Title 43—Public Lands: Interior--Volume 1
PART 3170—ONSHORE OIL AND GAS PRODUCTION
§ 3174.3   Incorporation by reference (IBR).
(a) Certain material specified in this section is incorporated by reference into this part with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. Operators must comply with all incorporated standards and material, as they are listed in this section. To enforce any edition other than that specified in this section, the BLM must publish a rule in the Federal Register, and the material must be reasonably available to the public. All approved material is available for inspection at the Bureau of Land Management, Division of Fluid Minerals, 20 M Street SE., Washington, DC 20003, 202-912-7162; at all BLM offices with jurisdiction over oil and gas activities; and is available from the sources listed below. It is also available for inspection at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030 or go to http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html .
(b) American Petroleum Institute (API), 1220 L Street NW., Washington, DC 20005; telephone 202-682-8000; API also offers free, read-only access to some of the material at http://publications.api.org .
(1) API Manual of Petroleum Measurement Standards (MPMS) Chapter 2—Tank Calibration, Section 2A, Measurement and Calibration of Upright Cylindrical Tanks by the Manual Tank Strapping Method; First Edition, February 1995; Reaffirmed February 2012 (“API 2.2A”), IBR approved for § 3174.5(c).
(2) API MPMS Chapter 2—Tank Calibration, Section 2.2B, Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method; First Edition, March 1989, Reaffirmed January 2013 (“API 2.2B”), IBR approved for § 3174.5(c).
(3) API MPMS Chapter 2—Tank Calibration, Section 2C, Calibration of Upright Cylindrical Tanks Using the Optical-triangulation Method; First Edition, January 2002; Reaffirmed May 2008 (“API 2.2C”), IBR approved for § 3174.5(c).
(4) API MPMS Chapter 3, Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products; Third Edition, August 2013 (“API 3.1A”), IBR approved for §§ 3174.5(b), 3174.6(b).
(5) API MPMS Chapter 3—Tank Gauging, Section 1B, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging; Second Edition, June 2001; Reaffirmed August 2011 (“API 3.1B”), IBR approved for § 3174.6(b).
(6) API MPMS Chapter 3—Tank Gauging, Section 6, Measurement of Liquid Hydrocarbons by Hybrid Tank Measurement Systems; First Edition, February 2001; Errata September 2005; Reaffirmed October 2011 (“API 3.6”), IBR approved for § 3174.6(b).
(7) API MPMS Chapter 4—Proving Systems, Section 1, Introduction; Third Edition, February 2005; Reaffirmed June 2014 (“API 4.1”), IBR approved for § 3174.11(c).
(8) API MPMS Chapter 4—Proving Systems, Section 2, Displacement Provers; Third Edition, September 2003; Reaffirmed March 2011, Addendum February 2015 (“API 4.2”), IBR approved for §§ 3174.11(b) and (c).
(9) API MPMS Chapter 4, Section 5, Master-Meter Provers; Fourth Edition, June 2016, (“API 4.5”), IBR approved for § 3174.11(b).
(10) API MPMS Chapter 4—Proving Systems, Section 6, Pulse Interpolation; Second Edition, May 1999; Errata April 2007; Reaffirmed October 2013 (“API 4.6”), IBR approved for § 3174.11(c).
(11) API MPMS Chapter 4, Section 8, Operation of Proving Systems; Second Edition, September 2013 (“API 4.8”), IBR approved for § 3174.11(b).
(12) API MPMS Chapter 4—Proving Systems, Section 9, Methods of Calibration for Displacement and Volumetric Tank Provers, Part 2, Determination of the Volume of Displacement and Tank Provers by the Waterdraw Method of Calibration; First Edition, December 2005; Reaffirmed July 2015 (“API 4.9.2”), IBR approved for § 3174.11(b).
(13) API MPMS Chapter 5—Metering, Section 6, Measurement of Liquid Hydrocarbons by Coriolis Meters; First Edition, October 2002; Reaffirmed November 2013 (“API 5.6”), IBR approved for §§ 3174.9(e), 3174.11(h) and (i).
(14) API MPMS Chapter 6—Metering Assemblies, Section 1, Lease Automatic Custody Transfer (LACT) Systems; Second Edition, May 1991; Reaffirmed May 2012 (“API 6.1”), IBR approved for § 3174.8(a) and (b).
(15) API MPMS Chapter 7, Temperature Determination; First Edition, June 2001, Reaffirmed February 2012 (“API 7”), IBR approved for §§ 3174.6(b), 3174.8(b).
(16) API MPMS Chapter 7.3, Temperature Determination—Fixed Automatic Tank Temperature Systems; Second Edition, October 2011 (“API 7.3”), IBR approved for § 3174.6(b).
(17) API MPMS Chapter 8, Section 1, Standard Practice for Manual Sampling of Petroleum and Petroleum Products; Fourth Edition, October 2013 (“API 8.1”), IBR approved for §§ 3174.6(b), 3174.11(h).
(18) API MPMS Chapter 8, Section 2, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products; Third Edition, October 2015 (“API 8.2”), IBR approved for §§ 3174.6(b), 3174.8(b), 3174.11(h).
(19) API MPMS Chapter 8—Sampling, Section 3, Standard Practice for Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products; First Edition, October 1995; Errata March 1996; Reaffirmed, March 2010 (“API 8.3”), IBR approved for §§ 3174.8(b), 3174.11(h).
(20) API MPMS Chapter 9, Section 1, Standard Test Method for Density, Relative Density, or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method; Third Edition, December 2012 (“API 9.1”), IBR approved for §§ 3174.6(b), 3174.8(b).
(21) API MPMS Chapter 9, Section 2, Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer; Third Edition, December 2012 (“API 9.2”), IBR approved for §§ 3174.6(b), 3174.8(b).
(22) API MPMS Chapter 9, Section 3, Standard Test Method for Density, Relative Density, and API Gravity of Crude Petroleum and Liquid Petroleum Products by Thermohydrometer Method; Third Edition, December 2012 (“API 9.3”), IBR approved for §§ 3174.6(b), 3174.8(b).
(23) API MPMS Chapter 10, Section 4, Determination of Water and/or Sediment in Crude Oil by the Centrifuge Method (Field Procedure); Fourth Edition, October 2013; Errata March 2015 (“API 10.4”), IBR approved for §§ 3174.6(b), 3174.8(b).
(24) API MPMS Chapter 11—Physical Properties Data, Section 1, Temperature and Pressure Volume Correction Factors for Generalized Crude Oils, Refined Products and Lubricating Oils; May 2004, Addendum 1 September 2007; Reaffirmed August 2012 (“API 11.1”), IBR approved for §§ 3174.9(f), 3174.12(a).
(25) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 1, Introduction; Second Edition, May 1995; Reaffirmed March 2014 (“API 12.2.1”), IBR approved for §§ 3174.8(b), 3174.9(g).
(26) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 2, Measurement Tickets; Third Edition, June 2003; Reaffirmed September 2010 (“API 12.2.2”), IBR approved for §§ 3174.8(b), 3174.9(g).
(27) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 3, Proving Report; First Edition, October 1998; Reaffirmed March 2009 (“API 12.2.3”), IBR approved for § 3174.11(c) and (i).
(28) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 4, Calculation of Base Prover Volumes by the Waterdraw Method; First Edition, December 1997; Reaffirmed March 2009; Errata July 2009 (“API 12.2.4”), IBR approved for § 3174.11(b).
(29) API MPMS Chapter 13—Statistical Aspects of Measuring and Sampling, Section 1, Statistical Concepts and Procedures in Measurements; First Edition, June 1985 Reaffirmed February 2011; Errata July 2013 (“API 13.1”), IBR approved for § 3174.4(a).
(30) API MPMS Chapter 13, Section 3, Measurement Uncertainty; First Edition, May, 2016 (“API 13.3”), IBR approved for § 3174.4(a).
(31) API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 1, General Equations and Uncertainty Guidelines; Fourth Edition, September 2012; Errata July 2013 (“API 14.3.1”), IBR approved for § 3174.4(a).
(32) API MPMS Chapter 18—Custody Transfer, Section 1, Measurement Procedures for Crude Oil Gathered From Small Tanks by Truck; Second Edition, April 1997; Reaffirmed February 2012 (“API 18.1”), IBR approved for § 3174.6(b).
(33) API MPMS Chapter 18, Section 2, Custody Transfer of Crude Oil from Lease Tanks Using Alternative Measurement Methods, First Edition, July 2016 (“API 18.2”), IBR approved for § 3174.6(b).
(34) API MPMS Chapter 21—Flow Measurement Using Electronic Metering Systems, Section 2, Electronic Liquid Volume Measurement Using Positive Displacement and Turbine Meters; First Edition, June 1998; Reaffirmed August 2011 (“API 21.2”), IBR approved for §§ 3174.8(b), 3174.9(f), 3174.10(f).
(35) API Recommended Practice (RP) 12R1, Setting, Maintenance, Inspection, Operation and Repair of Tanks in Production Service; Fifth Edition, August 1997; Reaffirmed April 2008 (“API RP 12R1”), IBR approved for § 3174.5(b).
(36) API RP 2556, Correction Gauge Tables For Incrustation; Second Edition, August 1993; Reaffirmed November 2013 (“API RP 2556”), IBR approved for § 3174.5(c).
You may also be able to purchase these standards from the following resellers: Techstreet, 3916 Ranchero Drive, Ann Arbor, MI 48108; telephone 734-780-8000; www.techstreet.com/api/apigate.html ; IHS Inc., 321 Inverness Drive South, Englewood, CO 80112; 303-790-0600; www.ihs.com ; SAI Global, 610 Winters Avenue, Paramus, NJ 07652; telephone 201-986-1131; http://infostore.saiglobal.com/store/ .
§ 3174.4   Specific measurement performance requirements.
(a) Volume measurement uncertainty levels. (1) The FMP must achieve the following overall uncertainty levels as calculated in accordance with statistical concepts described in API 13.1, the methodologies in API 13.3, and the quadrature sum (square root of the sum of the squares) method described in API 14.3.1, Subsection 12.3 (all incorporated by reference, see § 3174.3) or other methods approved under paragraph (d):
Table 1 to § 3174.4—Volume Measurement Uncertainty Levels
(2) Only a BLM State Director may grant an exception to the uncertainty levels prescribed in paragraph (a)(1) of this section, and only upon:
(i) A showing that meeting the required uncertainly level would involve extraordinary cost or unacceptable adverse environmental effects; and
(ii) Written concurrence of the PMT, prepared in coordination with the Deputy Director.
(b) Bias. The measuring equipment used for volume determinations must achieve measurement without statistically significant bias.
(c) Verifiability. All FMP equipment must be susceptible to independent verification by the BLM of the accuracy and validity of all inputs, factors, and equations that are used to determine quantity or quality. Verifiability includes the ability to independently recalculate volume and quality based on source records.
(d) Alternative equipment. The PMT will make a determination under § 3174.13 of this subpart regarding whether proposed alternative equipment or measurement procedures meet or exceed the objectives and intent of this section.
§ 3174.5   Oil measurement by tank gauging—general requirements.
(a) Measurement objective. Oil measurement by tank gauging must accurately compute the total net standard volume of oil withdrawn from a properly calibrated sales tank by following the activities prescribed in § 3174.6 and the requirements of § 3174.4 of this subpart to determine the quantity and quality of oil being removed.
(b) Oil tank equipment. (1) Each tank used for oil storage must comply with the recommended practices listed in API RP 12R1 (incorporated by reference, see § 3174.3).
(2) Each oil storage tank must be connected, maintained, and operated in compliance with §§ 3173.2, 3173.6, and 3173.7 of this part.
(3) All oil storage tanks, hatches, connections, and other access points must be vapor tight. Unless connected to a vapor recovery or flare system, all tanks must have a pressure-vacuum relief valve installed at the highest point in the vent line or connection with another tank. All hatches, connections, and other access points must be installed and maintained in accordance with manufacturers' specifications.
(4) All oil storage tanks must be clearly identified and have an operator-generated number unique to the lease, unit PA, or CA, stenciled on the tank and maintained in a legible condition.
(5) Each oil storage tank associated with an approved FMP that has a tank-gauging system must be set and maintained level.
(6) Each oil storage tank associated with an approved FMP that has a tank-gauging system must be equipped with a distinct gauging reference point, consistent with API 3.1A (incorporated by reference, see § 3174.3). The height of the reference point must be stamped on a fixed bench-mark plate or stenciled on the tank near the gauging hatch, and be maintained in a legible condition.
(c) Sales tank calibrations. The operator must accurately calibrate each oil storage tank associated with an approved FMP that has a tank-gauging system using either API 2.2A, API 2.2B, or API 2.2C; and API RP 2556 (all incorporated by reference, see § 3174.3). The operator must:
(1) Determine sales tank capacities by tank calibration using actual tank measurements;
(i) The unit volume must be in barrels (bbl); and
(ii) The incremental height measurement must match gauging increments specified in § 3174.6(b)(5)(i)(C);
(2) Recalibrate a sales tank if it is relocated or repaired, or the capacity is changed as a result of denting, damage, installation, removal of interior components, or other alterations; and
(3) Submit sales tank calibration charts (tank tables) to the AO within 45 days after calibration. Tank tables may be in paper or electronic format.
§ 3174.6   Oil measurement by tank gauging—procedures.
(a) The procedures for oil measurement by tank gauging must comply with the requirements outlined in this section.
(b) The operator must follow the procedures identified in API 18.1 or API 18.2 (both incorporated by reference, see § 3174.3) as further specified in this paragraph to determine the quality and quantity of oil measured under field conditions at an FMP.
(1) Isolate tank. Isolate the tank for at least 30 minutes to allow contents to settle before proceeding with tank gauging operations. The tank isolating valves must be closed and sealed under § 3173.2 of this part.
(2) Determine opening oil temperature. Determination of the temperature of oil contained in a sales tank must comply with paragraphs (b)(2)(i) through (iii) of this section, API 7, and API 7.3 (both incorporated by reference, see § 3174.3). Opening temperature may be determined before, during, or after sampling.
(i) Glass thermometers must be clean, be free of fluid separation, have a minimum graduation of 1.0 °F, and have an accuracy of ±0.5 °F.
(ii) Electronic thermometers must have a minimum graduation of 0.1 °F and have an accuracy of ±0.5 °F.
(iii) Record the temperature to the nearest 1.0 °F for glass thermometers or 0.1 °F for portable electronic thermometers.
(3) Take oil samples. Sampling operations must be conducted prior to taking the opening gauge unless automatic sampling methods are being used. Sampling of oil removed from an FMP tank must yield a representative sample of the oil and its physical properties and must comply with API 8.1 or API 8.2 (both incorporated by reference, see § 3174.3).
(4) Determine observed oil gravity. Tests for oil gravity must comply with paragraphs (b)(4)(i) through (iii) of this section and API 9.1, API 9.2, or API 9.3 (all incorporated by reference, see § 3174.3).
(i) The hydrometer or thermohydrometer (as applicable) must be calibrated for an oil gravity range that includes the observed gravity of the oil sample being tested and must be clean, with a clearly legible oil gravity scale and with no loose shot weights.
(ii) Allow the temperature to stabilize for at least 5 minutes prior to reading the thermometer.
(iii) Read and record the observed API oil gravity to the nearest 0.1 degree. Read and record the temperature reading to the nearest 1.0 °F.
(5) Measure the opening tank fluid level. Take and record the opening gauge only after samples have been taken, unless automatic sampling methods are being used. Gauging must comply with either paragraph (b)(5)(i) of this section, API 3.1A, and API 18.1 (both incorporated by reference, see § 3174.3); or paragraph (b)(5)(ii) of this section, API 3.1B, API 3.6, and API 18.2 (all incorporated by reference, see § 3174.3); or paragraph (b)(5)(iii) of this section for dynamic volume determination.
(i) For manual gauging, comply with the requirements of API 3.1A and API 18.1 (both incorporated by reference, see § 3174.3) and the following:
(A) The proper bob must be used for the particular measurement method, i.e., either innage gauging or outage gauging;
(B) A gauging tape must be used. The gauging tape must be made of steel or corrosion-resistant material with graduation clearly legible, and must not be kinked or spliced;
(C) Either obtain two consecutive identical gauging measurements for any tank regardless of size, or:
( 1 ) For tanks of 1,000 bbl or less in capacity, three consecutive measurements that are within 1/4-inch of each other and average these three measurements to the nearest 1/4 inch; or
( 2 ) For tanks greater than 1,000 bbl in capacity, three consecutive measurements within 1/8 inch of each other, averaging these three measurements to the nearest 1/8 inch.
(D) A suitable product-indicating paste may be used on the tape to facilitate the reading. The use of chalk or talcum powder is prohibited; and
(E) The same tape and bob must be used for both opening and closing gauges.
(ii) For automatic tank gauging (ATG), comply with the requirements of API 3.1B, API 3.6, and API 18.2 (all incorporated by reference, see § 3174.3) and the following:
(A) The specific makes and models of ATG that are identified and described at www.blm.gov are approved for use;
(B) The ATG must be inspected and its accuracy verified to within ± 1/4 inch in accordance with API 3.1B, Subsection 9 (incorporated by reference, see § 3174.3) at least once a month or prior to sales, whichever is latest, or any time at the request of the AO. If the ATG is found to be out of tolerance, the ATG must be calibrated prior to sales; and
(C) A log of field verifications must be maintained and available upon request. The log must include the following information: The date of verification; the as-found manual gauge readings; the as-found ATG readings; and whether the ATG was field calibrated. If the ATG was field calibrated, the as-left manual gauge readings and as-left ATG readings must be recorded.
(iii) For dynamic volume determination under API 18.2, Subsection 10.1.1, (incorporated by reference, see § 3174.3), the specific makes and models of in-line meters that are identified and described at www.blm.gov are approved for use.
(6) Determine S&W content. Using the oil samples obtained pursuant to paragraph (b)(3) of this section, determine the S&W content of the oil in the sales tanks, according to API 10.4 (incorporated by reference, see § 3174.3).
(7) Transfer oil. Break the tank load line valve seal and transfer oil to the tanker truck. After transfer is complete, close the tank valve and seal the valve under §§ 3173.2 and 3173.5 of this part.
(8) Determine closing oil temperature. Determine the closing oil temperature using the procedures in paragraph (b)(2) of this section.
(9) Take closing gauge. Take the closing tank gauge using the procedures in paragraph (b)(5) of this section.
(10) Complete measurement ticket. Following procedures in § 3174.12.
§ 3174.7   LACT system—general requirements.
(a) A LACT system must meet the construction and operation requirements and minimum standards of this section, § 3174.8, and § 3174.4.
(b) A LACT system must be proven as prescribed in § 3174.11 of this subpart.
(c) Measurement tickets must be completed under § 3174.12(b) of this subpart.
(d) All components of a LACT system must be accessible for inspection by the AO.
(e)(1) The operator must notify the AO, within 72 hours after discovery, of any LACT system failures or equipment malfunctions that may have resulted in measurement error.
(2) Such system failures or equipment malfunctions include, but are not limited to, electrical, meter, and other failures that affect oil measurement.
(f) Any tests conducted on oil samples extracted from LACT system samplers for determination of temperature, oil gravity, and S&W content must meet the requirements and minimum standards in § 3174.6(b)(2), (4), and (6) of this subpart.
(g) Automatic temperature compensators and automatic temperature and gravity compensators are prohibited.
§ 3174.8   LACT system—components and operating requirements.
