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1.1 This protocol may be used in lieu of continuous SO 1.2 Pursuant to the procedures in § 75.20, complete all testing requirements to certify use of this protocol in lieu of a flow monitor and an SO For each hour when the unit is combusting fuel, measure and record the flow rate of fuel combusted by the unit, except as provided in section 2.1.4 of this appendix. Measure the flow rate of fuel with an in-line fuel flowmeter, and automatically record the data with a data acquisition and handling system, except as provided in section 2.1.4 of this appendix.
2.1.1 Measure the flow rate of each fuel entering and being combusted by the unit. If, on an annual basis, more than 5.0 percent of the fuel from the main pipe is diverted from the unit without being burned and that diversion occurs downstream of the fuel flowmeter, an additional in-line fuel flowmeter is required to account for the unburned fuel. In this case, record the flow rate of each fuel combusted by the unit as the difference between the flow measured in the pipe leading to the unit and the flow in the pipe diverting fuel away from the unit. However, the additional fuel flowmeter is not required if, on an annual basis, the total amount of fuel diverted away from the unit, expressed as a percentage of the total annual fuel usage by the unit is demonstrated to be less than or equal to 5.0 percent. The owner or operator may make this demonstration in the following manner:
2.1.1.1 For existing units with fuel usage data from fuel flowmeters, if data are submitted from a previous year demonstrating that the total diverted yearly fuel does not exceed 5% of the total fuel used; or
2.1.1.2 For new units which do not have historical data, if a letter is submitted signed by the designated representative certifying that, in the future, the diverted fuel will not exceed 5.0% of the total annual fuel usage; or
2.1.1.3 By using a method approved by the Administrator under § 75.66(d).
2.1.2 Install and use fuel flowmeters meeting the requirements of this appendix in a pipe going to each unit, or install and use a fuel flowmeter in a common pipe header (i.e., a pipe carrying fuel for multiple units). However, the use of a fuel flowmeter in a common pipe header and the provisions of sections 2.1.2.1 and 2.1.2.2 of this appendix are not applicable to any unit that is using the provisions of subpart H of this part to monitor, record, and report NO 2.1.2.1 Measure the fuel flow rate in the common pipe, and combine SO 2.1.2.2 Provide information satisfactory to the Administrator on methods for apportioning SO 2.1.3 For a gas-fired unit or an oil-fired unit that continuously or frequently combusts a supplemental fuel for flame stabilization or safety purposes, measure the flow rate of the supplemental fuel with a fuel flowmeter meeting the requirements of this appendix.
For an oil-fired unit that uses gas solely for start-up or burner ignition or a gas-fired unit that uses oil solely for start-up or burner ignition, a flowmeter for the start-up fuel is not required. Estimate the volume of oil combusted for each start-up or ignition either by using a fuel flowmeter or by using the dimensions of the storage container and measuring the depth of the fuel in the storage container before and after each start-up or ignition. A fuel flowmeter used solely for start-up or ignition fuel is not subject to the calibration requirements of sections 2.1.5 and 2.1.6 of this appendix. Gas combusted solely for start-up or burner ignition does not need to be measured separately.
A gas or oil flowmeter used for commercial billing of natural gas or oil may be used to measure, record, and report hourly fuel flow rate. A gas or oil flowmeter used for commercial billing of natural gas or oil is not required to meet the certification requirements of section 2.1.5 of this appendix or the quality assurance requirements of section 2.1.6 of this appendix under the following circumstances:
(a) The gas or oil flowmeter is used for commercial billing under a contract, provided that the company providing the gas or oil under the contract and each unit combusting the gas or oil do not have any common owners and are not owned by subsidiaries or affiliates of the same company;
(b) The designated representative reports hourly records of gas or oil flow rate, heat input rate, and emissions due to combustion of natural gas or oil;
(c) The designated representative also reports hourly records of heat input rate for each unit, if the gas or oil flowmeter is on a common pipe header, consistent with section 2.1.2 of this appendix;
(d) The designated representative reports hourly records directly from the gas or oil flowmeter used for commercial billing if these records are the values used, without adjustment, for commercial billing, or reports hourly records using the missing data procedures of section 2.4 of this appendix if these records are not the values used, without adjustment, for commercial billing; and
(e) The designated representative identifies the gas or oil flowmeter in the unit's monitoring plan.
The designated representative of a unit that is restricted by its Federal, State or local permit to combusting a particular fuel only during emergencies where the primary fuel is not available is exempt from certifying a fuel flowmeter for use during combustion of the emergency fuel. During any hour in which the emergency fuel is combusted, report the hourly heat input to be the maximum rated heat input of the unit for the fuel. Additionally, begin sampling the emergency fuel for sulfur content only using the procedures under section 2.2 (for oil) or 2.3 (for gas) of this appendix. The designated representative shall also provide notice under § 75.61(a)(6)(ii) for each period when the emergency fuel is combusted.
For the purposes of initial certification, each fuel flowmeter used to meet the requirements of this protocol shall meet a flowmeter accuracy of 2.0 percent of the upper range value (i.e. maximum calibrated fuel flow rate) across the range of fuel flow rate to be measured at the unit. Flowmeter accuracy may be determined under section 2.1.5.1 of this appendix for initial certification in any of the following ways (as applicable): by design or by measurement under laboratory conditions; by the manufacturer; by an independent laboratory; or by the owner or operator. Flowmeter accuracy may also be determined under section 2.1.5.2 of
this appendix by measurement against a NIST traceable reference method.
