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National Greenhouse and Energy Reporting Scheme Measurement 

Technical Guidelines for the estimation of emissions by facilities in Australia 

Applies to the estimation of emissions in the 2017-18 reporting year  

October 2017 

Published by the  http://www.environment.gov.au 

ISSN  2202-3348 

© Commonwealth of Australia 2017 

This work is licensed under the Creative Commons Attribution 3.0 Australia Licence. To view a copy of this license, visit http://creativecommons.org/licenses/by/3.0/au. 

The Department of the Environment and Energy asserts the right to be recognised as author of the original material in the following manner:  

© Commonwealth of Australia (Department of the Environment and Energy) 2017. 

IMPORTANT NOTICE – PLEASE READ 

This document is produced for general information only and does not represent a statement of the policy of the Commonwealth of Australia. The Commonwealth of Australia and all persons acting for the Commonwealth preparing this report accept no liability for the accuracy of or inferences from the material contained in this publication, or for any action as a result of any person’s or group’s interpretations, deductions, conclusions or actions in relying on this material. 

October 2017 

  2 

Contents 

Chapter 1—General 31 

Part 1.1—Preliminary 31 

Division 1.1.1—Overview 31 

1.4  Overview—methods for measurement 35 

1.5  Overview—energy 38 

1.6  Overview—scope 2 emissions 38 

1.7  Overview—assessment of uncertainty 39 

Division 1.1.2—Definitions and interpretation 40 

1.9  Interpretation 40 

1.9A  Meaning of separate instance of a source 40 

1.9B  Meaning of separate occurrence of a source 41 

1.10  Meaning of source 41 

Part 1.2—General 43 

1.11  Purpose of Part 43 

Division 1.2.1—Measurement and standards 43 

1.12  Measurement of emissions 43 

1.13 General principles for measuring emissions 43 

1.14 Assessment of uncertainty 44 

1.15 Units of measurement 44 

1.16 Rounding of amounts 45 

1.17 Status of standards 45 

Division 1.2.2—Methods 46 

1.18  Method to be used for a separate occurrence of a source 46 

1.18A  Conditions—persons preparing report must use same method 47 

1.19  Temporary unavailability of method 48 

Division 1.2.3—Requirements in relation to carbon capture and storage 50 

1.19A  Meaning of captured for permanent storage 50 

1.19B  Deducting greenhouse gas that is captured for permanent storage 50 

1.19C  Capture from facility with multiple sources jointly generated 51 

1.19D  Capture from a source where multiple fuels consumed 52 

1.19E  Measure of quantity of captured greenhouse gas 52 

1.19F  Volume of greenhouse gas stream—criterion A 53 

1.19G  Volume of greenhouse gas stream—criterion AAA 53 

1.19GA  Volume of greenhouse gas stream—criterion BBB 54 

1.19H  Volumetric measurement—compressed greenhouse gas stream 54 

1.19I  Volumetric measurement—super-compressed greenhouse gas stream 56 

1.19J  Gas measuring equipment—requirements 56 

1.19K  Flow devices—requirements 56 

1.19L  Flow computers—requirements 57 

1.19M  Gas chromatographs 58 

Part 1.3—Method 4—Direct measurement of emissions 59 

Division 1.3.1—Preliminary 59 

1.20  Overview 59 

Division 1.3.2—Operation of method 4 (CEM) 61 

Subdivision 1.3.2.1—Method 4 (CEM) 61 

1.21  Method 4 (CEM)—estimation of emissions 61 

1.21A  Emissions from a source where multiple fuels consumed 64 

Subdivision 1.3.2.2—Method 4 (CEM)—use of equipment 65 

1.22  Overview 65 

1.23  Selection of sampling positions for CEM equipment 65 

1.24  Measurement of flow rates by CEM 66 

1.25  Measurement of gas concentrations by CEM 66 

1.26  Frequency of measurement by CEM 67 

Division 1.3.3—Operation of method 4 (PEM) 68 

Subdivision 1.3.3.1—Method 4 (PEM) 68 

1.27  Method 4 (PEM)—estimation of emissions 68 

1.27A  Emissions from a source where multiple fuels consumed 70 

1.28  Calculation of emission factors 71 

Subdivision 1.3.3.2—Method 4 (PEM)—use of equipment 72 

1.29  Overview 72 

1.30  Selection of sampling positions for PEM equipment 72 

1.31  Measurement of flow rates by PEM equipment 73 

1.32  Measurement of gas concentrations by PEM 73 

1.33  Representative data for PEM 73 

Division 1.3.4—Performance characteristics of equipment 74 

1.34  Performance characteristics of CEM or PEM equipment 74 

Chapter 2—Fuel combustion 75 

Part 2.1—Preliminary 75 

2.1  Outline of Chapter 75 

Part 2.2—Emissions released from the combustion of solid fuels 77 

Division 2.2.1—Preliminary 77 

2.2  Application 77 

2.3  Available methods for estimating emissions of carbon dioxide, methane and 

nitrous oxide 77 

Division 2.2.2—Method 1—emissions of carbon dioxide, methane and nitrous 

oxide from solid fuels 79 

2.4  Method 1—solid fuels 79 

Table 2.2.2: Emission and energy content factors — solid 

fuels and certain coal-based products 80 

Division 2.2.3—Method 2—emissions from solid fuels 84 

Subdivision 2.2.3.1—Method 2—estimating carbon dioxide using default oxidation factor 84 

2.5  Method 2—estimating carbon dioxide using oxidation factor 84 

Table 2.2.3  Analysis of solid fuels: standards and frequency of analysis for 

energy, carbon, moisture and ash 87 

Subdivision 2.2.3.2—Method 2—estimating carbon dioxide using an estimated oxidation factor93 

2.6  Method 2—estimating carbon dioxide using an estimated oxidation factor 93 

Subdivision 2.2.3.3—Sampling and analysis for method 2 under sections 2.5 and 2.6 95 

2.7  General requirements for sampling solid fuels 97 

2.8  General requirements for analysis of solid fuels 97 

2.9  Requirements for analysis of furnace ash and fly ash 98 

2.10  Requirements for sampling for carbon in furnace ash 99 

2.11  Sampling for carbon in fly ash 99 

Division 2.2.4—Method 3—Solid fuels 101 

2.12  Method 3—solid fuels using oxidation factor or an estimated oxidation factor 101 

Division 2.2.5—Measurement of consumption of solid fuels 103 

2.13  Purpose of Division 103 

2.14  Criteria for measurement 104 

2.15  Indirect measurement at point of consumption—criterion AA 105 

2.16  Direct measurement at point of consumption—criterion AAA 112 

2.17  Simplified consumption measurements—criterion BBB 114

Part 2.3—Emissions released from the combustion of gaseous 

fuels 115 

Division 2.3.1—Preliminary 115 

2.18  Application 115 

2.19  Available methods 115 

Division 2.3.2—Method 1—emissions of carbon dioxide, methane and nitrous 

oxide 117 

2.20  Method 1—emissions of carbon dioxide, methane and nitrous oxide 117 

Table 2.3.2A Emission and energy content factors — gaseous fuels 118 

Table 2.3.2B  Emissions and energy content factors — gaseous fuels for 

transport energy purposes 120 

Division 2.3.3—Method 2—emissions of carbon dioxide from the combustion of 

gaseous fuels 121 

Subdivision 2.3.3.1—Method 2—emissions of carbon dioxide from the combustion of gaseous 

fuels 121 

2.21  Method 2—emissions of carbon dioxide from the combustion of gaseous fuels 121 

2.22  Calculation of emission factors from combustion of gaseous fuel 122 

Subdivision 2.3.3.2—Sampling and analysis 124 

2.23  General requirements for sampling under method 2 124 

2.24  Standards for analysing samples of gaseous fuels 124 

2.25  Frequency of analysis 128 

Division 2.3.4—Method 3—emissions of carbon dioxide released from the 

combustion of gaseous fuels 130 

2.26  Method 3—emissions of carbon dioxide from the combustion of gaseous fuels 130 

Division 2.3.5—Method 2—emissions of methane from the combustion of 

gaseous fuels 132 

2.27  Method 2—emissions of methane from the combustion of gaseous fuels 132 

Division 2.3.6—Measurement of quantity of gaseous fuels 133 

2.28  Purpose of Division 133 

2.29  Criteria for measurement 134 

2.30  Indirect measurement—criterion AA 135 

2.31  Direct measurement—criterion AAA 135 

2.32  Volumetric measurement—all natural gases 137 

2.33  Volumetric measurement—super-compressed gases 138 

2.34  Gas measuring equipment—requirements 138 

2.35  Flow devices—requirements 139 

2.36  Flow computers—requirements 140 

2.37  Gas chromatographs—requirements 140 

2.38  Simplified consumption measurements—criterion BBB 140 

Part 2.4—Emissions released from the combustion of liquid fuels 142 

Division 2.4.1—Preliminary 142 

2.39  Application 142 

2.39A  Definition of petroleum based oils for Part 2.4 142 

Subdivision 2.4.1.1—Liquid fuels—other than petroleum based oils and greases 142 

2.40  Available methods 142 

Subdivision 2.4.1.2—Liquid fuels—petroleum based oils and greases 143 

2.40A  Available methods 143 

Division 2.4.2—Method 1—emissions of carbon dioxide, methane and nitrous 

oxide from liquid fuels other than petroleum based oils or 

greases 144 

2.41  Method 1—emissions of carbon dioxide, methane and nitrous oxide 145 

Table 2.4.2A  Emission and energy content factors — liquid fuels and certain 

petroleum-based products for stationary energy purposes 146

Table 2.4.2B  Emissions and energy content factors — fuels for transport 

energy purposes 147 

Division 2.4.3—Method 2—emissions of carbon dioxide from liquid fuels other 

than petroleum based oils or greases 149 

Subdivision 2.4.3.1—Method 2—emissions of carbon dioxide from liquid fuels other than 

petroleum based oils or greases 149 

2.42  Method 2—emissions of carbon dioxide from the combustion of liquid fuels 149 

2.43  Calculation of emission factors from combustion of liquid fuel 150 

Subdivision 2.4.3.2—Sampling and analysis 150 

2.44  General requirements for sampling under method 2 151 

2.45  Standards for analysing samples of liquid fuels 151 

2.46  Frequency of analysis 154 

Division 2.4.4—Method 3—emissions of carbon dioxide from liquid fuels other 

than petroleum based oils or greases 155 

2.47  Method 3—emissions of carbon dioxide from the combustion of liquid fuels 155 

Division 2.4.5—Method 2—emissions of methane and nitrous oxide from liquid 

fuels other than petroleum based oils or greases 158 

2.48  Method 2—emissions of methane and nitrous oxide from the combustion of 

liquid fuels 158 

Table 2.4.5A Fuel combustion — liquid fuels for transport energy 

purposes for post-2004 vehicles 159 

Table 2.4.5B Fuel combustion — liquid fuels for transport energy 

purposes for certain trucks 159 

Division 2.4.5A—Methods for estimating emissions of carbon dioxide from 

petroleum based oils or greases 162 

2.48A  Method 1—estimating emissions of carbon dioxide using an estimated 

oxidation factor 163 

2.48B  Method 2—estimating emissions of carbon dioxide using an estimated 

oxidation factor 164 

2.48C  Method 3—estimating emissions of carbon dioxide using an estimated 

oxidation factor 164 

Division 2.4.6—Measurement of quantity of liquid fuels 165 

2.49  Purpose of Division 165 

2.50  Criteria for measurement 166 

2.51  Indirect measurement—criterion AA 167 

2.52  Direct measurement—criterion AAA 167 

2.53  Simplified consumption measurements—criterion BBB 168 

Part 2.5—Emissions released from fuel use by certain industries 169 

2.54  Application 169 

2.55  Application 169 

2.56  Methods 169 

2.57  Application 169 

2.58  Methods 169 

Division 2.5.3—Energy—petrochemical production 180 

2.59  Application 180 

2.60  Available methods 180 

2.61  Method 1—petrochemical production 180 

2.62  Method 2—petrochemical production 182 

2.63  Method 3—petrochemical production 183 

Part 2.6—Blended fuels 185 

2.64  Purpose 185 

2.65  Application 185 

2.66  Blended solid fuels 185 

2.67  Blended liquid fuels 185

Part 2.7—Estimation of energy for certain purposes 188

2.68  Amount of energy consumed without combustion 188 

2.69  Apportionment of fuel consumed as carbon reductant or feedstock and energy 189 

2.70  Amount of energy consumed in a cogeneration process 190 

2.71  Apportionment of energy consumed for electricity, transport and for stationary 

energy 191 

Appendix 2A Notes on Energy and Emission Factors 192 

Chapter 3—Fugitive emissions 200 

Part 3.1—Preliminary 200 

3.1  Outline of Chapter 200 

Part 3.2—Coal mining—fugitive emissions 200 

Division 3.2.1—Preliminary 200 

3.2  Outline of Part 200 

Division 3.2.2—Underground mines 201 

Subdivision 3.2.2.1—Preliminary 201 

3.3  Application 201 

3.4  Available methods 201 

Subdivision 3.2.2.2—Fugitive emissions from extraction of coal 203 

3.5  Method 1—extraction of coal 203 

3.6  Method 4—extraction of coal 204 

3.7  Estimation of emissions 206 

3.8  Overview—use of equipment 207 

3.9  Selection of sampling positions for PEM 207 

3.10  Measurement of volumetric flow rates by PEM 207 

3.11  Measurement of concentrations by PEM 208 

3.12  Representative data for PEM 208 

3.13  Performance characteristics of equipment 208

Subdivision 3.2.2.3—Emissions released from coal mine waste gas flared 208 

3.14  Method 1—coal mine waste gas flared 208 

3.15  Method 2—emissions of carbon dioxide from coal mine waste gas flared 209 

3.15A  Method 2—emissions of methane and nitrous oxide from coal mine waste gas 

flared 210 

3.16  Method 3—coal mine waste gas flared 211 

Subdivision 3.2.2.4—Fugitive emissions from post-mining activities 215 

3.17  Method 1—post-mining activities related to gassy mines 215 

Division 3.2.3—Open cut mines 216 

Subdivision 3.2.3.1—Preliminary 216 

3.18  Application 216 

3.19  Available methods 216 

Subdivision 3.2.3.2—Fugitive emissions from extraction of coal 218 

3.20  Method 1—extraction of coal 219 

3.21  Method 2—extraction of coal 220 

3.22  Total gas contained by gas bearing strata 223 

3.23  Estimate of proportion of gas content released below pit floor 224 

3.24  General requirements for sampling 225 

3.25  General requirements for analysis of gas and gas bearing strata 225 

3.25A  Method of working out base of the low gas zone 226 

3.25B  Further requirements for estimator 227 

3.25C  Default gas content for gas bearing strata in low gas zone 228 

3.25D  Requirements for estimating total gas contained in gas bearing strata 228 

3.26  Method 3—extraction of coal 228 

Subdivision 3.2.3.3—Emissions released from coal mine waste gas flared 229 

3.27  Method 1—coal mine waste gas flared 229 

3.28  Method 2—coal mine waste gas flared 229

3.29  Method 3—coal mine waste gas flared 229 

Division 3.2.4—Decommissioned underground mines 230 

Subdivision 3.2.4.1—Preliminary 230 

3.30  Application 230 

3.31  Available methods 230 

Subdivision 3.2.4.2—Fugitive emissions from decommissioned underground mines 232 

3.32  Method 1—decommissioned underground mines 232 

3.33  Emission factor for decommissioned underground mines 233 

3.34  Measurement of proportion of mine that is flooded 234 

3.35  Water flow into mine 234 

3.36  Size of mine void volume 234 

3.37  Method 4—decommissioned underground mines 235 

Subdivision 3.2.4.3—Fugitive emissions from coal mine waste gas flared 235 

3.38  Method 1—coal mine waste gas flared 235 

3.39  Method 2—coal mine waste gas flared 235 

3.40  Method 3—coal mine waste gas flared 235 

Part 3.3—Oil and natural gas—fugitive emissions 236 

Division 3.3.1—Preliminary 236 

3.40A  Definition of natural gas for Part 3.3 237 

Division 3.3.2—Oil or gas exploration 238 

Subdivision 3.3.2.1—Preliminary 238 

3.42  Application 238 

3.43  Available methods 238 

3.44  Method 1—oil or gas exploration 239 

3.45  Method 2—oil or gas exploration (flared carbon dioxide emissions) 240 

3.45A  Method 2A—oil or gas exploration (flared methane or nitrous oxide emissions) 241 

3.46  Method 3—oil or gas exploration 241

Subdivision 3.3.2.3—Oil or gas exploration—fugitive emissions from system upsets, accidents 

and deliberate releases from process vents 241 

3.46A  Available methods 241 

3.46B  Method 4—vented emissions from well completions and well workovers 242 

Division 3.3.3—Crude oil production 258 

Subdivision 3.3.3.1—Preliminary 258 

3.47  Application 258 

Subdivision 3.3.3.2—Crude oil production (non-flared)—fugitive leak emissions of methane 258 

3.48  Available methods 259 

3.49  Method 1—crude oil production (non-flared) emissions of methane 259 

3.50  Method 2—crude oil production (non-flared) emissions of methane 261 

Subdivision 3.3.3.3—Crude oil production (flared)—fugitive emissions of carbon dioxide, 

methane and nitrous oxide 262 

3.51  Available methods 262 

3.52  Method 1—crude oil production (flared) emissions 263 

3.53  Method 2—crude oil production 264 

3.53A  Method 2A—crude oil production (flared methane or nitrous oxide emissions) 264 

3.54  Method 3—crude oil production 265 

Subdivision 3.3.3.4—Crude oil production (non-flared)—fugitive vent emissions of methane and 

carbon dioxide 265 

3.56A  Available methods 265 

Division 3.3.4—Crude oil transport 268 

3.57  Application 268 

3.58  Available methods 268 

3.59  Method 1—crude oil transport 269 

3.60  Method 2—fugitive emissions from crude oil transport 269 

Division 3.3.5—Crude oil refining 271

3.61  Application 271 

3.62  Available methods 271 

Subdivision 3.3.5.1—Fugitive emissions from crude oil refining and from storage tanks for crude 

oil 273 

3.63  Method 1—crude oil refining and storage tanks for crude oil 273 

3.64  Method 2—crude oil refining and storage tanks for crude oil 274 

Subdivision 3.3.5.2—Fugitive emissions from deliberate releases from process vents, system 

upsets and accidents 275 

3.65  Method 1—fugitive emissions from deliberate releases from process vents, 

system upsets and accidents 275 

3.66  Method 4—deliberate releases from process vents, system upsets and 

accidents 275 

Subdivision 3.3.5.3—Fugitive emissions released from gas flared from the oil refinery 276 

3.67  Method 1—gas flared from crude oil refining 276 

3.68  Method 2—gas flared from crude oil refining 277 

3.68A   Method 2A—crude oil refining (flared methane or nitrous oxide emissions) 277 

3.69  Method 3—gas flared from crude oil refining 278 

Division 3.3.6—Natural gas production or processing, other than emissions that 

are vented or flared 281 

3.70  Application 281 

3.71  Available methods 281 

3.72  Method 1—natural gas production and processing (other than emissions that 

are vented or flared) 282 

3.73  Method 2—natural gas production and processing (other than venting and 

flaring) 283 

Division 3.3.7—Natural gas transmission 285 

3.74  Application 285 

3.75  Available methods 285 

3.76  Method 1—natural gas transmission 286

3.77  Method 2—natural gas transmission 287 

Division 3.3.8—Natural gas distribution 289 

3.78  Application 289 

3.79  Available methods 289 

3.80  Method 1—natural gas distribution 290 

3.81  Method 2—natural gas distribution 291 

Division 3.3.9—Natural gas production or processing (emissions that are 

vented or flared) 294 

3.82  Application 294 

3.83  Available methods 294 

Subdivision 3.3.9.1—Fugitive emissions that result from deliberate releases from process vents, 

system upsets and accidents 295 

3.84  Method 1—emissions from system upsets, accidents and deliberate releases 

from process vents 296 

Subdivision 3.3.9.2—Emissions released from gas flared from natural gas production and 

processing 296 

3.85  Method 1—gas flared from natural gas production and processing 297 

3.86  Method 2—gas flared from natural gas production and processing 297 

3.86A  Method 2A—natural gas production and processing (flared methane or nitrous 

oxide emissions) 298 

3.87  Method 3—gas flared from natural gas production and processing 298 

Part 3.4—Carbon capture and storage—fugitive emissions 301 

Division 3.4.1—Preliminary 302 

3.88  Outline of Part 302 

Division 3.4.2—Transport of greenhouse gases 302 

Subdivision 3.4.2.1—Preliminary 302 

3.89  Application 302 

3.90  Available methods 302

Subdivision 3.4.2.2—Emissions from transport of greenhouse gases involving transfer 304 

3.91  Method 1—emissions from transport of greenhouse gases involving transfer 304 

Subdivision 3.4.2.3—Emissions from transport of greenhouse gases not involving transfer 304 

3.92  Method 1—emissions from transport of greenhouse gases not involving transfer 304 

Division 3.4.3—Injection of greenhouse gases 306 

Subdivision 3.4.3.1—Preliminary 306 

3.93  Application 306 

3.94  Available methods 306 

Subdivision 3.4.3.2—Fugitive emissions from deliberate releases from process vents, system 

upsets and accidents 307 

3.95  Method 2—fugitive emissions from deliberate releases from process vents, 

system upsets and accidents 307 

Subdivision 3.4.3.3—Fugitive emissions from injection of greenhouse gases (other than 

emissions from deliberate releases from process vents, system upsets and 

accidents) 307 

3.96  Method 2—fugitive emissions from injection of a greenhouse gas into a 

geological formation (other than deliberate releases from 

process vents, system upsets and accidents) 307 

3.97  Method 3—fugitive emissions from injection of greenhouse gases (other than 

deliberate releases from process vents, system upsets and 

accidents) 308 

Division 3.4.4—Storage of greenhouse gases 309 

Subdivision 3.4.4.1—Preliminary 309 

3.98  Application 309 

3.99  Available method 310 

Subdivision 3.4.4.2—Fugitive emissions from the storage of greenhouse gases 310 

3.100  Method 2—fugitive emissions from geological formations used for the storage 

of greenhouse gases 310 

Chapter 4—Industrial processes emissions 312

Part 4.1—Preliminary 312 

4.1  Outline of Chapter 312 

Part 4.2—Industrial processes—mineral products 314 

Division 4.2.1—Cement clinker production 314 

4.2  Application 314 

4.3  Available methods 315 

4.4  Method 1—cement clinker production 315 

4.5  Method 2—cement clinker production 316 

4.6  General requirements for sampling cement clinker 317 

4.7  General requirements for analysing cement clinker 318 

4.8  Method 3—cement clinker production 318 

4.9  General requirements for sampling carbonates 320 

4.10  General requirements for analysing carbonates 320 

Division 4.2.2—Lime production 321 

4.11  Application 321 

4.12  Available methods 321 

4.13  Method 1—lime production 322 

4.14  Method 2—lime production 323 

4.15  General requirements for sampling 324 

4.16  General requirements for analysis of lime 325 

4.17  Method 3—lime production 325 

4.18  General requirements for sampling 326 

4.19  General requirements for analysis of carbonates 327 

Division 4.2.3—Use of carbonates for production of a product other than 

cement clinker, lime or soda ash 328 

4.20  Application 328 

4.21  Available methods 329 

4.22  Method 1—product other than cement clinker, lime or soda ash 330 

4.22A  Method 1A—product other than cement clinker, lime or soda ash for use of 

carbonates in clay materials 331 

4.23  Method 3—product other than cement clinker, lime or soda ash 332 

4.23A  Method 3A—product other than cement clinker, lime or soda ash for use of 

carbonates in clay materials 333 

4.23B  General requirements for sampling clay material 334 

4.23C  General requirements for analysing clay material 334 

4.24  General requirements for sampling carbonates 334 

4.25  General requirements for analysis of carbonates 335 

Division 4.2.4—Soda ash use and production 336 

4.26  Application 336 

4.27  Outline of Division 336 

Subdivision 4.2.4.1—Soda ash use 336 

4.28  Available methods 336 

4.29  Method 1—use of soda ash 337 

Subdivision 4.2.4.2—Soda ash production 337 

4.30  Available methods 337 

4.31  Method 1—production of soda ash 338 

4.32  Method 2—production of soda ash 341 

4.33  Method 3—production of soda ash 344 

Division 4.2.5—Measurement of quantity of carbonates consumed and products 

derived from carbonates 345 

4.34  Purpose of Division 345 

4.35  Criteria for measurement 346 

4.36  Indirect measurement at point of consumption or production—criterion AA 347 

4.37  Direct measurement at point of consumption or production—criterion AAA 347 

4.38  Acquisition or use or disposal without commercial transaction—criterion BBB 348 

4.39  Units of measurement 348 

Part 4.3—Industrial processes—chemical industry 349 

Division 4.3.1—Ammonia production 349 

4.40  Application 350 

4.41  Available methods 350 

4.42  Method 1—ammonia production 350 

4.43  Method 2—ammonia production 351 

4.44  Method 3—ammonia production 352 

Division 4.3.2—Nitric acid production 353 

4.45  Application 353 

4.46  Available methods 353 

4.47  Method 1—nitric acid production 354 

4.48  Method 2—nitric acid production 355 

Division 4.3.3—Adipic acid production 356 

4.49  Application 356 

4.50  Available methods 356 

Division 4.3.4—Carbide production 357 

4.51  Application 357 

4.52  Available methods 357 

Division 4.3.5—Chemical or mineral production, other than carbide production, 

using a carbon reductant or carbon anode 358 

4.53  Application 358 

4.54  Available methods 358 

4.55  Method 1—chemical or mineral production, other than carbide production, using 

a carbon reductant or carbon anode 359 

4.56  Method 2—chemical or mineral production, other than carbide production, using 

a carbon reductant or carbon anode 361 

4.57  Method 3—chemical or mineral production, other than carbide production, using 

a carbon reductant or carbon anode 362 

Division 4.3.6—Sodium cyanide production 364 

4.58  Application 364 

4.59  Available methods 364 

Part 4.4—Industrial processes—metal industry 365 

Division 4.4.1—Iron, steel or other metal production using an integrated 

metalworks 365 

4.63  Application 366 

4.64  Purpose of Division 366 

4.65  Available methods for production of a metal from an integrated metalworks 366 

4.66  Method 1—production of a metal from an integrated metalworks 367 

4.67  Method 2—production of a metal from an integrated metalworks 369 

4.68  Method 3—production of a metal from an integrated metalworks 370 

Division 4.4.2—Ferroalloys production 378 

4.69  Application 378 

4.70  Available methods 378 

4.71  Method 1—ferroalloy metal 379 

4.72  Method 2—ferroalloy metal 381 

4.73  Method 3—ferroalloy metal 382 

Division 4.4.3—Aluminium production (carbon dioxide emissions) 384 

4.74  Application 384 

Sudivision 4.4.3.1—Aluminium—emissions from consumption of carbon anodes in aluminium 

production 384 

4.75  Available methods 384 

4.76  Method 1—aluminium (carbon anode consumption) 385 

4.77  Method 2—aluminium (carbon anode consumption) 386 

4.78  Method 3—aluminium (carbon anode consumption) 386 

Subdivision 4.4.3.2—Aluminium—emissions from production of baked carbon anodes in 

aluminium production 386 

4.79  Available methods 386 

4.80  Method 1—aluminium (baked carbon anode production) 387 

4.81  Method 2—aluminium (baked carbon anode production) 388 

4.82  Method 3—aluminium (baked carbon anode production) 388 

Division 4.4.4—Aluminium production (perfluoronated carbon compound 

emissions) 389 

4.83  Application 389 

Subdivision 4.4.4.1—Aluminium—emissions of tetrafluoromethane in aluminium production 389 

4.84  Available methods 389 

4.85  Method 1—aluminium (tetrafluoromethane) 389 

4.86  Method 2—aluminium (tetrafluoromethane) 390 

4.87  Method 3—aluminium (tetrafluoromethane) 390 

Subdivision 4.4.4.2—Aluminium—emissions of hexafluoroethane in aluminium production 390 

4.88  Available methods 390 

4.89  Method 1—aluminium production (hexafluoroethane) 391 

4.90  Method 2—aluminium production (hexafluoroethane) 391 

4.91  Method 3—aluminium production (hexafluoroethane) 391 

Division 4.4.5—Other metals production 392 

4.92  Application 392 

4.93  Available methods 392 

4.94  Method 1—other metals 393

4.95  Method 2—other metals 395

4.96  Method 3—other metals 396 

Part 4.5—Industrial processes—emissions of hydrofluorocarbons 

and sulphur hexafluoride gases 398 

4.97  Application 398 

4.98  Available method 398 

4.99  Meaning of hydrofluorocarbons 398 

4.100  Meaning of synthetic gas generating activities 398 

4.101  Reporting threshold 401 

4.102  Method 1 401 

4.103  Method 2 403 

4.104  Method 3 404 

Chapter 5—Waste 406 

Part 5.1—Preliminary 406 

5.1  Outline of Chapter 406 

Part 5.2—Solid waste disposal on land 407 

Division 5.2.1—Preliminary 407 

5.2  Application 407 

5.3  Available methods 407 

5.4  Method 1—methane released from landfills (other than from flaring of methane) 414 

5.4A  Estimates for calculating CH4gen 415 

5.4B  Equation—change in quantity of particular opening stock at landfill for 

calculating CH4gen 416 

5.4C  Equation—quantity of closing stock at landfill in particular reporting year 417 

5.4D  Equation—quantity of methane generated by landfill for calculating CH4gen 418 

5.5  Criteria for estimating tonnage of total solid waste 420 

5.6  Criterion A 421 

5.7  Criterion AAA 421 

5.8  Criterion BBB 421 

5.9  Composition of solid waste 421 

5.10  General waste streams 422 

5.10A  Homogenous waste streams 425 

5.11  Waste mix types 427 

5.11A  Certain waste to be deducted from waste received at landfill when estimating 

waste disposed in landfill 430 

5.12  Degradable organic carbon content 430 

5.13  Opening stock of degradable organic carbon for the first reporting period 431 

5.14  Methane generation constants—(k values) 432 

5.14A  Fraction of degradable organic carbon dissimilated (DOCF) 437 

5.14B  Methane correction factor (MCF) for aerobic decomposition 438 

5.14C  Fraction by volume generated in landfill gas that is methane (F) 439 

5.14D  Number of months before methane generation at landfill commences 439 

Division 5.2.3—Method 2—emissions of methane released from landfills 440 

Subdivision 5.2.3.1—methane released from landfills 440 

5.15  Method 2—methane released by landfill (other than from flaring of methane) 440 

5.15A  Equation—change in quantity of particular opening stock at landfill for 

calculating CH4gen 443 

5.15B  Equation—quantity of closing stock at landfill in particular reporting year 444 

5.15C  Equation—collection efficiency limit at landfill in particular reporting year 445 

Subdivision 5.2.3.2—Requirements for calculating the methane generation constant (k) 446 

5.16  Procedures for selecting representative zone 446 

5.17  Site plan—preparation and requirements 446 

5.17AA  Sub-facility zones—maximum number and requirements 447

5.17A  Representative zones—selection and requirements 448

5.17B  Independent verification 451 

5.17C  Estimation of waste and degradable organic content in representative zone 453 

5.17D  Estimation of gas collected at the representative zone 453 

5.17E  Estimating methane generated but not collected in the representative zone 454 

5.17F  Walkover survey 454 

5.17G  Installation of flux boxes in representative zone 455 

5.17H  Flux box measurements 457 

5.17I  When flux box measurements must be taken 460 

5.17J  Restrictions on taking flux box measurements 460 

5.17K  Frequency of measurement 461 

5.17L  Calculating the methane generation constant (ki) for certain waste mix types 461 

Division 5.2.4—Method 3—emissions of methane released from solid waste at 

landfills 465 

5.18  Method 3—methane released from solid waste at landfills (other than from 

flaring of methane) 465 

Division 5.2.5—Solid waste at landfills—Flaring 466 

5.19  Method 1—landfill gas flared 466 

5.20  Method 2—landfill gas flared 466 

5.21  Method 3—landfill gas flared 467 

Division 5.2.6—Biological treatment of solid waste 467 

5.22  Method 1—emissions of methane and nitrous oxide from biological treatment of 

solid waste at a landfill 467 

5.22AA  Method 4—biological treatment of solid waste at the landfill 468 

Division 5.2.7—Legacy emissions and non-legacy emissions 469 

5.22A  Legacy emissions estimated using method 1—sub-facility zone options 469 

5.22B  Legacy emissions—formula and unit of measurement 469 

5.22C  How to estimate quantity of methane captured for combustion from legacy 

waste for each sub-facility zone 471 

5.22D  How to estimate quantity of methane in landfill gas flared from legacy waste in 

a sub-facility zone 471 

5.22E  How to estimate quantity of methane captured for transfer out of landfill from 

legacy waste for each sub-facility zone 472 

5.22F  How to calculate the quantity of methane generated from legacy waste for a 

sub-facility zone (CH4genlw z) 472 

5.22G  How to calculate total methane generated from legacy waste 473 

5.22H  How to calculate total methane captured and combusted from methane 

generated from legacy waste 473 

5.22J  How to calculate total methane captured and transferred offsite from methane 

generated from legacy waste 473 

5.22K  How to calculate total methane flared from methane generated from legacy 

waste 474 

5.22L  How to calculate methane generated in landfill gas from non-legacy waste 474 

5.22M  Calculating amount of total waste deposited at landfill 475 

Part 5.3—Wastewater handling (domestic and commercial) 476 

Division 5.3.1—Preliminary 476 

5.23  Application 476 

5.24  Available methods 476 

Division 5.3.2—Method 1—methane released from wastewater handling 

(domestic and commercial) 478 

5.25  Method 1—methane released from wastewater handling (domestic and 

commercial) 478 

Division 5.3.3—Method 2—methane released from wastewater handling 

(domestic and commercial) 484 

5.26  Method 2—methane released from wastewater handling (domestic and 

commercial) 484 

5.26A  Requirements relating to sub-facilities 489

5.27  General requirements for sampling under method 2 489

5.28  Standards for analysis 489 

5.29  Frequency of sampling and analysis 490 

Division 5.3.4—Method 3—methane released from wastewater handling 

(domestic and commercial) 491 

5.30  Method 3—methane released from wastewater handling (domestic and 

commercial) 491 

Division 5.3.5—Method 1—emissions of nitrous oxide released from wastewater 

handling (domestic and commercial) 492 

5.31  Method 1—nitrous oxide released from wastewater handling (domestic and 

commercial) 492 

Division 5.3.6—Method 2—emissions of nitrous oxide released from wastewater 

handling (domestic and commercial) 495 

5.32  Method 2—nitrous oxide released from wastewater handling (domestic and 

commercial) 495 

5.33  General requirements for sampling under method 2 496 

5.34  Standards for analysis 496 

5.35  Frequency of sampling and analysis 496 

Division 5.3.7—Method 3—emissions of nitrous oxide released from wastewater 

handling (domestic and commercial) 497 

5.36  Method 3—nitrous oxide released from wastewater handling (domestic and 

commercial) 497 

Division 5.3.8—Wastewater handling (domestic and commercial)—Flaring 498 

5.37  Method 1—Flaring of methane in sludge biogas from wastewater handling 

(domestic and commercial) 498 

5.38  Method 2—flaring of methane in sludge biogas 498 

5.39  Method 3—flaring of methane in sludge biogas 499 

Part 5.4—Wastewater handling (industrial) 500

Division 5.4.1—Preliminary 500 

5.40  Application 500 

5.41  Available methods 500 

Division 5.4.2—Method 1—methane released from wastewater handling 

(industrial) 502 

5.42  Method 1—methane released from wastewater handling (industrial) 502 

Division 5.4.3—Method 2—methane released from wastewater handling 

(industrial) 508 

5.43  Method 2—methane released from wastewater handling (industrial) 508 

5.44  General requirements for sampling under method 2 508 

5.45  Standards for analysis 509 

5.46  Frequency of sampling and analysis 509 

Division 5.4.4—Method 3—methane released from wastewater handling 

(industrial) 510 

5.47  Method 3—methane released from wastewater handling (industrial) 510 

Division 5.4.5—Wastewater handling (industrial)—Flaring of methane in sludge 

biogas 511 

5.48  Method 1—flaring of methane in sludge biogas 511 

5.49  Method 2—flaring of methane in sludge biogas 511 

5.50  Method 3—flaring of methane in sludge biogas 512 

Part 5.5—Waste incineration 513 

5.51  Application 513 

5.52  Available methods—emissions of carbon dioxide from waste incineration 513 

5.53  Method 1—emissions of carbon dioxide released from waste incineration 513 

Chapter 6—Energy 515

Part 6.1—Production 515 

6.1  Purpose 515 

6.2  Quantity of energy produced 515 

Part 6.2—Consumption 519 

6.4  Purpose 519 

Chapter 7—Scope 2 emissions 522 

7.1  Application 522 

Table 7.2  Indirect (scope 2) emission factors from consumption of 

purchased electricity from a grid 524 

Chapter 8—Assessment of uncertainty 531 

Part 8.1—Preliminary 531 

8.1  Outline of Chapter 531 

Part 8.2—General rules for assessing uncertainty 533 

8.2  Range for emission estimates 533 

8.3  Required method 533 

Part 8.3—How to assess uncertainty when using method 1 535 

8.4  Purpose of Part 535 

8.7  Assessment of uncertainty for estimates of methane and nitrous oxide emissions 

from combustion of fuels 538 

8.8  Assessment of uncertainty for estimates of fugitive emissions 539 

8.9  Assessment of uncertainty for estimates of emissions from industrial process 

sources 540 

8.10  Assessment of uncertainty for estimates of emissions from waste 542 

8.11  Assessing uncertainty of emissions estimates for a source by aggregating 

parameter uncertainties 542 

Part 8.4—How to assess uncertainty levels when using method 2, 

3 or 4 544 

8.14  Purpose of Part 544 

8.15  Rules for assessment of uncertainty using method 2, 3 or 4 544 

Appendix A:  Schedule 3 Carbon content factors 549 

Part 1 Solid fuels and certain coal-based products 549 

Part 2 Gaseous fuels 550 

Part 3 Liquid fuels and certain petroleum-based products 551 

Part 4 Petrochemical feedstocks and products 552 

Part 5 Carbonates 553 

Appendix B: Definitions and interpretation 561 

Appendix C: Global Warming Potentials, Units and Conversions 575 

Appendix D: References 580 

Chapter 1—General 

Part 1.1—Preliminary 

Division 1.1.1—Overview 

The National Greenhouse and Energy Reporting Act 2007, the Regulations under that Act and the National Greenhouse and Energy Reporting (Measurement) Determination 2008 establish the legislative framework for a national greenhouse and energy reporting system.  

These Technical Guidelines embody the latest methods for estimating emissions and are based on the National Greenhouse and Energy Reporting (Measurement) Determination 2008 as amended (the Determination) and the National Greenhouse and Energy Reporting (Measurement) Amendment (Energy) Determination 2017).  

The Technical Guidelines provide additional guidance and commentary to assist Reporters in estimating greenhouse gas emissions for reporting under the NGER system and in general are applicable to the 2017-18 reporting year. 

The NGER System has two objectives which are set out in the National Greenhouse and Energy Reporting Act 2007 (the Act).   

The first set of objectives comprise: 

a) informing government policy formulation and the Australian public;  

b) meeting Australia’s international reporting obligations;  

c) assisting Commonwealth, State and Territory government programs and 

activities; and 

d) avoiding the duplication of similar reporting requirements in the States and Territories. 

Thresholds for reporting 

The Act makes reporting mandatory for corporations whose energy production, energy consumption, or greenhouse gas emissions meet certain specified thresholds. These thresholds are detailed in section 13 of the NGER Act and in supporting material available on the Clean Energy Regulator website at: http://www.cleanenergyregulator.gov.au/NGER/Forms-and-resources. 

The Determination is made under section 7B and subsection 10 of the Act. It provides methods, and criteria for methods, for the measurement of the following: 

(a) greenhouse gas emissions arising from the operation of facilities;  

(b) the production of energy arising from the operation of facilities; 

(c) the consumption of energy arising from the operation of facilities; and 

(d) potential greenhouse gas emissions embodied in an amount of natural gas. 

The structure of the Determination is designed to facilitate the integration of corporate and facility level data provided under the Act with international data standards on greenhouse emissions estimates. Descriptions of emissions sources are based on those provided in the IPCC Guidelines for National Greenhouse Gas Inventories, while estimation methods are based on those used by the Department on the Environment in preparing the Government’s annual submission to the United Nations Framework Convention on Climate Change (UNFCCC) in the National Inventory Report. 

These Technical Guidelines do not provide guidance on issues concerning the definition of a facility or who should report the emissions from a particular facility.  For guidance on these questions, consult the supporting material available on the Clean Energy Regulator website at: http://www.cleanenergyregulator.gov.au/NGER/Formsand-resources 

Emissions 

Scope 1 and scope 2 emissions are defined in the Regulations as the release of greenhouse gas emissions into the atmosphere either as a direct result of an activity that constitute the facility (scope 1) or as a result of activities that consume electricity, heat or steam at the facility (scope 2).  

The Determination and Technical Guidelines deal with scope 1 emissions and scope 2 emissions. Gaseous designated fuels are natural gas and liquefied natural gas. The Technical Guidelines are largely concerned with scope 1 emissions.  Scope 1 emissions concern emissions released from a facility as a direct result of the activities of the facility.   

The greenhouse gases covered by these Guidelines are defined in the Regulations and include: 

• carbon dioxide; 

• methane; 

• nitrous oxide; 

• specified hydrofluorocarbons 

• specified perfluorocarbons; and  sulphur hexafluoride. 

Scope 2 emissions are a form of indirect emission and are activities that generate electricity, heating, cooling or steam that is consumed by the facility but that do not form part of the facility. They occur principally at electricity generators as a result of electricity consumption at another facility.  Scope 2 emissions are covered only in Chapter 7. 

Natural gas is defined in the Regulations.  

Coverage of Scope 1 emission sources in the Determination is given by the following categories: 

(a) fuel combustion, which deals with emissions released from fuel combustion (see Chapter 2); and 

(b) fugitive emissions from fuels, which deals with emissions mainly released from the extraction, production, processing and distribution of fossil fuels (Chapter 3); and 

(c) industrial processes emissions, which deals with emissions released from the consumption of carbonates and the use of fuels as feedstocks or as carbon reductants, and the emission of synthetic gases in particular cases (see Chapter 4); and 

(d) waste emissions, which deals with emissions mainly released from the decomposition of organic material in landfill or wastewater handling facilities (see Chapter 5). 

The most important source is emissions from fuel combustion, which accounts for over 60 per cent of the emissions reported in the national greenhouse gas inventory. 

The scope of the Determination does not include land based emissions covered by the UNFCCC categories ‘Agriculture’ and ‘Land Use, Land Use Change and 

Forestry’.  However, emissions from fuel combustion or any other emission source listed above and which occurs from a facility operating within a land-based industry are, nonetheless, covered by the Determination. 

Updates of these Guidelines 

It is recognised that these Technical Guidelines will need to be updated as new information on emissions estimation methods becomes available.  This will need to be balanced against the need to maintain time-series consistency of the emissions data as far as possible.  Reflecting the need for this balance, it is planned that these Guidelines will be updated each year only for updated Scope 2 emission factors (see Chapter 7), while other revisions will occur on a periodic basis. It is planned that the Technical Guidelines will be updated periodically to: 

• provide Methods for emission sources where currently there are gaps or omissions in the Methods currently available;  

• take account of new documentary standards applicable to the estimation of emissions under Methods 2, 3 and 4; 

• take account of new information in relation to Method 1 emission factors; and 

• take account of new information in relation to the Methods detailed in the Determination. 

The Department will continue to refine and elaborate the Determination as other issues arise from ongoing consultation, and domestic and international developments.  

1.4  Overview—methods for measurement 

Emissions are rarely measured through direct observation and are most often estimated by reference to readily observable variables that are closely related to greenhouse gas emissions such as the quantity of fossil fuels consumed. 

These Guidelines provide Methods that allow for both direct emissions monitoring and the estimation of emissions through the tracking of observable, closely-related variables.  This framework reflects the approaches of the international guidelines governing the estimation of national greenhouse gas inventories and, similarly, national practice such as for the EU Guidelines for the Monitoring and Reporting of Greenhouse Gas Emissions and the US EPA Mandatory Greenhouse Gas Reporting Rule. 

At its simplest, emissions may be estimated by reference to reportable data such as fossil fuel consumption, evidenced by invoices, and the use of specified emission factors provided in these Guidelines. For emissions from fuel combustion, for example, data on consumption of a particular fuel would be multiplied by a specific emission factor for that fuel to generate an emissions estimate. 

Greater levels of complexity and measurement effort may in some circumstances produce better estimates of emissions at facility level.  This may result from, for example, sampling and analysis of a fuel consumed for its carbon content and other qualities that will affect actual emissions generated by its combustion at a facility.   In Australia, this kind of approach to emissions estimation has been used for a number of years in the electricity industry. 

Direct monitoring of emissions is also potentially an important approach to emissions estimation.  While not common, such direct monitoring already occurs in some form in some instances such as in the coal industry, where state legislation requires the monitoring of methane levels for health and safety reasons. 

Each of these broad approaches has been incorporated into the Guidelines as Methods for the estimation of emissions. 

In particular four Methods have been described which provide a framework for emissions estimation for a range of purposes. 

By drawing on existing emission estimation practices where possible, the Guidelines aim to allow reporters to meet their obligations efficiently.  As indicated above, there are many instances where higher order methods (2, 3 and 4 set out below) already reflect current commercial or regulatory practice. 

The provision for Reporters to select Methods for the estimation of emissions also allows Reporters to make their own judgements to balance the costs of using the higher-order methods with the benefits of potentially improved emission estimates.   

A Framework for Method selection 

For scope 1 emissions, the four Methods can be broadly described by the following: 

Method 1: the National Greenhouse Accounts default method   

Method 1 provides a class of estimation procedures derived directly from the methodologies used by the Department of the Environment and Energy for the preparation of the National Greenhouse Accounts.  The use of methodologies from the National Greenhouse Accounts also anchors Method 1 within the international guidelines adopted by the UNFCCC for the estimation of greenhouse emissions.   

Method 1 specifies the use of designated emission factors in the estimation of emissions. These emission factors are national average factors determined by the Department of the Environment and Energy using the Australian Greenhouse Emissions Information System (AGEIS).   

Method 1 is likely to be most useful for emission sources where the source is relatively homogenous, such as from the combustion of standard liquid fossil fuels, where the emissions resulting from combustion will be very similar across most facilities.   

Estimates of emissions will be able to be calculated under Method 1 by Reporters using tools provided by the Department of the Environment and Energy. 

Method 2: generally a facility-specific method using industry sampling and Australian or international standards listed in the Determination or equivalent for analysis of fuels and raw materials to provide more accurate estimates of emissions at facility level.    

Method 2 enables corporations to undertake additional measurements - for example, the qualities of fuels consumed at a particular facility - in order to gain more accurate estimates for emissions for that particular facility.   

Method 2 draws on the large body of Australian and international documentary standards prepared by standards organisations to provide the benchmarks for procedures for the analysis of, typically, the critical chemical properties of the fuels being combusted. 

Method 2 is likely to be most useful for fuels which exhibit some variability in key qualities, such as carbon content, from source to source.  This is the case for coal in Australia.     

Method 2 is based on technical guidelines that were used by reporters under the Generator Efficiency Standards program.  The possibility to report using this, higher order, approach is extended by the Determination from the electricity industry to all major consumers of fossil fuels. 

Method 3: generally a facility-specific method using Australian or international standards listed in the Determination or equivalent standards for both sampling and analysis of fuels and raw materials  

Method 3 is very similar to Method 2, except that it requires, additionally, Reporters to comply with Australian or international documentary standards for sampling (of fuels or raw materials) or equivalent as well as documentary standards for the analysis of fuels. 

Method 4: direct monitoring of emission systems, either on a continuous or periodic basis.  

Method 4 provides for a different approach to the estimation of emissions.  Rather than analysing the chemical properties of inputs (or in some case, products), Method 4 provides approaches to enable direct monitoring of greenhouse gas emissions arising from an activity.  This can provide a higher level of accuracy in certain circumstances, depending on the type of emission process although it is more data intensive than other approaches.  Such direct monitoring already occurs, for example, in underground coal mines reflecting the nature of the emission process and the importance of relatively accurate data to support health and safety objectives. 

As for Methods 2 and 3, there is a substantial body of documented procedures on monitoring practices and state and territory government regulatory experience that provide the principal sources of guidance for the establishment of such systems. 

It is intended that the Reporter may select different methods for each source.  For example, the Reporter may select different methods for different fuels and different methods for individual gases, subject to certain restrictions.  In part, these differences reflect Method availability.  For example, for solid fuels, only Method 1 has been provided for methane and nitrous oxide, reflecting the minor nature of the emission sources, whereas four methods are available for carbon dioxide.  

1.5  Overview—energy 

Methods for the estimation of the energy content of fuels produced and fuels consumed are addressed in Chapter 6.  Data collected for the estimation of emissions from fuel combustion as set out in Chapter 2 will serve a dual purpose as the data for the consumption of energy.  Separate collections are required, however, for the quantities of production of energy which, in general, do not enter directly into emission estimations. 

1.6  Overview—scope 2 emissions 

These Guidelines principally deal with Scope 1 emissions. These are direct emissions that arise on-site from the activities of a corporation.  There are a wide variety of emission sources that require a range of procedures to be described to cover the complexity of the emission pathways.    

Scope 2 emissions arise principally at an electricity generator, or through the loss of electricity from an electricity transmission network or distribution network, as a result of the purchase of electricity by a corporation.  The method for the estimation of scope 2 emissions is given in Chapter 7.  Scope 2 emission factors for the consumption of purchased electricity from Australia’s major electricity grids are updated annually to reflect the latest data on the mix of electricity generation sources, which is a major determinant of the factors. 

