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Home My WebLink AboutO 033Other Order 33 1. January 12, 2005 ConocoPhillips Alaska, Inc. ltr re: Annual pressure monitoring and Other Order 33 SCP CO Rule 2 requirements 2. February 16, 2005 e-mail re: ID -39 (Some emails held in Confidential Storage) 3. March 2005 e-mail 4. March 31, 2005 AOGCC's ltr to CPA re: Notice of proposed enforcement action 5. April 14, 2005 ConocoPhillips (Alaska), Inc. response to Commission's March 31, 2005 ltr re: Notice of Proposed enforcement Action 1D-39 6. April 21, 2005 AOGCC Scheduling of informal review 7. May 10, 2005 E-mail from CPA to Commissioner Foerster re: basic facts etc 8. May 11, 2005 Submittal of information from CPA re: 1D-39 9. May 11, 2005 Sign in Sheet Informal Review Meeting 10. June 21, 2005 ConocoPhillips (Alaska), Inc. Description of Corrective Actions Other Order 33 ) ') ¡ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue, Suite 100 Anchorage Alaska 99501-3539 Re: ConocoPhillips Alaska, Inc., as Operator of the Kuparuk River Unit; Kuparuk River Field; Well KRU 1D-39 Enforcement Action ) ) ) ) AOGCC Order No. 33 May 20, 2005 DECISION AND ORDER On March 31, 2005, the Alaska Oil and Gas Conservation Commission issued a Notice of Proposed Enforcement Action under 20 AAC 25.535(b), stating that it considered that ConocoPhillips Alaska, Inc. ("CP AI") may have violated provisions of regulation 20 AAC 25.402 and Area Injection Order No. 2B in connection with operating well Kuparuk River Unit ("KRU") 1D-39. The Commission proposed civil penalties under AS 31.05.150(a) in the total amount of $53,250, as well as specified corrective actions. Pursuant to CPAl's request for informal review under 20 AAC 25.535(c), CPAI met with the Commission on May 11, 2005. CP AI also provided by electronic mail written material referred to as "key points" for discussion at the May 11, 2005 meeting. A. Summary of Proposed Enforcement Action In its Notice of Proposed Enforcement Action, the Commission identified an apparent violation by CP AI of Rule 7 of Area Injection Order No. 2B ("AIO 2B") and regulation 20 AAC 25.402 by failing to timely report a well integrity failure that occurred on August 24, 2004, by failing to obtain Commission approval of a plan of corrective action, and by failing to obtain Commission approval to continue injection. AOGCC Order #33 Page 2 of6 ) ) May 20, 2005 The Commission proposed to order the following corrective actions by CP AI: (1) that within 30 days after the effective date of the enforcement order, CPAI correct deficiencies in its surveillance program; and (2) that within 30 days after the effective date of the enforcement order, CP AI provide the Commission with new protocols established to insure the timely identification and reporting of injection well mechanical integrity failures. In addition, the Commission proposed the following civil penalties under AS 31.05.150(a): (i) $5,000 for violating reporting requirements in AIO 2B, Rule 7 and 20 AAC 25.402(f); (ii) $5,000 for violating corrective action plan requirements in AIO 2B, Rule 7; and (iii) $250 per day for each 173 days for violating requirements for obtaining approval to continue injecting in AIO 2B, Rule 7 from August 25, 2005 through February 13, 2005, inclusive. The total of the proposed civil penalties was $53,250. B. Surveillance and Reporting Requirements for Injectors Commission requirements for demonstrating and monitoring mechanical integrity of injection wells are documented in regulation 20 AAC 25.402, and specifically for KRU in Area Injection Order 2B. CP AI does not dispute the facts of the case and acknowledges that KRU ID- 39 did point out the existence of a gap in their annular pressure monitoring and surveillance program. However, CP AI raised several concerns about the proposed enforcement action: (1) the Notice of Proposed Enforcement Action references 1 73 days that had passed between leak initiation and observation; CP AI believes only 171 days passed; AOGCC Order #33 Page 3 of6 ') ') May 20, 2005 (2) the Notice of Proposed Enforcement Action does not accurately reflect that CP AI reported tubing/annulus communication in KRU 1D-39 to the Commission within 1 day following leak observation, and voluntarily self-disclosed that 171 days had passed between leak initiation and observation; and (3) the circumstances surrounding KRU 1D-39 are not the same as previous well integrity enforcements, warranting a different response than the Commission applied in this case. The Commission agrees that language in the notice does not accurately reflect the fact that CP AI self-reported the tubing/annulus communication in this injection well. We also agree that the correct interval between leak observation and reporting was 171 days, not 173 days, as determined from the pressure trends and data provided with CPAI' s initial notice of well integrity failure. The circumstances CP AI alludes to were clarified in the May 11, 2005, informal meeting. CP AI stated that the significant differences were in the self-reporting of the well integrity failure and in the risk represented by the well integrity failure. The Commission does agree that, based on the evidence presented subsequent to the commencement of this review, KRU ID-39 was not ever in danger of annulus overpressure or misinjection of fluids (fluids remained confined to the wellbore and the injection zone). However, the fact remains that the clear regulatory requirements for well integrity were violated, and CP AI does not dispute that fact. As acknowledged by CP AI, reliance on the allowable thresholds for development well annular pressures as provided by Conservation Order 494 ("CO 494") is not appropriate for injection wells, since the Commission has clearly established different and more stringent regulatory requirements for injectors. AOGCC Order #33 Page 4 of6 ) ) May 20, 2005 C. Working Relationship CP AI expressed concerns that this enforcement action does little to improve well integrity, that it simply "adds strain" to the close and open working relationship that CP AI has endeavored to create with the Commission, particularly in the area of complex well integrity issues. The Commission recognizes CPAI' s efforts to work well integrity issues collaboratively with the Commission. However, that collaborative work relationship between the regulatory agency (Commission) and the regulated community (CP AI) does not negate the Commission's clear mandate for enforcement when rules are violated. Of particular concern to the Commission is the fact that the Commission had questioned CP AI personnel about their internal well operating guidelines, and more specifically, the treatment of injection wells as if they were governed by production well integrity rules several times prior to this incident [beginning with the publication of Conservation Order 494 for public comment on June 30, 2003 effective date of CO 494 was September 4,2003.] D. Corrective Actions In previous enforcement actions, the Commission has identified five factors that should be considered in determining appropriate penalties. These include: (1) the good or bad faith of the operator in violating the law; (2) the injury to the public resulting from the violation; (3) the benefits derived by the operator from its violation; (4) the operator's ability to pay any penalty; and (5) the need to deter similar behavior by the operator and others in the future. In addition, the Commission has considered the operator's voluntary remedial responses subsequent to the occurrence of a violation. AOGCC Order #33 Page 5 of6 ) ) May 20, 2005 Several mitigating factors appear applicable in the present situation. First, the Commission acknowledges the good faith of CP AI throughout this investigation. Particularly noteworthy was the voluntary self-disclosure that 171 days passed between leak initiation and observation. In considering the injury to the public or environment resulting from the violation, the Commission is convinced that the risks during the 1 71 days of operation were minimal. Because of the low injection pressures, fluids being injected (water), and well design (multiple casing strings with pressure ratings exceeding injection pressure available to contain pressure communication or leakage), there was never any danger of annulus overpressure and no misinjection of fluids. The Commission also recognizes that CP AI has instituted corrective actions to improve compliance with applicable regulations and orders. These actions were instituted on CPA!' s own initiative immediately following the identification of a gap in the annular pressure monitoring and surveillance program. F. Findings and Conclusions For the reasons stated above, the Commission finds that CP AI violated Area Injection Order 2B, Rule 7, and regulation 20 AAC 25.402(f). To deter future violations by any operator, the Commission concludes that civil penalties are called for and that the corrective actions set out below should be ordered. The Commission further concludes that because of CP AI's self- reporting and self-disclosure, cooperation throughout the investigation, and absence of substantial risk associated with the violations, the penalty amount originally proposed should be significantly reduced. AOGCC Order #33 Page 6 of6 ) ,} ) May 20, 2005 NOW THEREFORE IT IS ORDERED THAT: 1. CP AI shall pay to the Commission a civil penalty in the amount of $25,000 within 30 days after the date this Decision and Order becomes final; 2. CP AI shall comply with the following corrective actions within 30 days from the date this Decision and Order becomes final: a. CP AI shall provide the Commission with a detailed description of actions completed to correct deficiencies in the annular pressure monitoring and surveillance program. CP AI shall also identify any remaining actions and the timeframe for completion. b. CP AI shall provide the Commission with a description of its new protocols established to ensure the timely identification and reporting of injection well mechanical integrity failures. 3. This Decision and Order becomes final on the 11 th day after the date of its issuance shown below, unless within 10 days after the date of issuance CP AI files a written request for a , ':; "E~~~, .f. '~::;~;:::y}: :"i ~.. 0IL.rtA .....; ß~?'~~\'. r·;7~~~{~/.jA··' "': x' \, I":~ ~: , ~ '\g\.'} I ' !;.:),~~. f " ~NV( ,.,~~:~~.~:"~.~~~ Aj""',""" '. ""~">')"'J1 ~ . \ ;~.:;/; '<,..' '\. ,i\,:.,:I' ~¿~~1}t~:.'·~,;,~?~y ~ Daniel T. Seamount, Jr., Commissioner f!;~r .~;':¡¡,~~";:~~'~"'oI"'-:-:-,"::~.'''':''''.';::-'.V-:.'- '" ,. - . -" .~.";.:""¡.j".'''''''''''';';'''"'''''I.·'~'4·'''''_~'_'''''''''' _ ,...........'..............." .'_,.._....._~...,_._...4_~...____..... ----. -- -" . ..--------. SENDfR: COMPLETE THIS SECTION 1',,"":'- '.'·':'."\:~'I., ",''','..,''''.,'' "T,I"":,..', "·:':""','.';··":",~",;~,I,: "',-,..':' ::,..,:,.,~,_,.::., ",.........,",.., ;,""'.',.-, ~".::.I..:.,._' CQMPLETE THIS SECTION ON DELIVERY , I , " , "'~', '. .. .... ,,'-'-' '," .:- .:.' . '.. .",:, ' - ...~' ",' " ' -',' i ' .' , ' I Article Addre~,T~;9~~9: A. IS\gnqture . . . \2fÄ .' . . X U /k' . . . ÇJ~~:~~ssee : ~;~il(r;;;me) . ;;~;;~ . I D. 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H~' (!l , IT1 Total Postage & Fees $ 4.65 0 ,fj t.Q5'~!~07 ~ .:~Qt\.Ð--_\()~_\ji~~C~ or POBox No. . ëit.Ÿ: Stã¡ã; ŽiP+4· -. --- -. -. -...- -.. -... n.. - - - - -- -.- - -. - --- -. - -. --... - --.-... - -. -. - -.... Certified Fee ~~~~!.~1tJ~~~~¥~.w~:Ã;;;,.~itfl.~~hlt1ffJ't Ilia / ~~ ó'r - .&'0/4/2 (J/71 V -/iJcP/1 000077 093199 1 This check was issued b~ ConocoPhillips Alaska Inc I DATE INVOICE(DESCRIPT) CO DOCUMENT NO. GROSS DISCOUNT NET OS/2Ø/05 AOGCCORDER33 YA 1200008673 USD 25,00Ø.Ø0 0.0Ø' 25,0Ø0.00 PAYEE NUMBER CHECK DATE CIŒCK NO CHECK AMOUNT 71474 06/29/2ØØ5 Ø00Ø0371 250ØØ.Ø0 If ~ou have questions about this check, call (918)661-5746 or logon to https://vis.conocophillips.com. FORM 15750-N 11-04 I: 1 ~ ~W:.' ~ ~:1 ~'j ':.':1 ~~:t ..:1:.' .]::t:-" .11. ~ [I) ':.{I{~::t ~i .'¿'~ II~: [Ill.. ~[I) i I ~[eaW:.' ~::t :h'j '.:.':1 ~ .. (u. [ei :'.(I.'~::I :11 :a.·"'¿I/.:.,.::t:11'j':.':1 ~ Deutsche Bank Trust Compan~ Delaware ConocoPhillips Alaska Inc Anchorage, AK 9951Ø 62-38/311 11414 06/29/2005 00000311 .····25,000.00· PAY TO THE ORDER OF EXACTLY ***250ØØ US Dollars and øø Cents*** STATE OF ALASKA AOGCC 333 WEST 7TH AVENUE SUITE 100 ANCHORAGE, AK 995Ø1 q ttJ/þJ Treasurer 11100000 :1 7 ¡'III I: 0 :1 ¡. ¡. 0 0 :180 I: o 0 5 :18 7 :1 2 III #10 ) ') Ä. John Whitehead Vice President North Slope Operations and Development, Alaska 700 G Street, ATO 2100 (99501) P.O. Box 100360 Anchorage, AK 99510-0360 phone 907.265.6513 fax 907.263.4438 y ConocoPhillips Alaska, Inc. June 21, 2005 John K. Nonnan, Chainnan Alaska Oil & Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 JUN ,2 2~ í~005 ~~~~~ Re: AOGCC Order No. 33, Description of Corrective Actions Dear Mr. Nonnan: In compliance with AOGCC Order No. 33 dated May 20, 2005, ConocoPhillips Alaska, Inc. (CP AI) is submitting this description of corrective actions and protocols related to annular pressure monitoring and injection well integrity assurance. The Order provided in relevant part: CP AI shall comply with the following corrective actions within 30 days from the date this Decision and Order becomes final: a. CPAI shall provide the Commission with a detailed description of actions completed to correct deficiencies in the annular pressure monitoring and surveillance program. CP AI shall also identify any remaining actions and the timeframe for completion. b. CP AI shall provide the Commission with a description of its new protocols established to ensure the timely identification and reporting of injection well mechanical integrity failures. CP AI has initiated changes and improvements for monitoring well annular pressures in three ways-training, automation upgrades, and re-emphasized response actions. Training: An enhanced training program for Drillsite Operators has been developed and initiated by the Well Integrity Supervisor. Training will be completed by September 2005 for all CP AI assets. In order to assure competency, the training module will be included into our "Process Safety Management System." This will assure new hire training and 3 year recertification. Major topic areas include regulatory requirements (production equipment, sustained casing pressure, and injector mechanical integrity), company requirements (Well Operating Guidelines, waiver criteria, and documentation), surveillance criteria (annular pressure monitoring and recording, annular bleeds, and pressure gauge maintenance), recognition of annular communication symptoms, and understanding diagnostics tests, procedures