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Home My WebLink AboutCO 390• • Index Conservation Order 390 Milne Pointe Unit 1.) December 13, 1996 BP Exploration Alaska, Inc. Requests Exception to 20 AAC 25.200(d) 2.) January 10, 1997 Notice of Public Hearing, Affidavit of Public Hearing 3.) January 17, 1997 Letter from BP Exploration Alaska, Inc. Conservation Order 390 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re: THE APPLICATION OFBP EXPLORATION (ALASKA) INC. for an order granting an exception to 20 AAC 25.200(d) to allow completion of producing wells without a packer when electric submersible pumps are installed. ) Conservation Order No. 390 ) : ) Milne Point Unit and Adjacent Areas ) Kuparuk Oil Pool ) Schrader Bluff Oil Pool ) Sag River Undefined Oil Pool ) March 7, 1997 IT APPEARING THAT: BP Exploration (Alaska), Inc. submitted an application dated December 13,, 1996 requesting exception to 20 AAC 25.200(d) regarding completion of wells without a packer where electric submersible pumps (ESP's) are installed for all Milne Point Unit wells completed in the Kuparuk, Schrader Bluff and Sag River formations. 2. By letter dated January 17, 1997, BP Exploration submitted additional information supporting their application and a request to apply the exception to denoted acreage adjacent to the Milne Point Unit. 3. Notice of opportunity for public hearing was published in the Anchorage Daily News on January 10, 1997 pursuant to 20 AAC 25.540. 4. No protests to the application were received. FINDINGS: . AAC 25.200(d) requires all wells capable of unassisted flow to be completed with downhole tubing and packer that will isolate the tubing/casing annulus from produced fluid, unless otherwise specifically approved by the commission. All wells producing from the Kuparuk, Schrader Bluff, and Sag River Undefined pools through the Milne Point Unit facilities during December 1996 were on artificial lift, 13 of which were on gas lift and 79 were on ESP's. Corrosion has not been a problem in the Milne Point Unit since production operations began in 1985. . . . Industry normally will complete ESP wells without a packer unless subsurface safety valves (SSSV's) are required above the pump to provide downhole shut-in capability. Packers impede the efficient operation of ESP wells. Efficient pump operation requires venting gas away from the pump to prevent operational difficulties and damage to the pump. Setting packers shallOw to allow space for gas to accumulate in the annulus causes comPlications in killing the wells Prior to conducting well rePairs or changing pumps. Administrative Approval 173.11 dated June 14, 1994, allowed liquid level control valves as a replacement for Subsurface safety valves (SSSV's) at Milne Point Unit where ESP's were installed. Conservation OrderN:t .,0 March 7, 1997 . Conservation Order 348 (CO 348), issued December 16, 1994, modified Rule 5 of Conservation Order 173 and eliminated the need to install downhole SSSV's in the Kuparuk River Oil Pool, in both the Kuparuk River Unit and the Milne Point Unit. Pool rules for Milne Point Schrader Bluffwells do not require installation of SSSV's (CO 255, dated July 2, 1990). State-wide regulations governing wells drilled to the Sag River Undefined pool in the Milne Point Unit and adjacent lands do not require installation of SSSV's. CONCLUSIONS: , . Packers installed in conjunction with ESP's may cause premature failures, increase operational risk, reduce production efficiency and potentially reduce ultimate recovery. Subsurface safety valves are no longer required in Kuparuk oil pool wells and were not initially' required in the Schrader Bluffoil pool wells and Sag River Undefined oil pool wells in the Milne Point Unit and adjacent lands. Eliminating the need for SSSV's makes packer installations redundant where ESP's are installed. Completing ESP wells without packers is appropriate, will not cause waste and will promote safer operations. NOW, THEREFORE, IT IS ORDERED for the Kuparuk oil pool, Schrader Bluff oil pool and Sag River Undefined oil pool in the Milne Point Unit and adjacent lands described as follows: Umiat Meridian, T12N, R10E T12N R11E T13N R11E Sections 1, 2, 11, and 12 Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, and 12 Sections 27, 28, 33, and 34 Rule 1. Wells equipped with an electric submersible pump (ESP) and which do not require installation of SSSV's may be completed without a packer assembly. DONE at Anchorage, Alaska 7, 1 David W. Johnston, Alaska Oil id Gas Conserw ion Commission Mary Marsh~ommissioner- Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person aft~cted by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Colmnission 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 'fbr 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). BP EXPLORATION January 17, 1997 David