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Home My WebLink AboutCO 341 CConservation Order Cover Pad,., XHVZE This page is required for administrative purposes in managing the scanning process. It marks the extent of scanning and identifies certain actions that have been taken. Please insure that it retains it's current location in this file. L(2 Conservation Order Category Identifier Organizing (done) 74CM01-0-r items: ❑ Grayscale items: ❑ Poor Quality Originals: ❑ Other: NOTES: DIGITAL DATA ❑ Diskettes, No. ❑ Other, Nofrype OVERSIZED (Scannable with large plotter/scanner) ❑ Maps: ❑ Other items OVERSIZED (Not suitable for plotter/scanner, may work with 'log' scanner) ❑ Logs of various kinds ❑ Other BY: ROBIN MARIA DATE: /,, ` /S/ 1 , Scanning Preparation TOTAL PAGES --- I BY: ROBIN MARIA DATE: /_— /S/ Production Scanning (�% Stage 1 PAGE COUNT FROM SCANNED DOCUMENT: PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: YES NO BY: ROBIN MARIA DATE: 30 — Q3 /S/� Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: YES NO BY. ROBIN ARIA DATE: Q3 /s/ (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES) General Notes or Comments about this Document: Q1 V\C� s 5/21/03 ConservOrdCvrPg.wpd STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: AOGCC motion to amend Conservation ) Conservation Order No. 341 C Order 341 B, revoking rule 10 relating to ) facility gas flaring from the Prudhoe Oil ) Prudhoe Bay Field Pool. ) Prudhoe Oil Pool June 12, 1997 ON ". >>�13W111II,, EN?A By its own motion, the Alaska Oil and Gas Conservation Commission issued public notice of its intention to amend Conservation Order 341 B by revoking Rule 10, Facility Gas Flaring. The Commission considers this action necessary because new gas disposition regulations became effective on January 1, 1995 and functionally revoked all previously issued conservation orders relating to facility flaring. Subsequent revisions to Conservation Order 341 inadvertently retained an out-of-date rule describing approved flare volumes for Prudhoe Bay facilities. 2. Notice of opportunity for public hearing was published March 29, 1997. No protest were received. FINDINGS: Previously issued conservation orders for the Prudhoe Bay Field describing facility flaring are: a) Conservation Order 145A which established reporting requirements for flaring events as well as procedures to be taken to minimize waste. The rule also limited flaring during a single event to a twelve hour period before Commission approval must be obtained. b) Conservation Order 197 which prohibited the flaring or venting of gas except as authorized by the Commission in cases of emergency or operational necessity. This rule also allowed operators the chance to apply for Commission approval to permit well testing in areas of the pool where access to pool gas gathering facilities was not prudent. c) Conservation Order 219, Rule 1 which established daily flaring rates for specific facilities to maintain safety flares and allow purging of gas handling equipment. The Commission consolidated the aforementioned rules relating to facility flaring, along with other rules previously approved for the Prudhoe Oil Pool, in Conservation Orders 341 (consolidated), dated October 2, 1994. Rule 10, Facility Gas Flaring, of Conservation Order 341 was carried forward unchanged as Rule 10 of Conservation Order 341 A (amended Oct. 2, 1995) and as Rule 10 of Conservation Order 341B (amended Nov. 17, 1995). The Commission established new gas disposition regulations, 11 AAC 25.235, effective January 1, 1995 to cover flaring events at oil and gas production facilities statewide. The gas disposition regulations functionally revoked all previously issued flaring rules detailed in conservation orders issued prior to January 1, 1995. Conservation Order 34 June 12, 1997 Page 2 CONCLUSIONS: 1. Rules dealing with facility gas flaring under Conservation Orders 145A, 197, and 219 were revoked by 11 AAC 25.235 on January 1, 1995, as was Rule 10 of Conservation Order 341. 2. Incorporating Rule 10 of Conservation Order 341 in subsequent amendments to that order (i.e., CO 341A and CO 341B) was in error. 3. Revoking Rule 10 of Conservation Order 341 B will not promote waste, harm ultimate recovery nor jeopardize correlative rights, and will eliminate any confusion with existing regulations governing facility gas flaring. NOW, THEREFORE, IT IS ORDERED THAT Rule 10 of Conservation Order 341 B is revoked, and the following rules now apply to the following described area referred to in this order as the affected area: UMIAT MERIDIAN T. ION., R. 12E., Sections: 1, 2, 3, 4, 10, 11, 12 T. ION., R. 13E., 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 24 T. ION., R. 14E., 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 36 T. ION., R. 15E., all T. ION., R. 16E., 5, 6, 7, 8, 17, 18, 19, 20, 29, 30, 31 T. I IN., R. I IE., 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 24, 25 T. IIN., R. 12E., all T. IIN., R. 13E., all T. 11 N., R. 14E., all T. IIN., R. 15E., all T. 11N- R. 16E., 17, 18, 19, 30, 31, 32 T. 12N., R. 10E., 13, 24, T. 12N.. R. I 1 E., 15, 16, 17, 18, 19, 20, 21, 22, 25, 26, 27, 28, 29, 30, 32, 33, 34, 35, 36 T. 12N., R. 12E., 23, 24, 25, 26, 27, 28, 29, 30, 3l, 32, 33, 34, 35, 36 T. 12N., R. 13E., 19, 20, 21, 22, 23, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 Conservation Order 34. Page 3 T. 12N., R. 14E., T. 12N., R. 15E., 25, 26, 27, 28, 29, 31, 32, 33, 34, 35, 36 25, 26, 27, 28, 29, 30 ,31 ,32, 33, 34, 35, 36 June 12, 1997 (Source: C. 0. 145, page 7, expansions/contractions of initial participating area based on November 20, 1987 letter, Wade and Nelson to Eason, Re: Prudhoe Bay Unit Exhibits, Exhibit C, Part I Oil Rim Participating Area and Part lI Gas Cap Participating Area.) Rule 1 Pool Definition and Changing the Affected Area (ref. C.O. 145) (a) The Prudhoe Oil Pool is defined as the accumulations of oil that are common to and which correlate with the accumulations found in the Atlantic Richfield - Humble Prudhoe Bay State No. 1 well between the depths of 8,110 feet and 8,680 feet. (Source: C.O. 145, Rule 1) (b) The Commission may adjust the description of the affected area to conform to future changes in the initial participating area by administrative approval. (Source: C. 0. 