and tenninology. The goal of this training package is to support the timely recognition of well integrity problems by field personnel. The training is expected to meet the stated goal by ensuring that current standards are unifonnly understood and rigorously followed. ORIGINAL ) ') Mr. John K Nonnan, Chainnan Page 2 of2 June 21,2005 Automation upgrades: New surveillance routines have been implemented on the CP AI North Slope computer control system (SETCIM) to assist with monitoring annular pressures. One routine scaris injection well pressure readings daily for tubing and annulus (IA) pressures that are within 500 psi differential. A second routine scans all wells for IA and OA annular readings daily that are within 100 psi differential. Wells that are flagged by one of these routines are listed on the morning report which is distributed by email to Operations staff. These automation routines highlight wells that may exhibit characteristics of annular communication and require investigation by Operations personnel. We believe these new automated routines represent a significant increase in the robustness of our annular pressure monitoring and surveillance program. With this type of automated infonnation on pressure differentials, a delay in pressure communication detection such as occurred at well 1D-39 should be avoided in the future. Response actions: CP AI expects that any problems will first be recognized and reported by field personnel during execution of their routine duties. The staff has been instructed that standard protocol is to investigate any questionable gauge readings and computer surveillance alerts and report those findings to the Well Integrity staff as soon as reasonably possible. Additional diagnostics will be perfonned, if necessary, to confinn whether an annular communication problem exists. Appropriate notifications will be made by Well Integrity staff to the AOGCC as per existing requirements. I believe this description fulfills CP AI's reporting duty under AOGCC Order No. 33, and demonstrates that CPAI has improved its annular pressure monitoring and surveillance program to ensure timely detection and reporting of any injection well mechanical integrity failures. Please call me if you have any questions. Sincerely, {}{j~~ John Whitehead Vice President North Slope Operations and Development, Alaska #9 ) ) ALASKA OIL AND GAS CONSERVATION COMMISSION Date: \A~ ~~ \ t \. dûO <5" Time \Û$)O MEETING - Subject \ $ .- ~ ~ \J\ \\ 'Ç..~ \ .() \.~ E~Çc~,,",-Q.~ ~~\.'D'\\ - ..\..,,~~ \~\c..'\\J NAME - AFFILIATION TELEPHONE (PLEASE PRINT) :ro~~ \~!rtf~t'S - cPA r M \"'-.f=:. w~ 1_- C'PIr-:z. }/1l1(V M.ðbl\)(¿1 - (' p A--r: I)?~ Lt:Jvtø_/QIIJrl - CfJ/Jr (/~ ~sW A-06-·cc .....Jes 1;. N,¡{JIA.#\.. - M(}.('~c ~~'M T? ~ AiJGGC . ~·~~~r·Þõr~cC {¿,lf1- 71 2 7 h5'?-7"2..i'i ::l4fJ -503J 6s'l-ø 7 ~a 'I 793-/ 2- z- J 7'7' J> 1'1 -1 ~ lq1- J2;3Ç-7 '1'\-:s -\?-~ REG~'Vl:.D MAY 1 1 2005 · C Ot1\mis$iø" A\a!Ska u., & C'ÎU~ Cn"~. . . ,. An,~haraQe #8 ) 1D-39 Informal Hearing ) First and most importantly, we (ConocoPhillips) wish to continue the productive and collaborative relationship that COP and the AOGCC have nurtured over the years. We have always endeavored to work closely and openly with the commission to address the complex issues which surround well bore integrity. While we do not dispute the basic facts of the case, we believe that the points outlined below support the position that a fine is not warranted. · COP acknowledges that 10-39 did point out the existence of a gap in our annular pressure observation system. This gap has been addressed, with corrective actions committed to long before receipt of the letter. The proposed enforcement action does little to further improve well bore integrity; it simply adds strain to our working relationship. · The Letter of Proposed Enforcement Action implies that GKA knowingly operated 10-39 with compromised annulus integrity. We request that the letter be revised to reflect the fact that COP promptly notified AOGCC as soon as the pressure communication was observed. · The Letter of Proposed Enforcement Action implies that the AOGCC had to request the data which showed that 10-39 was operated for 171 days with tubing/annulus pressure communication. We request that the letter be revised to reflect the fact that COP's Well Integrity Supervisor notified the AOGCC via e- mail on February 13, within one day of the leak observation, as required by the Area Injection Order. This notification included pressure trends and tabular data which voluntarily self-disclosed that 171 days passed between leak initiation and observation. · We request that the letter acknowledge that at no time was this well ever in danger of annulus overpressure or miss-injection of fluids. · We request that the letter acknowledge that COP took immediate steps to improve compliance with the applicable regulations. Supervisors immediately re- RECEIVED emphasized the need to identify and report annular pressure tracking events, even when pressures remain within operating limits. A more detailed well MAY 11 Z005 integrity training package for all operations personnel is being developed. Training of all Lead Drill Operators will be complete by July 1. Documented A,. I k 01 & Gas Cons GammisMOWing for all Drill Site Operators will commence immediately thereafter. In as a I ~ ' addition, a daily report now flags injection wells in which the tubinQ and inner Anchorage annulus pressures are within sob psi. This report is sent to the Lead Drill Site- Operator each morning with the expectation that all wells on it are promptly investigated and reported as necessary. · An error in the letter states 173 days passed when in fact it was 171. Note there is also a discrepancy in some of the dates. · It appears as though the AOGCC is treating the GKA 10-39 event similarly to GPB's H-11 incident in 2004. The circumstances are very different, and suggest a different response. Given the points made above, COP does not believe that a fine is warranted. We have a demonstrated commitment to well integrity and sincerely hope that we can continue the close and open relationship which has proven to be mutually beneficial. 12-May-2005 #7 ID-39 Infonnal Hearing ...... :WI ) ) S'ubject: ID-39 Informal Hearing From: "Wheatall, Michael" <Michael. WheataIl@conocophilIips.com> Date: Tue, 10 May 2005 16:27:55 -0800 To: cathy _foerster@admin.state.ak.us Cathy, Thank you for providing the opportunity to discuss CononcoPhillips' concerns with the proposed enforcement action. The purpose of this note is to provide in advance the key points we'd like to discuss at the informal hearing on Wednesday. First and most importantly, we (ConocoPhillips) wish to continue the productive and collaborative relationship that COP and the AOGCC have nurtured over the years. We have always endeavored to work closely and openly with the commission to address the complex issues which surround well bore integrity. In most cases, these issues are worked to mutual satisfaction at the staff level. In the rare event of an enforcement action, we would have expected to receive some advance warning. We sincerely hope that the lack of consultation or advance notice on the letter to John Whitehead is not a sign that our relationship is changing or deteriorating. While we do not dispute the basic facts of the case, we will utilize