W. Johnston, Commissioner Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Dear Mr. Johnston: As requested by Jack Hartz of the AOGCC, Attachment 1 includes a draft proposal of Findings and Conclusions in support of the BPXA request for a Conservation Order to amend 20 AAC 25.200 (d); waiving the requirement for downhole packers in ESP lifted wells, completed in the Sag River, Kuparuk and Schrader Bluff Pools, within the Milne Point Unit. In addition, it is proposed to include the following acreage located adjacent to the Milne Point Unit: Sections 1, 2, 11, 12, T12N, R10E, Sections 1,2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, T12N, R11E and Sections 27, 28, 33, 34, T13N, R 11E. Plans are underway to expand the Milne Point Unit to include this acreage. Attachment 2 contains 20 AAC 25.200 (d) as currently written and a draft Conservation Order waiving prescribed requiremer~ts for wells produced with electrical submersible pumps. Granting this wavier will ensure sound operating practices, reduce environmental risk and will extend the economic life of ESP wells in the Milne Point Unit. Therefore, a favorable ruling will be in the best interests of the MPU working interest owners and the State of Alaska. Bruce J.--'Policky ~ Exploitation Managed cc: Howard Mayson, Tom Gray, Randy Thomas, Steve Rossberg, John Hendrix, Hal Stevens A~a~,,,.,.;==~ ,~ ~.~',~ Cons, Commission ,~'tcnorage Attachment 1 Proposed Findings and Conclusions in support of the BPXA request for a Conservation Order to amend 20 AAC 25.200 (d); waiving the requirement for downhole packers in ESP lifted wells, completed in the Sag River, Kuparuk and Schrader Bluff Pools, within the Milne Point Unit. In addition, it is proposed to include the following acreage located adjacent to the Milne Point Unit: Sections 1, 2, 11, 12, T12N, R10E, Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, T12N, R11E and Sections 27, 28, 33, 34, T13N, R11E. Plans are underway to expand the Milne Point Unit to include this acreage. Findings: 1) Regulation, 20 AAC 25.200 (d), requires all wells capable of unassisted flow be completed with downhole tubing and packer which effectively isolates the tubing/casing annulus from produced fluids, but allows commission discretion to waive this requirement on an individual well basis. 2) BPXA operates Sag River, Kuparuk and Schrader Bluff Pool wells within the Milne Point Unit and on acreage located adjacent to MPU. 3) Commercial production rates are not acheivable from typical Sag River, Kuparuk and Schrader Bluff Pool wells without artificial lift. 4) The majority of Milne Point Unit producing wells that are completed in the Sag River, Kuparuk and Schrader Bluff Pools utilize electrical submersible pumps (ESPs) as the artificial lift mechanism. Unless used in combination with subsurface safety valves (SSSVs)to provide downhole shut-in, it is standard practice within the oil industry to complete ESP wells without packers. 5) The annular operating pressure in a typical ESP well is considerably less than gas lift operating pressures. Due to the benign nature of the produced fluids at MPU and adjacent acreage, internal casing corrosion is not anticipated. 6) The intemal yield pressure of the production casing exceeds wellhead and tree pressure ratings; therefore, providing ample safety factor during shut-in conditions. 7) Shallow set packers used in conjunction with SSSVs greatly complicate routine ESP workovers, presenting additional environmental and safety risk. Deep set packers in ESP wells result in inefficient pumping, damage to ESPs and increased operating costs. 8) AOGCC Administrative Approval No. 173.11, allowed Liquid Level Control Valves to replace SSSVs at MPU in Kupamk wells produced via ESP; thereby, eliminating the requirement for a packer intended to isolate the tubing/casing annulus. 9) Conservation Order 348, eliminated the requirement for any type of subsurface safety valve in most wells within the Kuparuk Pool. Sag River and Schrader Bluff wells are also exempt from the requirement to run SSSVs. Since issuance of Conservation Order 348, it has been standard practice at MPU to complete all ESP producers without packers. Conclusions: 1) Packers installed in wells completed with ESPs may reduce ultimate recovery by contributing to higher operating costs. 2) Packers previously installed in ESP completions at Milne Point Unit have directly caused an increased incidence of workover related problems; and therefore, have not contributed to public safety, environmental protection or resource recovery. 3) Prudent operating practices, conservative casing design and generally benign operating conditions virtually eliminate any danger to casing integrity due to intemal corrosion or over pressuring. 