2.1.5.1 Use the procedures in the following standards to verify flowmeter accuracy or design, as appropriate to the type of flowmeter: ASME MFC-3M-1989 with September 1990 Errata ("Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi"); ASME MFC-4M-1986 (Reaffirmed 1990), "Measurement of Gas Flow by Turbine Meters;" American Gas Association Report No. 3, "Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 1: General Equations and Uncertainty Guidelines" (October 1990 Edition), Part 2: "Specification and Installation Requirements" (February 1991 Edition), and Part 3: "Natural Gas Applications" (August 1992 edition) (excluding the modified flow-calculation method in part 3); Section 8, Calibration from American Gas Association Transmission Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters (Second Revision, April, 1996); ASME MFC-5M-1985 ("Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters"); ASME MFC-6M-1987 with June 1987 Errata ("Measurement of Fluid Flow in Pipes Using Vortex Flow Meters"); ASME MFC-7M-1987 (Reaffirmed 1992), "Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles;" ISO 8316: 1987(E) "Measurement of Liquid Flow in Closed Conduits -- Method by Collection of the Liquid in a Volumetric Tank;" American Petroleum Institute (API) Section 2, "Conventional Pipe Provers", Section 3, "Small Volume Provers", and Section 5, "Master-Meter Provers", from Chapter 4 of the Manual of Petroleum Measurement Standards, October 1988 (Reaffirmed 1993); or ASME MFC-9M-1988 with December 1989 Errata ("Measurement of Liquid Flow in Closed Conduits by Weighing Method"), for all other flowmeter types (incorporated by reference under § 75.6). The Administrator may also approve other procedures that use equipment traceable to National Institute of Standards and Technology standards. Document such procedures, the equipment used, and the accuracy of the procedures in the monitoring plan for the unit, and submit a petition signed by the designated representative under § 75.66(c). If the flowmeter accuracy exceeds 2.0 percent of the upper range value, the flowmeter does not qualify for use under this part.
2.1.5.2 (a) Alternatively, determine the flowmeter accuracy of a fuel flowmeter used for the purposes of this part by comparing it to the measured flow from a reference flowmeter which has been either designed according to the specifications of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix, or tested for accuracy during the previous 365 days, using a standard listed in section 2.1.5.1 of this appendix or other procedure approved by the Administrator under § 75.66 (all standards incorporated by reference under § 75.6). Any secondary elements, such as pressure and temperature transmitters, must be calibrated immediately prior to the comparison. Perform the comparison over a period of no more than seven consecutive unit operating days. Compare the average of three fuel flow rate readings over 20 minutes or longer for each meter at each of three different flow rate levels. The three flow rate levels shall correspond to:
(1) Normal full unit operating load,
(2) Normal minimum unit operating load,
(3) A load point approximately equally spaced between the full and minimum unit operating loads, and
(b) Calculate the flowmeter accuracy at each of the three flow levels using the following equation:
ACC=Flowmeter accuracy at a particular load level, as a percentage of the upper range value.
R=Average of the three flow measurements of the reference flowmeter.
A=Average of the three measurements of the flowmeter being tested.
URV=Upper range value of fuel flowmeter being tested (i.e. maximum measurable flow).
(c) Notwithstanding the requirement for calibration of the reference flowmeter within 365 days prior to an accuracy test, when an in-place reference meter or prover is used for quality assurance under section 2.1.6 of this appendix, the reference meter calibration requirement may be waived if, during the previous in-place accuracy test with that reference meter, the reference flowmeter and the flowmeter being tested agreed to within ±1.0 percent of each other at all levels tested. This exception to calibration and flowmeter accuracy testing requirements for the reference flowmeter shall apply for periods of no longer than five consecutive years (i.e., 20 consecutive calendar quarters).
2.1.5.3 If the flowmeter accuracy exceeds the specification in section 2.1.5 of this appendix, the flowmeter does not qualify for use for this appendix. Either recalibrate the flowmeter until the flowmeter accuracy is within the performance specification, or replace the flowmeter with another one that is demonstrated to meet the performance specification. Substitute for fuel flow rate using the missing data procedures in section 2.4.2 of this appendix until quality assured fuel flow data become available.
2.1.5.4 For purposes of initial certification, when a flowmeter is tested against a reference fuel flow rate (i.e., fuel flow rate from another fuel flowmeter under section
2.1.5.2 of this appendix or flow rate from a procedure performed according to a standard incorporated by reference under section 2.1.5.1 of this appendix), report the results of flowmeter accuracy tests using the following Table D-1.
(a) Test the accuracy of each fuel flowmeter prior to use under this part and at least once every four fuel flowmeter QA operating quarters, as defined in § 72.2 of this chapter, thereafter. Notwithstanding these requirements, no more than 20 successive calendar quarters shall elapse after the quarter in which a fuel flowmeter was last tested for accuracy without a subsequent flowmeter accuracy test having been conducted. Test the flowmeter accuracy more frequently if required by manufacturer specifications.
(b) Except for orifice-, nozzle-, and venturi-type flowmeters, perform the required flowmeter accuracy testing using the procedures in either section 2.1.5.1 or section 2.1.5.2 of this appendix. Each fuel flowmeter must meet the accuracy specification in section 2.1.5 of this appendix.
(c) For orifice-, nozzle-, and venturi-type flowmeters, either perform the required flowmeter accuracy testing using the procedures in section 2.1.5.1 or 2.1.5.2 of this appendix or perform a transmitter accuracy test once every four fuel flowmeter QA operating quarters and a primary element visual inspection once every 12 calendar quarters, according to the procedures in sections 2.1.6.1 through 2.1.6.4 of this appendix for periodic quality assurance.
(d) Notwithstanding the requirements of this section, if the procedures of section 2.1.7 (fuel flow-to-load test) of this appendix are performed during each fuel flowmeter QA operating quarter, subsequent to a required flowmeter accuracy test or transmitter accuracy test and primary element inspection, where applicable, those procedures may be used to meet the requirement for periodic quality assurance testing for a period of up to 20 calendar quarters from the previous accuracy test or transmitter accuracy test and primary element inspection, where applicable.
(a) Calibrate the differential pressure transmitter or transducer, static pressure transmitter or transducer, and temperature transmitter or transducer, as applicable, using equipment that has a current certificate of traceability to NIST standards. Check the calibration of each transmitter or transducer by comparing its readings to that of the NIST traceable equipment at least once at each of the following levels: the zero-level and at least two other levels (e.g., "mid" and "high"), such that the full range of transmitter or transducer readings corresponding to normal unit operation is represented.
(b) Calculate the accuracy of each transmitter or transducer at each level tested, using the following equation:
ACC = Accuracy of the transmitter or transducer as a percentage of full-scale.
R = Reading of the NIST traceable reference value (in milliamperes, inches of water, psi, or degrees).
T = Reading of the transmitter or transducer being tested (in milliamperes, inches of water, psi, or degrees, consistent with the units of measure of the NIST traceable reference value).