(a) LACT system components. Each LACT system must include all of the equipment listed in API 6.1 (incorporated by reference, see § 3174.3), with the following exceptions:
(1) The custody transfer meter must be a positive displacement meter or a Coriolis meter. The specific make, models, and sizes of positive displacement or Coriolis meter and associated software that are identified and described at www.blm.gov are approved for use.
(2) An electronic temperature averaging device must be installed.
(3) Meter back pressure must be applied by a back pressure valve or other controllable means of applying back pressure to ensure single-phase flow.
(b) LACT system operating requirements. Operation of all LACT system components must meet the requirements of API 6.1 (incorporated by reference, see § 3174.3) and the following:
(1) Sampling must be conducted according to API 8.2 and API 8.3 (both incorporated by reference, see § 3174.3) and the following:
(i) The sample extractor probe must be inserted within the center half of the flowing stream;
(ii) The extractor probe must be horizontally oriented; and
(iii) The external body of the extractor probe must be marked with the direction of the flow.
(2) Any tests conducted on oil samples extracted from LACT system samplers for determination of oil gravity and S&W content must meet the requirements of either API 9.1, API 9.2, or API 9.3, and API 10.4 (all incorporated by reference, see § 3174.3).
(3) The composite sample container must be emptied and cleaned upon completion of sample withdrawal.
(4) The positive displacement or Coriolis meter (see § 3174.10) must be equipped with a non-resettable totalizer. The meter must include or allow for the attachment of a device that generates at least 8,400 pulses per barrel of registered volume.
(5) The system must have a pressure-indicating device downstream of the meter, but upstream of meter-proving connections. The pressure-indicating device must be capable of providing pressure data to calculate the CPL correction factor.
(6) An electronic temperature averaging device must be installed, operated, and maintained as follows:
(i) The temperature sensor must be placed in compliance with API 7 (incorporated by reference, see § 3174.3);
(ii) The electronic temperature averaging device must be volume-weighted and take a temperature reading following API 21.2, Subsection 9.2.8 (incorporated by reference, see § 3174.3);
(iii) The average temperature for the measurement ticket must be calculated by the volumetric averaging method using API 21.2, Subsection 9.2.13.2a (incorporated by reference, see § 3174.3);
(iv) The temperature averaging device must have a reference accuracy of ±0.5 °F or better, and have a minimum graduation of 0.1 °F; and
(v) The temperature averaging device must include a display of instantaneous temperature and the average temperature calculated since the measurement ticket was opened.
(vi) The average temperature calculated since the measurement ticket was opened must be used to calculate the CTL correction factor.
(7) Determination of net standard volume: Calculate the net standard volume at the close of each measurement ticket following the guidelines in API 12.2.1 and API 12.2.2 (both incorporated by reference, see § 3174.3).
§ 3174.9   Coriolis measurement systems (CMS)—general requirements and components.
The following Coriolis measurement systems section is intended for Coriolis measurement applications independent of LACT measurement systems.
(a) A CMS must meet the requirements and minimum standards of this section, § 3174.4, and § 3174.10.
(b) The specific makes, models, and sizes of Coriolis meters and associated software that have been reviewed by the PMT, as provided in § 3174.13, approved by the BLM, and identified and described at www.blm.gov are approved for use.
(c) A CMS system must be proven at the frequency and under the requirements of § 3174.11 of this subpart.
(d) Measurement tickets must be completed under § 3174.12(b) of this subpart.
(e) A CMS at an FMP must be installed with the components listed in API 5.6 (incorporated by reference, see § 3174.3). Additional requirements are as follows:
(1) The pressure transducer must meet the requirements of § 3174.8(b)(5) of this subpart.
(2) Temperature determination must meet the requirements of § 3174.8(b)(6) of this subpart.
(3) If nonzero S&W content is to be used in determining net oil volume, the sampling system must meet the requirements of § 3174.8(b)(1) through (3) of this subpart. If no sampling system is used, or the sampling system does not meet the requirements of § 3174.8(b)(1) through (3) of this subpart, the S&W content must be reported as zero;
(4) Sufficient back pressure must be applied to ensure single phase flow through the meter.
(f) Determination of API oil gravity. The API oil gravity reported for the measurement ticket period must be determined by one of the following methods:
(1) Determined from a composite sample taken pursuant to § 3174.8(b)(1) through (3) of this subpart; or
(2) Calculated from the average density as measured by the CMS over the measurement ticket period under API 21.2, Subsection 9.2.13.2a (incorporated by reference, see § 3174.3). Density must be corrected to base temperature and pressure using API 11.1 (incorporated by reference, see § 3174.3).
(g) Determination of net standard volume. Calculate the net standard volume at the close of each measurement ticket following the guidelines in API 12.2.1 and API 12.2.2 (both incorporated by reference, see § 3174.3).
§ 3174.10   Coriolis meter for LACT and CMS measurement applications—operating requirements.
(a) Minimum electronic pulse level. The Coriolis meter must register the volume of oil passing through the meter as determined by a system that constantly emits electronic pulse signals representing the indicated volume measured. The pulse per unit volume must be set at a minimum of 8,400 pulses per barrel.
(b) Meter specifications. (1) The Coriolis meter specifications must identify the make and model of the Coriolis meter to which they apply and must include the following:
(i) The reference accuracy for both mass flow rate and density, stated in either percent of reading, percent of full scale, or units of measure;
(ii) The effect of changes in temperature and pressure on both mass flow and fluid density readings, and the effect of flow rate on density readings. These specifications must be stated in percent of reading, percent of full scale, or units of measure over a stated amount of change in temperature, pressure, or flow rate ( e.g., “±0.1 percent of reading per 20 psi”);
(iii) The stability of the zero reading for volumetric flow rate. The specifications must be stated in percent of reading, percent of full scale, or units of measure;
(iv) Design limits for flow rate and pressure; and
(v) Pressure drop through the meter as a function of flow rate and fluid viscosity.
(2) Submission of meter specifications: The operator must submit Coriolis meter specifications to the BLM upon request.
(c) Non-resettable totalizer. The Coriolis meter must have a non-resettable internal totalizer for indicated volume.
(d) Verification of meter zero value using the manufacturer's specifications. If the indicated flow rate is within the manufacturer's specifications for zero stability, no adjustments are required. If the indicated flow rate is outside the manufacturer's specification for zero stability, the meter's zero reading must be adjusted. After the meter's zero has been adjusted, the meter must be proven required by § 3174.11. A copy of the zero value verification procedure must be made available to the AO upon request.
(e) Required on-site information. (1) The Coriolis meter display must be readable without using data collection units, laptop computers, or any special equipment, and must be on-site and accessible to the AO.
(2) For each Coriolis meter, the following values and corresponding units of measurement must be displayed:
(i) The instantaneous density of liquid (pounds/bbl, pounds/gal, or degrees API);
(ii) The instantaneous indicated volumetric flow rate through the meter (bbl/day);
(iii) The meter factor;
(iv) The instantaneous pressure (psi);
(v) The instantaneous temperature ( °F);
(vi) The cumulative gross standard volume through the meter (non-resettable totalizer) (bbl); and
(vii) The previous day's gross standard volume through the meter (bbl).
(3) The following information must be correct, be maintained in a legible condition, and be accessible to the AO at the FMP without the use of data collection equipment, laptop computers, or any special equipment:
(i) The make, model, and size of each sensor; and
(ii) The make, range, calibrated span, and model of the pressure and temperature transducer used to determine gross standard volume.
(4) A log must be maintained of all meter factors, zero verifications, and zero adjustments. For zero adjustments, the log must include the zero value before adjustment and the zero value after adjustment. The log must be made available upon request.
(f) Audit trail requirements. The information specified in paragraphs (f)(1) through (4) of this section must be recorded and retained under the recordkeeping requirements of § 3170.7 of this part. Audit trail requirements must follow API 21.2, Subsection 10 (incorporated by reference, see § 3174.3). All data must be available and submitted to the BLM upon request.
(1) Quantity transaction record (QTR). Follow the requirements for a measurement ticket in § 3174.12(b) of this subpart.
(2) Configuration log. The configuration log must comply with the requirements of API 21.2, Subsection 10.2 (incorporated by reference, see § 3174.3). The configuration log must contain and identify all constant flow parameters used in generating the QTR.
(3) Event log. The event log must comply with the requirements of API 21.2, Subsection 10.6 (incorporated by reference, see § 3174.3). In addition, the event log must be of sufficient capacity to record all events such that the operator can retain the information under the recordkeeping requirements of § 3170.7 of this part.
(4) Alarm log The type and duration of any of the following alarm conditions must be recorded:
(i) Density deviations from acceptable parameters; and
(ii) Instances in which the flow rate exceeded the manufacturer's maximum recommended flow rate or was below the manufacturer's minimum recommended flow rate.
(g) Data protection. Each Coriolis meter must have installed and maintained in an operable condition a backup power supply or a nonvolatile memory capable of retaining all data in the unit's memory to ensure that the audit trail information required under paragraph (f) of this section is protected.
§ 3174.11   Meter-proving requirements.
(a) Applicability. This section specifies the minimum requirements for conducting volumetric meter proving for all FMP meters.
(b) Meter prover. Acceptable provers are positive displacement master meters, Coriolis master meters, and displacement provers. The operator must ensure that the meter prover used to determine the meter factor has a valid certificate of calibration on site and available for review by the AO. The certificate must show that the prover, identified by serial number assigned to and inscribed on the prover, was calibrated as follows:
(1) Master meters must have a meter factor within 0.9900 to 1.0100 determined by a minimum of five consecutive prover runs within 0.0005 (0.05 percent repeatability) as described in API 4.5, Subsection 6.5 (incorporated by reference, see § 3174.3). The master meter must not be mechanically compensated for oil gravity or temperature; its readout must indicate units of volume without corrections. The meter factor must be documented on the calibration certificate and must be calibrated at least once every 12 months. New master meters must be calibrated immediately and recalibrated in three months. Master meters that have undergone mechanical repairs, alterations, or changes that affect the calibration must be calibrated immediately upon completion of this work and calibrated again 3 months after this date under API 4.5, API 4.8, Subsection 10.2, and API 4.8, Annex B (all incorporated by reference, see § 3174.3).
(2) Displacement provers must meet the requirements of API 4.2 (incorporated by reference, see § 3174.3) and be calibrated using the water-draw method under API 4.9.2 (incorporated by reference, see § 3174.3), at the calibration frequencies specified in API 4.8, Subsection 10.1(b) (incorporated by reference, see § 3174.3).
(3) The base prover volume of a displacement prover must be calculated under API 12.2.4 (incorporated by reference, see § 3174.3).
(4) Displacement provers must be sized to obtain a displacer velocity through the prover that is within the appropriate range during proving under API 4.2, Subsection 4.3.4.2, Minimum Displacer Velocities and API 4.2, Subsection 4.3.4.1, Maximum Displacer Velocities (incorporated by reference, see § 3174.3).
(5) Fluid velocity is calculated using API 4.2, Subsection 4.3.4.3, Equation 12 (incorporated by reference, see § 3174.3).
(c) Meter proving runs. Meter proving must follow the applicable section(s) of API 4.1, Proving Systems (incorporated by reference, see § 3174.3).
(1) Meter proving must be performed under normal operating fluid pressure, fluid temperature, and fluid type and composition, as follows:
(i) The oil flow rate through the LACT or CMS during proving must be within 10 percent of the normal flow rate;
(ii) The absolute pressure as measured by the LACT or CMS during proving must be within 10 percent of the normal operating absolute pressure;
(iii) The temperature as measured by the LACT or CMS during the proving must be within 10 °F of the normal operating temperature; and
(iv) The gravity of the oil during proving must be within 5° API of the normal oil gravity.
(v) If the normal flow rate, pressure, temperature, or oil gravity vary by more than the limits defined in paragraphs (c)(i) through (c)(iv) of this section, meter provings must be conducted, at a minimum, under the three following conditions: At the lower limit of normal operating conditions, at the upper limit of normal operation conditions, and at the midpoint of normal operating conditions.
(2) If each proving run is not of sufficient volume to generate at least 10,000 pulses, as specified by API 4.2, Subsection 4.3.2 (incorporated by reference, see § 3174.3), from the positive displacement meter or the Coriolis meter, then pulse interpolation must be used in accordance with API 4.6 (incorporated by reference, see § 3174.3).
(3) Proving runs must be made until the calculated meter factor or meter generated pulses from five consecutive runs match within a tolerance of 0.0005 (0.05 percent) between the highest and the lowest value in accordance with API 12.2.3, Subsection 9 (incorporated by reference, see § 3174.3).
(4) The new meter factor is the arithmetic average of the meter generated pulses or intermediate meter factors calculated from the five consecutive runs in accordance with API 12.2.3, Subsection 9 (incorporated by reference, see § 3174.3).
(5) Meter factor computations must follow the sequence described in API 12.2.3 (incorporated by reference, see § 3174.3).
(6) If multiple meters factors are determined over a range of normal operating conditions, then:
(i) If all the meter factors determined over a range of conditions fall within 0.0020 of each other, then a single meter factor may be calculated for that range as the arithmetic average of all the meter factors within that range. The full range of normal operating conditions may be divided into segments such that all the meter factors within each segment fall within a range of 0.0020. In this case, a single meter factor for each segment may be calculated as the arithmetic average of the meter factors within that segment; or
(ii) The metering system may apply a dynamic meter factor derived (using, e.g., linear interpolation, polynomial fit, etc.) from the series of meter factors determined over the range of normal operating conditions, so long as no two neighboring meter factors differ by more than 0.0020.
(7) The meter factor must be at least 0.9900 and no more than 1.0100.
(8) The initial meter factor for a new or repaired meter must be at least 0.9950 and no more than 1.0050.
(9) For positive displacement meters, the back pressure valve may be adjusted after proving only within the normal operating fluid flow rate and fluid pressure as described in paragraph (c)(1) of this section. If the back pressure valve is adjusted after proving, the operator must document the as left fluid flow rate and fluid pressure on the proving report.
(10) If a composite meter factor is calculated, the CPL value must be calculated from the pressure setting of the back pressure valve or the normal operating pressure at the meter. Composite meter factors must not be used with a Coriolis meter.
(d) Minimum proving frequency. The operator must prove any FMP meter before removal or sales of production after any of the following events:
(1) Initial meter installation;
(2) Every 3 months (quarterly) after the last proving, or each time the registered volume flowing through the meter, as measured on the non-resettable totalizer from the last proving, increases by 75,000 bbl, whichever comes first, but no more frequently than monthly;
(3) Meter zeroing (Coriolis meter);
(4) Modification of mounting conditions;
(5) A change in fluid temperature that exceeds the transducer's calibrated span;
(6) A change in pressure, density, or flow rate that exceeds the operating proving limits;
(7) The mechanical or electrical components of the meter have been changed, repaired, or removed;
(8) Internal calibration factors have been changed or reprogrammed; or
(9) At the request of the AO.
(e) Excessive meter factor deviation. (1) If the difference between meter factors established in two successive provings exceeds ±0.0025, the meter must be immediately removed from service, checked for damage or wear, adjusted or repaired, and reproved before returning the meter to service.
(2) The arithmetic average of the two successive meter factors must be applied to the production measured through the meter between the date of the previous meter proving and the date of the most recent meter proving.
(3) The proving report submitted under paragraph (i) of this section must clearly show the most recent meter factor and describe all subsequent repairs and adjustments.
(f) Verification of the temperature transducer. As part of each required meter proving and upon replacement, the temperature averager for a LACT system and the temperature transducer used in conjunction with a CMS must be verified against a known standard according to the following:
(1) The temperature averager or temperature transducer must be compared with a test thermometer traceable to NIST and with a stated accuracy of ±0.25 °F or better.
(2) The temperature reading displayed on the temperature averager or temperature transducer must be compared with the reading of the test thermometer using one of the following methods:
(i) The test thermometer must be placed in a test thermometer well located not more than 12″ from the probe of the temperature averager or temperature transducer; or
(ii) Both the test thermometer and probe of the temperature averager or temperature transducer must be placed in an insulated water bath. The water bath temperature must be within 20 °F of the normal flowing temperature of the oil.
(3) The displayed reading of instantaneous temperature from the temperature averager or the temperature transducer must be compared with the reading from the test thermometer. If they differ by more than 0.5 °F, then the difference in temperatures must be noted on the meter proving report and:
(i) The temperature averager or temperature transducer must be adjusted to match the reading of the test thermometer; or
(ii) The temperature averager or temperature transducer must be recalibrated, repaired, or replaced.
(g) Verification of the pressure transducer (if applicable). (1) As part of each required meter proving and upon replacement, the pressure transducer must be compared with a test pressure device (dead weight or pressure gauge) traceable to NIST and with a stated maximum uncertainty of no more than one-half of the accuracy required from the transducer being verified.
(2) The pressure reading displayed on the pressure transducer must be compared with the reading of the test pressure device.
(3) The pressure transducer must be tested at the following three points:
(i) Zero (atmospheric pressure);
(ii) 100 percent of the calibrated span of the pressure transducer; and
(iii) A point that represents the normal flowing pressure through the Coriolis meter.
(4) If the pressure applied by the test pressure device and the pressure displayed on the pressure transducer vary by more than the required accuracy of the pressure transducer, the pressure transducer must be adjusted to read within the stated accuracy of the test pressure device.
(h) Density verification (if applicable). As part of each required meter proving, if the API gravity of oil is determined from the average density measured by the Coriolis meter (rather than from a composite sample), then during each proving of the Coriolis meter, the instantaneous flowing density determined by the Coriolis meter must be verified by comparing it with an independent density measurement as specified under API 5.6, Subsection 9.1.2.1 (incorporated by reference, see § 3174.3). The difference between the indicated density determined from the Coriolis meter and the independently determined density must be within the specified density reference accuracy specification of the Coriolis meter. Sampling must be performed in accordance with API 8.1, API 8.2, or API 8.3 (incorporated by reference, see § 3174.3), as appropriate.
(i) Meter proving reporting requirements. (1) The operator must report to the AO all meter-proving and volume adjustments after any LACT system or CMS malfunction, including excessive meter-factor deviation, using the appropriate form in either API 12.2.3 or API 5.6 (both incorporated by reference, see § 3174.3), or any similar format showing the same information as the API form, provided that the calculation of meter factors maintains the proper calculation sequence and rounding.
(2) In addition to the information required under paragraph (i)(1) of this section, each meter-proving report must also show the:
(i) Unique meter ID number;
(ii) Lease number, CA number, or unit PA number;
(iii) The temperature from the test thermometer and the temperature from the temperature averager or temperature transducer;
(iv) For pressure transducers, the pressure applied by the pressure test device and the pressure reading from the pressure transducer at the three points required under paragraph (g)(3) of this section;
(v) For density verification (if applicable), the instantaneous flowing density (as determined by Coriolis meter), and the independent density measurement, as compared under paragraph (h) of this section; and
(vi) The “as left” fluid flow rate and fluid pressure, if the back pressure valve is adjusted after proving as described in paragraph (c)(9) of this section.
(3) The operator must submit the meter-proving report to the AO no later than 14 days after the meter proving. The proving report may be either in a hard copy or electronic format.
§ 3174.12   Measurement tickets.