the informal hearing on May 11 to clarify a few points which $hould be considered in deciding whether an enforcement action is warranted. With that said, we believe that the points outlined below support the position that a fine is not warranted. · COP acknowledges that 10-39 did point out the existence of a gap in our annular pressure observation system. This gap has been addressed, with corrective actions committed to long before receipt of the letter. The proposed enforcement action does little to further improve well bore integrity; it simply adds strain to our working relationship. · The Letter of Proposed Enforcement Action implies that GKA knowingly operated 1 0-39 with compromised annulus integrity. We request that the letter be revised to reflect the fact that COP promptly notified AOGCC as soon as the pressure communication was observed. · The Letter of Proposed Enforcement Action implies that the AOGCC had to request the data which showed that 10-39 was operated for 171 days with tubing/annulus pressure communication. We request that the letter be revised to reflect the fact that COP's Well Integrity Supervisor notified the AOGCC via e-mail on February 13, within one day of the leak observation, as required by the Area Injection Order. This notification included pressure trends and tabular data which voluntarily self-disclosed that 171 days passed between leak initiation and observation. · We request that the letter acknowledge that at no time was this well ever in danger of annulus overpressure or miss-injection of fluids. · We request that the letter acknowledge that COP took immediate steps to improve compliance with the applicable regulations. Supervisors immediately re-emphasized the need to identify and report annular pressure tracking events, of2 5/11/2005 9:21 AM .D-39 Informal Hearing ) ) even when pressures remain within operating limits. A more detailed well integrity training package for all operations personnel is being developed. Training of all Lead Drill Operators will be complete by July 1. Documented training for all Drill Site Operators will commence immediately thereafter. In addition, a daily report now flags injection wells in which the tubing and inner annulus pressures are within 500 psi. This report is sent to the Lead Drill Site Operator each morning with the expectation that all wells on it are promptly investigated and reported as necessary. . An error in the letter states 173 days passed when in fact it was 171. Note there is also a discrepancy in some of the dates. . These circumstances differ significantly from the those surrounding GPB's H-11 incident last year. Given the points made above, COP does not believe that a fine is warranted. We have proven our commitment to well integrity and sincerely hope that the AOGCC is equally committed to fostering the open and honest relationship which has proven to be mutually beneficial. I look forward to our meeting tomorrow. mw CN 1 HI I~C)i" U! (} --:-.---.. ZERO ~...'. I I' ~"- ~! -~j' GKA O'I'I:..ltl\fION5 Michael Wheatall GKA Operations Manager, NSK 69 907-659-7219 (Slope Office Phone) 907-659-7000,851 (Slope Voice Pager) 907-301-0812 (Cell Phone) : of2 5/1112005 9:21 AM #6 ~i ,~~ W\ .",' : \ / ,i\\ " .', 1: i / iU \. 'i~ it i ,./ì~~\\ ,,,:;v lu L l\j ',,w,,? iþ ! !I- ~ ) ,',',¡.·-.'I....\'~,;) .~r~~.,.. .,,' : I' ' i : : f ¡ ¡ II " ¡ , ! I I ~ 1Jd) fi! ) "l· ! ~ :L ~ ,( r~;J \~'\ ("'1\ ! \;:¿) FRANK H. MURKOWSKI, GOVERNOR AI1ASIiA. OIL AlWD GAS CONSERVATION COMMISSION 333 W. pH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 April 21, 2005 John Whitehead Vice-President ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Scheduled Informal Review Well1D-39 Dear Mr. Whitehead: The Alaska Oil and Gas Conservation Commission ("Commission") is in receipt of your April 14, 2005 letter requesting an Informal Review on the proposed enforcement action for Well 1D-39. The Informal Review you have requested has been scheduled for May 11, 2005 at 10:00 am. ( ~ If you have further information you wish the Co mis ion to consider please file by May 10,2005. cc: Daniel T. Seamount, Commissioner Cathy Foerster, Commissioner #5 ) ConocJ¡)hiUips Alaska, Inc. April 14, 2005 Mr. John Norman, Chairman Alaska Oil and Gas Conservation Cûn1mission State of Alaska 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 Re: Notice of Proposed Enforcement Action, Well1D-39 Dear Mr. Norman: )' A. John Whitehead Vice President North Slope Operations & Development, Alaska 700 G Street, A TO (99501) P. O. Box 100360 Anchorage, AK 99510-0360 Phone (907) 265-6513 Fax (907) 263-4438 RECEIVED APR 1 5 Z005 Alaska Oil & Gas Cons. Commission Anchorage I received your March 31, 2005, letter regarding a proposed enforcement action against ConocoPhillips Alaska, Inc. ("CP AI") in connection with Kuparuk River Unit ("KRU") well 1D-39. I believe it would be of value for both CP AI and the Alaska Oil and Gas Conservation Commission to have further discussion of the of the circumstances involved, so I hereby request an informal review as offered in your letter and described in 20 AAC 25.535(c). Hopefully, a time can be scheduled for the informal review that it mutually convenient, allowing participation by those most knowledgeable about the relevant circumstances. I ask your staff to contact Michael Mooney at 263-4574 to schedule a time for the informal review. Of course, you may also contact me if I can be of any assistance. Sincerely, tfú!~~ A. John Whitehead c: Ken L. Donajkowski E. Paul Dubuisson Michael Mooney ATO 2100 A TO 1226 ATO 1502 #4 99510":'0360", ." postage,O...;...···~,. .···.1.··.·, :,:Wtf, IT...' .l.II:,: .6~.,. . ....; U1 ~..·..·.".'T .····.,·.······/r·' :¡(0"RE'9~ CJ c.~"". . ........... ·~o ; :~;;~~~~~~~?¡:~. tli;~~~!c::)~~ ¡:nl Total Postages. Fees $ '··l/. «t·'" . ':"!'b"'ð~~~:;~"i~' ru. .,' ',,;~" ~l ·>~.Qj:t5~~t CJ' ;SentTo,~'u ,,:;,,1; \ .li::; ~':;.': :'.;':"01,// 'ë::'C- ~ -Siiè¢~i¡.,~.eEI~..;;._~..~.t~~~;,-,-..._.....,",,-,,-,. . ~~.~~: ~~~. ~.:b~~K~n .~.~ ~??_~~.~~.~~.ºn"; .n. mn___'" .~"~_ nnn· l..~. s,,;,/,;. ::tl"'¡ O~C:rC:: A-K ~.~'I': ¿øu ',':" '.',' . :"':. :'c··" ','" ',':' '.... .. ',': . ..' .Jl,11if.l1t llf1;]1 f11)1 tlIliJlllfitJillJ t1ll ~ll. iI, ;rHllf,}tl 1.{).·3c; ...... ...... ............ 'q .. ... .' .~, ~i.q'~~~'fll' " ", .' 1t:1,,*,,:,J~ . Complete items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. II Print your name ar¡d address on the reverse so that we can return the card to you. III Attach this card to the back of the mail piece, or on the front if space permits. 1. Article Addressed to: Jo{/~ Ic/jJ/~IIC~c£ . f/; c e )%4~/¿-k /) ;' /~1 /} 17 é 0·· / /../ //1 /,"'5 j/¿f.8 /cl¿J36 ¿/ /-1/?çl-. /JL qél?1 ¿J 2. Article Number (Transfer from service/al PS Form 3811, August 2001 .~' "" ", ~'" ~.., ',' '-;f~' ~'" '.'. r', .' . ", .. . ' ";'. .. .' ~ ",.' ~ ~;~M':"¡ ':t"¡HI'~ ¡,:,:.,:.'~;( ""'D Ir~ ., "', 11II' iI~":~~!J~l~' """,1 ,~~4i, Ihllilfll" ",~~.¡¡¡¡..~. _,..:'....'~' ", '~~iH&,.~~.Ji~~~ " ./ . A. Signature ~ ~ /1/ /'"" 9' Agent X . i::71'" 0 Addrei"ssee B eceived by ( Printed Name) C. Date of Delivery ;Pf/C)! IIÞ55 ()Lj'"#¥----- D. Is delivery address different from item 1? ~Yes If YES, enter delivery address below: os. No 3. Service Type !:i!rCertified Mail o Registered o Insured Mail o Express Mail 'øeturn Receipt for Merchandise o C.O.D. 4. Restricted Delivery? (Extra Fee) DYes -..,._._..,.,,_..,~._-- 7002 3150 0005 3521 1447 102595-02-M-0835 Domestic Return Receipt ') ) ~r~1TŒ (ffi~ ~~!