4) It is implicit in Administrative Order 173.11 that packers intended to isolate the tubing/casing annulus are not required in ESP completions within the Milne Point Unit. Conservation Order 348 eliminated the requirement for SSSVs within the Kuparuk Pool. In the context of these Commission Orders, continuing to require packers in ESP wells will not contribute to public safety, environmental protection or resource recovery. But, may actually pose additional environmental and safety risk during routine ESP replacement operations. 5) A Conservation Order, waiving packer requirements as stipulated in 20 AAC 25.200 (d), is appropriate for all wells completed with ESPs, in the Sag River, Kuparuk and Schrader BJuffPools, within the Milne Point Unit and adjacent acreage/(Sections 1, 2, 11, 12, T12N, R10E, Sections 1, 2~3, 4, 5, 6, 7, 8, 9, 10, 11, 12, T12N, RIlE and Sections 27, 28, 33, 34, T13N, RI 1E); and, conforms with Commission Orders 173.11 and 348 as referenced above. Attachment 2 20 AAC 25.200 (d) as currently written All wells capable of unassisted flow must be completed with downhole production equipment consisting of suitable tubing and packer which effectively isolates the tubing/casing annulus from fluids being produced, unless otherwise specifically approved by the commission. Proposed Conservation Order All wells within the Milne Point Unit and adjacent acreage located in Sections 1, 2, 11, 12, T12N, R10E, Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, T12N, RllE and Sections 27, 28, 33, 34, T13N, RI 1E, completed in the Sag River, Kuparuk or Schrader Bluff Pools, utilizing electrical submersible pumps as the artificial lift mechanism are exempt from the requirement to install a packer as prescribed in 20 AAC 25.200(d). Other completion/artificial lift configurations may be specifically approved by the commission. .Alasl(a Oil & a~ (x,,~ ~,;vmmlss~O #10324 STOF0330 A0-02714023 AFFiDAViT O F PUB L ICATiO N STATE OF ALASKA, ) THIRD JUDICIAL DISTRICT. ) 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 English 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 Jan. 10, 1997 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Subscribed and sworn to ~e~re me this ./..~. day o Notary Public in and l~or the State of Alaska. Third Division. Anchorage, Alaska MY CONtNtlSSION EXPIRES .... / ..... ............ Notice of Public Hearing STATE OP ALASKA Alaska 011 and .GaS ,Conservation Commission Re: The application 'of BP: Exploration, Alosko~ Inc. for exception to 20 AAC 25.200(d) to allow completions without packers in Milne Pt. Field wells. ,' pp, Exploration(Alaska, Inc.~ by letter received' I~b~cember' 13, 1996 has' re- quested an exception to the Prb~l~ions of 20 AAC 25.200(d) fo ,,allow the completing of weis, i,' the Milne Pt. Field I'wifhOut packers where electric IsUbmersible pumps (ESP's) IOr~ 'U~¢I .for artificial 'lift. The proposal will apply to wells in the Sag River, KUparuk and SChrader Bluff formations ~here .E PS's 'are run,, ,,;'A,l~rson who"may'be harm. ~d if the requ'ested order' i~. ':l~Sued maY' file, a, Written :'~0test ,prior t0. ;4:00:. PM ¢ ~huarY>24, 1997,:with the~: ~10sk'a Oil and,Gas ' Co,nservofion c6mmiss/on, ~:7/' ~--=:.-n'r,-. ~,r:,..~' Anchor. ?.':JO :i'.;~,~ ~,'~:'." :,-'-'"request. a ,lleqring on me moiler, if the' Pr~te'~t,~i,s: timely, filed and "."~ S~..? '.:'u%:"-. ': :r;' r.:.~,.,rt;j :- --': -,",:f,'~..r .. g.O.: .'.' :r = '.:;'.C~ ' ~';" 'ri ::m'~:~o"":,,'=.? .'-h ~ ~.~..;.:: .f % '::'-'.'~'5 '~ ::; .%: 'r~, 'e.'<..' ':.-.'..'~ ....'-'. er'..%.~'. · ~ ',~..=~.;-' .' '~ -.'..".;, ,'j..'.- Ii-.,~ .0nce,,,of",'the ;order,:,witl~OUt o hearJrjg." 'i'l :".' ' "" :. ,', f,',¥o,u,,i.~i~e d perSon'~wim "o', dlsabi.l.it~ "WHO' may'need o '.~r. 7;'~""' ~:1"¥3'"='~ ':"~'~' ,~.?~,- IO ~':,,?l"t'n' ~' '~, ,'1"l~:"..' '", ::...r, :. '.,.' :~- .'.' '; :=~,'.c:.':'~': I ,.'; '~,1'.,,. -;;,~ ',~ Z'r- ',:.' "'.. ,,... , ..... , .... ,~- .,:,~ I ¢l~oimon :, ", ,' I' Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of BP Exploration, Alaska, Inc. for exception to 20 AAC 25.200 (d) to allow completions without packers in Milne Pt. Field wells. BP Exploration Alaska, Inc. by letter dated December 13, 1996 has requested an exception to the provisions of 20 AAC 25.200 (d) to allow the completing of wells in the Milne Pt. Field without packers where electric submersible pumps (ESP's) are used for artificial lift. The proposal will apply to wells in the Sag River, Kuparuk and Schrader Bluff formations where ESP's are mn. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM January 24, 1997 with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on the matter. If the protest is timely filed and raises a substantial and material issue crucial to the Commission's determination, a hearing on the matter will be held at the above address at 9:00 AM on February 11, 1996 in conformance with 20 AAC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, (907) 279-1433 after January 24, 1997. If no protest is filed, the Commission will consider the issuance of the order without a hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please~at. 279-1433 no later than January 31, 1997 David Wx.. Johnston \ ~ Chairman~ Published January 10, 1997 ADN AO02714023 BP EXPLORATION December 13, 1996 BP Exploration (Alaska) Inc. 900 East Benson Boulevard RO. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 (q~ ~,I~ /,~ }~ t David W. Johnston, Commissioner Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 RECEIVED Dear Mr. Johnston: Alaska 0ii & Gas Cor~s. Commission Anchorage. AAC 20.200 (d) requires that all wells capable of unassisted flow be completed with tubing and packer capable of isolating the. annulus from produced fluids. BP Exploration as Milne Point Unit operator, requests administrative wavier to this regulation for all Milne Point Unit producing wells completed in the Sag River, Kuparuk and Schrader Bluff Pools where electrical submersible pumps (ESPs) are deployed as the artificial lift system. Since the issuance of Administrative Order No. 173.11 (allowed replacement of subsurface safety valves and shallow packer with a Liquid Level Control Valve LLCV) and Conservation Order No. 348 ( eliminated the requirement for any type of subsurface safety valve), packerless completions have been standard practice at MPU. The LLCV packer was not intended to isolate the annulus from produced fluids; therefore, BP Exploration considered it implicit in Administrative Order No. 173.11 that a packer intended for that purpose was no longer required. Approximately 90% of the 80 ESP wells at MPU are completed without packers. Unless used in conjunction with subsurface safety valves to provide down hole shut-in, it is standard practice within the industry to complete ESP wells without packers. As stated in the May 10, 1994 letter (Bruce J. Policky to David W. Johnston), shallow packers utilized in conjunction with subsurface safety systems greatly complicate routine ESP workovers, presenting additional environmental and safety risk. Further, it was stated that deep setting packers would result in gas locking and subsequent damage to the ESP. Additional background and justification for the current system is provided in a joint BPX/ARCO letter (Bruce J. Policky and TOm Wellman to David W. Johnston dated September 14, 1994). For clarity, both of the referenced letters are attached. The annular pressure in a typical Milne Point ESP well is considerably less than typical gas lift pressures. Average pressures are 350 psig and 1,200 psig for ESP and gas lifted wells respectively. David W. Johnston, December 13, 1996 Page 2 Commisioner In addition, MPU crude oil, from all three producing reservoirs, is basically non-corrosive and the annulus is not exposed to oxygen; therefore, internal casing corrosion is not anticipated. Granting this wavier will ensure sound operating practices, reduce environmental risk and will extend the economic life of ESP wells in the Milne Point Unit. Therefore, a favorable ruling will be in the best interests of the MPU working interest owners and the State of Alaska. Exploita~tion ManOr cc: Howard Mayson, Tom Gray, Randy Thomas, Steve Rossberg, John Hendrix, Hal Stevens WA LTER J. HICKEL, GOVERNOR Jtllle 14. 1994 ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECO PY: (907, 276-7542 7 7g ~. 75~( Re: ADMINISTRATIVE APPROVAL NO. 173.11 The application of BP Exploration (Alaska) Inc. to use liquid level control (LLC) valves in those Milnc Point Unit wells completed with electric submersible pumps (ESPs). Bruce J. Policky. Milnc Point Exploitation Manager BP Exploration (Alaska) Inc. PO Box 196612 Anchorage, Alaska 99519-6612 R ECF!V ED Dear Mr. Policky: [)Lr:r'u, '} ,'il "~!.~ 9 ~ Thc referenced application was received May 18, 1994. Alaska 0il & 6as Cons. oo~m'mss~or, ,qnchora~o,,~ At present, the packers in ESP wells are set shallow, about 500', to prevent gas locking. There is also a permanent packer and screen assembly located below the pump which is designed to limit sand production. The ESPs have to be changed eve~ 2 to 3 years, therefore ease and safety of pulling operations is a consideration. The shallow packer depth makes well killing operations difficult and uncertain; potentially, not all of the gas is displaced from the well bore and fornmtion damage is more likely to occur. The LLC is activatcd by shut-down of the ESP and is linked to the wellhead shut-in system. Installation of thc LLC valve in a "hang-off" packer will allow kill fluids to be circulated at near-formation depths prior to pulling the ESP and will provide subsurface shut-in capabilities below the pump. David W. Joh~ Chairxnan Thc Alaska Oil and Gas Conscv,,ation Commission has reviewed the evidence available and hereby anthorizes, pursuant to Consen'ation Order 173, Rule 5(a)(2), the use of liquid level controlled (LLC) N.,.