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Determinations/Other as amended, taking into account amendments up to National Greenhouse and Energy Reporting (Measurement) Amendment (2021 Update) Determination 2021
Administered by: Industry, Science, Energy and Resources
Registered 29 Jul 2021
Start Date 01 Jul 2021

Commonwealth Coat of Arms of Australia

National Greenhouse and Energy Reporting (Measurement) Determination 2008

made under subsection 10(3) of the

National Greenhouse and Energy Reporting Act 2007

Compilation No. 13

Compilation date:                              1 July 2021

Includes amendments up to:            F2021L00771

                                   

 

About this compilation

This compilation

This is a compilation of the National Greenhouse and Energy Reporting (Measurement) Determination 2008 that shows the text of the law as amended and in force on 1 July 2021 (the compilation date).

The notes at the end of this compilation (the endnotes) include information about amending laws and the amendment history of provisions of the compiled law.

Uncommenced amendments

The effect of uncommenced amendments is not shown in the text of the compiled law. Any uncommenced amendments affecting the law are accessible on the Legislation Register (www.legislation.gov.au). The details of amendments made up to, but not commenced at, the compilation date are underlined in the endnotes. For more information on any uncommenced amendments, see the series page on the Legislation Register for the compiled law.

Application, saving and transitional provisions for provisions and amendments

If the operation of a provision or amendment of the compiled law is affected by an application, saving or transitional provision that is not included in this compilation, details are included in the endnotes.

Modifications

If the compiled law is modified by another law, the compiled law operates as modified but the modification does not amend the text of the law. Accordingly, this compilation does not show the text of the compiled law as modified. For more information on any modifications, see the series page on the Legislation Register for the compiled law.

Self‑repealing provisions

If a provision of the compiled law has been repealed in accordance with a provision of the law, details are included in the endnotes.

  

  

  


Contents

Chapter 1—General                                                                           1

Part 1.1—Preliminary                                                                                                  1

1.1  Name of Determination......................................................................................................... 1

Division 1.1.1—Overview                                                                                       1

1.3  Overview—general............................................................................................................... 1

1.4  Overview—methods for measurement.................................................................................. 2

1.5  Overview—energy................................................................................................................ 2

1.6  Overview—scope 2 emissions.............................................................................................. 2

1.7  Overview—assessment of uncertainty.................................................................................. 2

Division 1.1.2—Definitions and interpretation                                                       3

1.8  Definitions...... ...................................................................................................................... 3

1.9  Interpretation.. .................................................................................................................... 18

1.9A  Meaning of separate instance of a source........................................................................ 18

1.9B  Meaning of separate occurrence of a source................................................................... 18

1.10  Meaning of source............................................................................................................ 19

Part 1.2—General                                                                                                       22

1.11  Purpose of Part.................................................................................................................. 22

Division 1.2.1—Measurement and standards                                                       22

1.12  Measurement of emissions and energy.............................................................................. 22

1.13  General principles for measuring emissions and energy.................................................... 22

1.14  Assessment of uncertainty................................................................................................. 22

1.15  Units of measurement........................................................................................................ 23

1.16  Rounding of amounts........................................................................................................ 23

1.17  Status of standards............................................................................................................ 23

Division 1.2.2—Methods                                                                                       24

1.18  Method to be used for a separate occurrence of a source................................................... 24

1.18A  Conditions—persons preparing report must use same method....................................... 25

1.19  Temporary unavailability of method.................................................................................. 26

Division 1.2.3—Requirements in relation to carbon capture and storage          27

1.19A  Meaning of captured for permanent storage................................................................. 27

1.19B  Deducting greenhouse gas that is captured for permanent storage.................................. 27

1.19C  Capture from facility with multiple sources jointly generated......................................... 28

1.19D  Capture from a source where multiple fuels consumed.................................................. 28

1.19E  Measure of quantity of captured greenhouse gas............................................................ 28

1.19F  Volume of greenhouse gas stream—criterion A............................................................. 29

1.19G  Volume of greenhouse gas stream—criterion AAA....................................................... 29

1.19GA  Volume of greenhouse gas stream—criterion BBB..................................................... 30

1.19H  Volumetric measurement—compressed greenhouse gas stream..................................... 30

1.19I  Volumetric measurement—super‑compressed greenhouse gas stream............................ 31

1.19J  Gas measuring equipment—requirements....................................................................... 32

1.19K  Flow devices—requirements.......................................................................................... 32

1.19L  Flow computers—requirements...................................................................................... 33

1.19M  Gas chromatographs...................................................................................................... 33

Part 1.3—Method 4—Direct measurement of emissions                                         34

Division 1.3.1—Preliminary                                                                                  34

1.20  Overview...... .................................................................................................................... 34

Division 1.3.2—Operation of method 4 (CEM)                                                    35

Subdivision 1.3.2.1—Method 4 (CEM)                                                                                         35

1.21  Method 4 (CEM)—estimation of emissions...................................................................... 35

1.21A  Emissions from a source where multiple fuels consumed.............................................. 36

Subdivision 1.3.2.2—Method 4 (CEM)—use of equipment                                                     36

1.22  Overview...... .................................................................................................................... 36

1.23  Selection of sampling positions for CEM equipment........................................................ 36

1.24  Measurement of flow rates by CEM................................................................................. 36

1.25  Measurement of gas concentrations by CEM.................................................................... 37

1.26  Frequency of measurement by CEM................................................................................. 37

Division 1.3.3—Operation of method 4 (PEM)                                                    38

Subdivision 1.3.3.1—Method 4 (PEM)                                                                                          38

1.27  Method 4 (PEM)—estimation of emissions...................................................................... 38

1.27A  Emissions from a source where multiple fuels consumed.............................................. 38

1.28  Calculation of emission factors.......................................................................................... 38

Subdivision 1.3.3.2—Method 4 (PEM)—use of equipment                                                      39

1.29  Overview...... .................................................................................................................... 39

1.30  Selection of sampling positions for PEM equipment......................................................... 39

1.31  Measurement of flow rates by PEM equipment................................................................ 39

1.32  Measurement of gas concentrations by PEM.................................................................... 40

1.33  Representative data for PEM............................................................................................. 40

Division 1.3.4—Performance characteristics of equipment                                 41

1.34  Performance characteristics of CEM or PEM equipment.................................................. 41

Chapter 2—Fuel combustion                                                           42

Part 2.1—Preliminary                                                                                                42

2.1  Outline of Chapter............................................................................................................... 42

Part 2.2—Emissions released from the combustion of solid fuels                           43

Division 2.2.1—Preliminary                                                                                  43

