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As was shown in Table 5-8, emissions from boilers/heaters, natural gas engines and flares are ranked in the top ten highest emission sources, with one source, emergency flare, contributing about 62% of the total. Uncertainty associated with the emergency flare was calculated to be 21.1%, or about ±6,500 tonnes CO 2 e/yr. By examining the calculations used for flaring, the following general strategies could be selected by the operating company to reduce uncertainty in flaring: • Refine the measurement of total gas flared (the activity factor), to reduce the activity factor uncertainty from the current value of 15% and/or; • Refine the gas composition measurements to reduce the uncertainty from 4%. Refining the measurement of total gas flared may result from many approaches, such as improving the meter quality (even possibly replacing the meter), improving the quality control of the existing meter (such as number of calibrations and inspections), or improving the number of measurements taken and recorded from the meter that is used to calculate the total gas flared (this assumes measurements were not already continuous). These approaches have varying costs, and some may be cost-prohibitive. The company would have to determine which approach was the most cost effective. Refining the gas composition data may also come from several methods, such as taking additional routine samples, installing a continuous gas analyzer, or using a better analysis method. As with the gas flow rate measurement, these approaches have varying costs, and some may be cost-prohibitive. The company would have to determine which approach was the most cost effective. If the company was effective in reducing the uncertainty in flare gas CO 2 emissions, it might then elect to proceed to the next largest CO 2 uncertainty source. The end-user will have to recalculate total emissions for the company or facility each time, and determine if the uncertainty goal or target has been reached. Reduction of Uncertainty in Vented CO 2 Sources If the company decided to take the next step of emission reductions, it may target the next largest category of uncertainty, which is vented CO 2 sources. Vented CO 2 emissions result from seven sources listed in Table F-15. The amine unit accounts for the over 98% of the emissions in this category. Amine unit CO 2 vented emissions have an uncertainty of 4,360 tonnes of CO 2 e in a category that only has an uncertainty of 4,420 tonnes of CO 2 e. Therefore any uncertainty reduction efforts in this area should be directed at the amine unit calculations. However, the calculations used for the amine units reveal that the uncertainty is actually relatively low. The uncertainty in that emission category is less than 7%. It is possible to reduce this uncertainty by improving the uncertainties for gas composition, and gas throughput. While it is possible to reduce this uncertainty, given the low percentage level of the uncertainty, any improvement may be small. Therefore this is likely a case where company efforts are best spent on the previous categories. Pilot Version, September 2009 5-23
6.0 REFERENCES AGA, 2008, Greenhouse Gas Emission Estimation Guidelines for the Natural Gas Distribution Sector; American Gas Association, Washington DC, April 2008 API 1985, Manual of Petroleum Measurement Standards, Chapter 13, Statistical Aspects of Measuring and Sampling, Part 1, “Statistical Concepts and Procedures in Measurement”, Reaffirmed February 2006, API Publications, Washington DC API, 2004 and 2009, Compendium of GHG Emissions Methodologies for the O&G Industry, American Petroleum Institute, Washington DC, February 2004 (Addendum 2005). Updated August 2009. API, 2009, revised and updated version of Reference 2. API/IPIECA, 2007, Greenhouse Gas Emissions Estimation & Inventories: An International Workshop Addressing Uncertainty & Accuracy, Workshop Report, London, UK http://www.ipieca.org/activities/climate_change/workshops/jan_07.php API/IPIECA, 2007, Oil & Natural Gas Industry Guidelines for Greenhouse Gas Reduction Projects, IPIECA, London, March 2007 API/IPIECA/OGP, 2003, Petroleum Industry Guidelines for Reporting GHG Emissions, IPIECA, London, December 2003 API Manual of Petroleum Measurement Systems, 2006, Chapter 14, “Natural Gas Fluids Measurement”, Sections 1 to 10, reaffirmed 2006, API Publications, Washington DC API Manual of Petroleum Measurement Systems, Chapter 14.1, “Collecting and Handling of Natural Gas Samples for Custody Transfer”, Sixth Edition, February 2006, API Publications, Washington DC API Manual of Petroleum Measurement Systems, Chapter 14.10, “Measurement of Flow to Flares”, First Edition, July 2007, API Publications, Washington DC ASTM 1945-03, “Analysis of Natural Gas by Gas Chromatography”, current edition approved May 10, 2003. Published July 2003. Originally approved in 1962. Last previous edition approved in 2001 as D1945–96(2001). ASTM D 1946 – 90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography, current edition approved June 1, 2006. Published June 2006 (Originally