,234 p _ 8-Feb•88 5.286 0 _ 9•Feb-98 1aFeb-98 5,283 4 711 1.4 0.27 ' ' ~''~~~ ~ , 4.3 0.91 11-Feb-98 4,726 5 1.06 12-Feb-98 4,726 5 1.06 MaY a ~ ~gg~ 13-Feb-9$ 4,514 0 _ 14=Feb-A8 15-Feb-98 3,704 4,343 1 1 5 0.27 0 35 ~k8~$cGBSCpIg,j 16-Feb-98 1,628 . 0.5 . 0.31 17-Feb-98 2,725 1 0.37 Page 1 SENT BY~Marathon 011 Company 5- 8-98 1~27PM Anchorage 907 276 7542:# 7/10 •, Spark Well S-2rd 1898 Gas Water Production Welt 3.2rd, Spark Platform, NTBU Gas Watar Water Ratio Date MCF bbl bbI/MMCF 18-Feb•98 0 ~ 0 - 19-Feb-98 50a e:, ; o _ 20-Feb-98 186 -% 0 - 21»Feb-98 0 a _ 22-Feb-98 0 p - 23-Fe1~98 3,188 p _ 24-Feb-98 5,071 %w~ 0 - 25-Feb-98 4,372 ' -' 0 _ 28-Feb-98 2,980 z o,87 27-Feb-98 p p _ 28-Feb-98 0 p _ 1-Mar.98 0 p _ 2-Mar-98 0 0 - 3-Mar-98 4,388 ,- '1 ' 15 3.42 4-Mar-88 4,388 2J 21 4.79 5-Mar-98 p 0 _ 6-Mar-98 0 0 _ 7-Mar 98 0 0 - SrMar-98 945 0 _ 9-Mar-88 0 0 - 10-Mar-98 0 0 _ 11-Mar-98 ~ 0 0 _ 1 Z-Mar-98 0 0 _ 13-Mar-98 0 0 - 14-Mar-98 10 0 - 15-Mar 98 p p - 18-Mar-98 0 p _ 17«Mar-98 0 0 - 18-Mar-98 0 0 - 19-Mar-98 p 0 _ 20-Mar-98 0 0 - 21-Mar-98 p p _ 23-Mar-98 0 0 » 24•Mar-98 D p _ 25-Mar-98 790 0 - 28-Mar 98 0 0 - 27-Mar-98 p 0 - 28»Ma~ 98 0 0 - 29-Mar-98 0 0 - 30-Mar-98 p p _ 31-Mar-98 0 0 - 1-Apr-98 ~ ~ 0 0 _ 2-Apr-98 0 0 _ 3-Apr-98 0 0 - 4-Apr-98 0 0 _ 5-Apr-98 0 0 .. 8-Apr-98 203 0 _ 7-Apr 98 p p _ Page 2 5ENT-BY~Marathon Oil Company 5- 8-98 1~27PM Anchorage-~ 907 276 7542;# 8/10 ' ~ Spark Well S-2rd 1998 Gas Water Production Well 5-2rd, Spark Platform, NTBU Gas Water Water Ratio Date MCF bbl bbilMMCF &Apr-98 0 0 _ 9-Apr-98 p p _ 10-Apr-98 q 0 - 11-Apr-98 0 0 _ 12-Apr-A8 p p _ 13-Apr-98 0 0 _ 14-Apt 98 0 0 _ 15-Apr-88 0 p _ 16-Apr-98 0 p _ 17-Apr-98 0 0 - 18-Apr•88 p p , 19-Apr-88 p p _ 20-Ap~ 98 0 0 _ 21-Apr-98 0 0 _ 22-Apr-98 d p _ 23-Apr-98 0 0 _ 24•Apr-98 0 0 25-Apr-98 0 0 _ 28-Apr-98 0 0 _ 27-Apr-98 0 0 - 28-Apr-98 0 0 - 29-Apr»88 0 0 - 30-Apr-98 0 0 _ 1-May-98 2,757 37.3 13.53 2-May-98 2,091 99.2 47.44 3-May-98 2,651 99.1 37.38 d-May-98 3,619 104.3 28.82 5-May98 3,713 118 31,78 8-May-98 3,72a 119 31.95 7-May-98 , ~ 3,727 116 31.12 8•May-as ~% o p _ Total 251,759 915 ~?~~r i!~dY ~ ~ i9`9 ~eice0~ & cast`,ons. Connllis~iorl Page 3 SFNT BY~Marathon Oil Company 5- 8-98 I~27PM ; Anchorage 907 276 7542;# 9/10 North Trading Bay Unit Spark Platiform, V~ell S-2rd Marathon Oil Co., Alaska Region FN1C TGIA-rNS-SPCC Tubing Hattgcr (cii 35' 3-1l8" 4SAM2-1.1-! lop x 2-318" EC7 lxittom Camco 77tDP-0A tit;SSV (ci), 593' w/ Clow couplings ID = 1,875" Tubing String: 2-3/8", 3.2158, Coil haring, Precision HS-70 CM, G1H)OUl! Yield 1D = 2, t U?" Calneo "X" Nipple (~ 9188' 1D ~ 1.875" ~ 13-318", G 1 ~, J-55, BTC Casing (i~~055' t'op ol'7" Liner (iiy 71 GT Calnut "X" Nipple (c~ 921 T fp = 1.875" S~~1tt Pertoratirnt~-I l/IG" strip guns, T;J-111.0 dcg) Br-1 9580' - 9590' T11'1' (4 spt; 1 1/22197) Br-2 9623' -,9633' TDT (q spt; l 1/22/97) 9650' - 9665' TDT (4 spt; 11/22197) I JG-1 9772' - 9787' TDT (4 spt; I I /22/97) UCl-2 9852' - 9867"1DT (4 spt; I I /22/97) UCr 3 9925' - 9940' TDT (4 spt; 11122!97) C7G-4 9984' • 9994' TDT (4 spt; 11/22/97) UG-S 10U5tP -10090' TDT (6 spt; 8/94) 1'lu ed c fs G-2 thnt H-I (iQ 111560' - 10822' (=etnent 10515' 1)II. - 10796' WI.M Pill 10796' W[,M - !0822' I?IL Cetucut 10822' I)IG - I(-R32' llIL 9-S/8", 47~, N-80, Butt Csg (u), 737U' -~:. ( Baker Mode:( HB Paek~7 (~7 920(1' Wirolittc Rc~-):ntry Guide (? 9227' Cut 2-318" Coil Tubging (a~~, 10210' Jwtk SC2-1'AII Packet Bc'i"ail Pipe (c~ 10345' ~,.- bridge Plug ([~? 10387' - 2-78" Cut Tubing (u) EU406' Baker 8U~40 Locator w/ 4.000" r 3.000" scut assy (10' Iong) {i~ 10430' - Baker FF3-1 Packer w! 10' SBE, hell gtiicle (4.00" ID) (i~ 10431' Halt=cut Mule Shoe (a7 10501' _. ~~ ~~ - -.~ "o' ID ~ 2.406" ~ ;~ .,r? "n ~~ o i~„ uo°n o ~~'i , - _ - ___- - ' 1ltru=l'ubittg Bridge Plug (i~ 10832' I_'LS eci I'etfs H 2 tlrru H-4 (ii> 10840' - I 1145' Top of rill (~~ 11201' DTL - ~ ^-~ ~ -= , ~\ 7", 29q, N-80, I1TC Liner (u? 1134 (' 7'f.) = 11352' Lnst RCV: J(.TE:, 12/29197 SENT SY~Marathon Oil Company 5- 8-98 1~28PM ; Anchorage 907 276 7542;#10/10 -~ North Trading Bay Unit Spark Platform, Well S-4 Marathon Oil Co., Alaska Region Water Disposal Via 4-1/2" x 9-5/8" Annulus 11/28/97 SC:SSV -Otis ball Vxive (?) 269' 13-3/$", l 1 #. J-S5, BT'C Casing c(~ 2132' Tubing: 4-Il2", t2.6#, N-8U, Hutt. 4" Cameo KBM Gas Lill Mandrels (all dummied) 2489' 4715' 6531' ?909' 8694' 8231' 9798' Fislt: 21' x I-1 I/1(i" w/ 3.789" gauge ring (]1123/97) 3-112", 9.2#, N-R(1,1'iutt. 'I'uhing IUO93'- 1U34t' Piu~ged Perferati~ns C3-1 10126'- 10138' (4 spy c,-2 I O 149' - 10213` (4 spt) tr-3/4/S 10226'- tU337' (4 spt) Plu~~cK1 e n 'n s li-1I2Li 10356' - 10476' (4 spf) H-2[./3 104R4' - 10553' (4 apt) H-3 fOS61'- 1OS92' (4 spt) TD r 10770' Tnbrsa=C_a~Pert's 4594' - 4624' DIL 4654' - 4684' DiI, Sd28'- 5418' llIL 5523' - 5543' L7IL S93T - 5967' UlL Tubing Restriction Aroung CTLM in) 9231' Tubing Bridge Plug (<~ 9245' this "XC)" Sliding Sleeva (e7 IUOST Ill = 3.R1;~" Raker Retrieve-D Packer ([~ 10341' Cros~vcr(4-112" x 3-l/2"}(c~ 10093' Portco "X" Nipple ([~ 10308' ID = 2.750" Porten "X" Nipple (~ I U34I' ID = 2.750" Baket' Retricva-17 Packer ~ 10341' Otis "(~" Nippk; (a~ 10304' ID = 2.635" i~5/8", 47g, N-$U, HTC Casing (cr110744' Last. Rev,: JGE, 12/29/97 ~5 • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of Marathon Oil Company ("Marathon") for an order allowing the underground injection of class II fluids in North Trading Bay Unit well S-4. Marathon by letter dated July 28, 1997 has requested the Alaska Oil and Gas Conservation Commission to issue an order in conformance with 20 AAC 25.252. The order would authorize the underground disposal of nonhazardous oil field wastes (class II fluids) by annular injection in North Trading Bay Unit well S-4, which is located on the Spark Platform. The disposal interval is between 1780' and 7045' measured depth. North Trading Bay Unit is part of the Trading Bay Field, an offshore oil and gas field in Trading Bay on the west side of Cook Inlet. Marathon's application will require an exception to 20 AAC 25.412(d), which requires injection wells to be equipped with tubing and packer, or other equipment which isolates pressure to the injection interval. Aquifers underlying the Trading Bay Field are exempt under federal regulation 40 CFR 147.102. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM August 14, 1997 with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on the matter. If the protest is timely filed and raises a substantial and material issue crucial to the Commission's determination, a hearing on the matter will be held at the above address at 9:00 am on September 3, 1997 in conformance with 20 AAC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, (907) 279-1433 after August 14, 1997. If no protest is filed, the Commission will consider the issuance of the order without a hearing. 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 Diana Fleck at 279-1433 no later than August 25, 1997. David Jo ton, Chairmar~ Alaska Oil an as Conse ation Commission Published July 31, 1997 ADN A002814005 ~~8539 8TOF0330 AO-02814005 AFF DAVIT OF PLiBLICATION $93.24 't~ttes~yt PttHiit Ete+9t'ttYy 6d if file requested ota9er la STATE OF ALASKA, ) iss(~~dd mar file a wrir~ ' THIRD JUDICIAL DISTRICT. ) STATE OP ALASKA AlOSka oil and Gas tNOtist prfar to 4-~ PM August T4, .1997 with the Conservation Commission Alaska qfl and Gas Conserva• Eva TAI. Kaufmann Re: The application of tilt ~amlt11351an, 3001 Pores- ?PineDrivo.Antha-o4p,Ateska ................................................... Marathon Qit CAmpartY 99501, and request a hearing being first duly sWOfn On Odth f`Marattron") for pn order allowing the underground ion the matter. if the protest is 'timely toed and raises asub- deposes and says that he/she Is iniocti0n of clpss I I fluids in North Trgdin6)Bay Unit wail '~ stantlal ared~ mat0rigl issue crucial to the commtasipq•s~ an advertisin re resentative of p s•4~' determinafion, ° irearlt>s on I the matter will be held-at the the Anchors a Dail News, a g y Marathon by letter. dated ~~ stove address at 9:(Rf ant on July 2®, 199 tws requested ine September 3,' 7997 in confor- i daily newspaper. That said Alaska Oi! and Gqs Canserva- ' manse with ?OAAC 25.540, ii a' newspaper has been approved tion Loirtmission to issue an order'in conformance with 20 hearing is to be Held, interested parties may 'coq-! by the Third jlldlClal COUCt, AAG 25.252. Tne order would authorize the underground firm this~bv caliing the Commission's office, (901) Anchorage, Alaska, and it now disp03ai Of naRhaLgrdbtS aiC field wastes fcla;s 11 #lui~) .279-1433 after AUgsut 14, 7997. If,no protest is tiled, the and has been ublished in the p by .annular inieetbn in North Trading Bar... UM( X11 5.4, Conunisslon w;n cprisiaer me issuance of the order wittrout a En lish Ian ua a eontinuall a5 a ¢ g ¢ y which iS located on tho Spark Pi hearing. u u u aHOrm. 