2.2  Application..... .................................................................................................................... 43

2.3  Available methods for estimating emissions of carbon dioxide, methane and nitrous oxide 43

Division 2.2.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide from solid fuels                                                                                                           44

2.4  Method 1—solid fuels......................................................................................................... 44

Division 2.2.3—Method 2—emissions from solid fuels                                         45

Subdivision 2.2.3.1—Method 2—estimating carbon dioxide using default oxidation factor     45

2.5  Method 2—estimating carbon dioxide using oxidation factor............................................. 45

Subdivision 2.2.3.2—Method 2—estimating carbon dioxide using an estimated oxidation factor           46

2.6  Method 2—estimating carbon dioxide using an estimated oxidation factor......................... 46

Subdivision 2.2.3.3—Sampling and analysis for method 2 under sections 2.5 and 2.6    48

2.7  General requirements for sampling solid fuels.................................................................... 48

2.8  General requirements for analysis of solid fuels.................................................................. 48

2.9  Requirements for analysis of furnace ash and fly ash.......................................................... 49

2.10  Requirements for sampling for carbon in furnace ash....................................................... 49

2.11  Sampling for carbon in fly ash.......................................................................................... 49

Division 2.2.4—Method 3—Solid fuels                                                                 51

2.12  Method 3—solid fuels using oxidation factor or an estimated oxidation factor................. 51

Division 2.2.5—Measurement of consumption of solid fuels                                53

2.13  Purpose of Division.......................................................................................................... 53

2.14  Criteria for measurement................................................................................................... 53

2.15  Indirect measurement at point of consumption—criterion AA.......................................... 53

2.16  Direct measurement at point of consumption—criterion AAA.......................................... 56

2.17  Simplified consumption measurements—criterion BBB................................................... 56

Part 2.3—Emissions released from the combustion of gaseous fuels                     57

Division 2.3.1—Preliminary                                                                                  57

2.18  Application... .................................................................................................................... 57

2.19  Available methods............................................................................................................. 57

Division 2.3.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide  58

2.20  Method 1—emissions of carbon dioxide, methane and nitrous oxide............................... 58

Division 2.3.3—Method 2—emissions of carbon dioxide from the combustion of gaseous fuels          59

Subdivision 2.3.3.1—Method 2—emissions of carbon dioxide from the combustion of gaseous fuels    59

2.21  Method 2—emissions of carbon dioxide from the combustion of gaseous fuels.............. 59

2.22  Calculation of emission factors from combustion of gaseous fuel..................................... 59

Subdivision 2.3.3.2—Sampling and analysis                                                                              61

2.23  General requirements for sampling under method 2.......................................................... 61

2.24  Standards for analysing samples of gaseous fuels............................................................. 62

2.25  Frequency of analysis........................................................................................................ 65

Division 2.3.4—Method 3—emissions of carbon dioxide released from the combustion of gaseous fuels                                                                                                           66

2.26  Method 3—emissions of carbon dioxide from the combustion of gaseous fuels.............. 66

Division 2.3.5—Method 2—emissions of methane from the combustion of gaseous fuels         68

2.27  Method 2—emissions of methane from the combustion of gaseous fuels......................... 68

Division 2.3.6—Measurement of quantity of gaseous fuels                                  69

2.28  Purpose of Division.......................................................................................................... 69

2.29  Criteria for measurement................................................................................................... 69

2.30  Indirect measurement—criterion AA................................................................................. 69

2.31  Direct measurement—criterion AAA................................................................................ 69

2.32  Volumetric measurement—all natural gases...................................................................... 71

2.33  Volumetric measurement—super‑compressed gases......................................................... 72

2.34  Gas measuring equipment—requirements......................................................................... 72

2.35  Flow devices—requirements............................................................................................. 72

2.36  Flow computers—requirements........................................................................................ 73

2.37  Gas chromatographs—requirements................................................................................. 74

2.38  Simplified consumption measurements—criterion BBB................................................... 74

Part 2.4—Emissions released from the combustion of liquid fuels                         75

Division 2.4.1—Preliminary                                                                                  75

2.39  Application... .................................................................................................................... 75

2.39A  Definition of petroleum based oils for Part 2.4.............................................................. 75

Subdivision 2.4.1.1—Liquid fuels—other than petroleum based oils and greases            75

2.40  Available methods............................................................................................................. 75

Subdivision 2.4.1.2—Liquid fuels—petroleum based oils and greases                                76

2.40A  Available methods.......................................................................................................... 76

Division 2.4.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide from liquid fuels other than petroleum based oils or greases                                      77

2.41  Method 1—emissions of carbon dioxide, methane and nitrous oxide............................... 77

Division 2.4.3—Method 2—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases                                                                                          78

Subdivision 2.4.3.1—Method 2—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases                                                                                                                     78

2.42  Method 2—emissions of carbon dioxide from the combustion of liquid fuels.................. 78

2.43  Calculation of emission factors from combustion of liquid fuel........................................ 78

Subdivision 2.4.3.2—Sampling and analysis                                                                              79

2.44  General requirements for sampling under method 2.......................................................... 79

2.45  Standards for analysing samples of liquid fuels................................................................ 79

2.46  Frequency of analysis........................................................................................................ 81

Division 2.4.4—Method 3—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases                                                                                          83

2.47  Method 3—emissions of carbon dioxide from the combustion of liquid fuels.................. 83

Division 2.4.5—Method 2—emissions of methane and nitrous oxide from liquid fuels other than petroleum based oils or greases                                                        86

2.48  Method 2—emissions of methane and nitrous oxide from the combustion of liquid fuels 86

Division 2.4.5A—Methods for estimating emissions of carbon dioxide from petroleum based oils or greases                                                                                               87

2.48A  Method 1—estimating emissions of carbon dioxide using an estimated oxidation factor 87

2.48B  Method 2—estimating emissions of carbon dioxide using an estimated oxidation factor 88

2.48C  Method 3—estimating emissions of carbon dioxide using an estimated oxidation factor 88

Division 2.4.6—Measurement of quantity of liquid fuels                                     89

2.49  Purpose of Division.......................................................................................................... 89

2.50  Criteria for measurement................................................................................................... 89

2.51  Indirect measurement—criterion AA................................................................................. 89

2.52  Direct measurement—criterion AAA................................................................................ 89

2.53  Simplified consumption measurements—criterion BBB................................................... 90

Part 2.5—Emissions released from fuel use by certain industries                          91

2.54  Application... .................................................................................................................... 91

Division 2.5.1—Energy—petroleum refining                                                       92

2.55  Application... .................................................................................................................... 92