~.,,~ Point u.,,,,, wclls being lifted by electric sub,ncrsible pumps (ESPs) safety valves BY ORDER OF THE COMMISSION BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard RO. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 May 10, 1994 David W. Johnston, Commissioner Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Dear Mr. Johnston: Pursuant to Kuparuk Pool Rule No. 5 requiring the use of surface controlled subsurface safety valves (SCSSSV), BPX (A) as Milne Point Unit operator, requests administrative approval to utilize liquid level control (LLC) valves as the subsurface safety valve in MPU electrical submersible pump (ESP) completionS. In addition to providing reliable subsurface shut-in, LLC's will reduce operational risk and cost associated with ESP workovers. Attachment 1 depicts a typical Kuparuk ESP completion with a packer and tubing retrievable SCSSSV located at +/- 600' below surface. The shallow packer depth is necessary to prevent gas locking and subsequent damage to the ESP. In addition, there is a permanent hang:off packer and screen assembly located below the pump, which is designed to limit sand production through the ESP. Kuparuk ESP run life is 2-3 years; therefore, efficient pulling and running of ESPs is an essential part of MPU well operatiOns. Prior to pulling a failed ESP it is necessary to perform well kill oPerations by circUlating hydrocarbons out of the well and displacing with kill weight workover fluid. The shallow depth of the packer greatly complicates and adds risk to this process. Kill fluids are either circulated around the packer after it is released or through an annular vent valve. In either case, pressure drops are often too great to allow for efficient circulation without significant losses to the formation. If circulation cannot be established, the tubing is perforated below the packer and kill weight fluid bullheaded into the well. Bull heading in deviated wells will not efficiently displace all of the hydrocarbons; therefore, potential exists for gas to be trapped under the packer. Installation of a LLC valve in the hang-off packer will provide subsurface shut-in capabilities below the pump, eliminating need for the tubing retrievable SCSSSV and associated packer (See attachment 2). LLC's are nitrogen activated valves, set to open and close at predetermined bottom hole pressures, governed by the hydrostatic head in the wellbore (i.e. When the ESP shuts down, hydrostatic pressure in the wellbore will increase and close the LLC). Since a nitrogen charge keeps the LLC open, it will fail in the closed position. Although not actually controlled from the surface, activation of the LLC is directly linked to the surface controlled ESP and wellhead shut-in systems. In the event that subsurface shut-in is required (catastrophic failure of the tree), the ESP will automatically shut-in, allowing bottom hole pressure to increase; thereby, actuating the LLC valve. In addition, the LLC will provide a flow barrier during well kill and workover operations. This will reduce workover risk and cost during routine ESP replacements. The LLC valve has been successfully used by other operators in domestic U.S. onshore fields and has been used extensively in Russia. It is proposed to function test the LLC valves as follows: 1) Shut -in the ESP and close the wing valve. Monitor surface pressure and BHP via the ESP bottom hole pressure sensor ( If the sensor is not functioning, shoot fluid levels and calculate BHP). 2) When the pressure stabilizes, bleed off tubing pressure to +/- 100 psig. Continue monitoring surface pressure and BHP for 30 minutes. If the LLC is functioning, both surface and BHP should remain constant. If necessary, shoot another fluid level and calculate BHP. Granting this wavier will result in improved operating practices, reduced workover costs and risks and will extend the economic life of ESP wells in the Milne Point Unit. Therefore, BPX (A) contends that a favorable ruling will be in the best interests of the MPU working interest owners, the State of Alaska and will protect correlative rights. Give me a call at 564-5232 if you would like to set up a meeting to further discuss this completion design change. Vep~ truly yours,~,,,'.,,~~~ Bruce.'3. Policky I~ Milne Point Exploitation Manager cc: S Rossberg,,S Lynch, H. Mayson, T. Gray WELL No. L-: COMPLETION SKETCH MILNE POINT UNIT (P) APl No.: 50-029-22.334 PERMIT No.: 93-11 COMPLETED: 7-4-93 LAST WORKOV1ER: N/A 266 JTS. 2 7/8" TBG TOTAL .