1?te di5irosat inter- If you are a person witty aj daily newspaper in Anchorage, vat is t~tween t7>~~ and 7o4s~ disabiaty wno maY -Hasa a Alaska, and ]t Is now and during measured dopih: North Trad• fng $av Unit is part of 4hg special meCtiticcrtlon irr order to comment Or to t!ittend tfto all said time was printed In an Trading Bar Field, an offsh9re oil sad gas field. In Trading public hearlrig, plodse coptact Diana Fleck at 279-1433 M1o office maintained at the aforesaid Baton the wort side ofCook` Inter: later than Augus# 25, 7997, 75/1)av7a ~r. Johnsian place of publication of said Marathon's apptlGation will regaireanoxcearlontdPOAAC' Chairman ; Alaska oll and Gas'" news a er. That the annexed is p p 2s.472cd1, whFCn roquires inieGrwn welts"to be equipped Conservation CamtYlissfgn Puh.i July 37, 7947 `; a copy of an advertisement as it wirn talyina and ~nacke#, .or was published in regular issues other equipment which isolatos p-eesure to the iniectian (and not in supplemental form) of interval. qqui#ers underlying. ,the Tradina- `B~v 1'iela ors said newspaper on exempt undee federal ~ e - regulations 40~CFR 7i7.,oY. '' - Apersob'wtmmav be harm- ulp 31, 1997 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Subscribed and swo to before me this~~~ . day o ....'L~G~C..~j..... ~~ ~....7. t` .~ ~. Notary Public m and for the State of Alaska. Third Division.' Anchorage, Alaska MY COMMISSION EXPIRES ......... ~y.. .... ;zs: 19...... February £S, 2pUp ~ 4 SFNT BY~Marathon Oil Company ; 7-28-97 2~39PM ; • Anchorage-~ 907 276 7542;# 1/ 5 ~~d ~ 13 ~~ ~~~ S_ y. i a / ~ +" ~,, ,. ~~ d„ t",~~ ~~v t'„ 3C~ y. • Cl,y'' t: ~jia is r/1~r~~ltay-; ,~ 3~ Re: B~,uest For Class l1 Disposal Well, North Tra~jng jiay ~Jnit Stark Well S-4 Dear Mx. Johnston: Marathon Oil Company formally requests permission to dispose of nonhazardous oil field exempt wastes by annular injection into Spark Well S-4. Marathon requests permission t.o inject solids and fluid wastes that have been generated l`rom normal workover and production operations into S-~1. The attached summary provides information required per 20 AAC 25.252, for the State of Alaska's Oil and Gas Conservation Commission (AQGCC). Although Maralhori is requesting a permit Cc~r injection of nonhazardous exempt wastes, the primary purpose for this proposal is to dispose of produced water from natural gas well S-2rd. S- 2rd was recompleted in November, 1994 and was produced during the 1996-97 winter season. S- 2rd's completion fluid was injected annularly in S-4 under an anmial disposal permit whiclt expired March 31, 1997. S-2rd is currently S1 awaiting additional gas demands typically associated with the winter months, and approval of this S-4 injection permit. It is estimated that a. maximum of200,000 bbls of fluid will be injected into S-4. Mast, if not all, of the fluid would come from the S-2rd completion. This low injection volume is based on several factors: 1) S-2rd produces from a depletion type gas reservoir so influx from a water drive is not expected; 2} S- 2rd sits on the top of the structure; 3) similar sands at Beaver Creek, Kenai Gas field and Steelhead Platform have all failed when water production increases to a large volume, thus requiring the water producing sand to be squeezed off, and an additional sands perforated; and 4) there are currently no workover/drilling programs planned where large volumes of liquidslsolids would be generated. Other disposal options reviewed were deemed either uneconomical and/or contained greater risk to the environment. Those options are discussed below. 1) Drill a new well or workover an existing completion, This was uneconomical due to SENT BY~Marathon Oil Company ; 7-28-97 ; 2~39PM ; Anchorage 907 276 7542;# 2/ 5 the high costs of reactivating a rig and the actual cost of the drilling/workover program. 2) Inject down the tubing of an existing completion was uneconomical. All Spark oil producion and water injection wells were killed with mud. Coiled tubing would likely be required to deanout the existing completion and the target injection would require reperforating. The integrity ofthe tubing is also in question due to failed gas lift valves. 3) Overboard the produced water. This is not feasible due to the platform being unmanned and the increased risk of a spill. 4) Store fluids on the platform and transport it onshore via barge, Al[ tanks and oil processesing equipment have been mothballed and are located in unheated areas of the platform. Installation of new tanks is uneconomical. There are also increased risks to the environment in the event ofloss of heat on the platform resulting in ruptured tanks. Barl;e transport of produced fluids is also uneconomical and carries a higher spill potential risk. 5) Ship produced water to Granite Point Production Facility via the gas pipeline. S-2rd is often used as a "swing" well and maybe Sl for extended periods during the winter months. Water in the pipeline would settle to low spots and likely freeze creating an ice plug and loss ofgas production until the plug thaws. An MIT has not been performed on Well S-4 due to the low water rate produced from S-2rd. It is propused to run a temperature log to verify depth on injection after the water production increases to 20013PD (annular velocity of ~4.5 RJmin in the 9-S/8" x 13-3/8" annulus). Attached are several documents to provide information as required by 20 AAC 25.252. if you have any questions concerning this request, please contact me at 9Q7-,5E>4-fi31 S. Sincerely, Michael R. Olson Production Engineer SENT BY~Marathon Oil Company 7-28-97 2~40PM Anchorage 907 276 7542;# 3J 5 • • SPARK PLATFORM S-4 APPLICATION FOR UNDERGROUND 1NJECTIUN Marathon Oil Company requests the Commission issue a disposal injection order authorizing S-4 to be used as a Class iI disposal well in accordance with 20 AAC 25.252. S-4 is a shut-in water flood injection well located on the Spark Platform in Cook Inlet, Alaska. 20 AAC 25.252(c)(1) 5-4 is located in the L-31eg on the Spark Platform in Cook Inlet Alaska. Section B contains a plat map showing the location of the proposed injection well (S~4) and all other (shut in) wells which penetrate the injection zone within one-quarter mile of the injection well, The plat includes eight wells: S-t(rd), S-2(rd,d2), S-3, S-4, S-5, S-7(rd), S-8, S-9. 20 AAC 25.252(c)(2) Marathon Oil Company is sole operator of the Spark flatforrn and owns 100% of the surface rights within one-quarter mile of the S-4 injection well, 20 AAC 25.252(c)(3) Does not apply. There are no other operators or surface owners within cone-quarter mile radius of S-4. 20 AAC 25.zsz(~)(a) Depth of injection will be between 178U' and (350' above the y-5/8" casing shoe) and 7045' snd (calculated tap of cement for the 9-Sl8" casing string), Injection may occur into 3SS' of potential zone [nested between 4590' and 7040' md, Injection may also occur between 1780' and 2132' and in the event the fluids are injected at or shove fracture pressures. Based on S-1 open hole logs, the confining layer is a S0' shale located at t $6D' and 1910' md. There are also smaller shale and coal intervals located up to 1280'. S-4 and S-l open hole logs are included in Section C. A fracture model showing a maximum height growth of 250' is included in Section E. 20 AAC Z5.252(c)(5) 5-4 open hole logs were run from 2132' to 10700' and and are include in Section 1). Potential receiving intervals are marked. The S-l open hole log is also included in Section D to show tog information above 21.00' md. S-1 lies adjacent to S-4 in this area and is expected to reflect similar log responses of S-4. Cement. bond logs were not run on the Spark platform well surface casing strings. The drilling reports were reviewed and based on volumes of cement pumped and/or notes indicatinb good cement returns at surface, the surface casing strings in wells S-1 through fi-9 should be well • 5EIVT BY:Marathon Oil Company ; ?-28-97 2:40PM Anchorage- 907 276 7542;# 4/ 5 • bonded. There was one complication noted while cementing the S-8 surface casing. Returns were lost approximately 50% through the disp)acement volume. Based on calculated volumes, good cement should lie between 2046' and 766'. A "top job" was also performed at 200' -good cement returns to surface were noted. 20 AAC 25.252(c)(6) Section A includes an S-4 wellbore schematic. The 9-S/$" 47# Iv-8U casing is set to 10744' md; the 13-318" 61# J-SS casing is set to 2132' md. Injection is being proposed between the 9-S/8" x 13-3/8" annulus. 20 AAC 25.252(c)(7) Potential injection fluids include non-hazardous exempt fluids associated with production and workovet operations. Such fluids may include, but are not limited to: - Produced water -Expected to consist cif 5,000-15,000 ppm Cl-, specific gravity ~ 0.44 psi/ft. - Completion fluids -Expected to mainly consist of 3-6% KCL brine with additives, specific gravity ~ 0.46 psi/ft. The initial average injection rate is estimated at less than 5 BPU of produced fluids. This number may increase over the life of the producing field. For tlus reason, a maximum daily volume of 300 bbls is requested. 20 AAC 25.252(c)(S) The estimated injection pressure is 700 psig with a maximum injection pressure of 1000 psig. 20 AAC 25.252(c)(9) Dowell has performed a hydraulic fracturing simulation using; their FracCade'"' Sim«lator. Stress values for sands, coals and sha]es were input into the model to determine a maximum height growth of a potential fracture. The model was initially nm at 300 bpd and 1000 psig injection pressure. The results indicated no hydraulic fracture could be initiated due to high Teak ot1' of the injected fluids. Another run was made to evaluate a "worst case scenario." At an injection rate of 28,800 bpd, the fracture grew to a maximum height of 250' above the casing shoe (top of fracture at 1900' md) but did not penetrate the thick shale at 18(10-1910', Section E includes the vowell FracCade"" model and graphical results from the "worst case scenario." 