2.56  Methods....... .................................................................................................................... 92

Division 2.5.2—Energy—manufacture of solid fuels                                           93

2.57  Application... .................................................................................................................... 93

2.58  Methods....... .................................................................................................................... 93

Division 2.5.3—Energy—petrochemical production                                            97

2.59  Application... .................................................................................................................... 97

2.60  Available methods............................................................................................................. 97

2.61  Method 1—petrochemical production............................................................................... 97

2.62  Method 2—petrochemical production............................................................................... 99

2.63  Method 3—petrochemical production............................................................................... 99

Part 2.6—Blended fuels                                                                                            101

2.64  Purpose........ .................................................................................................................. 101

2.65  Application... .................................................................................................................. 101

2.66  Blended solid fuels.......................................................................................................... 101

2.67  Blended liquid fuels......................................................................................................... 101

Part 2.7—Estimation of energy for certain purposes                                            102

2.68  Amount of energy consumed without combustion.......................................................... 102

2.69  Apportionment of fuel consumed as carbon reductant or feedstock and energy.............. 102

2.70  Amount of energy consumed in a cogeneration process.................................................. 103

2.71  Apportionment of energy consumed for electricity, transport and for stationary energy. 103

Chapter 3—Fugitive emissions                                                       104

Part 3.1—Preliminary                                                                                              104

3.1  Outline of Chapter............................................................................................................. 104

Part 3.2—Coal mining—fugitive emissions                                                            105

Division 3.2.1—Preliminary                                                                                105

3.2  Outline of Part .................................................................................................................. 105

Division 3.2.2—Underground mines                                                                   106

Subdivision 3.2.2.1—Preliminary                                                                                               106

3.3  Application..... .................................................................................................................. 106

3.4  Available methods............................................................................................................. 106

Subdivision 3.2.2.2—Fugitive emissions from extraction of coal                                       107

3.5  Method 1—extraction of coal............................................................................................ 107

3.6  Method 4—extraction of coal............................................................................................ 107

3.7  Estimation of emissions..................................................................................................... 108

3.8  Overview—use of equipment............................................................................................ 109

3.9  Selection of sampling positions for PEM.......................................................................... 109

3.10  Measurement of volumetric flow rates by PEM.............................................................. 109

3.11  Measurement of concentrations by PEM......................................................................... 109

3.12  Representative data for PEM........................................................................................... 110

3.13  Performance characteristics of equipment........................................................................ 110

Subdivision 3.2.2.3—Emissions released from coal mine waste gas flared                     110

3.14  Method 1—coal mine waste gas flared............................................................................ 110

3.15  Method 2—emissions of carbon dioxide from coal mine waste gas flared...................... 110

3.15A  Method 2—emissions of methane and nitrous oxide from coal mine waste gas flared. 111

3.16  Method 3—coal mine waste gas flared............................................................................ 111

Subdivision 3.2.2.4—Fugitive emissions from post‑mining activities                                112

3.17  Method 1—post‑mining activities related to gassy mines................................................ 112

Division 3.2.3—Open cut mines                                                                          113

Subdivision 3.2.3.1—Preliminary                                                                                               113

3.18  Application... .................................................................................................................. 113

3.19  Available methods........................................................................................................... 113

Subdivision 3.2.3.2—Fugitive emissions from extraction of coal                                       114

3.20  Method 1—extraction of coal.......................................................................................... 114

3.21  Method 2—extraction of coal.......................................................................................... 114

3.22  Total gas contained by gas bearing strata......................................................................... 115

3.23  Estimate of proportion of gas content released below pit floor........................................ 116

3.24  General requirements for sampling.................................................................................. 117

3.25  General requirements for analysis of gas and gas bearing strata...................................... 117

3.25A  Method of working out base of the low gas zone......................................................... 117

3.25B  Further requirements for estimator................................................................................ 118

3.25C  Default gas content for gas bearing strata in low gas zone............................................ 119

3.25D  Requirements for estimating total gas contained in gas bearing strata........................... 119

3.26  Method 3—extraction of coal.......................................................................................... 119

Subdivision 3.2.3.3—Emissions released from coal mine waste gas flared                     120

3.27  Method 1—coal mine waste gas flared............................................................................ 120

3.28  Method 2—coal mine waste gas flared............................................................................ 120

3.29  Method 3—coal mine waste gas flared............................................................................ 120

Division 3.2.4—Decommissioned underground mines                                        121

Subdivision 3.2.4.1—Preliminary                                                                                               121

3.30  Application... .................................................................................................................. 121

3.31  Available methods........................................................................................................... 121

Subdivision 3.2.4.2—Fugitive emissions from decommissioned underground mines   122

3.32  Method 1—decommissioned underground mines........................................................... 122

3.33  Emission factor for decommissioned underground mines............................................... 122

3.34  Measurement of proportion of mine that is flooded......................................................... 123

3.35  Water flow into mine....................................................................................................... 123

3.36  Size of mine void volume................................................................................................ 123

3.37  Method 4—decommissioned underground mines........................................................... 124

Subdivision 3.2.4.3—Fugitive emissions from coal mine waste gas flared                      124

3.38  Method 1—coal mine waste gas flared............................................................................ 124

3.39  Method 2—coal mine waste gas flared............................................................................ 124

3.40  Method 3—coal mine waste gas flared............................................................................ 124

Part 3.3—Oil and natural gas—fugitive emissions                                                 125

Division 3.3.1—Preliminary                                                                                125

3.41  Outline of Part................................................................................................................. 125

3.41A  Interpretation................................................................................................................ 126

Division 3.3.2—Oil or gas exploration and development                                   127

Subdivision 3.3.2.1—Preliminary                                                                                               127

3.42  Application... .................................................................................................................. 127

Subdivision 3.3.2.2—Oil or gas exploration and development (emissions that are flared) 127

3.43  Available methods........................................................................................................... 127

3.44  Method 1—oil or gas exploration and development........................................................ 127

3.45  Method 2—oil or gas exploration and development (flared carbon dioxide emissions).. 128

3.45A  Method 2A—oil or gas exploration and development (flared methane or nitrous oxide emissions)            129

3.46  Method 3—oil or gas exploration and development........................................................ 129

Subdivision 3.3.2.3—Oil or gas exploration and development—fugitive emissions from system upsets, accidents and deliberate releases                                                                                             129

3.46A  Available methods........................................................................................................ 129

Subdivision 3.3.2.3.1—Fugitive emissions that result from deliberate releases from process vents, system upsets and accidents–well completions                                                                             130

3.46AB  Method 1—vented emissions from natural gas well completions.............................. 130