~- WKM HANGER WITH 5" BPV PROFILE 16 JTS. 2 7/8" 6.5#/FT L-80 8rd EUE TBG. ELECTRIC SUBMERSIBLE PUMP CABLE NO. 2 CL-350 NOTES: 1. ALL DEPTHS MEASURED KDB-SL = 51' KDB-GL = 28' 2. MAX. ANGLE = 46' @ 4085' 5. K.O.P. = 500' 4. SLANT HOLE: YES 5. TREE TYPE: WKM 2 9/16" APl 5000# W/ 2 7/8" 8rd TREETOP CONNECTION 6. MIN I.D. = OTIS 'X' NIPPLE (2.313" I,D.) @ 621' 7. COMPLETION FLUID: 10.2 PPG NoBr 8. STIMULATION: FRACTURE STIMULATION 150,000# 12-18 ISP BEHIND PIPE MK. LZ. LK PERFORATIONS DENSITY: 12 SPF, 5" CSG GUNS 8751'-8771' MD (6940'-6955' TVO) 8812'-8832' MD (6987'-7002' TVD) 8854'-8864' MD (7019'-7027' TVD) 8878'-8888' MD (7038'-7045' TVD) 8910'-8940' MD (7061'-7085' TVD) 8950'-8980' MD (7093'-7117' TVD) 9030'-9050' MD (7156'-7172' TVD) 7" 26#/FT L-SO CSG---~ 587' 2 7/8" OTIS FMX SCSSV 607' ARROW HYDROW I IP DUAL' PACKER 619' 2 7/8" OTIS 'X' NIPPLE (2.313" I.D.) 666' 2 7/8" CAMCO KBMG MANDREL W/ 1" ORIFICE VALVE 246 JTS. 2 7/8" 6.5#/FT L-80 8rd EUE TBG. 8471' 2 7/8" CAMCO KBMG MANDREL W/ 1" HOT OIL VALVE SET @ .3200 PSI 1 JT. 2 7/8" 6.5#/FT L-80 8rd EUE TBG. 8513' 2 7/8" CONE CHECK VALVE 2 JTS. 2 7/8" 6.5#/FT L-80 8rd EUE TBG. 8594' CENTRLIFT ESP, 251 STAGE, FC-925, 100 HP, '2145V/27A, GSBT, KRYTOX 8632' BOTTOM OF ESP 8706' BAKER MODEL 'D' PERM PKR W/ MILLOUT EXTENSION 8717' 20' OF 20 GAUGE SCREEN ON 4" BASE 8738' 6'LG 5 1/2" PUP JOINT 8744' CAMCO 'D' NIPPLE WITH A-2 BLANKING PLUG ON C-LOCK 8746' WIRELINE RE-ENTRY GUIDE 9224' PBTD CONOCO INC. (cOn°c&) IAPPROVED BY: JHA DATE: 8-17-93 DRAFTED BY: G. FAST CAD FILE: WCOL12 TYPICAl-WELL SCHEMATIC WELL HEAD SHUT-IN FLUID LEVEL ,',--~-~~. , CASING TUBING ---~__~----_ · PUMP _ ,~-PO\VER CABLE . __----- PRODUCING FLUID LEVEL -- SUBMERSIBLE PUMP CLO.' LIQUID LEVEL SAFETY VALVE HYDRAULIC LOCK 3ER/RECEPTACL PACKER ~XF'~T T OPEN ECEIVED Dr'''''c. (, ] ~'9 'ig $ G , . AH~,, O: ~:!j'; ARCO Alask_a~' Post O~, ~, .~x 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 September 14, 1994 Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Request to Revise Conservation Order 173, Rule 5 Dear Mr. Johnston' ARCO Alaska, Inc., .Operator of the Kuparuk River Unit, and BP Exploration, Alaska, Inc., Operator of the Milne Point Unit, request that the Commission revise the requirements of Conservation Order 173, Rule 5 to require only a surface safety valve for wells capable of unassisted flow of hydrocarbons. The applicants request that this rule be revised as soon as possible and applied to the entire Kuparuk River Oil Pool, Kuparuk River Field and both operating Units. The purpose of this' request is to remove the subsurface safety valve requirement which will allow us to operate the fields more efficiently while maintaining a safe operation. This letter, which should be considered ARCO and BPX's formal request, is divided into three main sections covering the .background, proposal, and justification for.this action. BACKGROUND The field rules (Conservation Order No. 173) for the Kuparuk River Oil Pool, Kuparuk River Field, require' each well be equipped with both surface and subsurface 'safetY valves for all wells capable of unassisted flow of' hydrocarbons. The Kuparuk and Milne Point Units are the only producing operations within this field. Conservation Order 173 was issued on May 6, 1981, and has been in effect throughout the producing lives of the both Units. The subsurface, safety valve requirements in North Slope fields were originally requested by ARCO and BPX based on the Iow level of experience with arctic production operations. After many years of safe operations these concerns no longer exist. ARCO and BPX have gained substantial arctic operating experience and both the Kuparuk and Milne Point Units now possess an extensive infrastructure operated by a highly skilled work force. One of the main concerns during the early years of arctic operation was the potential freeze back of the permafrost. Subsurface valves were used to protect against the risk of loss of well control due to casing collapse during ARCO Alaska. inc. is a Subsidi,:~ry Ol AtlarlticRichfi,utc;Co;:!~,,,, , Mr. Davi( Johnston, Chairman (' Request to Revise Conservation Order 173, Rule .., Page 2 freeze back of the permafrost. The uncertainty relating to this risk, however, was eliminated with the improved design of casing strings and cement capable of withstanding the thaw - freeze back forces. Twelve years of production operations at Kuparuk have clearly demonstrated that this is no longer an area for concern. Outside of Alaska, subsurface safety valves are used primarily in offshore applications where wells and platforms are at risk due to hurricanes, ocean going ships, and subsea mud slides. The use of subsurface safety valves in onshore wells in the lower 48 is very rare and generally restricted to wells with extremely high levels of hydrogen sulfide, located in heavily populated urban areas. Consistent with the industry practice in the lower 48, the use of subsurface safety valves is not required or in use in any of the other onshore fields in Alaska outside of the North Slope. PROPOSAL ARCO and BPX propose that Conservation Order 173, Rule 5 be revised to eliminate the subsurface safety valve requirement for all wells, and to require a surface safety valve only in wells capable of unassisted flow of hydrocarbons. The pilot actuated surface valve is capable of automatically