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3.4.2 On-line Measurements On-line determination of fluid stream compositions is quite challenging due to possible variations in these compositions. This is especially notable for self-generated fuel gas such as refinery fuel gas or other processing plant gas. Conversely, for commercial products such as natural gas, liquid fuels, coal and coke, or for the analysis of associated gas in exploration and production operations, the challenges are more related to the ability to analyze multiple streams rapidly and ascertain that they all are within a desired property range. Instrumentation in this field has been developed to provide a measurement of stream components in order to achieve optimum control and assure product quality. The configurations of such analyzers are customized to accommodate typical site parameters and operating practices. Most such analyzers are designed with ASTM and ISO standards in mind and their calibration routines are designed to provide both reported data and its associated uncertainty. As mentioned previously, the two primary applications are for refinery gas analyzers and natural gas analyzers, and these are discussed briefly below. a. Refinery Gas Analyzer Refinery gas samples are delivered to the sample inlet of the GC after passing through a sample conditioning system that selectively removes any liquid fractions and particulate matter from the sample. This ensures that only the gas phase sample is delivered to the analyzer. An internal vacuum pump draws this conditioned sample into each injector, which then injects the mixture onto each of the columns for analysis. Typically, a complete analysis of hydrogen, saturated and olefinic hydrocarbons (C 1 -C 5 , and C 6+ grouped peaks), plus fixed gases (O 2 , N 2 , CO, and CO 2 ) is performed. Precise “retention times” information and component areas translate into accurate component identification and quantification of the relative magnitude of individual components present in refinery gas. b. Natural Gas Analyzer These types of analyzers are applicable to natural gas samples from wellhead to pipeline-quality gas. Samples are introduced using sample cylinders, Tedlar bags, or by direct connection to the pipeline or wellhead sampling points. Usually, two chromatographic modules are used to quickly separate and measure the individual components in natural gas. The analyzer separates and measures the permanent gases and hydrocarbons present via an optimized, dual-channel portable gas chromatograph. Wellhead samples may often contain significant amounts of H 2 S. Many instruments take this into account and there are no interferences, which means that H 2 S can be measured from 50 PPM to 30-mole%. Pilot Version, September 2009 3-18
3.5 Heat Content Determination The heating value or calorific value of a substance is the amount of heat released during the combustion of a specified amount of the substance. The calorific value is a characteristic for each substance and is measured in units of energy per unit of the substance, such as: kcal/kg, kJ/kg, J/mole, Btu/m³. The heat of combustion for fuels is expressed as: − − HHV – higher heating value (or gross calorific value or gross energy or upper heating value). This value is determined by bringing all the products of combustion back to the original precombustion temperature, and in particular condensing any water vapor produced. LHV – lower heating value (or net calorific value) is determined by subtracting the heat of vaporization of the water vapor from the higher heating value and treating any water formed as a vapor. The energy required to vaporize the water therefore is not realized as heat. In the O&G industry, the two most prevalent modes of determining heating values of gaseous fuels is either by measuring it directly, which can be accomplished either by stoichiometric combustion or by calorimetric techniques, or by computational methods that are based on standardized calculation procedures using gas sample composition data. A brief summary of these two types of practices is provided below. 3.5.1 Direct Measurements The heating value indicates the amount of energy that can be obtained as heat by burning a unit of gas. The heating values of a gas depend not only upon the temperature and pressure, but also upon the degree of saturation with water vapor. As mentioned above, general practices for determining fuel gas heating values rely on either calorimetric techniques or stoichiometric combustion practices. Table 3-5 provides a listing and a brief description of some selected methods for heating value determination for gaseous, liquid, and solid fossil fuels. Further discussion of the main features of these methods can be found in Appendix C. Pilot Version, September 2009 3-19
Page 1 and 2: Prepared by the LEVON Group, LLC an
Page 3 and 4: Table of Contents SECTION Page FORE
Page 5 and 6: List of Tables SECTION Page 2-1 Ove
Page 7 and 8: FOREWORD The global oil and natural
Page 9 and 10: DOCUMENT AT A GLANCE This document
Page 11 and 12: 1.0 INTRODUCTION Policymakers use e
Page 13 and 14: The Intergovernmental Panel on Clim
Page 15 and 16: 2.0 SOURCES OF UNCERTAINTY There ar
Page 17 and 18: Table 2-1. Overview of Methods Used
Page 19 and 20: the uncertainty associated with cur
Page 21 and 22: d. Data processing uncertainty Typi
Page 23 and 24: d. Material Balance For some emissi
Page 25 and 26: 3.0 OVERVIEW OF MEASUREMENT PRACTIC
