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Home My WebLink AboutCO 645• 0 INDEX CONSERVATION ORDER NO. 645 OOOGURUK FIELD OOOGURUK UNIT OOOGURUK-TOROK OIL POOL 1. February 22, 2011 Pioneer Natural Resources Alaska, Inc.'s (Pioneer) application for Pool Rules — Oooguruk-Torok Oil Pool, North Slope, AK (additional confidential information held in secure storage) 2. March 1, 2011 Notice of Public Hearing; Affidavits of Publication, email distribution, and mailings 3. April 26, 2011 Public Hearing Transcript 4. December 14, 2012 Letter from Pioneer to AOGCC regarding Multiphase Flow Meter Application (Micro Motion Coriolis Meter Application) 5. February 20, 2013 Email from Pioneer to AOGCC regarding amended Micro Motion Coriolis Meter Application letter dated December 14, 2012 6. February 20, 2013 Pioneer's amended Micro Motion Coriolis Meter Application (CO 645.001) 7. July 22, 2013 CPAI's letter to Pioneer regarding Gas Metering Maintenance Procedures INDEX CONSERVATION ORDER NO. 645 OOOGURUK FIELD OOOGURUK UNIT OOOGURUK-TOROK OIL POOL CONFIDENTIAL INFORMATION LOCATED IN SECURE STORAGE • • 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Pioneer Natural ) Docket CO -11 -01 Resources Alaska, Inc. for an order for ) Conservation Order No. 645 classification of a new oil pool and to ) prescribe pool rules for development of the ) Oooguruk -Torok Oil Pool within the ) Oooguruk Field Oooguruk Field, Oooguruk Unit, East ) Harrison Bay, Beaufort Sea, Alaska ) Oooguruk Unit ) Oooguruk -Torok Oil Pool May 26, 2011 NOTICE CLOSING DOCKET BY THE COMMISSION: The Commission has the closed the Docket in the above captioned matter. ENTERED AND EFFECTIVE at Anchorage, Alaska and this 26th day of May, 2011. BY DIRECTION OF THE COMMISSION i (48 li. J / Joy, . Colombie Sp al Assistant to the Commission • a STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Pioneer Natural ) Docket CO -11 -01 Resources Alaska, Inc. for an order for ) Conservation Order No. 645 classification of a new oil pool and to ) prescribe pool rules for development of the ) Oooguruk Field Oooguruk -Torok Oil Pool within the ) Oooguruk Unit Oooguruk Field, Oooguruk Unit, East ) Oooguruk -Torok Oil Pool Harrison Bay, Beaufort Sea, Alaska ) ) May 26, 2011 IT APPEARING THAT: 1. By application received February 22, 2011, Pioneer Natural Resources Alaska, Inc. (Pioneer), as operator of the Oooguruk Unit (OU) and on behalf of Pioneer and Eni Petroleum US LLC (Eni), working interest owners, requested an order defining a new oil pool, the Oooguruk -Torok Oil Pool (OTOP), within the OU and prescribing rules governing the development and operation of that pool. 2. A notice of a public hearing was published March 13, 2011 in the ALASKA JOURNAL OF COMMERCE, on the State of Alaska's Online Public Notice Web site, and on the Commission's Internet website. 3. The Commission convened a public hearing on the pool rules application on April 21, 2011. The public hearing was continued until April 26, 2011. 4. On April 26, 2011, testimony was received from the applicant, and the record was closed. No protests or comments were received regarding the application. FINDINGS: 1. Operator: Pioneer is the operator of the leases in the Affected Area, which is defined below. 2. Affected Area: As currently mapped, the Affected Area lies offshore in the Beaufort Sea and onshore in the Colville River Delta, within and outside of the existing OU (see Figure 1, below). The OTOP will be developed initially from the existing offshore Oooguruk Drill Site (ODS), which connects to the onshore Oooguruk Tie -in Pad (OTP), and then to the Kuparuk River Unit (KRU) processing facilities. Upon successful development of the proposed pool from the ODS, additional development may occur from a new onshore drill site located on the eastern side of the Colville River Delta. • • Conservation Order No. 645 Page 2 May 26, 2011 / TUVAAQ ST 1 - -f T 14N, RO7E � T 14N, RO8E HGUI 1 /.,? eaufo KALU 3 \ — Y 000GURUK 1 GLIKTOC PGIfdT I • .lea -- q IVK +' ODS '- COLVIL TI LUBIK 1 E H RISON BAY ST 1 r ( r /`�KALUBI COLVILLE D -LTA 1 Y NATCHIQ 1 0 IKTOK PT 1 r . COLVILLE 0 2 y { COLVILLE C L 4i4t d ti KUUKPIK 3 / Oooguruk Unit COLVILL 1 LTA 2 ; T 13N, RO7E T 13N, RO8E W SAK 25`, 23 16 ti • COLVILLEDELTA3 - , � 1 11 I ': � 0•0040 � KALU -c')- • PALM 1 Torok Poo1 . N T 12N, ROSE T 12N, RO8E 1 1 1 ■ t i l, 4 Miles COL 1 �. r . Figure 1. Affected Area for the Proposed Oooguruk -Torok Oil Pool (enclosed by gold - colored line) 3. Owners and Landowners: The planned development area is the portion of the proposed OTOP that lies in the gold- bordered polygon within T13N, RO7E, UM, as shown on Figure 1. All lands within the planned development area are leased from the State of Alaska, Department of Natural Resources and lie within the OU. There are two working interest owners in the planned development area: Pioneer (70 %) and Eni (30 %). 4. Exploration and Delineation History: In 1965, the Torok sandstone was first penetrated by the Sinclair Oil and Gas Colville No. 1 exploratory well in Section 25, T12N, RO7E, UM (located along the southern border of Figure 1, above). In 1985 and 1986, Texaco Inc. drilled and tested the Colville Delta No. 2 and No. 3 exploratory wells, but these wells achieved only very low flow rates from the Torok (less than 3 barrels per hour). 1 This map is provided by Pioneer for illustration purposes only. Refer to the legal description for the precise representation of the Affected Area of the proposed Oooguruk -Torok Oil Pool. Conservation Order No. • 645 Page 3 May 26, 2011 Correlates Depth Resis Porosity GR <MD ResD(RILD) RHOB -10 API 24 ].2 OHMM 200 .65 GM/CC 2.65 T [r_ _,> ResM(RILM) and - Silt - Shale OHMM 200 ow Poro 0.2 SP TVD ResS(RFOC) NPOR -100 MV 100 0.2 OHMM 200.0 0 Measured <MD DTCP(DT) Depth 1 \ 70 USFT 701 / , 4800 Asoa } 4900 0900 t .c------ C f -4900 �—_ i 5000 5000 F -5000 Oooguruk- 5100 5100 Torok 1 -5100 -- Oil Pool \ L 5200 = ^ on -5200 ter .. S 5300 _,,JI, i -5300 -f 5400 5 -3 G`-- _ 4 5aU1_, e"." -,---,- i y 5500 1 -550() _ -__ j i Figure 2. Kalubik No. 1— Type Well Log for Oooguruk -Torok Oil Pool 2 F 2 is for illustration purposes only. Refer to the well log measurements recorded in exploratory well Kalubik No. 1 for the precise representation of the proposed Oooguruk -Torok Oil Pool. The horizontal grid lines in this figure represent increments of ten feet measured depth. The acronym TVDSS refers to true vertical depth subsea (true vertical depth below sea level). Conservation Order No. 645 • • Page 4 May 26, 2011 Subsequent fracture stimulation of the lower portion of the Torok in Colville Delta No. 3 using diesel, gelled diesel, and Ottawa sand resulted in an average flow rate of 240 barrels of per day of crude oil and diesel mixture during two flow periods that totaled 84 hours. The gravity of the final oil sample measured 24.6° API. During 1998, a Modular Dynamics Tester (MDT) sample recovered from ARCO's Kalubik No.2 exploratory well yielded crude oil measuring 19.8° API gravity. In March 2010, Pioneer fracture- stimulated the 3,800 foot - long, horizontal, Oooguruk -Torok production interval within well ODST -45A and began regular production. As of March 1, 2011, ODST -45A had produced 167,681 barrels of oil over 328 days (an average rate of 511 barrels of oil per day). To date, 18 wells have penetrated the Oooguruk -Torok reservoir from the ODS. Information from these wells, nearby exploratory wells, and two overlapping, three - dimensional seismic surveys was used to determine the geologic structure and reservoir distribution for the proposed OTOP. Production test data, core data, and well log data were used to establish the reservoir and fluid properties for the OTOP. A three -well pilot program, involving ODST -45A and two other horizontal wells, is planned to further refine the estimates of those properties. 5. Pool Identification: The proposed OTOP is the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 4,991 and 5,272 feet on the resistivity well log recorded in exploratory well Kalubik No. 1. (See Figure 2, above.) 6. Geology: a. Stratigraphy: Within the OU, early Cretaceous -aged reservoir sandstones comprising the proposed OTOP are typically very fine sand -sized to coarse silt -sized and rich in quartz (20% to 50 %), feldspar (15% to 25 %), and clay (5% to 40 %), with metamorphic rock fragments and minor amounts of carbonate. These sandstones are sheet -like in form, and were deposited in a lower slope -to -basin floor environment. Within the proposed development area, the reservoir interval is 200 to 250 feet thick, but thins to the east, toward the paleo- basin, and pinches out to the west against the paleo -shelf slope. Net - to -gross sand thickness is typically 45% to 50 %. Porosity ranges from 12% to 26 %, averaging 19 %. Permeability ranges from 0.1 to 100 millidarcies and averages 4 millidarcies. Water saturation estimates for the reservoir sandstones range from 40% to 55 %, with an average of about 50 %. b. Structure: Within the development area, the structure of the proposed OTOP forms broad, east - plunging anticlinal nose cut by several, northwest- and north- trending, normal faults with vertical displacements ranging up to 40 feet. The top of the OTOP lies between about -4,800 feet TVDSS and -5,500 feet TVDSS. 3 Alaska Oil and Gas Conservation Commission Well History File 185 -211: flow rates estimated based on informa- tion presented on page 25. 4 To avoid confusion, when depths presented represent true vertical depth subsea, the footage will be preceded by a minus sign and followed by the acronym TVDSS (e.g., 3,000 feet true vertical subsea will be depicted as -3,000 feet TVDSS). Conservation Order No. 645 1110 • Page 5 May 26, 2011 c. Faults: The vertical displacement of faults observed within the Torok interval ranges up to 40 feet. Because of the thinly bedded nature of this reservoir, some faults may act as barriers. d. Trap Configuration and Seals: Well log and seismic information indicate that the OTOP accumulation is trapped by both structural and stratigraphic elements. The OTOP sandstones thin toward the west, and pinch out as they lap onto the toe of the paleo- slope. To the south and southwest, the depositional limit of the fan defines the pool boundary. To the north and east, structural dip, diminishing sand content in the sediments, and a southeast - trending, down -to- the -east fault appear to define the northeastern limit of the oil accumulation. The top seal for the OTOP is formed by more than 1,000 true vertical feet of shale and siltstone assigned to the undifferentiated Seabee Formation / Hue Shale. e. Reservoir Compartmentalization: At present, limited well test results suggest the reservoir sands are laterally continuous at the scale of the spacing of the planned development wells (1,000 to 2,000 feet apart). f. Permafrost Base: The base of permafrost is interpreted to lie between about -1,400 and -1,600 feet TVDSS. 7. Reservoir Fluid Contacts: The Colville Delta No. 3 exploratory well tested oil down to -5,150 feet TVDSS; the OTOP outline is based on this depth. The highest known water for the pool is established by MDT measurements in the Ivik No. 1 exploratory well at -5,212 feet TVDSS. 8. Reservoir Fluid Properties: The API gravity of Torok oil measures 24 °, and viscosity ranges from about 2 to 4 centipoise. The solution gas -oil ratio (GOR) is estimated to be 250 to 550 standard cubic feet per stock tank barrel, and the bubble point pressure is estimated between 1,000 psig to 2,200 psig. Initial reservoir pressure is 2,250 psi at a depth of -5,000 feet TVDSS. Reservoir temperature is about 135° F. The oil formation volume factor is estimated from 1.15 to 1.30 reservoir barrels per stock tank barrel of oil, and the gas formation volume factor is estimated at 1.234 reservoir barrels per thousand standard cubic feet of gas. Free gas has not been encountered with the Torok interval. 9. In -Place and Recoverable Oil Volumes and Production Rates: Hydrocarbon Resource Estimated Volume (MMSTB) ODS & Core Area Prospective Area Original Oil in Place (OOIP) 340 690 Primary Recovery (5% OOIP) 17 35 Primary + Waterflood (a total of 20% of OOIP) 68 138 5 Reservoir and reservoir fluid properties are based on samples and measurements collected from well ODST -45A. At present, this well utilizes gas for artificial lift, so the initial GOR of the reservoir is not known at this time. The ranges for associated oil properties are based on PVT studies conducted by Intertek for Pioneer. 6 The acronym MMSTB signifies millions of stock tank barrels. The "ODS and Core Area" is the planned initial development area where the Oooguruk -Torok reservoir is completely filled with oil. The "Prospective Area" is the planned future expansion area where the Oooguruk -Torok reservoir appears to be only partially filled with oil (i.e., the down - structure portions of the reservoir above the oil -water contact that are filled with oil overlying water). Conservation Order No. 645 • Page 6 May 26, 2011 Regular production of Torok oil began in March 2010 from well ODST -45A. The production rate for the OTOP over the project life of 20 to 30 years is expected to average about 4,000 to 9,000 barrels of oil per day (BOPD), with a peak production rate of about 8,000 to 15,000 BOPD and 2 to 8 million cubic feet of gas per day early in the project life. 10. Reservoir Development Drilling Plan: Pioneer currently plans to develop the OTOP in discrete phases using about 25 horizontal production and injection wells. Most wells will trend northwest, parallel with the major mapped normal faults that cut the reservoir and the direction of principal stress. The horizontal sections of these wells will range in length from 5,000 to 8,000 feet within the reservoir, be spaced about 1,500 feet apart, and be arranged end -to -end, forming alternating rows of producers and injectors in a line -drive flood pattern. All producers and injectors will be fracture stimulated. 11. Reservoir Management: Pioneer proposes to develop the OTOP as a water- and water - alternating -gas- injection enhanced oil recovery project. Production and injection voidage will be balanced to maintain reservoir pressure at or near the original measured pressure. Injection water will consist of produced water and water derived from the underlying Ivishak Formation. 12. Reservoir Surveillance Plans: Pioneer proposes to meet bottom -hole pressure survey requirements by obtaining stabilized, static pressure measurements at bottom -hole or by extrapolating from surface pressure fall -off measurements, pressure buildup measurements, multi -rate test results, drill -stem test results, formation test results, or other appropriate pressure transient or static test results. Pioneer proposes to meet the annual bottom -hole pressure measurement requirement by conducting one bottom -hole pressure survey annually within the OTOP. Pressures will be referenced to a datum of -5,000 feet TVDSS. Pioneer proposes to report the data and results from the pressure surveys annually. 13. Wellbore Construction: Pioneer proposes that the surface casing of wells drilled in the Oooguruk -Torok Oil Pool be set at approximately -3,000 feet TVDSS and cemented to surface. Intermediate casing will be set and cemented with the shoe just above, or just into, the target formation. Leak -off or formation integrity tests will be conducted, and significant hydrocarbon zones in the boreholes outside of the reservoir intervals will be isolated in conformance with Commission regulations. The proposed OTOP will be developed using horizontal wells with solid liners including pre - perforated pups and /or sliding sleeves and external swell packers to facilitate staged hydraulic fracture stimulation treatments for producers and injection conformance for injectors. Production wells will be equipped with Electric Submersible Pumps (ESPs) and 2 -7/8 -inch tubing, and injection wells will be completed with 3 -1/2 -inch to 4 -inch tubing. Pioneer proposes that, within the OTOP, subsurface safety valves (SSSV) be addressed well -by -well, either through the permit to drill or, if the well is already drilled, through an Administrative Action Rule. Conservation Order No. 645 • Page 7 May 26, 2011 14. Waivers: Pioneer requested the following waivers: a. Well Spacing: Pioneer proposes to waive the spacing restrictions of 20 AAC 25.055 to accommodate horizontal, line -drive wells and maximize ultimate recovery and proposes that, without notification, development wells may not be completed closer than 500 feet to an external boundary where working interest ownership changes. b. Directional Wellbore Plans: Pioneer proposes to provide a plan view well plat, vertical section diagram, close approach data and description of the proposed directional program in lieu of the requirements of 20 AAC 25.050(b). c. Petrophysical Logging: A complete petrophysical log suite acceptable to the Commission is required from below the conductor to total depth of the well for at least one well drilled from the onshore development in lieu of the requirements of 20 AAC 25.071(a). d. Gas -Oil Ratio Limits: Pioneer seeks an exemption from the GOR limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b)(1)apply. 15. Sustained Casing Pressure: Pioneer proposes to conduct and document a pressure test of tubulars and completion equipment in each development well at installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure or threat to human safety. 16. Metering and Measurement Processes: Pioneer proposes the following metering and measurement processes. a. A differential - pressure meter to measure single -phase flow of injected water. b. A differential - pressure orifice meter to measure single -phase injection rate of gas. c. A well -test header connected to a multiphase flow meter to measure oil, water and gas rates of a single well over a span of several hours. Wells will be rotated through the test system at least once per month. d. Custody transfer volumes for total Oooguruk produced oil, gas and water will be measured on a real -time, continuous basis using a separator, orifice meter and a multiphase flow meter. 17. Production Allocation: Pioneer proposes allocating production by use of a multiphase flow meter (MPFM) instead of a separator and standard, single -phase measurement to measure the total or aggregate daily volume. Each day the Oooguruk allocation system will calculate a "theoretical volume" for all well streams. The theoretical volume for each well will be summed to calculate the total theoretical volume for all Oooguruk wells. The actual aggregate volume will be determined at the Oooguruk field level from measurements made using an MPFM. The allocation factor will be the ratio of aggregate volume to total theoretical volume. The allocated volume for each well will be the product of the allocation factor and the well- specific theoretical volume. Conservation Order No. 645 • Page 8 May 26, 2011 CONCLUSIONS: 1. Pool Rules for the development of the OTOP in the OU and the Oooguruk Field are appropriate. 2. The OTOP is compartmentalized and requires unrestricted well spacing to optimize waterflood efficiency and resource recovery. Eliminating spacing restrictions on wellbores within the Affected Area, defined below, will increase the operator's flexibility in placing wells as the pool is developed and will not affect recovery, promote waste, jeopardize correlative rights, or result in an increased risk of fluid movement into freshwater. 3. Correlative rights of owners and landowners of offset acreage will be protected by a 500 -foot set -back requirement that conforms with regulation 20 AAC 25.055(a)(1). 4. Water and water - alternating -gas injection into the OTOP will preserve reservoir energy and increase ultimate recovery. 5. Monitoring reservoir performance will ensure proper management of the pool. Annual reports and technical review meetings will keep the Commission apprised of reservoir performance, promote greater ultimate recovery and prevent the waste of resources. 6. Annular pressure management is necessary to prevent failure of well integrity and uncontrolled release of fluids or pressure and to minimize threats to human safety and the environment. 7. Compliance with the Safety Valve System regulations, 20 AAC 25.265, and Industry Guidance Bulletin 10 -004 will ensure the environment is protected from uncontrolled releases of hydrocarbons. 8. Filing the proposed submittals, rather than those required by 20 AAC 25.050(b), will ensure equally "accurate surveying of the wellbore to prevent well intersection, to comply with spacing requirements, and ... protection of correlative rights." 20 AAC 25.050(h). 9. Adherence to the requirements of 20 AAC 25.071(a) would not significantly add to the geologic knowledge of the area as long as one well drilled from each drill site is logged with a complete suite of wireline or logging - while - drilling tools from the base of conductor through the OTOP. 10. A GOR limitation waiver is appropriate under 20 AAC 25.240(b)(1) because the OTOP will be developed as a waterflood and water - alternating -gas enhanced recovery project. Once pressure maintenance operations commence, GORs should not exceed the limits imposed by 20 AAC 25.240(a). However, before the pressure maintenance operations commence, injectors will be pre - produced to ensure adequate reservoir voidage to accommodate water injection. During this period there may be some wells that will exceed the GOR limits. 11. Pioneer's proposed production and fiscal allocation methodology is consistent with the methodology employed for the Oooguruk - Kuparuk and Oooguruk - Nuiqsut Oil Pools. Conservation Order No. 645 e • Page 9 May 26, 2011 NOW, THEREFORE, IT IS ORDERED: The development and operation of the OTOP is subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not superseded by these rules: Affected Area: Umiat Meridian Township, Range Description T13N, RO7E Section 3: SW 1/4 SW 1/4 Section4: SE' /4SE' /4,W %2 SE 1/4, SWI /4,SE' /4NW /4,W' /2 NW 1/4 Section 5: E %2 E %2 Section 8: E '/2 E 1 /2 Section 9: All Section10: SW 1/4 NE 1/4, SE 1 /4 SE' /4,W SE 1/4, W /2 Section 11: SW 1 /4 SW 1/4 Section 14: SE 1 /4 SE 1 /4, W '/2 SE 1 /4, W %2 Section 15: All Section 16: All Section 17: E 1 /2 E 1 /2, SW /4 SE 1/4 Section 20: E' /2, SW 1/4, SE 1 /4 NW 1/4 Section 21: All Section 22: All Section 23: All Section 24: SW 1 /4, W '/2 NW 1/4 Section 25: SE1/4 NE 1/4, W 1/2 NE 1 /4, SE 1 /4, W Section 26: All Section 27: All Section 28: All Section 29: E ' /2, E '/2 W '/2, NW 1/4 NW 1 /4 Section 32: E '/2, E '/2 W 1/2, W %2 SW 1 /4 Section 33: All Section 34: All Section 35: All Section 36: All T12N, RO7E Section 3: All Section 4: All Section 5: E '/2 NE 1 /4, SE 1 /4 Section 8: E '/2 Section 9: All Section 10: All Conservation Order No. 645 • • Page 10 May 26, 2011 Township, Range Description Section 15: All Section 16: All Section 17: E %2, E 1/2 SW % Section 20: E 1/2, E 1/2 W %2 Section 21: All Section 22: All Rule 1 Field and Pool Name The field is the Oooguruk Field. Hydrocarbons underlying the Affected Area and within the interval identified in Rule 2, below, constitute the Oooguruk -Torok Oil Pool (OTOP). Rule 2 Pool Definition The OTOP is the accumulation of hydrocarbons within the Affected Area common to and correlating with the interval between the measured depths of 4,991 and 5,272 feet on the resistivity log recorded in exploratory well Kalubik No. 1 Rule 3 Well Spacing There shall be no restrictions as to well spacing except that no pay shall be opened in a well within 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 4 Drilling Waivers All permits to drill deviated wells within the OTOP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). Rule 5 Well Logging and Sampling Requirements a. A suite of petrophysical well logs including, at a minimum, gamma ray, resistivity, neutron porosity, and density porosity logs shall be acquired across the OTOP in one well from each drill site. The Commission may require additional wells to be logged using one or more petrophysical logging tools. b. A mud log and cuttings samples shall be obtained from the base of the conductor through the OTOP in at least one well drilled from each drill site. Rule 6 Reservoir Pressure Monitoring a. A bottom -hole pressure survey shall be taken on each well prior to initial production or inj ection. b. The operator shall obtain the pressure surveys needed to manage the hydrocarbon recovery processes effectively subject to the annual plan outlined in Rule 9, below. At a minimum a pressure survey shall be acquired from at least one well on each drill site each year. c. The reservoir pressure datum will be - 5,000' TVDSS. Conservation Order No. 645 • Page 11 May 26, 2011 d. Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or be extrapolated from surface measurements (single phase fluid conditions), pressure fall -off measurements, pressure buildup measurements, multi -rate test results, drill stem test results, and open -hole formation tests or other methods approved by the Commission. e. A Reservoir Pressure Report, Form 10 -412, shall be utilized for all surveys; all relevant data shall be attached to the report. The data submitted shall include, at a minimum, rate, pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a complete analysis of each survey being conducted. f. The results and data from any special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 7 Gas -Oil Ratio Exemption Wells producing from the OTOP are exempt from the GOR limits of 20 AAC 25.240(a) as long as 20 AAC 25.240(b)(1) applies. An enhanced recovery operation, as required by 20 AAC 25.240(b)(1), must be initiated within 12 months of the issuance of this order. Rule 8 Annual Reservoir Review a. An annual reservoir surveillance report must be filed by April 1st of each year and include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: i. The voidage balance, by month, of produced fluids and injected fluids and the cumulative status for each producing interval; ii. A reservoir pressure map at datum, and a summary and analysis of the reservoir pressure surveys within the pool; iii. The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; iv. A review of pool production allocation factors and issues over the prior year. v. A review of the progress of the enhanced recovery project; and vi. A reservoir management summary, including results of any reservoir simulation studies. b. By June 1 of each year, the operator shall schedule and conduct a technical review meeting with the Commission to discuss the annual reservoir surveillance report and items that may require action within the coming year. The Commission may audit the technical data and analyses relating to the surveillance report's conclusions and reservoir depletion plans. Rule 9 Annular Pressures a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each development well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be made available for Commission inspection. Conservation Order No. 645 • • Page 12 May 26, 2011 c. The operator shall notify the Commission within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2,000 psig for all development wells, or (ii) sustained outer annulus pressure that exceeds 1,000 psig. d. The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10 -403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The Commission may approve the operator's proposal or require other corrective action or surveillance. The Commission may require corrective action be verified by a mechanical integrity test or other approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the Commission within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10 -403) a proposal for corrective action. The Commission may approve the operator's proposal or require other corrective action. The Commission may also require corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. f. Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut - in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 psig. A well subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the Commission under (c) of this rule, unless the Commission prescribes a different limit. g. For purposes of this rule, i. "inner annulus" means the space in a well between tubing and production casing; ii. "outer annulus" means the space in a well between production casing and surface casing; and iii. "sustained pressure" means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) is not pressure that has been applied intentionally. Rule 10 Production Surface Commingling, Measurement and Allocation Hydrocarbon measurement, production allocation, fiscal allocation, and surface commingling of production from the OTOP with the other OU and KRU Oil Pools is authorized provided it is done in accordance with the provisions of CO 596.007 et al. issued on July 30, 2009. Conservation Order No. 645 Page 13 May 26, 2011 Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. ENTERED at Anchorage, Alaska, and .. ed ay 25, 20 . p®i.�ty �S m an, o .sio Al . i it and Gas Conservation Commission Cathy P Foerster, Commissioner Alask. Oil and Gas Conservation Commission RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration. - In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. . 0 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton President 408 18 Street 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Y--('''• # N 7 )\ V 1 1 • . Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, May 27, 2011 9:18 AM To: '(michael.j. nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raft; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer'; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'caunderwood'; 'Chris Gay; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Scott'; 'David Steingreaber'; 'ddonkel @cfl.rr.com'; 'Dennis Steffy'; 'Elizabeth Bluemink'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Schultz (gary.schultz @alaska.gov)'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jeffery B. Jones (jeff.jones @alaska.gov)'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Nicks'; 'John Garing'; 'John Katz (john.katz @alaska.gov)'; 'John S. Haworth'; 'John Spain'; 'John Tower; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant (laura.gregersen @alaska.gov)'; 'Marilyn Crockett; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester; 'Marguerite kremer (meg.kremer @alaska.gov)'; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; 'Rena Delbridge'; 'Renan Yanish'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Rudy Brueggeman'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Sheltenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambet; 'Steve Moothart (steve.moothart @alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler; 'Tina Grovier'; 'Todd Durkee'; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); Yereth Rosen; 'Aaron Gluzman'; 'Ben Greene'; Bruno, Jeff J (PCO); 'Dale Hoffman'; David Lenig; 'Donna Vukich'; Eric Lidji; 'Gary Orr; Heusser, Heather A (DNR); 'Jason Bergerson'; 'Joe Longo'; King, Kathleen J (DNR); 'Lara Coates'; Lois Epstein; Marc Kuck; 'Marie Steele'; 'Mary Aschoff; 'Matt Gill'; Maurizio Grandi; Ostrovsky, Larry Z (DNR); 'Patricia Bettis'; Richard Garrard; 'Ryan Daniel'; 'Sandra Lemke'; Talib Syed; 'Wayne Wooster; 'Wendy Wollf; 'William Van Dyke'; Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Herrera, Matt F (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Matt Herrera; Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) Subject: co645 (Oooguruk Pool Rules) df Attachments: co645.pdf All - Have a nice long weekend. Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 • • THE S TATE l //7,.4. s I, OF T of S onservauo s, t GOVERNOR SEAN PARNELL 333 West Seventh Avenue 9 ALAS + Anchorage, Main: 907.279.1433 3 . 279.433 Fax: 907.276.7542 ADMINISTRATIVE APPROVAL CO 596.008 ADMINISTRATIVE APPROVAL CO 597.008 ADMINISTRATIVE APPROVAL CO 432D.011 ADMINISTRATIVE APPROVAL CO 406B.012 ADMINISTRATIVE APPROVAL CO 430A.011 ADMINISTRATIVE APPROVAL CO 435A.010 ADMINISTRATIVE APPROVAL CO 456A.010 ADMINISTRATIVE APPROVAL CO 645.001 Mr. Pat Foley Mr. John Gerd Manager - Land & External Affairs ConocoPhillips Alaska, Inc. Pioneer Natural Resources Alaska, Inc. P.O. Box 100360 700 G St., Suite 600 Anchorage, AK 99510 -0360 Anchorage, AK 99501 Re: Multiphase Flow Meter Application Oooguruk Production through KRU Facilities North Slope, Alaska Dear Mr. Foley and Mr. Gerd: By letter dated December 14, 2012 and received on December 18, 2012, Pioneer Natural Resources Alaska, Inc. (Pioneer), as the Oooguruk Unit (OU) operator, requested authorization to replace its Daniels JuniorSonic two path ultrasonic meter designated as FI -21781 with a Micro Motion ELITE Coriolis meter. The Daniels meter is being used to measure gas flow from the Oooguruk Production Separator V- 21701. According to Pioneer, the Coriolis meter will have improved measurement performance over a wider range of gas rates. The AOGCC Senior Staff, Pioneer and a representative from Conoco Phillips Alaska Inc. (CPAI) held an informal meeting on January 17, 2013, and additional information was requested. Information provided by Pioneer, including a calibration certificate of a similar meter showing calibration accuracy of 0.1% with error factors of 0.04% to 0.005 %, is sufficient for the Commission to determine that substitution of the Coriolis meter will result in equal or greater accuracy in measuring hydrocarbons. On January 11, 2013 CPAI, as operator of the KRU, approved Pioneers proposal to replace the meter. The Commission GRANTS Pioneer's request upon the following conditions: 1. Pioneer must update the table of Gas Metering Maintenance Procedures included in the June 25, 2009 Multiphase Flow Meter Approval Letter; 2. Pioneer and CPAI must comply with the conditions as stated, in the June 25, 2009 Letter; 3. Pioneer must perform a full functional checkout of the Coriolis meter prior to start-up, including the interface with the Kuparuk River Unit automation system. 4. In conjunction with CPAI, Pioneer must develop Commission approved installation and maintenance guidelines to ensure optimum performance from the Micro Motion ELITE Coriolis meter. • • Mr. Pat Foley March 28, 2013 Page 2 of 2 interface with the Kuparuk River Unit automation system. 4. In conjunction with CPAI, Pioneer must develop Commission approved installation and maintenan ce guidelines to ensure optimum performance from the Micro Motion ELITE Coriolis meter. 5. No proposed changes to the Multiphase Metering Operations and Maintenance Guidelines (last dated November 14, 2012 Rev 1001.00), may take effect without prior approval of the Commission; 6. Calibration of the pressure and temperature, and verification of installation of the new meter must be performed and witnessed by Commission Inspectors; Pioneer must provide the Commission's Inspectors at least 48 -hours notice; and 7. All other rules of the Orders remain unchanged. Corrected at Anchorage, Alaska on March 28, 2013. Nunc pro tunc February 20, 2013. /4t, Cathy P. ,oerster Daniel 7/Seamount, Jr Chair, Cha, ommisstoner Commissioner C � RECONSIDERATION AND APPEAL NOTICE 06 As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. if the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within l0 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court, That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. M provided in AS 31.05.080(6), "[t)he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration" In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, February 21, 2013 2:22 PM To: Singh, Angela K (DOA); Ballantine, Tab A (LAW); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Ferguson, Victoria L (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Bender, Makana K (DOA); Mdver, Bren (DOA); McMains, Stephen E (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqua!, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); ( michael j .nelson @conocophillips.com); Abbie Jossie; AKDCWelllntegrityCoordinator; alaska @petrocalc.com; Alexander Bridge; Andrew VanderJack; Anna Raff; Barbara F Fullmer bbritch; bbohrer @ap.org; Bill Penrose; Bill Walker Bowen Roberts; Brian Havelock; Bruce Webb; Burdick, John D (DNR); caunderwood @marathonoil.com; Cliff Posey; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David Duffy; David House; David Scott; David Steingreaber, Davide Simeone; ddonkel @cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer; Gary Laughlin; schultz, gary (DNR sponsored); ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; Gregory Geddes; gspfoff; Jdarlington (jarlington @gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Lastufka; news @radiokenai.com; Easton, John R (DNR); John Garing; John Spain; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark P. Worcester; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike @kbbi.org; Mike Morgan; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson @petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillem; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Robert Campbell; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Cranswick; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Miller; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield @aoga.org; Taylor, Cammy 0 (DNR); Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; yjrosen @ak.net; Aaron Gluzman; Aaron Sorrell; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Dale Hoffman; David Lenig; Donna Vukich; Eric Lidji; Erik Opstad; Franger, James M (DNR); Gary Orr; Smith, Graham 0 (PCO); Greg Mattson; Heusser, Heather A (DNR); James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod @conocophillips.com; Jim Magill; Joe Longo; King, Kathleen J (DNR); Laney Vazquez; Lara Coates; Lois Epstein; Louisiana Cutler; Marc Kuck; Steele, Marie C (DNR); Matt GUI; Ostrovsky, Larry (DNR sponsored); Bettis, Patricia K (DOA); Perrin, Don J (DNR); Peter Contreras; Pexton, Scott R (DNR); Pollard, Susan R (LAW); Pollet, Jolie; Richard Garrard; Ryan Daniel; Sandra Lemke; Talib Syed; Wayne Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke Subject: Administrative Approvals for MPM Attachments: Multiphase Flow Meter Application Oooguruk Production through KRU Facilities.pdf 1 • • • Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 (907) 793 -1221 (907) 276 -7542 2 Easy Peel® Labels i ® ® Bend along line to AVERY® 5960TM Use Avery® Template 5160® eed Paper g expose Pop -up EdgeTM l L Mr. Pat Foley Mr. John Gerd Manager— Land & External Affairs Pioneer Natural Resources Alaska, Inc. ConocoPhillips Alaska, Inc. 700 G St., Ste. 600 Post Office Box 100360 Anchorage, AK 99510-03600 Anchorage, AK 99501 _ ss ( - A? ..._ : :„.„_ . 4 a 4§kr I= tiquettes faciles a peter ; Repliez a la hachure afin de ; www.avery.com Alioov® 11en® : Sens de �_._�__ �- _ -�__� _MC ! 