closing to prevent an uncontrolled flow. Surface valves will continue to be tested as required by the AOGCC every six months. For clarity a copy of Rule 5 is included here in Attachment 1 with the paragraph of interest underlined. It is proposed that the entire paragraph (a) (2) and other references to SSSV's be deleted and that revised Rule. 5 read as shown in Attachment 2. Removing the requirement for subsurface valves at Kuparuk and Milne Point is consistent with the Commission's statewide regulation, 20 AAC 25.265, which imposes a universal subsudace valve requirement only for offshore wells. JUSTIFICATION SSSV's provide only a redundant level of protection to the SSV. The risks which were thought to justify the extra protection provided by SSSV's have proven to be either absent or extremely unlikely in Kuparuk River Oil Pool wells. In fact, subsurface valves actually create a small element of risk, as hundreds of downhole well operations are performed each year just to service and maintain existing valves. In addition, the requirement for subsurface valves may preclude the development and application of various alternate completion techniques being studied to extend the life of the Kuparuk River Field. Mr. Davt' Johnston, Chairman ( Request to Revise Conservation Order 173, Rule Page 3 Please note that ARCO and BPX are not asking for a waiver of a statewide rule as 20 AAC 25.265(b) does not require either a surface or subsurface safety valve for onshore wells. Our proposal is to continue to exceed the requirements of the statewide rules by continuing to install and maintain surface safety valves. This revision will result in a significant improvement in the efficiency of operations at Kuparuk and Milne Point. It conforms with prudent oil field management and will not adversely affect ultimate recovery. Please contact either of us if you have any questions, or need more information. Our phone numbers are 263-4304 and 564-5232 for the ARCO and BPX contacts respectively. .Sincerely, Tom Wellman KRU Staff Manager Kuparuk Business Unit Attachments MPU Exploitation Manager Milne Point Unit Attachment 1 Current Conservation Order 173, Rule 5. Rule 5. Automatic Shut-In Equipment (a) Upon completion, each well which is capable of unassisted flow of hydrocarbons must be equipped with a commission- approved fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow by automatically closing if such a flow should occur; and (2) fail-safe automatic surface controlled subsurface safety valve ($S$V). unless another type of subsurface valve is approved by the Commission: this valve must be in the tubing string located at a depth of 500 feet or greater below grQ~nd level; the valve must be capable Qf preventing an uncontrolled flow by automatically closing if such a flow should occur. (b) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SSV, SSSV, and all associated equipment are in proper working condition; and (c) 'A well that is not capable of unassisted flow of hydrocarbons as determined by a "no flow" performance test witnessed by a commission representative is not required to have fail-safe 'automatic SSV Or SSSV valves. Attachment 2 Proposed Revised Conservation Order 173, Rule 5. Rule 5. Auto (a) (b) (c) matic Shut-In Eouioment Upon completion, each well which is capable of unassisted flow of hydrocarbons must be equipped with a commission- approved fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow by automatically closing if such a flow should occur A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SSV and all associated equipment are in proper working condition; and 'A well that is not capable of unassisted flow of hydrocarbons as determined by a "no flow" pedormance test witnessed by a commission representative is not required to have fail-safe automatic SSV. . , STATE OF ALASKA OIL AND GAS CONSERVATION COM2VASSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 The Application of ARCO Alaska, Inc. ) and BP Exploration (Alaska) Inc. to ) diminatc the requirement for subsurface ) saf~y valves in walls drilled to the Kuparuk ) River oil pool. ) Conservation Order No. 34g Kuparuk River Field Kuparak River Oil Pool December 16, 1994 IT APPEARING TIiAT; . By letter daw_A September 14, 1994, ARCO Alaska, Inc. and BP Exploration (Alaska) Inc., as operators &thc Kupamk and Milnc Point Units, requesttxt a revision to Conservation Order 173, Rule 5, by ¢limingting the recuimment for subsu~ safety valves in the Kupamk River oil pool, Kuparuk Kiver Fi01d. 2. Notice of public hearing was published in the Anchorage Daft), News on October 11, 1994. 3. The Commission received no protest or request for a hearing regardi~ the petition. FINDINGS: Conmfission regulations, 20 AAC 25.265, require surface and subsurface safety valves only in wells located offshore that are capable ofunasaisted flow to the surface, but allows Cormnission di~croti°n for requiring SSV's or SSSV's, or both, on wells in other areas. 