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DIO 012
XHVZE ) ) Image Project Order File Cover Page 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. 1)1:(J () I d..- Order File Identifier Organizing (done) D Two-sided 1111111111111111111 ~can Needed 1111111111111111111 RE~AN Ltféolor Items: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Greyscale Items: D Diskettes, No. D Other, No/Type: D Poor Quality Originals: NOTES: OVERSIZED (Non-Scannable) ~s of various kinds: I ~ o Other:: o Other: BY: Helen <::Maria } 1 Date:q, ~7 OS- /5/ I Date: 1. :;).7 OS- Isl ~ 1111111111111111111 m~ , 1~ rnP BY: Helen .~ Project Proofing Scanning Preparation x 30 = + = TOTAL PAGES (Count does not inc 'ude cover sheet) Date:~. ~7 m~lil/lllllllll BY: Helen ~aria ) Production Scanning Stage 1 Page Count from Scanned File: J 3 0 (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES NO I ~ \IJAj) Helen ~ Date:q.J..7/JS- Isl YfJ If NO in stage 1, page(s) discrepancies were found: YES NO BY: Stage 1 BY: Helen Maria Date: /5/ 111111111111 Scanning is complete at this point unless rescanning is required. ReScanned 1111111111111111111 BY: Helen Maria Date: /5/ Comments about this file: Quality Checked 1111111111111111111 8/24/2004 Orders File Cover Page.doc INDEX DISPOSAL INJECTION ORDER NO. 12 Badami Unit Wells WD-1, WD-2 Badami Unit 1. May 12, 1997 US EPA's determination regarding underground sources drinking water in the Badami and Northstar Field Areas 2. May 1997 BP's Application for DIO Order 3. May 29, 1997 BP Revised surface and bottom hole locations 4. June 18, 1997 BP submits clarification of Order 5. May 30, 1997 Affidavit of Publication 6. July 17, 1997 BP's comments on the draft DIO 7. December 4, 1997 BP's reporting requirements 8. December 16, 1997 AOGCC response to 12/4/97 request 9. ------------------ various documents 10. March 30, 1998 BP's clarification of 3rd party audit finding concerning DIO #12 11. June 15, 1998 AOGCC response to 3/30/98 request 12. April 18, 2003 BP's request for Administrative Approval (DIO 12-001) 13. July 2, 2003 Annual Performance Report 7/l/02-6/30/03 14. June 28, 2004 Annual Performance Report 7/l/03-5/31/04 15. August 2, 2004 AOGCC request for addition information 16. September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells 17. June 30, 2005 Annual Performance Report 6/1/04-5/31/05 18. June 26, 2006 Annual Performance Report 6/1/05-5/31/06 19. June 14, 2007 Annual Performance Report 6/1/06-5/31/07 20. June 30, 2008 Annual Performance Report 6/1/07-5/31/08 21. June 18, 2009 Annual Performance Report 6/1/08-5/31/09 22. May 17, 2010 Quarterly Report 2/1/10-4/30/10 23. June 22, 2010 Annual Performance Report 6/l/09-5/3 1 /10 24. June 24, 2011 Annual Performance Report 6/1/10-5/31/11 25. May 8, 2012 Annual fill tag 26. June 14, 2014 Annual Performance Report 6/l/13-5/31/14 INDEX DISPOSAL INJECTION ORDER NO. 12 ') STATE OF ALASKA OIL ANn GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: The APPLICATION OF BP Exploration (Alaska) Inc. (BPX) for disposal of Class II oil field wastes by underground injection in the Badami Unit wells WD-1 and WD-2. ) Disposal Injection Order No. 12 ) ) ) ) ) Badami Unit Wells WD-1, WD-2 Badami Unit August 5, 1997 IT APPEARING THAT: 1. By correspondence dated May 22, 1997, BPX requested authorization from the Alaska Oil and Gas Conservation Commission (AOGCC) to inject Class II waste fluids into the Badami Unit WD-1 and WD-2 wells. 2. The AOGCC requested additional information June 11, 1997. BPX provided the requested information on June 18, 1997. 3. Notice of opportunity for public hearing was published in the Anchorage Daily News on May 30, 1997. 4. The Commission did not receive a protest or a request for a public hearing. FINDINGS: 1. BPX is the operator of the Badami Unit. There are no other operators within a one- quarter mile radius of the proposed disposal injection project. 2. The State of Alaska is the only surface owner within the Badami Unit. 3. The Badami Unit WD-l disposal well, (WD-l) will be the first well drilled from the unit's single development pad. BPX does not propose to drill any other well within a one-quarter mile radius of the WD-.l"penetration of the disposal injection zones. 4. BPX may drill an additional disposa!'well designated WD-2. BPX does not propose to drill any other well within a one-quarter mile radius of the WD-2 penetration of the disposal injection confining zones. SCANNED JUN 3 0 200~· Disposal Injection Order N' August 5, 1997 J ) Page 2 5. Logs from the Badami No.4 exploratory well may be used to define the disposal and confining zones in the Badami Unit. 6. BPX proposes to conduct disposal operations in the Badami Unit within the U gnu and Sagavanirktok Formations. 7. The Ugnu Formation consists of Eocene aged, predominately coarse grained, fluvial and shallow marine sediments. The interval is present within the Badami No.4 well from 7440'-7720' measured depth (MD). It has an average porosity of 27%, an average permeability of 350 millidarcies and an average net to gross ratio of 50%. 8. The Sagavanirktok Formation includes a basal unit which consists of Eocene to Oligocene aged, predominately fine grained marine sediments. The interval is present within the Badami No.4 well from 5526'-7440'-MD. 9. A regionally extensive, dominantly shale interval within the basal Sagavanirktok Formation is present within the Badami No.4 well from 5526'-5926' MD. This interval contains an aggregate thickness of shale in excess of 250'. 10. The basal Sagavanirktok Formation also contains numerous intervals of laterally extensive sandstones. The log character of these sands is similar to those which have demonstrated a large capacity to accept disposal fluids in other North Slope Fields. 11. Most of the Class II disposal fluids from other North Slope Fields has been confined by similar lithologic and stratigraphic intervals as those present within the U gnu and basal Sagavanirktok Formations underlying the Badami Unit. 12. Overlying the basal Sagavanirktok Formation, between 4450'-5526' MD interval in the Badami No.4 well, is an interval of approximately 65 percent highly porous and permeable, laterally continuous, fluvial to shallow marine sandstones. 13. A predominately mudstone interval exists between 3892'-4450' MD within the Badami No.4 well. It is considered the shallowest potential confining zone in the well. The gross lithologic character of this interval is persistent through the proposed WD-1 and WD-2 vicinity. 14. The 3892'-5526' MD interval in the Badami No.4 is designated the middle member of the Sagavanirktok Formation for the purposes of this order. 15. BPX does not plan to inject fluids within the middle member of the Sagavanirktok Formation unless injection in the Ugnu -basal Sagavanirktok Formation interval is unsuccessful. 16. BPX will run cement quality logs within the surface casing and long string of each well. The Commission will evaluate the logs and cement records to determine the adequacy of the cement to isolate disposal intervals. 5Ci\N~]ED JUN iJ 0 20D·¡~ Disposal Injection Order N,. ) August 5, 1997 ) Page 3 17. Completion plans entai120" conductor set at 110' subsea (SS), 13 3/8" surface casing set at +/-4230' SS and cemented to surface and a long string of 9 5/8" casing set at +/-7500' SS and cemented back into the surface casing. 18. BPX will test tubing and casing integrity according to 20 AAC 25.412 prior to initiation of disposal operations and every two years thereafter. 19. Disposal material will consist of Class II fluids generated from drilling, production, workover and completion operations. The typical disposal stream will consist of seawater, produced and fresh water, drilling mud, drill cuttings, workover fluids, stimulation materials, vessel cleaning material, formation sand, cement and other nominal Class II waste. Constituent volumes will vary depending on drilling, workover, stimulation and maintenance activity. 20. BPX expects to dispose of approximately 12,500 cubic yards (60,100 barrels) of solids during the life of the project. 21. Average disposal rate will be nominally 3000 BPD (,....,2 BPM) during development drilling and at other peak periods. The operator expects to average 300 to 500 BPD over the project life. Maximum instantaneous disposal rate is anticipated to be about 5 BPM. 22. Maximum operating pressure will vary depending on depth and the condition of the formation. Surface pressure is expected to range from 1800-3300 psi when disposing in the Ugnu-basal Sagavanirktok interval, with a corresponding bottom hole pressure (BHP) of 4950-6450 psi. In the mid-Sagavanirktok disposal intervals, estimated surface pressures will be 1300-2800 psi and estimated BHP 3500-4900 psI. 23. BPX expects to maintain injectivity by occasionally stimulating the disposal interval. Stimulation activity will entail pumping solid free fluid to disperse solids, chemical treatments and elevating pressure to breakdown the disposal interval. 24. Fracture propagation within the disposal interval is an integral part of the process of placing waste fluids into the disposal interval. Fractures will be created as the disposal zone begins to plug. Fractures or disaggregation of the clogged pores and rock matrix provide pathways to transport waste fluids to undamaged storage volume within the disposal zone. 25. Estimates of likely vertical growth of fractures in the upper disposal interval is approximately 250', based on rate and volume estimates. 26. Periodic surveillance of disposal operations will ensure waste fluids are contained within the disposal interval. Surveillance methods include temperature surveys, pressure transient tests, step rate tests, thermal decay time logs, disposal rate and pressure monitoring, mechanical integrity tests and tagging effective depth to determine fill buildup. 5CANNED JUN ~i {) 20D4 Disposal Injection Order Nl 2 August 5, 1997 ) Page 4 27. Reservoir surveillance techniques will also be used for tracking near wellbore fluid movement, estimating dimensions of disposal fracture or disposal storage volume and detecting changes in disposal zone characteristics. 28. Evaluation of operation performance and reservoir surveillance will aid in preventing fracturing of the confining zones. 29. BPX calculated formation fluid dissolved solid content from existing well control within the Badami Unit through analysis of geophysical logs calibrated to a single water sample from 4982' MD in the Badami No.5 well. Calculated salinity of formation waters ranged from 18,000 mg/liter to 48,000 mg/liter for formations between 2000' and 7,200' SS. 30. The U.S. Environmental Protection Agency (EP A) determined aquifers with total dissolved solids of less than 10,000 mg/liter are not present within the Badami Unit in either the U gnu or the Sagavanirktok Formations. 31. In correspondence dated May 12, 1997, the EP A notified BPX of its determination that no underground sources of drinking water (USDWs) were present in the Badami Unit. CONCLUSIONS: 1. The requirements of 20 AAC 25.252 have been met. 2. There are no USDW s present underlying the Badami Unit. 3. Waste fluids authorized for disposal under this order in the Badami Unit will consist exclusively of Class II waste generated from drilling, completion, workover and production operations. 4. Permeable strata which reasonably can be expected to contain the total volume of disposal fluids anticipated for this project are present in the Ugnu - basal Sagavanirktok Formation in the Badami Unit. 5. Movement of waste fluids will be confined within appropriate receiving intervals by confining lithology, cement isolation of the wellbore and operating conditions. 6. Periodic fracturing and stimulation will be required to place solids into the disposal interval. Fracture growth can be contained within the disposal interval by controlling the rate and volume of injection 7. Surveillance of disposal material movement, monitoring of operating parameters and demonstration of mechanical integrity every two years will ensure the materials are contained within the disposal interval. Changes in baseline data may be an indication that fluid is escaping beyond the designated confining zone. SCANhW¡i::~ì) JUN C). ,. vb,.(. I () 0 200i.} Disposal Injection Order NI.. ) August 5, 1997 ) Page 5 8. In the event disposal injection within the Ugnu - basal Sagavanirktok Formation interval is unsuccessful, alternative receiving and confining zones exist within the middle member of the Sagavanirktok Formation, which may serve as a secondary disposal zone. 9. Badami Unit disposal wells will be constructed and demonstrate mechanical integrity in accordance with the requirements of20 AAC 25.412. 10. Disposal injection operations in the Badami Unit will not cause waste, jeopardize correlative rights, or impair ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT: Rule 1 Authorized Injection Strata for Disposal. Class II oil field fluids may be injected in the Badami Unit WD-1 and WD-2 wells, in conformance with Alaska Administrative Code Title 20, Chapter 25, for the purpose of disposal into strata which correlates with the U gnu - basal Sagavanirktok Formation intervals between 5926'-7720' MD and the mid-Sagavanirktok Formation between 4450'- 5526' MD in the Badami #4 well. Disposal injection within the mid-Sagavanirktok F ormation must be specifically approved by the Commission, and may be further conditioned by administrative action after review of injection performance in the U gnu- basal Sagavanirktok Formation. Rule 2 Demonstration of Tubing/Casing Annulus Mechanical Integrity The tubing/casing annulus must be tested every two years for mechanical integrity in accordance with 20 AAC 25.412. Rule 3 Well Integrity Failure Whenever disposal rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action and obtain Commission approval to continue inj ection. Rule 4 Surveillance A baseline temperature survey from surface to total depth, initial step rate test to pressures equal or exceeding maximum injection pressure and pressure falloff are required prior to initiation of disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the Commission. Operating parameters including disposal rate, disposal pressure, annuli pressures and volume of solids pumped must be monitored and reported according to requirements of 20 AAC 25.432. SCANNED ~JUN 3 0 200.:' Disposal Injection Order NL August 5, 1997 ) \ Page 6 An annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth if any and updates of operational plans. Report submission will be on or about July 1. Rule 5 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. DONE at Anchorage, Alaska and dated August 5,1997. ~- -........... Robert N. Christenson, P.E., Commissioner 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 tile 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). ~~(,ìiN~JE-~> ì·· '. -,- <,JLJN 3 () 200<1 \"IT ¡,Ç . .1 u1 } ffiì [~®;1 ® ~ ryl® ~ J wL~cQ)"J~W AI/ASIiA OIL AlVD GAS CONSERVATION COMMISSION ') / / / FRANK H. MURKOWSKI, GOVERNOR 333 W. pH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. DIO 12.001 Ms. Janet D. Platt Environmental Manager BP Exploration (Alaska) Inc. PO Box 196612 Anchorage AK 99519-6612 Re: Request for amendment of Disposal Injection Order No. 12 Dear Ms. Platt: By letter dated April 18, 2003, BP Exploration (Alaska) Inc. requested amendment of Disposal Injection Order No. 12, Rule 4. The subject Order is so amended to read: Rule 4 Surveillance A baseline temperature survey from surface to total depth, initial step rate test to pressures equal or exceeding maximum injection pressure, and pressure falloff are required prior to initiation of disposal injection. Regular fill depth tags are required annually while drilling operations are on- going, once every two years after drilling operations have concluded, or as warranted following consultation with the Commission. Operating parameters including disposal rate, disposal pres- sure, annuli pressures, and volume of solids pumped must be monitored and reported according to requirements of20 AAC 25.432. An annual performance report will be required including rate and pressure performance, surveil- lance logging, fill depth if determined, survey results, volumetric analysis of disposal storage volume, estimate of fracture growth if any, and updates of operational plans. Report submission will be on or about July 1. DONE at Anchorage, Alaska and dated April 21, 2003. ~.. O!~\ /Î.,/ . ~.:t , fH;{;~'f "-. Sarah H.R~lin V Chair \ BY ORDER OF THE COMMISSION .- L~ ,el.-.-<~t"~'7ri1:..0IL - ~ Randy RUedriCh(v~~. T I ~ð Commissioner :/ ~'j."'t'-..... \f.·t\\ \ I / I I~_ .': ¡,7 '--.."--- fi :';\£ · '$ .I ~ '-. ....:.J·i:\ . ~~:"-- ~ ~ 1 ;: '¡ /::'::/~_:;"I, . ì'~'~""i~\;-~! , ;:'?:(~";'\"~~~i~ . ...... ."1A-0f! . . ~:. ..:~¡ ' (..:.;'" . <,;;' .....è.:>". '. :.··.:.Æ~.h/ : ..',;..':\~";' SÇ¡\NNEo-'; )11'1\1 <9,1 f¡ ....lrì[·J·, "'"' , ~ "...... .....' r,· '.c· J ~ ':) ..j L~J ,-}- , . #26 • • SAVANT Mail To: Physical Address: P.O. Box 112212 4720 Business Park Blvd., Suite G-40 A L A S K A Anchorage, AK 99511-2212 Anchorage, AK 99503 June 13, 2014 Ms. Sharon Morgan Mr. Edward Kowalski Program Manager Director, Office of Compliance and Enforcement Alaska Department of Environmental Conservation U.S. Environmental Protection Agency (EPA) PO Box 111800 1200 Sixth Avenue Suite 900 Juneau, Alaska 99801 Seattle, Washington 98101 Mr. Jim Regg Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501-3192 RE: Class I Injection Well B1-01 Disposal Injection Order No. 12 EPA UIC Permit Number AK11001-A ADEC Authorization No. 201ODB0001-0010 Annual Performance Report Ladies and Gentlemen: Mr. Thor Cutler, LEG, LHG, LG, CPG EPA (Mailstop: OCE-127) (12th floor) 1200 Sixth Avenue Seattle, Washington 98101 Pri) 11- 7 iY 74 D' C 1 Z Savant Alaska LLC respectfully submits the following annual report (June 1, 2013 through May 31, 2014) for the Badami Class I Well, 131-01. This submittal meets the reporting requirements in: • AOGCC Rule 4 of Disposal Injection Order 12.001 • EPA Underground Injection Control (UIC) Permit No. AK-1I001-A Part II E.2 • ADEC Authorization No. 201ODB0001-0010 The report provides information on annual surveillance logging and survey results, injection rates and performance data, fill depth, volumetric results of the disposal storage volume, and an update on operations. If you have questions, please call me at (907) 433-7808. Sincerely Rob Crotty HSE Manager Savant Alaska, LLC Attachments cc: Gerry Brown/ADEC-DW Jason Selitsch, PE / Denali Environmental Marc Bentley/ADEC-DW 1 • • SAVANT ALASKA B1-01 ANNUAL SURVEILLANCE and SURVEY RESULTS Annual Inspection and well integrity testing was conducted on 4 and 5 April 2014. Results were presented in the Badami B1-01 - 2014 Annual Surveillance Interpretive Report that was submitted to the EPA and AOGCC on 21 May 2014. In summary: 1. A successful MIT x IA test to 3,500 psi demonstrated mechanical integrity of the casing; tubing and packer run on 4 April 2014. 2. A Multi -finger caliper (MFC) run on 4 April 2014 showed the 2Y8' Velocity String from 8383 ft. MD to its top at 8474' MD and 4%2" tubing from 8075' MD to surface are in good condition. (mostly showing less than 20% penetration damage characterized by light to moderate pitting). Results showed the tubing to be generally 3. in a condition similar to that described by the MFC run in 2012, with most joints exhibiting less than 20% penetration damage or metal loss with that damage largely dominated by light to moderate pitting. 4. A Spectra Flow tool run on 5 April 2014 to check water flow behind the 9 5/8" casing showed no indication of water movement using impulse tests at 8340, 8325, 8300 and 8275 ft. MD, while injecting the well with water at a rate of 2 BPM.. 5. Fill was tagged at 8,391 feet measured depth below gravel pad surface As such, the B1-01 completion condition meets all requirements for continued use for Class 1 Underground Injection Cell well under Permit AK-11001-A. WASTER MANIFESTED and TOTAL INJECTED VOLUMES B1-01 Waste Manifested Volumes and Total Injected Volume: FROM 1 JUNE 2013 through 31 May 2014 Manifested Volumes Manifested (received) a total volume of 23,440 bbls of different waste streams RCRA-exempt waste stream accounted for 19,947 bbls or 85 % of total manifested (received) Domestic Wastewater accounted for 17,046 bbls or 15 % of exem t waste stream Non-exempt waste stream accounted for 3,493 bbls or 15 % of total manifested (received) Total Injected Volume Total Injected Volume 1 24,543 bbls from HoneyweIITM Chart Recorder Note: The difference between the "manifested (received) volume" and the "injected volume" is Savant does not manifest fresh water injected for well maintenance (flushing solids from well and freeze protection). B1-01 Waste Manifested Volumes and Total Injected Volume: October 1997 through May 2014 Manifested Volumes Manifested (received) a total volume of 960,460 bbls of different waste streams RCRA-exempt waste stream accounted for 589,624 bbls or 61 % of total manifested (received) Domestic Wastewater accounted for 290,236 bbls or 49 % of exem t waste stream Non-exempt waste stream accounted for 370,836 bbls or 39 % of total manifested (received) Total Injected Volume Total Injected Volume 1 1,064,175 bbis I from HoneyweIITM Chart Recorder Note: The difference between the "manifested (received) volume" and the "injected volume" is Savant does not manifest fresh water injected for well maintenance (flushing solids from well and freeze protection). SAVANT ALASKA DISPOSAL STORAGE VOLUME and ESTIMA E of FRACTURE GROWTH Vertical Fracture Extension. As part of B1-01 s irveillance in 2014, a Halliburton Spectra Flow Log was run on 5 April 2014 as a water flow log tool to ched for up -flow behind the 9%" casing. Savant also reviewed surveillance flow log reports prepared by Sava t in 2012, and BPXA in 2004, 2008 and 2010. No upward water movement was detected in water flow logs. This indicates water stayed within the permitted injection interval and there was no apparent vertical fracture extension. The next water flow log is scheduled for 2016. Horizontal Fracture Extension. Plotted volum s injected and estimated radii suggest radius assume uniform radial injection. To that end, Savant revieweq past BPXA and Savant annual performance reports for 2004, 2007, 2010, 2011, 2012 and 2013. Report data is summarized below, along with 5 months data from 2014. Disposal Storage Volume and Estimated Fracture Growth Running Total (1 June - 31 May) 2014 2013 2012 2011 2010 2007 2004 Barrels Injected 1,064,175 1052,061 1,023,378 973,551 940,474 827,511 776,800 Cubic ft. 5,974,276 906,270 5,745,244 5,465,515 5,279,821 4,645,647 4,360,955 Porosity 0.27 0.27 0.27 0.27 0.27 0.27 0.27 Estimated Total Volume (mmcf) 22.13 21.88 21.28 20.24 19.55 17.21 16.2 Estimated Perforation Interval (If) 21 21 21 22 22 22 22 Volume cf/If 1,053,665 1,041,670 1,013,271 920,120 888,859 782,095 734,168 Estimate Radius /If 335,348 330,901 322,492 292,845 282,896 248,916 233,662 Estimated Radius (ft.) 579 576 568 541 532 499 483 Change in bbls (Compared to 2014) 12,114 28,683 78,510 111,587 222,550 275,261 Est. Radius Change in ft. (Compared to 2014) 3 8 35 44 77 92 Notes: 1. Barrels to Cubic Feet conversion = 5.614 2. 2013 and 2014 Radii have been corrected to account for B1-01 borehole (0.82 ft.) 3. Assumes a homogeneous formation with consistent porosity of 0.27 Information presented on estimated radius versus estimated total volume injected also is plotted as follows. 23.00 __-_-- _-- _ _ ..___ __. __._� _ -_ � i i -3 2 )13 - -- ------ ----- 4 ----- - - - - --- I 21.00 - -- '---------- -- - ---- - +--------- s 011 2012�--- i i- --- -- -- -- - --- -- --- _ _ _.._. _ -- 1--------- +' 18.00 -----}--------- .------- i ---- - � --- ----� _._., u , ; 17.00 - 007 ---------- --------------------- -------�--------�---------- {-------- --- - -- { E I 16.00 --- --- '------- ------------------------- ------ ------ ----- -- ---- -- ----- 2004 i - 15 00------- '--------------------------------------- ------------------�------- -- ------ J 102 - ---- --- --+--------- 14.00 - - --- - -- --- --- ---- ------ - -- - --- { I 13.00 - - ----Disp)sal- ge Vo! � -and matedLFracW -Growth' - - - #---------- i � I 12.00 480 490 500 510 520 530 540 550 560 570 580 590 Radius (ft) 3 SAVANT 0 ALASKA Based on a 31 May 2014 cumulative volume of 1,064,175 barrels injected into the well since October 1997, it is estimated injected fluids now occupy a total volume of 22.13 million cubic feet within the disposal interval. This is equivalent to a radius of 579 feet aroundlthe wellbore at the perforated interval. UPDATE of OPERATIONAL PLANS The Badami field was restarted on November 5, 2010 after a three year warm shutdown. Badami B-01 has since been used primarily for produced water and camp waste disposal. Savant proposes to continue using 131- 01 for the same. No drilling cuttings will be disposed. Since taking over operations, Savant replaced the original Ball Mill facility fuel -fired glycol boiler with an electric boiler and repaired a storage tank. Sa ant also purchased and installed a heat exchanger. The new boiler, repaired storage tank and heat exchanger are scheduled to be connected in August to a downhole curtain string in the B1-01 outer annulus that r ns to 2,088 feet MD. This will help provide freeze protection to the lines leading to the well and downhole casings within permafrost. UPDATE of RECORDKEEPING PROCEDURES The B1-01 Class I Injection Well Permit (AK-11601-A) states in Part 1E 9.b that Savant, as "...permittee, shall retain records concerning the nature and composition of all injected fluids until three years after the completion of plugging and abandonment..." These records include North Slope Manifests, C�uarterly Injection Reports and Annual Reports. Relative to such records generated by past owner and operator] BP Exploration (Alaska), Inc. (BPXA), Savant took the following steps in early 2014 to meet this requirement. 1. Collected all hard copies of these records found at the Badami Central Production Facility (BAD-CPF), and especially the BAD-CPF Ball Mill. s 2. Requested hard copies and electronics copies of the same records from BPXA since injection started in 1997. 3. Ensured all similar records generated by Savant were available and accounted. As Part 1E 9.b does not require original record (hard copies) to be retained, Savant then proposed to manage such records as follows. 1. Scan all BPXA records in our possession and retain them electronically thereafter. Destroy the original hard copies 2. Retain hard copies of Savant records) for 1 year, and then scan them and retain them electronically thereafter. 3. Destroy the original hard copies. Savant gained approval from EPA on 29 April scanning old records. 14 to institute the new recordkeeping procedures and is now 4 • 1:1 m g00000000�noo" v a v N N a ry ry N ry N rn N a O m m E`o a N N N �-I rl N ey fi rl 'i rl 09 a a m v 0 1117 m M m M M N N .n v a w m A 0p M Ott M .V N 1p o0 a� '-I N n a A p � M a` O F � d E N a E " O o �noo�n0000�n�n�oM o o 0 o o o 0 o o M v A � N � o 0 i � � M a •- CL c u N of o as aN o.�vmoo O m m m mmrvof C C O O pdp A . N '-1 . . '-I ci . . .-I rl . . �"� �"� c-I c-I . . N N ei ALI v a r C cO R p A ei Ql y O LEM d I g M N N N N m M m m m m m N a a � a 0 u C V1 rl ti Ol o n M n N ry '-I n O V N V m O n i0 n V1 l0 v n O N A O C 00 V1 C M d N -1 e�i 'N-I co ei 0 m Q� O N N � N ry N Ory N ON C a' 0" Z° o " a N 17 425 • • SA'►ANT Mall to: Physical location: P 0. Box 112212 4720 Business Pdrk Blvd. ALASKA Anchorage, Alaska Suite G 40 99511 -2212 Anchorage, AK 99503 Phone 907 -868 -1258 Fax 907 -868- 1455 May 8, 2012 Mr. Guy Schwartz RECEIVES I ' Alaska Oil & Gas Conservation Commission 333 West 7 Avenue MAY 0 9 2012 k, Anchorage, Alaska 99501 -3192 AOGCC Badami Class 1 Injection Well B1 -01 AC GI'C Disposal Injection Order No. 12 UIC Permit AK 11001 -A Annual Fill Tag Dear Mr. Schwartz: In accordance with the annual fill tag requirement called out in Rule 4 of Disposal Injection Order 12.001. Savant Alaska LLC herewith is submitting the Halliburton Well Service Report (WSR) for a B1 -01 fill tag conducted on 25 April 2012 during annual EPA mandated surveillance work on the well. That tag reported top of fill at 8391' MD and was witnessed by EPA Inspector Talib Syed. Note that since the completion of B -38 in April 2010, B1 -01 has primarily been used for the disposal of camp waste and produced water. We have no plans to use the well for drill cuttings disposal any time in the immediate future. Please contact me if you have any questions. Sincerely, Savant Alaska LLC Erik • e ad, Drilling & Wells Manager • • • • t r`B X42 +� B1 -01 EPA WOMMEPANOWER NICHOLAS SANDERS Initial T /I /O: 11600/600/0 Final T /I /O: 11600/600/0 TIME Event 12:30 PJSM with all parties involved 13:00 Start rig up of MIT caliper tool, start MIT IA 14:30 MIT IA finished. Stab tools on well and pressure test to 3200 psi 16:15 Install fusable cap open swab RIH with tools 3 5' WB, TTTCU, CENT, 24 arm MIT Caliper, centralizer. 17:30 Vtiaitarairr open caliper and log up at 50 FPM 17 :45 Finish repeat pass. Close caliper and RIH 18:00 Open caliper and log to surface at 50 FPM 20:45 Close caliper, close swab, bleed down lubricator, RD tools, clean up tools, lay down lubricator for night 23:00 Job continues in morning 26- Apr -12 T /I /O: 1600/600/0 TREE = 4 - 1/16" / 5000 PSI ! CM/ • NOTES: INJECTION TEE ON TOP OF WELLHEAD = 13-5/8" / 5000 PSI / FMC B1 -01 111CYVALVE w/2.3" - 2.35" ID AS OF 07/19/06 ACTUATOR , KB. ELEV = 54.T BF. ELEV = 19.4' KOP = Max Angle = 24 @ 5016 - - 2088' I—17" CURTAIN STRING HEATER, 29 #, L -80 BTC Datum MD = Datum TV D = , 1 2112' H 4 -1 /2" HES X NIP, ID = 3.813" 1 113 -3/8" CSG, 68 #, L -80 BTC, ID = 12.415" `--' 4919' I • IL z 0 7941' 1-1 9-5/8" X 4-1/2" HES BWD PKR, ID = 3.850" 1 Minimum ID = 2.205" @ 8379' 2 -7/8" VELOCITY STRING XN NIPPLE 7954' 1-1 HES SEAL ASSY, ID = 5.00 "' M+ ` Z ■ Filiii 5' - I 9 -5/8" X 4 -1/2" HES BWD PKR, ID = 3.850" I ' 8065' 1-14-1/2" X NIP, ID = 3.813" I ' I 8085' I -14 -1/2" XN NIP, ID = 3.725" I 4 -1/2" TBG, 12.6 #, L -80 NSCT, I 8096' I ( 8096' H 4 -1/2" WLEG, ID= 3.958" I .0152 bpf, ID = 3.958" ' 8096' 1-1 ELMD TT LOGGED ON .. ? ?1 ? ?! ?2 1 1 F11376'1-1 2-7/8" XN NIP, ID = 2.205" I 2 -7/8" VELOCITY STRING, 6.4 #, ID = 2.441 " 8 NOTE: 2.332 ID ON CONNECTORS 8383' -i 2 -7/8" WLEG, ID = 2.50" I PERFORATION SUMMARY REF LOG: '?' '7 7440 -' ?k4o ANGLE AT TOP PERF: 11 @ 10600' �S ______----. i Lq0 Note: Refer to Production DB for historical pert data s / SIZE SPF INTERVAL (MD) Opn /Sqz DATE / �� 7980 - 7990 SQZ ? ?? ° /// 8390 - 8420 0 08/19/98 / �� 7 PBTD1-1 8612' vAlrAvAvAvgrAvAvAvAveg 19 -5/8" CSG, 47 #, N-80 BTC, ID = 8.681" H 8703' I 6'3262626 DATE REV BY COMMENTS DATE REV BY COMMENTS BADAMI ? ? ?? ORIGINAL COMPLETION WELL: B1 - 01 04/09/99 JTP UPDATE INFORMATION j PERMIT No: 1971570 04/06/01 JDE CORRECTION API No: 50- 029 - 22799 -00 07/19/06 JRP /PJC SAFETY NOTE SEC T N R E 08/30/06 WRR/TLH FORMAT CORRECTIONS BP Exploration (Alaska) • Page 1 of 2 • Schwartz, Guy L (DOA) From: Erik Opstad [Erik.Opstad @savantalaska.com] Sent: Thursday, May 10, 2012 11:52 AM To: Schwartz, Guy L (DOA) Subject: RE: B1 -01 Annual Fill Tag Guy, The BP reports I have record ELMD (corrected) tags of: 8393' ELMD (corrected to MD: 8366' actual a -line tag + 27' correction = 8393' MD equivalent) in 2009; 8385' ELMD (corrected to MD: 8354' actual a -line tag + 31' correction = 8385' MD equivalent) in 2010; t No tag run made in 2011; S)SC13 ' -46 s'385 z_ (e and then Savant tagged; F3 ` ►� 8391' ELMD (corrected) in 2012. So the top of fill is just below the top of the perforations, where it has been for years! Erik From: Schwartz, Guy L (DOA) [mailto:guy.schwartz @alaska.gov] Sent: Thursday, May 10, 2012 10:07 AM To: Erik Opstad Subject: RE: B1 -01 Annual Fill Tag So what is the actual tag then? Top perf is listed at 8390' on the schematic and the tag was 8391' on the report. SL usually correlates to the Eline measured Tubing tail depth... Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Erik Opstad [mailto:Erik.Opstad @savantalaska.com] Sent: Thursday, May 10, 2012 9:19 AM To: Schwartz, Guy L (DOA) Subject: RE: B1 -01 Annual Fill Tag No the perforations are not covered! From: Schwartz, Guy L (DOA) [mailto:guy.schwartz @alaska.gov] Sent: Thursday, May 10, 2012 9:13 AM To: Erik Opstad Subject: RE: B1 -01 Annual Fill Tag 5/10/2012 • Page 2 of 2 Eric, Is this tag depth correlated to OH log or Slickline? ( i.e. are perfs covered by fill ?) If this tag is SL measurement there would be another 25 ft or of depth since they Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Erik Opstad f mailto :Erik.Opstad ©savantalaska.coml Sent: Tuesday, May 08, 2012 3:51 PM To: Schwartz, Guy L (DOA) Subject: B1 -01 Annual Fill Tag Guy, Attached is a quick annual fill tag report for B1 -01. Nothing changed from the previous years. Erik 5/10/2012 d` N IF by • • BP Exploration (Alaska) Inc. 900 East Benson Boulevard P. 0. Box 196612 Anchorage, Alaska 99519 -6612 (907) 561 -5111 June 24, 2011 Mr. Jim Regg Alaska Oil and Gas Conservation Commission ~ 'E ; 333 West 7th Avenue x111 Anchorage, Alaska 99501 -3192 JON `' 4 �" E "nm%sSI0tl Mr. Edward Kowalski O Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency (EPA) 1200 Sixth Avenue Seattle, WA 98101 RE: Badami Class 1 Injection Well B1 -01 CC\71 S Disposal Injection Order No. 12 UIC Permit AK11001 -A Annual Performance Report Dear Mr. Regg & Mr. Kowalski: BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following annual performance report for the Badami Class I well, B1 -01. This submittal meets the AOGCC reporting requirement in Rule 4 of Disposal Injection Order 12.001. In addition, this submittal meets the EPA reporting requirement in Underground Injection Control (UIC) Permit No. AK- 11001 -A Part 11 E.2. Please note the reporting period for this annual report is June 1, 2010 through May 31, 2011. h 9 Y 1 Attached is monthly injection rate and performance data. No surveillance logs are planned during the 2011 Badami barging season. However, the annual mechanical integrity test of the inner annulus (MIT -IA) has been schedule to take place in August 2011. AOGCC and EPA representatives will be invited to witness this test. The mechanical integrity of B1 -01 was last demonstrated on September 5, 2010 with a passing MIT -IA. Prior to this test another successful MIT -IA was conducted nine days earlier on August 27, 2010 and was witnessed on site by EPA representative Thor Cutler. 