1_Rnn_f;A_AVFRV Easy Peel® Labels i ♦ ® Bend along line to 1 ® Y® 5960Tm Use Avery Template 5160® � eed Paper 4 expose Pop -up EdgeTM 2 David McCaleb Penny Vadla IHS Energy Group George Vaught, Jr. 399 W. Riverview Ave. GEPS Post Office Box 13557 Soldotna, AK 99669 -7714 5333 Westheimer, Ste. 100 Denver, CO 80201 -3557 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 40818 St. President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. Post Office Box 58055 Post Office Box 93330 Fairbanks, AK 99711 Anchorage, AK 99503 Anchorage, AK 99515-4295 North Slope Borough Planning Department Richard Wagner Gordon Severson Post Office Box 69 Post Office Box 60868 3201 Westmar Cir. Barrow, AK 99723 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Jack Hakkila Darwin Waldsmith James Gibbs Post Office Box 190083 Post Office Box 39309 Post Office Box 1597 Anchorage, AK 99519 Ninilchik, AK 99639 Soldotna, AK 99669 Etiquettes faciles a peter ; Repliez a la hachure afin de ; vuww.averycom 11 +1I. , In n�h�ri+ mirov® r. 1C.A® I Sens de -_ ^t �_ - _�_ -a „__ „_MC ! 1- ROA- CA -AVFRV #7 • • ConoCOPhilliPS REceiveD JUL 2 5 2013 AOGGO July 22, 2013 Mr. Dale Hoffman Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, AK 99501 RE: Gas Metering Maintenance Procedures Dear Dale: Bill Arnold Manager, North Slope Operations Post Office Box 100360 Anchorage, Alaska 99501 ATO-1220 Phone 907-263-4822 bill.arnold@conocophiIlip,.com On February 20, 2013, the Alaska Oil and Gas Conservation Commission granted Pioneer Natural Resources Alaska, Inc.'s ("Pioneer") request, as Oooguruk Unit operator, to replace its Daniels JuniorSonic two path ultrasonic meter designated as FI- 21781 with a Micro Motion ELITE Coriolis meter. The Commission's approval was subject to certain conditions, one of which was updating the table of Gas Metering Maintenance Procedures contained in the June 25, 2009 Multiphase Flow Meter Approval letter. The updated table of Gas Metering Maintenance Procedures is shown below, revisions were developed in consultation with Pioneer. Gas Metering - Maintenance Procedures Activity Gas Allocation Metering Daily Checks, incl draining of liquids General Meter Walkaround & Inspection Gas Sampling and Analysis Gas Pressure Transmitter Measurement Checks Gas Temperature Transmitter Measurement Checks Gas USM Flowmicro Constants Check Gas USM Meter Diagnostics Checks Gas Coriolis Meter Density Update Gas Coriolis Meter Diagnostics Checks Gas Coriolis Meter On -Board Verification Thermowell Inspection Gas Export Metering Flow Calculation Checks Recalibrate Dedicated Test Equipment at MIST/Approved Lab Bi-Annual Gas Meter Tube Inspection & Clean CheckFreq. ID 1D 7D 30D 30D 30D 30D 30D 30D 30D lY lY 2Y 2Y Page 1 of 2 Subject to compliance with the intervals contained in the updated table of Gas Metering Maintenance Procedures and agreed upon operating and maintenance guidelines, ConocoPhillips Alaska, Inc. will support the use of the Micro Motion ELITE Coriolis meter to measure gas flow from the Oooguruk Production Separator V-21701. If the maintenance procedures are not followed or the measurement appears not to work as reasonably expected, ConocoPhillips Alaska, Inc. may petition the Alaska Oil and Gas Conservation Commission or take other action to ensure accurate metering and otherwise protect the interests of the Kuparuk River Unit Working Interest Owners. Nothing in this letter is intended to waive or modify any aspect of the Production Processing and Services Agreement. Regards, IB'Arnold Manager, North Slope Operations Cc: Steve Bradley CPAI Victoria Ferguson AOGCC Page 2 of 2 146 • • Chris Wallace AOGCC chris.wallace @alaska.gov Pioneer Natural Resources requests approval to replace the Oooguruk gas export meter from the current Daniels Junior Ultrasonic to a Micromotion Coriolis meter. Current operating conditions require a lower separator pressure for production stability, which is at the minimum measurement pressure of the existing ultrasonic meter, and the gas production rate is at the maximum measurement range. The new Micromotion meter will allow larger turndown and higher upper end flow measurement with improved accuracy within the measurement system. Pioneer has received approval from ConocoPhillips for the installation of the Micromotion meter via email from Greg McDuffie to Dave Hart dated 01/10/2013. Pioneer Natural Resources and ConocoPhillips will develop and approve installation and maintenance guidelines to ensure optimum performance from the Micromotion Coriolis meter. There is not a specific standard listed in API MPMS for gas custody transfer using a Coriolis meter; however, API MPMS chapter 14 references acceptable custody calibration standard for orifice meters of + / -0 .5 %, or 1.0% overall. Alaska Administrative Code, 20 AAC 25.228, Production measurement equipment for custody transfer, paragragh (g) states that a meter should prove within 0.25% of previous values. The attached example calibration certificate of a meter similar to the one Pioneer proposes shows a calibration accuracy of 0 .1 %. The error factor between the test stand and the Micromotion meter is from - 0.04 to 0.005 %. The documented accuracy and calibration capability of the Micromotion Coriolis meter exceeds the requirements referenced in the Alaska Administrative code and the API MPMS standard for custody transfer. API MPMS 14.9 is the standard for Coriolis meters issued in 2003, and is referenced in the text below. The proposed Micromotion Coriolis meter design and operation conforms with AGA Report 11 (2009) and to API MPMS Chapter 14.9 requirements. AGA Report 11 states: Manufacturers are responsible for initial flow calibration of Coriolis meters prior to delivery see section 4.7.3. Calibration with an alternate calibration fluid (e.g. water) is valid with Coriolis sensor designs where the transferability of the alternate calibration fluid, with an added uncertainty relative to gas measurement, has been demonstrated by the meter manufacturer through tests conducted by an independent flow calibration laboratory. When the transferability of the manufacturer's calibration fluid to gas cannot be verified, the meter shall be flow calibrated on gas as per the requirements in 7.1. The proposed Coriolis meter will be installed as recommended by Micromotion, AGA Report 11, and API MPMS Chapter 14.9. The attachments are a summary of the design requirements for the Micromotion Coriolis meter at the operating conditions required by Pioneer, the Micromotion Coriolis datasheet, and an example calibration certificate that is provided with every meter. Your timely approval is requested. We plan on installing the meter during a mid -2013 shutdown and require several months lead for meter purchase. If there are any questions, please contact Dave Hart; 907 - 343 -2125; email david.hart @pxd.com Jim Gilroy Dave Hart • . Micro Motion Calculation Summary Date: 12/21/12 Company: PIONEER NATURAL RESOURCES CO Project Name: - Service: - Sensor Model #: CMF400M436NQBAEZZZWM Sensor Tag(s): - Transmitter Model #: 2700R12BBAEAWZ Transmitter Tag(s): - Wetted Material: 316L SS Fluid: Gas Fluid State: Gas Mass Flow Accuracy at Operating Flow ( +/- % of Rate): 0.3500 Density Accuracy at all Rates ( +/- ): 0.0312 Ib /ft3 Pressure Drop at Operating Flow: 1.7783 psi Sensor Minimum Pressure at operating conditions: 168.3398 psig Velocity at Operating Flow: 163.5697 ft /sec Min Operating* Max Design Units Flow Rate: 0.5000 15.0000 40.0000 - MMSCFD Pressure: - 170.0000 - - psig Process Fluid Temperature: - 95.0000 - - F Ambient Temperature: - 80.0000 - - F Density: - 0.6059 - - Ib /ft3 Viscosity: - 0.0115 - - cP Base Reference Temperature: F 60.0000 Density: Gas Only Base Reference Pressure: psia 14.7000 Base Reference Density: g /cm3 0.0510 Process Connection: 4 -inch ANSI 300 lb weld neck raised face flange Process Connection Pressure Rating: - @Temperature: - Flow Rate MMSCFD Mass Flow Pressure psi Velocity* y * ft /sec Re Accuracy +/- % of Rate Drop* 40.0000 0.35 12.44 436.2 6740000 36.0500 0.35 10.12 393.1 6075000 32.1000 0.35 8.03 350 5409000 28.1500 0.35 6.19 307 4744000 24.2000 0.35 4.59 263.9 4078000 20.2500 0.35 3.22 220.8 3412000 16.3000 0.35 2.1 177.7 2747000 12.3500 0.35 1.21 134.7 2081000 8.4000 0.50 0.57 91.6 1415000 4.4500 0.94 0.16 48.53 749900 . 0.5000 8.40 0 5.452 84250 Sizing Details 10 20 v E C V 'm 4 v Flow LL '6 g 4 N Accuracy -10 0 O N CO Vi CO CO m W A CA 'V 47 tO NN A hl V IV Q CO W CC W o c O O O O O O 8 8 8 O O 0 0 0 0 0 O 8 O 0 O o 0 O O O Flow Rate (MMSCFD) *AII pressure drop and velocity results are based on the process conditions (except flow rate) that are entered in the Operating column. Notes: - Prepared By: DAVID_MCKINNEY Project ID: 119368 Oracle Version: 11.5.10.2 Application: Gas • • Date: 21- DEC -12 Page 1 3 Company PIONEER NATURAL RESOURCES CO Micro Motion Spec No 1 - 1 Rev. 1 Contract I - I P.O I - Service: Gas Configuration Data Sheet Req. I - I By Manufacturer: Micro Motion, Inc. Chk'd 1 - 1 Appr. 1 - 1 Sensor Tag(s): 2 Transmitter Tag(s): 3 Fluid State I Fluid Name - Gas 4 Flow MinlOper I Max I Design .5 15 40 - MMSCFD Service 5 Pressure Min I Oper I Max I Design - 170 - - psig 6 Temperature Min I Oper I Max I Design - 95 - - F 7 Specific Gravity /Density (Operating) .60593 Ib /ft3 8 Viscosity (Operating) .01151 cP — 9 Product NolProposal Line No.IQty CMF400M436NQBAEZZZWM I 1.1 I 1 10 Description SENSOR, CMF400M 11 ETO #: I ETO Description - 1 - 12 ETO #: I ETO Description - 1 - 13 Process Connections 4 -inch ANSI 300 lb weld neck raised face flange 14 Approval - 15 Wetted Parts 316L SS 16 Mass Flow Accuracy @OpFlow( %rate) •351 Sensor 17 Density Accuracy @ All Rates .031211 Ib /ft3 18 Pressure Drop @ Op Flow 1.778331 psi 19 Calibration Type I Rate I Units Standard I 0 1 kg /min 20 Custom Calibration Points - 21 Density for Volume to Mass Conversion - 22 Special Units Text 'Totalizer Text - 1 - 23 Base Units: Flow ITimejConversion - I - 1 - 24 Warning 25 Sensor Notes - 26 Product NolProposal Line No.1 Qty 2700R12BBAEAWZ 1 1.43 1 1 27 Description TRANSMITTER,2700 28 ETO #:IETO Description - 1 - 29 ETO #: i ETO Description - 1 - 30 Input Power 18 to 100 VDC and 85 to 265 VAC; self switching 31 Approval CSA (US and Canada) 32 Transmitter Flow Units: Mass I Vol lb/hr 1 USGPM 33 Transmitter Units: Density I Temp lb/ft3 I F 34 Special Mass Units Test 1 Totalizer Text - 1 - Transmitter 35 Base Mass Units: Flow I Time 1 Conv - I - 1 - 36 Special Vol Units Test I Totalizer Text - 1 - 37 Base Vol Units: Flow 1 Time I Conv - - 1 - 38 Output 1 Type Variable Analog 1 Mass Flow Rate 39 Scaling 1 LRV URV 1 Units 4 -20mA 0 1 0 lb/hr 40 Output 2 Type Variable Analog 2 Density 41 Scaling 1 LRV URV 1 Units 4 -20mA 10 1 0 lb /ft3 42 Output 3 Type Variable Frequency I Mass Flow Rate 43 Setting 1 Rate - 1 Units OHz 1 0 1 - I lb /hr 44 Transmitter Notes - 45 Product NolProposal Line No.1 Qty - 1 - I Cable 46 Description - 47 Product No) Proposal Line No.IQty - 1 I 48 Description - 49 ETO #:1 ETO Description - 1 - Peripheral 50 ETO #: IETODescription - 1 - 51 Power - 52 Peripheral Tag(s): - 53 Peripheral Notes - Notes 54 - Prepared By: MARK_REYES Project Id: 119368 Oracle Version: 11.5.10.2 Application: Gas Prepared By: MARK_REYES Project Id: 119368 Oracle Version: 11.5.10.2 Micro Motion, Inc. Mass Flowmeter Calibration Certificate . . Product Code Serial ID Order ID Line Item Customer Tag C2.F4001.1435K3AEZZ2 11111111111110111 1.1 1 363-4B-FE-701 FUCK7 00 111111M1111 Process Detail Process ID : 1.2910E539 111111111111111111111 2 • Process Time : 2012.12.08 _._1:4...:08 , Process Stand : TSM3A@SSCB 1.5' Stand Uncertainty : - / - 0.030% 1 . . ' , Fluid : H20 0.5' i 00% Rate : 6804 KG/N11C . . Error(%) 0 . .t.::: :::: :::: ::::••••• :::: ....,.... :::: Pickoff : 1 •' 100%Pn": 20.83 PSIG/22.4 c - 05 Results • Status : PASS - 1.5 . DI : 3 D2 : 1, 0 10 20 30 40 50 60 70 80 90 100 K1 : 5737.792 icimer/4 K2 : 691E.257 Meter Reference DT: 4.33 Flow Flow Rate Total Total Error Specification FD : 61:1E (%) (kg/min) (kg) (kg) (%) OM) DTG : 0 100.0 6804 5103.454 5103.182 0.005 0.100 • DR21 : E80.4 509.E87 509.75 -0.012 0.100 3 DFQ2 : 3 .L0.0 50.0 E 3402 2555.015 255€.027 -0.040 0.100 FlowCal: 4254.34.19 100.0 6804 5102.773 5102.75 0.000 0.100 FFO : 3 FTG : 0 DensCal : 057330E9164.33 FCF : 4254.3 FT : 4.19 IENG X:ONG Technician Traceable to international Standards. Meter total based on pulse output. Details at www.micromotion.com. 2 013.01.21 10:2:33 1 / 1 I • • Colombie, Jody J (DOA) From: Hart, David <David.Hart @pxd.com> Sent: Wednesday, February 20, 2013 2:54 PM To: Wallace, Chris D (DOA) Cc: Foley, Pat; Gilroy, Jim; Hart, David; Colombie, Jody J (DOA) Subject: Pioneer Micromotion Meter application amendment Mr. Wallace, As you and Jody requested in your telephone call today, please find attached an amendment to our Micro Motion coriolis meter application dated December 14, 2012. Pioneer would like to amend our application to also include Conservation Order No. 645 (Oooguruk -Torok Oil Pool). Thank you for your consideration. Regards, Dave Hart David Hart Operations Manager Pioneer Natural Resources Alaska 700 G Street, ATO 600 Anchorage, AK 99501 : 907.343 -2125 I t : 907.244 -1722 I A: 907.343 -2194 I ®: david.hartpxd.com Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e -mail and delete the message and any attachments. 1 t 44 • PIONEER S RECEIVED DEC 18 2012 NATURAL RESOURCES ALASKA A. ti p .'' J. Patrick Foley Manager of Land & External Affairs Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Voice (907) 343 -2110 - Fax (907) 343 -2190 December 14, 2012 Alaska Oil & Gas Conservation Commission Commissioner Cathy Forester, Chair 333 West 7 Avenue, Suite 100 Anchorage AK 99501 -3539 Dear Commissioner Forester, RE: Multiphase Flow Meter Application Oooguruk Production through KRU Facilities North Slope, Alaska The Alaska Oil and Gas Conservation Commission has approved the Oooguruk Unit measurement equipment and allocation techniques by Administrative Approvals affecting the following conservation orders: Administrative Approval CO 596 Administrative Approval CO 597 Administrative Approval CO 432D Administrative Approval CO 406B Administrative Approval CO 430A Administrative Approval CO 435A Administrative Approval CO 456A The application and orders that relate to Oooguruk Unit production measurement and allocation reflect that a Daniels JuniorSonic two path ultrasonic meter designated as FI -21781 will be utilized to measure gas flow out of the Oooguruk Production Separator designated as V- 21701. Pioneer has determined that an improved meter is available and would result in improved measurement performance. The Daniels JuniorSonic will be replaced with a Micro Motion coriolis meter. The Micro Motion coriolis meter will offer a 0.35% mass flow accuracy over a wider range of gas rates up to 40 MMSCFD. This increased turndown will improve measurement performance during gas slugging events. Micro Motion coriolis meters are industry standard for custody transfer and other critical process control. A Micro Motion Elite product data sheet is attached for your information and files. If you have any question upon this matter or wish to arrange a meeting please contact me at (907) 343- 2110 or by email at pat.foley @pxd.com. Respectfully, 631 J Pat Foley Pioneer Natural Resources Alaska, Inc. cc: David Roby, AOGCC by email pdf only Temple Davison, DNR — DOG by email pdf only John Gerd, ConocoPhillips by email pdf only Robert Province, Eni by email pdf only Product Data Sheet • • PS- 00374, Rev. U September 2012 Micro Motion ELITE Coriolis Flow and Density Meters Micro Motion ELITE Coriolis meters are the leading precision flow and density measurement solutions. ELITE meters offer the most accurate and ELITE Peak performance repeatable measurement available for liquids, gases, or slurries. Coriolis meter ,,,,,,, ,---,,--- ,,, .„, *Agf i -t ; ... -- - 141 - ELITE HC Peak performance r high capacity 3 # meter , : , F . F - Series High performance ' compact drainable ` Coriolis meter . .., , VIN.,,, 1 —,,,,..--, ":- ' . 44-f-1: -= 4 . :. .. ,.. ' r °' H - Series Hygieniccompact drainable Coriolis meter Best precision flow and density measurement • Unique design delivers unparalleled measurement sensitivity and stability • Guarantees consistent, reliable performance over the widest flow range T- Series Straight tube full - bore • Smart Meter Verification for quick, complete meter diagnosis without Coriolis meter process interruption. • 2 -wire loop- powered option for installation simplification R - Series General purpose Superior performance in the most challenging applications flow - only Coriolis meter • Industry standard for custody transfer and critical process control • Best two -phase flow capability for batching, loading, and entrained air applications LF- Series Extreme low - flow Coriolis • Immune to fluid, process, or environmental effects for superb meter measurement confidence 4 , , Micro M EMERSON. Process Management i Micro Motion ELITE flow and density meters Micro Motion Coriolis meters meet a vast range of application needs, ranging from extreme low -flow up to high -flow, high- capacity lines. Cryogenic, hygienic, high- temperature, and high - pressure —Micro Motion meters can handle them all. Micro Motion meters are available with a variety of wetted parts to ensure the best material compatibility. Now with the industry's only 2 -wire Coriolis option, Micro Motion provides unsurpassed simplicity of installation and application flexibility. Coriolis meters. Coriolis meters offer dramatic ELITE Coriolis meters. Micro Motion ELITE meters benefits over traditional volumetric measurement are the leading meters for precision flow and density technologies. Coriolis meters: measurement. ELITE meters offer the most • Deliver accurate and repeatable process data accurate measurement available for virtually any over a wide range of flow rates and process process fluid, while exhibiting exceptionally low conditions. pressure drop. Every ELITE meter features standard secondary containment, and is available • Provide direct inline measurement of mass flow with stainless steel or nickel -alloy wetted parts and and density, and also measure volume flow and a wide variety of process connections to meet your temperature —all from a single device. every need. • Have no moving parts, so maintenance costs Now with Smart Meter Verification, ELITE delivers are minimal. the best in measurement and ease of use for critical • Have no requirements for flow conditioning or applications. ELITE meters offer the best straight pipe runs, so installation is simplified measurement performance for mass, density, and and less expensive. volume, regardless of process or environmental • Provide advanced diagnostic tools for both the conditions. ELITE meters provide measurement meter and the process. capability for two -phase flow, liquid, and gas custody transfer, and process conditions from –400 °F ( -240 °C) to 662 °F (350 °C). Contents Temperature limits 3 Environmental effects 21 Accuracy and repeatability 4 Hazardous area classifications 22 Liquid flow performance 5 Materials of construction 30 Gas flow performance 6 Weight 30 Density range (liquid only) 8 Dimensions 31 Vibration limits 8 Fitting options 42 Power consumption 8 Ordering information 55 Pressure ratings 9 2 Micro Motion ELITE Flow and Density Meters • • Temperature limits All models except high- 176 (80) 140 temperature models (1) (2) (3) (4) 0 1ao (60) (60) I en � 104 (40) 113 (45) 0 aroj 2 g u 32(0) ° g. Mount transmitter 2 'a5 - ( remotely; use j -box N 0 F .. C _ - 112 ( - 80) a -148 ( -100) La 0 co 0 CO ( 0 CO V Q . � 1 1 M 0 < 7_, co co 8 Tr y O a) W co ^1 N CO -- CO 1 C I I O 0 Maximum process temperature in °F ( °C) High- temperature models 176 (80) `0 8 140 (60) 0 0 104 (40) 0 a 2'--- 0 LL 32(0) o c 1 t = —40 (-40) - m c remotely; use -box a m E .t.-, m —148 ( -100) ID L .- co ( V N 0 Q J, cs 7. N _. M co co co cf) ,- 0 CO 0 co I CO d' CO N- N Maximum process temperature in °F ( °C) ( (1) Temperature limits may be further restricted by hazardous area approvals. See pages 22 -28. (2) The temperature graphs shown here are for use only as a general guide. (3) When ambient temperature is below -40 °F ( -40 °C), a core processor or Model 2400S transmitter must be heated to bring its local ambient temperature to between -40 °F ( -40 °C) and +140 °F ( +60 °C). Long -term storage of electronics at ambient temperatures below -40 °F ( -40 °C) is not recommended. (4) The temperature limits shown apply only when the electronics are not covered (for example, by insulation). if the sensor case must be insulated, use extended mount electronics. Micro Motion ELITE Flow and Density Meters 3 • • Accuracy and repeatability Electronics option Model 2400S, Other MVD transmitter, enh. core processor std. core processor Mass and Liquid Accuracy (2) ±0.05% of rate )3))4)(5) ±0.10% of rate (5)(5) volume flow') Repeatability ±0.025% of rate ±0.05% of rate Gas Accuracy ±0.35% of rate ±0.35% of rate Repeatability ±0.20% of rate ±0.20% of rate Density (1)(8) Liquid Accuracy ±0.0002 g /cm ±0.0005 g /cm (±0.2 kg /m (±0.5 kg /m Repeatability ±0.0001 g /cm ±0.0002 g /cm ( ±0.1 kg /m (±0.2 kg /m Temperature Accuracy ±1 °C± 0.5% of reading ±1 °C± 0.5% of reading Repeatability ±0.2 °C ±0.2 °C lb/min kg /h Zero stability CMFS010M 0.000075 0.002 CMFS010H, P 0.00015 0.004 CMFS015M 0.00037 0.01 CMFS015H, P 0.00073 0.02 CMF010M, H 0.000075 0.002 CMF010P 0.00015 0.004 CMF025 0.001 0.027 CMF050 0.006 0.163 CMF100 0.025 0.680 CMF200 0.08 2.18 CMF300 0.25 6.80 CMF400 1.50 40.91 (1) Accuracy options vary by model. Models CMF010, CMFS010, CMFS015, sensors with Model 2200S transmitter, and all high - temperature models have fewer accuracy options. See Ordering information on page 55. (2) Stated flow accuracy includes the combined effects of repeatability, linearity, and hysteresis. All specifications for liquids are based on reference conditions of water at 68 to 77 °F (20 to 25 °C) and 15 to 30 psig (1 to 2 bar), unless otherwise noted. (3) When flow rate is less than zero stability / 0.0005, accuracy = ±[(zero stability / flow rate) x 1001% of rate, and repeatability = ±(%(zero stability /flow rate) x 100J %. (4) When ordered with the ±0.10% factory calibration option, accuracy on liquid = ±0.10% when flow rate .-?zero stability / 0.001. When flow rate < zero stability / 0.001, accuracy = ±[(zero stability / flow rate) x 100J% of rate and repeatability = ±( %(zero stability / flow rate) x 100J% of rate. (5) For cryogenic applications (below —100 °C), mass flow accuracy is ±0.35% of rate. (6) When flow rate is less than zero stability / 0.001, accuracy = ±((zero stability / flow rate) x 1001% of rate and repeatability = ±[ %(zero stability / flow rate) x 100]% of rate. (7) When flow rate is less than zero stability/ 0.0035, accuracy equals ±[(zero stability / flow rate) x 100]% of rate and repeatability equals ±[ %(zero stability /flow rate) x 1001% of rate. (8) Specifications for ±0.0002 g /cm ( ±0.2 kg /m density accuracy are based on reference conditions of water at 68 to 140 °F (20 to 60 °C) and 15 to 30 psig (1 to 2 bar). 4 Micro Motion ELITE' Flow and Density Meters • • Liquid flow performance Mass Volume Ib /min kg /h gal /min I/h bbl /h m /h Maximum flow rate CMFS010 4 108 0.5 108 CMFS015 12 330 1.5 330 CMF010 4 108 0.5 108 CMF025 80 2180 10 2180 CMF050 250 6800 30 6800 CMF100 1000 27,200 120 27,200 CMF200 3200 87,100 385 87,100 550 87 CMF300 10,000 272,000 1200 272,000 1700 272 CMF400 20,000 545,000 2400 545,000 3400 545 Typical accuracy, turndown, and pressure drop with CMF100 and 2400S or enhanced core processor The graph below is an example of the relationship between accuracy, turndown, and pressure drop when measuring the flow of water with a Model CMF100 sensor and Model 2400S transmitter or enhanced core processor. Actual pressure drop is dependent on process conditions. To determine accuracy, turndown, and pressure drop with your process variables, use the Micro Motion product selector, available at www.micromotion.com. 2.5 -4-- 100:1 1:1 2.0 i-.— 20:1 1.5 1 10:1 '-4— 2 :1 1.0 as 0.5 — 0.5 —1.0 — 1.5 — 2.0 — 2.5 ' f . . . r . . 0 10 20 30 40 50 60 70 80 90 100 Flow rate, % of maximum Turndown from maximum flow rate 500:1 100 :1 20:1 10:1 2:1 Accuracy ±% 1.25 0.25 0.05 0.05 0.05 Pressure drop psi —0 —0 0.2 0.7 13.5 bar —0 —0 0.01 0.05 0.93 (1) Specifications for volumetric flow rate are based on a process -fluid density of 1 g /cm (1000 kg /m For fluids with density other than 1 g /cm (1000 kg /m the volumetric flow rate equals the mass flow rate divided by the fluid's density. Micro Motion ELITE Flow and Density Meters 5 • • Gas flow performance When selecting sensors for gas applications, measurement accuracy is a function of fluid mass flow rate independent of operating temperature, pressure, or composition. However, pressure drop through the sensor is dependent upon operating temperature, pressure, and fluid composition. Therefore, when selecting a sensor for any particular gas application, it is highly recommended that each sensor be sized using the Micro Motion product selector, available at www.micromotion.com. Mass Volume lb/min kg /h SCFM Nm /h Flow rates that produce CMFS010 0.3 8 4 6 approximately 10 psi (0.68 bar) CMFS015 1 24 12 18 pressure drop on airm CMF010M, H 0.30 8 4 6 CMF010P 0.2 6 3 5 CMF025 4 110 60 90 CMF050 10 300 145 230 CMF100 50 1300 640 1000 CMF200 150 4000 2000 3100 CMF300 490 13,300 6500 10,300 CMF400 1250 34,000 16,600 26,250 Flow rates that produce CMFS010 1 30 30 45 approximately 50 psi (3.4 bar) CMFS015 3 90 90 130 pressure drop on natural gasP) CMF010M, H 1 30 30 45 CMF010P 0.9 25 20 35 CMF025 16 450 380 600 CMF050 40 1140 970 1530 CMF100 185 5000 4300 6700 CMF200 560 15,200 13,000 20,500 CMF300 1850 50,500 43,000 68,000 CMF400 4700 128,000 109,000 172,000 (1) Standard (SCFM) reference conditions are 14.7 psia and 68 °F. Normal (Nm /h) reference conditions are 1.013 bar and 0 °C. (2) Air at 68 °F (20 °C) and 100 psia (6.8 bar). (3) Natural gas with MW 16.675 at 68 °F (20 °C) and 500 psia (34.0 bar). 6 Micro Motion ELITE Flow and Density Meters 1 • • Gas flow performance continued Typical mass flow accuracy and pressure drop with CMF100 and transmitter with MVD technology Air at 68 °F (20 °C), static pressures as indicated on graph Inches psi bar H 1.5 0.9 • 0.8 100 psia 500 psia 1000 psia - 300 ii (7 bar) (35 bar) (70 bar) 10 0.7 • i° 1.0- a c 0.6 2 e • .a • ±i 0.5 - 200 ; v 3 o N R 0.4 . d O • 0.5 - 5 a` u 0.3 Q 100 0.2 0.1 • 0 ,0 0 0 lb/min 0 20 40 60 80 100 120 140 160 kg /h 0 1000 2000 3000 4000 Flow rate Natural gas (MW 16.675) at 68 °F (20 °C), static pressure as indicated on graph Inches psi bar H 1.5 0.9 0.8 300 °' 10 0.7 ` - 100 psia 500 psia 1000 psia 6 1.0 (7 bar) (35 bar) (70 bar) 0.6 o 0.5 - 200 3 u a i° 0.4 0.5- 5 a O 0.3 • a - 100 0.2 . 0.1 • 0- 0 0 -0 lb/min 0 20 40 60 80 100 120 140 160 kg /h 0 1000 2000 3000 4000 Flow rate Standard or Normal Volumetric Capability Standard and normal volumes are "quasi mass" flow units for any fixed composition fluid. Standard and normal volumes do not vary with operating pressure, temperature, or density. With knowledge of density at standard or normal conditions (available from reference sources), a Micro Motion meter can be configured to output in standard or normal volume units without the need for pressure, temperature, or density compensation. Contact your local sales representative for more information. Micro Motion ELITE Flow and Density Meters 7 • • Density range (liquid only) Range Up to 5 g /cm Up to 5000 kg /m Vibration limits Meets IEC 68.2.6, endurance sweep, 5 to 2000 Hz, 50 sweep cycles at 1.0 g Power consumption Meter with core processor 4 watts maximum Meter with Model 2400S transmitter 7 watts maximum Meter with Model 2200S transmitter Loop - powered, 0.8 watts maximum Meter with Model 1700/2700 transmitter Refer to transmitter documentation 8 Micro Motion ELITE Flow and Density Meters • • Pressure ratings PED compliance Sensors comply with council directive 97/23/EC of 29 May 1997 on Pressure Equipment Dual seal compliance CSA sensors comply with ANSI /ISA 12.27.01 -2003 requirements for process sealing between electrical systems and flammable or combustible process fluids Secondary Burst pressure containment ratingo 2 Housing rating 0) psig bar psig bar CMFS010 743 51 5 33 9 368 CMFS015 743 51 5339 368 CMF010 425 29 3042 209 CMF025 850 58 5480 377 CMF050 850 58 5286 364 CMF100 625 43 3299 227 CMF200 550 37 2786 192 CMF300 275 18 1568 108 CMF400 250 17 1556 107 (1) The housing of high- temperature models is rated for neither secondary containment nor burst pressure. (2) Secondary containment rating is based on the ASME B31.3 proof test. (3) Optional rupture disks for high - pressure CMF010P will burst if pressure inside sensor housing reaches 400 psig (27 bar). Micro Motion ELITE Flow and Density Meters 9 • 0 Pressure ratings continued Sensor pressure/temperature rating with ASME B16.5 F316/F316L weld neck flanges Models CMF010M through CMF400M; Models CMF200A through CMF400A; and Models CMFS010M and CMFS015M 1800 i ! , I , I , 1 1 1 1600 1500 CL900 . i 1500 1500 1500 I I I 1392 1400 129 ------i ' 1 441 0 I a600 1 1440 1 : • 3 ; ■ ' I 1213 1179 1200 1 - - -- ' -4- 1 - . i - 4- . _ - I 1240 ■ i ' 1120 S 1 000 i- •i•- - ,--" ; I i 1025 ; 13. 1 955 , i CL300 1 i i 800 72 ' 0 - - - -I- 720 i i 450 441 i I' II!I• 275 I also . 275 235 215 195 170 200 1 1 121 - I ; I i I I I 1 662 -400 -300 -200 -100 0 100 200 300 400 500 600 700 Temperature (°F) Models CMFS010P and CMFS015P 7000 1 i 6000 CL2500 6600 I 6000 1 1 ! 1 51 I i i 5000 - 60 ; i I • 1 1 4280 I I i , CL1500 1 S 4000 300 - 3600 th ; E I I 1 309 5 i 1 • 3000 : to 2570 In fr. 2160 CL900 1860 , 2000 r r" -,-- 1540 1 ; ; 1 : • 1000 1 , . : 1 —.1.- --4 0 -400 -300 -200 -100 0 100 200 300 400 Temperature (°F) 10 Micro Motion ELITE Flow and Density Meters • 110 Pressure ratings continued Model CMF400P 3300 2973 I also() I 2973 2973 3000 1 --4--- 2795 2700 i I i--- . I : . - i ' t , - 2,0 T 1 2160 CL900 ; ; 2160 4 I , : : 2100 r------r 1 i .1860 I 1 . ; 2 1800 - ' t I 1 1440 CL600 I , 1440 I o 1500 - 4 ! 1 1 I I 1120 zi 1200 F -- ; 900 'r- i -;-- I 4 i , 600 ! ----, i ,- I : •-] 0 it- -4- -400 -300 -200 -100 0 100 200 300 400 Temperature (°F) Sensor pressure/temperature rating with ASME B16.5 UNS N06022 weldneck flanges Models CMF400H and CMF400B . T I i ; 1 i.- 2400 ' - i - t" ! 2250 2250 I I I 2250 CL900 , i 2185 -.......--j 4 2200 r ------ 1 i 2095 - I 1 1 I : I I 1995 ! . 2000 t' : 11- ,--1 1 : i ! 1815 1 1 ; 1 1747 ' 1800 ! ■ ----15cto-- — .0 1395 1 i 1400 _ .. 1- E 1200 ; ..... i 'i 7 In I : ! tn 1 ' o 1000 ; CL300 750 ! i 800 75°- ,._ _±.. 750 730 700 _1 - 665 —" ' - " 600 I ! I l i , ! CL150 1 ' 1 1 • 400 290 --------- --------- - 260 230 I I i 9 '7---.- 200 170 140 121 200 ; i 4 1 0 662 -400 -300 -200 -100 0 100 200 300 400 500 600 700 Temperature (°F) Micro Motion ELITE' Flow and Density Meters 11 • • Pressure ratings continued Sensor pressure/temperature ratings with ASME B16.5 F304/F304L weldneck flanges Models CMFO1OL through CMF300L 800 , 720 . CL300 i 720 ! I 1 1 i 1 i I , I , 600 i-- - i -, I --I- 540 1 ! ! ! 1 ! 1 ! I 495 500 7 , i 4 _ ! . ta . , 1 : . : j F2 i 1 = ; i u) I CL150 1 1 , 300 275 1 I I 1 230 ; ; 205 I 190 i : ! ! 1 i ! i ' -J- i I t I i -400 -300 -200 -100 0 100 200 300 400 Temperature (°F) Sensor pressure/temperature rating with ASME B16.5 F316L/F316L wafer flanges Models CMF025M through CMF100M 1600 . i ; , , ......._........._ . 1 1440 ! i CL600 , , 14.40 4 i , i 1 1240 ! i . T — 1025 a 800 I , . ! i -i- t 151 1 1 , in 1 1 C1300 1 , , 4 720 ! 720 ii 3 i co i 560 2 : , . 275 I CL150 275 ■ i ■ 4 # 235 215 195 200 -1 -4 t 0 : 1 i : 1 -400 -300 -200 -100 0 100 200 300 400 Temperature (°F) 12 Micro Motion ELITE Flow and Density Meters • • Pressure ratings continued Sensor pressure/temperature rating with ASME B16.5 F304/F304L lap joint flanges Models CMF010H through CMF400H; Models CMF200B through CMF400B; Models CMFS010H and CMFS015H 800 . , 7 1 t I f 1 I i I 1 1 720 1 CL300 i , I i 1 720 I II 1 1 i 700 • I • i 1 i 1 1 600 1 i ; I ; 1 1 1 1 I I 1 495 I , = Si 1 ; ! --I— E ! ! i 1 ! u) !! cu50 E 300 275 = --i- ; .._. 275 - o. 1 i 1 no 1 i 1 1 1 205 121 1 1 1 1 1 1 1 I 1 1 I 1 662 ; -400 -300 -200 -100 0 100 200 300 400 500 600 700 Temperature (°F) Sensor pressure/temperature ratings with ASME B16.5 A105 lap joint flanges Model CMF400P 2400 — -r- , -- , • ; 1 i 2220 ; CL600 2220 1 2200 ! — ; 2035 1 1— ! --f- , 1 1965 2000 I I 1 1 i I 1800 ! . ,..[... _,.., 1 I 1600 -I- - , CL300 - ! 1 1 i 1400 i a) 1 1360 13 .= 1200 1265 al I , 1 1 g 1000 : i 1 i 0 : i 1 i i 1 600 h---- 1 ri i i 1 1 1 400 : 4- - .---- ---- i 1 200 i-- ,-- --I ! 1 i ! 0 ,-.- - -20 -100 0 100 200 300 400 Temperature (°F) Micro Motion ELITE Flow and Density Meters 13 • 0 Pressure limits continued Sensor pressure/temperature ratings with Tri-Clamp compatible 316L hygienic fittings Models CMFS010M and CMFS015M 1700 1 i I I 1600 ,- i--- ; -,,- 1500 i 1500 1500 1500 1 ; 15004 , t . ! 1 : . 1 392 • 1400 "-t ! 1 1 11 I ' i 1300 .;-- , ir I I • 1200 ! I " 1100 ; a 1 - I 4a ! I I ta 1 I a) I ! 1000 r 1 - o_ I I i 900 ja - t--- - 1 ; ! , , i , . , I I 1 800 I-- --1- . : I --- - 1 I , i ■ ; 700 - i* I I 600 ! i --i --I -400 -300 -200 -100 0 100 200 300 400 Temperature (°F) Models CMF010M through CMF300M 1700 i i 1 1 1 1600 ,4 - -1 1500 ' 2" , 1. 1-1/2" i 1500 1500 1500 1500 4 1- t 1 + 1 I ; 1 1 . 1392 i 1400 1450 CM F100M : 1" - 450 ------ 1450 - ■ 1300 ! , : ...;.J ; i 7) 1200 ! 1 L ; . a. . ' I m , . ' 1100 !--- = 1 - - - I - co i O 1000 i 2" 3" l000 1000 1000 ■- 1000 a. 1 I , # 1 — -----' t I 928 • ! ! 1 1 800 1 ...... 4- i I I 1 700 i 1 -,-- : - i i I 600 i k- ;. fr ---i -400 -300 -200 -100 0 100 200 300 400 Temperature (°F) 14 Micro Motion ELITE Flow and Density Meters 0 41110 Pressure ratings continued Sensor pressure/temperature ratings with VCO 316/3161 fittings Models CMF010M, CMFS010M, CMFS015M, CMF025M, and CMF050M 2000 1812 1 #4 ! 1812 1812 1812 1 1 1600 moo --------1- #8& #12 ".---- : --,- 1 1500 - 1500 ---- 1500 - 1 t 1 i • 1 . 1392 , 1400 ! 1 1 1200 I — I i , i ! 1 i Ttn ; , ! a , ; 0. 1000 i- ; 1 ; I : 1 e --1 m 1 cn : . 600 h ! ..:.— 1 i I i i , i 1 400 ---- i i — I I 1 0 -400 -300 -200 -100 0 100 200 300 400 Temperature (°F) Models CMF010P, CMFS010P, and CMFS015P . 1 , i 1 6000 #4 1 6000 6000 , 6000 ! 4: . 5569 : CM FS: #8 i 5000 49°° — . """-- 4900 4900 4900 -I 63 . a 4 : I ca. 1‘............ 1 0 .- = w 0 0 1 I A I i i 1 ! ---1 3500 ; -- 1 ■ I ; -400 -300 -200 -100 0 100 200 300 400 Temperature (°F) Micro Motion ELITE Flow and Density Meters 15 0 0 Pressure ratings — continued Sensor pressure/temperature ratings with VCO UNS N06022 fittings Models CMF010H, CMFS010H, and CMFS015H . . 6000 i 6000 6000 6000 6000 4 i 4 5900 4 , - i -- ---- i 5400 1 ; 4900 ! —4- ! i _ Es 4400 0 ; ,.. I = I ; 3900 : 1 i 0 , , ;• 1 ; I 3400 " !- i i 1 , i • i . -400 -300 -200 -100 0 100 200 300 400 Temperature (°F) Sensor pressure/temperature ratings with EN1092-1 and DIN F316/F316L weldneck flanges Models CMF010M through CMF400M; CMF200A through CMF400A; CMFS010M and CMFS015M 120 1 1 i 100.0 PN100 1 : 100.0 1000 . , . 100 ';-4 ff---. ! --i 1 90.9 1 ■ i 84.2 . 4 742 4 71.4 . . ., . . , - ■ I , . . . to . 41 60 I i i E , = i . in : 40.0 40.0 ,..0 4 " ' PN40 , , 1 40 :- . . 1 , . I . , . I i : . 20 -.-, 0 . i_. 1 -i-- I . . , 1 i I i • : ; . -i- .._ _, -240 -250 -200 -150 -100 -50 0 50 100 150 200 250 300 350 Temperature (°C) 16 Micro Motion ELITE Flow and Density Meters • 0 Pressure ratings continued Sensor pressure/temperature ratings with EN1092-1 and DIN F304/F304L weldneck flanges Models CMFO1OL through CMF300L 45 1 I 1 40.0 ;PN40 i 40.0 ; I I ; 40 ; 1 ; i I i I , i 1 34.4 J 1 1 I , ! 30.8 I ; rtS .12 30 27.8 1 I 1 i I 1 U) 1 : U) , ■_°) 25 , --,--. -- I I 1 i 1 i i i ; , 20 'f, . i ..._ 1 -4 -I i 1 , I ; ; 1 1 ; ' i 15 - ! 240 J,... ---4 ; 38 204 -250 -200 -150 -100 -50 0 50 100 150 200 250 Temperature (°C) Sensor pressure/temperature ratings with EN1092-1 UNS N06022 weldneck flanges Models CMF400H and CMF400B 180 I 1 , ; 7 i , I 160.0 PN 160 160.0 160.0 160.0 160.0 160.0 160.0 160.0 160 4 ; 4. • • $ 4 4 I , 140 r t ,I-- --i L 1 I i 1 1 - 1 120 H--- ±- - i -4- i 1 100.0 PN100 100.0 100.0 100.0 100.0 100.0 100.0 100.0 . C' 100 S 4 4 t • t t co 1 ; .ra 1 1 I i 1 I 1 E 80 = an to 122 60 1 i -4 . a. 4 s s 4 40.0 • PN40 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40 ', 4 i • i 4 4 • • 4 4 , , 1 20 ..,t Ht - --, 0 I 1 1 ! _1... -240 -250 -200 -150 -100 -50 0 50 100 150 200 250 300 350 Temperature (°C) Micro Motion ELITE' Flow and Density Meters 17 • • Pressure ratings continued Sensor pressure/temperature ratings with JIS 2220 F316/F316L weldneck flanges Models CMF010M through CMF400M; CMF200A through CMF400A; CMF400P; CMFS010P and CMFS015P 40 ! , . 1 i ■ . 34.0 ; 20k i i 34.0 : ; 1 35 , i ; , ! , ' ' - 30.3 i ■ i 1-- - -4-- ..; -." -- 29 -- . • -- 1 i , 1 ` 1 ! 1 I 26.9 I : 1 ! , 1 i ' i i ; 1 _..,... --1- ---i I" ' 1 ; 1 ! ; 1 mi 1 ; 1 1 1 1 0 1 ..., e i : i I V) . ■ ; .0 10 1 I 1 12 ' .4 c• • 15 14 . -t-- i 1 14.0 1 . . 14 0,) 1 ; i 11.3 10.0 - 1 -4 i -1-- 1 1 ; 1 : - ; I 1 . . - i 1 1 1 1 1 1 5 -1 - ! . f 1 ; : - + i ; ; 1 , i ; ! 1 i i ; ---'-- -i— --;-. ; 240 -250 -200 -150 -100 -50 0 50 100 150 200 250 300 350 Temperature (°C) Sensor pressure/temperature ratings with DIN 316/316L wafer flanges Models CMF025M through CMF100M , 120; 100.0 PN100 100.0 100.0 ■ 100 80 I- • , • : 969 1 ; 1 i 1 i 1 ; I a 60 s- 1 3 1 1 1 1 in ; 1 a cu 40.0 ; PN40 . ,' 40.0 1 40.0 : 40 - , • I _ 36 . 33.5 ' 1 . ' . I i . i . 1 ; , 20 ! I - _..., , .-. I 1 ; 0 , I : ; ; ! i i 1 -1-;-; ; -4— ..._a_ -240 204 -250 -200 -150 -100 -50 0 50 100 150 200 250 Temperature (°C) 18 Micro Motion ELITE Flow and Density Meters S • Pressure ratings continued Sensor pressure/temperature ratings with JIS 2220 316/316L wafer flanges Models CMF025M through CMF100M 70 — -_ ._ _ _— _.....- . _ r ._.. _..__ 1 51.0 I 30k 51.0 I 51.0 50 ,---'--; -t- • as.s 1 i co 34.0 ' 20k 34,0 34,0 1 ± i ...............4 ................4............ 3 1.5 CT) 30 a 20 i II:ii i i.x:iiii:iiiiii1x f iiTT:ffiz: 14.0 I 10k 14.0 14.0 . • 2.3 , t s -240 - .._._...___y _.204 -250 -200 -150 -100 -50 0 50 100 150 200 250 Temperature ( °C) Sensor pressure /temperature ratings with EN1092 -1 and DIN F304/F304L lap joint flanges Models CMF010H through CMF300H; CMF200B and CMF300B; CMFS010H and CMFS015H 45 - I —_ 1 . , -- --- _ 40.0 PN40 40.0 40 I I 34.4 I 35 30.8 ... . 1 26.0 24.1 25 L L ____-_ z.._._..._......_.__. ....._.__�_........- ..__�.._.__ ..___.,.. _._ _____=.. -_. _ _ _ ..,.._.._ .,_,_.. -_ _._._. —_ .- 23.0 ■ a co i } I I N N N r i L ! 15 ' i 1 I I i • i 0 �._ -240 , 38 , -250 -200 -150 -100 -50 0 50 100 150 200 250 300 350 Temperature ( °C) Micro Motion ELITE Flow and Density Meters 19 • 0 Pressure ratings continued Sensor pressure/temperature ratings with JIS 2220 F304/F304L lap joint flanges Models CMF010H through CMF300H•, CMF200B and CMF300B; CMFS010H and CMFS015H 16 , i 1 i . 