(a) Tank gauging. After oil is measured by tank gauging under §§ 3174.5 and 3174.6 of this subpart, the operator, purchaser, or transporter, as appropriate, must complete a uniquely numbered measurement ticket, in either paper or electronic format, with the following information:
(1) Lease, unit PA, or CA number;
(2) Unique tank number and nominal tank capacity;
(3) Opening and closing dates and times;
(4) Opening and closing gauges and observed temperatures in °F;
(5) Observed volume for opening and closing gauge, using tank specific calibration charts (see § 3174.5(c));
(6) Total gross standard volume removed from the tank following API 11.1 (incorporated by reference, see § 3174.3);
(7) Observed API oil gravity and temperature in °F;
(8) API oil gravity at 60 °F, following API 11.1 (incorporated by reference, see § 3174.3);
(9) S&W content percent;
(10) Unique number of each seal removed and installed;
(11) Name of the individual performing the tank gauging; and
(12) Name of the operator.
(b) LACT system and CMS. (1) At the beginning of every month, and, unless the operator is using a flow computer under § 3174.10, before conducting proving operations on a LACT system, the operator, purchaser, or transporter, as appropriate, must complete a uniquely numbered measurement ticket, in either paper or electronic format, with the following information:
(i) Lease, unit PA, or CA number;
(ii) Unique meter ID number;
(iii) Opening and closing dates;
(iv) Opening and closing totalizer readings of the indicated volume;
(v) Meter factor, indicating if it is a composite meter factor;
(vi) Total gross standard volume removed through the LACT system or CMS;
(vii) API oil gravity. For API oil gravity determined from a composite sample, the observed API oil gravity and temperature must be indicated in °F and the API oil gravity must be indicated at 60 °F. For API oil gravity determined from average density (CMS only), the average uncorrected density must be determined by the CMS;
(viii) The average temperature in °F;
(ix) The average flowing pressure in psig;
(x) S&W content percent;
(xi) Unique number of each seal removed and installed;
(xii) Name of the purchaser's representative; and
(xiii) Name of the operator.
(2) Any accumulators used in the determination of average pressure, average temperature, and average density must be reset to zero whenever a new measurement ticket is opened.
§ 3174.13   Oil measurement by other methods.
(a) Any method of oil measurement other than tank gauging, LACT system, or CMS at an FMP requires prior BLM approval.
(b)(1) Any operator requesting approval to use alternate oil measurement equipment or measurement method must submit to the BLM performance data, actual field test results, laboratory test data, or any other supporting data or evidence that demonstrates that the proposed alternate oil equipment or method would meet or exceed the objectives of the applicable minimum requirements of this subpart and would not affect royalty income or production accountability.
(2) The PMT will review the submitted data to ensure that the alternate oil measurement equipment or method meets the requirements of this subpart and will make a recommendation to the BLM to approve use of the equipment or method, disapprove use of the equipment or method, or approve use of the equipment or method with conditions for its use. If the PMT recommends, and the BLM approves new equipment or methods, the BLM will post the make, model, range or software version (as applicable), or method on the BLM Web site www.blm.gov as being appropriate for use at an FMP for oil measurement without further approval by the BLM, subject to any conditions of approval identified by the PMT and approved by the BLM.
(c) The procedures for requesting and granting a variance under § 3170.6 of this part may not be used as an avenue for approving new technology, methods, or equipment. Approval of alternative oil measurement equipment or methods may be obtained only under this section.
§ 3174.14   Determination of oil volumes by methods other than measurement.
(a) Under 43 CFR 3162.7-2, when production cannot be measured due to spillage or leakage, the amount of production must be determined by using any method the AO approves or prescribes. This category of production includes, but is not limited to, oil that is classified as slop oil or waste oil.
(b) No oil may be classified or disposed of as waste oil unless the operator can demonstrate to the satisfaction of the AO that it is not economically feasible to put the oil into marketable condition.
(c) The operator may not sell or otherwise dispose of slop oil without prior written approval from the AO. Following the sale or disposal of slop oil, the operator must notify the AO in writing of the volume sold or disposed of and the method used to compute the volume.
§ 3174.15   Immediate assessments.
Certain instances of noncompliance warrant the imposition of immediate assessments upon the BLM's discovery of the violation, as prescribed in the following table. Imposition of any of these assessments does not preclude other appropriate enforcement actions.
Table 1 to § 3174.15—Violations Subject to an Immediate Assessment
§ 3175.10   Definitions and acronyms.
(a) As used in this subpart, the term:
AGA Report No. (followed by a number) means a standard prescribed by the American Gas Association, with the number referring to the specific standard.
Area ratio means the smallest unrestricted area at the primary device divided by the cross-sectional area of the meter tube. For example, the area ratio (A r ) of an orifice plate is the area of the orifice bore (A d ) divided by the area of the meter tube (A D ). For an orifice plate with a bore diameter (d) of 1.000 inches in a meter tube with an inside diameter (D) of 2.000 inches the area ratio is 0.25 and is calculated as follows:
As-found means the reading of a mechanical or electronic transducer when compared to a certified test device, prior to making any adjustments to the transducer.
As-left means the reading of a mechanical or electronic transducer when compared to a certified test device, after making adjustments to the transducer, but prior to returning the transducer to service.
Atmospheric pressure means the pressure exerted by the weight of the atmosphere at a specific location.
Beta ratio means the measured diameter of the orifice bore divided by the measured inside diameter of the meter tube. This is also referred to as a diameter ratio.
Bias means a systematic shift in the mean value of a set of measurements away from the true value of what is being measured.
British thermal unit (Btu) means the amount of heat needed to raise the temperature of one pound of water by 1 °F.
Component-type electronic gas measurement system means an electronic gas measurement system comprising transducers and a flow computer, each identified by a separate make and model, from which performance specifications are obtained.
Configuration log means a list of all fixed or user-programmable parameters used by the flow computer that could affect the calculation or verification of flow rate, volume, or heating value.
Discharge coefficient means an empirically derived correction factor that is applied to the theoretical differential flow equation in order to calculate a flow rate that is within stated uncertainty limits.
Effective date of a spot or composite gas sample means the first day on which the relative density and heating value determined from the sample are used in calculating the volume and quality on which royalty is based.
Electronic gas measurement (EGM) means all of the hardware and software necessary to convert the static pressure, differential pressure, and flowing temperature developed as part of a primary device, to a quantity, rate, or quality measurement that is used to determine Federal royalty. For orifice meters, this includes the differential-pressure transducer, static-pressure transducer, flowing-temperature transducer, on-line gas chromatograph (if used), flow computer, display, memory, and any internal or external processes used to edit and present the data or values measured.
Element range means the difference between the minimum and maximum value that the element (differential-pressure bellows, static-pressure element, and temperature element) of a mechanical recorder is designed to measure.
Event log means an electronic record of all exceptions and changes to the flow parameters contained within the configuration log that occur and have an impact on a quantity transaction record.
GPA (followed by a number) means a standard prescribed by the Gas Processors Association, with the number referring to the specific standard.
Heating value means the gross heat energy released by the complete combustion of one standard cubic foot of gas at 14.73 pounds per square inch absolute (psia) and 60 °F.
Heating value variability means the deviation of previous heating values over a given time period from the average heating value over that same time period, calculated at a 95 percent confidence level. Unless otherwise approved by the BLM, variability is determined with the following equation:
High-volume facility measurement point or high-volume FMP means any FMP that measures more than 200 Mcf/day, but less than or equal to 1,000 Mcf/day over the averaging period.
Hydrocarbon dew point means the temperature at which hydrocarbon liquids begin to form within a gas mixture. For the purpose of this regulation, the hydrocarbon dew point is the flowing temperature of the gas measured at the FMP, unless otherwise approved by the AO.
Integration means a process by which the lines on a circular chart (differential pressure, static pressure, and flowing temperature) used in conjunction with a mechanical chart recorder are re-traced or interpreted in order to determine the volume that is represented by the area under the lines. An integration statement documents the values determined from the integration.
Live input variable means a datum that is automatically obtained in real time by an EGM system.
Low-volume facility measurement point or low-volume FMP means any FMP that measures more than 35 Mcf/day, but less than or equal to 200 Mcf/day, over the averaging period.
Lower calibrated limit means the minimum engineering value for which a transducer was calibrated by certified equipment, either in the factory or in the field.
Mean means the sum of all the values in a data set divided by the number of values in the data set.
Mole percent means the number of molecules of a particular type that are present in a gas mixture divided by the total number of molecules in the gas mixture, expressed as a percentage.
Normal flowing point means the differential pressure, static pressure, and flowing temperature at which an FMP normally operates when gas is flowing through it.
Primary device means the volume-measurement equipment installed in a pipeline that creates a measureable and predictable pressure drop in response to the flow rate of fluid through the pipeline. It includes the pressure-drop device, device holder, pressure taps, required lengths of pipe upstream and downstream of the pressure-drop device, and any flow conditioners that may be used to establish a fully developed symmetrical flow profile.
Qualified test facility means a facility with currently certified measurement systems for mass, length, time, temperature, and pressure traceable to the NIST primary standards or applicable international standards approved by the BLM.
Quantity transaction record (QTR) means a report generated by an EGM system that summarizes the daily and hourly volumes calculated by the flow computer and the average or totals of the dynamic data that is used in the calculation of volume.
Reynolds number means the ratio of the inertial forces to the viscous forces of the fluid flow, and is defined as:
Redundancy verification means a process of verifying the accuracy of an EGM system by comparing the readings of two sets of transducers placed on the same primary device.
Secondary device means the differential-pressure, static-pressure, and temperature transducers in an EGM system, or a mechanical recorder, including the differential pressure, static pressure, and temperature elements, and the clock, pens, pen linkages, and circular chart.
Self-contained EGM system means an EGM system in which the transducers and flow computer are identified by a single make and model number from which the performance specifications for the transducers and flow computer are obtained. Any change to the make or model numbers of either a transducer or a flow computer within a self-contained EGM system changes the system to a component-type EGM system.
Senior fitting means a type of orifice plate holder that allows the orifice plate to be removed, inspected, and replaced without isolating and depressurizing the meter tube.
Standard cubic foot (scf) means a cubic foot of gas at 14.73 psia and 60 °F.
Standard deviation means a measure of the variation in a distribution, and is equal to the square root of the arithmetic mean of the squares of the deviations of each value in the distribution from the arithmetic mean of the distribution.
Tertiary device means, for EGM systems, the flow computer and associated memory, calculation, and display functions.
Threshold of significance means the maximum difference between two data sets (a and b) that can be attributed to uncertainty effects. The threshold of significance is determined as follows:
Transducer means an electronic device that converts a physical property such as pressure, temperature, or electrical resistance into an electrical output signal that varies proportionally with the magnitude of the physical property. Typical output signals are in the form of electrical potential (volts), current (milliamps), or digital pressure or temperature readings. The term transducer includes devices commonly referred to as transmitters.
Turndown means a reduction of the measurement range of a transducer in order to improve measurement accuracy at the lower end of its scale. It is typically expressed as the ratio of the upper range limit to the upper calibrated limit.
Type test means a test on a representative number of a specific make, model, and range of a device to determine its performance over a range of operating conditions.
Uncertainty means the range of error that could occur between a measured value and the true value being measured, calculated at a 95 percent confidence level.
Upper calibrated limit means the maximum engineering value for which a transducer was calibrated by certified equipment, either in the factory or in the field.
Upper range limit (URL) means the maximum value that a transducer is designed to measure.
Verification means the process of determining the amount of error in a differential pressure, static pressure, or temperature transducer or element by comparing the readings of the transducer or element with the readings from a certified test device with known accuracy.
Very-low-volume facility measurement point or very-low-volume FMP means any FMP that measures 35 Mcf/day or less over the averaging period.
Very-high-volume facility measurement point or very-high-volume FMP means any FMP that measures more than 1,000 Mcf/day over the averaging period.
(b) As used in this subpart the following additional acronyms carry the meaning prescribed:
GARVS means the BLM's Gas Analysis Reporting and Verification System.
GC means gas chromatograph.
GPA means the Gas Processors Association.
Mcf means 1,000 standard cubic feet.
psia means pounds per square inch—absolute.
psig means pounds per square inch—gauge.
§ 3175.20   General requirements.
Measurement of all gas at an FMP must comply with the standards prescribed in this subpart, except as otherwise approved under § 3170.6 of this part.
§ 3175.30   Incorporation by reference.
(a) Certain material identified in this section is incorporated by reference into this part with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. Operators must comply with all incorporated standards and material as they are listed in this section. To enforce any edition other than that specified in this section, the BLM must publish a rule in the Federal Register and the material must be reasonably available to the public. All approved material is available for inspection at the Bureau of Land Management, Division of Fluid Minerals, 20 M Street SE., Washington, DC 20003, 202-912-7162; and at all BLM offices with jurisdiction over oil and gas activities; and is available from the sources listed below. It is also available for inspection at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030 or go to http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.
(b) American Gas Association (AGA), 400 North Capitol Street NW., Suite 450, Washington, DC 20001; telephone 202-824-7000.
(1) AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids, Second Edition, September, 1985 (“AGA Report No. 3 (1985)”), IBR approved for §§ 3175.61(a) and (b), 3175.80(k), and 3175.94(a).
(2) AGA Transmission Measurement Committee Report No. 8, Compressibility Factors of Natural Gas and Other Related Hydrocarbon Gases; Second Edition, November 1992 (“AGA Report No. 8”), IBR approved for §§ 3175.103(a) and 3175.120(d).
(c) American Petroleum Institute (API), 1220 L Street NW., Washington, DC 20005; telephone 202-682-8000. API also offers free, read-only access to some of the material at http://publications.api.org.
(1) API Manual of Petroleum Measurement Standards (MPMS) Chapter 14—Natural Gas Fluids Measurement, Section 1, Collecting and Handling of Natural Gas Samples for Custody Transfer; Seventh Edition, May 2016 (“API 14.1”), IBR approved for §§ 3175.112(b) and (c), 3175.113(c), and 3175.114(b).
(2) API MPMS, Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 1, General Equations and Uncertainty Guidelines; Fourth Edition, September 2012; Errata, July 2013 (“API 14.3.1”), IBR approved for § 3175.31(a) and Table 1 to § 3175.80.
(3) API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 2, Specification and Installation Requirements; Fifth Edition, March 2016 (“API 14.3.2”), IBR approved for §§ 3175.46(b) and (c), 3175.61(a), 3175.80(c) through (g) and (i) through (l), and Table 1 to § 3175.80.
(4) API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 3, Natural Gas Applications; Fourth Edition, November 2013 (“API 14.3.3”), IBR approved for §§ 3175.94(a) and 3175.103(a).
(5) API MPMS Chapter 14, Natural Gas Fluids Measurement, Section 3, Concentric, Square-Edged Orifice Meters, Part 3, Natural Gas Applications, Third Edition, August, 1992 (“API 14.3.3 (1992)”), IBR approved for § 3175.61(b).
(6) API MPMS, Chapter 14, Section 5, Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer; Third Edition, January 2009; Reaffirmed February 2014 (“API 14.5”), IBR approved for §§ 3175.120(c) and 3175.125(a).
(7) API MPMS Chapter 21, Section 1, Flow Measurement Using Electronic Metering Systems—Electronic Gas Measurement; Second Edition, February 2013 (“API 21.1”), IBR approved for Table 1 to § 3175.100, §§ 3175.101(e), 3175.102(a) and (c) through (e), 3175.103(b) and (c), and 3175.104(a) through (d).
(8) API MPMS Chapter 22—Testing Protocol, Section 2, Differential Pressure Flow Measurement Devices; First Edition, August 2005; Reaffirmed August 2012 (“API 22.2”), IBR approved for § 3175.47(b) through (d).
(d) Gas Processors Association (GPA), 6526 E. 60th Street, Tulsa, OK 74145; telephone 918-493-3872.
(1) GPA Standard 2166-05, Obtaining Natural Gas Samples for Analysis by Gas Chromatography Revised 2005 (“GPA 2166-05”), IBR approved for §§ 3175.113(c) and (d), 3175.114(a), and 3175.117(a).
(2) GPA Standard 2261-13, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography; Revised 2013 (“GPA 2261-13”), IBR approved for § 3175.118(a) and (c).
(3) GPA Standard 2198-03, Selection, Preparation, Validation, Care and Storage of Natural Gas and Natural Gas Liquids Reference Standard Blends; Revised 2003 (“GPA 2198-03”), IBR approved for § 3175.118(c).
(4) GPA Standard 2286-14, Method for the Extended Analysis of Natural Gas and Similar Gaseous Mixtures by Temperature Program Gas Chromatography; Revised 2014 (“GPA 2286-14”), IBR approved for § 3175.118(e).
(e) Pipeline Research Council International (PRCI), 3141 Fairview Park Dr., Suite 525, Falls Church, VA 22042; telephone 703-205-1600.
(1) PRCI Contract-NX-19, Manual for the Determination of Supercompressibility Factors for Natural Gas; December 1962 (“PRCI NX 19”), IBR approved for § 3175.61(b).
(2) [Reserved]
You may also be able to purchase these standards from the following resellers: Techstreet, 3916 Ranchero Drive, Ann Arbor, MI 48108; telephone 734-780-8000; www.techstreet.com/api/apigate.html ; IHS Inc., 321 Inverness Drive South, Englewood, CO 80112; 303-790-0600; www.ihs.com ; SAI Global, 610 Winters Ave., Paramus, NJ 07652; telephone 201-986-1131; http://infostore.saiglobal.com/store/ .
§ 3175.31   Specific performance requirements.
(a) Flow rate measurement uncertainty levels. (1) For high-volume FMPs, the measuring equipment must achieve an overall flow rate measurement uncertainty within ±3 percent.
(2) For very-high-volume FMPs, the measuring equipment must achieve an overall flow rate measurement uncertainty within ±2 percent.
(3) The determination of uncertainty is based on the values of flowing parameters ( e.g., differential pressure, static pressure, and flowing temperature for differential meters or velocity, mass flow rate, or volumetric flow rate for linear meters) determined as follows, listed in order of priority:
(i) The average flowing parameters listed on the most recent daily QTR, if available to the BLM at the time of uncertainty determination; or
(ii) The average flowing parameters from the previous day, as required under § 3175.101(b)(4)(i) through (iii) (for differential meters).
(4) The uncertainty must be calculated under API 14.3.1, Section 12 (incorporated by reference, see § 3175.30) or other methods approved by the AO.
(b) Heating value uncertainty levels. (1) For high-volume FMPs, the measuring equipment must achieve an annual average heating value uncertainty within ±2 percent.
(2) For very-high-volume FMPs, the measuring equipment must achieve an annual average heating value uncertainty within ±1 percent.
(3) Unless otherwise approved by the AO, the average annual heating value uncertainty must be determined as follows:
(c) Bias. For low-volume, high-volume, and very-high-volume FMPs, the measuring equipment used for either flow rate or heating value determination must achieve measurement without statistically significant bias.
(d) Verifiability. An operator may not use measurement equipment for which the accuracy and validity of any input, factor, or equation used by the measuring equipment to determine quantity, rate, or heating value are not independently verifiable by the BLM. Verifiability includes the ability to independently recalculate the volume, rate, and heating value based on source records and field observations.
§ 3175.40   Measurement equipment approved by standard or make and model.
The measurement equipment described in §§ 3175.41 through 3175.49 is approved for use at FMPs under the conditions and circumstances stated in those sections, provided it meets or exceeds the minimum standards prescribed in this subpart.
§ 3175.41   Flange-tapped orifice plates.
Flange-tapped orifice plates that are constructed, installed, operated, and maintained in accordance with the standards in § 3175.80 are approved for use.