1.7  Overview—assessment of uncertainty 

Chapter 8 deals with the assessment of statistical uncertainty for scope 1 emissions estimates. It is recognised that these calculations of uncertainty can be complex and relatively imprecise.  A standardised approach to estimation of uncertainty of emissions estimates has been provided in Chapter 8.   

Proposed changes to the NGER Regulations will only require reporters with emissions of more than 25 kilotonnes of CO2-e from the combustion of a fuel type, or a source other than fuel combustion to calculate and report the statistical uncertainty associated with their scope 1 emissions. Sources are defined in section 1.10 of the Measurement Determination and fuel types are set out in Schedule 1 of the NGER Regulations. 

Division 1.1.2—Definitions and interpretation 

Definitions of key terms used in these Guidelines are to be found at Appendix B.  These definitions are drawn from both the Regulations and the Determination.  

Many of the estimation methods reference documentary standards developed by, inter alia, standards organisations.  Section 1.9 indicates that any standard, instrument or other writing must have been in force at 1 July 2012 to be applicable to an emissions estimation method.  This means that any standard or similar instrument released after 1 July 2012 is not able to be referenced in a higher-order method.  However, it is intended that the Determination will be reviewed at periodic intervals to consider recognition of such newly developed documentary standards.  

1.9  Interpretation 

(1) In this Determination, a reference to emissions is a reference to emissions of greenhouse gases. 

(2) In this Determination, a reference to a gas type (j) is a reference to a greenhouse gas. 

(3) In this Determination, a reference to a facility that is constituted by an activity is a reference to the facility being constituted in whole or in part by the activity. 

Note   Section 9 of the Act defines a facility as an activity or series of activities. 

(4) In this Determination, a reference to a standard, instrument or other writing (other than a Commonwealth Act or Regulations) however described, is a reference to that standard, instrument or other writing as in force on 1 July 2014. 

1.9A  Meaning of separate instance of a source 

  If 2 or more different activities of a facility have the same source of emissions, each activity is taken to be a separate instance of the source if the activity is performed by a class of equipment different from that used by another activity. 

Example: The combustion of liquefied petroleum gas in the engines of distribution vehicles of the facility operator and the combustion of liquid petroleum fuel in lawn mowers at the facility, although the activities have the same source of emissions, are taken to be a separate instance of the source as the activities are different and the class of equipment used to perform the activities are different. 

1.9B  Meaning of separate occurrence of a source 

(1) If 2 or more things at a facility have the same source of emissions, each thing may be treated as a separate occurrence of the source. 

Example: The combustion of unprocessed natural gas in 2 or more gas flares at a facility may be treated as a separate occurrence of the source (natural gas production or processing—flaring). 

(2) If a thing at a facility uses 2 or more energy types, each energy type may be treated as a separate occurrence of the source. 

Example: The combustion of diesel and petrol in a vehicle at a facility may be treated as a separate occurrence of the source (fuel combustion). 

1.10  Meaning of source 

Sources of emissions are based on those provided in the IPCC Guidelines for National Greenhouse Gas Inventories and are defined in the Determination. The categories of source are listed in the table below and also correspond to a chapter heading in the Determination while the source of emissions in column 3 relate to the divisions within the chapters. 

Item Category of source Source of emissions 

1 

Fuel combustion 

1A 

Fuel combustion 

2 

Fugitive emissions 

2A 

Underground mines 

2B 

Open cut mines  

2C 

Decommissioned underground mines 

2D 

Oil or gas exploration 

2E 

Crude oil production 

2F 

Crude oil transport 

2G 

Crude oil refining 

2H 

Natural gas production or processing (other than emissions that are vented or flared) 

2I 

Natural gas transmission 

2J 

Natural gas distribution 

2K 

Natural gas production or processing – flaring 

Item Category of source Source of emissions 

2L 

Natural gas production or processing – venting 

2M 

Carbon capture and storage 

3 

Industrial processes 

3A 

Cement clinker production 

3B 

Lime production 

3C 

Use of carbonates for the production of a product other than cement clinker, lime or soda ash 

3D 

Soda ash use 

3E 

Soda ash production 

3F 

Ammonia production 

3G 

Nitric acid production 

3H 

Adipic acid production 

3I 

Carbide production 

3J 

Chemical or mineral production, other than carbide production, using a carbon reductant and carbon anode 

3K 

Iron, steel or other metal production using an integrated metalworks 

3L 

Ferroalloys production 

3M 

Aluminium production  

3N 

Other metals production 

3O 

Emissions of hydrofluorocarbons and sulphur hexafluoride gases 

3P 

Sodium cyanide production 

4 

Waste 

4A 

Solid waste disposal on land 

4B 

Wastewater handling (industrial) 

4C 

Wastewater handling (domestic or commercial) 

4D 

Waste incineration 

Part 1.2—General 

1.11  Purpose of Part 

  This Part provides for general matters as follows: 

(a) Division 1.2.1 provides for the measurement of emissions and also deals with standards; 

(b) Division 1.2.2 provides for methods for measuring emissions. 

Division 1.2.1—Measurement and standards 

1.12  Measurement of emissions 

  The measurement of emissions released from the operation of a facility is to 

be done by estimating the emissions in accordance with this Determination. 

1.13 General principles for measuring emissions 

  Estimates for this Determination must be prepared in accordance with the following principles: 

(a) transparency—emission estimates must be documented and 

verifiable; 

(b) comparability—emission estimates using a particular method and produced by a registered corporation or liable entity in an industry sector must be comparable with emission estimates produced by similar corporations or entities in that industry sector using the same method and consistent with the emission estimates published by the Department in the National Greenhouse Accounts; 

(c) accuracy—having regard to the availability of reasonable resources 

by a registered corporation or liable entity and the requirements of this Determination, uncertainties in emission estimates must be minimised and any estimates must neither be over nor under 

estimates of the true values at a 95% confidence level; 

(d) completeness—all identifiable emission sources mentioned in section 1.10 must be accounted for. 

Time series consistency is also an important principle for measuring emissions. 

Chapter 5 of Volume 1 of the 2006 IPCC Guidelines for National Greenhouse Gas Inventories provides a detailed discussion of the issue. In short reporters should aim to estimate emissions in a time series consistently, which means that as far as possible, the time series should be calculated using a consistent method and data sources over time. Restrictions on the method to be used for a source, provided in Division 1.2.2, and the criteria for measurement, provided in Part 1.3, and Divisions 2.2.5, 2.3.6, 2.4.6 and 4.2.5, have been put in place to promote time series consistency. These principles are derived from those that apply to the preparation of national inventories.  

Note that there is a difference in meaning between the common usage of the word 

"confidence" and its statistical usage in relation to ‘95% confidence level’. For an explanation of ‘95% confidence level’ please refer to Chapter 8. 

1.14 Assessment of uncertainty 

  The estimate of emissions released from the operation of a facility must include assessment of uncertainty in accordance with Chapter 8.     

A standardised approach to estimation of uncertainty of emissions estimates has been provided in Chapter 8.   

Proposed changes to the NGER Regulations will only require reporters with emissions of more than 25 kilotonnes of CO2-e from the combustion of a fuel type, or a source other than fuel combustion to calculate and report the statistical uncertainty associated with their scope 1 emissions. Sources are defined in section 1.10 of the Measurement Determination and fuel types are set out in Schedule 1 of the NGER Regulations. 

1.15 Units of measurement 

Standard units of measurement are prescribed for the standard reportable items. 

Emissions of each greenhouse gas should be estimated and reported in tonnes of CO2-equivalent.  Conversion factors from tonnes of emissions of each greenhouse gas to tonnes of emissions of carbon dioxide equivalent for that gas are called Global Warming Potentials and are listed in the Regulations and reproduced in Appendix C. 

Emission estimation methods utilise standard units of measurement for solid, gaseous and liquid fuels, unless otherwise specified.  For gaseous fuels, the standard unit of measurement is cubic metres, although allowance is made for measurement in gigajoules if data is available in those units.   

The standard units for fuels should also be used for reporting.  For example, solid fuels should be reported in tonnes. 

(1) For this Determination, measurements of fuel must be converted as follows: 

(a) for solid fuel, to tonnes; and 

(b) for liquid fuels, to kilolitres unless otherwise specified; and 

(c) for gaseous fuels, to cubic metres, corrected to standard conditions, unless otherwise specified. 

(2) For this Determination, emissions of greenhouses gases must be estimated in CO2-e tonnes. 

(3) Measurements of energy content must be converted to gigajoules. 

(4) The National Measurement Act 1960, and any instrument made under that Act, must be used for conversions required under this section. 

1.16 Rounding of amounts 

(1) If: 

(a) an amount is worked out under this Determination; and 

(b) the number is not a whole number; 

then: 

(c) the number is to be rounded up to the next whole number if the number at the first decimal place equals or exceeds 5; and 

(d) rounded down to the next whole number if the number at the first decimal place is less than 5. 

(2) Subsection (1) applies to amounts that are measures of emissions or energy. 

1.17 Status of standards 

  If there is an inconsistency between this Determination and a documentary standard, this Determination prevails to the extent of the inconsistency. 

Division 1.2.2—Methods 

1.18  Method to be used for a separate occurrence of a source 

(1) This section deals with the number of methods that may be used to estimate emissions of a particular greenhouse gas released, in relation to a separate occurrence of a source, from the operation of a facility. 

  (1A) Subsections (2) and (3) do not apply to a facility if: 

(a) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611) and the generating unit used to perform the principal activity: 

(i) does not have the capacity to generate, in a reporting year, the amount of electricity mentioned in subparagraph 2.3(3)(b)(i); and 

(ii) generates, in a reporting year, less than or equal to the amount of electricity mentioned in subparagraph 2.3(3)(b)(ii); or 

(b) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611) and the generating unit used to perform the principal activity: 

(i) does not have the capacity to generate, in a reporting year, the amount of electricity mentioned in subparagraph 2.19(3)(b)(i); and 

(ii) generates, in a reporting year, less than or equal to the amount of electricity mentioned in subparagraph 2.19(3)(b)(ii). 

(2) Subject to subsection (3) and (3A), one method for the separate occurrence of a source must be used for 4 reporting years unless another higher method is used. 

(3) If: 

(a) at a particular time, a method is being used to estimate emissions in relation to the separate occurrence of a source; and 

(b) either: 

(i) in the preceding 4 reporting years before that time, only that method has been used to estimate the emissions from the separate occurrence of the source; or 

(ii) a registered corporation or liable entity certifies in writing that the method used was found to be non-compliant during an external audit of the separate occurrence of the source; then a lower method may be used to estimate emissions in relation to the separate occurrence of the source from that time. 

  (3A) If section 22AA of the Act applies to a person, a lower method may be used to estimate emissions in relation to the source for the purposes of reporting under section 22AA. 

(4) In this section, reporting year, in relation to a source from the operation of a facility under the operational control of a registered corporation and entities that are members of the corporation’s group, means a year that the registered corporation is required to provide a report under section 19 of the Act in relation to the facility 

(5) Higher method, is: 

(a) a prescribed alternative method; or 

(b) in relation to a method (the original method) being used to estimate emissions in relation to a separate occurrence of a source, a method for the source with a higher number than the number of the original method. 

(6) Lower method, is: 

(a) a default method; or 

(b) in relation to a method (the original method) being used to estimate 

emissions in relation to a separate occurrence of a source, a method for the source with a lower number than the number of the original method. 

1.18A  Conditions—persons preparing report must use same method 

(1) This section applies if a person is required, under section 19, 22A, 22AA, 22E, 22G or 22X of the Act (a reporting provision), to provide a report to the Regulator for a reporting year or part of a reporting year (the reporting period). 

(2) For paragraph 10(3)(c) of the Act: 

(a) the person must, before 31 August in the year immediately following the reporting year, notify any other person required, under a reporting provision, to provide a report to the Regulator for the same 

facility of the method the person will use in the report; and 

(b) each person required to provide a report to the Regulator for the same facility and for the same reporting period must, before 31 October in the year immediately following the reporting year, take all reasonable steps to agree on a method to be used for each report provided to the Regulator for the facility and for the reporting period. 

(3) If the persons mentioned in paragraph (2)(b) do not agree on a method 

before 31 October in the year immediately following the reporting year, 

each report provided to the Regulator for the facility and for the reporting period must use the method: 

(a) that was used in a report provided to the Regulator for the facility for the previous reporting year (if any); and 

(b) that will, of all the methods used in a report provided to the Regulator for the facility for the previous reporting year, result in a measurement of the largest amount of emissions for the facility for the reporting year. 

(4) In this section, a reference to a method is a reference to a method or available alternative method, including the options (if any) included in the method or available alternative method. 

Note 1: 

Reporting year has the meaning given by the Regulations. 

Note 2: 

An example of available alternative methods is method 2 in section 2.5 and method 2 in section 2.6. 

Note 3: 

An example of options included within a method is paragraphs 3.36(a) and (b), which provide 2 options of ways to measure the size of mine void volume. 

Note 4: 

An example of options included within an available alternative method is the options for identifying the value of the oxidation factor (OFs) in subsection 2.5(3). 

1.19  Temporary unavailability of method 

(1) The procedure set out in this section applies if, during a reporting year, a method for a separate occurrence of a source cannot be used because of a mechanical or technical failure of equipment or a failure of measurement systems during a period (the down time). 

(2) For each day or part of a day during the down time, the estimation of emissions from the separate occurrence of a sourcemust be consistent with the principles in section 1.13. 

(3) Subsection (2) only applies for a maximum of 6 weeks in a year. This period does not include down time taken for the calibration of the equipment. 

(4) If down time is more than 6 weeks in a year, the registered corporation or liable entity must inform the Regulator, in writing, of the following: 

(a) the reason why down time is more than 6 weeks;  (b) how the corporation or entity plans to minimise down time;  (c) how emissions have been estimated during the down time. 

(5) The information mentioned in subsection (4) must be given to the Regulator within 6 weeks after the day when down time exceeds 6 weeks in a year. 

(6) The Regulator may require a registered corporation or liable entity to use method 1 to estimate emissions during the down time if: 

(a) method 2, 3 or 4 has been used to estimate emissions for the separate occurrence of a source; and 

(b) down time is more than 6 weeks in a year. 

Division 1.2.3 Requirements in relation to carbon capture and storage 

The National Greenhouse and Energy Reporting Regulations currently require facilities involved in carbon capture and storage to report fugitive emissions from transport, injection and the storage site as well as the stock of carbon dioxide stored and the amount of carbon dioxide captured, imported and injected (see Regulation 4.12). 

This division sets out methods to support the requirements of the regulations for carbon capture and storage.  

This division defines the meaning of ‘captured for permanent storage’ and the requirements allowing facilities that capture carbon dioxide for permanent storage in an underground geological formation to deduct that amount of carbon dioxide in the emissions estimation process for that facility.  The storage must be permanent and is defined as such only if the carbon dioxide is transferred to an underground geological formation that is regulated under national or State legislation. 

Other requirements for carbon capture and storage (CCS) define how the deductions are to be attributed where there are multiple sources or fuels consumed and the measurement criteria to be applied for the carbon dioxide captured.  

Methods to estimate fugitive emissions from transport of the carbon dioxide for permanent storage can be found in Part 3.4.  

The scope of the amendments for CCS reflects the status of the regulatory framework as well as the technology available for permanent storage of carbon dioxide. The CCS regulatory framework is under development and is not yet comprehensive. 

The provisions for CCS should be considered to be a first step in the process of the development of a comprehensive provision for the treatment of carbon capture and storage in the NGER system. 

Division 1.2.3—Requirements in relation to carbon capture and storage 

1.19A  Meaning of captured for permanent storage 

  For this Determination, a greenhouse gas is captured for permanent storage only if it is captured by, or transferred to: 

(a) the registered holder of a greenhouse gas injection licence under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 for the purpose of being injected into an identified greenhouse gas storage formation under the licence in accordance with that Act; or 

(b) the holder of an injection and monitoring licence under the Greenhouse Gas Geological Sequestration Act 2008 (Vic) for the purpose of being injected into an underground geological formation under the licence in accordance with that Act; or 

(c) the registered holder of a greenhouse gas injection licence under the Offshore Petroleum and Greenhouse Gas Storage Act 2010 (Vic) for the purpose of being injected into an identified greenhouse gas storage formation under the licence in accordance with that Act; or 

(d) the holder of a GHG injection and storage lease under the Greenhouse Gas Storage Act 2009 (Qld) for the purpose of being injected into a GHG stream storage site under the lease in accordance with that Act; or 

(e) the holder of an approval under the Barrow Island Act 2003 (WA) 

for the purpose of being injected into an underground reservoir or 

other subsurface formation in accordance with that Act; or 

(f) the holder of a gas storage licence under the Petroleum and Geothermal Energy Act 2000 (SA) for the purpose of being injected into a natural reservoir under the licence in accordance with that Act. 

1.19B  Deducting greenhouse gas that is captured for permanent storage 

The amount of carbon dioxide captured for permanent storage may be deducted from the emissions estimate for the relevant source. Where method 4 is used to measure emissions from a facility a deduction for carbon dioxide captured for permanent storage is not required since emissions are measured directly under this method and do not include the carbon dioxide captured for permanent storage.  

In determining the amount of carbon dioxide that is captured for permanent storage it is considered good practice to measure the volume of the carbon dioxide stream and the concentration of carbon dioxide in the stream at the point of capture.  

(1)If a provision of this Determination provides that an amount of a greenhouse gas that is captured for permanent storage may be deducted in the estimation of emissions under the provision, then the amount of the greenhouse gas may be deducted only if: 

(a) the greenhouse gas that is captured for permanent storage is captured by, or transferred to, a relevant person; and 

(b) the amount of the greenhouse gas that is captured for permanent storage is estimated in accordance with section 1.19E; and 

(c) the relevant person issues a written certificate that complies with subsection (2). 

(2) The certificate must specify: 

(a) if the greenhouse gas is captured by the relevant person and is neither transferred to the relevant person nor transferred by the relevant person to another person—the following information: 

(i) the amount of the greenhouse gas, measured in CO2-e tonnes, captured by the relevant person; 

(ii) the volume of the greenhouse gas stream containing the captured greenhouse gas; 

(iii) the concentration of the greenhouse gas in the stream; or 

(b) if the greenhouse gas is transferred to the relevant person—the following information: 

(i) the amount of the greenhouse gas, measured in CO2-e tonnes, 

that was transferred to the relevant person; 

(ii) the volume of the greenhouse gas stream containing the transferred greenhouse gas; 

(iii) the concentration of the greenhouse gas in the stream. 

(3) The amount of the greenhouse gas that may be deducted is the amount specified in the certificate under paragraph (1)(c). 

1.19C  Capture from facility with multiple sources jointly generated 

  If, during the operation of a facility, more than 1 source generates a greenhouse gas, the total amount of the greenhouse gas that may be deducted in relation to the facility is to be attributed: 

(a) if it is possible to determine the amount of the greenhouse gas that is captured for permanent storage from each source—to each source 

from which the greenhouse gas is captured according to the amount captured from the source; or 

(b) if it is not possible to determine the amount of the greenhouse gas captured for permanent storage from each source—to the main source that generated the greenhouse gas that is captured during the operation of the facility. 

1.19D  Capture from a source where multiple fuels consumed 

  If more than 1 fuel is consumed for a source that generates a greenhouse gas that is captured for permanent storage, the total amount of the greenhouse gas that may be deducted in relation to the source is to be attributed to each fuel consumed in proportion to the carbon content of the fuel relative to the total carbon content of all fuel consumed for that source. 

1.19E  Measure of quantity of captured greenhouse gas 

(1) For paragraph 1.19B(1)(b), the amount of a greenhouse gas that is captured must be estimated in accordance with this section. 

(2) The volume of the greenhouse gas stream containing the captured greenhouse gas must be estimated: 

(a) if the greenhouse gas stream is transferred to a relevant person— using: 

(i) criterion A in section 1.19F; or 

(ii) criterion AAA in section 1.19G; or 

(b) if the greenhouse gas stream is captured by the relevant person and is neither transferred to the relevant person nor transferred by the relevant person to another person—using: 

(i) criterion AAA in section 1.19G; or  (ii) criterion BBB in section 1.19GA. 

(3) The greenhouse gas stream must be sampled in accordance with ISO 10715:1997, or an equivalent standard. 

(4) The concentration of the greenhouse gas in the greenhouse gas stream must be analysed in accordance with the following parts of ISO 6974 or an equivalent standard: 

(a) Part 1 (2000); 

(b) Part 2 (2001); 

(c) Part 3 (2000); 

(d) Part 4 (2000); 

(e) Part 5 (2000); 

(f) Part 6 (2002). 

(5) The volume of the greenhouse gas stream must be expressed in cubic metres. 

(6) The greenhouse gas stream must be analysed for the concentration of the greenhouse gas on at least a monthly basis. 

1.19F  Volume of greenhouse gas stream—criterion A 

(1) For subparagraph 1.19E(2)(a)(i), criterion A is the volume of the greenhouse gas stream that is: 

(a) transferred to the relevant person during the year; and 

(b) specified in a certificate issued by the relevant person under paragraph 1.19B(1)(c). 

(2) The volume specified in the certificate must be accurate and must be evidenced by invoices issued by the relevant person. 

1.19G  Volume of greenhouse gas stream—criterion AAA 

(1) For subparagraphs 1.19E(2)(a)(ii) and (b)(i), criterion AAA is the measurement during the year of the captured greenhouse gas stream from the operation of a facility at the point of capture. 

(2) In measuring the quantity of the greenhouse gas stream at the point of capture, the quantity of the greenhouse gas stream must be measured: 

(a) using volumetric measurement in accordance with: 

(i) for a compressed greenhouse gas stream—section 1.19H; and 

(ii) for a super-compressed greenhouse gas stream—section 1.19I; and 

(b) using gas measuring equipment that complies with section 1.19J. 

(3) The measurement must be carried out using measuring equipment that: 

(a) is in a category specified in column 2 of an item in the table in 

subsection (4) according to the maximum daily quantity of the greenhouse gas stream captured specified in column 3 for that item from the operation of the facility; and 

(b) complies with the transmitter and accuracy requirements for that equipment specified in column 4 for that item, if the requirements are applicable to the measuring equipment being used. 

(4) For subsection (3), the table is as follows. 

Item 

Gas measuring equipment category 

Maximum daily quantity of greenhouse gas stream  (cubic metres/day) 

Transmitter and accuracy requirements (% of range) 

1 

1 

0–50 000 

Pressure <±0.25% 

Diff. pressure <±0.25% 

Temperature <±0.50%  

2 

2 

50 001–100 000 

Pressure <±0.25% 

Diff. pressure <±0.25% 

Temperature <±0.50% 

3 

3 

100 001–500 000 

Smart transmitters: 

Pressure <±0.10% 

Diff. pressure <±0.10% 

Temperature <±0.25% 

4 

4 

500 001 or more 

Smart transmitters: 

Pressure <±0.10% 

Diff. pressure <±0.10% 

Temperature <±0.25% 

1.19GA  Volume of greenhouse gas stream—criterion BBB 

  For subparagraph 1.19E(2)(b)(ii), criterion BBB is the estimation of the volume of the captured greenhouse gas stream from the operation of the facility during a year measured in accordance with industry practice, if the equipment used to measure the volume of the captured greenhouse gas stream does not meet the requirements of criterion AAA. 

Note: An estimate obtained using industry practice must be considered with the principles in section 1.13. 

1.19H  Volumetric measurement—compressed greenhouse gas stream 

(1) For subparagraph 1.19G(2)(a)(i), volumetric measurement of a compressed greenhouse gas stream must be in cubic metres at standard conditions. 

  (1A) For this section and subparagraph 1.19G(2)(a)(i), a compressed 

greenhouse gas stream does not include either of the following: 

(a) a super-compressed greenhouse gas stream; 

(b) a greenhouse gas stream that is compressed to a super-critical state. 

(2) The volumetric measurement is to be calculated using a flow computer that measures and analyses flow signals and relative density: 

(a) if the greenhouse gas stream is captured by the relevant person and is neither transferred to the relevant person nor transferred by the relevant person to another person—at the point of capture of the greenhouse gas stream; or 

(b) if the greenhouse gas stream is transferred to a relevant person—at the point of transfer of the greenhouse gas stream. 

(3) The volumetric flow rate must be continuously recorded and integrated using an integration device that is isolated from the flow computer in such a way that if the computer fails, the integration device will retain the last reading, or the previously stored information, that was on the computer immediately before the failure. 

(4) Subject to subsection (5), all measurements, calculations and procedures used in determining volume (except for any correction for deviation from the ideal gas law) must be made in accordance with the instructions contained in the following: 

(a) for orifice plate measuring systems: 

(i) the publication entitled AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 3: 

Natural Gas Applications, published by the American Gas Association in August 1992; or 

(ii) Parts 1 to 4 of the publication entitled ANSI/API MPMS Chapter 14.3 Part 2 (R2011) Natural Gas Fluids Measurement: 

Concentric, Square-Edged Orifice Meters - Part 2: Specification and Installation Requirements, 4th edition, published by the American Petroleum Institute on 30 April 2000; 

(b) for turbine measuring systems—the publication entitled AGA Report No. 7, Measurement of Natural Gas by Turbine Meter (2006), published by the American Gas Association on 1 January 2006; 

(c) for positive displacement measuring systems—the publication entitled ANSI B109.3—2000, Rotary Type Gas Displacement Meters, published by the American Gas Association on 13 April 2000. 

(5) Measurements, calculations and procedures used in determining volume may also be made in accordance with an equivalent internationally recognised documentary standard or code. 

(6) Measurements must comply with Australian legal units of measurement. 

1.19I  Volumetric measurement—super-compressed greenhouse gas stream 

(1) For subparagraph 1.19G(2)(a)(ii), volumetric measurement of a super-compressed greenhouse gas stream must be in accordance with this section. 

(2) If, in determining volume in relation to the super-compressed greenhouse gas stream, it is necessary to correct for deviation from the ideal gas law, the correction must be determined using the relevant method contained in the publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994. 

(3) The measuring equipment used must calculate super-compressibility by: 

(a) if the measuring equipment is category 3 or 4 equipment in accordance with column 2 the table in subsection 1.19G(4)—using composition data; or 

(b) if the measuring equipment is category 1 or 2 equipment in accordance with column 2 of the table in subsection 1.19G(4)— using an alternative method set out in the publication entitled AGA 

Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994. 

1.19J  Gas measuring equipment—requirements 

  For paragraph 1.19G(2)(b), gas measuring equipment that is category 3 or 

4 equipment in accordance with column 2 of the table in subsection 1.19G(4) must comply with the following requirements: 

(a) if the equipment uses flow devices—the requirements relating to flow devices set out in section 1.19K; 

(b) if the equipment uses flow computers—the requirement relating to flow computers set out in section 1.19L; 

(c) if the equipment uses gas chromatographs—the requirements relating to gas chromatographs set out in section 1.19M. 

1.19K  Flow devices—requirements  

(1) If the measuring equipment has flow devices that use orifice measuring systems, the flow devices must be constructed in a manner that ensures that the maximum uncertainty of the discharge coefficient is not greater than ±1.5%. 

Note: The publication entitled AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 3: Natural Gas Applications, published by the American Gas Association in August 1992, sets out a manner that ensures that the maximum uncertainty of the discharge coefficient is not greater than ±1.5%. 

(2) If the measuring equipment has flow devices that use turbine measuring systems, the flow devices must be installed in a manner that ensures that the maximum uncertainty of the flow measurement is not greater than ±1.5%. 

Note: The publication entitled AGA Report No. 8, Compressibility Factor of Natural 

Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994, sets out a manner that ensures that the maximum uncertainty of the flow measurement is not greater than ±1.5%. 

(3) If the measuring equipment has flow devices that use positive displacement measuring systems, the flow devices must be installed in a manner that ensures that the maximum uncertainty of flow is ±1.5%. 

Note: The publication entitled ANSI B109.3—2000, Rotary Type Gas Displacement Meters, published by the American Gas Association on 13 April 2000, sets out a manner for installation that ensures that the maximum uncertainty of flow is ±1.5%. 

(4) If the measuring equipment uses any other type of flow device, the maximum uncertainty of flow measurement must not be greater than ±1.5%. 

(5) All flow devices that are used by measuring equipment of a category specified in column 2 of the table in subsection 1.19G(4) must, wherever possible, be calibrated for pressure, differential pressure and temperature in accordance with the requirements specified in column 4 for the category of equipment specified in column 2 for that item. The calibrations must take into account the effects of static pressure and ambient temperature. 

1.19L  Flow computers—requirements 

  For paragraph 1.19J(b), the requirement is that the flow computer that is used by the equipment for measuring purposes must record the instantaneous values for all primary measurement inputs and must also record the following outputs: 

(a) instantaneous corrected volumetric flow; 

(b) cumulative corrected volumetric flow; 

(c) for turbine and positive displacement metering systems— instantaneous uncorrected volumetric flow; 

(d) for turbine and positive displacement metering systems—cumulative uncorrected volumetric flow;  (e) super-compressibility factor. 

1.19M  Gas chromatographs 

  For paragraph 1.19J(c), the requirements are that gas chromatographs used by the measuring equipment must: 

(a) be factory tested and calibrated using a measurement standard produced by gravimetric methods and traceable to Australian legal units of measurement; and 

(b) perform gas composition analysis with an accuracy of ±0.25% for calculation of relative density; and 

(c) include a mechanism for re-calibration against a certified reference gas.

Part 1.3—Method 4—Direct measurement of emissions 

Division 1.3.1—Preliminary 

1.20  Overview 

Method 4 provides for direct measurement of emissions of greenhouse gases.  Such measurement systems can be established, for example, in flues, stacks, pipes or ducts and may be applicable in a number of industries, although not all.  

Method 4 establishes a framework for the design, installation, performance and maintenance of direct emissions measurement systems for stationary emission sources and a guide to measurement, recording, and standardised reporting for estimating greenhouse gas emissions.  

Two systems for direct emissions monitoring are available including:  

(a) Continuous emissions monitoring (CEM); 

(b) Periodic emissions monitoring (PEM). 

The use of Method 4 by corporations will likely depend on a number of factors including the type of emissions process, the structures of the facility and any current direct measurement systems that corporations may have in place for measuring pollutants for other purposes. 

The general framework for Method 4 draws on the following publications: 

• U.S. Environmental Protection Agency. 2003. Code of Federal Regulations: Standards of Performance for New Stationary Sources. Appendix A – Test Methods. 40 CFR 60 Appendix A. Washington, D.C. These methods can be obtained from: http://www.epa.gov/ttn/emc/promgate.html 

• The Commission of the European Communities, Commission Decision establishing guidelines for the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and 

of the Council. Brussels, 2006. This document can be obtained from: http://ec.europa.eu/index_en.htm 

• The Environmental Protection Agency, Load Calculation Protocol for use by holders of NSW environment protection licenses when calculating assessable pollutant loads. Department of Environment and Conservation (NSW), February 2005. This document can be obtained from: http://www.environment.nsw.gov.au/licensing/lblprotocol/ 

• Department of Environment and Heritage, National Pollutant Inventory – Emission Estimation Manual for Fossil Fuel Electric Power Generation, Version 2.4, March 2005. This document can be obtained from: http://www.npi.gov.au/ 

• West Australian Department of Environment and Conservation, Department of Environment and Conservation Continuous Emissions Monitoring System (CEMS) Code for Stationary Source Air Emissions, October 2006. This document can be obtained from http://www.dec.wa.gov.au/ 

(1) This Chapter provides for method 4 for a source. 

Note: Method 4 as provided for in this Part applies to a source as indicated in the Chapter, Part, Division or Subdivision dealing with the source. 

(2) Method 4 requires the direct measurement of emissions released from the source from the operation of a facility during a year by monitoring the gas stream at a site within part of the area (for example, a duct or stack) occupied for the operation of the facility. 

(3) Method 4 consists of the following: 

(a) method 4 (CEM) as specified in section 1.21 that requires the measurement of emissions using continuous emissions monitoring (CEM); 

(b) method 4 (PEM) as specified in section 1.27 that requires the measurement of emissions using periodic emissions monitoring (PEM). 

Division 1.3.2—Operation of method 4 (CEM) 

Continuous Emissions Monitoring (CEM) systems are designed to monitor real-time occurrence of emissions. The aim of the CEM method is to provide the framework for calculating emissions and also to provide standards for the location of sampling positions, measurement of flow rates and gas concentrations and the frequency of measurements. 

Subdivision 1.3.2.1—Method 4 (CEM) 

1.21  Method 4 (CEM)—estimation of emissions 

CEM systems may record emissions automatically via a computer or it may be necessary for emissions to be calculated manually. The equation in 1.21 (1) provides a method to be used to calculate emissions manually from direct emissions monitoring under CEM systems. The equation uses the data gathered from flow rate and gas analyser equipment to calculate mass emissions.  

In order to convert volumetric flow rates to mass flow rates accurately, direct measurement also requires the measurement of temperature and pressure to reduce the amount of error that is associated with the variability of density factors used to convert from volume of a gas to the mass of a gas. The equation in 1.21 (1) is cited from the report:  

 Mark, M., Worrall, R., Mallett, C., and Xue, S. (2001). Measuring and Reporting Greenhouse Gas Emissions. ACARP Project C8061. CSIRO Exploration and Mining Report 805C.  

This report can be obtained from: http://www.acarp.com.au/reports.aspx. 

(1)To obtain an estimate of the mass of emissions of a gas type (j), being methane, carbon dioxide or nitrous oxide, released at the time of measurement at a monitoring site within the area occupied for the operation of a facility, the following formula must be applied: 

MM ×P ×FR ×Cj ct ct

Mjct = jct

  8.314Tct  

where: 

Mjct is the mass of emissions in tonnes of gas type (j) released per second. 

MMj is the molecular mass of gas type (j) measured in tonnes per kilomole which: 

(a) for methane is 16.04 10-3; or 

(b) for carbon dioxide is 44.01 10-3; or  (c) for nitrous oxide is 44.01 10-3. 

Pct is the pressure of the gas stream in kilopascals at the time of measurement. 

FRct is the flow rate of the gas stream in cubic metres per second at the time of measurement. 

Cjct is the proportion of gas type (j) in the volume of the gas stream at the time of measurement. 

Tct is the temperature, in degrees kelvin, of the gas at the time of measurement. 

(2) The mass of emissions estimated under subsection (1) must be converted into CO2-e tonnes. 

(3) Data on estimates of the mass emissions rates obtained under subsection (1) during an hour must be converted into a representative and unbiased estimate of mass emissions for that hour. 

(4) The estimate of emissions of gas type (j) during a year is the sum of the estimates for each hour of the year worked out under subsection (3). 

(5) If method 1 is available for the source, the total mass of emissions for a gas from the source for the year calculated under this section must be reconciled against an estimate for that gas from the facility for the same period calculated using method 1 for that source. 

Example: Continuous emissions monitoring of CH4 from fugitive emissions associated with underground coal mining. 

Step 1. Calculate the emission rate for each measurement period using the equation in section 1.21.  

Measurement 

(time) 

MMct 

(CO2 tonnes per 

kilomole) 

Pct (kPa) 

FRct 

(M3/sec) 

Cjct 

(v/v) 

Gas constant 

Tct 

(degrees Kelvin) 

Emission rate 

(CH4 tonnes per sec)  

Emission rate 

(CO2-e tonnes per sec) 

a 

b 

c 

d 

e 

f 

g 

H 

1.00PM 

0.01604 

101.300 

300 

0.009 

8.314 

295.0 

1.79E-03 

4.47E-02 

1.15PM 

0.01604 

101.320 

310 

0.012 

8.314 

295.5 

2.46E-03 

6.15E-02 

1.30PM 

0.01604 

101.315 

307 

0.011 

8.314 

295.4 

2.23E-03 

5.59E-02 

1.45PM 

0.01604 

101.315 

305 

0.010 

8.314 

295.1 

2.02E-03 

5.05E-02 

2.00PM 

0.01604 

101.310 

303 

0.010 

8.314 

295.2 

2.01E-03 

5.02E-02 

2.15PM 

0.01604 

101.315 

304 

0.011 

8.314 

295.3 

2.21E-03 

5.53E-02 

2.30PM 

0.01604 

101.320 

308 

0.011 

8.314 

295.3 

2.24E-03 

5.61E-02 

2.45PM 

0.01604 

101.320 

311 

0.012 

8.314 

295.4 

2.47E-03 

6.17E-02 

Step 2. Calculate the average emissions rate for an hour by summing the emission estimates in column h of the table and divide by the number of sample periods for the hour: 

Average emission rate for the first hour (1.00PM to 2.00PM) 

= (4.47E-02+6.15E-02+5.59E-02+5.05E-02)/4 

= 5.32E-02 CO2-e tonnes per second 

Average emission rate for the second hour (2.00PM to 3.00PM) 

= (5.02E-02+5.53E-02+5.61E-02+6.17E-02)/4 

= 4.69E-02 CO2-e tonnes per second 

Step 3. The mass emissions for the hour is then calculated by multiplying the average emission rate for the hour in step 1 by the number of seconds in an hour, which is 3600.  

Therefore: 

Emissions for the first hour = 5.32E-02 x 3600 

191.3 tonnes CO2-e for the hour 

Emissions for the second hour = 5.58E-02 x 3600 

201.0 tonnes CO2-e for the hour 

To aggregate emissions for a period, the hourly emissions estimates are summed together.  For example, total emissions between 1.00 and 3.00pm in the above example is calculated by adding together 191.3 and 201.0 tonnes of CO2-e which equals 392.3 tonnes of CO2-e. 

1.21A  Emissions from a source where multiple fuels consumed 

  If more than one fuel is consumed for a source that generates carbon dioxide that is directly measured using method 4 (CEM), the total amount of carbon dioxide is to be attributed to each fuel consumed in proportion to the carbon content of the fuel relative to the total carbon content of all fuel consumed for that source. 

Example: Attributing CO2 emissions from fuel combustion measured using method 4 where diesel oil and natural gas is consumed 

A facility combusts 5,000 kilolitres of diesel oil and 1,800,000 GJ of natural gas in a gas turbine during the reporting year.  

The facility elects to use continuous emissions monitoring (CEM) under Method 4 to estimate emissions of carbon dioxide. The reporter estimates a total of 104,852 tonnes CO2 from this source using continuous emissions monitoring (CEM) during the year. 

In order to attribute these emissions to each fuel the carbon content of the two fuels are estimated using the default carbon content factors published in Schedule 3 of the NGER (Measurement) Determination. 

CO2 emissions attributed to fuel x = total CEM emission estimate * carbon content of fuel x/ carbon content of all fuels 

Carbon content of diesel oil = 5,000 kL * 0.736 t C/kL = 3,680 t C 

Carbon content of natural gas = 1,800,000 GJ * 0.014 t C/GJ = 25,200 t C 

CO2 emissions attributed to diesel oil = total CEM emission estimate * carbon content of diesel oil/ (carbon content of diesel oil+ carbon content of natural gas) 

Emissions attributed to diesel oil = 104852 t  CO2 * 3,680 t C/ 28,880 t C = 13,361 t CO2 

Emissions attributed to natural gas = total CEM emission estimate * carbon content of natural gas/ (carbon content of diesel oil+ carbon content of natural gas) 

Emissions attributed to natural gas = 104852 t CO2 * 25,200 t C/ 28,880 t C = 91,491 t CO2 

Subdivision 1.3.2.2—Method 4 (CEM)—use of equipment 

1.22  Overview 

  The following apply to the use of equipment for CEM: 

(a) the requirements in section 1.23 about location of the sampling positions for the CEM equipment;  

(b) the requirements in section 1.24 about measurement of volumetric flow rates in the gas stream;  

(c) the requirements in section 1.25 about measurement of the concentrations of greenhouse gas in the gas stream;  

(d) the requirements in section 1.26 about frequency of measurement.  

CEM systems have a number of specific requirements, including the location of sampling positions, measuring flow rates and gas concentrations and the frequency of measurement. These specific components of CEM systems are founded on internationally recognised standards or methods. The organisations that have been cited include: 

• Standards Australia (AS) 

• International Organization for Standardization (ISO) 

• United States Environmental Protection Agency (US EPA) 

A detailed list of the standards cited and how to obtain them can be found in Appendix D. 

1.23  Selection of sampling positions for CEM equipment 

  For paragraph 1.22(a), the location of sampling positions for the CEM equipment in relation to the gas stream must be selected in accordance with an appropriate standard.  

Note: Appropriate standards include: 

• AS 4323.1—1995 Stationary source emissions - Selection of sampling positions. 

• AS 4323[1].1—1995 Amdt 1-1995 Stationary source emissions - Selection of sampling positions. 

• ISO 10396:2007 Stationary source emissions - Sampling for the automated determination of gas emission concentrations for permanently-installed monitoring systems. 

• ISO 10012:2003 Measurement management systems - Requirements for measurement processes and measuring equipment. 

• USEPA – Method 1 – Sample and Velocity Traverses for Stationary Sources (2000). 

1.24  Measurement of flow rates by CEM 

  For paragraph 1.22(b), the measurement of the volumetric flow rates by CEM of the gas stream must be undertaken in accordance with an appropriate standard.  

Note: Appropriate standards include: 

• ISO 10780:1994 Stationary source emissions—Measurement of velocity and volume flowrate of gas streams in ducts. 

• ISO 14164:1999 Stationary source emissions—Determination of the volume flowrate of gas streams in ducts - Automated method. 

• USEPA Method 2 Determination of Stack Gas Velocity and Volumetric flowrate (Type S Pitot tube) (2000). 

• USEPA Method 2A Direct Measurement of Gas Volume Through Pipes and Small Ducts (2000). 

1.25  Measurement of gas concentrations by CEM 

  For paragraph 1.22(c), the measurement of the concentrations of gas in the gas stream by CEM must be undertaken in accordance with an appropriate standard.  

Note: Appropriate standards include: 

• USEPA Method 3A Determination of oxygen and carbon dioxide concentrations in emissions from stationary sources (instrumental analyzer procedure) (2006). 

• USEPA Method 3C Determination of carbon dioxide, methane, nitrogen, and oxygen from stationary sources (1996). 

• ISO 12039:2001 Stationary source emissions—Determination of carbon monoxide, carbon dioxide and oxygen—Performance characteristics and calibration of automated measuring system. 

1.26  Frequency of measurement by CEM 

(1) For paragraph 1.22(d), measurements by CEM must be taken frequently enough to produce data that is representative and unbiased. 

(2) For subsection (1), if part of the CEM equipment is not operating for a period, readings taken during periods when the equipment was operating may be used to estimate data on a pro rata basis for the period that the equipment was not operating. 

(3) Frequency of measurement will also be affected by the nature of the equipment. 

Example: If the equipment is designed to measure only one substance, for example, carbon dioxide or methane, measurements might be made every minute. However, if the equipment is designed to measure different substances in alternate time periods, measurements might be made much less frequently, for example, every 15 minutes. 

(4) The CEM equipment must operate for more than 90% of the period for which it is used to monitor an emission. 

(5) In working out the period during which CEM equipment is being used to monitor for the purposes of subsection (4), exclude downtime taken for the calibration of equipment.

Division 1.3.3—Operation of method 4 (PEM) 

Subdivision 1.3.3.1—Method 4 (PEM) 

Whereas CEM systems are designed to measure real-time emissions estimates, Periodic Emissions Monitoring (PEM) systems are designed to measure emissions at periodic intervals (e.g. daily, weekly, monthly measurements) over a specified period. The equations for calculating emissions from flow rate and gas concentration data is closely related to that of the CEM approach, however the frequency of measurement and operational time of PEM is less than for CEM.  

1.27  Method 4 (PEM)—estimation of emissions 

(1) To obtain an estimate of the mass emissions rate of methane, carbon dioxide or nitrous oxide released at the time of measurement at a monitoring site within the area occupied for the operation of a facility, the formula in subsection 1.21(1) must be applied. 

(2) The mass of emissions estimated under the formula must be converted into CO2-e tonnes. 

(3) The average mass emissions rate for the gas measured in CO2-e tonnes per hour for a year must be calculated from the estimates obtained under subsection (1). 

(4) The total mass of emissions of the gas for the year is calculated by multiplying the average emissions rate obtained under subsection (3) by the number of hours during the year when the site was operating. 

(5) If method 1 is available for the source, the total mass of emissions of the gas for a year calculated under this section must be reconciled against an estimate for that gas from the site for the same period calculated using method 1 for that source. 

Example: Periodic (e.g. monthly sampling regime) emissions monitoring of CH4 from fugitive emissions associated with underground coal mining 

Measurement 

(time) 

MMct  

(CO2 tonnes per 

kilomole) 

Pct  

(kPa) 

FRct 

(M3/sec) 

Cjct 

(v/v) 

Gas constant 

Tct 

(degrees 

Kelvin)  

Emission estimate 

(CH4 tonnes per sec)  

Emission estimate 

(CO2-e tonnes per sec) 

a 

b 

c 

d 

e 

f 

g 

H 

January 

0.01604 

101.320 

270 

0.009 

8.314 

296.0 

1.60E-03 

4.01E-02 

February 

0.01604 

101.290 

255 

0.008 

8.314 

295.6 

1.35E-03 

3.37E-02 

March 

0.01604 

101.280 

260 

0.009 

8.314 

295.4 

1.55E-03 

3.87E-02 

April 

0.01604 

101.350 

275 

0.009 

8.314 

295.1 

1.64E-03 

4.10E-02 

May 

0.01604 

101.400 

280 

0.010 

8.314 

295.5 

1.85E-03 

4.63E-02 

June 

0.01604 

101.320 

265 

0.008 

8.314 

294.3 

1.41E-03 

3.52E-02 

July 

0.01604 

101.260 

260 

0.008 

8.314 

294.0 

1.38E-03 

3.46E-02 

August 

0.01604 

101.400 

285 

0.011 

8.314 

294.4 

2.08E-03 

5.21E-02 

September 

0.01604 

101.500 

295 

0.012 

8.314 

295.5 

2.35E-03 

5.86E-02 

October 

0.01604 

101.330 

270 

0.009 

8.314 

295.6 

1.61E-03 

4.02E-02 

November 

0.01604 

101.450 

290 

0.013 

8.314 

296.2 

2.49E-03 

6.23E-02 

December 

0.01604 

101.280 

255 

0.007 

8.314 

296.5 

1.18E-03 

2.94E-02 

To obtain the annual emission estimate the following steps are then taken. 

Step 1. Calculate the average emissions rate for the year by summing the monthly emission rate estimates in column h of table 1 and divide by the number of sample periods: 

= (4.01E-02 + 3.37E-02 + 3.87E-02 + 4.10E-02 + 4.63E-02 + 3.52E-02 + 3.46E-02 + 5.21E-02 + 5.86E02 + 4.02E-02 + 6.23E-02 + 2.94E-02)/12 

= 4.27E-02 CO2-e tonnes per second 

Step 2. The emissions for the year are calculated by multiplying the average emission rate for the year in step 1 by the number of seconds in a year, which is 31,536,000. Therefore: 

Emissions for the year = 4.27E-02 x 31,536,000    

                               = 1,346,062 tonnes CO2-e   

1.27A  Emissions from a source where multiple fuels consumed 

  If more than one fuel is consumed for a source that generates carbon dioxide that is directly measured using method 4 (PEM), the total amount of carbon dioxide is to be attributed to each fuel consumed in proportion to the carbon content of the fuel relative to the total carbon content of all fuel consumed for that source. 

Example: Attributing CO2 emissions from fuel combustion measured using method 4 where diesel oil and natural gas is consumed 

A facility combusts 5,000 kilolitres of diesel oil and 1,800,000 GJ of natural gas in a gas turbine during the reporting year.  

The facility elects to use periodic emissions monitoring (PEM) under Method 4 to estimate emissions of carbon dioxide. The reporter estimates a total of 104,852 tonnes CO2 from this source during the year. 

In order to attribute these emissions to each the carbon content of the two fuels are estimated using the default carbon content factors published in schedule 3 of the NGER (Measurement) Determination. 

CO2 emissions attributed to fuel x = total PEM emission estimate * carbon content of fuel x/ carbon content of all fuels 

Where carbon content of diesel oil = 5,000 kL * 0.736 t C/kL = 3,680 t C 

Where carbon content of natural gas = 1,800,000 GJ * 0.014 t C/GJ = 25,200 t C 

Emissions attributed to diesel oil = total PEM emission estimate * carbon content of diesel oil/ 

(carbon content of diesel oil+ carbon content of natural gas) 

Emissions attributed to diesel oil = 104,852t CO2 * 3,680 t C/ 28,880 t C = 13,361t CO2 

Emissions attributed to natural gas = total PEM emission estimate * carbon content of natural gas/ 

(carbon content of diesel oil+ carbon content of natural gas) 

Emissions attributed to natural gas = 104,852t CO2 * 25,200 t C/ 28,880 t C = 91,491t CO2 

1.28  Calculation of emission factors 

PEM data calculated in Method 4 can be used to calculate emission factors for use in Method 2 by dividing the emissions estimated from a PEM system by the amount of fuel combusted or raw material produced during the year.   

(1) Data obtained from periodic emissions monitoring of a gas stream may be used to estimate the average emission factor for the gas per unit of fuel consumed or material produced. 

(2) In this section, data means data about: 

(a) volumetric flow rates estimated in accordance with section 1.31; or 

(b) gas concentrations estimated in accordance with section 1.32; or 

(c) consumption of fuel or material input, estimated in accordance with Chapters 2 to 7; or 

(d) material produced, estimated in accordance with Chapters 2 to 7. 

Example 

If the annual methane emissions from an underground coal mine was 1,130,729 tonnes CO2-e and 2,500,000 tonnes of Run-of-mine (ROM) coal was extracted from the mine, the emission factor would be: 

EF = 1 130 729 tonnes CO2-e / 2 500 000 tonnes ROM coal 

EF = 0.45 tonnes CO2-e / tonne ROM coal 

The calculation of emission factors may apply to a number of industries including electricity generation and production of industrial products (e.g. nitric acid). 