145, Rule 12) Rule 2 Well Spacing (ref. C.O. 145, 174) There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area. (Source: C.O. 174, Rule 2) Rule 3 Casing and Cementing Requirements (ref. C.O. 145, 238) (a) Conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe to the surface. Rigid high density polyurethane foam may be used as an alternate to cement, upon approval by the Commission. The Commission may also administratively approve other sealing materials upon application and presentation of data which show the alternate is appropriate based on accepted engineering principles. (Source: C.O. 238, Rule 3a) (b) Surface casing to provide proper anchorage for equipment, to prevent uncontrolled flow, to withstand anticipated internal pressure, and to protect the well from the effects of permafrost thaw -subsidence or freeze -back loading shall be set at least 500 feet, measured depth, below the base of the permafrost but not below 5000 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the casing to the surface. The surface casing shall have minimum axial strain properties of 0.5% in tension and 0.7% in compression. (Source: C.O. 238, Rule 3b) (c) Alternate casing programs may be administratively approved by the Commission upon application and presentation of data which show the alternatives are appropriate, based upon accepted engineering principles. (Source: C.O. 238, Rule 3c) Conservation Order 34, June 12, 1997 Page 4 Rule 4 Blowout Prevention Equipment and Practice (ref. C.O. 145) (a) The use of blowout prevention equipment shall be in accordance with good established practice and all equipment shall be in good operating condition at all times. All blowout prevention equipment shall be adequately protected to ensure reliable operation under the existing weather conditions. All blowout prevention equipment shall be checked for satisfactory operation during each trip. (Source: C.O. 145, Rule 4a) (b) Before drilling below the conductor string, each well shall have installed at least one remotely controlled annular type blowout preventer and flow diverter system. The annular preventer installed on the conductor casing shall be utilized to permit the diversion of hydrocarbons and other fluids. This low pressure, high capacity diverter system shall be installed to provide at least the equivalent of a 6-inch line with at least two lines venting in different directions to insure downwind diversion and shall be designed to avoid freeze-up. These lines shall be equipped with full -opening butterfly type valves or other valves approved by the Commission. A schematic diagram, list of equipment, and operational procedure for the diverter system shall be submitted with the application Permit to Drill or Deepen (Form 10-401) for approval. The above requirements may be waived for subsequent wells drilled from a multiple drill site. (Source: C.O. 145, Rule 4b) (c) Before drilling below the surface casing all wells shall have three remotely controlled blowout preventers, including one equipped with pipe rams, one with blind rams and one annular type. The blowout preventers and associated equipment shall have 3000 psi working pressure and 6000 psi test pressure. (Source: C.O. 145, Rule 4c) (d) Before drilling into the Prudhoe Oil Pool, the blowout preventers and associated equipment required in (c) above shall have 5000 psi working pressure rating and 10,000 psi test pressure rating. (Source: C.O. 145, Rule 4d) (e) The associated equipment shall include a drilling spool with minimum three-inch side outlets (if not on the blowout preventer body), a minimum three-inch choke manifold, or equivalent, and a fill -up line. The drilling string will contain full -opening valves above and immediately below the kelly during all circulating operations with the kelly. Two emergency valves with rotary subs for all connections in use will be conveniently located on the drilling floor. One valve will be an inside blowout preventer of the spring -loaded type. The second valve will be of the manually -operated ball type, or any other type which will perform the same function. (Source: C.O. 145, Rule 4e) (f) All ram -type blowout preventers, kelly valves, emergency valves and choke manifolds shall be tested to required working pressure when installed or changed and at least once each week thereafter. Annular preventers shall be tested to 50% recommended working pressure when installed and once each week thereafter. Test results shall be recorded on written daily records kept at the well. (Source: C.O. 145, Rule 4f) Conservation Order 34 June 12, 1997 Page 5 Rule 5 Automatic Shut-in Equipment (ref. C.O. 145, 333, 363) (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead and shutting down any artificial lift system where an over pressure of equipment may occur. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the well head and at the manifold building. Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. 2. A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re -activation dates must be maintained current and available for Commission inspection on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS is in proper working condition. (d) The SVS must be maintained in working condition at all times unless the well is shut in and secured, or the well is being operated in conformance with other sections of this rule. (e) Upon proper application or its own motion, the Commission may administratively waive or amend the requirements of this rule as long as the change does not promote waste, jeopardize correlative rights or compromise ultimate recovery, and is based on sound engineering principles. (f) Nothing in this rule precludes the installation of a SSSV in wells designated by the operator. If a SSSV is installed, it must be maintained in working order and is subject to performance testing as part of the SVS. Rule 6 Pressure Surveys (ref. C.O. 145, 165, 192, 208, 213, 220, AA 220.1, 341B) (a) Prior to regular production, a static bottom hole or transient pressure survey shall be taken on at least one in three wells drilled from a common drilling site. (Source: C.O. 220, Rule 1, C.O. 341B) (b) An annual pressure surveillance plan shall be submitted to the Commission in conjunction with the Annual Prudhoe Pool Reservoir Surveillance Report by April 1, each year. The plan will contain the number of pressure surveys anticipated for the next calendar year and be subject to approval by the Commission by May 1. These surveys are needed to effectively monitor reservoir pressure in the Prudhoe Oil Pool. The surveys required in (a) of this rule may be used to fulfill the minimum requirements. (Source: C.O. 220, Rule 6, C.O. 341B) Conservation Order 34 Page 6 June 12, 1997 (c) Data from the surveys required in (a) and (b) of this rule shall be filed with the Commission by the last day of the month following the month in which each survey is taken. Form 10- 412, Reservoir Pressure Report, shall be used to report the data from these surveys. Data submitted shall include rate, pressure, time, depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall -off test, a multi -rate test or an interference test are acceptable. Other quantitative methods may be administratively approved by the Commission. (Source: C.O. 220, Rule 7) (d) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (c) of this rule. (Source: C.O. 220, Rule 8) (e) By administrative approval the Commission may grant