§ 3175.42   Chart recorders.
Chart recorders used in conjunction with approved differential-type meters that are installed, operated, and maintained in accordance with the standards in § 3175.90 are approved for use for low-volume and very-low-volume FMPs only, and are not approved for high-volume or very-high-volume FMPs.
§ 3175.43   Transducers.
(a) A transducer of a specific make, model, and URL is approved for use in conjunction with differential meters for high-volume or very-high-volume FMPs if it meets the following requirements:
(1) It has been type-tested under § 3175.130;
(2) The documentation required in § 3175.134 has been submitted to the PMT; and
(3) It has been approved by the BLM and placed on the list of type-tested equipment maintained at www.blm.gov.
(b) A transducer of a specific make, model, and URL, in use at an FMP before January 17, 2017, is approved for continued use if:
(1) Data supporting the published performance specification of the transducer are submitted to the PMT in lieu of the documentation required in paragraph (a)(2) of this section; and
(2) It has been approved by the BLM and placed on the list of type-tested equipment maintained at www.blm.gov .
(c) All transducers are approved for use at very-low- and low-volume FMPs.
§ 3175.44   Flow-computer software.
(a) A flow computer of a particular make and model, and equipped with a particular software version, is approved for use at high- and very-high-volume FMPs if the flow computer and software version meet the following requirements:
(1) The documentation required in § 3175.144 has been submitted to the PMT;
(2) The PMT has determined that the flow computer and software version passed the type-testing required in § 3175.140, except as provided in paragraph (b) of this section; and
(3) The BLM has approved the flow computer and software version and has placed them on the list of approved equipment maintained at www.blm.gov .
(b) Software versions (high- and very-high-volume FMPs). (1) Software revisions that affect or have the potential to affect determination of flow rate, determination of volume, determination of heating value, or data or calculations used to verify flow rate, volume, or heating value must be type-tested under § 3175.140.
(2) Software revisions that do not affect or have the potential to affect the determination of flow rate, determination of volume, determination of heating value, or data and calculations used to verify flow rate, volume, or heating value are not required to be type-tested, however, the operator must provide the BLM with a list of these software versions and a brief description of what changes were made from the previous version. (The software manufacturer may provide such information instead of the operator.)
(c) Software versions (low- and very-low-volume FMPs). All software versions are approved for use at low- and very-low-volume FMPs, unless otherwise required by the BLM.
§ 3175.45   Gas chromatographs.
GCs that meet the standards in §§ 3175.117 and 3175.118 for determining heating value and relative density are approved for use.
§ 3175.46   Isolating flow conditioners.
The BLM will list on www.blm.gov the make, model, and size of isolating flow conditioner that is approved for use in conjunction with a flange-tapped orifice plate, so long as the isolating flow conditioner is installed, operated, and maintained in compliance with the requirements of this section. Approval of a particular make and model is obtained as prescribed in this section.
(a) All testing required under this section must be performed at a qualified test facility not affiliated with the flow-conditioner manufacturer.
(b) The operator or manufacturer must test the flow conditioner under API 14.3.2, Annex D (incorporated by reference, see § 3175.30) and submit all test data to the BLM.
(c) The PMT will review the test data to ensure that the device meets the requirements of API 14.3.2, Annex D (incorporated by reference, see § 3175.30) and make a recommendation to the BLM to either approve use of the device, disapprove use of the device, or approve it with conditions for its use.
(d) If approved, the BLM will add the approved make and model, and any applicable conditions of use, to the list maintained at www.blm.gov.
§ 3175.47   Differential primary devices other than flange-tapped orifice plates.
A make, model, and size of differential primary device listed at www.blm.gov is approved for use if it is installed, operated, and maintained in compliance with any applicable conditions of use identified on www.blm.gov for that device. Approval of a particular make and model is obtained as follows:
(a) All testing required under this section must be performed at a qualified test facility not affiliated with the primary device manufacturer.
(b) The primary device must be tested under API 22.2 (incorporated by reference, see § 3175.30).
(c) The operator must submit to the BLM all test data required under API 22.2 (incorporated by reference, see § 3175.30). (The manufacturer of the primary device may submit such information instead of the operator.)
(d) The PMT will review the test data to ensure that the primary device meets the requirements of API 22.2 (incorporated by reference, see § 3175.30) and § 3175.31(c) and (d) and make a recommendation to the BLM to either approve use of the device, disapprove use of the device, or approve its use with conditions.
(e) If the primary device is approved by the BLM, the BLM will add the approved make and model, and any applicable conditions of use, to the list maintained at www.blm.gov.
§ 3175.48   Linear measurement devices.
A make, model, and size of linear measurement device listed at www.blm.gov is approved for use if it is installed, operated, and maintained in compliance with any conditions of use identified on www.blm.gov for that device. Approval of a particular make and model is obtained as follows:
(a) The linear measurement device must be tested at a qualified test facility not affiliated with the linear-measurement-device manufacturer;
(b) The operator or manufacturer must submit to the BLM all test data required by the PMT;
(c) The PMT will review the test data to ensure that the linear measurement device meets the requirements of § 3175.31(c) and (d) and make a recommendation to the BLM to either approve use of the device, disapprove use of the device, or approve its use with conditions; and
(d) If the linear measurement device is approved, the BLM will add the approved make and model, and any applicable conditions of use, to the list maintained at www.blm.gov.
§ 3175.49   Accounting systems.
An accounting system with a name and version listed at www.blm.gov is approved for use in reporting logs and records to the BLM. The approval is specific to those makes and models of flow computers for which testing demonstrates compatibility. Approval for a particular name and version of accounting system used with a particular make and model of flow computer is obtained as follows:
(a) For daily QTRs (see § 3175.104(a)), an operator or vendor must submit daily QTRs to the BLM both from the accounting system and directly from the flow computer for at least 6 consecutive monthly reporting periods;
(b) For hourly QTRs (see § 3175.104(a)), an operator must submit hourly QTRs to the BLM both from the accounting system and directly from the flow computer for at least 15 consecutive daily reporting periods. (A vendor may submit such information on behalf of an operator);
(c) For configuration logs (see § 3175.104(b)), an operator must submit at least 10 configuration logs to the BLM taken at random times covering a span of at least 6 months both from the accounting system and directly from the flow computer. (A vendor may submit such information on behalf of an operator);
(d) For event logs (see § 3175.104(c)), an operator must submit an event log to the BLM containing at least 50 events both from the accounting system and directly from the flow computer. (A vendor may submit such information on behalf of an operator);
(e) For alarm logs (see § 3175.104(d)), an operator must submit an alarm log to the BLM containing at least 50 alarm conditions both from the accounting system and directly from the flow computer (a vendor may submit such information on behalf of an operator);
(f) The BLM may require additional tests and records that may be necessary to determine that the software meets the requirements of § 3175.104(a);
(g) The records retrieved directly from the flow computer in paragraphs (a) through (d) of this section must be unedited;
(h) The records retrieved from the accounting system in paragraphs (a) through (d) must include both edited and unedited versions; and
(i) The BLM will approve the accounting system name and version for use with the make and model of flow computer used for comparison, and add the system name and version to the list of approved systems maintained at www.blm.gov if:
(1) The BLM compares the records retrieved directly from the flow computer with the unedited records from the accounting system and there are no significant discrepancies; and
(2) The BLM compares the records retrieved directly from the flow computer with the edited records from the accounting system and all changes are clearly indicated, the reason for each change is indicated or is available upon request, and the edited version is clearly distinguishable from the unedited version.
§ 3175.60   Timeframes for compliance.
(a) New FMPs. (1) Except as allowed in paragraphs (a)(2) through (4) of this section, the measuring procedures and equipment installed at any FMP on or after January 17, 2017 must comply with all of the requirements of this subpart upon installation.
(2) The gas analysis reporting requirements of § 3175.120(e) and (f) will begin on January 17, 2019.
(3) High- and very-high-volume FMPs must comply with the sampling frequency requirements of § 3175.115(b) starting on January 17, 2019. Between January 17, 2017 and January 17, 2019, the initial sampling frequencies required at high- and very-high-volume FMPs are those listed in Table 1 to § 3175.110.
(4) Equipment approvals required in §§ 3175.43, 3175.44, and 3175.46 through 3175.49 will be required after January 17, 2019.
(b) Existing FMPs. (1) Except as allowed in § 3175.61, measuring procedures and equipment at any FMP in place before January 17, 2017 must comply with the requirements of this subpart within the timeframes specified in this paragraph (b).
(2) High- and very-high-volume FMPs must comply with:
(i) All of the requirements of this subpart except as specified in paragraphs (b)(2)(ii) and (iii) of this section by January 17, 2018;
(ii) The gas analysis reporting requirements of § 3175.120(e) and (f) starting on January 17, 2019; and
(iii) Equipment approvals required in §§ 3175.43, 3175.44, and 3175.46 through 3175.49 starting on January 17, 2019.
(3) Low-volume FMPs must comply with all of the requirements of this subpart by January 17, 2019.
(4) Very-low-volume FMPs must comply with all of the requirements of this subpart by January 17, 2020.
(c) During the phase-in timeframes in paragraph (b) of this section, measuring procedures and equipment in place before January 17, 2017 must comply with the requirements in place prior to the issuance of this rule, including Onshore Oil and Gas Order No. 5, Measurement of Gas, and applicable NTLs, COAs, and written orders.
(d) Onshore Oil and Gas Order No. 5, Measurement of Gas, statewide NTLs, variance approvals, and written orders that establish requirements or standards related to gas measurement and that are in effect on January 17, 2017 are rescinded as of:
(1) January 17, 2018 for high-volume and very-high-volume FMPs;
(2) January 17, 2019 for low-volume FMPs; and
(3) January 17, 2020 for very-low-volume FMPs.
§ 3175.61   Grandfathering.
(a) Meter tubes. Meter tubes installed at high- and low-volume FMPs before January 17, 2017 are exempt from the meter tube requirements of API 14.3.2, Subsection 6.2 (incorporated by reference, see § 3175.30), and § 3175.80(f) and (k). For high-volume FMPs, the BLM will add an uncertainty of ±0.25 percent to the discharge coefficient uncertainty when determining overall meter uncertainty under § 3175.31(a), unless the PMT reviews, and the BLM approves, data showing otherwise. Meter tubes grandfathered under this section must still meet the following requirements:
(1) Orifice plate eccentricity must comply with AGA Report No. 3 (1985), Section 4.2.4 (incorporated by reference, see § 3175.30).
(2) Meter tube construction and condition must comply with AGA Report No. 3 (1985), Section 4.3.4 (incorporated by reference, see § 3175.30).
(3) Meter tube lengths. (i) Meter tube lengths must comply with AGA Report No. 3 (1985), Section 4.4 (dimensions “A” and “A'” from Figures 4-8) (incorporated by reference, see § 3175.30).
(ii) If the upstream meter tube contains a 19-tube bundle flow straightener or isolating flow conditioner, the installation must comply with § 3175.80(g);
(b) EGM software. (1) EGM software installed at very-low-volume FMPs before January 17, 2017 is exempt from the requirements in § 3175.103(a)(1). However, flow-rate calculations must still be calculated in accordance with AGA Report No. 3 (1985), Section 6, or API 14.3.3 (1992), and supercompressibility calculations must still be calculated in accordance with PRCI NX 19 (all incorporated by reference, see § 3175.30).
(2) EGM software installed at low-volume FMPs before January 17, 2017 is exempt from the requirements at § 3175.103(a)(1)(i) if the differential-pressure to static-pressure ratio, based on the monthly average differential pressure and static pressure, is less than the value of “ x i ” shown in API 14.3.3 (1992), Annex G, Table G.1 (incorporated by reference, see § 3175.30). However, flow-rate calculations must still be calculated in accordance with API 14.3.3 (1992) (incorporated by reference, see § 3175.30).
§ 3175.70   Measurement location.
(a) Commingling and allocation. Gas produced from a lease, unit PA, or CA may not be commingled with production from other leases, unit PAs, CAs, or non-Federal properties before the point of royalty measurement, unless prior approval is obtained under 43 CFR subpart 3173.
(b) Off-lease measurement. Gas must be measured on the lease, unit, or CA unless approval for off-lease measurement is obtained under 43 CFR subpart 3173.
§ 3175.80   Flange-tapped orifice plates (primary devices).
Except as stated in this section, as prescribed in Table 1 to this section, or grandfathered under § 3175.61, the standards and requirements in this section apply to all flange-tapped orifice plates (Note: The following table lists the standards in this subpart and the API standards that the operator must follow to install and maintain flange-tapped orifice plates. A requirement applies when a column is marked with an “x” or a number.).
(a) The Beta ratio must be no less than 0.10 and no greater than 0.75.
(b) The orifice bore diameter must be no less than 0.45 inches.
(c) For FMPs measuring production from wells first coming into production, or from existing wells that have been re-fractured (including FMPs already measuring production from one or more other wells), the operator must inspect the orifice plate upon installation and then every 2 weeks thereafter. If the inspection shows that the orifice plate does not comply with API 14.3.2, Section 4 (incorporated by reference, see § 3175.30), the operator must replace the orifice plate. When the inspection shows that the orifice plate complies with API 14.3.2, Section 4 (incorporated by reference, see § 3175.30), the operator thereafter must inspect the orifice plate as prescribed in paragraph (d) of this section.
(d) The operator must pull and inspect the orifice plate at the frequency (in months) identified in Table 1 to this section. The operator must replace orifice plates that do not comply with API 14.3.2, Section 4 (incorporated by reference, see § 3175.30), with an orifice plate that does comply with these standards.
(e) The operator must retain documentation for every plate inspection and must include that documentation as part of the verification report (see § 3175.92(d) for mechanical recorders, or § 3175.102(e) for EGM systems). The operator must provide that documentation to the BLM upon request. The documentation must include:
(1) The information required in § 3170.7(g) of this part;
(2) Plate orientation (bevel upstream or downstream);
(3) Measured orifice bore diameter;
(4) Plate condition (compliance with API 14.3.2, Section 4 (incorporated by reference, see § 3175.30));
(5) The presence of oil, grease, paraffin, scale, or other contaminants on the plate;
(6) Time and date of inspection; and
(7) Whether or not the plate was replaced.
(f) Meter tubes must meet the requirements of API 14.3.2, Subsections 5.1 through 5.4 (incorporated by reference, see § 3175.30).
(g) If flow conditioners are used, they must be either isolating-flow conditioners approved by the BLM and installed under BLM requirements (see § 3175.46) or 19-tube-bundle flow straighteners constructed in compliance with API 14.3.2, Subsections 5.5.2 through 5.5.4, and located in compliance with API 14.3.2, Subsection 6.3 (incorporated by reference, see § 3175.30).
(h) Basic meter tube inspection. The operator must:
(1) Perform a basic inspection of meter tubes within the timeframe (in years) specified in Table 1 to this section;
(2) Conduct a basic inspection that is able to identify obstructions, pitting, and buildup of foreign substances (e.g., grease and scale);
(3) Notify the AO at least 72 hours in advance of performing a basic inspection or submit a monthly or quarterly schedule of basic inspections to the AO in advance;
(4) Conduct additional inspections, as the AO may require, if warranted by conditions, such as corrosive or erosive-flow (e.g., high H 2 S or CO 2 content) or signs of physical damage to the meter tube;
(5) Maintain documentation of the findings from the basic meter tube inspection including:
(i) The information required in § 3170.7(g) of this part;
(ii) The time and date of inspection;
(iii) The type of equipment used to make the inspection; and
(iv) A description of findings, including location and severity of pitting, obstructions, and buildup of foreign substances; and
(6) Complete the first inspection after January 17, 2017 within the timeframes (in years) given in Table 1 to this section.
(i) Detailed meter tube inspection. (1) Within 30 days of a basic inspection that indicates the presence of pitting, obstructions, or a buildup of foreign substances, the operator must:
(i) For low-volume FMPs, clean the meter tube of obstructions and foreign substances;
(ii) For high- and very-high-volume FMPs, physically measure and inspect the meter tube to determine if the meter tube complies with API 14.3.2, Subsections 5.1 through 5.4 and API 14.3.2, Subsection 6.2 (incorporated by reference, see § 3175.30), or the requirements under § 3175.61(a), if the meter tube is grandfathered under § 3175.61(a). If the meter tube does not comply with the applicable standards, the operator must repair the meter tube to bring the meter tube into compliance with these standards or replace the meter tube with one that meets these standards; or
(iii) Submit a request to the AO for an extension of the 30-day timeframe, justifying the need for the extension.
(2) For all high- and very-high volume FMPs installed after January 17, 2017, the operator must perform a detailed inspection under paragraph (i)(1)(ii) of this section before operation of the meter. The operator may submit documentation showing that the meter tube complies with API 14.3.2, Subsections 5.1 through 5.4 (incorporated by reference, see § 3175.30) in lieu of performing a detailed inspection.
(3) The operator must notify the AO at least 24 hours before performing a detailed inspection.
(j) The operator must retain documentation of all detailed meter tube inspections, demonstrating that the meter tube complies with API 14.3.2, Subsections 5.1 through 5.4 (incorporated by reference, see § 3175.30), and showing all required measurements. The operator must provide such documentation to the BLM upon request for every meter-tube inspection. Documentation must also include the information required in § 3170.7(g) of this part.
(k) Meter tube lengths. (1) Meter-tube lengths and the location of 19-tube-bundle flow straighteners, if applicable, must comply with API 14.3.2, Subsection 6.3 (incorporated by reference, see § 3175.30).
(2) For Beta ratios of less than 0.5, the location of 19-tube bundle flow straighteners installed in compliance with AGA Report No. 3 (1985), Section 4.4 (incorporated by reference, see § 3175.30), also complies with the location of 19-tube bundle flow straighteners as required in paragraph (k)(1) of this section.
(3) If the diameter ratio (β) falls between the values in Tables 7, 8a, or 8b of API 14.3.2, Subsection 6.3 (incorporated by reference, see § 3175.30), the length identified for the larger diameter ratio in the appropriate Table is the minimum requirement for meter-tube length and determines the location of the end of the 19-tube-bundle flow straightener closest to the orifice plate. For example, if the calculated diameter ratio is 0.41, use the table entry for a 0.50 diameter ratio.
(l) Thermometer wells. (1) Thermometer wells used for determining the flowing temperature of the gas as well as thermometer wells used for verification (test well) must be located in compliance with API 14.3.2, Subsection 6.5 (incorporated by reference, see § 3175.30).
(2) Thermometer wells must be located in such a way that they can sense the same flowing gas temperature that exists at the orifice plate. The operator may accomplish this by physically locating the thermometer well(s) in the same ambient temperature conditions as the primary device (such as in a heated meter house) or by installing insulation and/or heat tracing along the entire meter run. If the operator chooses to use insulation to comply with this requirement, the AO may prescribe the quality of the insulation based on site specific factors such as ambient temperature, flowing temperature of the gas, composition of the gas, and location of the thermometer well in relation to the orifice plate (i.e., inside or outside of a meter house).
(3) Where multiple thermometer wells have been installed in a meter tube, the flowing temperature must be measured from the thermometer well closest to the primary device.
(4) Thermometer wells used to measure or verify flowing temperature must contain a thermally conductive liquid.
(m) The sampling probe must be located as specified in § 3175.112(b).
§ 3175.90   Mechanical recorder (secondary device).
(a) The operator may use a mechanical recorder as a secondary device only on very-low-volume and low-volume FMPs.