2011 AOGCC B1 -01 AnnLerformance Report • June 24, 2011 Page 2 Based on a cumulative injection volume of 973,551 barrels into the well since October 1997, it is estimated that the fluids occupy a total volume of 20.25 million cubic feet within the disposal interval. This is equivalent to a radius of 541 feet around the wellbore. As an update of operational plans for B1 -01, the Badami field was restarted on November 5, 2010 after a three year warm shutdown. Since the field restart B1 -01 has been used primarily for produced water and camp waste disposal. No drilling cuttings disposal has been required since the completion of new well B1 -38 in April 2010. If you have any questions, please contact Mark Sauve at (907) 564 -4660 or Alison Cooke at (907) 564 -4838. Sincerely, Bruce Price Area Operations Manager North Attachment cc: Dan Seamount, AOGCC Thor Cutler, EPA 2011 AOGCC B1 -01 Annulerformance Report • June 24, 2011 Page 3 Copies to: Mr. Thor Cutler, EPA Region 10 EPA (OW -137) 1200 6th Ave. Seattle, WA 98101 Mr. Talib Syed, EPA Consultant c/o TSA, Inc. 6551 South Revere Pkwy, Suite 215 Centennial, CO 80111 Mr. Shawn Stokes Alaska Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 File 608.01 Bcc: Mark Sauve End /Bad Area Manager Badami, Operations Lead Tech Greg Vihil - Savant Resources Environmental Advisor East Alison Cooke Compliance Matrix Administrator / Compliance Matrix ID #7293 • • • 11111k• 4P C is Badami Waste Manifested Volumes and Injection Well Report. From the dates of October 1997 through May 31st 2011 We have Manifested (Received) a total of 880,775 bbls. of different waste streams Exempt waste stream accounted for 294,277 bbls or 33.41% of total bbls manifested (Received). Non Exempt waste stream accounted for 586,459 bbls or 66.58% of total bbls manifested (Received). Treated Effluent accounted for 247,857 bbls or 42.26% of the "Non Exempt" fluids We Have "Injected" a total of 973,551 bbls Total from the Chart recorder Note: The difference between the "received volume" and the "injected volume" is that we do not manifest fresh water used for the maintenance purpose of flushing solids from the well and for injections to keep flow lines from freezing. Badami B1 -01 Monthly Injection 6/1/2010 - 5/31/2011 Report Date Report Date Days BBLS Avg Inj Avg Wellhead Max Wellhead Avg Casing Max Casing Begin End Operating Injected Rate Pressure Pressure Pressure Pressure 6/1/2010 6/30/2010 20 9,551 478 505 2,192 0 0 7/1/2010 7/31/2010 14 4,194 300 408 2,931 0 0 8/1/2010 8/31/2010 16 2,653 166 295 2,452 0 0 9/1/2010 9/30/2010 16 2,878 180 727 2,220 0 0 10/1/2010 10/31/2010 12 1,419 118 943 2,317 0 0 11/1/2010 11/30/2010 12 1,218 102 709 1,999 0 0 12/1/2010 12/31/2010 13 1,354 104 763 2,361 0 0 • 1/1/2011 1/31/2011 12 1,416 118 829 2,927 0 0 2/1/2011 2/28/2011 9 1,212 135 828 2,890 0 0 3/1/2011 3/31/2011 13 1,954 150 891 2,019 0 0 4/1/2011 4/30/2011 12 1,439 120 981 1,800 0 0 5/1/2011 5/31/2011 14 3,789 271 647 1,786 0 0 Total 33,077 • 131.01 Annulus pressure Data rn • o 2 -♦ Tubing Pressure (psi) d - IA Pressure (psi) 0 p -&-OA Pressure (psi) O ° OOA Pressure (psi) � O " I -0-000A Pressure (psi) O J • •On- Line/Off -Line F' f ti • o l.t I t hi l t ', } ti �� :'' ' �' t 1 .1 if 4 { y,•, -P O I .AS• • 11� O • • 5/312010 7!312010 91302010 11/302010 1/312011 38312011 5/312011 -~23 by ~ ~~~ ~~~F~~~~ JUN ~ ~ ~(J10 June 22, 2010 Alaska tl~l ~ Cap C~~ Commission r'+n~hnr~r#}a Mr. Jim Regg Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501-3192 Mr. Edward Kowalski Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency (EPA) 1200 Sixth Avenue Seattle, WA 98101 RE: Badami Class I Injection Well B1-01 Dlspt~sai trajection Order No. 12 UIC Permit AK111001-A Annual Performance Report Dear Mr. Regg & Mr. Bussell: BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 1 ~~, - ~ S~ BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following annual performance report for the Badami Class I well, B1-01. This submittal meets the AOGCC reporting requirement in Rule 4 of Disposal Injection Order 12.001. In addition, this submittal meets the EPA reporting requirement in Underground Injection Control (UIC) Permit No. AK-11001-A Part II E.2. Please note the reporting period for this annual report is June 1, 2009 through May 31, 2010. Attached is monthly injection rate and performance data. A surveillance log is planned during the 2010 Badami barging season. A water flow log and temperature log will be performed during the logging activity to confirm that injection continues to stay in zone. Fill depth will also be determined at that time. Copies of the logs and a descriptive report will be submitted to the Commission and EPA following completion of the surveillance log. A Mechanical Integrity Test (MIT) of the inner annulus is also planned for the 2010 Badami barging season. AOGCC and EPA representatives will be invited to witness 2010 AOGCC 81-01 Ann• Performance Report • June 22, 2010 Page 2 this test. The mechanical integrity of 61-01 was last demonstrated on February 9, 2010 to diagnose a high annulus pressure reading on February 6, 2010. The well passed the MIT-1 A. Prior to this test the last MIT was in August 2009 and was witnessed on site by EPA representative, Thor Cutler. Based on a cumulative injection volume of 940!,474 barrels into the well since October 1997, it is estimated that the fluids occupy a total volume of 19.56 million cubic feet within the disposal interval. This is equivalent to a radius of 532 feet around the wellbore. S.`~'~C, ,._,_ ~'"1 o~~s~- ~ v~~.o, o ~ ~~r~~ ~~a ~Skz~~ As an update of operational plans for B1-01, Badami was restarted in September 2005, returned to warm shutdown in September 2007, and is currently in warm shutdown. In March 2010 Savant Resources completed a sidetrack of B1-18 and in April 2010 completed drilling new well B1-38, during which extensive use was made of B1-01 for cuttings disposal. Restart of the production facilities is anticipated to occur in September 2010 at which time produced water injection down B1-01 will be re- initiated. If you have any questions, please contact Mark Sauve at (907) 564-4660 or Alison Cooke at (907) 564-483,8. p~~-~~~rvc~.~ ~ s ~s3~rl~~~`1ao =~~` Sincerely, ~ ~ `~ _ ~ ~ X13 ~ ~~~~~ 4 "S C ~ Arlene Chow ~~~ ~~ ~~~ Area Operations Manager North ~`\~'`' ~ ~ ~` ~°\~' ~~cS ~~~~ Attachment cc: ,/Dan Seamount, AOGCC Thor Cutler, EPA ~~`S~~vS CW\~V~~~ot~`~S C®r~~CVc~+ ~~ ~I`-to • '~' ..~- '~ SiY ... ~~ Badami Waste Manifested Volumes and Injection Well Report. From the dates of October 1997 through May 31st 2010 We have Manifested (Received) a total of 852,887 bbls. of different waste streams Exempt waste stream accounted for 293,702 bbls or 34.44% of total bbls manifested (Received . Non Exempt waste stream accounted for 559,145 bbls or 65.56% of total bbls manifested Received . Treated Effluent accounted for 235,537 bbls or 42.12% of the "Non Exempt" fluids We Have "In'ected" a total of 940,474 bbls Total from the Chart recorder Note: 4S'154s"1 ~o~~ S ®~ cl ,3°20 0~ ~o~c.\ ~''"'~ `t 1 ~ - ~~ The difference between the "received volume" and the "injected volume" is that we do not manifest fresh water used for the maintenance purpose of flushing solids from the well and for injections to keep flow lines from freezing. Badami B1-01 Monthly Injection 6/1/2009 - 5/31/2010 Report Date Begin Report Date End Days Operating BBLS Injected Avg Inj Rate Avg Wellhead Pressure Max Wellhead Pressure Avg Casing Pressure Max Casing Pressure 6/1/2009 6/30/2009 15 6,273 418 274.73 1,709 0 0 7/1/2009 7/31/2009 14 7,292 521 311.19 1,978 0 0 8/1/2009 8/31/2009 11 4,682 426 154 2,195 0 0 9/1/2009 9/30/2009 12 2,921 243 83 1,759 0 0 10/1/2009 10/31/2009 9 835 93 48 1,446 0 0 11 /1 /2009 11 /30/2009 8 875 109 66.8 1,151 0 0 12/1 /2009 12/31 /2009 9 1083 120 65.5 1, 389 0 0 1/1/2010 1/31/2010 19 6193 326 74.5 1,725 0 0 2/1/2010 2/28/2010 16 6246 390 105 1,658 0 500 3/1/2010 3/31/2010 28 9427 337 145 1,845 0 0 4/1/2010 4/30/2010 20 5,198 260 394 2,098 0 0 5/1/2010 5/31/2010 11 2,856 260 346 1,794 0 0 Total 53,881 C~ B1-01 Annulus Pressure Data 3 OJ a` Q O C7 O Q O O Q O .n -•Tubing Pressure (psi) -f-IA Rressure (psi) BOA Pressure (psi) Q4A Pressure (psi) Q40A Pressure (psis 4n-LinelOff-Line 5131(2009 7f31 X2009 9~30f2009 11 f30F2009 1!31 (2010 331 /2010 Sf31(2010 ~~~ by ~ ~ .~~ -~ BP Exploration (Alaska) Inc. By Certified Mail # 7008 3230 0000 2496 4693 P o. eox 196612 900 East Benson Boulevard Anchorage, AK 99519-6612 May 17, 2010 Peter Contreras, Ground Water Protection Unit U.S. Environmental Protection Agency (OCE-127) 1200 Sixth Avenue Suite 900 Seattle, Washington 98101 RE: Class I Injection Well -Quarterly Report ~ Badami Development Project Permit Number AK-11001-A Dear Mr. Contreras: REDEIVED JUN 0 3 2010 Alaska 0~ ~i Sas Cant, Carrr>nssion Ancherane ~.~~~ ~~tc~e~e-~ ~ ~ ~3 In order to meet the reporting requirements of the Badami Class I Injection Well Permit (AK-11001-A) Part II E. 1, BP Exploration (Alaska) Inc. (BPXA) submits the attached quarterly report to the Environmental Protection Agency (EPA). The reporting period for this report is February 1, 2010 to April 30, 2010. The EPA requested we use-this reporting period by letter dated November 6, 1997. The quarterly report contains the following information: Monthly average, maximum and minimum values for injection pressure, rate, and volume reported on INJECTION WELL MONITORING REPORT (EPA Form 7520-8). 2. Graphical plots of continuous injection pressure and rate monitoring are presented on the "Honeywell Truline Daily Charts." These charts record the injection rate and pressure for a running 24-hour period, as well as keep a running total for the actual volume injected during a month. Please note that a summary of the waste manifested to the Badami Grind and Inject Plant is included on the "Monthly Manifested Volume by Waste Composition Form." This report shows the volume of waste manifested for each listed composition during the given month. The Daily Chart, from the Honeywell recorder, records the actual volume injected down hole. Please note that there is a difference between the total monthly volumes because not all fluids are manifested to the facility. In addition to the manifested waste, the Daily Chart records all Peter Contreras, Gro~Water Protection Unit • U.S. Environmental Protection Agency May 17, 2010 Page 2 water flushes used to displace the well over to clear fluids (water) after any injection of solids laden fluids, viscosity pills used to keep a spacer between fluids with suspended solids and lighter fluids which have little or no viscosity, and hourly water injections that verify surface lines are not freezing during periods of slow injection activity. These volumes are operationally necessary and are not manifested waste. In addition, a record and explanation of all chart upsets during the month is included in the report. Please note that there are days when no injection activity takes place at the facility. Days where no injection takes place are noted on the monthly sheets that record chart upsets. 3. Electronic monitoring data. 4. Physical, chemical, and other relevant characteristics of the injected fluids are included in "Drilling Fluids Reports" and "Fingerprint Data" in the attached report. 5. No well work over or other significant maintenance of downhole components was conducted during the reporting period. 6. A mechanical integrity test (MIT) was conducted on the inner annulus (IA) on February 9, 2010 to determine if well integrity was maintained. This test was conducted after the annulus pressure of 500 psi was exceeded. See #8 below and attached notification to the EPA submitted on February 10, 2010. 7. The injection rate limits of 5 barrels/min, 65,000 barrels/month, and injection pressure limit of 3000 psi were not exceeded for the reporting period. 8. On Saturday, February 6, 2010 at 6:30PM the high level alarm on the glycol recirculation tank tripped and automatically closed the curtain string and suction discharge (supply and return) line valves to the glycol recirculation tank. An estimated 5 barrels of glycol were in the tank. BPXA was injecting waste fluids at the time. The annulus pressure gauge was bouncing at and around 500 psig during the injection right before BPXA stopped injecting and shut-in the well. The pressure was Peter Contreras, Gr~ Water Protection Unit U.S. Environmental Protection Agency May 17, 2010 - Page 3 at or just above 500 psig on and off for an estimated 30 minutes between 6:30PM and 7:OOPM. There was no other exceedence of the 500 psi annulus pressure limit. I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment. Sincerely, Arlene Chow Area Operations Manager North Attachments cc: Thor Cutler, EPA Region 10 (without attachment) Talib Syed, PE/Talib Syed and Associates (without electronic data) Jim Regg, AOGCC (without electronic data) Sharmon Stambaugh, ADEC (without electronic data) ~1 by • David J. Szabo Head of Resource Management Alaska ConsoBidated Team (ACT) June 18, 2009 Mr. Jim Regg Alaska Oil and Gas Conservation Commission 333 West 7ih Avenue, Suite 100 Anchorage, Alaska 99501-3192 Mr. Mike Bussell Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency (EPA) 1200 Sixth Avenue Seattle, Washington 98101 RE: Badami Class I Injection Well B1-01 Disposal Injection Order No. 12 UIC Permit AK111001-A Annual Performance Report Dear Mr. Regg & Mr. Bussell: Phone: (907) 564-4788 Fax: (9078 564-4440 Email SzaboDJ~bp.com Web: www.bp.com BP Exploration (Alaska) tnc. (BPXA) respectfully submits the following annual performance report for the Badami Class I well, B1-01. This submittal meets the AOGCC reporting requirement in Rule 4 of Disposal Injection Order 12.001. In addition, this submittal meets the intent of the EPA reporting requirements for Assurance of Underground Injection Control (UIC) Permit No. AK-11001-A Part II E.2. Please note the reporting period for this annual report is June 1, 2008 through May 31, 2009. Attached is monthly injection rate and performance data. A surveillance log is planned during the 2009 Badami barging season. A water flow log and temperature log will be performed during the logging activity to confirm that injection continues to stay in zone. Fill depth will also be determined at that time. Copies of the logs and a descriptive report will be submitted to the Commission and EPA following completion. of the surveillance log. A Mechanical Integrity Test (MIT) of the inner annulus is also planned for the 2009 Badami barging season. AOGCC and EPA representatives will be invited to witness this test. The mechanical integrity of B1-01 was last demonstrated in April 2008 and was witnessed onsite by EPA representatives Talib Syed and Thor Cutler. • „J ~ ~,~ ~ ,~ ~,~ ,l ~~, ~ ~ BP Exploration (Alaska) Bnc. 900 East Benson Boulevard /~l:~Ska Ott ~ r P.O. Box 196612 ~3it` ,,i::,; ;~;~,; ; Anchorage, Alaska 99519-6612 "(91~f~ 561-5111 q IiCb(lp,A(~,F 2009-AOGCC-B1-01 Ar~l Performance Report • June 17, 2009 Page 2 Based on a cumulative injection volume of 886,593 barrels into the well since October 1997, it is estimated that the fluids occupy a total volume ofi 18.47 million cubic feet within the disposal interval. This is equivalent to a radius ofi 517 feet around the wellbore. As an update of operational plans for B1-01, Badami was restarted in September 2005, returned to warm shutdown in September 2007, and is currently in warm shutdown. In March 2009 Savant Resources initiated drilling of new well B1-38 at Badami and extensive use was made of B1-01 for cuttings disposal. Completion of B1-38 was not concluded during the winter drilling season and is anticipated to resume this summer. When drilling operations resume at Badami, injection levels into B1-01 may increase significantly. If you have any questions, please contact Mark Sauve at (907) 564-4660 or Alison Cooke at (907) 564-4838. Sincerely, ~~ David J. Szabo Head of Resource Management -Alaska Consolidated Team Attachment cc: Dan Seamount, AOGCC / Thor Cutler, EPA ~;i`~ ~~ •,,,~,c ~ X05 Badami Waste Manifested Volumes and injection Well Report. From the dates o1 October 1997 throu h Ma 31st 2009 W e have i~Aanitested Receive a total of 805,511 bbis_ of ditterent waste streams Exem t waste scream accounted for 278,453 bbis or 34.57°6 of tots! bbis manHested Received . Non Exem t waste stream accounted for 527 058 bDls or 65.43% of total bbis manNesied Received . rested Etlluent accounted for 221,346 bbis or 42.00°6 of the "Non Exem t"fluids We Have "M' fed" a total of 885,593 bbis Total from the Chart recorder Note: he ditterer~e between the "received volume" and the "injected volume" is that we do not manifest fresf~ water used for the maintenance purpose of flushing solids from the well anti for injections fa keep tlow lines from freezing. Badami B1-01 Monthly Injection 6/1/2008 - 5/31/2009 Report Date Begin Report Date End Days Operating BBLS Injected Avg Inj Rate Avg Wellhead Pressure Max Wellhead Pressure Avg Casing Pressure Max Casing Pressure 6/1 /2008 6/30/2008 24 9 034 376.42 235.03 i 670 0 0 7/1 /2008 7/31/2008 12 2,420 201.67 200.67 1,667 0 0 8/1/2008 8/31/2008 10 2,138 213.8 74.512 1,713 0 0 9/1/2008 9/30/2008 10 1,015 101.5 67, 762 1,441 0 0 10/1 /2008 10/31/2008 7 770 110 46.874 1,300 0 0 11 /1/200$ 11 /30/2008 7 761 108.71 72.945 1,422 0 0 12/1/2008 12/31/2008 8 704 88 58.815 1,305 0 0 1 /1 /2009 1 /31/2009 9 798 88.67 112.44 2 600 0 0 2/1 /2009 2/28/2009 12 656 54.67 224.858 2 120 0 0 3/1/2009 3/31/2009 20 2 348 117.4 57.525 2 062 0 0 4/i /2009 4/30/2009 27 22144 820.15 222.28 1,833 0 0 5/1 /2009 5/31/2009 13 3,601 277 83.115 1,639 0 0 Total 46,389 • B1-01 Annulus Pressure Data .r 0 ,~ -~-TUbinp Prc:L+,tre lp,i~ ~ ~- tq Pr es s+at a (psl) ~~ f-~~b Pressv~ (psp a'~ W '~' 40A Fl'~Srt.ltA'lPcli N . ~ i'p1f1R PfA*~rlt~r I'p~it ~~r` ~ E.t.. IAt~A.SP O,u ~,-r~~5p o sr~ ams ~:~~ nanF, ~~r3~rnn~ ,1 r~onrns ~ ~~ rn~ ar~~ ROrtc sr~»4m? ~~o r by • • Jean A. Celestain , Performance Unit Leader - Northstar, Endicott,-Badart~i ~ Alaska Consolidated Team (ACT) r.~-~~ ,.„ Alas~a t `t;~ ~ ~-. June 30, 2008 Mr. Jim Regg Alaska Oil and Gas Conservation Commission 333 West 7t" Avenue Anchorage, Alaska 99501-3192 Mr. Mike Bussell Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency (EPA) 1200 Sixth Avenue Seattle, WA 98101 RE: Badami Class I Injection Well B1-01 Disposal Injection Order No. 12 UIC Permit AK111001-A Annual Performance Report Dear Mr. Regg & Mr. Bussell: BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO Box 196612 Anchorage, AK 99519-6612 (907) 564-5111 Phone: (907) 564-5107 Fax: (907) 564-4441 Email: CelestJ~bp.com Web: www.bp.com BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following annual performance report for the Badami Class I well, B1-01. This submittal meets the AOGCC reporting requirement in Rule 4 of Disposal Injection Order 12.001. In addition, this submittal meets the intent of the EPA reporting requirements for Assurance of Underground Injection Control (UIC) Permit No. AK-11001-A Part II E.2. Please note the reporting period for this annual report is June 1, 2007 through May 31, 2008. Attached is monthly injection rate and performance data. A surveillance log is planned during the 2008 Badami barging season. A water flow log and temperature log will be performed during the logging activity to confirm that injection continues to stay in zone. Fill depth will also be determined at that time. Copies of the logs and a descriptive report will be submitted to the Commission and EPA following completion of the surveillance log. A Mechanical Integrity Test (MIT) of the inner annulus was performed on April 11, 2008. The AOGCC representative waived the right to witness the April 2008 test; however the test was witnessed onsite by EPA Mr. Jim Regg Alaska Oil and Gas Conservation Commission Mr. Mike Bussell, Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency June 30, 2008 Page 2 representatives Talib Syed and Thor Cutler. The mechanical integrity of B1-01 was demonstrated during the test and no communication from the inner annulus to the tubing or outer annulus was evident. Based on a cumulative injection volume of 840,204 barrels into the well since October 1997, it is estimated that the fluids occupy a total volume of 17.5 million cubic feet within the disposal interval. This is equivalent to a radius of 503 feet around the wellbore. As an update of operational ,plans for B1-01, Badami was restarted in September 2005, returned to warm shutdown in September 2007, and is currently in warm shutdown. BP continues to evaluate the use of new technology, such as horizontal drilling, to further develop the reservoir. Should drilling operations resume at Badami, injection levels into B1-01 may return to levels of injection seen in 1998. If you have any questions, please contact Robert Younger at (907) 564- 5392 or Alison Cooke at (907) 564-4838. Sincerely, Jean A. Celestain SFG/ADC Attachment cc: Dan Seamount, AOGCC Thor Cutler, EPA Talib Syed • • i ~* ~ ~ a ~ ~ o ~' ~ is r Badami Waste Manifested Volumes and Injection Well Report. From the dates of October 1997 throu h Ma 31st 2008 We have Manifested Received a total of 762,937 bbls. of different waste streams Exem t waste stream accounted for 265 661 bbls or 34.82% of total bbls manifested Received . Non Exem t waste stream accounted for 497 276 bbls or 65.189'° of total bbls manifested Received . Treated Effluent accounted for 210,238 bbls or 42.28% of the "Non Exem t" fluids We Have "In'ected" a total of 840,204 bbls Total from the Chart recorder Note: The difference between the "received volume" and the "injected volume" is that we do not manifest fresh water used for the maintenance purpose of flushing solids from the well and for injections to keep flow lines from freezing. B1-01 Annulus Pressure Data B'i -0't Tlo Plot ~ .•. Tbg -~- IA 2,000 1,000 0 sr1 r2oo7 -~l- OA OOA i~ -f- OOOA • L.~__ .. 7/92007 9J17l2007 11 !26!2007 2/4E2008 4M 42008 6~23~008 r - Badami 81-01 Monthly Injection fii1/2007 - 5/3'1/2008 Report Date Begin Report Date End Days Operating BBLS Injected Avg Inj Rate Avg Wellhead Pressure Max Wellhead Pressure Avg Casing Pressure Max Casing Pressure 6/1 /2007 6/30/2007 9 1428 159 293 1861 0 0 7/1/2007 7/31/2007 17 4732 278 352 1920 0 0 8/1/2007 8/31/2007 11 1731 157 202 1820 0 0 9/1/2007 9/30/2007 8 615 77 91 1467 0 0 10/1/2007 10/31/2007 6 479 80 i 17 1289 0 0 11 /1 /2007 11 /30/2007 5 481 96 134 1298 0 0 12/1 /2007 12/31 /2007 8 661 83 166 1302 0 0 1h/2008 1/31/2008 8 327 41 201 i 983 0 0 2/1 /2008 2/28/2008 19 522 27 i 35 1095 0 0 3/1 /2008 3/31 /2008 21 470 22 160 1309 0 0 4/1 /2008 4/30!2008 17 575 34 203 1209 0 0 5/1 /2008 5/31 /2008 9 672 75 232 1389 0 0 Total 12,693 -# ~19 by • • Jean A. Celestain Performance Unit Leader - Northstar, Endicott, Badami BP Exploration (Alaska) Inc. Alaska Consolidated Team (ACT) 900 East Benson Boulevard PO Box 196612 ,~wE~ 907)56451AK 99519-6612 lUN ~. ~ 2007 Phone: (907) 564-5107 June 14, 2007 -~~aska ~~°~ ~ Gss Cons. Commission Email: Celes ~bp.com AnChaCago Web: www.bp.com Mr. Jim Regg Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3192 RE: Badami Class I Injection Well Disposal Injection Order No. 12 Annual Performance Report Dear Mr. Regg: BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following Annual Performance Report for the Badami Class I well, B1-01. This submittal meets the reporting requirement in Rule 4 of Disposal Injection Order 12.001. The reporting period for this annual report is June 1, 2006 through May 31, 2007. Attached is monthly injection rate and performance data. A surveillance log is planned during the 2008 Badami barging season. A water flow log and temperature log will be performed during the logging activity to confirm that injection continues to stay in zone. Fill depth will also be determined at that time. Copies of the logs and a descriptive report will be submitted to the Commission following completion of the sur~reillance log. A Mechanical Integrity Test (MIT) of the inner annulus was performed on April 12, 2007. The AOGCC representative waived the right to witness the April 2007 test; however the tests were witnessed by EPA representative Talib Syed. The mechanical integrity of B1-01 was demonstrated and no communication from the inner annulus to the tubing or outer annulus was evident. Based. on a cumulative injection volume of 827,511 barrels into the well, it is estimated that the fluids occupy a total volume of 17.2 million cubic feet within the disposal interval. This is equivalent to a radius of 499 ft around the wellbore. Mr. Jim Regg Alaska Oil and Gas Conservation Commission June 14, 2007 Page 2 Please note that the cumulative injection volume and corresponding radius of injection was overstated on the cover page of the report dated June 30, 2005. However, the supporting attachments in last year's 2006 report are accurate. As an update of operational plans for B1-01, Badami was restarted in September 2005. Injection levels into B1-01 have increased since Badami resumed operational status, and a return to the levels of injection seen in 1998 is possible should drilling operations resume. If you have any questions, please contact Robert Younger at (907) 564- 5392 or Ms. Alison Cooke at (907) 564-4838. Sincerely, Jean A. Celestain SFG/ADC Attachment cc: Dan Seamount, AOGCC Badami File • • ~f ~ ~ ~ r - ' ,~ , Badami Waste Manifested Volumes and Injection Well Report. From the dates of Occtober 1997 throu h Ma 31st 2007 We have Manifested (Received a total of 753,082 bbls. of different waste streams Exempt waste stream accounted for 265,636 bbls or 35.27% of total bbls manifested Received). Non Exem t waste stream accounted for 487,446 bbls or 64.73% of total bbls manifested (Received . Treated Effluent accounted for 203,875 bbls or 41.83% of the "Non Exem t" fluids We Have "In'ected" a total of 827,511 bbls Total from the Chart recorder Note: The difference between the "received volume" and the "injected volume" is that we do not manifest fresh water used for the maintenance purpose of flush ing solids from the well and for injections to keep flow lines from freezing. Badami B1-01 Monthly Injection 6/1/2006 - 5/31/2007 Report Date Begin Report Date End Days Operating BBLS Injected Avg Inj Rate Avg Wellhead Pressure Max Wellhead Pressure Avg Casing Pressure Max Casing Pressure 6/1 /2006 6/30/2006 14 3,096 221.14286 215 1,934 0 0 7/1/2006 7/31/2006 12 1,936 161.33333 240 2,558 0 0 8/1/2006 8/31/2006 14 4,091 292.21429 273 2,495 0 0 9/1/2006 . 9/30/2006 9 2,360 262.22222 375 2,565 0 0 10/1/2006 10/31/2006 9 1,204 133.77778 332 2,979 0 0 11 /1 /2006 11 /30/2006 11 1,104 100.36364 296.11 2,063.92 0 0 12/1/2006 12/31/2006 12 955 79.58333 358 2,287 0 0 1 /1 /2007 1 /31 /2007 12 641 53.41667 443 2,101 0 0 2/1/2007 2/28/2007 7 514 73.42857 552 2,689 0 0 3/1 /2007 3/31 /2007 20 1,166 58.3 365 3,000 0 0 4/1 /2007 4/30/2007 9 808 89.77778 385 2,000 0 0 5/1 /2007 5/31 /2007 9 838 93 309 1,815 0 0 Total 18,713 L.J • ~1$ by ~ Robert O. Younger Production Engineer Alaska Consolidated Team (ACTT June 26, 2006 Alaska qil ~ Gas Cons. C~mmissitln Anchorage ~~,d;9~, `""" "" BP Exploration (Alaska) Inc. "~i 900 East Benson Boulevard I, I~ Y ~ ~n~~ P. O. Box 196612 J v L J Anchorage, Alaska 99519-6612 (9071561-5111 Mr. Jim Regg Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501-3192 RE: Badami Class I Injection Well Disposal Injection Order No. 12 Annual Performance Report Dear Mr. Regg: Phone: (907) 564-5392 Fax: (907) 564-4441 Email Robert.Younger~bp.com Web: www.bp.com BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following annual performance report for the Badami Class I well, B1-01. This submittal meets the reporting requirement in Rule 4 of Disposal Injection Order 12.001. The reporting period for this annual report is June 1, 2005 through May 31, 2006. Attached is monthly injection rate and performance data. A surveillance log is planned during the 2006 Badami barging season. A water flow log and temperature log will be performed during the logging activity to confirm that injection continues to stay in zone. Fill depth will also be determined at that time. Copies of the logs and a descriptive report will be submitted to the Commission following completion of the surveillance log. Mechanical Integrity Tests (MIT) of the inner annulus were performed on January 28, 2006 and April 18, 2006. The AOGCC representative waived the right to witness the April 2006 test; however the tests were witnessed by EPA representative Talib Sayed. He was present over the phone in January and on site in April. The mechanical integrity of B1-01 was demonstrated for both tests and no communication from the inner annulus to the tubing or outer annulus was evident. Based on a cumulative injection volume of 808,889 barrels into the well, it is estimated that the fluids occupy a total volume of 16.8 million cubic feet within the disposal interval. This is equivalent to a radius of 493 ft around the wellbore. ~J r Mr. Jim Regg Alaska Oil and Gas Conservation Commission June 26, 2006 Page 2 Please note that the cumulative injection volume and corresponding radius of injection was overstated on the cover page of last year's report dated June 30, 2005. However, the supporting attachments in last year's report are accurate. As an update of operational plans for B1-01, Badami was restarted in September 2005. BP continues to evaluate the use of new technology, such as horizontal drilling, to further develop the reservoir. Injection levels into B1-01 have increased since Badami resumed operational status, and a return to the levels of injection seen in 1998 is possible should drilling operations resume. If you have any questions, please contact Robert Younger at (907) 564- 5392 or Ms. Alison Cooke at (907) 564-4838. Sincerely, Robert Younger Enclosures cc: Dan Seamount, AOGCC • ~.~ .~ ~. i ~~ i3 ' ~ ~' IS `C' Badami Waste Manifested Volumes and Injection Well Report. From the dates of Occtober 1997 throw h June 7th 2006 We have Manifested Received a total of 735,439 bbls. of different waste streams Exem t waste stream accounted for 263,336 bbls or 35.81% of total bbls manifested Received . Non Exem t waste stream accounted for 472,103 bbls or 64.19% of total bbls manifested Received . Treated Effluent accounted for 195,851 bbls or 41.48% of the "Non Exem t" fluids We Have "In"acted" a total of 808,889 bbls Total from the Chart recorder Note: The difference between the "received volume" and the "injected volume" is that we do not manifest fresh water used for the maintenance purpose of flushing solids from the well and for injections to keep flow lines from freezing. .- Badami B1-01 Monthly Injection 6/1/2005 - 5/31/2006 Report Date Begin Report Date End Days Operating BBLS Injected Avg Inj Rate Avg Wellhead Pressure Max Wellhead Pressure Avg Casing Pressure Max Casing Pressure 6/1/2005 6/30/2005 14 4,470 319 203 1,603 0 0 7/1 /2005 7/31 /2005 18 7,568 420 149 1,623 0 0 8/1 /2005 8/31 /2005 12 1,127 94 62 1,410 0 0 9/1 /2005 9/30/2005 9 1,062 118 73 1,520 0 0 10/1 /2005 10/31 /2005 9 916 102 77 2,261 0 0 11 /1 /2005 11 /30/2005 13 673 52 182 2,305 0 0 12/1 /2005 12/31 /2005 12 577 48 78 1,150 0 0 1 /1 /2006 1 /31 /2006 10 634 63 82 1,786 0 0 2/1 /2006 2/28/2006 10 491 49 97 1,312 0 0 3/1 /2006 3/31 /2006 8 446 56 166 1, 934 0 0 4/1 /2006 4/30/2006 7 1,037 148 157 1,614 0 0 5/1 /2006 5/31 /2006 8 1,089 136 166 2,266 0 0 Total 20,090 digital weiif~le TIOs » Home 4,000 U More Links ~ OneE • r a 3,000 2,000 1,000 0 6030/2005 813112005 10/3102005 MAASP (Maximum Allowable Annulus Surface Pressure) Maximum IA Pressure 500 Maximum OA Pressure 500 Maximum OOA Pressure 500 Maximum OOOA Pressure 500 --Tubing Pressure (psi) -f-IA Pressure (psi) -f- OA Pressure (psi) OOA Pressure (psi) OOOA Pressure (psi) 1203112005 2128!2006 4/3001006 Well: B1-O1 __~ OK O ALASKA CONSOLIDATED TEAM » END » Bi » B1-O1 ~~ by • • By Facsimile June 30, 2005 Mr. Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7th Avenue - Anchorage, Alaska 99501-3192 Badami Class I Injection Well Disposal Injection Order No. 12 Annual Performance Report Dear Mr. Seamount: BP Exploration (Alaska) Inc. P.O. Box 196612 900 East Benson Boulevard Anchorage, AK 99519-6612 (907)564-5111 BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following annual performance report for the Badami Class I well, B1-01. This submittal meets the reporting requirement in Rule 4 of Disposal Injection Order 12.001. The reporting period for this .annual report is June 1, 2004 through May 31, 2005. Attached is monthly injection rate and performance data. A surveillance log was run during the reporting period. A water flow log and temperature log was performed during the September, 2004 barging season which confirmed that injection continues to stay in zone. Fill depth was also determined at that time. Copies of the logs and a descriptive report were submitted to the Commission in October, 2004. A Mechanical Integrity Test (MIT) of the inner annulus was performed on January 30, 2005. The AOGCC representative waived the right to witness the test. The mechanical integrity of B1-01 was demonstrated and no communication from the inner annulus to the tubing or outer annulus was evident. Based on a cumulative injection volume of 804,750 barrels into the well, it is estimated that the fluids occupy a total volume of 16.7 million cubic feet within the disposal interval. This is equivalent to a radius of 491 feet around the wellbore. As an update of operational plans for B1-01, we inform you that BP is preparing to restart production at Badami in late summer, 2005, when regulatory and technical requirements are in place. In addition, BP is evaluating the use of recent technology, such as horizontal drilling, to further develop the reservoir. Should new reservoir modeling support it, two wells may be drilled early in 2006 during the ice road season, Mr. Dan Seamount • June 30, 2005 Page 2 and if they are successful, up to six more wells in 2007 are possible. These plans for drilling are in the evaluation stage. Injection levels into B1-01 are likely to increase as Badami moves from warm shutdown to restart status, and return to the levels of injection seen in 1998 should drilling operations resume. If you have any questions, please contact me at (907) 564-5210 or Ms. Alison Cooke of my staff at (907) 564-4838. Sincerely, !.'