time extensions and waive requirements of this rule, and by administrative order the Commission may require additional pressure surveys in (b) of this rule. (Source: C.O. 220, Rule 5) Rule 7 Gas -Oil Contact Monitoring (ref. C.O. 145, 165, 192, 208, 213, AA 213.39) (a) Prior to initial sustained production, a cased or open hole neutron log shall be run in each well. (Source: C.O. 165, Rule 9a) This requirement is waived for waterflood/EOR areas encompassed by the expanded Prudhoe Bay Miscible Gas Project outlined in C.O. 290, and for those areas not expected to have significant GOC movement or gas encroachment from the gravity drainage area defined by the Commission through Administrative Approval. (Source: AA 213.39, excerpts from paragraph 1) (b) A minimum of 40 repeat cased hole neutron log surveys shall be run annually. (Source: C.O. 208, Rule 4) (c) The neutron logs run on any well and those required in (a) and (b) of this rule shall be filed with the Commission by the last day of the month following the month in which the logs were run. (Source: C.O. 165, Rule 9d) (d) By administrative approval, the Commission may delay, modify or waive the logging requirements of this rule or may require additional wells to be logged. (Source: C.O. 213, Rule 3) Rule 8 Productivity Profiles (ref. C.O. 145, 165, 192, 208, 213, AA 213.40) (a) A spinner flow meter or tracer survey shall be run in each well during the first six months the well is on production. (Source: C.O. 165, Rule 1 la) This requirement is waived for wells completed with a single perforated interval, or with perforations in a single reservoir zone including highly deviated (greater than 65 degrees) and horizontal wells. (Source: AA 213.40 paragraph 3) Conservation Order 34 Page 7 June 12, 1997 (b) Follow-up surveys shall be performed on a rotating basis so that a new production profile is obtained on each well periodically. Nonscheduled surveys shall be run in wells which experience an abrupt change in water cut, gas -oil ratio, or productivity. (Source: C.O. 165, Rule l lb) (c) The complete spinner flow meter or tracer data and results shall be recorded and filed with the Commission by the last day of the month following the month in which each survey is taken. (Source: C.O. 165, Rule l lc) (d) The Commission may administratively approve alternate methods and time periods in the enforcement of this rule provided that the data obtained is appropriate for monitoring the Prudhoe Oil Pool or may waive the requirements of (a), (b) and (c). By administrative order the Commission may specify additional surveys other than the surveys submitted under (a), (b) and (c) of this rule. (Sources: C.O. 208, Rule 8 and C.O. 213, Rule 2) 0 Rule 9 Pool Off -Take Rates (ref. C.O. 145, 214) The maximum annual average oil offtake rate is 1.5 million barrels per day plus condensate production. The maximum annual average gas offtake rate is 2.7 billion standard cubic feet per day, which contemplates an annual average gas pipeline delivery sales rate of 2.0 billion standard cubic feet per day of pipeline quality gas when treating and transportation facilities are available. Daily offtake rates in excess of these amounts are permitted only as required to sustain these annual average rates. The annual average offtake rates as specified shall not be exceeded without the prior written approval of the Commission. Annual average offtake rates mean the daily average rate calculated by dividing the total volume produced in a calendar year by the number of days in the year. However, in the first calendar year that large gas offtake rates are initiated, following the completion of a large gas sales pipeline, the annual average offtake rate for gas shall be determined by dividing the total volume of gas produced in the calendar year by the number of days remaining in the year following initial delivery to the large gas sales pipeline. Rule 10 Facility Gas Flaring revoked (ref. C. O. 341 C) Rule 11 Annual Surveillance Reporting (ref. C.O. 165, 186, 195, 208, 223, 224, 279, AA 279.1) (a) An annual Prudhoe Oil Pool surveillance report will be required by April 1 of each year. The report shall include but is not limited to the following: 1. Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. 2. Voidage balance by month of produced fluids, oil, water and gas, and injected fluids, gas, water, low molecular weight hydrocarbons, and any other injected substances (which can be filed in lieu of monthly Forms 10-413 for each FOR project). (Source C.O. 279, Rule 7 and AA 279.1 excerpt from paragraph 3) Conservation Order 34, . June 12, 1997 Page 8 3. Analysis of reservoir pressure surveys within the field. 4. Results and where appropriate, analysis of production logging surveys, tracer surveys and observation well surveys. Results of gas movement and gas -oil contact surveillance efforts including a summary of wells surveyed and analysis of gas movement within the reservoir. The analysis shall include map(s) and/or tables showing the locations of various documented gas movement mechanisms as appropriate. (Source: C.O. 279, Rule 7) (b) Upon its own motion or upon written request, the Commission may administratively amend this rule so long as the change does not promote waste nor jeopardize correlative rights and is based on sound engineering principles. (Source: C.O. 279, Rule 8) Rule 12 Prudhoe Bay Miscible Gas Project (PBMGP) (ref. C.O. 195, 290) (a) Expansion of the PBMGP and infill expansion of miscible gas injection in the NWFB is approved for the 59,740 acre portion of the Prudhoe Oil Pool defined in the record. (Source: C.O. 290, Rule 1, AA 290.1) (b) An annual report must be submitted to the Commission detailing performance of the PBMGP and outlining compositional information for the current miscible injectant (MI) necessary to maintain miscibility under anticipated reservoir conditions. (Source: C.O. 290, Rule 2) (c) The operator will maintain a pressure differential of at least 250 psi between the minimum miscibility pressure (MMP) of the MI and the prevailing reservoir pressure at the time of injection. This differential is based on a projected prevailing reservoir pressure decline of no more than 30 psi/year over the life of the project. (Source: C.O. 290, Rule 4) (d) The operators are directed to continue investigating options to mitigate pressure decline and to provide an annual progress report to the Commission. (Source: C.O. 290, Rule 5) (e) Upon its own motion or upon written request, the Commission may amend this rule by administrative action if the change does not promote waste, violate correlative rights, nor jeopardize ultimate recovery, and is based on sound engineering principles. (Source: C.O. 290, Rule 6) Rule 13 Waiver of GOR Limitation (ref. 8/22/86 letter) The Commission waives the requirements of 20 AAC 25.240(b) for all oil wells