Subdivision 1.3.3.2—Method 4 (PEM)—use of equipment 

1.29  Overview 

PEM systems have a number of specific requirements, including the location of sampling positions, measuring flow rates and gas concentrations and the frequency of measurement. These specific components of PEM systems are founded on internationally recognised standards or methods. The organisations that have been cited include: 

• Standards Australia (AS) 

• International Organization for Standardization (ISO) 

• United States Environmental Protection Agency (US EPA) 

A detailed list of the standards cited and how to obtain them can be found in Appendix D. 

  The following requirements apply to the use of equipment for PEM: 

(a) the requirements in section 1.30 about location of the sampling positions for the PEM equipment;  

(b) the requirements in section 1.31 about measurement of volumetric flow rates in a gas stream; 

(c) the requirements in section 1.32 about measurement of the concentrations of greenhouse gas in the gas stream;  

(d) the requirements in section 1.33 about representative data. 

1.30  Selection of sampling positions for PEM equipment 

  For paragraph 1.29(a), the location of sampling positions for PEM equipment must be selected in accordance with an appropriate standard.  

Note: Appropriate standards include: 

• AS 4323.1—1995 Stationary source emissions—Selection of sampling positions. 

• AS 4323.1-1995 Amdt 1-1995 Stationary source emissions—Selection of sampling positions. 

• ISO 10396:2007 Stationary source emissions—Sampling for the automated determination of gas emission concentrations for permanently-installed monitoring systems. 

• ISO 10012:2003 Measurement management systems—Requirements for measurement processes and measuring equipment. 

• USEPA Method 1 Sample and Velocity Traverses for Stationary Sources (2000). 

1.31  Measurement of flow rates by PEM equipment 

  For paragraph 1.29(b), the measurement of the volumetric flow rates by PEM of the gas stream must be undertaken in accordance with an appropriate standard.  

Note: Appropriate standards include: 

• ISO 10780:1994 Stationary source emissions – Measurement of velocity and volume flowrate of gas streams in ducts. 

• ISO 14164:1999 Stationary source emissions. Determination of the volume flow rate of gas streams in ducts – automated method. 

• USEPA Method 2 Determination of stack velocity and volumetric flow rate (Type S Pitot tube) (2000). 

• USEPA Method 2A Direct measurement of gas volume through pipes and small ducts (2000). 

1.32  Measurement of gas concentrations by PEM 

  For paragraph 1.29(c), the measurement of the concentrations of greenhouse gas in the gas stream by PEM must be undertaken in accordance with an appropriate standard.  

Note: Appropriate standards include: 

• USEPA Method 3A Determination of oxygen and carbon dioxide concentrations in emissions from stationary sources (instrumental analyser procedure) (2006). 

• USEPA Method 3C Determination of carbon dioxide, methane, nitrogen, and oxygen from stationary sources (1996). 

• ISO12039:2001 Stationary source emissions – Determination of carbon monoxide, carbon dioxide and oxygen – Performance characteristics and calibration of an automated measuring method. 

1.33  Representative data for PEM 

(1) For paragraph 1.29(d), sampling by PEM must be undertaken during the 

year for a sufficient duration to produce representative data that may be reliably extrapolated to provide estimates of emissions across the full range of operating conditions for that year. 

(2) Emission estimates using PEM equipment must also be consistent with the principles in section 1.13. 

Division 1.3.4—Performance characteristics of equipment 

1.34  Performance characteristics of CEM or PEM equipment 

(1) The performance characteristics of CEM or PEM equipment must be measured in accordance with this section. 

(2) The test procedure specified in an appropriate standard must be used for measuring the performance characteristics of CEM or PEM equipment. 

(3) For the calibration of CEM or PEM equipment, the test procedure must be: 

(a) undertaken by an accredited laboratory; or 

(b) undertaken by a laboratory that meets requirements equivalent to ISO 17025; or 

(c) undertaken in accordance with applicable State or Territory 

legislation. 

(4) As a minimum requirement, a cylinder of calibration gas must be certified by an accredited laboratory accredited to ISO Guide 34:2000 as being within 2% of the concentration specified on the cylinder label. 

Chapter 2—Fuel combustion 

Part 2.1—Preliminary 

2.1  Outline of Chapter 

The principle greenhouse gas generated by the combustion of fossil fuels for energy is carbon dioxide. The quantity of gas produced depends on the carbon content of the fuel and the degree to which the fuel is fully combusted. Small quantities of methane and nitrous oxide are also produced, depending on the actual combustion conditions. Methane may be generated when fuel is heated, but only partially burnt, and depends on combustion temperatures and the level of oxygen present. Nitrous oxide results from the reaction between nitrogen and oxygen in the combustion air. 

The principle purpose of the combustion of fossil fuels in the Australian economy is for the consumption or use of energy. This chapter addresses the general case of the estimation of emissions from the combustion of fossil fuels for that purpose.  

  This Chapter provides for the following matters: 

  (a) emissions released from the following sources: 

(i) the combustion of solid fuels (see Part 2.2); 

(ii) the combustion of gaseous fuels (Part 2.3); 

(iii) the combustion of liquid fuels (Part 2.4); 

(iv) fuel use by certain industries (Part 2.5);  (b) the measurement of fuels in blended fuels (Part 2.6);  (c) the estimation of energy for certain purposes (Part 2.7). 

Reporting context 

Under subdivision 4.4.5 of the Regulations, Reporters should submit data for each individual fuel type on the quantity of fuel consumed for:  

(a) electricity generation; 

(b) transport (excluding international bunker fuels); 

(c) carbon reductants or feedstocks; 

(d) other stationary energy purposes; and  

(e) fuels consumed without combustion. 

For each fuel type the Reporter should also submit: 

i) the amount of fuel consumed for each purpose (a) to (e);  ii) the emissions of each greenhouse gas for each purpose (a) to (d);  iii) the Method used to estimate the emissions (a) to (d); and   iv) the criterion used to estimate the amount of fuel consumed (a) to (e). 

More detail on the reporting requirements are set out in Part 2.7A. 

Part 2.2—Emissions released from the combustion of solid fuels 

Division 2.2.1—Preliminary 

2.2  Application 

From the 2013-14 reporting year the measurement and reporting of emissions and energy associated with the combustion of a solid fuel is optional if the quantity of solid fuel combusted in a separate instance of a source is 1 tonne or less. Separate instance of a source is defined in section 1.9A. Amounts below the reporting threshold may still be reported if doing so is more efficient for the reporter. 

  This Part applies to emissions released from the combustion of solid fuel in relation to a separate instance of a source if the amount of solid fuel combusted in relation to the separate instance of the source is more than 1 tonne. 

2.3  Available methods for estimating emissions of carbon dioxide, methane and nitrous oxide 

(1) Subject to section 1.18, for estimating emissions released from the combustion of a solid fuel consumed from the operation of a facility during a year:  

(a) one of the following methods must be used for estimating emissions of carbon dioxide: 

(i) subject to subsection (3), method 1 under section 2.4; 

(ii) method 2 using an oxidation factor under section 2.5 or an estimated oxidation factor under section 2.6; 

(iii) method 3 using an oxidation factor or an estimated oxidation factor under section 2.12; 

(iv) method 4 under Part 1.3; and 

(b) method 1 under section 2.4 must be used for estimating emissions of methane and nitrous oxide. 

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

(3) Method 1 must not be used for estimating emissions of carbon dioxide for the main fuel combusted from the operation of the facility if: 

(a) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611); and 

(b) the generating unit: 

(i) has the capacity to produce 30 megawatts or more of electricity; and 

(ii) generates more than 50 000 megawatt hours of electricity in a reporting year. 

Note: There is no method 2, 3 or 4 for paragraph (1)(b).

Division 2.2.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide from solid fuels 

2.4  Method 1—solid fuels 

Method 1 is derived from the National Greenhouse Accounts national methodology as published in the National Inventory Report.  Estimates of emissions from the combustion of individual solid fuel types are made by multiplying a (physical) quantity of fuel combusted by a fuel-specific energy content factor and a fuel-specific emission factor for each relevant greenhouse gas (in this case, carbon dioxide, methane and nitrous oxide). 

The list of solid fuels for which emissions must be calculated is given in Table 2.2.2 (taken from Schedule 1 of the Regulations).  

Energy content and emission factors required for the estimation of emissions from the combustion of solid fuels using this approach are given below.  These factors are intended to be default factors – to be used in the absence of better information about the qualities of the fuels combusted at a particular facility. (If better information on fuel qualities or emissions is available, the Reporter may utilise Method 2, 3 or 4).  

Once selected the energy content factor (ECi) for a particular fuel must be applied to all calculations of energy emissions from that fuel for a facility in the reporting year. 

The emission factors for use in Method 1 have been estimated using the Australian Greenhouse Emissions Information System (AGEIS) operated by the Department on the Environment. Consequently, they are determined simultaneously with the 

production of Australia’s National Greenhouse Accounts ensuring that inventories of emissions at both facility and corporate levels are consistent with those of the national accounts. 

  For subparagraph 2.3(1)(a)(i), method 1 is: 

E =  ij QiCiEFijoxec

  1 000  

where: 

Eij is the emissions of gas type (j), being carbon dioxide, methane or nitrous oxide, released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2-e tonnes. 

Qi is the quantity of fuel type (i) measured in tonnes and estimated under Division 2.2.5. 

ECi  is the energy content factor of fuel type (i) estimated under section 6.5.  

EFijoxec is the emission factor for each gas type (j) (which includes the effect of an oxidation factor) released from the combustion of fuel type (i) measured in kilograms of CO2-e per gigajoule according to source as mentioned in Schedule 1. 

Table 2.2.2: Emission and energy content factors — solid 

fuels and certain coal-based products 

Item Fuel combusted Energy content Emission factor 

factor kg CO2-e/GJ 

GJ/t (RELEVANT OXIDATION 

FACTORS INCORPORATED) 

CO2 CH4 N2O 

1 Bituminous coal 27.0 90.0 0.03 0.2 

1A Sub-bituminous coal 21.0 90.0 0.03 0.2 

1B Anthracite 29.0 90.0 0.03 0.2 

2 Brown coal 10.2 93.5 0.02 0.4 

3 Coking coal 30.0 91.8 0.02 0.2 

4 Coal briquettes 22.1 95.0 0.07 0.3 

5 Coal coke 27.0 107.0 0.04 0.2 

6 Coal tar 37.5 81.8 0.03 0.2 

7 Solid fossil fuels other than those 22.1 95.0 0.07 0.3 

mentioned in items 1 to 5 

8 Industrial materials and tyres that 26.3 81.6 0.02 0.2 

are derived from fossil fuels, if recycled and combusted to produce heat or electricity 

Item Fuel combusted Energy content Emission factor 

factor kg CO2-e/GJ 

GJ/t (RELEVANT OXIDATION 

FACTORS INCORPORATED) 

CO2 

CH4 

N2O 

9 Non-biomass municipal 

materials, if recycled and combusted to produce heat or 

electricity 

10.5 

87.1 

0.7 

1.1 

10 Dry wood 

16.2 

0.0 

0.10 

1.2 

11 Green and air dried wood 

10.4 

0.0 

0.10 

1.2 

12 Sulphite lyes 

12.4 

0.0 

0.07 

0.6 

13 Bagasse 

9.6 

0.0 

0.2 

1.2 

14 Biomass municipal and industrial materials, if recycled and combusted to produce heat or 

electricity 

12.2 

0.0 

0.7 

1.1 

15 Charcoal 

31.1 

0.0 

4.8 

1.1 

16 Primary solid biomass fuels other 

than those mentioned in items 10 to 15 

12.2 

0.0 

0.7 

1.1 

Note   Energy content factors for coal products are measured on an as combusted basis.  The energy content for black coal and coking coal (metallurgical coal) is on a washed basis. Notes on the sources of the factors listed above can be found at Appendix 2A. 

Additional coal classifications were introduced in the 2012-13 reporting year. The classifications are defined in the NGER Regulations (Regulation 1.03) and are based on Australian Standard AS2096-1987.  

The new classifications are defined in NGER Regulation 1.03 as follows: 

• Anthracite means coal having a volatile matter of less than 14.0% on a dry ash-free basis. 

• Bituminous coal means coal having: 

(a) a volatile matter of not less than 14.0% on a dry ash-free basis; and 

(b) gross specific energy of either: 

(i) not less than 26.50 megajoules per kilogram on an ash-free moist basis; or 

(ii) not less than 24.00 megajoules per kilogram on an ash-free moist basis if the crucible swelling number is not less than one. 

• Sub-bituminous coal means coal having a gross specific energy of: 

(a) 19.00–23.99 megajoules per kilogram on an ash-free moist basis; or 

(b) if the crucible swelling number is 0 or 1/2 — 19.00–26.49 megajoules per       kilogram on an ash-free moist basis. 

Example 

A facility consumes 20,000 tonnes of washed bituminous coal for a purpose other than for the production of electricity or coke.  The Reporter elects to use Method 1 (Division 2.2.2) for each of the three greenhouse emission gases (j) (carbon dioxide, methane and nitrous oxide), for the fuel type bituminous coal. Emissions are estimated as follows: 

Q

E =  ij iCiEFijoxec 

1 000

where: 

Eij is the emissions of gas type (j) released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2-e tonnes. 

Qi is the quantity of fuel type (i) estimated under Division 2.2.5 measured in tonnes. In this case it is 20,000 tonnes of bituminous coal. 

ECi is the energy content factor of fuel type (i) estimated under section 6.5. In this case it is assumed to be 27 gigajoules per tonne for bituminous coal. 

EFijoxec is the emission factor for each gas (which includes the effect of a default oxidation factor) released from the combustion of fuel type (i) measured in kilograms of CO2-e per gigajoule according to source as mentioned in Schedule 1. In this case, for carbon dioxide, it is 90.0 kg CO2-e per gigajoule for bituminous coal. For methane, the emission factor is 0.03 kilograms per gigajoule and for nitrous oxide, 0.2 kilograms per gigajoule. 

Emissions of greenhouse gases (carbon dioxide, methane and nitrous oxide) in tonnes of CO2-e are estimated as follows:  

Emissions of carbon dioxide from combustion of bituminous coal:  

= (20,000 x 27.0 x 90.0)/1,000 

= 48,600 t CO2-e  

Emissions of methane from combustion of bituminous coal:  

= (20,000 x 27.0 x 0.03)/1,000  

= 16 t CO2-e 

Emissions of nitrous oxide from combustion of bituminous coal: 

= (20,000 x 27.0 x 0.2)/1,000  

= 108 t CO2-e  

Division 2.2.3—Method 2—emissions from solid fuels 

Subdivision 2.2.3.1—Method 2—estimating carbon dioxide using default oxidation factor 

2.5  Method 2—estimating carbon dioxide using oxidation factor 

Method 1 applies national emission factors to the estimation of emissions.  This approach produces accurate estimates for each facility in the sense that they are expected to be neither over nor under-estimates, but the approach effectively averages out the variations in emission factors for the fuels that might be applicable for a particular facility.  Better estimates of emissions at a particular facility may be obtained by sampling and analysing the fuels actually combusted at the facility for the intrinsic qualities of the fuels themselves that affect actual emission levels.  These qualities include the carbon, ash and moisture content of a fuel and may vary reasonably significantly from source to source, particularly for coals. 

Method 2 is derived from the methodologies published in the Technical Guidelines for the Generator Efficiency Standards program, released in December 2006 by the Australian Greenhouse Office, Department of Environment and Heritage and is designed to enable more accurate estimates of emissions to be made at a particular facility.   

Under Method 2, representative and unbiased samples of fuels consumed must be obtained for analysis.  Analysis of the fuels for carbon, energy, ash or moisture content must be done in accordance with listed Australian or international documentary standards or equivalent.   

In order to deduct carbon dioxide captured for permanent storage reporters are required to use Method 2 or higher. These higher order methods provide a more accurate estimate of the carbon dioxide emissions than under Method 1, the default method. As the carbon dioxide captured is deducted from the emissions estimate it is necessary to have a greater level of accuracy in the emissions estimate than is achieved using Method 1.  

Division 2.2.3 also sets out a further choice for the estimation of emissions from solid fuel combustion, which is to estimate emissions with a) an assumed oxidation factor (sub-division 2.2.3.1) or b) to estimate the oxidation level by reference to additional information about the fuels combusted by the facility (Sub-division 2.2.3.2).   

For sub-division 2.2.3.1, oxidation factors are drawn from default factors utilised in the National Greenhouse Accounts. 

Once the analysis of the fuel for carbon, ash and moisture has been completed, emissions may then be estimated in accordance with the equations specified in Section 2.5 (1) or 2.6 (1).   

  (1) For subparagraph 2.3(1)(a)(ii), method 2 is: 

Eico2  Qi  ECi EFico oxec 2 γRCCSco2

  1 000 where: 

Eico2 means the emissions of carbon dioxide released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2-e tonnes. 

Qi is the quantity of fuel type (i) measured in tonnes and estimated under Division 2.2.5. 

ECi  is the energy content factor of fuel type (i) estimated under section 6.5.  

EFico2oxec is the carbon dioxide emission factor for fuel type (i) measured in kilograms of CO2-e per gigajoule as worked out under subsection (2). γ is the factor 1.861 × 10-3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2-e tonnes. 

RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3. 

(2) For EFico2oxec in subsection (1), estimate as follows: 

EFico ox,kg2

EFico oxec2 =   1 000

  ECi  

where: 

EFico2ox,kg is the carbon dioxide emission factor for fuel type (i) measured in kilograms of CO2-e per kilogram of fuel as worked out under subsection (3). 

ECi is the energy content factor of fuel type (i) as obtained under subsection (1). 

(3) For EFico2ox,kg in subsection (2), work out as follows: 

2 Car OF s  3.664

EFico ox,kg = 

  100   

where: 

Car is the percentage of carbon in fuel type (i), as received for the facility or as combusted from the operation of the facility, worked out under subsection (4). 

OFs, or oxidation factor, is 1.0. 

(4) For Car in subsection (3), work out as follows: 

C =  ar Cdaf  100 - M -  A ar ar 

  100  

where: 

Cdaf is the amount of carbon in fuel type (i) as a percentage of the dry ash-free mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3. 

Mar is the amount of moisture in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3. 

Aar is the amount of ash in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3. 

Table 2.2.3 Analysis of solid fuels: standards and frequency of analysis for energy, carbon, moisture and ash 

Item Fuel combusted Parameter Standard Frequency 

1 

Bituminous coal 

Energy content factor 

AS 1038.5—1998 

Monthly sample composite 

Carbon 

AS 1038.6.1—1997 

AS 1038.6.4—2005 

Monthly sample composite 

Moisture 

AS 1038.1—2001 

AS 1038.3—2000 

Each delivery 

Ash 

AS 1038.3—2000 

Each delivery 

1A 

Sub-bituminous coal 

Energy content factor 

AS 1038.5—1998 

Monthly sample composite 

Carbon 

AS 1038.6.1—1997 

AS 1038.6.4—2005 

Monthly sample composite 

Moisture 

AS 1038.1—2001 

AS 1038.3—2000 

Each delivery 

Ash 

AS 1038.3—2000 

Each delivery 

1B 

Anthracite 

Energy content factor 

AS 1038.5—1998 

Monthly sample composite 

Carbon 

AS 1038.6.1—1997 

AS 1038.6.4—2005 

Monthly sample composite 

Moisture 

AS 1038.1—2001 

AS 1038.3—2000 

Each delivery 

Ash 

AS 1038.3—2000 

Each delivery 

2 

Brown coal  

Energy content factor 

AS 1038.5—1998 

Monthly sample composite 

Carbon 

AS 2434.6—2002 

Monthly sample composite 

Moisture 

AS 2434.1—1999 

Each delivery 

Ash 

AS 2434.8—2002 

Each delivery 

3 

Coking coal 

Energy content factor 

AS 1038.5—1998 

Monthly sample composite 

Carbon 

AS 1038.6.1—1997 

AS 1038.6.4—2005 

Monthly sample composite 

Moisture 

AS 1038.1—2001 

AS 1038.3—2000 

Each delivery 

Ash 

AS 1038.3—2000 

Each delivery 

4 

Coal briquettes 

Energy content factor 

AS 1038.5—1998 

Monthly sample composite 

Carbon 

AS 2434.6—2002 

Monthly sample composite 

Moisture 

AS 2434.1—1999 

Each delivery 

Ash 

AS 2434.8—2002 

Each delivery 

5 

Coal coke 

Energy content factor 

AS 1038.5—1998 

Monthly sample composite 

Carbon 

AS 1038.6.1—1997 

AS 1038.6.4—2005 

Monthly sample composite 

Moisture 

AS 1038.2—2006 

Each delivery 

Ash 

AS 1038.3—2000 

Each delivery 

6 

Coal tar 

Energy content factor 

N/A 

Monthly sample composite 

Carbon 

N/A 

Monthly sample composite 

Moisture 

N/A 

Each delivery 

Ash 

N/A 

Each delivery 

7 

Solid fuels other than those mentioned in items 1 to 5 

N/A 

N/A 

N/A 

8 

Industrial materials and tyres that are derived from fossil fuels, if recycled and combusted to produce heat or electricity 

Energy content factor 

Carbon 

Moisture 

CEN/TS 15400:2006 CEN/TS 15407:2006 

CEN/TS 

15414-3:2006 

Monthly sample composite 

Monthly sample composite Each delivery 

Ash 

CEN/TS 15403:2006 

Each delivery 

9 

Non-biomass municipal materials, if recycled and combusted to produce heat or electricity  

Energy content factor Carbon 

CEN/TS 15400:2006 

CEN/TS 15407:2006 

Monthly sample composite 

Monthly sample composite 

Moisture 

CEN/TS 

15414-3:2006 

Each delivery 

Ash 

CEN/TS 15403:2006 

Each delivery 

10 

Dry wood 

Energy content factor 

CEN/TS 15400:2006 

Monthly sample composite 

Carbon 

CEN/TS 15407:2006 

Monthly sample composite 

Moisture 

CEN/TS 

15414-3:2006 CEN/TS 

14774-3:2004 

Each delivery 

Ash 

CEN/TS 15403:2006 

Each delivery 

11 

Green and air dried wood  

Energy content factor 

CEN/TS 15400:2006 

Monthly sample composite 

Carbon 

CEN/TS 15407:2006 

Monthly sample composite 

Moisture 

CEN/TS 

15414-3:2006 CEN/TS 

14774-3:2004 

Each delivery 

Ash 

CEN/TS 15403:2006 

Each delivery 

12 

Sulphite lyes  

Energy content factor 

CEN/TS 15400:2006 

Monthly sample composite 

Carbon 

CEN/TS 15407:2006 

Monthly sample composite 

Moisture 

CEN/TS 

15414-3:2006 CEN/TS 

14774-3:2004 

Each delivery 

Ash 

CEN/TS 15403:2006 

Each delivery 

13 

Bagasse  

Energy content factor 

CEN/TS 15400:2006 

Monthly sample composite 

Carbon 

CEN/TS 15407:2006 

Monthly sample composite 

Moisture 

CEN/TS 

15414-3:2006 CEN/TS 

14774-3:2004 

Each delivery 

Ash 

CEN/TS 15403:2006 

Each delivery 

Energy content factor 

CEN/TS 15400:2006 

Monthly sample composite 

Carbon 

CEN/TS 15407:2006 

Monthly sample composite 

14 Biomass municipal and industrial materials, if recycled and combusted to produce heat or electricity 

Moisture CEN/TS Each delivery 

Example: A facility consumes 100,000 tonnes of bituminous coal with a carbon content of 75 per cent and an energy content of 28.5 gigajoules per tonne for purposes other than coke or electricity production. The Reporter elects to use Method 2 (Division 2.2.3) for the estimation of emissions of carbon dioxide and Method 1 (Division 2.2.2) for the estimation of emissions from methane and nitrous oxide.  

Carbon dioxide emissions are estimated according to Method 2 as follows: 

1. Estimate the carbon dioxide emission factor (EFico2ox,kg) for fuel type (i) as follows: 

C

EFico ox,kg2 = ar  OF s  3.664

100   

where: 

15414-3:2006 

Ash CEN/TS 15403:2006 Each delivery 

15 Charcoal Energy content CEN/TS 15400:2006 Monthly sample 

factor composite 

Carbon 

CEN/TS 15407:2006 

Monthly sample composite 

Moisture 

CEN/TS 

15414-3:2006 

Each delivery 

Ash 

CEN/TS 15403:2006 

Each delivery 

Energy content factor 

CEN/TS 15400:2006 

Monthly sample composite 

Carbon 

CEN/TS 15407:2006 

Monthly sample composite 

Moisture 

CEN/TS 

15414-3:2006 CEN/TS 

14774-3:2004 

Each delivery 

Ash 

CEN/TS 15403:2006 

Each delivery 

16 Primary solid biomass fuels other than those items mentioned in items 10 to 15  

Fuel combustion

EFico2ox,kg the carbon dioxide emission factor for fuel type (i) in kilograms of CO2-e per kilogram of fuel; 

Car is the percentage of carbon in fuel type (i) as received for the facility. In this case the percentage of carbon in bituminous coal is estimated to be 75. 

OFs, ,or oxidation factor, is: 

(a) if the principal activity of the facility is electricity generation — 0.99; or 

(b) in any other case — 0.98. 

= 75/100 x 0.98 x 3.664 

= 2.69 kg of CO2-e per kg of fuel  

2. Estimate the carbon dioxide emission factor for fuel type (i) measured in kilograms of 

EF

CO2-e per gigajoule as follows: EFico oxec2 = ico ox,kg2  1 000 

ECi

where: 

EFico2ox,kg is the carbon dioxide emission factor for fuel type (i) measured in kilograms of CO2-e per kilogram of fuel. 

ECi is the energy content factor of fuel type (i) estimated under section 6.5.  In this case the energy content factor of bituminous coal is estimated to be 28.5 GJ/t. 

= 2.69/28.5 x 1 000 

= 94.4 kg of CO2-e per gigajoule 

3. Estimate emissions as follows: 

Q

Eico2  i  EC1 000i EFico oxec 2 γRCCSco2 

where: 

Eico2 means the emissions of carbon dioxide released from the combustion of a fuel type (i) from the operation of the facility during the year measured in CO2-e tonnes. 

Qi is the quantity of fuel type (i) measured in tonnes estimated under Division 2.2.5. 

ECi is the energy content factor of fuel type (i) estimated under section 6.5. 

γ is the factor 1.861 × 10 3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2 e tonnes. 

RCCSCO2  is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 

1.2.3. 

EFico2oxec is the carbon dioxide emission factor for fuel type (i) measured in kilograms of CO2-e per gigajoule. 

= 100,000 x 28.5 x 96.8/1 000 

= 269,040tonnes of carbon dioxide emissions (CO2-e). 

Methane and nitrous oxide emissions are estimated according to Method 1 as follows: 

Q

E =  ij iCiEFijoxec 

1 000

where: 

Eij is the emissions of gas type (j) released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2-e tonnes. 

Qi is the quantity of fuel type (i) estimated under Division 2.2.5 measured in tonnes. 

ECi is the energy content factor of fuel type (i) estimated under section 6.5. 

EFijoxec is the emission factor for each gas (which includes the effect of a default oxidation factor) released from the combustion of fuel type (i) measured in kilograms of CO2-e per gigajoule (Schedule 1). 

Emissions of methane from combustion of bituminous coal: 

= (100,000 x 28.5 x 0.03)/1 000  

= 86 t CO2-e  

Emissions of nitrous oxide from combustion of bituminous coal: 

= (100,000 x 28.5 x 0.2)/1 000  

= 570 t CO2-e  

Subdivision 2.2.3.2—Method 2—estimating carbon dioxide using an estimated oxidation factor 

2.6  Method 2—estimating carbon dioxide using an estimated oxidation factor 

Sub-division 2.2.3.2 sets out the second option for the estimation of emissions from solid fuel combustion using an estimated oxidation level by reference to additional information about the fuels combusted by the facility. An alternative approach, using an assumed oxidation factor, is set out in sub-division 2.2.3.1.  

  (1) For subparagraph 2.3(1)(a)(ii), method 2 is: 

Eico2  Qi  ECi EFico oxec 2 γRCCSco2

  1 000  

where: 

Eico2 means the emissions of carbon dioxide released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2-e tonnes. 

Qi is the quantity of fuel type (i) measured in tonnes and estimated under Division 2.2.5. 

ECi  is the energy content factor of fuel type (i) estimated under section 6.5.  

EFico2oxec is the amount worked out under subsection (2). 

γ is the factor 1.861 × 10-3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2-e tonnes. 

RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3. 

(2) For EFico2oxec in subsection (1), work out as follows: 

EFico ox,kg2

EFico oxec2 =   1 000

  ECi  

where: 

EFico2ox,kg is the carbon dioxide emission factor for the type of fuel measured in kilograms of CO2-e per kilogram of the type of fuel as worked out under subsection (3). 

ECi is the energy content factor of fuel type (i) as obtained under subsection (1). 

(3) For EFico2ox,kg in subsection (2), estimate as follows: 

EFico2ox,kg = Car 100Ca CaAar1003.664  

where: 

Car is the percentage of carbon in fuel type (i), as received for the facility or as combusted from the operation of the facility, worked out under subsection (4). 

Ca is the amount of carbon in the ash estimated as a percentage of the as-sampled mass that is the weighted average of fly ash and ash by sampling and analysis in accordance with Subdivision 2.2.3.3. 

Aar is the amount of ash in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3. 

  (4) For Car, in subsection (3), estimate as follows: 

C =  ar Cdaf  100 - M -  A ar ar 

Cdaf is the amount of carbon in fuel type (i) as a percentage of the dry ash-free mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3. 

Mar is the amount of moisture in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3. 

Aar is the amount of ash in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3. 

Subdivision 2.2.3.3—Sampling and analysis for method 2 under sections 2.5 and 2.6 

Under Method 2, representative and unbiased samples of fuels consumed must be obtained for analysis.   

As coal is a heterogeneous material, for the sample to be truly representative it must contain the correct proportions of each particle size present, as well as the correct proportions of particles of varying impurity content. Therefore, in the process of collecting a representative sample, each particle in the lot must have an equal 

probability of being sampled (‘equal selection probability’); the representativeness of the sample being a function of the mass of the sample, or more correctly, the number of particles in the sample. 

A mechanical sampling system, designed and operated in accordance with AS 4264 should be used to sample the coal or solid fuel. Ideally, this type of sampling system would be set up to obtain coal as it is either being loaded at the coal source or unloaded at the facility. One lot of coal will normally represent one day or one trainload of coal. If necessary, manual sampling of the coal may be used provided that the sampling equipment and procedure used is in accordance with AS 4264. 

Sample preparation as required providing a laboratory sample for analysis is normally carried out in two steps: 

Step 1: Initial crushing and subdivision of the samples as part of an operation that is integrated with the coal sampling; 

Step 2: Final crushing and subdivision at the laboratory to provide the analysis sample. 

Precision is defined as a measure of the extent to which the observations within a set agree with each other; usually expressed as twice the standard deviation (95% confidence level). Precision checks should be carried out on the sampling process to confirm that the sampling rate is acceptable. The procedure for determining the precision of coal sampling and sample preparation is prescribed in AS 4264.5. It is recommended that precision tests be undertaken on a yearly basis and whenever there is a change in the fuel source or a significant change in the quality characteristics of a particular fuel. 

If several sources of fuels are being sampled through a given plant, sampling conditions and sample precision checks should be carried out on the source that exhibits the highest degree of heterogeneity. 

Bias can be defined as the tendency to obtain a value that is either consistently higher or consistently lower than the reference value; in practice this is the difference between the reference value and the average result obtained from a large number of determinations. The recommended procedure for the estimation of bias in a coal sampling system is given in AS 4264.4. In the case of bias testing of mechanical samplers, the reference samples are usually stopped belt samples off a conveyor belt. For the purposes of verification of a coal sampling system, the coal samples taken for bias testing (pairs consisting of a reference sample and a sample taken by the coal sampler) should be analysed for total moisture and ash. 

Bias testing should always be carried out on a new sampling system. For an existing system, the following verification procedure may be followed if there is some doubt about the conformance of the sampling system: 

1. conduct a detailed technical audit of the sampling system; 

2. correct any non-conformances that have been observed; 

3. conduct a limited bias test on the system, usually with the coal that exhibits the widest stochastic variability in total moisture or ash, to provide a more quantitative verification that the sampling system is performing correctly. 

Analysis of the fuels for carbon, energy, ash or moisture content must be done in accordance with listed Australian or international documentary standards or by an on-line analyser in accordance with section 2.8 (3).  The listing of applicable standards for the analysis of solid fuels is given below.  Equivalent standards to those listed may also be used.  Examples of equivalent standards include those produced by AS, NZ, ASTM, ISO and CEN standards organisations. The standards must be in force on the date stated in section 1.9. A NATA (National Association of Testing Authorities) accredited laboratory or similar laboratory complying with ISO 17025 should be used to conduct the analysis.   

Minimum frequencies of analysis for solid fuels are also provided for in the table below. 

2.7  General requirements for sampling solid fuels 

(1) A sample of the solid fuel must be derived from a composite of amounts of the solid fuel combusted. 

(2) The samples must be collected on enough occasions to produce a representative sample. 

(3) The samples must also be free of bias so that any estimates are neither over nor under estimates of the true value. 

(4) Bias must be tested in accordance with an appropriate standard (if any). 

Note: An appropriate standard for most solid mineral fuels is AS 4264.4—1996 Coal and coke—Sampling—Determination of precision and bias. 

(5) The value obtained from the sample must only be used for the delivery period or consignment of the fuel for which it was intended to be representative. 

2.8  General requirements for analysis of solid fuels 

(1) A standard for analysis of a parameter of a solid fuel, and the minimum frequency of analysis of a solid fuel, is as set out in Schedule 2. 

(2) A parameter of a solid fuel may also be analysed in accordance with a standard that is equivalent to a standard set out in Schedule 2. 

(3) Analysis must be undertaken by an accredited laboratory that meets the requirements equivalent to those in AS ISO/IEC 17025:2005. However, analysis may be undertaken by an on-line analyser if: 

(a) the analyser is calibrated in accordance with an appropriate standard; and 

(b) analysis undertaken to meet the standard is done by a laboratory that meets the requirements equivalent to those in AS ISO/IEC 17025:2005.  

Note: An appropriate standard is AS 1038.24—1998, Coal and coke—Analysis and testing, Part 24: Guide to the evaluation of measurements made by on-line coal analysers. 

(4) If a delivery of fuel lasts for a month or less, analysis must be conducted on a delivery basis. 

(5) However, if the properties of the fuel do not change significantly between deliveries over a period of a month, analysis may be conducted on a monthly basis. 

(6) If a delivery of fuel lasts for more than a month, and the properties of the fuel do not change significantly before the next delivery, analysis of the fuel may be conducted on a delivery basis rather than monthly basis. 

2.9  Requirements for analysis of furnace ash and fly ash 

Sampling of furnace and fly ash is needed if the method of sub-division 2.2.3.2 is adopted rather than the alternative method of sub-division 2.2.3.1.  

It is recognised that the configuration of plant varies and measurement of carbon in ash should be based on representative operating conditions for the plant. 

Furnace ash includes ash collected at the bottom of the furnace hopper of the coal unit and ash collected within the economiser hopper at the rear pass of the coal fired power plant. There is no standard procedure to collecting furnace ash or economiser hopper ash; however, in a wet extraction system, reasonable samples may be obtained by using sampling ladles to collect material from sluiceways. In a dry extraction system, good representative samples can be obtained directly from the conveyor.  Particular care should be taken in attempting to obtain samples of furnace ash because of the inherent dangers associated with such operations. The Determination allows for alternative collection methods to be used to obtain samples where it is not feasible due to safety and operational considerations  

The legislation sets out the minimum frequency for sampling for carbon in fly ash. It is acknowledged that some facilities sample on a more regular basis and these more frequent measurements should be incorporated into a facilities estimates.  

Additional sampling should be undertaken for furnace and fly ash after a significant change in operating conditions as the amount and type of ash produced can vary significantly as a result of the change. 

For facilities where load profiles vary significantly throughout the operation of the facility it is recommended that ash is sampled as a function of load. 

  For furnace ash and fly ash, analysis of the carbon content must be undertaken in accordance with AS 3583.2—1991 Determination of moisture content and AS 3583.3—1991 Determination of loss on ignition or a standard that is equivalent to those standards. 

2.10  Requirements for sampling for carbon in furnace ash 

(1) This section applies to furnace ash sampled for its carbon content if the ash is produced from the operation of a facility that is constituted by a plant. 

(2) A sample of the ash must be derived from representative operating conditions in the plant. 

(3) A sample of ash may be collected: 

(a) if contained in a wet extraction system—by using sampling ladles to collect it from sluiceways; or 

(b) if contained in a dry extraction system—directly from the conveyer; or 

(c) if it is not feasible to use one of the collection methods mentioned in paragraph (a) or (b)—by using another collection method that provides representative ash sampling. 

2.11  Sampling for carbon in fly ash 

  Fly ash must be sampled for its carbon content in accordance with:  

(a) a procedure set out in column 2 of an item in the following table, and at a frequency set out in column 3 for that item; or 

(b) if it is not feasible to use one of the procedures mentioned in paragraph (a)—another procedure that provides representative ash sampling, at least every two years, or after significant changes in operating conditions. 

Item 

Procedure 

Frequency 

1 

At the outlet of a boiler air heater or the inlet to a flue gas cleaning plant using the isokinetic sampling method in AS 4323.1—1995 or AS 

At least every 2 years, or after significant changes in operating conditions 

Item 

Procedure 

Frequency 

4323.2—1995, or in a standard that is equivalent to one of those standards 

2 

By using standard industry ‘cegrit’ extraction equipment 

At least every year, or after significant changes in operating conditions 

3 

By collecting fly ash from: 

(a) the fly ash collection hoppers of a flue gas cleaning plant; or 

(b) downstream of fly ash collection hoppers from ash silos or sluiceways 

At least once a year, or after significant changes in operating conditions 

4 

From on-line carbon in ash analysers using sample extraction probes and infrared analysers 

At least every 2 years, or after significant changes in operating conditions 

Division 2.2.4—Method 3—Solid fuels 

Method 3 is a variation on Method 2.  Method 3 provides for the same requirements as Method 2 except that sampling of fuels should also be conducted in accordance with the Australian or international standards listed in section 2.12 or by an equivalent standard.  Once sampling of the fuel has been conducted in accordance with the standard, the analysis of the fuel for carbon, ash and moisture should be conducted as for Method 2.  Emissions may then be estimated in accordance with the equations set out in sections 2.5 (1) or 2.6 (1) in Method 2.   

2.12  Method 3—solid fuels using oxidation factor or an estimated oxidation factor 

(1) For subparagraph 2.3(1)(a)(iii) and subject to this section, method 3 is the same as method 2 whether using the oxidation factor under section 2.5 or using an estimated oxidation factor under section 2.6. 

(2) In applying method 2 as mentioned in subsection (1), solid fuels must be sampled in accordance with the appropriate standard mentioned in the table in subsection (3). 

(3) A standard for sampling a solid fuel mentioned in column 2 of an item in the following table is as set out in column 3 for that item: 

Item 

Fuel 

Standard 

1 

Bituminous coal 

AS 4264.1—2009 

1A 

Sub-bituminous coal 

AS 4264.1—2009 

1B 

Anthracite 

AS 4264.1—2009 

2 

Brown coal  

AS 4264.3—1996 

3 

Coking coal (metallurgical coal)  

AS 4264.1—2009 

4 

Coal briquettes 

AS 4264.3—1996 

5 

Coal coke 

AS 4264.2—1996 

6 

Coal tar 

7 

Industrial materials and tyres that are derived from fossil fuels, if recycled and combusted to produce heat or electricity 

CEN/TS 14778 – 

1:2006 

CEN/TS 

15442:2006 

8 

Non-biomass municipal materials, if recycled and combusted to produce heat or electricity 

CEN/TS 14778 – 

1:2005 

CEN/TS 

15442:2006 

Item 

Fuel 

Standard 

9 

Dry wood 

CEN/TS 14778 – 

1:2005 

CEN/TS 

15442:2006 

10 

Green and air dried wood 

CEN/TS 14778 – 

1:2005 

CEN/TS 

15442:2006 

11 

Sulphite lyes 

CEN/TS 14778 – 

1:2005 

CEN/TS 

15442:2006 

12 

Bagasse 

CEN/TS 14778 – 

1:2005 

CEN/TS 

15442:2006 

13 

Primary solid biomass other than items 9 to 12 and 14 to 15 

CEN/TS 14778 – 

1:2005 

CEN/TS 

15442:2006 

14 

Charcoal  

CEN/TS 14778 – 

1:2005 

CEN/TS 

15442:2006 

15 

Biomass municipal and industrial materials, if recycled and combusted to produce heat or electricity 

CEN/TS 14778 – 

1:2005 

CEN/TS 

15442:2006 

(4) A solid fuel may also be sampled in accordance with a standard that is equivalent to a standard set out in the table in subsection (3). 

Note: The analysis is carried out in accordance with the same requirements as for method 2. 

Division 2.2.5—Measurement of consumption of solid fuels 

2.13  Purpose of Division 

This Division sets out how quantities of solid fuels combusted from the operation of a facility are to be estimated for the purpose of working out the emissions released from the combustion of that fuel. 

Fuel types identified in the Determination are as specified in the Regulation, 

Schedule 1. The fuel types listed principally reflect the lists of fuels used by the 

Bureau of Resources and Energy Economics (BREE) to prepare Australia’s Energy Statistics and report, inter alia, on behalf of the Australian Government to the International Energy Agency.  

The quantities of fuels consumed should exclude those quantities consumed for international transport purposes to reflect international reporting requirements for the national inventory. It is intended that this may be achieved by excluding international bunker fuels as defined in National Greenhouse and Energy Reporting Regulations 2008, Regulation 1.03, and that the point of differentiation between domestic and international consumption will be identical to that provided by the Customs Act 1901 which is used also for excise and GST purposes.   

Division 2.2.5 specifies the criteria for the estimation of the amounts of each solid fuel type combusted from the operation of a facility during a year.   

There are four criteria available for the estimation of quantities combusted reflecting differing levels of measurement effort and precision.   

Under the National Greenhouse and Energy Reporting Regulations 2008, the criterion chosen by the Reporter to estimate combustion is required to be reported. Measuring equipment calibrated to a measurement requirement mentioned in Sections 2.16 and 2.17 refers to the standards required for measurement to support all commercial transactions covered by the National Measurement Act 1960 and associated instruments.   

In Section 2.17 it is intended that measured data for fuels delivered (at the point of sale) would also meet the Criterion AAA under certain circumstances.  These circumstances are that stocks of the fuel consumed at the facility are less than 5% of fuel consumption for the facility during the year and that the stock changes by less than 1% during the year.  It is intended that the analysis may be conducted by the supplier.  

The simplified measurement of consumption criterion is available in those cases where the Reporter does not purchase their fuel and where the Reporter also does not have metering equipment installed that meets the requirements of criterion AAA.  In these cases, it is intended that Reporters should estimate consumption using metering devices or measurement techniques in practice in the industry.  Such measurements would need to meet the criteria set out in section 1.13 of transparency, comparability, accuracy and completeness.  Such data would be classified and reported as ‘BBB’ data.     

The restriction on the choice of criteria at 2.14 (3) is designed to ensure time series consistency of the measurements. 

2.14  Criteria for measurement 

(1) For the purpose of calculating the amount of solid fuel combusted from the operation of a facility during a year and, in particular, for Qi in sections 2.4, 2.5 and 2.6, the quantity of combustion must be estimated in accordance with this section. 

Acquisition involves commercial transaction 

(2) If the acquisition of the solid fuel involves a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria: 

(a) the amount of the solid fuel delivered for the facility during the year as evidenced by invoices issued by the vendor of the fuel (criterion 

A); 

(b) as provided in section 2.15 (criterion AA);  (c) as provided in section 2.16 (criterion AAA). 

(3) If, during a year, criterion AA, or criterion AAA using 

paragraph 2.16(2)(a), is used to estimate the quantity of fuel combusted, 

then, in each year following that year, only criterion AA, or criterion AAA using paragraph 2.16(2)(a), (respectively) is to be used. 

Acquisition does not involve commercial transaction 

(4) If the acquisition of the solid fuel does not involve a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria: 

  (a) as provided in paragraph 2.16(2)(a) (criterion AAA);  (b) as provided in section 2.17 (criterion BBB). 

2.15  Indirect measurement at point of consumption—criterion AA 

(1) For paragraph 2.14(2)(b), criterion AA is the amount of the solid fuel combusted from the operation of the facility during a year based on amounts delivered for the facility during the year as adjusted for the estimated change in the quantity of the stockpile of the fuel for the facility during the year. 

(2) To work out the adjustment for the estimated change in the quantity of the stockpile of the fuel for the facility during the year, one of the following approaches must be used: 

(a) the survey approach mentioned in subsection (2C); 

(b) the error allowance approach mentioned in subsection (2D). 

  (2A) The approach selected must be consistent with the principles mentioned in section 1.13. 

  (2B) The same approach, once selected, must be used for the facility for each year unless: 

(a) there has been a material change in the management of the stockpile during the year; and 

(b) the change in the management of the stockpile results in the 

approach selected being less accurate than the alternative approach. 

  (2C) The survey approach is as follows: 

Step 1. Estimate the quantity of solid fuel in the stockpile by: 

(a) working out the volume of the solid fuel in the stockpile using aerial or general survey in accordance with industry practice; and 

(b) measuring the bulk density of the stockpile in accordance with subregulation (3). 

Step 2. Replace the current book quantity with the quantity estimated under step 1. 

Step 3. Maintain the book quantity replaced under step 2 by: 

(a) adding deliveries made during the year, using: 

(i) invoices received for solid fuel delivered to the facility; or 

(ii) solid fuel sampling and measurements provided by 

  measuring equipment calibrated to a measurement  requirement; and 

(b) deducting from the amount calculated under paragraph (a), solid fuel consumed by the facility. 

Step 4. Use the book quantity maintained under step 3 to estimate the change in the quantity of the stockpile of the fuel. 

Step 1. Estimate the quantity of solid fuel in the stockpile by:  

(a) working out the volume of the solid fuel in the stockpile using aerial or general survey in accordance with industry practice; and  

(b) measuring the bulk density of the stockpile in accordance with subregulation (3).  

Step 2. Replace the current book quantity with the quantity estimated under step 1.  

Step 3. Maintain the book quantity replaced under step 2 by:  

(a) adding deliveries made during the year, using:  

(i) invoices received for solid fuel delivered to the  facility; or  

(ii) solid fuel sampling and measurements provided by measuring equipment calibrated to a measurement requirement; and  

(b) deducting from the amount calculated under paragraph (a), solid fuel consumed by the facility.  

Step 4. Use the book quantity maintained under step 3 to estimate the change in the quantity of the stockpile of the fuel. 

Example - Estimating coal consumption using the survey approach 

A facility reports consumption of sub-bituminous coal using the survey approach under criteria AA.  

Step 1: At 2pm on 27 June, near the end of the reporting year, the facility measures the bulk density of the stockpile and estimates the volume of solid fuel in the stockpile. The resulting estimate is a stockpile of 52,000 tonnes of sub-bituminous coal. 

Step 2: The current book value is now 52,000 tonnes. 

Step 3:  

a) On 28 June a delivery of 21,530 tonnes is received by train and on 30 June a delivery of 25,690 tonnes is received by train.  The deliveries are evidenced by invoices. 

b) Sub bituminous coal consumption from 2pm-midnight on 27 June was estimated to be 6,543 tonnes. Consumption was estimated to be 15,128, 16,425 and 15,303 tonnes on 28, 29 and 30 June respectively. Fuel consumption was estimated based on the measured ‘as fired’ belt weigher readings adjusted for stocks held in unit bunkers. 

The book value as at 30 June is = Book value reported at step 2 + deliveries – fuel    consumed. 

The book value as at 30 June is = 52,000 + 21,530 + 25,690 – 6,543 – 15,128 – 16,425 – 15,303 = 45,821 tonnes of sub-bituminous coal. 

Step 4: 

The book value at the end of the reporting period is 45,821 tonnes. This value is used to estimate the change in the quantity of the stockpile of the fuel over the reporting year. 

(2D)The error allowance approach is as follows: 

Step 1. Estimate the quantity of the stockpile by: 

(a) working out the volume of the solid fuel in the stockpile using aerial or general survey in accordance with industry practice; and 

(b) measuring the bulk density of the stockpile in accordance with subregulation (3). 

Step 2. Estimate an error tolerance for the quantity of solid fuel in the stockpile. The error tolerance is an estimate of the uncertainty of the quantity of solid fuel in the stockpile and must be: 

(a) based on stockpile management practices at the facility and the uncertainty associated with the energy content and proportion of carbon in the solid fuel; and 

(b) consistent with the general principles in section 1.13; and 

(c) not more than 6% of the estimated value of the solid fuel in the stockpile worked out under step 1. 

Step 3. Work out the percentage difference between the current book quantity and the quantity of solid fuel in the stockpile estimated under step 1. 

Step 4. If the percentage difference worked out under step 3 is within the error tolerance worked out under step 2, use the book quantity to estimate the change in the quantity of the stockpile of the fuel. 

Step 5. If the percentage difference worked out in step 3 is more than the error tolerance worked out in step 2: 

(a) 

adjust the book quantity by the difference between the percentage worked out under step 3 and the error tolerance worked out under step 2; and 

  (b) 

use the book quantity adjusted under paragraph (a) to estimate the change in the quantity of the stockpile of the fuel. 

Example A  Estimating coal consumption using the error allowance approach – stockpile estimate within error tollerence 

A facility reports consumption of sub-bituminous coal using the error allowance approach under criteria AA. The book quantity of the stockpile as at 2pm on 27 June is 51,917 tonnes. 

Step 1: At 2pm on 27 June, near the end of the reporting year, the facility measures the bulk density of the stockpile and worked out the volume of solid fuel in the stockpile. The resulting estimate is a stockpile of 52,851 tonnes of sub-bituminous coal. 

Step 2: The error tolerance for the stockpile at this facility is estimated to be 4%. 

Step 3: The current book value is 51,917 tonnes and the quantity of sub-bituminous coal in the stockpile estimated under step 1 is estimated to be 52,851 tonnes. The difference between the two estimates is 1.8%.  