20 AAC 25.252(c}(10) There are no fluid samples from the proposed injection zones. Section F includes a produced water analysis from We11 S-2rd. 20 AAC 25.252(c)(11) Based on S-1 open hole logs, there are no fresh water zones below C00'. There are no drinking SFNT BY~Marathon Oil Company 7-28-97 2~40PM ; Anchorage-~ 907 276 7542;# 5/ 5 water aquifers above the proposed disposal zone. U.S. Congress has already exempted fresh water aquifers in similar geologic setting heneath the surface at Granite Point, Mc~rthur River, Middle Ground Shoal and Trading Bay fields. All of these Bolds lie below Cook Inlet sts does the well proposed in connection with this notice. U Q L s~ A • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon _ Suspend _ Operation Shutdown _ Re-enter Suspended Well Alter Casing _ Repair Well _ Plugging _ Time Extension _ Stimulate Change Approved Program _ Pull Tubing _ Variance _ Pertorate _ Other X 2. Name of Operator 5. Type of Well: s. Datum Elevation (DF or KB) MARATHON OIL COMPANY Development _ 115' KB above MSL feet 3. Address Exploratory _ 7. Unft or Property Name P. O. Box 196168, Anchora e, AK 99519-6168 Stratigraphic North Tradin Ba Unit 4. Location of Well at Surface Service X 8. Well Number 2615' FSL, 2492' FEL, Sec. 26-10N-13W-SM S-4 At top of Productive Interval 9. Permit Number 3158' FSL, 4202' FEL, Sec. 26-10N-13W-SM At Effective Depth 10. API Number 50-- 133-20184 At Total Depth 11. Field/Pool 3220' FSL, 4504' FEL, Sec. 26-10N-13W-SM Hemlock & G-Zone 12. Present Well Condition Summary Total Depth: measured 10770 feet Plugs (measured) true vertical 10237 feet Effective Depth: measured 10700 feet Junk {measured) 10595' - 10700' fill true vertical 10291 feet Casing Length Size Cemented Measured Depth True Vertical Depth Structural Conductor Surface 2132' 13 3/8" 1000 sx 2132' 2131' Intermediate 10744' 9 5/8" 1050 sx 10744' 10329' Production Liner Perforation Depth: measured 10126-10138', 10149-10213', 10226'-10337', 10356-10476', 1048410553', 10561-10592' true vertical 9787-9797', 9807-9864', 9875-9973', 9990-10095', 10102-10145', 10169-10199' Tubing (size, grade, and measured depth) 41/2", 12.6# N-80 Butt tbg ~ 0-10093'; 3-1/2", 9.2# N-80 Butt tbg ~ 10093-10364' Packers and SSSV (type and measured depth) 10087' Baker D Pkr; 10341' Baker D Pkr 13. Attachments Description Summary of Proposal _ Detailed Operations Program _ BOP Sketch _ A lication for In'ection X 14. Estimated Date for Commencing Operation 15. Status of Well Classification as: 10/1 /97 16. If Proposal was Verbally Approved Oil _ Gas _ Suspended _ Name of Approver Date Approved Service Class II Disposal Well ~ 7. 1 hereby certify that t foregoing is true and correct to the best of my knowledge. ~ Title Production En leer Oate 6/24/97 Si ned FOR COMMISSION USE ONLY Conditions of Approval: Notify Commission so representative may witness Approval No. Plug tntegrity BOP Test Location Clearance _ Mechanical Integrity Test Subsequent Form Required 10- A roved b Order of the Commission Commissioner Date i m ~o-aos Rey. oai~srea Submit in Triplicate 8. Plat flap • • 4 a.. lf.wf'J I ~ I ~ i t 2T I 1 I I S(/PFApN I 7CI4CU ~-i1Fl ¢ »_~~ I ~ e .,. '. ... ~r I I 34 1 ., ,~ ' ,~..~ ...:.., `•,o';K . ~~ :,~». Marathon Oii Company • NORTH TRADING 9AY UNIT Cook Inlet, Alaska STRUCTURE MAP TOP HEMLOCK PRODUG~10 INTERN ~ Q 8~~ ~ / w ~' a , ~°' 35 »,. / ( 1 ----------------~- ----F-- --- ~ Jh~UN ' I ~ NORTH TRAD/NG BAY UN/T I s-r° r ----.i.T- - ---T-----------,-- ~ 49GU I i ' 1 ' PROPOSED /N.~Ee~T/ON WELL I ~ ~ t ~ I I i i I I ~s ~ 26 I ~ . ... , ' ""' .tip ~ D 4 „_~e I I ~ '.. I 1 • I I 1 1 1 I 1 I , 1 1 .. I 1 ' I ' 1 I Wo 1 ' 1 G~ y °h 1 T ' ' u ' I . rn O J _~ O C fl. 0 U • - ~- ~~~ ~ l~ s CAL. ^~ t LL8 100 ~---------------~ r RdrHES _11117 `~f' -.ua t ILP~I t00 nv to GR ee~ i _ ILD t09~ t iz2 DT ss.st 400 . ~~ cnr'i r r7 r1 r rsr 1 t ~, ~ i r i __ 60 - 500 70 - 600 801 700 904 - 800 100 •900 110 100 1201 110 1306 120 D. WelFbore Diagram • .] • • 4-1/2"Tubing (35.4-10087.0, OD.4.500, ID:3.958) INTERMEDIATE CASING (35.4-10744.0, OD:9.625) SURFACE CASING (35.4-2132.0, OD:13.375) 4" Camco KBM Mandrel (2489.0-2499.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (4715.0-4725.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (6531.0-6541.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (7909.0-7919.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (8694.0-8704.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (9231.0-9241.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (9798.0-9808.0, OD:4.500, ID:3.958) XO Sleeve (10057.0-10059.0, OD:4.500, ID:3.813) Baker Retrieva D Packer (10087.0-10093.0, OD:8.681, ID:4.500) 4-1 /2" x 3-1 /2" XO (10093.0-10094.0, OD:4.500, ID:2.992) 3-1/2"Tubing (10094.0-10364.0, OD:3.500, ID:2.992} Perf (10126.0-10138 0; Perf (10149.0-1021', 0) Perf (10226.0-10337 O) Portco X Nipple Assembly (10308.0-10309.0, OD:3.500, ID:2.813) Portco X Nipple Assembly (10340.0-10341.0, OD:3.500, ID:2.813) Baker Retrieva D Packer (10341.0-10351.0, OD:8.681, ID:3.500) Perf (10356.0-10476,0) Otis O Nipple (10363.0-10364.0, OD:3.500, ID:2.635) Perf (10484.0-10553.0) Perf (10561.0-10592.0) Cement Plug (10700.0-10770.0, OD:8.641) API 50-133-20184 G-1 G-2 G-3 G-4 H-1 -_.._.... _........__. __. _ H_2 . .. ....... .... ....... H_3 6/20/97 S-4 • N a O U L W SENT BY:Marathon Oil Company 7-21-97 ; 9:28AM Anchorage-~ 907 276 7542;# 9113 July 10, 1987 To: Mike Olson IUTARATHON Oil Company From: Fred Peters Schlumberger Dowell Ref: Potential of Hydraulic Fracturing via Brine Disposal Operations in Well S-4. North Trading Bay Field Dowell's hydraulic fracturing simulation software, FracCADEt'", was used to evaluate the potential of fracturing to surface via disposal operations in well S-4 of North Trading Bay Field. To assume worst-case conditions, stresses were considered to be normal from surface to the bottom of the 13 318" surface casing, i.e. the shallowest possible point of infection into the open hole formations if the surface casing is adequately cemented. Coals and shale above the surface casing were included, since both types of formation are good fracture barriers. Actual stresses used can be seen on the attached plot. Under anticipated injection conditions of 300 barrels of brine per day and 1000 psi surface injection pressure, FracCADE~'" indicates no hydraulic fracture can be established. While adequate downhole pressure may be reached to initiate a fracture, the low injection rate would almost immediately be lost to leakoff through the fracture faces, and the fracture would close with little or no areal growth. Given the long interval of formation open behind production casing and below surface casing, it is impossible to determine with any accuracy how much brine could be injected before any hydraulic fracture created would be sustained and experience even minimal growth. To further evaluate the worst-case scenario, a conventional fracturing procedure was simulated using the normal stresses discussed above. The results are defined on the attached plot. Even at an injection rate nearly 100 times greater than that planned for disposal (ZO BPM, or 28,800 barrels per day), the upward .growth of the fracture is limited to about 300 feet above the surface casing shoe by the first thick shale found there. Under planned injection conditions, even this moderate upward growth would be impo&sible to achieve. Based on these studies, it is confirmed that the planned disposal operations create no haaard of fracturing upward to the surface, assuming the surtace casing shoe is properly cemented. Fred Peters Area Engineer, Alaska SENT BY~Marathon Oil Company ',~„~-21-97 9~28AM Anch ge-~ 907 276 7542;#10/13 ~'raCCADE* STIMULATION PROPOSAL Operator :MARATHON weli : s-~ Field : N.r.s.s. Formation :Surface Csg Shoe V-lell Locai~on County :Kenai State :Alaska Country :U.S.A. Prepared Tor Proposal No, Date Prepared • SBrvit;e Point KAK Rusin®ss Phone 07-1 Q-1 A97 FAX No. Prepared by Phone E-Mail Address peters(~sncharage.dowell.slb.com • Mark of 8chlumberger plecialmer Notice; this Ihfarmation fs pressrMed in good talm, uut ne w++reanty Is given by and Oowep assumes nb llabilily for aAvice or recanmentl~eGOns made aonceming results t0 be oMaMed from the use of any product w sorvlae, the ro9ulla pNen me estimates based on calculations produced by a computer model InClUtling Parlous a~4mptrons on the well, reserwir and treatment 71te rew1~ depend on Input data provided by the Operator and eadmatee as to onknawn data and can be no more aeeuate than iha madad, the ~umpthm9 and ouch Input data. The infarmapen presented la Dowep'e hest estimate of the aetuel rawl4s Neat may be aohisved and should be used for cemperison purppyeY rather than aheolute vawea. The quall~lr of input data, end hence resuns, maybe improved thfOLLph the use aF wrlain tests and procedures whleh Dawep can aviist in selecting. The Operator has supenor knrwletlge o/ the wee, dw reservoir, the fleltl and eOrltllGens aNeotirp them. M the Operator is aware of arry wnditiorre whereby a nelghberlrtg crop er wells might be affected by the treament proposed heroin it ~ die Operator's reeponalbllNy to nahTy the owner or owners of the wee or wells accordlrtgly. Prlcn quoted on aatlmobi only and are good for ~ Aayp from the eau a lases, Aotual ciwuperi }clay vary de~antllnp upon funs, equipinalt, and maurui ulpmatefy roqulrod to perMml Iheee aervioea, Frsbtlom from infringemam Of pearma Of bvwell or elhsro is not to be inferrod. ~~ ~' ~:~~~~ SENT SY:Marathon Oil Company ;~7-21-97 ; 9:28AM ; Anch~ge-~ 907 276 7542;#11/13 dow~ell Section 2; Wellbore Configuration Ctient MARATHON ~~~ ~~ Formation : Sut'faca Csg Shoe District KAK country u.s.A. Deviated Hole ................NO Treat Down_ _ _ _ , , , , , , , , ,Production Casin®/Surtace Casing Annulus Surtace Casin Data OD n Weight ib/ft ID in Depth ft 13.375 54.5 12.615 2132.0 2 Section '1: Zone Bata SENT BY~Marathon Oil Company ?