(b) Table 1 to this section lists the standards that the operator must follow to install, operate, and maintain mechanical recorders. A requirement applies when a column is marked with an “x” or a number.
§ 3175.91   Installation and operation of mechanical recorders.
(a) Gauge lines connecting the pressure taps to the mechanical recorder must:
(1) Have a nominal diameter of not less than 3/8 inch, including ports and valves;
(2) Be sloped upwards from the pressure taps at a minimum pitch of 1 inch per foot of length with no visible sag;
(3) Be the same internal diameter along their entire length;
(4) Not include tees, except for the static-pressure line;
(5) Not be connected to more than one differential-pressure bellows and static-pressure element, or to any other device; and
(6) Be no longer than 6 feet.
(b) The differential-pressure pen must record at a minimum reading of 10 percent of the differential-pressure-bellows range for the majority of the flowing period. This requirement does not apply to inverted charts.
(c) The flowing temperature of the gas must be continuously recorded and used in the volume calculations under § 3175.94(a)(1).
(d) The following information must be maintained at the FMP in a legible condition, in compliance with § 3170.7(g) of this part, and accessible to the AO at all times:
(1) Differential-pressure-bellows range;
(2) Static-pressure-element range;
(3) Temperature-element range;
(4) Relative density (specific gravity) of the gas;
(5) Static-pressure units of measure (psia or psig);
(6) Meter elevation;
(7) Meter-tube inside diameter;
(8) Primary device type;
(9) Orifice-bore or other primary-device dimensions necessary for device verification, Beta- or area-ratio determination, and gas-volume calculation;
(10) Make, model, and location of approved isolating flow conditioners, if used;
(11) Location of the downstream end of 19-tube-bundle flow straighteners, if used;
(12) Date of last primary-device inspection; and
(13) Date of last meter verification.
(e) The differential pressure, static pressure, and flowing temperature elements must be operated between the lower- and upper-calibrated limits of the respective elements.
§ 3175.92   Verification and calibration of mechanical recorders.
(a) Verification after installation or following repair. (1) Before performing any verification of a mechanical recorder required in this part, the operator must perform a leak test. The verification must not proceed if leaks are present. The leak test must be conducted in a manner that will detect leaks in the following:
(i) All connections and fittings of the secondary device, including meter manifolds and verification equipment;
(ii) The isolation valves; and
(iii) The equalizer valves.
(2) The operator must adjust the time lag between the differential- and static-pressure pens, if necessary, to be 1/96 of the chart rotation period, measured at the chart hub. For example, the time lag is 15 minutes on a 24-hour test chart and 2 hours on an 8-day test chart.
(3) The meter's differential pen arc must be able to duplicate the test chart's time arc over the full range of the test chart, and must be adjusted, if necessary.
(4) The as-left values must be verified in the following sequence against a certified pressure device for the differential-pressure and static-pressure elements (if the static-pressure pen has been offset for atmospheric pressure, the static-pressure element range is in psia):
(i) Zero (vented to atmosphere);
(ii) 50 percent of element range;
(iii) 100 percent of element range;
(iv) 80 percent of element range;
(v) 20 percent of element range; and
(vi) Zero (vented to atmosphere).
(5) The following as-left temperatures must be verified by placing the temperature probe in a water bath with a certified test thermometer:
(i) Approximately 10 °F below the lowest expected flowing temperature;
(ii) Approximately 10 °F above the highest expected flowing temperature; and
(iii) At the expected average flowing temperature.
(6) If any of the readings required in paragraph (a)(4) or (5) of this section vary from the test device reading by more than the tolerances shown in Table 1 to this section, the operator must replace and verify the element for which readings were outside the applicable tolerances before returning the meter to service.
(7) If the static-pressure pen is offset for atmospheric pressure:
(i) The atmospheric pressure must be calculated under appendix A to this subpart; and
(ii) The pen must be offset prior to obtaining the as-left verification values required in paragraph (a)(4) of this section.
(b) Routine verification frequency. The differential pressure, static pressure, and temperature elements must be verified under the requirements of this section at the frequency specified in Table 1 to § 3175.90, in months.
(c) Routine verification procedures. (1) Before performing any verification required in this part, the operator must perform a leak test in the manner required under paragraph (a)(1) of this section.
(2) No adjustments to the pens or linkages may be made until an as-found verification is obtained. If the static pen has been offset for atmospheric pressure, the static pen must not be reset to zero until the as-found verification is obtained.
(3) The operator must obtain the as-found values of differential and static pressure against a certified pressure device at the readings listed in paragraph (a)(4) of this section, with the following additional requirements:
(i) If there is sufficient data on site to determine the point at which the differential and static pens normally operate, the operator must also obtain an as-found value at those points;
(ii) If there is not sufficient data on site to determine the points at which the differential and static pens normally operate, the operator must also obtain as-found values at 5 percent of the element range and 10 percent of the element range; and
(iii) If the static-pressure pen has been offset for atmospheric pressure, the static-pressure element range is in units of psia.
(4) The as-found value for temperature must be taken using a certified test thermometer placed in a test thermometer well if there is flow through the meter and the meter tube is equipped with a test thermometer well. If there is no flow through the meter or if the meter is not equipped with a test thermometer well, the temperature probe must be verified by placing it along with a test thermometer in an insulated water bath.
(5) The element undergoing verification must be calibrated according to manufacturer specifications if any of the as-found values determined under paragraph (c)(3) or (4) of this section are not within the tolerances shown in Table 1 to this section, when compared to the values applied by the test equipment.
(6) The operator must adjust the time lag between the differential- and static-pressure pens, if necessary, to be 1/96 of the chart rotation period, measured at the chart hub. For example, the time lag is 15 minutes on a 24-hour test chart and 2 hours on an 8-day test chart.
(7) The meter's differential pen arc must be able to duplicate the test chart's time arc over the full range of the test chart, and must be adjusted, if necessary.
(8) If any adjustment to the meter was made, the operator must perform an as-left verification on each element adjusted using the procedures in paragraphs (c)(3) and (4) of this section.
(9) If, after an as-left verification, any of the readings required in paragraph (c)(3) or (4) of this section vary by more than the tolerances shown in Table 1 to this section when compared with the test-device reading, any element which has readings that are outside of the applicable tolerances must be replaced and verified under this section before the operator returns the meter to service.
(10) If the static-pressure pen is offset for atmospheric pressure:
(i) The atmospheric pressure must be calculated under appendix A to this subpart; and
(ii) The pen must be offset prior to obtaining the as-left verification values required in paragraph (c)(3) of this section.
(d) The operator must retain documentation of each verification, as required under § 3170.7(g) of this part, and submit it to the BLM upon request. This documentation must include:
(1) The time and date of the verification and the prior verification date;
(2) Primary-device data (meter-tube inside diameter and differential-device size and Beta or area ratio) if the orifice plate is pulled and inspected;
(3) The type and location of taps (flange or pipe, upstream or downstream static tap);
(4) Atmospheric pressure used to offset the static-pressure pen, if applicable;
(5) Mechanical recorder data (make, model, and differential pressure, static pressure, and temperature element ranges);
(6) The normal operating points for differential pressure, static pressure, and flowing temperature;
(7) Verification points (as-found and applied) for each element;
(8) Verification points (as-left and applied) for each element, if a calibration was performed;
(9) Names, contact information, and affiliations of the person performing the verification and any witness, if applicable; and
(10) Remarks, if any.
(e) Notification of verification. (1) For verifications performed after installation or following repair, the operator must notify the AO at least 72 hours before conducting the verifications.
(2) For routine verifications, the operator must notify the AO at least 72 hours before conducting the verification or submit a monthly or quarterly verification schedule to the AO in advance.
(f) If, during the verification, the combined errors in as-found differential pressure, static pressure, and flowing temperature taken at the normal operating points tested result in a flow-rate error greater than 2 percent or 2 Mcf/day, whichever is greater, the volumes reported on the OGOR and on royalty reports submitted to ONRR must be corrected beginning with the date that the inaccuracy occurred. If that date is unknown, the volumes must be corrected beginning with the production month that includes the date that is half way between the date of the last verification and the date of the current verification. For example: Meter verification determined that the meter was reading 4 Mcf/day high at the normal operating points. The average flow rate measured by the meter is 90 Mcf/day. There is no indication of when the inaccuracy occurred. The date of the current verification was December 15, 2015. The previous verification was conducted on June 15, 2015. The royalty volumes reported on OGOR B that were based on this meter must be corrected for the 4 Mcf/day error back to September 15, 2015.
(g) Test equipment used to verify or calibrate elements at an FMP must be certified at least every 2 years. Documentation of the recertification must be on-site during all verifications and must show:
(1) Test equipment serial number, make, and model;
(2) The date on which the recertification took place;
(3) The test equipment measurement range; and
(4) The uncertainty determined or verified as part of the recertification.
§ 3175.93   Integration statements.
An unedited integration statement must be retained and made available to the BLM upon request. The integration statement must contain the following information:
(a) The information required in § 3170.7(g) of this part;
(b) The name of the company performing the integration;
(c) The month and year for which the integration statement applies;
(d) Meter-tube inside diameter (inches);
(e) The following primary device information, as applicable:
(i) Orifice bore diameter (inches); or
(ii) Beta or area ratio, discharge coefficient, and other information necessary to calculate the flow rate;
(f) Relative density (specific gravity);
(g) CO 2 content (mole percent);
(h) N 2 content (mole percent);
(i) Heating value calculated under § 3175.125 (Btu/standard cubic feet);
(j) Atmospheric pressure or elevation at the FMP;
(k) Pressure base;
(l) Temperature base;
(m) Static-pressure tap location (upstream or downstream);
(n) Chart rotation (hours or days);
(o) Differential-pressure bellows range (inches of water);
(p) Static-pressure element range (psi); and
(q) For each chart or day integrated:
(i) The time and date on and time and date off;
(ii) Average differential pressure (inches of water);
(iii) Average static pressure;
(iv) Static-pressure units of measure (psia or psig);
(v) Average temperature ( °F);
(vi) Integrator counts or extension;
(vii) Hours of flow; and
(viii) Volume (Mcf).
§ 3175.94   Volume determination.
(a) The volume for each chart integrated must be determined as follows:
(1) If the primary device is a flange-tapped orifice plate, a single IMV must be calculated for each chart or chart interval using the following equation:
(2) For other types of primary devices, the IMV must be calculated using the equations and procedures recommended by the PMT and approved by the BLM, specific to the make, model, size, and area ratio of the primary device being used.
(3) Variables that are functions of differential pressure, static pressure, or flowing temperature (e.g., C d , Y, Z f ) must use the average values of differential pressure, static pressure, and flowing temperature as determined from the integration statement and reported on the integration statement for the chart or chart interval integrated. The flowing temperature must be the average flowing temperature reported on the integration statement for the chart or chart interval being integrated.
(b) Atmospheric pressure used to convert static pressure in psig to static pressure in psia must be determined under appendix A to this subpart.
§ 3175.100   Electronic gas measurement (secondary and tertiary device).
Except as stated in this section, as prescribed in Table 1 to this section, or grandfathered under § 3175.61, the standards and requirements in this section apply to all EGM systems used at FMPs (Note: The following table lists the standards in this subpart and the API standards that the operator must follow to install and maintain EGM systems. A requirement applies when a column is marked with an “x” or a number.).
§ 3175.101   Installation and operation of electronic gas measurement systems.
(a) Manifolds and gauge lines connecting the pressure taps to the secondary device must:
(1) Have a nominal diameter of not less than 3/8 -inch, including ports and valves;
(2) Be sloped upwards from the pressure taps at a minimum pitch of 1 inch per foot of length with no visible sag;
(3) Have the same internal diameter along their entire length;
(4) Not include tees except for the static-pressure line;
(5) Not be connected to any other devices or more than one differential pressure and static-pressure transducer. If the operator is employing redundancy verification, two differential pressure and two static-pressure transducers may be connected; and
(6) Be no longer than 6 feet.
(b) Each FMP must include a display, which must:
(1) Be readable without the need for data-collection units, laptop computers, a password, or any special equipment;
(2) Be on site and in a location that is accessible to the AO;
(3) Include the units of measure for each required variable;
(4) Display the software version and previous-day's volume, as well as the following variables consecutively:
(i) Current flowing static pressure with units (psia or psig);
(ii) Current differential pressure (inches of water);
(iii) Current flowing temperature ( °F); and
(iv) Current flow rate (Mcf/day or scf/day); and
(5) Either display or post on site and accessible to the AO an hourly or daily QTR (see § 3175.104(a)) no more than 31 days old showing the following information:
(i) Previous-period (for this section, previous period means at least 1 day prior, but no longer than 1 month prior) average differential pressure (inches of water);
(ii) Previous-period average static pressure with units (psia or psig); and
(iii) Previous-period average flowing temperature ( °F).
(c) The following information must be maintained at the FMP in a legible condition, in compliance with § 3170.7(g) of this part, and accessible to the AO at all times:
(1) The unique meter ID number;
(2) Relative density (specific gravity);
(3) Elevation of the FMP;
(4) Primary device information, such as orifice bore diameter (inches) or Beta or area ratio and discharge coefficient, as applicable;
(5) Meter-tube mean inside diameter;
(6) Make, model, and location of approved isolating flow conditioners, if used;
(7) Location of the downstream end of 19-tube-bundle flow straighteners, if used;
(8) For self-contained EGM systems, make and model number of the system;
(9) For component-type EGM systems, make and model number of each transducer and the flow computer;
(10) URL and upper calibrated limit for each transducer;
(11) Location of the static-pressure tap (upstream or downstream);
(12) Last primary-device inspection date; and
(13) Last secondary device verification date.
(d) The differential pressure, static pressure, and flowing temperature transducers must be operated between the lower and upper calibrated limits of the transducer. The BLM may approve the differential pressure to exceed the upper calibrated limit of the differential-pressure transducer for brief periods in plunger lift operations; however, the differential pressure may not exceed the URL.
(e) The flowing temperature of the gas must be continuously measured and used in the flow-rate calculations under API 21.1, Section 4 (incorporated by reference, see § 3175.30).
§ 3175.102   Verification and calibration of electronic gas measurement systems.
(a) Transducer verification and calibration after installation or repair. (1) Before performing any verification required in this section, the operator must perform a leak test in the manner prescribed in § 3175.92(a)(1).
(2) The operator must verify the points listed in API 21.1, Subsection 7.3.3 (incorporated by reference, see § 3175.30), by comparing the values from the certified test device with the values used by the flow computer to calculate flow rate. If any of these as-left readings vary from the test equipment reading by more than the tolerance determined by API 21.1, Subsection 8.2.2.2, Equation 24 (incorporated by reference, see § 3175.30), then that transducer must be replaced and the new transducer must be tested under this paragraph.
(3) For absolute static-pressure transducers, the value of atmospheric pressure used when the transducer is vented to atmosphere must be calculated under appendix A to this subpart, measured by a NIST-certified barometer with a stated accuracy of ±0.05 psi or better, or obtained from an absolute-pressure calibration device.
(4) Before putting a meter into service, the differential-pressure transducer must be tested at zero with full working pressure applied to both sides of the transducer. If the absolute value of the transducer reading is greater than the reference accuracy of the transducer, expressed in inches of water column, the transducer must be re-zeroed.
(b) Routine verification frequency. (1) If redundancy verification under paragraph (d) of this section is not used, the differential pressure, static pressure, and temperature transducers must be verified under the requirements of paragraph (c) of this section at the frequency specified in Table 1 to § 3175.100, in months; or
(2) If redundancy verification under paragraph (d) of this section is used, the differential pressure, static pressure, and temperature transducers must be verified under the requirements of paragraph (d) of this section. In addition, the transducers must be verified under the requirements of paragraph (c) of this section at least annually.
(c) Routine verification procedures. Verifications must be performed according to API 21.1, Subsection 8.2 (incorporated by reference, see § 3175.30), with the following exceptions, additions, and clarifications:
(1) Before performing any verification required under this section, the operator must perform a leak test consistent with § 3175.92(a)(1).
(2) An as-found verification for differential pressure, static pressure and temperature must be conducted at the normal operating point of each transducer.
(i) The normal operating point is the mean value taken over a previous time period not less than 1 day or greater than 1 month. Acceptable mean values include means weighted based on flow time and flow rate.
(ii) For differential and static-pressure transducers, the pressure applied to the transducer for this verification must be within five percentage points of the normal operating point. For example, if the normal operating point for differential pressure is 17 percent of the upper calibrated limit, the normal point verification pressure must be between 12 percent and 22 percent of the upper calibrated limit.
(iii) For the temperature transducer, the water bath or test thermometer well must be within 20 °F of the normal operating point for temperature.
(3) If any of the as-found values are in error by more than the manufacturer's specification for stability or drift—as adjusted for static pressure and ambient temperature—on two consecutive verifications, that transducer must be replaced prior to returning the meter to service.
(4) If a transducer is calibrated, the as-left verification must include the normal operating point of that transducer, as defined in paragraph (c)(2) of this section.
(5) The as-found values for differential pressure obtained with the low side vented to atmospheric pressure must be corrected to working-pressure values using API 21.1, Annex H, Equation H.1 (incorporated by reference, see § 3175.30).
(6) The verification tolerance for differential and static pressure is defined by API 21.1, Subsection 8.2.2.2, Equation 24 (incorporated by reference, see § 3175.30). The verification tolerance for temperature is equivalent to the uncertainty of the temperature transmitter or 0.5 °F, whichever is greater.
(7) All required verification points must be within the verification tolerance before returning the meter to service.
(8) Before putting a meter into service, the differential-pressure transducer must be tested at zero with full working pressure applied to both sides of the transducer. If the absolute value of the transducer reading is greater than the reference accuracy of the transducer, expressed in inches of water column, the transducer must be re-zeroed.
(d) Redundancy verification procedures. Redundancy verifications must be performed as required under API 21.1, Subsection 8.2 (incorporated by reference, see § 3175.30), with the following exceptions, additions, and clarifications:
(1) The operator must identify which set of transducers is used for reporting on the OGOR (the primary transducers) and which set of transducers is used as a check (the check set of transducers);
(2) For every calendar month, the operator must compare the flow-time linear averages of differential pressure, static pressure, and temperature readings from the primary transducers with those from the check transducers;
(3)(i) If for any transducer the difference between the averages exceeds the tolerance defined by the following equation:
(ii) The operator must verify both the primary and check transducer under paragraph (c) of this section within the first 5 days of the month following the month in which the redundancy verification was performed. For example, if the redundancy verification for March reveals that the difference in the flow-time linear averages of differential pressure exceeded the verification tolerance, both the primary and check differential-pressure transducers must be verified under paragraph (c) of this section by April 5th.
(e) The operator must retain documentation of each verification for the period required under § 3170.7 of this part, including calibration data for transducers that were replaced, and submit it to the BLM upon request.
(1) For routine verifications, this documentation must include:
(i) The information required in § 3170.7(g) of this part;
(ii) The time and date of the verification and the last verification date;
(iii) Primary device data (meter-tube inside diameter and differential-device size, Beta or area ratio);
(iv) The type and location of taps (flange or pipe, upstream or downstream static tap);
(v) The flow computer make and model;
(vi) The make and model number for each transducer, for component-type EGM systems;
(vii) Transducer data (make, model, differential, static, temperature URL, and upper calibrated limit);
(viii) The normal operating points for differential pressure, static pressure, and flowing temperature;
(ix) Atmospheric pressure;
(x) Verification points (as-found and applied) for each transducer;
(xi) Verification points (as-left and applied) for each transducer, if calibration was performed;
(xii) The differential device inspection date and condition (e.g., clean, sharp edge, or surface condition);
(xiii) Verification equipment make, model, range, accuracy, and last certification date;
(xiv) The name, contact information, and affiliation of the person performing the verification and any witness, if applicable; and
(xv) Remarks, if any.