FS = Full-scale range of the transmitter or transducer being tested (in milliamperes, inches of water, psi, or degrees, consistent with the units of measure of the NIST traceable reference value).
(c) If each transmitter or transducer meets an accuracy of ± 1.0 percent of its full-scale range at each level tested, the fuel flowmeter accuracy of 2.0 percent is considered to be met at all levels. If, however, one or more of the transmitters or transducers does not meet an accuracy of ± 1.0 percent of full-scale at a particular level, then the owner or operator may demonstrate that the fuel flowmeter meets the total accuracy specification of 2.0 percent at that level by using one of the following alternative methods. If, at a particular level, the sum of the individual accuracies of the three transducers is less than or equal to 4.0 percent, the fuel flowmeter accuracy specification of 2.0 percent is considered to be met for that level. Or, if at a particular level, the total fuel flowmeter accuracy is 2.0 percent or less, when calculated in accordance with Part 1 of American Gas Association Report No. 3, General Equations and Uncertainty Guidelines, the flowmeter accuracy requirement is considered to be met for that level.
(a) Record the accuracy of the orifice, nozzle, or venturi meter or its individual transmitters or transducers and keep this information in a file at the site or other location suitable for inspection. When testing individual orifice, nozzle, or venturi meter transmitters or transducers for accuracy, include the information displayed in the following Table D-2. At a minimum, record results for each transmitter or transducer at the zero-level and at least two other levels across the range of the transmitter or transducer readings that correspond to normal unit operation.
(b) When accuracy testing of the orifice, nozzle, or venturi meter is performed according to section 2.1.5.2 of this appendix, record the information displayed in Table D-1 in this section. At a minimum, record the overall flowmeter accuracy results for the fuel flowmeter at the three flow rate levels specified in section 2.1.5.2 of this appendix.
(c) Report the results of all fuel flowmeter accuracy tests, transmitter or transducer accuracy tests, and primary element inspections, as applicable, in the emissions report for the quarter in which the quality assurance tests are performed, using the electronic format specified by the Administrator under § 75.64.
If, during a transmitter or transducer accuracy test conducted according to section 2.1.6.1 of this appendix, the flowmeter accuracy specification of 2.0 percent is not met at any of the levels tested, repair or replace transmitter(s) or transducer(s) as necessary until the flowmeter accuracy specification has been achieved at all levels. (Note that only transmitters or transducers which are repaired or replaced need to be re-tested; however, the re-testing is required at all three measurement levels, to ensure that the flowmeter accuracy specification is met at each level). The fuel flowmeter is "out-of-control" and data from the flowmeter are considered invalid, beginning with the date and hour of the failed accuracy test and continuing until the date and hour of completion of a successful transmitter or transducer accuracy test at all levels. In addition, if, during normal operation of the fuel flowmeter, one or more transmitters or transducers malfunction, data from the fuel flowmeter shall be considered invalid from the hour of the transmitter or transducer failure until the hour of completion of a successful 3-level transmitter or transducer accuracy test. During fuel flowmeter out-of-control periods, provide data from another fuel flowmeter that meets the requirements of § 75.20(d) and section 2.1.5 of this appendix, or substitute for fuel flow rate using the missing data procedures in section 2.4.2 of this appendix. Record and report test data and results, consistent with sections 2.1.6.1 and 2.1.6.2 of this appendix and § 75.56 or § 75.59, as applicable.
(a) Conduct a visual inspection of the orifice, nozzle, or venturi meter at least once every twelve calendar quarters. Notwithstanding this requirement, the procedures of section 2.1.7 of this appendix may be used to reduce the inspection frequency of the orifice, nozzle, or venturi meter to at least once every twenty calendar quarters. The inspection may be performed using a baroscope. If the visual inspection indicates that the orifice, nozzle, or venturi meter has become damaged or corroded, then:
(1) Replace the primary element with another primary element meeting the requirements of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6);
(2) Replace the primary element with another primary element, and demonstrate that the overall flowmeter accuracy meets the accuracy specification in section 2.1.5 of this appendix under the procedures of section 2.1.5.2 of this appendix; or
(3) Restore the damaged or corroded primary element to "as new" condition; determine the overall accuracy of the flowmeter, using either the specifications of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6); and retest the transmitters or transducers prior to providing quality assured data from the flowmeter.
(b) If the primary element size is changed, calibrate the transmitter or transducers consistent with the new primary element size. Data from the fuel flowmeter are considered invalid, beginning with the date and hour of a failed visual inspection and continuing until the date and hour when:
(1) The damaged or corroded primary element is replaced with another primary element meeting the requirements of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6);
(2) The damaged or corroded primary element is replaced, and the overall accuracy of the flowmeter is demonstrated to meet the accuracy specification in section 2.1.5 of this appendix under the procedures of section 2.1.5.2 of this appendix; or
(3) The restored primary element is installed to meet the requirements of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6) and its transmitters or transducers are retested to meet the accuracy specification in section 2.1.6.1 of this appendix.
(c) During this period, provide data from another fuel flowmeter that meets the requirements of § 75.20(d) and section 2.1.5 of this appendix, or substitute for fuel flow rate using the missing data procedures in section 2.4.2 of this appendix.
2.1.7 Fuel Flow-to-Load Quality Assurance Testing for Certified Fuel Flowmeters
The procedures of this section may be used as an optional supplement to the quality assurance procedures in section 2.1.5.1, 2.1.5.2,
2.1.6.1, or 2.1.6.4 of this appendix when conducting periodic quality assurance testing of a certified fuel flowmeter. Note, however, that these procedures may not be used unless the 168-hour baseline data requirement of section 2.1.7.1 of this appendix has been met. If, following a flowmeter accuracy test or flowmeter transmitter test and primary element inspection, where applicable, the procedures of this section are performed during each subsequent fuel flowmeter QA operating quarter, as defined in § 72.2 of this chapter (excluding the quarter(s) in which the baseline data are collected), then these procedures may be used to meet the requirement for periodic quality assurance for a period of up to 20 calendar quarters from the previous periodic quality assurance procedure(s) performed according to sections 2.1.5.1, 2.1.5.2, or 2.1.6.1 through 2.1.6.4 of this appendix. The procedures of this section are not required for any quarter in which a flowmeter accuracy test or a transmitter accuracy test and a primary element inspection, where applicable, are conducted. Notwithstanding the requirements of § 75.54(a) or § 75.57(a), as applicable, when using the procedures of this section, keep records of the test data and results from the previous flowmeter accuracy test under section 2.1.5.1 or 2.1.5.2 of this appendix, records of the test data and results from the previous transmitter or transducer accuracy test under section 2.1.6.1 of this appendix for orifice-, nozzle-, and venturi-type fuel flowmeters, and records of the previous visual inspection of the primary element required under section 2.1.6.4 of this appendix for orifice-, nozzle-, and venturi-type fuel flowmeters until the next flowmeter accuracy test, transmitter accuracy test, or visual inspection is performed, even if the previous flowmeter accuracy test, transmitter accuracy test, or visual inspection was performed more than three years previously.