3.46B  Method 4—vented emissions from natural gas well completions, well workovers, cold process vents and well blowouts.................................................................................................................. 131

Division 3.3.3—Crude oil production                                                                 132

Subdivision 3.3.3.1—Preliminary                                                                                               132

3.47  Application... .................................................................................................................. 132

Subdivision 3.3.3.2—Crude oil production (non‑flared)—fugitive leak emissions of methane 132

3.48  Available methods........................................................................................................... 132

3.49  Method 1—crude oil production (non‑flared) emissions of methane.............................. 133

3.50  Method 2—crude oil production (non‑flared) emissions of methane.............................. 133

Subdivision 3.3.3.3—Crude oil production (flared)—fugitive emissions of carbon dioxide, methane and nitrous oxide                                                                                                                      136

3.52  Available methods........................................................................................................... 136

3.53  Method 1—crude oil production (flared) emissions........................................................ 136

3.54  Method 2—crude oil production..................................................................................... 137

3.54A  Method 2A—crude oil production (flared methane or nitrous oxide emissions).......... 137

3.55  Method 3—crude oil production..................................................................................... 138

Subdivision 3.3.3.4—Crude oil production (non‑flared)—fugitive vent emissions of methane and carbon dioxide                                                                                                                                138

3.56A  Available methods........................................................................................................ 138

3.56B  Method 1—emissions from system upsets, accidents and deliberate releases from process vents               139

Division 3.3.4—Crude oil transport                                                                   140

3.57  Application... 140

3.58  Available methods........................................................................................................... 140

3.59  Method 1—crude oil transport........................................................................................ 140

3.60  Method 2—fugitive emissions from crude oil transport.................................................. 140

Division 3.3.5—Crude oil refining                                                                      142

3.62  Application... .................................................................................................................. 142

3.63  Available methods........................................................................................................... 142

Subdivision 3.3.5.1—Fugitive emissions from crude oil refining and from storage tanks for crude oil 143

3.64  Method 1—crude oil refining and storage tanks for crude oil......................................... 143

3.65  Method 2—crude oil refining and storage tanks for crude oil......................................... 143

Subdivision 3.3.5.2—Fugitive emissions from deliberate releases from process vents, system upsets and accidents                                                                                                                                145

3.67  Method 1—fugitive emissions from deliberate releases from process vents, system upsets and accidents    145

3.68  Method 4—deliberate releases from process vents, system upsets and accidents............ 145

Subdivision 3.3.5.3—Fugitive emissions released from gas flared from the oil refinery 145

3.69  Method 1—gas flared from crude oil refining................................................................. 145

3.70  Method 2—gas flared from crude oil refining................................................................. 146

3.70A  Method 2A—crude oil refining (flared methane or nitrous oxide emissions)............... 146

3.71  Method 3—gas flared from crude oil refining................................................................. 147

Division 3.3.6A—Onshore natural gas production (other than emissions that are vented or flared)  148

3.72  Application... .................................................................................................................. 148

Subdivision 3.3.6A.1—Onshore natural gas production, other than emissions that are vented or flared—wellheads                                                                                                                                148

3.73  Available methods........................................................................................................... 148

3.73B  Method 2—onshore natural gas production, other than emissions that are vented or flared—wellheads     149

Division 3.3.6B—Offshore natural gas production (other than emissions that are vented or flared)  154

3.73D  Application .................................................................................................................. 154

Subdivision 3.3.6B.1—Offshore natural gas production, other than emissions that are vented or flared—offshore platforms.................................................................................................................. 154

3.73E  Available methods......................................................................................................... 154

3.73F  Method 1—offshore natural gas production (other than emissions that are vented or flared)      154

3.73G  Method 2—offshore natural gas production (other than venting and flaring)............... 155

Division 3.3.6C—Natural gas gathering and boosting (other than emissions that are vented or flared)                                                                                                         160

3.73I  Application.. 160

3.73J  Available methods......................................................................................................... 160

3.73K  Method 1—natural gas gathering and boosting (other than venting and flaring).......... 160

3.73L  Method 2—natural gas gathering and boosting (other than venting and flaring)........... 163

3.73LA  Method 2—natural gas gathering and boosting, other than emissions that are vented or flared—natural gas gathering and boosting stations....................................................................................... 163

Division 3.3.6D—Produced water from oil and gas exploration and development, crude oil production, natural gas production or natural gas gathering and boosting (other than emissions that are vented or flared)                                                                              170

3.73N  Available methods........................................................................................................ 170

3.73NA  Method 1—produced water (other than emissions that are vented or flared)............. 170

3.73NB  Method 2—produced water (other than emissions that are vented or flared)............. 171

Division 3.3.6E—Natural gas processing (other than emissions that are vented or flared)     173

3.73O  Application 173

3.73P  Available methods......................................................................................................... 173

3.73Q  Method 1—natural gas processing (other than emissions that are vented or flared)..... 173

3.73R  Method 2—natural gas processing (other than venting and flaring)............................. 175

3.73S  Method 3—natural gas processing (other than venting and flaring).............................. 176

Division 3.3.7—Natural gas transmission (other than emissions that are flared) 179

3.74  Application... .................................................................................................................. 179

3.75  Available methods........................................................................................................... 179

3.76  Method 1—natural gas transmission (other than flaring)................................................ 179

3.77  Method 2—natural gas transmission (other than flaring)................................................ 179

Division 3.3.7A—Natural gas storage (other than emissions that are vented or flared)          182

3.78A  Application .................................................................................................................. 182

3.78B  Available methods........................................................................................................ 182

3.78C  Method 1—natural gas storage (other than emissions that are vented or flared)........... 182

3.78D  Method 2—natural gas storage (other than emissions that are vented or flared)........... 183

3.78E  Method 3—natural gas storage (other than emissions that are vented or flared)........... 184

Division 3.3.7B—Natural gas liquefaction, storage and transfer (other than emissions that are vented or flared)                                                                                              187

3.78F  Application. .................................................................................................................. 187

3.78G  Available methods........................................................................................................ 187

3.78H  Method 1—natural gas liquefaction, storage and transfer (other than emissions that are vented or flared)  187

3.78I  Method 2—natural gas liquefaction, storage and transfer (other than emissions that are vented or flared)   188

3.78J  Method 3—natural gas liquefaction, storage and transfer (other than venting and flaring) 189

Division 3.3.8—Natural gas distribution (other than emissions that are flared) 192

3.79  Application... .................................................................................................................. 192

3.80  Available methods........................................................................................................... 192

3.81  Method 1—natural gas distribution................................................................................. 192