Æ~æ!Æ AI,ASKA. OIL AlU) GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 March 31, 2005 Certified Mail Return Receipt Requested 70023150000535211447 '. /j.. John Whitehead V ice- President ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Notice of proposed enforcement action Dear Mr. Whitehead: Pursuant to 20 AAC 25.535, the Alaska Oil and Gas Conservation Commission ("Commission") hereby notifies ConocoPhillips Alaska, Inc. ("CP AI") of a proposed enforcement action. The Commission considers that CP AI may have violated provisions of 20 AAC 25A02(f) and Area Injection Order 2B, Rule 7 (Well Integrity Failure) in connection with operating Kuparuk River Unit (" KRU") well1D-39. Specifically, it appears that CP AI violated Rule 7 of Area Injection Order No. 2B ("AIO 2B") and 20 AAC 25A02(f), by failing to timely report a well integrity failure that oc- curred on August 26, 2004, by failing to obtain Commission approval of a plan of correc- tive action, and by failing to obtain Commission approval to continue injection. 20 AAC 25 A02(f) provides, in relevant part: If an injection rate, operating pressure observation, or pressure test indicates pressure communication or leakage in any casing, tubing or packer, the operator shall notify the commission by the next working day ) "') John Whitehead March 31, 2005 Page 2 of3 Rule 7 of AIO 2B provides: Whenever operating pressure observances or pressure tests indi- cate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day follow- ing the observation, obtain Commission approval of a plan for corrective action, and when an USDW is not endangered, obtain Commission ap- proval to continue injection. .,'1, The well failed a mechanical integrity test ("MIT") on February 13, 2005. Tubing, inner annulus, and outer annulus ("TIO") pressure data provided by CP AI at Commission re- quest in conjunction with a review of the MIT failure shows a sudden increase in the in- ner annulus ("IA") pressure occurring on August 24, 2004. The Commission has found ....:v no evidence that CP AI took any action to report the indication of pressure communica- tion to the Commission as required by Rule 7. There is also no record that CP AI ob- tained Commission approval of a plan of corrective action addressing the August 24, 2004 apparent mechanical integrity failure. Further, the Commission is unaware of any effort by CP AI to obtain administrative relief from well integrity failure requirements as outlined in Rule 9 of AIO 2B. Finally, there is no record that CPAI obtained Commis- sion approval to continue injection. The Commission proposes to order CP AI to correct deficiencies in its well integrity sur- veillance program. Within 30 days after the effective date of the enforcement order, CP AI would be required to provide the Commission with new protocols established to in- sure the timely identification and reporting of injection well mechanical integrity failures. In addition, the Commission proposes to impose civil penalties on CP AI under AS 31.05.150 (a). The Commission proposes penalties for violating 20 AAC 25.402(t) and AIO 2B, Rule 7 as follows: $5000 for failure to timely report an injection well integrity failure (1 day); $5000 for failure to submit and obtain Commission approval of a corrective action plan (1 day); and $43,250 for failure to obtain Commission approval to continue injection into KRU 1 D-39 after the well integrity failure (173 days times $250/dayl). The total of the proposed civil penalties is $53,250. As provided by 20 AAC 25.535 (c), within 15 days after receipt of this notification CPAI may file with the Commission a written response that concurs in whole or in part with the proposed action described here, requests informal review, or requests a hearing under 20 I 173 days fTom August 25,2004 through February 13,2005; August 25 is one day after apparent well in- tegrity failure as demonstrated by well pressure data for KRU 1 D-39; February 13 is the day prior to notifi- cation by CP AI of a MIT failure ) john Whitehead March 31, 2005 Page 3 of3 AAC 25.540. If informal review is requested and CP AI disagrees with the Commission's proposed decision or order after that review, CP AI may then request a hearing within 10 days after the proposed decision or order is issued. If CP AI does not file a timely written response to this notification, the Commission will consider CP AI to have accepted by default the proposed action described above. If CP AI requires more than 15 days to respond, you y for good cause shown request an exten- sion of the IS-day response period. (. - ) ill Korman ~ Cha rman #3 [Fwd: KRU ID-39 (200-216)] ) ) Subject: [Fwd: KRU 1D-39 (200-216)] From: Thomas Maunder <tom_maunder@admin.state.akus> Date: Wed, 16 Feb 2005 09:53:59 -0900 To: Daniel T Seamount JR <dan_seamount@admin.state.akus>, John Norman <j 000_ nonnan@admin.state.akus> CC: Jody J Colombie <jody_colombie@admin.state.ak.us> Here is the email sent to CP AI regarding their reporting of a failed MIT on KRU well1D-39. Jody, would you please start an incident file on this matter. Thanks, Tom -------- Original Message -------- Subject:KRU 1D-39 (200-216) Date:Wed, 16 Feb 2005 09:52:35 -0900 From:Thomas Maunder <ton1 n1aunder(à}admin.state.akus> Organization:State of Alaska To:NSK Problem Well Supv <N1617Cä~conocophillips.com>, Mike Mooney <lu.n1ooney(á)conocophillips.conl>, Jerry Dethlefs <Jerry. C .Deth lef sCcl2conocophilli ps. COlll> CC:Jim Regg <jim :reggC¿~,adrnin.state.ak.us>, Robert Mintz <robert mintza~Jaw.state.akus> NSK Problem Wells, We have reviewed the tubing, inner annulus, and outer annulus (TIO) data for KRU 1D-39 (PTD 200-216) as provided in our email February 14, 2005. Your email provided notice of a failed mechanical integrity test (MIT) conducted on February 12, 2005 prior to a planned coil-tubing sidetrack. While this notification was timely with regard to the failed MIT, the Commission is concerned about the initial event dated August 26, 2004 where inner annulus (IA) pressure rapidly increased to near the surface injection pressure. Our initial review indicates there was no notification of that pressure increase as required in 20 AAC 25.402(f) or Area Injection Order 2B, Rule 7 (Well Integrity Failure) . <> The Commission is reviewing this to determine if there was a violation of regulation or injection order. To assist us, please provide the following information: 1) Are pressure data recorded prior to and including August 26, 2004 accurate? What do you base the response on? 2) Are pressure data recorded after August 26, 2004 accurate? Again, what do you base the response on? 3) How are pressure data collected on KRU 1D-39? 4) What are the pad operator (or appropriate field personnel) responsibilities for monitoring, recording and reporting pressures on injection wells, specifically KRU 1D-39? 5) What is ConocoPhillips' policy for recording, reporting and 10f2 4/1/2005 8:44 AM 4/1/2005 8:44 AM 2of2 Tom Maunder, PE AOGCC Please respond not later than March 1, 2005. You may contact Jim Regg (793-1236) or myself (793-1250) with any questions. Please provide a time line identifying major well/field events that have a bearing on KRU 1D-39 beginning on July 1, 2005. 