2. When cquipp'cd with both valves, th, SSSV's provides redm~dant protection against accidental release of hydrocarbons from wells capable of unassisted flow to the surface. 3. COnservation Order 173, Rule 5, requires both SSV's and SSSV~s for all wells capable of unassistc. A flow to the surface in the Kuparuk River oil pool,.Kuparuk River Field. 4. Conservation Order 173 was issued May 6, 1981. R }~ C }7... !'~,f ~! D . The Commission first 'reqUired SSV's and SSSV's for all onsh°re welis in the Pmdh&[:'~B~,y Field. The average well rate at fidd starmp in .].977 was 7000 bbl]day oil, with maximum rates as lfigh as 27,000 bbYday. Alaska Oil 8,, The requirements for SSV's and SSSV', for all onshore wells was extended to the Kuparuk River Field by C.O. 173 in 1981. Average well ra~ in the Kupa.mk River oil pool excooded 2000 bbl/day oil at field startup. 7. Average well rate for the Kupamk River oil pool in 1994 is 800 bbl/day with artificial lift. The majority of wells producing from th~ Kuparuk River oil pool today require artificial lift. Page 2 December 16, 1994 9. In 1981 dcvclopnwa~t activity and infrastructure in th: Kuparuk River Field was limited, today exten.~ive activity and infra.s~crure exists within the field and adjacent areas. 10. In ] 981 casjT~g sctting techniques conformed to lower 48 practices and operators had little experience producing through pcrmagrost or under Arctic con~tions. 11. 12. Operators today use cc'mcnt formulated for permafrost conditions, appropriate ca.sing grades, annular fluids to alleviate concerns for casing failure and enclosed well houses. The Commission has no record of an SSSV being used in Alas'La to prevent uncontrolled flow to the ~urface from an onshore well. 13. gSSV's contrJbut~ to higher operating costs for the state and operators. 14. S$$V's impede or prohibit some types of completions. 15. Conmzission requirements for automatic safety valve systems have evolved over tim~ ff. ~' F ~ ~ f ~- CONCLUSIONS: ? !:',. .... i ..::', ~I~; '.'" ,,,, I. $SSV's may r~ucc uJti~ recovery by contrjbutins; to higher costs. SSSV's in onshore wells in Alaska have provided limited benefit to public safety, environmental protection or resourc~ r~,ovcry. . . . . . , Experience mid new technology have reduced any danger to eash~g integxity from fi'eeze-baek or thaw subsidence eff~ts within permafrost. Thc probability of early detection and response to an accidental release of hydrocarbons is significantly greater today than in 1981 as a result of full field development and activ, ity. Eliminating tho requirement for SSSV's in onshore Kuparuk River oil pool wells will not likely contribute to waste and may contribute to safer well operations and greater ultimate recovery. For wells equipped with artificial lift, tho surfaco safety valve s);stem should b~ capable of shutting down the lift system if an over pressure of equipme~t could occur if the artificial lift systems were to remain functioning. It is appropriale to' mn~d Conservation Order 173, Rule 5, to conform with sinfilar surface safely valve system requirements now imposed for other North Slope poola. NOW, THEREFORE, IT IS ORDERED THAT Rule 5 of C.O. of 173 is mended to rca& Rule 5. Automatic Shut-In Equipment Each well shall be equipped wi~ a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shuttir~ off flow at the wellhead and shuttir~ down any artificial lift system where an over pressure of equipment may occur. PageC°nscrvati°n30rde( ' ',~ ~48 ~ December 16, 1994 The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if thc pad is manned. If the SVS cannot be re-mined to service within 24 hours, Lc well must be shut ia at the well head and at the manifold building. 1. Wells with a deactivated SVS ~hall be id~tifiod by a sign on the wellhead stating that the SVS has bccn de. activ~ and tho date it'was deactivated. o A list ofwell~ with the SVS dr, activated, the dates and reasmzs for de. activating, and file estimated m-activation daWs must be maintained current and available for Commission inspection on request. C. A representative of tho C_.omm.issiort will w/moss operation and peffornumee tests at intervals and times as prcscribod by the Commission to confirm that tt;e SVS is in proper working condition. DONE at Anchorage, Al · Alaska Oil and ~servati~n Commission Russoll A. Douglass, Commissj~er Alaska Oil and Gas ConservatiOn Commission ~uckerman Babcock, Commissioner Alaska Oil and Gas Conservation Commission A.q 3 ! .05.0g0 provi&~ thal within 20 day, ufl~ rr. ogqpt of~ notl~ W~ ~ ~,or~. & ~ ~ by R may file ~ ~o C~m~ion an ~li~li~ ~ ~8. Ar~ for ~g m~ ~ ~iv~ by 4:30 PM ~ ~ 23~ ~y fi,llo~ U~ ~ of~ p~ wlfll~ lO da~. ~o C~s~ ~ ~ ~ ~I;~ by~ ~8 ~ h ~ ~e lO~y ~. ~ ~ I~ ~ 30 C~mi~;m), ~ 30 day ~ f~ a~al to ~ ~ ~ ~ da~ ~ ~Bh ~ r~ it ~ ~n;~ {i.e., 10~ dny ~