in the Prudhoe Oil Pool of the Prudhoe Bay Field so long as the gas from the wells is being returned to the pool, or so long as the additional recovery project is in operation. (Source: Letter 8/22/86, L. Smith to Heinze/Nelson, paragraph 3) Conservation Order 34 Page 9 June 12, 1997 Rule 14 Waiver of "Application for SundryApproval" Requirement for Workover Operations (ref. C.O. 258) The requirements of 20 AAC 25.280(a) are waived for development wells in the Prudhoe Oil Pool of the Prudhoe Bay Field. (Source: C.O. 258) Rule 15 Waterflooding (ref. 3/20/81 letter Hamilton to Nelson/Norgaard) The commission approves the December, 1980 additional recovery application for water -flooding in the Prudhoe Oil Pool subject to the requirements listed in Rule 11 above. Any proposed changes must be submitted to the Commission for approval. (Source: Letter 3/20/81, Hamilton to Nelson/Norgaard) Rule 16 Orders Revoked The following Conservation Orders and associated Administrative Approvals and letter approvals are hereby revoked. Conservation orders 78, 83B, 85, 87, 88, 96, 97, 98B, 117, 117A, 118, 130, 137, 138, 139, 140, 141, 143, 145, 145A, 148, 155, 160, 164, 165, 166, 167, 169, 174, 178, 180, 181, 183, 184, 185, 186, 188, 189, 192, 194, 195, 195.1, 195.2, 195.4, 197, 199, 200, 204, 208, 213, 214, 219, 220, 223, 224, 238, 258, 259, 279, 290 and 333, 341, 341A and March 20, 1981 and August 22, 1986 letter approvals. The hearing records of these orders are made part of the record for this order. DONE at Anchorage, Alaska and dated June 12, 1997. David W. 7olffiston, Chai Alaska Oil d Gas Conse tion Commission Robert N. nstenson, Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30 day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). TONYKNOWLES, GOVERNOR ALASKA OIL AND GAS3001 ANCHORAGE. AL DRIVE ANCHORAGE. ALASKA 99501-3192 CONSERVATION COMMISSION PHONE: (907) 279-1433 June 22. 1999 FAX: (907) 276-7542 ADMINISTRaTINT APPROVAL 341C.01 Re: The application of BP Exploration (Alaska). Inc. and Arco Alaska. Inc. to change Rule 6. Conservation Order 341C. Prudhoe Oil Pool. Prudhoe Bav Field. Darrel Bose Bruce Luberski Manager. Prudhoe Bay Resource Development Manager. PBU Resource Management Arco Alaska. Inc. BP Exploration (Alaska). Inc. P.O. Box 100360 P.O. Box 19612 Anchorage. AK 99510-0360 Anchorage. AK 99519-6612 Gentlemen: We received your application June 4. 1999 requesting a change to Rule 6(c). Conservation Order 341C. to require reporting pressure data annually instead of monthly and change the filing document from Form 10-412 to filing with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Rule 6(e) allows the Commission to grant time extensions and waive requirements of Rule 6 by administrative approval and require additional surveys by administrative order. Rule 11 requires a reservoir surveillance report including pressure data to be filed annually. Monthly filing and annual reporting essentially duplicate the data submittal and create additional work for both the operators and the Commission. The Commission has the wherewithal to request data at any time it is needed to do its work. The Commission has reviewed the applicable rules and finds that reducing the reporting frequency and method will not affect the work of the agency and will reduce paperwork. handling and reduce or eliminate duplication of data reporting for the operators. All information formerly reported will be submitted with the annual report. The operators have indicated that pressure data will be made available on an interim basis should the need arise between annual reports. Changing the reporting method and frequency will not inhibit the effort of the Commission to conduct oversight of reservoir performance of the Prudhoe Oil Pool. These changes will not cause waste. harm correlative rights or reduce ultimate recovery. Therefore. Rule 6(c). Conservation Order 341C is restated as follows: (c) Data from the surveys required in (a) and (b) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Data submitted shall include rate. pressure. time depths, temperature. and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test. an injection well pressure fall -off test. a multi rate test or an interference test are acceptable. Other quantitative methods may be administratively approved by the Commission. NE at nc ra . Alaska and dated June 22. 1999. / - Ca,,,,' g� Robert N. stenson. P.E. Camille Oechsli Chairman Commissioner AA341 C-O L DOC INDEX CONSERVATION ORDER NO. 341C 1) May 19, 1999 ARCO Alaska, Inc. requests for Administrative change to Conservation Order 341 C, Rule 6 Prudhoe Bay Oil Pool, Prudhoe Bay Field 2) September 7, 1999 Report to the AOGCC on PBU Pressure Management in Compliance with Conservation Order No. 341 C, Rule 12(d) 3) May 4, 2000 Presentation by PSI Team on Pressure Mitigation 4) August 7, 2001 Sign In Sheet 5) August 24, 2001 Report to the AOGCC on PBU Pressure Management in Compliance with Conservation Order No.341 C, Rule 12(d) Conservation Order No. 341C it 5 August 24, 2001 RECEIVE® AUG 2 8 2001 Alaska Oil & Gas Cons. Commission Anchorage Commissioners Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, #100 Anchorage, Alaska 99501-3539 Re: Report to the AOGCC on PBU Pressure Management in Compliance with Conservation Order No. 341 C, Rule 12(d) Dear Commissioners, by 0 BP Exploration (Alaska) Inc. PO Box 196612 900 E. Benson Boulevard Anchorage, Alaska 99519-6612 This letter is provided in accordance with Conservation Order No. 341 C, Rule 12(d). As Operator of the Prudhoe Bay Unit, BP has continued monitoring pressure trends at Prudhoe Bay. BP has also continued to evaluate options for mitigating the pressure decline and increasing liquid hydrocarbon recovery in the Prudhoe Bay field. Pressure decline continues with ongoing oil production and replacement of production voidage from the waterflood areas of Prudhoe Bay. The Pressure Studies Initiative (PSI) team has evaluated options to increase hydrocarbon recovery by mitigating pressure decline. In the past year, the team has progressed the gas cap water injection (GCWI) project to sanction, with startup expected to begin in the second quarter of 2002. Enclosed are slides from a presentation given to the Alaska Oil & Gas Conservation Commission on August 71h, 2001. These slides describe the GCWI project and work that has been done in the last year and outline the next steps. Sincerely, q �e r Randy Frazier Greater Prudhoe Bay Resouce Development Manager BP Exploration (Alaska), Inc. GCWI Project Proposal PBU/AOGCC Review August 7, 2001 a 41 v O 3 90 C^ 1 l =r 0C m �� CO CD N o m (n: 0 GCWI Project Proposal • Inject up to 650 mbd seawater into eastern gas cap area • 150-200 mmbl gross reserves • 2Q 2002 project startup Apex East Dock August 7, 2001 2 Outline • Context - Conservation Order 290 • B ackground - PSI Evaluation