Step 4: The difference worked out under step 3 is less than the error tolerance of 4%. Therefore the book value of is retained 51,917 tonnes is maintained. 

On 28 June a delivery of 21,530 tonnes is received by train and on 30 June a delivery of 25,690 tonnes is received by train.  The deliveries are evidenced by invoices. 

Sub bituminous coal consumption from 2pm-midnight on 27 June was estimated to be 6,543 tonnes. Consumption was estimated to be 15,128, 16,425 and 15,303 tonnes on 28, 29 and 

30 June respectively. Fuel consumption was estimated based on the measured ‘as fired’ belt weigher readings adjusted for stocks held in unit bunkers. 

The book value as at 30 June is = Book value as at 2pm on 27 June + deliveries – fuel consumed. 

The book value as at 30 June is = 51,917 + 21,530 + 25,690 – 6,543 – 15,128 – 16,425 – 15,303 = 45,738 tonnes of sub-bituminous coal. 

The book value at the end of the reporting period is 45,738 tonnes. This value is used to estimate the change in the quantity of the stockpile of the fuel over the reporting year. 

Example B Estimating coal consumption using the error allowance approach - stockpile estimate greater then error tollerence 

A facility reports consumption of sub-bituminous coal using the error allowance approach under criteria AA. The book quantity of the stockpile as at 2pm on 27June is 51,917 tonnes. 

Step 1: At 2pm on 27 June, near the end of the reporting year, the facility measures the bulk density of the stockpile and worked out the volume of solid fuel in the stockpile. The resulting estimate is a stockpile of 54,625 tonnes of sub-bituminous coal. 

Step 2: The error tolerance for the stockpile at this facility is estimated to be 4%. 

Step 3: The current book value is 51,917 tonnes and the quantity of sub-bituminous coal in the stockpile estimated under step 1 is estimated to be 54,625 tonnes. The stockpile estimate is 5.2% greater than the current book value.  

Step 4: Step 4 is not applicable because the difference worked out under step 3 is greater than the error tolerance of 4.0%.  

Step 5: The difference worked out under step 3 is greater than the error tolerance of 4%. Therefore the book value is adjusted by the difference between the percentage worked out under step 3 (5.2%) and the error tolerance worked out under step 2 (4.0%). 

Revised book quantity = Current book value + Difference between estimated stockpile and the book value – error tolerance * book value 

Revised book quantity = 51,917 + (54,625-51,917) – (0.04 * 51,917) = 52,548 tonnes of subbituminous coal. 

On 28 June a delivery of 21,530 tonnes is received by train and on 30 June a delivery of 25,690 tonnes is received by train.  The deliveries are evidenced by invoices. 

Sub bituminous coal consumption from 2pm-midnight on 27 June was estimated to be 6,543 tonnes. Consumption was estimated to be 15,128, 16,425 and 15,303 tonnes on 28, 29 and 

30 June respectively. Fuel consumption was estimated based on the measured ‘as fired’ belt weigher readings adjusted for stocks held in unit bunkers. 

The book value as at 30 June is = Book value as at 2pm on 27 June + deliveries – fuel consumed. 

The book value as at 30 June is = 52,548 + 21,530 + 25,690 – 6,543 – 15,128 – 16,425 – 15,303 = 46,369 tonnes of sub-bituminous coal. 

The book value at the end of the reporting period is 46,369 tonnes of sub-bituminous coal. This value is used to estimate the change in the quantity of the stockpile of the fuel over the reporting year. 

(3) The bulk density of the stockpile must be measured in accordance with:  (a) the procedure in ASTM D/6347/D 6347M-99; or  (b) the following procedure: 

Step 1 

If the mass of the stockpile: 

(a) does not exceed 10% of the annual solid fuel combustion from the operation of a facility—extract a sample from the stockpile using a mechanical auger in accordance with ASTM D 4916-89; or 

(b) exceeds 10% of the annual solid fuel combustion — extract a sample from the stockpile by coring. 

Step 2 

Weigh the mass of the sample extracted. 

Step 3 

Measure the volume of the hole from which the sample has been extracted. 

Step 4 

Divide the mass obtained in step 2 by the volume measured in step 3. 

(4) Quantities of solid fuel delivered for the facility must be evidenced by invoices issued by the vendor of the fuel. 

(5) In this section: 

book quantity means the quantity recorded and maintained by the facility operator as the quantity of solid fuel in the stockpile. 

2.16  Direct measurement at point of consumption—criterion AAA 

(1) For paragraph 2.14(2)(c), criterion AAA is the measurement during a year of the solid fuel combusted from the operation of the facility. 

(2) The measurement must be carried out either: 

(a) at the point of combustion using measuring equipment calibrated to a measurement requirement; or 

(b) at the point of sale using measuring equipment calibrated to a measurement requirement. 

(3) Paragraph (2)(b) only applies if: 

(a) the change in the stockpile of the fuel for the facility for the year is less than 1% of total combustion on average for the facility during the year; and 

(b) the stockpile of the fuel for the facility at the beginning of the year is less than 5% of total combustion for the year. 

For AAA, calibration of the weighing system should be carried out as per the 

manufacturer’s instructions and at least on an annual basis. Some types of weighing systems, such as belt weighers, will require more frequent calibration. Calibration masses should be traceable to the appropriate National Standard of measurement. 

The maximum permissible errors for weighers set out in the National Measurement Act 1960 and associated instruments are given in the table. 

Maximum permissible errors for hopper weighers, belt weighers and automatic rail weighbridges for initial verification and when the equipment is in-service 

Weigher 

Accuracy Class 

Maximum Permissible 

Error 

I.V. 

I.S. 

Hopper weighers1 

Class 0.2 

Class 0.5 Class 1 

Class 2 

±0.10% 

±0.25% 

±0.50% 

±1.00% 

±0.2% 

±0.5% 

±1.0% 

±2.0% 

Belt weighers (dynamic conditions)2 

Class 0.5 

Class 1.0 

Class 2.0 

±0.25% 

±0.5% 

±1.0% 

±0.5% 

±1.0% 

±2.0% 

Automatic Rail-weighbridges (% or weight of single wagon or total train, as appropriate)2 

Class 0.2 

Class 0.5 Class 1 

Class 2 

±0.10% 

±0.25% 

±0.50% 

±1.00% 

±0.2% 

±0.5% 

±1.0% 

±2.0% 

I.V. = Initial verification 

I.S. = In-service 

Source: National Measurement Institute NMI R 107 Discontinuous Totalising Automatic Weighing Instruments (Totalising Hopper Weighers)1 

National Measurement Regulations 19992 

Accuracy classes are defined in the National Measurement Regulations 1999 and NMI R 107 document 

Maximum permissible errors for weigh bridges (static conditions) for initial verification and when the equipment is in-service 

Maximum 

permissible errors 

for loads m expressed in verification scale intervals e 

initial verification 

Class I 

Class II 

Class III 

Class IIII 

±0.5 e 

±1 e 

±1.5 e 

0 ≤ m ≤ 50 000 

50 000 < m ≤ 200 

000 

200 000 < m 

0 ≤ m ≤ 5 000 

5 000 < m ≤ 20 000 

20 000 < m ≤ 100 000 

0 ≤ m ≤ 500 

500 < m ≤ 2 000 

2 000 < m ≤ 10 000 

0 ≤ m ≤ 50 

50 < m ≤ 200 

200 < m ≤ 1 000 

In service 

Class I 

Class II 

Class III 

Class IIII 

±1.0 e 

±2.0 e 

±3.0 e 

0 ≤ m ≤ 50 000 

50 000 < m ≤ 200 

000 

200 000 < m 

0 ≤ m ≤ 5 000 

5 000 < m ≤ 20 000 

20 000 < m ≤ 100 000 

0 ≤ m ≤ 500 

500 < m ≤ 2 000 

2 000 < m ≤ 10 000 

0 ≤ m ≤ 50 

50 < m ≤ 200 

200 < m ≤ 1 000 

Source: National Measurement Institute NMI R 76-1 Non-automatic Weighing Instruments. Part 1: Metrological and Technical Requirements — Tests 

Accuracy classes for weigh bridges as defined in NMI R 76-1 document are: 

Special accuracy – Class I 

High accuracy – Class II 

Medium accuracy – Class III 

Ordinary accuracy – Class IIII 

2.17  Simplified consumption measurements—criterion BBB 

  For paragraph 2.14(d), criterion BBB is the estimation of the solid fuel combusted during a year from the operation of the facility in accordance with industry practice if the equipment used to measure combustion of the fuel is not calibrated to a measurement requirement. 

Note: An estimate obtained using industry practice must be consistent with the principles in section 1.13. 

Part 2.3—Emissions released from the combustion of 

gaseous fuels 

Division 2.3.1—Preliminary 

2.18  Application 

From the 2013-14 reporting year the measurement and reporting of emissions and energy associated with the combustion of a gaseous fuel is optional if the quantity of gaseous fuel combusted in a separate instance of a source is 1,000 cubic metres or less. Separate instance of a source is defined in section 1.9A. Amounts below the reporting threshold may still be reported if doing so is more efficient for the reporter. 

  This Part applies to emissions released from the combustion of gaseous fuels in relation to a separate instance of a source if the amount of gaseous fuel combusted in relation to the separate instance of the source is more than 1000 cubic metres. 

2.19  Available methods 

(1) Subject to section 1.18, for estimating emissions released from the combustion of a gaseous fuel consumed from the operation of a facility during a year: 

(a) one of the following methods must be used for estimating emissions of carbon dioxide: 

(i) method 1 under section 2.20; 

(ii) method 2 under section 2.21; 

(iii) method 3 under section 2.26; 

(iv) method 4 under Part 1.3; and 

(b) one of the following methods must be used for estimating emissions of methane: 

(i) method 1 under section 2.20; 

(ii) method 2 under section 2.27; and 

(c) method 1 under section 2.20 must be used for estimating emissions of nitrous oxide. 

Note: The combustion of gaseous fuels releases emissions of carbon dioxide, methane and nitrous oxide. Method 1 is used to estimate emissions of each of these gases. There is no method 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide. 

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

(3) Method 1 must not be used for estimating emissions of carbon dioxide for the main fuel combusted from the operation of the facility if: 

(a) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611); and 

(b) the generating unit: 

(i) has the capacity to produce 30 megawatts or more of electricity; and 

(ii) generates more than 50 000 megawatt hours of electricity in a reporting year.

Division 2.3.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide 

As for solid fuels, Method 1 for gaseous fuels is derived from the National 

Greenhouse Account national methodology as published in the National Inventory Report.  Emissions for each gas type - carbon dioxide, methane or nitrous oxide - are estimated for individual fuel types by multiplying a (physical) quantity of fuel combusted by a fuel-specific energy content factor and a fuel-specific emission factor for each relevant greenhouse gas. 

The list of gaseous fuels for which emissions must be calculated is given in Table 2.3.2A and 2.3.2B (taken from Schedule 1 of the National Greenhouse and Energy Reporting Regulations 2008). 

Energy content and emission factors required for the estimation of emissions using this approach are given below.  These factors are intended to be default factors – to be used in the absence of better information.   

Once selected the energy content factor (ECi) for a particular fuel must be applied to all calculations of energy emissions from that fuel for a facility in the reporting year. 

The emission factors listed have been estimated using the Australian Greenhouse 

Emissions Information System (AGEIS) operated by the Department on the Environment. Consequently, they are determined simultaneously with the production of Australia’s National Greenhouse Accounts ensuring that Reporter inventories are consistent with those national accounts. 

2.20  Method 1—emissions of carbon dioxide, methane and nitrous oxide 

  (1) For subparagraphs 2.19(1)(a)(i) and (b)(i) and paragraph 2.19(1)(c), method 1 for estimating emissions of carbon dioxide, methane and nitrous oxide is: 

E =  ij QiCiEFijoxec

  1 000  

where: 

Eij is the emissions of gas type (j), being carbon dioxide, methane or nitrous oxide, from each gaseous fuel type (i) released from the operation of the facility during the year measured in CO2-e tonnes. 

Qi is the quantity of fuel type (i) combusted, whether for stationary energy purposes or transport energy purposes, from the operation of the facility during the year measured in cubic metres or gigajoules and estimated under Division 2.3.6. 

ECi  is the energy content factor of fuel type (i) estimated under section 6.5.  

EFijoxec is the emission factor for each gas type (j) released during the year (which includes the effect of an oxidation factor) measured in kilograms 

CO2-e per gigajoule of fuel type (i) according to source as mentioned in: 

(a) for stationary energy purposes—Part 2 of Schedule 1; and 

(b) for transport energy purposes—Division 4.1 of Schedule 1. 

Note: The combustion of gaseous fuels releases emissions of carbon dioxide, methane and nitrous oxide. 

  (2) In this section: 

stationary energy purposes means purposes for which fuel is combusted that do not involve transport energy purposes. 

transport energy purposes includes purposes for which fuel is combusted that consist of any of the following: 

(a) transport by vehicles registered for road use; 

(b) rail transport; 

(c) marine navigation;  (d) air transport. 

Note: The combustion of gaseous fuels releases emissions of carbon dioxide, methane and nitrous oxide. 

Table 2.3.2A Emission and energy content factors — gaseous fuels 

Item Fuel combusted Energy content Emission factor 

factor kg CO2-e/GJ 

(GJ/m3 unless (RELEVANT OXIDATION otherwise FACTORS INCORPORATED) indicated) 

CO2 

CH4 

N2O 

17 Natural gas distributed in a pipeline 

39.3 × 10-3 

51.4 

0.1 

0.03 

18 Coal seam methane that is captured for combustion 

37.7 × 10-3 

51.4 

0.2 

0.03 

19 Coal mine waste gas that is captured for combustion 

37.7 × 10-3 

51.9 

4.1 

0.03 

20 Compressed natural gas that has reverted to standard conditions 

39.3 × 10-3 

51.4 

0.1 

0.03 

21 Unprocessed natural gas 

39.3 × 10-3 

51.4 

0.1 

0.03 

22 Ethane 

62.9 × 10-3 

56.5 

0.03 

0.03 

23 Coke oven gas 

18.1 × 10-3 

37.0 

0.03 

0.05 

24 Blast furnace gas 

4.0 × 10-3 

234.0 

0.0 

0.03 

25 Town gas 

39.0 × 10-3 

60.2 

0.0 

0.03 

26 Liquefied natural gas 

25.3 GJ/kL 

51.4 

0.1 

0.03 

27 Gaseous fossil fuels other than those mentioned in items 17 to 26 

39.3 × 10-3 

51.4 

0.1 

0.03 

28 Landfill biogas that is captured for combustion (methane only) 

37.7 × 10-3 

0.0 

4.8 

0.03 

29 Sludge biogas that is captured for combustion (methane only) 

37.7 × 10-3 

0.0 

4.8 

0.03 

30 A biogas that is captured for combustion, other than those mentioned in items 28 and 29 (methane only) 

37.7 × 10-3 

0.0 

4.8 

0.03 

Notes on the sources of the factors listed above can be found at Appendix 2A. 

Table 2.3.2B  Emissions and energy content factors — gaseous fuels for transport energy purposes 

Item Fuel combusted Energy content Emission factor 

factor kg CO2-e/GJ 

(GJ/kL unless (RELEVANT OXIDATION otherwise FACTORS INCORPORATED) 

indicated) 

CO2 

CH4 

N2O 

62 

Compressed natural gas that has reverted to standard conditions (light duty vehicles) 

39.3 × 10-3 

GJ/m3 

51.4 

6.5 

0.3 

63 

Compressed natural gas that has reverted to standard conditions (heavy duty vehicles) 

39.3 × 10-3 

GJ/m3 

51.4 

2.5 

0.3 

63A 

Liquefied natural gas (light duty vehicles) 

25.3 

51.4 

6.5 

0.3 

63B 

Liquefied natural gas (heavy duty vehicles) 

25.3 

51.4 

2.5 

0.3 

Notes on the sources of the factors listed above can be found at Appendix 2A. 

Definitions of the light and heavy duty vehicles for the purposes of applying gaseous fuels emissions factors can be found in Appendix B: Definitions and interpretation. 

Division 2.3.3—Method 2—emissions of carbon dioxide from the combustion of gaseous fuels 

Subdivision 2.3.3.1—Method 2—emissions of carbon dioxide from the combustion of gaseous fuels 

2.21  Method 2—emissions of carbon dioxide from the combustion of gaseous fuels 

As for solid fuels, Method 1 applies national average factors to the estimation of emissions.  More accurate estimates of emissions at a facility level may be obtained by sampling and analysing fuels for qualities that affect emission levels when the fuel is combusted.  These qualities include the composition of the constituent gases of the fuel combusted – for example, the share of methane in the combusted gas.  

Method 2 is designed to enable more accurate estimates of emissions at a particular facility.  

  (1) For subparagraph 2.19(1)(a)(ii), method 2 for estimating emissions of carbon dioxide is: 

Eico2  Qi  ECi EFico oxec 2  γRCCSco2

  1 000  

where: 

EiCO2 is emissions of carbon dioxide released from fuel type (i) combusted from the operation of the facility during the year measured in CO2-e tonnes. 

Qi is the quantity of fuel type (i) combusted from the operation of the facility during the year measured in cubic metres or gigajoules and estimated under Division 2.3.6. 

ECi  is the energy content factor of fuel type (i) estimated under section 6.5.  

EFiCO2oxec is the carbon dioxide emission factor for fuel type (i) measured in kilograms CO2-e per gigajoule and calculated in accordance with section 2.22. γ is the factor 1.861 × 10-3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2-e tonnes. 

RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3. 

2.22  Calculation of emission factors from combustion of gaseous fuel 

  (1) For section 2.21, the emission factor EFiCO2oxec from the combustion of 

fuel type (i) must be calculated from information on the composition of each component gas type (y) and must first estimate EFi,CO2,ox,kg in accordance with the following formula: 

 mol %  mw

  ( y )   100 

EFi, CO2,ox,kg =  y    ( y d ,y totalV   )   ( 44.010(mw   y  f   100)y  OFg )  



  

where: 

EFi,CO2,ox,kg is the carbon dioxide emission factor for fuel type (i), incorporating the effects of a default oxidation factor expressed as kilograms of carbon dioxide per kilogram of fuel. 

moly%, for each component gas type (y), is that gas type’s share of 1 mole of fuel type (i), or that gas type’s share of the total volume of fuel type (i), expressed as a percentage. 

mwy, for each component gas type (y), is the molecular weight of the component gas type (y) measured in kilograms per kilomole. 

V is the volume of 1 kilomole of the gas at standard conditions and equal to 23.6444 cubic metres. 

dy, total is as set out in subsection (2). 

fy for each component gas type (y), is the number of carbon atoms in a molecule of the component gas type (y). 

OFg is the oxidation factor 1.0 applicable to gaseous fuels. 

(2) For subsection (1), the factor dy, total is worked out using the following formula: 

mwy

dy, total = y mol % y  ( )

  V  

where: 

moly%, for each component gas type (y), is that gas type’s share of 1 mole of fuel type (i), or that gas type’s share of the total volume of fuel type (i), expressed as a percentage. 

mwy, for each component gas type (y), is the molecular weight of the component gas type (y) measured in kilograms per kilomole. 

(3) For subsection (1), the molecular weight and number of carbon atoms in a molecule of each component gas type (y) mentioned in column 2 of an item in the following table is as set out in columns 3 and 4, respectively, for the item: 

Item 

Component gas y 

Molecular Wt (kg/kmole) 

Number of carbon atoms in component molecules 

1 

Methane  

16.043 

1 

2 

Ethane  

30.070 

2 

3 

Propane 

44.097 

3 

4 

Butane  

58.123 

4 

5 

Pentane  

72.150 

5 

6 

Carbon monoxide  

28.016 

1 

7 

Hydrogen  

2.016 

0 

8 

Hydrogen sulphide  

34.082 

0 

9 

Oxygen  

31.999 

0 

10 

Water  

18.015 

0 

11 

Nitrogen  

28.013 

0 

12 

Argon 

39.948 

0 

13 

Carbon dioxide  

44.010 

1 

(4) The carbon dioxide emission factor EFiCO2oxec derived from the 

calculation in subsection (1) must be expressed in terms of kilograms of carbon dioxide per gigajoule calculated using the following formula: 

  EFi CO2oxec = EFi ,CO2ox,kg  ECCi i  

where: 

ECi is the energy content factor of fuel type (i), measured in gigajoules per cubic metre that is: 

  (a) mentioned in column 3 of Part 2 of Schedule 1; or  (b) estimated by analysis under Subdivision 2.3.3.2. 

Ci is the density of fuel type (i) expressed in kilograms of fuel per cubic metre as obtained under subsection 2.24(4). 

Subdivision 2.3.3.2—Sampling and analysis 

Under Method 2, representative and unbiased samples of fuels consumed must be obtained for analysis.  Analysis of the fuels for composition of constituent gases must be done in accordance with listed Australian or international standards.  A listing of applicable standards is given in Section 2.23.  Equivalent standards may also be selected.  Examples of equivalent standards include those produced by AS, NZ, ASTM, ISO and CEN standards organisations. The standards must be on the date stated in section 1.9.   

A NATA (National Association of Testing Authorities) accredited laboratory or similar laboratory complying with ISO 17025 should be used to conduct the analysis.   

Minimum frequencies of analysis of the gaseous fuels are also provided for in Section 2.25. With the results of the analysis, emissions may then be estimated in accordance the equations specified in Method 2.   

2.23  General requirements for sampling under method 2 

(1) A sample of the gaseous fuel must be derived from a composite of amounts of the gaseous fuel combusted. 

(2) The samples must be collected on enough occasions to produce a representative sample. 

(3) The samples must also be free of bias so that any estimates are neither over nor under estimates of the true value. 

(4) Bias must be tested in accordance with an appropriate standard (if any). 

(5) The value obtained from the samples must only be used for the delivery period, usage period or consignment of the gaseous fuel for which it was intended to be representative. 

2.24  Standards for analysing samples of gaseous fuels 

  (1) Samples of gaseous fuels of a type mentioned in column 2 of an item in the following table must be analysed in accordance with one of the standards mentioned in: 

  (a) for analysis of energy content—column 3 for that item; and  (b) for analysis of gas composition—column 4 for that item. 

Item 

Fuel type 

Energy content 

Gas Composition 

1 

Natural gas if distributed in a pipeline 

ASTM D 1826—94 

(2003) 

ASTM D 7164—05 

ASTM 3588—98 

(2003) 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

ISO 6976:1995 

GPA 2172—96 

ASTM D 1945—03 

ASTM D 1946—90 (2006) 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000) part 5 (2000)  part 6 (2002) 

GPA 2145 – 03 

GPA 2261 – 00 

2 

Coal seam methane that is captured for combustion 

ASTM D 1826—94 

(2003) 

ASTM D 7164—05  

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

ISO 6976:1995 

GPA 2172—96 

ASTM D 1945—03 

ASTM D 1946—90 (2006) 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

GPA 2145 – 03 

GPA 2261 – 00 

3 

Coal mine waste gas that is captured for combustion 

ASTM D 1826 – 94 (2003) 

ASTM D 7164 – 05 

ASTM 3588—98 

(2003) 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

ASTM D 1945 – 03 

ASTM D 1946 – 90 (2006) 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

GPA 2145 – 03 

GPA 2261 – 00 

Item 

Fuel type 

Energy content 

Gas Composition 

ISO 6976:1995 

GPA 2172—96 

4 

Compressed natural gas 

ASTM 3588—98 

(2003) 

N/A 

5 

Unprocessed natural gas 

ASTM D 1826—94 

(2003) 

ASTM D 7164—05 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

ISO 6976:1995 

GPA 2172—96 

ASTM D 1945—03 

ASTM D 1946—90 (2006) 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000) part 5 (2000)  part 6 (2002) 

GPA 2145 – 03 

GPA 2261 – 00 

6 

Ethane 

ASTM D 3588 – 98 (2003) 

IS0 6976:1995 

ASTM D 1945 – 03 

ASTM D 1946 – 90 (2006) 

7 

Coke oven gas 

ASTM D 3588—98 

(2003) 

ISO 6976:1995 

ASTM D 1945—03 

ASTM D 1946—90 (2006) 

8 

Blast furnace gas 

ASTM D 3588—98 

(2003) 

ISO 6976:1995 

ASTM D 1945—03 

ASTM D 1946—90 (2006) 

9 

Town gas 

ASTM D 1826—94 

(2003) 

ASTM D 7164—05 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

ISO 6976:1995 

GPA 2172—96 

ASTM D 1945—03 

ASTM D 1946—90 (2006) 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

GPA 2145 – 03 

GPA 2261 – 00 

10 

Liquefied natural gas 

ISO 6976:1995 

ASTM D 1945 – 03 ISO 6974 

Item 

Fuel type 

Energy content 

Gas Composition 

part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

11 

Landfill biogas that is captured for combustion 

ASTM D 1826—94 

(2003) 

ASTM D 7164—05 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

ISO 6976:1995 

GPA 2172—96 

ASTM D 1945—03 

ASTM D 1946—90 (2006) 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

GPA 2145 – 03 

GPA 2261 – 00 

12 

Sludge biogas that is captured for combustion 

ASTM D 1826 – 94 (2003) 

ASTM D 7164 – 05 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

ISO 6976:1995 

GPA 2172—96 

ASTM D 1945 – 03  

ASTM D 1946 – 90 (2006) 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  part 5 (2000) part 6 (2002) 

GPA 2145 – 03 

GPA 2261 – 00 

13 

A biogas that is captured for combustion, other than those mentioned in items 11 and 12 

ASTM D 1826—94 

(2003) 

ASTM D 7164—05 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  

ASTM D 1945—03  

ASTM D 1946—90 (2006) 

ISO 6974 part 1 (2000) part 2 (2001)  part 3 (2000)  part 4 (2000)  

part 4 (2000)  

part 5 (2000) 

Item 

Fuel type 

Energy content 

Gas Composition 

part 5 (2000) part 6 (2002) 

part 6 (2002) 

GPA 2145 – 03 

ISO 6976:1995 

GPA 2172—96 

GPA 2261 – 00 

(2) A gaseous fuel mentioned in column 2 of an item in the table in subsection (1) may also be analysed in accordance with a standard that is equivalent to a standard set out in column 3 and 4 of the item. 

(3) The analysis must be undertaken: 

(a) by an accredited laboratory; or 

(b) by a laboratory that meets requirements that are equivalent to the requirements in AS ISO/IEC 17025:2005; or  (c) using an online analyser if: 

(i) the online analyser is calibrated in accordance with an appropriate standard; and 

(ii) the online analysis is undertaken in accordance with this section. 

Note: An example of an appropriate standard is ISO 6975:1997—Natural gas— Extended analysis—Gas-chromatographic method. 

  (4) The density of a gaseous fuel mentioned in column 2 of an item in the table in subsection (1) must be analysed in accordance with ISO 6976:1995 or in accordance with a standard that is equivalent to that standard. 

2.25  Frequency of analysis 

  Gaseous fuel of a type mentioned in column 2 of an item in the following table must be analysed for the parameter mentioned in column 3 for that item at least at the frequency mentioned in column 4 for that item. 

Item 

Fuel 

Parameter 

Frequency 

1 

Pipeline quality gases 

Gas composition 

Energy content 

Monthly 

Monthly—if category 1 or 2 gas measuring equipment is used 

Continuous—if category 3 or 4 gas measuring equipment is used 

Item 

Fuel 

Parameter 

Frequency 

2 

All other gases (including fugitive emissions) 

Gas composition 

Energy content 

Monthly, unless the reporting corporation or liable entity certifies in writing that such frequency of analysis will cause significant hardship or expense in which case the analysis may be undertaken at a frequency that will allow an unbiased estimate to be obtained 

Note: The table in section 2.31 sets out the categories of gas measuring equipment.

Division 2.3.4—Method 3—emissions of carbon dioxide released from the combustion of gaseous fuels 

As for solid fuels, Method 3 is a variation on Method 2.  Method 3 provides for the same requirements as Method 2 except that sampling of fuels should also be conducted in accordance with the Australian or international standards listed below or by an equivalent standard.  Once sampling of the fuel has been conducted in accordance with the standard, the analysis of the fuel should be conducted as for Method 2.  Emissions may then be estimated in accordance with the equations specified in Section 2.21 (1) in Method 2. 

2.26  Method 3—emissions of carbon dioxide from the combustion of gaseous fuels 

(1) For subparagraph 2.19(1)(a)(iii) and subject to subsection (2), method 3 for estimating emissions of carbon dioxide is the same as method 2 under section 2.21. 

(2) In applying method 2 under section 2.21, gaseous fuels must be sampled in accordance with a standard specified in the table in subsection (3). 

(3) A standard for sampling a gaseous fuel mentioned column 2 of an item in the following table is the standard specified in column 3 for that item. 

Item 

Gaseous fuel 

Standard  

1 

Natural gas if distributed in a pipeline 

ISO 10715:1997 

ASTM D 5287–97 (2002) 

ASTM F 307–02 (2007) 

ASTM D 5503–94 (2003) 

GPA 2166–05 

2 

Coal seam methane that is captured for combustion 

ISO 10715:1997 

ASTM D 5287–97 (2002) 

ASTM F 307–02 (2007) 

ASTM D 5503–94 (2003) 

GPA 2166–05 

3 

Coal mine waste gas that is captured for combustion 

ISO 10715:1997 

ASTM D 5287–97 (2002) 

ASTM F 307–02 (2007) 

ASTM D 5503–94 (2003) 

GPA 2166–05 

Item 

Gaseous fuel 

Standard  

4 

Compressed natural gas 

ASTM F 307–02 (2007) 

5 

Unprocessed natural gas 

ASTM D 5287–97 (2002) 

ASTM F 307–02 (2007) 

ASTM D 5503–94 (2003) 

GPA 2166–05 

6 

Ethane 

ISO 10715:1997 

ASTM D 5287–97 (2002) ASTM F 307–02 (2007) 

ASTM D 5503–94 (2003) 

7 

Coke oven gas 

ISO 10715 -1997 

ASTM D 5287–97 (2002) ASTM F 307–02 (2007) 

ASTM D 5503–94 (2003) 

8 

Blast furnace gas 

ISO 10715:1997 

ASTM D 5287–97 (2002) ASTM F 307–02 (2007) 

ASTM D 5503–94 (2003) 

9 

Town gas 

ISO 10715:1997 

ASTM D 5287–97 (2002) 

ASTM F 307–02 (2007) 

ASTM D 5503–94 (2003) 

GPA 2166–05 

10 

Liquefied natural gas 

ISO 8943:2007 

11 

Landfill biogas that is captured for combustion  

ISO 10715:1997 

ASTM D 5287–97 (2002) 

ASTM F 307–02 (2007) 

ASTM D 5503–94 (2003) 

GPA 2166–05 

12 

Sludge biogas that is captured for combustion 

ISO 10715:1997 

ASTM D 5287–97 (2002) 

ASTM F 307–02 (2007) 

ASTM D 5503–94 (2003) 

GPA 2166–05 

13 

A biogas that is captured for combustion, other than those mentioned in items 11 and 12 

ISO 10715:1997 

ASTM D 5287–97 (2002) 

ASTM F 307–02 (2007) 

ASTM D 5503–94 (2003) 

Item 

Gaseous fuel 

Standard  

GPA 2166–05 

(4) A gaseous fuel mentioned in column 2 of an item in the table in subsection (3) may also be sampled in accordance with a standard that is equivalent to a standard specified in column 3 for that item. 

Division 2.3.5—Method 2—emissions of methane from the combustion of gaseous fuels 

Section 2.27 sets out a Method 2 for methane emissions from the combustion of gaseous fuels.  The quantity of methane emissions from the combustion of fuels depends on the equipment used. In the case of gaseous fuels, small variations in emissions are possible. Consequently, in this Method emissions may be estimated by substituting equipment-specific methane emission factors drawn from 2006 IPCC Guidelines for National Greenhouse Gas Inventories (Volume 2) for the methane emission factors listed in the Table in Section 2.20. 

2.27  Method 2—emissions of methane from the combustion of gaseous fuels 

(1) For subparagraph 2.19(1)(b)(ii) and subject to subsection (2), method 2 for estimating emissions of methane is the same as method 1 under section 2.20. 

(2) In applying method 1 under section 2.20, the emission factor EFijoxec is to be obtained by using the equipment type emission factors set out in Volume 2, section 2.3.2.3 of the 2006 IPCC Guidelines corrected to gross calorific values. 

Division 2.3.6—Measurement of quantity of gaseous fuels 

2.28  Purpose of Division 

  This Division sets out how quantities of gaseous fuels combusted from 

the operation of a facility are to be estimated for the purpose of working out the emissions released from the combustion of that fuel. 

The quantity of consumption of each of the fuel types specified in the Regulations, Schedule 1, are to be estimated according to one of the criterion set out below. 

The fuel types listed principally reflect the lists of fuels used by the Department of 

Industry to prepare Australia’s Energy Statistics and report, inter alia, on behalf of the Australian Government to the International Energy Agency.  

Separate estimates of the quantities of each fuel type consumed for the purpose of making electricity; for use as reductants or feedstocks; for use in transport (excluding international bunker fuels) and other stationary energy are required.     

The quantities of fuels consumed for transport should exclude those quantities consumed for international transport purposes, if any, to reflect international reporting requirements for the national inventory. It is intended that this may be achieved by excluding international bunker fuels as defined in National Greenhouse and Energy Reporting Regulations 2008, Regulation 1.03, and that the point of differentiation between domestic and international consumption will be identical to that provided by the Customs Act 1901 which is used also for excise and GST purposes.   

As for solid fuels, there are four criteria available for the estimation of quantities combusted.  Under the National Greenhouse and Energy Reporting Regulations 2008, the criterion chosen will need to be reported.  

The criteria include: 

(a) Criterion A - the amount of the fuel delivered for the facility during the year as evidenced by invoices or delivery records issued by the vendor of the fuel (2.29);  

(b) Criterion AA - indirect measurement at the point of consumption - based on the amount of fuel delivered for the facility and adjusted for changes in stocks (2.30); 

Fuel combustion

(c) Criterion AAA - direct measurement at the point of consumption - based on the amount of fuel combusted as estimated by measurement equipment that comply with specified standards (2.31 – 2.37); 

(d) Criterion BBB - simplified measurement of consumption (2.38). 

Measuring equipment requirements set out in Sections 2.31 to 2.37 are drawn from the requirements set out in the Technical Guidelines for the Generator Efficiency Standards program for gaseous fuels.   These standards have been broadened to provide for a measurement threshold that is not technology-specific (2.35 (4)), reflecting comparable State-specific thresholds for small to medium-sized consumers. 

In Sections 2.31 it is intended that measured data for fuels delivered would also meet the Criterion AAA under certain circumstances.  These circumstances are that stocks of the fuel consumed at the facility are less than 5% of fuel consumption for the facility during the year and that the stock changes by less than 1% during the year.   

The simplified measurement of consumption criterion is available in those cases where the Reporter does not purchase fuel and where the Reporter also does not have metering equipment installed that meets the requirements of criterion AAA.  In these cases, it is intended that Reporters should estimate consumption using metering devices or measurement techniques in practice in the industry.  Such measurements would need to meet the criteria set out 1.13 - of transparency, comparability, accuracy and completeness, and would be classified and reported as ‘BBB’ data.     

For landfill gas, the BBB criterion includes provision for the estimation of gas quantities based on the practice available under the NSW GGAS scheme – see the notice, Determining the energy content of waste methane under the generation rules, NSW IPART, 1 December 2006. 

The restriction on the choice of criteria at 2.29 (3) is designed to ensure time series consistency of the measurements. 

2.29  Criteria for measurement 

(1) For the purposes of calculating the combustion of gaseous fuel from the operation of a facility for a year and, in particular, for Qi in sections 2.20 and 2.21, the combustion must be estimated in accordance with this section. 

Acquisition involves commercial transaction 

(2) If the acquisition of the gaseous fuel involves a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria: 

(a) the amount of the gaseous fuel, expressed in cubic metres or gigajoules, delivered for the facility during the year as evidenced by invoices issued by the vendor of the fuel (criterion A); 

(b) as provided in section 2.30 (criterion AA);  (c) as provided in section 2.31 (criterion AAA). 

(3) If, during a year, criterion AA, or criterion AAA using paragraph 2.31(3)(a), is used to estimate the quantity of fuel combusted, then, in each year following that year, only criterion AA, or criterion AAA using paragraph 2.31(3)(a), (respectively) is to be used. 

Acquisition does not involve commercial transaction 

(4) If the acquisition of the gaseous fuel does not involve a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria: 

  (a) as provided in section 2.31 (criterion AAA);  (b) as provided in section 2.38 (criterion BBB). 

2.30 Indirect measurement—criterion AA 

  For paragraph 2.29(2)(b), criterion AA is the amount of a gaseous fuel 

combusted from the operation of the facility during the year based on amounts delivered during the year (evidenced by invoices) as adjusted for the estimated change in the quantity of the stockpile of the fuel for the facility during the year. 

2.31 Direct measurement—criterion AAA 

(1) For paragraph 2.29(2)(c), criterion AAA is the measurement during the year of a gaseous fuel combusted from the operation of the facility. 

(2) In measuring the quantity of gaseous fuel, the quantities of gas must be measured: 

  (a) using volumetric measurement in accordance with: 

  (i) for gases other than super-compressed gases—section 2.32; and  (ii) for super-compressed gases—sections 2.32 and 2.33; and  (b) using gas measuring equipment that complies with section 2.34. 

(3) The measurement must be either: 

  (a) carried out at the point of combustion using gas measuring equipment that: 

(i) is in a category specified in column 2 of an item in the table in subsection (4) according to the maximum daily quantity of gas combusted from the operation of the facility specified, for the item, in column 3 of the table; and 

(ii) complies with the transmitter and accuracy requirements 

specified, for the item, in column 4 of the table, if the requirements are applicable to the gas measuring equipment being used; or 

  (b) carried out at the point of sale of the gaseous fuels using measuring equipment that complies with paragraph (a). 

(4) For subsection (3), the table is as follows: 

Item 

Gas measuring equipment category 

Maximum daily quantity of gas combusted (GJ/day) 

Transmitter and accuracy requirements (% of range) 

1 

1 

0–1750 

Pressure <±0.25% 

Diff. pressure <±0.25% 

Temperature <±0.50%  

2 

2 

1751–3500 

Pressure <±0.25% 

Diff. pressure <±0.25% 

Temperature <±0.50% 

3 

3 

3501–17500 

Smart transmitters: 

Pressure <±0.10% 

Diff. pressure <±0.10% 

Temperature <±0.25% 

4 

4 

17501 or more 

Smart transmitters:  

Pressure <±0.10% 

Diff. pressure <±0.10% 

Temperature <±0.25% 

(5) Paragraph (3)(b) only applies if: 

(a) the change in the stockpile of the fuel for the facility for the year is less than 1% of total consumption on average for the facility during the year; and 

(b) the stockpile of the fuel for the facility at the beginning of the year is less than 5% of total consumption of the fuel from the operation of the facility during the year. 

2.32  Volumetric measurement—all natural gases 

(1) For subparagraph 2.31(2)(a)(i) and (ii), volumetric measurement must be calculated at standard conditions and expressed in cubic metres. 

(2) The volumetric measurement must be calculated using a flow computer that measures and analyses the following at the delivery location of the gaseous fuel: 

(a) flow; 

(b) relative density; 

(c) gas composition. 

(3) The volumetric flow rate must be: 

(a) continuously recorded; and 

(b) continuously integrated using an integration device. 

  (3A) The integration device must be isolated from the flow computer in such a way that, if the computer fails, the integration device will retain: 

(a) the last reading that was on the computer immediately before the 

failure; or 

(b) the previously stored information that was on the computer immediately before the failure. 

(4) All measurements, calculations and procedures used in determining volume (except for any correction for deviation from the ideal gas law) must be made in accordance with: 

(a) the instructions mentioned in subsection (5); or 

(b) an appropriate internationally recognised standard or code. 

Note: An example of an internationally recognised equivalent standard is New Zealand standard NZS 5259:2004. 

(5) For paragraph (4)(a), the instructions are those mentioned in:  (a) for orifice plate measuring systems: 

(i) the publication entitled AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 3: 

Natural Gas Applications, published by the American Gas Association in August 1992; or 

(ii) Parts 1 to 4 of the publication entitled ANSI/API MPMS Chapter 14.3 Part 2 (R2011) Natural Gas Fluids Measurement: 

Concentric, Square-Edged Orifice Meters - Part 2: Specification and Installation Requirements, 4th edition, published by the American Petroleum Institute on 30 April 2000; 

(b) for turbine measuring systems—the publication entitled AGA Report No. 7, Measurement of Natural Gas by Turbine Meter (2006), published by the American Gas Association on 1 January 2006; 

(c) for positive displacement measuring systems—the publication entitled ANSI B109.3—2000, Rotary Type Gas Displacement Meters, published by the American Gas Association on 13 April 2000. 

(6) Measurements must comply with Australian legal units of measurement. 

(7) Standard conditions means, as measured on a dry gas basis: 

  (a) air pressure of 101.325 kilopascals; and  (b) air temperature of 15.0 degrees Celsius; and  (c) air density of 1.225 kilograms per cubic metre. 

2.33  Volumetric measurement—super-compressed gases 

(1) For subparagraph 2.31(2)(a)(ii), this section applies in relation to measuring the volume of super-compressed natural gases. 

(2) If it is necessary to correct the volume for deviation from the ideal gas law, the correction must be determined using the relevant method set out in the publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994. 

(3) The measuring equipment used must calculate super-compressibility by: 

(a) if the measuring equipment is category 3 or 4 equipment in accordance with the table in section 2.31—using gas composition data; or 

(b) if the measuring equipment is category 1 or 2 equipment in accordance with the table in section 2.31—using an alternative method set out in the publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994. 

2.34  Gas measuring equipment—requirements 

  For paragraph 2.31(2)(b), gas measuring equipment that is category 3 or 4 equipment in accordance with column 2 of the table in section 2.31 must comply with the following requirements: 

(a) if the equipment uses flow devices—the requirements relating to flow devices set out in section 2.35; 

(b) if the equipment uses flow computers—the requirement relating to flow computers set out in section 2.36; 

(c) if the equipment uses gas chromatographs—the requirements relating to gas chromatographs set out in section 2.37. 

2.35  Flow devices—requirements 

  (1A) This section is made for paragraph 2.34(a). 

(1) If the measuring equipment has flow devices that use orifice measuring systems, the flow devices must be constructed in a manner that ensures that the maximum uncertainty of the discharge coefficient is not greater than ±1.5%. 

Note: The publication entitled AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 3: Natural Gas Applications, published by the American Gas Association in August 1992, sets out a manner of construction that ensures that the maximum uncertainty of the discharge coefficient is not greater than ±1.5%. 

(2) If the measuring equipment has flow devices that use turbine measuring systems, the flow devices must be installed in a manner that ensures that the maximum uncertainty of the flow measurement is not greater than ±1.5%. 

Note: The publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994, sets out a manner of installation that ensures that the maximum uncertainty of the flow measurement is not greater than ±1.5%. 

(3) If the measuring equipment has flow devices that use positive displacement measuring systems, the flow devices must be installed in a manner that ensures that the maximum uncertainty of flow is ±1.5%. 

Note: The publication entitled ANSI B109.3—2000, Rotary Type Gas Displacement Meters, published by the American Gas Association on 13 April 2000, sets out a manner of installation that ensures that the maximum uncertainty of flow is ±1.5%. 

(4) If the measuring equipment uses any other type of flow device, the maximum uncertainty of flow measurement must not be greater than ±1.5%. 

(5) All flow devices that are used by gas measuring equipment in a category specified in column 2 of an item in the table in section 2.31 must, wherever possible, be calibrated for pressure, differential pressure and temperature: 

(a) in accordance with the requirements specified, for the item, in column 4 of the table; and 

(b) taking into account the effects of static pressure and ambient temperature. 

2.36  Flow computers—requirements 

  For paragraph 2.34(b), the requirement is that the flow computer that is used by the equipment for measuring purposes must record:  (a) the instantaneous values for all primary measurement inputs; and  (b) the following outputs: 

(i) instantaneous corrected volumetric flow; 

(ii) cumulative corrected volumetric flow; 

(iii) for turbine and positive displacement metering systems— instantaneous uncorrected volumetric flow; 

(iv) for turbine and positive displacement metering systems— cumulative uncorrected volumetric flow; 

(v) super-compressibility factor. 

2.37  Gas chromatographs—requirements 

  For paragraph 2.34(c), the requirements are that gas chromatographs used by the measuring equipment must: 

  (a) be factory tested and calibrated using a measurement standard: 

(i) produced by gravimetric methods; and 

(ii) that uses Australian legal units of measurement; and  (b) perform gas composition analysis with an accuracy of: 

(i) ±0.15% for use in calculation of gross calorific value; and 

(ii) ±0.25% for calculation of relative density; and 

  (c) include a mechanism for re-calibration against a certified reference gas. 

2.38  Simplified consumption measurements—criterion BBB 

(1) For paragraph 2.29(4)(b), criterion BBB is the estimation of gaseous fuel 

in accordance with industry practice if the measuring equipment used to estimate consumption of the fuel does not meet the requirements of criterion AAA. 

(2) For sources of landfill gas captured for the purpose of combustion for the production of electricity: 

(a) the energy content of the captured landfill gas may be estimated: 

(i) if the manufacturer’s specification for the internal combustion engine used to produce the electricity specifies an electrical efficiency factor—by using that factor; or 

(ii) if the manufacturer’s specification for the internal combustion engine used to produce the electricity does not specify an electrical efficiency factor—by assuming that measured 

Fuel combustion

electricity dispatched for sale (sent out generation) represents 36% of the energy content of all fuel used to produce electricity; and 

(b) the quantity of landfill gas captured in cubic metres may be derived from the energy content of the relevant gas set out in Part 2 of Schedule 1.

Part 2.4—Emissions released from the combustion of liquid fuels 

Division 2.4.1—Preliminary 

2.39  Application 

  This Part applies to emissions released from: 

(a) the combustion of petroleum based oil (other than petroleum based oil used as fuel) or petroleum based grease, in relation to a separate instance of a source, if the total amount of oil and grease combusted in relation to the separate instance of the source is more than 5 kilolitres; and 

(b) for a liquid fuel not of the kind mentioned in paragraph (a)—the combustion of liquid fuel in relation to a separate instance of a source, if the total amount of liquid fuel combusted in relation to the separate instance of the source is more than 1 kilolitre. 

2.39A  Definition of petroleum based oils for Part 2.4 

  In this Part: 

petroleum based oils means petroleum based oils (other than petroleum based oils used as fuel). 

Subdivision 2.4.1.1—Liquid fuels—other than petroleum based oils and greases 

2.40  Available methods 

(1) Subject to section 1.18, for estimating emissions released from the combustion of a liquid fuel, other than petroleum based oils and petroleum based greases, consumed from the operation of a facility during a year: 

(a) one of the following methods must be used for estimating emissions of carbon dioxide: 

(i) method 1 under section 2.41; 

(ii) method 2 under section 2.42; 

(iii) method 3 under section 2.47; 

(iv) method 4 under Part 1.3; and 

(b) one of the following methods must be used for estimating emissions of methane and nitrous oxide: 

(i) method 1 under section 2.41; 

(ii) method 2 under section 2.48. 

(2) Under paragraph (1)(b), the same method must be used for estimating emissions of methane and nitrous oxide. 

(3) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

Note: The combustion of liquid fuels releases emissions of carbon dioxide, methane and nitrous oxide. Method 1 may be used to estimate emissions of each of these gases. There is no method 3 or 4 for emissions of methane or nitrous oxide. 

Summary of available Methods by emissions of gas type (j) 

CO2 

CH4 

N2O 

Method 1 

Section 2.41 

Section 2.41 

Section 2.41 

Method 2 

Sections 2.42 

Section 2.48 

Section 2.48 

Method 3 

Section 2.47 

Method 4 

Part 1.3 

Subdivision 2.4.1.2—Liquid fuels—petroleum based oils and greases 

2.40A  Available methods 

(1) Subject to section 1.18, for estimating emissions of carbon dioxide released from the consumption, as lubricants, of petroleum based oils or petroleum based greases, consumed from the operation of a facility during a year, one of the following methods must be used: 

(a) method 1 under section 2.48A; 

(b) method 2 under section 2.48B;   (c) method 3 under section 2.48C. 

(2) However, for incidental emissions, another method may be used that is consistent with the principles in section 1.13.   

Note: The consumption of petroleum based oils and greases, as lubricants, releases emissions of carbon dioxide.  Emissions of methane and nitrous oxide are not estimated directly for this fuel type. 

Division 2.4.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide from liquid fuels other than petroleum based oils or greases 

As for solid and gaseous fuels, Method 1 is derived from the National Greenhouse Accounts national methodology as published in the National Inventory Report. Emissions are estimated for individual fuel types by multiplying a (physical) quantity of fuel combusted by a fuel-specific energy content factor and a fuel-specific  emission factor for each relevant greenhouse gas (in this case, carbon dioxide, methane and nitrous oxide). 

The list of liquid fuels for which emissions must be calculated is given in Appendix A (taken from Schedule 1 of the National Greenhouse and Energy Reporting Regulations 2008). 

Energy content and emission factors required for the estimation of emissions using this approach are given below.  These factors are intended to be default factors – to be used in the absence of better information.  

Once selected the energy content factor (ECi) for a particular fuel must be applied to all calculations of energy emissions from that fuel for a facility in the reporting year. 

The emission factors listed have been estimated using the Australian Greenhouse 

Emissions Information System (AGEIS) operated by the Department on the Environment. Consequently, they are determined simultaneously with the production of Australia’s National Greenhouse Accounts ensuring that Reporter inventories are consistent with those national accounts.  

Equipment specific factors for methane and nitrous oxide are provided for transport fleets.  It is intended that the methane and nitrous oxide factors applicable to particular transport fleet should be utilised in the estimation of emissions for the fuel combusted for those fleets.  No transport factors are provided for vehicles not registered for road use.  Stationary energy factors for individual fuel types should be used in these cases.    