7) What diagnostics were performed after the IA pressure increased on August 26, 2004? What were the results of those diagnostics? 6) Are there pressure thresholds that trigger reporting and diagnostics? If so, what are they? diagnostic testing when a pressure increase is detected in the annulus? ) ) [Fwd: KRU ID~39 (200-216)] Re: ID-39 (PTD 200-216) Failed MITIA ) , 'I, } Subject: Re: 1D-39 (PTD 200-216) Failed MITIA From: James Regg <jim_regg@admin.state.ak.us> Date: Mon, 14 Feb 2005 15:28:37 -0900 To: Thomas Maunder <tom_maunder@admin.state.ak.us> Tom - With just a cursory review of facts provided, I don't agree re: timeliness of notification; their notice should have occurred in August 2004 when there was a significant pressure increase with T and IA pressures tracking each other. Rapid increase in IA pressure when injection was restored after a couple days SI should have triggered diagnostics; without diagnostics, I don't understand how is it possible to distinguish between thermal effects and an indication of well integrity loss. For KRU injection wells, I think AIO 2B supercedes 25.402{f) - "Whenever operating pressure observances 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 when a USDW is not endangered, obtain Commission approval to continue injection." Their notice would have occurred in August 2004 had they been relying on our requirements as guiding principle and not their internal policy (which we have told them repeatedly is inconsistent with our rules). Just FYI, we nailed BP pretty hard for not reporting an indication of loss of well integrity on PBU H-11 (producer) - 3 "violations" were failure to bleed pressure, failure to report pressure exceeding reporting threshold, and failure to maintain records. We obviously do not want to jump to conclusions. This should be looked into closely to determine appropriate regulatory response. Jim Thomas Maunder wrote: MJ, Based on your intent to perform the diagnostics in the 10 day or so period you plan and since there is no evidence of communication to the OA, it is acceptable to keep the well online. Good luck with the diagnostics, please keep us informed. Tom Maunder, PE AOGCC NSK Problem Well Supv wrote: Tom, In most cases, the drillsite operator is the first one to identify a problem and they in turn notify the PWS. The PWS, Brad, Jerry, Marie, Nina, or I, will review the well to see if it is related to well work, thermal effects, or etc. If it cannot easily be explained with well work or thermal effects we imeditately (within 24 hours) notify the AOGCC of the problem and then schedule a MITIA or BUR (Build up rate). If it looks like it is related to thermal expansion or well work we usally test it anyway, but only notify the AOGCC if it fails the MITIA or BUR. This well is currently still online. Should I be arranging freeze protection? or can we leave it on until the TTP is set? MJ Loveland ConocoPhillips Problem Well Supervisor 659-7224 -----Original Message----- *From:* Thomas Maunder [mailto:tom maunder@admin.state.ak.us] 10f3 4/1/2005 8:42 AM Re: 1D-39 (PTD 200-216) Failed MITIA 20f3 ) ) *Sent:* Monday, February 14, 2005 11:08 AM *To:* NSK Problem Well Supv * C C : * j...~..~~_~.~.9:9:S~.?:.ª:~:~.~.~?:..:...~~..~::..?:.!~..~...~...~.~..:..:~~.?. ¡Mooney, M *Subject:* Re: 1D-39 (PTD 200-216) Failed MITIA MJ, I concur that your notification was timely to your becoming aware of the issue. Not seeing indications, based on the experience I have with you all, is rare. This is good. One thing I would like to understand further is if the pressure increase had been observed back in August, what process would have been triggered?? I too will look at the well record. Nick is correct that ZXPs can be run on DP after the liner has been set and cement, but I understood the procedure normally employed up there was to run it all at once to avoid extra trips. Tom Maunder NSK Problem Well Supv wrote: Tom, Here are some answers to some of your questions. 1. Yes, the T/I/O pressures are automatically recorded on this well. 2. I do believe that we fulfilled 20 AAC 25.402 (f) {/If an injection rate, operating pressure observation, or pressure test indicates pressure communication or leakage in any casing, tubing, or packer, the operator shall notify the commission by the next working day and shall implement corrective action or increased surveillance as the commission requires to ensure protection of freshwater/.}. In that we notified you within 24 hours of the failed MIT, which was our first indication of a problem on this well. I can not speculate as to why this well did not get flagged sooner by the current surveillance systems. There are no automatic alarms for this type of service. 3. The initial diagnostics, TTP and CMIT, should be completed with in the next 10 days. 4. The available information on this well does not give us a good indication as to whether it is the tubing, seals, or packer. However, given the recent failed MIT and tubing leaks in 1D-10 (also a young well), my guess is that it is the tubing. But that is just a guess. 5. The well schematic shows the casing to stop at 12370', well above TD at 13545'. However, it also shows the cemented liner and perforated C sand which might be confusing on the picture if you are not used to looking at them. 6. The information that I passed on about the ZXP was quoted directly from our drilling supervisor, Nick Scales. According to him ZXP's are set on drill pipe with weight. This is not my area of expertise, however, I can review the drilling report and follow up with the exact setting method used if you would like. 7. Yes, it is my understanding that "the tubing just stings into the sealbore with the combination of sealbore and ZXP effectively being the packer", but I can confirm this detail as well. Please let me know if you have any additional questions or would like more data. MJ Loveland ConocoPhillips Problem Well Supervisor 659-7224 -----Original Message----- *From:* Thomas Maunder [maìlto:tom maunder@admin.state.ak.us] * Sent: * Monday I February--·i-4-;"---2"6-ö-·5-·8~ 2 9 AM ---..--...-.---..---....-.-.- *To:* NSK Problem Well Supv *Cc: * j_~..~e9.g@admin. state. ak .~~ *Subject:* Re: 1D-39 (PTD 200-216) Failed MITIA MJ, It is interesting that the annular pressure increase got by your surveillance systems. The T/I/O plot correctly shows the IA change in August. It seems clear that with such a dramatic change in IA pressure that communication would have been suspected. The detail of the plotted information would seem to indicate that the tubing and IA pressures are automatically recorded. Is that 4/1/2005 8:42 AM Re: 1D-39 (PTD 200-216) Failed MITIA 30f3 ') ) the case?? This situation is another example where operating injection wells according to CPAI's internal "WOG" appears to conflict with regulation 20 MC 2S.402(f) which is also restated in most injection orders. What is the timing of the diagnostics?? Based on the plotted information, pressure changes on the T or IA do not appear to affect the OA. I would expect that the diagnostics will be conducted shortly since you indicate additional drilling activity is planned. Do you feel from the available information you have that the leak is into the tubing?? A few comments. Referring to the well sketch it would appear to show that the 7" casing goes all the way to TD which is not correct since the well is completed with a liner. I am also surprised with the comment