~ Stan F. Gates, Technical and Regulatory Team Lead HSE Alaska SFG/ADC Attachment cc: Jim Regg, AOGCC Badami B1-01 Monthly Injection 6/1/2004 - 5/31/2005 Report Date Begin Report Date End Days Operating BBLS Injected Avg Inj rate Avg Wellhead pressure Max Wellhead Pressure Avg Casing Pressure Max Casing Pressure 6/1 /2004 6/30/2004 17 11,230 660 1,939 2,092 0 0 7/1 /2004 7/31 /2004 17 8,655 509 1,982 2,128 0 0 8/1/2004 8/31/2004 25 2,676 107 1,681 2,074 0 0 9/1 /2004 9/30/2004 20 1,278 63 1544 1, 937 0 0 10/1 /2004 10/31 /2004 17 803 47 1,356 1,605 0 0 11 /1 /2004 11 /30/2004 6 372 62 1,172 1,503 0 0 12/1 /2004 12/31 /2004 7 262 37 826 1,291 0 0 1 /1 /2005 1 /31 /2005 16 518 32 918 1,418 0 0 2/1 /2005 2/28/2005 14 387 27 957 1,294 0 0 3/1 /2005 3/31 /2005 13 492 37 133 1,046 0 0 4/1 /2005 4/30/2005 10 779 77 161 1,148 0 0 5/1 /2005 5/31 /2005 6 504 84 166 1,146 0 0 Total 27,956 • • X16 ~~ ' ~ r ~. ~ ~ ~ ~ ' i~ ~ ~ ~+ ~, °°' ~ ~ ~ ~ ~' fl FRANK H. MURKOWSKI, GOVERNOR ;; ~~~ OIL ~ ua-7 ~+ 333 W. 7"' AVENUE, SUITE 100 CORSERQATIOR COl-i1rII5SIOIQ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 ' FAX (907) 27&7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing mechanical integrity of wells in all existing area injection orders, storage injection orders, enhanced recovery injection orders, and disposal injection orders. There are numerous different versions of wording used for each of the rules that create confusion and inconsistent implementation of well integrity requirements for injection wells when pressure communication or leakage is indicated. In several injection orders, there are no rules addressing requirements for notification and well disposition when a well integrity failure is identified. Wording used for the administrative approval rule in injection orders is similarly inconsistent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and before returning a well to service following a workover affecting mechanical integrity. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. ~J • Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. The following table identifies the specific rules affected by the rewrite. Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" Area In'ection Orders AIO 1 -Duck Island Unit 6 ~ g AIO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, Ugnu, West Sak 6 ~ 9 Fields AIO 3 -Prudhoe Bay Unit; Western Operating Area 6 ~ 9 AIO 4C -Prudhoe Bay Unit; Eastern Operating Area 6 ~ 9 AIO 5 -Trading Bay Unit; McArthur River Field 6 6 9 AIO 6 -Granite Point Field; Northern Portion 6 ~ 9 AIO 7 -Middle Ground Shoal; Northern Portion 6 ~ 9 AIO 8 -Middle Ground Shoal; Southern Portion 6 ~ 9 AIO 9 -Middle Ground Shoal; Central Portion 6 ~ 9 AIO 1 OB -Milne Point Unit; Schrader Bluff, Sag River, 4 5 g 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 11~ n • Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Inte rity" Confinement" River Unit AIO 16 - Kuparuk River Unit; Tarn Oil Pool 6 7 10 AIO 17 - Badami Unit S 6 8 AIO 18A -Colville River Unit; Alpine Uil Pool 6 ~ 1 I AIO 19 -Duck Island Unit; Eider Oil Pool S 6 9 AIO 20 -Prudhoe Bay Unit; Midnight Sun Oil Pool S 6 9 AIO Z 1 - Kuparuk River Unit; Meltwater Oil Pool 4 No rule 6 AIO 22C -Prudhoe Bay Unit; Aurora Oil Pool S No rule 8 AIO 23 - Northstar Unit S 6 9 AIO 24 -Prudhoe Bay Unit; Borealis Oil Pool S No rule 9 AIO 2S -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 S -Barrow Gas Field; South Barrow #S 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 S DIO 8 -Beaver Creek Unit; BC-3 2 3 S DIO 9 -Kenai Unit; KU 11- 17 2 3 4 DIO 10 -Granite Point Field; GP 44-11 2 3 S Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" DIO 11 -Kenai Unit; KU 24-7 2 3 4 DIO 12 - Badami Unit; WD- 1, 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 Storage In'ection 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 Recove In'ection Orders EIO 1 -Prudhoe Bay Unit; Prudhoe Bay Field, Schrader No rule No rule 8 Bluff Formation Well V-105 L Injection Order EIO 2 -Redoubt Unit; RU-6 "Demonstration of Mechanical Integrity" 5 • Affected Rules "We1i Integrity Failure and Confinement" 8 "Administrative Action" 9 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AO-O2S'14016 ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE 'SEE B°TT(3M rrOlt INVOICE ADIJRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7th Avenue, Suite 100 ° Anchorage, AK 99501 PHONE Pc "' 907-793-1221 DATES ADVERTISEMENT REQUIRED: T Journal of Commerce 0 301 Arctic Slope Ave #350 Anchorage, AK 99518 October 3, 2004 THE MATERIAL BETWEEN THE DOGBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America State of ss division. Before me, the undersigned, a notary public this day personally appeared he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for consecutive days, the last publication appearing on the day of _ .2004, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2004, who, being first duly sworn, according to law, says that REMINDER INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE Notary public for state of My commission expires _ Public Notices Subject: Public Notices From: Jody Colombie <jody_colombie@admin.state.ak,us> Date: Wed, 29 Sep 2004 13:01:04 -0800 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mcver@admin.state.ak.us>, ~-ingela ~~ehh <angie_webb@admin:state.ak.us>, Robert E Mintz <robert mintz(u;law.state.ak.us>, Christine Hansee <c`:hansee@iogec.state.ok.us>, Terre Hubble <i~ubbletl(rl!bp.coni=, Sondra Stewman <StewmaSD@BP.com> Scott & Cammy Taylor <staylar@laska.net>, stanekj <stanek@unocaI.cotr~>, ecalaw <ecolaw@rustees.org@ roseragsdale <raseragsdale@gci.net>, trmjrl <trmjrl@aol.cam>, jbrddle'<jbriddle@marathonoLcom>, rockhll = rockhill~aaga.org>, shaneg ' <shaneg@evergreengas.com>, jdarlington <jdariiegton@f~restoil.com>, nelson <knelson@petroleumnews.com>, cboddy:<cboddy@sibell.com>, Mark Dalton <mark.Balton@hdrinc.com>,_ShaneoeDonnelly<Shannon.danrrelly«:conocophillp~.eortr? "Mark. P. Worcester" <mark.p.warcester@conocophillps.com>, "Jt:rrv C`. Dethlefs" ferry.c.dethlefs@onocaphillips.com>, Bob <bob@inletkeeper.org>, ~-tdv <wd~tu%dnr.state.ak.us>, tjr <tjr@dnr:stateak.us>, bbritch <bbritch@alaska.net>, nljnelsan <mjnelson~apur-~~inaertz.com>, Charles O'Donnell <chares.o'donnell@veco.cam>, 'Randy L. Skillern" <Ski11eRI@BP.corn>, "Deborah J. Janes" <JonesD6~a BP.cam>, "Paul G.,Hyatt" <hyattpg@BP.corn>, "StevemR. Rassberg" <RossbeR5@BP.com>, Lais <lois@inletkeeper.arg>, Dan Bross <kuacnews 1%kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SornmerPS~~i;BP.com-Y, hiikel Schultz <Mikel.Schultz@BP.cam>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BPcom>, "Janet D. Platt" <PlattJD@BP.eorn>, "Rosanne ~~1. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.cam>, Collins >Vlount <collies_mount@revenue.state.ak.us>, mckay <mckay@gci.net>, Barh~~-a_F Fullmer <Barbara.ffullmer@conocophillips.cam>, bocastwf <boeast`vf@bp.carn~. Charles Barker <barker@usgs.gov>, doug_schultze <doug_schuttze@xtcienergy.ec~m? Hank A'Ifurd <hank.alford@exxonmobil.corn?, Mark Kavac <yesnol@gci.net==, gsptoff <gspfaff@aurorapower.com>, Gregg Nady <gregg.nady~_a~shell.com-= ,Fred Stecce <fred.steece@tale.sd.us>, rcrotty <rcrotty@eh2m.com>, j~jones <jejone5;~zaurorapo~~er.eo~n>, dapa <dapa~a alaska.net>, jroderick <jroderck@gei.net>, eyancy <evancy(~seal-tite.net>, "James 1\il. Ruud" ~'ja~xres.m.ruud~cr<~onocophillips.com>, Brit Lively <mapalaska(~r ak.net-~, fah <jah@drtr.state.ak.us>, Kurt EOlsan <kurt_alson@legisatate.ak.us=, buonoje ~~buonoja@bp.~o~m>, Mark Hanley.<mark hanley@a,~adarko.com>, Loren Leman <Lorenlemanla: ~~ov.state.ak.us>, Julie Haute <juke_houle@dru-.state.ak.us> John W Katz <jwkatz~~i;sso.org>, Suzan J Hill <suzan_hiIl@dec.state.akus>, tablerk.<tablerk@unocal.eom>, Brady ~~brady~uaoga.arg> Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpvpp~@barough.kenai.ak.us%. Jim White jimwhite@satx.rr.canl~;'"John:S. Haworth"'<Sohn.s.haw~~rt11(~iexxomnobil.com>, marty <marty@rkiridustrial.cam=~, ghammons <ghammons'a aaI'.com>, rmclean <rmclean@obox.alaska.rtet>, mkm7200 <mkm7?00(uaol.com'=, Brian. Gillespie <ifbmg@uaa.alaska.edu->, David L Boelens ~dbaelens~ ;aurorapower.eom ~, Todd Durkee <TDURKEE@KI~1G.com>. Marv Schultz y~barv_ sclultz(~t,dnr.state.ak.us=, ~'~ra~ne Rancier <RANCIER@petro-canada.ca=~, Bill Miller <Bill_1~Iiller(axtoalaska.com=, Brandon Ga~nion <bgagnon@brenalaw.corn>, Paul Wind@ <=pmwinslow/a,forestoil.com>, Gam' Catron <catrongr@bp.com==, Sharmaine Copeland <copelasv~~bp.com>, Suzanne Allexan <sallexan(uhelmener~.eom -, Kristin Dirks -=kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman~ci.marathonal.com>, John Tower <John.Tower@eia.doe.gav>, Bill Fowler <Bill_l4owler@anadarka.COM>, Vaughn Swartz <vaughn.swartz(~irbccm.com>, Scott Cranswick 1 of 2 9/29/2004 1: l0 PM Public Notices • <scott.cranswick@mms_gov>, Brad McKim <mckimbs@BP.eom> Please find the attached Notice and Attachment for the proposed amendment. of underground injection orders and the Public Notice Happy Valley.#10. Jody Colombie Content-Type: applieatiotv'msword ' Mechanical Integrity proposal.doe Content-Encoding.: base64 ___ Content-Type:. application/msword Mechanical Integrity of Wells Notice.doc , Content-Encoding: base6=l Content-Type:. applcatiorL'msword IlappyVallevl0 HearingNotice.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 @alaskajournal. 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 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Kelly Valadez Robert Gravely George Vaught, Jr. Tesoro Refining and Marketing Co. 7681 South Kit Carson Drive PO Box 13557 Supply & Distribution Littleton, CO 80122 Denver, CO 80201-3557 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Richard Neahring John Levorsen Hodgden Oil Company NRG Associates 200 North 3rd Street, #1202 408 18th Street President Boise, ID 83702 Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Kay Munger Samuel Van Vactor Michael Parks Munger Oil Information Service, Inc Economic Insight Inc. Marple's Business Newsletter PO Box 45738 3004 SW First Ave. 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Portland, OR 97201 Seattle, WA 98119-3960 Mark Wedman Schlumberger David Cusato Halliburton Drilling and Measurements 200 West 34th PMB 411 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Baker Oil Tools Ciri Jill Schneider 4730 Business Park Blvd., #44 Land Department US Geological Survey Anchorage, AK 99503 PO Box 93330 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 Williams Thomas North Slope Borough Arctic Slope Regional Corporation PO Box 69 Land Department Barrow, AK 99723 PO Box 129 Barrow, AK 99723 [Fwd: Re: Consistent Wording for Injection lrs -Well Integrity Subject:{Fwd: Re: Consistent Wording for Injection Orders - From: John Norman <john_norman@admin.state.ak.us> Date: Fri; Ol Oct 2004 11:09:26 -0800 To: Jody J Colombie <jody_eolombie@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(a~admin.state.ak.us CC:dan seamount r(i).,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~~~;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 reag(c~admin.state.ak.us> 8/17/2004 4:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing 1 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injectior'ters -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 Alaska Oil & Gas Cariservation Commission 2 of 2 10/2/2004 4:07 PM ,[Fwd: Re: Consistent Wording for Injection ~s -Well Integrity ... • Sub,jeet: [Fwd: Re Consistent.. Wording for Injection Orders - Weli Integrity (Revised)) From: John Norman <john_norman@admin.state.ak.us> Date: Fri, O1 Oct 2004 11:08:5 -0800 To: Jody J Calombie <~ody eolombie~adminatate.ak.us> please print all and put in file for me to review just prior to hearing on these amendments. thanx ------- Original Message -------- Subjeet:Re: Consistent Wording for Injection Orders -Well Integrity (Revised) Date:Thu, 19 Aug 2004 15:46:31 -0800 From:Rob Mintz <robert mintz(a,law.state.ak.us> To:dan seamount(~r~,admin.state.ak.us, jim regg~admin.state.ak.us, john norman(a~admin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim regg~ admin.state.ak.us> 8/17/2004 4:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Weli 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 cocTective 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 ... • - adopts "Administrative Actions" title (earlier rules used "Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norman(a~admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission Content-Type: application/msword ;Injection Order language - questions.doc Content-Encoding: base64 __ _ __ __ __ _ __ _ __ -_ __ Content-Type: application/msword 'Injection Orders language edits.doc Content-Encoding: base64 __ _. 2 of 2 10/2/2004 4:07 PM • • Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubin /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 inf ectfon «•ell}, anal before returning_a «•ell to ser~•ice follo`vin~ a workover affecting mechanical integrity, .,~,, „*'.,,a.~;t ~;:;~:;~ ...,, ,'. ~,-. .~ ~~- *~ °~-• ~ ~ +: y , ULl(A U y~r(Ll ,] i"VTiiR RG'l.lYi~l-i"Vii['LjTC,. tTnless an alternate means is approved by the Commission mechanical integrity must be demonstrated by a tubing pressure test using a ?~-1-surface pressure ofn~ 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that shows stabilizing pressure that does~€~-may not change more than 10°re-percent during a 30 minute period. -4~= .. - The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Irate rity Failure and Confinement Except as otherwise provided in this rule Tthe tubing, casing and packer of an injection well must aen~.~~maintain integrity during operation. ti~'henever any pressure communication, Ieaka~e or lack of iniection__zone isolation is indicated by infection rate, operating pressure obse~ti~atic?~~, test, survey log, or other evidence tThe operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval_ ,~ ~~ , ,•, .The operator shall shut in the well if so directed by the Commission. The operator shall shut fn the well without aEwaitin~ a response Ii•om tl~e Commission if continued operation ~d•ould be unsafe or wcxild threaten contamination of freshwater U..~.,~. ~ ... ,.vz °~"" r°~ux=~~, tl~ ' " * ` '' * ' ~. Until,correctiye 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: Re: [Fwd: AOGCC Proposed WI Lan for Injectors]] Subiect: [Fwd: Re: [Fwd: AOGCC Proposed WI Language for Injectors]] From: Winton Aubert <winton aubert@admin.state.ak.us> Date: Thu,.28 Oct 2404 09:48':53 -0&00 Ta; Jody J Calombie <jody_colombie@adminatate.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 Aubert <winton aubert@admin.state.ak.us> References: <41812422.8080604@admin.state.ak.us> These should be provided to Jody as part of public review record Jim Winton Aubert wrote: FYI. -------- Original Message -------- Subject: AOGCC Proposed WI Language for Injectors Date: Tue, 19 Oct 2004 13:49:33 -0800 From: Engel, Harry R <EngelHR@BP.com> To: winton aubert@admin.state.ak.us Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven; Engel, Harry R; Cismoski, Doug A; NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.; Reeves, Donald F; Dube, Anna T; NSU, ADW Well Integrity Engineer *Subject: * AOGCC Proposed WI Language for Injectors Hi Guys. John McMullen sent this to us, it's an order proposed by the AOGCC to replace the well integrity related language in the current Area Injection Orders. Listed below are comments, not sure who is coordinating getting these in front of Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few comments, but could live with the current proposed language. Note the proposed public hearing date is November 4. The following language does not reflect what the slope AOGCC inspectors are currently requiring us to do: "The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and * before* ** 1 of 3 10/28/2004 11:09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI 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:jody colombie~admin.state.ak.us Sent: Wednesday, September 29, 2004 1:01 PM Subject: Public Notices Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal.ZIP » «Mechanical Integrity of Wells Notice.doc » 2 of 3 10/28/2004 11:09 AM ~i5 F ,.~~:__:_._. A ~.i € ~t °~t ~ ~!! d ! ~ ~ I ~ ~. { ~ ~~ ~~.J ~ t i t ~ I ~ $ 4,.-. ~'. °~ ~ ~_' ~ f -'~4~ ~ri s.,.;s4~1 ~ ( E.k , L.~ ~r~~, .'m. 4 a ~LASS~ OIL A1~1D G~5 COI~TSERVA~`I011T COMI-II5SIOI~T F t` August 2, 2004 Mr. Stan F. Gates HSE Technical and Regulatory Team Lead ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Dear Mr. Gates: FRANK H. MURKOWSKI, GOVERNOR 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 IJisposal Injection Order 12 dated August 5, 1997, addresses requirements for waste injection into specific disposal injection intervals within the Badami Unit. Rule 4 of DIO 12 requires an annual performance report that includes "rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans." The Alaska Oil and Gas Conservation Commission ("Commission") received from BP Exploration Alaska, Inc. ("BPXA") the annual Disposal Performance Report for the Badami Class I well, for July 1, 2003 through May 31, 2004. The report is dated June 28, 2004, and summarizes pressure and rate performance, mechanical integrity testing of Well B1-O1. Noted in BPXA's report is that fill depth tags, water flow logs, and temperature logs will be performed during July-August timeframe. Please note that the following addition information is required in conjunction with the planned submittal of a descriptive report (and logging/survey data) to meet the requirements of DIO 12 Rule 4: Summary of all well pressures (tubing, inner annulus; outer annulus); Estimate of fracture growth; Update of operational plans. The above noted information should be provided to the Commission by September 30, 2004. Sincerely, ~z~~ ~~~ James Regg UIC Manager cc: John K. Norman, Chair Daniel T. Seamount, Jr., Commissioner SCA~N~ AUG 2 ~ 200 ~~ A s I ~ , by By Facsimile June 28, 2004 • ~~ BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Mr. Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501-3192 .iUL ~ ~. 2004 .~`tF'~. L~`',~ fr'~~ { ~ l3ui S.a 1~5 :,, lr~~". ". itE~:l;i;z.{;'::', i•. `s iW ~ it 1 Badami Class I Injection Well Disposal Injection Order No. 12 Annual Performance Report Dear Mr. Seamount: BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following annual performance report for the Badami Class I well. This submittal meets the reporting requirement in Rule 4 of Disposal Injection Order 12.001. The reporting period for this annual performance report is July 1, 2003 through May 31, 2044. Attached is monthly injection rate and performance data. No surveillance logs were run during the reporting period. A water flow log and tempera#ure log will be performed later this summer during the July-August barging season to confirm that injection continues to stay in zone. Copies of the logs and. a descriptive report will be submitted to the Commission when complete. Fill depth will also be determined during this time. A Mechanical Integrity Test (MIT) of the inner annulus was performed on March 12, 2004 with AOGCC witness. The mechanical integrity of B1-01 was demonstrated and no communication to the tubing or outer annulus was evident. t, ~ ~ A Mr. Dan Seamount June 28, 2004 Page 2 Based on a cumulative injection volume of 776,800 barrels into well Badami B1-01, it is estimated that the fluids occupy a total volume of 16.2. million cubic feet within the disposal interval. This is equivalent to a radius of 483 ft around the wellbore. If you have any questions, please contact me at (907) 564-5210 or Ms. Alison Cooke of my staff at (907) 564-4838. Sincerely, Stan F. Gates, Technical and Regulatory Team Lead HSE Alaska SFG/ADC Attachment ~~ cc: Jim Regg, AOGCC iZ - (Z~ ~~~ ~ L~ de ~ ~ -~~-- ~ ~ - ~~ p~s~ ~suL~e - CLnnul,i ~~fsSL~s -~ ~-~~ti~ ~ ~, ~C C~ V~1u~ c~ ~ Z ~ s n U,~,P.z cj .~.~Y. 4 c~spos ,~G~d`.~ S ~ ~ v~s p'la-,mss =~ ~ j ~ - l~u..~~!- Zv~Xr 7 °° ! „ ,' .. Badami B1-01 Monthly Injection 5/1/03 - 6/1/04 Report Date Begin Report Date End Days Operating BBLS Injected Avg Inj rate Avg Wellhead Pressure Max Wellhead Pressure Avg Casing Pressure Max Casing Pressure 5/1 /2003 6/1/2003 5/31 /2003 6/30/2003 14 19 3,124 12,960 223 682 1, 940 2,046 2,123 2,198 0 0 0 0 7/1 /2003 7/31 /2003 22 13,513 614 1,988 2,141 0 0 8/1 /2003 8/31 /2003 17 2,151 127 1, 850 2,160 0 0 9/1/2003 9/30/2003 24 13,367 557 239 2,031 0 0 10/1 /2003 10/31 /2003 10 943 94 1, 565 1, 960 0 0 11 /1 /2003 11 /30/2003 5 459 92 1,305 1,661 0 0 12/1 /2003 12/31 /2003 7 576 82 1,245 1,578 0 0 1 /1 /2004 1 /31 /2004 8 491 61 1,103 1,391 0 0 2/1 /2004 2/29/2004 5 166 33 907 1,153 0 0 3/1 /2004 3/31 /2004 7 346 49 922 1, 525 0 0 4/1 /2004 4/30/2004 7 372 53 859 1,369 0 0 5/1 /2004 5/31 /2004 5 337 67 1,005 1,312 0 0 Total 48,805 • r~ ` ,.'- ,Disposal Injection Order 12~ ~ Page 1 of 2 "? _.__--- NOW, THEREFORE, IT IS ORDERED .THAT: Rule 1 Authorized I~ection Strata for Disposal. Class II oil field fluids may be injected in the Badami Unit WD-1 and WD-2 wells, in conformance with Alaska Administrative Code Title 20, Chapter 25, for the purpose of disposal into strata which correlates with the Ugnu-basal Sagavanirktok Formation intervals between 5926'-7720' MD and the mid-Sagavanirktok Formation between 4450'-5526' MD in the Badami #4 well. Disposal injection within the mid-Sagavanirktok Formation must be specifically approved by the Commission, and may be further conditioned by administrative action after review of injection performance in the Ugnu-basal Sagavanirktok Formation. Rule 2 Demonstration of Tubing/Casing Annulus Mechanical Integrity The tubing/casing annulus must be tested every two years for mechanical integrity in accordance with 20 AAC 25.412. Rule 3 Well Integrity Failure Whenever disposal rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action and obtain Commission approval to continue injection. Rule 4 Surveillance A baseline temperature survey from surface to total depth, initial step rate test to pressures equal or exceeding maximum injection pressure and pressure falloff are required prior to initiation of disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the Commission. Operating parameters including disposal rate, .disposal pressure, annuli pressures and volume of solids pumped must be monitored and reported according to requirements of 20 AAC 25.432. An annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth if any and updates of operational plans. Report submission will be on or about July 1. Rule 5 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. DONE at Anchorage, Alaska and dated August 5, 1997. David W. Johnston, Chairman Robert. N. Christenson, P.E., Commissioner http://www.aogcc.alaska.gov/orders/dio/diol2.htm 7/13/2004 X13 b ~ ~ p BP Exploration (Alaska) Ina 900 East Benson Boulevard P.O. Box 196612 By Facsimile Anchorage, Alaska 99519-6612 (907) 561-5111 July 2, 2003 Ms. Sarah Palin Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501-3192 Badami Class I Infection Well Disposal Injection Order No. 12 Dear Ms. Palin: BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following annual performance report for the Badami Class I well. This submittal meets the reporting requirement in Rule 4 of Disposal Injection Order 12.001. The reporting period for this annual performance report is July 1, 2002 through June 30, 2003. Attached is monthly injection rate and performance data. No surveillance logs were run during the reporting period. A water flow log and temperature log were run on March 28 and 29, 2002. Copies of the logs and a descriptive report were transmitted to the Commission on May 1, 2002. The surveillance logs confirmed that there is no movement of fluids in vertical channels adjacent to the wellbore and that the confining zone is not fractured. Based on the surveillance log results and the low injection pressures and rates in the Badami 1-01 well, BP believes there is minimum fracture growth within the disposal interval. A Mechanical Integrity Test (MIT) was run on March 13, 2003. The mechanical integrity of the B1-01 well was demonstrated and no communication to the tubing or outer annulus was evident. A copy of the MIT report is attached for your convenience. The fill depth was not determined during the reporting period. Ms. Sarah Palin July 2, 2003 Page 2 Based on a cumulative injection volume of 728,041 barrels into well Badami 1-01, it is estimated that the fluids occupy a total volume of 15.14 million cubic feet within the disposal interval. This is equivalent to a radius of 468 ft around the wellbore. The Badami Field is preparing to go into a warm shutdown. The injection volumes in the Badami 1-01 well will therefore be decreasing in the future. If you have any questions, please contact me at (907) 564-5501 or Ms. Alison Cooke of my staff at (907) 564-4838. Sincerely, 'V . . Ja et D. Platt, Environmental Manager E Alaska JDP/ADC Attachments cc: Jim Regg, AOGCC "'"' '""' "' ~"'"' "~~~ JV/ UJy 1LUJ 1J1 A[1 llt1Lr11111 ~/. UUL E PA U~ ~~ E~~ ~.~~~ ~~,, W eelllnyton DC 20460 Injection Well Monitoring Report Year ~ Month Month Month Injection Pressure (PSI) Ma June Jul 1. Minimum 554 566 783 2. Average 15i 0 2011 2069 3. Maximum 1860 2133 2264 Injection Rate (GaUMin) 1. Minimum 27 22 26.1 2. Average 153.4 153.9 152.3 3. Maximum 159.5 170.8 183.6 Annular Pressure (PSI) 1. Minimum 0 0 0 2. Average 0 0 0 3. Maximum 0 0 ~ 0 Injection Volume (Bbls) 1. Monthly Total as of 943 11005 8967 2. Yearly Culmative 676,270 687,275 696,242 Temperature (F) 1. Minimum 2. Average 3. Maximum pH 1. Minimum 2. Average 3. Maximum Other Natne and of PermIKN Pemdt NYmbef Nana and Oplclaf Tige (Plesae type of pyM) r ~~ ~ ~ slpMtun Date 8lpned O.L U r 1 EPA Ungeo Slates £nvuomenlal ProtecAOn Agency wash~ngton DC 20460 Injection Well Monitoring Report Year ZD Month Month Month Injection Pressure (PSI) U SE UGtp g 1. Minimum ~ Jra b s~7 2. Average sy ~~6 ~-75a 3. Maximum a1S{o ~ ~ alO~/ Injection Hate (Gal/Min) t. Minimum 3 ~S', 2. Average a , a ~S ~S-~ 3. Maximum ~~0. ,~ ~ ~~-~~ a Annular Pressure (PSI) 1. Minimum ~ 0 O 2. Average Q 3. Maximum (~j Injection Volume (Bbls) 1. Monthly Total as of 71.3/02 2,~j~75~ 3~- ~g7 2. Yearly Culmative ~Oy~ ~+-f a (og9f/7 7~ /Lj 7~ X31 Temperature (F) 1. Minimum 2. Average 3. Maximum pH 1. Minimum 2. Average 3. Maximum Other Name and Address of Permntee Permit Number Name and Official Titte (Please type or print] Signature Date Signed _` 99 Form Approved OMB No. 21140-0042 United States Environmental ProteMion Agency ~-EPA Washington, OC 20460 Injection Well Monitoring Report Year L~'~ Month Month Month Injection Pressure (PSI) ~ ~ 2~ ZQV t. Minimum ~ 75 ~~b ~ ~ S 2. Average ~ l 7 ~J 3. Maximum ~ i 2 2 ~ Z ~ Z(~ Injection Rate (GallMin) 1. Minimum 2 S 8 2~ i v 2 ~ S 2. Average 37, /' l7 f r ~ q ) 15 o, J 3. Maximum J ~~ g t ~ ~ ~ s, 7 v) ~ t7 / ~ Annular Pressure (PSI) 1. Minimum 2. Average ~ ~ g 3. Maximum ~ ~/ ,~ Injection Volume~,e1~ C~C~~ t. Monthly Total ~ (]/~(/O ~ / 3 ~ Z 6 ? 2. Yearly Cumulative X03 3 ~ 5 p ~} G 31 706 p y~ '0 `t3 Temperature (F °) 1. Minimum 2. Average 3. Maximum pN 1. Minimum 2. Average 3. Maximum Other Name and Address of Permittee Permit Number Name and Official Title (Please type or print) ~1~,r 1 Aol ornPJ~ ~e (riYt, - SO Signature .~a~..~~,,,t~/G- ~ Oate Signed 2 -3-- 03 EPA Form 7520-8 (Rev. 9-91) EPA United States Enviromental Protection Agency Washington DC 20460 Injection Well Monitoring Report Year pO3 Month Month Month Injection Pressure (PSI) 1. Minimum ~ v 2. Average 1 / 6 ~ 3. Maximum i` ~ ~ 2'vS~l Injection Rate (Gal/Min) 1. Minimum 2>> 3 6 2. Average i 2 v = S ~° ~ 3. Maximum 162,1 1 1 2 i 6ti. 3 Annular Pressure (PSI) Minimum 1 ~ . Average 2 Q' . 3. Maximum Injection Volume (Bbls) Monthly Total as of 1 I/~~~~~~~ . 2. Yearly Culmative ~7U~,0~ 3 U` . ~ 7/U _ ~ erature (F) Tem p Minimum 1 . e Avera 2 g . 3. Maximum H p Minimum 1 . Average 2 . 3. Maximum Other Name and Address of Permittee Permit Number Name and Official Title (Please type or print) .1'~Il lthnl-~-,r~_.a J/,°.VCI:..n~_ne-r?~,~ " 1J1_~~) Signature ! r f~'i/ ~ ~-._.. Date Signed J /~I (i~~ State of Alaska Run Date: 06/05/2003 Alaska Oil and Gas Conservation Commission Run Time: 14:32:00 Monthly Injection Report 20 AAC 25.432 BP Exploration (Alaska) Inc. Badami Badami Tubing Pressure Casing Pressure Well API T Field M Days Max Average Max Average Name Number Y & E in PSIG PSIG PSIG PSIG 50- P E Pool Code T H Oper. B1-01 0292279900 5 060036 9 14 2,123.00 0.00 0.00 0.00 060036 Pool Injection Totais ...... ........... ..... 61-14 0292287400 4 060100 7 31 4,436.80 4,345.30 0.00 0.00 B1-21 0292280900 4 060100 7 31 4,358.50 4,294.70 0.00 0.00 060100 Pool Injection Totals ...... ........... ..... 61 Gathering Center Totals ........ .......... ..................... ... Field Injection Total ................................................................................ Page 1 May, 2003 Daily Average Injection Total Monthly Injection Liquid Gas Liquid Gas BBL MCF BBL MCF 209 0 2,934 0 2,934 0 0 6,561 0 203, 0 12,024 0 372, 0 576,178 2,934 576,178 2,934 576,178 • Form 10-406 • ~~ z z J ~ Z ~ ~ H 0 ~ O H o gw ~ U J ~ 0 .-. Z ~ ~ aD M M C 0 r CJ m t'r+ N Q F"' J `'~ ~ rl N ~ ~.," N "~ ~ J T~ z r z ~ a z ~o ~>~ U Q } ~ OJ z C~ Z rom o ~ O ~ ~ ~ ~ ~ Z O a ~ J Q i~ 0 ~ a W ~ V N ~ W U ~ Z ~ ~ A C ~' a a ~ G Z a J ~. _ ~ Z Q i N O J ~~ Q U z w ~ ¢ c7 o T ~~ O a C7 Z O a'~a U 0 a ~ ~ W a~ ~ cII ~ ~W~ N ~ ~ ~ ~ a ll: ~ ? ~ ~ 00 Q~ m ~ ~ d N co Q Z O I ~ ui aOH13W I O1 ~Wao 0 tLL. ~ U ~p ai 3dJll I ~ O m ~ ~ C~ ~2 ~ N `~ ~ Q~ ~ ~ z o ~ N d d Q a o .., p ~ ~ J r.{ ~ ~ >> T 7 Z ~Q z a~ m U Q 7 C 7 m 0 v N 0 a a~ 0 E 0 n c ~ ~ ~U ~ ~C ~ ~ O U F m C ~ ~ U v ; ~ 2 .~ o ~ C y O ~ 'o O m '~ N O LL ~ . _ ~ ~ . -~ t C ~ ~ O a ~ cD U "Cf T. ~ N ~ r ~- C m E ~ rn ~, _ in Z00 ~j I3QVQHH ~'%dg 69ZT 659 LO6 XV~ 80 ~ ET EO/TO/LO THE "/ 5000 psi ! CIW WELLHE ~/8"/ 10000 psi /FMC B1-01 Curtain Str 7", L80, Bl 2088 13-3/8" 68#/f L-80, BTC. 4919 4 1: HES X Nipple 2112 ID (3.813") HES BWD Permanent Packer 7941 Seal Assembly 7854 I Deviation ~ Perforation Date I 8-19-98 7 E HES BWD 8055 Permanent Packer HES X Nipple 8065 ID (3.813") HES XN Nipple " 8085 ID (3.725 ) WLEG 8096 ELMD 8096 XN Nipple Min ID (2.205") 8379 WLEG 8383 9 5/8" N-80 BTC 47 #/ft Casing TD 8612 sing Shoe 8703 DATE REV. BY COMMENTS gADAMI WELL B1-01 4-9-99 JTP U date Information PERMIT # 97-157 4-6-01 jde Corrected Informati API # 50-029-22799 BP EXPLORATION, INC. • • Well Operations Report BADAMI, ALASKA To: Dan Robertson /Jim Ambrose /Mark Weggeland From: Jeff Eckstein /Rick Brenegan /Bart DeGraffenreid /Matthew Fort Well Name: B1-01 Operation: Mechanical Integrity Test Operation Date: 3/13/03 Cost Code: BAWWEL000 81-01 Mechanical Integrity Test Operations Summary Pre-job meeting and hazard assessment attended by Little Red Services crew (Craig Ramm and Jerry Webre), EPA representative (Talib Syed), Badami operations (Jeff Eckstein, Bart DeGraffenreid, Matthew Fort, Rick Brenegan, Larry Thompson, Shawn Miller) and ACS technician (Alex Reyes). AOGCC inspector (John Crisp) waived the opportunity to witness. Rig up Little Red Services; pressure test lines to 4,000 psi. Shut down glycol pump and isolate circulation system. Pump inner annulus pressure up to 3,500 psi in stages. IAP decreased 75 psi during 30-minute test (allowable is 5% of 3,500 psi = 175 psi). No communication to the tubing or the outer annulus was evident -Passed MIT. Flow diesel out of the annulus back to pump truck, rig down Little Red Services and return well to normal operations. Initial well status: SIWHP = 1150 psi IAP = 0 psi OAP = 0 psi 1530 Pre-job meeting and hazard assessment. 1900 Rig up Little Red Services to the inner annulus. 1900 Shut down glycol boiler and pump and block in circulation system. 1953 PT lines with diesel to 4,000 psi. 1955 Open up to inner annulus. SIWHP = 1150 psi, IAP = 0 psi, OAP = 0 psi. 1957 Pressure IA to 500 psi with diesel, 0.7 bbls away. 2001 Pressure IA to 1,000 psi with diesel, 1.1 bbls away. 2006 Pressure IA to 2,000 psi with diesel, 2.4 bbls away. 2012 Pressure to to 3,500 psi with diesel, 4.3 bbls away. 2017 05 minutes: SIWHP = 1175 psi, IAP = 3485 psi, OAP = 0 psi. 2022 10 minutes: SIWHP = 1170 psi, IAP = 3470 psi, OAP = 0 psi. 2027 15 minutes: SIWHP = 1165 psi, IAP = 3450 psi, OAP = 0 psi. 2032 20 minutes: SIWHP = 1160 psi, IAP = 3440 psi, OAP = 0 psi. 2037 25 minutes: SIWHP = 1155 psi, IAP = 3425 psi, OAP = 0 psi. 2042 30 minutes: SIWHP = 1150 psi, IAP = 3425 psi, OAP = 0 psi. 2045 Bleed back 4.3 barrels of diesel from inner annulus. 2055 Rig down Little Red Services and return to normal (resume glycol circulation). Final well status: SIWHP = 1150 psi IAP = 0 psi OAP = 0 psi Test Gauge: 0 - 5,000-psi test gauge calibrated on 3/25/02 #12 bp ) ) April 18, 2003 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P,O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 By Facsimile Ms. Sarah Palin Alaska Oil & Gas Conservation Commission 333 W. 7th Ave., Ste.100 Anchorage, Alaska 99501 Request for Administrative Amendment Dear Ms. Palin: BP Exploration (Alaska) Inc. (BPXA) requests an administrative amendment of Disposal . Injection Order No. 12. During a third party environmental audit by Residual Management Technology (RMT) Inc. The auditors made the following observation at Badami: Badami, Disposal Injection Order No, 12, Rule 4, Surveillance Badami currently conducts an annual fill depth tag in conjunction with e-line survey work. The schedule for future e-1Ïne survey work at Badami is now extended to once every two years. Badami will need an AOGCC waiver from the annual requirement Disposal Injection Order No. 12, Rule 4 states, '"Regular fill depth tags are required at least once· annually or as warranted following consultation with the Commission." On March 18, 2002, the Environmental Protection Agency modified the surveillance logging requirements in the Badami Class I Well Permit No. AK-1-I001-A. The new requirement states that, "fluid movement tests are required annually during drilling operations and every other year after drilling operations have been concluded." In order to make the permit requirenlents consistent, BPXA requests that the Alaska Oil and Gas Conservation Commission amend the requirement in DIO No 12, Rule 4 for a fill depth tag to annually during drilling operations and every other year after drilling operations have been concluded. RECEIVED APR 2 I 2003 Alaska Oil & Gas Cons. Commission Anchorage SCANNEr:,; JUN 3 0 2004· Ms. Sarah Palin April 18, 2003 Page 2 ) ) If you have any questions, please contact Alison Cooke of my staff at (907) 564-4838 or me at (907) 564-5501. Sincerely, .IfMdOfM I CC: James Regg SC~?