(a) Determine R where:
R Q L (b) In Equation D-1b, for a common pipe header, L (c) Alternatively, a baseline value of the gross heat rate (GHR) may be determined in lieu of R (GHR) (Heat Input) L (d) Report the current value of R (a) Evaluate the fuel flow rate-to-load ratio (or GHR) for each fuel flowmeter QA operating quarter, as defined in § 72.2 of this chapter. At the end of each fuel flowmeter QA operating quarter, use Equation D-1d in this appendix to calculate R where:
R Q L (b) For a common pipe header, L (c) Alternatively, calculate the hourly gross heat rates (GHR) in lieu of the hourly flow-to-load ratios. If this option is selected, calculate each hourly GHR value as follows:
(GHR) (Heat Input) L (d) Evaluate the calculated flow rate-to-load ratios (or gross heat rates) as follows. Perform a separate data analysis for each fuel flowmeter following the procedures of this section. Base each analysis on a minimum of 168 hours of data. If, for a particular fuel flowmeter, fewer than 168 hourly flow-to-load ratios (or GHR values) are available, a flow-to-load (or GHR) evaluation is not required for that flowmeter for that calendar quarter.
(e) For each hourly flow-to-load ratio or GHR value, calculate the percentage difference (percent D %D R R (f) Consistently use R (g) Next, determine the arithmetic average of all of the hourly percent difference (percent D E %D q = Number of hours used in fuel flow-to-load (or GHR) evaluation.
(h) When the quarterly average load value used in the data analysis is greater than 50 MWe (or 500 klb steam per hour), the results of a quarterly fuel flow rate-to-load (or GHR) evaluation are acceptable and no further action is required if the quarterly average percentage difference (E (a) If E (b) After identifying and excluding all non-representative hourly fuel flow-to-load ratios or GHR values, analyze the quarterly fuel flow rate-to-load data a second time.
(a) If E (b) Substitute for fuel flow rate, for any hour when that fuel is combusted, using the missing data procedures in section 2.4.2 of this appendix, beginning with the first hour of the calendar quarter following the quarter for which E Report the results of each quarterly flow rate-to-load (or GHR) evaluation, as determined from Equation D-1g, in the electronic quarterly report required under § 75.64. Table D-3 is provided as a reference on the type of information to be recorded under § 75.59 and reported under § 75.64.
Perform sampling and analysis of oil to determine the following fuel properties for each type of oil combusted by a unit: percentage of sulfur by weight in the oil; gross calorific value (GCV) of the oil; and, if necessary, the density of the oil. Use the sulfur content, density, and gross calorific value, determined under the provisions of this section, to calculate SO 2.2.1 When combusting oil, use one of the following methods to sample the oil (see Table D-4): sample from the storage tank for the unit after each addition of oil to the storage tank, in accordance with section 2.2.4.2 of this appendix; or sample from the fuel lot in the shipment tank or container upon receipt of each oil delivery or from the fuel lot in the oil supplier's storage container, in accordance with section 2.2.4.3 of this appendix; or use the flow proportional sampling methodology in section 2.2.3 of this appendix; or use the daily manual sampling methodology in section 2.2.4.1 of this appendix. For purposes of this appendix, a fuel lot of oil is the mass or volume of product oil from one source (supplier or pretreatment facility), intended as one shipment or delivery (e.g., ship load, barge load, group of trucks, discrete purchase of diesel fuel through pipeline, etc.). A storage tank is a container at a plant holding oil that is actually combusted by the unit, such that no blending of any other fuel with the fuel in the storage tank occurs from the time that the fuel lot is transferred to the storage tank to the time when the fuel is combusted in the unit.
2.2.2 [Reserved]
Conduct flow proportional oil sampling or continuous drip oil sampling in accordance with ASTM D4177-82 (Reapproved 1990), "Standard Practice for Automatic Sampling of Petroleum and Petroleum Products" (incorporated by reference under § 75.6), every day the unit is combusting oil. Extract oil at least once every hour and blend into a composite sample. The sample compositing period may not exceed 7 calendar days (168 hrs). Use the actual sulfur content (and where density data are required, the actual density) from the composite sample to calculate the hourly SO Representative oil samples may be taken from the storage tank or fuel flow line manually every day that the unit combusts oil according to ASTM D4057-88, "Standard Practice for Manual Sampling of Petroleum and Petroleum Products" (incorporated by reference under § 75.6). Use either the actual daily sulfur content or the highest fuel sulfur content recorded at that unit from the most recent 30 daily samples for the purpose of calculating SO Take a manual sample after each addition of oil to the storage tank. Do not blend additional fuel with the sampled fuel prior to combustion. Sample according to the single tank composite sampling procedure or all-levels sampling procedure in ASTM D4057-88, "Standard Practice for Manual Sampling of Petroleum and Petroleum Products" (incorporated by reference under § 75.6). Use the
sulfur content (and where required, the density) of either the most recent sample or one of the conservative assumed values described in section 2.2.4.3 of this appendix to calculate SO (a) The most recent oil sample taken or
(b) One of the conservative assumed values described in section 2.2.4.3 of this appendix.
(a) Alternatively, an oil sample may be taken from --
(1) The shipment tank or container upon receipt of each lot of fuel oil or
(2) The supplier's storage container which holds the lot of fuel oil. (Note: a supplier need only sample the storage container once for sulfur content, GCV and, where required, the density so long as the fuel sulfur content and GCV do not change and no fuel is added to the supplier's storage container.)