1 : 14.0 10k 1 1 14.0 14.0 . i 1 12.4 ■ i ! - : 1 ; 4— " 1 . ; 4... i" - ---1 1 ---i- - 1 ; 1 I 1 1 I .12 H I I i 8 ;-± -4 -4— -4-- -1 -÷- i --i 1 , 1 ... g i , to • , ----;- --4- - --- 1 , , ! I 1 1 . 4 ; I : -I- ! ; 1 1 i I ; 1 1 -c , . 1 2 I ; 1 1 i 0 •-40 -1 ' ; ■ ! -250 -200 -150 -100 -50 0 50 100 150 200 250 300 350 Temperature (C) Sensor pressure/temperature ratings with 1S02852 Clamp 316L hygienic fittings Models CMFS010M and CMFS015M if 125.0 1 i i 125.0 125.0 124.8 120 H ; — : 1 - ! 1 , I i i - [ I I 110 I ca ; ; I c... , = co g; 100 t- 1......._ i -, 95 H 1- - . 1 1 . 1 i . i i 1 90 ; -1--- i _ _ .; ,„ ., 1 ' ; ; 1 -- I 85 : . i 1 : i f 80 ----1-- , 1 : L -240 204 -250 -200 -150 -100 -50 0 50 100 150 200 250 Temperature (°C) 20 Micro Motion ELITE Flow and Density Meters • • Environmental effects Process temperature effect Process temperature effect is defined as: • For mass flow measurement, the worst -case zero offset due to process fluid temperature change away from the zeroing temperature. • For density measurement, the maximum measurement offset due to process fluid temperature change away from the density calibration temperature. Process temperature effect % of maximum flow rate per °C density accuracy per °C g /cm kg /m CMFS010, CMFS015, CMF010, CMF025, ±0.0002 ±0.000015 ±0.015 CMF050, and CMF100 CMF200 ±0.0005 ±0.000015 ±0.015 CMF300 ±0.0005 ±0.000015 ±0.015 CMF400 ±0.0007 ±0.000015 ±0.015 Pressure effect Pressure effect is defined as the change in sensor flow and density sensitivity due to process pressure change away from the calibration pressure. Pressure effect can be corrected. Pressure effect on flow accuracy % of rate per psi % of rate per bar liquid gas liquid gas CMFS010 None None None None CMFS015 None None None None CMF010 None None None None CMF025 None None None None CMF050 None None None None CMF100 — 0.0002 None —0.003 None CMF200 — 0.0008 — 0.0004 —0.012 —0.006 CMF300 — 0.0006 — 0.0003 —0.009 — 0.0045 CMF400 — 0.0011 — 0.0011 —0.016 —0.016 Pressure effect on density accuracy g /cm per psi kg /m per bar CMFS010 None None CMFS015 None None CMF010 None None CMF025 0.000004 0.058 CMF050 — 0.000002 —0.029 CMF100 — 0.000006 —0.087 CMF200 - 0.000001 — 0.0145 CMF300 — 0.0000002 — 0.0029 CMF400 — 0.00001 —0.145 (1) For —100 °C and above. Micro Motion ELITE Flow and Density Meters 21 • • Hazardous area classifications UL'' All models with core processor Ambient temperature: —40 to +104 °F ( -40 to +40 °C) Class I, Div. 1, Groups C and D Class I, Div. 2, Groups A, B, C, and D Class II, Div.1, Groups E, F, and G All models with junction box Ambient temperature: +104 °F ( +40 °C) maximum Class I, Div. 1, Groups C and D Class I, Div. 2, Groups A, B, C, and D Class II, Div.1, Groups E, F, and G CSA and CSA C -US All models with Model 2400S transmitter Ambient temperature: —40 to +140 °F (-40 to +60 °C) Class I, Div. 2, Groups A, B, C and D Class II, Div. 2, Groups F and G Models CMFS010 and CMFS015 with Ambient temperature: —13 to +140 °F ( -25 to +60 °C) FMT transmitter Class I, Div. 2, Groups A, B, C and D Class II, Div. 2, Groups F and G All models with core processor Ambient temperature: —40 to +140 °F (-40 to +60 °C) or Model 2200S transmitter Class I, Div. 1, Groups C and D Class I, Div. 2, Groups A, B, C, and D Class II, Div.1, Groups E, F, and G All models with junction box Ambient temperature: +140 °F ( +60 °C) maximum Class I, Div. 1, Groups C and D Class I, Div. 2, Groups A, B, C, and D Class II, Div.1, Groups E, F, and G NEPSI All models with Model 2400S transmitter Ex nA II T1 —T5, DIP A22 To T1 —T5 Models CMF010, CMF025, CMF050, CMF100, Ex ib IIC T1 —To DIP A22 To T1—To CMFS010, and CMFS015 with core processor or junction box Models CMF200, CMF300, and CMF400 Ex ib IIB /IIC T1 —To DIP A22 T° T1—To with core processor or junction box (1) The following products are not available with UL approval; sensors with enhanced core processor, Model 2400S transmitter, FMT transmitter, or Model 2200S transmitter; high - temperature sensors; extreme high- temperature sensors. (2) The following products are available only with CSA C -US approval (i.e., not CSA): sensors with enhanced core processor or Model 2400S transmitter; high- temperature sensors; extreme high- temperature sensors. (3) For ambient and process temperature limits, refer to the temperature graphs on pages 24-27. 22 Micro Motion ELITE Flow and Density Meters • • Hazardous area classifications continued ATEX All models with Model 2400S transmitter; C E 0 II 3G Ex nA IIC T1 -T5 Gc Models CMFS010 and CMFS015 with FMT transmitter II 3D Ex tc IIIC To °C Dc IP66 Models CMFS010, CMFS015, CMF010, CMF025, C E 0575 Ex II 2G Ex ib IIC T1 -T4 CMF050, and CMF100 with Model 2200S transmitter II 2D Ex ibD 21 T° °C E Ex II 3G Ex nA IIC T1 -T4 Gc II 3D Ex tc IIIC To °C Dc IP66 Models CMF200, CMF300, and CMF400 with ( E 0575 Ex 112G Ex ib IIB /IIC T1 -T4 Model 2200S transmitter II 2D Ex ibD 21 To °C E Fx II 3G Ex nA IIC T1 -T4 Gc II 3D Ex tc IIIC To °C Dc IP66 Models CMFS010 and CMFS015 (E 0575 Ex II 2G Ex ib IIC T1 -To with core processor or junction box II 2D Ex tD A21 IP65 To °C Models CMF010, CMF025, CMF050, and CMF100, ( E 0575 Ex I I 2G Ex ib IIC T1 -To Gb with core processor or junction box II 2D Ex ib IIIC To °C Db IP66 Models CMF200, CMF300, and CMF400 C E 0575 I:x II 2G Ex ib IIB /IIC T1 -To Gb with core processor or junction box II 2D Ex ib IIIC To °C Db IP66 IECEx All models with Model 2400S transmitter; Ex nA IIC T1 -T5 Gc Models CMFS010 and CMFS015 with FMT transmitter Models CMF010, CMF025, CMF050, CMF100, Ex ib IIC T1 -Tw Gb CMFS010, and CMFS015 with core processor or junction box Models CMF200, CMF300, and CMF400 Ex ib IIB /IIC T1 -T Gb with core processor or junction box Models CMFS010, CMFS015, CMF010, CMF025, Ex ib IIC T1 -T4 CMF050, and CMF100 with Model 2200S transmitter Ex nA IIC T1 -T4 Gc Model CMF200, CMF300, and CMF400 with Ex ib IIB /IIC T1 -T4 Model 2200S transmitter Ex nA IIC T1 -T4 Gc (1) For ambient and process temperature limits, refer to the temperature graphs on pages 24-27. Micro Motion ELITE Flow and Density Meters 23 • • Hazardous area classifications continued Model CMF010, CMF025, or CMF050 with junction box connected to MVD transmitter 90 - 80 - 70 o 60 - 55 a 50 - 45 N 40 30 20 - E 10 - T6 T5 T4 T3 T1 -T2 co • 0 - co • -10 - -240 I I 30 1 45 I I I 1 145 I 1 -240 0 20 40 60 80 100 120 140 160 180 204 220 Sensor fluid temp ( °C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T6:T 80 °C, T5:T 95 °C, T4:T 130 °C, T3:T 195 °C, T2 to T1:T 254 °C. The minimum ambient and process fluid temperature allowed for dust is -40 °C. The use of the sensor at an ambient temperature higher than +55 °C is possible, provided that the ambient temperature does not exceed the maximum temperature of the medium taking into account the temperature classification and the maximum operating temperature of the sensor. Ambient temperature range Ta -240 °C to +55 °C Model CMF100 with junction box connected to MVD transmitter 90 - 80 - _ 70 - U 60 55 a 50 - 45 g 40 - c 30 • 20 - m 10 - T6 T5 T4 T3 T1 -T2 • 0 - 2 -10 - -60 30 145 1 1145 I I -60 0 20 40 60 80 100 120 140 160 180 204 220 Sensor fluid temp ( °C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T6:T 80 °C, T5:T 95 °C, T4:T 130 °C, T3:T 195 °C, T2 to T1:T 254 °C. The minimum ambient and process fluid temperature allowed for dust is -40 °C. The use of the sensor at an ambient temperature higher than +55 °C is possible, provided that the ambient temperature does not exceed the maximum temperature of the medium taking into account the temperature classification and the maximum operating temperature of the sensor. Ambient temperature range Ta -60 °C to +55 °C 24 Micro Motion ELITE" Flow and Density Meters • • Hazardous area classifications continued Model CMF200 or CMF300 with junction box connected to MVD transmitter 90 - 80 70 — U 60 55 - °- 50 E 45 2 40 — 30 20 — m 10 — T6 T5 T4 T3 T1 —T2 x m 0 - - 10 — — 55 30 145 I I 1 1145 I I l —55 0 20 40 60 80 100 120 140 160 180 204 220 Sensor fluid temp ( °C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T6:T 80 °C, T5:T 95 °C, T4:T 130 °C, T3:T 195 °C, T2 to T1:T 254° C. The minimum ambient and process fluid temperature allowed for dust is —40 °C. The use of the sensor at an ambient temperature higher than +55 °C is possible, provided that the ambient temperature does not exceed the maximum temperature of the medium taking into account the temperature classification and the maximum operating temperature of the sensor. Ambient temperature range Ta —55 °C to +55 °C Model CMF400 with junction box connected to MVD transmitter 90 — 80 — 70 - ( j 60 50 — a E 40 - w 30 20 T6 T5 T4 T3 T1 —T2 :0 to — ® 0— x a s -10 • -20 -30 - -40 - -66 I I I I I 1 1 I I 1 I -68 -40 -20 0 20 40 50 60 80 100 120 140 160 180 204 220 Sensor fluid temp ( °C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T6:T 80 °C, T5:T 95 °C, T4:T 130 °C, T3:T 195 °C, T2: to T1:T 234 °C. The minimum ambient and process fluid temperature allowed for dust is —40 °C. The use of the sensor at an ambient temperature higher than +60 °C is possible, provided that the ambient temperature does not exceed the maximum temperature of the medium taking into account the temperature classification and the maximum operating temperature of the sensor. Ambient temperature range Ta —68 °C to +60 °C (1) Refer to page 26 for `T" rating graph for high - temperature models with junction box. Micro Motion ELITE" Flow and Density Meters 25 • • Hazardous area classifications continued High- temperature models CMF200A, CMF200B, CMF300A, CMF300B, CMF400A, or CMF400B with junction box connected to MVD transmitter 90 - 80 - 70 - U 60 55 n 50 - d 40 - 30 - iv 20 - la E 10 - T6 T5 T4 T3 T2 T1 co 0 - m -10- 2 -20- - 30 - 50 , i r '67 'a2 ' 117 • 162 277 I 350' -50 -20 0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 340 360 Sensor fluid temp ( °C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T6:T 80 °C, T5:T 95 °C, T4:T 130 °C, T3:T 195 °C, T2:T 290 °C, T1:T 363 °C. The minimum ambient and process fluid temperature allowed for dust is -40 °C. The use of the sensor at an ambient temperature higher than +55 °C is possible, provided that the ambient temperature does not exceed the maximum temperature of the medium taking into account the temperature classification and the maximum operating temperature of the sensor. Ambient temperature range Ta -50 °C to +55 °C Models CMF010, CMF025, CMF050, CMF100, CMF200 or CMF300 with core processor 80 - 70 60 50 E i 40 30 - 15 20 - m 10 T5 T4 T3 T1 -T2 x m 0 - - 1 0 - 40 I 1 45 53 1 I I 1145 I I I -40 0 20 40 60 80 100 120 140 160 180 204 220 Sensor fluid temp ( °C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T5:T 95 °C, T4:T 130 °C, T3:T 195 °C, T2 to T1:T 254 °C. Ambient temperature range Ta -40 °C to +60 °C (1) Refer to page 27 for "T" rating graph for high - temperature models with core processor. 26 Micro Motion ELITE Flow and Density Meters • • Hazardous area classifications continued Model CMF400 with core processor 80 - 70 - 60 50 - U 40 46. E 3 0 - 2 0 - T 5 T4 T3 T1 -T2 :o E 0 - m m x -10 • -20 - -30 - -40 I 1 I 53 1 65 I I I 165 -40 -20 0 20 40 60 80 100 120 140 160 180 204 220 Sensor fluid temp ( ° C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T5:T 95 °C, T4:T 130 °C, T3:T 195 °C, T2 to T1:T 234 °C. Ambient temperature range Ta -40 °C to +60 °C High- temperature models CMF200A, CMF200B, CMF300A, CMF300B, CMF400A, or CMF400B with core processor or Model 1700/2700 transmitter 90 - 80 - 70 - U 055 ° n 50 - aEi 40 - 30 - w 20 - L. E 10 - T5 T4 T3 T2 T1 as 0 - • -10- -20- -30 -50 X82 ' 117 '182 ' ' 277 350 - - 0 20 40 60 80 100 120 14.0 160 180 200 220 240 260 280 300 320 340 360 Sensor fluid temp ( ° C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T5:T 95 °C, T4:T 130 °C, T3:T 195 °C, T2: T 290 °C, T1:T 363 °C. The minimum ambient and process fluid temperature allowed for dust is -40 °C. Since the electronics are mounted approx. 1 meter away from the sensor by means of a flexible stainless steel hose, the use of the sensor at an ambient temperature higher than +55 °C is possible, provided that the ambient temperature does not exceed the maximum temperature of the medium taking into account the temperature classification and the maximum operating temperature of the sensor. Ambient temperature range Ta -50 °C to +55 °C Micro Motion ELITE Flow and Density Meters 27 • • Hazardous area classifications continued Models CMFS010 or CMFS015 with core processor 90 - 80 - _ 70 - U 60 - 55 50 46 - °-' 40 - a 30 - E 20 - x 10 - T5 T4 T3 2 -T 1 as 2 0 - - 10 - - 40 92 1 103 1 127 I 1 192 -40 0 20 40 60 80 100 120 140 160 180 204 220 Sensor fluid temp ( °C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T5:T 95 °C, T4:T 130 °C, T3:T 195 °C, T2 to T1:T 207 °C. The minimum ambient and process fluid temperature allowed for dust is —40 °C. Ambient temperature range Ta —40 °C to +55 °C Models CMF010, CMF025, CMF050, CMF100, CMF200, and CMF300 with Model 2200S transmitter 80 - V 70 - a 60 a) 50 46 C 40 - ▪ 30 - S 20 - a 10 - T4 T3 T1 -T2 • 0 - -10 - -40 I I 53 I I 1 1 145 1 1 -40 0 20 40 60 80 100 120 140 160 180 204 220 Sensor fluid temp ( °C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T4:T 130 °C, T3:T 195 °C, T2 to T1:T 254 °C. Ambient temperature range Ta —40 °C to +60 °C 28 Micro Motion ELITE Flow and Density Meters • Hazardous area classifications continued Models CMFS010 and CMFS015 with Model 2200S transmitter 80 - _ 70 - U 60 I 504i- co 40- 30 - n 20 - m 0 _ T4 T3 .-T1 -T2 m 0 - -10 - -40 1 so I I 127 1 192 -40 0 20 40 60 80 100 120 140 160 180 204 220 Sensor fluid temp ( ° C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T4:T 130 °C, T3:T 195 °C, T2 to T1:T 207 °C. Ambient temperature range Ta -40 °C to +60 °C Models CMF400 with Model 2200S transmitter 80 - 70 - 60 U 50 a 40 - E a; 30 - • 20 - - E 10 T4 T3 T1 - T2 m x 0 - m -10- -20 - - 30 - - 40 1 53 I 1165 1 -40 -20 0 20 40 60 80 100 120 140 160 180 204 220 Sensor fluid temp ( ° C) Use the above graph to determine the temperature class for a given fluid and ambient temperature. The maximum surface temperature for dust is as follows: T4:T 130 °C, T3:T 195 °C, T2 to T1:T 234 °C Ambient temperature range Ta -40 °C to +60 °C Micro Motion ELITE Flow and Density Meters 29 • • Materials of construction Wetted parts° 304L or 316L stainless steel; or Nickel Alloy C22 (N06022) Housing 304L stainless steelo Junction box 300 - series stainless steeP or polyurethane - painted aluminum; NEMA 4X (IP66) Core processor 300 - series stainless steel or polyurethane - painted aluminum; NEMA 4X (IP66) Model 2400S transmitter Polyurethane - painted aluminum or 316L stainless steel; NEMA 4X (IP66) Model 2200S transmitter Polyurethane - painted aluminum or 316L stainless steel; NEMA 4X (IP66167) (1) General corrosion guides do not account for cyclical stress, and therefore should not be relied upon when choosing a wetted material for your Micro Motion sensor. Please refer to the Micro Motion corrosion guide for proper material compatibility information. (2) The outer flange ring on lap joint type flanges is non - wetted and is 304L stainless steel. Consult factory for other materials. (3) Models CMF010P, CMFS010P, CMFS015P, and CMF400P have nickel alloy tubes and stainless steel fittings. Material compatibility is never better than 316L stainless steel. Refer to the Micro Motion Corrosion Guide for the Micro Motion policy on fixed bi- metallic sensor capability. (4) 316L stainless steel is available. Weight Weights provided are the weight of the flowmeter with 150 lb weld neck raised face flanges. With core processor, Model 2400S,or Model 2200S With junction box transmitter' With FMT transmitter lb kg lb kg lb kg CMFS010 — — 9 4 12 5 CMFS015 — — 9 4 12 5 CMF010 14 7 19 9 — — CMF025 8 4 13 6 — — CMF050 12 6 17 8 — — CMF100 29 13 34 16 — — CMF200 63 29 68 31 — — CMF300 165 75 170 77 — — CMF400 441 200 446 202 — — (1) Weight stated for sensor with aluminum core processor. Add 4 lb (2 kg) for stainless steel core processor or stainless steel Model 2400S transmitter. 30 Micro Motion ELITE Flow and Density Meters 0 • Dimensions Models CMFS010 and CMFS015 with Model 2200S, Model 2400S, or enhanced core processor Dimensions in inches (mm) Flow y 2 . 2 9/16 \. �� 0' 2 �_— ^- 21/16 31/4 (66) ' fi e.• (52) (83) —' - o Model 2400S or — I 1 u`i'i enhanced core %i ce 13 1/2** processor: � ;I I��l ` � (342) 2 x 1/2 " -14 NPT female (f or M20 x 1.5 female � \ �� // . •'� \ �ll I Model 2200S: o � �� • � i� �� ul 8 1/4 "' 01 1/4 1 x 1/2" -14 NPT female 'N " Optional 1N (32) 209 or M20 x 1.5 female '\ female NPT ( ) e purge plug MIMI �7..E IMO �� . Y 201 alrk it ,� ,�, , '• �� Ida. (� Pl at ■la 11110 � 11 1 11'1slmi■ 1 11 z z�J ■I1IqI1 f 1 �Illslr C II 1111 ...J (19) i 3/4 v I (19) 4 7/16 11111 �Vi/ (113) 1 1 1 1 A 1111 2 3/16 2 1/8 8 5/8 (56) (54) (219) 3 Dim. A (76) face -to -face f1/8 (3) 7.20 Flange detail (183) IDim, B !�� '111 111 � � / 111 1 ■_ _. 11 u �_ -emu -......i. ( ,N, 2 Mil THUM adapter detail Dim. A face -to -face ±1/8 (3) For dimensions A and B, see fittings options on pages 42 -43. *" Electronics with painted aluminum housing shown. For stainless steel housing, add 0.40 inches (10 mm). No. of Flow tube ID Model flow tubes inches (mm) CMFS010 2 0.07 (1.8) CMFS015 2 0.11 (2.9) Micro Motion ELITE Flow and Density Meters 31 • • Dimensions continued Models CMFS010 and CMFS015 with Filling Mass Transmitter Dimensions in inches (mm) 2 50) Flow in 3/16 (5) 3 • 1/2 8 1/2 1/4 16) M12 flush type (13) (216) (6) I,4 plug male �' PROFIBUS -DP or t " III' blank plug BM � M12 flush type PZ: i plug female kW- /% 75/8 _►:� (194) IIMM 5 /8 (102) (137) 4 11/16 /1 �� (119) x& } ® ® 1 I _ _ 1'_ 2 e 0 3 1 —t 111 1■ �I I ■l = _ ' (88.9 ) ®® 1 I l 47/16 (113) I + 2 1/8 (54) 12 5/8 ±1/8 (397 ±3) ^ Flange detail I .411=1" t l i_I i1 i1,' ,,II Dim. B II I \ii.....1 Dim. A face -to -face ±1/8 (3) For dimensions A and B, see fittings options on pages 42 -43. No. of Flow tube ID Model flow tubes inches (mm) CMFS010 2 0.07 (1.8) CMFS015 2 0.11 (2.9) 32 Micro Motion ELITE Flow and Density Meters • • Dimensions continued Model CMF010 Dimensions in inches (mm) Side view with Flow it♦ rupture disk 2 13/16 2 x (71) 2 0 1 9/16 4 3/8 Optional 2 x 1/2 " -14 female purge I (40) r (112) — ' plug fitting r sa �� _ 1:(110: ■ �� ■ C��1�� ik / �� Optional rupture II 1 13/16 disks (46) Dim. A face -to -face Flange detail 11/8 (3) r Dim. A face -to -face 49 /16 1 2 x 5/16 ) dril„ (116) (59) 71/8 Dim. 913 i OM -r=1.= -2 1 thru (180) r 3 3/8 (86) 9 (229) * For dimensions A and B, see fittings options on pages 44-45. ** Dimensions for each electronics option are shown on page 37. No of Flow tube ID Model flow tubes inches Orin) CMF010 1 0.11 (2.9) Micro Motion ELITE Flow and Density Meters 33 • • Dimensions continued Models CMF025, CMF050, and CMF100 Dimensions in / (mm) Flow y I 2x Dim. J Dim. C Optional 2 x 1/7' -14 female purge plug fitting a ;: Dim. H \Oa j MT P Dim. D 1 Dim. E Dim. G Dim. A face -to -face Wafer detail +1/8 (3) .-1 Dim. OB la - I ,_1400 :l+ Union detail Dim. A face -to -face ±1/8 (3) 2x13/4 ` (45) I 1/2 " -14 NPT female I 1 1 �T� III Flange detail Dim. A face -to -face ±1/8 (3) Dim. 0 B ' m r,�: - � ,�.�1il No. of War Dimensions in inches (mm) Model flow tubes Flow tube ID C 0 ' E G , H , - J CMF025 2 0.21 2 13/16 8 1/4 10 1 5/8 3 5/16 2 1/4 (5.2) (72) (209) (255) (41) (85) (58) CMF050 2 0.35 5 11 1/16 14 5/16 2 4 3/8 2 1/2 (8.8) (126) (280) (364) (51) (111) (63) CMF100 2 0.65 5 15/16 15 15/16 21 1/2 3 9/16 5 3/8 3 5/16 (16) (150) (405) (546) (91) (136) (83) (1) For dimensions A and B, see fittings tables on pages 45 -49. (2) Dimensions for each electronics option are shown on page 37. 34 Micro Motion ELITE Flow and Density Meters • • Dimensions continued Models CMF200 and CMF300 Dimensions in inches (mm) Flow y Dim. A face -to -face ±1/8 (3) 1 ri Dim 0I Ii 1i' " iii lit I � -- I ' I 1 � 0 01 . : ��1 _ - Dim. H /� Dim. D Optional 2 • 1/2 " -14 female purge plug fitting i tillit 2 • Dim. J — Dim. G f Dim. C Dim. E Dimensions in inches (mm) ' No of . Model flow tubes Flow tube ID C CMF200 2 1.1 14 28 5/8 19 9/16 5 9/16 11 7/8 4 5/16 (27) (356) (727) (497) (142) (302) (110) CMF300 2 1.8 22 38 7/16 30 3/16 8 3/16 13 7/8 5 5/8 (45) (559) (977) (767) (209) (352) (143) (1) For dimensions A and B, see fittings tables on pages 50-53. (2) Dimensions for each electronics option are shown on page 37. Micro Motion ELITE Flow and Density Meters 35 • • Dimensions continued Model CMF400 Dimensions in inches (mm) Flow Dim. A face -to -face ±1/8 (3) Dim.O� J �� - - - - -- 111 1III 1 1 12 3/8 (314) 17 3/8 (441) 38 1/4 \\ / (971) \ I / Optional 2.1 " -11 1/2 female purge plug fitting 2x67/16 22 (163) 10 3/4 (559) (274) 32 3/4 (832) * For dimensions A and B, see fittings options on pages 53-54. ** Dimensions for each electronics option are shown on page 37. No. of Flow tube ID Model flow tubes inches (mm) CMF400 2 2.9 (73) 36 Micro Motion ELITE Flow and Density Meters 0 • Dimensions continued Electronics detail for Models CMF010, CMF025, CMF050, CMF100, CMF200, CMF300, and CMF400 Enhanced core processor, Model 2400S, or Model 2200S with painted aluminum housing Flange center Dimensions in inches (mm) ' - ._._._. Model F M P _ S T 2 x I I 1/2 " -14 NPT or CMF010 513/16 (147) 3 7/8 (98) 9 5/16 (236) 71/8 (180) 121/2 (318) M20x1.5 female 1 F r., I CMF025 7 7/16 (188) 313/16 (97) 9 5/16 (236) 71/16 (179) 121/2 (318) "0 ,,,._., -- /10 CMF050 10 1/16 (255) 4 1/16 (103) 97/16(240) 75/16(185) 1211/16(322) O O �I`•' ,• S � � I tit ® _ � i r CMF 100 141/8 (360) 4 3/4 (121) 101/8 (257) 8 (204) 133/8 (340) // 13/16 / / CMF200 6 7/8 (175) 5 7/8 (150) 11 1/4 (286) 91/8 (232) 14112 (368) l I M ( 23 ) P i CMF300 9 3/8 (238) 7 3/16 (183) 12 5/8 (320) 101/2 (266) 15 7/8 (403) l 1 3/16 (29) 1 3/16 (29) CMF400 12 3/8 (314) 8 7/16 (215) 13 7/8 (352) 11 11/16 (297) 171/16 (434) I I f- S �i T —�i Enhanced core processor, Model 2400S, or Model 2200S Flange center with stainless steel housing I Dimensions,iri inches (mm) 2 x I Model F M P S _ T 1/2"-14 NPT or M20x1.5 female F CMF010 513/16 (147) 41/16 (103) 9 5/16 (236) 7 9/16 (192) 1213/16 (325) CMF025 7 7/16 (188) 41/16 (103) 9 5116 (236) 7 9/16 (192) 1213/16 (325) . , 4J An= Y `∎J �i� = ��! r o r r CMFO50 101/16 (255) 4 (102) 9 3/16 (234) 7 9116 (192) 12 3/4 (324) 1 3/16 miaow � NE � CMF100 14 3/16 (360) 4 7/8 (124) 101/8 (257) 8 3/8 (213) 135/8 (346) - I M ( P CMF200 6 718 (175) 5 3/4 (147) 11(280) 9 7/16 (239) 14 5/8 (372) j 1 3/16 (29) 1 3/16 (29) I CMF300 9 3/8 (238) 71/4 (183) 12 7/16 (316) 10 3/4 (273) 16 (406) I j CMF400 12 3/8 (314) 81/2 (216) 133/4 (349) 121/16 (306) 171/4 (439) S --I T 1 Model 2200S with THUM adapter Flange center Dimensions in inches (rnnl) . " � I Model I r CMF010 5 13/16 (147) 5 3/16 (132) 7 9/16 (192) I I 7.20 CMF025 7 7/16 (188) 5 3/16 (132) 7 9/16 (192) (183) CMF050 10 1/16 (255) 5 1/8 (130) 7 9/16 (192) j F CMF100 14 3/16 (360) 6 (152) 8 3/8 (213) V. _ { II' ` CMF200 6 7/8 (175) 6 7/8 (175) 9 7/16 (239) CO '� !II, CMF300 9 3/8 (238) 8 5/16 (212) 10 3/4 (273) / .4 *>/ 1 + f, ll� i ll II I` 2 CMF400 12 3/8 (314) 9 5/8 (245) 12 1/16 (306) (51) I I I 1/2 " -14 NPT l female P —. I S I Micro Motion ELITE Flow and Density Meters 37 S • Dimensions continued Electronics detail for Models CMF010, CMF025, CMF050, CMF100, CMF200, CMF300, and CMF400 Standard core processor Flange center ' Dimensions in inches (mm) - ! Model F M S ! CMF010 8 7/16 (214) 2 7/8 (73) 4 9/16 (116) CMF025 10 1/16 (255) 2 15/16 (75) 4 11/16 (119) — F CMF050 12 11/16 (322) 3 1/16 (77) 4 3/4 (121) ilk ily CMF100 16 13/16 (426) 3 13/16 (96) 5 1/2 (139) li CMF200 9 1/2 (241) 4 13/16 (122) 6 1/2 (165) /t' ! CMF300 11 15/16 (303) 6 1/8 (155) 7 13/16 (199) r I- -i M CMF400 15 (380) 7 3/8 (188) 9 1/8 (231) s --- 1/2 " -14 NPT or M20x1.5 female Junction box Flange center Dimensions in inches (mm) 1 Model F M S l CMF010 7 3/4 (197) 2 (50) 3 5/16 (84) CMF025 9 11/16 (246) 2 1/16 (53) 3 7/16 (87) F CMF050 12 (305) 2 3/16 (55) 3 1/2 (89) A CMF100 16 1/8 (409) 2 15/16 (74) 4 1/4 (108) CMF200 8 13/16 (223) 3 15/16 (100) 5 1/4 (134) ! CMF300 11 1/4 (286) 5 1/4 (133) 6 9/16 (167) I- , —I— M CMF400 14 5/16 (363) 6 3/8 (162) 7 11/16 (195) 3/4 " - 14 NPT ! S female Extended 9 -wire junction box Dimensions in inches (mm) -- Model P1 P2 . Ti . TZ ! _ ! CMF010 95/16 (236) 9 5/16 (236) 121/2 (318) 1213/16 (325) /I p� CMF025 95/16 (236) 95/16 (236) 121/2 (318) 1213116 (325) � � � ��:1 �c Li � CMF050 9 7/16 (240) 9 3/16 (234) 1211/16 (322) 123/4 (324) // / CMF100 101/8 (257) 101/8 (257) 133/8 (340) 135/8 (346) P1 _ I P2 --""1 CMF200 111/4 (286) 11(280) 141/2 (368) 145/8 (372) ! 1 1 ! I CMF300 12 5/8 (320) 127/16 (316) 15 7/8 (403) 16 (406) T I - 12 CMF400 137/8 (352) 133/4 (349) 171/16 (434) 171/4 (439) 38 Micro Motion ELITE Flow and Density Meters • • Dimensions continued High- temperature Models CMF200A, CMF200B, CMF300A, and CMF300B Dimensions in inches (mm) ii 71.7 Transmitter, core processor, or 1 �■�, , junction box mounts on end of flexible 41/8 (1 05) lei conduit. Dimensions for electronics t is are s o page 41 . Dim. Q I Dim. K III P' �- //V1- �i.�.i� Dim. H L I ' .■ 111 • III 01 5/16 (33) Alaj K Flexible conduit 48 (1219) minimum bend radius 6 in (152 mm) 3 (76) 4 . Refer to page 35 for additional sensor dimensions. Dimensions in inches (mm) Model : F H K Q CMF200A and 6 7/8 (175) 6 5/16 (160) 3 15/16 (100) 6 7/16 (163) CMF200B CMF300A and 9 3/8 (238) 9 1/4 (235) 5 1/4 (134) 7 3/4 (197) CMF300B Micro Motion ELITE Flow and Density Meters 39 • 0 Dimensions continued High- temperature Models CMF400A and CMF400B Dimensions in inches (mm) i Transmitter, core processor, or junction box lir - — l mounts on end of flexible conduit. Dimensions for 4 1/8 (105) � 9 electronics are shown on page 41. ( � I — (229) lei 2 61/ 61/2 I I I ii _ VA I , $N119 (199) 5/16 ■ ■ • Il i, 48 (1219) Flexible conduit minimum bend radius 6 in (152 mm) 3 (76) i ll Refer to page 36 for additional sensor dimensions. 40 Micro Motion ELITE Flow and Density Meters • • Dimensions continued Electronics mounted on high- temperature sensor flexible conduit Dimensions in inches (mm) Model 2400S, 1700, 2700, or enhanced core processor: 2 = 1/T -14 NPT female _ / , % or M20 x 1.5 female I 4 Standard core processor: 1/2" —NPT female .�_ orM20.1.5fema ` �■A Dim. C • / Junction box: 1 3/8 3/4 " -14 NPT female - - (36) E-II'II■ :IEEE it ii r �� — MIlrlitill 11.1 NE III li �I� �I 1 3/8 (36) 4 x 03/8 (10) 1 3/8 1 3/8 (36) (36) 4 9/16 (116) Electronics interface option Dimension C in inches (mm) 0 Model 2400S transmitter, painted aluminum housing 8 7/8 (225) Model 2400S transmitter, stainless steel housing 9 1/4 (235) 2 Enhanced core processor, painted aluminum housing 8 7/8 (225) 3 Enhanced core processor, stainless steel housing 9 1/4 (235) Q Standard core processor, painted aluminum housing 6 5/16 (161) A Standard core processor, stainless steel housing 6 5/16 (161) C Model 1700/2700 transmitter 10 1/4 (261) R Junction box, painted aluminum housing 3 9/16 (91) S Junction box, stainless steel housing 3 9/16 (91) Micro Motion ELITE Flow and Density Meters 41 • S Fitting options Dimensions are in inches (mm). Fittings listed here are standard options. Other types of fittings are available. The face to face dimensions for any custom fittings ordered using a 998 or 999 fitting code are not represented in this table. It is necessary to confirm face to face dimensions of these fittings at time of ordering. Contact your local Micro Motion representative. Models CMFS010M and CMFS015M Code Description. Dim: A Dim. 13 172 DN25 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 12.37 (314) 4 1/2 (115) 176 DN15 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 12.21 (310) 3 3/4 (95) 177 DN15 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 12.76 (324) 4 1/8 (105) 178 DN15 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 12.76 (324) 4 1/8 (105) 183 DN25 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 12.37 (314) 4 1/2 (115) 300 DN15 PN40 DIN 2635 F316/F316L Weld neck flange Type C face 12.21 (310) 3 3/4 (95) 301 DN15 PN40 DIN 2635 F316/F316L Weld neck flange Type N grooved 12.21 (310) 3 3/4 (95) face 302 DN15 PN100 DIN 2637 F316/F316L Weld neck flange Type E face 12.76 (324) 4 1/8 (105) 303 DN15 PN100 DIN 2637 F316/F316L Weld neck flange Type N grooved 12.76 (324) 4 1/8 (105) face 304 15mm 10K JIS B 2220 F316/F316L Weld neck flange Raised face 11.98 (304) 3 3/4 (95) 305 15mm 20K JIS B 2220 F316/F316L Weld neck flange Raised face 11.98 (304) 3 3/4 (95) 310 DN15 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 12.21 (310) 3 3/4 (95) 313 1/2" CL150 ASME B16.5 F316/F316L Weld neck flange Raised face 12.64 (321) 3 1/2 (89) 314 1/2" CL300 ASME B16.5 F316/F316L Weld neck flange Raised face 13.00 (330) 3 3/4 (95) 315 1/2" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 13.50 (343) 3 3/4 (95) 319 #8 VCO 316/316L Swagelok 1/2" 316 NPT 11.52 (293) - compatible fitting female adapter 321 (1) 1/2" Tri -Clamp 316L Hygienic fitting 11.52 (293) 1 (25) compatible 323 #4 VCO 316/316L Swagelok 1/4" NPT female 12.16 (309) - compatible fitting adapter 324 #4 VCO 316/316L Swagelok 1/4" tube 12.16 (309) - compatible fitting compression fitting adapter 325 #4 VCO 316/316L Swagelok 6mm tube 12.16 (309) - compatible fitting compression fitting adapter 334 #4 VCO 316/316L Swagelok 12.16 (309) - compatible fitting 335 #8 VCO 316/316L Swagelok 11.52 (293) - compatible fitting 344 3/4" Tri -Clamp 316L Hygienic fitting 11.52 (293) 1.0 (25) compatible 345 DN10 ISO 2852/ 316L Hygienic fitting 11.2 (284) 1.34 (34) ISO 1127 346 DN15 ISO 2852/ 316L Hygienic fitting 11.2 (284) 1.34 (34) DIN 11850 (1) Sensor is 3A authorized but not EHEDG certified when ordered with fitting code 321. (2) Sensor is 3A authorized and EHEDG certified when ordered with fitting code 344, 345, or 346. 42 Micro Motion ELITE' Flow and Density Meters • . Fitting options continued Models CMFS010H and CMFSO15H Code Description Dim: A Dim. B 323 #4 VCO N06022 Swagelok 1/4 -inch N10276 12.16 (309) — compatible fitting NPT female adapter 334 #4 VCO N06022 Swagelok 12.16 (309) — compatible fitting 520 1/2 -inch CL150 ASME B16.5 F304/F304L Lap joint flange N06022 stub 12.64 (321) 3 1/2 (89) 521 1/2 -inch CL300 ASME B16.5 F304/F304L Lap joint flange N06022 stub 13.00 (330) 3 3/4 (95) 522 15mm 10K JIS B 2220 F304/F304L Lap joint flange N06022 stub 12.98 (330) 3 3/4 (95) 523 DN15 PD40 DIN 2656 F304/F304L Lap joint flange Type C face, 13.22 (336) 3 3/4 (95) N06022 stub 524 DN15 PD40 EN 1092 -1 F304/F304L Lap joint flange Form B1, 13.22 (336) 3 3/4 (95) N06022 stub Models CMFS010P and CMFSO15P Code Description Dim. A Dim. B 150 1/2" CL900/ ASME B16.5 F316/F316L Weld neck flange Raised face 14.48 (368) 4.75 (121) 1500 191 1/2" CL2500 ASME B16.5 F316/F316L Weld neck flange Raised face 15.48 (393) 5.25 (133) 319 #8 VCO 316/316L Swagelok 1/2" 316 NPT 11.52 (293) — compatible fitting female adapter 323 #4 VCO 316/316L Swagelok 1/4" NPT female 12.16 (309) — compatible fitting adapter 324 #4 VCO 316/316L Swagelok 1/4" tube 12.16 (309) — compatible fitting compression fitting adapter 325 #4 VCO 316/316L Swagelok 6mm tube 12.16 (309) — compatible fitting compression fitting adapter 334 #4 VCO 316/316L Swagelok 12.16 (309) — compatible fitting 335 #8 VCO 316/316L Swagelok 11.52 (293) — compatible fitting Micro Motion ELITE Flow and Density Meters 43 • S Fitting options continued Model CMF010M Code . Description Dim. A Dim. B 172 DN25 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 7 9/16 (193) 4 1/2 (115) 176 DN15 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 7 7/16 (189) 3 3/4 (95) 177 DN15 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 8 (203) 4 1/8 (105) 178 DN15 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 8 (203) 4 1/8 (105) 183 DN25 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 7 9/16 (193) 4 1/2 (115) 300 DN15 PN40 DIN 2635 F316/F316L Weld neck flange Type C face 7 7/16 (189) 3 3/4 (95) 302 DN15 PN100 DIN 2637 F316/F316L Weld neck flange Type E face 8 (203) 4 1/8 (105) 304 15mm 10K JIS B 2220 F316/F316L Weld neck flange Raised face 7 3/16 (183) 3 3/4 (95) 305 15mm 20K JIS B 2220 F316/F316L Weld neck flange Raised face 7 3/16 (183) 3 3/4 (95) 310 DN15 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 7 7/16 (189) 3 3/4 (95) 313 1/2" CL150 ASME B16.5 F316/F316L Weld neck flange Raised face 7 7/8 (199) 3 1/2 (89) 314 1/2" CL300 ASME B16.5 F316/F316L Weld neck flange Raised face 8 3/16 (209) 3 3/4 (95) 315 1/2" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 8 11/16 (221) 3 3/4 (95) 321 1/2" Tri -Clamp 316L Hygienic fitting 6 15/16 (177) 1 (25) compatible 323 #4 VCO 316/316L Swagelok 1/4" NPT female 6 7/16 (164) — compatible fitting adapter 324 #4 VCO 316/316L Swagelok 1/4" tube 6 7/16 (164) — compatible fitting compression fitting adapter 325 #4 VCO 316/316L Swagelok 6mm tube 6 7/16 (164) — compatible fitting compression fitting adapter 334 #4 VCO 316/316L Swagelok 6 7/16 (164) — compatible fitting Model CMFO10H Code . Description Dim. A Dim. B 323 #4 VCO N06022 Swagelok 1/4 -inch N10276 6 7/16 (164) — compatible fitting NPT female adapter 334 #4 VCO N06022 Swagelok 6 7/16 (164) — compatible fitting 520 1/2" CL150 ASME B16.5 F304/F304L Lap joint flange N06022 stub 7 7/8 (199) 3 1/2 (89) 521 1/2" CL300 ASME B16.5 F304/F304L Lap joint flange N06022 stub 8 3/16 (209) 3 3/4 (95) 522 15mm 10K JIS B 2220 F304/F304L Lap joint flange N06022 stub 8 3/16 (208) 3 3/4 (95) 523 DN15 PN40 DIN 2656 F304/F304L Lap joint flange Type C face, 9 7/16 (240) 3 3/4 (95) N06022 stub 52413 DN15 PN40 EN 1092 -1 F304/F304L Lap joint flange Form B1, 9 7/16 (240) 3 3/4 (95) N06022 stub 44 Micro Motion ELITE' Flow and Density Meters • • Fitting options continued Model CMFO1OL Code Description Dim. A , Dim., B .. . 413 1/2" CL150 ASME B16.5 F304/F304L Weld neck flange Raised face 7 7/8 (199) 3 1/2 (89) 414 1/2" CL300 ASME B16.5 F304/F304L Weld neck flange Raised face 8 3/16 (209) 3 3/4 (95) 421 DN15 PN40 EN 1092 -1 F304/F304L Weld neck flange Form B1 7 7/16 (189) 3 3/4 (95) 423 DN15 PN40 DIN 2526 F304/F304L Weld neck flange Type C face 7 7/16 (189) 3 3/4 (95) Model CMF010P Code Description . Dim. A : Dim. B 323 #4 VCO 316/316L Swagelok 1/4" NPT female 6 7/16 (164) — compatible fitting adapter 324 #4 VCO 316/316L Swagelok 1/4" tube 6 7/16 (164) — compatible fitting compression fitting adapter 325 #4 VCO 316/316L Swagelok 6mm tube 6 7/16 (164) — compatible fitting compression fitting adapter 334 #4 VCO 316/316L Swagelok 6 7/16 (164) — compatible fitting Model CMF025M Code Description . Dim. 'A Dim. B 009 1/2" CL150/ ASME B16.5 F316/F316L Wafer style flange 2 3/8 (60) 1 13/16 (46) 300 bolt kit 016 DN15 PN40 DIN 2526 F316/F316L Wafer style flange Type C face 2 3/8 (60) 1 13/16 (46) bolt kit 017 DN15 PN40 DIN 2512 F316/F316L Wafer style flange Type N grooved 2 3/8 (60) 1 13/16 (46) bolt kit face 018 DN15 PN100 DIN 2526 F316/F316L Wafer style flange Type E face 2 3/8 (60) 1 13/16 (46) bolt kit 019 DN15 PN100 DIN 2512 F316/F316L Wafer style flange Type N grooved 2 3/8 (60) 1 13/16 (46) bolt kit face 029 15mm 10K/ JIS B 2220 F316/F316L Wafer style flange 2 3/8 (60) 1 13/16 (46) 20K bolt kit 172 DN25 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 6 7/16 (164) 4 1/2 (115) 176 DN15 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 6 5/16 (160) 3 3/4 (95) 177 DN15 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 6 15/16 (176) 4 1/8 (105) 178 DN15 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 6 15/16 (176) 4 1/8 (105) 183 DN25 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 6 7/16 (164) 4 1/2 (115) 300 DN15 PN40 DIN 2635 F316/F316L Weld neck flange Type C face 6 5/16 (160) 3 3/4 (95) 301 DN15 PN40 DIN 2635 F316/F316L Weld neck flange Type N grooved 6 5/16 (160) 3 3/4 (95) face 302 DN15 PN100 DIN 2637 F316/F316L Weld neck flange Type E face 6 15/16 (176) 4 1/8 (105) Micro Motion ELITE Flow and Density Meters 45 4 • Fitting options continued Model CMF025M continued Code Description Dim. A Dim. B 303 DN15 PN100 DIN 2637 F316/F316L Weld neck flange Type N grooved 6 15/16 (176) 4 1/8 (105) face 304 15mm 10K JIS B 2220 F316/F316L Weld neck flange Raised face 6 1/8 (156) 3 3/4 (95) 305 15mm 20K JIS B 2220 F316/F316L Weld neck flange Raised face 6 1/8 (156) 3 3/4 (95) 310 DN15 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 6 5/16 (160) 3 3/4 (95) 313 1/2" CL150 ASME B16.5 F316/F316L Weld neck flange Raised face 6 3/4 (172) 3 1/2 (89) 314 1/2" CL300 ASME B16.5 F316/F316L Weld neck flange Raised face 7 1/8 (181) 3 3/4 (95) 315 1/2" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 7 5/8 (194) 3 3/4 (95) 319 #8 VCO 316/316L Swagelok 1/2" NPT female 4 11/16 (119) — compatible fitting adapter 321 1/2" Tri -Clamp 316L Hygienic fitting 4 11/16 (119) 1 (25) compatible 335 #8 VCO 316/316L Swagelok 4 11/16 (119) — compatible fitting Model CMF025L Code Description Dim. A ; Dim. B 413 1/2" CL150 ASME B16.5 F304/F304L Weld neck flange Raised face 6 3/4 (172) 3 1/2 (89) 414 1/2" CL300 ASME B16.5 F304/F304L Weld neck flange Raised face 7 1/8 (181) 3 3/4 (95) 421 DN15 PN40 EN 1092 -1 F304/F304L Weld neck flange Form B1 6 5/16 (160) 3 3/4 (95) 423 DN15 PN40 DIN 2526 F304/F304L Weld neck flange Type C face 6 5/16 (160) 3 3/4 (95) Model CMF025H Code Description Dim. A- Dim. B 520 1/2" CL150 ASME B16.5 F304/F304L Lap joint flange N06022 stub 6 3/4 (172) 3 1/2 (89) 521 1/2" CL300 ASME B16.5 F304/F304L Lap joint flange N06022 stub 7 1/8 (181) 3 3/4 (95) 522 15mm 10K JIS B 2220 F304/F304L Lap joint flange N06022 stub 7 1/8 (181) 3 3/4 (95) 523 DN15 PN40 DIN 2656 F304/F304L Lap joint flange Type C face, 7 5/16 (186) 3 3/4 (95) N06022 stub 524 DN15 PN40 EN 1092 -1 F304/F304L Lap joint flange Form B1, 7 5/16 (186) 3 3/4 (95) N06022 stub 46 Micro Motion ELITE Flow and Density Meters S Fitting options continued Model CMF050M Code Description Dim. A Dim. 009 1/2" CL150/ ASME 816.5 F316/F316L Wafer style flange 3 1/2 (89) 1 13/16 (46) 300 bolt kit 016 DN15 PN40 DIN 2526 F316/F316L Wafer style flange Type C face 3 1/2 (89) 1 13/16 (46) bolt kit 017 DN15 PN40 DIN 2512 F316/F316L Wafer style flange Type N grooved 3 1/2 (89) 1 13/16 (46) bolt kit face 018 DN15 PN100 DIN 2526 F316/F316L Wafer style flange Type E face 3 1/2 (89) 1 13/16 (46) bolt kit 019 DN15 PN100 DIN 2512 F316/F316L Wafer style flange Type N grooved 3 1/2 (89) 1 13/16 (46) bolt kit face 029 15mm 10K/ JIS B 2220 F316/F316L Wafer style flange 3 1/2 (89) 1 13/16 (46) 20K bolt kit 172 DN25 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 7 11/16 (195) 4 1/2 (115) 176 DN15 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 7 1/2 (191) 3 3/4 (95) 177 DN15 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 8 1/16 (205) 4 1/8 (105) 178 DN15 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 8 1/16 (205) 4 1/8 (105) 183 DN25 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 7 11/16 (195) 4 1/2 (115) 300 DN15 PN40 DIN 2635 F316/F316L Weld neck flange Type C face 7 1/2 (191) 3 3/4 (95) 301 DN15 PN40 DIN 2635 F316/F316L Weld neck flange Type N grooved 7 1/2 (191) 3 3/4 (95) face 302 DN15 PN100 DIN 2637 F316/F316L Weld neck flange Type E face 8 1/16 (205) 4 1/8 (105) 303 DN15 PN100 DIN 2637 F316/F316L Weld neck flange Type N grooved 8 1/16 (205) 4 1/8 (105) face 304 15mm 10K JIS B 2220 F316/F316L Weld neck flange Raised face 7 1/4 (184) 3 3/4 (95) 305 15mm 20K JIS B 2220 F316/F316L Weld neck flange Raised face 7 1/4 (184) 3 3/4 (95) 310 DN15 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 7 1/2 (191) 3 3/4 (95) 313 1/2" CL150 ASME B16.5 F316/F316L Weld neck flange Raised face 7 15/16 (202) 3 1/2 (89) 314 1/2" CL300 ASME B16.5 F316/F316L Weld neck flange Raised face 8 5/16 (211) 3 3/4 (95) 315 1/2" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 8 13/16 (224) 3 3/4 (95) 319 #8 VCO 316/316L Swagelok 1/2" NPT female 6 7/8 (175) — compatible fitting adapter 320 #12 VCO 316/316L Swagelok 3/4" NPT female 6 1/2 (165) — compatible fitting adapter 322 3/4" Tri -Clamp 316L Hygienic fitting 6 1/2 (165) 1 (25) compatible 336 #12 VCO 316/316L Swagelok 6 1/2 (165) — compatible fitting Micro Motion ELITE Flow and Density Meters 47 S • Fitting options continued Model CMFO5OL Code Description . . Dim. A Dim.13 413 1/2" CL150 ASME B16.5 F304/F304L Weld neck flange Raised face 7 15/16 (202) 3 1/2 (89) 414 1/2" CL300 ASME B16.5 F304/F304L Weld neck flange Raised face 8 5/16 (211) 3 3/4 (95) 421 DN15 PN40 EN 1092 -1 F304/F304L Weld neck flange Form B1 7 1/2 (191) 3 3/4 (95) 423 DN15 PN40 DIN 2526 F304/F304L Weld neck flange Type C face 7 1/2 (191) 3 3/4 (95) Model CMF050H Code Description . : Dim. A Dim. i3 520 1/2" CL150 ASME B16.5 F304/F304L Lap joint flange N06022 stub 7 15/16 (202) 3 1/2 (89) 521 1/2" CL300 ASME B16.5 F304/F304L Lap joint flange N06022 stub 8 5/16 (211) 3 3/4 (95) 522 15mm 10K JIS B 2220 F304/F304L Lap joint flange N06022 stub 8 1/4 (210) 3 3/4 (95) 523 DN15 PN40 DIN 2656 F304/F304L Lap joint flange Type C face, 8 1/2 (216) 3 3/4 (95) N06022 stub 524 DN15 PN40 EN 1092 -1 F304/F304L Lap joint flange Form B1, 8 1/2 (216) 3 3/4 (95) N06022 stub Model CMF100M Code ` Description Dim. A Dim. B ," ". 