Technical Drivers - History and Summary of Key Reviews (1990 — 1999) • Outcome of Recent Technical Reviews &Unit Work (2000 - O 1) - Recommendations from AOGCC and Unit Reviews (Summer 00) - Review and conclusions of recent technical efforts (Sep 00 — May 01) • GCWI Project Proposal • State Approval Process - next steps August 7, 2001 3 Context • AOGCC Conservation Order 290 (February 21, 1992) - Rule 5 • Investigate options to mitigate pressure decline • Provide annual progress report to the Commission August 7, 2001 4 Background —PSI Evaluation Technical Drivers • Objective : Evaluate potential projects to mitigate pressure decline Bull Me a vn 3600 a L 3400 N 3200 L a 5 3000 :11 2600 1995 2005 2015 2025 2035 • decreasing vaporization efficiency (lower K values) • lower gravity drainage performance (viscosity increase, shrinkage) • decreasing waterflood performance (reservoir energy, throughput, shrinkage) • lower FOR efficiency (MI supply, throughput) August 7, 2001 5 Background —History of Key Reviews APPRAISE 01491 SELECT DSP I ■ DSP 1990-19921 1992-1994 • Scoped 13 PSI options • RMF Review 2/92 • Selected GCWI Option • Identified Project Risks • Tech. Review 3/94 DEFINE M te 1994 — 1997 1998-1999 2000-2001 • Selected East Dock Option • RMF Review 8/94 • Gas Reserves Impacts Estimated RMF Review 6/95 • FFCM Benefits Review Plano Review 11 /97 • Water Breakthrough Risks Evaluated • MF Water Breakthrough Risks Review 10/98 Technical Focus Areas •AOGCC Review 5/00 Unit Peer ,,Review 8/00 `Unit Work Shop 11/00 Internal Company Project Reviews 5/01 August 7, 2001 6 Background -Summary of Findings from Key Reviews 1990-1994 • Identified & Evaluated Several Potential PSI Options Gas Cap Water Injection (GCWI) Supplemental Hydrocarbon Gas Injection (SGI) Nitrogen Gas Injection r Flue Gas Injection Fuel Gas Options • Preferred PSI option identified (GCWI) r Significant unit effort initiated for detailed evaluation of GCWI Several project risks revealed August 7, 2001 7 Background -Summary of Findings from Key Reviews 1994 - 1999 • Estimates of recovery factors for various mechanisms in the FFCM validated through fine grid compositional modeling • Relationship between project timing and risks revealed • Preferred location for GCWI determined August 7, 2001 8 Background -Summary of Findings from Key Reviews Validation of Reservoir Benefits Predicted by FFCM - Completed mechanistic studies of GCWI using fully compositional 1 D, 2D, NGIX strip, and M 12 type pattern models, benefits consistent with FFCM Incremental Recovery to 2031: Change in Oil -in -Place Area Mechanistic Studies FFM2 Volume (MMSTB) Gas Cap -2 % to -4 % -3.4 % -20 Gravity Drainage 1.6 % 1.5 % 163 Gravity Drainage/Water Flood Interaction 1.6 % 1.2 % 37 Water Flood 0.8 % 0.3 % 24 EWE 0.5 % 4 Sag River 0.3 % 5 Total 0.9 % 213 ✓ The potential reserve add is approximately 150 to 200 MMB predicted by detailed mechanistic and FFCM runs. August 7, 2001 9 Background -Summary of Findings from Key Reviews ✓ East Dock identified as optimum location for GC WI • Reduces risks of water/gas interference problems • Better able to maintain target gas and water injection rates • Increases flexibility: phasing of well drilling & surveillance • Reduces capital costs 1 STP West Dock Staging Area $133MM AGI EAST NWGI NGt DOCK WG, W) $ 75 M M CGF Prudhoe GCP Bay OS 18 FS#2 IDS 11 IDS 5 DS 4 FW IMF1t2 IDS 2 ESIP August 7, 2001 10 Outcome of Recent Technical Reviews &Unit Work (2000 - Ol) • Recommendations from AOGCC &Unit Reviews (Summer 2000) ➢ What is the true risk of early water breakthrough (geologic sensitivity) ? ➢ What is the long-term impact on gas cap gas injection (potential FGO impacts) ? ➢ What is the long-term water inj ectivity in the gas cap ? ➢ What is the relationship between GCWI and a potential MGS ? ➢ What are sensible GCWI Surveillance Options/Programs ? • Unit work plan initiated in Aug 2000 to address these specific questions and define an optimized project scope for GCWI August 7, 2001 11 Early Water Breakthrough Risk Evaluation Saturation map after 14 yrs of GCWI, Layer 10 (Base of Zone 3) 0 1 -Jan-2015 DS4/1 I Upstructure C- r- r- Z August 7, 2001 12 Early Water Breakthrough Risk Evaluation • FFM reservoir description sensitivities to address risks of early water breakthrough permeability fairways vertical to horizontal permeability ratio r gas cap faults Tango shales open framework conglomerates • Mechanistic model studies with relative permeability sensitivities and high perm thief zone • Favorable mobility of water displacing gas significantly dampens effects of reservoir heterogeneities August 7, 2001 13 Early Water Breakthrough Risk Evaluation Effect of Mobility Ratio on Breakthrough Time 20 M 15 P ai GCWI E 10 s a� 0 w 5 Gas/Oil WF d ML W 0 0.01 0.1 1 10 100 1000 Mobility Ratio • Mobility ratio strongly influences breakthrough time • GCWI mobility ratio very favorable for stable displacement August 7, 2001 14 Early Water Breakthrough Risk Evaluation swr►w t%«M.a.+r.,.l T".<++Im+,w+�auao,+teaae.�i, Ta+�+rK ANK*y+my aa5o7 We+.-+rM aaat Water Saturation Map for High Perm Channel Sensitivity (40 Darcy) after 20 yrs GCWI(Base of Zone 3) -.��,��.1►��+ .ems ,,,r � , '4 11" O.00 P 10 0.20 0.30 O aO 0-5O 0.60 r O.7O r O ✓ Early water breakthrough is not an issue as the displacement is mobility dominated August 7, 2001 16 Impact on Gas Cap Gas Injection (FGO) • Gas injectivity reduction may occur due to higher pressure in gas cap & relative perm impacts in regions with water invasion ✓ Impact of GCWI on FGO is not significant 0 8000000 V 7500000 Base Case O 7000000 6500000 - GCW1 Case = 6000000 O 5500000 _ C� O 5000000 4500000 -- h CO 4000000 C7 2000.0 2005.0 2010.0 2015.0 2020.0 2025.0 2030.0 August 7, 2001 17 Early Water Breakthrough Risk Evaluation OR W R-X kw 9A[ Saturation map after 14 yrs of GCWI, Layer 10 (Base of Zone 3) 0 1 Jan-2015 DS4/11 Upstructurc August 7, 2001 18 Water Infectivity In Gas Cap • FFM used to model water inj ectivity & wellbore hydraulics ➢ Validated inj ectivity modeling with field data • Utilized permeability sensitivity studies to establish range of uncertainty in water inj ectivity ✓ Bottom hole locations for water injectors have been optimized by considering interaction with updip GD, FS2, and the gas injection area August 7, 2001 19 GCWI -Optimized Injector Location --is I? �00 0 Figure 13 -5967000 0 705- "0 U .1 ST2 0 4A phn• how ZO M 3 1.,. B nc 4. pork ZB 7 Proposed Location 4 6 "9"p0"0' Z.n * 2A W o Plnc hoot ZO no\'l Fidd UMN Pinc hoot 5979000, L'5 �2 LO-2,1 3976000 L I OY 2A LG 59 000 2 *1 B ST. I East Dock Pad L3' O 59 7000- L2 4 B 2 B 3 2 All - I A T�Olc ' `7 - ---. L =12 2 B 9 N L_OC L2 A ♦% 2A %* f r 4 B B 2 2 S 12A 6 900 70**000 t4j.000 73.4000 717 4B - Z o n e D rectly beneath LC U li-09A 4-20 04-24 4.25 August 7, 2001 20 Impacts with a Potential MGS • Water -free area