addressing uncertainty in oil and natural gas industry greenhouse

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calculation of GHG emissions. The measurement standards cited in Appendix B are current as of the date of this publication (i.e., June 2009). However, it is up to the user of these measurement standards to reference the specific standards/editions used for a given measurement, and to incorporate the updated measurement procedures, as applicable. Custody transfer measurements are typically expected to meet a set of performance specifications. For other measurements, such as those performed to support the development of a GHG emissions inventory, data quality objectives should be established prior to initiating any data collection in order to ensure that the uncertainty ranges of the measured quantities are consistent with the intended use of the data. Throughout this section we provide references and describe a select subset of industry standards that are most typically used for the respective measurements discussed. Even so, the full list of measurement methods provided in Appendix B could be used to provide equivalent measurements to meet company practices and available instrumentation. For many O&G industry installations, CO 2 emissions from combustion and flaring are the largest contributors to overall GHG emissions. Therefore, this section focuses on measurements and methods typically used for quantification of these CO 2 emissions. The subsections below provide details on flow measurement practices, and their associated uncertainties, as well as methods for the measurement of carbon content and heating values of combusted fuels. For some other O&G industry sectors, such as exploration, production, processing, transmission and distribution operations, emissions from other GHGs (such as methane) can contribute significantly to a facility’s GHG emissions. Available emission factors exhibit large uncertainties and might not be representative of current operating practices. Therefore, for inventories where CH 4 constitutes a larger fraction of the emissions, the overall uncertainty would be expected to be substantially higher. Industry is now more fully internalizing the potential impact of measurement errors and bias through the full chain of emission calculations including measurement equipment, software calculations, simulation models, and the limitations of reliance on existing emission factors on the uncertainty range of resultant GHG emissions inventories. Considerations of the need for more representative measurement data, and the assessment of equipment design and age, are gaining more prominence in the process of assembling high certainty emission inventories. This section focuses on measurements that are pertinent to improved characterization of combusted fuels and the quantities used, but might not be directly applicable to measurement of leakages and fugitive emissions. The measurement practices highlighted here represent an initial step in what could end up being a multi-year effort to improve measurements of GHGs and quantify the activities that cause their emissions. Pilot Version, September 2009 3-2
3.1 Flow Measurement Practices Continuous handling of very large liquid and gas flow volumes is a characteristic of all the sectors of the O&G industry. Therefore, an in-depth understanding of flow measurement is essential both for internal process control and for transferring “custody” of intermediate streams or finished products. The accuracy of measurements of “custody meters” is historically quite high, and practices follow rigorous industry standards. Industry has been instrumental in developing international voluntary standards such as ISO 5168 (see Reference 8) establishing general principles and describing procedures for evaluating the uncertainty of measuring fluid flow rate or quantity. Annex A of ISO 5168 provides a step-by-step procedure for calculating and reporting these measurement uncertainties. Similarly, Chapter 14 of the API Manual of Petroleum Measurement Standards (MPMS), contains detailed procedures and practices for all aspects of natural gas (and similar gases) fluids measurement and calculation of their associated uncertainties, at the point where oil or gas enters the marketplace (“custody transfer”) (API MPMS, 2006). Those same practices are not as rigorously applied to internal accounting and process control during normal operations. 3.1.1 Measurements by Orifice Meters Orifice meters are by far the most prevalent flow meter type used in the O&G industry, and are used for metering products during “custody transfer” as well as for process control and internal accounting. These same flow meters are used to account for fuel volumes when estimating CO 2 emissions. Most of these flow meters are of the orifice type and are designed for long-term reliability and ruggedness under a variety of component mixtures and conditions that are essential for consistent fluid blending and processing. Although for these type of meters temperature and pressure calibrations can be done while the units are operating, they generally have limited access to direct orifice plate inspections and maintenance outside of planned shutdown (‘turnaround’) cycles. Recommended practices for the installation, calibration and calculation of flows for these custody meters are provided in Section 3 of Chapter 14 of API’s MPMS (API, 2005). This standard was developed by a collaborative effort by members of API, AGA, and the Processing Gas Association and with contributions from the Canadian Gas Association, American Chemical Council, the European Union, Norway, Japan and others. It is designed to ensure global consistency for O&G transactions. The four-part standard for square-edged, concentric orifice meters consists of: Part 1 – General equations and uncertainty guidelines; Part 2 – Specifications and installation requirements; Pilot Version, September 2009 3-3
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: 3.0 OVERVIEW OF MEASUREMENT PRACTIC
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 and 42: Table 3-4. Summary of Selected Carb
Page 43 and 44: 3.5 Heat Content Determination The
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
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Table 4-13 shows the uncertainty in
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Table 4-13. Comparison of Annual Em
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• The evolution of activity and e
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These guidelines concentrate solely
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(Reprinted from the API Compendium)
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Table 5-2. Onshore Oil Field (High
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associated with them are assigned b
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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:
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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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