010 1" CL150 ASME B16.5 F316/F316L Wafer style flange 4 (102) 2 1/2 (64) bolt kit 011 1" CL300/ ASME B16.5 F316/F316L Wafer style flange 4 (102) 2 1/2 (64) 600 bolt kit 020 DN25 PN40 DIN 2526 F316/F316L Wafer style flange Type C face 4 (102) 2 1/2 (64) bolt kit 021 DN25 PN40 DIN 2512 F316/F316L Wafer style flange Type N grooved 4 (102) 2 1/2 (64) bolt kit face 022 DN25 PN100 DIN 2526 F316/F316L Wafer style flange Type E face 4 (102) 2 1/2 (64) bolt kit 023 DN25 PN100 DIN 2512 F316/F316L Wafer style flange Type N grooved 4 (102) 2 1/2 (64) bolt kit face 030 25mm 10K/ JIS B 2220 F316/F316L Wafer style flange 4 (102) 2 1/2 (64) 20K bolt kit 179 DN25 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 8 5/16 (211) 4 1/2 (115) 180 DN25 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 9 11/16 (246) 5 1/2 (140) 181 DN25 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 9 11/16 (246) 5 1/2 (140) 306 DN25 PN40 DIN 2635 F316/F316L Weld neck flange Type C face 8 5/16 (211) 4 1/2 (115) 307 DN25 PN40 DIN 2635 F316/F316L Weld neck flange Type N grooved 8 5/16 (211) 4 1/2 (115) face 308 DN25 PN100 DIN 2637 F316/F316L Weld neck flange Type E face 9 11/16 (246) 5 1/2 (140) 309 DN25 PN100 DIN 2637 F316/F316L Weld neck flange Type N grooved 9 11/16 (246) 5 1/2 (140) face 311 DN25 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 8 5/16 (211) 4 1/2 (115) 48 Micro Motion ELITE Flow and Density Meters • • Fitting options continued Model CMF100M continued Code Description Dim. A Dim: B . 317 25mm 10K JIS B 2220 F316/F316L Weld neck flange Raised face 8 5/16 (211) 4 15/16 (125) 318 25mm 20K JIS B 2220 F316/F316L Weld neck flange Raised face 8 5/16 (211) 4 15/16 (125) 328 1" CL150 ASME B16.5 F316/F316L Weld neck flange Raised face 9 1/4 (235) 4 1/4 (108) 329 1" CL300 ASME B16.5 F316/F316L Weld neck flange Raised face 9 3/4 (248) 4 7/8 (124) 330 1" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 10 1/4 (260) 4 7/8 (124) 331 1 -1/2" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 10 7/8 (276) 6 1/8 (156) 339 1" Tri -Clamp 316L Hygienic fitting 8 3/8 (213) 2 (50) compatible Model CMF100L Code Dim. A Dim: B 415 1" CL150 ASME B16.5 F304/F304L Weld neck flange Raised face 9 1/4 (235) 4 1/4 (108) 416 1" CL300 ASME B16.5 F304/F304L Weld neck flange Raised face 9 3/4 (248) 4 7/8 (124) 422 DN25 PN40 EN 1092 -1 F304/F304L Weld neck flange Form B1 8 9/16 (217) 4 1/2 (115) 424 DN25 PN40 DIN 2526 F304/F304L Weld neck flange Type C face 8 9/16 (217) 4 1/2 (115) Model CMF100H Code Description Dim. A Dim. B 530 1" CL150 ASME B16.5 F304/F304L Lap joint flange N06022 stub 9 1/4 (235) 4 1/4 (108) 531 1" CL300 ASME B16.5 F304/F304L Lap joint flange N06022 stub 9 3/4 (248) 4 7/8 (124) 532 25mm 10K JIS B 2220 F304/F304L Lap joint flange N06022 stub 9 5/16 (237) 4 15/16 (125) 533 DN25 PN40 DIN 2656 F304/F304L Lap joint flange Type C face, 9 9/16 (243) 4 1/2 (115) N06022 stub 534 DN25 PN40 EN 1092 -1 F304/F304L Lap joint flange Form B1, 9 9/16 (243) 4 1/2 (115) N06022 stub Micro Motion ELITE Flow and Density Meters 49 • • Fitting options continued Models CMF200M and CMF200A Code Description Dim. A Dim. B 312 DN40 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 21 9/16 (547) 5 15/16 (150) 316 DN50 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 21 3/4 (553) 6 1/2 (165) 341 1 -1/2 -inch CL150 ASME B16.5 F316/F316L Weld neck flange Raised face 22 7/8 (581) 5 (127) 342 1 -1/2 -inch CL300 ASME B16.5 F316/F316L Weld neck flange Raised face 23 3/8 (594) 6 1/8 (156) 343 1 -1/2 -inch CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 23 7/8 (606) 6 1/8 (156) 351 (1) 1 -1/2 -inch Tri -Clamp 316L Hygienic fitting 21 3/8 (543) 2 (51) compatible 352 2 -inch Tri -Clamp 316L Hygienic fitting 21 3/8 (543) 2 1/2 (64) compatible 363 DN40 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 22 7/8 (580) 6 11/16 (170) 365 DN50 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 23 5/16 (593) 7 11/16 (195) 366 DN40 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 22 7/8 (580) 6 11/16 (170) 367 DN50 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 23 5/16 (593) 7 11/16 (195) 368 DN40 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 21 9/16 (547) 5 15/16 (150) 369 DN50 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 21 3/4 (553) 6 1/2 (165) 377 DN40 PN100 DIN 2637 F316/F316L Weld neck flange Type E face 23 1/8 (587) 6 11/16 (170) 378 DN50 PN100 DIN 2637 F316/F316L Weld neck flange Type E face 23 9/16 (598) 7 11/16 (195) 379 DN40 PN100 DIN 2637 F316/F316L Weld neck flange Type N grooved 23 1/8 (587) 6 11/16 (170) face 380 DN50 PN100 DIN 2637 F316/F316L Weld neck flange Type N grooved 23 9/16 (598) 7 11/16 (195) face 381 DN40 PN40 DIN 2635 F316/F316L Weld neck flange Type C face 21 11/16 (551) 5 15/16 (150) 382 DN50 PN40 DIN 2635 F316/F316L Weld neck flange Type C face 21 15/16 (557) 6 1/2 (165) 383 DN40 PN40 DIN 2635 F316/F316L Weld neck flange Type N grooved 21 11/16 (551) 5 15/16 (150) face 384 DN50 PN40 DIN 2635 F316/F316L Weld neck flange Type N grooved 21 15/16 (557) 6 1/2 (165) face 385 40mm 10K JIS B 2220 F316/F316L Weld neck flange Raised face 21 9/16 (548) 5 1/2 (140) 387 40mm 20K JIS B 2220 F316/F316L Weld neck flange Raised face 21 9/16 (548) 5 1/2 (140) 418 2 -inch CL150 ASME B16.5 F316/F316L Weld neck flange Raised face 22 7/8 (581) 6 (152) 419 2 -inch CL300 ASME B16.5 F316/F316L Weld neck flange Raised face 23 3/8 (594) 6 1/2 (165) 420 2 -inch CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 23 5/8 (600) 6 1/2 (165) B85 50mm 10K JIS B 2220 A105 Carbon Lap joint flange 316/316L stub 21 13/16 (554) 6 1/8 (155) Steel B86 50mm 20K JIS B 2220 A105 Carbon Lap joint flange 316/316L stub 21 13/16 (554) 6 1/8 (155) Steel (1) Available only with Model CMF200M. (2) Low volume process connection. Consult factory for lead time. 50 Micro Motion ELITE Flow and Density Meters • Fitting options continued Model CMF200L Code Description Dim. A Diim.;B 441 1-1/2" CL150 ASME B16.5 F304/F304L Weld neck flange Raised face 22 7/8 (581) 5 (127) 442 1 -1/2" CL300 ASME B16.5 F304/F304L Weld neck flange Raised face 23 3/8 (594) 6 1/8 (156) 457 DN40 PN40 EN 1092 -1 F304/F304L Weld neck flange Form B1 21 9/16 (547) 5 15/16 (150) 458 DN50 PN40 EN 1092 -1 F304/F304L Weld neck flange Form B1 21 3/4 (553) 6 1/2 (165) 481 DN40 PN40 DIN 2526 F304/F304L Weld neck flange Type C face 21 11/16 (551) 5 15/16 (150) 482 DN50 PN40 DIN 2526 F304/F304L Weld neck flange Type C face 21 15/16 (557) 6 1/2 (165) 518 2 -inch CL150 ASME B16.5 F304/F304L Weld neck flange Raised face 22 7/8 (581) 6 (152) 519 2 -inch CL300 ASME B16.5 F304/F304L Weld neck flange Raised face 23 1/2 (597) 6 1/2 (165) Models CMF200H and CMF200B Code Description Dim: A Dim. 540 1 -1/2" CL150 ASME B16.5 F304/F304L Lap joint flange N06022 stub 22 7/8 (581) 5 (127) 541 1 -1/2" CL300 ASME B16.5 F304 /F304L Lap joint flange N06022 stub 23 3/8 (594) 6 1/8 (156) 542 40mm 10K JIS B 2220 F304/F304L Lap joint flange N06022 stub 21 9/16 (548) 5 1/2 (140) 543 DN40 PN40 DIN 2656 F304/F304L Lap joint flange Type C face, 21 11/16 (551) 5 15/16 (150) N06022 stub 544 2" CL150 ASME B16.5 F304/F304L Lap joint flange N06022 stub 22 7/8 (581) 6 (152) 545 2" CL300 ASME B16.5 F304/F304L Lap joint flange N06022 stub 23 3/8 (594) 6 1/2 (165) 546 50mm 10K JIS B 2220 F304/F304L Lap joint flange N06022 stub 21 13/16 (554) 6 1/8 (155) 547 DN50 PN40 DIN 2656 F304/F304L Lap joint flange Type C face, 21 15/16 (557) 6 1/2 (165) N06022 stub 548 DN40 PN40 EN 1092 -1 F304/F304L Lap joint flange Form B1, 21 11/16 (551) 5 15/16 (150) N06022 stub 549 DN50 PN40 EN 1092 -1 F304/F304L Lap joint flange Form B1, 21 15/16 (557) 6 1/2 (165) N06022 stub Micro Motion ELITE' Flow and Density Meters 51 • Fitting options continued Models CMF300M and CMF300A Code Description" Dim. A Dim. B 326 DN80 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 32 3/4 (832) 7 7/8 (200) 333 DN100 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 33 1/4 (845) 9 1/4 (235) 355 3" CL150 ASME 816.5 F316/F316L Weld neck flange Raised face 33 11/16 (856) 7 1/2 (191) 356 3" CL300 ASME B16.5 F316/F316L Weld neck flange Raised face 34 7/16 (875) 8 1/4 (210) 357 3" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 35 3/16 (894) 8 1/4 (210) 358 3" CL900 ASME B16.5 F316/F316L Weld neck flange Raised face 36 3/4 (933) 9 1/2 (241) 359 DN100 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 35 1/4 (896) 10 7/16 (265) 361 3" Tri -Clamp 316L Hygienic fitting 32 (813) 3 9/16 (90) compatible 371 DN80 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 32 3/4 (832) 7 7/8 (200) 372 DN100 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 33 1/4 (845) 9 1/4 (235) 373 DN80 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 34 5/16 (872) 9 1/16 (230) 374 DN100 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 35 1/4 (896) 10 7/16 (265) 375 DN80 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 34 5/16 (872) 9 1/16 (230) 391 DN80 PN40 DIN 2635 F316/F316L Weld neck flange Type C face 32 7/8 (835) 7 7/8 (200) 392 DN100 PN40 DIN 2635 F316/F316L Weld neck flange Type C face 33 1/4 (845) 9 1/4 (235) 393 DN80 PN40 DIN 2635 F316/F316L Weld neck flange Type N grooved 32 7/8 (835) 7 7/8 (200) face 394 DN100 PN40 DIN 2635 F316/F316L Weld neck flange Type N grooved 33 1/4 (845) 9 1/4 (235) face 395 DN80 PN100 DIN 2637 F316/F316L Weld neck flange Type E face 34 9/16 (878) 9 1/16 (230) 396 DN100 PN100 DIN 2637 F316/F316L Weld neck flange Type E face 35 9/16 (903) 10 7/16 (265) 397 DN80 PN100 DIN 2637 F316/F316L Weld neck flange Type N grooved 34 9/16 (878) 9 1/16 (230) face 398 DN100 PN100 DIN 2637 F316/F316L Weld neck flange Type N grooved 35 9/16 (903) 10 7/16 (265) face 400 80mm 10K JIS B 2220 F316/F316L Weld neck flange Raised face 33 3/8 (848) 7 5/16 (186) 402 80mm 20K JIS B 2220 F316/F316L Weld neck flange Raised face 33 3/8 (848) 7 7/8 (200) 425 4" CL150 ASME B16.5 F316/F316L Weld neck flange Raised face 34 1/16 (865) 9 (229) 426 4" CL300 ASME B16.5 F316/ Weld neck flange Raised face 35 (889) 10 (254) F96316L 427 4" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 36 11/16 (932) 10 3/4 (273) 428 1) 4" CL900 ASME B16.5 F316/F316L Weld neck flange Raised face 37 1/4 (946) 11 1/2 (292) B87 100mm 10K JIS B 2220 A105 Carbon Lap joint flange 316/316L stub 35 9/16 (903) 8 1/4 (210) Steel B88 100mm 20K JIS B 2220 A105 Carbon Lap joint flange 316/316L stub 35 9/16 (903) 8 7/8 (225) Steel (1) Available only with Model CMF300A. (2) Low volume process connection. Consult factory for lead time. 52 Micro Motion ELITE Flow and Density Meters • • Fitting options continued Model CMF300L Code Description Dim. A : Dim. B 455 3" CL150 ASME B16.5 F304/F304L Weld neck flange Raised face 33 11/16 (856) 7 1/2 (191) 456 3" CL300 ASME B16.5 F304/F304L Weld neck flange Raised face 34 7/16 (875) 8 1/4 (210) 459 DN80 PN40 EN 1092 -1 F304/F304L Weld neck flange Form B1 32 3/4 (832) 7 7/8 (200) 491 DN80 PN40 DIN 2526 F304/F304L Weld neck flange Type C face 32 7/8 (835) 7 7/8 (200) Models CMF300H and CMF300B Code Des cription Dim: A . Dim. B 550 3" CL150 ASME B16.5 F304/F304L Lap joint flange N06022 stub 33 11/16 (856) 7 1/2 (191) 551 3" CL300 ASME B16.5 F304/F304L Lap joint flange N06022 stub 34 7/16 (875) 8 1/4 (210) 552 80mm 10K JIS B 2220 F304/F304L Lap joint flange N06022 stub 33 3/8 (848) 7 5/16 (185) 553 DN80 PN40 DIN 2656 F304/F304L Lap joint flange Type C face, 32 7/8 (835) 7 7/8 (200) N06022 stub 554 DN80 PN40 EN 1092 -1 F304/F304L Lap joint flange Form B1, 32 7/8 (835) 7 7/8 (200) N06022 stub Models CMF400M and CMF400A Code Description Dim. A Dim. B 435 4" CL150 ASME B16.5 F316/F316L Weld neck flange Raised face 40 3/16 (1021) 9 (229) 436 4" CL300 ASME B16.5 F316/F316L Weld neck flange Raised face 41 (1041) 10 (254) 437 4" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 4211/16 (1084) 10 3/4 (273) 438 4" CL900 ASME 816.5 F316/F316L Weld neck flange Raised face 43 3/4 (1111) 11 1/2 (292) 443 DN100 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 39 5/16 (999) 9 1/4 (235) 444 DN150 PN40 EN 1092 -1 F316/F316L Weld neck flange Form B1 40 1/16 (1018) 11 13/16 (300) 445 DN100 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 41 5/16 (1049) 10 7/16 (265) 446 DN150 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 43 1/4 (1099) 14 (355) 447 DN100 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 41 5/16 (1049) 10 7/16 (265) 448 DN150 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 43 1/4 (1099) 14 (355) 451 6" CL150 ASME B16.5 F316/F316L Weld neck flange Raised face 40 5/16 (1024) 11 (279) 452 6" CL300 ASME B16.5 F316/F316L Weld neck flange Raised face 41 5/16 (1049) 12 1/2 (318) 453 6" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 43 1/2 (1105) 14 (356) 460 DN100 PN40 DIN 2635 F316/F316L Weld neck flange Type C face 39 5/16 (999) 9 1/4 (235) 461 DN150 PN40 DIN 2635 F316/F316L Weld neck flange Type C face 39 5/8 (1006) 11 13/16 (300) 462 DN100 PN40 DIN 2635 F316/F316L Weld neck flange Type N grooved 39 5/16 (999) 9 1/4 (235) face 463 DN150 PN40 DIN 2635 F316/F316L Weld neck flange Type N grooved 39 5/8 (1006) 11 13/16 (300) face 464 DN100 PN100 DIN 2637 F316/F316L Weld neck flange Type E face 41 5/16 (1049) 10 7/16 (265) 465 DN150 PN100 DIN 2637 F316/F316L Weld neck flange Type E face 41 15/16 (1065) 14 (355) 466 DN100 PN100 DIN 2637 F316/F316L Weld neck flange Type N grooved 41 5/16 (1049) 10 7/16 (265) face (1) Available only with Model CMF400A. Micro Motion ELITE Flow and Density Meters 53 a • Fitting options continued • Models CMF400M and CMF400A continued Code Description: Dire. A Dim. B 467 DN150 PN100 DIN 2637 F316/F316L Weld neck flange Type N grooved 41 15/16 (1065) 14 (355) face 470 100mm 10K JIS B 2220 F316/F316L Weld neck flange Raised face 39 5/16 (999) 8 1/4 (210) 472 100mm 20K JIS B 2220 F316/F316L Weld neck flange Raised face 3913/16 (1011) 8 7/8 (225) 478 DN150 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 40 1/16 (1018) 11 13/16 (300) 480 DN100 PN40 EN 1092 -1 F316/F316L Weld neck flange Form D 39 5/16 (999) 9 1/4 (235) B89 150mm 10K JIS B 2220 A105 Carbon Lap joint flange 316/316L stub 39 5/8 (1007) 11 (280) Steel B90 150mm 20K JIS B 2220 A105 Carbon Lap joint flange 316/316L stub 40 1/8 (1019) 12 (305) Steel (1) Low volume process connection. Consult factory for lead time. Models CMF400H and CMF400B Code . Description Dim: A Dim. B 906 DN100 PN40 EN 1092 -1 N06022 Weld neck flange Form B1 39 1/4 (997) 9 1/4 (235) 907 4" CL150 ASME B16.5 F304/F304L Lap joint flange N06022 stub 42 5/8 (1083) 9 (229) 908 DN100 PN100 EN 1092 -1 F304/F304L Lap joint flange Form B2 41 1/4 (1048) 10 7/16 (265) 910 DN100 PN160 EN 1092 -1 F304/F304L Lap joint flange Form B2 42 (1067) 10 7/16 (265) 911 4" CL150 ASME B16.5 N06022 Weld neck flange Raised face 40 1/8 (1019) 9 (229) 912 4" CL300 ASME B16.5 N06022 Weld neck flange Raised face 4015/16 (1040) 10 (254) 913 4" CL600 ASME B16.5 N06022 Weld neck flange Raised face 42 5/8 (1083) 10 3/4 (273) 914 4" CL900 ASME B16.5 N06022 Weld neck flange Raised face 43 5/8 (1108) 11 1/2 (292) Model CMF400P Code Description Dim: A . - Dim. B 437 4" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 4211/16 (1084) 10 3/4 (273) 438 4" CL900 ASME B16.5 F316/F316L Weld neck flange Raised face 4311/16 (1110) 11 1/2 (292) 439 4" CL1500 ASME 816.5 F316/F316L Weld neck flange Raised face 44 7/16 (1129) 12 1/4 (311) 445 DN100 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 41 5/16 (1049) 10 7/16 (265) 446 DN150 PN100 EN 1092 -1 F316/F316L Weld neck flange Form B2 431/4 (1099) 14 (356) 447 DN100 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 41 5/16 (1049) 10 7/16 (265) 448 DN150 PN100 EN 1092 -1 F316/F316L Weld neck flange Form D 43 1/4 (1099) 14 (356) 453 6" CL600 ASME B16.5 F316/F316L Weld neck flange Raised face 43 1/2 (1105) 14 (356) 468 DN100 PN160 EN 1092 -1 F316/F316L Weld neck flange Form B2 42 1/16 (1068) 10 7/16 (265) 472 100mm 20K JIS B 2220 F316/F316L Weld neck flange Raised face 3913/16 (1011) 8 7/8 (225) 473 150mm 20K JIS B 2220 F316/F316L Weld neck flange Raised face 40 1/8 (1018) 12 (305) 562 4" CL600 ASME B16.5 A105 Carbon Lap joint flange 316/316L stub 4311/16 (1110) 10 3/4 (273) Steel 563 4" CL900 ASME 816.5 A105 Carbon Lap joint flange 316/316L stub 4311/16 (1110) 11 1/2 (292) Steel 54 Micro Motion ELITE Flow and Density Meters Ordering information Model Product description St dare �ncx '€ x CMFS010M Micro Motion Coriolis ELITE sensor; 1/10 to 1/6 -inch (2 to 4 mm); 316L stainless steel CMFS010H Micro Motion Coriolis ELITE sensor; 1/10 to 1/6 -inch (2 to 4 mm); Nickel Alloy C22 (N06022) CMFS015M Micro Motion Coriolis ELITE sensor; 1/6 to 1/4 -inch (4 to 6 mm); 316E stainless steel CMFS015H Micro Motion Coriolis ELITE sensor; 1/6 to 1/4 -inch (4 to 6 mm); Nickel Alloy C22 (N06022) CMF010M Micro Motion Coriolis ELITE sensor; 1/10 to 1/6 -inch (2 to 4 mm); 316L stainless steel CMF010H Micro Motion Coriolis ELITE sensor; 1/10 to 1/6 -inch (2 to 4 mm); Nickel Alloy C22 (N06022) CMF010L Micro Motion Coriolis ELITE sensor; 1/10 to 1/6 -inch (2 to 4 mm); 304L stainless steel CMF025M Micro Motion Coriolis ELITE sensor; 1/4 to 1/2 -inch (6 to 13 mm); 316L stainless steel CMF025H Micro Motion Coriolis ELITE sensor; 1/4 to 1/2 -inch (6 to 13 mm); Nickel Alloy C22 (N06022) CMF025L Micro Motion Coriolis ELITE sensor; 1/4 to 1/2 -inch (6 to 13 mm); 304L stainless steel CMF050M Micro Motion Coriolis ELITE sensor; 1/2 to 1 -inch (13 to 25 mm); 316L stainless steel CMF050H Micro Motion Coriolis ELITE sensor; 1/2 to 1 -inch (13 to 25 mm); Nickel Alloy C22 (N06022) CMF050L Micro Motion Coriolis ELITE sensor; 1/2 to 1 -inch (13 to 25 mm); 304L stainless steel CMF100M Micro Motion Coriolis ELITE sensor; 1 to 2 -inch (25 to 50 mm); 316E stainless steel CMF100H Micro Motion Coriolis ELITE sensor; 1 to 2 -inch (25 to 50 mm); Nickel Alloy C22 (N06022) CMF100L Micro Motion Coriolis ELITE sensor; 1 to 2 -inch (25 to 50 mm); 304L stainless steel CMF200M Micro Motion Coriolis ELITE sensor; 2 to 3 -inch (50 to 75 mm); 316L stainless steel CMF200H Micro Motion Coriolis ELITE sensor; 2 to 3 -inch (50 to 75 mm); Nickel Alloy C22 (N06022) CMF200L Micro Motion Coriolis ELITE sensor; 2 to 3 -inch (50 to 75 mm); 304L stainless steel CMF300M Micro Motion Coriolis ELITE sensor; 3 to 4 -inch (75 to 100 mm); 316L stainless steel CMF300H Micro Motion Coriolis ELITE sensor; 3 to 4 -inch (75 to 100 mm); Nickel Alloy C22 (N06022) CMF300L Micro Motion Coriolis ELITE sensor; 3 to 4 -inch (75 to 100 mm); 304L stainless steel CMF400M Micro Motion Coriolis ELITE sensor; 4 to 6 -inch (100 to 150 mm); 316L stainless steel CMF400H Micro Motion Coriolis ELITE sensor; 4 to 6 -inch (100 to 150 mm); Nickel Alloy C22 (N06022) Hi .h r sure modete : ' a CMFS010P Micro Motion Coriolis ELITE sensor; 1/10 to 1/6 -inch (2 to 4 mm); high pressure; nickel alloy with stainless steel fittings CMFS015P Micro Motion Coriolis ELITE sensor; 1/6 to 1/4 -inch (4 to 6 mm); high pressure; nickel alloy with stainless steel fittings CMF010P Micro Motion Coriolis ELITE sensor; 1/10 to 1/6 -inch (2 to 4 mm); high pressure; nickel alloy with stainless steel fittings CMF400P Micro Motion Coriolis ELITE sensor; 4 to 6 -inch (100 to 150 mm); high pressure; nickel alloy with stainless steel fittings Hi 114e3i 'era ure models CMF200A Micro Motion Coriolis ELITE sensor; 2 to 3 -inch (50 to 75 mm); high temperature; 316L stainless steel CMF200B Micro Motion Coriolis ELITE sensor; 2 to 3 -inch (50 to 75 mm); high temperature; Nickel Alloy C22 (N06022) CMF300A Micro Motion Coriolis ELITE sensor; 3 to 4 -inch (75 to 100 mm); high temperature; 316L stainless steel CMF300B Micro Motion Coriolis ELITE sensor; 3 to 4 -inch (75 to 100 mm); high temperature; Nickel Alloy C22 (N06022) CMF400A Micro Motion Coriolis ELITE sensor; 4 to 6 -inch (100 to 150 mm); high temperature; 316L stainless steel CMF400B Micro Motion Coriolis ELITE sensor; 4 to 6 -inch (100 to 150 mm); high temperature; Nickel Alloy C22 (N06022) Code Process Connections ### See process fitting options on pages 42 -54. Continued on next page Micro Motion ELITE Flow and Density Meters 55 Ordering information continued Code Case options w Standard pressure containmen pn) Purge fittings (see pages 33-36) Do) r �� ' Rupmnadisks ywo40O�e��8ua0 disks) � `� . ��^ ��_�� i. � ` � �� '/'��'��'`'`��- ��`��'��/�� Standard case (300-series stainless steel) J Standard case (300-series stainless steel) with mounting bracke � 310L stainless steel case O 316L stainless steel case with mounting bracket *p/ Hygienic; nuna finish (o.oxm);31OL stainless steel case Tn Hygienic; 32 Ra finish (0.8 pm); 316L stainless steel case with mounting bracket p Purge fitting (see page 31); standard case u Purge fitting (see page 31); standard case with mounting bracke Code Electronics interface O Model 2400S transmitter 1 Extended mount Model 2400S transmitter 2 4-wire polyurethane-painted aluminum integral enhanced core processor for remote mount transmitters 3 4-wire stainless steel integral enhanced core processor for remote mount transmitters 4 4-wire polyurethane-painted aluminum integral extended mount enhanced core processor for remote mount transmitters 5 4+wi,00x�ndedmovn�mum|oao�en|in�enm|en»ancmdcomp,oceaso,|b,mmommvun\��nvminom � 4-wire polyurethane-painted aluminum integral core processor for remote mount transmitters A 4-wire stainless steel integral core processor for remote mount transmitters j (4) e+viminmgroUymnunoedMnuo)22OOSt�nsmi«or � U 2-wire extended Model 2200S transmitter R 9-wire polyurethane-painted aluminum junction box G 9-wire 316L stainless steel junction box H 9-wire extended mount polyurethane-painted aluminum junction box T 9-wire extended mount stainless steel junction box '.� / ' ' ' `.�'�`'/,'`''`'� ��'' �� `�� '� ' � ' ' ' ` '� ( ' � ^ . ' - � ��'�� , -`�� ' ��' '�, ` �' . '�!��` � ��!��„:' 0 Model 2400S transmitter 2 4-wire polyurethane-painted aluminum integral enhanced core processo for remote mount transmitters 3 4-wire stainless steel integral enhanced core processor for remote mount transmitters ' � 4-wire polyureth ne-painted aluminum integral core processor for remote mount transmitters A 4-wire stainless steel integral core processor for remote mount transmitters C Model 17OO/27OU�o,nsm|oe, - - ' ' ---'----- n 9-wire polyurethane-painted aluminum junction box S 9-wire 316L stainless steel junction box Continued on next page (1) Not available with high-temperature models. (2) Available only with Mode/CMF01op (3) Available only with process connection 321, 344, 345, or 346. (4) Available only with calibration option Z. 56 Micro Motion ELITE Flow and Density Meters • • Ordering information continued Code Electronics interface 0 Model 2400S transmitter 1 Extended mount Model 2400S transmitter 2 4 -wire polyurethane - painted aluminum integral enhanced core processor for remote mount transmitters 3 4 -wire stainless steel integral enhanced core processor for remote mount transmitters 4 4 -wire polyurethane - painted aluminum integral extended mount enhanced core processor for remote mount transmitters 5 4 -wire extended mount stainless steel integral enhanced core processor for remote mount transmitters Niro Integral FMT Filling Transmitter No Integral FMT Filling Transmitter with improved surface finish (64 Ra) J (2) 2 -wire integrally mounted Model 2200S transmitter U( 2 -wire extended Model 2200S transmitter Code Conduit connections -r�.: , � ��,� iw„�`-z"`�*n.<'= •?°�,� fix=.. "� ": "�'- - �' . �".z� -fin ',�" ��^�'`'. � �C�"^',° '�"".,",� - A Not applicable Fo . 4 it n , _ _._.r_eiectrontcs irtlerface.00�es.� 3 _ 5. .. T � e d ^' B 1/2 -inch NPT — no gland E M20 — no gland F Brass /nickel cable gland (cable diameter 0.335 to 0.394 inches [8.5 to 10 mm]) G Stainless steel cable gland (cable diameter 0.335 to 0.394 inches [8.5 to 10 mm]) For electronics lntetfoce codes Rand.$ 9-wire junction box A 3/4 -inch NPT — no gland H Brass /nickel cable gland J Stainless steel cable gland Code Approvals FQr a 4ct06 ics in a ace co s ' .1, 1f ,. b N M Micro Motion Standard (no approval) N Micro Motion Standard / PED compliant 2 CSA C -US (U.S.A. and Canada) Class I, Div. 2 ✓ ATEX — Equipment Category 3 (Zone 2) / PED compliant 3 IECEx Zone 2 Continued on next page (1) Must be ordered with FMT Filling Transmitter. Transmitter is welded to the sensor case. (2) Available only with calibration option Z. Micro Motion ELITE Flow and Density Meters 57 • S Ordering information continued Code Approvals •^�,. � 3 ^�i ��'�,�= '``��` ,� - - °"- �`-�. - ._�,- �?�,-��— .�`-� ,,; , -�� ; �`��`��^� =�" -F ..•: .�. - . �±�C $ ,� � a� 3'�, �;dt1t� �,� �� a , �� r� ten- ,� F ,"�- ,H M Micro Motion Standard (no approval) N Micro Motion Standard / PED compliant A CSA C -US (U.S.A. and Canada) Z ) ATEX – Equipment Category 2 (Zone 1) / PED compliant 6 (1) ATEX – Equipment Category 2 (Zone 1, IIC modified) / PED compliant; Models CMF200, CMF300, and CMF400 only lo IECEx Zone 1 7 (1) IECEx Zone 1, IIC modified; Models CMF200, CMF300, and CMF400 only p (1)(2) NEPSI 8(1)(2) NEPSI, IIC modified o n nit . _ . ,... ,. Fr . �ectr4t .ica�i a ce :":?.:- _;:; "- =, :: = °_; :.-; _ .:.:- .•. -,:.:, .." ,.;;.::.< M Micro Motion Standard (no approval) N Micro Motion Standard / PED compliant ✓ ATEX — Equipment Category 3 (Zone 2) / PED compliant 3 IECEx Zone 2 A CSA C -US (U.S.A. and Canada) Z ATEX – Equipment Category 2 (Zone 1) / PED compliant IECEx Zone 1 - For e interface ; codes ,2,, A C, !2, S, "}i; and T ; :;. ; M Micro Motion Standard (no approval) N Micro Motion Standard / PED compliant U UL — Not available with electronics interface code C C CSA (Canada only) — Not available with electronics interface code C A CSA C -US (U.S.A. and Canada) Z ATEX – Equipment Category 2 (Zone 1) / PED compliant 6( ATEX – Equipment Category 2 (Zone 1, IIC modified) / PED compliant; Models CMF200, CMF300, and CMF400 only I (1) IECEx Zone 1 7 (1) IECEx Zone 1, IIC modified; Models CMF200, CMF300, and CMF400 only pnx2) NEPSI 8(1)(2) NEPSI, IIC modified Code Language A Danish CE requirements document and English installation manual D Dutch CE requirements document and English installation manual E English installation manual F French installation manual G German installation manual H Finnish CE requirements document and English installation manual Italian installation manual J Japanese installation manual M Chinese installation manual Continued on next page (1) Models CMF200, CMF300, and CMF400 are rated for Group 118 with standard ATEX approval code Z, IECEx approval code 1, or NEPSI approval code P. The IIC modification option (approval codes 6, 7, and 8) should be used only when necessary for the specific area classification. (2) Available only with language option M (Chinese). 58 Micro Motion ELITE Flow and Density Meters • • Ordering information continued Code Language (continued) N Norwegian CE requirements document and English installation manual O Polish installation manual P Portuguese installation manual S Spanish installation manual W Swedish CE requirements document and English installation manual C Czech installation manual B Hungarian CE requirements document and English installation manual K Slovak CE requirements document and English installation manual T Estonian CE requirements document and English installation manual U Greek CE requirements document and English installation manual L Latvian CE requirements document and English installation manual ✓ Lithuanian CE requirements document and English installation manual Y Slovenian CE requirements document and English installation manual Code Calibration options ��;: � °' -- �� ,_.�" � —� �' �ra -�, ?�;;.`� �'sr��',`��, �,�:.,4 -. �`"•"" r , � ,, �"�"` �. s,��; ,ee e � Fo' imode s. , F . �, I -5, . �.: a,,rn gh raf.�mo e�l$ Z 0.10% mass flow and 0.0005 g /cm (0.5 kg /m density DP 0.10% mass flow and 0.0002 g /cm (0.2 kg /m density 2(2) 0.05% mass flow and 0.0005 g /cm (0.5 kg /m density 3 (2) 0.05% mass flow and 0.0002 g /cm (0.2 kg /m density For ' models CMF„SOIO;an l °C, FS015 `° :.'; ::;` C 0.10% mass flow and 0.002 g /cm (2.0 kg /m density K 0.10% mass flow and 0.0005 g /cm (0.5 kg /m density 2 0.05% mass flow and 0.0005 g /cm (0.5 kg /m density For : inodel CMF010 Z 0.10% mass flow and 0.0005 g /cm (0.5 kg /m density 2 0.05% mass flow and 0.0005 g /cm (0.5 kg /m density F - � h tens ra'Eu .. tiiodels .cif... Z 0.10% mass flow and 0.0005 g /cm (0.5 kg /m density Code Measurement application software Z No measurement application software Co Cryogenic application (includes remote core processor for direct host connection) Code Factory options Z Standard product X ETO product Typical model number: CMF050M 313 N 2 BA E Z Z Z (1) For gas or cryogenic liquid applications, select calibration option Z. Mass flow accuracy on gas or cryogenic liquid is ±0.35 %. (2) Requires electronics interface codes 0-5. (3) For gas or cryogenic liquid applications, select calibration option C. Mass flow accuracy on gas or cryogenic liquid is ±0.35 %. (4) Available only with electronics interface code R, conduit option A, and approval options M, 19 or Z. Available only with Models CMF025M, CMF050M, and CMF100M. Not available with wafer process connections. Micro Motion ELITE Flow and Density Meters 59 • il Micro Motion —The undisputed leader in flow and density measurement --°. « World- leading Micro Motion measurement solutions from Emerson ,, 4 n Process Management deliver what you need most: Technology leadership / 4 :4„. i F ': Micro Motion introduced the first reliable Coriolis meter in 1977. Since -, ; t , that time, our ongoing product development has enabled us to ``," "`'\ provide the highest performing measurement devices available. r to `, ` ` s ue , • - , - u Product breadth From compact, drainable process control to high flow rate fiscal / -, transfer —look no further than Micro Motion for the widest range of %, measurement solutions. Unparalleled value Benefit from expert phone, field, and application service and support made possible by more than 750,000 meters installed worldwide and over 30 years of flow and density measurement experience. ibA WW.micromotion.com © 2012 Micro Motion, Inc. All rights reserved. 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Seamount, Chairman John K. Norman 3 Cathy Foerster 4 In the Matter of Application of ) 5 PIONEER NATURAL RESOURCES ALASKA, ) Inc. for Pool Rules for the ) 6 Proposed Oooguruk -Torok Oil Pool ) CO -11 -01 Oooguruk Unit, Beaufort Sea, ) 7 Alaska in Conformance with ) 20 AAC 25.520 ) 8 ) 9 ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska 10 Volume I 11 Public Hearing 12 April 21, 2011 - Pages 02 through 04 April 26, 2011 - Pages 05 through 63 13 9:00 o'clock a.m. 14 BEFORE: John K. Norman, Acting Chairman 15 Cathy Foerster, Commissioner 16 17 18 19 20 21 22 23 24 25 R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 . 411 1 TABLE OF CONTENTS 2 Opening remarks by Acting Chairman John K. Norman 03 Testimony by Dale Hoffman 09/36 3 Testimony by Mike Morgan 12 Testimony by Vern Johnson 53 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 • 4 1 P R O C E E D I N G S 2 (On record - 9:03 a.m.) 3 ACTING CHAIRMAN NORMAN: Good morning. I'll call this 4 hearing to order. This matter comes before the Commission upon 5 the application of Pioneer Natural Resources Alaska, Inc. It 6 involves an application by Pioneer Natural Resources, Inc. for 7 pool rules of proposed Oooguruk -Torok Oil Pool which is 8 situated within the Oooguruk Unit, Beaufort Sea area, Alaska. 9 The application was submitted in compliance with 20 AAC 10 25.520 of the Alaska Administrative Code. The non - confidential 11 portions of the application may be reviewed, if not already 12 done so, at the offices of the Commission. A copy of the non - 13 confidential portions may be obtained by any person by 14 contacting the Commission's special assistant Jody Colombie. 15 My name is John Norman. I am a Commissioner and I am 16 presiding today as temporary chair in the absence the Chairman 17 of the Commission Commissioner Daniel Seamount. Both 18 Commissioners are currently out of town. One required to be 19 out of town on a rather urgent matter. Consequently we lack a 20 quorum this morning and will not be able to proceed with the 21 hearing. 22 The proceeding, however, are being recorded and persons 23 may obtained a copy of these proceedings, as well as any 24 continuation of these proceedings by contacting either the 25 Commission's special assistant or R & R Court Reporting. R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 3 1 The reference to this matter is Docket Number CO- 11 -01. 2 And notice of the hearing as disclosed in the file was duly 3 published in the Alaska Journal of Commerce on March 13th, 4 2011. 5 Accordingly lacking a quorum we will now recess the 6 hearing and reconvene at the hour of 9:00 o'clock a.m. on the 7 morning of Tuesday, April 26th at which time the Commission 8 will have a quorum and be able to consider this matter on its 9 merits. 10 And Ms. Columbie, I would ask that you notify the affected 11 persons of the continuation date. 12 MS. COLUMBIE: Already done. 13 ACTING CHAIRMAN NORMAN: Thank you. Are there any persons 14 before we adjourn who have anything that they would like to 15 say? The Chair sees no one asking to be recognized and 16 accordingly this hearing is concluded and recessed to be 17 continued at the time stated. 18 (Recessed - 9:06 a.m.) 19 20 21 22 23 24 25 R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 4 1 P R O C E E D I N G S 2 (On record - 9:02 a.m.) 3 ACTING CHAIRMAN NORMAN: Good morning. I'll call this 4 hearing to order. This is a continuation of a hearing 5 originally convened last Thursday, April 21st at 9:00 o'clock 6 a.m. At that time lacking a quorum the Commission recessed 7 until we could be joined by Commissioner Foerster. 8 As most of you know the law requires that there must be at 9 least two Commissioners of the three to make a decision and so 10 her return from travel completes the process establishing a 11 quorum. 12 This matter comes before us. It's assigned Docket Number 13 CO- 11 -01. It is an application filed by PIONEER NATURAL 14 RESOURCES ALASKA, INC. for Pool Rules for the Proposed 15 Oooguruk- Torok. And is Torok the general pronunciation 16 this 17 MR. HOFFMAN: Yes. 18 ACTING CHAIRMAN NORMAN: That a new one, okay. The 19 Oooguruk -Torok Oil Pool that being within the Oooguruk Unit, 20 Beaufort Sea area, Alaska. 21 This hearing is being held in conformance with Section 22 25.520 of the Commission's regulation. And briefly those 23 regulations provide that upon the motion a request of an 24 affected owner or operator at any time after discovery of oil 25 or gas in a pool the Commission will hold a hearing in R & R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274 -8982 ANCHORAGE, ALASKA 99501 5 1 accordance with 25.540 which are the general rules applicable 2 to hearing. 3 The Commission will receive a presentation, take evidence 4 and then depending on what is put in the record will issue an 5 Order and established requirements for the further exploration 6 and development of the pool. Those requirements will cover 7 whatever the Commission feels necessary to prevent waste and 8 will be based upon the operating and technical data presented. 9 For the record, again, my name is John Norman. 10 Commissioner to my left is Cathy Foerster, the engineering 11 Commissioner. 12 If there are any persons present who may have special 13 needs to enable you to participate in these proceedings, please 14 see the Commission's special assistant, Jody Colombie who is 15 seated in the rear of the room. 16 R & R Court Reporting will be recording the proceedings 17 and you may obtain a copy of the transcript of proceedings upon 18 conclusion by contacting R & R Reporting or contacting the 19 Commission's special assistant Ms. Colombie who will assist 20 you. 21 We would like to remind all of those who testify to speak 22 into the microphones so that persons in the rear of the room 23 can hear you and also so that the Court Reporter may obtain a 24 clear recording for purposes of creating the transcript of this 25 hearing R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 6 411 411 1 Notice of this hearing was published on March 13th, 2011 2 in the Alaska Journal of Commerce, as well as on the State of 3 Alaska Online Notices and the AOGCC's website, the latter also 4 being published on March 13th, 2011. 5 Before we proceed I would like to ask Commissioner 6 Foerster if she has any comments or anything she would like to 7 add? 8 COMMISSIONER FOERSTER: Not at this time. 9 ACTING CHAIRMAN NORMAN: Very well. Then is the applicant 10 ready to proceed? 