-21-97 9~29AM Anchorage 907 276 7542;#12/13 i ~- Dowell Section 3: propped Fracture Schedule Clrent MARATHON Wel! : s-4 Formation : Surface Csg shoe District : KAK Country U.S.A. The following pumping schedule resulted in a fracture height at the wellbore of approadmately 35p ft. (Nv fracture volume could be created at the anticipated conditions of 300 batr®Is per day meacimium raie.) ' Job Descri tiorl Stage Pump Fluid Name Stage Qel prop, prep. Name Rate Fluid Conc. Type and Mesh Conc. (bbUmin) Volume (Ib/mgal) (ppq) al Ped 20.0 YF120D 20,000 20,p 0.p • n U Flu(d Totals 20 000 al p( YF120D Pro ant Totals N/A :~Y N . __ _ ~ ~~« ~~ 3 SENT SY~Marathon Oil Company 7-21-97 9~29AM ; r • m a ~ aC n ~ M ~f- m r~ ao c> d ~ o 0 o c ca o a r ~ ~~ o ~~ o o .- m •et m ~ 00 o t- ~d~ ~4~0000~~ Q.~o ~~~~~~ ~1 ~~~~ r~ ~J ..,r C U c O a C m ~d v ~ ~ ~~ i~ ~ LL. Q Anchorage 907 276 7542;#13/13 ~ ~ ~ 'x- r N N N Q ~ , ~ ~ ~. o ~ r m ~ LL . • o ~ 0 v .. i-., ~ -. .o ~~ ~ ~ °, ~,~;~ ';3 ~~ ~` .. , 3,r~ r ~~ Q ~. ` _., ~_ ~r as 0 cd SENT SY~Marathon Oll Company ; 7-21-97 9~25AM ; _. ~ i i '11 -1~ l:~pl~1~ 13 5h X13 •1~~~14 snai 1:,Y 1 ~;~ COAL S- i o~~~,e. 1 d~S S~ y~ ~ .//a~~//;,~.1~. /lL~~sJ OGq 6cL Anchorage-~ 907 276 7542;# 6/13 ~t ,.rc,, -.- ~_ ,~~;, e.!va~t ~9~61iFii3a'- ` ~&~~~~ SENT BY~Marathon Oil Company ; 7-21-97 9~26AM Anchorage 907 276 7542;# 7/13 1~~~ r~ 16rti~1 ~~ n ~~ o~i ~ ~~ 1; oa oa~ 28 i OaN , <'S~Of~..2~J SENT BY~Marathon Oil Company ; 7-21-97 9~27AM Anchorage 907 276 7542;# 8/13 t ~~~ O 11(~ n U ha X10 ?.5 ~~ %' ~'I 0 C9a 24 ~1.5(d ~J . ~4l3, ~~"~ ~" w :: ~; A-, ,~, ~~ :~ ... __ d, ~~~•~ ~~~s~~ ,_ Li • CT&E Environmental Services Inc. rriiiiiwiiiriiiiiiiiiiiiios • CT&E Ref./# Client Name Project Name/# Client Sample ID Matrix Ordered By PWSID 970500001 Marathon Oil Co AK Region Routine Oilfield H2O Analysis S-2rd Produced Water Sample Other Liquids Client PO/# Printed Date/Time 02/12/97 15:17 Collected Date/Time 02/03/97 00:00 Received Date/Time 02/05/97 16:30 Technical Director: Stephen C. Ede Released B~y~-~~~_~_ ~ f Sample Remarks: Sample was analyzed undigested for potassium. Parameter Allowable Prep Analysis Results PQL Units Method Limits Date Date Init Potassium 294 50.0 mg/L SW846-7610 02/12/97 02/12/97 BJS Barium 1.59 0.200 mg/L EPA 200.7 02/11/97 EMM Calcium 5.27 2.00 mg/L EPA 200.7 02/11/97 EMM 'ron 5.45 0.500 mg/L EPA 200.7 02/11/97 EMM #,gnesium 3.35 2.00 mg/L EPA 200.7 02/11/97 EMM Sodium 108 5.00 mg/L EPA 200.7 02/11/97 EMM Strontium 1.09 0.300 mg/L EPA 200.7 02/11/97 EMM Aluminum 1.00 U 1.00 mg/L EPA 200.7 02/11/97 EMM Manganese 0.200 U 0.200 mg/L EPA 200.7 02/11/97 EMM pH 8.38 pH units EPA 150.1 02/06/97 EMB Alkalinity as CaC03 124 1.00 mg/L SM18 23206 02/07/97 EMB Bicarbonate Alkalinity 105 1.00 mg/L SM18 23208 02/07/97 EMB Carbonate Alkalinity 19.0 1.00 mg/L SM18 23206 02/07/97 EMB Conductivity 702 0.100 mmhos/cm SM 25106 02/06/97 EMB 14.2 ohm-meters Chloride 240 2.00 mg/L EPA 300.0 02/11/97 SPM Sulfate 2.8 0.200 mg/L EPA 300.0 02/11/97 SPM ~3 ~ Flo #' I~ f4 APPLICATION FOR INJECTION SPARK PLATFORM, WELL S-4 COOK INLET, ALASKA • Submitted by: Marathon Oil Company P.O. Box 196168 Anchorage, Alaska 99519-6168 July 29, 1997 M Marathon MARATHON Oil Company ;July 29, 1997 Mr. David W. Johnston Chairman, AOGCC 3001 Porcupine Dr. Anchorage, Alaska 99501-3192 ~ska Region mestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Re: Request for Class II Disposal Well, North Trading Bay Unit Spark Well S-4 Dear Mr. Johnston: Marathon Oil Company formally requests permission to dispose of nonhazardous oil field exempt wastes by annular injection into Spark Well S-4. Marathon requests permission to inject solids and fluid wastes that have been generated from normal workover and production operations into • S-4. The attached summary provides information required per 20 AAC 25.252, for the State of Alaska's Oil and Gas Conservation Commission (AOGCC). Although Marathon is requesting a permit for injection of nonhazardous exempt wastes, the primary purpose for this proposal is to dispose of produced water from natural gas well S-2rd. S- 2rd was recompleted in November, 1994 and was produced during the 1996-97 winter season. S- 2rd's completion fluid was injected annularly in S-4 under an annual disposal permit which expired March 31, 1997. S-2rd is currently SI awaiting additional gas demands typically associated with the winter months, and approval of this S-4 injection permit. It is estimated that a maximum of 200,000 bbls of fluid will be injected into S-4. Most, if not all, of the fluid would come from the S-2rd completion. This low injection volume is based on several factors: 1) S-2rd produces from a depletion type gas reservoir so influx from a water drive is not expected; 2) S- 2rd sits on the top of the structure; 3) similar sands at Beaver Creek, Kenai Gas Field and Steelhead Platform have all failed when water production increases to a large volume, thus requiring the water producing sand to be squeezed off, and an additional sands perforated; and 4) there are currently no workover/drilling programs planned where large volumes of liquids/solids would be generated. Other disposal options reviewed were deemed either uneconomical and/or contained greater risk to the environment. Those options are discussed below. • 1) Drill a new well or workover an existing completion. This was uneconomical due to A subsidiary of USX Corporation Environmentally aware for the long run. the high costs of reactivating a rig and the actual cost of the drilling/workover program. 2) Inject down the tubing of an existing completion was uneconomical. All Spark oil production and water injection wells were killed with mud. Coiled tubing would likely be required to cleanout the existing completion and the target injection would require reperforating. The integrity of the tubing is also in question due to failed gas lift valves. 3) Overboard the produced water. This is not feasible due to the platform being unmanned and the increased risk of a spill. 4) Store fluids on the platform and transport it onshore via barge. All tanks and oil processing equipment have been mothballed and are located in unheated areas of the platform. Installation of new tanks is uneconomical. There are also increased risks to the environment in the event of loss of heat on the platform resulting in ruptured tanks. Barge transport of produced fluids is also uneconomical and carries a higher spill potential risk. 5) Ship produced water to Granite Point Production Facility via the gas pipeline. S-2rd is often used as a "swing" well and may be SI for extended periods during the winter months. Water in the pipeline would settle to low spots and likely freeze creating an ice plug and loss of gas production until the plug thaws. An MIT has not been performed on Well S-4 due to the low water rate produced from S-2rd. It • is proposed to run a temperature log to verify depth on injection after the water production increases to 200 BPD (annular velocity of ~4.5 ft/min in the 9-5/8" x 13-3/8" annulus). Attached are several documents to provide information as required by 20 AAC 25.252. If you have any questions concerning this request, please contact me at 907-564-6315. Sincerel , Michael R. Olson Production Engineer • SPARK PLATFORM S-4 APPLICATION FOR UNDERGROUND INJECTION Marathon Oil Company requests the Commission issue a disposal injection order authorizing S-4 to be used as a Class II disposal well in accordance with 20 AAC 25.252. S-4 is a shut-in water flood injection well located on the Spark Platform in Cook Inlet, Alaska. 20 AAC 25.252(c)(1) S-4 is located in the L-3 leg on the Spark Platform in Cook Inlet Alaska. Section B contains a plat map showing the location of the proposed injection well (S-4) and all other (shut in) wells which penetrate the injection zone within one-quarter mile of the injection well. The plat includes eight wells: S-1(rd), S-2(rd,d2), S-3, S-4, S-5, S-7(rd), S-8, S-9. 20 AAC 2s.252(c)(2) Marathon Oil Company is sole operator of the Spark Platform and owns 100% of the surface rights within one-quarter mile of the S-4 injection well. 20 AAC 25.252(c)(3) Does not apply. There are no other operators or surface owners within aone-quarter mile radius • of S-4. 