(b) For the purpose of this section, a lot is defined as a shipment or delivery (e.g., ship load, barge load, group of trucks, discrete purchase of diesel fuel through a pipeline, etc.) of a single fuel.
(c) Oil sampling may be performed either by the owner or operator of an affected unit, an outside laboratory, or a fuel supplier, provided that samples are representative and that sampling is performed according to either the single tank composite sampling procedure or the all-levels sampling procedure in ASTM D4057-88, "Standard Practice for Manual Sampling of Petroleum and Petroleum Products" (incorporated by reference under § 75.6). Except as otherwise provided in this section, calculate SO (1) The highest value sampled during the previous calendar year (this option is allowed for any consistent fuel which comes from a single source whether or not the fuel is supplied under a contractual agreement) or
(2) The maximum value indicated in the contract with the fuel supplier. Continue to use this assumed contract value unless and until the actual sampled sulfur content, density, or gross calorific value of a delivery exceeds the assumed value.
(d) If the actual sampled sulfur content, gross calorific value, or density of an oil sample is greater than the assumed value for that parameter, then use the actual sampled value for sulfur content, gross calorific value, or density of fuel to calculate SO 2.2.5 Split and label each oil sample. Maintain a portion (at least 200 cc) of each sample throughout the calendar year and in all cases for not less than 90 calendar days after the end of the calendar year allowance accounting period. Analyze oil samples for percent sulfur content by weight in accordance with ASTM D129-91, "Standard Test Method for Sulfur in Petroleum Products (General Bomb Method)," ASTM D1552-90, "Standard Test Method for Sulfur in Petroleum Products (High Temperature Method)," ASTM D2622-92, "Standard Test Method for Sulfur in Petroleum Products by X-Ray Spectrometry," or ASTM D4294-90, "Standard Test Method for Sulfur in Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectroscopy" (incorporated by reference under § 75.6).
2.2.6 Where the flowmeter records volumetric flow rate rather than mass flow rate, analyze oil samples to determine the density or specific gravity of the oil. Determine the density or specific gravity of the oil sample in accordance with ASTM D287-82 (Reapproved 1991), "Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method)," ASTM D941-88, "Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Lipkin Bicapillary Pycnometer," ASTM D1217-91, "Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Bingham Pycnometer," ASTM D1481-91, "Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Lipkin Bicapillary," ASTM D1480-91, "Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Bingham Pycnometer," ASTM D1298-85 (Reapproved 1990), "Standard Practice for Density, Relative Density (Specific Gravity) or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method," or ASTM D4052-91, "Standard Test Method for Density and Relative Density of Liquids by Digital Density Meter" (incorporated by reference under § 75.6).
2.2.7 Analyze oil samples to determine the heat content of the fuel. Determine oil heat content in accordance with ASTM D240-87 (Reapproved 1991), "Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter," ASTM D2382-88, "Standard Test Method for Heat or Combustion of Hydrocarbon Fuels by Bomb
Calorimeter (High-Precision Method)", or ASTM D2015-91, "Standard Test Method for Gross Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter" (incorporated by reference under § 75.6) or any other procedures listed in section 5.5 of appendix F of this part.
2.2.8 Results from the oil sample analysis must be available no later than thirty calendar days after the sample is composited or taken. However, during an audit, the Administrator may require that the results of the analysis be available as soon as practicable, and no later than 5 business days after receipt of a request from the Administrator.
(a) Account for the hourly SO (b) The procedures in sections 2.3.1 and 2.3.2 of this appendix, respectively, may be used to determine SO The owner or operator may determine the SO For a fuel that meets the definition of pipeline natural gas under § 72.2 of this chapter, the owner or operator may determine the SO Calculate hourly heat input rate, in mmBtu/hr, for a unit combusting pipeline natural gas, using the procedures of section 3.4.1 of this appendix. Use the measured fuel flow rate from section 2.1 of this appendix and the gross calorific value from section 2.3.4.1 of this appendix in the calculations.
For pipeline natural gas combustion, calculate the SO2 mass emission rate, in lb/hr, using Equation D-5 in section 3.3.2 of this appendix (when the default SO (a) For pipeline natural gas, provide information in the monitoring plan required under § 75.53, demonstrating that the definition of pipeline natural gas in § 72.2 of this chapter has been met. The information must demonstrate that the fuel has a hydrogen sulfide content of less than 0.3 grain/100scf. The demonstration must be made using one of the following sources of information:
(1) The gas quality characteristics specified by a purchase contract or by a pipeline transportation contract;
(2) A certification of the gas vendor, based on routine vendor sampling and analysis (minimum of one year of data with samples taken monthly or more frequently);
(3) At least one year's worth of analytical data on the fuel hydrogen sulfide content from samples taken monthly or more frequently;
(4) For fuels delivered in shipments or lots, the sulfur content from all shipments or lots received in a one year period; or
(5) Data from a 720-hour demonstration conducted using the procedures of section 2.3.6 of this appendix.
(b) When a 720-hour test is used for initial qualification as pipeline natural gas, the owner or operator is required to continue sampling the fuel for hydrogen sulfide at least once per month for one year after the initial qualification period. The use of the default natural gas SO The owner or operator may determine the SO The owner or operator may account for SO 2.3.2.1.1 In lieu of daily sampling of the sulfur content of the natural gas, an SO ER = Default SO H 2.3.2.1.2 The hydrogen sulfide value used in Equation D-1h may be obtained from one of the following sources of information:
(a) The highest hydrogen sulfide content specified by a purchase contract or by a pipeline transportation contract;
(b) The highest hydrogen sulfide content from a certification of the gas vendor, based on routine vendor sampling and analysis (minimum of one year of data with samples taken monthly or more frequently);
(c) The highest hydrogen sulfide content from at least one year's worth of analytical data on the fuel hydrogen sulfide content
from samples taken monthly or more frequently;
(d) For fuels delivered in shipments or lots, the highest hydrogen sulfide content from all shipments or lots received in a one year period; or
(e) the highest hydrogen sulfide content measured during a 720-hour demonstration conducted using the procedures of section 2.3.6 of this appendix.
Calculate hourly heat input rate for natural gas combustion, in mmBtu/hr, using the procedures in section 3.4.1 of this appendix. Use the measured fuel flow rate from section 2.1 of this appendix and the gross calorific value from section 2.3.4.2 of this appendix in the calculations.