regarding the ZXP, which in my experience is hydraulically set unless difficulties are encountered. Does the tubing just sting into the sealbore with the combination of sealbore and ZXP effectively being the packer?? Look forward to your reply. Tom Maunder, PE NSK Problem Well Supv wrote: Tom/Jim 1D-39 (PTD 200-216) failed a pre coiled tubing drilling sidetrack diagnostic MITIA Saturday 2/12/0S. The MIT was done as a standard pre rig operation, however the failure was completely unexpected especially since the well was originally completed in 2001. Upon further inspection and completing a T/I/O plot the failure actually occurred 8/26/04 and was unnoticed due to the low injection pressure and corresponding IA pressure within the WOG. I also reviewed the 4th Quarter SOO PSI differ report to ensure we didn't miss any obvious indicators that come through this office. It did not appear on the report, so I re ran the retrieval for the 4th quarter differ report to ensure it was not human error and it still did not appear on the report, but it does appear on an early run of the 1st quarter differ report for 200S. Please note that while the well was SI the first week of Feb. the FTP shows trapped pressure in a very short span of piping between the choke and the wing valve. Even though this FTP data looks odd and skews the graph, I believe it is unrelated to the failure. The action plan for this well includes installing a TTP and completing a combo TxIA MIT and corresponding LDL. The packer is a Baker ZXP liner top (a weight set packer from DP before the tubing is stabbed in) and it is not known at this time whether the problem is the packer, seal assembly, or a tubing problem. ConocoPhillips requests approval to leave the well online until the tubing tail plug, CMIT, and freeze protection can be coordinated (-1-2 weeks) after which time the well will remain SI until a repair plan and corresponding Sundry is filed and approved. MJ Loveland ConocoPhillips Problem Well Supervisor 6S9-7224 «lD-39 T-I-O 02-13-0S.xls» «lD-39 schematic.pdf» «MIT KRU 1D-39 02-12-0S.xls» 4/1/2005 8:42 AM ID-39 (PTD 200-216) Failed MITIA ) ') Subject: ID-39 (PTD 200-216) Failed MITIA From: NSK Problem Well Supv <n1617@conocophillips.com> Date: Sun, 13 Feb 2005 09:51 :27 -0900 To: Thomas Maunder <tom_maunder@admin.state.ak.us>, jim_regg@admin.state.ak.us CC: bob_fleckenstein@admin.state.ak.us Tom/Jim 10-39 (PTO 200-216) failed a pre coiled tubing drilling sidetrack diagnostic MITIA Saturday 2/12/05. The MIT was done as a standard pre rig operation, however the failure was completely unexpected especially since the well was originally completed in 2001. Upon further inspection and completing a T/I/O plot the failure actually occurred 8/26/04 and was unnoticed due to the low injection pressure and corresponding IA pressure within the WOG. I also reviewed the 4th Quarter 500 PSI differ report to ensure we didn't miss any obvious indicators that come through this office. It did not appear on the report, so I re ran the retrieval for the 4th quarter differ report to ensure it was not human error and it still did not appear on the report, but it does appear on an early run of the 1 st quarter differ report for 2005. Please note that while the well was SI the first week of Feb. the FTP shows trapped pressure in a very short span of piping between the choke and the wing valve. Even though this FTP data looks odd and skews the graph, I believe it is unrelated to the failure. The action plan for this well includes installing a TTP and completing a combo TxlA MIT and corresponding LDL. The packer is a Saker ZXP liner top (a weight set packer from DP before the tubing is stabbed in) and it is not known at this time whether the problem is the packer, seal assembly, or a tubing problem. ConocoPhillips requests approval to leave the well online until the tubing tail plug, CMIT, and freeze protection can be coordinated (-1-2 weeks) after which time the well will remain SI until a repair plan and corresponding Sundry is filed and approved. MJ Loveland ConocoPhillips Problem Well Supervisor 659-7224 «10-39 T-I-O 02-13-05.xls» «10-39 schematic.pdf» «MIT KRU 10-39 02-12-05.xls» Content-Description: ID-39 T-I-O 02-13-05.xls ID-39 T -1-0 02-13-05.xls Content-Type: application/vnd.ms-excel Content-Encoding: base64 lof2 4/1/2005 8:39 AM ID-39 (PTD 200-216) Failed MITIA 20f2 ') Content-Description: 1D-39 schematic.pdf ID-39 schematic.pdf. Content-Type: application/octet-stream Content-Encoding: base64 Content-Description: MIT KRU ID-39 02-12-05.xls KRU ID-39 02-12-05.xls Content-Type: app1ication/vnd.ms-excel Content-Encoding: base64 4/1/2005 8:39 AM STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test ) ", Email to:Tom_Maunder@admin.state.ak.us;Bob_Fleckenstein@admin.state.ak.us;andJim_Regg@admin.state.ak.us OPERATOR: FIELD I UNIT I PAD: DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska Inc. Kuparuk / KRU/ 1 D 02/12/05 Brake/Rogers -AES Packer Depth Pretest Initial 15 Min. 30 Min. Well 1 D-39 Type Inj S T.V.D. 6200 Tubing 1800 1800 Interval 0 P.T.D. 2002160 Type Test P Test psi 1550 Casing 1930 1950 P/F F Notes: Diagnostic MIT lA, Liquid leak rate at 1950 psi was approx. 5 gpm - would not pressure up above 1950 psi nor bleed below 1900 psi Well Type Inj P.T.D. Type Test Notes: T.V.D. Test psi 1500 Tubing Casing Interval P/F Well Type Inj T.V.D. Tubing Interval P.T.D. Type Test T est psi 1500 Casing P/F Notes: Well Type Inj T.V.D. Tubing Interval P.T.D. Type Test T est psi 1500 Casing P/F Notes: Well Type Inj T.V.D. Tubing Interval P.T.D. Type Test T est psi 1500 Casing P/F Notes: Test Details: TYPE INJ codes F = Fresh Water Inj G = Gas I nj S = Salt Water Inj N = Not Injecting TYPE TEST Codes M = Annulus Monitoring P= Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance Test during Workover o = Other (describe in notes) M IT Report Form Revised: 05/19/02 MIT KRU 1D-39 02-12-05.xls 4/1/2005 ') ConocoPhilliþs Alaska,I"~~ 1D-39 NIP (526-527. 00:4.562) TUBING (0-12275, 00:3.500, 10'2.992) Injection 3ndrel/Oummy Valve 1 (4306-4307, 00:5.968) NIP (12192-12193, 00:4.520) PACKER (12215-12216, 00:7.000) LINER (12207-13545, 00:350D, Wt.9.3D) SBE (12234-12235, 00:5.00D) SEAL (12238-12239, 00:4.00D) NIP (12293-12294, 00:4. 52D) Perf :13070-13090) Perf :13160-13180) Perf :13256-13286) Perf :13310-13320) I 'II' ~, j II .: .L. .. ,.,':;;1. ~1··1It ....:.rW :¡-;~_ .~~ :~'. II~ 6 L, ~ ) KRU 1 D-39 Angle @ TS: 73 deg @ 13054 Angle @ TD: 69 deg @ 13545 $timÚlätiohš&Trèåtmên~s . Interval I Date j Type .P9?0-~.3~0.... ....~(1/2091. .~~~D InJëë1ionMäridrels/Valves: .' '. St MD TVD Man Man Type Mfr 1 4306 3765 CAMCO MMG CAMCO DMY 1.5 RK 0.000 0 'Öther(þIÙgsjequip:;etC:);':JEWËLRY' ...... Depth TVD Type Description 526 526 NIP Cameo 'DS' Nipple w/2.875" No-Go profile 12192 6192 NIP Camco 'DS' Nipple w/2.818" No-Go profile 12215 6200 PACKER Baker 7" x 5" ZXP Liner Top Packer w/5" TKC coupling 12234 6206 SBE Baker 80-40 SBE w/TKC couplings & XO 12238 6207 SEAL Baker 4" x 3" GBH-22 Seal Assembly w/17' seals 12293 6225 NIP Howco XN Nipple 13543 6625 SHOE Baker Float Shoe API: SSSV Type: NIPPLE Annular Fluid: Reference Log: Last Tag: 13478 L~st !aQ ~at~:,2/6/2905 Ca$ingStrjng~ÄLL:; Description CONDUCTOR SURF CASING PROD CASING LINER TUbing;$tririg~· TUBING::, Size I Top 3.500 0 ··PåHOråtÎbrisSÚmm:àry;: ' Interval TVD 13070 - 13090 6467 - 6473 13160 - 13180 6494 - 6501 13256 - 13286 6526 - 6536 13310 - 13320 6544 - 6547 13320 - 13340 6547 - 6554 Well Type: INJ Orig 2/7/2001 Completion: Last W/O: Ref Log Date: TD: 13545 ftKB Max Hole Angle:. 