\J'J;\~F¡'- JlJNI ~ [,I 200 I) . h, C ".~ --" , I' .:}~) "I "J #11 I ) ) DIÛ #/;:2 TONY KNOWLES, GOVERNOR ALASIiA. OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 June 15, 1998 Mr. David A. Wallace HSE Business Manager BP Exploration (Alaska) Inc. P,O. Box 196612 Anchorage AK 99519-6612 Re: Clarification of Third Party Audit Finding concerning Disposal Injection Order (DIO) # 12 Dear Mr, Wallace: You have requested our recommendation \vhethcr modification of Disposal Injection Order # 12 (010 # 12) for Class II underground injection in the Badami Unit wells WD-l and WD-2 is necessary in order to recognize the EP A authorization to operate these wells under the Class I Underground Injection permit. BP Exploration (Alaska) Inc, (BPXA) requested Commission approval for Class II injection permits for these \veIls and concurrently sought approval for Class I injection permits from the V.S, Environmental Protection Agency (EP A). BPX is currently operating these wells under the authority of EP A's Class I injection permit which allows disposal of Class II fluids. DIO #12 only addresses BPX's request to inject Class II fluids under the Commission's authority to issue Class II UIC permits, Therefore, DIO #12 can only authorize the disposal of Class II fluids. 010 # 12 does not limit BPX's authorization to inject according to the terms of a valid Class I underground injection permit issued by the EP A. In closing, \ve do not believe any modification is necessary to 010 # 12 in order to operate these wells under the current Class I penllit issued by EP A. ----.... David W. Joh~ton Chairman ~ cc, Jonathan Williams, EP A, Region 10 Rob Mintz - Department of La\\" ~í ìÌ\1 Ó\ f\ 2DD¿~ . 'If " f\t.r,~·....\F\\·· ',: J¡' ,. - \.~"J":...rI~ ',,':"<.L \,,~r'o.,..' #10 ') ) BP EXPLORATION BP Exploration (Alaska) Inc, 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 ¡£ (907) 561-5111 COMM - . " COMM ,COMM (Ä) R~S EN.~"",_<~. 'SRENG. ~ NRO -............ ~l . . SR. GËõt-lI~4- fGËf1~A~/~·)frr" i ~:'~-~~~~~":!' . ~ ~·ST...Ál rEChl ':--' i. ~ .V_o\t,,,'I'r~'~"" ,,,,,,.,,,,,,, f Sl ¢" 'r Tt·¡"H) ~~~:""~~~~~.....,~-" ! .' r---t--1 - ""-~'''_-1E' .'--' '" ' _ By Facsimile March 30, 1998 Mr. David Johnston Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: Clarification of Third Party Audit Finding Concerning Disposal Injection Order No. 12 Badami Unit Wells WD-l and WD-2 ~... ,_...I,~, Dear Mr. Johnston: As you are aware, BP Exploration (Alaska) Inc. (BPXA) is in the process of responding to issues raised during a third party environmental management audit by Arthur D. Little, Inc. On March 20, 1998, Alison Cooke of my staff met with you to discuss certain preliminary findings relating to underground injection at Badami. At your suggestion, we are providing the following information to summarize the audit findings. The auditors made the following comment about Badami: Well Disposal Authorization (Good Management Practice) The injection facility is regulated by the EP A, the Alaska Department of Environmental Conservation (ADEC), and the Alaska Oil and Gas Conservation Commission (AOGCC). The injection facility is used for disposing Class I and Class II non-hazardous wastes. The Badami Unit obtained permits from the EP A and ADEC permitting the disposal of Class I and Class II wastes, and a Disposal Injection Order No. 12 from the AOGCC for the operation of the injection facility for Class II wastes. The Oil and Gas Conservation Commission Disposal Injection Order No. 12, however, has not been modified nor does the Badami Unit have documentation supporting that the injection facility is authorized to dispose Class I oil field wastes. [Good Management Practice related to 20 AAC 25.252(a) and AOGCC, Disposal Injection Order No. 12, Conclusion 3]. As we explained to the auditors, Class I disposal is clearly authorized by the EP A permit. BPXA also recognizes that the Commission can only authorize injection for Class II wells in their Orders. Copies of the Class I Underground Injection Control (UIC) permit are kept on site at Badami. RECEIVED tlPr{ G2 199~C./~:~~\~¡\~E['; JUN ~~ 0200¿1 Alaska Oil & Gas Cons. Commission AnrI1nr;Jnp. · !. M,~, David Johnston I . l\i¡~lCh 30, 1998 , Page 2 ') ') BPXA applied for the Class II Disposal Injection Order as a backup to the Class I permit. Without this backup, any delays or problems with the Class I permit application would have left BPXA without a viable option for disposal of drilling wastes at Badami. We believe that AOGCC understood that Class II disposal would only be required as a contingency. AOGCC issued Disposal Injection Order No. 12 without a specific expiration date, and did not rescind it when the Class I permit was finally approved. This means that the notification and reporting requirements of the Injection Order are still in effect. However, AOGCC has agreed that copies of the Class IIEP A reports would satisfy the reporting and notification requirements of the Disposal Injection Order. Since the Class I permit is both broader in scope (wastes approved for disposal in a Class II well can be accepted) and more stringent than the Class II Disposal Injection Order, it is considered the primary authorization for underground disposal. We would appreciate your recommendations whether modification of the Disposal Injection Order should occur to recognize other permitted authorities, such as the EP A Class I DIC permit. We request a written response at your earliest convenience so that we may bring this particular issue to closure. If you have any questions, please contact Ms. Janet Platt at (907) 564-5501. D id A Wallace SE Business Manager cc: EPA, Region 10 RECEIVFn Ann r" 1C9f\ h ¡o L\. V .c.... ...1 0 Alaska Oil & Gas Con~: ,., Inml,;U)ft Anchoraÿt #9 J _ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive - Anchorage, Alaska 99501-3192 Re: THE REQUEST OF STANDARD ) ALASKA PRODUCTION COMPANY ) for an Area Injection Order) for that portion of the ) Prudhoe Bay Unit commonly ) known as the Western ) Operating Area ) including the contiguous ) K Pad Area. - ) Area Injection Order N~~ 3 Western Operating Area including the K Pad Area Prudhoe Bay Unit Prudhoe Bay Field July 11, 1986 IT APPEARING THAT: 1. Standard Alaska Production Company.(SAPC) requested the Alaska Oil and Gas Conservation Commission to issue an Area Injection Order permitting the underground injection of fluids within the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for the purposes of enhanced recovery and the disposal of non-hazardous oil field waste fluids. 2. Notice of an opportunity for a public hearing on June 25, 1986, was published in the Anchorage~Times on May 22, 1986. 3. Neither a protest nor a request for a public hearing was timely filed. Accordingly, the Commission will, in its discretion, issue an order without a public hearing. FIND INGS : 1. An order permitting the underground injection of non-hazardous fluids on an area basis, rather than for each injection well individually, provides for effi- ciencies in the administration and surveillance of underground fluid injection operations. 20 AAC 25.460 provides the Commission with the authority to issue an order governing underground injection operations on an area basis. 2. The Western Operating Area and the contiguous K )'~d Area constitute a compact "project areau for the operat¡ion of a portion of the Prudhoe Bay Unit and can readily þe described by governmental subdivisions. The Proje~t Area is operated by a single operator. ' SCtÜ\H~ED JUN 3 0 20D4 ,~ ) Area Injection Oraer No. 3 Page 2 ( July 11, 1986 10. 3 . The Project Area encompasses approximately the western one-half of the Prudhoe Oil Pool. The Project Area includes all existing injection wells and injection well· sites planned for enhanced recovery from this portion~of the Prudhoe Oil Pool. The Project Area includes all existing injection wells and injection well sites planned for disposal by injection into Cretaceous and Tertiary strata of oil field waste fluids developed from the operation of this portion of the Prudhoe Bay Unit. 4. Those portions of aquifers described by a 1/4 mile area beyond and lying directly below the Project Area are exempted for Class II injection activities by Aquifer Exemption Order No.1. 5 . · Less stringent requirements for well construction, operation, monitoring and reporting of injection op- erations may be more appropriate than would be required when injection occurs into, through or above portions of aquifers not exempted. 6. The vertical limits of injection strata and the confining formations may be defined in the ARGO Alaska Inc. '-(Atlantic Richfield-Humb Ie) Prudhoe Bay, State Well No. 1 and the SAFC Prudhoe Bay Unit Well No. C-11. 7 . The strata into which fluids are to be inJ· ected will :il 11?1'\0 I {\}J..llu . accept fluids at injection pressures which are less than ~ the fracture pressure of the inj ection strata and their 1f-' conf;~;~a £nrm~rions. '-/I 8. Statewide regulations and conservation orders govern field operations except as modified by this order. 9. To ensure that fluids injected are confined to injection strata, the mechanical integrity of an injection well should be demonstrated periodically and monitored rou- tinely for disclosure of possible~abnormalities in opera ting condi tions . .. . .Injection wells existing on the date of this order were constructed and completed in accordance with regulations which conform to the requirement of 20 AAC 25.412. rer-;, i1\.n.IE-I¡-'" Jl ~ 0 ·0i\:,.1il~l6~H'\.J!;; IN· -~ 'I 200" ~ !,j L,. ,. .,~.' 71. ~ '0 "I.>- _ " ....i ) / (' Area Injection Oraer No. 3 Page 3 July 11, 1986 NOW, THEREFORE, IT IS ORDERED THAT the rules hereinafter set forth govern Class II underground injection operations in the following described area referred to in this order as the affect- ed area: ~ UMIAT MERID IAN T12N RIOE T12N RIlE T12N R12E Sections 13 and 24 Sections 9 , 10, 11, 12, 13, 14, IS , 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 32, 33, 34, 35 and 36. Sections 7, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, ,28, 29, 30, 31, 32, 33, 34, 35 and 36. T12N R13E Sections 19, 20, 21, 22, 23, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35 and 36. T12N R14E Sections 27, 28, 29, 31, 32, 33, and 34. T11N RIlE Sections 1 , 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 24, an d 25. TI1N R12E Entire Township TIIN R13E Entire Township TIIN R14E Sections 3, 4, 5, 6 , 7, 8, 17, 18, 19, 20, 29, 30, 31 and 32. TI0N R12E Sections 1, 2, 3, 4, 10, 11 and 12. TION RI3E Sections 1, 2, 3, 4, 5 , 6, 7, 8, 9, 10, 11, 12, 13'; 14, 15, 16 and 24. T10N R14E Sectiop.s 5, 6, 7, 8, 17, 18, 19 and 20. Rule 1 Authorized Injection Strata for Enhanced Recovery Within the affected area, non-hazardous fluids may be injected for purposes of pressure maintenance and enhanced oil recovery into strâta defined as those strata which correlate with the strata found in ARCO Alaska Inc. (Atlantic Richfield-Humble) Prudhoe Bay State Well No. 1 between the measured depths ·óf 8110 feet and 8680 feet. . SC/\NN" . ET" p ¡~¡ '.:~ ,In 200'~ ..' ..,¡ r.; " ~ll~ \",.1 tS' ð\i ~'.': ,~;" , ....f ,~ ) ./) - Area Injection Oraer No. 3 Page 4 July 11, 1986 Rule 2 Authorized Injection Strata for Disposal Within the affected area, non-hazardous oil field fluids may be injected for the purpose of fluid disposal into strata defin~d as those strata which correlate with the strata found in SAFC's Prudhoe Bay Unit Well No. C-l1 between the measured depths of 3990 feet and 6293 feet. Rule 3 Fluid Injection Wells The underground injection of fluids must be: 1) through a new well that has béen permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; 2) through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280; or 3) through a well that existed as a service well for injection purposes on the date of this order. Pumping of excess non-hazardous fluids that are developed solely from well op- erations, or necess-ary to control the fluid level of reserve pits, into surface/production casing annuli is exempted from the above requirements. Rule 4 Monitoring The Tubing/Casing Annulus Pressures The tubing/casing annulus pressure of each injection well must be checked weekly as a routine duty to ensure there is no leakage and that it does not exceed a pressure that ·will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 5 Reporting the Tubing/Casing Annulus Pressure Variations Tubing/casing annulus pressure variations between consecutive observations need not be reported to the Commission. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission - which ensures that the tubing/casing annulus for each injection well is pressure tested prior to initiating injection and at least once every four years thereafter. A test surface pressure of ~500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, which ever is greater, must be held for 30 minutes with no more than a 10 percent decline. The Commission must be notified at least 24 hours in advance to enable. a representative to witness pressure tests. SCAhH\~EL.' ~)!UN ~ C) 200~ ') Area Injection Oraer No.3 Page 5 July 11, 1986 Rule 7 Well Integrity Failure Whenever operating pressure observances or pressure tests indi- cate pressure communication or leakage of any casing, tubing ,ðr packer, the operator must immediately cease injection, notify the Commission, and obtain approval for corrective action. Rule 8 Plugging and Abandonment of Fluid Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accor- dance with 20 AAC 25.105. Rule 9 Administrative Relief ,Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Com- mission's- satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of' fluid movement into an undergro~nd source of drinking water~ DONE at Anchorage, Alaska and dated July 11, 1986. rØjþ!.. Ol.t~ ~r¿, .~-ò ;if_~ '~t'-' ~..,.:,..,., r @"t'.~ ~ "' .....'!!';L:,\ -. ~~.".;' . "~, o . __ I _ \ftr1. ,\,.-:~ o ~--'~'1IM':Z ...¡.,. --::-:::3' ~, : , ' < 0 ~ --:--- ~' ~ ~,¥~~l!J. ,~ ~?-lON co../iiY (}1a~ C. V. Chatterton, C airman Alaska Oil and Gas Conservation Commission it: , /()~ . ........_-~ C'/ onnie C. Sm t, Commissioner Alaska Oil and Gas Conservation Commission ~·tJ- ~ ~ William W. Barnwell Commissioner Alaska Oil and Gas Conservation Commission ~ . . .; :jCI1NNE[i ·n ~N~ c~; f'l 20" '1 '- "~.. f.:¡1 ~,,; ., U¿, ) ( August 15, 1986 Telecopy No. (90ì) 276-7542 ADM I N I S T RAT I V E A P PRO V A L N O. AIO 3.1 Re: Reauest b~ Standard Alaska Production Company to Modify RuÍe 2 of Area Injection Order No.3 Mr. J. P. Lucido, Manager Environmental and Regulatory Affairs Standard Alaska Production Company P. O. Box 196612 . Anchorage, AK 99519-6612 Dear Mr. Luëido: By letter dated August 6, 1986, Standard Alaska Production Company has requested that Rule 2 of the subject area injection order be modified to allow injection of non-hazardous oil field fluids into those strata which correlate with the strata found in the SAFC Prudhoe Bay Unit No. C-11 between 34161 and 6293' ~ID. This request is precipitated by a need to improve injection capabilities in the PBU GC-2A and GC-2B produced water disposal wells. The Alaska Oil and Gas Conservation Commission has reviewed the data available and agrees that injection of non-hazardous oil field fluids into strata correlative with the above depths will not result in an increa5ed risk o£ fluid movement into an underground source of drinking water. Accordingly, pursuant to Rule 9 of Area Injection Order No.3, Rule 2 of said area injection order is ~ended to read: Rule 2 Authorized Inj ection S'trata for Dis-posal \. Within the affected area, non-hazardous oil field fluids may be injected for the purpose of fluid disposal into strata defined as those strata which correlate with the strata found in SAFC's Prudhoe Bay Unit Well No. C-l1 between the measure4 depths of 3416 feet and 6293 feet. Y~r~ tru~7 yours, ~?~______ ¿// &1/ ¡2-"~J~ w. w. Ba~well Con:n:nissioner BY ORDER OF THE CO~IISSION jo:3.AA AID 3 8C!U'~lNF~!;, P }1\1 Q) fì 200 ~ "" ,-. u ,~" J'¡; (:.'1 U '. "';f .~ ) '- ::''':':'::; ,:c:;;.~ .' . . .....~:- '..... -, \. .Telecopy No. . . (907) 276-7542 October 27, 1986 ADM I N I S T RAT I V E A P PRO V A L N O. AID 3.2 . Re: Amend Rule 7 of Area Injection Order (AIC) No.3 Mr. J.P. Lucido, Manager Environmental & Regulatory Affairs Standard·Alaska Production Company P. O. Box 196612 Anchorage, AK 99519-6612 Dear Hr. Lucido: The Commission has determined that Rule 7 of AlO No. 3 as set forth is unclear as to the Commission's intent. Therefore, Rule 7 is amended to read: Rule 7 Well Integrity Failure Whenever operating pressure observations or pressure tests indicate'pressure communication or leakage of any casing, tubing or packer, the operator must [IMMEDIATELY CEASE INJECTION,] notify the Commission on the firs~ working day following the observation, [AND] obtain Commission approval [FOR CORRECTIVE ACTION] of a plan for corrective action, and when an USDW is not endan~ered, obtain Commission approval to continue injection. Sinceret;;J , /1.,'., ,-¡ t/r ,/' . . Q. 7J hé/ff;!: C. V. Chatterton Chairman jo/3.AA AID 3.2 SC/\~\tNErj ,JUN ~ Ü .200,']. ) ) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: The APPLICATION OF BP Exploration (Alaska) Inc. (BPX) for disposal of Class II oil field wastes by underground injection in the Badami Unit wells WD-l and WD-2, ) Disposal Injection Order No. 12 ) ) ) ) ) Badami Unit Wells WD-l, WD-2 Badami Unit August 5, 1997 IT APPEARING THAT: 1. By correspondence dated May 22, 1997, BPX requested authorization from the Alaska Oil and Gas Conservation Commission (AOGCC) to inject Class II waste fluids into the Badami Unit WD-l and WD-2 weIls, 2, The AGGCC requested additional information June 11, 1997. BPX provided the requested information on June 18, 1997. 3. Notice of opportunity for public hearing was published in the Anchorage Daily News on May 30, 1997. 4. The Commission did not receive a protest or a request for a public hearing. FINDINGS: 1. BPX is the operator of the Badami Unit. There are no other operators within a one- quarter mile radius of the proposed disposal injection project. 2, The State of Alaska is the only surface owner within the Badami Unit. ~ 3. The Badami Unit WD-l disposal well (WD-]) will be the first weIl drilled from the unit's single development pad. BPX does not propose to drill any other well within a one-quarter mile radius of the WD-l penetration of the disposal injection zones, 4. BPX may driIl an additional disposal well designated WD-2. BPX does not propose to drill any other well within a one-quarter mile radius of the WD-2 penetration of the disposal injection confining zones. ,.fUN ¿!. G 20Q,q. ) ') Disposal Injection Order No. 12 ..\ ugust S. 1997 Page 2 ). Logs fron1 the Badami No.4 exploratory well may be used to detine the disposal and coníìning zones in the Badami Unit. 6. BPX proposes to conduct disposal operations in the Badami Unit \'vithin the Ugnu and Sagavanirktok Formations. 7, The Ugnu Formation consists of Eocene aged. predominately coarse grained. t1uvial and shallow marine sediments. The interval is present within the Badami No.4- \vell from 7440'-77'10' measured depth (MD). It has an average porosity of 27~/o~ an average penneability of 350 millidarcies and an average net to gross ratio of 500/0. 8. The Sagavanirktok Formation includes a basal unit which consists of Eocene to Oligocene aged. predominately fine grained marine sediments. The interval is present within the Badami No.4 well from 5526'-7440'-MD. 9, .-\ regionally extensive. dominantly shale interval \vithin the basal Sagavanirktok Formation is present within the Badami No. -+ well from 5526'-5926' MD. This interval contains an aggregate thickness of shale in excess of 250', 10. The basal Sagavanirktok Formation also contains numerous intervals of laterally extensive sandstones. The log character of these sands is similar to those \vhich have demonstrated a large capacity to accept disposal fluids in other North Slope Fields. 11. \10st of the Class II disposal fluids from other North Slope Fields has been confined by similar lithologic and stratigraphic intervals as those present within the U gnu and basal Sagavanirktok Formations underlying the Badami Unit. 12. Overlying the basal Sagavanirktok Formation. between 4450'-5526' MD interval in the Badami No. -+ well. is an interval of approximately 65 percent highly porous and permeable. laterally continuous. t1uvial to shallo\\: Il1arine sandstones. 13. A predominately mudstone interval exists between 3892'-4450' MD within the Badami No. -+ well. It is considered the shallowest potential contìning zone in the well. The gross lithologic character of this interval is persistent through the proposed \VD-l and WD-2 vicinity. 14. The 3892'-5526' MD interval in the Badami No. -+ is designated the middle member of the Sagavanirktok Formation for the purposes of this order. 15. BPX does not plan to inject t1uids within the middle member of the Sagavanirktok Formation unless injection in the U gnu -basal Sagavanirktok Formation interval is unsuccessful. 16. BPX \Nill run cement quality logs within the surface casing and long string of each well. The Commission will evaluate the logs and cement records to determine the adequacy of the cement to isolate disposal intervals. 8Cl\.NNEL) JUN 3 C 20D~· J) Disposal Injection Order No. 12 August 5. 1997 Page 3 1 7, Completion plans entail 20" conductor set at 110' subsea (SS). 13 3/8" surface casing set at ...../-4230' SS and cemented to surface and a long string of 9 5/8" casing set at +/-7500' SS and cemented back into the surface casing. 18. BPX will test tubing and casing integrity according to 20 AAC 25.412 prior to initiation of disposal operations and every two years thereafter. úV Disposal material will consist of Class II fluids generated from drilling. production. workover and completion operations. The typical disposal stream will consist of seawater. produced and fresh water. drilling mud. drill cuttings. workover t1uids. stimulation materials. vessel cleaning material. formation sand. cement and other nominal Class II waste. Constituent volumes will vary depending on drilling. workover. stimulation and maintenance activity. 20. BPX expects to dispose of approximately 12.500 cubic yards (60.100 barrels) of solids during the life of the project. 21. A v.erage disposal rate will be nominally 3000 BPD (~2 BPM) during development drilling and at other peak periods. The operator expects to average 300 to 500 BPD over the project life. Maximum instantaneous disposal rate is anticipated to be about 5 BPM. 22. Maximun1 operating pressure will vary depending on depth and the condition of the fon11ation. Surface pressure is expected to range from 1800~3300 psi when disposing in the U gnu-basal Sagavanirktok interval. with a corresponding bottom hole pressure (BHP) of 4950-6450 psi. In the mid-Sagavanirktok disposal intervals. estimated surface pressures will be l300~2800 psi and estimated BHP 3500-4900 pSI. 23. BPX expects to maintain injectivity by occasionally stimulating the disposal interval. Stimulation activity will entail pumping solid free tluid to disperse solids. chemical treatments and elevating pressure to breakdown the disposal interval. 24. Fracture propagation within the disposal interval is an integral part of the process of placing \vaste tluids into the disposal interval. Fractures will be created as the disposal zone begins to plug. Fractures or disaggregation of the clogged pores and rock matrix provide pathways to transport waste t1uids to undamaged" storage volume within the disposal zone. 25. Estimates of likely vertical gro\\1h of fractures in the upper disposal interval is approximately 250'. based on rate and volume estimates. 26. Periodic surveillance of disposal operations will ensure waste tluids are contained \vithin the disposal interval. Surveillance methods include temperature surveys. pressure transient tests. step rate tests. thermal decay time logs. disþersal rate and pressure monitoring, mechanical integrity tests and tagging effective depth to determine till buildup. SC./\!\!NEt:>ì ,.HJr.ì ~ n fOD/] ) ) Disposal Injection Order 1'io. 12 August 5. 1997 Page 4 27, Reservoir sur\"eillance techniques will also be used for tracking near well bore t1uid movement. estimating dimensions of disposal fracture or disposal storage volume and detecting changes in disposal zone characteristics. 28. Evaluation ot operation performance and reservoir surveillance \\"ill aid in preventing fracturing of the confining zones. 29. BPX calculated formation t1uid dissolved solid content from existing well control within the Badami Unit through analysis of geophysical logs calibrated to a single water sample from 4982' ]\1D in the Badami No.5 well. Calcùlated salinity of formation waters ranged from 18~000 mg/liter to 48.000 mgl1iter for formations between 2000' and 7.200' SS. 30. The U,S. En\"ironmental Protection Agency (EP A) determined aquifers with total dissolved solids of less than 10.000 mg/liter are not present \\'ithin the Badami Unit in either the L- gnu or the Sagavanirktok Formations. 31, In correspondence dated May 12. 1997. the EP A notiíìed BPX of its determination that no underground sources of drinking water (USDWs) \vere present in the Badami U nit. CONCLUSIONS: 1. The requirements of 20 AAC 25.252 have been met. 2. There are no CSDWs present underlying the Badami Unit. \yaste t1uids authorized for' disposal ~~d~r:t'þ'is .~'rd;~in the Badami Unit~~iLL consist exclusi\'elv of Class II waste generated from drilling:. completion. 'vvorkover 1'-."; ..'IP'WI" .- ....,~IIII "k.. ".'"""....... j""""I_III/f""'f~_"'III''''iI¡I...",........MIIIIWI¥Iw~'''''"'''_'......I\I ~'~",II'....'''''ISI<p,''"'\' - and production operations. CD~~ J, 4. Permeable strata which reasonably can be expected to contain the total volume of disposal fluids anticipated for this project are present in the U gnu - basal Sagavanirktok Formation in the Badami Unit. 5. Movement of \vaste fluids will be confined within appropriate receiving intervals by confining lithology, cement isolation of the wellbore and operating coõditions. 6. Periodic fracturing and stimulation will be required to place solids into the disposal interval. Fracture gro\\1h can be contained within the disposal interval by controlling the rate and \'olume of injection 7. Surveillance of disposal material movement. monitoring of operating parameters and demonstration of mechanical integrity every two years will ensure the materials are contained \\'ithin the disposal interval. Changes in baseline data may be an indication that t1uid is escaping beyond the designated contining zone. S··~!\U\~rf\UC~- 1'~Hi\~ '9! fì200¡;: ~,L"~j 'J~ 'JI¡,,;.L) ch;!\1 ('.ìì ~J ,4 ') Disposal Injection Order ~o. 12 August 5. 1997 Page 5 8. In the event disposal injection within the Ugnu - basal Sagavanirktok Formation interval is unsuccessful. alternative receiving and contining zones exist within the middle member of the Sagavanirktok Formation. which may serve as a secondary disposal zone. 9. ßadami Unit disposal \veils will be constructed and demonstrate· mechanical integrity in accordance \\lith the requirements of 20 AAC 25.412. 10. Disposal injection operations in the Badami Unit \vill not cause waste. jeopardize correlative rights. or impair ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT: Rule 1 Authorized Injection Strata for Disposal. Class II oil field tluids lnay be injected in the Badami Cnit WD-l and WD-2 \vells. in conformance with Alaska Adn1inistrative Code Title 20. Chapter 25. for the purpose of disposal into strata which correlates with the Ugnu - basal Sagavanirktok Formation intervals between 5926'-7720' MD and the mid-Sagavanirktok Formation between 4450'- 5526' MD in the Badami #4 well. Disposal injection \vithin the mid-Sagavanirktok Formation must be specitically approved by the Commission. and may be further conditioned by administrative action after review of injection performance in the Ugnu- basal Sagavanirktok F onnation. Rule 2 Demonstration of Tubing/Casing Annulus Mechanical Integrity The tubing/casing annulus must be tested every two years for mechanical integrity in accordance with 20 AAC 25 A12. Rule 3 Well Integrity Failure Whenever disposal rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any ~asing, tubing or packer. the operator must notify the Commission on the tirst working day follo\Ning the observation. obtain Commission approyal of a plan for corrective action and obtain Commission approval to continue injection. Rule 4 Surveillance A baseline temperature survey from surface to total depth. initial step rate test to pressures equal or e:'\ceeding rnaximum injection pressure and pressure falloff are required prior to initiation of disposal injection. Regular till depth tags are required at least once annually or as warranted following consultation \vith the Commission. Operating parameters including disposal rate. disposal pressure. annuli pressures and volume of solids pU111ped 111ust be monitored and reported according to requirements of 20 AAC 25.432. SCfJ\H~EC JUN j r ZOGl; ) Disposal Injection Order No. 12 August 5. 1997 Page 6 An am1ual performance report will be required including rate and pressure performance. surveillance logging. till depth. survey results. and volumetric analysis of the disposal storage volume. estimate of fracture gro\\1h if any and updates of operational plans. Report submission will be on or about July 1. Rule 5 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 allo\v waste t1uids to escape from the disposal zone. DONE at Anchorage. Alaska and dated August 5. 1997. ,.,...§....~-Ò~t ~ C / ~/ ~ ,,' ..:r /~ /V/~~. ~. I Jtf I ~ . ~ i:17:t:~ (ft 1 I~ ..~~~ v- I ~ r~ '~~~Ä~ì·· ~ ."¡(~';~~~ \ r~'~ I~' '1'';.'' \'6\~~-" ~. ~ \ "t- \-:--' .3" ..' 0 . .n, -.'- ,...... ~~~<, ~ '~N c~~ Robert N. Christenson. P.E.. Commissioner AS 31.05.080 provides that within 20 days atter recelp¡ ot'wnnen notice of the entry of an order. a person affected h\ it may tile with the Commission an application lor rehearing. :\ request for rehearing must be received by 4:30 PM on the 23rd day following ¡he date of ¡he order. or next working day if a holiday or weekend. to be timely tiled, The Commission shall grant or refuse the application in whole or in pan within 10 days. The Commission can refuse an application by not acting on it wahin the 10-day period. An atfected person has 30 days from ¡he date ¡he Commission refuses the application or malls (or otherwise distributes) an order upon rehearing. both being ¡he tinal order of the Commission. to appeal the decision to Superior CoUn7 Where a request tor rehearing is denied by nonaction of the Commission. the 30-day period for appeal to Superior (ourt runs from the date on which the n:quest is dœmed denied (i.~.. 10th da\' at1er the application t0r rehearing was tiled). 8CÞ:,N¡\1C':~ I .H hN, ~ D.,' 2.0n_,~.,. ;;J...... .' \,.í~L~H__ (~~~l! ~ c/ t}' l~" ';)EF- .'17. 1997 10: 46AM E) HSE AK ~~&~E [1 m~m~~~ DEPT. OF ENVIRONMENTAL CONSERVATION Division of Air and Water Quality Watershed Management Section 555 Cordova Street Anchorage, AK 99501 }r i /1 r~o. 164 P.2/12 TONY KNO WLES, GOVERNOR H (,' Phone: (907) 269-7565 Fax: (907) 269-7508 TrY: (907) 269-7511 rvir. Peter Hanley BP Exploration (Alaska), Inc. 900 East Benson Boulevard p ,0. Box 196612 Anchorage, Alaska 99519-6612 August 21, 1997 ;:NVIRONMENTA~ AUG 2 R f997 & REG. AFFAIRS Certified Mail Return Receipt Reqt¡1ested P 292 225 977 Subject: Waste Disposal Permit Application, ADEC Fùe No. 9631-DBOO4 Dear Mr. Hanley: The Department of Environmental Conservation has reviewed your Waste Disposal Permit Application for wastewater associated with oil and gas production. Based on our evaluation, Permit No. 9631-DBOO4 is hereby granted and found to'be consistent with the Standards of the Alaskan Coastal Management Program, 6 MC 80. Please note the conditions in Appendices A, B, and C. This permit expires August 1, 2002 and must be renewed by that date for continued operation of the facility. Department regulation,s require that renewal requests be received at least 30 days prior to expiration of a wastewater disposal pemrlt. RequestS not received prior to tlús date cannot be renewed and must be reissued 'as a new permit. This process takes a minimum of 60 days, during which time the facility may be prohibited from operation. Department of Environmental Conservation regulations provide that any person who disagrees with any portion of this decision. may request an adjudicatory hearing in accordance with 18 MC 15.200-920. The request should be mailed to the Commissioner of the Alaska Department of Environmental Conservation, 410 Willoughby Ave, Suite 105, Juneau, Alaska 99801-1795. Please send a copy of any such requests to the undersigned. You are reminded that even if an adjudicatory hearing has been requested and granted, all pennit conditions remain in full force and effect Failure to submit a hearing request within thirty (30) days of receipt of this letter shall constitute a waiver of that person's right to judicial review of this decision. "'=' ;ZøÁ .(! ¥ Brad Fristoe Environmental Engineer BF /RD/j cb (G:\I?QoCU!R\JUX)L.A."l\96J 1.004- liMY) Enclosures cc: Brad Fristoe, FairbankslADEC (w/encl) Glen Gray, DGClJuneau (w/encl) ~~ pr"'1~1· on rcC'v::lF!d paper tI y c. o. '\~\!r\jFt I ¡¡J!\! ¡¡y¡ ¡¡ 2nrH ......"...,-.' ,-Jr'\,:,~~ (J ~J t'LiL~J- ~EP.17.1997 10:46AM 13 ) HSE AI< ) ì U), 164 P.3/12 -' STATE OF ALASKA DEPARTMENT OF ENVIRONMENT AL CONSERVATION DMSION OF'AIR AND WATER QUAIlTY WATERSHED MANAGEMENT SECTION 555 CORDOVA STREET, ANC~9RAGE, ALASKA 99501 " \--.,/ BP Exploration (Alaska), Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 PERMIT NO.: 9631-DBOO4 This permit is issued to BP Exploration (Alaska), Inc., for the disposal of wastewater resu1tq1g from oil and gas production and associated support facilities. The waste will be disposed of by subsurface injection into the Ugnu formation through the injecûon well located at the Bad31Ui project, 27 miles northeast of Prudhoe Bay, Umiat Meridian, Township 9 North, Range 20 East, Section 20. T1ús permit is subject to the conditions contained in Appendices At B and C which are incorporated herein by reference. This petmit is issued under provisions of Alaska Statutes 46.03, the Alaska Administraûve Çode v as amended or revised, and other applicable State laws and regulations, including standards of the Alaska Coastal Management Program under 6 MC 80. This pennit is effective on issuance and expires August 1, 2002. It may be terminated or modified in accordance with AS 46.03.120. f/~/ /t )___ Date / /' ~ ./~/tI~ r~ Brad Fristoe, Environmental Engineer __ .. ,_ a .. - =::~ -~ ',7-: .