(2) For redundancy verification checks, this documentation must include;
(i) The information required in § 3170.7(g) of this part;
(ii) The month and year for which the redundancy check applies;
(iii) The makes, models, upper range limits, and upper calibrated limits of the primary set of transducers;
(iv) The makes, models, upper range limits, and upper calibrated limits of the check set of transducers;
(v) The information required in API 21.1, Annex I (incorporated by reference, see § 3175.30);
(vii) The tolerance for differential pressure, static pressure, and temperature as calculated under paragraph (d)(2) of this section; and
(viii) Whether or not each transducer required verification under paragraph (c) of this section.
(f) Notification of verification. (1) For verifications performed after installation or following repair, the operator must notify the AO at least 72 hours before conducting the verifications.
(2) For routine verifications, the operator must notify the AO at least 72 hours before conducting the verification or submit a monthly or quarterly verification schedule to the AO in advance.
(g) If, during the verification, the combined errors in as-found differential pressure, static pressure, and flowing temperature taken at the normal operating points tested result in a flow-rate error greater than 2 percent or 2 Mcf/day, whichever is greater, the volumes reported on the OGOR and on royalty reports submitted to ONRR must be corrected beginning with the date that the inaccuracy occurred. If that date is unknown, the volumes must be corrected beginning with the production month that includes the date that is half way between the date of the last verification and the date of the present verification. See the example in § 3175.92(f).
(h) Test equipment requirements. (1) Test equipment used to verify or calibrate transducers at an FMP must be certified at least every 2 years. Documentation of the certification must be on site and made available to the AO during all verifications and must show:
(i) The test equipment serial number, make, and model;
(ii) The date on which the recertification took place;
(iii) The range of the test equipment; and
(iv) The uncertainty determined or verified as part of the recertification.
(2) Test equipment used to verify or calibrate transducers at an FMP must meet the following accuracy standards:
(i) The accuracy of the test equipment, stated in actual units of measure, must be no greater than 0.5 times the reference accuracy of the transducer being verified, also stated in actual units of measure; or
(ii) The equipment must have a stated accuracy of at least 0.10 percent of the upper calibrated limit of the transducer being verified.
§ 3175.103   Flow rate, volume, and average value calculation.
(a) The flow rate must be calculated as follows:
(1) For flange-tapped orifice plates, the flow rate must be calculated under:
(i) API 14.3.3, Section 4 and API 14.3.3, Section 5 (incorporated by reference, see § 3175.30); and
(ii) AGA Report No. 8 (incorporated by reference, see § 3175.30), for supercompressibility.
(2) For primary devices other than flange-tapped orifice plates, for which there are no industry standards, the flow rate must be calculated under the equations and procedures recommended by the PMT and approved by the BLM, specific to the make, model, size, and area ratio of the primary device used.
(b) Atmospheric pressure used to convert static pressure in psig to static pressure in psia must be determined under API 21.1, Subsection 8.3.3 (incorporated by reference, see § 3175.30).
(c) Hourly and daily gas volumes, average values of the live input variables, flow time, and integral value or average extension as required under § 3175.104 must be determined under API 21.1, Section 4 and API 21.1, Annex B (incorporated by reference, see § 3175.30).
§ 3175.104   Logs and records.
(a) The operator must retain, and submit to the BLM upon request, the original, unaltered, unprocessed, and unedited daily and hourly QTRs, which must contain the information identified in API 21.1, Subsection 5.2 (incorporated by reference, see § 3175.30), with the following additions and clarifications:
(1) The information required in § 3170.7(g) of this part;
(2) The volume, flow time, and integral value or average extension must be reported to at least 5 decimal places. The average differential pressure, static pressure, and temperature as calculated in § 3175.103(c), must be reported to at least three decimal places; and
(3) A statement of whether the operator has submitted the integral value or average extension.
(b) The operator must retain, and submit to the BLM upon request, the original, unaltered, unprocessed, and unedited configuration log, which must contain the information specified in API 21.1, Subsection 5.4 (including the flow-computer snapshot report in API 21.1, Subsection 5.4.2), and API 21.1, Annex G (incorporated by reference, see § 3175.30), with the following additions and clarifications:
(1) The information required in § 3170.7(g) of this part;
(2) Software/firmware identifiers under API 21.1, Subsection 5.3 (incorporated by reference, see § 3175.30);
(3) For very-low-volume FMPs only, the fixed temperature, if not continuously measured ( °F); and
(4) The static-pressure tap location (upstream or downstream).
(c) The operator must retain, and submit to the BLM upon request, the original, unaltered, unprocessed, and unedited event log. The event log must comply with API 21.1, Subsection 5.5 (incorporated by reference, see § 3175.30), with the following additions and clarifications: The event log must have sufficient capacity and must be retrieved and stored at intervals frequent enough to maintain a continuous record of events as required under § 3170.7 of this part, or the life of the FMP, whichever is shorter.
(d) The operator must retain an alarm log and provide it to the BLM upon request. The alarm log must comply with API 21.1, Subsection 5.6 (incorporated by reference, see § 3175.30).
(e) Records may only be submitted from accounting system names and versions and flow computer makes and models that have been approved by the BLM (see § 3175.49).
§ 3175.110   Gas sampling and analysis.
Except as stated in this section or as prescribed in Table 1 to this section, the standards and requirements in this section apply to all gas sampling and analyses. (Note: The following table lists the standards in this subpart and the API standards that the operator must follow to take a gas sample, analyze the gas sample, and report the findings of the gas analysis. A requirement applies when a column is marked with an “x” or a number.)
§ 3175.111   General sampling requirements.
(a) Samples must be taken by one of the following methods:
(1) Spot sampling under §§ 3175.113 through 3175.115;
(2) Flow-proportional composite sampling under § 3175.116; or
(3) On-line gas chromatograph under § 3175.117.
(b) At all times during the sampling process, the minimum temperature of all gas sampling components must be the lesser of:
(1) The flowing temperature of the gas measured at the time of sampling; or
(2) 30 °F above the calculated hydrocarbon dew point of the gas.
§ 3175.112   Sampling probe and tubing.
(a) All gas samples must be taken from a sample probe that complies with the requirements of paragraphs (b) and (c) of this section.
(b) Location of sample probe. (1) The sample probe must be located in the meter tube in accordance with API 14.1, Subsection 6.4.2 (incorporated by reference, see § 3175.30), and must be the first obstruction downstream of the primary device.
(2) The sample probe must be exposed to the same ambient temperature as the primary device. The operator may accomplish this by physically locating the sample probe in the same ambient temperature conditions as the primary device (such as in a heated meter house) or by installing insulation and/or heat tracing along the entire meter run. If the operator chooses to use insulation to comply with this requirement, the AO may prescribe the quality of the insulation based on site specific factors such as ambient temperature, flowing temperature of the gas, composition of the gas, and location of the sample probe in relation to the orifice plate (i.e., inside or outside of a meter house).
(c) Sample probe design and type. (1) Sample probes must be constructed from stainless steel.
(2) If a regulating type of sample probe is used, the pressure-regulating mechanism must be inside the pipe or maintained at a temperature of at least 30 °F above the hydrocarbon dew point of the gas.
(3) The sample probe length must be the shorter of:
(i) The length necessary to place the collection end of the probe in the center one third of the pipe cross-section; or
(ii) The recommended length of the probe in Table 1 in API 14.1, Subsection 6.4 (incorporated by reference, see § 3175.30).
(4) The use of membranes, screens, or filters at any point in the sample probe is prohibited.
(d) Sample tubing connecting the sample probe to the sample container or analyzer must be constructed of stainless steel or nylon 11.
§ 3175.113   Spot samples—general requirements.
(a) If an FMP is not flowing at the time that a sample is due, a sample must be taken within 15 days after flow is re-initiated. Documentation of the non-flowing status of the FMP must be entered into GARVS as required under § 3175.120(f).
(b) The operator must notify the AO at least 72 hours before obtaining a spot sample as required by this subpart, or submit a monthly or quarterly schedule of spot samples to the AO in advance of taking samples.
(c) Sample cylinder requirements. Sample cylinders must:
(1) Comply with API 14.1, Subsection 9.1 (incorporated by reference, see § 3175.30);
(2) Have a minimum capacity of 300 cubic centimeters; and
(3) Be cleaned before sampling under GPA 2166-05, Appendix A (incorporated by reference, see § 3175.30), or an equivalent method. The operator must maintain documentation of cleaning (see § 3170.7), have the documentation available on site during sampling, and provide it to the BLM upon request.
(d) Spot sampling using portable gas chromatographs. (1) Sampling separators, if used, must:
(i) Be constructed of stainless steel;
(ii) Be cleaned under GPA 2166-05, Appendix A (incorporated by reference, see § 3175.30), or an equivalent method, prior to sampling. The operator must maintain documentation of cleaning (see § 3170.7), have the documentation available on site during sampling, and provide it to the BLM upon request; and
(iii) Be operated under GPA 2166-05, Appendix B.3 (incorporated by reference, see § 3175.30).
(2) The sample port and inlet to the sample line must be purged using the gas being sampled before completing the connection between them.
(3) The portable GC must be operated, verified, and calibrated under § 3175.118.
(4) The documentation of verification or calibration required in § 3175.118(d) must be available for inspection by the BLM at the time of sampling.
(5) Minimum number of samples and analyses. (i) For low- and very-low-volume FMPs, at least three samples must be taken and analyzed;
(ii) For high-volume FMPs, samples must be taken and analyzed until the difference between the maximum heating value and minimum heating value calculated from three consecutive analyses is less than or equal to 16 Btu/scf;
(iii) For very-high-volume FMPs, samples must be taken and analyzed until the difference between the maximum heating value and minimum heating value calculated from three consecutive analyses is less than or equal to 8 Btu/scf.
(6) The heating value and relative density used for OGOR reporting must be:
(i) The mean heating value and relative density calculated from the three analyses required in paragraph (d)(5) of this section;
(ii) The median heating value and relative density calculated from the three analyses required in paragraph (d)(5) of this section; or
(iii) Any other method approved by the BLM.
§ 3175.114   Spot samples—allowable methods.
(a) Spot samples must be obtained using one of the following methods:
(1) Purging—fill and empty method. Samples taken using this method must comply with GPA 2166-05, Section 9.1 (incorporated by reference, see § 3175.30);
(2) Helium “pop” method. Samples taken using this method must comply with GPA 2166-05, Section 9.5 (incorporated by reference, see § 3175.30). The operator must maintain documentation demonstrating that the cylinder was evacuated and pre-charged before sampling and make the documentation available to the AO upon request;
(3) Floating piston cylinder method. Samples taken using this method must comply with GPA 2166-05, Sections 9.7.1 to 9.7.3 (incorporated by reference, see § 3175.30). The operator must maintain documentation of the seal material and type of lubricant used and make the documentation available to the AO upon request;
(4) Portable gas chromatograph. Samples taken using this method must comply with § 3175.118; or
(5) Other methods approved by the BLM (through the PMT) and posted at www.blm.gov .
(b) If the operator uses either a purging—fill and empty method or a helium “pop” method, and if the flowing pressure at the sample port is less than or equal to 15 psig, the operator may also employ a vacuum-gathering system. Samples taken using a vacuum-gathering system must comply with API 14.1, Subsection 11.10 (incorporated by reference, see § 3175.30), and the samples must be obtained from the discharge of the vacuum pump.
§ 3175.115   Spot samples—frequency.
(a) Unless otherwise required under paragraph (b) of this section, spot samples for all FMPs must be taken and analyzed at the frequency (once during every period, stated in months) prescribed in Table 1 to § 3175.110.
(b) After the time frames listed in paragraph (b)(1) of this section, the BLM may change the required sampling frequency for high-volume and very-high-volume FMPs if the BLM determines that the sampling frequency required in Table 1 in § 3175.110 is not sufficient to achieve the heating value uncertainty levels required in § 3175.31(b).
(1) Timeframes for implementation. (i) For high-volume FMPs, the BLM may change the sampling frequency no sooner than 2 years after the FMP begins measuring gas or January 19, 2021, whichever is later; and
(ii) For very-high-volume FMPs, the BLM may change the sampling frequency or require compliance with paragraph (b)(5) of this section no sooner than 1 year after the FMP begins measuring gas or January 17, 2020, whichever is later.
(2) The BLM will calculate the new sampling frequency needed to achieve the heating value uncertainty levels required in § 3175.31(b). The BLM will base the sampling frequency calculation on the heating value variability. The BLM will notify the operator of the new sampling frequency.
(3) The new sampling frequency will remain in effect until the heating value variability justifies a different frequency.
(4) The new sampling frequency will not be more frequent than once every 2 weeks nor less frequent than once every 6 months.
(5) For very-high-volume FMPs, the BLM may require the installation of a composite sampling system or on-line GC if the heating value uncertainty levels in § 3175.31(b) cannot be achieved through spot sampling. Composite sampling systems or on-line gas chromatographs that are installed and operated in accordance with this section comply with the uncertainty requirement of § 3175.31(b)(2).
(c) The time between any two samples must not exceed the timeframes shown in Table 1 to this section.
(d) If a composite sampling system or an on-line GC is installed under § 3175.116 or § 3175.117, either on the operator's own initiative or in response to a BLM order for a very-high-volume FMP under paragraph (b)(5) of this section, it must be installed and operational no more than 30 days after the due date of the next sample.
(e) The required sampling frequency for an FMP at which a composite sampling system or an on-line gas chromatograph is removed from service is prescribed in paragraph (a) of this section.
§ 3175.116   Composite sampling methods.
(a) Composite samplers must be flow-proportional.
(b) Samples must be collected using a positive-displacement pump.
(c) Sample cylinders must be sized to ensure the cylinder capacity is not exceeded within the normal collection frequency.
§ 3175.117   On-line gas chromatographs.
(a) On-line GCs must be installed, operated, and maintained under GPA 2166-05, Appendix D (incorporated by reference, see § 3175.30), and the manufacturer's specifications, instructions, and recommendations.
(b) The GC must comply with the verification and calibration requirements of § 3175.118. The results of all verifications must be submitted to the AO upon request.
(c) Upon request, the operator must submit to the AO the manufacturer's specifications and installation and operational recommendations.
§ 3175.118   Gas chromatograph requirements.
(a) All GCs must be installed, operated, and calibrated under GPA 2261-13 (incorporated by reference, see § 3175.30).
(b) Samples must be analyzed until the un-normalized sum of the mole percent of all gases analyzed is between 97 and 103 percent.
(c) A GC may not be used to analyze any sample from an FMP until the verification meets the standards of this paragraph (c).
(1) GCs must be verified under GPA 2261-13, Section 6 (incorporated by reference, see § 3175.30), not less than once every 7 days.
(2) All gases used for verification and calibration must meet the standards of GPA 2198-03, Sections 3 and 4 (incorporated by reference, see § 3175.30).
(3) All new gases used for verification and calibration must be authenticated prior to verification or calibration under the standards of GPA 2198-03, Section 5 (incorporated by reference, see § 3175.30).
(4) The gas used to calibrate a GC must be maintained under Section 6 of GPA 2198-03 (incorporated by reference, see § 3175.30).
(5) If the composition of the gas used for verification as determined by the GC varies from the certified composition of the gas used for verification by more than the reproducibility values listed in GPA 2261-13, Section 10 (incorporated by reference, see § 3175.30), the GC must be calibrated under GPA 2261-13, Section 6 (incorporated by reference, see § 3175.30).
(6) If the GC is calibrated, it must be re-verified under paragraph (c)(5) of this section.
(d) The operator must retain documentation of the verifications for the period required under § 3170.6 of this part, and make it available to the BLM upon request. The documentation must include:
(1) The components analyzed;
(2) The response factor for each component;
(3) The peak area for each component;
(4) The mole percent of each component as determined by the GC;
(5) The mole percent of each component in the gas used for verification;
(6) The difference between the mole percents determined in paragraphs (d)(4) and (5) of this section, expressed in relative percent;
(7) Evidence that the gas used for verification and calibration:
(i) Meets the requirements of paragraph (c)(2) of this section, including a unique identification number of the calibration gas used, the name of the supplier of the calibration gas, and the certified list of the mole percent of each component in the calibration gas;
(ii) Was authenticated under paragraph (c)(3) of this section prior to verification or calibration, including the fidelity plots; and
(iii) Was maintained under paragraph (c)(4) of this section, including the fidelity plot made as part of the calibration run;
(8) The chromatograms generated during the verification process;
(9) The time and date the verification was performed; and
(10) The name and affiliation of the person performing the verification.
(e) Extended analyses must be taken in accordance with GPA 2286-14 (incorporated by reference, see § 3175.30) or other method approved by the BLM.
§ 3175.119   Components to analyze.
(a) The gas must be analyzed for the following components:
(1) Methane;
(2) Ethane;
(3) Propane;
(4) Iso Butane;
(5) Normal Butane;
(6) Pentanes;
(7) Hexanes + (C 6 +);
(8) Carbon dioxide; and
(9) Nitrogen.
(b) When the concentration of C 6 + exceeds 0.5 mole percent, the following gas components must also be analyzed:
(1) Hexanes;
(2) Heptanes;
(3) Octanes; and
(4) Nonanes +.
(c) In lieu of testing each sample for the components required under paragraph (b) of this section, the operator may periodically test for these components and adjust the assumed C 6 + composition to remove bias in the heating value (see § 3175.126(a)(3)). The C 6 + composition must be applied to the mole percent of C 6 + analyses until the next analysis is done under paragraph (b) of this section. The minimum analysis frequency for the components listed in paragraph (b) of this section is as follows:
(1) For high-volume FMPs, once per year; and
(2) For very-high-volume FMPs, once every 6 months.
§ 3175.120   Gas analysis report requirements.
(a) The gas analysis report must contain the following information:
(1) The information required in § 3170.7(g) of this part;
(2) The date and time that the sample for spot samples was taken or, for composite samples, the date the cylinder was installed and the date the cylinder was removed;
(3) The date and time of the analysis;
(4) For spot samples, the effective date, if other than the date of sampling;
(5) For composite samples, the effective start and end date;
(6) The name of the laboratory where the analysis was performed;
(7) The device used for analysis (i.e., GC, calorimeter, or mass spectrometer);
(8) The make and model of analyzer;
(9) The date of last calibration or verification of the analyzer;
(10) The flowing temperature at the time of sampling;
(11) The flowing pressure at the time of sampling, including units of measure (psia or psig);
(12) The flow rate at the time of sampling;
(13) The ambient air temperature at the time of sampling;
(14) Whether or not heat trace or any other method of heating was used;
(15) The type of sample (i.e., spot-cylinder, spot-portable GC, composite);
(16) The sampling method if spot-cylinder (e.g., fill and empty, helium pop);
(17) A list of the components of the gas tested;
(18) The un-normalized mole percents of the components tested, including a summation of those mole percents;
(19) The normalized mole percent of each component tested, including a summation of those mole percents;
(20) The ideal heating value (Btu/scf);
(21) The real heating value (Btu/scf), dry basis;
(22) The hexane+ split, if applicable;
(23) The pressure base and temperature base;
(24) The relative density; and
(25) The name of the company obtaining the gas sample.