3.82  Method 2—natural gas distribution................................................................................. 193

3.82A  Method 3—natural gas distribution.............................................................................. 194

Division 3.3.9A—Natural gas production (emissions that are vented or flared) 196

3.83  Application... .................................................................................................................. 196

Subdivision 3.3.9A.1—Natural gas production—emissions that are vented—gas treatment processes   196

3.84  Available methods........................................................................................................... 196

3.85  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas treatment processes.................................................................................................................. 196

Subdivision 3.3.9A.2—Natural gas production—emissions that are vented—cold process vents             197

3.85A  Available methods........................................................................................................ 197

3.85B  Method 1—emissions from system upsets, accidents and deliberate releases from process vents               197

Subdivision 3.3.9A.3—Natural gas production—emissions that are vented—natural gas blanketed tanks and condensate storage tanks                                                                                  197

3.85C  Available methods........................................................................................................ 197

3.85D  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—natural gas blanketed tanks and condensate storage tanks........................................................... 198

Subdivision 3.3.9A.4—Natural gas production—emissions that are vented—gas driven pneumatic devices        198

3.85E  Available methods......................................................................................................... 198

3.85F  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas driven pneumatic devices...................................................................................................... 198

Subdivision 3.3.9A.5—Natural gas production—emissions that are vented—gas driven chemical injection pumps                                                                                                                                199

3.85G  Available methods........................................................................................................ 199

3.85H  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas driven chemical injection pumps......................................................................................... 199

Subdivision 3.3.9A.6—Natural gas production—emissions that are vented—well blowouts      199

3.85K  Available methods........................................................................................................ 199

3.85L  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—production related non-routine emissions—well blowouts............................................................ 200

Subdivision 3.3.9A.7—Natural gas production—emissions that are vented—CO2 stimulation 200

3.85M  Available methods....................................................................................................... 200

3.85N  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—production related non-routine emissions—CO2 stimulation......................................................... 200

Subdivision 3.3.9A.8—Natural gas production—emissions that are vented—well workovers  201

3.85O  Available methods........................................................................................................ 201

3.85P  Method 1—vented emissions from well workovers..................................................... 201

3.85Q  Method 4—vented emissions from gas well workovers.............................................. 202

Subdivision 3.3.9A.9—Natural gas production—emissions that are vented—vessel blowdowns, compressor starts and compressor blowdowns                                                                             202

3.85R  Available methods........................................................................................................ 202

3.85S  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—production related non-routine emissions—vessel blowdowns, compressor starts and compressor blowdowns         203

Subdivision 3.3.9A.10—Natural gas production (emissions that are flared)                   203

3.86  Method 1—gas flared from natural gas production......................................................... 204

3.87  Method 2—gas flared from natural gas production......................................................... 204

3.87A  Method 2A—natural gas production (flared methane or nitrous oxide emissions)....... 205

3.88  Method 3—gas flared from natural gas production......................................................... 205

Division 3.3.9B—Natural gas gathering and boosting (emissions that are vented or flared)   206

3.88A  Application .................................................................................................................. 206

Subdivision 3.3.9B.1—Natural gas gathering and boosting (emissions that are vented) 206

3.88B  Available methods........................................................................................................ 206

3.88C  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas gathering and boosting emissions.................................................................................... 206

Subdivision 3.3.9B.2—Natural gas gathering and boosting (emissions that are flared) 207

Division 3.3.9C—Natural gas processing (emissions that are vented or flared) 208

3.88E  Application. .................................................................................................................. 208

Subdivision 3.3.9C.1—Natural gas processing (emissions that are vented)                      208

3.88F  Available methods......................................................................................................... 208

3.88G  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas processing   208

Subdivision 3.3.9C.2—Natural gas processing (emissions that are flared)                      208

Division 3.3.9D—Natural gas transmission (emissions that are flared)            210

3.88I  Application.. .................................................................................................................. 210

Division 3.3.9E—Natural gas storage (emissions that are vented or flared)    211

3.88K Application. .................................................................................................................. 211

Subdivision 3.3.9E.1——Natural gas storage (emissions that are vented)                       211

3.88L  Available methods......................................................................................................... 211

3.88M  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas storage related non‑routine emissions............................................................................... 211

Subdivision 3.3.9E.2—Natural gas storage (emissions that are flared)                            212

Division 3.3.9F— Natural gas liquefaction, storage and transfer (emissions that are vented or flared)                                                                                                         213

3.88O  Application .................................................................................................................. 213

Subdivision 3.3.9F.1—Natural gas liquefaction, storage and transfer (emissions that are vented)          213

3.88P  Available methods......................................................................................................... 213

3.88Q  Method 1—emissions from system upsets, accidents and deliberate releases from process vents— natural gas liquefaction, storage and transfer................................................................................... 213

Subdivision 3.3.9F.2—Natural gas liquefaction, storage and transfer (emissions that are flared)           214

Division 3.3.9G—Natural gas distribution (emissions that are flared)              215

3.88S  Application. .................................................................................................................. 215

Part 3.4—Carbon capture and storage and enhanced oil recovery—fugitive emissions            216

Division 3.4.1—Preliminary                                                                                216

3.88  Outline of Part................................................................................................................. 216

Division 3.4.2—Transport of greenhouse gases                                                 217

Subdivision 3.4.2.1—Preliminary                                                                                               217

3.89  Application... .................................................................................................................. 217

3.90  Available methods........................................................................................................... 217

Subdivision 3.4.2.2—Emissions from transport of greenhouse gases involving transfer 218

3.91  Method 1—emissions from transport of greenhouse gases involving transfer................ 218

Subdivision 3.4.2.3—Emissions from transport of greenhouse gases not involving transfer    218

3.92  Method 1—emissions from transport of greenhouse gases not involving transfer.......... 218

Division 3.4.3—Injection of greenhouse gases                                                   220

Subdivision 3.4.3.1—Preliminary                                                                                               220

3.93  Application... .................................................................................................................. 220

3.94  Available methods........................................................................................................... 220

Subdivision 3.4.3.2—Fugitive emissions from deliberate releases from process vents, system upsets and accidents                                                                                                                                220

3.95  Method 2—fugitive emissions from deliberate releases from process vents, system upsets and accidents    220

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)                      221

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)..................................... 221

3.97  Method 3—fugitive emissions from injection of greenhouse gases (other than deliberate releases from process vents, system upsets and accidents)................................................................................. 221

Division 3.4.4—Storage of greenhouse gases                                                     222

Subdivision 3.4.4.1—Preliminary                                                                                               222

3.98  Application... .................................................................................................................. 222

3.99  Available method............................................................................................................. 222