approved in 1962) ASTM UOP, 1997, UOP539-97, Refinery Gas Analysis by Gas Chromatography ASTM D 2650, 2004, Standard Test Method for Chemical Composition of Gases by Mass Spectrometry, Published November 1, 2004. ASTM D 1826 – 94 (Reapproved 2003), “Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter”, Current edition approved May 10, 2003. Published May 2003. Originally approved in 1961. Last previous edition approved in 1998 as D 1826 – 94 (1998). ASTM D-3588-98, “Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels”, Current edition approved May 10, 2003. Published May 2003. Originally approved in 1998. Last previous edition approved in 1998 as D 3588 – 98. ASTM D 4891 – 89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, Current edition approved June 1, 2006. Published June 2006. Originally approved in 1989. Last previous edition approved in 2001 as D4891–89 (2001) ASTM D7313-08, “Standard Practice for Determination of the Heating Value of Gaseous Fuels using Calorimetry and On-line/At-line Sampling”, Current edition approved May 1, 2008. Published May 2008. Pilot Version, September 2009 6-1
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Prepared by the LEVON Group, LLC an
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Table of Contents SECTION Page FORE
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List of Tables SECTION Page 2-1 Ove
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FOREWORD The global oil and natural
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DOCUMENT AT A GLANCE This document
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1.0 INTRODUCTION Policymakers use e
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The Intergovernmental Panel on Clim
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2.0 SOURCES OF UNCERTAINTY There ar
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Table 2-1. Overview of Methods Used
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the uncertainty associated with cur
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d. Data processing uncertainty Typi
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d. Material Balance For some emissi
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3.0 OVERVIEW OF MEASUREMENT PRACTIC
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3.1 Flow Measurement Practices Cont
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All these factors should be assesse
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Table 3-1. Example of FFMS Combined
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3.2 Uncertainties of Flow Measureme
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Table 3-3. Compilation of Specifica
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EXHIBIT 3-3: FACTORS TO CONSIDER WH
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3.3.2 Quantifying Sampling Precisio
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Table 3-4. Summary of Selected Carb
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3.5 Heat Content Determination The
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3.5.2 Computational Methods Heating
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using standard methods, non-standar
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0.6 0.4 0.2 Error 0 -0.2 -0.4 -0.6
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s ± t × (Equation 4-1) n where s
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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
Page 93 and 94: 5.2.4 Propagating Assymetric Uncert
Page 95 and 96: U( rel) = U( rel) + U( rel) + U( re
Page 97 and 98: Coke burn rate approach (Equation 5
Page 99 and 100: Wt% C ∑ lbmole x lbmole C 12 lb C
Page 101 and 102: The CO 2 emissions are calculated u
Page 103 and 104: GHG Emissions, tonnes/yr 60,000 50,
Page 105: vast majority of the uncertainty fo
Page 109 and 110: The Alberta Energy and Utilities Bo
Page 111 and 112: Appendix A GLOSSARY OF STATISTICAL
Page 117 and 118: APPENDIX B LIST OF INDUSTRY MEASURE
Page 119 and 120: Chapter 2.8B Establishment of the L
Page 121 and 122: Chapter 11.5.3 Chapter 12.1.1 Chapt
Page 123 and 124: Chapter 19.4 Chapter 20.1 RP 85 RP
Page 125 and 126: ISO 8222:2002 ISO 8697:1999 ISO 902
Page 127 and 128: ISO 7194:2008 Measurement of fluid
Page 129 and 130: ASTM D4292 ASTM D4892 ASTM D5002 AS
Page 131 and 132: APPENDIX C OPERATING CONDITIONS, IN
Page 133 and 134: Appendix C OPERATING CONDITIONS, IN
Page 135 and 136: Appendix D SELECT MEASUREMENT METHO
Page 137 and 138: c. ASTM UOP539-97, Refinery Gas Ana
Page 139 and 140: interference between known componen
Page 141 and 142: maintained over the room temperatur
Page 143 and 144: APPENDIX E UNITS CONVERSION
Page 145 and 146: − Gasoline density (average) = 0.
Page 147 and 148: Appendix F UNCERTAINTY ESTIMATION D
Page 149 and 150: The uncertainty for the heaters/reb
Page 151 and 152: ∑ 2 U ( abs) = U( abs) ∑(Wt%C)
Page 153 and 154: Combining the fuel usage for the tw
Page 155 and 156: 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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