2.41  Method 1—emissions of carbon dioxide, methane and nitrous oxide 

  (1) For subparagraphs 2.40(1)(a)(i) and (b)(i), method 1 for estimating emissions of carbon dioxide, methane and nitrous oxide is: 

QiCiEF

E =  ij ijoxec

  1 000  

where: 

Eij is the emissions of gas type (j), being carbon dioxide, methane or nitrous oxide, released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2-e tonnes. 

Qi is the quantity of fuel type (i) combusted from the operation of the facility for: 

(a) stationary energy purposes; and 

(b) transport energy purposes; 

during the year measured in kilolitres and estimated under Division 2.4.6. 

ECi  is the energy content factor of fuel type (i) estimated under section 6.5.  

EFijoxec is the emission factor for each gas type (j) released from the operation of the facility during the year (which includes the effect of an oxidation factor) measured in kilograms CO2-e per gigajoule of fuel type (i) according to source as mentioned in: 

  (a) for stationary energy purposes—Part 3 of Schedule 1; and  (b) for transport energy purposes—Division 4.1 of Schedule 1. 

  (2) In this section: 

stationary energy purposes means purposes for which fuel is combusted that do not involve transport energy purposes.  

transport energy purposes includes purposes for which fuel is combusted that consist of any of the following: 

(a) transport by vehicles registered for road use; 

(b) rail transport; 

(c) marine navigation;  (d) air transport. 

Note: The combustion of liquid fuels produces emissions of carbon dioxide, methane and nitrous oxide. 

Table 2.4.2A  Emission and energy content factors — liquid fuels and certain petroleum-based products for stationary energy purposes 

Item 

Fuel combusted 

Energy content factor 

(GJ/kL unless otherwise indicated) 

Emission factor kg CO2-e/GJ 

(RELEVANT OXIDATION 

FACTORS INCORPORATED) 

CO2 CH4 N2O 

31 Petroleum based oils (other than 38.8 13.9 0.0 0.0 

petroleum based oil used as fuel) 

32 Petroleum based greases 38.8 3.5 0.0 0.0 

33 Crude oil including crude oil 45.3 GJ/t 69.6 0.1 0.2 

condensates 

34 Other natural gas liquids  46.5 GJ/t 61.0 0.1 0.2 

35 Gasoline (other than for use as 34.2 67.4 0.2 0.2 

fuel in an aircraft) 

36 Gasoline for use as fuel in an 33.1 67.0 0.2 0.2 

aircraft 

37 Kerosene (other than for use as 37.5 68.9 0.0 0.2 

fuel in an aircraft) 

38 Kerosene for use as fuel in an 36.8 69.6 0.02 0.2 

aircraft 

39 Heating oil 37.3 69.5 0.03 0.2 

40 Diesel oil 38.6 69.9 0.1 0.2 

41 Fuel oil 39.7 73.6 0.04 0.2 

42 Liquefied aromatic hydrocarbons 34.4 69.7 0.02 0.2 

43 Solvents if mineral turpentine or 34.4 69.7 0.02 0.2 

white spirits 

44 Liquefied petroleum gas 25.7 60.2 0.2 0.2 

45 Naphtha 31.4 69.8 0.00 0.01 

46 Petroleum coke 34.2 GJ/t 92.6 0.07 0.2 

47 Refinery gas and liquids 42.9 GJ/t 54.7 0.02 0.0 

48 Refinery coke 34.2 GJ/t 92.6 0.07 0.2 

Item Fuel combusted Energy content Emission factor 

factor kg CO2-e/GJ 

(GJ/kL unless (RELEVANT OXIDATION otherwise FACTORS INCORPORATED) 

indicated) 

CO2 

CH4 

N2O 

49 Petroleum based products other than: 

(a) petroleum based oils and petroleum based greases mentioned in items 31 and 32; and 

(b) the petroleum based products mentioned in items 33 to 48. 

34.4 

69.8 

0.0 

0.2 

50 Biodiesel 

34.6 

0.0 

0.07 

0.2 

51 Ethanol for use as a fuel in an internal combustion engine 

23.4 

0.0 

0.07 

0.2 

52 Biofuels other than those mentioned in items 50 and 51 

23.4 

0.0 

0.07 

0.2 

Notes on the sources of the factors listed above can be found at Appendix 2A. 

Note: The National Greenhouse and Energy reporting Regulations 2008 makes reference to Petroleum Coke as being a solid substance under Section 1.03. However, for the purposes of estimating emissions under the NGER (Measurement) Determination 2008, Petroleum coke is classified in Part 3 of Schedule 1 under "Liquid and other certain petroleum-based products". This classification is consistent with IPCC Guidelines and the International Energy Agency fuel classification system. 

Table 2.4.2B  Emissions and energy content factors — fuels for transport energy purposes 

Item 

Fuel combusted 

Energy content factor 

(GJ/kL unless otherwise indicated) 

Emission factor kg CO2-e/GJ 

(RELEVANT OXIDATION 

FACTORS INCORPORATED) 

CO2 CH4 N2O 

53 Gasoline (other than for use as fuel in an aircraft) 

34.2 

67.4 

0.5 

1.8 

54 Diesel oil 

38.6 

69.9 

0.1 

0.5 

Item 

Fuel combusted 

Energy content factor 

(GJ/kL unless otherwise indicated) 

Emission factor kg CO2-e/GJ 

(RELEVANT OXIDATION 

FACTORS INCORPORATED) 

CO2 

CH4 

N2O 

55 Gasoline for use as fuel in an aircraft 

33.1 

67.0 

0.05 

0.7 

56 Kerosene for use as fuel in an aircraft 

36.8 

69.6 

0.01 

0.6 

57 Fuel oil 

39.7 

73.6 

0.07 

0.6 

58 Liquefied petroleum gas 

26.2 

60.2 

0.6 

0.7 

59 Biodiesel 

34.6 

0.0 

0.7 

1.9 

60 Ethanol for use as fuel in an internal combustion engine 

23.4 

0.0 

0.7 

1.9 

61 Biofuels other than those mentioned in items 59 and 60 

23.4 

0.0 

0.7 

1.9 

Notes on the sources of the factors listed above can be found at Appendix 2A. 

Division 2.4.3—Method 2—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases 

As for solid and gaseous fuels, Method 1 applies national average factors to the estimation of emissions.  More accurate estimates of emissions at a facility level may be obtained by sampling and analysing fuels for qualities that affect emission levels 

when the fuel is combusted.  These qualities include the fuel’s carbon content which may vary from fuel to fuel, albeit reasonably marginally for standard commercial fuels.  

The list of liquid fuels for which emissions must be calculated is given in Table 2.4.3 (taken from Schedule 1 of the National Greenhouse and Energy Reporting Regulations 2008). 

Subdivision 2.4.3.1—Method 2—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases  

2.42  Method 2—emissions of carbon dioxide from the combustion of liquid fuels  

  (1) For subparagraph 2.40(1)(a)(ii), method 2 for estimating emissions of carbon dioxide is: 

Q × EC × EFi i ico oxec 2

Eico2 = - γRCCSco2

  1 000  

where: 

EiCO2 is the emissions of carbon dioxide released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2-e tonnes. 

Qi is the quantity of fuel type (i) combusted from the operation of the facility during the year measured in kilolitres . 

ECi is the energy content factor of fuel type (i) estimated under section 6.5.  

EFiCO2oxec is the carbon dioxide emission factor for fuel type (i) measured in kilograms of CO2-e per gigajoule. 

γ is the factor 1.861 × 10-3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2-e tonnes. 

RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3. 

(2) Method 2 requires liquid fuels to be sampled and analysed in accordance with the requirements in sections 2.44, 2.45 and 2.46. 

2.43  Calculation of emission factors from combustion of liquid fuel 

(1) For section 2.42, the emission factor EFi,CO2,ox,ec from the combustion of fuel type (i) must allow for oxidation effects and must first estimate EFi,co2,ox,kg in accordance with the following formula: 

EFi, co2,ox,kg = Ca  OF  3.664

  100 i  

where: 

Ca is the carbon in the fuel expressed as a percentage of the mass of the fuel as received, as sampled, or as combusted, as the case may be. 

OFi is the oxidation factor 1.0 applicable to liquid fuels. 

Note: 3.664 converts tonnes of carbon to tonnes of carbon dioxide. 

(2) The emission factor derived from the calculation in subsection (1), must be expressed in kilograms of carbon dioxide per gigajoule calculated using the following formula:  

EFi, co2,ox,ec = EFi, co2,ox,kg  ECi 

   Ci  

where: 

ECi is the energy content factor of fuel type (i) estimated under subsection 2.42(1). 

Ci is the density of the fuel expressed in kilograms of fuel per thousand litres as obtained using a Standard set out in section 2.45. 

Subdivision 2.4.3.2—Sampling and analysis 

Under Method 2, representative and unbiased samples of fuels consumed must be obtained for analysis.  Analysis of the fuels for carbon, energy, ash or moisture content must be done in accordance with listed Australian or international standards.  

A listing of applicable standards is given in Section 2.45.  Examples of equivalent standards include those produced by AS, NZ, ASTM, ISO and CEN standards organisations. The standards must be in force on the date stated in section 1.9.   

Unlike solid and gaseous fuels, standards for analysis have not been listed for a number of fuel types, reflecting the apparent absence of such standards particularly for volatile fuels.  It is considered that for many liquid fuels that the use of Method 2 facility-specific emission factors would be likely to bring only marginal benefits in any case.     

A NATA (National Association of Testing Authorities) accredited laboratory or similar laboratory complying with ISO 17025 should be used to conduct the analysis.   

Minimum frequencies of analysis are also provided for in section 2.46.  

2.44  General requirements for sampling under method 2 

(1) A sample of the liquid fuel must be derived from a composite of amounts of the liquid fuel. 

(2) The samples must be collected on enough occasions to produce a representative sample. 

(3) The samples must also be free of bias so that any estimates are neither over nor under estimates of the true value. 

(4) Bias must be tested in accordance with an appropriate standard (if any). 

(5) The value obtained from the samples must only be used for the delivery period or consignment of the liquid fuel for which it was intended to be representative. 

2.45  Standards for analysing samples of liquid fuels 

  (1) Samples of liquid fuel of a type mentioned in column 2 of an item in the following table must be analysed in accordance with a standard (if any) mentioned in: 

  (a) for energy content analysis—column 3 for that item; and  (b) for carbon analysis—column 4 for that item; and  (c) density analysis—column 5 for that item. 

Item 

Fuel 

Energy Content  

Carbon 

Density 

1 

Petroleum based oils (other than petroleum based oils used as fuel) 

N/A 

ASTM D 

5291-02 (2007) 

ASTM D 

1298 – 99 

(2005) 

2 

Petroleum based greases 

N/A 

ASTM D 

5291-02 (2007) 

ASTM D 

1298 – 99 

(2005) 

3 

Crude oil including crude oil condensates 

ASTM D 

240-02 (2007) 

ASTM D 

4809-06 

ASTM D 

5291-02 (2007) 

ASTM D 

1298 – 99 

(2005) 

ASTM D 

5002 – 99 

(2005) 

4 

Other natural gas liquids  

N/A 

N/A 

ASTM D 

1298 – 99 

(2005) 

5 

Gasoline (other than for use as fuel in an aircraft) 

ASTM D 

240-02 (2007) 

ASTM D 

4809-06 

N/A 

ASTM D 

1298 – 99 

(2005) 

6 

Gasoline for use as fuel in an aircraft 

ASTM D 

240-02 (2007) 

ASTM D 

4809-06 

N/A 

ASTM D 

1298 – 99 

(2005) 

7 

Kerosene (other than for use as fuel in an aircraft) 

ASTM D 

240-02 (2007) 

ASTM D 

4809-06 

N/A 

ASTM D 

1298 – 99 

(2005) 

ASTM D 

4052 – 96 

(2002) e1 

8 

Kerosene for use as fuel in an aircraft 

ASTM D 

240-02 (2007) 

ASTM D 

4809-06 

N/A 

ASTM D 

1298 – 99 

(2005) 

ASTM D 

4052 – 96 

(2002) e1 

9 

Heating oil 

ASTM D 

240-02 (2007) 

ASTM D 

4809-06 

ASTM D 

5291-02 (2007) 

ASTM D 

1298 – 99 

(2005) 

Item 

Fuel 

Energy Content  

Carbon 

Density 

10 

Diesel oil 

ASTM D 

240-02 (2007) 

ASTM D 

4809-06 

ASTM D 

5291-02 (2007) 

ASTM D 

1298 – 99 

(2005) 

11 

Fuel oil 

ASTM D 

240-02 (2007) 

ASTM D 

4809-06 

ASTM D 

5291-02 (2007) 

ASTM D 

1298 – 99 

(2005) 

12 

Liquefied aromatic hydrocarbons 

N/A 

N/A 

ASTM D 

1298 – 99 

(2005) 

13 

Solvents if mineral turpentine or white spirits 

N/A 

N/A 

N/A 

14 

Liquefied 

Petroleum Gas 

N/A 

ISO 7941:1988 

ISO 

6578:1991 ISO 

8973:1997 ASTM D 

1657 – 02 

15 

Naphtha 

N/A 

N/A 

N/A 

16 

Petroleum coke 

N/A 

N/A 

N/A 

17 

Refinery gas and liquids 

N/A 

N/A 

N/A 

18 

Refinery coke 

N/A 

N/A 

N/A 

19 

Petroleum based products other than: 

(a) petroleum based oils and petroleum based greases mentioned in items 1and 2 

(b) the petroleum based products mentioned in items 3 to 18 

N/A 

N/A 

N/A 

20 

Biodiesel  

N/A 

N/A 

N/A 

21 

Ethanol for use as a fuel in an 

N/A 

N/A 

N/A 

Item 

Fuel 

Energy Content  

Carbon 

Density 

internal 

combustion engine  

22 

Biofuels other than those mentioned in items 20 and 21 

N/A 

N/A 

N/A 

(2) A liquid fuel of a type mentioned in column 2 of an item in the table in subsection (1) may also be analysed for energy content, carbon and density in accordance with a standard that is equivalent to a standard mentioned in columns 3, 4 and 5 for that item. 

(3) Analysis must be undertaken by an accredited laboratory or by a laboratory that meets requirements equivalent to those in AS ISO/IEC 17025:2005. 

2.46  Frequency of analysis 

  Liquid fuel of a type mentioned in column 2 of an item in the following table must be analysed for the parameter mentioned in column 3 for that item at least at the frequency mentioned in column 4 for that item. 

Item 

Fuel 

Parameter 

Frequency 

1 

All types of liquid fuel 

Carbon 

Quarterly or by delivery of the fuel 

2 

All types of liquid fuel 

Energy 

Quarterly or by delivery of the fuel 

Fuel combustion

Division 2.4.4—Method 3—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases 

As for solid and gaseous fuels, Method 3 is a variation on Method 2.  Method 3 provides for the same requirements of Method 2 except that sampling of fuels should also be conducted in accordance with listed Australian or international standards in section 2.47 or by an equivalent standard.  Once sampling of the fuel has been conducted in accordance with the standard, the analysis of the fuel for carbon and other factors should be conducted as for Method 2.  Emissions may then be estimated in accordance with Method 2.   

2.47  Method 3—emissions of carbon dioxide from the combustion of liquid fuels 

(1) For subparagraph 2.40(1)(a)(iii) and subject to this section, method 3 for estimating emissions of carbon dioxide is the same as method 2 under section 2.42. 

(2) In applying method 2 under section 2.42, liquid fuels must be sampled in accordance with a standard specified in the table in subsection (3). 

(3) A standard for sampling a liquid fuel of a type mentioned in column 2 of an item in the following table is specified in column 3 for that item. 

item 

Liquid Fuel 

Standard 

1 

Petroleum based oils (other than petroleum based oils used as fuel) 

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

2 

Petroleum based greases 

3 

Crude oil including crude oil condensates 

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

ASTM D 4177 – 95 (2005) 

4 

Other natural gas liquids  

ASTM D1265 – 05 

5 

Gasoline (other than for use as fuel in an aircraft) 

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

ASTM D 4177 – 95 (2005) 

item 

Liquid Fuel 

Standard 

6 

Gasoline for use as fuel in an aircraft 

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

ASTM D 4177 – 95 (2005) 

7 

Kerosene (other than for use as fuel in an aircraft) 

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

ASTM D 4177 – 95 (2005) 

8 

Kerosene for use as fuel in an aircraft 

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

ASTM D 4177 – 95 (2005) 

9 

Heating oil 

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

ASTM D 4177 – 95 (2005) 

10 

Diesel oil 

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

ASTM D 4177 – 95 (2005) 

11 

Fuel oil 

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

ASTM D 4177 – 95 (2005) 

12 

Liquefied aromatic hydrocarbons  

ASTM D 4057 – 06 

13 

Solvents if mineral turpentine or white spirits 

ASTM D 4057 – 06 

14 

Liquefied Petroleum Gas 

ASTM D1265 – 05) ISO 4257:2001 

15 

Naphtha 

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

16 

Petroleum coke 

ASTM D 4057 – 06 

17 

Refinery gas and liquids 

ASTM D 4057 – 06 

18 

Refinery coke 

ASTM D 4057 – 06 

19 

Petroleum based products other than: 

ISO 3170:2004 

item 

Liquid Fuel 

Standard 

(a) petroleum based oils and petroleum based greases mentioned in items 1 and 2; and  

(b) the petroleum based products mentioned in items 3 to 18 

ISO 3171:1988 

ASTM D 4057 – 06 

20 

Biodiesel  

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

ASTM D 4177 – 95 (2005) 

21 

Ethanol for use as a fuel in an internal combustion engine 

ASTM D 4057 – 06 

22 

Biofuels other than those mentioned in items 20 and 21 

ISO 3170:2004 

ISO 3171:1988 

ASTM D 4057 – 06 

ASTM D 4177 – 95 (2005) 

(4) A liquid fuel may also be sampled in accordance with a standard that is equivalent to a standard set out in the table in subsection (3) in relation to that liquid fuel. 

Division 2.4.5—Method 2—emissions of methane and nitrous oxide from liquid fuels other than petroleum based oils or greases 

Method 2 for the estimation of methane and nitrous oxide emissions from the combustion of liquid fuels is very similar to Method 1 - however the Reporter uses an equipment-specific emission factor set out in Schedule 1 of the Determination.  This approach is only available for post-2004 vehicles and certain trucks with specified engine designs.  

No sampling and analysis of fuels are required for this Method 2 for non-carbon dioxide emissions.   This is because the emissions of methane and nitrous oxide depend, in general, on combustion conditions and the equipment used to combust the fuel. In contrast, the carbon dioxide emissions depend on the chemical qualities of the fuels themselves which can only be ascertained by analysis.   

2.48  Method 2—emissions of methane and nitrous oxide from the combustion of liquid fuels 

(1) For subparagraph 2.40(1)(b)(ii) and subject to subsection (2), method 2 for estimating emissions of methane and nitrous oxide is the same as method 1 under section 2.41. 

(2) In applying method 1 in section 2.41, the emission factor EFijoxec is taken to be the emission factor set out in: 

(a) for combustion of fuel by vehicles manufactured after 2004— columns 5 and 6 of the table in Division 4.2 of Part 4 of Schedule 1; and 

(b) for combustion of fuel by trucks that meet the design standards mentioned in column 3 of the table in Division 4.3 of Part 4 of Schedule 1—columns 6 and 7 of the table in that Division. 

Table 2.4.5A Fuel combustion — liquid fuels for transport energy purposes for post-2004 vehicles 

Item Fuel combusted Energy content Emission factor 

factor kg CO2-e/GJ 

GJ/kL (RELEVANT OXIDATION 

FACTORS INCORPORATED) 

CO2 

CH4 

N2O 

64 Gasoline (other than for use as fuel in an aircraft) 

34.2 

67.4 

0.02 

0.2 

65 Diesel oil 

38.6 

69.9 

0.01 

0.6 

66 Liquefied petroleum gas 

26.2 

60.2 

0.4 

0.3 

67 Ethanol for use as fuel in an internal combustion engine 

23.4 

0.0 

0.2 

0.2 

Notes on the sources of the factors listed above can be found at Appendix 2A. 

Table 2.4.5B 

Fuel combustion — liquid fuels for transport energy purposes for certain trucks 

Item Fuel type 

Heavy vehicles Energy content Emission factor 

design standard factor kg CO2-e/GJ 

GJ/kL (RELEVANT OXIDATION 

FACTORS INCORPORATED) 

CO2 

CH4 

N2O 

68 Diesel oil 

Euro iv or higher 

38.6 

69.9 

0.06 

0.5 

69 Diesel oil 

Euro iii 

38.6 

69.9 

0.1 

0.5 

70 Diesel oil 

Euro i 

38.6 

69.9 

0.2 

0.5 

Notes on the sources of the factors listed above can be found at Appendix 2A. 

Example 

A company consumes 35 000 kL (kilolitres) of diesel oil: 25 000 kL for transport purposes (with a post-2004 vehicle fleet) and 10 000 kL for stationary energy purposes.  The Reporter elects to use Method 1 (Division 2.4.2) for each of the three greenhouse emission gases (j) (carbon dioxide, methane and nitrous oxide) for the diesel consumed for stationary energy purposes and Method 2 for methane and nitrous oxide emissions from diesel consumed for transport by post 2004 vehicles.  Emissions are estimated as follows: 

Q

E =  ij iCiEFijoxec

1 000  

where: 

Eij is emissions of gas type (j) released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2-e tonnes. 

Qi is the quantity of the fuel type (i) combusted from the operation of the facility during the year measured in tonnes and estimated under Division 2.4.6. In this case 25 000 kL of diesel is used for transport purposes and 10 000kL of diesel is for stationary energy purposes. 

ECi is the energy content factor of fuel type (i) estimated under section 6.5 

(a) for stationary energy purposes — column 3 of the table 2.4.2A (Part 3 of Schedule 1 of the Determination). In this case being 38.6 GJ/kL. 

(b) for post-2004 vehicles — column 3 of table 2.4.5A (Division 4.2 of Part 4 of Schedule 1 of the Determination). In this case being 38.6 GJ/kL. 

EFoxij is the emission factor for each gas type (j) released from the operation of the facility during the year (which includes the effect of a default oxidation factor) measured in kilograms CO2- e per gigajoule of the fuel type (i) according to source as mentioned in: 

(a) for stationary energy purposes — columns 4-6 of the table 2.4.2A (Part 3 of Schedule 1 of the Determination); and 

(b) for post-2004 vehicles — column 4-6 of table 2.4.5A (Division 4.2 of Part 4 of Schedule 1 of the Determination). 

Therefore, emissions of greenhouse gases (carbon dioxide, methane and nitrous oxide) in tonnes of CO2-e are estimated as follows:  

  Combustion of diesel oil for stationary energy purposes (Method 1):  

Emissions of carbon dioxide  

= (10 000 x 38.6 x 69.9)/1 000 

= 26, 981 t CO2-e 

 Emissions of methane  

= (10 000 x 38.6 x 0.1)/1 000 

= 39 t CO2-e 

  Emissions of nitrous oxide  

= (10 000 x 38.6 x 0.2)/1 000 

= 77 t CO2-e 

Combustion of diesel oil for transport purposes for post-2004 vehicles:  

Emissions of carbon dioxide   

= (25 000 x 38.6 x 69.9)/1 000 

= 67,454 t CO2-e  

Emissions of methane  (Method 2) 

= (25 000 x 38.6 x 0.01)/1 000  

= 10 t CO2-e 

Emissions of nitrous oxide (Method 2) 

= (25 000 x 38.6 x 0.6)/1 000  

= 579  t CO2-e 

Fuel combustion

Division 2.4.5A—Methods for estimating emissions of carbon dioxide from petroleum based oils or greases 

This method applies to the consumption of petroleum based oils or greases (PBOGs) as lubricants or greases. 

PBOGs that are consumed without combustion should be reported under section 2.68. Some scenarios to which section 2.68 of the Determination would apply include: 

• coating of metal products with petroleum-based oils for corrosion protection; 

• use of petroleum-based oils as hydraulic fluids (including brake fluids); 

• greases used in electric motor applications; 

• oils used in gearboxes; 

• use of petroleum-based oils as components of products such as oil-extended polymers or elastomers, paints, solvents or sprays; 

• use of oils in electrical equipment (e.g. transformer oil); and 

• use of oils as heat transfer fluids or working fluids in industrial applications. 

Depending on the operating conditions of the facility and the number and complexity of consumption points, reporters may wish to use the flash point of the fuel to identify whether or not the PBOG could be combusted. The flash point is the lowest temperature at which a product can form a vapour/air mixture capable of combustion. It is a measurable and testable physical property of all petroleum-based products and is stated on the Material Safety Data Sheet of every PBOG product sold. 

By comparing the maximum operating temperature that each PBOG is likely to be exposed, it is possible to show that a given PBOG is appropriately reported as consumed without combustion. 

2.48A  Method 1—estimating emissions of carbon dioxide using an estimated oxidation factor 

  (1) For paragraph 2.40A(1)(a), method 1 for estimating emissions of carbon dioxide from the consumption of petroleum based oils or petroleum based greases using an estimated oxidation factor is: 

EFpogco2oxec

Epogco2  =  Qpog  ECpogco2  

  1 000  

where: 

Epogco2 is the emissions of carbon dioxide released from the consumption of petroleum based oils or petroleum based greases from the operation of the facility during the year measured in CO2-e tonnes. 

Qpog is the quantity of petroleum based oils or petroleum based greases consumed from the operation of the facility, estimated in accordance with Division 2.4.6. 

ECpogco2 is the energy content factor of petroleum based oils or petroleum based greases measured in gigajoules per kilolitre as mentioned in Part 3 of Schedule 1. 

EFpogco2oxec has the meaning given in subsection (2). 

(2) EFpogco2oxec is: 

(a) the emission factor for carbon dioxide released from the operation of 

the facility during the year (which includes the effect of an oxidation factor) measured in kilograms CO2-e per gigajoule of the petroleum based oils or petroleum based greases as mentioned in Part 3 of Schedule 1; or 

(b) to be estimated as follows: 

  EFpogco2oxec =  OFpog  EFpogco2ec where: 

OFpog is the estimated oxidation factor for petroleum based oils or petroleum based greases. 

EFpogco2ec is 69.9. 

(3) For OFpog in paragraph (2)(b), estimate as follows: 

Qpog  Oil Transferred Offsite

OFpog = pog

  Qpog  

where: 

Qpog is the quantity of petroleum based oils or petroleum based greases consumed from the operation of the facility, estimated in accordance with Division 2.4.6. 

Oil Transferred Offsitepog is the quantity of oils, derived from petroleum based oils or petroleum based greases, transferred outside the facility, and estimated in accordance with Division 2.4.6. 

2.48B  Method 2—estimating emissions of carbon dioxide using an estimated oxidation factor 

  For paragraph 2.40A(1)(b), method 2 is the same as method 1 but the emission factor EFpogco2ec must be determined in accordance with Division 2.4.3. 

2.48C  Method 3—estimating emissions of carbon dioxide using an estimated oxidation factor 

  For paragraph 2.40A(1)(c), method 3 is the same as method 1 but the emission factor EFpogco2ec must be determined in accordance with Division 2.4.4. 

Division 2.4.6—Measurement of quantity of liquid fuels 

2.49  Purpose of Division 

This Division sets out how quantities of liquid fuels combusted from the operation of a facility are to be estimated for the purpose of working out the emissions released from the combustion of that fuel. 

The quantity of consumption of each of the fuel types specified in the Regulations, Schedule 1, are to be estimated according to one of the criterion set out below. 

The fuel types listed principally reflect the lists of fuels currently used by the Bureau 

of Resources and Energy Economics (BREE) to prepare Australia’s Energy Statistics and report, inter alia, on behalf of the Australian Government to the International Energy Agency.  

Separate estimates of the quantities of each fuel type consumed for the purpose of making electricity; for use as reductants or feedstocks; for use in transport (excluding international bunker fuels) and other stationary energy are required.     

The quantities of fuels consumed for transport should exclude those quantities consumed for international transport purposes, if any, to reflect international reporting requirements for the national inventory. It is intended that this may be achieved by excluding international bunker fuels as defined in National Greenhouse and Energy Reporting Regulations 2008, Regulation 1.03, and that the point of differentiation between domestic and international consumption will be identical to that provided by the Customs Act 1901 which is used also for excise and GST purposes.   

Biogenic carbon fuels attract a zero carbon dioxide emission factor to ensure that the reporting system aligns with the reporting requirements of the IPCC reporting guidelines for national inventories and the practice, for example, of the EU for its Emissions Trading System.  Non-carbon dioxide emissions from the combustion of biogenic fuels must be reported, however.  

Division 2.4.6 specifies the criteria for the estimation of the amounts of liquid fuels combusted from the operation of a facility during a year.  There are four criteria available for the estimation of quantities combusted.  Under the National Greenhouse and Energy Reporting Regulations 2008, the criterion chosen will need to be reported.  

The criteria include: 

(a) Criterion A - the amount of the fuel delivered for the facility during the year as evidenced by invoices or delivery records issued by the vendor of the fuel (2.50);  

(b) Criterion AA - indirect measurement at the point of consumption - based on the amount of fuel delivered for the facility and adjusted for changes in stocks (2.51); 

(c) Criterion AAA - direct measurement at the point of consumption - based on the amount of fuel combusted as estimated by measurement equipment that comply with specified standards (2.52); 

(d) Criterion BBB - simplified measurement of consumption (2.53). 

Measuring equipment calibrated to a measurement requirement in Section 2.52 refers to the standards required for measurement to support excise taxation arrangements.     

In Section 2.52 it is intended that measured data for fuels delivered would also meet the Criterion AAA under certain circumstances.  These circumstances are that stocks of the fuel consumed at the facility are less than 5% of fuel consumption for the facility during the year and that the stock changes by less than 1% during the year.   

The simplified measurement of consumption criterion is available in those cases where the Reporter does not purchase fuel and where the Reporter does not have metering equipment installed that meets the requirements of criterion AAA.  In these cases, it is intended that Reporters should estimate consumption using metering devices or measurement techniques in practice in the industry.  Such measurements would need to meet the criteria set out 1.13 of transparency, comparability, accuracy and completeness. These data would be classified and reported as BBB criterion data.   

The restriction on the choice of criteria at 2.50 (3) is designed to ensure time series consistency of the measurements. 

2.50  Criteria for measurement 

(1) For the purpose of calculating the combustion of a liquid fuel from the 

operation of a facility for a year and, in particular, for Qi in sections 2.41 

and 2.42 the combustion must be estimated in accordance with this section. 

Acquisition involves commercial transaction 

(2) If the acquisition of the liquid fuel involves a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria: 

(a) the amount of the liquid fuel delivered for the facility during the year as evidenced by invoices issued by the vendor of the fuel (criterion 

A); 

(b) as provided in section 2.51 (criterion AA);  (c) as provided in section 2.52 (criterion AAA). 

(3) If, during a year, criterion AA, or criterion AAA using paragraph 2.52(2)(a), is used to estimate the quantity of fuel combusted then, in each year following that year, only criterion AA, or criterion AAA using paragraph 2.52(2)(a), (respectively) may be used. 

Acquisition does not involve commercial transaction 

(4) If the acquisition of the liquid fuel does not involve a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria:  

  (a) as provided in paragraph 2.52(2)(a) (criterion AAA);  (b) as provided in section 2.53 (criterion BBB). 

2.51 Indirect measurement—criterion AA 

  For paragraph 2.50(2)(b), criterion AA is the amount of the liquid fuel 

combusted from the operation of the facility during the year based on amounts delivered during the year (evidenced by invoices) as adjusted for the estimated change in the quantity of the stockpile of the fuel for the facility during the year. 

2.52 Direct measurement—criterion AAA 

(1) For paragraph  2.50(2)(c), criterion AAA is the measurement during the year of the liquid fuel combusted from the operation of the facility. 

(2) The measurement must be carried out: 

(a) at the point of combustion at ambient temperatures and converted to standard temperatures, using measuring equipment calibrated to a measurement requirement; or 

(b) at ambient temperatures and converted to standard temperatures, at the point of sale of the liquid fuel, using measuring equipment calibrated to a measurement requirement. 

(3) Paragraph (2)(b) only applies if: 

(a) the change in the stockpile of fuel for the facility for the year is less than 1% of total combustion on average for the facility during the year; and 

(b) the stockpile of the fuel for the facility at the beginning of the year is less than 5% of total combustion from the operation of the facility for the year. 

2.53  Simplified consumption measurements—criterion BBB 

  For paragraph 2.50(4)(b), criterion BBB is the estimation of the combustion of a liquid fuel for the year using accepted industry measuring devices or, in the absence of such measuring devices, in accordance with industry practice if the equipment used to measure consumption of the fuel is not calibrated to a measurement requirement.

Part 2.5—Emissions released from fuel use by certain industries 

2.54  Application 

  This Part applies to emissions from petroleum refining, solid fuel transformation (coke ovens) and petrochemical production. 

Division 2.5.1—Energy—petroleum refining 

2.55  Application 

  This Division applies to petroleum refining. 

2.56  Methods 

(1) If: 

(a) the operation of a facility is constituted by petroleum refining; and 

(b) the refinery combusts fuels for energy; 

then the methods for estimating emissions during a year from that combustion are as provided in Parts 2.2, 2.3 and 2.4. 

(2) The method for estimating emissions from the production of hydrogen by the petroleum refinery must be in accordance with the method set out in section 5 of the API Compendium. 

(3) Fugitive emissions released from the petroleum refinery must be estimated using methods provided for in Chapter 3. 

Division 2.5.2—Energy—manufacture of solid fuels 

2.57  Application 

  This Division applies to solid fuel transformation through the pyrolysis of coal or the coal briquette process. 

2.58  Methods 

(1) One or more of the following methods must be used for estimating emissions during the year from combustion of fuels for energy in the manufacture of solid fuels: 

(a) if a facility is constituted by the manufacture of solid fuel using coke 

ovens as part of an integrated metalworks—the methods provided in Part 4.4 must be used; and 

(b) in any other case—one of the following methods must be used: 

(i) method 1 under subsection (3); 

(ii) method 2 under subsections (4) to (7);  (iii) method 3 under subsections (8) to (10);  (iv) method 4 under Part 1.3. 

(2) These emissions are taken to be emissions from fuel combustion. 

Method 1 

(3) Method 1, based on a carbon mass balance approach, is: 

Step 1 Work out the carbon content in fuel types (i) or carbonaceous input material delivered for the activity during the year, measured in tonnes of carbon, as follows: 

i CCF i  Qi where: 

i means the sum of the carbon content values obtained for all fuel types (i) or carbonaceous input material. 

CCFi is the carbon content factor mentioned in Schedule 3,  measured in tonnes of carbon, for each appropriate unit of fuel type (i) or carbonaceous input material consumed during the year from the operation of the activity. 

Qi is the quantity of fuel type (i) or carbonaceous input material  delivered for the activity during the year, measured in an appropriate unit and estimated in accordance with criterion A in Divisions 2.2.5, 2.3.6 and 2.4.6. 

Step 2 

Work out the carbon content in products (p) leaving the activity during the year, measured in tonnes of carbon, as follows: 

Step 3 

Step 4 

p CCF p  Ap where: 

p means the sum of the carbon content values obtained for all product types (p). 

CCFp is the carbon content factor, measured in tonnes of carbon, for each tonne of product type (p) produced during the year. 

Ap is the quantity of product types (p) produced leaving the activity during the year, measured in tonnes. 

Work out the carbon content in waste by-product types (r) leaving the activity, other than as an emission of greenhouse gas, during the year, measured in tonnes of carbon, as follows: 

r CCF r  Yr 

where: 

r means the sum of the carbon content values obtained for all waste by-product types (r). 

CCFr is the carbon content factor, measured in tonnes of carbon, for each tonne of waste by-product types (r). 

Yr is the quantity of waste by-product types (r) leaving the activity during the year, measured in tonnes. 

Work out the carbon content in the amount of the change in stocks of inputs, products and waste by-products held within the boundary of the activity during the year, measured in tonnes of carbon, as follows: 

i CCFi  S + qi p CCFp  S + ap r CCFr  Syr where: 

i has the same meaning as in step 1. 

CCFi has the same meaning as in step 1. 

ΔSqi is the change in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year, measured in tonnes. 

p has the same meaning as in step 2. 

CCFp has the same meaning as in step 2. 

ΔSap is the change in stocks of product types (p) produced by the  activity and held within the boundary of the activity during the year, measured in tonnes. 

r has the same meaning as in step 3. 

CCFr has the same meaning as in step 3. 

ΔSyr is the change in stocks of waste by-product types (r) produced from the operation of the activity and held within the boundary of the activity during the year, measured in tonnes. 

Step 5 Work out the emissions of carbon dioxide released from the operation of the activity during the year, measured in CO2-e tonnes, as follows: 

(a) add the amounts worked out under steps 2, 3 and 4 to work out a new amount (amount A); 

(b) subtract amount A from the amount worked out under step 1 to work out a new amount (amount B); 

(c) multiply amount B by 3.664 to work out the amount of emissions released from the operation of the activity during the year. 

Method 2 

(4) Subject to subsections (5) to (7), method 2 is the same as method 1 under subsection (3). 

(5) In applying method 1 as method 2, step 4 in subsection (3) is to be omitted and the following step 4 substituted. 

Step 4 Work out the carbon content in the amount of the change in stocks of inputs, products and waste by-products held within the boundary of the activity during the year, measured in tonnes of carbon, as follows: 

i CCF i  Sqi  + p CCFp  Sap  + r CCFr  Syr  + γRCCSco2 where: 

i has the same meaning as in step 1. 

CCFi has the same meaning as in step 1. 

ΔSqi is the change in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year, measured in tonnes. 

p has the same meaning as in step 2. 

CCFp has the same meaning as in step 2. 

  ΔSap is the change in stocks of product types (p) produced by the activity and held within the boundary of the activity during the year, measured in tonnes. 

r has the same meaning as in step 3. 

CCFr has the same meaning as in step 3. 

ΔSyr is the change in stocks of waste by-product types (r) produced 

from the operation of the activity and held within the boundary of the activity during the year, measured in tonnes.1 

  α is the factor 3.664 for converting the mass of carbon dioxide to a mass of carbon. 

  γ is the factor 1.861 × 10-3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2-e tonnes. 

RCCSCO2 is carbon dioxide captured for permanent storage, measured in cubic metres in accordance with Division 1.2.3.

(6) If a fuel type (i) or carbonaceous input material delivered for the activity during the year accounts for more than 5% of total carbon input for the activity, based on a calculation using the factors specified in Schedule 3, sampling and analysis of fuel type (i) or carbonaceous input material must be carried out to determine its carbon content. 

(7) The sampling and analysis is to be carried out using the sampling and analysis provided for in Divisions 2.2.3, 2.3.3 and 2.4.3 that apply to the combustion of solid, gaseous and liquid fuels. 

Method 3 

(8) Subject to subsections (9) and (10), method 3 is the same as method 2 under subsections (4) to (7). 

(9) If a fuel type (i) or carbonaceous input material delivered for the activity during the year accounts for more than 5% of total carbon input for the activity, based on a calculation using the factors specified in Schedule 3, sampling and analysis of fuel type (i) or carbonaceous input material must be carried out to determine its carbon content. 

(10) The sampling and analysis is to be carried out using the methods set out in Divisions 2.2.4, 2.3.4 and 2.4.4 that apply to the combustion of solid, gaseous and liquid fuels. 

Estimating emissions from standalone coke production using method 1 

An example for estimating emissions from a standalone coke production facility using the method 1 carbon mass balance approach is provided below. The example uses coking coal and fuel oil to produce coke. The facility also produces coal tar and waste in the form of un-oxidised carbon, in addition to experiencing stock changes during the year. The relevant data for the coke production facility is outlines in the table below: 

Fuel or product type 

Fuels delivered during the year 

Products produced and leaving the 

activity during the year 

Change 

(increase) in stocks during the year 

Carbon content factor 

(CCF) 

Coke oven coke 

9,000 tonnes 

-300 tonnes 

0.789 

Coking coal 

14,500 tonnes 

500 tonnes 

0.752 

Fuel oil 

100 kilolitres 

0.797 

Coal tar 

400 tonnes 

20 tonnes 

0.837 

Step 1 Calculate the carbon content in fuel types (i) or carbonaceous input material delivered for the activity during the year measured in tonnes of carbon as follows: 

  Where: i CCFiQi  

CCFi is the carbon content factor mentioned in Appendix A measured in tonnes of carbon for each appropriate unit of fuel type (i) or carbonaceous input material consumed during the year from the operation of the activity. 

The Method 1 default carbon content factors can be found in Schedule 3 of the NGER (Measurement) Determination and are shown in the table above. 

Qi is the quantity of fuel type (i) or carbonaceous input material delivered for the activity during the year measured in an appropriate unit and estimated in accordance with criterion A in Division 2.2.5, 2.3.6 and 2.4.6. In this case the quantities of input materials are shown in the table above: 

To calculate the carbon content for the input materials: 

Carbon content of coking coal = (14,500 x 0.752) = 10,904 tonnes of carbon 

Carbon content of fuel oil = (100 x 0.797) = 79.7 tonnes of carbon 

Therefore, total carbon = (10,904 + 79.7)  = 10,983.7 tonnes  

Step 2 Calculate the carbon content in products (p) leaving the activity during the year measured in tonnes of carbon as follows: 

Where: 

p CCFpAp  

CCFp is the carbon content factor measured in tonnes of carbon for each tonne of product type (p) produced during the year. In this case the carbon content factor of each product type is shown in the table above: 

Ap is the quantity of product types (p) produced leaving the activity during the year measured in tonnes. In this case the quantity of products are shown in the table above: 

To calculate the carbon content for the products leaving the activity during the year: 

Fuel combustion

Carbon content of coke oven coke = (9,000 x 0.789) = 7,101 tonnes of carbon 

Carbon content of coal tar = (400 x 0.837) = 334.8 tonnes of carbon 

  Therefore, total carbon = (7,101 + 334.8)  = 7435.8 tonnes  

Step 3 Calculate the carbon content in waste by product types (r) leaving the activity, other than as an emission of greenhouse gas, during the year, measured in tonnes of carbon, as follows: 

  Where: 

r CCFrYr  

CCFr is the carbon content factor measured in tonnes of carbon for each tonne of waste by product types (r). 

Yr is the quantity of waste by product types (r) leaving the activity during the year measured in tonnes. In this case the quantities of waste by-products are non-oxidised carbon, estimated in accordance with the NGER (Measurement) Determination as being 100 tonnes. 

To calculate the carbon content for the waste products leaving the activity during the year: 

Carbon content of non-oxidised carbon = 100 tonnes of carbon  

  Therefore, total carbon  = 100 tonnes 

Step 4 Calculate the carbon content in the amount of the increase in stocks of inputs, products and waste by products held within the boundary of the activity during the year in tonnes of carbon as follows: 

Where:  

i CCFi S + qi p CCFp S + ap r CCFrSyr 

CCFi has the same meaning as in step 1. 

ΔSqi is the increase in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year measured in tonnes. In this case the quantities of increases in stocks are shown in the table above: 

To calculate the carbon content for increase of fuel types 

Carbon content of coking coal = (500 x 0.752) = 376 tonnes of carbon 

Therefore, total carbon = 376 tonnes  

CCFp has the same meaning as in step 2. 

ΔSap is the increase in stocks of product types (p) produced by the activity and held within the boundary of the activity during the year measured in tonnes. In this case the quantities of product types shown in the table above: 

To calculate the carbon content for increase in stock of product type: 

Carbon content of coal tar = (20 x 0.837) = 16.74 tonnes of carbon 

Carbon content of coke oven coke = (-300 x 0.789) = -236.7 tonnes of carbon 

Therefore, total carbon = (16.74 + -236.7)  = -219.96 tonnes  

CCFr has the same meaning as in step 3. 

ΔSyr is the increase in stocks of waste by product types (r) produced from the operation of the activity and held within the boundary of the activity during the year measured in tonnes. 

There was no change in waste product stock produced and held during the year. 

To calculate the total carbon contained in the change of stock: 

Carbon content of increase in fuel types = 376 tonnes 

Carbon content of increase in product types = -219.96 tonnes 

Carbon content of increase in waste by-products = 0 tonnes 

Therefore, total carbon = (376 + -219.6 + 0)  = 156.04 tonnes 

Step 5 Calculate the emissions of carbon dioxide released from the operation of the activity during the year measured in CO2 e tonnes as follows: 

(a) add the amounts worked out under steps 2, 3 and 4 to work out a new amount (amount A); 

In this case A is: 

  = 7435.8 + 100  + 156.04 

  = 7,691.84 tonnes of carbon 

(b) subtract amount A from the amount worked out under step 1 to work out a new amount (amount B); 

In this case: 

  = 10,983.7   7,691.84 

  = 3,291.86 tonnes of carbon 

  (c) multiply amount B by 3.664 to work out the amount of emissions released from the operation of the activity during a year. 

  = 3,291.86  x 3.664 

  = 12,061.37504 tonnes CO2-e 

Therefore, total carbon balance CO2 emissions from the source = 12,061 tonnes 

Division 2.5.3—Energy—petrochemical production 

2.59  Application 

  This Division applies to petrochemical production (where fuel is consumed as a feedstock). 

2.60  Available methods 

(1) Subject to section 1.18 one of the following methods must be used for estimating emissions released during a year from the operation of a facility that is constituted by an activity that is petrochemical production: 

(a) method 1 under section 2.61; 

(b) method 2 under section 2.62; 

(c) method 3 under section 2.63;  (d) method 4 under Part 1.3. 

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

2.61  Method 1—petrochemical production 

  Method 1, based on a carbon mass balance approach, is: 

Step 1 

Calculate the carbon content in all fuel types (i) delivered for the activity during the year as follows: 

Step 2 

i CCFi Qi  

where: 

i means sum the carbon content values obtained for all fuel types 

(i). 

CCFi is the carbon content factor measured in tonnes of carbon for each tonne of fuel type (i) as mentioned in Schedule 3 consumed in the operation of the activity. 

Qi is the quantity of fuel type (i) delivered for the activity during the year measured in tonnes and estimated in accordance with criterion A in Divisions 2.2.5, 2.3.6 and 2.4.6. 

Calculate the carbon content in products (p) leaving the activity during the year as follows: 

p CCFpAp  

where: 

p means sum the carbon content values obtained for all product types (p). 

CCFp is the carbon content factor measured in tonnes of carbon for each tonne of product (p). 

Ap is the quantity of products produced (p) leaving the activity during the year measured in tonnes. 

Step3 

Calculate the carbon content in waste by-products (r) leaving the activity, other than as an emission of greenhouse gas, during the year as follows: 

Step 4 

r CCFrYr  where: 

r means sum the carbon content values obtained for all waste by-product types (r). 

CCFr is the carbon content factor measured in tonnes of carbon for each tonne of waste by-product (r). 

Yr is the quantity of waste by-product (r) leaving the activity during the year measured in tonnes. 

Calculate the carbon content in the amount of the increase in stocks of inputs, products and waste by-products held within the boundary of the activity during the year as follows: 

i  CCFi S + qi p CCFp S +  CCFap r rSyr where: 

i has the same meaning as in step 1. 

CCFi has the same meaning as in step 1. 

ΔSqi is the increase in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year measured in tonnes. 

p has the same meaning as in step 2. 

CCFp has the same meaning as in step 2. 

ΔSap is the increase in stocks of products produced (p) by the activity and held within the boundary of the activity during the year measured in tonnes. 

r has the same meaning as in step 3. 

CCFr has the same meaning as in step 3. 

ΔSyr is the increase in stocks of waste by-products (r) produced by the activity and held within the boundary of the activity during the year measured in tonnes. 

Step 5 Calculate the emissions of carbon dioxide released from the activity during the year measured in CO2-e tonnes as follows: 

(a) add the amounts worked out under steps 2, 3 and 4 to work out a new amount (amount A) 

(b) subtract amount A from the amount worked out under step 1 to work out a new amount (amount B); 

(c) multiply amount B by 3.664 to work out the amount of emissions released from the activity during a year. 

2.62  Method 2—petrochemical production 

(1) Subject to subsections (2) and (3), method 2 is the same as method 1 under section 2.61 but sampling and analysis of fuel types (i) is used to determine carbon content of the fuel. 

(2) The sampling and analysis is to be carried out using the methods set out in Divisions 2.2.3, 2.3.3 and 2.4.3 that apply to the combustion of solid, liquid or gaseous fuels. 

(3) In applying method 1 as method 2, step 4 in section 2.61 is to be omitted and the following step 4 substituted: 

Step 4 Calculate the carbon content in the amount of the increase in stocks of inputs, products and waste by-products held within the boundary of the activity during the year as follows: 

i CCF i  S + qi p CCF p  S + ap r CCF r  S + yr α γRCCSco2 

where: 

i has the same meaning as in step 1. 

CCFi has the same meaning as in step 1. 

  ΔSqi is the increase in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year measured in tonnes. 

p has the same meaning as in step 2. 

Fuel combustion

CCFp has the same meaning as in step 2.

  ΔSap is the increase in stocks of products produced (p) by the activity and held within the boundary of the activity during the year measured in tonnes. 

r has the same meaning as in step 3. 

CCFr has the same meaning as in step 3.ΔSyr is the increase in stocks of waste by-products (r) produced by the activity and held within the boundary of the activity during the year measured in 

tonnes. 1

  α is the factor 3.664 for converting the mass of carbon dioxide to a mass of carbon. 

  γ is the factor 1.861 x 10-3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2-e tonnes. 

RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3. 

2.63  Method 3—petrochemical production 

(1) Subject to subsections (2) and (3), method 3 is the same as method 1 in section 2.61 but the sampling and analysis of fuel types (i) is used to determine carbon content of the fuel. 

(2) The sampling and analysis is to be carried out using the methods set out in Divisions 2.2.4, 2.3.4 and 2.4.4 that apply to the combustion of solid, liquid or gaseous fuels. 

(3) In applying method 1 as method 3, step 4 in section 2.61 is to be omitted and the following step 4 substituted. 