11 MR. HOFFMAN: Commissioner Foerster, this is Dale Hoff- -- 12 and Commissioner Norman, this is Dale Hoffman, yes, we are. 13 ACTING CHAIRMAN NORMAN: Very well. Well -- Mr. Hoffman, 14 will more than one person be testifying? 15 MR. HOFFMAN: At present Mike Morgan and I are the ones 16 that have signed in to testify and then if others are necessary 17 we have Staff here to answer questions. 18 ACTING CHAIRMAN NORMAN: Sure. Well, I think, what we'll 19 do for clarity is just swear each of you separately and you 20 will be proceeding first, Mr. Hoffman? 21 MR. HOFFMAN: Yes, sir. 22 ACTING CHAIRMAN NORMAN: Then will you please raised your 23 right hand. 24 (Oath Administered) 25 MR. HOFFMAN: I do. R & R C O U R T R E P O R T E R S 811 G STREET (907)277 -0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 7 41, 410 1 ACTING CHAIRMAN NORMAN: Very well. Please state your 2 name? 3 MR. HOFFMAN: My name is Dale Hoffman. 4 ACTING CHAIRMAN NORMAN: And your affiliation, your 5 company affiliation? 6 MR. HOFFMAN: I'm a senior staff land man for Pioneer 7 Natural Resources Alaska, Inc. 8 ACTING CHAIRMAN NORMAN: Very well. And will you be 9 testifying as to any aspects of the application that require 10 special knowledge or expertise? 11 MR. HOFFMAN: Perhaps in the land area, sir. 12 ACTING CHAIRMAN NORMAN: Very well. Could you then 13 describe for us your experience, background so we can have on 14 the record your credentials? 15 MR. HOFFMAN: Yes, sir. Briefly, stated in the oil and 16 gas business as a land man for Union Oil Company in California 17 in Ventura, California in 1977. Subsequent to that I went to 18 work for Conoco in Ventura, also, in 1979. From there I moved 19 to Alaska in 1982 and worked as a district land man here for 20 Conoco in 1982, '83. I went to the Gulf of Mexico and was a 21 land manager for the Gulf of Mexico for Conoco. 22 Came back and worked Alaska and offshore California for 23 Conoco as their land manager for those areas. I've also worked 24 for Venico (ph) in Santa Barbara, California. Royal Energy in 25 San Diego and moved back to Alaska in 2006 as a land man for R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 8 III 410 1 Pioneer Natural Resources -- or 2005, excuse me, so 2 ACTING CHAIRMAN NORMAN: Very well, thank you. I just 3 mentioned once, but often we have witnesses that are known to 4 the Commission that appear before us, but each time we make a 5 separate record and it is necessary for everyone to remember 6 that you are speaking and making a record that could 7 conceivably be read two or three or four years from now and 8 consequently we can't rely upon the fact that we've seen you 9 before. 10 Commissioner Foerster, do you have any comments or 11 questions of Mr. Hoffman? 12 COMMISSIONER FOERSTER: Not at this time. 13 ACTING CHAIRMAN NORMAN: Okay. Is there any objection to 14 accepting Mr. Hoffman as an expert witness in the area of 15 petroleum land management? 16 COMMISSIONER FOERSTER: None at all. 17 ACTING CHAIRMAN NORMAN: Very well. Mr. Hoffman, please 18 proceed. 19 MR. HOFFMAN: Thank you, sir. Well, I'll be brief in my 20 comments. I want to thank the Commissioners and the AOGCC 21 Staff and the others for the opportunity to speak today about 22 our Oooguruk -Torok pool. 23 I'll start with the slide presentation on the screen and 24 this is slide number 1. And just for our agenda we'll do a 25 brief update of the Oooguruk Unit. We'd like to talk a little R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 9 . . 1 bit about our Torok oil pool proposal, specifically the land. 2 A little bit of history. Mike Morgan will start speaking at 3 that point. He'll talk also about the reservoir, our 4 development plans. 5 I'll come back and address some of the proposed rules and 6 then if there are any questions -- and obviously I expect if 7 there are questions along the way you would have those for us. 8 And, again, we do have staff here in the event that -- we have 9 our drilling manager, subsurface team. We have a number of 10 staff here to answer questions if they're outside our area. 11 So slide 2, just a brief overview. This is our Oooguruk 12 Unit. And I'm using the laser pointer here for the screen. 13 This is our Oooguruk drill site also known as ODS located about 14 six miles offshore. It comes onshore to our Oooguruk tie -in 15 pad with about two miles of flow line. 16 We've been producing since 2008. Our current production 17 when it's steady is around 10,000 barrels a day. Our gross 18 potential at the project is 120 to 150,000 million barrels. 19 And presently were very active in the business of 20 permitting an onshore expansion and you can see faintly a 21 couple proposed pads that were permitting right now and 22 they're also shown on this plat and that's referred to as Nuna 23 drill site 1 and Nuna drill site 2, so you may have seen some 24 things in the paper about that activity. 25 From a land standpoint this is the unit as it currently R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 10 411 411 1 exists. (Slide 3) Our leases are indicated in yellow. 2 There's a blue outline around the existing unit boundary and 3 this is -- you can barely see it in blue. And then we have a 4 proposed unit expansion in with the Department of Natural 5 Resources in this area outlined in red. 6 And then on this particular lease here we recently farmed 7 in Chevron's interes- -- or excuse me, ConocoPhillips interest 8 on that and were working on a Chevron interest, so we have 95 9 percent of that lease sown up right now and were working with 10 Chevon on that. 11 And we've got a Torok participating area that we've 12 applied for with DNR and again that's pending. Any questions 13 on the land situation? 14 ACTING CHAIRMAN NORMAN: Commissioner Foerster? 15 COMMISSIONER FOERSTER: None. 16 ACTING CHAIRMAN NORMAN: Nothing at this time. 17 MR. HOFFMAN: Okay. And now I'd like to introduce Mike 18 Morgan who will give you a little Oooguruk area overview and 19 get into some of the reservoir characteristics. 20 MR. MORGAN: Do I need to be sworn? 21 MR. HOFFMAN: Yeah. 22 ACTING CHAIRMAN NORMAN: Mr. Morgan, would you raise your 23 right hand, please? 24 (Oath Administered) 25 MR. MORGAN: I do. R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 11 . • 1 ACTING CHAIRMAN NORMAN: Very well. Please state your 2 name, your company affiliation? Also your background, 3 experience, anything that would be relevant to gauging you as 4 an expert witness? 5 MR. HOFFMAN: Okay. My name is Mike Morgan. I'm with 6 Pioneer Natural Resources Alaska. I graduated from Colorado 7 School of Mines in 1986. Came directly to Alaska and since 8 then I've worked for various companies starting with ARCO and 9 then their subsequent owners BP, ConocoPhillips in various 10 aspects from field operations through workovers and drilling, 11 reservoir engineering, business development, exploration and at 12 Pioneer I'm known as a reservoir engineer /technical advisor, so 13 25 years in the field. 14 ACTING CHAIRMAN NORMAN: And the last title is reservoir 15 engineering technical what? 16 MR. MORGAN: Advisor. 17 ACTING CHAIRMAN NORMAN: Advisor, okay. 18 MR. MORGAN: Am I close enough to the microphone, can you 19 hear me? 20 ACTING CHAIRMAN NORMAN: Yes, yes, uh -huh, you are. I 21 just wanted to catch that last part of that. Very well. 22 Commissioner Foerster, questions? 23 COMMISSIONER FOERSTER: I'm very familiar with Mr. Morgan. 24 ACTING CHAIRMAN NORMAN: Good. Mr. Morgan, thank you. 25 And then without objection you will be considered qualified and R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 12 1 accepted by the Commission as an expert in this -- in the area 2 of petroleum reservoir engineering. 3 MR. MORGAN: Okay. So I'd like -- with that I'd like to 4 move on to the slides we've got here. I've got 13 slides to, 5 kind of, walk through a general overview history like Dale said 6 and up through our planned development for the Torok oil pool 7 that we proposed. 8 This map basically shows the 9 COMMISSIONER FOERSTER: Mr. Morgan, 10 MR. MORGAN: Yes. 11 COMMISSIONER FOERSTER: Mr. Morgan, we forgot to correct 12 Dale -- Mr. Hoffman with this, but we'll not forget with you. 13 For the record there will be a transcript of your words 14 and 15 MR MORGAN: Um -hum. (Affirmative) 16 COMMISSIONER FOERSTER: you'll be -- every slide 17 you'll say this slide, but when 18 MR. MORGAN: Okay. 19 COMMISSIONER FOERSTER: people are looking to say 20 which slide is this slide knowing that number would be helpful, 21 so we'll add to your technical challenge by making -- asking 22 you to identify 23 MR. MORGAN: Okay. 24 COMMISSIONER FOERSTER: each slide by its number at 25 the start of your R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 13 ill III • 1 MR. MORGAN: Number and title? 2 COMMISSIONER FOERSTER: discussion of it. Yes. 3 MR. MORGAN: Okay. This is slide 4, an area overview of 4 Oooguruk and the proposed pool. Like Dale mentioned here is 5 our unit outline surrounding the development area off the ODS 6 island right up here around this block. And we -- you'll see 7 this rectangle in the slides I go through and that's 8 notionally, kind of, our capture area for this initial phase 9 development of the Nuiqsut reservoir and the Kuparuk reservoir. 10 You can see this is the delta here. You've got the Alpine 11 infrastructure over here, that's Colville Delta 1, 2, 3 and 4. 12 The eastern extent of the Kuparuk River on this side of the map 13 on the eastern side with the Palm 3S and ROTP drill site 3H and 14 then our island out here. 15 And this green outline is basically our -- what we title 16 as the core development area for the Torok so that's basically 17 where we've got proven oil down to the base of the Torok in 18 this Colville Delta 3 well and up to the top and then we define 19 it with the 3D seismic and the well control we have. 20 To get a little vertical perspective the reservoirs we've 21 targeted to date are the Nuiqsut which is the primary resource 22 driver off the island and then the Kuparuk C -sand which is the 23 current rate driver. We wish it were bigger, but were doing 24 the best to get everything can out of it. 25 And then if you move up hole about 1,000 to 1,300 feet R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 14 . . 1 depending which reservoir you're referencing you'll see the 2 Torok interval. It's about a 200 to 250 foot thick section. 3 It's a Turbidite sequence so it's very different depositionally 4 than the C -sand or the Nuiqsut. It's down in the deep -- the 5 deeper water basins. It's similar to the Tarn area, Nanuq, 6 things you might be familiar with, Meltwater. And conventional 7 logging doesn't do it justice as far as how much sand is in 8 there and I'll get into that in a little more detail. 9 So if we go to the next slide, slide 5, I could go over a 10 little bit of the history. It's basically a zoom in of that 11 map. We've got the unit outline again and then I've 12 highlighted -- we've highlighted the exploration wells in that 13 area -- this area. There's up -- in this map alone there's 20 14 exploration wells which define the accumulation. We've also 15 got two 3D seismic surveys that we've merged to define it. And 16 the basis of this orange outline which is our proposed pool 17 outline will become apparent as we talk through the slides. 18 This interval was first seen in 1965 in the Sinclair 19 Colville 1 which is just to the south edge of this map. It was 20 recognized as perspective, but it wasn't until 1986 when Texaco 21 got out here chasing Jurassic, Kuparuk and some of the deeper 22 plays that they actually pursued testing it in the Colville 23 Delta 2 and Colville Delta 3 wells. They also drilled these 24 Colville Delta 1 wells off to the side, but the Torok isn't 25 present and I'll -- they're basically up on the shelf slope and R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 15 . • 1 so they tested these wells. 2 Colville Delta 2 didn't test very well. They had a lot of 3 issues with the cement integrity on the well and they only 4 perforated it and tested it and it flowed -- just basically mud 5 filtrate (ph) back and they gave up on it. 6 Colville Delta 3 was the same way until they fracture 7 stimulated it and they pumped a very small fracture stimulation 8 from today's standards and it produced about 240 barrels a day 9 over about three and a half days. The oil gravity ended at 10 about 24 API. It was diesel based frac so it started out at 11 about 38 so there's some question what's the low (ph) quality 12 out there, but it was a decent test. At that time the oil 13 prices were so low that it was not probably considered 14 commercial. 15 COMMISSIONER FOERSTER: What was the year of that test? 16 MR. MORGAN: 1986. 17 COMMISSIONER FOERSTER: Oil price was low that year. 18 MR. MORGAN: That's when I graduated, so -- and then the 19 -- so the next activity was basically ARCO drilling the Kalubik 20 1 well, Kalubik 3 in the mid to late '90s and Kalubik 2 which 21 is on the upside of this line here and I'll define what that 22 means. 23 This well they actually tested, Kalubik 1, perforated the 24 entire Torok section. Flowed it for -- I don't remember that. 25 It was about 12 hours, but they returned only water, so that's R & R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274 -8982 ANCHORAGE, ALASKA 99501 16 ! • 1 very significant when we go -- start going through the geology 2 as far as water and oil contents. 3 Kalubik 2 which was done in 1998, they didn't actually 4 test that well. They drilled into an amplitude thinking they - 5 - they were hoping to see, kind of, amalgamated channels like 6 they see at Tarn, but they saw these thin bedded, single 7 channel in that well. I'll show you a log in a minute, but 8 they were able to capture an oil sample out of that with an 9 MDT. It was about 19.8 -- 19.8 API which was, you know, tends 10 to be on the lower end. You like to see higher things, but -- 11 but it was captured on an MDT which is good news. 12 It was in 2003 Pioneer came out and was exploring for 13 Kuparuk, Nuiqsut Torok with the Ivik 1, Oooguruk 1 and -- I 14 don't see the Natchiq 1 on there, but -- yeah, here it is down 15 here. And in the process of collecting that data we also did 16 pressure with an MDT tool to establish gradients and, again, we 17 saw -- we saw shows in these wells when we drilled them, but 18 they were pretty faint and then the pressure data suggests 19 these were on a water gradient that was consistent with the 20 pressure we saw -- they saw in Kalubik 1 back in the early 21 '90s. 22 I'm spending some time on this 'cause it's very important 23 on how we define this pool 'cause we do dispose of Class 1 and 24 2 waste off the island into this Torok interval, but we believe 25 its fault separated from this oil accumulation up dip and R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 17 1 we've got pretty good data, you know, this test here and the 2 MDT data that suggests that's the case. 3 And then in 2010 the latest -- or 2009 actually we drilled 4 a well as part of our Oooguruk development in the Nuiqsut. One 5 of the biggest wells we drilled into the Nuiqsut out to the 6 southwest and we -- unfortunately we lost the well, but were 7 able to salvage it and well, let's -- it was a good opportunity 8 to test the Torok and so that's what we did in what we call the 9 ODST -45A. It's also been known as the N -45A. 10 And so we drilled and completed that well. We completed 11 it last March with a fracture stimulation, about 600,000 and it 12 IP'ed at over 1,000 barrels a day, some water which was frac 13 water, but it also produces some formation water. And to date 14 it's produced almost 170,000 barrels over 300 days of 15 production which has been very encouraging 'cause it was, kind 16 of, a short test well. So that's the real first long term test 17 of the Torok. So a little more detail than you might have 18 wanted, but 19 So we're on slide 6, unfortunately it doesn't show up all 20 that great on this projection, so basically what this is, is a 21 structural cross section. It goes from the Kalubik 2 well, the 22 well that was -- tested oil in 1998, the 20 API and my little 23 box goes over the channel sand, but right here's about an eight 24 foot channel sand and you can see that the resistivity here go 25 from one to 10 ohms so it goes over 10 ohms. It approaches R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 18 • 1 close to 40 ohms which suggests that it's got quite a bit of 2 oil in it and pretty low water saturations. 3 The rest of the section on the left here you've got gamma 4 rays so as it moves -- swings to the left it's sandier and as 5 it goes to the right you'll see shales, so the entire Torok 6 package is encased in shale. From our surface casing shoe at 7 about 3,000 feet down to the top of the reservoir hue shale. 8 There's no sands that we've seen in it. And below that from 9 the base of the Torok down to the top of the Kuparuk is shale, 10 so it's pretty well encased. 11 And you can see on these logs that the resistivity in 12 those shales is two to three ohms. And in our reservoir 13 section, this 4,900 feet to 5,100 feet the ohms -- the 14 resistivity goes up to maybe three to five, so what is that and 15 that's always been the question. 16 You can see as you move out into the system you start 17 seeing what we dia- -- the geologists have put in here as 18 sandier sections. It's basically tied to the gamma ray with 19 these yellow and versus orange markings, but you tend to see 20 more sands in this lower member as you go out to the northeast. 21 This would be the Ivik well up towards Thetis Island and 22 Oooguruk 1. Thetis Island would be off the map here. 23 And so the -- the other demarcations on this plot are, 24 there's a number of cores which have been very helpful 25 describing the reservoir which are these green lines is R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 19 i . 1 basically where they've cored things, so in our area we've got 2 three cores, conventional cores. We've got four other wells 3 with rotary side wall cores or percussion side wall cores, so 4 we've got pretty good rock data. Unfortunately we don't have 5 it in our hands, but we're working on that, try to get some 6 more tests done on it. 7 And then these blue bars basically represent where things 8 were tested -- or actually I flipped those around, excuse me. 9 The blue are the core and the green are the test intervals, 10 excuse me. 11 So Kalubik 2 the cored the entire interval almost. 12 Colville Delta 3 just the lower member and Kalubik 1 the lower 13 member. And like I said, the Colville Delta 3 tested at about 14 240 barrels a day. Colville Delta 2 was a short test with 15 water, mostly mud filtrate diagnosed based on the fluoride 16 concentration. And then we had the one test out of the channel 17 sand at Kalubik 2. 18 And then the MDT data basically suggests that out here 19 that you've got water up to 5,210 based on the pressure 20 gradient. And then we've also got this test on Kalubik 1 that 21 suggests we've got water in this zone over here and they 22 perforated the entire interval and returned water over that 23 test. 24 And you step across this fault which is a major feature 25 and it's the definition of our northeast bound of the pool, you R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 20 • 1 start to see oil. You look at the Kalubik 2 we've got an oil 2 test in there. Our ODS or T -45A is basically between Kalubik 2 3 and Colville Delta 2 and it produces at about 800 barrels a 4 day, 10 to 20 percent water cut depending on the day, so that, 5 kind of, describes what we know about the context of the fluids 6 in the reservoir. 7 ACTING CHAIRMAN NORMAN: Could you go back to the 8 preceding slide just for a moment and with the laser pointer 9 show me where that -- that fault sits? What (ph) 10 MR. MORGAN: Basically this pool outline defines where 11 that fault sits, so 12 ACTING CHAIRMAN NORMAN: Okay. 13 MR. MORGAN: it basically runs from the northwest to 14 the southeast. 15 ACTING CHAIRMAN NORMAN: And that's what you're using then 16 is the northern -- okay, got it. 17 MR. MORGAN: Yeah, that's what we define as the boundary. 18 And you 19 ACTING CHAIRMAN NORMAN: Thank you. 20 MR. MORGAN: can map -- that's a deep seated fault 21 that, kind of -- you can see on all the (indiscernible - voice 22 lowers) and I'll show you a line, I think, later that has some 23 -- some of that in there. 24 ACTING CHAIRMAN NORMAN: Okay, please proceed. 25 MR. MORGAN: Okay. So I'll move on to the next slide. R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 21 410 110 1 And, again, the project- -- this is slide 7. Talked a little 2 bit about the reservoir properties. This 3 COURT REPORTER: Mr. Morgan 4 MR. MORGAN: basically is a union of those logs I was 5 showing you on that -- that cross section 6 COURT REPORTER: Mr. Morgan, could you 7 MR. MORGAN: Yes. 8 COURT REPORTER: do me a favor 'cause you're talking 9 away from the mic, just slide them down a little bit. 10 MR. MORGAN: Okay. 11 COURT REPORTER: I don't even know if the (simultaneous 12 speech) 13 MR. MORGAN: I want to stand up, but I won't do that. 14 COURT REPORTER: Thank you. 15 ACTING CHAIRMAN NORMAN: So basically just to give you a 16 feel for the reservoir properties and I'll talk about the 17 structure in the next couple of slides. This is the type log, 18 Kalubik 2. There is where -- the well we offset with our 45A 19 well and you can see the gamma ray. You can see the scatter on 20 it, so there's a lot of sand in there if you were able to 21 resolve it. 22 Conventional logs do not resolve these thin bedded sands. 23 They typically are less than an inch to a few feet thick. And 24 if you look at the core which we don't have permission to show 25 on Kalubik 2, it looks almost identical to this. This is R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 22 41) 111 1 basically an outcrop that shows these kind of sequences, how 2 they -- you know, they're just totally laminated. They 3 alternate sands, shales, sand, shales and they can go for 4 thousands of feet if you look at some of that outcrop data. 5 And that was one of the objectives of the 45A test is do 6 these things really go that far and if they did (ph) the well 7 would have died rather quickly. The performance would have 8 really fallen off, but it hasn't and the pressure hasn't fallen 9 off so it's indicative that were in this basin type system 10 where these sands can go laterally for quite a ways. 11 And so we typically divided up into three zones that we 12 can see on the logs basically, an upper, a mid and a lower. 13 The mid tends to be more channelized where there are channels, 14 but they're pretty few and far between. 15 And if you look at this section, in the Torok cores 16 anyway, there's 40 to 50 percent sand, not all of it's pay 17 quality. You know, we define pay as greater than one 18 millidarcie, but about 75 percent of it is and it average 19 between right around four to 10 millidarcie depending on your 20 cutoffs. It's got decent porosity, you know, 19 percent on 21 average, 20 percent plus in the pay. So it appears to be, you 22 know, from our perspective a very perspective reservoir and 23 that was the purpose of this test, can it flow and it certainly 24 has and that's why we're moving it forward. 25 Additionally we do have some analogues. The Tarn per- - - R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 - 8982 ANCHORAGE, ALASKA 99501 23 i . 1 the Tarn field, particularly the peripheral area of that, 2 that's more sheet sand base if you look at some of the 3 exploration wells out there. Meltwater and Nanuq are also 4 similar. Nanuq more than Meltwater. 5 I'll go to the next slide. Oh, let's back up real quick. 6 I'm back on -- I don't know what number it is. I think 7 it's 8 COMMISSIONER FOERSTER: Seven. 9 MR. MORGAN: Is it seven, okay, thanks, Cathy. Just to 10 give you a perspective of this outcrop. This is a zoom in. 11 This six inches, and you can't see it real well on this slide. 12 It's about the size of our bit, so when were drilling 13 horizontally or, you know, through a section on this thing, our 14 bit may be contacting three or four different sand intervals 15 and three or four different shale sequences which can be an 16 issue depending on the flow you're using drilling through. 17 So I'll go on to the next slide. So this is a seismic 18 line. Basically runs 19 COMMISSIONER FOERSTER: This is slide number 8? 20 MR. MORGAN: Slide number 8, thanks, Cathy. I'll try to 21 do better next time. You go bas- -- this base is going to show 22 the depositional stratigraphic setting of this sand. It goes 23 from Kalubik 3 up on the shelf edge down to the thick area that 24 were working in right here around Kalubik 1, then out towards 25 Thetis Island. It's the best well control we had to show that R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 24 111 411 1 the thinning and the depositional sequence. 2 So this is a seismic line. You can see this broad -- or 3 this bright pink here is the HRZ (ph) which shows up pretty 4 much everywhere and if you were to flatten that completely on 5 that you'd see this is the shelf edge coming over here by 6 Kalubik 3. There's really no sand up there at this point. 7 It's been displaced down into the basin out here and then it 8 ponds along where the shelf edge breaks so they call that a 9 slope apron deposit. 10 We have really good well control like I mentioned. We've 11 got 20 exploration wells. Numerous wells off our drill site. 12 Some of the Kuparuk wells and then our 3D seismic to describe 13 the tank. Ad then it ties very well with the seismic. 14 This is, kind of, a schematic of it, kind of, showing you, 15 you know, if you were to think of, you know, the shelf edge 16 near the beach here and you move out into the basin. These 17 Turbidite sediments come off the shelf, work their way down 18 into the basin and then they settle out right here in the 19 flatter area. 20 Okay. This is slide 9 basically to talk about the 21 structure and isopach of the tank. So the definition of this 22 trap is basically it's a -- you've got on the western side, I 23 think I've talked about, you've got no -- it's a pinch out up 24 along the slope edge. 25 And then to the -- there's a -- basically a plunge to the R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 25 . . 1 east on the structure and then you've got assist (ph) from 2 these faults, these rift -- deep rift faults that drop down as 3 you go to the northeast. And this is the closure we see right 4 here along this mean -- this fault here that we mentioned 5 earlier that defines the northeast part of the pool rules. It 6 also separates us from the Torok disposal zone. 7 And then on the west side the pinch out and then it just 8 thins stratigraphically as you go out into the basin and you 9 can see this on the map on the right. This is a gross 10 thickness map. The orange color is basically, you know, 250 11 feet plus thickness based on our seismic data and well control 12 and then it thins out into the greener, lighter colors about 13 100 feet. 14 Not all of this is oil fill that we can understand. 15 Again, the simplest explanation I'll show the oil in place is 16 that it's one big tank. Turbidities don't tend to behave that 17 way, so as we go along we expect well learn some things and 18 we've tried to, you know, develop our plan accordingly. I 19 don't know if I need to do anything more on that. 20 Fluid properties, we were able to get a really good data 21 set from the 45A well. This is slide 10. It was the first 22 samples of fluids, oil samples and we actually captured water 23 samples, but they were a bit contaminated from the frac water. 24 We weren't able to get a native gas sample because the way we 25 need to flow back our wells off the island is after we frac 'em R & R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274 -8982 ANCHORAGE, ALASKA 99501 26 411 410 1 they've got a four and a half inch completion string. We use 2 gas lift which contaminates the gas. 3 So what we've got, the known data points are basically the 4 pressures, the initial pressure about 2,250 at 5,000 TVD 5 subsea. We have a really good measurement there. We run 6 gauges in all our -- downhole gauges in all our wells, that's 7 been very helpful in diagnosing reservoir performance and 8 production problems. 9 The oil properties it's consistently 24 API gravity which 10 is consistent with the Colville Delta 3 well to the south about 11 three miles and higher than the test on the Kalubik 2 well 12 which is not unusual. In those MDT samples you tend to flash 13 off a lot of light ends (ph). 14 The things we don't know is what is the GOR, the solution 15 GOR (ph) of this oil 'cause we didn't have a native gas sample 16 or we weren't able to do a bottom hole sample, but we put a 17 range in of 250 to 550 so at these pressures and temperature of 18 550 cubic feet per barrel would be a saturated oil and then 19 that spins off these associated properties. 20 You know, you could have a bubble point pressure from 21 1,000 to 2,200 pounds and formation volume factors that range 22 from 1.15 to 1.3 which are a big deal when you get to oil 23 viscosity. This is a first order parameter for your flow and 24 it appears were closer to the two centipoise based on the in 25 flow modeling we've done which is a good thing from recovery R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 27 410 110 1 perspective, too. 2 This is slide 11, the oil in place. This is that same 3 structure map with the Colville Delta underneath it. I didn't 4 explain that earlier. This is our expansion area in red that 5 were proposing to expand the unit to incorporate the Torok 6 development in PA. 7 And then you can't see it real well on here, I've got a 8 green outline here. It's solid green outline. That's 9 basically where we project oil is at the base of the Torok up 10 onto this structure. So basically you look at this map and so 11 you've got oil down to the base, that's what this smaller 12 polygon is. And then this dashed outline is associated where 13 we've got -- you know, on the simplest model oil out to the top 14 over water. 15 And so if you look at that dashed outline it's a very 16 large area. It's 23,000 acres. It averages about 124 feet in 17 thickness. And if you put the parameters we used for our 18 volumetrics in there it's almost 700 million barrels in place, 19 so it's a very large target. And certainly caught our eyes as 20 we starting working and definitely after we got the production 21 up on 45A. 22 Let's go to the next one. Initially what we plan to do, 23 this is slide 12 we're talking about the development area, is 24 we plan to target that smaller area based -- that's defined by 25 the Colville Delta 3 to the south with oil down to 5,150 to the R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 28 411 410 1 base. 2 All our wells, even our injection wells are planned to be 3 fracture stimulated so we really think that if you've got oil 4 over water there's a good chance you're not going to have a 5 long term producing well or an effective flood. You'll tend to 6 bypass the flood through the water, so that's one of the 7 reasons we define this, plus there's just a lot we don't know. 8 We've got a data point of one down there and we hope to change 9 that in the next year so to drill an appraisal well, but that's 10 our initial target area. 11 It averages about 200 -- 210 feet thick on a gross basis. 12 W ere looking at two drill sites. Dale mentioned them earlier, 13 Nuna 1 which is this northern drill site and Nuna 2 that would 14 capture this area and anything that -- you know, else might be 15 out here. And basically those drill sites would be -- we'd 16 have a road coming out from 3S and then we'd take our 17 production back to our OTP for processing and I'll get into 18 that in a little bit more detail. 19 And this is slide 13, it talks basically about the timing 20 of the development and where were at. We notionally called 21 our Oooguruk drill site a pilot 'cause we're basically stepping 22 into this and try to minimize risk and maximize our 23 understanding before we step onshore, so we've got a three well 24 pilot in progress. 25 We just finished drilling the -- hope -- should be the R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 29 . . 1 future injection well once we get our area injection order 2 approved. It's the T46 which offsets the T45A well. We plan 3 to drill two other wells to offset that well at conventional 4 spacing, about 1,500, so that's in progress. We're just 5 clearing that well up from the drilling perspective. We're a 6 bit behind schedule, though, so we probably won't get the 7 second well we planned to this quarter. We'll defer that to 8 fourth quarter or first quarter 2012. 9 We are moving forward with our onshore drill site 10 permitting. That's -- we actually started studies for those 11 sites last year and we started the regulatory process now this 12 year. And we're moving into our more detailed engineering 13 design for the facilities associated with permitting and as we 14 get more data. And were also integrating that with what were 15 doing at Oooguruk as far as trying to maximize production there 16 and minimize back out to Kuparuk. 17 Notionally well drill an appraisal well in 2012 or 2013. 18 Were leaning towards 2012, so that basically would be a well 19 that we drill from the Nuna 1 drill site offsetting that 20 Colville Delta 3 well, but it would be a horizontal well, 21 fracture stimulated just to confirm that we understand what's 22 out there and that we can drill that section 'cause we've had a 23 number of surprises drilling the Oooguruk section. 24 And so our development drilling and construction would 25 start in 2013 and 14 from -- for the Nuna drill sites and our R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 30 • i 1 development drilling would be sometime in the 2014 range. 2 First oil would be in 2015. 3 So slide 14 is to kind of give you a picture of what our 4 conceptual development is. On the right is a -- it's a 5 structure map. It's a little different color coded. You can 6 see the thicks here in orange and, you know, that's basically 7 250 feet plus thick in orange and then the core area that were 8 looking at is about 200 feet thing. 9 That outline around that is in orange here, it's basically 10 that 5150 at the base projected to the top. And then these 11 lines here are basically the 25 wells that range from 5,000 12 feet to 8,000 feet in length that we plan to put in for the -- 13 both the ODS development, these three wells up here and the 22 14 wells to follow from onshore. 15 They're at 1,500 foot inter -well spacing, that's basically 16 40 acre spacing so it's tighter than conventional standards, 17 but its what you need in this type of reservoir. If we could 18 do it tighter we would, but we can't do it cost effectively. 19 These wells typically range from 15 to $20 million depending on 20 where they're at in the section. 21 Were looking to use water and gas when we have it, 22 admissible gas. The same reason we use that in the Nuiqsut is 23 it provide benefits as far as swelling the oil if the oil's 24 under - saturated which reduces the viscosities and allows you to 25 sweep it better. And then it also can connect pore -- or R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 31 . III 1 contact pore volume that water might not be able to so it 2 provides another benefit there. 3 Were limited to what we produce so it's just what we have 4 available unless we can negotiate a contract that's workable 5 with some of the owners for gas. 6 I think I mentioned it would be a phased development. 7 We've got our -- I've got the three wells up here that we plan 8 to drill, the 46 well which we just drilled offsetting the 45A 9 well which is a short term producers. We purposely put 46 500 10 feet away from 45A so we'd can see that response early and get 11 a feel for how this flood performs. And then 47 and 39 will 12 follow either late this year or early next year and then we'll 13 move on to the drill sites. 14 So you're looking at oil in place. You know, this area 15 covers about 8,000 acres between the ODS and Nuna drill site. 16 That's about 340 million barrels in place and we think that we 17 -- between the two, you know, using a modest secondary recovery 18 we can get about 70 million barrels. 19 So to jump into the facilities, Dale described this map 20 earlier. We've got our island out there. We've got about six 21 miles 1 22 ACTING CHAIRMAN NORMAN: Mr. Morgan, 23 MR. MORGAN: Yes, sir. 24 ACTING CHAIRMAN NORMAN: I just want to be sure I'm 25 understanding correctly. So back to slide 14. R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 32 . 411 1 MR. MORGAN: Um -hum. (Affirmative) 2 ACTING CHAIRMAN NORMAN: So then the notation there in 3 that third column 20 percent recovery, that's what you're 4 estimating with this play (ph) of original oil in place is my 5 understanding if I'm reading it right? 6 MR. MORGAN: You're correct, yeah. 7 ACTING CHAIRMAN NORMAN: Okay. 8 MR. MORGAN: Five percent is estimated primary without 9 secondary and then were thinking well get an incremental 15 10 percent from water and admissible gas. And that's one of the 11 work products were doing this year is were upgrading our 12 model to a more sophisticated simulation model and now that we 13 actually have some data we can match performance and so were - 14 - hopefully it will match, but it's very similar to what you 15 see in our Oooguruk reservoir. A little bit lower actually. 16 So on the -- this is slide 15 to talk about the facilities 17 we're planning right now and permitting. We've basically got 18 our existing infrastructure ODS which ties back to OTP via 19 about an eight mile pipeline, part of that subsea. And then we 20 basically rode a drill site from -- take a road from drill site 21 3S out to Nuna drill site 1 and Nuna drill site 2. And then we 22 take our production back to OTP because a three phase 23 production. 24 There's a lot of benefits to us and to Kuparuk that we 25 partial process, get as much gas and water out of the system as R & R C O U R T R E P O R T E R S 811 G STREET (907)277 - 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 33 III III 1 we can and send it on to them for final processing. And then 2 we'd also take water for injection and gas for injection out to 3 the Nuna drill sites from that area, so it's very similar to 4 our island concept, its just onshore. 5 Can we go to the next slide, thanks. From a completion 6 perspective, this is slide 16, this -- our plans are very 7 similar to what were already doing out on the island both for 8 Nuiqsut and for the Torok initial phase development wells. 9 We've got a surface casing that is 13 and a half inch hole, 10 10 and a half -- 10 and three - quarter inch surface casing. It 11 goes down to about 3,000 feet which is just below the West Sac 12 into the hue shale. 