For natural gas combustion, calculate the SO (a) For natural gas, provide information in the monitoring plan required under § 75.53, demonstrating that the definition of natural gas in § 72.2 of this chapter has been met. The information must demonstrate that the fuel has a hydrogen sulfide content of less than 1.0 grain/100 scf. This demonstration must be made using one of the following sources of information:
(1) The gas quality characteristics specified by a purchase contract or by a transportation contract;
(2) A certification of the gas vendor, based on routine vendor sampling and analysis (minimum of one year of data with samples taken monthly or more frequently);
(3) At least one year's worth of analytical data on the fuel hydrogen sulfide content from samples taken monthly or more frequently;
(4) For fuels delivered in shipments or lots, sulfur content from all shipments or lots received in a one year period; or
(5) Data from a 720-hour demonstration conducted using the procedures of section 2.3.6 of this appendix.
(b) When a 720-hour test is used for initial qualification as natural gas, the owner or operator shall continue sampling the fuel for hydrogen sulfide at least once per month for one year after the initial qualification period. The use of the default natural gas SO The owner or operator of a unit may determine SO 2.3.3.1.1 Analyze the total sulfur content of the gaseous fuel in grain/100 scf, at the frequency specified in Table D-5 of this appendix. That is: for fuel delivered in discrete shipments or lots, sample each shipment or lot; for fuel transmitted by pipeline, if a demonstration is provided under section 2.3.6 of this appendix showing that the gaseous fuel has a "low sulfur variability," determine the sulfur content daily using either manual sampling or a gas chromatograph; and for all other gaseous fuels, determine the sulfur content on an hourly basis using a gas chromatograph.
2.3.3.1.2 Use one of the following methods when using manual sampling (as applicable to the type of gas combusted) to determine the sulfur content of the fuel: ASTM D1072-90, "Standard Test Method for Total Sulfur in Fuel Gases", ASTM D4468-85 (Reapproved 1989) "Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Radiometric Colorimetry," ASTM D5504-94 "Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence," or ASTM D3246-81 (Reapproved 1987) "Standard Test Method for Sulfur in Petroleum Gas By Oxidative Microcoulometry" (incorporated by reference under § 75.6).
2.3.3.1.3 The sampling and analysis of daily manual samples may be performed by the owner or operator, an outside laboratory, or the gas supplier. If hourly sampling with a gas chromatograph is required, or a source chooses to use an online gas chromatograph to determine daily fuel sulfur content, the owner or operator shall develop and implement a program to quality assure the data from the gas chromatograph, in accordance with the manufacturer's recommended procedures. The quality assurance procedures shall be kept on-site, in a form suitable for inspection.
2.3.3.1.4 Results of all sample analyses must be available no later than thirty calendar days after the sample is taken.
2.3.3.2 SO Calculate the SO Calculate the hourly heat input rate for combustion of the gaseous fuel, using the provisions in section 3.4.1 of this appendix. Use the measured fuel flow rate from section 2.1 of this appendix and the gross calorific value from section 2.3.4.3 of this appendix in the calculations.
Determine the GCV of each gaseous fuel at the frequency specified in this section, using one of the following methods: ASTM D1826-88, ASTM D3588-91, ASTM D4891-89, GPA Standard 2172-86 "Calculation of Gross Heating Value, Relative Density and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis," or GPA Standard 2261-90 "Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography" (incorporated by reference under § 75.6 of this part). Use the appropriate GCV value, as specified in section 2.3.4.1, 2.3.4.2 or 2.3.4.3 of this appendix, in the calculation of unit hourly heat input rates.
Determine the GCV of fuel that is pipeline natural gas, as defined in § 72.2 of this chapter, at least once per calendar month. For GCV used in calculations use the specifications in Table D-5: either the value from the most recent monthly sample, the highest value specified in a contract or tariff sheet, or the highest value from the previous year. The fuel GCV value from the most recent monthly sample shall be used for any month in which that value is higher than a contract limit. If a unit combusts pipeline natural gas for less than 48 hours during a calendar month, the sampling and analysis requirement for GCV is waived for that calendar month. The preceding waiver is limited by the condition that at least one analysis for GCV must be performed for each quarter the unit operates for any amount of time.
Determine the GCV of fuel that is natural gas, as defined in § 72.2 of this chapter, on a monthly basis, in the same manner as described for pipeline natural gas in section 2.3.4.1 of this appendix.
For gaseous fuels other than natural gas or pipeline natural gas, determine the GCV as specified in section 2.3.4.3.1, 2.3.4.3.2 or 2.3.4.3.3, as applicable.
2.3.4.3.1 For a gaseous fuel that is delivered in discrete shipments or lots, determine the GCV for each shipment or lot. The determination may be made by sampling each delivery or by sampling the supply tank after each delivery. For sampling of each delivery, use the highest GCV in the previous year's samples. For sampling from the tank after each delivery, use either the most recent GCV sample or the highest GCV in the previous year.
2.3.4.3.2 For any gaseous fuel that does not qualify as pipeline natural gas or natural gas and which is not delivered in shipments or lots which performs the required 720 hour test under section 2.3.5 of this appendix, and the results of the test demonstrate that the gaseous fuel has a low GCV variability, determine the GCV at least monthly. In calculations of hourly heat input for a unit, use either the most recent monthly sample or the highest fuel GCV from the previous year's samples.
2.3.4.3.3 For any other gaseous fuel, determine the GCV at least daily and use the actual fuel GCV in calculations of unit hourly heat input. If an online gas chromatograph or on-line calorimeter is used to determine fuel GCV each day, the owner or operator shall develop and implement a program to quality assure the data from the gas chromatograph or on-line calorimeter, in accordance with the manufacturer's recommended procedures. The quality assurance procedures shall be kept on-site, in a form suitable for inspection.
(a) This demonstration is required of any fuel which does not qualify as pipeline natural gas or natural gas, and is not delivered only in shipments or lots. The demonstration data shall be used to determine whether daily or monthly sampling of the GCV of the gaseous fuel or blend is required.