Subdivision 3.4.4.2—Fugitive emissions from the storage of greenhouse gases             222

3.100  Method 2—fugitive emissions from geological formations used for the storage of greenhouse gases         222

Chapter 4—Industrial processes emissions                                    224

Part 4.1—Preliminary                                                                                              224

4.1  Outline of Chapter............................................................................................................. 224

Part 4.2—Industrial processes—mineral products                                                225

Division 4.2.1—Cement clinker production                                                        225

4.2  Application..... .................................................................................................................. 225

4.3  Available methods............................................................................................................. 225

4.4  Method 1—cement clinker production.............................................................................. 225

4.5  Method 2—cement clinker production.............................................................................. 226

4.6  General requirements for sampling cement clinker............................................................ 227

4.7  General requirements for analysing cement clinker........................................................... 227

4.8  Method 3—cement clinker production.............................................................................. 227

4.9  General requirements for sampling carbonates.................................................................. 229

4.10  General requirements for analysing carbonates............................................................... 229

Division 4.2.2—Lime production                                                                        230

4.11  Application... .................................................................................................................. 230

4.12  Available methods........................................................................................................... 230

4.13  Method 1—lime production............................................................................................ 230

4.14  Method 2—lime production............................................................................................ 231

4.15  General requirements for sampling.................................................................................. 231

4.16  General requirements for analysis of lime....................................................................... 232

4.17  Method 3—lime production............................................................................................ 232

4.18  General requirements for sampling.................................................................................. 233

4.19  General requirements for analysis of carbonates............................................................. 234

Division 4.2.3—Use of carbonates for production of a product other than cement clinker, lime or soda ash                                                                                                    235

4.20  Application... .................................................................................................................. 235

4.21  Available methods........................................................................................................... 235

4.22  Method 1—product other than cement clinker, lime or soda ash..................................... 236

4.22A  Method 1A—product other than cement clinker, lime or soda ash for use of carbonates in clay materials  236

4.23  Method 3—product other than cement clinker, lime or soda ash..................................... 237

4.23A  Method 3A—product other than cement clinker, lime or soda ash for use of carbonates in clay materials  238

4.23B  General requirements for sampling clay material.......................................................... 239

4.23C  General requirements for analysing clay material.......................................................... 239

4.24  General requirements for sampling carbonates................................................................ 239

4.25  General requirements for analysis of carbonates............................................................. 240

Division 4.2.4—Soda ash use and production                                                     241

4.26  Application... .................................................................................................................. 241

4.27  Outline of Division.......................................................................................................... 241

Subdivision 4.2.4.1—Soda ash use                                                                                               241

4.28  Available methods........................................................................................................... 241

4.29  Method 1—use of soda ash............................................................................................. 241

Subdivision 4.2.4.2—Soda ash production                                                                                242

4.30  Available methods........................................................................................................... 242

4.31  Method 1—production of soda ash................................................................................. 242

4.32  Method 2—production of soda ash................................................................................. 244

4.33  Method 3—production of soda ash................................................................................. 246

Division 4.2.5—Measurement of quantity of carbonates consumed and products derived from carbonates                                                                                       247

4.34  Purpose of Division........................................................................................................ 247

4.35  Criteria for measurement................................................................................................. 247

4.36  Indirect measurement at point of consumption or production—criterion AA.................. 248

4.37  Direct measurement at point of consumption or production—criterion AAA................. 248

4.38  Acquisition or use or disposal without commercial transaction—criterion BBB............. 249

4.39  Units of measurement...................................................................................................... 249

Part 4.3—Industrial processes—chemical industry                                               250

Division 4.3.1—Ammonia production                                                                 250

4.40  Application... .................................................................................................................. 250

4.41  Available methods........................................................................................................... 250

4.42  Method 1—ammonia production..................................................................................... 250

4.43  Method 2—ammonia production..................................................................................... 251

4.44  Method 3—ammonia production..................................................................................... 252

Division 4.3.2—Nitric acid production                                                               253

4.45  Application... .................................................................................................................. 253

4.46  Available methods........................................................................................................... 253

4.47  Method 1—nitric acid production.................................................................................... 253

4.48  Method 2—nitric acid production.................................................................................... 254

Division 4.3.3—Adipic acid production                                                              255

4.49  Application... .................................................................................................................. 255

4.50  Available methods........................................................................................................... 255

Division 4.3.4—Carbide production                                                                   256

4.51  Application... .................................................................................................................. 256

4.52  Available methods........................................................................................................... 256

Division 4.3.5—Chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode                                                              257

4.53  Application... .................................................................................................................. 257

4.54  Available methods........................................................................................................... 257

4.55  Method 1—chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode 257

4.56  Method 2—chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode 259

4.57  Method 3—chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode 260

Division 4.3.6—Sodium cyanide production                                                       261

4.58  Application... .................................................................................................................. 261

4.59  Available methods........................................................................................................... 261

Division 4.3.7—Hydrogen production                                                                261

4.60  Application... .................................................................................................................. 261

4.61  Available methods........................................................................................................... 261

4.62A  Method 2—hydrogen production................................................................................. 263

4.62B  Method 3—hydrogen production................................................................................. 264

Part 4.4—Industrial processes—metal industry                                                     265

Division 4.4.1—Iron, steel or other metal production using an integrated metalworks           265

4.63  Application... .................................................................................................................. 265

4.64  Purpose of Division........................................................................................................ 265

4.65  Available methods for production of a metal from an integrated metalworks.................. 265

4.66  Method 1—production of a metal from an integrated metalworks................................... 265

4.67  Method 2—production of a metal from an integrated metalworks................................... 267

4.68  Method 3—production of a metal from an integrated metalworks................................... 268

Division 4.4.2—Ferroalloys production                                                             269

4.69  Application... 269

4.70  Available methods........................................................................................................... 269

4.71  Method 1—ferroalloy metal............................................................................................ 269

4.72  Method 2—ferroalloy metal............................................................................................ 271

4.73  Method 3—ferroalloy metal............................................................................................ 272

Division 4.4.3—Aluminium production (carbon dioxide emissions)                   273

4.74  Application... .................................................................................................................. 273

Sudivision 4.4.3.1—Aluminium—emissions from consumption of carbon anodes in aluminium production       273

4.75  Available methods........................................................................................................... 273

4.76  Method 1—aluminium (carbon anode consumption)...................................................... 273

4.77  Method 2—aluminium (carbon anode consumption)...................................................... 274

4.78  Method 3—aluminium (carbon anode consumption)...................................................... 274

Subdivision 4.4.3.2—Aluminium—emissions from production of baked carbon anodes in aluminium production                                                                                                                                274