Step 4 Calculate the carbon content in the amount of the increase in stocks of inputs, products and waste by-products held within the boundary of the activity during the year as follows: 

i CCF i  S + qi p CCF p  S + ap r CCF r  S + yr αγRCCSco2 

where: 

i has the same meaning as in step 1. 

CCFi has the same meaning as in step 1. 

ΔSqi is the increase in stocks of fuel type (i) for the activity and held within the boundary of the activity during the year measured in tonnes. 

p has the same meaning as in step 2. 

CCFp has the same meaning as in step 2. 

ΔSap is the increase in stocks of products produced (p) by the activity and held within the boundary of the activity during the year measured in tonnes. 

r has the same meaning as in step 3. 

CCFr has the same meaning as in step 3. 

ΔSyr is the increase in stocks of waste by-products (r) produced by the activity and held within the boundary of the activity during the year measured in tonnes. 

  α is the factor 3.664 for converting the mass of carbon dioxide to a mass of carbon. 

  γ is the factor 1.861 x 10-3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2-e tonnes. 

RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3.

Part 2.6—Blended fuels 

2.64  Purpose 

  This Part sets out how to determine the amounts of each kind of fuel that is in a blended fuel. 

2.65  Application 

  This Part sets out how to determine the amount of each fuel type (i) that is in a blended fuel if that blended fuel is a solid fuel or a liquid fuel. 

2.66  Blended solid fuels 

(1) In determining the amounts of each kind of fuel that is in a blended solid fuel, a person may adopt the outcome of the sampling and analysis done by the manufacturer of the fuel if: 

(a) the sampling has been done in accordance with subsections 2.12(3) and (4); and 

(b) the analysis has been done in accordance with one of the following 

standards or a standard that is equivalent to one of those standards: 

  (i) CEN/TS15440:2006;  (ii) ASTM D6866—10. 

(2) The person may use his or her own sampling and analysis of the fuel if the sampling and analysis complies with the requirements of paragraphs (1)(a) and (b). 

2.67  Blended liquid fuels 

  The person may adopt the manufacturer’s determination of each kind of fuel that is in a blended liquid fuel or adopt the analysis arrived at after doing both of the following: 

(a) sampling the fuel in accordance with a standard mentioned in subsections 2.47(3) and (4); 

(b) analysing the fuel in accordance with ASTM: D6866—10 or a 

standard that is equivalent to that standard. 

These standards include the following approaches to quantification: 

Manual sorting (CEN/TS 15440:2006) 

The manual sorting technique involves a sample of the solid blended fuel being sorted by hand into sub-fractions of biomass and non-biomass matter. 

This procedure however is limited to fuels with a minimum particle size greater than 1 cm and only applies to blends of solid fuels. 

Selective dissolution (CEN/TS 15440:2006) 

The selective dissolution method for the determination of the biomass content involves the treatment of a sample of blended solid fuel with concentrated sulphuric acid topped with hydrogen peroxide. The biomass in the solid recovered fuel will selectively dissolve and the non-biomass will remain in the residue. 

This technique is not applicable to the following blended fuels: 

• charcoal, peat and solid fossil fuels like hard coal, coke, brown coal and lignite and to mixtures of these and solid recovered fuels; 

• solid recovered fuels that contain more than 10 % of natural and/or synthetic rubber residues; 

• solid recovered fuels that contain a combination of more than 5 % by weight of: o nylon, polyurethane or other polymers containing molecular amino groups; o biodegradable plastics of fossil origin; 

• solid recovered fuels that contain a combination of more than 5 % by weight of: o wool or viscose; o non-biodegradable plastics of biogenic origin; o oil or fat present as a constituent of biomass. 

Radiocarbon Analysis 

The ASTM D 6866-08 standard also provides for a radiocarbon analysis method. The standard describes techniques for determining the biogenic content of solid, liquid and gaseous samples using radiocarbon analysis. The basic premise is that Carbon14 (14C), a radioactive isotope of carbon, has a half life of 5,730 years once it is no longer part of a living organism. This means that no 14C will remain in fossil fuels because it has completely decayed, whereas in recent biomass, such as wood, a portion of 14C still remains.  

In effect, it is argued that biogenic matter contains a well characterized amount of carbon-14 that is easily distinguished from other materials such as fossil fuels that do not contain any carbon-14.  Since the amount of carbon-14 in biomass is well known, a percentage of biogenic carbon can be calculated easily from the overall carbon atoms in the sample. 

This technique may be applied to any type of blended fuel including gaseous, liquid and solid fuels. The technique may be used to analyse the fuels directly or can be used to analyse the combustion gases once the fuel has being burned. The latter technique may be useful where direct emissions monitoring systems are already in place to measure CO2 emissions and where sampling fuels can be difficult. 

Part 2.7—Estimation of energy for certain purposes 

2.68  Amount of energy consumed without combustion 

  For paragraph 4.22(1)(b) of the Regulations: 

(a) the energy is to be measured: 

(i) for solid fuel—in tonnes estimated under Division 2.2.5; or 

(ii) for gaseous fuel—in cubic metres estimated under 

Division 2.3.6; or 

(iii) for liquid fuel—in kilolitres estimated under Division 2.4.6; and  (iv) for electricity—in kilowatt hours: 

(A) worked out using the evidence mentioned in 

paragraph 6.5(2)(a); or 

(B) if the evidence mentioned in paragraph 6.5(2)(a) is 

unavailable—estimated in accordance with paragraph 6.5(2)(b). 

(b) the reporting threshold is: 

(i) for solid fuel—20 tonnes; or 

(ii) for gaseous fuel—13 000 cubic metres; or 

(iii) for liquid fuel—15 kilolitres; or 

(iv) for electricity consumed from a generating unit with a maximum capacity to produce less than 0.5 megawatts of electricity—100 000 kilowatt hours; or 

(v) for all other electricity consumption—20 000 kilowatt hours. 

Example: A fuel is consumed without combustion when it is used as a solvent or a flocculent, or as an ingredient in the manufacture of products such as paints, solvents or explosives. 

Examples of non-combustive use of fuels 

• When used directly in a non-fuel manner – for example, fuels used directly as a solvent or a flocculent; 

• When used as an ingredient in the manufacture of short-life products such as paints, cleaning agents and explosives manufactured for sale; 

• When packaged for non-internal combustion engine use (restricted to containers less than 20 litres and kerosene, mineral turpentine, white spirit, liquid aromatic hydrocarbons and other petroleum products as defined in 10.28 of the schedule to the Excise Tariff Act); 

• When blended with other products and then packaged for non-internal combustion engine use; 

• When unprocessed natural gas is consumed to create natural gas distributed in a pipeline. 

• Some uses of petroleum based oils and greases. Division 2.4.5A provides more guidance on the reporting of petroleum based oils and greases. 

Note the reporting thresholds in 2.68 apply to each fuel type individually. For example, where a facility consumes 10 kL of diesel and 10 kL of solvents for noncombustion purposes this facility is not required to report under this provision.  

2.69  Apportionment of fuel consumed as carbon reductant or feedstock and energy 

  (1) This section applies, other than for Division 2.5.3, if: 

(a) a fuel type as provided for in a method is consumed from the 

operation of a facility as either a reductant or a feedstock; and 

(b) the fuel is combusted for energy; and 

(c) the equipment used to measure the amount of the fuel for the 

relevant purpose was not calibrated to a measurement requirement. 

Note: Division 2.5.3 deals with petrochemicals. For petrochemicals, all fuels, whether used as a feedstock, a reductant or combusted as energy are reported as energy. 

  (2) The amount of the fuel type consumed as a reductant or a feedstock may be estimated: 

(a) in accordance with industry measuring devices or industry practice; or 

(b) if it is not practicable to estimate as provided for in paragraph (a)— to be the whole of the amount of the consumption of that fuel type from the operation of the facility. 

  (3) The amount of the fuel type combusted for energy may be estimated as the difference between the total amount of the fuel type consumed from the operation of the facility and the estimated amount worked out under subsection (2). 

Fuel combustion

2.70  Amount of energy consumed in a cogeneration process 

Cogeneration processes are situations where two products – electricity and another product – are produced from the consumption of a single quantity of fuel.  

This section specifies that for the purpose of complying with the National Greenhouse and Energy Reporting Regulations 2008, subregulation 4.23 (3), the quantity of fuel consumed and allocated to the production of electricity should be estimated using the efficiency method as described in the Allocation of Emissions from a Combined Heat and Power (CHP) Plant Guide to calculation worksheets (September 2006) v1.0 (the cogeneration guide) issued by World Resource Institute and World Business Council for Sustainable Development unless the heat is to be used for producing mechanical work when the work potential method described in the cogeneration guide may be used. 

The efficiency method is the preferred method of the World Resource Institute and World Business Council for Sustainable Development.  Limiting the approaches that can be used provides for more consistent interpretation of reported data and establishes well-understood boundaries for all data reported.   

(1) For subregulation 4.23(3) of the Regulations and subject to subsection (3), the method is the efficiency method. 

(2) The efficiency method is as described in the publication entitled 

Allocation of Emissions from a Combined Heat and Power (CHP) Plant 

Guide to calculation worksheets (September 2006) v1.0 issued by the World Resource Institute and World Business Council for Sustainable Development. 

(3) Where heat is to be used mainly for producing mechanical work, the work potential method may be used. 

(4) The work potential method is as described in the publication entitled 

Allocation of Emissions from a Combined Heat and Power (CHP) Plant 

Guide to calculation worksheets (September 2006) v1.0 issued by the World Resource Institute and World Business Council for Sustainable Development. 

2.71  Apportionment of energy consumed for electricity, transport and for stationary energy 

Apportionment of fuels consumed between various purposes is considered to be less critical than the overall estimate of fuel consumed for a facility.  Consequently, allocations of fuels consumed between purposes may be determined by facility records based on facility measurement techniques. 

For the purpose of determining fuels consumed in transport, road transport means fuel consumed by a vehicle registered for road use.  

  Subject to section 2.70, the amount of fuel type (i) consumed by a 

reporting corporation or liable entity that is apportioned between electricity generation, transport (excluding international bunker fuels) and other stationary energy purposes may be determined using the records of the corporation or liable entity if the records are based on the measurement equipment used by the corporation or the liable entity to measure consumption of the fuel types. 

Appendix 2A Notes on Energy and Emission 

Factors 

The following notes apply to energy content and emission factors in the following tables: 

• Table 2.2.2 

• Table 2.3.2 

• Table 2.4.2A 

• Table 2.4.2B 

• Table 2.4.5A  

• Table 2.4.5B 

1. Energy value: Source – DCCEE analysis of NGER reporting data for reporting years 2008-09 to 2010-11 and industry advice.  CO2 emission factor: Source - National Inventory Report 2006, Department of Climate Change.  .  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency and Energy Efficiency. 

1A. Energy value: Source – DCCEE analysis of NGER reporting data for reporting years 2008-09 to 2010-11 and industry advice.  CO2 emission factor: Source - National Inventory Report 2006, Department of Climate Change.  .  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency and Energy Efficiency. 

1B. Energy value: Source – DCCEE analysis of NGER reporting data for reporting years 2008-09 to 2010-11 and industry advice.  CO2 emission factor: Source - National Inventory Report 2006, Department of Climate Change.  .  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency and Energy Efficiency. 

2. Energy value: Source – AGEIS database, Department of Climate Change and Energy 

Efficiency (based on facility reports).   CO2 emission factor: Source - AGEIS database, Department of Climate Change and Energy Efficiency (based on facility reports).  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency.  

3. Energy value: Source – ABARE1 (washed coking).   CO2 emission factor: Source - National Inventory Report 2006, Department of Climate Change.  .  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency.  

4. Energy value: Source – ABARE1. CO2 emission factor: Source - AGEIS database, Department of Climate Change and Energy Efficiency (based on facility reports).  .  Non-CO2 factors:  Source: 

AGEIS database, Department of Climate Change and Energy Efficiency. 

5. Energy value: Source – ABARE1. CO2 emission factor: Source – National Inventory Report 

2006, Department of Climate Change.  .  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency.  

6. Energy value: Source – ABARE1. CO2 emission factor: Source – National Inventory Report 

2006, Department of Climate Change (coal tar).  .  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency. 

7. See (4) 

8. Energy value: Source – GHD Review of Sectoral Models, Internal report to the AGO, 2006. 

CO2 emission factor: Source – National Inventory Report 2006, Department of Climate Change.  .  

Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency. 

9. Energy value: Source – IPCC 2006. Derived from NCV using factor of 5% of gross calorific value. CO2 emission factor: Source: IPCC 2006. Derived using conversion factor of 0.95.  .  Non-CO2 factors:  Source: IPCC 2006. Derived using conversion factor of 0.95. 

10. Energy value: Source: ABARE1 (dry wood).  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency. 

11. Energy value: Source: ABARE1 (green wood).  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency.  

12. Energy value: Source – IPCC 2006. Derived from NCV using factor of 5% of gross calorific value.  Non-CO2 factors:  Source: IPCC 2006. Derived using conversion factor of 0.95. 

13. Energy value: Source: ABARE1.  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency. 

14. IPCC 2006. Derived from NCV using factor of 5% of gross calorific value.  Non-CO2 factors:  Source: IPCC 2006. Derived using conversion factor of 0.95. 

15. Energy value: Source – IPCC 2006. Derived from NCV using factor of 5% of gross calorific value.  Non-CO2 factors:  Source: IPCC 2006. Derived using conversion factor of 0.95.  

16. See (14) 

17. Energy value: Source: ABARE1 (weighted average). CO2 emission factor: Source - AGEIS database, Department of Climate Change and Energy Efficiency. Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency. 

18. Energy value: Source: ABARE1 (coal seam methane). CO2 emission factor: Source - AGEIS database, Department of Climate Change and Energy Efficiency. Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency.  

19. Energy value: Source: ABARE1 (coal seam methane). CO2 emission factor: Source - AGEIS database, Department of Climate Change and Energy Efficiency. Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency. 

20. See (17) 

21. See (17) 

22. Energy value: Source: ABARE1 (weighted average). CO2 emission factor: Source – National 

Inventory Report 2006, Department of Climate Change.. Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency. 

23. Energy value: Source: ABARE1. CO2 emission factor: Source – National Inventory Report 

2006, Department of Climate Change. Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency. 

24. Energy value: Source – ABARE1. CO2 emission factor: Source: IPCC 2006. Derived using conversion factor of 0.90.  .  Non-CO2 factors:  Source: IPCC 2006. Derived using conversion factor of 

0.90. 

25. (synthetic natural gas).  CO2 emission factor: Source: 

National Inventory Report 2006, Department of Climate Change..  Non-CO2 factors:  Source: AGEIS database. 

26. Energy value: Source – ABARE1.  CO2 emission factor: Source - AGEIS database, Department of Climate Change and Energy Efficiency. Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency. 

27. See (17) 

28. Energy value: Source – ABARE1.  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency. 

29. Energy value: Source – ABARE1.  Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency. 

30. See (28)  

31. Energy value: Source – ABARE2 (lubricants and greases). CO2 emission factor: Source: 

National Inventory Report 2006, Department of Climate Change (lubricants). Oxidation factor 0.2.  

Non-CO2 factors:  nil. 

32. Energy value: Source – ABARE2 (lubricants and greases). CO2 emission factor: Source: 

National Inventory Report 2006, Department of Climate Change (lubricants). Oxidation factor 0.2.  

Non-CO2 factors:  nil. 

33. Energy value: Source – ABARE2 (weighted average).  CO2 emission factor: Source: IPCC 2006. Derived using conversion factor of 0.95.  .  Non-CO2 factors:  IPCC 2006 (Energy Industries).  

Derived using conversion factor of 0.95. 

34. Energy value: Source – IPCC 2006. Derived from NCV using factor of 5% of gross calorific value. CO2 emission factor: Source: IPCC 2006. Derived using conversion factor of 0.95.  .  Non-CO2 factors:  IPCC 2006 (Energy Industries).  Derived using conversion factor of 0.95. 

35.

2006, Department of Climate Change..  Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

36. Energy value: Source – ABARE2. CO2 emission factor: Source: National Inventory Report 

2006, Department of Climate Change.  Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

37. Energy value: Source – ABARE2 (power kerosene). CO2 emission factor: Source: National 

Inventory Report 2006, Department of Climate Change.  Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

38. Energy value: Source – ABARE2. CO2 emission factor: Source: National Inventory Report 

2006, Department of Climate Change..  Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

39. Energy value: Source – ABARE2. CO2 emission factor: Source: National Inventory Report 

2006, Department of Climate Change..  Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

40. Energy value: Source – ABARE2. CO2 emission factor: Source National Inventory Report 

2006, Department of Climate Change..  Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

41. Energy value: Source – ABARE2 (low sulphur). CO2 emission factor: Source: National Inventory Report 2006, Department of Climate Change. Derived using conversion factor of 0.95.  .  

Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

42. Energy value: Source – ABARE2. Given same energy content as solvents. CO2 emission factor: Source: National Inventory Report 2006, Department of Climate Change (assumed same as solvents)..  Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

43. Energy value: Source – ABARE2. CO2 emission factor: National Inventory Report 2006, Department of Climate Change. Derived using conversion factor of 0.95..  Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

44.

2006, Department of Climate Change.. Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

45. Energy value: Source – ABARE2. CO2 emission factor: Source: National Inventory Report 

2006, Department of Climate Change.. Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

46. Energy value: Source – IPCC 2006. CO2 emission factor: Source: IPCC 2006. Derived using conversion factor of 0.95.. Non-CO2 factors:  IPCC 2006, Manufacturing category. Derived using conversion factor 0.95. 

47. Energy value: Source – ABARE1 (refinery fuel). CO2 emission factor: Source: IPCC 2006. Derived using conversion factor of 0.95.. Non-CO2 factors:  IPCC 2006. Derived using conversion factor 0.95. 

48. See (46) 

49. Energy value: Source – ABARE2. Based on IPCC 2006, given same energy content as solvents. CO2 emission factor: Source National Inventory Report 2006, Department of Climate Change 

(set same as solvents). Oxidation factor 0.99.  Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

50. Energy value: Source – Derived from US Department of Energy. Non-CO2 factors:  IPCC 2006. Derived using conversion factor 0.95. 

51. Energy value: Source – ABARE2. Non-CO2 factors:  IPCC 2006. Derived using conversion factor 0.95. 

52. See (51).  

53. Energy value: Source – ABARE2. CO2 emission factor: Source: National Inventory Report 

2006, Department of Climate Change..  Non-CO2 factors:  AGEIS database Department of Climate Change and Energy Efficiency. 

54.

2006, Department of Climate Change..  Non-CO2 factors:  AGEIS database Department of Climate Change and Energy Efficiency. 

55. Energy value: Source – ABARE2. CO2 emission factor: Source: National Inventory Report 2006, Department of Climate Change..  Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

56. Energy value: Source – ABARE2. CO2 emission factor: Source: National Inventory Report 

2006, Department of Climate Change..  Non-CO2 factors:  AGEIS database Department of Climate Change and Energy Efficiency. 

57. Energy value: Source – ABARE2 (low sulphur). CO2 emission factor: Source: National Inventory Report 2006, Department of Climate Change. Derived using conversion factor of 0.95.  .  

Non-CO2 factors:  AGEIS database Department of Climate Change and Energy Efficiency. 

58. Energy value: Source – Derived from ABARE2. CO2 emission factor: Source: National 

Inventory Report 2006, Department of Climate Change..  Non-CO2 factors:  AGEIS database Department of Climate Change and Energy Efficiency. 

59. Energy value: Source – Derived from US Department of Energy, 2006. Non-CO2 factors: 

IPCC 2006. Derived using conversion factor 0.95. 

60. Energy value: Source – ABARE2.  Non-CO2 factors: IPCC 2006. Derived using conversion factor 0.95. 

61. See (60) 

62. Energy value: Source: ABARE1 (weighted average). CO2 emission factor: Source - AGEIS database, Department of Climate Change and Energy Efficiency.  Non-CO2 factors:  AGEIS database, Department of Climate Change and Energy Efficiency. 

63. Energy value: Source: ABARE1 (weighted average). CO2 emission factor: Source - AGEIS database, Department of Climate Change and Energy Efficiency.   Non-CO2 factors: AGEIS database, Department of Climate Change and Energy Efficiency. 

63A ABARE1.  CO emission factor: Source - AGEIS database, 

Department of Climate Change and Energy Efficiency. Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency 

64B Energy value: Source – ABARE1.  CO2 emission factor: Source - AGEIS database, 

Department of Climate Change and Energy Efficiency. Non-CO2 factors:  Source: AGEIS database, Department of Climate Change and Energy Efficiency 

64. Energy value: Source – ABARE2. CO2 emission factor: Source: National Inventory Report 2006, Department of Climate Change..   Non-CO2 factors: Derived from AGEIS database, Department of Climate Change and Energy Efficiency. 

65. Energy value: Source – ABARE2. CO2 emission factor: Source: National Inventory Report 2006, Department of Climate Change.. Non-CO2 factors:  Derived from AGEIS database, Department of Climate Change and Energy Efficiency. 

66. Energy value: Source – ABARE2. CO2 emission factor: Source: National Inventory Report 2006, Department of Climate Change..  Non-CO2 factors:  Derived from AGEIS database, Department of Climate Change and Energy Efficiency. 

67. Energy value: Source – ABARE2.  Non-CO2 factors:  Derived from AGEIS database, Department of Climate Change and Energy Efficiency. 

68. Energy value: Source – ABARE2. CO2 emission factor: Source: National Inventory Report 2006, Department of Climate Change.. Non-CO2 factors: Derived from AGEIS database, Department of Climate Change and Energy Efficiency. 

69. Energy value: Source – ABARE2. CO2 emission factor: Source National Inventory Report 2006, Department of Climate Change. Non-CO2 factors:  Derived from AGEIS database, Department of Climate Change and Energy Efficiency.  

70. Energy value: Source – ABARE2. CO2 emission factor: Source National Inventory Report 2006, Department of Climate Change.. Non-CO2 factors:  Derived from AGEIS database, Department of Climate Change and Energy Efficiency. 

Chapter 3—Fugitive emissions 

Part 3.1—Preliminary 

3.1  Outline of Chapter 

  This Chapter provides for fugitive emissions from the following: 

(a) coal mining (see Part 3.2); 

(b) oil and natural gas (see Part 3.3);  (c) carbon capture and storage (see Part 3.4). 

Part 3.2—Coal mining—fugitive emissions 

Division 3.2.1—Preliminary 

The principal sources of fugitive greenhouse gases from coal mining include emissions from underground and open cut mining activities and emissions from decommissioned mines. A small amount of emissions are also associated with flaring coal mine waste gas and post-mining activities such as from the stockpiling of coal. This chapter describes the methods for estimating emissions from each of these sources. 

Other sources of emissions arising from the coal production process, such as from the combustion of fuels for energy (e.g. electricity production), are not described in this chapter and must be estimated using the Methods described in other chapters. 

3.2  Outline of Part 

  This Part provides for fugitive emissions from coal mining, as follows: 

(a) underground mining activities (see Division 3.2.2); 

(b) open cut mining activities (see Division 3.2.3); 

(c) decommissioned underground mines (see Division 3.2.4). 

Division 3.2.2—Underground mines 

Subdivision 3.2.2.1—Preliminary 

Fugitive emissions from underground mines involve the release of methane and carbon dioxide during the mining process due to the fracturing of coal seams, overburden and underburden strata. Emissions also arise from post mining activities such as the stockpiling of coal from the release of residual gases within the coal not released during the mining process. Emissions also occur when coal mine waste gas is flared.  

3.3  Application 

  This Division applies to fugitive emissions from underground mining activities (other than decommissioned underground mines). 

3.4  Available methods 

(1) Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by underground mining activities (other than decommissioned underground mines) the methods as set out in this section must be used. 

Methane from extraction of coal 

(2) Method 4 under section 3.6 must be used for estimating fugitive emissions of methane that result from the extraction of coal from the underground mine. 

Note: There is no method 1, 2 or 3 for subsection (2). 

Carbon dioxide from extraction of coal 

(3) Method 4 under section 3.6 must be used for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from the underground mine.  

Note: There is no method 1, 2 or 3 for subsection (3). 

Flaring 

(4) For estimating emissions released from coal mine waste gas flared from the underground mine: 

(a) one of the following methods must be used for estimating emissions of carbon dioxide released: 

(i) method 1 under section 3.14; 

(ii) method 2 under section 3.15; 

(iii) method 3 under section 3.16; and 

(b) one of the following methods must be used for estimating emissions of methane released: 

(i) method 1 under section 3.14; 

(ii) method 2 under section 3.15A; and 

(c) one of the following methods must be used for estimating emissions of nitrous oxide released: 

(i) method 1 under section 3.14; 

(ii) method 2 under section 3.15A. 

Note: The flaring of coal mine waste gas releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 under section 3.14 or method 2 under section 3.15A is a reference to these gases. The same formula in Method 1 is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide and no method 3 or 4 for emissions of methane or nitrous oxide. 

Venting or other fugitive release before extraction of coal 

(5) Method 4 under Part 1.3 must be used for estimating fugitive emissions of 

each gas type, being carbon dioxide and methane, that result from venting or other fugitive release of gas from the underground mine before coal is extracted from the mine. 

Note: There is no method 1, 2 or 3 for subsection (5). 

Post-mining activities 

(6) Method 1 under section 3.17 must be used for estimating fugitive emissions of methane that result from post-mining activities related to a gassy mine. 

Note: There is no method 2, 3 or 4 for subsection (6). 

(7) However, for incidental emissions, another method may be used that is consistent with the principles in section 1.13. 

Summary of available methods, for estimating emissions from underground mines, by emissions of gas type (j) 

CO2 

CH4 

N2O 

Underground mining activities 

Method 1 

NA 

NA 

NO 

Method 2, 3 

NA 

NA 

NO 

Method 4 

Section 3.6 

Section 3.6 

NO 

Post-mining Activities 

Method 1 

NA 

Section 3.17 

NO 

Methods 2, 3 and 4 

NA 

NA 

NO 

Flaring 

Method 1 

Section 3.14 

Section 3.14 

Section 3.14 

Method 2 

Section 3.15 

Section 3.15A 

Section 3.15A  

Method 3 

Section 3.16 

NA 

NA 

Method 4 

NA 

NA 

NA 

Venting 

Methods 1, 2 and 3 

NA 

NA 

NO 

Method 4 

Part 1.3 

Part 1.3 

NO 

NA = Not available.  NO = Not occurring  

Subdivision 3.2.2.2—Fugitive emissions from extraction of coal 

3.5  Method 1—extraction of coal 

  For subsection 3.32(1), method 1 is: 

  E = Q j  EF j 

where: 

Ej is the fugitive emissions of methane (j) that result from the extraction of coal from the mine during the year measured in CO2-e tonnes. 

Q is the quantity of run-of-mine coal extracted from the mine during the year measured in tonnes. 

EFj is the emission factor for methane (j), measured in CO2-e tonnes per tonne of run-of-mine coal extracted from the mine, as follows: 

 (a) for a gassy mine—0.363;  (b) for a non-gassy mine—0.010. 

3.6  Method 4—extraction of coal 

Method 4 for estimating emissions associated with underground mining operations involves directly measuring emissions within ventilation shafts and degasification systems. This Method is dealt with in detail in Part 1.3 of Chapter 1.  

Estimation methods under current applicable state or territory legislation 

In addition to the methods outlined in Part 1.3, Reporters may also directly measure emissions using periodic emissions measurement (PEM) in accordance with elements of relevant State Government legislation. This legislation includes the following: 

Coal Mine Health and Safety Act 2002 (NSW) and the Coal Mine Health and Safety 

Regulation 2006 (NSW) 

Coal Mining Safety and Health Act 1999 (Qld) and the Coal Mining Safety and Health Regulation 2001 (Qld). 

It is intended that, as a minimum, existing practices for the monitoring of gases at underground mines may be maintained as input into the emissions estimation process under Method 4. 

(1) For subsections 3.4(2) and (3), method 4 is: 

  E = COj 2-ej gen, total  j Q ij,cap +  Qij,flared +  Qijtr  

where: 

Ej is the fugitive emissions of gas type (j) that result from the extraction of coal from the mine during the year, measured in CO2-e tonnes. 

CO2-e j gen, total is the total mass of gas type (j) generated from the mine during the year before capture and flaring is undertaken at the mine, measured in CO2-e tonnes and estimated using the direct measurement of emissions in accordance with subsection (2). 

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions of pressure and temperature to CO2-e tonnes, being: 

(a) for methane—6.784 × 10-4 × 25; and  (b) for carbon dioxide—1.861 × 10-3. 

Qij,cap is the quantity of gas type (j) in coal mine waste gas type (i) captured for combustion from the mine and used during the year, measured in cubic metres and estimated in accordance with Division 2.3.6. 

Qij,flared is the quantity of gas type (j) in coal mine waste gas type (i) flared from the mine during the year, measured in cubic metres and estimated in accordance with Division 2.3.6. 

Qijtr is the quantity of gas type (j) in coal mine waste gas type (i) transferred out of the mining activities during the year measured in cubic metres.  

(2) The direct measurement of emissions released from the extraction of coal from an underground mine during a year by monitoring the gas stream at the underground mine may be undertaken by one of the following: 

(a) continuous emissions monitoring (CEM) in accordance with 

Part 1.3;  

(b) periodic emissions monitoring (PEM) in accordance with 

sections 3.7 to 3.13. 

Note: Any estimates of emissions must be consistent with the principles in section 1.13. 

(3) For Qijtr in subsection (1), the quantity of gas type (j) must be estimated in accordance with Division 2.3.6 as if a reference in that Division to quantities of gaseous fuels combusted from the operation of a facility was a reference to quantities of gaseous fuels transferred out of the operation of a facility. 

Emissions from diesel combustion emissions and the ambient CO2 in air 

When estimating fugitive emissions from underground mine, it is important be mindful that Ej in paragraph (1) above represents the fugitive emissions that result from the extraction of coal from the mine. Volumetric flow within underground coal mine ventilation systems may also include gases that arise from sources other than fugitive emissions such as; 

• fuel combustion diesel emissions arising from the use of machinery, while the machinery is in the underground mine, and 

• ambient carbon dioxide present in the air that was drawn into the mine ventilation intake.   

To ensure accurate emission estimation it may be necessary to make a deduction of these non-fugitive source gasses from the gas volumes measured in mine ventilation systems. 

The Determination provides methods for estimating fuel combustion emissions from diesel under Part 2.4, however no specific guidance is given on avoiding any double counting of those emissions entrained in mine ventilation measurements. To ensure accuracy, fuel combustion emissions arising from the use of machinery in the underground mine should be deducted from mine ventilation volumes. 

Any deductions of fuel combustion emissions arising from the use of machinery in the underground mine must be done in accordance with the general principles in 1.13 of the Determination. 

The Determination also provides no specific guidance on the deduction of ambient carbon dioxide from mine ventilation air. However, as in the case above for diesel combustion emissions, the estimation must be done in accordance with the general principles in 1.13 of the Determination. 

3.7  Estimation of emissions 

This section describes how measurements of gas flow rates and concentrations are converted from volumetric flow rates to mass emission estimates. 

(1) To obtain an estimate of the mass emissions rate of gas (j), being methane and carbon dioxide, at the time of measurement at the underground mine, the formula in subsection 1.21(1) must be applied. 

(2) The mass of emissions estimated under the formula must be converted into CO2-e tonnes. 

(3) The average mass emission rate for gas type (j) measured in CO2–e tonnes per hour for a year must be calculated from the estimates obtained under subsections (1) and (2). 

(4) The total mass of emissions of gas type (j) from the underground mine for the year is calculated by multiplying the average emissions rate obtained under subsection (3) by the number of hours during the year. 

3.8  Overview—use of equipment 

  The following requirements apply to the use of PEM equipment: 

(a) the requirements in section 3.9 about location of the sampling positions for the PEM equipment;  

(b) the requirements in section 3.10 about measurement of volumetric flow rates in a gas stream;  

(c) the requirements in section 3.11 about measurement of the concentrations of gas type (j) in the gas stream;  

(d) the requirements in section 3.12 about representative data. 

(e) the requirements in section 3.13 about performance characteristics of equipment. 

3.9  Selection of sampling positions for PEM 

  For paragraph 3.8(a), an appropriate standard or applicable State or Territory legislation must be complied with for the location of sampling positions for PEM equipment. 

Note: Appropriate standards include: 

• AS 4323.1—1995/Amdt 1-1995, Stationary source emissions—Selection of sampling positions 

• USEPA Method 1—Sample and velocity traverses for stationary sources (2000) 

3.10  Measurement of volumetric flow rates by PEM 

  For paragraph 3.8(b), the measurement of the volumetric flow rates by PEM of the gas stream must be undertaken in accordance with an appropriate standard or applicable State or Territory legislation.  

Note: Appropriate standards include: 

• ISO 14164:1999 Stationary source emissions. Determination of the volume flowrate of gas streams in ducts – automated method 

• ISO 10780:1994 Stationary source emissions. Measurement of velocity and volume flowrate of gas streams in ducts 

• USEPA Method 2—Determination of stack gas velocity and volumetric flow rate (Type S Pitot tube) (2000) 

• USEPA Method 2A—Direct measurement of gas volume through pipes and small ducts (2000). 

3.11 Measurement of concentrations by PEM 

  For paragraph 3.8(c), the measurement of the concentrations of gas type (j) in the gas stream by PEM must be undertaken in accordance with an appropriate standard or applicable State or Territory legislation.  

Note: Appropriate standards include USEPA—Method 3C—Determination of carbon dioxide, methane, nitrogen and oxygen from stationary sources (1996). 

3.12 Representative data for PEM 

(1) For paragraph 3.8(d), sampling by PEM must be undertaken during the year for a sufficient duration to produce representative data that may be reliably extrapolated to provide estimates of emissions across the full range of operating conditions for that year. 

(2) Emission estimates of PEM equipment must also be consistent with the principles in section 1.13. 

3.13 Performance characteristics of equipment 

  For paragraph 3.8(e), the performance characteristics of PEM equipment must be consistent with an appropriate standard or applicable State or Territory legislation. 

Note: The performance characteristics of PEM equipment includes calibration. 

Subdivision 3.2.2.3—Emissions released from coal mine waste gas flared 

3.14 Method 1—coal mine waste gas flared 

Method 1 describes how to estimate greenhouse gas emissions from the flaring of coal mine waste gas - by multiplying the quantity of coal mine waste gas flared by the energy content and emission factor for each gas type. The quantity of coal mine waste gas flared is estimated in accordance with Division 2.3.6. The energy content and emission factors are obtained from Division 2.3.2 in Chapter 2. 

  For subparagraph 3.4(4)(a)(i) and paragraphs 3.4(4)(b) and (c), method 1 

is: 

  Efl ij =  Qi,flared 1000 EC i  EFij  OFif 

where: 

E(fl)ij is the emissions of gas type (j) released from coal mine waste gas (i) flared from the mine during the year, measured in CO2-e tonnes. 

Qi,flared is the quantity of coal mine waste gas (i) flared from the mine during the year, measured in cubic metres and estimated under Division 2.3.6. 

ECi is the energy content factor of coal mine waste gas (i) mentioned in item 19 of Schedule 1, measured in gigajoules per cubic metre. 

EFij is the emission factor for gas type (j) and coal mine waste gas (i) mentioned in item 19 of Schedule 1, measured in CO2-e kilograms per gigajoule. 

OFif is 0.98, which is the destruction efficiency of coal mine waste gas (i) flared. 

3.15  Method 2—emissions of carbon dioxide from coal mine waste gas flared 

Method 2 requires representative and unbiased samples of coal mine waste gas consumed and the analysis of the coal mine waste gas to determine gas composition. The methane and carbon dioxide content should be analysed and accounted for independently in accordance with Australian or equivalent international standards.  The quantity of methane determined within the coal mine waste gas stream to be flared is applied to Section 3.15 to estimate carbon dioxide emissions and Section 3.15A to estimate methane and nitrous oxide emissions. 

  For subparagraph 3.4(4)(a)(ii), method 2 is: 

Qk × EC × EFi k

Eico2 = × OF + QCOi 2 

1000

where: 

EiCO2 is the emissions of CO2 released from coal mine waste gas (i) flared from the mine during the year, measured in CO2-e tonnes. 

ECi is the energy content factor of the methane (k) within coal mine waste gas (i) mentioned in item 19 of Schedule 1, measured in gigajoules per cubic metre. 

EFk is the emission factor for the methane (k) within the fuel type from the mine during the year, measured in kilograms of CO2-e per gigajoule, estimated in accordance with Division 2.3.3. 

OFi is 0.98, which is the destruction efficiency of coal mine waste gas (i) flared. 

Qk is the quantity of methane (k) within the fuel type from the mine during the year, measured in cubic metres in accordance with Division 2.3.6. 

QCO2 is the quantity of carbon dioxide within the coal mine waste gas emitted from the mine during the year, measured in CO2-e tonnes in accordance with Division 2.3.3. 

3.15A  Method 2—emissions of methane and nitrous oxide from coal mine waste gas flared 

  For subparagraphs 3.4(4)(b)(ii) and (c)(ii), method 2 is: 

Q × EC × EFk i kj

E =ij × OFi 

1000

where: 

Eij is the emissions of gas type (j), being methane or nitrous oxide, released from coal mine waste gas (i) flared from the mine during the year, measured in CO2-e tonnes. 

ECi is the energy content factor of methane (k) within coal mine waste gas (i) mentioned in item 19 of Schedule 1, measured in gigajoules per cubic metre. 

EFkj is the emission factor of gas type (j), being methane or nitrous oxide, for the quantity of methane (k) within coal mine waste gas (i) flared, mentioned in item 19 of Schedule 1 and measured in kilograms of CO2-e per gigajoule. 

OFi is 0.98, which is the destruction efficiency of coal mine waste gas (i) flared. 

Qk is the quantity of methane (k) within the coal mine waste gas (i) flared from the mine during the year, measured in cubic metres in accordance with Division 2.3.3. 

3.16  Method 3—coal mine waste gas flared 

Method 3 is the same as for Method 2 except that it requires samples to be obtained in accordance with Australian or equivalent international standards.   

(1) For subparagraph 3.4(4)(a)(iii), method 3 is the same as method 2 under section 3.15. 

(2) In applying method 2 under section 3.15, the facility specific emission factor EFk must be determined in accordance with the procedure for determining EFiCO2oxec in Division 2.3.4. 

Estimating Carbon dioxide emissions from Coal mine waste gas flaring using Method 2 

Coal mining operations often involve the flaring of coal mine waste gas. In this example a facility flares a coal mine waste gas stream from pre-drainage activities of 1,000,000 cubic meters (at standard pressure and temperature) during the year. The gas stream is predominantly methane, but also contains some carbon dioxide and nitrogen. The reporters have chosen to use method 2 to estimate emissions as this approach provides the opportunity to develop a carbon dioxide emission factor that better reflects the methane present in the gas stream, as well as account for the in-situ carbon dioxide quantity which is emitted, but not combusted in the flare. The relevant data for the flaring of coal mine waste gas are as follows in the table below: 

Data inputs for carbon dioxide emissions from coal mine waste gas flaring example. 

Quantity of coal mine waste gas flared (at 

standard pressure and temperature) 

(cubic metres) 

Component gas type of coal mine waste gas 

gas type’s share of the total coal 

mine waste gas volume 

(%) 

gas type’s volume 

(cubic metres) 

1,000,000 

Methane 

91 

910,000 

Carbon dioxide 

7 

70,000 

Nitrogen 

2 

20,000 

Calculate the carbon dioxide emissions using Method 2 in section 3.15  of NGER (Measurement) Determination 

Where:  

EiCO2 is the emissions of CO2 released from coal mine waste gas (i) flared from the mine during the year, measured in CO2-e tonnes.  

Qk is the quantity of methane (k) within the coal mine waste gas from the mine during the year, measured in cubic metres in accordance with Division 2.3.3.  

• This was determined by gas composition analysis of the coal mine waste gas (in accordance with Division 2.3.3)  

• The average methane composition of the coal mine waste gas being flared during the year was estimated to be 91%. 

• Therefore, to calculate the volume of methane within the coal mine waste gas: 

Coal mine waste gas volume = 1,000,000 

Methane composition = 91% 

Total volume of methane (Qk) = 1,000,000 x 91/100 = 910,000 m3 

QCO2 is the quantity of carbon dioxide within the coal mine waste gas emitted from the mine during the year, measured in CO2-e tonnes in accordance with Division 2.3.3.  

This was also determined by gas composition analysis of the coal mine waste gas(in accordance with Division 2.3.3). 

The average carbon dioxide composition of the coal mine waste gas being flared during the year was 7%. 

Therefore, to calculate the volume of carbon dioxide within the coal mine waste gas: 

Coal mine waste gas volume = 1,000,000 

Carbon dioxide composition = 7% 

Total volume of carbon dioxide = 1,000,000 x 7/100 = 70,000 m3 

Carbon dioxide m3 to tonnes conversion factor at standard pressure and temperature (see Determination Section 3.21)  = 1.861 x 10-3 

Therefore: 

QCO2  = 70,000 x 1.861 x 10-3 

QCO2  = 130.27 tonnes of carbon dioxide 

EFj is the emission factor for carbon dioxide resulting from the flaring of the methane component (j) within the coal mine waste gas from the mine during the year, measured in kilograms of CO2-e per gigajoule..  

This is determined using Section 2.22, where in; 

Section 2.22 (1) the mol% will be 100% methane as the EF is specifically for methane only, and 

o Section2.22 (4) the carbon dioxide emission factor for the flared methane has been converted to kilograms of CO2-e per gigajoule, using: 

The energy content of coal mine waste gas mentioned in item 19 of Schedule 1 of the Determination. 

The density of methane as calculated using its molecular weight in Section 2.22 (2) 

• In this example it was estimated  that the carbon dioxide emission factor for the methane within the coal mine waste gas = 49.12525 kg CO2-e/GJ 

ECi is the energy content factor of methane within the coal mine waste gas (i), taken to be equivalent to  item 19 of Schedule 1 of the Determination, measured in gigajoules per cubic metre.  

• In this example the energy content for coal mine waste gas in Schedule 1 of the 

NGER (Measurement) Determination = 37.7 x 10-3 GJ/m3 

OFi = 0.98, which is the flaring efficiency factor of coal mine waste gas (i) flared.  

Therefore, to calculate the CO2 emissions from coal mine waste gas flared: 

Qj = 910,000 m3 of methane 

ECi =37.7 x 10-3 GJ/m3 

EFj = 49.12525 kg CO2-e/GJ 

OFi = 0.98 

QCO2  = 130.27 tonnes of carbon dioxide 

= ((910,000 x 37.7 x 10-3 x 49.12525)/1000 x 0.98) + 130.27 

=  1781.90325819221 

Therefore, the total CO2 emissions from the flaring of coal seam waste gas = 1,781.90 tonnes. 

Subdivision 3.2.2.4—Fugitive emissions from post-mining activities 

Most fugitive greenhouse gas emissions are released from coal during the mining process. However some residual gas remains trapped within the coal after extraction, and is slowly released during, handling, transportation and stockpiling of the coal. 

3.17  Method 1—post-mining activities related to gassy mines 

Method 1 for estimating emissions from post-mining activities, with the source as described in IPCC 2006, is associated with gassy underground mines only.  

The method is derived from the National Greenhouse Account national methodology as published in the National Inventory Report. Emissions are estimated by multiplying a (physical) quantity of run-of-mine coal extracted by an emission factor.  

It is intended that consideration will be given to the development of additional higher order methods for this source in future.  

(1) For subsection 3.4(6), method 1 is the same as method 1 under section 3.5. 

(2) In applying method 1 under section 3.5, EFj is taken to be 0.017, which is the emission factor for methane (j), measured in CO2-e tonnes per tonne of run-of-mine coal extracted from the mine. 

Division 3.2.3—Open cut mines 

Fugitive emissions from open cut mines involve the release of methane and carbon dioxide during the mining process due to the fracturing of coal seams, overburden and underburden strata. Emissions also occur when coal mine waste gas is flared or is vented during degasification of the coal seams prior to the commencement of coal extraction.  

Subdivision 3.2.3.1—Preliminary 

3.18  Application 

  This Division applies to fugitive emissions from open cut mining 

activities. 

3.19  Available methods 

(1) Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by an open cut mine the methods as set out in this section must be used. 

Methane from extraction of coal 

(2) Subject to subsection (7), one of the following methods must be used for estimating fugitive emissions of methane that result from the extraction of coal from the mine: 

(a) method 1 under section 3.20; 

(b) method 2 under section 3.21;  (c) method 3 under section 3.26. 

Note: There is no method 4 for subsection (2). 

Carbon dioxide from extraction of coal 

(3) If method 2 under section 3.21 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from the open cut mine. 

(4) If method 3 under section 3.26 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from the open cut mine. 

Note: There is no method 1 or 4 for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from an open cut mine. 

Flaring 

(5) For estimating emissions released from coal mine waste gas flared from the open cut mine: 

(a) one of the following methods must be used for estimating emissions of carbon dioxide released: 

(i) method 1 under section 3.27; 

(ii) method 2 under section 3.28; 

(iii) method 3 under section 3.29; and 

(b) method 1 under section 3.27 must be used for estimating emissions of methane released; and 

(c) method 1 under section 3.27 must be used for estimating emissions of nitrous oxide released. 

Note: The flaring of coal mine waste gas releases emissions of carbon dioxide, methane and nitrous oxide. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide, no method 2, 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide.  

Venting or other fugitive release before extraction of coal 

(6) Method 4 under Part 1.3 must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, that result from venting or other fugitive release of gas from the mine before coal is extracted from the mine. 

Note: There is no method 1, 2 or 3 for subsection (6). 

(7) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

Summary of available methods for estimating emissions from open cut mines, by emissions of gas type (j) 

CO2 

CH4 

N2O 

Open cut  mining activities 

Method 1 

NA 

Section 3.20 

NO 

Method 2 

Section 3.21 

Section 3.21 

NO 

Method 3 

Section 3.26 

Section 3.26 

NO 

Method 4 

NA 

NA 

NO 

Flaring 

Method 1 

Section 3.27 

Section 3.27 

Section 3.27 

Method 2 

Section 3.28 

NA 

NA 

Method 3 

Section 3.29 

NA 

NA 

Method 4 

NA 

NA 

NA 

Venting 

Methods 1, 2 and 3 

NA 

NA 

NO 

Method 4 

Part 1.3 

Part 1.3 

NO 

NA = Not available.  NO = Not occurring 

Subdivision 3.2.3.2—Fugitive emissions from extraction of coal 

Method 1 for open cut mining operations associated with the extraction of coal is derived from the National Greenhouse Account national methodology as published in the National Inventory Report. Emissions are estimated for a particular location of the mine by multiplying a (physical) quantity of run-of-mine coal extracted by an emission factor.   

3.20  Method 1—extraction of coal 

  For paragraph 3.19(2)(a), method 1 is: 

  E = Q j  EF j 

where: 

Ej is the fugitive emissions of methane (j) that result from the extraction of coal from the mine during the year measured in CO2-e tonnes. 

Q is the quantity of run-of-mine coal extracted from the mine during the year measured in tonnes. 

EFj is the emission factor for methane (j), measured in CO2-e tonnes per tonne of run-of-mine coal extracted from the mine, taken to be the following: 

(a) for a mine in New South Wales — 0.054; 

(b) for a mine in Victoria — 0.00027; 

(c) for a mine in Queensland — 0.02; 

(d) for a mine in Western Australia — 0.02;  (e) for a mine in South Australia — 0.00027;  (f) for a mine in Tasmania — 0.017. 

Example 

A facility constituted by an open cut coal mine in NSW extracts 2,554,000 tonnes of run-ofmine coal during the year.  The Reporter elects to use Method 1 (Section 3.20) to estimate fugitive emissions of methane. Emissions are estimated as follows: 

E = Q j  EF j 

where: 

Ej is the emissions of methane (j) released from the extraction of coal from the mine during the year, measured in CO2-e tonnes. 

Q is the quantity of run-of-mine coal extracted from the mine during the year, measured in tonnes. In this case being 2,554,000 tonnes of raw coal. 

EFj is the emission factor for methane (j), measured in CO2 e tonnes per tonne of raw coal extracted from the mine. In this case, for an open cut mine in NSW the emission factor is 

0.054 tonnes CO2-e per tonne of raw coal extracted. 

Therefore, the estimate of methane emissions in CO2-e tonnes: 

Ej = (2,554,000 x 0.054) 

Total emissions of methane  = 137,916 t CO2-e 

3.21  Method 2—extraction of coal 

Method 2 for estimating emissions from open cut mining requires the estimation of the total in-situ stock of gas held within the mine’s gas bearing strata.  

The framework for the method is based on the following ACARP project: 

Saghafi, A. (2008), Evaluating a tier 3 method for estimating fugitive emissions from open cut mining,  Joint Research Project ACARP (C15076) and CSIRO. CSIRO Investigation Report ET/IR 1011. This report can be obtained from: http://www.acarp.com.au/reports.aspx.  

To facilitate the practical application of Method 2/3, an elaboration of the method through amendments to the Determination were introduced for the 2012/13 reporting year. 

In parallel to these latest amendments, ACARP published an industry guideline on 

December 2011 as Project C20005: Guidelines for the Implementation of NGER Method 2 or 3 for Open Cut Coal Mine Fugitive GHG Emissions Reporting. The document contains guidance for the measurement, estimation and reporting of fugitive emissions from open cut mines and is available at: www.acarp.com.au/abstracts.aspx?repId=C20005 

The Determination amendments incorporate the ACARP guidelines through the referencing of specific sections of the guidelines. The ACARP Guidelines should be read in conjunction with the Determination. In cases of apparent inconsistency between the ACARP Guidelines and the Determination, the Determination takes precedence. 

The Technical Guidelines have been updated to include the  amendments to open cut mine methods 2/3. Key changes include: 

• The introduction of a low gas zone approach, for which methods for defining a low gas zone and an emission factor are provided. 

• The introduction of the Estimator, along with setting minimum qualification for the Estimator. 