13 Permafrost onshore ranges from 1,400 to 1,600 feet so that 14 will be behind pipe (ph) as we go through. Well use a water 15 based mud, conventional mud drilling system through that 16 system. Then we'll drill down pretty high candid section on 17 some of these wells. Some of them approach 80 degrees in 18 concept down to the top of the reservoir. 19 Again, were drilling basically through that hue shale and 20 we haven't had too much difficulty drilling it off the island 21 (ph) but, you know, you can if you do a lot of directional 22 work, but we're getting quite good at it. Vern's group is. 23 So we'll drill that hole, a nine and seven - eights hole 24 down to the -- just into the top of the reservoir or just above 25 it and set seven and five - eighths intermediate casing at about R & R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274 -8982 ANCHORAGE, ALASKA 99501 34 1 5,000 feet and then well drill out our reservoir section and 2 typically that will be horizontal. 3 Were not planning undulating wells like we do in our 4 Nuiqsut well, but it is a thick zone so we're still working 5 through, you know, how do you best fracture stimulate that. 6 It's 200 feet thick. It's got interbedded shales and depending 7 on what model you use some of these fracs break through, some 8 don't so that's part of our goal in our appraisal well is to go 9 in there with a much more aggressive mechanical diversion 10 system and start at the toe of the well and frac backwards and 11 try to contact as much as we can. 12 So that will be a -- typically it's a -- right now we run 13 a solid pipe with perf'ed (ph) holes in it for dynamic 14 diversion, but we're looking at more sophisticated systems with 15 sliding sleeves to do a staged mechanical frac. And then so 16 while were doing that we run a temporary completion of four 17 and a half inch completion for the frac. Well clean it up 18 through a test separator, get all the sand and frac fluids out 19 of there and then we'll recomplete the well with an ESP. 20 On the island well run surface control, subsurface safety 21 valves and associated Packer vent valves and safety systems. 22 Were placing the onshore drill site far enough away from the 23 coast that we shouldn't be required to do that and so that's 24 part of our design basis, but, you know if needed we will run 25 subsurface safety valves. R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 35 • • 1 So it's a real similar completion to what you've seen in 2 the past and the only change will probably be in this 3 production hole in how we frac that. 4 So I think that's all I had and Dale is going to walk 5 through some of the proposed pool rules. 6 ACTING CHAIRMAN NORMAN: Mr. Hoffman, I'll remind you 7 again just for the record that you remain under Oath and you 8 understand that? 9 COMMISSIONER FOERSTER: And I'll remind you that our 10 failure to harass you about calling out the slide number at the 11 start doesn't continue now. 12 MR. HOFFMAN Thank you, Commissioner, and I'll just 13 mention if you read the record of this transcript you'll note 14 that I was doing that from the git -go, so git -go is a 15 colloquialism meaning from the start. 16 COMMISSIONER FOERSTER: Maybe that's why we didn't harass 17 you. 18 MR. HOFFMAN: Thank you. For the record this is Dale 19 Hoffman again. And what I'd like to do if it suits the 20 Commission is just read through our proposed pool rules if 21 that's appropriate for the record. 22 I'm on slide 17, so rule number 1, field and pool names. 23 The field name would be the Oooguruk Field and our defined pool 24 would be the Oooguruk -Torok oil pool. 25 And then rule number 2 for pool definitions, the Oooguruk- R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 36 1 Torok oil pool is defined as the accumulation of oil and gas 2 common to and correlating to the interval found in the ARCO 3 Kalubik number 1 well between the depths of 4,991 feet and 4 5,272 feet measured depth. 5 I'm on slide 18 now, rule 3, well spacing. The 6 requirements of 20 AAC 25.055 are waived for development wells 7 in the Oooguruk -Torok oil pools. Without prior notification, 8 development wells may not be completed closer that 500 feet to 9 an external boundary where the working interest ownership 10 changes. 11 I'm on slide 19, this is drilling and completions, rule 4. 12 After drilling no more than 50 feet below a casing shoe set in 13 the 000guruk -Torok oil pool, a formation integrity test must be 14 conducted. The test pressure need not exceed a predetermined 15 pressure. 16 Casing and completion designs may be approved by the AOGCC 17 upon application and presentation of data that demonstrate the 18 designs are appropriate and based on sound engineering 19 principles. 20 Permits to drill deviated wells shall include a plat with 21 a plan view, vertical section, close approach data and a 22 directional program description in lieu of the requirements of 23 20 AAC 25.050 (b) . 24 A complete petrophysical log suite acceptable to the AOGCC 25 is required from below the conductor to TD for at least one R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 37 III III 1 well drilled from the onshore development in lieu of the 2 requirements of 20 AAC 25.071(a). 3 This is slide 20, rule 5, automatic shut -in equipment. 4 Well safety valves systems shall be installed, if required, 5 pursuant to 20 AAC 25.265. 6 Slide 21, rule 6, reservoir pressure monitoring. A 7 minimum of one bottomhole pressure survey shall be measured 8 annually in the Oooguruk -Torok Oil Pool. 9 The reservoir pressure datums shall be 5,000 feet TVD 10 subsea for the Oooguruk -Torok oil pool. 11 Pressure surveys may consist of stabilized static pressure 12 measurements at bottom -hole or extrapolated from surface 13 pressure fall -off, pressure build -up, multi -rate tests, drill 14 stem tests or formation tests. 15 Data and results from pressure surveys shall be reported 16 annually on Form 10 -412, Reservoir Pressure Report. All data 17 necessary for the analysis of each survey shall not be -- 18 excuse me, shall -- need not be submitted with the Form 10 -412, 19 but shall be made available to the AOGCC upon request. 20 Slide 22, rule 7, gas -oil ratio exemption. Wells 21 producing from the Oooguruk -Torok oil pool are exempt from the 22 gas -oil ratio limits of 20 AAC 25.240(a) so long as the 23 provisions of 20 AAC 25.240(c) apply. 24 Rule 8, common production facilities and surface 25 commingling. Production from the Oooguruk -Torok oil pool may R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 38 • 1 be commingled on the surface prior to custody transfer. 2 Production shall be allocated to the pool on the basis of each 3 well testing and producing conditions for each well. 4 Slide 23, well testing, rule 9. All producing wells must 5 be tested at least once per month. Stabilization and test 6 duration times will be managed to obtain representative tests. 7 Operating conditions shall be recorded in a manner 8 appropriate for maintaining accurate field production history. 9 Records to allow verification of production allocation 10 methodologies shall be maintained and be available to the AOGCC 11 upon request. 12 Slide 24, rule 10, sustained casing pressure. (a) the 13 operator shall conduct and document a pressure test of tubulars 14 and completion equipment in each development well at the time 15 of installation or replacement that is sufficient to 16 demonstrate that planned well operations will not result in 17 failure of well integrity, uncontrolled release of fluid or 18 pressure or threat to human safety. 19 (b) the operator shall monitor each development well to 20 check for sustained pressure, except if prevented from doing so 21 by extreme weather conditions, emergency situations or similar 22 unavoidable circumstances. Monitoring results shall be made 23 available for AOGCC inspection. 24 (c) the operator must notify the AOGCC within three 25 working days after the operator identifies a well as having, R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 39 III 1 one, sustained inner annulus pressure that exceeds 2,000 psig 2 or two, sustained outer annulus pressure that exceeds 1,000 3 psig. 4 (d) the AOGCC may require the operator to submit in an 5 Application for Sundry Approvals (Form 10 -403) a proposal for 6 corrective action or increased surveillance for any development 7 well having sustained pressure that exceeds a limit set out in 8 part (c) of this rule. The AOGCC may approve the operator's 9 proposal or may require other corrective action or 10 surveillance. The AOGCC may require that corrective action be 11 verified by mechanical integrity testing or other AOGCC 12 approved diagnostic tests. The operator shall give AOGCC 13 sufficient notice of the testing schedule to allow AOGCC to 14 witness the tests. 15 Twenty -five, this is slide 25, (e) if the operator 16 identifies sustained pressure in the inner annulus of a 17 development well that exceeds 45 percent of the burst pressure 18 rating of the well's production casing for inner annulus 19 pressure or sustained pressure in the outer annulus that 1 20 exceeds 45 percent of the burst pressure of the well's surface 21 casing for outer annulus pressure, the operator shall notify 22 the AOGCC within three working days and take corrective action. 23 Unless well conditions require the operator to take 24 emergency corrective action before the AOGCC approval can be 25 obtained, the operator shall submit in an Application for R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 40 . . 1 Sundry Approvals (Form 10 -403) a proposal for corrective 2 action. 3 The AOGCC may approve the operator's proposal or may 4 require other corrective action. The AOGCC may also require 5 that correction action be verified by mechanical integrity 6 testing or other AOGCC approved diagnostic tests. The operator 7 shall give AOGCC sufficient notice of the testing schedule to 8 allow AOGCC to witness the tests. 9 (f) except as otherwise approved by the AOGCC under part 10 (d) and (e) of this rule, before a shut -in well is placed in 11 service, any annulus pressure must be relieved to a sufficient 12 degree, one, that the inner annulus pressure at operating 13 temperature will be below 2,000 psig. And, two, that the outer 14 annulus pressure at operating temperature will be below 1,000 15 psig. 16 However, a well that is subject to part (c), but not part 17 (e) of this order may reach an annulus pressure at operating 18 temperature that is described in the operator's notification to 19 the AOGCC under part (c), unless the AOGCC prescribes a 20 different limit. 21 (g) for purposes of these rules, "inner annulus" means the 22 space in a well between tubing and production casing. "Outer 23 annulus" means the space in a well between the production 24 casing and surface casing. "Sustained pressure" means pressure 25 that, one, is measurable at the casing head of an annulus. R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 41 . . 1 Two, is not caused solely by temperature fluctuations. And, 2 three, is not pressure that has been applied intentionally. 3 I'm on page 26, rule 11, administrative action. Upon 4 proper application of its own motion, the AOGCC may 5 administratively waive the requirements of any rule stated 6 above or administratively amend this order. 7 And slide 27 just ask if there are any questions from the 8 Commission. 9 ACTING CHAIRMAN NORMAN: Just one general question, Mr. 10 Hoffman. The slides and the proposed rules reflected therein, 11 is there any variation between those and the rules that were -- 12 that are contained here -- we've not put those side by side and 13 compared them, so were there any changes between the time of 14 the original filing and what you've read? 15 MR. HOFFMAN: This is Dale Hoffman. Commissioner Norman, 16 slide -- on page 20 -- slide 20, rule 5 is different from what 17 we had applied for initially. 18 ACTING CHAIRMAN NORMAN: Very good. And that's it, right? 19 MR. HOFFMAN: Yes, sir. 20 ACTING CHAIRMAN NORMAN: Okay. Commissioner Foerster? 21 COMMISSIONER FOERSTER: I have a lot of questions, but I'd 22 like to take a recess first so that our Staff can eliminate the 23 stupid questions. 24 ACTING CHAIRMAN NORMAN: Very well. But I've never known 25 you to ask a stupid question, Commissioner Foerster. R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 42 1 At the request of Commissioner Foerster we will take a -- 2 we'll take a 10 minute recess so we will reconvene at five 3 after 10:00. 4 (Off record - 9:55 a.m.) 5 (On record - 10:08 a.m.) 6 ACTING CHAIRMAN NORMAN: I'll call the meeting back to 7 order. The Commission has taken a brief recess to review and 8 consolidate questions to avoid repetition and I will call upon 9 Commissioner Foerster to see if she has any questions she would 10 -- of the applicant. 11 COMMISSIONER FOERSTER: Well, surprisingly none of my 12 questions were eliminated, so yes, I do. Let's go to slide 4 13 for just a minute. And on slide 4 it appears that the 14 southeastern boundary is defined simply by the unit boun- - -the 15 acreage ownership boundaries, is that correct? 16 MR. MORGAN: This is Mike Morgan. Yes. And to where the 17 -- you start to see oil over water and we don't have any well 18 control in that area, so 19 COMMISSIONER FOERSTER: But looking on your subsequent 20 slides that show, let's see which one was it, slide number 9 it 21 appears that -- and -- well, let's see, where's a better one 22 than slide number 9. I think slide number 11 it appears that 23 your boundary goes a little bit into the drill site 3S area. 24 So my question is, have you had any con- -- any discussions 25 with Conoco about development of that area and possibly R & R C O U R T R E P O R T E R S 811 G STREET (907)277 - 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 43 411 410 1 pooling, combining acreage ownership? 2 MR. HOFFMAN: This is Dale Hoffman. We have had 3 conversations with ConocoPhillips about the possibility of 4 doing some work with them in that area, but at this point we've 5 not gotten any further than just preliminary conversations. 6 COMMISSIONER FOERSTER: Okay. Let's look at slide number 7 10. I'm going to, kind of, bounce around a little bit, we'll 8 just do the stream of consciousness approach. Do you have any 9 plans to get better fluid property data? 10 MR. MORGAN: This is Mike Morgan. We do. Actually we 11 just completed the 46A -- or 46 well and we've also recompleted 12 the 45A well with an ESP so we'll be able to get a composition 13 on the gas and we'll take additional oil samples. 14 COMMISSIONER FOERSTER: And, you know, you've given a 15 broad range of could be this, anywhere from this to this on 16 some of the properties, would there be any changes to your 17 development plan or your producing strategy if you got 18 additional data and you went from one end to another of this 19 range or went outside the range? 20 MR. MORGAN: Again, this is Mike Morgan. Our expectations 21 would be on recovery, if you had the higher saturations, the 22 oil is less viscus and you may displace it better. The one 23 outcome that could change things is if there were a gas cap 24 that may -- that may displace some of our wells. There isn't a 25 market for gas right now and the back out to Kuparuk would be R & R C O U R T R E P O R T E R S 811 G STREET (907)277 -0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 44 i i 1 rather large so that would have an outcome. 2 COMMISSIONER FOERSTER: Okay. But it wouldn't change your 3 development plan? 4 MR. MORGAN: No, it would basically still be a horizontal 5 line drive, about 1,500 foot. You know, that may go down or up 6 depending on what the more rigorous simulation work shows and 7 the results from these series of wells we're drilling in the 8 next year as far as performance. 9 COMMISSIONER FOERSTER: Okay. I forget which slide it 10 was, but you talked about 40 acre spacing in one of -- in one 11 of your slides. Well, let's just look at 14, that's a good 12 one. It shows all the drilling. You mentioned that if you 13 were able to go to denser spacing you would, but its not 14 economical. If you were able to economically justify denser 15 spacing, what spacing would you consider to be the boundary and 16 what additional recovery would you anticipate with the denser 17 spacing? 18 MR. MORGAN: This is Mike Morgan. With this kind of rock 19 averaging four to 10 millidarcies, you know, ideally you'd be 20 down in the 20 acre spacing and so, again, it improves your 21 aerial sweep and your vertical sweep in all directions, but at 22 the cost you have for drilling 6,000 foot horizontal wells you 23 just can't afford it, so we -- 24 COMMISSIONER FOERSTER: Well, I 25 MR. MORGAN. I haven't done the rigorous modeling as R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 45 4111 411 1 far as we don't have the -- you know, the relevant perm data 2 from the rocks. 3 COMMISSIONER FOERSTER: So in our unrigorous modeling, 4 what 5 MR. MORGAN: Well, if you look at analogues on the North 6 Slope that are at similar types of developments, the Alpines, 7 the Tarns, Fjords, the range in spacing on these type of rocks, 8 they're typically in the 10 millidarcy range is anywhere from 9 1,000 feet to 2,000 feet inter -well spacing. 10 COMMISSIONER FOERSTER: Well, what I'm looking for is the 11 second half of my question, what is (indiscernible) recovery 12 would you anticipate with it -- with -- if you don't hold your 13 spacing, if you went to 20 acre spacing or have (ph) 14 MR. MORGAN: To be honest with you, Commissioner, I can't 15 tell you off the top of my head. 16 COMMISSIONER FOERSTER: Okay. So how did you make the 17 decision that it wasn't economical if you didn't know how much 18 more oil you'd get? 19 MR. MORGAN: I assumed. Again, probably back in 2009, I 20 assumed a -- you know, probably just a linear relationship and 21 I don't recall what it was, but it's not a huge recovery 22 because you're staring with pretty high saturations. Were 23 looking at oil saturations approaching 50 percent so your 24 displaceable pore volume is pretty small to start with and then 25 you'd throw in a vertical and aerial sweep component over - - R & R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274 -8982 ANCHORAGE, ALASKA 99501 46 1 you know, the vertical is 200 feet. There's a lot of 2 uncertainty. So I basically had a, you know, very modest 3 improvement with increasing tighter well spacing. 4 COMMISSIONER FOERSTER: Okay. 5 MR. MORGAN: And it -- the metric I used basically was 6 just an F &D, you know, you assume a constant well cost and 7 then, you know, what do you realize as far as barrels and you 8 come up with a dollar per barrel cost and it pretty quickly 9 goes over to 40 bucks a barrel when you start going below 10 COMMISSIONER FOERSTER: So you turned a corner at 40 and 11 so you didn't keep looking? 12 MR. MORGAN: Uh -huh. (Negative) 13 COMMISSIONER FOERSTER: Okay. Since you -- you've got 14 your well paths laid out, I'm assuming that you already know 15 what your frac direction is and that, that has influenced the 16 direction of your drilling, is that correct? 17 MR. MORGAN: This is Mike Morgan. Yeah, we've done quite 18 a bit of work in trying to understand the tectonics of the 19 area. Similar to our Nuiqsut wells we've pretty well defined 20 what we think the principal orientations are for the stress and 21 we tend to drill these horizontal wells along that direction, 22 especially fractured wells, otherwise you could have bypass 23 events between the -- 24 COMMISSIONER FOERSTER: Right. 25 MR. MORGAN: between the wells. R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 47 411 411 1 COMMISSIONER FOERSTER: Okay. 2 MR. MORGAN: It's -- but that's still the data were 3 looking to collect is -- it wasn't obvious what the orientation 4 was, but if you look at the regional context this fits pretty 5 well. And 6 COMMISSIONER FOERSTER: Okay. 7 MR. MORGAN: today at the Nuiqsut level this seems to 8 be working out well, this orientation. 9 COMMISSIONER FOERSTER: So how far into this plan are you 10 going to get before you know whether you're right or not? 11 MR. MORGAN: Well, that's part of the purpose of the pilot 12 is to -- is the reason we put 45A and 46 so close together is 13 -- you know, 14 COMMISSIONER FOERSTER: Okay. 15 MR. MORGAN: is the -- is the break through event, if 16 it does occur, is it associated with a channel or is it 17 associated with fracture propagation (ph) and 18 COMMISSIONER FOERSTER: Okay. So you could be -- there 19 could be major amendments to this drilling plan based on the 20 pilot? 21 MR. MORGAN: Yeah. And just 22 COMMISSIONER FOERSTER: Okay. 23 MR. MORGAN: a comment on that. I would say there 24 could be, but it's unlikely given the regional (ph) data that 25 we have on this stress orientations. R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 48 1 COMMISSIONER FOERSTER: Okay. Go back to slide number 9 2 for just a minute. Is the Torok present in any of the wells 3 drilled at 3S pad? 4 MR. MORGAN: This is Mike Morgan. Yes, it's present. I 5 mean, we basically use that data to help control our seismic. 6 COMMISSIONER FOERSTER: Okay. It -- has 7 MR. MORGAN: It hasn't been tested that we're aware of. 8 COMMISSIONER FOERSTER: Does it have log characteristics 9 comparable to the ones that you consider to be productive or 10 does it loo- -- does it look wet? 11 MR. MORGAN: Again, it's hard to resolve on conventional 12 logs and typically the logs completed (ph) on those wells is 13 pretty limited. 14 COMMISSIONER FOERSTER: Okay. 15 MR. MORGAN: They're development wells, especially in that 16 section. 17 COMMISSIONER FOERSTER: Okay. 18 MR. MORGAN: I'm not sure where the surface hole (ph) is 19 at these time, but 20 COMMISSIONER FOERSTER: Okay. So its possible as you 21 advance in your Torok development you could very well be 22 approaching Conoco for some involvement? 23 MR. MORGAN: It's possible, yes. 24 COMMISSIONER FOERSTER: Okay. Does the Torok produce 25 anywhere else on the North Slope? R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274-8982 ANCHORAGE, ALASKA 99501 49 411 410 1 MR. MORGAN: This is Mike Morgan again. I'm not aware of 2 anywhere else. You know, there's other cretaceous 3 (indiscernible) analogues, but not -- not specifically the 4 Torok. 5 COMMISSIONER FOERSTER: What rate do you anticipate from 6 this development when it -- at peak? 7 MR. MORGAN: Peak rates, depending on your pace and how 8 you -- how effective our completions are. Completions are a 9 big deal. We -- depending on the scenario we have rates that 10 range from 7,000 to 15,000 barrels a day 11 COMMISSIONER FOERSTER: Okay. 12 MR. MORGAN. and it's a wide range, but we have one 13 test to date, so 14 COMMISSIONER FOERSTER: Okay. And I'm assuming there will 15 be a lot of water with that initially at least with your fracs, 16 but do your existing separation facilities, will they be 17 adequate to handle your initial production or do you anticipate 18 expansion of your production facilities? 19 MR. MORGAN: We anticipate we -- we'd be expanding our 20 production facilities at OTP. We'll be doing some of that 21 anyway with the break through at the ODS development as far as 22 water production and things, so just 23 COMMISSIONER FOERSTER: Okay. One more reservoir question 24 and then some more esoteric questions. That big fault, do you 25 see a difference in pressure on the -- up to the northeast than R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 50 19 1 you do in the producing area? 2 MR. MORGAN: We see -- we do see a difference in pressure, 3 but its -- this reservoir is not very over pressured, but when 4 you're down on the down throne (ph) side of that fault, down 5 towards Kalubik 1 and Ivik 1 your at pretty -- you're at a 6 water gradient basically, you know, 8.5, 7 COMMISSIONER FOERSTER: Um - hum. 8 MR. MORGAN. 8 6 (ph) pounds per gallon equivalent. 9 When you step up to Kalubik 2 and the 45A well you're at an 10 8.7, you know, 8.7 pound per (indiscernible), so it's slight 11 and in this type of rock you'd expect very transit- -- long 12 transition zones, but you do see a difference. And you 13 definit- -- and if you look at cores under UV light you can see 14 a difference in the Kalubik 1 core versus the Kalubik 2 and 15 Colville Delta 3. 16 COMMISSIONER FOERSTER: Do you have Conoco's concurrence 17 for the surface commingling of this new production stream or do 18 you need it? 19 MR. MORGAN: We will -- we do have from ODS from the 20 existing production from 45A. Were producing to Conoco right 21 now. We have their concurrence 22 COMMISSIONER FOERSTER: Okay, okay. 23 MR. MORGAN. and we're working with them on our Nuna 24 expansion. 25 COMMISSIONER FOERSTER: Okay, all right. The success of R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 51 . . 1 this program is going to rely on being able to frac these 2 wells, is Pioneer concerned about political trend and EPA 3 involvement in fracing regulations? 4 MR. MORGAN: Do you want to answer that (ph)? 5 MR. HOFFMAN: Sure. This is Dale Hoffman. 6 COMMISSIONER FOERSTER: Well, this is the first esoteric 7 question, by the way. 8 MR. MORGAN: That's perfect. 9 MR. HOFFMAN: I'm sure there will be more. This is Dale 10 Hoffman. I believe Pioneer is concerned about the 11 environmental, potential political implications of fracing. I 12 know that Jay Still (ph) one of our senior officers is working 13 with people in the Lower 48 on that, so we're very much engaged 14 in that given the operations we have in Texas certainly. 15 COMMISSIONER FOERSTER: Okay, all right. I have one more 16 request. As you were reading through the proposed pool rules, 17 Mr. Hoffman, two thoughts came to mind. First, if you ever 18 decide to quit your job as a land man you might go to a 19 publisher and be one of those people who reads audio books 20 because you have a lovely voice, that was my 21 MR. HOFFMAN: Thank you, Commissioner Foerster. 22 COMMISSIONER FOERSTER: attempt at a laugh. 23 Now, the serious question, it appears that some of your 24 rules are simply a restatement of regulations and so when 25 that's the case don't be disappointed, but those probably won't R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 52 1 show up in our official rules 'cause we try not to restate 2 regulations so that it's clear that you're expected to follow 3 all of our regulations unless something is specifically 4 different in the pool rules. 5 So that leads to my last question and probably my most 6 painful one, would you go back to slide 17 and starting from 17 7 go rule by rule and address just the rules that are a 8 difference and explain why the difference is needed? 9 MR. HOFFMAN: This is Dale Hoffman. Can I use my Oil and 10 Gas statutes book? I mean, I -- I think the one that is the 11 exception to that really is going to be I believe rule 5 and I 12 may defer this question to Vern Johnson our drilling manager on 13 some of the pool rules if that's acceptable? 14 COMMISSIONER FOERSTER: Okay. That's a -- however you 15 want to answer the question is fine by me. 16 MR. HOFFMAN: You okay addressing some of that? 17 MR. JOHNSON: (Indiscernible - away from microphone) 18 ACTING CHAIRMAN NORMAN: Mr. Johnson, why don't you come 19 forward and be seated right here and we will quickly place you 20 on the record, also for the purpose. Would you raise your 21 right hand, please? 22 (Oath Administered) 23 MR. JOHNSON: I do. And would you state your name and 24 briefly your position and professional experience? 25 MR. JOHNSON: Okay. My name is Vern Johnson. I am the R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 53 1 drilling manager for Pioneer Natural Resources Alaska. I've 2 been in the drilling and completions industry in various roles 3 for the last 14 years both in Alaska and the Middle East and 4 some in Canada. Been with Pioneer for just over two years. 5 Prior to that I worked for Halliburton in various roles all in 6 drilling and completions. 7 ACTING CHAIRMAN NORMAN: Thank you. Now we'll turn it 8 back to Mr. Hoffman, but if you are called upon I remind you 9 that you will remain under Oath. Mr. Hoffman. 10 MR. HOFFMAN: Thank you. And -- and, Commissioner Norman, 11 I'd like to defer to Vernon to just address some of those 12 proposed changes in our pool rules if that's acceptable? 13 ACTING CHAIRMAN NORMAN: That is accepted. 14 MR JOHNSON: And were specifically talking about 15 the 16 MR HOFFMAN: Any of them that are just different from -- 17 I mean, obviously the first two are just a resistation 18 COMMISSIONER FOERSTER: Right. 19 MR. HOFFMAN: of the pool and the title and 20 COMMISSIONER FOERSTER: And rule 3 I understand that -- 21 you know, I don't need a description of why you're looking for 22 rule 3, but let's start with rule 4 then and move -- and go 23 from there down if -- if its different from our statewide 24 regulations then what's the justification for wanting to be 25 special? R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 54 . . 1 MR. JOHNSON: Okay. 2 ACTING CHAIRMAn NORMAN: I would like to ask, if you would 3 permit me, Commissioner Foerster, on rule 3, Mr. Johnson, 4 second sentence, without prior notification, development wells 5 may not be completed 500 within external boundary, et cetera, 6 is that to be read without prior notification and approval by 7 the Commission? 8 COMMISSIONER FOERSTER: Yeah. 9 ACTING CHAIRMAN NORMAN: I mean, that's what the intent of 10 that is, correct? 11 MR. JOHNSON: Yes. 12 ACTING CHAIRMAN NORMAN: Okay. 13 COURT REPORTER: Actually, who answered yes? 14 MR. JOHNSON: Sorry, this is Vern Johnson. Yes. 15 COURT REPORTER: I just can't identify a voice in one 16 word. 17 ACTING CHAIRMAN NORMAN: Please proceed, Mr. Johnson. 18 MR. JOHNSON: Okay. Rule 4, the drilling and completion 19 practices on slide 19. Just looking through this slide I don't 20 think there's anything that deviates from what's already in the 21 AOGCC regs. 22 COMMISSIONER FOERSTER: Okay. Well, then you -- we may 23 not -- a drilling and completion practices rule may not appear 24 in the final order unless someone on our Staff feels that 25 there's a need for something tighter. Okay. R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 55 1 MR. JOHNSON: Yup, and 2 COMMISSIONER FOERSTER: And rule 5 is another one that 3 probably won't show up. 4 MR. JOHNSON: Right. And that was -- that was one slide 5 that had been changed from the original application, is that 6 right, Dale? 7 MR. HOFFMAN: Yes, correct. 8 COMMISSIONER FOERSTER: Well, since you're up there let's 9 see -- I don't think there are any other ones that relate to 10 drilling. Well -- but you would probably be the one to answer 11 on sustain casing pressure and that sort of stuff as well, 12 wouldn't you or is there a production engineer that would be 13 better prepared to -- rule 10? 14 MR. JOHNSON: I think I can answer that. 15 COMMISSIONER FOERSTER: Okay. Well, just for simplicity, 16 flow, let's just let you answer all the ones that relate to you 17 and then well 18 MR. JOHNSON: All right. And 19 COMMISSIONER FOERSTER: ....release you. 20 MR. JOHNSON: as before, you know, on slide -- this 21 is Vern Johnson. The sustained casing pressure, rule 10, I 22 believe that is all very much a paraphrase of what's in the 23 AOGCC regulations. 24 COMMISSIONER FOERSTER: Okay, okay. Well, then it likely 25 won't show up in the final order. Okay. How about rules 6 R & R C O U R T R E P O R T E R S 811 G STREET (907)277 - 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 56 • 1 through 9, anything there? Those -- I don't think those relate 2 to drilling. They're more production operations related. I 3 don't know who you want to have answer those questions. 4 (Side conversation) 5 COMMISSIONER FOERSTER: So, Mr. Morgan, you're going to? 6 MR. MORGAN: So this is Mike Morgan. On rule 6, page 21, 7 I believe this is consistent with what the regulations also say 8 that you will, you know, obtain this data, anything (ph), in 9 this manner, so -- and then if you go to rule 7 (ph) 10 COURT REPORTER: I'm sorry, you're dropping your voice so 11 I can't hear you. 12 MR. MORGAN: Oh, I'm sorry. It's consistent with the regs 13 from what I know so it's not necessary. 14 Rule 7, the gas -oil ratio exemption, I think that applies 15 here. And then I think well also be requesting a GOR 16 exemption during the interim period between producing now and 17 when we start injecting in -- after our Area Injection Order 18 review. 19 COMMISSIONER FOERSTER: Okay. 20 MR. MORGAN: And rule 8 on slide 22, I'm not sure if this 21 is in the regs, but it's part of our existing pool rules for 22 the Nuiqsut and Kuparuk and it's what we plan to do, so I'm not 23 certain on that. 24 COMMISSIONER FOERSTER: So will your well testing 25 equipment and practices be the same as you're currently using R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 57 • 1 at the ODS? 2 MR. MORGAN: This is Mike Morgan. Our plan is to use the 3 same systems, multi -phase flow meters 4 COMMISSIONER FOERSTER: Okay. 5 MR. MORGAN: for well testing and then custody 6 transfer at OTP with multi -phase flow meters. 7 COMMISSIONER FOERSTER: Okay. 8 MR. MORGAN: Rule 9, slide 23, well testing. Again. I'm 9 not sure this is spelled out in the regulations of the AOGCC, 10 but its part of our rules on our other pools 11 COMMISSIONER FOERSTER: Okay. 12 MR. MORGAN: so we just incorporated that. 13 COMMISSIONER FOERSTER: Okay. 14 MR. MORGAN: Slide 24, I think we've covered, 15 COMMISSIONER FOERSTER: Right. 16 MR. MORGAN. that's the sustained casing pressure. 17 COMMISSIONER FOERSTER: Okay, that's -- that takes care of 18 it. And I hope you didn't take that as -- you know, my comment 19 as criticism because often we cause our own confusion by 20 restating our regulations, but we're trying harder not to do 21 that because then it implies that those are the only ones you 22 have to follow rather than following all of them and we are 23 trying hard not to do that. 24 ACTING CHAIRMAN NORMAN: Mr. Hoffman, you 25 MR. HOFFMAN: I was just going to sa- -- this is Dale R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 58 • 1 Hoffman for the record. We don't take it as a criticism and we 2 appreciate it and the next time we submit pool rules we won't 3 do that. 4 COMMISSIONER FOERSTER: That's all I have other than I 5 really appreciate the quality of the presentation today and the 6 fact that you brought all the right people. 7 MR. HOFFMAN: Thank you. 8 ACTING CHAIRMAN NORMAN: Thank you, Commissioner Foerster. 9 Just a footnote to the commentary on the regulations, the 10 Commission from time to time may, as a result of advances in 11 good oil field practices, change the regulations. And another 12 concern, of course, that we have is if we have sprinkled 13 throughout different orders than it makes it a more challenging 14 task to do back and change everything as opposed to the 15 regulations. 16 So as Commissioner Foerster, were trying to work away 17 from that, but we do acknowledge that if you were to go back in 18 the history of the Commission you would find places where the 19 regulations are stated and so its certainly no criticism. 20 I am going to -- yes, Mr. Hoffman. 21 MR. HOFFMAN: Before you close I have a couple comments, 22 if that's -- whenever 23 ACTING CHAIRMAN NORMAN: Please. appropriate? First I'd j 24 MR. HOFFMAN: that's just 25 like to say thanks to the AOGCC Staff that helped us through R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 59 • i 1 this process particularly Steve, Guy and Dave were all great. 2 And then Christine helped us with some research, so really 3 appreciate the work that we do with your Staff and want to say 4 thank you on the record for that. 5 And lest you go home tonight and wake up in the middle of 6 the night and the one question you forgot to ask is why do we 7 call the drill sites Nuna. We did such a fine job with 8 Oooguruk when we took over the project that we decided that we 9 would actually research whatever were going to call our 10 onshore drill site, Nuna being an Inupiat word for land or 11 onshore, so that was deemed appropriate and that's why its 12 Nuna and not N- o -o -n -a or anything like that, so 13 COMMISSIONER FOERSTER: And if you go to Midnight Sun 14 they'll have a beer that you will definitely not want to name 15 any of your drill sites after. 16 MR. HOFFMAN: I've seen those. 17 COMMISSIONER FOERSTER: Okay. 18 MR. HOFFMAN: Yes, thank you. 19 ACTING CHAIRMAN NORMAN: And correct me if I'm wrong, Mr. 20 Hoffman, but as I recall Oooguruk means hair seal in Inupiat, 21 is that correct? 22 MR. HOFFMAN: It is bearded seal and 23 ACTING CHAIRMAN NORMAN: Bearded -- bearded seal. 24 MR. HOFFMAN: it's a special spelling of that word, 25 so yes, you're correct, Commissioner Norman. R & R C O U R T R E P O R T E R S 811 G STREET (907)277 - 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 60 • • 1 ACTING CHAIRMAN NORMAN: And then pool name 2 MR. HOFFMAN: Torok. 3 ACTING CHAIRMAN NORMAN: Yes. And what in Inupiat does 4 that mean, if you know 5 MR. HOFFMAN: I'm not sur- 6 ACTING CHAIRMAN NORMAN: 'cause I don't? 7 MR. HOFFMAN: This is Dale Hoffman. I'm not sure that 8 Torok means anything in Inupiat, but I will check that for you 9 and let you know. 10 COMMISSIONER FOERSTER: Well, how was it named? 11 MR. HOFFMAN: Say again? 12 COMMISSIONER FOERSTER: How did you come with -- how did 13 you determine the name Torok or is that -- was that in place 14 before you guys got here? 15 MR. HOFFMAN: We had a -- this is Dale Hoffman. We had 16 several names for it. Originally it was Moraine (ph) and then 17 I think Torok became the specific section of Moraine that we 18 decided to use and for consistency in our office we settled on 19 that. 20 ACTING CHAIRMAN NORMAN: Okay, very well. That, I assume, 21 concludes the presentation of the application. The Commission 22 has had, I think, an ample opportunity to ask questions of the 23 witnesses. 