4.79  Available methods........................................................................................................... 274

4.80  Method 1—aluminium (baked carbon anode production)............................................... 275

4.81  Method 2—aluminium (baked carbon anode production)............................................... 275

4.82  Method 3—aluminium (baked carbon anode production)............................................... 276

Division 4.4.4—Aluminium production (perfluoronated carbon compound emissions)            277

4.83  Application... .................................................................................................................. 277

Subdivision 4.4.4.1—Aluminium—emissions of tetrafluoromethane in aluminium production               277

4.84  Available methods........................................................................................................... 277

4.85  Method 1—aluminium (tetrafluoromethane)................................................................... 277

4.86  Method 2—aluminium (tetrafluoromethane)................................................................... 277

4.87  Method 3—aluminium (tetrafluoromethane)................................................................... 277

Subdivision 4.4.4.2—Aluminium—emissions of hexafluoroethane in aluminium production  278

4.88  Available methods........................................................................................................... 278

4.89  Method 1—aluminium production (hexafluoroethane).................................................... 278

4.90  Method 2—aluminium production (hexafluoroethane).................................................... 278

4.91  Method 3—aluminium production (hexafluoroethane).................................................... 278

Division 4.4.5—Other metals production                                                           279

4.92  Application... .................................................................................................................. 279

4.93  Available methods........................................................................................................... 279

4.94  Method 1—other metals.................................................................................................. 279

4.95  Method 2—other metals.................................................................................................. 281

4.96  Method 3—other metals.................................................................................................. 282

Part 4.5—Industrial processes—emissions of hydrofluorocarbons and sulphur hexafluoride gases    283

4.97  Application... .................................................................................................................. 283

4.98  Available method............................................................................................................. 283

4.99  Meaning of hydrofluorocarbons..................................................................................... 283

4.100  Meaning of synthetic gas generating activities.............................................................. 283

4.101  Reporting threshold....................................................................................................... 284

4.102  Method 1.... .................................................................................................................. 284

4.103  Method 2.... .................................................................................................................. 285

4.104  Method 3.... .................................................................................................................. 285

Chapter 5—Waste                                                                          286

Part 5.1—Preliminary                                                                                              286

5.1  Outline of Chapter............................................................................................................. 286

Part 5.2—Solid waste disposal on land                                                                   287

Division 5.2.1—Preliminary                                                                                287

5.2  Application..... .................................................................................................................. 287

5.3  Available methods............................................................................................................. 287

Division 5.2.2—Method 1—emissions of methane released from landfills        289

5.4  Method 1—methane released from landfills (other than from flaring of methane)............ 289

5.4A  Estimates for calculating CH4gen..................................................................................... 290

5.4B  Equation—change in quantity of particular opening stock at landfill for calculating CH4gen 291

5.4C  Equation—quantity of closing stock at landfill in particular reporting year..................... 291

5.4D  Equation—quantity of methane generated by landfill for calculating CH4gen.................. 292

5.5  Criteria for estimating tonnage of total solid waste............................................................ 294

5.6  Criterion A..... .................................................................................................................. 294

5.7  Criterion AAA........................................................................................................................         294

5.8  Criterion BBB .................................................................................................................. 294

5.9  Composition of solid waste............................................................................................... 295

5.10  General waste streams..................................................................................................... 295

5.10A  Homogenous waste streams......................................................................................... 297

5.11  Waste mix types.............................................................................................................. 298

5.11A  Certain waste to be deducted from waste received at landfill when estimating waste disposed in landfill   301

5.12  Degradable organic carbon content.................................................................................. 301

5.13  Opening stock of degradable organic carbon for the first reporting period...................... 302

5.14  Methane generation constants—(k values)...................................................................... 303

5.14A  Fraction of degradable organic carbon dissimilated (DOCF)........................................ 306

5.14B  Methane correction factor (MCF) for aerobic decomposition....................................... 307

5.14C  Fraction by volume generated in landfill gas that is methane (F).................................. 307

5.14D  Number of months before methane generation at landfill commences.......................... 307

Division 5.2.3—Method 2—emissions of methane released from landfills        308

Subdivision 5.2.3.1—methane released from landfills                                                          308

5.15  Method 2—methane released by landfill (other than from flaring of methane)................ 308

5.15A  Equation—change in quantity of particular opening stock at landfill for calculating CH4gen        311

5.15B  Equation—quantity of closing stock at landfill in particular reporting year................... 311

5.15C  Equation—collection efficiency limit at landfill in particular reporting year.................. 312

Subdivision 5.2.3.2—Requirements for calculating the methane generation constant (k) 313

5.16  Procedures for selecting representative zone................................................................... 313

5.17  Site plan—preparation and requirements......................................................................... 313

5.17AA  Sub‑facility zones—maximum number and requirements......................................... 313

5.17A  Representative zones—selection and requirements....................................................... 314

5.17B  Independent verification................................................................................................ 314

5.17C  Estimation of waste and degradable organic content in representative zone.................. 315

5.17D  Estimation of gas collected at the representative zone................................................... 315

5.17E  Estimating methane generated but not collected in the representative zone.................... 316

5.17F  Walkover survey........................................................................................................... 316

5.17G  Installation of flux boxes in representative zone........................................................... 317

5.17H  Flux box measurements................................................................................................ 318

5.17I  When flux box measurements must be taken................................................................. 319

5.17J  Restrictions on taking flux box measurements............................................................... 319

5.17K  Frequency of measurement........................................................................................... 320

5.17L  Calculating the methane generation constant (ki) for certain waste mix types................ 320

Division 5.2.4—Method 3—emissions of methane released from solid waste at landfills         323

5.18  Method 3—methane released from solid waste at landfills (other than from flaring of methane)   323

Division 5.2.5—Solid waste at landfills—Flaring                                               324

5.19  Method 1—landfill gas flared.......................................................................................... 324

5.20  Method 2—landfill gas flared.......................................................................................... 324

5.21  Method 3—landfill gas flared.......................................................................................... 324

Division 5.2.6—Biological treatment of solid waste                                           325

5.22  Method 1—emissions of methane and nitrous oxide from biological treatment of solid waste      325

5.22AA  Method 4—emissions of methane and nitrous oxide from biological treatment of solid waste                325

Division 5.2.7—Legacy emissions and non‑legacy emissions                             326

5.22A  Legacy emissions estimated using method 1—sub‑facility zone options...................... 326

5.22B  Legacy emissions—formula and unit of measurement.................................................. 326

5.22C  How to estimate quantity of methane captured for combustion from legacy waste for each sub‑facility zone             327