20 AAC 25.252(c)(4) Depth of injection will be between 1780' and (350' above the 9-5/8" casing shoe) and 7045' and (calculated top of cement for the 9-5/8" casing string). Injection may occur into 355' of potential zone located between 4590' and 7040' md. Injection may also occur between 1780' and 2132' and in the event the fluids are injected at or above fracture pressures. Based on S-1 open hole logs, the confining layer is a 50' shale located at 1860' and 1910' md. There are also smaller shale and coal intervals located up to 1280'. S-4 and S-1 open hole logs are included in Section C. A fracture model showing a maximum height growth of 250' is included in Section E. 20 AAC 25.252(c)(5) S-4 open hole logs were run from 2132' to 10700' and and are include in Section D. Potential receiving intervals are marked. The S-1 open hole log is also included in Section D to show log information above 2100' md. S-1 lies adjacent to S-4 in this area and is expected to reflect similar log responses of S-4 20 AAC 25.252(c)(6) Section D includes an S-4 wellbore schematic. The 9-5/8" 47# N-80 casing is set to 10744' md; the 13-3/8" 61# J-55 casing is set to 2132' md. Injection is being proposed between the 9-5/8" x 13-3/8" annulus. • 20 AAC 25.252(c)(7) Potential injection fluids include non-hazardous exempt fluids associated with production and workover operations. Such fluids may include, but are not limited to: - Produced water -Expected to consist of 5,000-15,000 ppm Cl-, specific gravity ~ 0.44 psi/ft. - Completion fluids -Expected to mainly consist of 3-6% KCL brine with additives, specific gravity ~ 0.46 psi/ft. The initial average injection rate is estimated at less than 5 BPD of produced fluids. This number may increase over the life of the producing field. For this reason, a maximum daily volume of 300 bbls is requested. ZO AAC 25.252(c)(8) The estimated injection pressure is 700 psig with a maximum injection pressure of 1000 psig. 20 AAC 2s.252(c)(9) Dowell has performed a hydraulic fracturing simulation using their FracCadeT"" Simulator. Stress values for sands, coals and shales were input into the model to determine a maximum height growth of a potential fracture. The model was initially run at 300 bpd and 1000 psig injection • pressure. The results indicated no hydraulic fracture could be initiated due to high leak off of the injected fluids. Another run was made to evaluate a "worst case scenario." At an injection rate of 28,800 bpd, the fracture grew to a maximum height of 250' above the casing shoe (top of fracture at 1900' md) but did not penetrate the thick shale at 1860-1910'. Section E includes the Dowell FracCadeT"" model and graphical results from the "worst case scenario." 20 AAC 25.252(c)(10) There are no fluid samples from the proposed injection zones. Section F includes a produced water analysis from Well S-2rd. 20 AAC 25.252(c)(11) Based on S-1 open hole logs, there are no fresh water zones below 600'. There are no drinking water aquifers above the proposed disposal zone. U.S. Congress has already exempted fresh water aquifers in similar geologic setting beneath the surface at Granite Point, McArthur River, Middle Ground Shoal and Trading Bay fields. All of these fields lie below Cook Inlet as does the well proposed in connection with this notice. 20 AAC 25.252(h) Cement bond logs were not run on the Spark Platform well surface casing strings. The drilling reports were reviewed and based on volumes of cement pumped and/or notes indicating good • cement returns at surface, the surface casing strings in wells S-1 through S-9 should be well ~ ~ bonded to prevent the migration of fluids. There was one complication noted while cementing the S-8 surface casing. Returns were lost approximately 50% through the displacement volume. Based on calculated volumes, good cement should lie between 2046' and 766'. A "top job" was also performed at 200' -good cement returns to surface were noted. • as v 0 Z °~ c ~ ~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Suspend _ Operation Shutdown Re-enter Suspended Well Alter Casing _ Repair Well _ Plugging _ Time EMension _ Stimulate Change Approved Program _ Putl Tubing _ Variance _ Perforate _ Other X 2. Name of Operator 5. Type of Well: s. Datum Elevation (DF or KB) MARATHON OIL COMPANY Development _ 115' KB above MSL feet 3. Address Exploratory _ 7. Unit or Property Name P. O. Box 196168, Anchora e, AK 99519-6168 Stratigraphic North Tradincl Ba Unit 4. Location of Well at Surface Service X 8. Well Number 2615' FSL, 2492' FEL, Sec. 26-10N-13W-SM S-4 At top of Productive Interval 9. Permit Number 3158' FSL, 4202' FEL, Sec. 26-tON-13W-SM At Effective Depth 10. API Number 50- 133-20184 At Total Depth 11. FieldlPool 3220' FSL, 4504' FEL, Sec. 26-10N-13W-SM Hemlock & G-Zone 12. Present Well Condition Summary Total Depth: measured 10770 feet Plugs (measured) true vertical 10237 feet Effective Depth: measured 10700 feet Junk (measured) 10595' - 10700' fill krue vertical 10291 feet Casing Length Size Cemented Measured Oepth True Vertical Depth Structural Conductor Surface 2132' 13 3/8" 1000 sx 2132' 2131' Intermediate 10744' 9 5/8" 1050 sx 10744' 10329' Production Liner Perforation Depth: measured 10126-10138', 10149-10213', 10226'-10337', 10356-10476', 1048410553', 10561-10592' true vertical 9787-979T, 9807-9864', 9875-9973', 9990-10095', 10102-10145', 10169-10199' Tubing (size, grade, and measured depth) 41 /2", 12.6# N-80 Butt tbg ~ 0-10093'; 3-1 /2", 9.2# N-80 Butt tbg ~ 10093-10364' Packers and SSSV (type and measured depth) 1008T Baker D Pkr; 10341' Baker D Pkr 13. Attachments Description Summary of Proposal _ Detailed Operations Program BOP Sketch _ A lication for In'ection X 14. Estimated Date for Commencing Operation 15. Status of Well Classification as: 10/1 /97 16. If Proposal was Verbally Approved Oil _ Gas _ Suspended Name of Approver Date Approved Service Class II Disposal Well 17. I hereby certify that t foregoing is true and correct to the best of my knowledge. ~ Si ned Title Production En leer Date 6/24/97 FOR COMMISSION USE ONLY Conditions of Approval: Notify Commission so representative may witness Approval No. Plug Integrity_ BOP Test Location Clearance_ Mechanical Integrity Test _ Subsequent Form Required 10- A roved b Order of the Commission Commissioner Date rm 10-403 Rev. 08/15188 Submit in Triplicate a R .. ea :~ r. • ~j .. -___.._ _ .. . I I SUPER/OR TEXACO ,. F TExA ~ LI 93 r5-5-RO-1 ~_ -- ¢ ''' ' o r TfilOt TS-S-RO-3 ~avlx 4,._., . r.9T 34 i I TE%ACO ~T95/-/ EL 24 K6 TD 9104 TVD 9104 ~_x 9b 73 L. ~ ( S a o, tD 10770 TVD 10352 «-~~,94 S-3 TD local rw1DIZ6 - 7 6 TS-9 /o TD 10367 12~~ TVD 9962 5-/ RD ~~ ~.."... _9601 ,a r°A TD 11060 -- "---- ------ ` TVD ICI68 lp° I~ V+ x -9fiIP ,i-/ - 3727 yS_/ i TD 10615 ° I ~ - - STD 10529 TVDIOII7 e 2Z/~{ TVD 10071 A I ~t"~` `! ~ i ~ i i .. / ~ - i ARCa. I y SPARK I ,~~ EL IISKB ~' / I . p' °41' ~ e: 1> ~ ~' Y ~ f I Y° ~n ,t , .~ ~ I -__ ~ ~ 113 _. r.; I x'ss4z - - - - s tl, - ` -- - _ - p,ia w~ b l T. 10 N. R.13W. - - - '~ - -i~rt`I~s rrr rte.-~~ irr~~ ~{11~/ UNION T 9 N. R. 13 W. MARATHC ADL-187 ! a'~980d i~S'7-O.R y 9699 TD 12005 TVD 10229 ~ [1je '\ I 1 /-7-RO ~TD 12353 I; / TVD 10063 l•a x S-9 TD 1277 TVD 10066 / J de I RC B £-/ ds ' 57KB / 110950 ,' /D 10950 > s 1 I A.R.Co. ADL-18776 1 9' o ,',e,. ~ O / I O eA' I 9~ t 9. _ I, I I 35 ~ I I I I II i I NORTH TRADING BAYY UN~~~ UN/ON MARATHON ADL-175y6 I I I I I I - I I I I I I C f I l I I 1 l ( 1 I { I I I UN/ON MARATHON IADL-17596 1 I I I I I I I I I I I I I I I I I I I I I I I 1 I I 1 UN/ON MARATHON ADL-17596 REVISIONS Dol. Dftg. Expl. Cnx'd AtlanticRichfieldCompany ~.i . xxzrn eoR Alaska DiSiTiCt ' LEGEND • TD 118 TVD 1 5 970 , ' is° ,' F -sa6lrs-aRa ~° ~ ° ~(-9F Oa ~ / TD 10250 ~ . -°J TVDI0094 I ' S-2 °~ TD.II,500 ;d/ ~, -9565 TVD.10609 I / ~' f ~ ~ S-2RD ~ ~ ^~ ~ ~~ OQ1 • TD II~53 ~ ~ ~; 01 TVD IgILB I I ~°e I I ~~ r I -9742 t~~ TS-S 4680 > ~ TD10405 ldy TVDIOII~' ~, ~-S 7011562 TVDI0256 my I lfio ~ ~ ComPlebe NI Well Pmya.a Wla aeonama PIU9CeE an0 PDanOmeE r/Oll SAOr Q Locolion Gat Water I 1 cute SuaPenUeU Wa11 A.a~MOneo pil we11 NORTH TRADING BAY UNIT 1DING BAY FIELD, NORTHEAST OIL POOL Cook Inlet, Alaska STRUCTURE MAP TOP HEMLOCK PRODUCING INTERVAL INTERPRETED BYE GEOLOGICAL SUB COMMITTEE C.I. = 100 Scale: I" = 500 Dialripulion~ UNIT MEMBERS Data Com: 9-22-69 Flla No. 10-D-5 N CI O J O C d Q V -t= t-- 0_ W • • S.-~I~To V,u..~, ~<- ~,.~. ~ COAL I ~ INCHES -se SP ~ i I I_ f'I i4~j~7 I5s DT ~~,5 MV ~~ GR z~v~~I _ ILD ie~~e~I.~2 RI IOf3~.ss~ c~P:r cic3 4 5 (d , ft} 4 5(~fD- 6 ~1 7 D. W ellbore Diagram • i• 4-1/2" x 3-112" XO (10093.0-10094.0, OD:4.500, ID:2.992) 3-1/2"Tubing (10094.0-10364.0, OD:3.500, ID:2.992) Perf (10126.0-10138.0) Perf (10149.0-10213.0) Perf (10226.0-10337.0) 4-1/2'' Tubing (35.4-10087.0, OD:4.500, ID:3.958) INTERMEDIATE CASING (35.4-10744.0, OD:9.625) SURFACE CASING (35.4-2132.0, OD:13.375) 4" Camco KBM Mandrel (2489.0-2499.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (4715.0-4725.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (6531.0-6541.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (7909.0-7919.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (8694.0-8704.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (9231.0-9241.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (9798.0-9808.0, OD:4.500, ID:3.958) XO Sleeve (10057.0-10059.0, OD:4.500, ID:3.813) Baker Retrieva D Packer (10087.0-10093.0, OD:8.681, ID:4.500) Portco X Nipple Assembly (10308.0-10309.0, OD:3.500, ID:2.813) Portco X Nipple Assembly (10340.0-10341.0, OD:3.500, ID:2.813) Baker Retrieva D Packer (10341.0-10351.0, OD:8.681, ID:3.500) Perf (10356.0-10476.0) i~ Otis O Nipple (10363.0-10364.0, OD:3.500, ID:2.635) Perf (10484.0-10553.0) Perf (10561.0-10592.0) Cement Plug (10700.0-10770.0, OD:8.641) .