Page 27 and 28: 3.1 Flow Measurement Practices Cont
Page 29 and 30: All these factors should be assesse
Page 31 and 32: Table 3-1. Example of FFMS Combined
Page 33 and 34: 3.2 Uncertainties of Flow Measureme
Page 35 and 36: Table 3-3. Compilation of Specifica
Page 37 and 38: EXHIBIT 3-3: FACTORS TO CONSIDER WH
Page 39 and 40: 3.3.2 Quantifying Sampling Precisio
Page 41: Table 3-4. Summary of Selected Carb
Page 45 and 46: 3.5.2 Computational Methods Heating
Page 47 and 48: using standard methods, non-standar
Page 49 and 50: 0.6 0.4 0.2 Error 0 -0.2 -0.4 -0.6
Page 51 and 52: s ± t × (Equation 4-1) n where s
Page 53 and 54: 4.2.1 Propagation Equations There a
Page 55 and 56: For two terms that might be correla
Page 57 and 58: EXHIBIT 4-1: Uncertainty Example fo
Page 61 and 62: Further guidance for assigning unce
Page 63 and 64: 4.4 Quantifying Measurement Uncerta
Page 69 and 70: Are the data based on a single poin
Page 71 and 72: Two methods are compared. The first
Page 73 and 74: . EXHIBIT 4-6: Uncertainty Example
Page 77 and 78: Table 4-13 shows the uncertainty in
Page 79 and 80: Table 4-13. Comparison of Annual Em
Page 81 and 82: • The evolution of activity and e
Page 83 and 84: These guidelines concentrate solely
Page 85 and 86: (Reprinted from the API Compendium)
Page 87 and 88: Table 5-2. Onshore Oil Field (High
Page 89 and 90: associated with them are assigned b
Page 91 and 92: Table 5-4. Onshore Oil Field (High
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5.2.4 Propagating Assymetric Uncert
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U( rel) = U( rel) + U( rel) + U( re
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Coke burn rate approach (Equation 5
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Wt% C ∑ lbmole x lbmole C 12 lb C
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The CO 2 emissions are calculated u
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GHG Emissions, tonnes/yr 60,000 50,
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vast majority of the uncertainty fo
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6.0 REFERENCES AGA, 2008, Greenhous
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The Alberta Energy and Utilities Bo
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Appendix A GLOSSARY OF STATISTICAL
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Page 115 and 116:
Page 117 and 118:
APPENDIX B LIST OF INDUSTRY MEASURE
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Chapter 2.8B Establishment of the L
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Chapter 11.5.3 Chapter 12.1.1 Chapt
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Chapter 19.4 Chapter 20.1 RP 85 RP
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ISO 8222:2002 ISO 8697:1999 ISO 902
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ISO 7194:2008 Measurement of fluid
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ASTM D4292 ASTM D4892 ASTM D5002 AS
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APPENDIX C OPERATING CONDITIONS, IN
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Appendix C OPERATING CONDITIONS, IN
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Appendix D SELECT MEASUREMENT METHO
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c. ASTM UOP539-97, Refinery Gas Ana
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interference between known componen
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maintained over the room temperatur
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APPENDIX E UNITS CONVERSION
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− Gasoline density (average) = 0.
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Appendix F UNCERTAINTY ESTIMATION D
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The uncertainty for the heaters/reb
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∑ 2 U ( abs) = U( abs) ∑(Wt%C)
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Combining the fuel usage for the tw
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Uncertainty Estimate of CO 2 e Emis
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U ( abs) = ( U ( abs) + U ( abs) +
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E E CO2e 219 tonne CO ⎛ 2 0.0108
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E CO 2 6 500× 10 scf gas lbmole ga
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• Fuel Economy (miles per gallon)
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Upper: U ( abs) = (U( abs) +U( abs)
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default CH 4 content is 5.53% from
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Uncertainty Estimate of CO 2 e Emis
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( ) Urel ( ) = Urel ( ) = Urel ( )
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Uncertainty Estimate for CH 4 and C
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specific mole % for CH 4 and CO 2 i
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E CO2 0.07239 tonne CH 4 tonne mole
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U ( rel) = U( rel) +U( rel) +U( rel
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Table F-14. Fugitive Emission and U
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U ( abs) = (U( abs) +U( abs) +U( ab
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Table F-15. Onshore Oil Field (High
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