• Guidance on sampling, analysis, data validation and gas distribution modelling are provided through references within the Determination to relevant sections of the ACARP Guidelines. 

A number of new definitions were introduced as part of the set of amendments associated with the elaboration of methods 2/3 for open cut mines. Definitions are listed in section 1.8 of the Determination. Those related to methods 2/3 for open cut mines include the following; 

ACARP Guidelines means the document entitled Guidelines for the Implementation of NGER Method 2 or 3 for Open Cut Coal Mine Fugitive GHG Emissions Reporting (C20005), published by the Australian Coal Association Research Program in December 2011. 

base of the low gas zone means the part of the low gas zone worked out in accordance with section 3.25A. 

domain, of an open cut mine, means an area, volume or coal seam in which the variability of gas content and the variability of gas composition in the open cut mine have a consistent relationship with other geological, geophysical or spatial parameters located in the area, volume or coal seam. 

Fugitive emissions

estimator, of fugitive emissions from an open cut mine using method 2 under section 3.21 or method 3 under section 3.26, means: 

(a) an individual who has the minimum qualifications of an estimator set out in the ACARP Guidelines; or 

(b) individuals who jointly have those minimum qualifications. 

gas bearing strata is coal and carbonaceous rock strata: 

(a) located in an open cut mine; and 

(b) that has a relative density of less than 1.95 g/cm3. 

low gas zone means the part of the gas bearing strata of an open cut mine: 

(a) that is located immediately below the original surface of the mine and above the base of the low gas zone; and 

(b) the area of which is worked out by working out the base of the low gas zone. 

open cut mine: 

(a) means a mine in which the overburden is removed from coal seams to allow coal extraction by mining that is not underground mining; and 

(b) for method 2 in section 3.21 or method 3 in section 3.26—includes a mine of the kind mentioned in paragraph (a): 

(i) for which an area has been established but coal production has not commenced; or 

(ii) in which coal production has commenced. 

(1) For paragraph 3.19(2)(b) and subsection 3.19(3), method 2 is: 

  E = j j z Sj,z  

where: 

Ej is the fugitive emissions of gas type (j) that result from the extraction of coal from the mine during the year, measured in CO2-e tonnes. 

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions of pressure and temperature to CO2-e tonnes, as follows: 

(a) for methane—6.784 × 10-4 × 25; 

(b) for carbon dioxide—1.861 × 10-3. 

∑z (Sj,z) is the total of gas type (j) in all gas bearing strata (z) under the extraction area of the mine during the year, measured in cubic metres, where the gas in each strata is estimated under section 3.22. 

(2) Method 2 requires each gas in a gas bearing strata to be sampled and analysed in accordance with the requirements in sections 3.24, 3.25 and 3.25A. 

3.22  Total gas contained by gas bearing strata 

  (1) For method 2 under subsection 3.21(1), Sj,z for gas type (j) contained in a gas bearing strata (z) under the extraction area of the mine during the year, measured in cubic metres, is: 

  S = M jz z  β z  GCjz   t Qij, cap,z t Qij,flared,z t Qijtr t Ej,vented,z where: 

Mz is the mass of the gas bearing strata (z) under the extraction area of the mine during the year, measured in tonnes. 

βz is the proportion of the gas content of the gas bearing strata (z) that is released by extracting coal from the extraction area of the mine during the year, as follows: 

  (a) if the gas bearing strata is at or above the pit floor—1;  (b) in any other case—as estimated under section 3.23.  

GCjz is the content of gas type (j) contained by the gas bearing strata (z) before gas capture, flaring or venting is undertaken at the extraction area of the mine during the year, measured in cubic metres per tonne of gas bearing strata at standard conditions. 

∑Qij,cap,z is the total quantity of gas type (j) in coal mine waste gas (i) captured for combustion from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres. 

∑Qij,flared,z is the total quantity of gas type (j) in coal mine waste gas (i) flared from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres. 

∑Qijtr is the total quantity of gas type (j) in coal mine waste gas (i) transferred out of the mining activities at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres. 

∑Ej,vented,z is the total emissions of gas type (j) vented from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres and estimated under subsection 3.19 (6). 

(2) For ∑Qij,cap,z, ∑Qij,flared,z and ∑Qijtr in subsection (1), the quantity of gas type (j) must be estimated in accordance with Division 2.3.6 as if a reference in that Division to quantities of gaseous fuels combusted from the operation of a facility was a reference to the following: 

(a) for ∑Qij,cap,z—quantities of gaseous fuels captured from the operation 

of a facility; 

(b) for ∑tQij,flared,z—quantities of gaseous fuels flared from the operation of a facility; 

(c) for ∑Qijtr—quantities of gaseous fuels transferred out of the operation of a facility. 

(3) In subsection (1), ∑Qijtr applies to carbon dioxide only if the carbon dioxide is captured for permanent storage. 

Note: Division 1.2.3 contains a number of requirements in relation to deductions of carbon dioxide captured for permanent storage. 

(4) For GCjz in subsection (1), the content of gas type (j) contained by the gas bearing strata (z) must be estimated in accordance with sections 3.24, 3.25, 3.25A and 3.25B. 

3.23  Estimate of proportion of gas content released below pit floor 

  For paragraph (b) of the factor βz in subsection 3.22(1), estimate βz using one of the following equations: 

  (a) equation 1: 

x  h

  z  1  ; 

  dh

  (b) equation 2: 

   z  0.5. 

where: 

x is the depth in metres of the floor of the gas bearing strata (z) measured from ground level. 

h is the depth in metres of the pit floor of the mine measured from ground level. 

dh is 20, being representative of the depth in metres of the gas bearing strata below the pit floor that releases gas. 

3.24  General requirements for sampling 

(1) Core samples of a gas bearing strata must be collected to produce estimates of gas content that are representative of the gas bearing strata in the extraction area of the mine during the year. 

(2) The sampling process must also be free of bias so that any estimates are neither over nor under estimates of the true value. 

(3) Bias must be tested in accordance with an appropriate standard (if any). 

(4) The value obtained from the samples must only be used for the open cut mine from which it was intended to be representative.  

(5) Sampling must be carried out in accordance with: 

(a) the minimum requirements for data collection and gas testing mentioned in section 2 of the ACARP Guidelines; and 

(b) the data validation, analysis and interpretation processes mentioned in section 3 of the ACARP Guidelines. 

3.25  General requirements for analysis of gas and gas bearing strata 

Measurement of the gas content from coal and other gas bearing strata layers requires use of borecores. Geological characteristics can help to identify possible gas bearing areas based on previous evidence of gas content in a region and to infer gas content of coal and rock strata between actual borecore measurements. However knowledge of geological characteristics of a site, with no specific borecore measurements, would not be able to adequately predict gas content (Saghafi, 2008). 

  Analysis of a gas and a gas bearing strata, including the mass and gas content of the strata, must be done in accordance with:  

(a) the minimum requirements for data collection and gas testing mentioned in section 2 of the ACARP Guidelines; and 

(b) the data validation, analysis and interpretation processes mentioned in section 3 of the ACARP Guidelines; and 

(c) the method of applying the gas distribution model to develop an emissions estimate for an open cut mine mentioned in section 4 of the ACARP Guidelines. 

3.25A  Method of working out base of the low gas zone 

(1) The estimator must: 

(a) take all reasonable steps to ensure that samples of gas taken from the 

gas bearing strata of the open cut mine are taken in accordance with the minimum requirements for data collection and gas testing mentioned in section 2 of the ACARP Guidelines; and 

(b) take all reasonable steps to ensure that samples of gas taken from boreholes are taken in accordance with the requirements for: 

(i) the number of boreholes mentioned in sections 2 and 3 of the ACARP Guidelines; and 

(ii) borehole spacing mentioned in section 2 of the ACARP 

Guidelines; and 

(iii) sample selection mentioned in section 2 of the ACARP 

Guidelines; and 

(c) work out the base of the low gas zone by using the method mentioned in subsection (2); and 

(d) if the base of the low gas zone worked out in accordance with subsection (2) varies, in a vertical plane, within: 

(i) a range of 20 metres between boreholes located in the same domain of the open cut mine—work out the base of the low gas 

zone using the method mentioned in subsection (3); or 

(ii) a range of greater than 20 metres between boreholes located in 

the same domain of the open cut mine—the method mentioned in subsection (4). 

Preliminary method of working out base of low gas zone 

(2) For paragraph (1)(c), the method is that the estimator must perform the following steps: 

Step 1 For each borehole, identify the depth at which: 

(a) the results of greater than 3 consecutive samples taken in the borehole indicate that the gas content of the gas bearing strata is greater than 0.5 m3/t; or 

(b) the results of 3 consecutive samples taken in the borehole indicate that the methane composition of the gas bearing strata is greater than 50% of total gas composition by volume. 

Step 2 If paragraph (a) or (b) of step 1 applies, identify, for each borehole, the depth of the top of the gas bearing strata at which the first of the 3 consecutive samples in the borehole was taken. 

Note   The depth of the top of the gas bearing strata worked out under step 2 is the same as the depth of the base of the low gas zone. 

Method of working out base of low gas zone for subparagraph (1)(d)(i) 

(3) For subparagraph (1)(d)(i), the method is that the estimator must work out 

the average depth at which step 2 of the method in subsection (2) applies. 

Method of working out base of low gas zone for subparagraph (1)(d)(ii) 

(4) For subparagraph (1)(d)(ii), the method is that the estimator must construct a 3-dimensional model of the surface of the low gas zone using a triangulation algorithm or a gridding algorithm. 

3.25B  Further requirements for estimator 

(1) This section applies if: 

(a) the estimator constructs a 3-dimensional model of the surface of the 

base of the low gas zone in accordance with the method mentioned in subsection 3.25A(4); and 

(b) the 3-dimensional model of the surface of the low gas zone is extrapolated beyond the area modelled directly from boreholes in the domain. 

(2) The estimator must: 

(a) ensure that the extrapolated surface: 

(i) applies the same geological modelling rules that were applied in the generation of the surface of the base of the low gas zone from the boreholes; and 

(ii) represents the base of the low gas zone in relation to the geological structures located within the domain; and 

(iii) is generated using a modelling methodology that is consistent with the geological model used to estimate the coal resource; and 

(iv) the geological model used to estimate the coal resource meets the minimum requirements and the standard of quality mentioned in section 1 of the ACARP Guidelines. 

(b) make and retain a record: 

Fugitive emissions

(i) of the data and assumptions incorporated into the generation of the 3-dimensional surface; and 

(ii) that demonstrates that the delineation of the 3-dimensional surface complies with sections 1.13 and 3.24. 

3.25C  Default gas content for gas bearing strata in low gas zone 

  A default gas content of 0.00023 tonnes of carbon dioxide per tonne of gas bearing strata must be assigned to all gas bearing strata located in the low gas zone. 

3.25D  Requirements for estimating total gas contained in gas bearing strata 

(1) The total gas contained in gas bearing strata for an open cut coal mine must be estimated in accordance with the emissions estimation process mentioned in section 1 of the ACARP Guidelines. 

(2) The gas distribution model used for estimating emissions must be applied in accordance with section 4.1 of the ACARP Guidelines; and 

(3) The modelling bias must be assessed in accordance with section 4.2 of the ACARP Guidelines. 

(4) The gas distribution model must be applied to the geology model in accordance with section 4.3 of the ACARP Guidelines. 

3.26  Method 3—extraction of coal 

(1) For paragraph 3.19(2)(c) and subsection 3.19(4), method 3 is the same as method 2 under section 3.21 

(2) In applying method 2 under section 3.21 a sample of gas bearing strata 

must be collected in accordance with an appropriate standard, including: 

(a) AS 2617—1996 Sampling from coal seams or an equivalent standard; and 

(b) AS 2519—1993 Guide to the technical evaluation of higher rank coal deposits or an equivalent standard. 

Subdivision 3.2.3.3—Emissions released from coal mine waste gas flared 

3.27  Method 1—coal mine waste gas flared 

(1) For subparagraph 3.19(5)(a)(i) and paragraph 3.19(5)(b) and paragraph (5)(c), method 1 is the same as method 1 under section 3.14. 

(2) In applying method 1 under section 3.14, a reference to an underground mine is taken to be a reference to an open cut mine. 

3.28 Method 2—coal mine waste gas flared 

Method 2 is the same as method 2 under section 3.15. Method 2 requires representative and unbiased samples of coal mine waste gas consumed and analysis of the coal mine waste gas to determine gas composition and must be done in accordance with Australian or equivalent international standards and as set out for Division 2.3.3 

For subparagraph 3.19(5)(a)(ii), method 2 is the same as method 2 under section 3.15. 

3.29 Method 3—coal mine waste gas flared 

Method 3 is the same as for Method 2 except that it requires samples to be obtained in accordance with Australian or equivalent international standards and as set out in Division 2.3.4. 

For subparagraph 3.19(5)(a)(iii), method 3 is the same as method 3 under section 3.16. 

Division 3.2.4—Decommissioned underground mines 

Greenhouse gas emissions are known to occur following the closure of coal mines. Leakages to the atmosphere occur through fractured rock strata, open vents and seals over daily to decadal timescales. However, emissions will be reduced by flooding of the mine, which prevents desorption of gases from the remaining coal strata and non-coal strata layers in the closed mine. 

Subdivision 3.2.4.1—Preliminary 

3.30  Application 

  This Division applies to fugitive emissions from decommissioned underground mines that have been closed for a continuous period of at least 1 year but less than 20 years. 

3.31  Available methods 

(1) Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by a decommissioned underground mine that has been closed for a continuous period of at least 1 year but less than 20 years the methods as set out in this section must be used. 

Methane from decommissioned mines 

(2) One of the following methods must be used for estimating fugitive emissions of methane that result from the mine:  (a) subject to subsection (6), method 1 under section 3.32;  (b) method 4 under section 3.37. 

Note: There is no method 2 or 3 for subsection (2). 

Carbon dioxide from decommissioned mines 

(3) If method 4 under section 3.37 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the mine. 

Note: There is no method 1, 2 or 3 for subsection (3). 

Flaring 

(4) For estimating emissions released from coal mine waste gas flared from the mine: 

(a) one of the following methods must be used for estimating emissions of carbon dioxide released: 

(i) method 1 under section 3.38; 

(ii) method 2 under section 3.39; 

(iii) method 3 under section 3.40; and 

(b) method 1 under section 3.38 must be used for estimating emissions of methane released. 

(c) method 1 under section 3.38 must be used for estimating emissions of nitrous oxide released. 

Note: The flaring of coal mine waste gas releases emissions of carbon dioxide, methane and nitrous oxide. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide, no method 2, 3 or 4 for emissions of methane and no method 2, 3 or 4 for nitrous oxide.  

(5) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

(6) If coal mine waste gas from the decommissioned underground mine is captured for combustion during the year, method 1 in subsection (2) must not be used.

Summary of available methods for estimating emissions from decommissioned mines, by emissions of gas type (j) 

CO2 

CH4 

N2O 

Underground decommissioned mines 

Method 1 

NA 

Section 3.32 

NO 

Methods 2, 3 

NA 

NA 

NO 

Method 4 

Section 3.37 

Section 3.37 

NO 

Flaring 

Method 1 

Section 3.38 

Section 3.38 

Section 3.38 

Method 2 

Section 3.39 

NA 

NA 

Method 3 

Section 3.40 

NA 

NA 

Method 4 

NA 

NA 

NA 

NA = Not available.  NO = Not occurring 

Subdivision 3.2.4.2—Fugitive emissions from decommissioned underground mines 

Method 1 for emissions from decommissioned mines is derived from the National Greenhouse Account national methodology as published in the National Inventory Report.  

3.32  Method 1—decommissioned underground mines 

(1) For paragraph 3.31(2)(a), method 1 is: 

  Edm = E[ tdm  EF dm (1  F )dm ] 

where: 

Edm is the fugitive emissions of methane from the mine during the year measured in CO2-e tonnes. 

Etdm is the emissions from the mine for the last full year that the mine was in operation measured in CO2-e tonnes and estimated under section 3.5 or 3.6. 

EFdm is the emission factor for the mine calculated under section 3.33. 

Fdm is the proportion of the mine flooded at the end of the year, as estimated under section 3.34, and must not be greater than 1. 

(2) However, if, under subsection (1), the estimated emissions in CO2-e tonnes for the mine during the year is less than 0.02  Etdm, the estimated emissions for the mine during the year is taken to be 0.02  Etdm. 

3.33  Emission factor for decommissioned underground mines 

The emission factor for Method 1 is derived from an emission decay curve (EDC). The EDC describes the decline in fugitive methane emissions overtime following mine closure. Hyperbolic curves have been found to function best in portraying the rapid decline in emissions in the first few years, followed by a slow decline over time of the remaining emissions (National Inventory Report).  

Australian-specific EDCs developed for the national inventory have being utilized for both gassy and non-gassy mines.  

For section 3.32, EFdm is the integral under the curve of: 

  (1 + A Τ)b C 

for the period between T and T-1, where: 

A is: 

(a) for a gassy mine—0.23; or 

(b) for a non-gassy mine—0.35. 

T is the number of years since the mine was decommissioned. b is: 

(a) for a gassy mine—-1.45; or 

(b) for a non-gassy mine—-1.01. 

C is: 

(a) for a gassy mine—0.024; or 

(b) for a non-gassy mine—0.088. 

Fugitive emissions

3.34  Measurement of proportion of mine that is flooded 

Emissions from decommissioned mines are reduced as a mine floods due to the reduction of gas desorption from the coal remaining in the closed mine. The variables required to estimate the portion of the mine flooded at a point in time is the size of the void volume and the water inflow rate into the closed mine.  

For subsection 3.32(1), Fdm is: 

MWI × years

  MVV  

where: 

MWI is the rate of water flow into the mine in cubic metres per year as measured under section 3.35. 

MVV is the mine void volume in cubic metres as measured under section 3.36. years is the number of years since the mine was decommissioned. 

3.35  Water flow into mine  

  For MWI in section 3.34, the rate of water flow into the mine must be measured by: 

(a) using water flow rates for the mine estimated in accordance with an appropriate standard; or 

(b) using the following average water flow rates: 

  (i) for a mine in the southern coalfield of New South Wales—

913 000 cubic metres per year; or 

(ii) for a mine in the Newcastle, Hunter, Western or Gunnedah coalfields in New South Wales—450 000 cubic metres per year; or 

(iii) for a mine in Queensland—74 000 cubic metres per year. 

Note: An appropriate standard includes AS 2519—1993 Guide to the technical evaluation of higher rank coal deposits. 

3.36  Size of mine void volume 

  For MVV in section 3.34, the size of the mine void volume must be measured by: 

(a) using mine void volumes for the mine estimated in accordance with industry practice; or 

(b) dividing the total amount of run-of-mine coal extracted from the mine before the mine was decommissioned by 1.425. 

3.37  Method 4—decommissioned underground mines 

(1) For paragraph 3.31(2)(b) and subsection 3.31(3), method 4 is the same as method 4 in section 3.6. 

(2) In applying method 4 under section 3.6, a reference to an underground 

mine is taken to be a reference to a decommissioned underground mine. 

Subdivision 3.2.4.3—Fugitive emissions from coal mine waste gas flared 

3.38  Method 1—coal mine waste gas flared  

Emissions using Method 1 are estimated by multiplying the quantity of gas flared by the energy content and emission factor for the coal mine waste gas. The quantity of coal mine waste gas flared should be estimated in accordance with Division 2.3.6. The energy content and emission factors are obtained from Division 2.3.2 of Chapter 2. 

(1) For subparagraph 3.31(4)(a)(i) and paragraphs 3.31(4)(b) and (4)(c), method 1 is the same as method 1 under section 3.14. 

(2) In applying method 1 under section 3.14, a reference to an underground 

mine is taken to be a reference to a decommissioned underground mine. 

3.39 Method 2—coal mine waste gas flared 

  For subparagraph 3.31(4)(a)(ii), method 2 is the same as method 2 under section 3.15. 

3.40 Method 3—coal mine waste gas flared 

  For subparagraph 3.31(4)(a)(iii), method 3 is the same as method 3 under section 3.16.  

Part 3.3—Oil and natural gas—fugitive emissions 

Division 3.3.1—Preliminary 

This part includes fugitive emissions from exploration, production, transport, storage, processing and refining of oil or gas.  

Other sources of emissions arising from the production processes, such as from the combustion of fuels for energy, are not described in this chapter and must be estimated using the Methods described in other chapters.    

Fugitive emissions in the oil and gas sector can be largely classified as being either a vent, leak or a flare. A flare involves the combustion of a gas or liquid for a nonenergy purpose. The distinction between leaks and vents was derived from the definition used by the American Petroleum Institute Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry (API) and was developed for the application for the Determination in consultation with industry.  

Vent 

Vents are considered to be emissions that are the result of process or equipment design or operational practices; and; 

Leak 

Leaks are considered to be emissions from unintentional equipment leaks from valves, flanges, pump seals, compressor seals, relief valves, sampling connections, process drains, process drains, open-ended lines, casing, tanks, casing leaks and other leakage sources from pressurised equipment not defined as a vent. 

The Determination makes use of methods for estimating emissions from vents and leaks in the API Compendium. Amendments for July1 2012 have updated references from the 2004 API to the 2009 version of the API Compendium. The Determination refers to specific section of API 2009 for methods such as engineering approaches and activity or equipment type factors. Most sections of the API Compendium provide the gas content basis for the emission factors and note that the factors can be adjusted based on site-specific gas composition. Conversion flared cubic meters to flared tonnes 

Depending on the original data units available to reporters, method 1 for estimating emissions from flaring may require a density conversion for the quantity of fuel type flared from cubic metres to tonnes. Rather than the Determination setting a default density, it is considered that the reporter would be best positioned to understand the characteristics of their flared gas stream. Considerable variability would be expected in the density of flare gas depending on plants and processes, and therefore a universal default figure is unlikely to be useful. 

To complement the reporters understanding of their flared gas stream, various gas density values are available in national and international literature such as in the API 2009 Compendium or National Pollution Inventory manuals. Conversions are required to be estimated in standard conditions as specified in the Determination in 2.32 (7). Site specific density figures may also be derived using sampling and measurement approaches under section 2.24 of the Determination. Reporters are reminded of that the approach should be consistent with the general principles detailed in Section 1.13 of the Determination. 

3.40A  Definition of natural gas for Part 3.3 

    In this Part: 

natural gas includes the following: 

 (a) shale gas;  (b) tight gas;  (c) coal seam methane. 

3.41  Outline of Part 

  This Part provides for fugitive emissions from the following: 

(a) oil or gas exploration (see Division 3.3.2); 

(b) crude oil production (see Division 3.3.3); 

(c) crude oil transport (see Division 3.3.4); 

(d) crude oil refining (see Division 3.3.5); 

(e) natural gas production or processing, other than emissions that are vented or flared (see Division 3.3.6); 

(f) natural gas transmission (see Division 3.3.7); 

(g) natural gas distribution (see Division 3.3.8); 

(h) natural gas production or processing (emissions that are vented or flared) (see Division 3.3.9). 

Division 3.3.2—Oil or gas exploration 

Emissions may occur during the process of drilling for oil or gas either during exploration or development drilling whenever gas or liquid hydrocarbons are encountered. CO2, some unburnt methane and N2O are released as a result of the flaring of oil or gas. Emissions may also occur as a result of venting and accidental releases such as blowouts. 

Subdivision 3.3.2.1—Preliminary 

3.42  Application 

  This Division applies to fugitive emissions from venting or flaring from oil or gas exploration activities, including emissions from:  

(a) oil well drilling; and 

(b) gas well drilling; and 

(c) drill stem testing; and   (d) well completions; and  (e) wellworkovers. 

Subdivision 3.3.2.2—Oil or gas exploration (flared) emissions 

3.43  Available methods 

Methods 1, 2 and 3 are set out below for the estimation of emissions from flaring of fuel.  Flaring is the combustion of fuels for non-productive (non-commercial) reasons –for example for health and safety reasons.   Methods 2 and 3 rely on the sampling and analysis of the fuel to estimate the composition of the gases in the fuel in accordance with the provisions of chapter 2. 

(1)Subject to section 1.18, for estimating emissions released by oil or gas flaring during the year from the operation of a facility that is constituted by oil or gas exploration: 

(a) if estimating emissions of carbon dioxide released—one of the following methods must be used: 

(i) method 1 under section 3.44; 

(ii) method 2 under section 3.45; 

(iii) method 3 under section 3.46; and 

(b) if estimating emissions of methane released—one of the following methods must be used: 

(i) method 1 under section 3.44; 

(ii) method 2A under section 3.45A; and 

(c) if estimating emissions of nitrous oxide released—one of the following methods must be used: 

(i) method 1 under section 3.44; 

(ii) method 2A under section 3.45A. 

Note: There is no method 4 under paragraph (a) and no method 2, 3 or 4 under paragraph (b) or (c). 

  (2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

Summary of available methods, for estimating flaring emissions from oil and gas exploration, by emissions of gas type (j) 

CO2 

CH4 

N2O 

Method 1 

Section 3.44 

Section 3.44 

Section 3.44 

Method 2 

Section 3.45 

NA 

NA 

Method 3 

Section 3.46 

NA 

NA 

Method 4 

NA 

NA 

NA 

NA = Not available.   

3.44  Method 1—oil or gas exploration 

Method 1 for oil exploration and gas exploration is derived from the National Greenhouse Accounts.  

(1)Method 1 is: 

E = Qij iEFij 

where: 

Eij is the fugitive emissions of gas type (j) from a fuel type (i) flared in the oil or gas exploration during the year measured in CO2-e tonnes. 

Qi is the quantity of fuel type (i) flared in the oil or gas exploration during the year measured in tonnes. 

EFij is the emission factor for gas type (j) measured in tonnes of CO2-e emissions per tonne of the fuel type (i) flared. 

  (2) For EFij in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor, for gas type (j), for each fuel type (i) specified in column 2 of that item. 

Item Fuel type (i) Emission factor for gas type (j) (tonnes CO2-e/tonnes of fuel flared) 

CO2 CH4 

N2O 

1 

Unprocessed gas flared 

2.8 0.8 

0.03 

2 

Crude oil 

3.2 0.008 

0.07 

3.45  Method 2—oil or gas exploration (flared carbon dioxide emissions) 

Combustion of gaseous fuels (flared) emissions 

  (1) For subparagraph 3.43(1)(a)(ii), method 2 for combustion of gaseous fuels 

is: 

  Eico2  Qh  EF h  OF i  QCO2 

where: 

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in oil or gas exploration during the year, measured in CO2-e tonnes. 

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in oil or gas exploration during the year, measured in tonnes in accordance with Division 2.3.3. 

EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in oil or gas exploration during the year, measured in CO2-e tonnes per tonne of the fuel type (i) flared, estimated in accordance with Division 2.3.3. 

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared. 

QCO2 is the quantity of CO2 within fuel type (i) in oil or gas exploration during the year, measured in CO2-e tonnes in accordance with Division 2.3.3. 

Combustion of liquid fuels (flared) emissions 

  (2) For subparagraph 3.43(1)(a)(ii), method 2 for combustion of liquid fuels is the same as method 1 under section 3.44, but the carbon dioxide emissions 

factor EFij must be determined in accordance with method 2 in Division 2.4.3. 

3.45A  Method 2A—oil or gas exploration (flared methane or nitrous oxide emissions) 

  For subparagraphs 3.43(1)(b)(ii) and (c)(ii), method 2A is: 

E = Q × EF × OFij h hij i where: 

EFhij is the emission factor of gas type (j), being methane or nitrous oxide, for the total hydrocarbons (h) within the fuel type (i) in oil or gas exploration during the year, mentioned for the fuel type in the table in subsection 3.44(2) and measured in CO2-e tonnes per tonne of the fuel type (i) flared. 

Eij is the fugitive emissions of gas type (j), being methane or nitrous oxide, from fuel type (i) flared from oil or gas exploration during the year, measured in CO2-e tonnes. 

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared. 

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in oil or gas exploration during the year, measured in tonnes in accordance with Division 2.3.3 for gaseous fuels or Division 2.4.3 for liquid fuels. 

3.46  Method 3—oil or gas exploration 

Combustion of gaseous fuels (flared) emissions 

(1) For subparagraph 3.43(1)(a)(iii), method 3 for the combustion of gaseous fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.3.4. 

Combustion of liquid fuels (flared) emissions 

(2) For subparagraph 3.43(1)(a)(iii), method 3 for the combustion of liquid fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.4.4. 

Subdivision 3.3.2.3—Oil or gas exploration—fugitive emissions from system upsets, accidents and deliberate releases from process vents 

3.46A  Available methods 

(1) Subject to section 1.18, the methods mentioned in subsections (2) and (3) must be used for estimating fugitive emissions that result from system 

upsets, accidents and deliberate releases from process vents during a reporting year from the operation of a facility that is constituted by oil or gas exploration. 

(2) To estimate emissions that result from deliberate releases from process vents, systems upsets and accidents at a facility during a year, for each oil or gas exploration activity one of the following methods must be used: 

  (a) method 1 under section 3.84;  (b) method 4 under: 

(i) for emissions of methane and carbon dioxide from natural gas 

well completions or well workover activities—section 3.46B; or 

(ii) for emissions and activities not mentioned in subparagraph (i)—

Part 1.3. 

(3) For estimating incidental emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, another method may be used that is consistent with the principles mentioned in section 1.13. 

Note: There is no method 2 or 3 for this Subdivision. 

3.46B  Method 4—vented emissions from well completions and well workovers 

Vented volume measured for all wells and well types in a basin 

An optional method 4 has been introduced for estimating vented methane and carbon dioxide emissions from coal seam gas well completions and workovers. Two approaches are provided: 

1) Vented volume measured for all wells and well types in a basin; where all vented volumes for well completions or workover are measured for all well types(vertical and horizontal); and 

2) Vented volume measured for a sample of wells and well types in a basin; where the total emissions for well completions or workovers are estimated based on the measurement of flow rate taken from a sample of the well population during the year.  

Conversion to standard conditions 

All gas volumes are to be converted to standard conditions as set out in 

2.32(7). 

Measurement of gaseous quantities. 

Division 2.3.6  sets out requirements for the measurement of gaseous quantities, including criterion BBB - estimation in accordance with industry practice). 

Vented volume measured for all wells and well types in a basin  

Emissions arising from both strata and gas injected for each well are summed and converted to carbon dioxide equivalents in subsection (1). 

The volume of methane vented from the strata for each well (ESp) is estimated in subsection (2).  Methane volume from strata is estimated by subtracting the volume of gas measured on the vent line from the any volumes of gas injected during a completion or workover. This approach assumes that gas volumes from strata are methane and therefore gas compositional analysis under Division 2.3.3 is not required. 

The volume of any injected methane and carbon dioxide (VIGG jp) is estimated in subsection (3). Compositional analysis of the gas under Division 2.3.3 is required to separate methane and carbon dioxide components of the injected gas. 

  (1) For subparagraph 3.46A(2)(b)(i), where vented volume is measured for all wells and well types (horizontal or vertical) in a basin, method 4 is: 

 W  Z 

Emj = γj × ESp + VIGGj,p  

 p=1  j=1 

where: 

Emj is total emissions for gas type (j), being methane and carbon dioxide from all well completions and well workovers during a year in a basin, measured in CO2-e tonnes. 

ESp is the volume of methane vented during a well completion or well workover from strata for each well (p) in cubic metres at standard conditions, worked out in accordance with subsection (2). 

VIGGj,p is the volume of gas type (j) in cubic metres at standard conditions, being methane and carbon dioxide, injected into the well during well completion or well workover, worked out in accordance with subsection (3). 

W is the total number of well completions and well workovers in the basin during a year. 

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions to CO2-e tonnes, being: 

  (a) for methane—6.784 × 10-4 × 25; and  (b) for carbon dioxide—1.861 × 10-3. 

Z is the total number of greenhouse gas types. 

(2) For subsection (1), the factor ESp is worked out using the formula: 

FVp - VIp where: 

FVp is the flow volume of each well (p) in cubic metres at standard conditions, measured using a digital or analog recording flow metre on the vent line to measure flowback during the well completion or well workover, estimated in accordance with Division 2.3.6. 

VIp is the volume of injected gas in cubic metres at standard conditions that is injected into the well during the well completion or well workover, estimated in accordance with Division 2.3.6. 

(3) For subsection (1), VIGGj,p is worked out using the following formula: 

VIp × molj,p % where: 

molj,p%, for each gas type (j), being methane and carbon dioxide, is the gas type’s share of one mole of VIp expressed as a percentage, estimated in accordance with Division 2.3.3. 

VIp is the volume of injected gas in cubic metres at standard conditions that is injected into the well during the well completion or well workover, estimated in accordance with Division 2.3.6. 

Vented volume measured for a sample of wells and well types in a basin 

Vented volume measured for a sample of wells and well types in a basin  

The vented volume is estimated in subsection (4) by using a sampling approach, where a subset of all the well completions/workers, by well type, are sampled during the year for a basin. Subsection (8) sets out the well sampling requirements where, for well completions or workovers,  a minimum of 10% of all well types in a basin are to be sampled.  

Measurement is required of the flow rate for both the flowback and the first 30 day production, in accordance with Division 2.3.6, to derive average flow rates. These average flow rates are used in subsection (7) to derive the ratio of flowback to 30 day production rate (FRMbt) for each well type sampled. 

In subsection (5), the ratio (FRMbt) is extrapolated to all respective well completion/workovers in the basin during the year to give EVp, being the estimated volume of methane flowback during well completions/workovers from strata, for each well. 

Subection (4) estimates net vented emissions for each well by allowing for the subtraction of captured or flared gas type volumes and the addition of gas volume types injected, before finally summing emission net emissions across all wells. 

  (4) For subparagraph 3.46A(2)(b)(i), where vented volume is measured for a sample of wells and well types (horizontal or vertical) in a basin, method 4 is: 

 W Z 

Em =j γj ×  EV +p VIGGj,p - SGj,p  

 p=1 j=1 

where: 

Emj is total emissions for gas type (j), being methane and carbon dioxide from all well completions and well workovers during a year in a basin, measured in CO2-e tonnes. 

Fugitive emissions

EVp is the volume of methane flowback during a well completion or well workover from strata for each well (p) in cubic metres at standard conditions, worked out in accordance with subsection (5). 

SGj,p is the volume of gas type (j), being methane and carbon dioxide, in cubic metres at standard conditions that is captured or flared for each well (p) during the well completion or well workover, estimated in accordance with: 

  (a) for the volume of the gas—Division 2.3.6; and  (b) for the gas composition—Division 2.3.3. 

VIGGj,p is the volume of gas type (j), being methane and carbon dioxide, injected into each well (p) during the well completion or well workover, worked out in accordance with subsection (6). 

W is the total number of well completions and well workovers during a year in the basin. 

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions to CO2-e tonnes, being: 

  (a) for methane—6.784 × 10-4 × 25; and  (b) for carbon dioxide—1.861 × 10-3. 

Z is the total number of greenhouse gas types. 

  (5) For subsection (4), the factor EVp is worked out using the following formula: 

Tp × FRMbt × PRp - VIp where: 

FRMbt is the ratio of flowback during well completions and well workovers to the 30 day production rate for the basin (b) and the well type combination (t), as worked out in accordance with subsection (7). 

PRp is the first 30 days average production flow rate in cubic metres per hour at each well (p), estimated in accordance with Division 2.3.6. 

Tp is the total number of hours for the reporting year of flowback for the well completion or well workover for each well (p) and well type (horizontal or vertical) in a basin. 

VIp is the volume of injected gas in cubic metres at standard conditions that is injected into the well during the well completion or well workover, estimated in accordance with Division 2.3.6. 

(6) For subsection (4), VIGGj,p is worked out using the following formula: 

VIp × molj,p % 

where: 

molj,p%, for each gas type (j), being methane and carbon dioxide, is the gas type’s share of one mole of VIp expressed as a percentage, estimated in accordance with Division 2.3.6. 

VIp is the volume of injected gas in cubic metres at standard conditions that is injected into the well during the well completion or well workover, estimated in accordance with Division 2.3.6. 

(7) For subsection (5), the factor FRMbt is worked out using the following formula: 

N

FRp(bt)

p=1N  

PRp(bt)

p=1 where: 

FRp(bt) is the average flow rate for flowback during well completions and well workovers in cubic metres per hour at standard conditions for each basin (b) and well type combination (t), determined using a digital or analog recording flow metre on the vent line to measure flowback during the well completion or well workover, estimated in accordance with Division 2.3.6. 

N is the number of measured well completions or well workovers in the basin. 

PRp(bt) is the first 30 days production flow rate in cubic metres per hour for each well (p) and well type (t) measured in a basin (b), estimated in accordance with Division 2.3.6. 

  (8) For subsection (7), the sampling requirements for the number of well completions or well workovers performed during a year for each basin and well type (horizontal or vertical) are as follows: 

(a) if one to 5 well completions or workovers are performed during a year, all wells are to be measured; 

(b) if 6 to 50 well completions or workovers are performed during a year, a minimum of 5 wells are to be measured; 

(c) if more than 50 well completions or workovers are performed during a year, a minimum of 10% of wells are to be measured. 

Example of estimating vented emissions from well completions and well workovers using method 4  - subsection (1) Vented volume measured for all wells and well types in a basin Where in subsection (1) 

Input Data 

An example is detailed in the table below of a company performing four well completions during the year in a basin. The company chooses to use the method 4 approach set out in subsection (1) where the vented volume is measured for all four wells. The volume of the flowback gas and gas injected were measured for each well and converted to standard conditions (columns B and C). The methane and carbon dioxide composition of the injected were determined (columns D and E) 

A 

B 

C 

D 

E 

F 

G 

H 

Well No. 

Flow volume of flowback 

measured for well in standard conditions  

Volume of gas 

injected 

into well, in 

standard conditions  

CH4 share of one 

mole of 

VIp, as a percentage 

CO2 share of one 

mole of 

VIp, as a percentage 

Volume of CH4 

injected 

into well  

Volume of CO2 

injected 

into well  

Volume of 

CH4 vented from 

strata for each well 

FVp 

VIp 

molp % 

molp % 

VIGGp 

VIGGp 

ESp 

Cubic metres 

Cubic metres 

% 

% 

Cubic metres 

Cubic metres 

Cubic metres 

D x C 

E x C 

B - C 

1 

22 

2 

20 

80 

0.4 

1.6 

20 

2 

50 

5 

25 

75 

1.25 

3.75 

45 

3 

27 

8 

90 

10 

7.2 

0.8 

19 

4 

15 

4 

95 

5 

3.8 

0.2 

11 

Note: Relatively small quantities have been used for simplicity of example. 

Step 1  Calculate VIGGjp - the volume of CH4 and CO2 injected into each well. 

VIGGj,p is worked in subsection (3) using the following formula: 

VIp × molj,p % 

Referring to the table above, VIGGp for methane and carbon dioxide have been worked out for each well in columns F and G respectively. 

Step 2  Calculate ESp ; the volume of CH4 vented from strata for each well. 

ESp is worked in subsection (2) using the following formula: 

FVp - VIp 

Referring to the table above, ESp has been worked out for each well in column H. 

Step 3  Calculate total vented methane and carbon dioxide volumes for each well:  

For methane (column I) = ESp (column H) + VIGGp (column F) For carbon dioxide (column J) = VIGGp (column G) 

A 

F 

H 

I 

J 

Well No. 

Volume of CH4 

injected 

into well  

Volume of CH4 vented from 

strata for each well 

CH4 well emissions  

CO2 well emissions. 

Equals the 

Volume of CO2 

injected into well  

(VIGGp) 

(ESp) 

(VIGGp) 

Cubic metres 

Cubic metres 

Cubic metres 

Cubic metres 

F + H 

G 

1 

0.4 

20 

20.4 

1.6 

2 

1.25 

45 

46.25 

3.75 

3 

7.2 

19 

26.2 

0.8 

4 

3.8 

11 

14.8 

0.2 

Step 4  Calculate final methane and carbon dioxide emissions for all wells:  

Sum emissions for all wells by gas type and convert from cubic metres to tonnes CO2-e. 

For methane: 

Sum column I 

= 20.4 + 46.25 + 26.2 + 14.8 

= 107.65 m3 

Methane conversion factor γj = 6.784 × 10-4 × 25  

= 107.65 x 6.784 × 10-4 × 25 

= 1.8257 tonnes CO2-e 

For carbon dioxide: 

Sum column J 

= 1.6 + 3.75 + 0.8 + 0.2 

= 6.35 m3 

Carbon dioxide conversion factor γj =  1.861 × 10-3 

= 6.35 x 1.861 × 10-3 

= 0.012 tonnes CO2-e 

Therefore: total vented emissions from well completions performed to the four wells during the year are: 

Methane = 1.8257 tonnes CO2-e 

Carbon dioxide = 0.012 tonnes CO2-e 

Example of estimating vented emissions from well completions and well workovers using method 4  - subsection (1) Vented volume measured for a sample of wells and well types in a basin 

Where in subsection (4) 

 W Z 

Em =j γj ×  EV +p VIGGj,p - SGj,p  

 p=1 j=1 

Input Data 

An example is detailed in the table below of a company performing four well completions during the year in a basin. The company chooses to use the method 4 approach set out in subsection (4) where the vented volume is estimated using the measurement of flowback and production rate within a well sampling framework.  

The average rate of flowback gas per well completion (FRp(bt) ) and the average 30 day production rate per well (PRp(bt) ) were deterimined by measurement (columns B and C).  

The total number of hours of flowback for the well completion (Tp ) were recorded (column D). 

The volumes of gas injected were measured for each well (VIp ) and converted to standard conditions (column E). The methane and carbon dioxide composition (molj,p%) of the injected gas were determined (columns F and G). Volumes of methane and carbon dioxide captured during well completions (SGj,p ), converted to standard conditions, were estimated for each well (columns J and K).  

Fugitive emissions

A 

B 

C 

D 

E 

F 

G 

H 

I 

J 

K 

Well No. 

Average rate of 

flowback 

gas per well 

completio n 

Average 

30 day productio

n rate per well 

Number of hours of 

flowback for the well 

completio n 

Volume of gas 

injected 

into well 

CH4 

share of 

one mole 

of VIp, as a 

percentag

e 

CO2 

share of 

one mole 

of VIp, as a 

percentag

e 

Volume of CH4 

injected 

into well  

Volume of CO2 

injected 

into well  

Volume of CH4 captured  

Volumes of CO2 captured 

FRp(bt) 

PRp(bt) 

Tp  

VIp 

molp % 

molp % 

VIGGp 

VIGGp 

SGj,p  

SGj,p  

Cubic metres per hour 

Cubic metres per hour 

Hours 

Cubic metres 

% 

% 

Cubic metres 

Cubic metres 

Cubic metres 

Cubic metres 

E x F 

E x G 

1 

5 

2 

22 

2 

20 

80 

0.4 

1.6 

8 

0.5 

2 

4 

2 

50 

5 

25 

75 

1.25 

3.75 

8 

1 

3 

3 

1 

27 

8 

90 

10 

7.2 

0.8 

7 

0 

4 

6 

4 

87 

4 

95 

5 

3.8 

0.2 

8 

0 

Note: Relatively small quantities have been used for simplicity of example. 

Step 1  Determine the well sampling requirements: 

Sampling requirments are set out in subsection (8). In this example only four vertical well completions were performed in the basin during the year. Therefore, according to paragraph 

(8)(a), all four wells are required to be measured.  

Step 2  Calculate FRMbt ; the ratio of flowback during well completions to the 30 day production rate for each well. 

FRMbt  is worked in subsection (7) using the following formula: 

N

FRp(bt)

p=1

N

PRp(bt)

p=1

Therefore FRMbt is calculated for each well in column L of the following table: 

A 

B 

C 

L 

Well No. 

Average rate of flowback gas per well completion 

Average 30 day production rate per well 

The ratio of flowback during well completions to 

the 30 day production rate   

FRp(bt) 

PRp(bt) 

FRMbt 

Cubic metres per hour 

Cubic metres per hour 

B / C 

1 

5 

2 

2.5 

2 

4 

2 

2 

3 

3 

1 

3 

4 

6 

4 

1.5 

Step 3  Calculate EVp ; the volume of methane flowback during a well completion from strata for each well. 

EVp  is worked in subsection (5) using the following formula: 

T × FRMp bt × PRp - VIp 

Therefore EVp  is calculated for each well in column M of the following table: 

A 

D 

L 

C 

E 

M 

Well No. 

Number of hours of flowback for the well 

completion 

The ratio of flowback during 

well completions to the 30 day 

production rate   

Average 30 day production rate per well 

Volume of gas injected into 

well, in standard conditions  

Volume of CH4 flowback during a well 

completion from 

strata  

Tp  

FRMbt 

PRp(bt) 

VIp 

EVp 

Hours 

Cubic metres per hour 

Cubic metres 

Cubic metres 

D x L x C - E 

1 

22 

2.5 

2 

2 

108 

2 

50 

2 

2 

5 

195 

3 

27 

3 

1 

8 

73 

4 

87 

1.5 

4 

4 

518 

Step 4  Calculate VIGGjp ; the volume of CH4 and CO2 injected into each well. 

VIGGj,p is worked in subsection (6) using the following formula: 

VIp × molj,p % 

Referring to the input data table, VIGG j,p for methane and carbon dioxide have been worked out for each well in columns H and I respectively. 

Step 5  Calculate total vented methane and carbon dioxide volumes for each well:  

For methane (column N) = EVp (column M) + VIGGp (column H) - SGp (column J)  

A 

M 

H 

J 

N 

Well No. 

Volume of CH4 

injected into well 

Volume of CH4 

injected into well 

Volume of CH4 captured 

CH4 well emissions 

EVp 

VIGGp 

SGp  

Cubic metres 

Cubic metres 

Cubic metres 

Cubic metres 

M + H - J 

1 

108 

0.4 

8 

100.4 

2 

195 

1.25 

8 

188.25 

3 

73 

7.2 

7 

73.2 

4 

518 

3.8 

8 

513.8 

For carbon dioxide (column O) = VIGGp (column I) - SGp (column K) 

A 

I 

K 

O 

Well No. 

Volume of 

CO2 injected into well  

Volume of CO2 captured 

CO2 well emissions 

VIGGp 

SGp 

Cubic metres 

Cubic metres 

Cubic metres 

I - K 

1 

1.6 

0.5 

1.1 

2 

3.75 

1 

2.75 

3 

0.8 

0 

0.8 

4 

0.2 

0 

0.2 

Step 6  Calculate final methane and carbon dioxide emissions for all wells:  

Sum emissions for all wells by gas type and convert from cubic metres to tonnes CO2-e. 

For methane sum column N 

= 100.4 + 188.25 + 73.2 + 513.8 

= 875.65 m3 

Apply methane conversion factor γj = 6.784 × 10-4 × 25  

= 875.65 x 6.784 × 10-4 × 25 

= 14.851 tonnes CO2-e 

For carbon dioxide 

Sum column O 

= 1.1 + 2.75 + 0.8 + 0.2 

= 4.85 m3 

Apply carbon dioxide conversion factor γj =  1.861 × 10-3 

= 4.85 x 1.861 × 10-3 

= 0.009 tonnes CO2-e 

Therefore: total vented emissions from well completions performed to the four wells during the year are: 

Methane = 14.851 tonnes CO2-e 

Carbon dioxide = 0.009 tonnes CO2-e 

Fugitive emissions

Division 3.3.3—Crude oil production 

Emissions arise for this category from fugitive sources such as leaks, accidental releases, vents, storage losses and from flaring of fuels (that is, the combustion of fuels for non-productive or non-commercial reasons) – for example for health and safety reasons.    

Subdivision 3.3.3.1—Preliminary 

3.47  Application 

(1) This Division applies to fugitive emissions from crude oil production activities, including emissions from flaring, from: 

(a) an oil wellhead; and 

(b) well servicing; and 

(c) oil sands mining; and 

(d) shale oil mining; and 

(e) the transportation of untreated production to treating or extraction plants; and 

(f) activities at extraction plants or heavy oil upgrading plants, and gas reinjection systems and produced water disposal systems associated with the those plants; and 

(g) activities at upgrading plants and associated gas reinjection systems and produced water disposal systems. 

(2) For paragraph (1)(e), untreated production includes: 

(a) well effluent; and 

(b) emulsion; and  (c) oil shale; and  (d) oil sands. 

Subdivision 3.3.3.2—Crude oil production (non-flared)—fugitive leak emissions of methane 

Fugitive leakage emissions of methane may occur in crude oil production from sources such as the unintentional equipment leaks from valves, flanges, pump seals, compressor seals, relief valves, sampling connections, process drains, open-ended lines, casing, tanks and other leakage sources from pressurised equipment not classed as a vent. 

3.48  Available methods 

(1) Subject to section 1.18, for estimating fugitive emissions of methane, other than fugitive emissions of methane specified in subsection (1A), during a year from the operation of a facility that is constituted by crude oil production, one of the following methods must be used: 

(a) method 1 under section 3.49; 

(b) method 2 under section 3.50; 

Note: There is no method 3 or 4 for this Division. 

  (1A) For subsection (1), the following fugitive emissions of methane are specified: 

(a) fugitive emissions from oil or gas flaring; 

(b) fugitive emissions that result from system upsets, accidents or deliberate releases from process vents. 

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

Summary of available methods, for estimating fugitive leak emissions from crude oil production (non-flared), by emissions of gas type (j) 

CO2 

CH4 

N2O 

Method 1 

NO 

Section 3.49 

NO 

Method 2 

NO 

Section 3.50 

NO 

Method 3 

NO 

NA 

NO 

Method 4 

NO 

NA 

NO 

NA = Not available.  NO = Not occurring 

3.49  Method 1—crude oil production (non-flared) emissions of methane 

  (1) Method 1 is: 

  E = ij k (Q  EF ) + Q  EF  ik  ijk i  (l) ij 

where: 

Eij is the fugitive emissions of methane (j) from the crude oil production during the year measured in CO2-e tonnes. 

Σk is the emissions of methane (j) measured in tonnes of CO2-e and estimated by summing up the emissions released from all of the equipment of type (k) specified in column 2 of the table in subsection (2), if the equipment is used in the crude oil production. 

Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment of type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the crude oil production. 

EFijk is the emission factor for methane (j) measured in tonnes of CO2-e per tonne of crude oil that passes through each equipment of type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the crude oil production. 

Qi is the total quantity of crude oil (i) measured in tonnes that passes through the crude oil production. 

EF(l) ij is 1.4 x 10-3, which is the emission factor for methane (j) from general leaks in the crude oil production, measured in CO2-e tonnes per tonne of crude oil that passes through the crude oil production. 

  (2) For EFijk mentioned in subsection (1), column 3 of an item in the following table specifies the emission factor for an equipment of type (k) specified in column 2 of that item: 

Item Equipment type (k) Emission factor for gas type (j) (tonnes CO2-e/tonnes fuel throughput) 

CH4 

1 

Internal floating tank 

1.0  106 

2 

Fixed roof tank 

5.0  106 

3 

Floating tank 

4.0  106 

(3) For EF(l) ij in subsection (1), general leaks in the crude oil production comprise the emissions (other than vent emissions) from equipment listed in sections 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production. 

3.50  Method 2—crude oil production (non-flared) emissions of methane 

Method 2 requires the use of equipment-specific emission factors and more detail on the types of equipment used at the facility. The Method is intended to be as specified in the American Petroleum Institute’s Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Natural Gas Industry 2009, sections 5 and 

6.1.2.     

  (1) Method 2 is: 

  E = ij  k (Qik  EF )ijk 

where: 

Eij is the fugitive emissions of methane (j) from the crude oil production during the year measured in CO2-e tonnes. 

Σk is the emissions of methane (j) measured in tonnes of CO2-e and estimated by summing up the emissions released from each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment type is used in the crude oil production. 

Qik is the total of the quantities of crude oil that pass through each equipment type (k), or the number of equipment units of type (k), listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production, measured in tonnes. 

EFijk is the emission factor of methane (j) measured in tonnes of CO2-e per tonne of crude oil that passes through each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production. 

  (2) For EFijk, the emission factors for methane (j), as crude oil passes through an equipment type (k), are: 

(a) as listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, for the equipment type; or 

(b) if the manufacturer of the equipment supplies equipment-specific emission factors for the equipment type—those factors. 

Subdivision 3.3.3.3—Crude oil production (flared)—fugitive 

emissions of carbon dioxide, methane and nitrous oxide 

Methods 1, 2 and 3 are provided for flaring of fuels.  Methods 2 and 3 rely on the sampling and analysis of the fuel to estimate the composition of the gases in the fuel in accordance with the provisions of chapter 2. 

3.51  Available methods 

(1) Subject to section 1.18, for estimating emissions released by oil or gas flaring during a year from the operation of a facility that is constituted by crude oil production: 

(a) if estimating emissions of carbon dioxide released—one of the following methods must be used: 

(i) method 1 under section 3.52; 

(ii) method 2 under section 3.53; 

(iii) method 3 under section 3.54; and 

(b) if estimating emissions of methane released—one of the following methods must be used: 

(i) method 1 under section 3.52; 

(ii) method 2A under section 3.53A; and 

(c) if estimating emissions of nitrous oxide released—one of the following methods must be used: 

(i) method 1 under section 3.52; 

(ii) method 2A under section 3.53A. 

Note: There is no method 4 under paragraph (a) and no method 2, 3 or 4 under paragraph (b) or (c). 

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

Available methods, for estimating emissions from crude oil production (flared), by emissions of gas type (j) 

CO2 

CH4 

N2O 

Method 1 

Section 3.52 

Section 3.55 

Section 3.55 

Method 2 

Section 3.53 

NA 

NA 

Method 3 

Section 3.54 

NA 

NA 

Method 4 

NA 

NA 

NA 

NA = Not available.  NO = Not occurring 

3.52  Method 1—crude oil production (flared) emissions 

(1) For subparagraph 3.51(a)(i), method 1 is: 

  E = Q  EFij i  ij 

where: 

Eij is the emissions of gas type (j) measured in CO2-e tonnes from a fuel type (i) flared in crude oil production during the year. 

Qi is the quantity of fuel type (i) measured in tonnes flared in crude oil production during the year. 

EFij is the emission factor for gas type (j) measured in tonnes of CO2-e emissions per tonne of the fuel type (i) flared. 

(2) For EFij mentioned in subsection (1), columns 3, 4 and 5 of an item in following table specify the emission factor for each fuel type (i) specified in column 2 of that item. 

Item Fuel type (i) Emission factor for gas type (j) (tonnes CO2-e/tonnes of fuel flared) 

CO2 CH4 

N2O 

1 

Unprocessed gas flared 

2.8 0.8 

0.03 

2 

Crude oil 

3.2 0.008 

0.07 

3.53  Method 2—crude oil production 

Combustion of gaseous fuels (flared) emissions of carbon dioxide 

  (1) For subparagraph 3.51(1)(a)(ii), method 2 for combustion of gaseous fuels 

is: 

Eico2 =  Q × EF ×  OFh h i +  QCO2    

where: 

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in crude oil production during the year, measured in CO2-e tonnes. 

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil production during the year, measured in tonnes in accordance with Division 2.3.3. 

EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in crude oil production during the year, measured in CO2-e tonnes per tonne of fuel type (i) flared, estimated in accordance with method 2 in Division 2.3.3. 

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared. 

QCO2 is the quantity of CO2 within the fuel type (i) in crude oil production during the year, measured in CO2-e tonnes in accordance with Division 2.3.3. 

Combustion of liquid fuels (flared) emissions of carbon dioxide 

  (2) For subparagraph 3.51(1)(a)(ii), method 2 for combustion of liquid fuels is the same as method 1, but the carbon dioxide emissions factor EFh must be determined in accordance with method 2 in Division 2.4.3. 

3.53A  Method 2A—crude oil production (flared methane or nitrous oxide emissions) 

  For subparagraphs 3.51(1)(b)(ii) and (c)(ii), method 2A is: 

E = Q × EF × OFij h hij i where: 

EFhij is the emission factor of gas type (j), being methane or nitrous oxide, for the total hydrocarbons (h) within the fuel type (i) in crude oil production during the year, mentioned for the fuel type in the table in subsection 3.52(2) and measured in CO2-e tonnes per tonne of the fuel type (i) flared. 

Eij is the fugitive emissions of gas type (j), being methane or nitrous oxide, from fuel type (i) flared from crude oil production during the year, measured in CO2-e tonnes. 

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared. 

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil production during the year, measured in tonnes in accordance with Division 2.3.3 for gaseous fuels or Division 2.4.3 for liquid fuels. 

3.54  Method 3—crude oil production 

Combustion of gaseous fuels (flared) emissions of carbon dioxide 

(1) For subparagraph 3.51(1)(a)(iii), method 3 for the combustion of gaseous fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.3.4. 

Combustion of liquid fuels (flared) emissions of carbon dioxide 

(2) For subparagraph 3.51(1)(a)(iii), method 3 for the combustion of liquid fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.4.4. 

Subdivision 3.3.3.4—Crude oil production (non-flared)—fugitive vent emissions of methane and carbon dioxide 

3.56A  Available methods 

(1) Subject to section 1.18, the methods mentioned in subsections (2) and (3) must be used for estimating fugitive emissions that result from system upsets, accidents and deliberate releases from process vents during a year from the operation of a facility that is constituted by crude oil production. 

(2) To estimate emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, one of the following methods must be used: 

  (a) method 1 under section 3.84;  (b) method 4 under Part 1.3. 

(3) For estimating incidental emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the 

operation of the facility, another method may be used that is consistent with the principles mentioned in section 1.13. 

Note: There is no method 2 or 3 for this Subdivision. 

Summary of available methods, for estimating fugitive vent emissions from crude oil production (non-flared), by emissions of gas type (j) 

CO2 

CH4 

N2O 

Method 1 

Section 3.56A 

Section 3.56A 

NO 

Method 2 

NA 

NA 

NO 

Method 3 

NA 

NA 

NO 

Method 4 

Part 1.3 

Part 1.3 

NO 

NA = Not available.  NO = Not occurring 

Example 

A crude oil production platform has a throughput of 710,400 tonnes of crude oil during the year.  It has an equipment type constituting a floating tank in which 685,000 tonnes of crude oil throughput occurred during the year. 400 tonnes of crude oil were flared during the year.  

The Reporter elects to use Method 1 to calculate fugitive emissions from crude oil production and flaring, for each of the greenhouse emission gases (j) (carbon dioxide, methane and nitrous oxide). Emissions are estimated as follows: Part A: Crude oil production (non flared component) 

  Eij = Σk (Qik  EFijk) +  Qi  EF(l) ij  

where: 

Eij is the emissions measured in CO2 e tonnes of methane (j), released from the crude oil production during the year. 

Σk is the sum of emissions of methane (j) (tonnes of CO2-e) arising from equipment of types (k) listed in the table in section 3.49. 

Qik is the total of the quantities of crude oil (tonnes) that pass through each equipment of type (k) listed in the table in section 3.49 . In this case it is the crude oil throughput for the floating tank is 685,000 tonnes. 

EFijk is the emission factor for methane (j) measured as tonnes of CO2-e per tonne of crude oil that passes through each equipment of type (k).  In this case the emission factor  for  the  floating tank is 3.2 x 10-6 CO2-e/tonnes fuel throughput. 

Qi is the total quantity of crude oil (i) measured in tonnes of crude oil production. In this case the crude oil production throughput is 710,400 tonnes. 

EF(l) ij  1.4 x 10-3, is the emission factor for methane (j) from general leaks in the crude oil production, measured in CO2 e tonnes per tonne of crude oil production. 

Therefore, the estimate of methane emissions in CO2-e tonnes : 

= (685,000 x 4.0 x10-6) + (710,400 x 1.4 x 10-3) 

Total emissions of methane  = 997 t CO2-e 

Part B: Crude oil production (flared component) 

Eij = Qi  EFij 

where: 

Eij is the emissions of gas type (j)  (CO2-e tonnes) released from a fuel type (i) flared. 

Qi is the quantity of fuel type flared (i) (tonnes). In this case  the quantity of crude oil flared is 400 tonnes. 

EFij is the emission factor for gas type (j) in tonnes of CO2-e emissions per tonne of the fuel type (i) flared. The emission factors are obtained from Method 1, section 3.52 

Therefore, the estimate of greenhouse gas emissions (from carbon dioxide, methane and nitrous oxide (j)) in CO2-e tonnes: 

For carbon dioxide 

=400 x 3.2 

Total emissions of carbon dioxide  = 1280 t CO2-e 

For methane 

=400 x 0.008 

Total emissions of methane  = 3 t CO2-e 

For nitrous oxide 

=400 x 0.07 

Total emissions of nitrous oxide  = 28 t CO2-e 

Part C: Crude oil production (vented emissions component) 

The Reporter is directed to section 3.84 which specifies the applicable sections of the 

American Petroleum Institute’s Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Natural Gas Industry 2009(API Compendium). The reporter estimates their vented emissions in accordance with those methods detailed in the API Compendium, producing the following results: 

Total emissions of carbon dioxide  = 380 t CO2-e 

Total emissions of methane  = 980 t CO2-e 

Division 3.3.4—Crude oil transport 

The crude oil transport subsector includes fugitive methane emissions associated with the marine, road and rail transport of crude oil. Emissions result largely from three types of activities: loading, transit, and ballasting.  

3.57  Application 

  This Division applies to fugitive emissions from crude oil transport activities, other than emissions that are flared.  

3.58  Available methods 

(1) Subject to section 1.18, one of the following methods must be used for estimating fugitive emissions of methane released during a year from the operation of a facility that is constituted by crude oil transport: 

  (a) method 1 under section 3.59;  (b) method 2 under section 3.60. 

Note: There is no method 3 or 4 for this Division. 

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

Available methods, for estimating emissions from crude oil transport), by emissions of gas type (j) 

CO2 

CH4 

N2O 

Method 1 

NO 

Section 3.59 

NO 

Method 2 

NO 

Section 3.60 

NO 

Method 3 

NO 

NA 

NO 

Method 4 

NO 

NA 

NO 

NA = Not available. NO = Not occurring 

3.59  Method 1—crude oil transport 

Method 1 for crude oil transport for fugitive emissions is derived from the National Greenhouse Accounts. 

Method 1 is: 

E = Q  EFij i  ij 

where: 

Eij is the fugitive emissions of methane (j) from the crude oil transport during the year measured in CO2-e tonnes. 

Qi is the quantity of crude oil (i) measured in tonnes and transported during the year. 

EFij is the emission factor for methane (j), which is 8.7 x 10-4 tonnes CO2-e per tonnes of crude oil transported during the year. 

3.60  Method 2—fugitive emissions from crude oil transport 

Method 2 requires the use of equipment-specific emission factors and more detail on the types of equipment used at the facility. The Method is intended to be as specified in the American Petroleum Institute’s Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Natural Gas Industry 2009sections 5 and 6.1.2.    

  (1) Method 2 is: 

Fugitive emissions

  E = ij k (Qik  EF )ijk 

where: 

Eij is the fugitive emissions of methane (j) from the crude oil transport during the year measured in CO2-e tonnes. 

Σk is the emissions of methane (j) measured in tonnes of CO2-e and estimated by summing up the emissions from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport. 

Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport. 

EFijk is the emission factor of methane (j) measured in tonnes of CO2-e per tonne of crude oil that passes though each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport. 

  (2) For EFijk, the emission factors for methane (j), as crude oil passes through equipment type (k), are: 

(a) as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or 

(b) if the manufacturer of the equipment supplies equipment-specific emission factors for the equipment type—those factors. 

Division 3.3.5—Crude oil refining 

Emissions arise for this category from fugitive sources (for example gas leaks), flaring and from the process vents, system upsets and accidents, including the combustion of catalyst coke for non-energy purposes.   

Other sources of emissions arising from the crude oil refining, such as from the combustion of fuels for energy or from the production of hydrogen, are not described in this chapter and must be estimated using the Methods described in other chapters.   

3.61  Application 

  This Division applies to fugitive emissions from crude oil refining activities, including emissions from flaring at petroleum refineries. 

3.62  Available methods 

(1) Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by crude oil refining the methods as set out in this section must be used. 

Crude oil refining and storage tanks 

(2) One of the following methods must be used for estimating fugitive emissions of methane that result from crude oil refining and from storage tanks for crude oil: 

(a) method 1 under section 3.63;  (b) method 2 under section 3.64. 

Note: There is no method 3 or 4 for subsection (2). 

Process vents, system upsets and accidents 

(3) One of the following methods must be used for estimating fugitive emissions of each type of gas, being carbon dioxide, methane and nitrous oxide, that result from deliberate releases from process vents, system upsets and accidents: 

  (a) method 1 under section 3.65;  (b) method 4 under section 3.66. 

Note: There is no method 2 or 3 for subsection (3). 

Flaring 

(4) For estimating emissions released from gas flared from crude oil refining:  (a) one of the following methods must be used for estimating emissions of carbon dioxide released: 

(i) method 1 under section 3.67; 

(ii) method 2 under section 3.68; 

(iii) method 3 under section 3.69; and 

(b) if estimating emissions of methane released—one of the following methods must be used: 

(i) method 1 under section 3.67; 

(ii) method 2A under section 3.68A; and 

(c) if estimating emissions of nitrous oxide released—one of the following methods must be used: 

(i) method 1 under section 3.67; 

(ii) method 2A under section 3.68A. 

Note: The flaring of gas from crude oil refining releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 under section 3.67 is a reference to these gases. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide and no method 2, 3 or 4 for emissions of nitrous oxide or methane. 

(5) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

Summary of available methods, for estimating emissions from crude oil refining, by emissions of gas type (j) 

CO2 

CH4 

N2O 

Crude oil refining and storage tanks 

Method 1 

NO 

Section 3.63 

NO 

Method 2 

NO 

Section 3.64 

NO 

Methods 3, 4 

NO 

NA 

NO 

Process vents, system upsets and accidents 

Method 1 

Section 3.65 

Section 3.65 

Section 3.65 

Methods 2, 3 

NA 

NA 

NA 

Method 4 

Section 3.66 

Section 3.66 

Section 3.66 

Flaring 

Method 1 

Section 3.67 

Section 3.67 

Section 3.67 

Method 2 

Section 3.68 

NA 

NA 

Method 3 

Section 3.69 

NA 

NA 

Method 4 

NA 

NA 

NA 

NA = Not available. NO = Not occurring  

Subdivision 3.3.5.1—Fugitive emissions from crude oil refining and from storage tanks for crude oil 

3.63  Method 1—crude oil refining and storage tanks for crude oil 

Method 1 for fugitive emissions from crude oil refining is derived from the National Greenhouse Accounts. 

Method 1 is: 

  E = ij i  Q  EFi  ij 

where: 

Eij is the fugitive emissions of methane (j) from fuel type (i) being crude oil refined or stored in tanks during the year measured in CO2-e tonnes. 

∑I is the sum of emissions of methane (j) released during refining and from storage tanks during the year. 

Qi is the quantity of crude oil (i) refined or stored in tanks during the year measured in tonnes. 

EFij is the emission factor for methane (j) being 8.5 x 10-4 tonnes CO2-e per tonne of crude oil refined and 1.5 x 10-4 tonnes CO2-e per tonne of crude oil stored in tanks. 

3.64  Method 2—crude oil refining and storage tanks for crude oil 

Method 2 for fugitive emissions from crude oil refining requires the use of equipmentspecific emission factors and more detail on the types of equipment used at the facility. The Method is intended to be as specified in the American Petroleum Institute’s Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Natural Gas Industry 2009 sections 5 and 6.1.2. 

  (1) Method 2 is: 

E = ij k (Qik  EF )ijk 

where: 

Eij is the fugitive emissions of methane (j) from the crude oil refining and from storage tanks during the year measured in CO2-e tonnes. 

Σk is the emissions of methane (j) measured in tonnes of CO2-e estimated by summing up the emissions released from each equipment types (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks. 

Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks. 

EFijk is the emission factor for methane (j) measured in tonnes of CO2-e per tonne of crude oil that passes though each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks. 

  (2) For EFijk, the emission factors for methane (j) as the crude oil passes through an equipment type (k) are: 

(a) as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or 

(b) if the manufacturer of the equipment supplies equipment-specific emission factors for the equipment type—those factors. 

Subdivision 3.3.5.2—Fugitive emissions from deliberate releases from process vents, system upsets and accidents 3.65  Method 1—fugitive emissions from deliberate releases from process vents, system upsets and accidents 

Method 1 for the estimation of emissions from the burning of catalyst coke for nonenergy purposes is derived from the American Petroleum Institute’s Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Natural Gas Industry 2009 sections 5.2.   

It is intended that there should be no double count or omissions of emissions from the estimation of emissions from the combustion of the catalyst coke. Where it is difficult to distinguish between the emissions from combustion of catalyst coke for non-energy purposes from its use as an energy source, it is intended that all emissions should be attributed to the combustion of fuels for energy. 

  Method 1 is: 

E = Qi i CCFi 

where: 

Ei is the fugitive emissions of carbon dioxide during the year from deliberate releases from process vents, system upsets and accidents in the crude oil refining measured in CO2-e tonnes. 

Qi is the quantity of refinery coke (i) burnt to restore the activity of the catalyst of the crude oil refinery (and not used for energy) during the year measured in tonnes. 

CCFi is the carbon content factor for refinery coke (i) as mentioned in Schedule 3. 

3.664 is the conversion factor to convert an amount of carbon in tonnes to an amount of carbon dioxide in tonnes. 

3.66  Method 4—deliberate releases from process vents, system upsets and accidents 

Method 4 is provided as an additional option and is taken from the American 

Petroleum Institute’s Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Natural Gas Industry 2009 sections 5 and 6.1.2.  

Consistent with the American Petroleum Institute methodology, emissions of carbon 

Fugitive emissions

monoxide must be treated as if they fully oxidise to carbon dioxide and estimated accordingly.  

(1) Method 4 is: 

(a) is as set out in Part 1.3; or 

(b) uses the process calculation approach in section 5.2 of the API Compendium.  

(2) For paragraph (1)(b), all carbon monoxide is taken to fully oxidise to carbon dioxide and must be included in the calculation. 

Subdivision 3.3.5.3—Fugitive emissions released from gas flared from the oil refinery 

Flares are commonly used at refineries for the disposal of vented waste gases. The flaring of refinery gases results in the emission of CO2, methane, nitrous oxide and products of incomplete combustion. Method 1 is derived from the methods used for the National Greenhouse Accounts.  Methods 2 and 3 rely on the sampling and analysis of the fuel to estimate the composition of the gases in the fuel in accordance with the provisions of chapter 2. 

3.67  Method 1—gas flared from crude oil refining 

(1) Method 1 is: 

E = Qij i  EFij 

where: 

Eij is the emissions of gas type (j) released from the gas flared in the crude oil refining during the year measured in CO2-e tonnes. 

Qi is the quantity of gas type (i) flared during the year measured in tonnes. 

EFij is the emission factor for gas type (j) measured in tonnes of CO2-e emissions per tonne of gas type (i) flared in the crude oil refining during the year. 

(2) For EFij in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor for gas type (j) for the fuel type (i) specified in column 2 of that item: 

Item fuel type (i) Emission factor of gas type (j) (tonnes 

CO2-e/tonnes fuel flared) 

CO2 

CH4 

N2O 

1 gas  

2.7 

0.1 

0.03 

3.68  Method 2—gas flared from crude oil refining   For subparagraph 3.62(4)(a)(ii), method 2 is: 

  Eico2 =  Q ×  EF ×  OFh h i +  QCO2 

where: 

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in crude oil refining during the year, measured in CO2-e tonnes. 

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, measured in tonnes in accordance with Division 2.3.3. 

EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in the crude oil refining during the year, measured in CO2-e tonnes per tonne of fuel type (i) flared, estimated in accordance with method 2 in Division 2.3.3. 

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared. 

QCO2 is the quantity of CO2 within the fuel type (i) in the crude oil refining during the year, measured in CO2-e tonnes in accordance with Division 2.3.3. 

3.68A   Method 2A—crude oil refining (flared methane or nitrous oxide emissions) 

  For subparagraphs 3.62(4)(b)(ii) and (c)(ii), method 2A is: 

E = Q × EF × OFij h hij i where: 

EFhij is the emission factor of gas type (j), being methane or nitrous oxide, for the total hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, mentioned for the fuel type in the table in subsection 3.67(2) and measured in CO2-e tonnes per tonne of the fuel type (i) flared. 

Eij is the fugitive emissions of gas type (j), being methane or nitrous oxide, from fuel type (i) flared from crude oil refining during the year, measured in CO2-e tonnes. 

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared. 

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, measured in tonnes in accordance with Division 2.3.3. 

3.69  Method 3—gas flared from crude oil refining 

  For subparagraph 3.62(4)(a)(iii), method 3 is the same as method 2 under section 3.68, but the emission factor EFij must be determined in accordance with method 3 for the consumption of gaseous fuels as specified in Division 2.3.4. 

Estimating carbon dioxide emissions from crude oil refining flaring using Method 2 

Crude oil refining usually involves some flaring of a waste gas stream. In this example a facility flares a waste gas stream of 10,000 tonnes during the year, which contains a relatively high content of carbon dioxide in addition to some hydrogen sulphide and hydrocarbons. The reporters have chosen to use method 2 as this approach provides the opportunity to develop a carbon dioxide emission factor that better reflects the hydrocarbons present in the gas stream, as well as account for the in-situ carbon dioxide quantity which is emitted, but not combusted in the flare. 

Calculate the carbon dioxide emissions using Method 2 in section 3.68 of NGER 

(Measurement) Determination 

Eico2 = (Qh × EFh × OFi ) + QCO2 

  Where: 

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in crude oil refining during the year, measured in CO2-e tonnes. 

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, measured in tonnes in accordance with Division 2.3.3. 

QCO2 is the quantity of CO2 within the fuel type (i) in crude oil refining during the year, measured in CO2-e tonnes in accordance with Division 2.3.3. 

In this example it was determined (in accordance with Division 2.3.3) that the average composition of the waste gas stream being flared during the year is as follows: 

Hydrocarbons C1 to C5 = 0.87 tonnes/ tonne of waste gas stream 

Hydrogen sulphide  = 0.05 tonnes/ tonne of waste gas stream 

Nitrogen = 0.02 tonnes/ tonne of waste gas stream 

Carbon dioxide  = 0.06 tonnes/ tonne of waste gas stream 

Therefore: 

Qh  = 0.87  x 10,000 t of waste gas stream flared during the year 

Qh  = 8700 tonnes   

QCO2 = 0.06  x 10,000 t of waste gas stream flared during the year 

QCO2 = 600 tonnes 

EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, measured in CO2-e tonnes per tonne of fuel type (i) flared, estimated in accordance with method 2 in Division 2.3.3. 

In this example it was determined (in accordance with Division 2.3.3) that the emission factor derived from the average hydrocarbon composition of the waste gas stream being flared during the year was: 

2.4 tonnes of CO2 per tonne of waste gas stream flared 

Therefore: 

EFh = 2.4 

  OFi is 0.98, which is the correction factor for the oxidation of fuel type (i) flared. 

To calculate the CO2 emissions from waste gas flared: 

  = (8700 x 2.4 x 0.98) + 600 = 21,062.4  

Therefore, the total emissions from the source = 21,062 tonnes of CO2  

Division 3.3.6—Natural gas production or processing, other than emissions that are vented or flared 

Fugitive leakage emissions of methane may occur in natural gas production from sources such as the unintentional equipment leaks from valves, flanges, pump seals, compressor seals, relief valves, sampling connections, process drains, open-ended lines, casing, tanks and other leakage sources from pressurised equipment not classed as a vent. 

The venting of CO2 and methane extracted from raw gas and flaring of unusable gas produced at various stages of processing are separately accounted for under venting and flaring. 

Other sources of emissions arising from natural gas production and processing, such as from the combustion of fuels for energy, are not described in this chapter and must be estimated using the Methods described in other chapters.   

Note that in this part the definition of natural gas is as follows: 

natural gas includes coal seam methane that is captured for combustion where the production of coal is not intended to occur 

3.70  Application 

  This Division applies to fugitive emissions from natural gas production or processing activities, other than emissions that are vented or flared, including emissions from: 

(a) a gas wellhead through to the inlet of gas processing plants; and 

(b) a gas wellhead through to the tie-in points on gas transmission systems, if processing of natural gas is not required; and 

(c) gas processing plants; and 

(d) well servicing; and 

(e) gas gathering; and 

(f) gas processing and associated waste water disposal and acid gas disposal activities. 

3.71  Available methods 

(1) Subject to section 1.18, one of the following methods must be used for estimating fugitive emissions of methane (other than emissions that are 

Fugitive emissions

vented or flared) released during a year from the operation of a facility that is constituted by natural gas production and processing: 

  (a) method 1 under section 3.72;  (b) method 2 under section 3.73. 

Note: There is no method 3 or 4 for this Division. 

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

Summary of available methods, for estimating emissions from natural gas production and processing (other than emissions that are vented or flared), by emissions of gas type (j) 

CO2 

CH4 

N2O 

Method 1 

NO 

Section 3.72 

NO 

Method 2 

NO 

Section 3.73 

NO 

Method 3 

NO 

NA 

NO 

Method 4 

NO 

NA 

NO 

NA = Not available. NO = Not occurring 

3.72  Method 1—natural gas production and processing (other than emissions that are vented or flared) 

  (1) Method 1 is: 

E = ij k (Q   EF ) + Q   EFik  ijk i  (l) ij 

where: 

Eij is the fugitive emissions of methane (j) (other than emissions that are vented or flared) from the natural gas production and processing during the year measured in CO2-e tonnes. 

Σk is the total emissions of methane (j), measured in CO2-e tonnes and estimated by summing up the emissions released from each equipment type (k) specified in column 2 of an item in the table in subsection (2), if the equipment is used in the natural gas production and processing. 

Qik is the total of the quantities of natural gas that pass through each equipment type (k), or the number of equipment units of type (k) specified in column 2 of the table in subsection (2), measured in tonnes. 

EFijk is the emission factor for methane (j) measured in CO2-e tonnes per tonne of natural gas that passes through each equipment type (k) during the year if the equipment is used in the natural gas production and processing. 

Qi is the total quantity of natural gas (i) that passes through the natural gas production and processing measured in tonnes. 

EF(l) ij is 1.2 x 10-3, which is the emission factor for methane (j) from general leaks in the natural gas production and processing, measured in CO2-e tonnes per tonne of natural gas that passes through the natural gas production and processing. 

(2) For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor for methane (j) for an equipment type (k) specified in column 2 of that item: 

Item 

Equipment type (k) 

Emission factor for methane (j)  

(tonnes CO2-e/tonnes fuel throughput) 

1 

Internal floating tank 

1.0  107 

2 

Fixed roof tank 

5.0  106 

3 

Floating tank 

3.8  106 

(3) For EF(l) ij in subsection (1), general leaks in the natural gas production and processing comprise the emissions (other than vent emissions) from equipment listed in sections 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing. 

3.73  Method 2—natural gas production and processing (other than venting and flaring) 

Method 2 for fugitive emissions from natural gas production and processing requires the use of equipment-specific emission factors and more detail on the types of equipment used at the facility. The Method is intended to be as specified in the 

American Petroleum Institute’s Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Natural Gas Industry 2009 sections 5 and 

6.1.2.    

  (1) Method 2 is: 

E = ij k (Q   EF ) ik  ijk  

where: 

Eij is the fugitive emissions of methane (j) from the natural gas production and processing during the year measured in CO2-e tonnes. 

Σk is the emissions of methane (j) measured in CO2-e tonnes and estimated by summing up the emissions released from each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing. 

Qik is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing. 

EFijk is the emission factor of methane (j) measured in tonnes of CO2-e per tonne of natural gas that passes through each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing. 

  (2) For EFijk, the emission factors for methane (j) as the natural gas passes through the equipment types (k) are: 

(a) as listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, for the equipment type; or 

(b) if the manufacturer of the equipment supplies equipment-specific emission factors for the equipment type—those factors. 

Division 3.3.7—Natural gas transmission 

Emissions may occur as a result of compressor blow downs for maintenance at compressor stations, maintenance on pipelines, leakage and accidents. 

Transmission mains are defined as high-pressure pipelines greater than 1050 kilopascals, as used in the Energy Supply Association of Australia natural gas statistics.  

Note that in this part the definition of natural gas is as follows: 

natural gas includes coal seam methane that is captured for combustion where the production of coal is not intended to occur 

3.74  Application 

  This Division applies to fugitive emissions from natural gas transmission 

activities. 

3.75  Available methods 

(1) Subject to section 1.18 and subsection (2), one of the following methods must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, released from the operation of a facility that is constituted by natural gas transmission through a system of pipelines during a year: 

  (a) method 1 under section 3.76;  (b) method 2 under section 3.77. 

Note: There is no method 3 or 4 for this Division. 

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

Summary of available methods, for estimating emissions from natural gas transmission, by emissions of gas type (j) 

CO2 

CH4 

N2O 

Method 1 

Section 3.76 

Section 3.76 

NO 

Method 2 

Section 3.77 

Section 3.77 

NO 

Method 3 

NO 

NA 

NO 

Method 4 

NO 

NA 

NO 

NA = Not available.  NO = Not occurring 

3.76  Method 1—natural gas transmission   Method 1 is: 

E = Q  EFij i  ij 

where: 

Eij is the fugitive emissions of gas type (j) from natural gas transmission through a system of pipelines of length (i) during the year measured in CO2-e tonnes. 

Qi is the length of the system of pipelines (i) measured in kilometres. 

EFij is the emission factor for gas type (j), which is 0.02 for carbon dioxide and 10.4 for methane, measured in tonnes of CO2-e emissions per kilometre of pipeline (i). 

Example 

A company has a network of natural gas transmission pipelines with a total length of 3600 km, over a year. The Reporter elects to use Method 1 to calculate fugitive emissions from natural gas transmission, for carbon dioxide and methane. Emissions are estimated as follows: 

Eij = Qi  EFij 

where: 

Eij is the emissions measured in CO2 e tonnes of gas type (j), being either carbon dioxide or methane, released from natural gas transmission through a system of pipelines of length (i) during the year measured in CO2-e tonnes. 

Qi is the length of the system of pipelines (i) measured in kilometres. In this case pipeline length is 3600 km. 

EFij is the emission factor for gas type (j) being 0.02 for carbon dioxide and 8.7 for methane measured in tonnes of CO2 e emissions per kilometre of pipeline (i). 

Therefore, to estimate greenhouse gas emissions (from carbon dioxide and methane) in CO2-e tonnes: 

For carbon dioxide 

=3600 x 0.02 

Total emissions of carbon dioxide  = 72 t CO2-e 

For methane 

=3600 x 10.4 

Total emissions of methane  = 37,440  t CO2-e 

3.77  Method 2—natural gas transmission 

Method 2 for fugitive emissions from natural gas transmission requires the use of equipment-specific emission factors and more detail on the types of equipment used at the facility. The Method is intended to be as specified in the American Petroleum Institute’s Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Natural Gas Industry 2009 sections 5 and 6.1.2.   The option is also provided to refine the emission factors from information on the composition of the gases, using the engineering calculations and from information on the leakage rates for specific pipeline materials for the industry.  

  (1) Method 2 is: 

E = j k (Qk  EF ) jk  

where: 

Ej is the fugitive emissions of gas type (j) measured in CO2-e tonnes from the natural gas transmission through the system of pipelines during the year. 

Σk is the total of emissions of gas type (j) measured in CO2-e tonnes and estimated by summing up the emissions released from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas transmission. 

Qk is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) or the number of equipment units of type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas transmission. 

EFjk is the emission factor of gas type (j) measured in CO2-e tonnes for each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, where the equipment is used in the natural gas transmission. 

  (2) For EFjk, the emission factors for a gas type (j) as the natural gas passes through the equipment type (k) are: 

(a) as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or 

(b) as listed in that Compendium for the equipment type with emission factors adjusted for variations in estimated gas composition, in accordance with that Compendium’s sections 5 and 6.1.2, and the requirements of Division 2.3.3; or 

(c) as listed in that Compendium for the equipment type with emission factors adjusted for variations in the type of equipment material estimated in accordance with the results of published research for the crude oil industry and the principles of section 1.13; or 

(d) if the manufacturer of the equipment supplies equipment-specific emission factors for the equipment type—those factors; or 

(e) estimated using the engineering calculation approach in accordance with sections 5 and 6.1.2 of the API Compendium. 

Note: The API Compendium is available at www.api.org. 

Division 3.3.8—Natural gas distribution 

Emissions arise for this category from fugitive sources (for example gas leaks, accidental releases).  The boundary between natural gas transmission and distribution is generally taken to be the city gate regulator stations at which gas pressures are reduced from transmission pressures to sub-transmission pressures. For the purposes of this methodology, natural gas distribution comprises low, medium and high-pressure reticulation ≤ 1050 kilopascals. 

Other sources of emissions arising from the natural gas distribution, such as from the combustion of fuels for energy, are not described in this chapter and must be estimated using the Methods described in other chapters.   

Note that in this part the definition of natural gas is as follows: 

natural gas includes coal seam methane that is captured for combustion where the production of coal is not intended to occur 

3.78  Application 

  This Division applies to fugitive emissions from natural gas distribution activities. 

3.79  Available methods 

(1) Subject to section 1.18 and subsection (2), one of the following methods must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, released during a year from the operation of a facility that is constituted by natural gas distribution through a system of pipelines: 

  (a) method 1 under section 3.80;  (b) method 2 under section 3.81. 

Note: There is no method 3 or 4 for this Division. 

(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

Summary of available methods, for estimating emissions from natural gas distribution, by emissions of gas type (j) 

CO2 

CH4 

N2O 

Method 1 

Section 3.80 

Section 3.80 

NO 

Method 2 

Section 3.81 

Section 3.81 

NO 

Method 3 

NA 

NA 

NO 

Method 4 

NA 

NA 

NO 

NA = Not available.  NO = Not occurring 

3.80  Method 1—natural gas distribution 

Method 1 for fugitive emissions from natural gas distribution is derived from the National Greenhouse Accounts. 

  (1) Method 1 is: 

    E jp  S p  %UAG p  0.55  Cjp 

where: 

Ejp is the fugitive emissions of gas type (j) that result from natural gas distribution through a system of pipelines with sales of gas in a State or Territory (p) during the year, measured in CO2-e tonnes. 

Sp is the total sales during the year from the pipeline system in a State or Territory (p), measured in terajoules. 

%UAGp is the percentage of unaccounted for gas in the pipeline system in a State or Territory, relative to the amount of gas issued annually by gas utilities in that State or Territory. 

Note: The value 0.55 following the variable %UAGp in method 1 represents the proportion of gas that is unaccounted for and released as emissions. 

Cjp is the natural gas composition factor for gas type (j) for the natural gas supplied from the pipeline system in a State or Territory (p), measured in CO2-e tonnes per terajoule. 

(2) For %UAGp in subsection (1), column 3 of an item in the following table specifies the percentage of unaccounted for gas in the pipeline system in a State or Territory specified in column 2 of that item. 

(3) For Cjp in subsection (1), columns 4 and 5 of an item in the following table specify the natural gas composition factor for carbon dioxide and methane for a pipeline system in a State or Territory specified in column 2. 

Item 

State 

Unaccounted for gas (a)% 

Natural gas composition factor (a)(tonnes CO2-e/TJ) 

UAGp 

CO2 

CH4 

1 

NSW and ACT 

2.2 

0.8 

390 

2 

VIC 

3.0 

0.9 

388 

3 

QLD 

1.7 

0.8 

377 

4 

WA 

2.9 

1.1 

364 

5 

SA 

4.9 

0.8 

390 

6 

TAS 

0.2 

0.9 

388 

7 

NT 

2.2 

0.0 

314 

3.81  Method 2—natural gas distribution 

Method 2 for fugitive emissions from natural gas distribution requires the use of equipment-specific emission factors and more detail on the types of equipment used at the facility. The Method is intended to be as specified in the American Petroleum Institute’s Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Natural Gas Industry 2009 sections 5 and 6.1.2.   The option is also provided to refine the emission factors from information on the composition of the gases and from information on the leakage rates for specific pipeline materials for the industry. 

  (1) Method 2 is: 

E = j k (Qk  EF )jk  

where: 

Ej is the fugitive emissions of gas type (j) that result from the natural gas distribution during the year measured in CO2-e tonnes. 

Σk is the total of emissions of gas type (j) measured in CO2-e tonnes and estimated by summing up the emissions from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas distribution. 

Qk is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) or the number of equipment units of type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas distribution. 

EFjk is the emission factor for gas type (j) measured in CO2-e tonnes for each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas distribution. 

(2) For EFjk, the emission factors for gas type (j) as the natural gas passes through the equipment type (k) are: 

(a) as listed in sections 5 and 6.1.2 of the API Compendium; or 

(b) as listed in that Compendium for the equipment type with emission factors adjusted for variations in estimated gas composition, in accordance with that Compendium’s Sections 5 and 6.1.2, and the requirements of Division 2.3.3; or 

(c) as listed in that Compendium for the equipment type with emission factors adjusted for variations in the type of equipment material using adjusted factors; or 

(d) if the manufacturer of the equipment supplies equipment-specific emission factors for the equipment type—those factors. 

(3) In paragraph 3.81(2)(c), a reference to factors adjusted is a reference to the factors in Table 5-3 of the publication entitled Greenhouse Gas Emission Estimation Methodologies, Procedures and Guidelines for the Natural Gas Distribution Sector, American Gas Association, April 2008, that are adjusted for variations in estimated gas composition in accordance with: 

 (a) section 5.2.1 of that publication; and  (b) Division 2.3.3. 

Note that 3.81 (2) (c) allows adjustment of emission factors for variations in the type of material from which the equipment is made. This adjustment is made using Table 

5-3 and section 5.2.1 of the publication entitled Greenhouse Gas Emission 

Estimation Methodologies, Procedures and Guidelines for the Natural Gas Distribution Sector, American Gas Association, April 2008. Table 5-3 includes the emission factors for equipment made from different materials, for example, cast iron pipelines or plastic pipelines. Section 5.2.1 provides a description of how to apply the information in Table 5-3. 

The publication entitled Greenhouse Gas Emission Estimation Methodologies, Procedures and Guidelines for the Natural Gas Distribution Sector, American Gas Association, April 2008, is available from: 

http://www.aga.org/legislative/legislative+advocacy/environmentalinforma... nviro/2008/aga+greenhouse+gas+emission+estimation+guidelines+for+the+natural+ gas+distribution+sector.htm 

Fugitive emissions

Division 3.3.9—Natural gas production or processing (emissions that are vented or flared) 

3.82  Application 

  This Division applies to fugitive emissions from venting or flaring from 

natural gas production or processing activities, including emissions from: 

(a) the venting of natural gas; and 

(b) the venting of waste gas and vapour streams at facilities that are constituted by natural gas production or processing; and 

(c) the flaring of natural gas, waste gas and waste vapour streams at 

those facilities. 

Note that in this part the definition of natural gas is as follows: 

natural gas includes coal seam methane that is captured for combustion where the production of coal is not intended to occur 

3.83  Available methods 

(1) Subject to section 1.18, for estimating emissions (emissions that are vented or flared) released during a year from the operation of a facility that is constituted by natural gas production and processing the methods as set out in this section must be used. 

(2) One of the following methods must be used for estimating fugitive emissions that result from deliberate releases from process vents, system upsets and accidents: 

  (i) method 1 under section 3.84; and  (ii) method 4 under Part 1.3. 

Note: There is no method 2 or 3 for subsection (2). 

(3) For estimating emissions released from gas flared from natural gas production and processing: 

(a) one of the following methods must be used for estimating emissions of carbon dioxide released: 

(i) method 1 under section 3.85; 

(ii) method 2 under section 3.86; 

(iii) method 3 under section 3.87; and 

(b) if estimating emissions of methane released—one of the following methods must be used: 

(i) method 1 under section 3.85; 

(ii) method 2A under section 3.86A; and 

(c) if estimating emissions of nitrous oxide released—one of the following methods must be used: 

(i) method 1 under section 3.85; 

(ii) method 2A under section 3.86A. 

Note: The flaring of gas from natural gas production and processing releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 in section 3.85 is a reference to these gases. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide and no method 2, 3 or 4 for emissions of nitrous oxide or methane. 

(4) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13. 

Summary of available methods, for estimating emissions from natural gas production and processing (emissions that are vented or flared), by emissions of gas type (j) 

CO2 

CH4 

N2O 

Deliberate releases from process vents, system upsets and accidents 

Method 1 

Section 3.84 

Section 3.84 

NO 

Method 2 

NA 

NA 

NO 

Method 3 

NA 

NA 

NO 

Method 4 

Method 4 under 

Part 1.3 

Method 4 under 

Part 1.3 

NO 

Flaring 

Method 1 

Section 3.85 

Section 3.85 

Section 3.85 

Method 2 

Section 3.86 

NA 

NA 

Method 3 

Section 3.87 

NA 

NA 

NA = Not available.  NO = Not occurring 

Subdivision 3.3.9.1—Fugitive emissions that result from deliberate 

releases from process vents, system upsets and accidents  

Venting refers to emissions that are the result of processes or equipment design or operational practices. Venting at oil or gas processing facilities is mainly associated with the release of CO2, which is extracted from the raw gas stream in the course of gas processing. Because separation of the other components of the gas stream from the CO2 is incomplete, the vented CO2 contains small quantities of methane.  

3.84  Method 1—emissions from system upsets, accidents and deliberate releases from process vents 

  Method 1 is, for a process mentioned in column 2 of an item in the following table, as described in the section of the API Compendium mentioned in column 3 for the item. 

Item 

Emission process 

API 

Compendium 

section 

1 

Gas treatment processes 

Section 5.1 

2 

Cold process vents 

Section 5.3 

3 

Natural gas blanketed tank emissions 

Section 5.4.4 

4 

Other venting sources—gas driven pneumatic devices 

Section 5.6.1 

5 

Other venting sources—gas driven chemical injection pumps 

Section 5.6.2 

6 

Other venting sources—coal seam exploratory drilling, well testing and mud degassing 

Section 5.6.3 and 5.6.6 

7 

Non-routine activities—production related non-routine emissions 

Section 5.7.1 or 

5.7.2 

8 

Non-routine activities—gas processing related non-routine emissions 

Section 5.7.1 or 

5.7.3 

Subdivision 3.3.9.2—Emissions released from gas flared from natural gas production and processing 

Flaring refers to the controlled release to combustion of a mixed flammable gas stream. At gas processing plants, flared gas may arise from natural gas processing. Where there is no market for gas separated from the wellhead production stream, the gas is reinjected or flared. 

This subsector does not include flaring from petroleum refining activities, which should be reported separately under 1.B.2a.iv Crude Oil refining and storage. 

Method 1 is derived from the methods used for the National Greenhouse Accounts.  Methods 2 and 3 for carbon dioxide rely on the sampling and analysis of the fuel to estimate the composition of the gases in the fuel in accordance with the provisions of chapter 2. 

3.85  Method 1—gas flared from natural gas production and processing 

(1) Method 1 is: 

E = Qij i  EFij 

where: 

Eij is the emissions of gas type (j) measured in CO2-e tonnes that result from a fuel type (i) flared in the natural gas production and processing during the year. 

Qi is the quantity measured in tonnes of gas flared during the year. 

EFij is the emission factor for gas type (j) measured in CO2-e tonnes of emissions per tonne of gas flared (i) in the natural gas production and processing during the year. 

(2) For EFij mentioned in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor for fuel type (i) specified in column 2 of that item. 

Item 

fuel type (i) 

Emission factor of gas type (j) (ton CO2-e/tonnes fuel flared) 

CO2 CH4 

nes 

N2O 

1 

gas  

2.7 0.1 

0.03 

3.86  Method 2—gas flared from natural gas production and processing 

  For subparagraph 3.83(3)(a)(ii), method 2 is: Eico2 = Qh × EFhi × OF + QCOi

2 

where: 

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in the natural gas production and processing during the year, measured in CO2-e tonnes. 

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in the natural gas production and processing during the year, measured in tonnes in accordance with Division 2.3.3. 

EFhi is the carbon dioxide emission factor for the total hydrocarbons (h) within the fuel type (i) in the natural gas production and processing during the year, measured in CO2-e tonnes per tonne of fuel type (i) flared, estimated in accordance with Division 2.3.3. 

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared. 

QCO2 is the quantity of CO2 within the fuel type (i) in the natural gas production and processing during the year, measured in CO2-e tonnes in accordance with Division 2.3.3. 

3.86A  Method 2A—natural gas production and processing (flared methane or nitrous oxide emissions) 

  For subparagraphs 3.83(3)(b)(ii) and (c)(ii), method 2A is: 

Eij = Qh × EFhij × OFi where: 

EFhij is the emission factor of gas type (j), being methane or nitrous oxide, for the total hydrocarbons (h) within the fuel type (i) in natural gas production and processing during the year, mentioned for the fuel type in the table in subsection 3.85(2) and measured in CO2-e tonnes per tonne of the fuel type (i) flared. 

Eij is the fugitive emissions of gas type (j), being methane or nitrous oxide, from fuel type (i) flared from natural gas production and processing during the year, measured in CO2-e tonnes. 

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared. 

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in natural gas production and processing during the year, measured in tonnes in accordance with Division 2.3.3. 

3.87  Method 3—gas flared from natural gas production and processing 

  For subparagraph 3.83(3)(a)(iii), method 3 is the same as method 2 under section 3.86, but the emission factor (EFij) must be determined in accordance with method 3 for the consumption of gaseous fuels as specified in Division 2.3.4. 

Estimating Carbon dioxide emissions from natural gas production and processing flaring using Method 2 

Natural gas production and processing generally involves some flaring of a waste gas stream. In this example a facility flares a waste gas stream of 1,000 tonnes during the 

year, which contains a relatively high content of carbon dioxide in addition to some hydrogen sulphide and hydrocarbons. The reporters have chosen to use method 2 as this approach provides the opportunity to develop a carbon dioxide emission factor that better reflects the hydrocarbons present in the gas stream, as well as account for the in-situ carbon dioxide quantity which is emitted, but not combusted in the flare. 

Calculate the carbon dioxide emissions using Method 2 in section 3.86 of NGER 

(Measurement) Determination 

Eico2 = (Qh × EFh × OFi ) + QCO2 

  Where: 

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in natural gas production and processing during the year, measured in CO2-e tonnes. 

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in natural gas production and processing during the year, measured in tonnes in accordance with Division 2.3.3. 

QCO2 is the quantity of CO2 within the fuel type (i) in natural gas production and processing during the year, measured in CO2-e tonnes in accordance with Division 2.3.3. 

In this example it was determined (in accordance with Division 2.3.3) that the average composition of the waste gas stream being flared during the year is as follows: 

  Hydrocarbons C1 to C5 = 0.78 tonnes/ tonne of waste gas stream 

  Hydrogen sulphide  = 0.0.04 tonnes/ tonne of waste gas stream 

Nitrogen = 0.08 tonnes/ tonne of waste gas stream 

Carbon dioxide  = 0.10 tonnes/ tonne of waste gas stream 

Therefore: 

Fugitive emissions

  Qh  = 0.78  x 1000 t of waste gas stream flared during the year 

Qh  = 780 tonnes   

QCO2 = 0.10  x 1000 t of waste gas stream flared during the year 

QCO2 = 100 tonnes 

  EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in natural gas production and processing during the year, measured in CO2-e tonnes per tonne of fuel type (i) flared, estimated in accordance with method 2 in Division 2.3.3. 

In this example it was determined (in accordance with Division 2.3.3) that the emission factor derived from the average hydrocarbon composition of the waste gas stream being flared during the year was: 

 2.2 tonnes of CO2 per tonne of waste gas stream flared 

Therefore:  

EFh = 2.2 

  OFi is 0.98, which is the correction factor for the oxidation of fuel type (i) flared. 

To calculate the CO2 emissions from waste gas flared: 

  = (780 x 2.2 x 0.98) + 100 = 1,781.7 

Therefore, the total emissions from the source = 1,782 tonnes 

Part 3.4—Carbon capture and storage—fugitive emissions