24 If you will remain at your table though, I will ask if 25 there are any other persons present, members of the public that R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 61 i • 1 would like any questions posed or would like to address the 2 Commission? For the record, the Chair sees no one asking to be 3 recognized, there being none. 4 And I would like to conclude on behalf of Commissioner 5 Foerster, myself, the entire Commission in telling you that it 6 is our opinion that this was a very well prepared, presented 7 application. It was done with professionalism, with 8 forethought and you've anticipated a great many questions that 9 the Commission would ask. 10 And, I think, you also have done what we very much 11 appreciate and that is you have taken the time to bring 12 personnel here that could respond to the questions and we don't 13 want that to go unnoticed, so I think it reflects well on all 14 of you here with Pioneer, as well as your company 15 MR. HOFFMAN: Thank you. 16 ACTING CHAIRMAN NORMAN: and we thank you. Without 17 objection we will stand adjourned at the hour of 10:35 a.m. 18 (Recessed - 10:35 a.m.) 19 20 21 22 23 24 25 R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274-8982 ANCHORAGE, ALASKA 99501 62 i • 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) ) ss. 3 STATE OF ALASKA 4 I, William Rice, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Reporter for R & R 5 Court Reporters, Inc., do hereby certify: 6 THAT the annexed and foregoing Public Hearing In the Matter of Application of PIONEER NATURAL RESOURCES ALASKA, Inc. 7 for Pool Rules for the Proposed Oooguruk -Torok Oil Pool Oooguruk Unit, Beaufort Sea, Alaska in Conformance with 8 20 AAC 25.520, was taken by William Rice on the 21st day of April, 2011 and continued by Suzan Olson on the 26th day of 9 April, 2011, commencing at the hour of 9:00 a.m., at the Alaska Oil and Gas Conservation Commission, Anchorage, Alaska; 10 THAT this Hearing Transcript, as heretofore annexed, is a 11 true and correct transcription of the proceedings taken by William Rice and Suzan Olson and transcribed by Suzan Olson; 12 IN WITNESS WHEREOF, I have hereunto set my hand and 13 affixed my seal this 6th day of May, 2011. 14 15 Notary Public in and for Alaska My Commission Expires: 10/08/14 16 17 18 19 20 21 22 23 24 25 R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 } { t { � �+�^4rcbAYa+W rtD ✓a`.a lMx�.; �' n c ■ NATURAL RESOURCES ALASKA • 000gurukUnit AOGCC Pool Rules Application Oooguruk-Torok Oil Pool kom } k „R ,%w . w•�k� ,»,+.,5'x'6` y� r NYSE: PXD` www.pxd.com April 26, 2011 I ' P Agenda PIONEER RESOURCES ALASKA a a. • Ooog u ru k update 0 ® Torok Oil Pool proposal 000guruk — Land -- H i sto r .� y ,z.. — Reservoir a — Development plan �.�„ . '`�;� s ue. °, �..,� tt+ '� — Proposed rules ry • Questions 1 P 000guruk Area Overview NATURAL RESOURCES ALASKA': • First production in June 2008 ---, • 10 MBOPD current production f , ■ 120 -150 MMBO gross potential Na UN„ �� 1 il (J i L PRUONO[9PY UNIT ,RFO,FR a Permitting onshore expansion q � � TM N Nui sut 1 �' Deadhorses , Or 6— .- ARCTIC FOP n,uoe u i t�:4 ,. \ ' II � N 1 t 0 2.55 10 15 20 Miles PROJECT LOCATION MAP HARRISON BAY OLIKTOK POINT ODS r S . __ Proposed Nuna Drillsite Location • — - Proposed Road Proposed Flowline 4 -- Existing Roads ii - -- Existing Pipelines e R J`�`, NDS1 OTP GO V NDS2 L-^- .. , f - I I I t 5 Miles 2 L PIONEER NATURAL RESOURCES ALASKA ■ 71! sNECi. - YI ... E :. m s Pioneer Natural Resources ._ U014 Trutt 4 71401 5 U01 7 301.391565 ADW69956 ADL369955 Alaska, Inc. / 0% 014NOOTE U PIONEER NR PIONEER NP T 19 , ... ADLaKA3911 1 MaIE@p A0,39139C 1C 4 138 TrA01 f6 IfAI ' TK3 ira1177 Tracl6 N O T1) 3 149 AOL3699043 -.._ - 300399959 A01309956 * En i Petroleum US LLC 30 % PIONEER NR PIONEER NR PIONEER NR 1 Tract!! • - c;3NEER NR MONEER 0 mx. i l Unit expansion pending with K` -' ADL 903 AD:�31QITSEb 3 30009950 301.389949 Tract 13 Tr:y;t t] PIONEER NR PIONEER N f 40055036 300355037 P IONEER NR R DNR (red outline) ____ IU67kT PIONEER N • %Kt 11 Tract 12 [DlY1lLF t>tLTAt 400389952 300389951 PIONEER NR PIONEER N .. _. *0339 3U9399 C0. • .. . . , G 6- ,MHai • 7 05148 703146 a Torok participating area U019N006E f i Tracs 19 _ ._.. Tract 15 A01.355032 pending with D N R �� 300 CPA 300365501 WONEER NR N PIONEER EER N R CPAI 30139/460 - *� 301 _ _ ./ T03143 PIONEER NR •' .A11'7131 1 i AO- 02551'4 a Farmed in CPAI interest in . ` CPAI 301.391450 300990504 70317 - PIONEER NR 41120 Tract 21 ADL 390506 working with - 3 00990505 A0L333434- - - -i DLOE6620 400380106 ADL025532 wONEER NP ROWER NR CPAI CPA■ CORI T031ab - - - :. ._.... ___...... PIONEER Chevron on remaining Tract 23 _ 30139050E Oooguruk Unit PIONEER NR 41122 ` " "" interest I *70391453 60.391452 - 012910 301300647 301055544 t 7 0-s 148 703 tab PIO NEER NR CPA, r: Oooguruk Unit Expansion U012N006E Q Oooguruk Unit .....,................".......! Royalty Reduction Tracts AOL39t322--- _.._._ 401331653 •D1_39 'l a AD 39'52' A01025651 70 706148 49RC 4SR:. CPAI M a.. ,t Ix1jINmIE fNL1.. 1 F 211N1On A0L390453 I A131390498 1 301.391024 A04.39102340.391 541 301.391510 - 0 0.5 1 2 MdeS AVCG AVCG ASK A5R0 AVCO .__ AVCG __� Pioneer Oooguruk Area Overview PIONEER E 1VSHGR ILD — ;0 1.5 1 10�' Oooguruk Initial Oooguruk Unit Development Area Kalubik 1 ODST -45A ,� Torok Stimp on Lagoon o 0 / ODS LL t #i1 _ _. -- .. r D eve l opment j �� ODS 8 EN 111111 IE1111 _ - milig,ii i1' T13NR7E 1 ' 3 � � L I 3 INN Ti3N O g 1 i. PXD i . Acreac Cp3 ' - -- / CD3 (Fiord) _. N ' . r 0 :ic �u vLr - _ y.$ :ice] Dela M ir. O 541 1 I ,:� ' Kuparuk River PA er Unit i 'n ,, _ ( LM) 1 CD2 (Alpine) CD1 (Alpin ' i mm l ou rmi 1 T12NR7E T12NR9E / O tdr meds�i O r o ODS - cn:Kup C CD4 (Nanuq) Development w ili.. :. I Oooguruk Oil Filled Torok 8 ��m _Al Core Development _ _� s .FI CD3 Lowest Known Oil Nui . sut r I-- 1 , ODS D evelopment ' fl ° _� Oooguruk Development Project N _ Are Location Map �� ENechelik Projection AK State Plane Zone 4 NAC 2'r PIONEER k r Torok Exploration & Delineation History PIONEER y NATURAL RESOURCES ALASKA r, • 1 65 Colville 1 I TUVaA °5T' n ctia LAND 1 • '86 Colville Delta 2 GUr • • Colville Delta 3 KALUBIK3 OLIKTO,; POINT (Lowest Known Oil) QOO UK 1 • • '92 Kalubik 1 1 IV K 1 O DS i C OLVILLE DF!_?A ST 1 1„ • '93 Thetis Island 1 LU EH RRISON BAY ST1 IA '` KAL B " '98 Kalubik 2 COLVILLE D: TA4 OD -45A NATCHIQ 1 O .IKTOK PT 1 21 i'41 COLVILLE O D 2 `: COLVILLE C LTA 1- 4 K UUKPIK 3 / , Oooguruk Unit '03 Ivik 1 !f a „„„„ „_„__ . .s, ., Oooguruk 1 COLVILLE C_ LTA 25, . .1 Natchiq 1 cz1 Li.1; W SAK 25;23 16 , -' '10 ODST -45A fi ANG., • ILL 1 ! , KALUBIK CK 1 _ , � 1 • Torok Pool .. O Oil I 1 r I l 0 Water 0 2 4 Miles COLVILLE 1 0 Undetermined D Fluid Data on Structural Cross Section PIONEER h�r Kalubik -2 CD -3 CD -2 Kalubik -1 DW 1 -44 IVIK -1 03 -1 O C a* -. + , D T - o - _ O - -o • . iu - -s i~ I co co - -_ -. w S « O MDT { 06 t -� � FAULT. S q 4 v . v v 240 bopd after 7 ■1IIIIII 19 8 API Oil frac 16 -24 a•i r I �O�II 140 bbls of - _ -o r water S produced • r n Test roduced �? Mr I � �ili -- 1 2000 m over 12 hrs. - El i@i „II d..a — - PP _ _ r BIM filtrate e• 'rol N- - - : \ or "►_ -- . „l „test _ _- _ o ,,..,: _ II& --,..„. r ...- ... s I - 'mfr - o l D _.. ” 7 � = ,1 -- - -r - - _ - fig' ` o _ -tiei ��__ _ _ 3 � min LKO -51 CD t 3te st n ' ..di - -- _ r ' i a� � i Mew: =: 1 o _ Ali \ `� HK S -- CJ rJ EMI }YI ..e• CJ -. 7 I _ . ` - cJ ` � e W 5 0 Ivlk MDT _ i - 111 1 P MEW .. SITEIWZ-a19..e” . . . -I = O� , 2 o Core , - F,� �vm £ a _ _ �. - - o RISE o i q suggests Jo • I o 1 .tli∎ - f o ii, I I .n -- iri ? 2 residual oil in r- 71Ii \ 1 ui , ...t' i III i MDT wtr 1 ' rice tb AND 1 — ? - -- �_ _ ` - el I ` • fadlent =' . • .,. \ ` : O ,S O O. a uR O =Lit T y _ • In � L() �_ f. � _ J III L __ KALOBIF - ' ' ,. 4'" , )c;URVI: t —`- 111 ' - • I T o `- 9s1 .. a� -© am- ODS Ln _ 6 114 ? • mr -- r + x .—_ ; i'rt j - O .. 4 CO -VILLE otto -45A NATCRIU 1 T S , '- \ LIME D 2 f- . . =1 COLVILLE C LTA I Oooguruk Unit CD -3 lowest known oil at 5,150 ft TVDSS F n . COL /IL . FtIA3 Ivik -1 highest known water at 5,210 ft TVDSS ®LKO - T - " m 1 Kalubik-1 tested water 6 ._ _ ____ __ ___ __. _____ Torok Reservoir Properties PIONEER ■ NATURAL. RESOURCES ALASKA I KALUBIK -2 Vsand _.._ Resistivity ■ Lower Cretaceous turbidite 1 30 �` L oca l analogs: Tarn, Meltwater, and Nanuq �- ` Upper Tor Ss — g s wim . - - -- — Thinly- bedded alternating sands & shales IIV I ____ _ (0.5 in. to 6 in. beds common) - Ord Torok Ss — 45% to 50% sand — Lower Torok Ss — 12% to 26% porosity -g — 0.1 - 100 and permeability __ _ " - - ase Torokss — 40% to 55% estimated water saturation ,s : Outcrop Views of Thinly- Bedded Turbidites \- --. ----4 Y 5 ft ws y. rv - .. de. . 1 t � s � y x i . ... . 'v,. M "•*''�` ........v _ « x....,... �.. lc, .... fir. +�� x :,. ,: "- A+ Reservoir Extent PIONEER NATURAL RESOURCES ALASKA utt 1 I « , , - LANE) 1 0. ' 4 ..t ' H * ' t ' t 41k ,,,,,,.. I* ' ' ' ' ' ' , . , ,, t KALUBIK . — — , l 1.1Hl+. 1 ■ . .r . .. ...Z.: Oooguruk Torok Reservoir Interval r . , ....... "',.. "^ : -, • . ....,..,,o.. • F$ • RI 0 44i1.1i*,,,,4i.4,..:„„— ,.... All 7" 1 t 500— COLVILLE DELTA 1 41. ODST NATCHIO 1 Alii- .. 4.** • LTA A 0 1 COLVILLE L., 2 -e-,_ Ll Oooguruk Unit I ...... .. o _ .4, =4"............... ....MM Ili IC 1 ......,. ..410.... , .....e— ■ .......,'".... e .... ,„,77 .. ....... . i • Arb Line Oooguruk 3D I ''"' ......pwww- ,... , E tTA 51 2 II A90 ......--.......— ..'.... ' ....I x , 1 . . I .■ t COLVILLE DELTA 3 W NE 0 LKO KAL USK + KALUBIK 1 DW 1 44 -IETIS ISLAND 1 — -- ------ - I .., .. ' ) I ' \ ; 1 S ? ' .4. Merged 3D seismic - Torok sand in over 20 41/ . 0 e servoir 1 , .. r°13:s7b okroRk R wells ,.. , .... e servoir .. — Numerous synthetic 4 --, ----- . ;, ! 1 1 , i ties _ , '-, , I .1 i .4 ( • Slope apron setting , -...--7.1--..., Top HRZ % L _ : _-, ...., f (14. ,....., Structure & Isopach 226" 1 PIONEER NATUFtAL RESOURCES ALASKA Torok Top Structure % - -- , ,,,....................„ 4600 Torok Gross Isopach ' L 4704 0 i 4756 , I I . + 0 t) , \ \ \ 4e53 ,,,<), • / \ d \ ( L 1 ( /". \---/-\-, -A . . 4905 4951 \\'\ '\' '\\\.*-. '-'7.:.\-\\15 _ 5003 1 / 0 o ) ) . 4 A') (2A ....., ( / c4. i . 5055 0 c '\' 4 \ i ) A .--., / sloo ' ) c*1) ' i' '''..1, ---------- 300 ) r \, v 0 \ ?0' 1 r ` 1 )f i 5152 ., , 0 ..----., t i • : F. '‘AN ok .„.,,....,., ....-.", `0 7 :3 • 1---\ 52'56 ' ( - 5302 it ..> / "'Y.?, 1 \ ; ,› ,....t, - , 4... --- , IfiitE' 1 f ir? T ,2 \\-‘ ° 5406 ,4,,,. . i 7* `,,,, , t ? -C**-- •\-' %-i=r' • -. > v .. oi..,- 1 i 1,7",' 0 5503 I \ J , 220 t , ,,i Ittl , ,.. , --., 0, ' i (,./ q 'ks,..---, 'i ..; ' ." ./.. 1 ' , g) ,,,,,._ ^\ ;. ,\\ \ \ :,.N .,..? • 5750 , ,----\:■,1 - r' t ) 5802 ' 1 1 hi ej ,„ 111111 r - r -/ —a - 1) ;;:"°' \ --\" C'7) / ' ' \ ,--e------ - 1 -,- -. ----2 . _ : J w i 40 ;611A,4) 5%0 "-------;---------'---=--- N' ' i ' , \ I ' - i ii.k. - 7 , _.--)",.. 7 ‘..; -, lw z_A) ,10, ...N.......... 2, 7 ., ( TOO' ,,_:' N6:' • " '-----:.:.,. 7 ,---- n p V- ., 1 K Pioneer ,,,,,A2-..,/-;--te - ,• -, . 0 1.,i .,. s s 11 :\--"yil / li 42:: NaturaiResources 9 - ' ' 4 0.., l'' K ,c', ' ; -_.. ti._.) ci= 50 x \, 6 ? ...,--. ' < A. 7 .7-_)( . 0 1 0 j Oooguruk Torok Reservoir FT ' ( , 4 1 6 / r''" ./'''—' ( IIII l , 1 2 Mies 4 --5 2 ° -■-- -''' . 2 ' ..., Oooguruk Torok 200 ft to 250 ft thick Thins eastward (basinward), pinches out to west along slope 9 i PIONEER 1 \ ON Fluid Properties RESOURCES ALASKA Preliminary data from the ODST -45A studies indicate the Torok reservoir Y and fluid properties are (5,000 ft TVDSS datum): • Initial reservoir pressure: 2,250 psig (measured) • Reservoir temperature: 135° F (measured) ka da` • API gravity: 24° (measured) • GOR: 250 to 550 SCF /STBO (measured *) • Bubble point pressure: 1,000 psig to 2,200 psig (measured *) • Oil formation volume factor: 1.15 to 1.30 RB /STBO (measured *) • Oil viscosity: 2 to 4 centipoise (measured *) • Gas formation volume factor: 1.234 RB /MSCF (from correlation) * Because the ODST -45A utilizes gas for artificial lift, the reservoir initial GOR is not known at this time. PVT studies were conducted by Intertek to assess the range in associated oil properties. 10 ,. Torok Oil In Place PIONEER NAt)RAL RESOURCES ALASKA `- t:zr, ° °t • Torok Prospective __ 4500.000 1 4552.000 Area I` \\\ � �.– I 4804.000 4656 000 4701 500 \ 4753 500 4805.500 44903 3D Seismic 49 55 000 . .. � � 11 5052.500 . -..... 5000 5104.500 .500 �\ II -. -_ -_ 5156 + ., - -._- 5202 000 —' CD-3 Lowest r� J i , ^ ;: \ 5254 000 V C ` 5306.000 r ` ` J 5351.500 ^_' � ^ r t ► � ' 5455.500 K I� O W I� O I I t O Y J( / 5403 500 I fr 'l l t r X4 � [ ) /� Y� 5501 -000 i % t' � '!!►� `�' 5605 000 5 f t TV D S S t / .-:; n h.. J / 5650 500 Y/p:' 0 58000 , r, � ' �� ; 00 • 23,000 acres ri y/ , - 1 r - • 124 ft average ge / 1 �1-A P 1' ° • 690 MMSTBOIP il l ��: � ��tesolarce -51'� Ba rl(` Z 1 ` • rok Reso . rce op. 9� • -L.�- - -- ..... • • — . - Map Base Cutoff • - • 1 I Ike` I 5154 _ --4%. NI \ 1 1 Torok Top Spucture Ma. 1 33% Net to Gross, 21% porosity (> 1md), 48% water saturation, 1.15 RB /STBO 11 Development Area PIONEER NATLFIAL RESOURCES ALASKA _,0■_, Preliminary Nuna ti . li it ''' drillsite locations _ 711 l' — 450001J0 [ filled area defined by oil tests within 4552 000 a Initially target oil ) \\ - 7LI I ,r, 4604 000 4656 000 4701 500 4753 500 :. \ . — 77" -- 4805 500 :, 4851 000 + ' \ - 1 4903 OM 4955 000 the expanded 0 , 5 0 0 0 5 0 0 5 0 5 2 50 0 5104 500 Oooguruk Unit , , .,.... A., i 1 5 :Lli v l woo . ..% . I 5351 500 I I i4 it -.-- 1 1\ • Y\ !J 6; k 4 NZe,.•. N )N 4 4= area 0 1 .■501 000 t 0 11 ) 1 ) . tie,,,,414 5553 000 ,,, „,) /" . 1 :- WI L+ . r 5605 000 l / V 65 50 500 5702 500 4 Future expansion if .... . (/ ,,. + . / to areas with of , 5800 000 + ' 0,080 r— - ' , , t -,;,,,•-_::" /I. ------‘ ,4.10, I over water '4' Afer ' -'-' -,... la „ow 1 CD3 0 ( Onshore Nuna i4 a. • • '‘L-a, ,:,..;: * '''' ' -r .1 s'N EP ...... 1 ....... .... gi : . 7 7 .1. _ =- .1 ince -51„ 3a ' k ___. ----- '= OTP, DS 3H drillsites .....--- N. Noliw.--- , r ---J • , \ e'. , • .--.: I ,- ., •__ ...._.. ir 0 - L --._, Map Base Cutoff ..... . — . . / . ....„ i I ... (/ I -5150 , / CS41 \ CD3 CDT 1 Torok Top Structure Ma • L. 12 Torok Phased Development PIONEER ., ,1-404. RESOUtiCES AtikSiV\ Conceptual Oooguruk Torok Timeline Oooguruk Island T45a Test 2010 2011 2012 2013 2014 2015+ • (400 to 800 BOPD; 3,800' lateral) 2010 -12: 800 acre, 3 well "pilot" .. «.,. � t Oooguruk ODS "Pilot" ?x' Onshore Drill Site Permitting ___._ - 2010 -11: Field studies a : 2011: Permit & regulatory applications :; , 2011 -12: Permit & regulatory approvals Onshore Drill Site Permitting , f yay � Fw, Facility Design & Construction 2011: Conceptual Engineering 2013: Final design & long lead purchases 2014: Begin onshore drill site construction Facility Design & Construction 2015: First onshore production Onshore Development Drilling , -- - Pre I Pre Development 2012 -13: Pre - development well and test Dev Dev Drilling '; 2014 +: Development drilling Well ( Well , ,,, sk " "`1.A �h w , t ". F , .. y r r PIONEER NATURAL RESOURCES ,k y .. . � ,.. , . , 5 ... , . a , Y> ;; ,; , . , , ,,;, +: t.� e'w 4,e:' o . Viz ; ; �„ ��ly � ` as R „, Conceptual Torok Development PIONEE NATURAL RESOURCES E ALASKA • Horizontal line drive 1,500 ft inter -well spacing Torok Ss Isopach 39 25 wells (excludes T45A) ODSandCoreArea 46 47 Development Wells t 45A ■ • Secondary recovery (IWAG) - Water and gas when available '' • Phased Development \:\\\ \ \ ODS "pilot” (in progress) "\\ \ \ . Onshore Nuna Drillsite ., i \ \\:\ '.,\ , ' ' • Rates and Recoverable Resource w: ,, - 4,000 to 9,000 STBOPD (avg.) ,\,\, , ' ..-4; '" 4.* \ , Primary +� Secondary \\\ Potential , Resource Development Area OOIP (20% Recovery) Phase (acres) (MMSTBO) (MMSTBO) \ \\\>#' ODS 1,000 50 10 I Onshore Core Area 7,000 290 58 Torok Pool Total 8,000 340 68 14 Facilities PIONEER NATURAL RESOURCES ALASKA • 1 -2 drillsites • Roads connected to DS -3S • Small pig - launching & receiving pad 1 • a Flowlines to Oooguruk tie -in pad (OTP) existing infrastructure - Three -phase production, water, gas and power • Sales oil to OTP to TAPS PROJECT LOCATION MAP HARRISON BAY OLI OK POINT ODS h Proposed Nuna Drillsite Location ____ — - Proposed Road • Proposed Flowline h — Existing Roads Existing Pipelines -\, NDS1 ap�a''x NDS2 N _. z { , p I I -. ' + Q 2 5 Miles t 15 Drilling & Completion PIONEER NATURAL RESOURCES ALASI(A 10 -' /. °' Surface Casing Section Hole MD rw Mud ► •• Set at -3,000' TVD Size (ft) (ft) Surface 13-1/2" 3,600 3,000 Spud Intermediate 9 -7 /8" 10,000 5,000 LSID SCSSSVi% WBM - 2,000' TVD (if required) Production 6 -3/4" 16,500 5,100 MCBM Feed through Packer with Gas Vent Valve - 2,500' TVD 65 Tangent F Section ` 4" 1 /2" Production Liner Ig - 6,500' in length 0 0 0 0 0 .t► 0 0 0 0 0 0 0 0 0 0 7-518" Intermediate Casing Set at - 5,000' ND Injectors and producers hydraulically fracture stimulated 16 a^h k., as \1F \e:4f e,e ,. .. .. M� '1:`\ F, rya ,.•.�. �: E \\cei. t5a Proposed Field / Pool and Definition P(o sou c at�s xn Rule 1. Field and Pool Names uruk Field • Field Name: Ooo 9 �zrF • Defined Pool: Oooguruk -Torok Oil Pool kE k•. Rule 2. Pool Definitions • The Oooguruk -Torok Oil Pool is defined as the accumulation of oil and gas common to and 9 aa . correlating to the interval found in the ARCO Kalubik No. 1 well between the depths of 4,991 ft and 5,272 ft measured depth. 17 '.',;:; vF �, .'va ., A. a,.'. ,x,.a ,:,, �., .':' ,... ,. .., �' �, .�. „� •..t, v ., ?.;5, \.. :� � M \.� .ar'v a.. � � . n2- .,.WP4x t :'.. a�.,'i *'�''?'�'? <. �; v °� ^'.' �,. '''., .. ... ., 1V.�: vl a ., , »..v ... 1 Well S R P P IONEE IRALRESOURCESALA - 4� F`\ Rule 3. Well Spacing • The requirements of 20 AAC 25.055 are waived for development wells in the Oooguruk -Torok Oil Pools. Without rior notification, development p � p wells may not be completed closer than 500 ft to an external boundary where working interest ownership changes. s 18 CY E4 5 F fit\ ° t a ? v x r F F a.. Fe? ?Fk t ?F . ,;... •e e:, ,.,,, ; ..... .,. . >+ .. „. gt „ . .,, ;, ,: ....... - t, ,., „i,. e 1,w..., ,.A,, ,. c.. c. ,.... ,.,. ,.. .„ ?k „e, ?. , c,.0 .,. ,r.... z. .,. s.'^,�le <...:,rwk . t,,, ,.. E F Drilling & Completions NATURAL RESOURCES ALASKA Rule 4. Drilling and Completion Practices • After drilling no more than 50 ft below a casing shoe set in the Oooguruk -Torok Oil Pool, a formation integrity test must 9 Y be conducted. The test pressure need not exceed a predetermined pressure. • Casing and completion designs may be approved by the AOGCC upon application and presentation of data that demonstrate the designs are appropriate and based on sound engineering principles. • Permit(s) to drill deviated well(s) shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). • A complete petrophysical log suite acceptable to the AOGCC is required from below the conductor to TD for at least one well drilled from the onshore development in lieu of the requirements of 20 AAC 25.071(a). 19 . PIONE Automatic Shut-in Equipmen NATURAL RE! R Rule 5. Automatic Shut -in Equipment • Well safety valves systems shall be installed, if ,p re uired pursuant to 20 AAC 25.265. Q n E die 20 Reservoir Pressure Monitoring PI NAT KA Rule 6. Reservoir Pressure Monitoring e onitoring ■ A minimum of one bottomhole pressure survey shall be measured annually in the Oooguruk -Torok Oil Pool. • The reservoir pressure datums shall be 5,000 ft TVD subsea for the Oooguruk -Torok Oil Pool. • Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or extrapolated from surface pressure fall -off, pressure build -up, multi -rate tests, drill stem tests, or formation tests. • Data and results from ressure surveys shall be reported p y annually on Form 10 -412, Reservoir Pressure Report. All data necessary for the analysis of each survey need not be submitted with the Form 10 -412 but shall be made E ,F available to the AOGCC upon request. 21 YG Gas -Oil Ratio & Surface Commingling PIONEER g g NATURAL RESOURCES ALASKA Rule 7. Gas -Oil Ratio Exemption • Wells p roducing from the Oooguruk -Torok Oil Pool are exempt from the gas -oil ratio limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(c) apply. Rule 8. Common Production Facilities and Surface Commingling • Production from the Oooguruk -Torok Oil Pool may be commingled . on the surface prior to custody transfer. Production shall be allocated to the pool k,a on the basis of well testing and producing conditions for each well. 22 ;*. „M.. � * \ y we r �i�\ \ ��.:; \'S v. `F .•";�o:q i ,", ..�k ,S+., �w� a w \ *;1ti G ;�. Well Testing NATURAL RESOURCES ALASKA Rule 9. Well Testing • All producing wells must be tested at least once per month. • Stabilization and test duration times will be managed to obtain representative tests. • Operating conditions shall be recorded in a vv manner appropriate for maintaining accurate field production history. • ar � Records to allow verification of production allocation methodologies shall be maintained and be made available to the AOGCC upon request. quest . 23 � �, n,Yir.n we t. . � ��... A ., .a, i ? �. .. .. z.e� .� � ., .vo�A •s �„,��! v ,�� _ C .. � a\5"a.i �`J � .,. ,.. " ^ , Jv y ° ,,,, ,. a , � � Sustained Casing Pressure NATURAL CES ALASKA Rule 10. Sustained Casing Pressure • (a) The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure or threat to human safety. • (b) The operator shall monitor each development well to check for sustained pressure, except if prevented from doing so by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. • (c) The operator must notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2,000 psig, or (ii) sustained outer annulus pressure that exceeds 1,000 psig. • (d) The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10 -403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in part (c) of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. 24 ei. '. •i." ' .,. ,., . c...t,. ABU .. ,v A4n .. . ,,. .. r .c,. .,. .a,n.. . .. \, cn 1 .... ...,=;o° 3.u1,,.i awl<<V \v . , „ ,,. .,, „`c ., .. ., . , , >.a ,. x . , .. . s, .. ,evr v a . :. , . ,_.,, .a t,et•�. ,ta . a. ., oMVS, (\. ,,, , .... ., �avrv; s„ . "m• acbr awae„,+� \vx a..ar',s�.r�,m� � .� d ro'e�9�;k�ss. 1: , ..,e�r,. .. �; ry4 \0 �s . s , Sustained Casing Pressure (C O n t d) NATURAL RESOURCES ALASI(A':. • (e) If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before the AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10 -403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC- approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. • (f) Except as otherwise approved by the AOGCC under part (d) and (e) of this rule, before a shut -in well is placed in service, any annulus pressure must be relieved to a sufficient degree (i) that the inner annulus pressure at operating temperature will be tk below 2,000 psig and (ii) that the outer annulus pressure at operating temperature will be below 1,000 psig. However, a well that is subject to part (c), but not part (e), of this order may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under part (c), unless the AOGCC prescribes a different limit. • (g) For purposes of these rules, "inner annulus" means the space in a well between 4rti tubing and production casing; "outer annulus" means the space in a well between the production casing and surface casing; "sustained pressure" means pressure that (i) is measurable at the casing head of an annulus, (ii) is not caused solely by temperature fluctuations, and (iii) is not pressure that has been applied intentionally. 25 PION Administrative Action E R � RESOURCESALtkSKA Rule 11. Administrative Action • proper Upon application of its own motion, the p p p AOGCC may administratively waive the requirements of any rule stated above or administratively amend this order. 4x« k II 26 LZ VAYN S301M10S31111V1i1LLVN suo gsanb 2133 NO1d • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION CO 11 -01 Continued Pool Rules Hearing Oooguruk Unit April 26, 2011 at 9am NAME AFFILIATION PHONE # TESTIFY (Yes or No) ci l +7, n- 1 -} Zt DLO 4100 ps"vw 0 Ver-, 3 1 g t - ( - 2\ 5 hif ki6IS6 - 11' y ai5 -5S5 3 1�C� M 114t_ m.a,2.A AcQ AeT .S .v`r A,�sii Avc�cc ?9s-4.23e5 il/o Roby AoG« 773 - /232- A/0 0 Co ICAO e, AZ () • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION CO 11 -01 Pool Rules Hearing Oooguruk Unit April 21, 2011 at 9am NAME AFFILIATION PHONE # TESTIFY (Yes or No) r?0( //C,7 I N STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING A SHO ADVERTISING ORDER NO., CERTIFIED A O- 02114026 AFFIDAVIT INVOICE MUST OF PUBLICATION BE IN TRIPLIC ( PART TE 2 OF WING THIS FORM) WITH ATTACHED COPY OF !1 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. March 1, 2011 R 333 W 7th Ave, Ste 100 Jody Colombie ° Anchorage, AK 99501 PHONE PCN M (907) 793 —1221 DATES ADVERTISEMENT REQUIRED: T Alaska Journal of Commerce ASAP 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement SEE ATTACHED Pioneer Natural resources Docket #CO - 11 - 01 SEND INVOICE IN TRIPLICATE. AOGCC, 333 W. 7th Ave., Suite 100 PAGE 1 OF TOTAL OF TO Anchorage, AK 99501 2 PAGES ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LID 1 10 02140100 73451 2 REQUISITIO BY: A DIVISION APPROVAL: 11 i (44______— 02 -902 (Rev. / ) Publisher /Original Copies: Department Fiscal, Department, Receiving AO.FRM • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket No. CO- 11 -01. Pioneer Natural Resources Alaska, Inc. (Pioneer) has applied for Pool Rules for the proposed Oooguruk -Torok Oil Pool, Oooguruk Unit, Beaufort Sea, Alaska in conformance with 20 AAC 25.520. The non - confidential portions of Pioneer's application may be reviewed at the offices of the Commission, 333 West 7th Avenue, Suite 100, Anchorage, Alaska, or a copy of the non - confidential portions may be obtained by phoning the Commission at (907) 793 -1221. The Commission has tentatively scheduled a public hearing on this application for April 21, 2011 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West th 7Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the Commission no later than 4:30 p.m. on March 29, 2011. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the hearing, call 793- 1221 after March 30, 2011. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 7 Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on April 15, 2011, except that, if a hearing is held, comments must be received no later than the conclusion of the April 21, 2011 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the Commission's Special Assistant, Jody Colombie, at 793 -1221, no later than April 18, 2011. Daniel T. Seamount, Jr. Chair ALASKA Jotirnal Alaska Oil & Gas Conservation Commission Public Notices FILE NO: AO- 02114026 Ad #: 10147286 AO- 02114026 Oooguruk -Totok AFFIDAVIT OF PUBLICATION UNITED STATES OF AMERICA, STATE OF ATTACH PROOF OF PUBLICATION HERE ALASKA, THIRD DISTRICT BEFORE ME, THE UNDERSIGNED, A NOTARY PUBLIC THIS Notice of Public Hearing DAY PERSONALLY APPEARED Tracy Allison STATE OF ALASKA WHO, BEING FIRST DULY SWORN, Alaska Oil and Gas Conservation ACCORDING TO THE LAW, SAYS THAT HE IS Commission THE Accounting Manager OF THE ALASKA Re: Docket No. C0 11 - 01. Pioneer JOURNAL OF COMMERCE PUBLISHED AT 301 Natural Resources Alaska, Inc. (Pio ARTIC SLOPE AVENUE, SUITE 350, IN SAID the r) pr�oposed Oooguruk-Torok Oil THIRD DISTRICT AND STATE OF ALASKA Pool, Oooguruk Unit, Beaufort Sea, Alaska AND THAT ADVERTISEMENT, OF WHICH THE 25.520. Theonon- confident al p AAC ANNEXED IS A TRUE COPY, WHICH WAS tons of Pioneer's application may be PUBLISHED IN SAID PUBLICATION reviewed at the offices of the Com- mission, 333 West 7th Avenue, Suite 100, Anchorage, Alaska, or a copy of 03/13/2011 the non - confidential portions may be 13th DAY OF MARCH 2011 obtained by phoning the Commission at (907) 793 -1221. The Commission has tentatively AND THERE AFTER FOR 1 scheduled a public hearing on this ap- plication for April 21, 2011 at 9:00 CONSECUTIVE WEEK(S) AND THE LAST PUBLICATION APPEARING ON vat ion on m Coisson, 7th 03/13/2011 Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively 13th DAY OF MARCH 2011 scheduled hearing be held, a written request must be filed with the Com- mission later than 4:30 p.m. on March 29, 2011. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a Tracy Allison hearing. To learn if the Commission Accounting Manager will hold the hearing, tali 793-1221 SUBSCRIBED AND SWORN BEFORE ME after Mao In addition, , w 0, 2011. written comments regard- ing this application may be submitted THIS 14th DAY OF March 2011 to the Alaska Oil and Gas Conserva- tion Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska • `� "' t 99501. Comments must be received _ kik.lt 1,k no later than 4:30 p.m. on April 15, NOTARY PUBLIC STATE OF ALAS 4% 2011, except that, if a hearing is held, MY CQMMISSION EXIIRES . 6/L4L1 comments n c u io received thed April later .� _.. than the conclusion of the Apri! 21, , 4 NOTARY PUBLIC If, hearing. If, because of a disability, special ac- 4 4 BELINDA CUMMINGS commodations may be needed to comment or attend the hearing, con- STATE OF ALASKA tact the Commission's Special Assis- My Commission Expires June 14, 2012;, tant, Jody Colombie, at 793 - 1221, no later than April 18, 2011. By: /s/Daniel T. Seamount, Jr., Chair Pub: 3/13/2011. Ad #10147286 • • • STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE AFFIDAVIT MUST OF BEB IN PUBLICATION TRIPLICATE (PART SHOWING 2 OF THIS ADVERTISING ATTACH ORDER ED NO., COPY CERTIFIED OF I1 /r► O_02114026 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7 Avenue. Suite 100 Jodv Colomhie March 1. 2011 ° Anchorage_ AK 99501 PHONE PCN M (9071 793 -1221 DATES ADVERTISEMENT REQUIRED: Alaska Journal of Commerce ASAP 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he /she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2010, and thereafter for consecutive days, the last publication appearing on the day of , 2010, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This day of 2010, Notary public for state of My commission expires • • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, March 01, 2011 1:15 PM To: Ballantine, Tab A (LAW); (foms2 @mtaonline.net); ( michael .j.nelson @conocophillips.com); ( Von. L.Hutchins @conocophillips.com); 'AKDCWelllntegrityCoordinator; Alan Dennis; alaska @petrocalc.com; Anna Raff; 'Barbara F Fullmer; bbritch; Becky Bohrer; Bill Penrose; Bill Walker; Bowen Roberts; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; caunderwood; Chris Gay; Cliff Posey; Crandall, Krissell; 'D Lawrence'; dapa; Daryl J. Kleppin; 'Dave Matthews'; David Boelens; David House; 'David Scott'; David Steingreaber; 'ddonkel @cfl.rr.com'; 'Dennis Steffy'; 'Elizabeth Bluemink'; Elowe, Kristin; Erika Denman; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz (gary.schultz @alaska.gov); ghammons; Gordon Pospisil; Gorney, David L.; 'Greg Duggin'; Gregg Nady; gspfoff; Harry Engel; Jdarlington (jarlington @gmail.com); 'Jeanne McPherren'; Jeff Jones; Jeffery B. Jones (jeff.jones @alaska.gov); Jerry McCutcheon; Jill Womack; Jim White; Jim Winegarner; Joe Nicks; John Garing; John Katz (john.katz @alaska.gov); John S. Haworth; John Spain; John Tower; Jon Goltz; Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; 'Kim Cunningham'; Larry Ostrovsky; Laura Silliphant (laura.gregersen @alaska.gov); Marilyn Crockett; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark Kovac; Mark P. Worcester; Marguerite kremer (meg.kremer @alaska.gov); 'Michael Dammeyer'; Michael Jacobs; Mike Bill; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker @alaska.gov); 'Paul Figel'; PORHOLA, STAN T; Randall Kanady; Randy L. Skillern; 'Rena Delbridge'; rob.g.dragnich @exxonmobil.com; 'Robert Brelsford'; Robert Campbell; 'Rudy Brueggeman'; 'Ryan Tunseth'; Scott Cranswick; 'Scott Griffith'; Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Steve Lambert; Steve Moothart (steve.moothart @ alaska.gov); Steven R. Rossberg; Suzanne Gibson; tablerk; Tamera Sheffield; Taylor, Cammy 0 (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; 'Valenzuela, Mariam '; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); Yereth Rosen; 'Aaron Gluzman'; Ben Greene; Bettis, Patricia K (DNR); 'Dale Hoffman'; David Lenig; 'Gary Orr; 'Jason Bergerson'; 'Joe Longo'; 'Lara Coates'; Marc Kuck; 'Mary Aschoff; 'Matt Gill'; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; 'Ryan Daniel'; 'Sandra Lemke'; Steele, Marie C (DNR); Talib Syed; 'Tiffany Stebbins'; 'Wayne Wooster; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Matt Herrera; Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: 3 Public Notices Attachments: PNR Pool Rules.pdf; PNR Notice ODST 47.pdf; PNR Notice ODST 46.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 . . Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman NRG Associates Hodgden Oil Company Halliburton President 408 18 Street 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 r • PIONEER NATURAL RESOURCES ALASKA Dale Hoffman, CPL Senior Staff Landman Pioneer Natural Resources Alaska, inc. 700 G Street. Suite 600 Anchorage, AK 99501 (907) 343 -2108 dale.hoffman@pxd.com February 22, 2011 ��, �, � . FEB 2 2 ZUil Mr. Daniel Seamount, Chair Alaska Oil and Gas Conservation Commission Maim I & Ges Cow Commission 333 West 7 Ave., Suite 100 Anchorage, AK 99501 Anrherags Application for Pool Rules Oooquruk -Torok Oil Pool, North Slope, AK Dear Commissioner Seamount: In accordance with 20 AAC 25.520, Pioneer Natural Resources Alaska, Inc. (Pioneer) as operator of the Oooguruk Unit and on behalf of the Working Interest Owners, requests the Alaska Oil and Gas Commission approve the application for Pool Rules for the Oooguruk -Torok Oil Pool. Enclosed are three printed originals and a disk containing an electronic version of the application. If you have any questions, please call or email me care of the letterhead address. Sincerely, Dale Hoffman cc: R. Province, Eni T. Davidson, DNR Attachment 0 Information for the Alaska Oil and Gas Conservation Commission Classification and Rules for the Proposed Oooguruk -Torok Oil Pool Oooguruk Field North Slope, Alaska EEt' FEB 2 2 ?tM Note 61? & Gas Cons. Commission Anc Pioneer Natural Resources Alaska, Inc. Eni Petroleum US LLC February 2011 • Table of Contents 1. Introduction 2. Reservoir Description 2.1. Geology 2.2. Fluid Description 2.3. Oil In Place 3. Reservoir Development 4. Drilling, Completion and Well Operations 4.1. Drilling Plan 4.2. Drilling and Logging 4.3. Well Spacing 4.4. Well Work Plan 5. Facilities Scope and Design 6. Gas Oil Ratio 7. Operating Agreements and Production Allocations 8. Proposed Conservation Order List of Figures Figure 1 -- Proposed Oooguruk -Torok Pool Figure 2-- Kalubik -1 type log Figure 3- -Depth structure top Oooguruk Torok reservoir Figure 4-- Isopach Oooguruk Torok reservoir Figure 5 - -West to northeast cross - section through wells Figure 6 - -West to northeast arbitrary seismic section through wells Figure 7 - -Log cross - section with oil shows and distribution Figure 8-- Subsurface drilling plan for Oooguruk -Torok Oil Pool Figure 9 -- Proposed Oooguruk Torok producing well schematic List of Attachments Attachment 1- 0ooguruk -Torok Oil Pool legal description • 1. Introduction Pioneer Natural Resources Alaska, Inc., as operator of the Oooguruk Unit, submits this document to the Alaska Oil and Gas Conservation Commission (AOGCC) on behalf of the Pioneer Natural Resources Alaska, Inc. (Pioneer), the Operator, and Eni Petroleum US LLC (Eni), 70% and 30% working interest owners (WIOs), respectively. This document provides information to classify the Torok reservoir in the Oooguruk Field as an oil pool and to prescribe rules to govern development and management of the proposed Oooguruk -Torok Oil Pool in accordance with 20 AAC 25.520. Pioneer plans to use a horizontal well line -drive pattern immiscible water alternating gas flood (IWAG) to enhance recovery from the proposed Oooguruk -Torok Oil Pool. Given the commercial uncertainties surrounding the availability and delivery of gas to the Oooguruk project, the future volume and rate of injected gas cannot be predicted. Nevertheless, one or more Torok patterns will likely employ some form of IWAG injection. • The Oooguruk -Torok Oil Pool is located on the eastern side of the Colville Delta within the southwest area of the Oooguruk Unit, up -dip and fault separated from the Torok disposal interval. The Torok formation is approximately 1,000' TVDSS above the Kuparuk and 1,300' TVDSS above the Nuiqsut intervals. The Lower Cretaceous Torok turbidite sandstone was first penetrated in 1965 by the Sinclair Colville 1 well en route to a deeper structural target. In 1986 Texaco recognized the interval as potentially productive and tested it in both the Colville Delta 2 and Colville Delta 3 wells. Unstimulated, both wells produced at very low flow rates returning only completion fluids, and minor amounts of formation crude despite very low bottom hole flowing pressures. However, following a modest fracture stimulation of the lower Torok interval in Colville Delta 3, the well averaged 240 STBOPD over an 84 hour flow period. In 1992, ARCO drilled the Kalubik 1 well and performed an unstimulated 12 hour test of the Torok returning completion fluids and water. Formation tests in the Oooguruk 1 and Ivik 1 wells confirmed water in the down -dip Oooguruk area. An MDT sample in the 1998 ARCO Kalubik 2 well returned 19.8° API crude, but a drill stem test was not performed. To date, Pioneer has drilled 18 Oooguruk Drill Site (ODS) wells through the Torok interval. One well targeted the wet, fault separated down -dip Torok interval for disposal, six were completed in the Kuparuk and 11 targeted the Nuiqsut. One wellbore, ODSN -45, a planned southern Nuiqsut injection well, was plugged back to the top of the Torok due to operational difficulties in 2008. In 2009, the wellbore was salvaged to drill a lateral into the Torok near the ARCO Kalubik 2 well. The horizontal well, ODST -45A, was fracture stimulated in March, 2010 and through January, 2011 had produced 143 MSTBO over 248 cumulative days of production, demonstrating first commercial production from the proposed Oooguruk -Torok Oil Pool. Well data and 3D seismic have been used to define the geologic trap and potential reservoir distribution. Production tests, cores, well log data, RFT and MDT data have been used to establish reservoir boundaries and fluid properties. For the initial proposed Oooguruk -Torok Oil Pool the Oooguruk Operator plans to form an Oooguruk- Torok participating area within the unit. The proposed pool is shown on Figure 1 with the present unit boundary. The initial pool development area targets the oil filled Torok (base above lowest known oil of 5,150' TVDSS) within the operating area of the Oooguruk WIOs; however, there is potential the pool may extend outside the initial proposed area. Initial Oooguruk -Torok Oil Pool development will be from the existing offshore Oooguruk Drillsite (ODS) which connects to the onshore Oooguruk Tie -in Pad (OTP) and then enters the Kuparuk River Unit (KRU) process facilities. Dedicated Torok wells will be drilled from ODS so there will be no downhole commingling of production from the Torok, Nuiqsut or Kuparuk reservoirs. Commingling of production on the surface, downstream of well rate measurements and allocations, is planned to continue. Following a successful ODS Torok development and secondary response, the southwest area of the Torok Oil Pool may be developed from a new onshore drill site on the eastern side of the Colville River delta, approximately five miles west of KRU Drillsite 3S. Notionally, the onshore development will expand the horizontal line -drive pattern established at ODS to the south toward the proven oil in the Colville Delta 3 location. 