(b) Components that are listed on the analysis report, but not tested, must be annotated as such.
(c) The heating value and relative density must be calculated under API 14.5 (incorporated by reference, see § 3175.30).
(d) The base supercompressibility must be calculated under AGA Report No. 8 (incorporated by reference, see § 3175.30).
(e) The operator must submit all gas analysis reports to the BLM within 15 days of the due date for the sample as specified in § 3175.115.
(f) Unless a variance is granted, the operator must submit all gas analysis reports and other required related information electronically through the GARVS. The BLM will grant a variance to the electronic-submission requirement only in cases where the operator demonstrates that it is a small business, as defined by the U.S. Small Business Administration, and does not have access to the Internet.
§ 3175.121   Effective date of a spot or composite gas sample.
(a) Unless otherwise specified on the gas analysis report, the effective date of a spot sample is the date on which the sample was taken.
(b) The effective date of a spot gas sample may be no later than the first day of the production month following the operator's receipt of the laboratory analysis of the sample.
(c) Unless otherwise specified on the gas analysis report, the effective date of a composite sample is the first of the month in which the sample was removed.
(d) The provisions of this section apply only to OGORs, QTRs, and gas sample reports generated after January 17, 2017.
§ 3175.125   Calculation of heating value and volume
(a) The heating value of the gas sampled must be calculated as follows:
(1) Gross heating value is defined by API 14.5, Subsection 3.7 (incorporated by reference, see § 3175.30) and must be calculated under API 14.5, Subsection 7.1 (incorporated by reference, see § 3175.30); and
(2) Real heating value must be calculated by dividing the gross heating value of the gas calculated under paragraph (a)(1) of this section by the compressibility factor of the gas at 14.73 psia and 60 °F.
(b) Average heating value determination. (1) If a lease, unit PA, or CA has more than one FMP, the average heating value for the lease, unit PA, or CA for a reporting month must be the volume-weighted average of heating values, calculated as follows:
(2) If the effective date of a heating value for an FMP is other than the first day of the reporting month, the average heating value of the FMP must be the volume-weighted average of heating values, determined as follows:
(c) The volume must be determined under § 3175.94 (mechanical recorders) or § 3175.103(c) (EGM systems).
§ 3175.126   Reporting of heating value and volume.
(a) The gross heating value and real heating value, or average gross heating value and average real heating value, as applicable, derived from all samples and analyses must be reported on the OGOR in units of Btu/scf under the following conditions:
(1) Containing no water vapor (“dry”), unless the water vapor content has been determined through actual on-site measurement and reported on the gas analysis report. The heating value may not be reported on the basis of an assumed water-vapor content. Acceptable methods of measuring water vapor are:
(i) Chilled mirror;
(ii) Laser detectors; and
(iii) Other methods approved by the BLM;
(2) Adjusted to a pressure of 14.73 psia and a temperature of 60 °F; and
(3) For samples analyzed under § 3175.119(a), and notwithstanding any provision of a contract between the operator and a purchaser or transporter, the composition of hexane+ is deemed to be:
(i) 60 percent n-hexane, 30 percent n-heptane, and 10 percent n-octane; or
(ii) The composition determined under § 3175.119(c).
(b) The volume for royalty purposes must be reported on the OGOR in units of Mcf as follows:
(1) The volume must not be adjusted for water-vapor content or any other factors that are not included in the calculations required in § 3175.94 or § 3175.103; and
(2) The volume must match the monthly volume(s) shown in the unedited QTR(s) or integration statement(s) unless edits to the data are documented under paragraph (c) of this section.
(c) Edits and adjustments to reported volume or heating value. (1) If for any reason there are measurement errors stemming from an equipment malfunction that results in discrepancies to the calculated volume or heating value of the gas, the volume or heating value reported during the period in which the volume or heating value error persisted must be estimated.
(2) All edits made to the data before the submission of the OGOR must be documented and include verifiable justifications for the edits made. This documentation must be maintained under § 3170.7 of this part and must be submitted to the BLM upon request.
(3) All values on daily and hourly QTRs that have been changed or edited must be clearly identified and must be cross referenced to the justification required in paragraph (c)(2) of this section.
(4) The volumes reported on the OGOR must be corrected beginning with the date that the inaccuracy occurred. If that date is unknown, the volumes must be corrected beginning with the production month that includes the date that is half way between the date of the previous verification and the most recent verification date.
§ 3175.130   Transducer testing protocol.
The BLM will approve a particular make, model, and range of differential-pressure, static-pressure, or temperature transducer for use in an EGM system only if the testing performed on the transducer met all of the standards and requirements stated in §§ 3175.131 through 3175.135.
§ 3175.131   General requirements for transducer testing.
(a) All testing must be performed by a qualified test facility.
(b) Number and selection of transducers tested. (1) A minimum of five transducers of the same make, model, and URL, selected at random from the stock used to supply normal field operations, must be type-tested.
(2) The serial number of each transducer selected must be documented. The date, location, and batch identifier, if applicable, of manufacture must be ascertainable from the serial number.
(3) For the purpose of this section, the term “model” refers to the base model number on which the BLM determines the transducer performance. For example: A manufacturer makes a transmitter with a model number 1234-XYZ, where “1234” identifies the transmitter cell, “X” identifies the output type, “Y” identifies the mounting type, and “Z” identifies where the static pressure is taken. The testing under this section would only be required on the base model number (“1234”), assuming that “X”, “Y”, or “Z” does not affect the performance of the transmitter.
(4) For multi-variable transducers, each cell URL must be tested only once under this section. For example: A manufacturer of a transducer measuring both differential and static pressure makes a model with available differential-pressure URLs of 100 inches, 500 inches, and 1,000 inches, and static-pressure URLs of 250 psia, 1,000 psia, and 2,500 psia. Although there are nine possible combinations of differential-pressure and static-pressure URLs, only six tests are required to cover each cell URL.
(c) Test conditions—general. The electrical supply must meet the following minimum tolerances:
(1) Rated voltage: ±1 percent uncertainty;
(2) Rated frequency: ±1 percent uncertainty;
(3) Alternating current harmonic distortion: Less than 5 percent; and
(4) Direct current ripple: Less than 0.10 percent uncertainty.
(d) The input and output (if the output is analog) of each transducer must be measured with equipment that has a published reference uncertainty less than or equal to 25 percent of the published reference uncertainty of the transducer under test across the measurement range common to both the transducer under test and the test instrument. Reference uncertainty for both the test instrument and the transducer under test must be expressed in the units the transducer measures to determine acceptable uncertainty. For example, if the transducer under test has a published reference uncertainty of ±0.05 percent of span, and a span of 0 to 500 psia, then this transducer has a reference accuracy of ±0.25 psia (0.05 percent of 500 psia). To meet the requirements of this paragraph (d), the test instrument in this example must have an uncertainty of ±0.0625 psia or less (25 percent of ±0.25 psia).
(e) If the manufacturer's performance specifications for the transducer under test include corrections made by an external device (such as linearization), then the external device must be tested along with the transducer and be connected to the transducer in the same way as in normal field operations.
(f) If the manufacturer specifies the extent to which the measurement range of the transducer under test may be adjusted downward (i.e., spanned down), then each test required in §§ 3175.132 and 3175.133 must be carried out at least at both the URL and the minimum upper calibrated limit specified by the manufacturer. For upper calibrated limits between the maximum and the minimum span that are not tested, the BLM will use the greater of the uncertainties measured at the maximum and minimum spans in determining compliance with the requirements of § 3175.31(a).
(g) After initial calibration, no calibration adjustments to the transducer may be made until all required tests in §§ 3175.132 and 3175.133 are completed.
(h) For all of the testing required in §§ 3175.132 and 3175.133, the term “tested for accuracy” means a comparison between the output of the transducer under test and the test equipment taken as follows:
(1) The following values must be tested in the order shown, expressed as a percent of the transducer span:
(i) (Ascending values) 0, 10, 20, 30, 40, 50, 60, 70, 80, 90, and 100; and
(ii) (Descending values) 100, 90, 80, 70, 60, 50, 40, 30, 20, 10, and 0.
(2) If the device under test is an absolute-pressure transducer, the “0” values listed in paragraphs (h)(1)(i) and (ii) of this section must be replaced with “atmospheric pressure at the test facility;”
(3) Input approaching each required test point must be applied asymptotically without overshooting the test point;
(4) The comparison of the transducer and the test equipment measurements must be recorded at each required point; and
(5) For static-pressure transducers, the following test point must be included for all tests:
(i) For gauge-pressure transducers, a gauge pressure of −5 psig; and
(ii) For absolute-pressure transducers, an absolute pressure of 5 psia.
§ 3175.132   Testing of reference accuracy.
(a) The following reference test conditions must be maintained for the duration of the testing:
(1) Ambient air temperature must be between 59 °F and 77 °F and must not vary over the duration of the test by more than ±2 °F;
(2) Relative humidity must be between 45 percent and 75 percent and must not vary over the duration of the test by more than ±5 percent;
(3) Atmospheric pressure must be between 12.46 psi and 15.36 psi and must not vary over the duration of the test by more than ±0.2 psi;
(4) The transducer must be isolated from any externally induced vibrations;
(5) The transducer must be mounted according to the manufacturer's specifications in the same manner as it would be mounted in normal field operations;
(6) The transducer must be isolated from any external electromagnetic fields; and
(7) For reference accuracy testing of differential-pressure transducers, the downstream side of the transducer must be vented to the atmosphere.
(b) Before reference testing begins, the following pre-conditioning steps must be followed:
(1) After power is applied to the transducer, it must be allowed to stabilize for at least 30 minutes before applying any input pressure or temperature;
(2) The transducer must be exercised by applying three full-range traverses in each direction; and
(3) The transducer must be calibrated according to manufacturer specifications if a calibration is required or recommended by the manufacturer.
(c) Immediately following preconditioning, the transducer must be tested at least three times for accuracy under § 3175.131(h). The results of these tests must be used to determine the transducer's reference accuracy under § 3175.135.
§ 3175.133   Testing of influence effects.
(a) General requirements. (1) Reference conditions (see § 3175.132), with the exception of the influence effect being tested under this section, must be maintained for the duration of these tests.
(2) After completing the required tests for each influence effect under this section, the transducer under test must be returned to reference conditions and tested for accuracy under § 3175.132.
(b) Ambient temperature. (1) The transducer's accuracy must be tested at the following temperatures ( °F): +68, +104, +140, + 68, 0, −4, −40, +68.
(2) The ambient temperature must be held to ±4 °F from each required temperature during the accuracy test at each point.
(3) The rate of temperature change between tests must not exceed 2 °F per minute.
(4) The transducer must be allowed to stabilize at each test temperature for at least 1 hour.
(5) For each required temperature test point listed in this paragraph, the transducer must be tested for accuracy under § 3175.131(h).
(c) Static-pressure effects (differential-pressure transducers only). (1) For single-variable transducers, the following pressures must be applied equally to both sides of the transducer, expressed in percent of maximum rated working pressure: 0, 50, 100, 75, 25, 0.
(2) For multivariable transducers, the following pressures must be applied equally to both sides of the transducer, expressed in percent of the URL of the static-pressure transducer: 0, 50, 100, 75, 25, 0.
(3) For each point required in paragraphs (c)(1) and (2) of this section, the transducer must be tested for accuracy under § 3175.131(h).
(d) Mounting position effects. The transducer must be tested for accuracy at four different orientations under § 3175.131(h) as follows:
(1) At an angle of −10° from a vertical plane;
(2) At an angle of +10° from a vertical plane;
(3) At an angle of −10° from a vertical plane perpendicular to the vertical plane required in paragraphs (d)(1) and (2) of this section; and
(4) At an angle of +10° from a vertical plane perpendicular to the vertical plane required in paragraphs (d)(1) and (2) of this section.
(e) Over-range effects. (1) A pressure of 150 percent of the URL, or to the maximum rated working pressure of the transducer, whichever is less, must be applied for at least 1 minute.
(2) After removing the applied pressure, the transducer must be tested for accuracy under § 3175.131(h).
(3) No more than 5 minutes must be allowed between performing the procedures described in paragraphs (e)(1) and (2) of this section.
(f) Vibration effects. (1) An initial resonance test must be conducted by applying the following test vibrations to the transducer along each of the three major axes of the transducer while measuring the output of the transducer with no pressure applied:
(i) The amplitude of the applied test frequency must be at least 0.35mm below 60 Hertz (Hz) and 49 meter per second squared (m/s 2 ) above 60 Hz; and
(ii) The applied frequency must be swept from 10 Hz to 2,000 Hz at a rate not greater than 0.5 octaves per minute.
(2) After the initial resonance search, an endurance conditioning test must be conducted as follows:
(i) Twenty frequency sweeps from 10 Hz to 2,000 Hz to 10 Hz must be applied to the transducer at a rate of 1 octave per minute, repeated for each of the 3 major axes; and
(ii) The measurement of the transducer's output during this test is unnecessary.
(3) A final resonance test must be conducted under paragraph (f)(1) of this section.
§ 3175.134   Transducer test reporting.
(a) Each test required by §§ 3175.131 through 3175.133 must be fully documented by the test facility performing the tests. The report must indicate the results for each required test and include all data points recorded.
(b) The report must be submitted to the PMT. If the PMT determines that all testing was completed as required by §§ 3175.131 through 3175.133, it will make a recommendation that the BLM approve the transducer make, model, and range, along with the reference uncertainty, influence effects, and any operating restrictions, and posts them to the BLM's website at www.blm.gov as an approved device.
§ 3175.135   Uncertainty determination.
(a) Reference uncertainty calculations for each transducer of a given make, model, URL, and turndown must be determined as follows (the result for each transducer is denoted by the subscript i):
(1) Maximum error ( E i ). The maximum error for each transducer is the maximum difference between any input value from the test device and the corresponding output from the transducer under test for any required test point, and must be expressed in percent of transducer span.
(2) Hysteresis ( H i ). The testing required in § 3175.132 requires at least three pairs of tests using both ascending test points (low to high) and descending test points (high to low) of the same value. Hysteresis is the maximum difference between the ascending value and the descending value for any single input test value of a test pair. Hysteresis must be expressed in percent of span.
(3) Repeatability ( R i ). The testing required under § 3175.132 requires at least three pairs of tests using both ascending test points (low to high) and descending test points (high to low) of the same value. Repeatability is the maximum difference between the value of any of the three ascending test points for a given input value or of the three descending test points for a given value. Repeatability must be expressed in percent of span.
(b) Reference uncertainty of a transducer. The reference uncertainty of each transducer of a given make, model, URL, and turndown (U r,i ) must be determined as follows:
(c) Reference uncertainty for the make, model, URL, and turndown of a transducer (U r ) must be determined as follows:
(d) Influence effects. The uncertainty from each influence effect required to be tested under § 3175.133 must be determined as follows:
(1) Zero-based errors of each transducer. Zero-based errors from each influence test must be determined as follows:
(2) Span-based errors of each transducer. Span-based errors from each influence effect must be determined as follows:
(3) Zero- and span-based errors due to influence effects for a make, model, URL, and turndown of a transducer must be determined as follows:
§ 3175.140   Flow-computer software testing.
The BLM will approve a particular version of flow-computer software for use in a specific make and model of flow computer only if the testing performed on the software meets all of the standards and requirements in §§ 3175.141 through 3175.144. Type-testing is required for each software version that affects the calculation of flow rate, volume, heating value, live input variable averaging, flow time, or the integral value. Software updates or changes that do not affect these items do not require BLM approval.
§ 3175.141   General requirements for flow-computer software testing.
(a) Test facility. All testing must be performed by a qualified test facility not affiliated with the flow-computer manufacturer.
(b) Selection of flow-computer software to be tested. (1) Each software version tested must be identical to the software version installed at FMPs for normal field operations.
(2) Each software version must have a unique identifier.
(c) Testing method. Input variables may be either:
(1) Applied directly to the hardware registers; or
(2) Applied physically to a transducer. If input variables are applied physically to a transducer, the values received by the hardware registers from the transducer must be recorded.
(d) Pass-fail criteria. (1) For each test listed in §§ 3175.142 and 3175.143, the value(s) required to be calculated by the software version under test must be compared to the value(s) calculated by BLM-approved reference software, using the same digital input for both.
(2) The software under test may be used at an FMP only if the difference between all values calculated by the software version under test and the reference software is less than 50 parts per million (0.005 percent) and the results of the tests required in §§ 3175.142 and 3175.143 are satisfactory to the PMT. If the test results are satisfactory, the BLM will identify the software version tested as acceptable for use on its website at www.blm.gov .
§ 3175.142   Required static tests.
(a) Instantaneous flow rate. The instantaneous flow rates must meet the criteria in § 3175.141(d) for each test identified in Table 1 to this section, using the gas compositions identified in Table 2 to this section, as prescribed in Table 1 to this section.
(b) Sums and averages. (1) Fixed input values from test 2 in Table 1 to this section must be applied for a period of at least 24 hours.
(2) At the conclusion of the 24-hour period, the following hourly and daily values must meet the criteria in § 3175.141(d):
(i) Volume;
(ii) Integral value;
(iii) Flow time;
(iv) Average differential pressure;
(v) Average static pressure; and
(vi) Average flowing temperature.
(c) Other tests. The following additional tests must be performed on the flow-computer software:
(1) Each parameter of the configuration log must be changed to ensure the event log properly records the changes according to the variables listed in § 3175.104(c); and
(2) Inputs simulating a 15 percent and 150 percent over-range of the differential and static-pressure transducer's calibrated span must be entered to verify that the over-range condition triggers an alarm or an entry in the event log.
§ 3175.143   Required dynamic tests.
(a) Square wave test. The pressures and temperatures must be applied to the software revision under test for at least 60 minutes as follows:
(1) Differential pressure. The differential pressure must be cycled from a low value, below the no-flow cutoff, to a high value of approximately 80 percent of the upper calibrated limit of the differential-pressure transducer. The cycle must approximate a square wave pattern with a period of 60 seconds, and the maximum and minimum values must be the same for each cycle;
(2) Static pressure. The static pressure must be cycled between approximately 20 percent and approximately 80 percent of the upper calibrated limit of the static-pressure transducer in a square wave pattern identical to the cycling pattern used for the differential pressure. The maximum and minimum values must be the same for each cycle;
(3) Temperature. The temperature must be cycled between approximately 20 °F and approximately 100 °F in a square wave pattern identical to the cycling pattern used for the differential pressure. The maximum and minimum values must be the same for each cycle; and
(4) At the conclusion of the 1-hour period, the following hourly values must meet the criteria in § 3175.141(d):
(i) Volume;
(ii) Integral value;
(iii) Flow time;
(iv) Average differential pressure;
(v) Average static pressure; and
(vi) Average flowing temperature.