(b) To make this demonstration, proceed as follows. Provide a minimum of 720 hours of data, indicating the GCV of the gaseous fuel or blend (in Btu/100 scf). The demonstration data shall be obtained using either: hourly sampling and analysis using the methods in section 2.3.4 to determine GCV of the fuel; an on-line gas chromatograph capable of determining fuel GCV on an hourly basis; or an on-line calorimeter. For gaseous fuel produced by a variable process, the data shall be
representative of and include all process operating conditions including seasonal and yearly variations in process which may affect fuel GCV.
(c) The data shall be reduced to hourly averages. The mean GCV value and the standard deviation from the mean shall be calculated from the hourly averages. Specifically, the gaseous fuel is considered to have a low GCV variability, and monthly gas sampling for GCV may be used, if the mean value of the GCV multiplied by 1.075 is greater than the sum of the mean value and one standard deviation. If the gaseous fuel or blend does not meet this requirement, then daily fuel sampling and analysis for GCV, using manual sampling, a gas chromatograph or an on-line calorimeter is required.
(a) This demonstration is required for any fuel which does not qualify as pipeline natural gas or natural gas and is not delivered in shipments or lots. The results of the demonstration will be used to determine whether daily or hourly sampling for sulfur in the fuel is required. To make this demonstration, proceed as follows. Provide a minimum of 720 hours of data, indicating the total sulfur content (and hydrogen sulfide content, if needed to define a fuel as either pipeline natural gas or natural gas) of the gaseous fuel or blend (in gr/100 scf). The demonstration data shall be obtained using either manual hourly sampling or an on-line gas chromatograph capable of determining fuel total sulfur content (and, if applicable, H2. Procedure
2.1 Fuel Flowmeter Measurements
Table D-1--Table of Flowmeter Accuracy Results
------------------------------------------------------------------------
-------------------------------------------------------------------------
Test number:________ Test completion date\1\:____________________ Test
completion time\1\:____________
Reinstallation date\2\ (for testing under 2.1.5.1
only):____________________ Reinstallation time\2\:____________
Unit or pipe ID: Component/System ID:
Flowmeter serial number: Upper range value:
Units of measure for flowmeter and reference flow readings:
------------------------------------------------------------------------
Percent
Time of run Candidate Reference accuracy
Measurement level (percent of URV) Run No. (HHMM) flowmeter flow (percent of
reading reading URV)
----------------------------------------------------------------------------------------------------------------
Low (Minimum) level................ 1 ........... ........... ........... ...........
____ percent\3\ of URV............. 2 ........... ........... ........... ...........
3 ........... ........... ........... ...........
Average ........... ........... ........... ...........
Mid-level.......................... 1 ........... ........... ........... ...........
____ percent\3\ of URV............. 2 ........... ........... ........... ...........
3 ........... ........... ........... ...........
Average ........... ........... ........... ...........
High (Maximum) level............... 1 ........... ........... ........... ...........
____ percent\3\ of URV............. 2 ........... ........... ........... ...........
3 ........... ........... ........... ...........
Average ........... ........... ........... ...........
----------------------------------------------------------------------------------------------------------------
\1\Report the date, hour, and minute that all test runs were completed.
\2\For laboratory tests not performed inline, report the date and hour that the fuel flowmeter was reinstalled
following the test.
\3\It is required to test at least at three different levels: (1) normal full unit operating load, (2) normal
minimum unit operating load, and (3) a load point approximately equally spaced between the full and minimum
unit operating loads.
Table D-2--Table of Flowmeter Transmitter or Transducer Accuracy Results
Test number:________ Test completion date: ____________________ Unit or
pipe ID: ____________
Flowmeter serial number: Component/System ID:
Full-scale value: Units of measure:\3\
Transducer/Transmitter Type (check one):
____ Differential Pressure
____ Static Pressure
____ Temperature
------------------------------------------------------------------------
Expected
Run number Transmitter/ transmitter/ Actual Percent
Measurement level (percent of (if Run time transducer transducer transmitter/ accuracy
full-scale) multiple (HHMM) input (pre- output transducer (percent of
runs)\2\ calibration) (reference) output\3\ full-scale)
----------------------------------------------------------------------------------------------------------------
Low (Minimum) level
____ percent\1\ of full- ...........
scale
Mid-level
____ percent\1\ of full- ...........
scale
(If tested at more than 3
levels)
2nd Mid-level
____ percent\1\ of full- ...........
scale
(If tested at more than 3
levels)
3rd Mid-level
____ percent\1\ of full- ...........
scale
High (Maximum) level
____ percent\1\ of full- ...........
scale
----------------------------------------------------------------------------------------------------------------
\1\At a minimum, it is required to test at zero-level and at least two other levels across the range of the
transmitter or transducer readings corresponding to normal unit operation.
\2\It is required to test at least once at each level.
\3\Use the same units of measure for all readings (e.g., use degrees ( deg.), inches of water (in H<INF>2</INF>O), pounds
per square inch (psi), or milliamperes (ma) for both transmitter or transducer readings and reference
readings).
Table D-3--Baseline Information and Test Results for Fuel Flow-to-Load
Test
------------------------------------------------------------------------
-------------------------------------------------------------------------
Plant name:____________________State:______ORIS
code:____________________
Unit/pipe ID #:____________Fuel flowmeter component and system ID
#s:________-________Calendar quarter (1st, 2nd, 3rd, 4th) and
year:____________
Range of operation:____________ to ____________ MWe or klb steam/hr
(indicate units)
------------------------------------------------------------------------
Time period
-------------------------------------------------------------------------
Baseline period Quarter
------------------------------------------------------------------------
Completion date and time of most recent Number of hours excluded
primary element inspection (orifice-, nozzle- from quarterly average
, and venturi-type flowmeters only). due to co-firing
different fuels:________
hrs.
____/____/____ ____:____
Completion date and time of the most recent Number of hours excluded
flowmeter or transmitter accuracy test. from quarterly average
due to ramping load:
________ hrs.
____/____/____ ____:____
Beginning date and time of baseline period... Number of hours in the
lower 25.0 percent of
the range of operation
excluded from quarterly
average: ________ hrs.
____/____/____ ____:____
End date and time of baseline period......... Number of hours included
in quarterly average:
________ hrs.
____/____/____ ____:____
Average fuel flow rate____________________ Quarterly percentage
(100 scfh for gas and lb/hr for oil). difference between
hourly ratios and
baseline ratio: ________
percent.