~....~ '!! !:> ~ .. ';-. -~ ;.) \......./ ". . H:-'-- YUN I\l) (. 200" .'; ( ~ .t-., 1\! ~ \j i:: L> d'. ~,~,¡: ,~¿.. SEP.17.1997 10:46~M "- ,) HSE ~~< ~ 10. 164 P.4/12 PERMIT N~ 9631-DBOO4 Page 1 of9 AfPENPIX A - OPßMTIONS 1. CONDITIONS AW LllvllTATIONS a. The injection of hazardous waste as defined by 18 AAC 62.020 and Title 40, Part 261 of the Code of Federal Regulations (CPR), is prohibited. b. The discharge of wastewater to the surface of the ground as a result of activities authorized by tills pemùt including but not limited to activities associated with the reception. processing and handling of industrial waste is prolúbited. c. Injection shall be limited to the U gnu Formation below the stratigraphic marker 6, which corresponds to 7040 feet, true vertical depth, on the Badami-04 type log, Exhibit C-l of the mc Class I permit application. There shall be no penetrations of the U gnu Fonnation within 2000 feet of the injection well. d. Wastes authorized for disposal are those described in the Waste Analysis Plan or such plan as amended (required by the Class I VIC permit, AK.-IlOOl-A, for this facility) which is attached in Appendix C of this permit, and other non..bazardous wastes and wastes excluded fTom regulation as hazardous waste Wlder 40 CPR 261.4 as defmed by 18 AAC 62. e. The rate of waste iDjection shall be limited to a maximum of 65,000 barrels per month based on a 30 day month. The instantaneous injection rate shall not exceed 5 barrels per minute nor shall the injected volume exceed 3000 barrels in any 24- hour period. f. Up to three (3) times during the fl1'st six (6) months of operation and not more often than twice annually'thereafter. the Permittee may increase the injection pressure to not more than 5000 psìg, as measured at the wellhead, for periods of up to 30 minutes up to five (5) times over the interval" of three (3) consecutive days. The Permittee shall notify the Department by telephone or electronic mail ., "Within eight (8) hourn öf the initial exceedance of the 3000 psig limiâit1ðtnmG-=- shall submit a written incident report no later than ten (10) days theœafter. . "~-="..""""'~ ...... ~ g. The permittee must obtain written permission from the Department to dispose of wastes other than those authorized by 4, of this section. The permittee shall submit a written request to the Department to dispose of such wast~ at least 14 days prior to the planned disposal. The Department will review the proposal and approve or disapprove the request. 'oil! . _ ..J - . " -....... C' ,/', h '",~.H-\·\ £UN ú'i¡ f\· ?OO'! i1 ,,....~L;¡)""i,hJ~\:!~:::;,kJ J 0 \,,1 "'" .i.~. ~EP.17.1997 lØ:47~M E )~ HSE AK 'J I NO. 164 P.5/12 PERMIT NCL. 9631-DBOO4 Page '2 of 9 ~ APPENDIX A - QF~MTIONS 2. MONITORTNJl a. Samples and measurements taken as required by this permit or upon request from the Department shall be representative of the monitored activity. b. The permittee shall monitor all wastes received for disposal and reject wastes not approved for disposal by this permit. c. ' The-permittee shall maintain records of calibration and maintenance of instrumentation and recordings from continuous monitoring instrumentation including but not limited to those used in operation of the facility for analysis of materials received for disposal and required by Section I (Monitoring Systems). ' d. The pennittee shall complete a written manifest for each load of waste received. The manifest shall contain a description of the nature and composition of all injected fluids, date of receipt, source of-material received for disposal, name and address of the waste generator, a description of tho monitoring performed and the results, a statement stating if the waste is exempt from regulation as hazardous waste as defined by 18 MC 62.020 and 40 CFR 261.4 and any information on extraordinary occurrences. \ '--.-' e. Test procedures used to monitor wastes shall conform to methods cited in 18 MC 70.020(c), or as such regulations may be amended, and methods listed in Table 6 of the Waste Analysis Plan (or such plan as amended) in Appendix C. The permittee may substitute alternate methods of analysis upon receipt of prior written approval from the Department. 3. RECORD KFF.PTNG AND RRPORTTNG a. All records and information resulting from the monitoring activities required by this pemùt shall be retained inÀlaakaforòbservation by the Department for at least three years. Upon request from the Department, the permittee sball submit certified copies of such records. -. b. Reportinv ReQuirements i. The permittee sball,.subIIÚt quarterly reports containing the monthly average, maximum ud minimum values for injection pressure and annular pre's sure , the calculaœd monthly average and maximum flow rate, and the calculated monthly-average and maximum daily injected volume. EP A Fonn 7520-8 may be used for this report jf the applicant wishes. \J j \,¡~ .;::- ~ '", '"J~'iJ}O j d ¡\1 ~)\:y 2nn,.1 _IJ\;...¡,,~. SEP.17.1997 10:47~M B' ,) HSE ~I< ) NO. 164 P.6/12 PERMIT No... 9631-DBOO4 Page 3 of9 APPENDIX A - OPERAJ,"'IONS. 11. The permittee shaU subnút annual reports containing values for the total volume of wastes injected, the-volume of each type of waste disposed, the volume of wastes disposed and manage that are excluded from regulation as hazardous waste under 40 CPR 261.4 as defined by l'S AAC 62, and the totaJ volume of wastes disposed by third parties. Third parties are defmed in this instance as, organizations that are not among the co-owners of the Badami Unit (e.g., North Slope Borough, oilfield service companies). This report is due each January 30. A final report is due on the [30 days after the expiration date] which shall cover activities since the previous report. 111. Additional reports shall be required as requested by the Department. IV. All reports shall be submitted to the following adð¡ess: Alaska Depart.ment of Environmental Conservation 610 University Avenue Fairbanks, Alaska 99709 4. CHANGB IN DISCHARGE All disposal authorized herein shall be consistent with the tenns and conditions of this permit. Any anticipated facility expansions, flow increases, or process modifications which will result in new, different, or increased disposal of pollutants will require written notification as per Appendix B, Section H. 5. MA~NANCE OF FACILITTFS The permittee.shall, at all times, prpperly operate and maintain all facilities and systems of treatment and control (and related accessory equipment) which are installed or"used by the permittee to achieve.cempliance with the conditions of this permit. Proper operation and maintenance mcludes effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including quality assurance proc~ures. .~ 6, NONCQMPLIANÇE NOTIFICATION a. If, for any reason. the permittee does not comply with or will be unable to comply with an}Wmitation or condition specified in the pennit, the permittee shall report the noncompliance to the Department WÌthin 24 hours, or as soon as possible, of becoming aware of such conditions. SC,/-\\,r,¿Þ\JE[. JUN :) 0: 20Q.;:¡ $EP.17.1997 10:47~M E ) HSE A~( ¡) ~jO. 164 P.7/12 PERMIT NO., 9631-DBOO4 Page 4 of9 ~.. \.J APPEr-.,TDrx A - OPERA TrONS b. A written follow-up report shall be sent to the Department within seven days of the noncompliance event. The writteñreport shall contain, but is not limited to: i. Times and dates on which the event occurred and, if not corrected, the anticipated time the non..compliance is expected to cease; ü. A detailed description of the event including quantities and types of material involved; .. . - . "-." """:.... -. -- ~ ... iü. Details of any actual or potential impact on the receiving environment or public health; iv. Details of actions taken or to be taken to correct the cause of the event; and v. Details of actions taken or to be taken to correct any damage resulting from the event. 7. CON~TI{QCI10N \- All disposals shall be made through tubing with a packer. Tubings and packers shall be installed in a manner similar to that shown in Appendix C. 8. MRQHANICAL INTEGRITY (L A demonstration of mechanical integrity as described in 3, of this section is required for each well authorized by this pennit and to be used for injection. Mechanical Integrity Tests (H.3.a.) are required to be conducted every year and the tracer surveYt temperature log or noise log (H.3.b.) must be conducted every , three years. Mechanical integrity test are valid, for the purposed of this pemrlt, for ~ --:- QJlC .year from the date of the demonstration. Likewise, tracer surveys; :7 -... .;-~.- temperature logs or noise logs are 'valid for three years from the date of demonstration. Mechanical integrity demonstrations are not required for wells which will not be used, however, disposal may be made only through wells with a -.J!' valid mechanical integrity demonstration. The permittee shall notify the .. ~ Department at least 30 days .prior to conducting the mechanical integrity tests so a-. ; Department representative may be present. b," In the event that a well fails to demonstrate mechanical integrity during a test or a loss of mechanical integrity occurs during operation, the permittee shall balt all waste injection immediately and shall not resume waste injection until approval is given by the Department. '.~-J' ~'H~~' nJI\~ ~ (\ Lon?"t ¡ \, 1...._ ¡'.. ^.i'" ¡ \j ,} I)' . ./'.j> SEP.17,1997 10:48AM F .~ HSE m< ) ! r~o. 164 P.8/12 PERMIT NO- 9631-DBOO4 Page 5 of9 - :. APPENDIX A - O~ERATIO~.s. c. Mechanical integrity demonstrations shall be performed as follows: 1. To detect leaks in the casing. tubing, or packer. the casing-tubing annulus m.ust be pressure tested to 3500 psig for 30 minutes. Pressure loss may not ex~ed 175 psig at the end of the 30 minute test. This test is required to be conducted once every year as per section H.t. .:' . ?- ü. To detect movement of fluids in vertical channels adjacent to the weU bore "'-~.~~.:; 7·-'~~"'9.1\d to determine that the confIning zone is not f~ctured, a radioactive tracer survey, temperature log or noise log shall be conducted at an injection pressure at least equal to the maximum continuous injecüon pressure observed in the previous six months. The tracer tests shall be mn in the slurry injection mode, by adding the tracer to the operational injection stream in sufficient concentration to ensure detection behind the casing. A copy of the log shall be accompanied by a descriptive report. This test is required to be conducted once every three years as per section H.t. . .- :.......-:.--::. d. Mechanical integrity shall be demonstrated by the pressure test in H.3.a. any time tubing is removed from the wen or if a loss of mechanical integrity becomes evident during operation. The permittee shall report the results of such tests to the Department within 45 days of completion of the tests. e. If a well does not pass a mechanical integrity test and is not to be repaired within 90 days of the test failure, the permittee must provide evidence to the Department within 45 days of the test failure that the well will not act as a conduit. f. If a mechanical integrity demonstration required by H.I. is not performed, the pennittee shall halt operations.at that well on the anniversary date of the mechanical integrity demonstration (Le., one year anniversary of mechanical integrity test and three year anniversary"oftracer surveys, temperature logs or noise logs) and demonstrate to-the Department within 45 days of that date that the well will not act as a conduit. -..r g. The Department may, by written notice, require the permittee to demonstrate mechanical integrity (Sections H.3.a. or H.3.b.) at any time. C6c·'·t~~\.~\~~i'~·" n g n Ç¡I (' D p '0~ íõ;",W'ì¡ :'\) hJ t: L ~j ti ~,j c;f u: 2 D,..!;· ,SEP . 1 7 . 1997 10: 48AM ) HSE AK ) NO. 164 P.9/12 PERMIT N-Q~ 9631-DB004 Page '6 of 9 APPJ1NDrx A." OPERATIONS 9, MONITORING SYSTßMS a. Continuous monitoring devices shall be installed, maintained and used to monitor injection pressure and annulus pressure between the tubing and the long string casing. Pump stroke rate counters shall be installed, maintained and used on all ,injection pumps. r' b. The permittee shall install. continuously operatet and maintain· alanns to dete'ct excess injection pressures and excess annular pressures. c. A pressure relief valve must be installed to ensure that fluids are not injected at pressures higher than that listed in Section A.6. d, A positive pressure (> 0 psig) shall be maintained on the tubing/casing annulus and the permittee shall automatically or manually shut-in the well if the pressure on the annulus exceeds a pressure of 500 psig. 10. MECHANICAJ. TNTßGRlTY R'RPORTIN_G Mechanical integrity results required under section H.l. must be completed and reported to the Department by January 30 of the year following the demonstration. The Department will notify the pemùttee of the acceptability of a mechanical integrity demo~stration within 14 days of receipt of the results. 'Injection operations may continue during this review period. If the Department does not respond within 14 days, injection may continµe. 11. TERMS a. The annulus between the tubing and the long string casing shall be filled with a , corro$ion inhibiting freeze protection solution. b. The permittee shall notify the Department no later than 45 days before conversion and abandonment of the well, SCANNEr') ,HJN ~J C ?OO,.1 " c, '"-,,,' ',-- \ "-.,./' ·SEP. 17. 1997 1{2 : 48AM ) HSE AK ') NO. 164 P.10/12 PERMIT. N.Q .9631~DBOO4 Page 7 of9 .. ~ ( APPENDIX B - GF.NERAL A. Access _~d Inspection The department's representatives shall be allowed access to the pemúttee's facilities to conduct scheduled or unscheduled inspections or tests to determine compliance with tills pem1Ít and State laws and regulations. B. AvailabilitY of Rec9fÔS Except for ilÛonnation related to 'confidential processe.s or methods of manufacture, all application materials and records and reports submitted in accordance with the terms of 'this pennit shall be available for public inspection at the department's Southcentral Regional Office. C. J-,Qcation of Permit and Application The pennittee sball maintain a copy of this pennit and facility plans at the disposal facility or, if that is not feasible, at the pemuttee's or operator's place of business. D. Civil and Criminal Liability Nothing in this permit shall be construed to relieve the pemùttee from civil or crimimal penalties for noncompliance. whether or not such noncompliance is due to factors beyond their control, including but not limited to accìdents, equipment breakdowns, or labor dispute. E. Adverse ITI\l7acts ..- ~ '. .~ The permittee shall take all necessary means to minimize any adverse impact to the receiving waters or lands resulting from a violation or noncompliance with any limitations specified in this permit. including any additional monitoring needed to detennine the nature and impact of the activity in noncompliance. The.permittee shall clean-up and restore all axeas adversely impacted by the noncompliance. F. Çu1turR1 or Pa]eontolorical~~sources -': Should cultural or paleontological resources be discovered as~a result of this activity, work wlùch would disturb such resources is to be stopped, and the Office of Histo1j' and Archaeology, Division of Parks and Outdoor Recreation, Depanment of Natural Resources, is to be notified immediately (907)269-8715. .;>' J UN j (} 20D¿1· ·SEP.17.1997 10:48AM , ,HSE m< ) ~iO. 164 P.11/12 PERlvUT NQ...:- 9631- DBOO4 Page,;S of9 . '. \ ',,--, - ARPENDDCB-GENERAL G. propertY Ri gQts The issuance of this permit does not convey any property rights in either real or personal property, nor doeslt authorize any damage to private propertY. H. Moclific~tions or flJ1mres This permit authorizes' only that operation specified in the application and permít. ~y alteration, installation, expansion or modification which was not submitted as a component of the pennitted faCility plan will require a written plàn approval or Penriit amendment prior to implementation. Any expansion, modification, or other changei~n a facility process or operation which may result in an increase in emissions or discharg~s or may cause other detrimental environmental impacts from the permittee's facility reqq;.res a new pennit. 1. APplications for PeunitRen~w.Ñ, Amendment 01' P1an A.pproYa.1 Application for a renewal of or amendment to a pennit will be treated in the same manner as the initial application, except that public notice or hearing will not be required for applications for renewal or amendment. Application for renewal or amendment or p~an approval must be made no later than 30 days before the expiraúon of the permit or the . planned effective date of the amendment or change. \ ' ~ J. Transfers Should operation of the facility be contracted or a change in contractors be made, thellnew contractor shall be notified of the existence of the pennit and its conilitions. The permittee may request to transfer this pennit to another proposed pemùttee. The written request must include a certifiec! s'igned affidavit from the proposed new permittee sta~ng that they ACCept this permit in its entirety. This department reserves the sole discretidn to transfer this pennit. K. Termination '''~ This permit tenninates upon the expiraüon date. The department has the authority to! temúnate a permit upon 30 daYs written notice if the department fwds that there has been a violation of the conditions of:the pemrlt. , '~ ,~ "\.". t\ !~"'\r. " !Iii n'il ~) r"'i 2nfl,¡;¡ ",Il:~ ¡\, ~~þ u _lk'·¡f ,,--.J' ',.-/ ",-,. ~SEP.17.1997 10:49AM )~ HSE A~( \ ) NO. 164 P.12/12 PERMIT NO.. 9631 ~DBOO4 Page 9 of 9 - .. f-PPHNPIX B.. GENERAL L. Pollution Preventior¡ In order to miniII1Ìze present and future threats to human health and the environment, the Permittee shall make waste management decisions which 1) DÙIÙmize pollution entering the air, land, and water, and 2) promote the following waste management practices in the following order of priority: 1) source reduction 2) recycling/reuse 3) treatment, and 4) disposal ".,,: L'..r·!}\~. ~N~'::\ fUI'~ 3 C 2.0e,~;· \.~~~"b· '~I: \..l \JL...,.,...., \.".~ ~","m~~"':"~~:--;,",":':r~·'·;~:",,,,:w:--·':""··---,,,,,,,,,,,,,,,~~ BADAMIPE,897 ISSUANCE DATE AND SIGNATURE PAGE U,S, ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-11001-A In compliance with provisions of the Safe Drinking Water Act (SDWA), as amended, (42 U,S.C, 300f-300j-9), and attendant regulations incorporated by the U.S. Environmental Protection Agency (EPA) under Title 40 of the Code of Federal Regulations, BP Exploration (Alaska) Inc. (permittee) is authorized to inject non-hazardous industrial waste through one or two Class I injection wells at the Badami oil development 27 miles east of Prudhoe Bay, on the North Slope of Alaska, into the Ugnu Formation, in accordance with conditions set forth herein, Injection of hazardous waste as defined under the Resource Conservation and Recovery Act (RCRA), as amended, (42 USC 6901) or radioactive substances are not authorized under this permit. Injection shall not cQmmence until the operator has received written authorization from the EPA Director, Region 10 Office of Water, to inject. All references to Title 40 of the Code of Federal Regulations are to all regulations that are in effect on the date that this permit is issued, Appendices are referenced to the Badami Development Project Underground Injection Control Permit Application dated April 1996. This permit shall become effective on , in accordance with 40 CFR 124,15. This permit and the authorization to inject shall expire at midnight, terminated. , unless Signed this day of Philip G, Millam Director, Office of Water U.S, Environmental Protection Agency Region 10 (;:->c" /~~" II "j '--"', 1'1' j 1\ \ ", (\ 2 n C 't 0"":,\1, i,-'I'" .\.~ ~", 'i-· ~ ¡ I ,! ~ I:' ",,' ,. ," I , ~ IJ '110' J... ~u..",.., '-...J'I.:... 11~ I..'I ' \¿:I _\""". ,I..... -···ŠADAMIPE:"897---"'~'·"""~"~"~~·~7=-C-C-~~~'~ TABLE OF CONTENTS ISSUANCE DATE AND SIGNATURE PAGE 1 GENERAL PERMIT CONDITIONS 4 EFFECT OF PERMIT 4 PERMIT ACTIONS 4 SEVERABILITY 5 CONFIDENTIALITY 5 GENERAL DUTIES AND REQUIREMENTS 5 Duty to Comply 5 Penalties for Violations of Permit Conditions 5 Duty to Reapply 5 Need to Halt or Reduce Activity Not a Defense 6 Duty to Mitigate 6 Proper Operation and Maintenance 6 Duty to Provide Information 6 I nspection and Entry 6 Records 7 Reporting Requirements 8 Anticipated Noncompliance 8 Twenty-Four Hour Reporting 8 Other Noncompliance 9 Reporting Corrections 9 Signatory Requirements 9 PLUGGING AND ABANDONMENT 9 Notice of Plugging and Abandonment 9 Plugging and Abandonment Report 10 Cessation Limitation 10 Cost Estimate for Plugging and Abandonment 10 FINANCIAL RESPONSIBILITY 11 WELL SPECIFIC CONDITIONS 12 CONSTRUCTION 12 Casing and Cementing 12 SCJ~1N!\~E~:i JiUN (; n 20D4 Tubing and Packer Specifications 12 New Wells in the Area of Review 12 CORRECTIVE ACTION 12 WELL OPERATION 12 Prior to Commencing Injection 12 Mechanical Integrity 13 Injection Zone 14 - Injection Pressure Limitation 14 Annulus Pressure 14 Injection Rate Limitation 14 Injection Fluid Limitation 14 MONITORING 15 Monitoring Requirements 15 Continuous Monitoring Devices 15 Alarms and Operational Modifications 15 REPORTING REQUIREMENTS 15 Quarterly Reports 15 Report Certification 15 REPORTING FORMS 16 r'> '-'/,\ ~~ " u r- t· ' T ~ I ~~ ') n 2 0 D n ~t..:i--~},,!'\Jg;::,~) d~J1I~ ".p >./ _. "'d s·ÄÔÃ'M'ipÊ·':'§97·"·'·"·,·····,,c...,.....,' PART I GENERAL PERMIT CONDITIONS A. EFFECT OF PERMIT The permittee is allowed to engage in underground injection in accordance with the conditions of this permit. The underground injection activity, otherwise authorized by this permit, shall not allow the movement of fluid containing any contaminant into underground sources of drinking water, if the presence of that contaminant may cause a violation of any primary drinking water regulation under 40 CFR Part 141 or may otherwise adversely affect the health of persons or the environment. Compliance with this permit during its term constitutes compliance for purposes of enforcement with Part C of the Safe Drinking Water Act (SDWA), Such compliance does not constitute a defense to any action brought under Section 1431 of the SDWA, or any other law governing protection of public health or the environment from imminent and substantial endangerment to human health or the environment. This permit may be modified, revoked and reissued, or terminated during its term for cause. Issuance of this permit does not convey property rights or mineral rights of any sort or any exclusive privilege; nor does it authorize any injury to persons or property, any invasion of other private rights, or any infringement of State or local law or regulations. This permit does not authorize any above ground generating, handling, storage, or treatment facilities. This permit is based on the permit application submitted on April 1 0, 1996, and supplemental material dated June 10,1996; November 21,1996; December 3,1996; February 5,1997; May 12,1997; and May 29, 1997. B. PERMIT ACTIONS 1. Modification, Reissuance or Termination This permit may be modified, revoked and reissued, or terminated for cause as specified in 40 CFR 144.39 and 144.40. Also, the permit can undergo minor modifications for cause as specified in 40 CFR 144.41, The filing of a request for a permit modification, revocation and reissuance, or termination, or the notification of planned changes, or anticipated noncompliance on the part of the permittee does not stay the applicability or enforceability of any permit condition, 2. Transfer of Permits This permit is not transferable to any person except after notice to the Director on APPLICATION TO TRANSFER PERMIT (EPA Form 7520-7) and in accordance with 40 CFR 144.38, The Director may require modification or revocation and reissuance of the permit to change the name of the permittee and incorporate such other requirements as may be necessary under the SDWA. C. SEVERABILITY The provisions of this permit are severable, and if any provision of this permit or the application of any provision of this permit to any circumstance is held invalid, the application of such provision to other circumstances, and the remainder of this permit, shall not be affected thereby, D, CONFIDENTIALITY SC/\f\H~Er n F~ '1 fì 2007 ........ t,,~ \\... II \1 (..1,1 ~./ i.(.~~ BADAMIPE.897 -,.....,.:':':"~i':::":c:~~':~:-~':.,...,:-.,:~".,-~"'~';':'.,..."., ,......":-"~-' .~.~_. -....,.....":.-.:",~,~":"..".:o;':'", In accordance with 40 CFR Part 2, any information submitted to EPA pursuant to this permit may be claimed as confidential by the submitter. Any such claim must be asserted at the time of submission in the manner prescribed in 40 CFR 2.203 and on the application form or instructions, or, in the case of other submissions. by stamping the words "confidential" or "confidential business information" on each page containing such information. If no claim is made at the time of submission, EPA may make the information available to the public without further notice. If a claim is asserted, the information will be treated in accordance with the procedures in 40 CFR Part 2 (Public Information). Claims of confidentiality for the following information will be denied: 1 . The name and address of the permittee. 2. Information which deals with the existence, absence, or level of contaminants in drinking water. E. GENERAL DUTIES AND REQUIREMENTS 1. Duty to Comply The permittee shall comply with all conditions of this permit. Any permit noncompliance constitutes a violation of the SDWA and is grounds for enforcement action, permit termination, revocation and reissuance, modification, or for denial of a permit renewal application; except that the permittee need not comply with the provisions of this permit to the extent and for the duration such noncompliance is authorized in an emergency permit under 40 CFR 144.34. 2. Penalties for Violations of Permit Conditions Any person who violates a permit condition is subject to a civil penalty not to exceed $27,500 per day of such violation. Any person who willfully or negligently violates permit conditions is subject to a fine of not more than $27,500 per day of violation and/or being imprisoned for not more than three (3) years. 3. Duty to Reapply If the permittee wishes to continue an activity regulated by this permit after the expiration date of this permit, the permittee must apply for and obtain a new permit. To be timely, a complete application for a new permit must be received at least 180 days before this permit expires. 4. Need to Halt or Reduce Activity Not a Defense It shall not be a defense for a permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. 5. Duty to Mitiqate The permittee shall take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with this permit. 6. Proper Operation and Maintenance The permittee shall, at all times, properly operate and maintain all facilities and systems of treatment and control (and related appurtenances) which are installed or used by the permittee to achieve compliance with the conditions of this permit. Proper operation and maintenance SI(""l\N NF:i-', J~ jñ\í ~., n ? 0 nil. ~~" V6 .." \1.. ".,~...... _'~.-. ~,ä \ (~ ..~ ..._ ,¡I l) J - ._...,..:,,~,~~-,-,- ..,-':;.....'~:m"~.,-,;o:.':"'~':':"':~"-'.._'..~_..'-:""":':'~"":'..~~.,...,......:------.,""'.."""""".:~,~".,...~""",,~,;,~--,-..,.,.,...:-- BADAMIPE.897 includes effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of this permit. 7. Duty to Provide Information The permittee shall provide to the Director, within a reasonable time, any information which the Director may request to determine whether cause exists for modifying, revoking and reissuing, or terminating this permit, or to determine compliance with this permit. The permittee shall also provide to the Director, upon request, copies of records required to be kept by this permit. 8. ,Inspection and Entry The permittee shall allow the Director, or an authorized representative, upon the presentation of credentials and other documents as may be required by law to: a. Enter upon the permittee's premises where a regulated facility or activity is located or conducted, or where records are kept under the conditions of this permit; b, Have access to and copy, at reasonable times, any records that are kept under the conditions of this permit; c. Inspect at reasonable times any facilities, equipment (including monitoring and control equipment), practices, or operations regulated or required under this permit; and d. Sample or monitor at reasonable times, for the purposes of assuring permit compliance or as otherwise authorized by SDWA, any contaminants or parameters at any location. 9. Records a. The permittee shall retain records and all monitoring information, including all calibration and maintenance records and all original strip chart recordings for continuous monitoring instrumentation, copies of all reports required by this permit and records of all data used to complete this permit application for a period of at least three years from the date of the sample, measurement, report or application. These periods may be extended by request of the Director at any time, b. The permittee shall retain records concerning the nature and composition of all injected fluids until three years after the completion of plugging and abandonment. At the conclusion of the retention period, if the Director so requests, the permittee shall deliver the records to the Director. The permittee shall continue to retain the records after the three year retention period unless he delivers the records to the Director or obtains written approval from the Director to discard the records. c. Records of monitoring information shall include: (1) The date, exact place, and time of sampling or measurements; (2) The name(s) of the individual(s) who performed the samplU:1~r measurements; (3) The date(s) analyses were performed; SCl\~n\IE~- JUN C! ?O[\:ì ',' ,. .". '" .,-:~ BADAMIPE.897 .~;~~;::-::';.~,~'~.':O:-~""".'~=- .... 7' (4) The name(s) of the individual(s) who performed the analyses; (5) The analytical techniques or methods used; and (6) The results of such analyses. d. Monitoring of the nature of injected fluids shall comply with applicable analytical methods cited and described in Table I of 40 CFR 136.3 or in appendix III of 40 CFR Part 261 or in certain circumstances by other methods that have been approved by the Administrator. e. All environmental measurements required by the permit, including, but not limited to measurements of pressure, temperature, mechanical integrity, and chemical analyses shall be done in accordance with EPA's Quality Assurance, Program Plan, f. As part of the COMPLETION REPORT, the operator must submit a PLAN that describes the procedures to be carried out to obtain detailed chemical and physical analysis of representative samples of the waste including the quality assurance procedures used including the following: (1) The parameters for which'the waste will be analyzed and the rationale for the selection of these parameters; (2) The test methods that will be used to test for these parameters; and (3) The sampling method that will be used to obtain a representative sample of the waste to be analyzed, Where applicable, the Waste Analysis Plan (WAP) from the permit application may be incorporated by reference, g, The permittee shall complete a written manifest for each load of waste received, The manifest shall contain a description of the nature and composition of all injected fluids, date of receipt, source of material received for disposal, name and address of the waste generator, a description of the monitoring performed and the results, a statement stating if the waste is exempt from regulation as hazardous waste as defined by 40 CFR 261.4, and any information on extraordinary occurrences. For waste streams piped more or less continuously from the source(s) to the wellhead, the permittee shall provide for continuous, recorded measurement of the discharge volume and shall provide such sampling and testing as may be necessary to provide a description of the nature and composition of all injected fluids, and to support any statements that the waste is exempt from regulation as hazardous waste as defined by 40 CFR 261.4 h. Dates of most recent calibration or maintenance of gauges and meters used for monitoring required by this permit shall be noted on the gauge or meter, 10. Reportinq Requirements The permittee shall give notice to the Director, as soon as possible, of any planned physical alterations or additions to the permitted facility or changes in type of injected fluid, 11. Anticipated Noncompliance SCl\NN,~::~ \ !ì ¡í\; ,~, q 'ï'O[,,1( \j 0-:1,... ~..,.." \.! ~l",' H \ ~.) ~" If 10._ ) Ie} "'BAî5AMIPÊ:a97' ,. ) ) The permittee shall give advance notice to the Director of any planned changes in the permitted facility or activity which may result in noncompliance with permit requirements. 12, Twenty-Four Hour Reporting a. The permittee shall report to the Director any noncompliance which may endanger health or the environment. Any information shall be provided orally within 24 hours from the time the permittee becomes aware of the circumstances. The following shall be included as information which must be reported orally within 24 hours: (1) Any monitoring or other information which indicates that any contaminant may cause an endangerment to an underground source of drinking water, (2) Any noncompliance with a permit condition or malfunction of the injection system, b, A written submission shall also be provided within five (5) days of the time the permittee becomes aware of the circumstances, The written submission shall contain a description of the noncompliance and its cause, the period of noncompliance, including exact date and times, and, if the noncompliance has not been corrected, the anticipated time it is expected to continue, and steps taken or planned to reduce, eliminate, and prevent recurrence of the noncompliance. 