(b) Sawtooth test. The pressures and temperatures must be applied to the software revision under test for 24 hours as follows:
(1) Differential pressure. The differential pressure must be cycled from a low value, below the no-flow cutoff, to a high value of approximately 80 percent of the maximum value of differential pressure for which the flow computer is designed. The cycle must approximate a linear sawtooth pattern between the low value and the high value and there must be 3 to 10 cycles per hour. The no-flow period between cycles must last approximately 10 percent of the cycle period;
(2) Static pressure. The static pressure must be cycled between approximately 20 percent and approximately 80 percent of the maximum value of static pressure for which the flow computer is designed. The cycle must approximate a linear sawtooth pattern between the low value and the high value and there must be 3 to 10 cycles per hour;
(3) Temperature. The temperature must be cycled between approximately 20 °F and approximately 100 °F. The cycle should approximate a linear sawtooth pattern between the low value and the high value and there must be 3 to 10 cycles per hour; and
(4) At the conclusion of the 24-hour period, the following hourly and daily values must meet the criteria in § 3175.141(d):
(i) Volume;
(ii) Integral value;
(iii) Flow time;
(iv) Average differential pressure;
(v) Average static pressure; and
(vi) Average flowing temperature.
(c) Random test. The pressures and temperatures must be applied to the software revision under test for 24 hours as follows:
(1) Differential pressure. Differential-pressure random values must range from a low value, below the no-flow cutoff, to a high value of approximately 80 percent of the upper calibrated limit of the differential-pressure transducer. The no-flow period between cycles must last for approximately 10 percent of the test period;
(2) Static pressure. Static-pressure random values must range from a low value of approximately 20 percent of the upper calibrated limit of the static-pressure transducer, to a high value of approximately 80 percent of the upper calibrated limit of the static-pressure transducer;
(3) Temperature. Temperature random values must range from approximately 20 °F to approximately 100 °F; and
(4) At the conclusion of the 24-hour period, the following hourly values must meet the criteria in § 3175.141(d):
(i) Volume;
(ii) Integral value;
(iii) Flow time;
(iv) Average differential pressure;
(v) Average static pressure; and
(vi) Average flowing temperature.
(d) Long-term volume accumulation test. (1) Fixed inputs of differential pressure, static pressure, and temperature must be applied to the software version under test to simulate a flow rate greater than 500,000 Mcf/day for a period of at least 7 days.
(2) At the end of the 7-day test period, the accumulated volume must meet the criteria in § 3175.141(d).
§ 3175.144   Flow-computer software test reporting.
(a) The test facility performing the tests must fully document each test required by §§ 3175.141 through 3175.143. The report must indicate the results for each required test and include all data points recorded.
(b) The report must be submitted to the AO by the operator or the manufacturer. If the PMT determines all testing was completed as required by this section, it will make a recommendation that the BLM approve the software version and post it on the BLM's website at www.blm.gov as approved software.
§ 3175.150   Immediate assessments.
(a) Certain instances of noncompliance warrant the imposition of immediate assessments upon discovery. Imposition of any of these assessments does not preclude other appropriate enforcement actions.
(b) The BLM will issue the assessments for the violations listed as follows:
§ 3176.1   Authority.
This subpart is established pursuant to the authority granted to the Secretary of the Interior through various Federal and Indian mineral leasing statutes and the Federal Oil and Gas Royalty Management Act of 1982. This authority has been delegated to the Bureau of Land Management and is implemented by the onshore oil and gas operating regulations contained in 43 CFR part 3160. More specifically, this subpart implements and supplements the provisions of 43 CFR 3162.1, 3162.5-1(a), (c), and (d), 3162.5-2(a), and 3162.5-3.
§ 3176.2   Purpose.
The purpose of this subpart is to protect public health and safety and those personnel essential to maintaining control of the well. This subpart identifies the Bureau of Land Management's uniform national requirements and minimum standards of performance expected from operators when conducting operations involving oil or gas that is known or could reasonably be expected to contain hydrogen sulfide (H 2 S) or which results in the emission of sulfur dioxide (SO 2 ) as a result of flaring H 2 S. This subpart also identifies the gravity of violations, probable corrective action(s), and normal abatement periods.
§ 3176.3   Scope.
(a) This subpart is applicable to all onshore Federal and Indian (except Osage Tribe) oil and gas leases when drilling, completing, testing, reworking, producing, injecting, gathering, storing, or treating operations are being conducted in zones which are known or could reasonably be expected to contain H 2 S or which, when flared, could produce SO 2 , in such concentrations that upon release could constitute a hazard to human life. The requirements and minimum standards of this subpart do not apply when operating in zones where H 2 S is presently known not to be present or cannot reasonably be expected to be present in concentrations of 100 parts per million (ppm) or more in the gas stream.
(b) The requirements and minimum standards in this subpart do not relieve an operator from compliance with any applicable Federal, State, or local requirement(s) regarding H 2 S or SO 2 which are more stringent.
§ 3176.4   Definitions.
As used in this subpart, the term:
Authorized officer means any employee of the Bureau of Land Management authorized to perform the duties described in 43 CFR parts 3000 and 3100 (43 CFR 3000.0-5).
Christmas tree means an assembly of valves and fittings used to control production and provide access to the producing tubing string. The assembly includes all equipment above the tubinghead top flange.
Dispersion technique means a mathematical representation of the physical and chemical transportation, dilution, and transformation of H 2 S gas emitted into the atmosphere.
Escape rate means that the maximum volume (Q) used as the escape rate in determining the radius of exposure shall be that specified in paragraphs (1) through (4) of this definition, as applicable:
(1) For a production facility, the escape rate shall be calculated using the maximum daily rate of gas produced through that facility or the best estimate thereof;
(2) For gas wells, the escape rate shall be calculated by using the current daily absolute open-flow rate against atmospheric pressure;
(3) For oil wells, the escape rate shall be calculated by multiplying the producing gas/oil ratio by the maximum daily production rate or best estimate thereof; or
(4) For a well being drilled in a developed area, the escape rate may be determined by using the offset wells completed in the interval(s) in question.
Essential personnel means those on-site personnel directly associated with the operation being conducted and necessary to maintain control of the well.
Exploratory well means any well drilled beyond the known producing limits of a pool.
Gas well means a well for which the energy equivalent of the gas produced, including the entrained liquid hydrocarbons, exceeds the energy equivalent of the oil produced.
H 2 S Drilling Operations Plan means a written plan which provides for safety of essential personnel and for maintaining control of the well with regard to H 2 S and SO 2.
Lessee means a person or entity holding record title in a lease issued by the United States (43 CFR 3160.0-5).
Major violation means noncompliance which causes or threatens immediate. substantial, and adverse impacts on public health and safety, the environment, production accountability, or royalty income (43 CFR 3160.0-5).
Minor violation means noncompliance which does not rise to the level of a major violation (43 CFR 3160.0-5).
Oil well means a well for which the energy equivalent of the oil produced exceeds the energy equivalent of the gas produced, including the entrained liquid hydrocarbons.
Operating rights owner means a person or entity holding operating rights in a lease issued by the United States. A lessee may also be an operating rights owner if the operating rights in a lease or portion thereof have not been severed from record title (43 CFR 3160.0-5).
Operator means any person or entity including but not limited to the lessee or operating rights owner who has stated in writing to the authorized officer that he/she is responsible under the terms of the lease for the operations conducted on the leased lands or a portion thereof (43 CFR 3160.0-5).
Potentially hazardous volume means a volume of gas of such H 2 S concentration and flow rate that it may result in radius of exposure-calculated ambient concentrations of 100 ppm H 2 S at any occupied residence, school, church, park, school bus stop, place of business, or other area where the public could reasonably be expected to frequent, or 500 ppm H 2 S at any Federal, State, County, or municipal road or highway.
Production facilities means any wellhead, flowline, piping, treating, or separating equipment, water disposal pits, processing plant, or combination thereof prior to the approved measurement point for any lease, communitization agreement, or unit participating area.
Prompt correction means immediate correction of violations, with operation suspended if required at the discretion of the authorized officer.
Public Protection Plan means a written plan which provides for the safety of the potentially affected public with regard to H 2 S and SO 2.
Radius of exposure means the calculation resulting from using the following Pasquill-Gifford derived equation, or by such other method(s) as may be approved by the authorized officer:
(1) For determining the 100 ppm radius of exposure where the H 2 S concentration in the gas stream is less than 10:
(2) For determining the 500 ppm radius of exposure where the H 2 S concentration in the gas stream is less than 10:
(3) For determining the 100 ppm or the 500 ppm radius of exposure in gas streams containing H 2 S concentrations of 10 percent or greater, a dispersion technique that takes into account representative wind speed, direction, atmospheric stability, complex terrain, and other dispersion features shall be utilized. Such techniques may include, but shall not be limited to, one of a series of computer models outlined in the Environmental Protection Agency's “Guidelines on Air Quality Models” (EPA-450/2-78-027R).
(4) Where multiple H 2 S sources ( i.e., wells, treatment equipment, flowlines, etc.) are present, the operator may elect to utilize a radius of exposure which covers a larger area than would be calculated using radius of exposure formula for each component part of the drilling/completion/workover/production system.
(5) For a well being drilled in an area where insufficient data exits to calculate a radius of exposure, but where H 2 S could reasonably be expected to be present in concentrations in excess of 100 ppm in the gas stream, a 100 ppm radius of exposure equal to 3,000 feet shall be assumed.
Zones known not to contain H 2 S means geological formations in a field where prior drilling, logging, coring, testing, or producing operations have confirmed the absence of H 2 S-bearing zones that contain 100 ppm or more of H 2 S in the gas stream.
Zones known to contain H 2 S means geological formations in a field where prior drilling, logging, coring, testing, or producing operations have confirmed that H 2 S-bearing zones will be encountered that contain 100 ppm or more of H 2 S in the gas stream.
Zones which can reasonably be expected to contain H 2 S means geological formations in the area which have not had prior drilling, but prior drilling to the same formations in similar field(s) within the same geologic basin indicates there is a potential for 100 ppm or more of H 2 S in the gas stream.
Zones which cannot reasonably be expected to contain H 2 S means geological formations in the area which have not had prior drilling, but prior drilling to the same formations in similar field(s) within the same geologic basin indicates there is not a potential for 100 ppm or more of H 2 S in the gas stream.
§ 3176.5   Requirements.
The requirements of this subpart are the minimum acceptable standards with regard to H 2 S operations. This subpart also classifies violations as typically major or minor for purposes of the assessment and penalty provisions of 43 CFR part 3160, subpart 3163, specifies the corrective action which will probably be required, and establishes the normal abatement period following detection of a major or minor violation in which the violator may take such corrective action without incurring an assessment. However, the authorized officer may, after consideration of all appropriate factors, require reasonable and necessary standards, corrective actions, and abatement periods that may, in some cases, vary from those specified in this subpart that he/she determines to be necessary to protect public health and safety, the environment, or to maintain control of a well to prevent waste of Federal mineral resources. To the extent such standards, actions, or abatement periods differ from those set forth in this subpart, they may be subject to review pursuant to 43 CFR 3165.3.
§ 3176.6   Applications, approvals, and reports.
(a) Drilling. For proposed drilling operations where formations will be penetrated which have zones known to contain or which could reasonably be expected to contain concentrations of H 2 S of 100 ppm or more in the gas stream, the H 2 S Drilling Operation Plan and, if the applicability criteria in § 3176.7(a) are met, a Public Protection Plan as outlined in § 3176.7(b), shall be submitted as part of the Application for Permit to Drill (APD) (refer to subpart 3171 of this part). In cases where multiple filings are being made with a single drilling plan, a single H 2 S Drilling Operations Plan and, if applicable, a single Public Protection Plan may be submitted for the lease, communitization agreement, unit, or field in accordance with subpart 3171. Failure to submit either the H 2 S Drilling Operations Plan or the Public Protection Plan when required by this subpart shall result in an incomplete APD pursuant to 43 CFR 3162.3-1.
(b) Drilling plan. The H 2 S Drilling Operations Plan shall fully describe the manner in which the requirements and minimum standards in § 3176.8, shall be met and implemented. As required by this subpart (§ 3176.8), the following must be submitted in the H 2 S Drilling Operations Plan:
(1) Statement that all personnel shall receive proper H 2 S training in accordance, with § 3176.8(c)(1).
(2) A legible well site diagram of accurate scale (may be included as part of the well site layout as required by subpart 3171 of this part) showing the following:
(i) Drill rig orientation;
(ii) Prevailing wind direction;
(iii) Terrain of surrounding area;
(iv) Location of all briefing areas (designate primary briefing area);
(v) Location of access road(s) (including secondary egress);
(vi) Location of flare line(s) and pit(s);
(vii) Location of caution and/or danger signs; and
(viii) Location of wind direction indicators.
(3) As required by this subpart, a complete description of the following H 2 S safety equipment/systems:
(i) Well control equipment. (A) Flare line(s) and means of ignition;
(B) Remote controlled choke;
(C) Flare gun/flares; and
(D) Mud-gas separator and rotating head (if exploratory well);
(ii) Protective equipment for essential personnel. (A) Location, type, storage, and maintenance of all working and escape breathing apparatus; and
(B) Means of communication when using protective breathing apparatus;
(iii) H 2 S detection and monitoring equipment. (A) H 2 S sensors and associated audible/visual alarm(s); and
(B) Portable H 2 S and SO 2 monitor(s);
(iv) Visual warning systems. (A) Wind direction indicators; and (B) Caution/danger sign(s) and flag(s);
(v) Mud program. (A) Mud system and additives; and (B) Mud degassing system;
(vi) Metallurgy. Metallurgical properties of all tubular goods and well control equipment which could be exposed to H 2 S (§ 3176.8(d)(3)); and
(vii) Communication. Means of communication from wellsite.
(4) Plans for well testing.
(c) Production. (1) For each existing production facility having an H 2 S concentration of 100 ppm or more in the gas stream, the operator shall calculate and submit the calculations to the authorized officer within 180 days of January 22, 1991, the 100 and, if applicable, the 500 ppm radii of exposure for all facilities to determine if the applicability criteria in § 3176.7(a) are met. Radii of exposure calculations shall not be required for oil or water flowlines. Further, if any of the applicability criteria (§ 3176.7(a)) are met, the operator shall submit a complete Public Protection Plan which meets the requirements of § 3176.7(b)(2) to the authorized officer within 1 year of January 22, 1991. For production facilities constructed after January 22, 1991, and meeting the minimum concentration (100 ppm in gas stream), the operator shall report the radii of exposure calculations, and if the applicability criteria in § 3176.7(a) are met, submit a complete Public Protection Plan (§ 3176.7(b)(2)) to the authorized officer within 60 days after completion of production facilities.
Table 1 to § 3176.6( c )(1)
(2) The operator shall initially test the H 2 S concentration of the gas stream for each well or production facility and shall make the results available to the authorized officer, upon request.
Table 2 to § 3176.6( c )(2)
(3) If operational or production alterations result in a 5 percent or more increase in the H 2 S concentration ( i.e., well recompletion, increased gas-to-oil ratios) or the radius of exposure as calculated under paragraph (c)(1) of this section, notification of such changes shall be submitted to the authorized officer within 60 days after identification of the change.
Table 3 to § 3176.6( c )(3)
(d) Plans and reports. (1) H 2 S Drilling Operations Plan(s) or Public Protection Plan(s) shall be reviewed by the operator on an annual basis and a copy of any necessary revisions shall be submitted to the authorized officer upon request.
Table 4 to § 3176.6( d )(1)
(2) Any release of a potentially hazardous volume of H 2 S shall be reported to the authorized officer as soon as practicable, but no later than 24 hours following identification of the release.
Table 5 to § 3176.6( d )(2)
§ 3176.7   Public protection.
(a) Applicability criteria. For both drilling/completion/workover and production operations, the H 2 S radius of exposure shall be determined on all wells and production facilities subject to this subpart. A Public Protection Plan (paragraph (b) of this section) shall be required when any of the following conditions apply:
(1) The 100 ppm radius of exposure is greater than 50 feet and includes any occupied residence, school, church, park, school bus stop, place of business, or other areas where the public could reasonably be expected to frequent;
(2) The 500 ppm radius of exposure is greater than 50 feet and includes any part of a Federal, State, County, or municipal road or highway owned and principally maintained for public use; or
(3) The 100 ppm radius of exposure is equal to or greater than 3,000 feet where facilities or roads are principally maintained for public use. Additional specific requirements for drilling/completion/workover or producing operations are described in §§ 3176.8 and 3176.9, respectively.
(b) Public Protection Plan —(1) Plan submission/implementation/availability. (i) A Public Protection Plan providing details of actions to alert and protect the public in the event of a release of a potentially hazardous volume of H 2 S shall be submitted to the authorized officer as required by § 3176.6(a) for drilling or by § 3176.6(c) for producing operations when the applicability criteria established in paragraph (a) of this section are met. One plan may be submitted for each well, lease, communitization agreement, unit, or field, at the operator's discretion. The Public Protection Plan shall be maintained and updated, in accordance with § 3176.6(d).
(ii) The Public Protection Plan shall be activated immediately upon detection of release of a potentially hazardous volume of H 2 S.
Table 1 to § 3176.7 (b)(1)(ii)
(iii) A copy of the Public Protection Plan shall be available at the drilling/completion site for such wells and at the facility, field office, or with the pumper, as appropriate, for producing wells, facilities, and during workover operations.
Table 2 to § 3176.7 (b)(1)(iii)
(2) Plan content. (i) The details of the Public Protection Plan may vary according to the site-specific characteristics (concentration, volume, terrain, etc.) expected to be encountered and the number and proximity of the population potentially at risk. In the areas of high population density or in other special cases, the authorized officer may require more stringent plans to be developed. These may include public education seminars, mass alert systems, and use of sirens, telephone, radio, and television depending on the number of people at risk and their location with respect to the well site.
(ii) The Public Protection Plan shall include:
(A) The responsibilities and duties of key personnel, and instructions for alerting the public and requesting assistance;
(B) A list of names and telephone numbers of residents, those responsible for safety of public roadways, and individuals responsible for the safety of occupants of buildings within the 100 ppm radius of exposure ( e.g., school principals, building managers, etc.) as defined by the applicability criteria in paragraph (a) of this section. The operator shall ensure that those who are at the greatest risk are notified first. The Plan shall define when and how people are to be notified in case of an H 2 S emergency;
(C) A telephone call list (including telephone numbers) for requesting assistance from law enforcement, fire department, and medical personnel and Federal and State regulatory agencies, as required. Necessary information to be communicated and the emergency responses that may be required shall be listed. This information shall be based on previous contacts with these organizations;
(D) A legible 100 ppm (or 3,000 feet, if conditions unknown) radius plat of all private and public dwellings, schools, roads, recreational areas, and other areas where the public might reasonably be expected to frequent;
(E) Advance briefings, by visit, meeting, or letter to the people identified in paragraph (b)(2)(ii)(B) of this section, including:
( 1 ) Hazards of H 2 S and SO 2 ;
( 2 ) Necessity for an emergency action plan;
( 3 ) Possible sources of H 2 S and S0 2 ;
( 4 ) Instructions for reporting a leak to the operator;
( 5 ) The manner in which the public shall be notified of an emergency; and
( 6 ) Steps to be taken in case of an emergency, including evacuation of any people;
(F) Guidelines for the ignition of the H 2 S bearing gas. The Plan shall designate the title or position of the person(s) who has the authority to ignite the escaping gas and define when, how, and by whom the gas is to be ignited;
(G) Additional measures necessary following the release of H 2 S and SO 2 until the release is contained are as follows:
( 1 ) Monitoring of H 2 S and SO 2 levels and wind direction in the affected area;
( 2 ) Maintenance of site security and access control;
( 3 ) Communication of status of well control; and
( 4 ) Other necessary measures as required by the authorized officer; and
(H) For production facilities, a description of the detection system(s) utilized to determine the concentration of H 2 S released.