• Irll API 50-133-20184 7/29/97 N O U L W • July 10, 1997 To: Mike Olson MARATHON Oil Company From: Fred Peters Schlumberger Dowell Ref: Potential of Hydraulic Fracturing via Brine Disposal Operations in Well S-4, North Trading Bay Field Dowell's hydraulic fracturing simulation software, FracCADE~"', was used to evaluate the potential of fracturing to surface via disposal operations in well S-4 of North Trading Bay Field. To assume worst-case conditions, stresses were considered to be normal from surface to the bottom of the 13 3/8" surface casing, i.e. the shallowest possible point of injection into the open hole formations if the surface casing is adequately cemented. Coals and shale above the surface casing were included, since both types of formation are good fracture barriers. Actual stresses used can be seen on the attached plot. • Under anticipated injection conditions of 300 barrels of brine per day and 1000 psi surface injection pressure, FracCADEt"' indicates no hydraulic fracture can be established. While adequate downhole pressure may be reached to initiate a fracture, the low injection rate would almost immediately be lost to leakoff through the fracture faces, and the fracture would close with little or no areal growth. Given the long interval of formation open behind production casing and below surface casing, it is impossible to determine with any accuracy how much brine could be injected before any hydraulic fracture created would be sustained and experience even minimal growth. To further evaluate the worst-case scenario, a conventional fracturing procedure was simulated using the normal stresses discussed above. The results are defined on the attached plot. Even at an injection rate nearly 100 times greater than that planned for disposal (20 BPM, or 28,800 barrels per day), the upward growth of the fracture is limited to about 300 feet above the surface casing shoe by the first thick shale found there. Under planned injection conditions, even this moderate upward growth would be impossible to achieve. Based on these studies, it is confirmed that the planned disposal operations create no hazard of fracturing upward to the surface, assuming the surface casing shoe is properly cemented. • Fred Peters Area Engineer, Alaska • Dowell • FracCADE STIMULATION PROPOSAL Operator :MARATHON Well S-4 Field N.T.B.S. Formation : Surface Csg Shoe Well Location County : Kenai State : Alaska Country : U.S.A. • • Prepared for Proposal No. Date Prepared Mark of Schlumberger Service Point KAK Business Phone 07-10-1997 FAX No. Prepared by Phone E-Mail Address peters@anchorage.dowell.slb.com Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Dowell assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Dowell's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Dowell can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operators responsibility to notify the owner or owners of the well or wells accordingly. Pricec quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Dowell or others is not to be inferred. • •- .- Dowell t Clien : MARATHON Well S-4 Formation Surtace Csg Shoe District KAK Country U.S.A. Section 1: Zone Data • For mation M echan ical Pro perties Zone Name Top MD (ft) Zone Height ft Frac Grad. soft Insitu Stress sl Youngs Modulus sl Poisons Ratio Tough- Hess si.in0.5 CLEAN-SANDSTONE 0.0 500.0 0.700 175 2.000E+06 0.20 1200 CLEAN-SANDSTONE 500.0 500.0 0.700 525 Z.000E+06 0.20 1200 CLEAN-SANDSTONE 1000.0 500.0 0.700 875 2.000E+06 0.20 1200 CLEAN-SANDSTONE 1500.0 360.0 0.700 1176 2.000E+06 0.20 1200 Shale 1860.0 50.0 0.900 1696 4.000E+06 0.35 1400 CLEAN-SANDSTONE 1910.0 60.0 0.700 1358 2.000E+06 0.20 1200 Coal 1970.0 10.0 0.500 987 5.000E+05 0.18 1000 CLEAN-SANDSTONE 1980.0 35.0 0.700 1398 2.000E+06 0.20 1200 Coal 2015.0 7.0 0.500 1009 2.000E+06 0.20 1000 CLEAN-SANDSTONE 2022.0 53.0 0.700 1434 2.000E+06 0.20 1200 Coal 2075.0 10.0 0.500 1040 2.000E+06 0.20 1000 CLEAN-SANDSTONE 2085.0 47.0 0.700 1476 2.000E+06 0.20 1200 In'ection Zone 2132.0 25.0 0.650 1394 2.000E+06 0.20 1200 CLEAN-SANDSTONE 2157.0 200.0 0.650 1467 2.000E+06 0.20 1200 CLEAN-SANDSTONE 2357.0 200.0 0.650 1597 2.000E+06 0.20 1200 CLEAN-SANDSTONE 2557.0 200.0 0.650 1727 2.000E+06 0.20 1200 CLEAN-SANDSTONE 2757.0 200.0 0.650 1857 2.000E+06 0.20 1200 CLEAN-SANDSTONE 2957.0 200.0 0.650 1987 2.000E+06 0.20 1200 Section 2: Wellbore Configuration Deviated Hole NO Treat Down_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Production Casing/Surface Casing Annulus SurFace Casing Data OD in Weight Ib/ft ID in Depth ft 13.375 54.5 12.615 2132.0 • 2 Client: MARATHON Well S-4 ' ~ ' ~ Formation Surface Csg Shoe Dowell District KAK Country U.S.A. • Section 3: Propped Fracture Schedule The following pumping schedule resulted in a fracture height at the wellbore of appro~amately 350 ft. (No fracture volume could be created at the anticipated conditions of 300 barrels per day ma~amium rate.) Job Description Stage Pump Fluid Name Stage Gel Prop. Prop. Name Rate Fluid Conc. Type and Mesh Conc. (bbl/min) Volume (Ib/mgal) (PPA) al Pad 20.0 YF120D 20,000 20.0 0.0 Fluid Totals-~ 20,000 al of YF120D Proppant Totals N/A • 3 • FracCADE ACL Fracture Profile and Proppant Concentration 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 *Mark of Schlumberger 2 MARATHON S-4 Coal/Shale Added 07-10-1997 ~i D owe I I Stress(psi) ACL Width at Wellbore(in; Fracture Half-Length (ft) ti CT&E Environmental Services Inc. • CT&E Ref.# Client Name Project Name/# Client Sample ID Matrix Ordered By PWSID 970500001 Marathon Oil Co AK Region Routine Oilfield H2O Analysis S-2rd Produced Water Sample Other Liquids Client PO# Printed Date/Time 02/12/97 15:17 Collected Date/Time 02/03!97 00:00 Received Date/Time 02/05/97 16:30 Technical Director: Stephen C. Ede Released By- - ~ ,. Sample Remarks: Sample was analyzed undigested for potassium. Allowable Prep Analysis Parameter Results PaL Units Method Limits Date Date Init Potassium 294 50.0 mg/L SN846-7610 02/12/97 02/12/97 BJS Barium 1.59 0.200 mg/L EPA 200.7 02/11/97 EMM Calcium 5.27 2.00 mg/L EPA 200.7 02/11/97 EMM 'ron 5.45 0.500 mg/L EPA 200.7 02/11/97 EMM ~~gnesium 3.35 2.00 mg/L EPA 200.7 02/11/97 EMM Sodium 108 5.00 mg/L EPA 200.7 02/11/97 EMM Strontium 1.09 0.300 mg/L EPA 200.7 02/11/97 EMM Aluminum 1.00 U 1.00 mg/L EPA 200.7 02/11/97 EMM Manganese 0.200 U 0.200 mg/L EPA 200.7 02/11!97 EMM PH 8.38 pH units EPA 150.1 02/06/97 EMB Alkalinity as CaC03 124 1.00 mg/L SM18 23206 02/07/97 EMB Bicarbonate Alkalinity 105 1.00 mg/L SM18 23208 02/07/97 EMB Carbonate Alkalinity 19.0 1.00 mg/L SM18 23206 02/07/97 EMB Conductivity 702 0.100 mmhos/cm SM 25106 02/06/97 EMB 14.2 ohm-meters Chloride 240 2.00 mg/L EPA 300.0 02/11/97 SPM Sulfate 2.8 0.200 mg/L EPA 300.0 02/11/97 SPM • ALO% :.Wz • ~ ~~o~ l3 APPLICATION FOR INJECTION SPARK PLATFORM, WELL S-4 COOK INLET, ALASKA Submitted by: Marathon Oil Company P.O. Box 196168 Anchorage, Alaska 99519-6168 June 24, 1997 ~.E~~1VED ~ aura Zs ~ss~ Alaska 1Jil & Gas Cons. Commission Anchorage ;~~:~ Marathon MARATHON Oil Company June 24, 1997 Mr. David W. Johnston Chairman, AOGCC 3001 Porcupine Dr. Anchorage, Alaska 9950 1-3 1 92 ~ka Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Re: Request for Class II disposal Well North Trading Bav Unit Spark Well S-4 Dear Mr. Johnston: Marathon Oil Company formally requests permission to dispose of nonhazardous oil field exempt wastes by annular injection into Spark Well S-4. Marathon requests permission to inject solids and fluid wastes that have been generated from normal workover and production operations into S-4. The attached summary provides information required per 20 AAC 25.252, for the State of Alaska's Oil and Gas Conservation Commission (AOGCC). The primary purpose for this proposal is to dispose of produced water from natural gas well S- 2rd. S-2rd was recompleted in November, 1994 and was produced during the 1996-97 winter season. Completion fluid was injected annularly in S-4 under an annual disposal permit which expired March 31, 1997. S-2rd is currently SI awaiting additional gas demands typically associated with the winter months, and approval of the S-4 injection permit. An MIT has not been performed on Well S-4 due to the low water rate produced from S-2rd. It is proposed to run a temperature log to verify depth on injection after the water production increases to 200 BPD (annular velocity of -4.5 t}/min in the 9-5/8" x 13-3/8" annulus). Attached are several documents to provide information as required by 20 AAC 25.252. If you have any questions concerning this request, please contact me at 907-564-6315. Sincerely ~~~/ Michael R. Olson Production Engineer A subsidiary of USX Corporation Environmentally aware for the long run. • SPARK PLATFORM S-4 APPLICATION FOR UNDERGROUND INJECTION Marathon Oil Company requests the Commission issue a disposal injection order authorizing S-4 to be used as a Class II disposal well in accordance with 20 AAC 25.252. S-4 is a shut-in water flood injection well located on the Spark Platform in Cook Inlet, Alaska. 20 AAC 25.252(c)(1) S-4 is located in the L-3 leg on the Spark Platform in Cook Inlet Alaska. Section B contains a plat map showing the location of the proposed injection well (S-4) and all other (shut in) wells which penetrate the injection zone within one-quarter mile of the injection well. The plat includes eight wells: S-1(rd), S-2(rd,d2), S-3, S-4, S-5, S-7(rd), S-8, S-9. 20 AAC 25.252(c)(2) Marathon Oil Company is sole operator of the Spark Platform and owns 100% of the surface rights within one-quarter mile of the S-4 injection well. 20 AAC 25.252(c)(3) Does not apply. There are no other operators or surface owners within cone-quarter mile radius of S-4. 