in western part of gas cap and GD will be available to blowdown reservoir and recover gas in GCWI scenario • Gas remobilization saturation is low so impact on gas reserves is not an issue (could actually lead to increase gas recovery) + Supported by laboratory work and simulation • Increased reservoir energy off -sets pressure losses with a potential MGS ✓ GCWI is synergistic with a potential MGS August 7, 2001 21 Surveillance Plan • Inj ection Wells Integrity and Conformance - Surface Measurements: injection rate, temp, & press - Downhole Measurements: temp surveys & spinner logs • Water Movement - 4D Gravity Method - Cased Hole Logging including RST ✓ A comprehensive surveillance program has been developed for monitoring the GCWI project August 7, 2001 22 GCWI Facilities Scope • STP/SIP Upgrades • New S WI Line, F S 2 to East Dock • East Dock Injection Facility • 5-7 Injection Wells 1 STP West Dock Staging Area AGI EAST NWGI NGI DOCK WGI GGF Prudhoe GCP Bay DS 18 FS#2� „ DS 5 , DS 4 FSg1 IMFN2 DS 2 ESIP August 7, 2001 23 GCWI - Next Steps • Submit permit applications for Surface Facilities and Pipeline • Update AIO application information to include GCWI • Submit Plan of Development for 2002 to include GCWI • Construction to begin IQ 2002 August 7, 2001 24 .00#4 ALASKA OIL AND GAS CONSERVATION COMMISSION Date: < o/ MEETING — Subject NAME — AFFILIATION TELEPHONE (PLEASE PRINT) /j (!C - /2 �05 LA co t3 PX P� S7� �{ — L4L 9 �a�-�G.._ l-7 'k..✓r-ns Tc,�otJ3-476 k CO 11CO S6 �( _s J 263-390 cue_ Nec�S� � A06Oc-793-1)41 n �, Pressure Studies Initiative Team Prudhoe Bay Unit Pressure Mitigation Review May 4, 2000 Conservation Order No. 341 Rule 12 (d) Pressure Studies Initiative Team 5-04-00 Contents • B ackground Objective ➢ GCWI Project Pan View Recovery Processes ➢ Other Possible Projects 1977 Cross Section ➢ GCWI Project Technical Issues 1998 Cross Section ➢ Selected EDWI Option PSI Options ➢ GCWI Project Focused View • Review of 97-00 Technical Work on GCWI Reservoir Benefits Mechanisms Benefits Analysis & FFM Evaluation Water Breakthrough Risk Evaluation • PSI Project Progress • Current Workplans Impact on Gas Cap Gas Injection Water Injectivity in the Gas Cap Major Gas Sales Impacts Pressure Studies Initiative Team 5-04-00 2 Background -Objective • PSI Team Objective :Evaluate all potentially viable projects to mitigate the pressure decline and increase the ultimate recovery of the field. 4,500 4,000 a 3,500 3,000 W W E a 2,500 .h 0 r'r 2,000 d a 1,500 1,000 500 0 19"75 1980 1985 1990 1995 2000 2005 2010 Pressure Studies Initiative Team 5-04-00 3 Background -Recovery Processes Waterflood Miscible Gas Displacement Gas Cap Expansion / Gravity Gas Cycling 50' Light Oil Column Pressure Studies Initiative Team 5-04-00 4 Background - 1977 Cross Section of Prudhoe Bay Gas Cap Pressure Studies Initiative Team 5-04-00 Background - 1998 Cross Section of Prudhoe Bay MI, Water Producers Gas Injectors Injectors 0 0 flma A 1 aVV Waterflood Gravity Drainage Gas Cap —I /FOR Pressure Studies Initiative Team 5-04-00 6 Background -PSI Options • PSI Identified & Screened Several Potential Options Gas Cap Water Injection (GCWI) Supplemental Hydrocarbon Gas Injection (SGI) Nitrogen Gas Injection �+�°� c 91" 5�-#y Flue Gas Injection Fuel Gas Options . Gas Cap Water Injection selected for further evaluation Pressure Studies Initiative Team 5-04-00 7 Background - GCWI Project Pan View • • The supplemental water injection rate required to maintain reservoir pressure at the current voidage rate is - 650,000 BWPs Continue all existing depletion mechanisms, but at higher reservoir pressure .� P L e- N Pressure Studies Initiative Team 5-04-00 8 Background -Other Possible Projects Apex �i* • + a 4�+ . Q VROM Potential of 47 SWIPE Zone 4 Injectors E L5 PSI i a I FS2 Updip Victor Pressure Studies Initiative Team 5-04-00 9 Background -Other Possible Projects • Major GCWI would result in significantly larger cumulative injected water volumes and pressure benefits than other projects m 5000 - 4500 - c 4000 - 3500 - L 3000 - 2500 - 2000 - 1500 - aD 1000 - 500 - 0 U Cumulative Injected (Stored) Water Volume for Projects with Pressure Benefits n. ,10 ,F k 1 2,375---- -�I, - --- -------- --------------`----- ---- 365 375 --------------------------- -- rti , 1BO 1 OOF �Mrw j� 20 yr 10 yr L5 PSI SWIPE— EWE W F FS2 Updip GCWI GCWI Victor Pressure Studies Initiative Team 5-04-00 10 Background - GCWI Project Technical Issues • Select GCWI location • Understand and evaluate reservoir benefits mechanisms risks of early water breakthrough impact on gas cap gas injection « �r water injectivity issues major gas sales impact . Develop benefits prediction methodology Pressure Studies Initiative Team 5-04-00 11 Background -Selected EDWI Option • Determined that East Dock is the preferred location — Reduces capital costs — Reduces risks of water/gas interference problems — Better able to maintain target gas and water injection rates — Increases flexibility: phasing of well drilling & surveillance • Supply seawater from FS-2 to East Dock, drill 10 injectors • Est. capex: $75 million STP r West Doric $ 133 MM AGI EAST [SOCK NWGI.�� 3 $75MM CGF WOI" o ` Prudhoe CCP n ay DS 18 FS#2 D811 5 �= 1 DS 8�,,,y+- IMRZ D6 • 1 FS#1 ems_ ES1..,: Pressure Studies Initiative Team 5-04-00 12 672000 676000 680000 684000 688000 _ 69zoo0 __*"eVII' Background - GCWI Apex G I Am1A4009A&M3 Focused View AdW7 1 A1441AIM4 ��r.� \`� �� Aao�w►os 1 ■ r Noel NC*l0 \ ■ ` Gm 9 NCP14J %Agfos K �2 'ACW 1 V 1 N aM 4 L1�S�_ M • �, s %A 6 y l a N ^`�^� N TA 5 ti� t7 N;12 NO]i02 1 70400�-��__?080oa 712000 716000 ~ Lf 5954000 k5 e 5980000' GCWI Injection Area L3�21 ■ 4 L Gr1-0 ■ i 15�>t r • 44, 141 i ■ ■: ■ � 5 2000' 1541A n42� � 97 = - r East 58000' 15 s 15% Iva , � ,.. 1a,� Dock . - �sr6 s • � his-� � ■ 'i 15�1 13 i71S� 1 01s 18 A ■ t2-1}_ ■ r / +i 1sRa 13-0.31 15A 1! Sg 15-&9A ,1 �5 �(jr f 1■8 i 18 AQ 1l 4C6 50' NLOC F ' 15 �'ys A 15 9 i ■-- J[�" D [J Y 1 1 1 S�a7� ■ 0411 ■ ■ t. �■ 1 S ■ L _ 2--m-FIC 13.-9VA Q 11 SA 1 A o00, A1 t 2M3 SA t tam 18-t96 ` L2 SA 17f YFA�__ �I !,4p 04fi0 FO 1 GN 7 0 18 �4AL2 1S A A 11 IIV.■� 11i10 4 V 0 0 W3 15 �yA 13:iJt-tM 18�9 1 8 4 i 0 ■.