13, Other Noncompliance The permittee shall report all other instances of noncompliance not otherwise reported at the time monitoring reports are submitted, The reports shall contain the information listed in Permit Condition E-12,b, 14, Reporting Corrections When the permittee becomes aware that he failed to submit any relevant facts in the permit application or submitted incorrect information in a permit application or in any report to the Director, the permittee shall promptly submit such facts or information. 15, Signatory Requirements a. All permit applications, reports required by this permit and other information requested by the Director shall be signed by a principal executive officer of at least the level of vice-president, or by a duly authorized representative of that person. A person is a duly authorized representative only if: (1) The authorization is made in writing by a principal executive of at least the level of vice-president. (2) The authorization specifies either an individual or a position having responsibility for the overall operation of the regulated facility or activity, such as the position of plant manager, operator of a well or a well field, superintendent, or position of equivalent responsibility. A duly authorized representative may thus be either a named individual or any individual occupying a named position. (3) The written authorization is submitted to the Director. b. If an authorization under paragraph a, of this section is no longer accurate because a ..0[,.., "~ "N'" çt· f} ~OD'~ ~,,:"',', ii "¡f\ ¡~\'~ í\q:...¡ ,ìl d ,:; ¿~ It.,'i c.. '-if ~~v:r \:,B ,;'.\ 'ðL~..-' "'-"~ ~I~ 1.0 ' different individual or position has responsibility for the overall operation of the facility, a new authorization satisfying the requirements of paragraph a, of this section must be submitted to the Director prior to or together with any reports, information or applications to be signed by an authorized representative, c, Any person signing a document under paragraph a, of this section shall make the following certification: "I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment." F, PLUGGING AND ABANDONMENT 1. Notice of Pluqging and Abandonment The permittee shall notify the Director no later than 45 days before conversion or abandonment of the well. 2, Pluqqinq and Abandonment Report The permittee shall plug and abandon the well as provided in the PLUGGING AND ABANDONMENT PLAN (Appendix F), which is hereby incorporated as a part of this permit. Within 60 days after plugging any well the permittee shall submit a report to the Director in accordance with 40 CFR 144,51 (p). EPA reserves the right to change the manner in which the well will be plugged if the well is not proven to be consistent with EPA requirements for construction and mechanical integrity. The Director may ask the permittee to update the estimated plugging cost periodically. 3, Cessation Limitation After a cessation of operations of two years, the permittee shall plug and abandon the well in accordance with the plan unless he: a, Provides notice to the Director; b. Demonstrates that the well will be used in the future; or c, Describes actions or procedures, satisfactory to the Director, that the permittee will take to ensure that the well will not endanger underground sources of drinking water during the period of temporary abandonment. These actions and procedures shall include compliance with the technical requirements applicable to active injection wells unless waived by the Director. 4. Cost Estimate for Pluqging and Abandonment a. The permittee estimates the 1997 cost of plugging and abandonment of the permitted well as $400,000. b. The permittee must submit financial assurance and a revised estimate in April of each year. The estimate shall be made in accord with 40 CFR 144.62. ,JUN~) DZOill'J ,; L <:;1 t:'J q' ~, (If BA'[)ArVrrp"E":'g'§7'"'''''''''''''''''''''''''''''''''','".""" .:.:':':::;;;';:;:~~;:;:J'::::;:':.-w.;:;';;';::j;,;;~:~;:~;:;:::~;:;¡;:;;;:~:;~:::;!:ill::~:~::,j1,:j:~.:!l'~;~::::zt:;~~;;.:;.:;;.:~:,;,:~~t:ili::i':;~:~;:~;:;:~~~.:::'~:;i;;:::::';:;:;:;:;~;:;:;:.~m;i.:t, ;::':':':~~:~;·":;":';;;'~::':;:::;';:.:::::::;::::;;':.~:;:::¡::;:;:;:;':::;';:;!;i;.:~~::::::~:;j;.:;:;.:.:m;:::~~.:~~;':;':';:ill;i;!;:::::;~:i:"::;:;¡:It:~;:~W;:.:::::~;:;;':~;.i.;!;i;¡;':;':;¡'ili;:;:~;:;:::,:::,,:;::i::.:.:.i::;:;';'::~;:¡¡¿;;':~.:~:;:;:.. c. The permittee must keep at the facility during the operating life of the facility the latest plugging and abandonment cost estimate. d. When the cost estimate changes, the documentation submitted under 40 CFR 144.63(f) shall be amended as well to ensure that appropriate financial assurance for plugging and abandonment is maintained continuously, e, The permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S, Code, naming the owner or operator as debtor, within 10 business days after the commencement of the proceeding, G. FINANCIAL RESPONSIBILITY The permittee shall maintain continuous compliance with the requirement to maintain financial responsibility and resources to close, plug, and abandon the underground injection well. If the financial test and corporate guarantee provided under 40 CFR 144,63(f) should change, the permittee shall immediately notify the Director, The permittee shall not substitute an alternative demonstration of financial responsibility for that which'the Director has approved, unless it has previously submitted evidence of that alternative demonstration to the Director and the Director notifies him that the alternative demonstration of financial responsibility is acceptable. ..~~. t 1\1 h,If:'::':, \ nJ~¡ ~ f,1 ?DDP '..- \,J. .~" \J ~~~ d l t 'J iì' ~) t:. ."~,,. I3ADAMI PÈ.897 ...... PART II WELL SPECIFIC CONDITIONS A. CONSTRUCTION 1, Casing and Cementing The permittee shall case and cement the well(s) to prevent the movement of fluids into strata other than the authorized injection interval (see II.C.3, below), Casing and cement shall be installed in accordance with Application Appendix F, with the exception that the cement in the annulus between the 9-5/8 string and surface casing shall be run and logged to the surface. If primary cement returns to surface are not observed, the Director is to be notified as to the nature of the augmented testing proposed to ensure the integrity of cement between the 9-5/8 string and the surface casing. The permittee shall provide not less than ten days advance notice to the Director of all cementing operations. If primary cement returns to surface are not observed for any cementing procedure, the Director is to be notified as to the nature of the augmented testing proposed to ensure the integrity of the cement bond and adequacy of any Top Job procedure, 2, Tubing and Packer Specifications The well shall inject fluids through tubing with a packer, Tubing and packer shall be installed in accordance with Appendix F, except that the packer shall be set not more that 200 feet up the casing from the top of the permitted injection interval. (See II, C, 4" below) 3. New Wells in the Area of Review New wells within the area of review shall be constructed in accordance with· the Alaska Oil and Gas Conservation Commission Regulations Title 20 - Chapter 25. 8, CORRECTIVE ACTION No wells in the area of review require corrective action, C. WELL OPERATION 1. Prior to Commencing Injection Injection operations pursuant to this permit may not commence until: a. Construction is complete and the permittee has submitted two copies of COMPLETION FORM FOR INJECTION WELLS (EPA Form 7520-9), see APPENDIX; and (1) The Director has inspected or otherwise reviewed the new injection well and finds it is in compliance with the conditions of the permit; or (2) The permittee has not received notice from the Director of intent to inspect or otherwise review the new injection well within thirteen (13) days of receiving the COMPLETION REPORT in which case prior inspection or review is waived and the permittee may commence injection, b. The operator demonstrates that the well has mechanical integrity as described below and the permittee has received notice from the Director that such a demonstration is satisfactory. The permittee shall notify EPA two weeks prior to conducting this initial test so that an EPA _.' u ï ¡ M ".t n 6) \ì fl8. SC/\NNEL' ~)I.\oJl\l ç' ~) l-U- 0 ·SADAMÎP'Ë':'S9'7"""······ ',' ..,,·,,·~,"w:;':;N:;·:,:·:':·:;':':·::,·:;':·:¡":': , ), . representative may be present. In order to demonstrate there is no significant leak in the casing, tubing or packer, the tubing/casing annulus must be pressure tested to at least 3,500 pounds per square inch gauge (psig) for thirty minutes, Pressure may not decline more than 5 percent in the thirty minutes, 2. During Injection The injection facility shall be manned 24 hours per day by trained and qualified operators during injection. 3, Mechanicallnteqritv a. Standards The injection well(s) must have and maintain mechanical integrity pursuant to 40 CFR 146.8. b. Prohibition Without Demonstration of Mechanicallntegritv Injection operations are prohibited after the effective date of this permit unless the permittee has conducted the following tests and submitted the results to the Director: (1) To detect leaks in the casing, tubing, or packer, the casing-tubing annulus must be pressure tested to at least 3,500 psig for thirty minutes, Pressure may not decline more than 5 percent in thirty minutes. This pressure test is required at a time interval of no more than 12 months between tests. (2) To detect movement of fluids in vertical channels adjacent to the well bore and to determine that the confining zone is not fractured, a radioactive or borax tracer survey and a temperature or noise log shall be conducted at an injection pressure at least equal to the maximum continuous injection pressure observed in the previous six months. The tracer tests shall be run in the slurry injection mode, by adding the tracer to the operational injection stream in sufficient concentration to ensure detction behind the casing. Copies of all logs shall be accompanied by a descriptive and interpretive report. Fluid movement tests are required annually beginning after the first six months of normal operation, c. Terms and Reporting (1) Two (2) copies of the log(s) and two (2) copies of a descriptive and interpretive report of the mechanical integrity tests identified in 2.b shall be submitted within 45 days of completion of the logging. (2) Mechanical integrity shall also be demonstrated by the pressure test in 2.b.(1) any time the tubing is removed from the well or if a loss of mechanical integrity becomes evident during operation. The permittee shall report the results of such tests within 45 days of completion of the tests. (3) After the initial mechanical integrity demonstration, the permittee shall notify the Director of intent to demonstrate mechanical integrity at least 30 days prior to subsequent demonstrations, SII--' " t\ ~ ¡'\á Ie ~ \:.·~\i;.9b~&\;î ~r( LL . HJ!\~ ~ i~ ~. ~. · \' rJ Q.' 20fL1 ..... t~ jf (4) The Director will notify the permittee of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests. Injection operations may continue during this 13 day review period, If the Director does not respond within 13 days, injection may continue. (5) In the event that the well fails to demonstrate mechanical integrity during a test or a loss of mechanical integrity occurs during operation, the permittee shall halt operation immediately and shall not resume operation until the Director gives approval-to resume injection, (6) The Director may, by written notice, require the permittee to demonstrate mechanical integrity at any time, 4, Injection Zone Injection shall be limited to the Ugnu Formation below stratigraphic marker 6, which corresponds to 7040 feet, true vertical depth, on the Badami-04 type log, Exhibit C-1 of the permit application. There shall be no penetrations of the Ugnu Formation within 2000 feet of the injection well. 5. Injection Pressure Limitation Injection pressures shall not initiate new fractures or propagate existing fractures in the upper confining zone as that stratigraphic interval is described in the Badami type log, Exhibit C-1 of the permit application. Neither shall the maximum injection pressure, measured at the wellhead, exceed 3000 pounds per square inch (psig), except as follows. Up to three (3) times during the first six (6) months of operation and not more often than twice annually threafter, the Permittee may increase the injection pressure to not more than 5000 psig, as measured at the wellhead, for periods of up to 30 minutes up to five (5) times over an interval of three (3) consecutive days, The Permittee shall notify the Director or his designee by telephone or electronic mail within eight (8) hours of the initial exceedance of the 3000 psig limitation and shall submit a written incident report not later than ten (10) days thereafter. 6. Annulus Pressure The annulus between the tubing and the long string casing shall be filled with a corrosion inhibited non- freezing solution. A positive surface pressure up to 500 psig is authorized. 7. Injection Rate Limitation The rate of waste injection shall be limited to a maximum of 65,000 barrels per month based on a 30 day month, The instantaneous injection rate shall not exceed 5 barrels per minute nor shall the injected volume exceed 3000 barrels in any 24-hour period. 8. Injection Fluid Limitation No substance other than those non-hazardous wastes noted in the permit application shall be injected. In the event that third party wastes are accepted the third party must certify that hazardous waste or radioactive substances are not injected. NOTE: Neither hazardous waste as defined in 40 CFR 261 nor radioactive substances other than naturally occuring radioactive material (NORM) from pipe scale shall be injected for disposal. 51(;tiN~\ìEL/ JUN ;:, 0 200:'J · BADAMIPE.897 D. MONITORING 1. Monitoring Requirements Samples and measurements collected for the purpose of monitoring shall be representative of the monitored activity. 2, Continuous Monitoring Devices Continuous monitoring devices shall be installed, maintained, and used to monitor injection pressure and rate, and to monitor the volume of glycol in the annulus between the tubing and the long string casing. Calculated flow rates and calculated volumes are not acceptable, 3. Alarms and Operational Modifications a. The permittee shall install, continuously operate, and maintain alarms to detect excess injection pressures and rates and significant changes in annular fluid volume. These alarms must be of sufficient placement and urgency to alert operators in all operating spaces. b, The permittee shall install and maintain an emergency shutdown system for the annular fluid recirculation system. c. Plans and specifications for the alarms and pressure relief valve shall be submitted to the Director prior to the initiation of injection. E. REPORTING REQUIREMENTS 1, Quarterly Reports The permittee shall submit quarterly reports to the Director containing the following information: a, Monthly average, maximum and minimum values for injection pressure, rate, and volume shall be reported on INJECTION WELL MONITORING REPORT (EPA Form 7520-8). b, Graphical plots of continuous injection pressure and rate monitoring. c. Raw monitoring data in an electronic format. d. Physical, chemical, and other relevant characteristics of the injected fluid, e, Any well work over or other significant maintenance of downhole or injection-related surface components. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any "practice" tests. g. Any other tests required by the Director. 2. Report Certification All reporting and notification required by this permit shall be signed and certified in accordance with Part 1.E.15., and submitted to the following address: ~SCl\ ù''-,J !'~ F 0'~ \ 'j J?l1 ~.! f. ~ ? On 'ì .w' , .'0"" ,,"'~. uc, J 8 "I ',I.... U.} #8 ') TONY KNOWLES, GOVERNOR ALASIiA. OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 December 16, 1997 Janet D, Platt Supervisor, Environmental, HSE Alaska BP Exploration (Alaska), Inc. P.O. Box 196612 , ILl) Anchorage, AK 99519-6612 /j;'- Re: Disposal Injection Order #12 Reporting Requirements Dear Ms. Platt: By letter dated December 4, 1997, BP Exploration (Alaska), rnc, ("BPXA") asked the Commission to consider accepting the reports required by the Environmental Protection Agency ("EPA") in lieu of those required by Disposal Injection Order ("DIO") #12 for the Badami B 1-0 1 well. This well is currently operating under EP A requirements as a Class I well. Class I reporting requirements for the B 1-01 well are more rigorous than those for Class II wells. The intent of DIO # 12 would be met if BPXA submitted to the Commission those reports required by EP A. Therefore, in the interest of streamlining reporting, the Commission will accept the EP A notification and reporting requirements as specified in the Class I permit. In the event that well B 1-0 1 is operated as a Class II well, the Commission would require BPXA to operate under the constraints of DIO # 12. cc: Jonathan Williams, USEP A Region 10 ~~Cl.\f,\n~H::t·. P' FI\Q ~f n 20 ll1 ..... "'" ~} u. \.~.~I'- t;)~)~\) /,"; ~' ., ..l!.:). #7 m ) - ') ,; BP EXPLORATION BP Exploration (Alaska) Inc, 900 East Benson Boulevard P'Q, Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 By Facsimile December 4, 1997 Mr. David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Disposal Injection Order No. 12, Badami Unit Reporting Requirements Dear Mr. Johnston: BP Exploration (Alaska) Inc. (BPXA) requests that the Commission consider receiving the reports required by the Environmental Protection Agency (EPA)Clas.s I well permit for the Badami 81'-01 well in lieu of the reports required by the Disposal Injection Order (010) No. '12. Ms. Alison Cooke of my staff discussed this suggestion with Mr. Blair WondzeH on December 3, 1997. Mr. Wondzell suggested we follow up with a written request to the Commission for concurrence. While BPXA are operating under the EPA Class I requirements at Badami, we would like to copy the Commission on all EPA notification and reporting requirements. In the event that we cease injection of Class I waste for any reason and operate under the AOGCC 010, BPXA would then meet the reporting and notification requirements in the 010. BPXA makes this request in order to streamline and ensure compliance with reporting and notification requirements for the Badami B1-01 injection well. Currently the well is regulated by the EPA Class I well permit, the AOGCC 010, and an Alaska Department of Environmental Conservation Wastewater Disposal Permit. Although we worked with the agencies to negotiate consistent requirements in these permits, there are some differences in the specific information requested, the frequency of reporting (monthly, quarterly, annually), and the timing for R E (- E ,- V E D submittal of information. Overall the EPA requirements are the most comprehensive of the three governing permits. BPXA is confident that DEC 10 1991 S(;ß~lf~¡NEl,i JUN ~j1 0 ZOOt} Alaska Oil & Gas Cons. Commission Anchorage .. " Mr. David Johnston ) Page 2 December 4, 1997 ) by meeting the notification and reporting requirements set by the EPA that we will also meet the intent of the requirements in the 010. Thank you for your consideration of our request to streamline the reporting requirements at the Badami waste injection well. In order to expedite your response, if you concur with this request, we are providing a signature line below for your convenience. If you have any questions please call Ms. Alison Cooke at 564-4838. Concurrence: David Johnston, Chairman Date Alaska Oil and Gas Conservation Commission Sincerely, /D. flK t D. Platt, Supervisor Compliance ska JDP/ADC cc: Blair Wondzell, AOGCC SCl\N~'~Er, p I~; '=, {1 20n ,'1 ..... t.I ~~ '., ~... ~,,j ~~,l\ ç} '-.'!¡ L'l."¡), #6 ') ) BP EXPLORATION ~ f.-0cJ (iP1~ŠJ rf "9~U) y Facsimile BP Exploration (Alaska) Inc, 900 East Benson Boulevard P.O. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 July 17,1997 Commissioner David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Comments on the Draft Disposal I njection Order Badami Unit. North Slope Basin Dear Commissioner Johnston: BP Exploration (Alaska) Inc.(BPX), thanks the Commission for the opportunity to provide the following comments on the draft Disposal Injection Order for the Badami Unit wells: Finding 21. The maximum instantaneous disposal rate will be 5 BPM. As the Commission noted the average disposal rate will be 1-2 BPM. Finding 28. BPX has previously proposed to meet with the Commission to discuss the specific surveillance program for the Badami wells. " j ~ ·f "I, - .-.........,,). ""~, I¡ FtLE-' i·'" '-"~':"".,,,,,,,~! ~:), i:'. '---w,,,,,..,,,!4.,,,,,,..,f ¡X}\' I, 1.i"", ';, ,1'1 ,.,{:. :~'!~' .I)t~.." \I>' 1J"'t"'''' ·,F Rule 4 Surveillance As mentioned above, BPX would like to meet with the Commission to discuss the Badami surveillance program. BPX prefers to perform fill depth tags on an as needed basis, not to exceed once a yeaí. Thank you for your timely issuance of the Badami DIO and the opportunity to comment. If you have any questions regarding these comments please call Ms. Alison Cooke at 564-4838. Sincerely, RfGEfVED David A. Wallace HSE Manager . ~ ') 1 - (., I ']997 DAW/ADC '.Ia~' :',' , : ".,! , . .. ,;)¡'.~ .1.il4.~ ;..JQ~"U:1S. ~/om¡mss.\·· '~I~ ~nc!tQrade p Ii\g ') f\ 20n '" \) ~, ! ,I i'¡ I:} _ v¿.1. #5 4/3 394 STOF0330 AO-02714032 $69.93 ) ) AFFIDAVIT OF PUBLICATION ................................................... N,O, ' t¡C"e,0' f",",,',P, "', II" Þ,J""i,'C,' , ',','"He, ,ä", r,.,'"i,n" ,g,',', ',','",',',.,,:,,','," ,1',0 ""'"" \ ',,' "'i':"1 STATE, OF' 'ALAsKA',',:',>'!' 'Alaska 011 and ,(;05',,''::,,::' " conserVal¡On:C l~ 1\¡~SI~~,: ",' Re: The apPli~~t;ori, 9f" ','BP'" Ë'xploratlon (A'l.askej), 'Inc,. ( B P X) for an order óllowll'19, the, IJndergro\jndc:llsposol',:~f,: 'class,l,I,"tf l:JidS' by In lectlq'rt\'ll)l~i\!~:,' ·th~:'BQ~Q:rþiU.oJt,WDrJ ',~(", I ,t~!!:,B~~9.r~:I'pll FIeld;, I IIL-""::" ,'.,' .1'li"'":',I,,,. '" I' ",",,1 LI,a.P~,'þ·l¡)I~tter dote~MQ'y , i 1~7' hO~req~ested the "AII:jS "!,,I: i'oir'o,nd¡Gos ' Conservdtl~h;k' ¡Commission ,to Issue an orde,F.I',I, In conformance with 20 '~IAÇ t 125.252, The order wouldautht:!r" I rlze the disposal of class: I,I:' , fluids 'by Inlection, Into tti~", , Ugnu and ,Sogovqnirktbk","-' , Formations in,wel\,WiPo) at't~'",' Badamf Oil"Fleld;"ol'1"onst\O!:/!.':'" oil field In the ,Mikkelsen, BQY¡I:,' vicinity oftha',North, ;Slope,' A person who may be har~· ed If the reque~tèd order'!:>,' issued mdY filp.,o written ' ',' protest prior to 4:QO PM Jun~':,,: 116, 1997, withJt~e, Alas~Q "Oil ',III \ and Gas Conservation Co!)'1~" ~'I mission. 3001 Porcupine Drive, , 'AnChoroge Alosko 99501, and ' I r..aIJe.t 0 neorlng on ,t~en'lat- T,:or II Tn':' Drc.t.,o;,T Is timelY Iii.." one ;'Ol~"'~ 0 ..,ubstqntlal" : on,j maTerlol L~~up CfU:~'IOI¡,tl:)',.: I rn.. (omml..,..,lon ~ detp'r'mlno·' .tlon, a heorlng (In Tt,p "'otter wHI bl¡o Mia 0.1 The (lI:)(I.e od dress 01 v·OO ,)11'1 on Jul, 1 1997 In ((lnl(.rmon,.. \IIIUn 20 AAC is ~JO It 0 neorm", IS to be',.,...ld int..re~tpo .,arTI..~. may confirm' thIs bY call1n¡:J'':''! tile Comml~sIQn. s office. (907.)' Î 279·1433 after_,~une:'6,' )~91;1f, , no protest "Is flied. the "" CommlsslQn Will consider ~l'1e:~, Issuance 'qf.1 ttle: orpe~" vvl,boul:p, \ heorin9, ' '," ~ "", 1" ,"',~ If youQ~e a' PèrsonVfiæ,:¡:a'I;d': ~~~~~~llt~~~n?c~Wg~'j~'~~rd~~/':' 'I 1(1 commenT (lr to onenÇl In., publl'=' hearing Dleo'òe (onToct . Dlono FIE-Cll ,)t 219· lJ3] no lot,¡r Tnon J un.. 15 1997 !~IRobE-rt Cnrl'òt..n'òon 1~~~;~i~~~n~6, 1997 A STATE OF ALASKA, THIRD JUDICIAL DISTRI0'. Eva M. Kaufmann being first duly sworn on oath deposes and says that he/she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the Engl ish language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on Hay 30, 1997 and that such newspaper was regularly distributed to its su bscribers 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. signed fA-JL^---~ r~ Subscribed and sworn to bÙ me this J.. day ofq.kl'!.¿ C:¡1 19,..... // /J ...........r·9~·ddJ. Notary Public in and fJ" the State of Alaska. Third Division. Anchorage. Alaska MY COMMISSION EXPIRES My Conur.is.)10n E~ Jires: ...... ...... ····February8;2000······19...... ':\¡E.:~: ¡Ul\¡ ') 'ì u h ~J ~) 2004 #4 ) ') mi BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 By Facsimile June 18, 1997 Commissioner David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Badami Unit Disposal Injection Order Dear Commissioner Johnston: BP Exploration (Alaska) Inc.(BPX), respectfully submits the following clarification requested by Mr. Bob Crandall concerning the application for a Disposal Injection Order at the Badami Development Project. Mr. Crandall requested that BPX address the maximum operating pressure, vertical fracture growth, well surveillance, and the Area of Review. They are each discussed below: 1) Maximum pressure The normal operating pressure of the Badami Class I well will be below 3000 psi. There are two situations, where the maximum well pressure might go up to 4800 psi for a short period of time. The first situation might be at the initial breakdown of the formation if there is near wellbore damage or plugged perforations and the extra pressure will allow these to breakdown. The second situation is at any time in the well's life if the solids injection causes perforation plugging, there will be a need to apply extra wellhead pressure (up to 4800 psi) to overcome the blockage. f~EGEIVED .I~ :\' 2.0 1997 A'aska Oil & Gas Cons. ComHl\S~' SC.AN,Nf!1EÞ~'~ ~i 0 2004 ) ) Badami 010 Page 2 June 18, 1997 2) Fracture Growth from the upper injection zone Field evidence and laboratory experiments indicate there is no basis to expect that the upper confining zone will be penetrated. Should the upper injection zone be used for solids storage, it will be perforated in its lower few feet of section. This will provide approximately 950 feet of separation between the perforations and the base of the confining zone. Comparing the Badami disposal operation with other projects indicates vertical growth might be in the 250 foot range. A maximum case might be 500 feet. This generates a safety factor between 2 and 4. The relationship of the Badami project with others can be seen on the following table. Average Total Max Injection Solids Fracture Fracture Project Rate Volume Length Height (BPO) (Cu Yds) (Feet) (Feet) Prudhoe OS4-19 20 400,000 2000 1600 Jasper County, Tx. 10-15 1,500 1200 confined by shales Prudhoe CC-2 2.5 130,000 800 300 Badami 1 12,500 3) Badami Class II well surveillance The Badami waste injection well has been designed in a very conservative manner to ensure that there is little risk of a broach or fracturing into or through the confining zone. This has been achieved by placing the well at over 2000ft from other wells and limiting the injection rates, thus inducing a smaller injection domain. The well has also been designed with the casing cemented back to the surface casing shoe, which is placed across the confining zone. ·::::;~..t.,;\!i\IEr.\ .JUN 3 G 2004 .REt¡r:i\/~D l~ ~: .\ &~ ~~ \ :.! Ii 2 0 1997 Alas.ka ,Oil.& Gas Cons. .CQnmÜs$l~ Anchoragg ) ) Badami 010 Page 3 June 18, 1997 This conservative approach allows BPX confidence in ensuring the injection domain is contained. Normal mechanical integrity tests will be performed on the well to identify any mechanical failures. The well will also be monitored for any unusual changes in injection pressure and rate, which might indicate loss of containment, such as continual lowering of injection pressures. Logs that might be run to investigate unusual well responses are temperature or borax logs. These are both near wellbore logs and could help identify channels behind casing, but from previous experience are unlikely to give fracture height. Another form of monitoring is a pressure falloff test, several of these will be performed in the well's life. The pressure falloff test should help delineate the maximum dimension of the injection domain, if not the exact shape. As discussed with Mr. Crandall, BPX would like to meet with the AOGCC to discuss the surveillance plan for the Badami disposal well. 4) Area of Review There are no existing or planned wells with a quarter mile radius, measured at the top of the confining zone, of the Badami disposal well. Therefore, there are no wells within the Area of Review (AOR) for Badami. Under separate cover BPX will forward a map which shows the AOR. Inquiries regarding this clarification should be directed to Ms. Alison Cooke at this office. Sincerely, ~ REGEIVED David A. Wallace HSE Manager .. 20 1997 Alaska Oil & ¡'~ ~ ,., - . . uas Lons. Commis~' ~chorage DAW/KPB/ADC cc: Bob Crandall, AOGCC SC¡-\\~\j!~~JEe JUN ~1 (J 20D4. ~;:, (' (~:, ~\\ ¡>. t t'¡::: Ii"'; ¡ 'i .J flj C» f\\ ~ f'\ Ü· 11 .." ...., ,\;, _L "I. 1'4 ~) U LU 9ì -4000 -2000 v "'C ::s ...... .~ ~ 10000 Departure I ,. -4000 I , -6000 I I I I I I I I I I I I -8000 Scale: I inch = 2000ft ~. ì .Custo~~r: :Shar~d.~ervices Drin~ng ~ - : Field: .·6adarnl. ...!: .. .. .. .. :. .... l,.............···· .~ ~ .", : 10049: Pro~~~t~ ;~I~.~~~ :~t.a~~ ~la,r1,eZon~3 . ~ '. ~ . .., .1~72 .. .. . I. Structure: Badami: ~est Pad· : ~.. .., . .""" .... ....:.. ...... ..... ..... ......... ....... ...... ..........,.. "". .,.... ,................,............,.....:.....:..,'.....,'. . . 1'Q327 : \ L 1Ò.149 \L h· . gj' 4° , . ~~ \ . .~: 72 ~ I Exhibit 2 '10077 ~~9 : : ~7 \ ' : : . ~ \ ; . \. :.. ., :.; ..' :. :. '.. ' :1.: 091491 . . . . . 1~21 9:\' CD I ...~.. ......... Ng .... ..~T1·Iz ..... 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')1 8 71 .. .......... / ., ... ';.. " . . . ". ,v. . ... ... 9 '2.6 . ~ 93~ 0045 . . . .~. ... ~~ ~ 9 . 6 7"1 . ,.. , ... ..:).. . 102..), .. ~. . . .... I" , . _HHHH'HH 'HH'HH'H HH,: ~rg·. ~HH~5$~H~~H~~~¡¡ .. i·...··H:f.'..·. ..... '''''¡;'HHit <µ H' 'HH.' ...... .... H.X!H' \~~. '.'¡H'HH 'HH :.. 'H:HH'H_ .~ . ~1~' 'N~~~1~ 1 871 ..Ø).' .'" '~···7··· ~.. .'. . . ,,,~fl 10510.'~'.' .... ,....~......... .,. '. ..... ..' ., :." :\; 6' 9' ~~7 6 72 . ~ : r: : ~: ~, / 8045/· 104~4F ~ ,>< : : : J ~>~ 1~ì25: . .. , . ~'-9' 5~ \6! .1' 8. ~ ~·8. 2 ~ : # g../. ß334 /' ;... : 1000?.·' . . . .:. ;/,;'110244 .:' ..... .~~\ \ \.7'0 :. ::'::8 /'03 ,/ ~/ ooy/ :/'" ·;,>·~::·I":'·: : :'.. - ..... : _. - 1\78û ',,1 J 1JYÞ, \3497' '. ,/ 7.545 ,/. 9"'.JO)/:'- Q~'l ..' 0" .9744. ": ... .. ...;.; . '..' ,.... . Af.l6t~ w:p ~" 6ì-~ ~ J '856'7' Z8$4' ... . 9384/" ,.~ ".' ...... ..... . .'. ...' ....'...... :..'... ... _ . :... . : . : "'. ~77 7t::5flß"~ '\1" ?~/J: i .j'- .7 /' " /'/ !;~/jpOO5..~; .< 9244 ..:. . ~ . '.' ~ - _ . . . .....84 '0'" ~6./. 704588%' . '. ./ 8744 . . '..' ... ... " - ............:....:.... ... .......... ........:.......... ..·..........·i . ~~' ~~7"" <.1 '~~:~. fl'.. I~, 8~··J33.4'.·.-:.········~·~'::'~~~44· ...:...... ..,. ............+.:........ ~··_··,····.··f·······:····..·:····~··:·i··:·..·::·····=- - ..... ?Q,:,¡4iii1i 7 I t / 7.-:...-.~832'¡i99-,/t!.953.- . ..... ...... .. .,. .- - . .:. : . ..'-.: 'H~/_\ ./ '7" 7:126"~/' /' , /c,/.:/-,/ -::..-:-.....7744 :.. ...: .., :.....:..- . : 7c~' Z::~.~ o.U""I,~ . .... I "/ .. ¿: F ......' : 1011'X1 . : . :: : - ::: :. . .403. . ~ d .... 7.815 . 198...1~~'" : . " .~-': :~(}~': : :: : : : : : '. ~;:'33. . _..'... .. .......... .......... H.'. ......... HH!·:B.Im,wr,¡~~'rm +H H'H:r ... HH:I::~;::~:::!H·!l!:I::~~:~ ::¡;{jH H:_ II I I I I I I I ! I, II , I .I¡ I I I I I I I I I' I I I I "1 I I I ., I I " I '1 I f Ii I III I I I I I I ¡- -2000 0 2000 4000 6000 8000 \ 10000 12000 I I I . . . . . . .. . ..... . ~ ....., -.. -4000 -2000 -. . . . . . . . 2000 4000 6000 ...... ...'. .J..., .'.... -.............. .~::< ~. ~:. 8000 ~b.<> , . . "" o 2000 4000 6000 8000 10000 12000 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I Scale: I inch = 2000ft -8000 -6000 -4000 -2000 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I Departure ( ~ 2000 Q) "'C :s ...... '"ª ~- 4000 6000 8000 10000 ( medium to very coarse sandstone and gravel log marker (structure map in appendix C) t ~f/J':;'~~~~i ~ada,mi~rea:, ~?,~ex ~1' -i ~.. "w:~ f . . ! N j ~,/L I~ TT 1 ~~/ : ~! "·4~ ': - ,~"-' ~)~ ~/1.. '. 1\.. I f~ I J Q oJ \ i \' 0 I ' ""I , '\ '-, -\1%'=' U \\. . -r-- ~ j g 1 ~c..A Ln" l' r ¡: B , I · \ 1) \ L...t I \ i ~ : ('Y i Èlad+m¡'t1 ~---+--:~~._.~.~~ ! j~~1 i Im,LmEL! ~ 'U i ~ =""...,.,.-.:~~~1~#_____l-_____.._1___..___ Exhibit 4 Generalized Cross Section Across Badami Unit COLOR KEY I I shale and siltstone MARKER KEY ~-;.._r;-:-~.;~_.~-"..?~-' .'S" permafrost ----- log marker very fine to fine grained sandstone I -2000 _~~.~. _.__b....-....-c..,.~-----"'-··..~·-"'· Badami 4 I --- -~ ,...~__.~<"T~r_...=-~·,,~~''''-- -='1~"-~'-=-----:~ .~.:=:=":_::.: ==- ,- r~ I Ie 1° I -3000 -- I~ -- -- - .- - - - - - - - - - - I i ~-------------- 1E. r ---~--~--__~_ .4000 I ~~.: :t~~~~~~. ~d-: ~ ~~~ ~-~ _ ~~:~n~~J~~~e~; ~;;~~h;~~~~~~;~~~~~:;;:~~;;~::;;-~~~~~::;7;.:.:~· ·4000 m ;;; "" arresting zone .- - . I -. -, '. r~__- ~ '- . - - -..... - - ~ - -';" - -. -, -, , - '-'~: I ..' - - - - - · mark 2 a:: ,_ ~ ,r' ' ..' .' r - - er -- - - - t W ~ -' -5000 ~ =4~.~---,~-------- - - - - -!- - - - - 1- - - - - - - .. : -~ .. :-.", .'j" _iJ1j~ctiorÍ' zone~ - -,~. :::.:.:- ~ ...::.... ,;'" .~..; . i;'{r;~~:::~X " ..~ '." .;~ ",,',. ~ ¡ire-- ' { ·,:!;UÞ.f~ . ~ :.':. . '::"'" . ,,-:::.;:-;' ., -7000 I Uanu F II or;] .J'" "E ,I '" ,. ,,'. .'':~ff\:~:>r'"' - z-~~ (L.r".-?~j~-~ ~~l;:-~':-:' - - - - - ~- - ,- '---:.:.- .- ~---;-. ,-¡.:.=--:"_'--:r',<:-:'-"~',~'~",'_, « ','r', .J',,,.,,,}!, _ _ '.'."" ~ "f"- ___ _ _ _ _ _ I IIIII _ _ _ _ _ _ marker _o¿ r 1.-0,J' '.. . -..... - .-~II!-,,~.~';.-~!!III.~- --.~~~.~~.,-~:.---------- g '::~'.'¡~sí Sa~ ;:ormat~~' _-- ' " , ' , 4 " ',_',.' " " ,,~ - ::- - -- -- - -- - ~ ma"'", 7 ---- .8000 ~...:¡- _~ -=--.::. m :":m _ _ arresting zone ..;.l,c; 'P,~, - - ·8000 ..J'-~--------- L marker 8_~__ . o : " -f . --------- .' -.' --=- ~ í' -------'!"'----------. . ... '. , '..' e ,Canning FormatlonJ conf,"n," I -..... - - - - - - - - - - ... .. - - - - - - - - - - - ::2 ,.,' _. n~.;zone_. . . . . . ---:-_...~.marker9~ - ~r~~~r~r~r~~~~~r~~~~~r~r~~ NE '--"'" ~sw , . ~~.:r'~.~~~.....-~~...... -2000 -3000 -5000 (,¡: ("':, :þ ·~Z z rrJ ~) -- - _,1.1' ", ~~ /:i~'l~:~~~~;' _. . '-1' ..~. _ ~. ..::.--.,-.i " -:-." -6000 -6000 ~~ :.-.