20 AAC 25.252(c)(a) Depth of injection will be between 1780' and (350' above the 9-5/8" casing shoe) and 7045' and (calculated top of cement for the 9-5/8" casing string). Injection may occur into 355' of potential zone located between 4590' and 7040' md. Injection may also occur between 1780' and 2132' and in the event the fluids are injected at or above fracture pressures. Based on S-1 open hole logs, the confining layer is between 1500' and 2100' and and is believed to consist of 10-20' coal layers separated by tight siltstone. S-4 and S-1 open hole logs are included in Section C. A fracture model showing a maximum height growth of 350' is included in Section E. 20 AAC 25.252(c)(5) S-4 open hole logs were run from 2132' to 10700' and and are include in Section D. Potential receiving intervals are marked. The S-1 open hole log is also included in Section D to show log information above 2100' md. S-1 lies adjacent to S-4 in this area and is expected to reflect similar log responses of S-4 There were no cement bond logs run in S-4; however, based on daily drilling reports, good cement returns were received at surface. 20 AAC 25.252(c)(6) Section D includes an S-4 wellbore schematic. The 9-5/8" 47# N-80 casing is set to 10744' md; the 13-3/8" 61# J-55 casing is set to 2132' md. Injection is being proposed between the 9-5/8" x 13-3/8" annulus. 20 AAC 25.252(c)(7) Potential injection fluids include non-hazardous exempt fluids associated with production and workover operations. Such fluids may include, but are not limited to: - Produced water -Expected to consist of 5,000-15,000 ppm Cl-, specific gravity ~ 0.44 psi/ft. - Completion fluids -Expected to mainly consist of 3-6% KCL brine with additives, specific gravity ~ 0.46 psi/ft. The initial average injection rate is estimated at less than 5 BPD of produced fluids. This number may increase over the life of the producing field. For this reason, a maximum daily volume of 300 bbls is requested. 20 AAC 2s.252(c)(s) The estimated injection pressure is 700 psig with a maximum injection pressure of 1000 psig. 20 AAC 25.252(c)(9) . Dowell has performed a hydraulic fracturing simulation using their FracCade"`" Simulator. The model was initially run at 100 and 300 bpd at 1000 psig injection pressure. The results indicated no hydraulic fracture could be initiated. Another run was made to evaluate a "worst case scenario." At an injection rate of 28,800 bpd, the fracture grew to a maximum height of 350' above the casing shoe (top of fracture at l 780' md). Section E includes the Dowell FracCadeT"' model and results from the "worst case scenario." 20 AAC 2s.252(c)(><o) There are no fluid samples from the proposed injection zones. Section F includes a produced water analysis from Well S-2rd. 20 AAC 25.252(c)(><><) Based on S-1 open hole logs, there are no fresh water zones below 600'. There are no drinking water aquifers above the proposed disposal zone. The AOGCC has already exempted aquifers in similar geologic setting beneath the surface at Granite Point, McArthur River, Middle Ground Shoal and Trading By fields. All of these field lie below Cook Inlet as does the well proposed in connection with this notice. • U O Z a L s3 A Q STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon _ Suspend _ Operation Shutdown _ Re-enter Suspended Well Alter Casing _ Repair Well _ Plugging _ Time Extension _ Stimulate Change Approved Program _ Pull Tubing _ Variance _ Perforate _ Other X 2. Name of Operator 5. Type of Welt: 6. Datum Elevation (DF or KB) MARATHON OIL COMPANY Oevelopment_ 115' KB above MSL feet 3. Address Exploratory_ 7. Unit or Property Name P. O. Box 196168, Anchors e, AK 99519-6168 Stratigraphic North Tradin Ba Unit 4. Location of Well at Surtace Service X 8. Well Number 2615' FSL, 2492' FEL, Sec. 26-10N-13W-SM S-4 At top of Productive Interval 9. Permit Number 3158' FSL, 4202' FEL, Sec. 26-10N-13W-SM At Effective Depth 111. API Number 50-- 133-20184 At Total Depth 11. Field/Pool 3220' FSL, 4504' FEL, Sec. 26-10N-13W-SM Hemlock & G-Zone 12. Present Well Condition Summary Total Depth: measured 10770 feet Plugs (measured) true vertical 10237 feet Effective Depth: measured 10700 feet Junk (measured) 10595' - 10700' fill true vertical 10291 feet Casing Length Size Cemented Measured Depth True Vertical Depth Structural Conductor Surface 2132' 13 3/8" 1000 sx 2132' 2131' Intermediate 10744' 9 5/8" 1050 sx 10744' 10329' Production Liner Pertoration Depth: measured 10126-10138', 10149-10213', 10226'-1033T, 10356-10476', 10484-10553', 10561-10592' true vertical 9787-9797', 9807-9864', 9875-9973', 9990-10095', 10102-10145', 10169-10199' Tubing (size, grade, and measured depth) 4-1/2", 12.6# N-80 Butttbg ~ 0-10093'; 3-1/2", 9.2# N-80 Butt tbg ~ 10093-10364' Packers and SSSV (type and measured depth) 1008T Baker D Pkr; 10341' Baker D Pkr 13. Attachments Description Summary of Proposal _ Detailed Operations Program _ BOP Sketch A lication for In'ection X 14. Estimated Date for Commencing Operation 15. Status of Well Classification as: 10/1 /97 16. If Proposal was Verbally Approved Oil Gas Suspended Name of Approver Date Approved Service Class II Disposal Well 17. I hereby certify that t foregoing is true and correct to the best of my knowledge. ~ Si ned Title Production En leer Date 6/24197 FOR COMMISSION USE ONLY Conditions of Approval: Notify Commission so representative may witness Approval No. Plug Integrity BOP Test Location Clearance _ _ Mechanical Integrity Test _ Subsequent Form Required 10- A roved b Order of the Commission Commissioner Date 1 ~'m 10.403 Rev. 08/15/88 Submit in Triplicate B. Pla# Map ~ ~ • 1 ~I ~J • "" _ ~ i ~ ~ ~-~ Imo-" ~~ ~ t f4!'t~ ~ 4 ; ~ 1f ~iCJ ~ ~ I i PROPOSED /N„EtTlON WELL i ~ ~ , ` ~ i I ~ 2T ~ ~,-.~ ~ -; .. I ~ .r,. Q _ I s-a 4 n s .~ ~ ' 1 ~~ ~ ~ I '~ ~' ~ i ' ~(/P~77~Wt ' 7FiKu ~r I 3~ I I I I ~u.m •r• -• ~~o~+Ki •~ •~nw I I r~+~ R t}yy _______-_ ~,-n S.va J.G ~~~~. ~~~~ ~~~~~ ~~~ I 1 I•, I ~ I I Q ~«', e'~ ~ I I w ~ I ~ ~" 35 ~ ~ , '°~ I •a I I 1 I ~a.un wn1'n[W i I ' I I ~ ~ ~ I ~ I L__ NORTH TRAD/NG BAY UN/T ___ Marathon Oil Company NORTH TRADING BAY UNIT Cook Inlet, Alasko STRUCTURE MAP TOP F~ALOCK PROpUG7d0 INTERN --+----- U D. Wellbore Diagram • • ~i 4-1 /2"Tubing (35.4-10087.0, 0D.4.500, ID:3.958) INTERMEDIATE CASING (35.4-10744.0, 0D:9 625) I SURFACE CASING (35.4-2132.0, 0D:13.375) I, 4" Camco KBM Mandrel (2489.0-2499.0, 0D:4.500, ID:3.958) 4" Camco KBM Mandrel (4715.0-4725.0, OD:4.500, ID:3.958) 4" Camco KBM Mandrel (6531.0-6541.0, OD:4.500. ID:3.958} I ' 4" Camco KBM Mandrel (7909.0-7919.0, 00:4.500, ID:3.958) i 4" Camco KBM Mandrel (8694.0-8704.0, OD:4.S0Q ID:3.958) 4" Camco KBM Mandrel (9231.0-9241.0, 0D:4.S0Q ID:3.958) '' 4" Camco KBM Mandrel (9798.0-9808.0, OD:4.500, ID:3.958) ~~, XO Sleeve (10057.0-10059.0, OD:4.500, ID:3.813) Baker Retrieva D Packer (10087.0-10093.0, OD:8.681, ID:4.500) 4-1/2" x 3-1 /2" XO (10093.0-10094.0, OD:4.500, ID:2.992) 3-1/2" Tubing (10094.0-10364.0, OD:3.500, ID:2.992) Perf (10126.0-10138.0) Perf (10149.0-10213.0) Perf (10226.0-10337.0) Portco X Nipple Assembly (10308.0-10309.0, 0D:3.500, ID:2.813) Portco X Nipple Assembly (10340.0-10341.0, OD:3.500, ID:2.813) Baker Retrieva D Packer (10341.0-10351.0, OD:8.681, ID:3.500) Perf (10356.0-10476.0) Otis D Nipple (10363.0-10364.0, OD:3.500, ID:2.835) Perf (10484.0-10553.0) Perf (10561.0-10592.0) Cement Plug (10700.0-10770.0, OD:8.641) API 50-133-20184 S-4 G-1 G-2 G-3 G-4 H-1 --- H_2 H3 6/20/97 a O U (~ L w Doweil Scr.lumberger Incorporated 7955E Arapahoe Court. Suite 3000E Englewood. Colorado 80112 . (303) 773-8800 June 17, 1997 To: Mike Olsen MARATHON Oil Company From: Fred Peters Schlumberger Dowell Ref: Potential of Hydraulic Fracturing via Brine Disposal Operations in Well S-4, North Trading Bay Field Dowell's hydraulic fracturing simulation software, FracCADE``", was used to evaluate the potential of fracturing to surface via disposal operations in well S-4 of North Trading Bay Field. To assume worst-case conditions, stresses were considered to be normal from surface to the bottom of the 13 3/8" surface casing, i.e. the shallowest possible point of injection into the open hole formations if the surface casing is adequately cemented. Actual stresses used can be seen on the attached plot. Under anticipated injection conditions of 100 barrels of brine per day and 1000 psi surface injection pressure, FracCADEt"' indicates no hydraulic fracture can be established. While adequate downhole pressure may be reached to initiate a fracture, the low injection rate would almost immediately be lost to leakoff through the fracture faces, and the fracture would close with little or no areal growth. Given the long interval of formation open behind production casing and below surface casing, it is impossible to determine with any accuracy how much brine could be injected before any hydraulic fracture created would be sustained and experience even minimal growth. To further evaluate the worst-case scenario, a conventional fracturing procedure was simulated using the normal stresses discussed above. The results are defined on the attached plot. Even at an injection rate 100 times greater than that planned for disposal (20 BPM, or 28,800 barrels per day), the upward growth of the fracture is limited to about 350 feet above the surface casing shoe. Under planned injection conditions, even this moderate upward growth would be impossible to achieve. Based on these studies, it is confirmed that the planned disposal operations create no hazard of fracturing upward to the surface, assuming the surface casing shoe is properly cemented. .., '~~ Fred Peters Area Engineer,. Alaska • • • • FracCADE .. ,~ ~ ~ , ,. ~,y~ i""e+,,.a:Cs~~+. ~ .;~ YID; x,n~a.