75 . 5625 Rev Reason: TAG FILL Last Update: 2/7/2005 I, Size Top 20.000 0 9.625 0 7.000 0 3.500 Thread WELDED BTC-MOD BTC-MOD SLHT Zone C-4 C-4 Status Ft SPF Date Type Comment 20 4 4/24/2001 IPERF 2.5" HC/DP, 60-120 deg ph, random orientation 20 4 4/23/2001 IPERF 2.5" HC/DP, 60-120 deg ph, random orientation 30 4 4/23/2001 IPERF 2.5" HC/DP, 60-120 deg ph, random orientation 10 4 4/23/2001 IPERF 2.5" HC/DP, 60-120 deg ph, random orientation 20 4 4/22/2001 IPERF 2.5" HC/DP, 60-120 deg ph, random orientation C-2 C-1 C-1 Cmnt ID 2.875 2.818 5.000 4.000 3.000 2.750 0.000 1 D-39 T/I/O '::.~ -'~/ ~l-~~ ~"\~>A~':; ~ -- lAP GAP -.- FTP -m- ~ . ~ ~ \, ~..i I ~I "" .I!! - ~.. ~kf" . ~:w~~_ . t ~ ~ - --...-==---=----- ~~~ P 'iV ..~. ; " ; J ~~ " i " , .-. j..n ~.' :.;. ~ I· ~ . r 5000 4500 4000 3500 2500 3000 2000 1500 1000 - en a. 17-Feb-05 29-Dec-04 '< . '. lr ~:. 9~Nbv-04 " ~i .1' :1 Date 500 #2 [Fwd:KRU ID-39 (200-216)] ') ) Strbject:- [Fwd: KRU 1D-39 (200-216)] From: Thomas Maunder <tom _ maunder@admin.state.ak.us> Date: Wed, 16 Feb 2005 09:53:59 -0900 To: Daniel T Seamount JR <dan_seamount@admin.state.ak.us>, John Norman <joOO_ norman@admin.state.ak.us> CC: Jody J Colombie <jody_colombie@admin.state.ak.us> Here is the email sent to CPAI regarding their reporting of a failed MIT on KRU well1D-39. lody, would you please start an incident file on this matter. Thanks, Tom -------- Original Message -------- Subject:KRU 1D-39 (200-21'6) Date: Wed, 16 Feb 2005 09:52:35 -0900 From:Thomas Maunder <tom maunder@admin.state.ak.us> Organization: State of Alaska To:NSK Problem Well Supv <N1617@Jconocophillips.com>, Mike Mooney <m.mooney@conocophillips.com>, Jerry Dethlefs <Jerry. C.Dethlefs@conocophillips.com> CC:Jim Regg <jim regg@admin.state.ak.us>, Robert Mintz <robert mintz@law.state.ak.us> NSK Problem Wells, We have reviewed the tubing, inner annulus, and outer annulus (TIO) data for KRU 1D-39 (PTD 200-216) as provided in our email February 14, 2005. Your email provided notice of a failed mechanical integrity test (MIT) conducted on February 12, 2005 prior to a planned coil-tubing sidetrack. While this notification was timely with regard to the failed MIT, the Commission is concerned about the initial event dated August 26, 2004 where inner annulus (IA) pressure rapidly increased to near the surface injection pressure. Our initial review indicates there was no notification of that pressure increase as required in 20 AAC 25.402(f) or Area Injection Order 2B, Rule 7 (Well Integrity Failure) . <> The Commission is reviewing this to determine if there was a violation of regulation or injection order. To assist us, please provide the following information: 1) Are pressure data recorded prior to and including August 26, 2004 accurate? What do you base the response on? 2) Are pressure data recorded after August 26, 2004 accurate? Again, what do you base the response on? 3) How are pressure data collected on KRU ID-39? 4) What are the pad operator (or appropriate field personnel) responsibilities for monitoring, recording and reporting pressures on injection wells, specifically KRU 1D-39? lof2 2/1612005 12:20 PM [Fwd: KRU ID-39 (200·216)] 2of2 ') ') 5) What is ConocoPhillips' policy for recording, reporting and djragnos'tic testing when a pressure increase is detected in the annulus? 6) Are there pressure thresholds that trigger reporting and diagnostics? If so, what are they? 7) What diagnostics were performed after the IA pressure increased on August 26, 2004? What were the results of those diagnostics? Please provide a time line identifying major well/field events that have a bearing on KRU ID-39 beginning on July 1, 2005. Please respond not later than March 1, 2005. You may contact Jim Regg (793-1236) or myself (793-1250) with any questions. Tom Maunder, PE AOGCC 2/16/2005 12:20 PM #1 " ,~ -'. y ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 RECEIVED JAN 1 4 Z005 January 12, 2005 Alaska Oil & Gas Cons. Commission Anchorage Mr. Tom Maunder Alaska Oil & Gas Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 Subject: Annular pressure monitoring and SCP CO Rule 2 requirements Dear Mr. Maunder: As per request in your recent discussion with CP AI (MJ Loveland), the following is a description of the process used for all CP AI wells, including Kuparuk, Alpine, and Cook Inlet regarding monitoring of annular pressures.W e believe these steps meet the intent of the Sustained Casing Pressure (SCP) Conservation Orders to identify changes in annular pressures and monitor them over long periods of time. After the Prudhoe Bay A-22 incident, a complete review was performed on CPAI's well monitoring process. Best practices were determined and documented in the "Annulus Pressure Surveillance Requirements." This document, along with other Well Integrity program material, was submitted to the AOGCC as per request on September 16, 2002. The document details the minimum requirements for monitoring and maintaining equipment for all CP AI wells. Excerpts from the document are as follows: ~ Dailv: Take annulus readings on all the Suspect, Waivered, Problem, and Trouble (SWPT) wells. Each SWPT wells' annulus pressure will be checked daily and entered into Setcim if the pressures change by more than 50 psig. Non-SWPT well annulus pressures will also be monitored daily as part of routine operations. Any well that requires bleeding for annulus pressure control requires update of both the Setcim bleed log and annulus pressure data to reflect the bleed event. There are no requirements for daily data input on non-SWPT wells as long as they remain within the well operating guidelines. ~ Weeklv: Once a week, take annulus pressure readings for all wells and record the pressures in Setcim if the pressure changes by more than 50 psig. Verify valve position and gauge functionality on any suspect readings. <!II ¡....... ,. ~ ) ) "''t l Mr. Tom Maunder Page 2 of2 01/12/05 ~ Quarterlv: Perform a quarterly function check of the annulus gauges on all Suspect, Waivered, Problem, and Troubled (SWPT) wells. These inspections on set time intervals are in addition to inspections performed during weekly readings or well start up events. ~ Annuallv: Perform an annual function check of the annulus gauges on all wells. These inspections on set time intervals are in addition to inspections performed during weekly readings or well start up events. In summary, all SWPT wells have the annular pressures monitored daily and changes greater than 50-psi are recorded, all wells in the field are monitored daily for compliance with the Well Operating Guidelines, annular bleeds are recorded in the bleed log, and monitoring equipment is tested on a periodic basis. CP Al Operations management believe the monitoring and recording actions described above .meet the intent of the SCP Conservation Orders applicable to CP AI operations in Alaska. More importantly, the effort helps to ensure that CP AI is providing a safe environment for the company and contractor workforce. Weare interested in hearing the AOGCC's opinion of our annular monitoring process, so please call after you review this letter. Sincerely, Jµb Mike Mooney Wells Team Leader ConocoPhillips Alaska, Inc.