1 0 Oooguruk Total Torok Reservoir Potential: • Estimated Original Oil In -Place (OOIP): 690 MMSTBO • Primary recovery (5 %): 35 MMSTBO • Primary and IWAG secondary recovery (20 %): 138 MMSTBO Key milestones: • ODS Torok Development Drilling (two initial wells) 10 2011 • ODS Torok Injection 2Q 2011 • Onshore Drill Site Permitting 2010 -13 • Onshore Facility Design 2010 -13 • Onshore Drill Site Construction 2013 -15 • Onshore Development Drilling 2013 -18 • Onshore Drill Site First Production 2014 -15 TUVAAQ ST 1 LT "c''. nc no LAND 10 KIGUI 1 h KALUBIK 3 A OLIKTO : POINT I -2 OOOGURUK1 0 1} ■ ■ I \, K 1 `` ODS ./‘,,- COLVILLE DELTA ST 1 LUBIK 1 E H 2RISON BAY ST 1 t LUBI O COLVILLE = • y , s NATCHIQ 1 0 .IKTOK PT 1 " COLVILLE D 2 II COLVILLE C LTA '''' t KUUKPIK 3 i / Oooguruk Unit COLVILLE C LTA 25 f ; h WSAK 25` 23 16 COLVILLE DELTA 3 4 * d • r 1LL 1 KALUBIK CK 1 ■ PALM 1 Tarok Pool • a , 1 1 1 1 I j • * 0 2 4 Miles COLVILLE 1 Figure 1 -- Proposed Oooguruk -Torok Oil Pool 2. Reservoir Description The Oooguruk -Torok reservoir's principal reservoir is the Torok sandstone, a Lower Cretaceous, marine slope sandstone deposit. Nearby fields producing from similar facies include Tarn, Meltwater, and Nanuq. These sands are found in the Kalubik -1 type log (Figure 2) at 4,991' to 5,272' MD, 4,954' to 5,235' TVDSS. The thin bedded turbidite nature of the sands is difficult to characterize with logs due to 2 . • II, logging tool resolution limitations, but core analysis shows porosities and permeabilities sufficient for production and secondary recovery. Production tests, conventional core, electric -line and LWD log data and seismic data were used to determine the reservoir extent and properties. The Oooguruk development is covered by two overlapping 3D seismic surveys. KALUBIK - Nr Pi I '.o 110 affillilliGIZal „r te ; C t ,.. air t �€ i = tea lr Al I i iwc i � r .acl repo r � SE UGNU_C � t r I : k..... :,fit If ._ l , !e a sr. - r, 77_1AtEST SAK E k� � . r � i ,r. �s �t�rec 174 LK_ 'f dP r l itanIF; l dU inimmes lannuma. .� Illip IP WEE `� t ' i a y I .1110 mr-iintanrsofilut l it :11 IE1 . i s! to —IC I= iiiiiiimeniiiiii" - -t ■ �11t[iIIMIN i U__ .. ,i iIr .,.,.�g �� M �i.- Vit-t=real....-2....- i�'. w wa rar 1i., 12_1. K at - atuoill4 al =al HI i1 -t sg a ,1 'MC , I �i To Torok Res Sands N �� P a�n � 11 �-�- -� - I � " u I -`- . j - Base Torok Res Sands A � hi mar I t -- : 115 'BA J4 R InirLi • � um •- tom 6A5 E_HRZ Ng * i t � * ' . i� y ; j .-• :158 NE>rHEI ►PC i a MIL - - ..,. � ,�� r...... .w. ,...a , .w..►..a .►. ass..► s... ,� . ��$ �+UU Figure 2-- Kalubik 1 Type Log 3 0 2.1 Geology As seen in core and on logs, the Torok turbidite reservoir interval is composed of very thin inter - bedded sands and shale. Individual sand and shale layers are commonly only a few inches to a few feet thick. Sands are composed of very fine sand to coarse silt sized grains with 20% to 50% quartz, 15% to 25% feldspar, 5% to 40% clay, 4% mica, metamorphic rock fragments and minor amounts of carbonate. At Oooguruk, the Torok contains predominantly sheet sands and is only occasionally channelized. The sands appear to lie on the lower slope to basin floor and may have been derived from episodic collapse of the shelf edge. Due to the thin - bedded nature, individual sands are difficult to correlate, even between closely- spaced wells, but packages of sands and shale can be correlated; the entire Torok reservoir can be divided into upper, middle, and lower members. The entire interval is commonly 200' to 250' thick, but thins eastward (basinward) and pinches out along its west side against a Lower Cretaceous slope. The net sand to gross thickness ratio of the Torok reservoir is typically 45% to 50 %. Sandstone porosity is 12% to 26% with an average of 19 %. Sandstone permeability ranges from 0.1 and to 100 md, averaging 4 md. Routine core data suggests 75% of the sand has a permeability greater than 1 md. The structure at the Torok level is a broad eastward plunging nose. A few northeast and northwest trending normal faults offset the Torok, but it is not highly faulted and the faults have relatively small displacements in comparison to the reservoir thickness. The faults in the Torok interval tend to link to the older, deeper faults but often exhibit less relief in the Torok and sometimes appear more as flexures. As such they may reach 40 ft in some areas. Figure 3 is a depth structure map at the top of the reservoir unit and depicts this relationship. In general, the gross Isopach in Figure 4 shows that the thickest part is coincident with the break at the toe of slope. Long transport distances are not envisioned and line sourcing or numerous, closely- spaced point sources are thought to prevail as a feeder channel system mechanism. $3 .s -a63 �4 $ �soo� d' Is ii „f0 4600 CO3 $ \ �i s o� I Oo 0 owmoi 5055.000 5100 MO xj.\\\. O _ 51552.500 " _ _ ' r '1 � o ` � 5256500 _ lT° oo , L 5 ; _. 4, 2 5.61 500 0 f —✓ ?� i 5853000 l i t !� . 411 \ \ �♦ O O . /J ��.(( 5802300 '''' ' 4 - ! L:c1 - Ilim a i. r ..l r f a h - --, 4 .. t 71 1 - - L tom' Pioneer /),' rmo cf ✓ y ,E a t 3.11 , > } Q 1 y Depth Structure ( � " ' of' T �. Top Oooguruk Torok ■ 1 {t/ 2 Miles - -5 2 0... v g ',:i \ Figure 3- -Depth Structure Top Oooguruk Torok Reservoir (shows 2010 -11 planned ODS Torok development wells) 4 0 • o r r �►, , 300 000 i ,) an } CO3 260 000 O 6 240 [ I 00 Q e f ' 220. CS ° _ \ i 1 � 160.000 I IL r \ 000 180.000 a i N. h N O . 7 V-''1 v PT ic ', y 1 (\ / � MQ1 / _ { .. � q t 7l ' ..�� / /1� 140 000 ! / 120.000 5 d' i /11 t r 700.000 CP I I r J \ � \ � a o f � 80 000 1! i, J� - (- \ \ � 60 000 4 1-14i1 ' wry { '.'` 1 CR i _ r 4 #-- 40.000 {, o G ' /./ 6 7 — 0 20 000 'ts ..r t . ('‘i ' , ' i/ t -- N. owl '' i 1 ,4, \ ke fkl ii = , 2 �r � ;, ■ t Pioneer ( . 0 \ r j �. Natural Resources U J , r Isopach • / l c�ct Oooguruk Torok Reservoir 5,- �.. ; r — 1 l 4. CI =50FT O 'f % 1 2 Miles In- Figure 4-- Isopach Oooguruk-Torok Reservoir Because conventional density and resistivity logs have resolution of a few feet, the thin beds of the Torok reservoir cannot be resolved adequately on these logs. Therefore, it is not possible to accurately calculate porosity, water saturation, net pay, or hydrocarbon pore feet using the currently available log data in the thin sands. Porosity ranges used in Torok resource calculations were derived from core data. Due to the fine grain and expected large transition zone from the water to oil, relatively high water saturations are estimated in the net pay sands, averaging from 55% to 40 %, with an expected case of 52 %. Conventional cores have been acquired in three area wells (Colville Delta 3, Kalubik 1 and Kalubik 2) and sidewall cores in four area wells (Colville Delta 2, Thetis Island 1, Ivik 1 and Oooguruk 1). The core data have been used for porosity and permeability measurements, detailed petrographic descriptions, and limited special core analyses. At this stage of the development additional core studies will not sufficiently resolve the uncertainty and risks associated with the development of this thin - bedded reservoir. Net/gross and net sand calculations were based on Vshale logs derived from gamma ray logs, but a less common methodology was also utilized. The typical method of using a Vshale cutoff, such as 60 %, to determine net to gross and net sand results in an overestimation of these values when log calculations are compared to core data. For example, using the typical methodology, if Vsh < 60% for a 0.5 ft foot sample, then the net/gross would be 1.0 and the net sand would be 0.5 ft for that sample. Given the 1 thinly bedded nature of the sands with a typical 0.5 ft core sample containing approximately 50% sand 5 , 40 • (0.25 ft) and 50% shale (0.25 ft), the typical methodology overestimates the amount of sand in a given sample. Therefore a different methodology was used. Using the Vshale log, a Vsand log was created (Vsand = 1 — Vshale). The Vsand log was then summed to obtain a net sand value and that net sand was divided by the gross thickness to obtain a net to gross. This method results in net to gross and net sand values that are very close to values obtained from counting sands and shales in Torok core data. Figures 5 and 6 are a cross - section of a few key wells and the equivalent arbitrary seismic line from the 3D survey. These wells and the associated logs show the sands and their stratigraphic and depositional position relative to the slope. Well to seismic ties are illustrated in Figure 6. w NE KALUBIK 3 KALU131K 1 1 44 -1E 71S ISLAND 1 ME f ..,),. 1 - T 1 . ,- r ' t .. l' i i °P Torok Re . ' Rase Torok Reservoir r i ,) i ti f d 3r Top HRZ 0 _— - _ -..... ... _ _ Figure 5 - -West to Northeast Cross - Section Through Wells Showing Oooguruk Torok Reservoir Sands Flattened on HRZ Pick. W IMAM . _.______ _._. _ � ,.. i- .___._ - ____._________Mal* i - 1 _ if 6 1." a n ► { amw'+o _ Oooguruk Torok Reservoir Interval * i . ' �. . r� � ,M any � �, .- � i e` i , t 1a„ 1 -k 4... ! w — ., -., d °' -4Y*+3+ .4*. �' : r ,,,, ' -.: 'mow Arb Line Oooguruk 3D i _ _ "0 Figure 6 - -West to Northeast Arbitrary Seismic Section Through Wells. 6 46 • The Oooguruk -Torok Oil Pool is thought to be a combination trap. The up -dip, depositional limit of the sands as they on -lap the toe of slope defines the pool to the west. The depositional limit of the fan defines it to the south and southwest, and fault- assisted structural closure defines it to the east, and northeast. The limit of the structural closure /water contact for the Oooguruk -Torok pool is defined from the structure interpretation from the top reservoir down to the highest known water (HKW) and by tested water in the Kalubik 1 well. The HKW is defined by the MDT interval taken in the Ivik 1 well where a water gradient was established. This subsea depth is 5,212' TVDSS. Another well, the Colville Delta 3 (CD -3), tested oil down to 5,150' TVDSS, defining the lowest known oil (LKO). It is this level, the LKO, that is the basis for the Oooguruk -Torok pool outline. Also, there appears to be a boundary for fluids defining the northeastern edge. This boundary is a northwest- southeast trending, down to the northeast fault. This fault separates the ODSN -45A (near Kalubik 2), CD -2, and CD -3 wells from both the Kalubik 1 well, which tested water, and the ODS disposal well (DW1 -44). Figure 7 depicts these relationships. Wells northeast of this fault exhibit lower resistivity and inferred oil saturations from those southwest of this fault. For the reasons previously explained, namely the thin - bedded nature of the sands and log resolution, the water saturation interpretation is based on the relative resistivity of the thicker sands encountered in the wells. Above 5,150' TVDSS and on the up- thrown side of the fault separating Kalubik 2 and Kalubik 1 resistivity in the thicker sands range from 19 to 38 ohm -m, whereas in the down -dip, down- thrown area thicker sand resistivities are typically below 10 ohm -m and decrease with increasing depth. Kalubik -2 CD -3 CD -2 Kalubik -1 DW1 -44 IVIK -1 03 -1 $ MDT v Y F A ULT ' 351 i :ED MI 2 36bopd after ¢ ` r ' if. 19.8API Oil frac,16 -24 aim 1f .''+- -- Y water 46bbIs o AS ..e.,. rV . Y Tes 0 Protluced .`r s i j , -f 3 t f ' a ' ? s e .�`. i V-' 12000 o ver12hrs. i A a ... � mud filtrate M FF ,— i O sat ° o �d $ ( o o 4 . con F' moo_ �_ .. =9 F v° ° t u " N Y N i ‘A L test .ea... Q' S mom _ LKO Z150 CD3 i o s { o ; o Con °o o . o suggests i � M ; M s # 2 nsltl oil? v> ' .'. # . � ':^ :: T wtr 77 u $ �i � - la - . u� �I.! .Y u ' ] . t. FAULT r ,° __- ..,..: ; ° u1 N ° m Figure 7 - -Log Cross - Section With Oil Shows and Distribution. The pressures in the Oooguruk -Torok formation in the Ivik 1 and Oooguruk 1 wells drilled in 2003 indicate pressure communication between the wells within the Torok water leg. 2.2 Fluid Description Surface fluid samples were collected during the initial testing of ODST -45A in March, 2010. Reservoir fluid PVT and oil characterization studies are in progress. 7 • Preliminary data from the studies indicate the Torok reservoir and fluid properties are (5,000' TVDSS datum): • Initial reservoir pressure: 2,250 psig (measured) • Reservoir temperature: 135° F (measured) • API gravity: 24° (measured) • GOR: 250 to 550 SCF /STBO (measured *) • Bubble point pressure: 1,000 psig to 2,200 psig (measured *) • Oil formation volume factor: 1.15 to 1.30 RB /STBO (measured *) • Oil viscosity: 2 to 4 centipoise (measured *) • Gas formation volume factor: 1.234 RB /MSCF (from correlation) * Because the ODST -45A utilizes gas for artificial lift, the reservoir initial GOR is not known at this time. PVT studies were conducted by Intertek to assess the range in associated oil properties. 2.3 Oil In Place As described above, the Oooguruk -Torok Oil Pool is defined by 3D seismic, well control and production tests. Core data analyses have been used to describe the expected net pay within the pool area. The mapped seismic gross rock volume constrained to a proven oil down to of 5,150' TVDSS, and the area south of the northern fault is 2,850,000 acre -ft with an associated area of approximately 23,000 acres, yielding an average gross thickness of 124 ft. From core and log interpretation the average net pay to gross thickness ratio is estimated at 33% (50% sand with 75% of the sand greater than 1 and permeability); average pay porosity is 21 % (average porosity of core greater than 1 md) and the expected average water saturation in the pay is 48% (initial oil saturation 52 %). Assuming a 1.15 RB /STBO oil formation volume factor the estimated original oil in place is 690 MMSTBO. Free gas has not been encountered nor is it expected within the Torok interval. The solution gas /oil ratio is estimated at 250 SCF /STBO, yielding 170 BSCF of in -place associated gas. 3. Reservoir Development The proposed Oooguruk -Torok Oil Pool will employ a horizontal well line -drive pattern immiscible water alternating gas flood (IWAG) to enhance recovery from the reservoir. Given the commercial uncertainties surrounding the availability and delivery of gas to the Oooguruk project, the future volume and rate of injected gas cannot be predicted. Development of the pool will be completed in discrete phases to mitigate risk and improve recovery from this unconventional North Slope resource. Primary uncertainties in the development of the Torok are the lateral continuity of thin sand beds and the effective displaceable pore volume. Outcrop data from the analogous Jack Fork formation in Arkansas demonstrate basin floor sheet sands can extend laterally for thousands of feet. The extended production test results of ODST- 45A are consistent with laterally continuous productive sands over development well spacing distances of 1,000 to 2,000 ft. As a turbidite system, larger scale compartmentalization is possible but the data set is insufficient to resolve it. Analytical modeling suggests primary depletion of the Torok will yield approximately 5% recovery of the OOIP; secondary recovery models suggest an expected incremental recovery of 15% of the OOIP, with a low end of 5% and high end of 25 %. Petrographic descriptions and core flood data indicate the Torok pay sands are compatible with water and gas planned for injection. Initial development will target the northern area of the pool that can be reached from ODS where the base of the Torok is above the 5,150' TVDSS LKO (Figure 8). Studies suggest a 1,500' inter -well spacing is optimal assuming modest secondary response. Due to the highly laminated nature of the reservoir, all the wells, including the injectors, will be hydraulically fracture stimulated to enhance productivity and improve vertical injection sweep. The initial ODS development will serve as a pilot flood of the Torok and provide critical performance and injection data for the pool. Where possible, additional geologic and engineering data will be acquired to improve reservoir characterization. The initial injection well, ODST- 8 • • 46i, will be placed approximately 500 ft up -dip and parallel to the existing ODST -45A horizontal appraisal well, which will help to provide early performance data from the flood. ODST -46i will be completed and pre - produced to provide additional interval performance data. Ultimately, the well will provide secondary recovery for ODST -45A, ODST -47 and future producer ODST -39 following issuance of an area injection order. Torok Ss Isopach 3 ODS and Core Area 4s 47; Development Wells ! 45 A w:, PXD Leases E is It "' Tor.L. Ss r.. i v y /:\ ' ' ‘.1---- , . ..„,,, %, i ,, ., / \ . , c \ .,, \ / \1/4 \ ..,, ,.. , ,,,, \\„>-.---- , _ , Figure 8-- Subsurface Drilling Plan for Oooguruk -Torok Oil Pool 9 • • Assuming a successful ODS Torok development, the core area of the Torok pool will be developed from an onshore drill site on the edge of the Colville River. The initial onshore development again targets the area where the base of the Torok is above the 5,150' TVDSS LKO. Notionally, a horizontal line drive with 22 wells at 1,500' inter -well spacing is planned for the core area onshore development, with development drilling planned to start as early as 2013. Expansion of the Oooguruk -Torok pool development into areas with known oil over water will also be evaluated. The table below summarizes the potential resource associated with the Torok pool development. Primary + Primary Potential Secondary Resource Potential Resource Development Area OOIP (5% Recovery) (20% Recovery) Phase (acres) (MMSTBO) (MMSTBO) (MMSTBO) ODS 1,000 50 2.5 10 Onshore Core Area 7,000 290 14.5 58 Expansion Area 15,000 350 17.5 70 Torok Pool Total 23,000 690 34.5 138 There is considerable uncertainty in Oooguruk -Torok Oil Pool rates given the limited data available on well performance and uncertainty on drilling times. However, onshore development scenarios of the core oil filled area suggest the production rate for the proposed Oooguruk -Torok Oil Pool over the project life of 20 to 30 years is expected to average from 4,000 to 9,000 STBOPD, with a peak production rate ranging from 7,000 to 15,000 STBOPD and an associated peak gas rate of 2 to 8 MMSCFPD early in the project life. 4. Drilling, Completion, and Well Operations The well designs for the Oooguruk -Torok Oil Pool are similar to the Oooguruk - Nuiqsut Oil Pool with an intermediate casing set at a high angle just into the target reservoir and a horizontal lateral drilled and lined through the reservoir section. The surface and intermediate sections will be directionally drilled with water -based mud systems and cased. Within the proposed initial development area, the base of permafrost is interpreted to lie between 1,400' and 1,600 ft TVDSS. The horizontal intervals will be drilled with a reservoir drill -in -fluid (DIF) to maintain hole integrity. The laterals in the Oooguruk -Torok reservoir are planned to be cased with solid liners which include pre - perforated pups and external swell packers for staged hydraulic fracture stimulation treatments. Due to the low permeability and limited kv /kh of the sands, all producers and the injectors will be fracture stimulated. The producers are planned to be recompleted with electric submersible pumps (ESPs). In the Oooguruk -Torok reservoir, wellbore orientation relative to the major mapped faults and the plane of principal stress may have a significant impact on secondary recovery, depending on the nature of the faulting. Studies done of the interval suggest that the optimum orientation for the wells is in the direction of principal stress, similar to the Nuiqsut and Kuparuk wellbores. 4.1 Drilling Plan Initial development drilling from ODS began in early 2011, with one producer and one injector. Hole and casing sizes, mud systems, directional profile and departure, and geological steering techniques are similar to practices in the Oooguruk - Nuiqsut Oil Pool. As with the Oooguruk - Nuiqsut and Oooguruk- Kuparuk Oil Pool developments, the wells will be drilled from two surface rows of wells on seven foot centers within the confines of the wellbay modules installed on ODS. Disposal of drilling wastes will be 10 • • via a Class I /II disposal well also located on ODS. Onshore Development drilling is expected to begin as early as 2013. Drilling will begin once all permits have been secured and this phase of the project is sanctioned. Hole and casing sizes, mud systems, directional profile and departure, and geological steering techniques will be similar to practices in the Oooguruk - Nuiqsut Oil Pool. Disposal of drilling wastes during the onshore development phase will be via an onshore Class I /II disposal well drilled prior to drilling the first onshore development well. For both phases of the development, primary, secondary and general well control for drilling and completion operations will be performed in accordance with 20 AAC 25 Articles 1 and 6. The casing and cementing will be performed in accordance with 20 AAC 25.030. Surface casing, cemented to surface, is planned to be set in the shale below the base of the West Sak Sands, at approximately 3,000' TVDSS (Figure 9). The section between the proposed surface casing shoe and 4,000' TVDSS consists of Hue shale and contains no sands as shown in Figure 2. Intermediate hole will be drilled to the target formation and cemented with the shoe just above or just into the target formation. If a significant hydrocarbon zone(s) is indicated by the logging, the cementing program will be designed for that well to protect that zone(s). Leak -off tests are planned after drilling 20' to 50' beyond the surface casing shoe and the intermediate casing shoe. To maximize reservoir exposure, the development plan for the proposed Oooguruk -Torok Oil Pool is to drill formation cross - cutting horizontal wells with lengths from 5,000' to 8,000'. The horizontal section will be drilled with a drilling fluid designed to maintain hole integrity. The wells are planned to be completed with solid liners which include pre - perforated pups and /or sliding sleeves to facilitate proppant fracture stimulation treatments (for producers) and injection conformance (for injectors). The Oooguruk -Torok Oil Pool will be completed with 2 -7/8" tubing for producers and 31" to 41" tubing for injectors. A proposed producing well schematic is shown in Figure 9 below. 10 -/4" Surface Casing Section Hole M D TVD Mud v . �" Set at — 3,000' TVD Size (ft) (n) Surface 13 -1/2" 3,600 3,000 Spud Intermediate 9 -7/8" 10,000 5,000 LSND SCSSSV WBM — 2,000' TVD (if required) Production 6 -3/4" 16,500 5,100 MOBM Feed t rough Packer with Gas Vent Valve —2,500' TVD 65°_75° Tangent fi sA 4 - / Production Liner Section " - 6,500' in length 0 o 0 0 0 �. 0 0 0 0 0 0 0 0 0 0 7-5/8" Intermediate Casing Set at — 5,000' TVD Figure 9--Proposed Torok Producing Well Schematic 9 p 11 • • 4.2 Drilling and Logging Preliminary slot assignments on ODS and directional plans for the wells have been generated for the initial phase of the development. Based on logging information gathered while drilling the Oooguruk- Nuiqsut and Oooguruk - Kuparuk developments and the experience to date, diverter waivers have been granted while drilling the surface hole sections. Notional wells for the onshore development have been planned, but the final development will be based on information gathered during the initial development and following the design of the onshore pads and facility placement. At the start of this phase of the development, drilling of the surface hole will be done using a diverter line. This practice will continue until it has been determined there are no shallow gas hazards present and the drilling of the surface hole can be done safely. At that time, a diverter waiver request will be submitted with the permit to drill package on a well by well basis. The diverter line placement will be based on the final pad layout, well house construction and drilling rig selected for the development. Close approaches and anti - collision scans show no major proximity issues. Assuming conservative build and turn rates of no more than 47100', all targets are reached with intermediate hole tangent angles of -70 °. The horizontals are also planned at 3 7100' for any course corrections that are needed. Directional profiles were used to spot check torque and drag, hydraulics and horizontal liner running. Well modeling (torque, drag, casing running, hydraulics, hole cleaning) results showed no major risks to drilling the wells. Most of the drilling and completions of the Oooguruk -Torok wells can be accomplished with current designs and drilling practices; however, there are some extended reach drilling (ERD) targets that are being evaluated. Pioneer requests the requirements described in 20 AAC 25.050(b) be waived for the proposed Oooguruk- Torok Oil Pool to relieve administrative burden. In lieu of requirements under 20 AAC 25.050(b), Pioneer proposes that permit(s) to drill deviated wells shall include a plat with a plan view, vertical section, close approach data and a directional program description. The planned minimum log suite for the initial disposal well of an onshore development includes resistivity, gamma ray (GR), and density /neutron to total depth (TD). The minimum log suite for the second well of the onshore development includes resistivity, gamma ray (GR), and density /neutron logs from surface casing to TD. Additional logs may include image logs, sonic, and pressure tools. These logs will be obtained from logging - while - drilling and wireline tools. Mudlogs will be generated and cuttings acquired from surface casing to TD on the initial wells drilled during the onshore phase of development. Additional mudlogging needs will be evaluated and planned for accordingly. 4.3 Well Spacing and Naming Pioneer requests well spacing requirements under 20 AAC 25.055 be waived because the horizontal well development of the proposed Oooguruk -Torok Pool, via line -drive waterflood with the possibility of alternating gas injection, will yield greater recovery than a conventional vertical /slant well development plan with a minimum spacing rule. Vertical well simulation indicated production capacity for individual wells in the Oooguruk -Torok reservoir would range from 100 to 200 BOPD. Horizontal wells are required to make the project economic. Each horizontal well replaces four to five conventional wells drilled on 40 acre spacing. The wells to be drilled from the Oooguruk Drill Site will be named with the following nomenclature to designate the well site, surface slot, reservoir completed and service as follows: ODST -01 i Oooguruk Drill Site, Torok Formation, Surface Slot 01 injector. Wells drilled from in onshore development will use a similar unique drillsite identifier. 12 4.4 Well Work Plan Well service operations are planned in accordance with 20 AAC 25 Article 3. Routine reservoir surveillance activities including pressure measurement and production and injection profiles will be accomplished with instruments deployed either with fiber optics, electric -line, slickline or coiled tubing. Remedial wax and /or asphaltene management is planned with slickline and /or hot oil treatments. Reservoir pressure monitoring will be through permanent down -hole pressure gauges on producing wells. Injection well pressure monitoring will be acquired via surface pressure readings or wireline pressure gauges run in the well. Pressure datum for the Oooguruk -Torok Oil Pool is chosen at 5,000' TVDSS. The datum represents the average depth of the reservoir within the development area. Initial pressure surveys on injectors will be taken prior to regular injection. 5. Facilities Scope and Design The Oooguruk Torok onshore surface facility scope includes an onshore gravel drillsite, located just east I of the Colville River Delta, which was selected for the following reasons: • Centrally located in the accumulation so the Oooguruk -Torok Oil Pool can be developed using horizontal wells • Onshore to optimize operational access and to minimize environmental impacts This facility may include drillsite facilities for managing and measuring fluids, space for a drilling rig and consumables, a tie -in pad to locate pigging and various production modules. Produced and injection fluids will exit and enter the drillsite via three mile VSM- supported flowlines to /from or DS -3H of the KRU. The project utilizes many of the same technologies that are standard to North Slope fields. A multiphase flow meter (MPFM) will be used for custody transfer from Oooguruk -Torok Oil Pool to the KRU owned process facilities. The project includes produced fluid, water injection, and gas injection flowlines that connect to the KRU facilities, adjacent to DS 3H. Drillsite,tie -in pad facilities, and OTP expansion include the following: • Production, test, gas lift, gas injection, and water injection headers; • Lateral piping with chokes from wellhead to headers; • Tie -in slots for 50 wells (including spares); • Individual well shelters; • Electrical and instrumentation modules with transformers, switch gear, Variable Frequency Drives (VFD), and telecommunications; • Air compressor and nitrogen generation unit; • Multiphase meter for individual well tests; • Emergency shut down (ESD) system; • Water injection line pig launcher /receiver; • Production line pig launcher /receiver; • Provisions for future gas line piglaucher /receiver • Chemical injection and storage module; • Production heater; • Production separator module; • Gas compression module; • Produced water handling • Water Injection booster pump module; • Wellhead hydraulic panels; and • Lighting, surveillance, and communication equipment. 6. Gas /Oil Ratio 13 • . Pioneer requests an exemption from gas /oil ratio (GOR) limits of 20 AAC 25.240(b) due to the nature of the Oooguruk -Torok development strategy. The Oooguruk -Torok Oil Pool may have gas injection for improved oil recovery from IWAG, which would increase GOR production above the solution GOR for periods of time. Long term, production and injection are to be balanced to maintain original reservoir pressure. 7. Operating Agreements, Metering and Production Allocation A separate participating area is planned for the Oooguruk -Torok reservoir. The Oooguruk project area is also subject to the Oooguruk Unit Operating Agreement (OUOA), which governs the development of the Oooguruk project for the WIO. Development of the proposed Oooguruk -Torok Oil Pool is planned with development wells dedicated to a single pool with no subsurface commingling. Unitized substances produced from the proposed Oooguruk -Torok Oil Pool will be commingled on the surface. The metering and measurement process for injected fluids and produced fluids consists of the following: • For injected water volumes, a differential - pressure meter will be used to measure single -phase flow rate of water. For injected gas volumes, a differential - pressure orifice meter will be used to measure single -phase rate of gas. • For individual well produced fluid volumes, a test header connected to a MPFM will be used to measure oil, water, and gas rates of a single well, over a span of several hours. Wells will be rotated through the test system with at least one cycle per month. • For total Oooguruk produced volumes, a separator, orifice meter and MPFM will be used to measure oil, water, and gas on a real -time, continuous basis. This meter will be used to establish custody transfer to the KRU for downstream processing and eventual sales. The AOGCC previously approved use of MPFMs in the Oooguruk development. Production will be allocated to each producing well using the same process regardless of the pool. The allocation method will be based on MPFM well testing and the MPFM orifice at OTP. Production and injection allocation is a daily process used to assign and balance production from wells, and injection into wells, that have surface commingled production streams and injection streams, respectively. The basic process used at Oooguruk is the same process used at all fields on the North Slope, with the exception of using a MPFM instead of a separator to measure the total or aggregate daily volume. Each day, the Oooguruk allocation system calculates a "theoretical volume" for all well streams using the metering and measurement processes described above. The theoretical volume for each well is summed to calculate a total theoretical volume for all Oooguruk wells. The actual aggregate volume is determined at the Oooguruk level from measurements made using a MPFM. The allocation factor is the ratio of aggregate volume to total theoretical volume. The allocated volume for each well is the product of the allocation factor and the well- specific theoretical volume. 8. Proposed Conservation Order for the Oooguruk -Torok Oil Pool It is ordered that the rules hereinafter set forth, in addition to the statewide requirements under 20 AAC 25, apply to the following affected area referred to in this order. Oooguruk -Torok Oil Pool Attachment 1 provides the legal description of the Oooguruk —Torok Oil Pool. Rule 1. Field and Pool Names The field is the Oooguruk Field and the pool is defined as the Oooguruk -Torok Oil Pool. Rule 2. Pool Definitions 14 • . The Oooguruk -Torok Oil Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the ARCO Kalubik No. 1 well between the depths of 4,991' and 5,272' measured depth. Rule 3. Well Spacing The requirements of 20 AAC 25.055 are waived for development wells in the Oooguruk -Torok Oil Pools. Without prior notification, development wells may not be completed closer than 500' to an external boundary where working interest ownership changes. Rule 4. Drilling and Completion Practices (a.) After drilling no more than 50' below a casing shoe set in the Oooguruk -Torok Oil Pool, a formation integrity test must be conducted. The test pressure need not exceed a predetermined pressure. (b.) Casing and completion designs may be approved by the AOGCC upon application and presentation of data that demonstrate the designs are appropriate and based on sound engineering principles. (c.) Permit(s) to drill deviated well(s) shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). (d.) A complete petrophysical log suite acceptable to the AOGCC is required from below the conductor to TD for at least one well drilled from the onshore development in lieu of the requirements of 20 AAC 25.071(a). Rule 5. Automatic Shut -in Equipment Subsurface safety valves shall be addressed on a well -by -well basis either through the permit to drill or, if the well is already drilled, through the Administrative Action rule (i.e. Rule 11, below). Rule 6. Reservoir Pressure Monitoring (a.) A minimum of one bottomhole pressure survey shall be measured annually in the Oooguruk -Torok Oil Pool. (b.) The reservoir pressure datums shall be 5,000' TVD subsea for the Oooguruk -Torok Oil Pool. (c.) Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or extrapolated from surface pressure fall -off, pressure build -up, multi -rate tests, drill stem tests, or formation tests. (d.) Data and results from pressure surveys shall be reported annually on Form 10 -412, Reservoir Pressure Report. All data necessary for the analysis of each survey need not be submitted with the Form 10 -412 but shall be made available to the AOGCC upon request. Rule 7. Gas -Oil Ratio Exemption Wells producing from the Oooguruk -Torok Oil Pool are exempt from the gas -oil ratio limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(c) apply. Rule 8. Common Production Facilities and Surface Commingling Production from the Oooguruk -Torok Oil Pool may be commingled on the surface prior to custody transfer. Production shall be allocated to the pool on the basis of well testing and producing conditions for each well. Rule 9. Well Testing (a) All producing wells must be tested at least once per month. (b) Stabilization and test duration times will be managed to obtain representative tests. (c) Operating conditions shall be recorded in a manner appropriate for maintaining accurate field production history. (d) Records to allow verification of production allocation methodologies shall be maintained and be made available to the AOGCC upon request. Rule 10. Sustained Casing Pressure (a) The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure or threat to human safety. 15 • • (b) The operator shall monitor each development well to check for sustained pressure, except if prevented from doing so by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. (c) The operator must notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2,000 psig, or (ii) sustained outer annulus pressure that exceeds 1,000 psig. (d) The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10- 403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in part (c) of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. (e) If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before the AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10 -403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC- approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. (f) Except as otherwise approved by the AOGCC under part (d) and (e) of this rule, before a shut -in well is placed in service, any annulus pressure must be relieved to a sufficient degree (i) that the inner annulus pressure at operating temperature will be below 2,000 psig and (ii) that the outer annulus pressure at operating temperature will be below 1,000 psig. However, a well that is subject to part (c), but not part (e), of this order may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under part (c), unless the AOGCC prescribes a different limit. (g) For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between the production casing and surface casing; "sustained pressure" means pressure that (i) is measurable at the casing head of an annulus, (ii) is not caused solely by temperature fluctuations, and (iii) is not pressure that has been applied intentionally. Rule 11. Administrative Action Upon proper application of its own motion, the AOGCC may administratively waive the requirements of any rule stated above or administratively amend this order. 16 • • Attachment 1 Oooguruk -Torok Pool Legal Description Township 13 North, Range 7 East, Umiat Meridian Section 3: SW /4 SW /4 Section 4: SE /4 SE /4, W/2 SE /4, SW /4, SE /4 NW /4, W/2 NW /4 Section 5: E/2 E/2 Section 8: E/2 E/2 Section 9: All Section 10: SW /4 NE /4, SE /4 SE /4, W/2 SE /4, W/2 Section 11: SW /4 SW /4 - ri Section 14: SW /4 SE /4, W/2 SE /4, W/2 Section 15: All ,, Section 16: All Section 17: E/2 E/2 • Section 20: E /2, SW /4, SE /4 NW /4 Section 21: All • Section 22: All Section 23: All Section 24: SW /4, W/2 NW /4 V Section 25: SW /4 NE /4, W/2 NE /4, SW /4, W/2 Section 26: All Section 27: All • Section 28: All Section 29: E /2, E/2 W /2, NW /4 NW /4 Section 32: E /2, E/2 W /2, W/2 SW /4 Section 33: All Section 34: All Section 35: All Section 36: All Township 12 North, Range 7 East, Umiat Meridian Section 3: All Section 4: All Section 5: E/2 NE /4, SE /4 Section 8: E/2 Section 9: All Section 10: All Section 15: All Section 16: All Section 17: E /2, E/2 SW /4 Section 20: E /2, E/2 W/2 Section 21: All Section 22: All 17