-:..,.... , ~ . . :. . . -.".J,":' . , -. ""---..0.--' -7000 .~-. '--' """7' ,,~ ~~~ r---: c: c: ..f- -~......,.> #3 ) ) BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P'Q, Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 By Facsimile ~CJ t'" , Æ ''II d,'''"~'''''' ~~ t ¡ /; l"'l\ .,."" :J.'L...¡I ~,'~''" -. ~,;:~.¡~~~~,t,O,n".',' ...~, ...~ ' " ~ ,',J,i, -;oT-!IA,;¡rJhb~\1 ~ . "...! 4I111,tPJSð~. , _ ,r" _.,¡ Crandall Y../ ¡ t FT~~~.;Jì~t~ '8 ~ ._ ' -.] ~_. Jiartz,~ ¡ : Mahan ""'foot ,__._~_. ,_~ I ~ ~ McMains 1-·----okiând,· ~ - "" '/'.-- -'-~ ..' . ~,_... '_ .¥V0n,dzell. ., -- ,,~. I FILE . . , " " " --I .. ,,~~liœe.rm It(~.!1 ttlfiek1fe!C, ,.._~ May 29, 1997 A!'......¡~ 'J~ViíJ' Or/ I ill (:: Gas (' . ,1n " ·.'OJ/~ ",~ . J(;'t'iOt~1 ': {;-01]1111' . c.[J:J lA'!8S!O{¡ ~.....~ <: 19'9 ì' ~{ Mr. Jonathan Williams U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle WA 98109 Badami Class I Disposal Well WD-1 Revised Surface and Bottom Hole Locations Dear Mr. Williams: On December 3, 1996, BP Exploration (Alaska), Inc. (BPX) submitted correspondence to the Environmental Protection Agency which discussed Badami Project changes. These changes included a new location for the Badami central facilities and drilling pad. The correspondence also discussed two proposed disposal well bottom hole locations" The well coordinates were not listed at that time. The first Badami disposal well BPX plans to drill, WD-1, will have the following surface location: ASP "X" 363756 and ASP "Y" 5906425 NAD 27 - Zone 3 3853 Feet FSL and 256 Feet FEL, See 8, T9N, R20E It will be drilled at an azimuth of approximately 165 degrees to the WD- 2 bottom hole location shown on the December 3, 1996 map. The bottom hole location will be: ASP "X" 364645 and ASP "Y" 5902175 SC/-\NNED JUN 3 0 200(1 ') ) Mr. Jonathan Williams OS/29/97 Page 2 Surface and bottom hole coordinates, azimuth, and trajectory are detailed in the attached well plan. . Please contact Ms. Alison Cooke at (907) 564-4838 if you have any questions. Sincerely, ~~ "'b,~' W Janet D. Platt, Compliance ¡:¡:;:;sor Environmental and Regulatory Affairs JDP/ADC Attachment: cc: Grover Partee, EP A, Region 10 David Johnston, AOGCC SCANNEU JUN 3 0 2004 ...... .,~ ) o o o o ú) 1.þE~~V-&LJr1 ~-DbL..D N ~ 5E~VDIt:E 5 Q) 0 Tie on 0 <.) (.f) 500 - End of Turn 1.00 2.00 3,00 4,00 1 000 - End of Build 7.49 ~'i~o End of Build 14.98 1500 - 17.97 20,96 ...c 23,96 26.95 29,95 -+- 2000 - 32.95 Kick off Point (L 35,97 End of Build Q) 0 2500 - 0 3000 - Ü -f- L 3500 - Q) > 4000 - Q) ::J L 4500 - l- II 5000 - V 5500 - 6000 - 6500 - 7000 - 7500 - 8000 -500 o 500 1000 1500 2000 2500 3000 3500 4000 4500 5000'~500 6000 .1 Scale 1 500,00 ) BP Exploration structure: Badami Well: WD-1 Field: Badami Location: Alaska ------ WELL PROFILE DATA ------ ---- Point ---- lAD Inc Dir TVD North East DlS (deg/1 OOft) lie on 0 0.00 0.00 ° ° ° 0,00 End ofTum 500 0.00 165,00 500 ° ° 0,00 End of Build 1000 5.00 165.00 999 -21 6 1,00 End of Build 1241 11.00 160.00 1238 -53 16 2,50 KOP 2043 35,00 155,00 1971 -337 141 3,00 End of Build 2238 36.08 164.86 2129 -443 180 3.00 End of Hold 5591 36.08 164.86 4840 - 2350 696 0,00 Torget 5734 35,00 172.00 4956 -2431 712 3,00 Target 8908 35.00 171.99 7556 -4234 966 0,00 PRELIMINARY Target 95/8" Vertical Section on 167.15 ozimuth with reference 0.00 N, 0.00 E from 8D-1 SCl~NNEU (,HJN 3 0 200L} ') ) BP Exploration structure: Badami Well: WD-1 Field: Badami Location: Alaska 500 1000 1500 2000 2500 3000 3500 Ep·~~V~ELJn CA ILLuD N G 5EIFt1VIlb:EU!\¡ -2500 -2000 -1500 -1000 -500 0 1000 I I I I I . Scale 1 : 500.00 N 500 - ~ 0 - . TRUE HORTH -500 - -1000- -1 500- -2000- ^ II -2500- ....c -3000- -f- L 0 . -3500- Z -4000- -4500- -5000- \ East => -5500- o o o -6000- o ú) 1000 - 500 - 0 - -500 --1000 --1500 --2000 ^ --2500 II --3000 z 0 --3500 , -+- ::r- --4000 Lower Inj- ) - - 4500 - - 5000 --5500 (J) () - - 6000 0 ([) -6500- PRELIMINARY --6500 g o o - 7000 0 500 1000 1500 2000 2500 3000 3500 <V o u en - 7000 -2500 -2000 -1500 -1000 -500 0 SCANNElL) JUN S V 2004 VV U-I VV pb Vertical Section RKB 56.00 MD Inc. AzI. TVDss TVDrkb Rect. Coordinates Grid Coordinates DLS Vertical Northing Eastlng Easting Northing deg/100ft Section Comment 0.00 0.00 0.00 -56.00 0.00 O.OOn O.OOe 363755.76 5906425.03 0.00 0.00 100.00 0.00 165.00 44.00 100.00 O.OOn O.OOe 363755.76 5906425.03 0.00 0.00 200.00 0.00 165.00 144.00 200.00 O.OOn O.OOe 363755.76 5906425.03 0.00 0.00 300.00 0.00 165.00 244.00 300.00 O.OOn O.OOe 363755.76 5906425.03 0.00 0.00 400.00 0.00 165.00 344.00 400.00 O.OOn O.OOe 363755.76 5906425.03 0.00 0.00 500.00 0.00 165.00 444.00 500.00 O.OOn O.OOe 363755.76 5906425.03 0.00 0.00 600.00 1.00 165.00 543.99 599.99 0.845 0.23e 363755.97 5906424.18 1.00 0.87 700.00 2.00 165.00 643.96 699.96 3.375 0.90e 363756.60 5906421.64 1.00 3.49 800.00 3.00 165.00 743.86 799.86 7.585 2.03e 363757.65 5906417.41 1.00 7.85 ' 900.00 4.00 165.00 843.68 899.68 13.485 3.61 e 363759.13 5906411.49 1.00 13.95 1000.00 5.00 165.00 943.37 999.37 21.065 5.64e 363761.02 5906403.87 1.00 21 .79 ..~/ 1100.00 7.48 161.96 1042.77 1098.77 31 .465 8.7ge 363763.98 5906393.42 2.50 32.63 1200.00 9.97 160.43 1141.60 1197.60 45.805 13.70e 363768.63 5906378.99 2.50 47.70 1241.38 11.00 160.00 1182.29 1238.29 52.895 16.25e 363771.05 5906371.86 2.50 55.18 1300.00 12.75 159.02 1239.65 1295.65 64.185 20.48e 363775.08 5906360.49 3.00 67.13 1400.00 15.73 157.85 1336.57 1392.57 87.055 29.54e 363783.72 5906337.47 3.00 ' 91.44 1500.00 18.72 157.04 1432.07 1488.07 114.395 40.92e 363794.60 5906309.93 3.00 120.63 1600.00 . 21.72 156.45 1525.90 1581.90 146.145 54.57 e 363807.68 5906277.94 3.00 154.61 1700.00 24.71 156.00 1617.79 1673.79 182.205 70.47e 363822.92 5906241.60 3.00 193.31 1800.00 27.71 155.64 1707.50 1763.50 222.485 88.56e 363840.28 5906201.00 3.00 236.61 1900.00 30.70 155.34 1794.78 1850.78 266.875 108.81 e 363859.72 5906156.26 3.00 284.39 2000.00 33.70 155.10 1879.39 1935.39 315.255 131.15e 363881.18 5906107.49 3.00 336.52 2043.34 35.00 155.00 1915.16 1971.16 337.425 .141.46e 363891.10 5906085.14 3.00 360.43 2100.00 35.23 157.93 1961.52 2017.52 367.305 154.47e 363903.56 5906055.03 3.00 392.45 2200.00 35.81 163.00 2042.93 2098.93 422.015 173.87e 363921.97 5905999.98 3.00 450.11 2237.64 36.08 164.86 2073.40 2129.40 44$.245 179.98e 363927.70 5905978.64 3.00 472.17 2300.00 36.08 164.86 2123.80 2179.80 478.695 189.57e 363936.64 5905943.03 0.00 508.86 --' 2400.00 36.08 164.86 2204.62 2260.62 535.545 204.95e 363950.99 5905885.92 0.00 567.71 2500.00 36.08 164.86 2285.44 2341.44 592.385 220.32e 363965.33 5905828.81 0.00 626.55 2600.00 36.08 164.86 2366.27 2422.27 649.235 235.70e 363979.68 5905771.70 0.00 685.39 2700.00 36.08 164.86 2447.09 2503.09 706.085 251.08e 363994.03 5905714.59 0.00 744.23 '2800.00 36.08, 164.86 2527.91 2583.91 762.925 266.45e 364008.37 5905657.48 0.00 803.07 2900.00 36.08' ' 164.86 2608.73 2664.73 819.775 281.83e 364022.72 5905600.37 0.00 861.92 3000.00 36.08 164.86 2689.55 2745.55 876.625 297.20e 364037.06 5905543.26 0.00 920.76 3100.00 36.08 164.86 2770.37 2826.37 933.465 312.58e 364051.41 5905486.15 0.00 979.60 3200.00 36.08 164.86 2851.19 2907.19 990.315 327.95e 364065.76 5905429.04 0.00 1 038.44 3300.00 36.08 164.86 2932.02 2988.02 1047.155 343.33e 364080.10 5905371.93 0.00 1097.28 3400.00 36.08 164.86 3012.84 3068.84 1104.005 358.71 e 364094.45 5905314.82 0.00 1156.13 3500.00 36.08 164.86 3093.66 3149.66 1160.858 374.08e 364108.79 5905257.71 0.00 1214.97 4/21/979:57 AM ::j(;/\~\jh!EÜ JUN ~~ 0 2004 Page 1 of 3 VV U-I VVpO Vertical Section RKB 56.00 MD Inc. AzI. TVDss TVDrkb Reel Coordinates Grid Coordinates DLS Vertical Northing Easting Eastlng Northing deg/100ft Section Comment 3600.00 36.08 164.86 3174.48 3230.48 1217.695 389.46e 364123.14 5905200.60 0.00 1273.81 3700.00 36.08 164.86 3255.30 3311.30 1274.545 404.83e 364137.48 5905143.49 0.00 1332.65 3800.00 36.08 164.86 3336.12 3392.12 1331.385 420.21e 364151.83 5905086.38 0.00 1391 .50 3900.00 36.08 164.86 3416.95 3472.95 1388.235 435.5ge 364166.18 5905029.27 0.00 1450.34 4000.00 36.08 164.86 3497.77 3553.77 1445.085 450.96e 364180.52 5904972.16 0.00 1509.18 4100.00 36.08 164.86 3578.59 3634.59 1501.925 466.34e 364194.87 5904915.05 0.00 156RO_2 4200.00 36.08 164.86 3659.41 3715.41 1558.775 481.71 e 364209.21 5904857.94 0.00 1626.86 4300.00 36.08 164.86 3740.23 3796.23 1615.625 497.0ge 364223.56 5904800.83 0.00 1685.71 4400.00 36.08 164.86 3821.05 3877.05 1672.465 512.46e 364237.90 5904743.72 0.00 1744.55 4500.00 36.08 164.86 3901.87 3957.87 1729.315 527.84e 364252.25 5904686.61 0.00 1803.39 4600.00 36.08 164.86 3982.70 4038.70 1786.155 543.22e 364266.60 5904629.50 0.00 1862.23 -~ 4700.00 36.08 164.86 4063.52 4119.52 1843.005 558.5ge 364280.94 5904572.39 0.00 1921.07 4800.00 36.08 164.86 4144.34 4200.34 1899.855 573.97e 364295.29 5904515.28 0.00 1979.92 4900.00 36.08 164.86 4225.16 - 4281.16 1956.695 589.34e ' 364309.63 5904458.17 0.00 2038.76 5000.00 36;08 164.86 4305.98 4361.98 2013.545 604.72e 364323.98 5904401.06 0.00 2097.60 5100.00 36.08 164.86 4386.80 4442.80 2070.395 620.0ge 364338.32 5904343.95 0.00 2156.44 5200.00 36.08 164.86 4467.62 4523.62 2127.235 635.47e 364352.67 5904286.84 0.00 2215.28 5300.00 ' 36.08 164.86 4548.45 4604.45 2184.085 650.85e 364367.02 5904229.73 0.00 2274.13 5400.00 36.08 164.86 4629.27 4685.27 2240.925 666.22e 364381.36 5904172.62 0.00 2332.97 5500.00 36.08 164.86 4710.09 4766.09 2297.775 q81.60e 364395.71 5904115.51 0.00 2391.81 5591.17 36.08 164.86 4783.77 4839.77 2349.605 695.62e 364408.79 5904063.45 0.00 2445.46 5600.00 36.00 165.29 4790.91 4846.91 2354.625 696.95e 364410.03 5904058.40 3.00 2450.65 5700.00 35.22 170.27 4872.23 4928.23 2411.485 709.2ge 364421.34 5904001.34 3.00 2508.83 5733.94 35.00 172.00 4900.00 4956.00 2430.765 712.30e 364424.00 5903982.00 3.00 2528.30 Upper Inj 5800.00 35.00 172.00 4954.11 5010.11 2468.285 717.57e 364428.59 5903944.39 0.00 2566.05 5900.00 35.00 172.00 5036.03 5092.03 2525.085 725.56e 364435.55 5903887.46 0.00 2623.21 6000.00 35.00 172.00 5117.94 5173.94 2581.885 733.54e 364442.51 5903830.53 0.00 2680.36 ._1 6100.00 35.00 172.00 5199.86 5255.86 2638.685 741.52e 364449.46 5903773.60 0.00 2737.51 6200.00 35.00 172.00 5281.77 5337.77 2695.485 749.51e 364456.42 5903716.67 0.00 2794.66 6300.00 35.00 172.00 5363.68 5419.68 2752.285 757.4ge 364463.38 5903659.74 0.00 2851 .82 6400.00 35.00 172.00 5445.60- 5501.60 2809.085 765.48e 364470.34 5903602.81 0.00 2908.97 6500.00 35.00 172.00 5527.51 5583.51 2865.885 773.46e 364477.30 5903545.88 0.00 2966.12 6600.00 35.00 ' ,172.00 5609.43 5665.43 2922.685 781.45e 364484.25 5903488.95 0.00 3023.28 6700.00 35.001 172.00 5691.34 5747.34 2979.485 789.44e 364491.21 5903432.02 0.00 3080.43 6800.00 35.00 172.00 5773.26 5829.26 3036.285 797.43e 364498.17 5903375.09 0.00 3137.58 6900.00 35.00 171.99 5855.17 5911.17 3093.085 805.41 e 364505.13 5903318.16 0.00 3194.74 7000.00 35.00 171.99 5937.09 5993.09 3149.885 813.40e 364512.10 5903261.23 0.00 3251.89 7100.00 35.00 171.99 6019.00 6075.00 3206.685 821.3ge 364519.06 5903204.30 0.00 . 3309.05 7200.00 35.00 171.99 6100.92 6156.92 3263.485 829.38e 364526.02 5903147.37 0.00 3366.20 4/21/97 9:57 AM Page 2 of 3 ~r ~ f\ll'dç;r' 1I1t\\ ~ () ?nnll WD-1 Wp6 Vertical Section l· RKB 56,00 MD Inc. Azl. TVDss TVDrkb Rect. Coordinates Grid Coordinates DLS Vertical Northing Easting Easting Northing deg/1 DDft Section Comment 7300.00 35.00 171.99 6182.83 6238.83 3320.288 837.37e 364532.98 5903090.44 0.00 3423.35 7400.00 35.00 171.99 6264.74 6320.74 3377.088 845.36e 364539.94 5903033.51 0.00 3480.51 7500.00 35.00 171.99 6346.66 6402.66 3433.888 853.35e 364546.91 t?902976.58 0.00 3537.66 7600.00 35.00 171.99 6428.57 6484.57 3490.688 861.34e 364553.87 5902919.65 0.00 3594.82 7700.00 35.00 171.99 6510.49 6566.49 3547.485 869.33e 364560.83 5902862.72 0.00 3651.97 7800.00 35.00 171.99 6592.40 6648.40 3604.285 877.33e 364567.80 5902805.79 0.00 3709.13 7900.00 35.00 171.99 6674.31 6730.31 3661.085 885.32e 364574.76 5902748.86 0.00 3766.28 8000.00 35.00 171.99 6756.23 6812.23 3717.885 893.31e 364581.73 5902691.93 0.00 3823.44 8100.00 35.00 171.99 6838.14 6894.14 3774.685 901.30e 364588.70 5902635.00 0.00 3880.59 8200.00 35.00 171.99 6920.05 6976.05 3831.485 909.30e 364595.66 5902578.07 0.00 3937.75 8300.00 35.00 171.99 7001.97 7057.97 3888.285 917.2ge 364602.63 5902521.14 0.00 3994.90 '~ 8400.00 35.00 171.99 7083.88 7139.88 3945.085 925.2ge 364609.60 5902464.21 0.00 4052.06 8500.00 35.00 171.99 7165.80 . 7221.80 4001.888 933.28e 364616.57 5902407.28 0.00 4109.22 8600.00 35.00 171.99 7247.71 7303.71 4058.688 941.28e 364623.53 5902350.35 0.00 4166.37 8700.00 35.00 171.99 7329.62 7385.62 4115.488 949.28e 364630.50 5902293.41 0.00 4223.53 8800.00 35.00 171.99 7411.53 7467.53 4172.285 957.27e 364637.4 7 5902236.48 0.00 4280.68 8900.00 35.00 171.99 7493.45 7549.45 4229.085 965.27e 364644.44 5902179.55 0.00 4337.84 8908.00 35.00 171.99 7500.00 7556.00 4233.625 965.91 e 364645.00 5902175.00 0.00 4342.41 Lower Inj ({; () ";<;, Z ;:: jTj >_-4"- '" '"- -- c: z ~ C') í'-' c:J CJ k!~ 4/21/979:57 AM Page 3 of 3 #2 SCl~~\H\~EC; JUN ~ 0 200·:) May 1997 20 ACC 25.252 North Slope basin Badami Unit Application For Disposal Injection Order ') ~' ) ) i' ') mi BP EXPLORATION BP Exploration (Alaska) Inc, 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 By Certified Mail # 2 Lj I f.:> 5D3 ,~8tf May 22, 1997 Commissioner David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Application for Disposal Injection Order Badami Unit. North Slope Basin REŒEIVBD Dear Commissioner Johnston: MAY 27 1991 âlaska OU &. Gas Cons. CQ.~~$l~Uì , ~hQrag.ø " ",1->'"' BP Exploration (Alaska) Inc.(BPX), as operator of the Badami unit, hereby makes application for a disposal injection order to authorize injection of Class II drilling and production wastes into strata within the unit boundary. As BPX has discussed with Ms. Wendy Mahan of your staff, a Class II disposal injection order is needed to provide a contingency for our Badami project in the unlikely event that the Environmental Protection Agency (EP A) does not issue a Class I well permit prior to commencement of drilling operations. Development drilling will begin on or about September 1, 1997, and a disposal well will be the first well drilled. A ruling is requested that will allow for appropriate planning and other activities to occur before that time. Suitable injection zones have been identified between 4900 and 7350 feet. They are bounded by arresting zones and upper and lower confining zones. The waste disposal system will consist of a solids grinding plant, a pipeline network, manifold hookups, tanks, pumps, and a Class II well. The injection stream will consist of drilling muds - 'I¡"---, q II ¡ '\ n '2" (\[1 ~ SC/\Nf\H::)o" , ,,[I.) I~' ,"Ii (~ "J .I¡ ) ) Application for 010 Page 2 May 22, 1997 and cuttings, production fluids, and RCRA exempt wastes that are suitable for injection into a Class II well. The EP A Region 10 office has ruled that there are no USOWs within the Badami unit boundary (May 12, 1997 correspondence from Mr. Jonathan Williams, EPA, to Ms. Alison Cooke, BPX). A copy of the EP A letter is attached for your reference. The application and supporting information was prepared in accordance with AAC Title 20, Chapter 25.252. It shows that wastes will be confined to the injection zone and contamination will not occur above the confining zone. Inquiries regarding clarification should be directed to Ms. Alison Cooke at this office. Sincerely, Çid;Þ~;~r HSE Manager OAW/AOC Attachments cc: Johnathan Williams, EPA Region 10 (letter only) ç::.r",~\hJi\,I~::-h·" JUtI.¡ ~ D 200 1 '\)~ii "S\"j 'j~.t..) , ". Hi d) i) _ ,r.,,, 20 AAC 25.252 (c) 1 (c) 2&3 (c) 5 (c) 6 (c) 7 (c) 8 (c) 9 (c) 10&11 (d) & (e) Exhibits 1 2 3 4 5 6 7 8 9 10 11 12 '\ Table of Contents Plat of Well Locations Geologic Details Well Logs Well Construction Waste Types and Volumes Injection Pressures Fluid Confinement Formation Water Salinities Mechanical Integrity Unit Boundary Spider Map of Well Courses Type Log - Badami #4 Well Generalized Cross-Section Structure Map Marker #8 Structure map Marker #3 Structure Map Marker #1 Seismic Section Permafrost Map Wen Schematic Well Head Valving North slope Disposal projects ) II SCi,\~\H\jEL; JUN ~~ 0 2004 ) ) Well Locations 20 AAC 25.252 (c) 1 Exhibit 1 outlines the Badami Unit and Exhibit 2 is a spider map developed in November 1996 showing the proposed development plan for the Badami project. There will be approximately 36 conventional wells drilled from a central pad. Surface casings will be set in a confining zone at approximately 4200 feet. The first well drilled will be for disposal of Class IT wastes. It will be directed in a sout~erly direction away from the other wellbores The spider map shows two disposal wells, WD-l at an azimuth of 250 degrees and well WD-2 at 165 degrees. Please note that the location named WD-2 on the spider map will probably be drilled first, in September, 1997. Throughout the remainder of the document this well location has been renamed WD-l. The WD-llocation (identified on the spider map) will be referred to as WD-2, and would not be drilled unless required at a later date. There are no existing wells within 1A mile of the proposed injection points at depth. The closest existing well is Badami #1 which is 4200 feet from WD-l and 3200 feet from WD-2 at the proposed upper injection interval at 4950 feet (subsea). All of the proposed producing wells will maintain a minimum offset of 2000 feet at the upper injection zone. The lower injection zone at Badami #1 is 6000 feet from WD-l, and 5000 feet from WD- 2. Surface Owners and Operators 20 AAC 25.252 (c) 2&3 The State of Alaska is the only surface owner within or adjacent to the Badami Unit and no other operators are in the development area; therefore, no copies of the application need to be distributed and no notification affidavits are required. 0C!\~\~NE[> ~ßVN 3 0 2001:1 ) ) Geolofic Details Maps, Cross Section, Well Lo~, Structure and Stratifraphy 20 AAC 25.252 (c) 4 Introduction Following is a description of the geology of Tertiary (Paleocene to Oligocene) age stratigraphy across the Badami Unit Area with specific reference to proposed injection and confining intervals. A series of informal key markers are identified and correlated from wireline logs. These are summarized in the following table and are shown on the . type log (Exhibit 3) and the generalized cross section (Exhibit 4). These markers are strictly litho-stratigraphic but can be correlated regionally. The intervals comprise siliclastic rocks in the West Sak, U gnu and Sagavanirktok Formations (FM) overlying a thick shale sequence called the Canning Formation (equivalent in part to the Seabee shale to the west). Structure maps on key marker horizons are presented in Exhibits 5-7. The overall sequence including the Canning, West Sak and U gnu strata comprise the final regressive sequence in the Middle Brookian of Tertiary age (Paleocene to Middle Eocene). The overlying Sagavanirktok strata comprise at least two cycles of transgression-regression in the Upper Brookian section of younger Tertiary age (Upper Eocene to Oligocene). The Middle Brookian sequence shows a pronounced upward shallowing cycle starting with deep water marine shales (Canning FM) followed by shelf shales, siltstones and very fine to medium grained sandstone (West Sak FM) and capped by shallow shelf and coastà1 plain / fluvial fine to medium grained sandstone (U gnu FM). The strata in this sequence are moderately consolidated. Sandstone porosity is susceptible to degradation by compaction (rather than cementation) because of the high content of ductile lithic sand grains. The Upper Brookian sequences begin with a major shale unit which is the Fesult of a transgression creating a subsiding muddy shelf. This is overlain by a sand unit recording fITst regression and then transgression sequences. The sand is fine to coarse grained (some gravel) and of fluvial to shallow shelf origin. Continued transgression resulted in shelf mud deposition creating a thick shale unit which is overlain by 3000 to 4000 feet of largely coarse sand and gravel resulting from the final regressive phase of the Sagavanirktok. SCANNED JUN 3 {) 200~ ') 0) The Sagavanirktok sands and gravels are loosely consolidated and have maintained much of their original porosity framework owing to their shallow burial. The base of the pennafrost intercepts this coarse member of the Sagavanirktok and is evident in all wells in this coastal area. Additional discussion, maps, and x-sections on the geologic sequence are included in the Class I Industrial Well Pennit Application submitted to the EP A and copied to the Alaska Oil and Gas Commission in April, 1996. Reference is ~ade to Section 3 and Appendix C of that document. Formation I Marker Sag FM. regressive clastics --------------------------marker 1 Sag FM. upper shale --------------------------marker 2 to Sag PM. -transgressive sand I marine shelf bars to deltaic sands and mud ----- --- - - -- ------- --- ----- marke r 3 Formation Names Tertiary Age Oligocene late Eocene --------.-----..-- mid Eocene , to late Paleocene Depositional EnvironmentILithology shelf sands overlain by coarse fluvial clastics I marine shelf mud and silts Sag FM. -regressive sand I shoreline to fluvial deltaic coarse clastic unit --- ----- --- -- - ---- --- --- --- marker4 Sag FM. - major shale barrier I deep to shallow shelf shales and siltstone --------------------------marker 6 U gnu Formation J shoreline to fluvial deltaic coastal plain sands --------------------------marker 7 West Sak. Formation ----------------- ------ ----marke r9 Canning Formation shallow shelf shale, siltstone and sandstone bathyal to deep shelf & shelf edge shales Note: 1) Sag FM. = Sagavanirktok Formation 2) marker 8 is top of a shale horizon near the base of the West Sak Foqnation Geolo~y of the Tertiary Upper and Middle Brookian Strata The geologic subdivisions encompassing the confining, arresting and proposed injection zones are shown on the type log. Badami #4 was picked as the type log based on its SCl\NNED ,JON 3 0 2004 ') ) proximity to the proposed development area and disposal well site. Other wells close to the development area are Badami #1, #2, #5, and Mikkelsen Bay State #1. These wells best depict the expected properties of the confining, arresting and injection zones. Basal Confininf Zone Canning Formation: In the Badami Unit area the name Canning Formation is used for the thick (2,500-3,000 foot) shale unit which lies benea~ the West Sak Formation and above the Hue Shale (includes the "HRZ" unit). In the Prudhoe Bay Unit this unit is called the Colville Mudstone or the Seabee Formation. In this area, approximately the lower third of the Canning Formation is Upper Cretaceous in age and the upper two thirds is Lower Tertiary (Paleocene to Eocene) age. This thick unit contains chiefly shale and shaley siltstone originally deposited as muddy sediments spread on a deep marine slope and basin plain with maximum water depths of around 3,000 to 4,000 feet. The marine slope prograded to the northeast. These slope sediments are overlain by deposits of the marine shelf, shoreline and coastal plain environments. The transition from the slope to the shelf is marked by the gradational contact (marker 9) of the Canning Formation and overlying West Sak Formation. The shales and muddy siltstones of the upper Canning Formation are regionally continuous. The contact with the overlying West Sak Formation (marker #9) is gradational and subject to irregularity caused by inter-tonguing of West Sak fine grained sandstones with the underlying Canning shales. For this reason a structure map of marker #8, (Exhibit 4) which is a regionally correlative marine shelf shale within the West Sak Formation, is used to better depict the structure of beds near the contact. Proposed Injection Zone The proposed injection zone includes the section from the base of the U gnu Foimation (marker 7) to the top of a thick regressive sandstone unit in the Sagavanirktok Formation (marker 3). This encompasses about 2300 to 2400 feet of section; however, a major _ barrier shale unit approximately 1750 feet in thickness divides the Ugnu Formation from the overlying Sagavanirktok sandstone unit. Ugnu Formation: In the Badami Unit area the Ugnu Formation is 200 to 250 feet thick and composed predominantly of sandstone with interbeds of mudstone and siltstone with rare thin coal beds. The top of the U gnu (marker 6) is picked at the abrupt contact , (indicated by wireline logs) with a regionally correlative mudstone. This change in SCANNEL: ,JUN ~:~ 0 2nD¿~ ) ) lithology is indicative of the beginning of a marine flooding event and the end of the Middle Brookian regressive episode. The U gnu Sandstone beds have a variety of wireline log signatures indicating shifting environments of deposition ranging from fluvial, to marine deltaic channels, to shoreline, and shallow marine near shore sand bars. The coals and mudstone are consistent with deposits in bays, lakes and swamps characteristic of delta environments. The U gnu sands are loosely consolidated and apparently maintained significant original porosity and permeability (average 27% porosity and ±~SOmd permeability, range ISO to 750 milidarcies, based on log analysis of the four Badami wells). The interbedded mudstones should provide at least local barriers to vertical flow. Because of the relatively high net reservoir sand to gross interval (approximated at 40 to 60 percent) connectivity between U gnu sands~should be expected. The major shale barrier overlying the U gnu Formation provides confinement immediately above this injection zone target. The West Sak Formation and Canning Formation provide thick arresting and confining zones below the U gnu Formation. Major Shale Barrier: A basal Sagavanirktok unit of 1750 feet of shale and siltstone (with very rare and thin beds of sandstone) constitutes a major barrier within the injection zone. The unit records the major marine transgression at the beginning of the Upper Brookian during which aggradational deposits of mainly muddy sediment accumulated on a broad shelf. Several aggradation cycles are visible in the unit as "cleaning upward" sequences on the wireline logs (gamma ray decreasing upward; resistivity increasing upward), These sequences range from 100 to 400 feet in thickness and generally have a few thin beds. of very fine to medium grained sand interbedded with silt at the top. Near the top of this major shale barrier unit is a clay shale unit (about 200 feet thick) which has a much higher gamma ray reading. This is an apparent condensed clay which has règional extent, and its sharp base (marker 5) is used as a datum for log cross sections. The upper contact of the major shale barrier (marker 4) is picked at an abrupt gamma ray and resistivity decrease reflecting the clean sands and gravels of the initial regressive unit of the Sagavanirktok Formation. Sagavanirktok Initial Regressive Sandstone Unit: A zone about 300 to 400 feet thick of mainly unconsolidated sands comprise the top of the proposed injection zone. This upper target for injection is dominated by medium to very coarse sand with some gravel generally at the base of the unit. Thin interbeds of mud, silt and clay are present but do not appear to be laterally extensive. The unit is interpreted to be the product of fluvial channel deposition resulting from a sudden increase in sediment supply and possibly sea ~':"'(t--.^~~I" Be\~-, II'~ ilìl.j "J) ;~ ...,OO-í ~~'))~~:9!rè.B'\1~JC.~¡..~ ~..' ~J~" o'¡) l' t." '.."11 ') ) level drop. This thick basal unit of Sagavanirktok sand deposition is an extensive and correlative deposit within the Badami Unit The reservoir properties of the Sagavanirktok initial regressive sandstone unit are very good with average porosity of about 31 % and permeability ranging from 500 to 2500 milidarcies. The shallow depth of burial and coarse nature of the sediment have led to preservation of a very large amount of its original porosity and permeability. The unit also has a high net sand to gross content of about 70 to 90 percent. The upper contact (marker 3) and top of the proposed injection zone is picked at the base of the lowest major correlative mud bed of the overlying unit. The influx of mud as major units above the contact may indicate the initial onset of a slow marine transgression Upper Confininf Zone Sagavanirktok Upper Shale (Mud) Unit: Above the upper arresting zone a 300 to 500 foot thick unit of dominantly mud and muddy silt is present in the Sagavanirktok Formation across the Badami Unit area. This mud dominated unit constitutes the Upper Confining Zone. This upper shale unit is very similar in composition and log signature ("cleaning upward "cycles) to the major shale barrier which divides the proposed injection zone. The upper shale unit is interpreted to have been deposited on a mud dominated marine shelf during the maximum transgression of the sea. This led to the widespread mud deposition of uniform thickness.' Sand interbeds within this unit are rare within the Badami Unit development area but appear to thicken in wells at the northwest and west edge of the Unit area. At the top of the upper shale (marker 1) there is a correlative shale (mud) bed of75 to 125 feet in thickness. This shale results from the most widespread mud deposition prior to the beginning of marine regression and the upward increasing dominance of sand deposition. Structure Structure maps for marker horizons 1, 3, 8, and the base of permafrost are included. These maps were constructed from contouring well data and are not directly constrained by mapping of seismic data. There are s.ix wells (Badami #1, #2, #4, #5, West Mikkelsen #2 and Mikkelsen Bay State #1) within the Badami Unit outline and effectively three wells (East Mikkelsen #1, West Mikkelsen #1 and #4) adjacent to the Unit. SC/\NNEIC" JUN J 0 200..~ ), ') The structural dip on the ~arker horizons is relatively simple with dips of about one to two degrees toward the northeast to east. Shallow horizons, such as marker 1, have dip generally toward the northeast. Progressively deeper horizons show dips to the east- northeast with the deepest, marker 8, showing predominantly east dip. Examination of the shallow horizons on the 3D-seismic data did not indicate any significant offsets due to faulting (See Exhibit 8). The structUral contour of the permafrost base is shown in Exhibit 9. Base-permafrost picks on thewireline logs depend primarily on the quali,ty of resistivity and sonic log measurements, as well as the sharpness of the transition from frozen to non-frozen sediments. Permafrost is present on land to depths of around 2000 feet. Offshore the base of permafrost begins to èlimb as the water deepens. The base is projected to be at 1600 to 1700 feet at the northern boundary of the Badami Unit. Occurrence of Hydrocarbons Within the Badami Unit area, there are no indications of trapped hydrocarbons in the upper part of the Canning Formation and shallower formations. Residual oil shows are present in some of the area wells in the West Sak below marker 8. Farther to the west (10 miles) in West Mikkelsen Bay #1 the residual oil shows are present throughout the West Sak fine grained sands. Although the possibility exists for gas hydrate to be trapped in Sagavanirktok sands and gravels at the base permafrost there is no indication of this type of hydrocarbon occurrence within the Unit area. Outcrops and Rechar~e None of these formations proposed as confining, arresting or injection zones outcrop in the general area. Within the Badami Unit the top of the Upper Confining Zone is in excess of 3300 feet deep and the top of the proposed Injection Zone is in excess of 4200 feet subsea. An examination of regional seismic lines shows that these zones come near or to the surface approximately 20 to 25 miles southwest of the Badami Unit. Approximately 10 to 15 miles southwest, the Upper Confining Zone and subsequently the Injection Zone is projected to intercept a 2000 foot thick permafrost zone. The thick permafrost (generally at 2000 feet or greater onshore) is considered a barrier to recharge and discharge. SC/\NNEC: ~HJN 2 0 200¿1 ') ,) Well Lo~s 20 AAC 25.252 (c) 5 Well logs will be provided when the disposal well is drilled. Logs from the existing exploratory wells have been provided to the Oil and Gas Commission. SC!\NJ~~::C; tlON 3 Ð 20D4 ) ) Well Construction 20AAC 25.252 (c) 6 Construction Procedures and Details Disposal wells will be directionally drilled to a bottom hole location with departure of approximately 4020 feet and to a final vertical depth of ~pproximately 7500 feet. This discussion details construction for well WD-l although there is a possibility the WD- 2 location will be drilled first. The drilling program calls for kicking out from the vertical at 500 feet, building angle to 35 degrees, and maintaining an accuracy that will allow for hitting within 200 feet of the target. All construction requirements exceed the specifications required by the State of Alaska regulations. The casing-cementing program is depicted in the schematic of Exhibit 10. The surface hole will be logged as specified to ensure that the surface casing shoe is set near the base of the confining zone and well bonded to the fonnation. This placement, plus the use of Class-G cement as the tail slurry around the casing shoe will ensure good zonal isolation up to the permafrost. A full logging program will be run in the lower hole. The long string,will be cemented with an excess volume to ensure bonding. Zonal isolation will be verified by cement bond logs. Both surface casing and long string integrity will be verified by pressure testing. The tubing by casing annulus will be isolated above the injection intervals by stabbing a tubing seal assembly into the injection packer's polish bore receptacle. A landing nipple will be installed in the tubing string below the pennafrost at 2200 feet. The annulus will be filled with gelled sea water with a diesel cap for freeze protection prior to initiating heated glycol circulation down the heater string. These fluids will be treated with corrosion inhibitor. The tubing and tubing by casing annulus will be pressure tested to 3000 psi. Should the well not pressure test satisfactorily the tubing will be removed and the problem corrected before the drilling rig leaves location. The well head assembly is shown in Exhibit 11. The wellhead, controls, arid monitoring instrumentation will all be enclosed in an insulated and heated well house. The lines to the well will be heat traced and insulated. ~~ ti'~-~'~ ~l ~),J c-] r'ìI¡ 20D'~ SCJ{~Ü~EL\; -:..11 ,.H~¡ \~))~) . ,.'