Average load;____________________ (MWe or Test result: pass, fail.
1000 lb steam/hr).
Baseline fuel flow-to-load
ratio____________________
Units of fuel flow-to-
load:____________________
Baseline GHR: ____________________
Units of fuel flow-to-
load:____________________
Number of hours excluded from baseline ratio
or GHR due to ramping load:________
Number of hours in the lower 25.0 percent of
the range of operation excluded from
baseline ration or GHR: ________ hrs.
------------------------------------------------------------------------
2.2 Oil Sampling and Analysis
Table D-4--Oil Sampling Methods and Sulfur, Density and Gross Calorific Value Used in Calculations
----------------------------------------------------------------------------------------------------------------
Parameter Sampling technique/frequency Value used in calculations
----------------------------------------------------------------------------------------------------------------
Oil Sulfur Content.................... Daily manual sampling......... 1. Highest sulfur content from previous
30 daily samples; or
2. Actual daily value.
-------------------------------------------------------------------------
Flow proportional/weekly Actual measured value.
composite.
-------------------------------------------------------------------------
In storage tank (after 1. Actual measured value; or
addition of fuel to tank). 2. Highest of all sampled values in
previous calendar year; or
3. Maximum value allowed by contract.\1\
-------------------------------------------------------------------------
As delivered (in delivery 1. Highest of all sampled values in
truck or barge).\1\. previous calendar year; or
2. Maximum value allowed by contract.\1\
----------------------------------------------------------------------------------------------------------------
Oil Density........................... Daily manual sampling......... 1. Use the highest density from the
previous 30 daily samples; or
2. Actual measured value.
-------------------------------------------------------------------------
Flow proportional/weekly Actual measured value.
composite.
-------------------------------------------------------------------------
In storage tank (after 1. Actual measured value; or
addition of fuel to tank). 2. Highest of all sampled values in
previous calendar year; or
3. Maximum value allowed by contract.\1\
-------------------------------------------------------------------------
As delivered (in delivery 1. Highest of all sampled values in
truck or barge).\1\. previous calendar year; or
2. Maximum value allowed by contract.\1\
----------------------------------------------------------------------------------------------------------------
Oil GCV............................... Daily manual sampling......... 1. Highest fuel GCV from the previous 30
daily samples; or
2. Actual measured value.
-------------------------------------------------------------------------
Flow proportional/weekly Actual measured value.
composite.
-------------------------------------------------------------------------
In storage tank (after 1. Actual measured value; or
addition of fuel to tank). 2. Highest of all sampled values in
previous calendar year; or
3. Maximum value allowed by contract.\1\
-------------------------------------------------------------------------
As delivered (in delivery 1. Highest of all sampled values in
truck or barge).\1\. previous calendar year; or
2. Maximum value allowed by contract.\1\
----------------------------------------------------------------------------------------------------------------
\1\Assumed values may only be used if sulfur content, gross calorific value, or density of each sample is no
greater than the assumed value used to calculate emissions or heat input.
Table D-5--Gas Sulfur and GCV Values Used in Calculations for Various Fuel Types
----------------------------------------------------------------------------------------------------------------
Parameter Fuel type and sampling frequency Value used in calculations
----------------------------------------------------------------------------------------------------------------
Gas Sulfur Content.................... Pipeline Natural Gas with H<INF>2</INF>S 0.0006 lb/mmBtu.
content less than or equal to 0.3
grains/100scf when using the
provisions of section 2.3.1 to
determine SO<INF>2</INF> mass emissions.
-------------------------------------------------------------------------
Natural Gas with H<INF>2</INF>S content less Default SO<INF>2</INF> emission rate
than or equal to 1.0 grain/100scf calculated from Eq. D-1h, using
when using the provisions of either the fuel contract maximum
section 2.3.2 to determine SO<INF>2</INF> H<INF>2</INF>S or the maximum H<INF>2</INF>S from
mass emissions. historical sampling data.
-------------------------------------------------------------------------
Any gaseous fuel delivered in Actual % sulfur from most recent
shipments or lots--Sample each lot shipment or
or shipment. 1. Highest % sulfur from previous
year's samples\1\; or
2. Maximum % sulfur value allowed
by contract\1\.
-------------------------------------------------------------------------
Any gaseous fuel transmitted by Actual % sulfur from daily sample;
pipeline and having a demonstrated or Highest % sulfur from previous
``low sulfur variability'' using 30 daily samples.
the provisions of section 2.3.6--
Sample daily.
-------------------------------------------------------------------------
Any gaseous fuel--Sample hourly.... Actual hourly sulfur content of the
gas.
----------------------------------------------------------------------------------------------------------------
Gas GCV............................... Pipeline Natural Gas--Sample 1. GCV from most recent monthly
monthly. sample (with <gr-thn-eq> 48
operating hours in the month); or
2. Maximum GCV from contract\1\; or
3. Highest GCV from previous year's
samples.\1\
-------------------------------------------------------------------------
Natural Gas--Sample monthly....... 1. GCV from most recent monthly
sample (with <gr-thn-eq> 48
operating hours in the month); or
2. Maximum GCV from contract\1\; or
3. Highest GCV from previous year's
samples.\1\
-------------------------------------------------------------------------
Any gaseous fuel delivered in Actual GCV from most recent
shipments or lots--Sample each lot shipment or lot or
or shipment. 1. Highest GCV from previous year's
samples1; or
2. Maximum GCV value allowed by
contract.\1\
-------------------------------------------------------------------------
Any gaseous fuel transmitted by 1. GCV from most recent monthly
pipeline and having a demonstrated sample (with <gr-thn-eq> 48
``low GCV variability'' using the operating hours in the month); or
provisions of section 2.3.5-- 2. Highest GCV from previous year's
Sample monthly. samples.\1\
-------------------------------------------------------------------------
Any other gaseous fuel not having a Actual daily or hourly GCV of the
``low GCV variability''--Sample at gas.
least daily. (Note that the use of
an on- line GCV calorimeter or gas
chromatograph is allowed).
----------------------------------------------------------------------------------------------------------------
\1\Assumed sulfur content and GCV values (i.e., contract values or highest values from previous year) may only
continue to be used if the sulfur content or GCV of each sample is no greater than the assumed value used to
calculate SO<INF>2</INF> emissions or heat input.