� ' 0 11� 2 1� S 4� s 0 02-�7A 18i2A yyyyyy �A1 a A 42-i, _ 11-HA 11�6 11r! lima 04-MA 04■7 0d■95 �600 l 0-I1A s0 -FdA �+ i t 1a 05� 6• 11 A c ■i 07 O11 4 1., 0 -116A I + 0 `,,, , cn. 05 S r 11�4 id5 it■6 DS-'-0 �!A t ti ° 1u' f5- 3 B u _ �T 7Ug00cp740'i, 676000 &6 9JQ ya684MQ D1�a`'�'88•$�O�i3OR 02 2600 696000 W4, 00 08 004-0A 712000 716000 Pressure Studies Initiative Team 5-04-00 13 Review of 97-00 Technical Work on GCWI • Benefits analyses & FFM evaluation . Early water breakthrough risk evaluation • Impact on gas cap gas injection . Water infectivity in the gas cap . Major gas sales impact Pressure Studies Initiative Team 5-04-00 14 Reservoir Benefits Mechanisms • Black -Oil Considerations Reduced oil shrinkage (Bo effects) ma's tt Q r...4 5V t' r Increased reservoir energy Increased throughput in VWF areas Improved drainage and coning behavior in GD regions • Compositional Increased lean as vaporization efficient & condensate recover g p Y Y Improved lean gas sweep of GD residual oil, particularly in downdip GD regions Increased MI supply (leaner MI composition) Sa �IAJ �) 7�> Pressure Studies Initiative Team 5-04-00 /p7, w 25; f 1207 s&"Ps� t) 15 97-99 Work - FFM Benefits Analyses • Completed mechanistic studies of GCWI using fully compositional ID, 2D, NGIX strip, and M 12 type pattern models. • Conclusion: FFM benefits are consistent with mechanistic studies. Incremental Recovery to 2031: Change in Oil-in-Place's�v Area Mechanistic Studies FFM2 Volume (MMSTB) Gas Cap -2 % to -4 % -3.4 % -20 Gravity Drainage 1.6 % 1.5 % 163 Gravity Drainage/Water Flood Interaction 1.6 % 1.2 % 37 Water Flood 0.8 % 0.3 % 24 EWE 0.5 % 4 Sag River 0.3 % 5 Total 0.9 % 213 • The potential prize is approximately 150 to 200 MMSTB. vq'" 'elf �' " �" Pressure Studies Initiative Team 5-04-00 ( vr � <-z --7 ) 16 97-99 Work - Water Breakthrough Risk Evaluation PH 650 �w �3 Pressure Studies Initiative Team 5-04-00 17 97-99 Work -Water Breakthrough Risk Evaluation • FFM reservoir description sensitivities to address risks of early water breakthrough s permeability fairways vertical to horizontal permeability ratio gas cap faults Tango shales Jwq open framework conglomerates (GU k-� q-3-12) loos J • Mechanistic model studies with relative permeability sensitivities and high perm thief zone - • Favorable mobility of water displacing gas significantly dampens effects of reservoir heterogeneities Pressure Studies Initiative Team 5-04-00 18 . 1, - I . 11 97-99 Work -Water Breakthrough Risk Evaluation 30'r 4w 1 r—r- I -JAN-21W. 1564t r,t T—S *,N' as A� t4 C, DO , -1—U1 I axw Water Saturation Map -n Channel -0 Darcy) 7.one 3) —1 111,11 tilt] I I I k:14, le r t"l, I 1'0'i - I till $I Iffitt III# I 000 0. 2 0.1111.1 0. .41 111 0 -'� 0 0, 60 0.70 ry8() 1.90 100 Pressure Studies Initiative Team 5-04-00 20 97-00 Work - Impact on Gas Cap Gas Injection oAJ g6t"C7 Gas inj ectivity reduction occurs due to higher pressure in gas cap & relative perm impacts in regions with water invasion ; .P 2 � 's • Mechanistic refined grid studies to evaluate FFM2 for gas inj ectivity calculations • Run FFM2 in conjunction with Facility Model (iterative) to determine FO impacts A py- t CA-PdP4 A.,--W /�p 5� .. ', (�,, �f - (�&� :::Q 4--cl- (-a--t & -� 1`4 ' ( - Pressure Studies Initiative Team 5-04-00 21 " / �k 97-00 Work - Water Infectivity in the Gas Cap • Obj ective is to determine number and location of water injection wells Water infectivity study process FFM used to model water injectivity & wellbore hydraulics Validate injectivity modeling with field data Utilize permeability sensitivity studies to establish range of uncertainty in water infectivity OA* ,AP, .. cz� • Optimize selection of bottomhole locations for water injectors wi ��¢ CIRc�'�� J r� 1 _1 Pressure Studies Initiative Team 5-04-00 22 97-00 Work - Major Gas Sales Impacts . Began evaluation of impact of GCWI on gas recovery and operating costs during MGS Potential positive impact on gas recovery if GCWI does not impede gas movement in gas cap Potential negative impact on gas recovery if gas is trapped and re -mobilized at a higher saturation Incremental Water Production Costs Pressure Studies Initiative Team 5-04-00 23 PSI Project Progress ,. Identify & screen potential options v Select GCWI location Understand and evaluate reservoir benefits mechanisms risks of early water breakthrough -► impact on gas cap gas injection water infectivity issues major gas sales impact -. Develop benefits prediction methodology Pressure Studies Initiative Team 5-04-00 24 I' , Current Workplans • Complete gas infectivity study • Complete water infectivity work • Complete major gas sales impact work • Finalize benefits estimate � Peer review of technical work�Q/� . Next Steps resolution of technical issues from peer review finalize project scope define surveillance plan economics decision Jro' ect 1 0 1 p Q ) Pressure Studies Initiative Team 5-04-00 25 A A r 0404 C H H (01) i3) 0. s/v/2aw-D .4 M PPS- ce�.... �� r _ � � 'o...-- -4e . 2 0 017-� 0 L NZ m • 7 % a BP EXPLORATION September 7, 1999 Mr. Robert N. Christenson, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 ARCO Alaska, Inc. ""'ECHVED SET G 9 199,r „aska OR & Gas Grjo ,. Gon dollon Anchorw Re: Report to the AOGCC on PBU Pressure Management in Compliance with Conservation Order No. 341C, Rule 12(d}-, Dear Mr. Christenson, This letter is provided in accordance with Conservation Order No. 341C, Rule 12(d). The operators of the Prudhoe Bay Unit have continued monitoring pressure trends at Prudhoe Bay. The operators have also continued to evaluate options for mitigating the pressure decline and increasing liquid hydrocarbon recovery in the Prudhoe Bay field. Pressure decline continues with ongoing oil production and replacement of production voidage from the waterflood areas of Prudhoe Bay. See Figure 1 (attached) for a plot of the historical reservoir pressure and the forecast range of future reservoir pressures. No unusual trends in the pressure decline have been observed to date. i The Pressure Studies Initiative (PSI) team is evaluating gas cap water injection (GCWI) and supplemental gas injection (SGI) to increase hydrocarbon recovery by mitigating pressure decline. In the past year, the PSI team has focused on evaluation of GCWI. Examination of issues related to early water breakthrough has been completed, while work associated with other issues including water injectivity and gas injection interference is ongoing. This work is expected to be completed within the next report period. The PSI team is using full field models to evaluate GCWI. Results from earlier mechanistic studies have been compared to the full field models, with data from the lean gas surveillance program used to calibrate the full field models. Co -Operators, Prudhoe Bay Unit BP Exploration (Alaska) Inc. ARCO Alaska, Inc. Post Office Box 196612 Post Office Box 100360 Anchorage, Alaska 99519-6612 Anchorage, Alaska 99510-0360 Telephone (907) 561-5111 Telephone (907) 276-1215 Report to the AOGCC on PBU Pressure Management in Compliance with Conservation Order No. 341A, Rule 12(d) Page 2 During the first half of 1999 the Operators obtained gas samples from over 200 key wells as part of the lean gas surveillance program. Efforts to improve the surveillance of lean gas and its calibration with the full field models are expected to continue. Results of this work will be interpreted with other reservoir surveillance data to improve future reservoir management of the Prudhoe Bay field. Sincerely, Joe Hurliman Manager CNS Development Management BP