-~ ') ) Proposed Drillin~ and Completion Profram : Well WD-l Surface location: (Approx.) ASP "X" 363756 & ASP "Y" 5906425 3853' FSL & 256' FEL Sec 8, T9N R20 E ASP "X" 373711 & ASP "Y" 5900978 3858' FSL & '779' FEL Sec 15, T9N R20E 200 ft Radius (+1- 200 feet) Target location: (Approx.) Target Accuracy Estimated start date: September 1997 Maximum angle: Kick off depth: 36 degrees 500 feet MDrrVD Wellbore azimuth : Kelly bushing (KB) elevation: N 165 degrees E (average angle) Assumed 50 feet above ground level Item and Depths Subsea TVD (BKB) MD (BKB) (measured depth ) (below rig floor) 20" Conductor +110 Base Permafrost 1930 1959 1959 Top Confining Zone 3780 3830 4182 13 3/8" Casing Shoe 4200 4250 4693 Base Confining Zone 4230 4280 4729 Top Injection Zone 4900 4950 5543 Lower Injection Interval 7150 7200 8277 Base of Injection Zone 7350 7400 8520 9 5/8" Casing Shoe (Target) 7500 7550 8703 ,~ ", 1\ 11' I" IF'''(-' njN C)) ft¡ 200·9 ~)'c.[-'u~ ~\b.,..L.h ¡ d IJ' ,- ,(" ) ) Logging Program Open Hole: 17 1/2 Surface Hole: DIL/GR/SP/Caliper (From TD to 500' ) 12 1/4 Hole: DIL/GR/SP/BHC/CNL, RFf/GR (If hole conditions allow) Cased Hole: Cement bond log from 13 3/8 shoe up to 500 feet. Cement bond log from total depth to 13 ~/8 shoe. Directional gyroscopic survey run after rig released. Freeze Protection Plan The 4-1/2 X 9-5/8 tubing annulus will be freeze protected with corrosion inhibited diesel from the surface down to the base of the permafrost until heated glycol is circulated through the 7" heater string. Casing I Tubing Specifications Type Size Weight Grade Connection Tension Burst Collapse Surface 13 3/8" 68 lb 1ft K-55 Butt 1,140,000Ibs 3450 psi 1950 psi Inj. Csg 9 5/8" 47 lb 1ft N-80 NSCC 1,161,000 lbs 6870 psi 6620 psi Inj. Tbg 4-1/2 " 12.6 lb 1ft L-80 MSS 304,000 lbs 7780 psi 6350 psi Cement Volumes 13 3/8 Inch Surface Casing : Measured Depth: 4693 feet Basis: Pump twice Annular volume (17 1/2 X 9-5/8") Total Cement Vol.: 6500 (cu ft) Subject to revision Lead Slurry Vol.: 2000 (cu ft) 1041 sacks (sx) Cold Set III at 1.92 Cll ftIsx (from surface to 500 feet MD below Permafrost) Tail Slurry Vol.: 4500 (cu ft) 3912 sx Class G cement at 1.15 cu ft/sx (from 500 feet MD below Permafrost to casing shoe) ~C!\~tNEr!) ~JUN 3 0 2004 ') ) Top Job: If no cement returns to surface: Pump 250 sx Cold Set III at 1.92 cu ftlSx. 95/8 Inch Injection Csg : Measured Depth: Basis: Total Cement Vol.: 8703 feet 12 1/4 X 95/8 annulus volume with 30 % excess plus lap of 13 3/8 shoe. ' 1950 cu ft, 1655 sx at 1.18 cu ftlsx. Subject to revision based on hole conditions. Construction Procedures · Set and cement 20 inch conductor casing at ±110' TVD. Move in the drilling rig. Install the diverter and function test. · Directionally drill a 17 1/2 inch hole to the surface casing point. Rig up and run E-line logs: DIL/GR/SP/ Caliper. Run and cement the 13 3/8, surface casing. Install the blowout preventer (BOP) and pressure test per AOGCC regulations. · Run cement bond log from shoe depth to 500 feet. · Pick up a 7 3/4 inch bottom hole assembly (BHA) and run in the hole. Test the casing to 2,500 psi for 30 minutes. · Drill a 12 1/4 hole through the proposed injection interval to total depth (TD). Rig up and run E-line logs: DIL/GR/SP/BHC/CNL and RFT/GR if hole conditions allow. · Run the 9 5/8 casing to TD. Cement the string from TD to above surface csg shoe. Circulate out excess cement. · Clean out the 9 5/8 casing with a bit and displace the wellbore to clean sea water. · Run a cement bond log from TD to the 13 3/8 casing shoe · Run the 7 inch, 26# heater string and hang off in wellhead. t;Cl\NNED ~JUN ~ Ð 2004. ) ) · Run 4 1/2 12.6# L-80 tubing with down hole check valve. Freeze protect annulus with corrosion inhibited diesel-gelled water. Test the tubing and tubing annulus separately to 3000 psi. · Install the wellhead and test to 5000 psi. . Release the drilling rig. · The drilling fluid program and surface system will conform to the regulations set forth in the AOGCC Regulations - 20 AAC 25.033. SCþ ~~N~::~-') q 'i\1, (¡,} n, 2' 00 ~ .....~u1\J,' oi~,-, ~J ~_'. ~". c? {r _'. . ¿j ') ) Waste Sources and Characteristics 20 AAC 25.252 (c) 7 The Badami waste disposal system will consist of a solids grinding plant; a pipeline network that collects routinely generated and compositionally consistent wastes from the slurry plant, process vessels and wells; manifolding hookups for intermittent batch loads; and an injection facility that consists of tankage, pumps and a Class II well. Class II wells are defined as wells which inject wastes brought to the surface in connection with oil and gas production, with natural gas or liquid hydrocarbon storage operations, and may be mixed with other wastes from plant operations; unless those wastes are classified at the time of injection as a hazardous waste under 40 CFR 261.3. Class II wastes acceptable for injection must originate down hole and will include the following: Water Based Cuttings Oil Based Cuttings Water Base Mud Oil Base Mud Well W orkover Fluids Water Gel Fresh or Sea Water Stimulation Fluid Frac Sand Crude Oil Diesel Methanol Production Vessel Sludge/Sand Production Line Pigging Waste Reserve Pit Meltwater Well Cellar Fluids Class II Contaminated Gravel Produced Water Cement Wastes Well Completion Fluids Rig Wash Class II Waste Rinsate Other Class II Wastes Typical Injection Stream The following typical disposal stream is projected for Badami over the life of the project. · Industrial waters consisting of sea-source, produced brine, fresh, and water gel ( 64 percent) · Water-based drilling mud (14 percent) · Water-based drill cuttings (2-3 percent) · W orkover fluids, crude oil, vessel sludge/sand, diesel, methanol, spent acid, cement, frac sand, snow melt and other minor waste streams (20 percent) ..- -, J' IN I '-ì n 20(1/1 5C¡\~H~H:J\ ,-l) \ ~:!! i." -,' : ) ) Injection Rates /' (fl.') 0y'~ ;-' 1/'" V "_,, The estimated maximum injection rate is 3000 BPD. This will occur while the drilling rig is operating and on an infrequent basis. An average rate over the life of the project will be in the range of 300-500 BPD. sct\NNEU JUN ~\ 0 20D/!- ) ) Injection Pressures 20 AAC 25.252 (c) 8 Field experience from three Prudhoe Bay solids disposal projects provides the basis to estimate pressure trends that will occur as the disposal process proceeds. The following tabulation shows the range of injection pressures that are estimated to occur through the life of a single well. This includes the time from when it is initially completed in the deep interval, through abandonment of that interval as it might become plugged with solids, and further through its life as the shallower interval is used for storage. The intent is to use the lower interval as long as solids can be transported into and through the formation. However, progressive plugging may occur and ultimately further stimulations become ineffective, and a lockup situation evolve. That interval would then be abandoned. The range of injection pressures are relatively high, well above the fracture gradient for the receiving sands (0.65 psi/foot of depth). By necessity, the pressures must be at these levels since the receiving reservoirs must be fractured for a slurry-solids type placement process to work. It should also be emphasized that the expected pressures, as shown, reflect operation of a well when no major plugging of the wellbore or region adjacent to it has occurred. Periodically, the solids being transported and the filter cake additives in the mud will combine to begin a gradual plugging of the then-existing fracture faces and matrix porosity. When this occurs, if injection operations cease and the wellbore is not flushed adequately with .clear fluid, the pore throats and flow channels will become plugged. To, re-initiate communication with the reservoir, surface pressure may sometimes have to be temporarily surged above those pressures listed. This temporary surge acts the same as a stimulation procedure and flow can once again be established. This type of operation is typically done with clean brine. Except for these necessary brief stimulation exercises, it is expected that injection pressures would generally be at or below the indicated levels, which are viewed as maximum levels that would occur as lockup of a completion interval progressed. "-'" '.'-... I\\.'~I~--r\' JUN ç, r~ 20011 ~t;.f\ß':;1 ~ "\.HC ".j "- ' ~) 1.(..1 ,:I i., ) \ / Ran~e of Pressures Expected Under Different Operatin~ Conditions: Water Mud/Solids (S.G.=1.0) (S.G.=I.3) Upper Sand (4900 ft) Expected Maximum Bottom Hole Pressures New Completions 3,500 3,500 Old Completions 4,900 ' 4,900-Lockup Injection Gradient (psi/ft) 1.0 1.0 Expected Maximum Suiface Pressures New Completions 1,300 700-1,300 Old Completions 2,800 2,400-Lockup Lower Sand (7150 ft) Expected Maximum Bottom Hole Pressures New Completions 4,950 4,950 Old Completions 6,450 6,450-Lockup Injection Gradient (psi/ft) 0.9 0.9 Expected Maximum Suiface Pressures New Completions 1,800 900-1,800 Old Completions 3,300 2,400-Lockup Type of Fluid Behavior Newtonian Non-Newtonian SC!ì~,~NE[) .JUN ~~ {~ 200lj, ) k '\ ) Waste Confinement 20 AAC 25.252 (c) 9 The following discussion addresses the environmental and safety risk associated with deep well injection of Badami drilling, and production wastes. It focuses on the possibility of failure to keep injected waste confined to the subsurface strata located below the upper confining zone, approximatèly 4230 feet of depth. The purpose of the assessment is to provide discussion on potential problems, how these problems will be avoided, and how they will be handled in the unlikely event that they occur. Reservoir Fracturinf/Solids Stora~e The sandstone intervals that will receive fluid and solids injection will initially fracture at a gradient of 0.65 psi/foot of depth. With injection pressures that may reach 1.0 psi/foot, fractures will occur. Maintenance of an open system will require an internal pressure greater than the fracture gradient. '; ( ./ At the central pad, approximately 2000 feet of separation will exist between the oil well casings and the disposal well at the upper disposal interval. At the lower interval, the separations will be approximately 2800 feet or greater. Two source water wells, completed under the pad between 2700 and 3400 feet, will also have a separation of several thousand feet The waste disposal wells will be directed as shown on the spider map of Exhibit 2. No natural faulting exists that is significant enough to provide migration paths for breaching the confining shales. This means that subsurface confinement can only be jeopardized by hydraulic fracturing of the confining zone, recirculation of wastes to the surface through a source water well, fluid migration through an uncemented annulus, or an uncontrolled flow while drilling a new well. These confinement issues are defined as follows. Confininf Zone Inte~rity and Subsurface Waste Confinement Fracturing, Placement of Waste, and Confining Zone Penetration : The injection of solids necessitates fracturing the injection zone and transporting solids between fracture planes created and held apart hydraulically. In the lower disposal zone a SCANNEC; ~JUN j 0 2004 ) -----".. ,l, ') ) conventional fracture is expected to develop with vertical growth restricted by the massive bounding shales. Lateral growth, fracture width, and solids transport will be governed by the fluid leakoff rate; which itself, is a function of interacting rock mechanics, fluid rheology properties, and injection rate. An estimate of how extensive the fracture system will be and how efficient storage will become can be made from the following table which compares other slurry injection disposal projects. In addition to Badami having a smaller slurry injection rate it will have a lower cumulative volume spread over a longer period. The lower zone may eventually lock up and become useless. Further disposal would then have to move up-hole or to ,a new well bore. Disposal Project Maximum Fracture Lateral Dimension (ft) Average Inj. Rate (BPM) Prudhoe DS 4-19 Jasper County Texas Prudhoe CC-2A Badami 2000 1200 800 20 10-15 2.5 1 Should the upper disposal interval be needed, it will be perforated in its lower section ( approximately 5150-5195 feet). Vertical fracturing will also occur but a dendritic -- ~ variation may develop. It is even possible that some rock along the fracture faces will become disaggregated, begin to move, and could further enhance solids storage. It is anticipated that vertical fractures will grow from the lower perforations upward to the c:"i/ ,~hale-~.!!!§!º!l~ªt 4900 feet, and may continue to the shale at 4560 (eet. Based on experience monitoring other North Slope disposal wells, the confining zone should not be fractured. Since maintaining an open fracture system will require an internal pressure greater than the fracture gradient and pore pressure of adjacent reservoir rock, this impacts significantly the following aspects of confinement. Recirculation of Wastes Through Source W ater Wells : Two water source wells will be completed in the saline aquifers above 3400 feet. Very probably they will be drilled as fairly straight holes under the central facilities pad. Alternately they might be drilled directionally away from the disposal well. The source wells will be completed between 2700 - 3400 feet. This means that the vertical separation between them and the upper disposal zone will be 1500 to 1900 feet, ,..... t!~'l\ r~ r'i'l.J'~ r) n! N (I) n, 2 0 0 ,~ ~VIr~n~1'\JE~,,' d í..J ,1 ~',~ ilß - I~ ) ) ler~ [;Ie ~, ') ): and with a lateral separation of 2200 feet or greater. For recirculation to occur, the disposal well would have to fracture into these shallow aquifers and a significant amount of fluid leak off into them. With so much vertical and horizontal separation between completion points, wastes would not be able to streamline to a withdrawal well. The likelihood of recirculation is low because all of the development wells will be drilled prior to initiation of source water withdrawal and; therefore, all solids injection will be effectively completed and fracture growth tenninated before the source wells are functional. Subsequent injection of low solids wastes will not be able to generate a directional transmissibility capable of supporting recirculation. Recirculation potential is almost non-existent. Nevertheless, should this somehow occur, recirculated waste would be confined to the production equipment and again be reinjected. It would also be so diluted that it could not be measured. There would be no environmental or safety risk. Fluid Migration Through an Uncemented Wellbore : There are two concerns associated with upward fluid migration in a poorly cemented annulus. Firstly, should migration extend past the confining zone but then leak off to the overlying aquifers, there is a regulatory problem but no environmental or safety issue since fluids would be confined to the subsurface, and in this area no USDW s exist to be compromised. Secondly and more seriously, should migration reach the surface, while no safety issue can be envisioned, contamination of gravel pad, tundra, or surface water may occur. However, for this to happen, fluids would have to move through the source water sands and not be diverted laterally. Uncontrolled Flow While Drilling a New Well : This risk exists because the fracture system will be at a hydraulic pressure somewhat higher than the fracture gradient, and thus greater than the pore pressure of the surrounding reservoir rock matrix. Should the drill bit encounter a major fracture plane and a high enough pressure exist at the time, flow into the uncased wellbore would result. An extreme case could allow flow to the surface until the fracture pressure was bled down. The risk of intersecting a pressurized fracture system with the drill bit can be effectively managed by drilling the wells closest to the disposal well early in the sequence, when the fracture system is smallest. Flowable liquid volumes would also be smaller and less pressured. Clearly the greatest risk would occur if injection was occuring into the upper zone later in the drilling program and a well course had to pass nearby. Should 8CÞ~NINE[\' JUN ~¡; 0 2004 ) ') progressive events cause increasing concern or injection pressures indicate a change in the disposal program was needed, one alternative would be to minimize injection volumes by maximizing use of annular pumping of mud and other rig liquids. Since most of the mud and clay solids generated while drilling below 5000 feet can be pumped with little or no grinding, half of the rig waste could go down open surface casing annuli at alternate locations if that became desirable. This would, redirect a large volume from the disposal well fracture system. Should flow enter a new wellbore either because of bit penetration or a result of extending fracture growth, the following actions would be taken. 1. The injection well would be shut in and the AOGCC notified of corrective plans. 2. The mud system would be weighted up to 13 #/ gallon ( 0.68 psi/it of depth) or the estimated fracture gradient. 3. If the new well continued to flow, a decision would be made whether to route fluids to tankage or shut in at the wellhead and risk breaking down the cement bonding at the shoe of the surface casing. 4. If the well was shut in and the casing-formation bonding broke down, flow would enter the formations above the confining zone until the pressure bled off. 5. If the well was allowed to flow up the drill string to the surface it would be routed to tankage. Surplus fluid might be weighted-up and reused as additional kill fluid, and/or injection might be started into one of the oil reservoir waterflood wells. 6. As a last resort, flow would be diverted to a surface impoundment area for later disposal and cleanup. SCi-\NNEC JUN 3 0 200,1 ') ) Comparison with Similar Disposal Projects There are five waste disposal, injection projects that can be used as analogies to Badami. Four of them are on the North Slope and one in Canada. Their relevance is as follows. Prudhoe Bay CC-2 Facility: This disposal plant has been in operation five years, grinding up drill cuttings for injection into a single Class II well. Disposal volume is over 8 million barrels as shown in Exhibit 11. With a solids content estimated at 7-8 percent, 625,000 barrels of solids have been injected through an open hole completion at 3500 feet. The facility and well have operated without significant problems and no negative environmental impact. Prudhoe Bay Pad-3 Facility: Since 1979 this facility has injected 9 million barrels of wastes which often included a significant volume of solids. At an estimate of 2 percent, this means 180,000 barrels of solids have been injected. These three Class I wells are completed at 2000 feet, just under the permafrost with 30 feet of separation. They are located about 600 feet from the edge of a development drilling pad with over 40 wellbores. Extensive logging and field testing have not detected any up-hole channeling or other problem. Prudhoe Bay DS4-19 Demonstration: This facility successfully operated from 1995 to the Spring of 1997 to test the feasibility of using grind-inject technology for reserve pit closure on a large scale. Injection rates were high (Average rates 20 times higher than Badami) with solids slurry placed in the same zones as those proposed for Badami. The single injection well performed as planned and no up hole communication was detected until March 17, 1997, after approximately 2,000,000 barrels of slurry was injected. Further details on the breaching incident will be in an ARCa report expected by the end of May, 1997. Endicott Island Disposal Well : At the Endicott oil field (Duck Island Unit) located between Prudhoe and Badami, Class II disposal well2-02/P18 has injected 6 million barrels since 1987. The solids content is less than one percent. The well is located on a drilling island with 55 other wells, all on 15-foot centers at the surface. Waste disposal at a depth of 7000 feet has been confined even though numerous wellbores pass within several hundred feet of the disposal well perforations. \SG/~\.N¡\ì!:;~1 í~JN ",} if) 200 ¡j , ,~ ,- c__. ~. I\! ej ~u ~J' ) ) Lloydminster, Alberta Canada, Celtic Formation Fines Disposal Project: Approved by the Canadian Government, this plant has operated for several years disposing of large volumes of fonnation fines and sand generated by a steam flooded oil reservoir. Injection rate is reportedly high, at a depth of 2000 feet. No other operating details are known. Summary The relationship of these North Slope facilities, and others, to the proposed Badami Project is tabulated in Exhibit 12. Further discussion on waste confinement is included in the Class I Well Permit Application submitted to' the EP A and copied to the Oil and Gas Commission in April, 1996. (Reference is made to sections 3 and 6 within the text.) BPX is confident that mitigation of the problems discussed can be managed at an acceptable cost and the impact of an event can be successfully handled should one occur. It is felt the risk of environmental damage should be viewed as minimal to non-existent. 1:::.'11'.... i\ L"qÜ!L:"[ì" q 'N ~) 0 20 O·r¡ ....'lJvr~ß ~¡'ìJCc._· I.) d 1 (), L,. ) ) Mechanical IntefJrity 20 ACC 25.252 (d) (e) Mechanical integrity will be verified after well construction by testing to 3000 psi as outlined earlier in part 25.252 (c) 6. The casing-tubing annulus pressure will be monitored regularly and reported to the Commission on Injection Report Form 10-406. The tubing-casing annulus volume will vary, and the annulus fluid itself will expand and contract due to temperature changes. At the present time it is hard to specify exactly what high-low annulus pressure limits should be established to trigger a warning and possible shutdown. The exact points will need to be established once a repeatable pattern of fluctuation has been established. This can be determined after several months of performance that would include both the summer and winter ambient temperature swings which affect this operation. .... '-. .!' 1\\~i:\~Er" ~UN \f1¡ to 200 ~ ~t..J-~ß~~'~ ~'.d' d ,I ~:i) ~,J ,L¡, ) Exhibits ) ~';/"'\ I '!~b I~!ì' YRJN ~ í'\ 200 ~ " ~v/!-,,~~, '\3.cL ,J ~ ~) ~J .'1' Cartography 5/97. bs12845.dgn ~I ~\ \ I I I I I äll! I , : I : ¡¡; 2 : : : \'" ¡' , . I ' , · I - , · , · , · I' · · ,I'., · ,,' I' · .'.' , I I I \ ' , 2 ~ \ _' .\. _ .i. _ -. -- (?" -~- -- -1m -- t· -- '1-- - - -~ _m -1- - - ' --~~- r _JI__-~~- -1' --- +c'~:j',- I ! I 9 : -0 \ "~T:- \" l' ' : . I . : " I WI" : ~ '. " · p :' " : ' :' _', ¡. : ! . :~ ...; . . .: ctW.LENGE1.... .: -,- -t- - _+___~_. '. ___ ___, -,- +-- - -,- - -+ - - ~ - -'I"""-~, \ 1IGIIAfIIAI< I-:::=- \! \ I I :' ....., ':.,': ,"'", 1__ :: i':: I 17 \. ¡ß , ;5 \ ,,~ \"":..·',..'ëat!!f ¡'.. ,9 \ " r ,,, I ¡~ Ë! I >;; , '\7 19 \ 15 \g ! t'l ,¡; I __.-r~...y. I I··d~.'./ '. I · I \ I \ I I I : '"""'-. : /" ': : ' : ' : ' -r-~:---:'-~_r~-- I ~r~---r~~r-~m·--:-r~ -I $ i : n____-~__;---~--1:--~--~---~- ',--''- I I -::r.-+ I \ I' I \ \ ~ t I I t l,t I " ,I --,- - - - ø-r. .-- - -¡ --, - - -- - -,-~' ---t .-- -}--- - -..-. .........--- I I.. . '.' 'I I 1 ¡ .. ¡ , ¡' ¡ PT ,-<U~.Ont..1 IU..·IT I " ,"_ . __ . _ .' _ . _ . ......... ' . '.nvM'>V'" ".. , r . I I~; ,~I --r-- \ ' ' I 23 I _ œ . . I 25 \--¡--- W I z¡ , BADAMI UNO" . \.' ;W , ¡¡:;. ! ro \. œ I z¡ ¡¡;¡, 2i> , SO , 1 ÞN:Ið_ ! I \ \ , I ¡ I I \ \ \ r _ ' '... I BADAMI-02 I ¡).,fL j I I ,_..... \ · , 1 I PoNa ,- _ '¡~n' c-r.' "iC- -¡-, _.-- - -- ·\----+-~8E~-----IUr----- ----\+--~t~-- --:-~:~=t------\ -- ---;----¡-- w. ..:)3 1 ... re \ t1 I M I S3 , :M I I t "'" ~ -J~~~~=.-:-,:::-~ '80 .r '-~ ' $ ,-t- 3\ ,----- L I 1- ' I :! : ,~I-I- ;', -: ~ --- {~:--~---<-.:-=-- ~~ rloN , . .' . ..,.::' Ie BAQAMI-05 I I I ~, -~ \ --" -,'" . ---,I 'noN "TiN ~ I ----;.,.. ~'- ~ ~ :71 - ,--c- .:r J · '" .. ;ar .-¿' --:-------, :=--- ~- ,'f--- ~- \ " ':/' '. .'.., I ! I BÞfA.... ^1 BADAMt-'04 '-"--I~ ' ',.: '== ' ,~ 'c' = I ~'I I I .., I! I"\fVfrv I I' I I' / ~ I .,., ¡;: , \ f A 3 -L J S t 5. . '" ,8 :> ¡ 1 . ¡¡ I i;; 2 ì ·L .; I . 1 I _ " ,. I _I è:'1"- " : ~"fj'M I ~:æ~Jvr: ~ ,:.t " : ", I ~ " " I ~ , $1 " , ~ ~ ~I :"~: :"" '\lìôrrr_'.A:,-;>:~,,_>~~-"-à;.i~A-~;~-r~'~S{".7; \1 -,- : ~\II '~__'--[,,--: ~ '-= Z ;¡,~ ~ r-..) c:::> C'::J J::::......, (f: () );;. ~ ~~ ~ m fJ SCALE: 111 = 2 MILES Badami Unit Area EXHIBIT 1 _-L I, -.;: - ...... \\ \\ \\ \ ". '\ ~. ~y:\ ~ BADAM= I' """... \ mlOf"N 6O.D I -._-~---- ~~'65 \ -~ ,~ '" ,5) ~uT ':'i:"'7810 i .(Å R" ""'; ~IJ' (j o ;~ " ~ ~... ~ ;) 00 ? LH'o"~ ..,-= ~nQ':3A . II-Y.l-J. i - .... PROJECTION AHO SPHEROID SPECIFICATION ¡ - I IUIIIftI:I ~o a.ownas R.UVØ -.ao , ·t . . IP 1UJV1'I..... --..-........ ....... 11II. -.-... ~ .. .....- -- - --- -- -- ~.,~ I........... -~..........- --......,..-....- --.............--.. --- -' LEG£ND . -8205 Well Data Point Depth in Feet Subsea _ . EXPLORATION (ALASKA' ,He, ~' Badami Area Stucture Map Top Of MBK 90 Flood Shale (Near top of Lower Confining Zone) -,.. Marker (8) Exhibit 5 Çf) (j "r-. ".Y Z Z m n ....,"'" .-. It.. \ '~ (\'~ ~ .. Q ~1y;~ ('" ¿J,? o ~o{{:¡'. l~O "'ù ~~ ' ¿J ·....'·b.: (\ ~~~.JJP .J 7JV'i> \)~, ~~) I ~ o.~~' ¡} JcJ :~ \ ( 'O~ o (;I~ \c=. Of ç,~' ¡;;:;L.?' ..ø= "'~. ) 0° c9~\ ,\ ¡ "...-.. /JÆ (H'.U ð' \ \ ~ IT )) q-Jo)-'!o i . {}~ c: Z 02 \)\) CJ r'-' c=> c:::::::> -+= <? ,..--,~" 0 Jr ~ooo"" PROJECTION AND SPHEROID SPECIfICATION , I ........~- .r&rVØ -.ay , _. .. ... 1P I'IIIV!S .-&II ---..-......... ~ ... -.-... \Mr ......... -.-. - --- Þw;'" ....-..__ ~~...... ,..~.... ....~...........- .........-- oil -... __. ..... .....-.................. -.- -~r LEGEND . -3995Well Data Point Depth in Feet Subsea _ .. EXPLORATION 'ALASKA' INC, -' Badami Area Structure Map Top Injection Zone Marker (3) Exhibit 6 ~~ I --{ \\. ' \ ' ~' ........ ...., I + .,"'.......1 ¡ I .l:_ ;¡} () l> 2' ¿ IT! ') ~"'J -~~ ~. , . i , I {}'ô- o· '<>.Q . dl>o~\ ~!. .~ c:: z' ê;!,;? .~ N C) ----- b, " '1.01> :) 0° C.....' lJ .". ~~, 0 II-.sa-I) PROJECTION AND SPHEROID SPECIfICATION - I ~~.~ ftØVDI ilia' , f , . .11 IEaVØ -.a ...... --........- ..................---- ............,..- ~===- ~-=7=... MI-.w-=':::- -::::-~ -- LEGEND . -3995 Well Data Point Depth in Feet Subsea _ .,. EXPLORAßOH 'ALASKAI INC, .~ Badami Area Structure Map Top Upper Confining Zone -.... Marker (1) Exhibit 7 --- ~. F ... " J- . Seismic Line from 3D. Survey SW Mlkkersen #1 Badami #1 Badami #4 - NE .., .'", 111111111111111111[1[llllillllllllll lilillll!llilillllillilillil¡ilillill¡¡ililiiili¡illllil¡iljllll!II¡i!¡llliili:ilillillil!:llii1Iilimill;:iilIii Ilil!:ill¡;¡il¡I¡¡I¡I!¡I¡:I:I¡:i¡¡¡I¡I~i¡i[:lillii¡lll!!II¡!!illliii!¡¡II:I¡I:¡~!!:li¡!!i¡I:¡i¡¡jl Iii ¡[I:!~I¡il:!!i¡'il¡ Iii ¡iii: !1!¡l;¡!¡!I:i::~'~":'·: ,:, ::';,,: :11' :~::: '::II:~J",11I: ': :: ,:: !l~~~;':.'~ ~~'~,!:~~~';':~~:':'" t :~ :.~, .. 11III1IIIII1 JIll! 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'¡ ¡- mlOAC.&lO.o} "'-."_M ( - -----~----- -1709 - /"~ '". ~ ../ \600______ --;,,,-"/, / - :_~,:" ~_.. _,./~S"'>_ -~:: . _.'.1 ~ ..'. .. I;:' ¡ ......>n'" ". . =' ~: 0 ' --- '" ~ . . «, ~ fßg ,.:Iunu. ~ 0'" '-~ ¿) =0 . .. Q , . 001 go""",_ "" o ~ <l:. \'¡.. '[ ¡¡.~o\\ .l.,,,~ t>o .n"'>.r::. . .. . () "J.. PROJECTION AHD SPHEROID SPECIFICATION J . I auvø~: _:~ ~J~__ ...... ~ ...- ....-. ~... -...-.. .., ......... -.- - --- "'-- --- ,..,.....,.,... ,.......- -,.............- ...-~.......-_.- ....-..~.......-.. ,....... ..,AIM........ ~~ lEGEND . -1900 Well Dolo Point Depth in Feel Subsea _ ., EXPl.ORATlON fALASKA' INC. .~ Badami Area Structure Map Base Permaf rost Exhibit 9 ) Exhibit 10 ) Proposed Completion Diaaram Badami Well WD-1 Tree: Well Head: KOP: Max. Angle: Departure : 41/16" /5,000 psi Cooper' ~. ': 13 5/8" / 5,000 psi FMC 500' 35° Approx 4020' ! \ I ~ I ,.~ ¡'1 \ í! j J. 1 ~l I MD (BKB) 1959' MD PERMAFROST MD (BKB) (measured depth below rig) 20" Conductor 110'MD 7" Heater String 2050'MD 13 3/8", 68#, K-55, Casing . .;- 4182' MD 41/2",12.6#, L-80 Tubing ~"""" "'''''''''''~ ~ONFINING ZONE ~ 4729' MD .... """""'" 13 3/S" Casing Shoe 4693'MD C) , Packer and Seal Assembly .5.s . 1ijt! ('..... " " " " " " " " " " " "" "., I e- <°1 5543' MD L........................................................................,,'\J .. 12 1/4" Hole 5970' MD 9 5/S", 47#, N-SO Casing c- oca ;¡~ UCD CI).. :5'.5 , . 9 5/S" Csg Shoe S703'MD 8520' MD S-1/2" Open Hole ~ '\.:\. " " \.:\. " ',:', ~~ ~STING ZONE~ ~ :~~(J\~\i\~E'C' JUN :~ 0 200£ ') Exhibit 11 ') Well Head Schematic WD-1 Wing Valve Master Valve WELL HEAD - TREE DESCRIPTION - SINGLE TUBING HANGER! WELLHEAD - 4 1/2" - METAL TO METAL RING SEAL ASSEMBLY - SINGLE MASTER VALVE - MANUAL - SINGLE WING VALVE - AUTOMATED FOR SHUT IN - PRESSURE RATING - 5000 PSI - WELL HEAD TEST PORTS - AS REQUIRED - COLD WEATHER METALLURGY - TYPICAL N. S. - CORROSSION METALLURGY - WASTE DISPOSAL WELL - ENCLOSURE (INSIDE INSULATED WELLHOUSE) 1@Is Glycol Circulating Valve SC?\.NNEC JUN 3 0 200/) Exhibit 12 (Revised 11/96) North Slope Solids Disposal and Fluid Confinement (1/96) Comparison to Northstar and Badami Projects Injection Solids Instant Injection Distance to Facility Volume Volume Rate Depth Other Wells Fluid Confinement Data (Bbls) (Bbls) *(BPM) (Feet) (Feet) CC-2 8MM 624M 3-10 3500 +/-2000 J-pad located 2500 ft. away but may be off fracture direction. N pad at 7000 ft. and Q-pad at 5200 ft. Three year average rate 4.4 BPM. (Volumes are thru Sept. 1996). Pad-3 9MM +/-200 M 1-5 2000 600-1 000 DS-6 located on strike with numerous wells within 1200 ft. All ~ surface casings set below injection depth. Suspect horizontal fracture of limited radius and small reservoir pressure buildup. Shales at base of permafrost are sealing. (Volumes are thru July 1996). DS4-19 38MM <0.1 % 8-30 5930-6900 400-1500 Produced water disposal prior to slurry injection. DS4-19 5MM 1137 M 22-27 5622-5627 Solids disposal test at high rates. Numerous pad wells 4MM <0.1 % 22-27 5622-5627 within 400-1500 ft. Seismic events seem to indicate communication up to +/-4200 ft. No communication with offset wells. Extensive annular and seismic monitoring programs are ongoing. (Volumes are thru May 1996). Endicott P-18 6MM <0.1% 1-6 7200 +/-300 Several wells within 300 ft. at injection depth. No reports of uphole fluid migration. Reservoir pressure build up at 300 psi level. iF: GC-1 158 M M <0.1 % 7-40 5000 300-3000 No annular communication problems at adjacent wells or -- Þ GC-2 138 M M <0.1% 7-27 5000 300-3000 on surrounding pads at 3000 ft. Pressure at outlying pads ~ GC-3 83MM <0.1 % 7-10 5000 300-3000 up +/-200 psi. /. rn ;-~ Northstar 116 MM <0.1 % 3-20 4000-6500 +/-2200 Produced water disposal volume (Maximum case). :- Project 4MM 80M 3-5 4000-6500 +/-2200 Project operational wastes. Average slurry injection rate is 1 BPM. I-,. Distance to other wells is 2200 ft., more at depth. Surface casings z ?oÇ) set below upper confining zone. :::>Badami ~Project 4.3MM 60M 3-5 5000-7200 +/-2300 Distance to other wells is 2300+ ft. Surface casings set in upper :=¡ confining zone. Average rate during slurry injection is 1 BPM. ---~ *(BPM = Bbls per minute) #1 -- ~ #fIJ S7"A~ i ~ t, ~~ffi ~ ~ ~ çt 1r~{ pp.o~v-<::: UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 10 1200 Sixth Avenue Seattle, Washington 98101 -, May 12, 199J ENVIRONMENTAL MAY 1 9 1997 & REG. AFFA'AS Reply To Attn Of: OW-13? Alison Cooke, Senior Geologist BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.o. Box 196612 Anchorage, Alaska 99519-6612 Subject: EPA Determination Regarding Underground Sources of Drinking Water (USDWs) in the Badami and Northstar Field Areas of the North Slope of Alaska Dear Ms. Cooke: This letter con~irms and augments our telephone conversation of May ~~ 1997, _regardiri~ EPA's determination that there are no USDWs in- the Badami field area. Also, this letter will serve to document EPA's determination that, based upon the information submitted to date, there are aquifers which narrowly meet the regulatory formation water quality threshold for protection as USDWs in the Northstar field area. EPA determined that there are no USDWs at Badami shortly after receiving the supplemental Class I injection well permit information that BPX sent us on June 10, 1996. That submittal contains a detailed set of calculated formation water quality estimates based upon geophysical borehole log data and a realistic range of technical assumptions. We think that this information amply demonstrates that the aquifers beneath the permafrost at Badami are too naturally saline to meet the Underground Injection Control (UIC) program regulatory threshold of 10,000 milligrams per liter (mgjL) of total dissolved solids (TDS), and thus do not qualify for protection as USDWs under the Safe Drinking Water Act. Our first permit application review letter of September 30, 1996, did not mention whether or not EPA agreed with BPX's assertion that there are no USDWs beneath the permafrost at Badami. Subsequent letters also made no mention of the topic. We think that's because those letters focused upon EPA questions and concerns rather than the many areas of agreement with the permit application. The information BPX submitted on June 10, 1996, had convinced us that there are no USDWs in the Badami o Printed on Recycled Paper ,~ /-, ,\\,</ L:' í i I í\1 ~~ n t)nI"L' ".-., ~ field area, as you know from our past conversations. We trust that this letter will serve to document that understanding. In terms of Northstar, our review of the permit application has led us to conclude that there are most likely some USDWs beneath the permafrost. And we also think that they meet the aquifer exemption criteria under 40 CFR 144.6, as described in the BPX permit application. Therefore, we are prepared to process an aquifer exemption at Northstar as part of the Class I injection well permitting process, as BPX has requested. However, a final decision to prepare a draft permit for Northstar cannot be made until the Environmental Impact statement (EIS) on that proposed project has been completed. Sincerely, (i W~IJ ~ <7 E>"-rJi'[t.^"'\. ..#~ Jonathan Williams, Hydrogeologist Regional UIC Program Coordinator cc: David Johnston, AOGCC SCr!\hH\'q.:;u. n,'¡\í ~~ [\ ?nrí/ì -..;:.....~. ø~~.,ä~~;_/ {,t.. í,:- {-) 't-I !~J