~ "' ,.r~..~l3cl1~~ ~.~~.~ai~..i:i-tys:iti.it.~~~4 25 50 75 100 125 150 175 200 225 250 275 300 30 ACL Width at Wellbo~re(in) .~ ~~,~,~~i~i~,_:~ ., •: r- .~ l'6_ i ;~ ~ ;.y < 0.0 ~ 0.0 - 0.4 ^ 0.4 - 0.7 0.7 - 1.1 ® 1.1 - 1.4 ® 1.4-1.8 ~ , 1.8 - 2.2 2.2 - 2.5 2.5 - 2.9 >2.9 Fracture Half-Length (ft) 5 L~ Stress(psi) Dowell • • • FracCADE STIMULATION PROPOSAL Operator :MARATHON Well S-4 Field N.T.B.S. Formation :Surface Csg Shoe Well Location County Kenai State Alaska Country U.S.A. Prepared for Service Point KAK Proposal No. Business Phone Date Prepared 06-15-1997 FAX No. `Mark of Schlumberger Prepared by Phone E-Mail Address peters@anchorage.dowell.slb.com Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Dowell assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Oowell's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Dowell can assist in selecting. The Operator has superior knowledge of the well, the reservoir, [he field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Priees quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon 6me, equipment, and material ultimately required to perform these seMces. Freedom from infringement of patents of Dowell or others is not to be inferred. • .- .- Dowell • Client MARATHON Well S-4 Formation Surtace Csg Shoe District KAK Country U.S.A. Section 1: Zone Data I~ For mation M echan ical Properties Zone Name Top MD (ft) Zone Height ft Frac Grad. si/ft Insitu Stress si Youngs Modulus si Poissons Ratio Tough- Hess si.in0.5 CLEAN-SANDSTONE 0.0 250.0 0.800 100 2.000E+06 0.20 1200 CLEAN-SANDSTONE 250.0 250.0 0.750 281 2.000E+06 0.20 1200 CLEAN-SANDSTONE 500.0 250.0 0.750 469 2.000E+06 0.20 1200 CLEAN-SANDSTONE 750.0 250.0 0.750 656 2.000E+06 0.20 1200 CLEAN-SANDSTONE 1000.0 250.0 0.750 844 2.000E+06 0.20 1200 CLEAN-SANDSTONE 1250.0 250.0 0.750 1031 2.000E+06 0.20 1200 CLEAN-SANDSTONE 1500.0 250.0 0.750 1219 2.000E+06 0.20 1200 CLEAN-SANDSTONE 1750.0 250.0 0.750 1406 2.000E+06 0.20 1200 CLEAN-SANDSTONE 2000.0 132.0 0.779 1610 2.000E+06 0.20 1200 In'ection Zone 2132.0 25.0 0.750 1608 2.000E+06 0.20 1200 Clean SS 2157.0 200.0 0.723 1632 2.000E+06 0.20 1200 Clean SS 2357.0 200.0 0.704 1729 2.000E+06 0.20 1200 Clean SS 2557.0 200.0 0.679 1805 2.000E+06 0.20 1200 Clean SS 2757.0 200.0 0.658 1880 2.000E+06 0.20 1200 Clean SS 2957.0 200.0 0.639 1953 2.000E+06 0.20 1200 Section 2: Wellbore Configuration Deviated Hole NO Treat Down_ _ _ _ _ _ _ _ _ _ ____ _ ___Production Casing/Surface Casing Annulus Surface Casing Data OD in Weight Ib/ft ID in Depth ft 13.375 54.5 12.615 4000.0 • 2 • .- .- Dowell Section 3: Propped Fracture Schedule t Clien : MARATHON Well S-4 Formation Surtace Csg Shoe District KAK Country U.S.A. The following pumping schedule resulted in a fracture height at the wellbore of approximately 350 ft. (No fracture volume could be created at the anticipated conditions of 300 barrels per day maximium rate.) Job Description Stage Pump Fluid Name Stage Gel Prop. Prop. Name Rate Fluid Conc. Type and Mesh Conc. (bbl/min) Volume (Ib/mgal) (PPq) al Pad 20.0 YF120D 20,000 20.0 0.0 Fluid Totals 20,000 al of YF120D Proppant Totals N/A • 3 L1. ~~ CT&E Environmental Services Inc. C7 CT&E Ref.# Client Name Project Name/# Client Sample ID Matrix Ordered By PWSID 970500001 Marathon Oil Co AK Region Routine Oilfield H2O Analysis S-2rd Produced Water Sample Other Liyuids L.J Client PO# Printed Date/Time 02/ 12/97 15:17 Collected Date/Time 02/03/97 00:00 Received Date/Time 02/05/97 16:30 Technical Director: Stephen C. Ede Released Bic-- ~ ~ Sample Remarks: Sample was analyzed undigested for potassium. Parameter Potassium Barium Calcium Tron •,gnesium Sodium Strontium Aluminum Manganese pH Alkalinity as CaC03 Bicarbonate Alkalinity Carbonate Alkalinity Conductivity Chloride Sulfate Allowable Prep Analysis Results PaL Units Method Limits Date Date Init 294 50.0 mg/L SW846-7610 02/12/97 02/12/97 BJS 1.59 0.200 mg/L EPA 200.7 02/11/97 EMM 5.27 2.00 mg/L EPA 200.7 02/11/97 EMM 5.45 0.500 mg/L EPA 200.7 02/11/97 EMM 3.35 2.00 mg/L EPA 200.7 02/11/97 EMM 108 5.00 mg/L EPA 200.7 02/11/97 EMM 1.09 0.300 mg/L EPA 200.7 02/11/97 EMM 1.00 U 1.00 mg/L EPA 200.7 02/11/97 EMM 0.200 U 0.200 mg/L EPA 200.7 02/11/97 EMM 8.38 pH units EPA 150.1 02/06/97 EMB 124 1.00 mg/L SM18 23208 02/07/97 EMB 105 1.00 mg/L SM18 23208 02/07/97 EMB 19.0 1.00 mg/L SM18 23208 02/07/97 EMB 702 0.100 mmhos/cm SM 25106 02/06/97 EMB 14.2 ohm-meters 240 2.00 mg/L EPA 300.0 02/11/97 SPM 2.8 0.200 mg/L EPA 300.0 02/11/97 SPM c: MEMORANDUM gdb . 1,.~ 1,7ew.~ Q~ ~ ~ ~ ~Q~ `rk~ ~ t s ~(( ~~ ~~ ~( ~e ~ ~"' 6~~ State Oii and Gas Conservation Commission To: David Johnston Tuckerman Babcock From: Blair Wondzell of Alaska Date: Ocfober 22, 1996 File: S4wdisp.doc Sub: Annular disposal of work-over and produced fluids, Spark Platform, Trading Bay Field Situation: Marathon Oil Company plans to produce gas from well S-2rd on the Spark Platform, Trading Bay Field, North Trading Bay Unit (NTBU). On a drill stem test, the well produced gas without any water production. However, at this time the tubing probably contains completion fluid; with continued production of gas, minor water production will probably occur (eventually up to 5 bbl. per day is expected). Disposal of this water is the problem. Analysis and Recommendations: The completion fluid and early produced fluids (probably mud filtrate) are clearly drilling/workover fluids and come under the annular disposal regulations 20 AAC 25.080. Long term produced fluid would be formation water and would therefore come under the normal disposal well regulation 20 AAC 25.252. I propose that we approve Marathon's 10-403 proposal to pump completion fluids and mud filtrate into the 9-5/8" by 13-3/8" annulus of NTBU well S-4 until 90 days after productions starts; after that time, fluid disposal would be under the normal disposal well regulation 20 AAC 25.252. Options: Several options for disposing of the completion fluids and produced fluids from NTBU well S-2rd have been considered, they are: 1) disposal to Cook Inlet from the platform is not economic due to the equipment and man power required to treat the small volumes of water expected; 2) there is no enhanced recovery on this platform so it can not be used for that purpose; 3) it can not be pumped down the tubing in an existing well because they have been killed to secure them in a safe condition; 3) It would be uneconomic to store the water on the platform and barge it ashore or to an approved facility; 4) it can not be shipped ashore in a separate line because there is only one line to shore; 5) it can not be sent ashore with the gas for onshore separation and disposal because this would cause the gas line to "water load"; and (6) annular disposal is a viable option. .~ The best option appears to dispose of it down the annulus of Spark well S-4. Thy proi~{ern with thi:,s a~ption is that an annulus :does. not fit the criteria of a normal disposat..welt nor does thy'#luid type match #hatYwhi~li can riormaily be pumped down an annctlus: However, the fluid in the tubing to be unloaded prior to production could be considered a drilling (completion) waste and could properly be pumped down the annulus of well S-4; the water production which is expected in the future. is not a drilling waste: Marathon's proposal: Marathon submitted a 10-403 request to dispose of the wellbore-load fluids and future produced water from NTBU well S-2rd down the annulus of well S-4. The data required by 20 AAC 25.080 for annular disposal has been furnished except data on the confining and receiving zones; data required by 20 AAC 25.252(c) for a disposal well has been submitted as follows: (1) a plat; (2) a list of affected operators; (3) an affidavit is not necessary; (4) (5) Logs of the disposal well previously submitted; (6) construction of the disposal well; (7) (8) estimated average and maximums injection pressure; (9) (10) and (1 1) data on the aquifer exemption. Produced water will be injected directly from the separator to the annulus. A high pressure shutdown switch is installed on the separator liquid discharge line to prevent the injection pressures from exceeding 1000 psig. Mike 01'~en with Marathon told me that some years back they checked to see if the annulus was open, at that time it would take fluid (at low rates) without pumping. Well construction: N, Trading Bay Unit well S-4 was drilled and completed in June, 1969 by cementing 13-3/8" 61 # J-55 surface casing at 2,132' with 1400 sx of "G" cement (had good cement returns to surface) and by cementing 9-5/8" 47# N-80 casing at 10,744' with 1050 sx of "G" cement. The well was completed as a water injection well -our records show that cumulative injection has been 13,322,174 bbls of water. The fast injection was in January of 1981; the well was secured in February, 1992. Aquifers: Prior to our taking over primacy of the Alaska Class II UIC program, EPA exempted the aquifers at Trading Bay Field; the citation 147.102 is as follows: (b) The following aquifers are exempted in accordance with the provisions of 144.7(b) and 146.4 of this chapter for Class II injection activities only: (2)The portion of aquifers beneath Cook Inlet described by a 1 /4 mile area beyond and lying directly below the following oil and gas producing fields: (iv) Trading Bay Field. 1 ~ ~ Btu` ~ot22 of ~' Gin ~~ j' ~ ~. S~G~ ra//~ ~C~ ~'/ c.~/ir/~i / cue ~ p a ~'.~ ` ~~/G~-~.J~l !~ ~'~ G/ -~c.~n~/i~ ~c.w ~ ~Z1~.rc~ ~L2~ ,p.~ ~~~ ~. ~ ~7 ~ ,~-~~~ ~ ~~ 1 a ~. ~ 1 ~.~, 2