Exploration (Alaska), Inc. lf- Darrel 4Bose Manager Prudhoe Bay Resource Development ARCO Alaska, Inc. Report to the AOGCC on PBU Pressure Management in Compliance with Conservation Order No. 341A, Rule 12(d) Page 3 4,500 3,500 Q a 0 3,000 3 d! N a` 2,500 0 m 2,000 U) 1,500 a m Q 1,000 500 0 4- 1975 Figure 1 HIStoricd and Forecast Nt3u IPAAveracteKeservoir rressure His toriod F ore= t 1980 1985 1990 1995 2000 2005 2010 ir 1 May 19, 1999 Mr. Robert Christenson, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Road Anchorage, Alaska 99501 ORIGINAL Re: Request for Administrative Change to Conservation Order 341C, Rule 6 Prudhoe oil Pool, Prudhoe Bay Field As operators of the Prudhoe Bay Unit, ARCO Alaska, Inc. and BP Exploration, Inc., request an administrative change to Conservation Order 341C, Rule 6 to modify the frequency and method of filing of data from reservoir pressure surveys. Conservation Order 341C, Rule 6(c) specifies that the reservoir pressure data acquired on new wells (Rule 6a), to satisfy the approved annual pressure surveillance plan (Rule 6b) and from any special reservoir pressure monitoring (Rule 6d) be filed with the Commission by the last day of the month following the month in which each survey is taken using Form 10-412. Rule 1 l a requires an Annual Prudhoe Oil Pool Surveillance Report which includes an analysis of reservoir pressure surveys within the field. (Attachment 1 contains the full text of these rules.) We request Rule 6(c) be administratively changed under the waiver provisions of Rule 6(e) to allow pressure data to be tabulated and submitted with the annual surveillance report rather than filed monthly on Form 10-412. This change would eliminate what is in essence duplicate reporting. In addition, in most areas of the field, the pressure decline is on a steady, predictable trend. Should the Commission at any time require a tabulation of recent pressure data, it will be provided. For clarity, Attachment 2 contains the proposed verbiage for these changes. If you require additional information, please contact Mike Bill at 263-4254 or Randy Frazier at 564-4556. Sinc , Darrel Bose Manager, Prudhoe Bay Resource Development ARCO Alaska, Inc. Bruce Luberski 1(` Manager, PBU Resource Management BP Exploration (Alaska) RECEIVED JUN - 41999 Alaska 011 &�GaCOMWa'or, e Mr. Robert Christenson May 19, 1999 Page 2 Distribution M. L. Bill - ATO 1530 J. L.. Cawvey - ATO 1626 S. Harvey - ATO 1570 R. M. Lemon - ATO 1520 K. W. Lynch - ATO 1150 G. Pospisil - ATO 1420 E. M. Oba - ATO 1526 P. Richmond - ATO 1676 M. P. Worcester - ATO 2020 Attachment 1: CURRENT Sections of Conservation Order 341C Rule 6: Pressure Surveys (a) Prior to regular production, a static bottom hole or transient pressure survey shall be taken on at least one in three wells drilled from a common drilling site. (b) An annual pressure surveillance plan shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1, each year. The plan will contain the number of pressure surveys anticipated for the next calendar year and be subject to approval by the Commission by May 1. These surveys are needed to effectively monitor reservoir pressure in the Prudhoe Oil Pool. The surveys required in (a) of this rule may be used to fulfill the minimum requirements. (c) Data from the surveys required in (a) and (b) of this rule shall be filed with the commission by the last day of the month following the month in which each survey is taken. Form 10- 412, Reservoir Pressure Report, shall be used to report the data from these surveys. Data submitted shall include rate, pressure, time, depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall -off test, a multi rate test or an interference test are acceptable. Other quantitative methods may be administratively approved by the Commission. (d) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (c) of this rule. (e) By administrative approval the Commission may grant time extensions and waive requirements of this rule, and by administrative order, the Commission may require additional pressure surveys in (b) of this rule. Rule 11: Annual Surveillance Reporting (a) An annual Prudhoe Oil Pool surveillance report will be required by April 1 of each year. The report shall include but is not limited to the following: 1) Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. 2) Voidage balance by month of produced fluids, oil, water, and gas, and injected fluids, gas, water, low molecular weight hydrocarbons, and any other injected substances (which can be filed in lieu of monthly Forms 10-413 for each FOR project). 3) Analysis of reservoir pressure surveys within the field. 4) Results and where appropriate, analysis of production logging surveys, tracer surveys and observation well surveys. 5) Results of gas movement and gas -oil contact surveillance efforts including a summary of wells surveyed and analysis of gas movement within the reservoir. The analysis shall include map(s) and tables showing the locations of various documented gas movement mechanisms as appropriate. (b) Upon its own motion or upon written request, the Commission may administratively amend this rule so long as the change does not promote waste nor jeopardize correlative rights and is based on sound engineering principles. Attachment 2: PROPOSED CHANGE to Conservation Order 341C, Rule 6 (Text to be added is Underlined in Bold, Text to be deleted is in Strtkethr-atigh) Rule 6: Pressure Surveys (a) Prior to regular production, a static bottom hole or transient pressure survey shall be taken on at least one in three wells drilled from a common drilling site. (b) An annual pressure surveillance plan shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1, each year. The plan will contain the number of pressure surveys anticipated for the next calendar year and be subject to approval by the Commission by May 1. These surveys are needed to effectively monitor reservoir pressure in the Prudhoe Oil Pool. The surveys required in (a) of this rule may be used to fulfill the minimum requirements. (c) Data from the surveys required in (a) and (b) of this rule shall be filed • ith the 412, ReseFveir- Pressure Repeft, shall be used to r-epet4 the data ffem these . submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1, each year. Data submitted shall include rate, pressure, time, depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall -off test, a multi rate test or an interference test are acceptable. Other quantitative methods may be administratively approved by the Commission. (d) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (c) of this rule. (e) By administrative approval the Commission may grant time extensions and waive requirements of this rule, and by administrative order, the Commission may require additional pressure surveys in (b) of this rule. kECEIVED U N ` 4 1999 Ajaska Oil &AassCC missior