5.22D  How to estimate quantity of methane in landfill gas flared from legacy waste in a sub‑facility zone           328

5.22E  How to estimate quantity of methane captured for transfer out of landfill from legacy waste for each sub‑facility zone.................................................................................................................. 328

5.22F  How to calculate the quantity of methane generated from legacy waste for a sub‑facility zone (CH4genlw z)                329

5.22G  How to calculate total methane generated from legacy waste........................................ 329

5.22H  How to calculate total methane captured and combusted from methane generated from legacy waste         329

5.22J  How to calculate total methane captured and transferred offsite from methane generated from legacy waste               330

5.22K  How to calculate total methane flared from methane generated from legacy waste....... 330

5.22L  How to calculate methane generated in landfill gas from nonlegacy waste.................. 330

5.22M  Calculating amount of total waste deposited at landfill................................................. 331

Part 5.3—Wastewater handling (domestic and commercial)                                332

Division 5.3.1—Preliminary                                                                                332

5.23  Application... .................................................................................................................. 332

5.24  Available methods........................................................................................................... 332

Division 5.3.2—Method 1—methane released from wastewater handling (domestic and commercial)                                                                                                         333

5.25  Method 1—methane released from wastewater handling (domestic and commercial)..... 333

Division 5.3.3—Method 2—methane released from wastewater handling (domestic and commercial)                                                                                                         337

5.26  Method 2—methane released from wastewater handling (domestic and commercial)..... 337

5.26A  Requirements relating to sub‑facilities.......................................................................... 341

5.27  General requirements for sampling under method 2........................................................ 341

5.28  Standards for analysis..................................................................................................... 342

5.29  Frequency of sampling and analysis................................................................................ 342

Division 5.3.4—Method 3—methane released from wastewater handling (domestic and commercial)                                                                                                         343

5.30  Method 3—methane released from wastewater handling (domestic and commercial)..... 343

Division 5.3.5—Method 1—emissions of nitrous oxide released from wastewater handling (domestic and commercial)                                                                                     344

5.31  Method 1—nitrous oxide released from wastewater handling (domestic and commercial) 344

Division 5.3.6—Method 2—emissions of nitrous oxide released from wastewater handling (domestic and commercial)                                                                                     347

5.32  Method 2—nitrous oxide released from wastewater handling (domestic and commercial) 347

5.33  General requirements for sampling under method 2........................................................ 347

5.34  Standards for analysis..................................................................................................... 348

5.35  Frequency of sampling and analysis................................................................................ 348

Division 5.3.7—Method 3—emissions of nitrous oxide released from wastewater handling (domestic and commercial)                                                                                     349

5.36  Method 3—nitrous oxide released from wastewater handling (domestic and commercial) 349

Division 5.3.8—Wastewater handling (domestic and commercial)—Flaring    350

5.37  Method 1—Flaring of methane in sludge biogas from wastewater handling (domestic and commercial)      350

5.38  Method 2—flaring of methane in sludge biogas.............................................................. 350

5.39  Method 3—flaring of methane in sludge biogas.............................................................. 350

Part 5.4—Wastewater handling (industrial)                                                           351

Division 5.4.1—Preliminary                                                                                351

5.40  Application... .................................................................................................................. 351

5.41  Available methods........................................................................................................... 351

Division 5.4.2—Method 1—methane released from wastewater handling (industrial) 352

5.42  Method 1—methane released from wastewater handling (industrial).............................. 352

Division 5.4.3—Method 2—methane released from wastewater handling (industrial) 356

5.43  Method 2—methane released from wastewater handling (industrial).............................. 356

5.44  General requirements for sampling under method 2........................................................ 356

5.45  Standards for analysis..................................................................................................... 356

5.46  Frequency of sampling and analysis................................................................................ 357

Division 5.4.4—Method 3—methane released from wastewater handling (industrial) 358

5.47  Method 3—methane released from wastewater handling (industrial).............................. 358

Division 5.4.5—Wastewater handling (industrial)—Flaring of methane in sludge biogas        359

5.48  Method 1—flaring of methane in sludge biogas.............................................................. 359

5.49  Method 2—flaring of methane in sludge biogas.............................................................. 359

5.50  Method 3—flaring of methane in sludge biogas.............................................................. 359

Part 5.5—Waste incineration                                                                                   360

5.51  Application... .................................................................................................................. 360

5.52  Available methods—emissions of carbon dioxide from waste incineration..................... 360

5.53  Method 1—emissions of carbon dioxide released from waste incineration..................... 360

Chapter 6—Energy                                                                        362

Part 6.1—Production                                                                                                362

6.1  Purpose.......... .................................................................................................................. 362

6.2  Quantity of energy produced............................................................................................. 362

6.3  Energy content of fuel produced........................................................................................ 363

Part 6.2—Consumption                                                                                            365

6.4  Purpose.......... .................................................................................................................. 365

6.5  Energy content of energy consumed.................................................................................. 365

Chapter 7—Scope 2 emissions                                                       368

7.1  Application..... .................................................................................................................. 368

7.2  Method 1—purchase and loss of electricity from main electricity grid in a State or Territory 368

7.3  Method 1—purchase and loss of electricity from other sources........................................ 369

Chapter 8—Assessment of uncertainty                                          370

Part 8.1—Preliminary                                                                                              370

8.1  Outline of Chapter............................................................................................................. 370

Part 8.2—General rules for assessing uncertainty                                                 371

8.2  Range for emission estimates............................................................................................ 371

8.3  Required method............................................................................................................... 371

Part 8.3—How to assess uncertainty when using method 1                                  372

8.4  Purpose of Part.................................................................................................................. 372

8.5  General rules about uncertainty estimates for emissions estimates using method 1........... 372

8.6  Assessment of uncertainty for estimates of carbon dioxide emissions from combustion of fuels    372

8.7  Assessment of uncertainty for estimates of methane and nitrous oxide emissions from combustion of fuels  375

8.8  Assessment of uncertainty for estimates of fugitive emissions.......................................... 376

8.9  Assessment of uncertainty for estimates of emissions from industrial process sources.... 377

8.10  Assessment of uncertainty for estimates of emissions from waste.................................. 378

8.11  Assessing uncertainty of emissions estimates for a source by aggregating parameter uncertainties               378

Part 8.4—How to assess uncertainty levels when using method 2, 3 or 4            380

8.14  Purpose of Part................................................................................................................ 380

8.15  Rules for assessment of uncertainty using method 2, 3 or 4............................................ 380

Chapter 9—Application and transitional provisions                    381

9.10  Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (Energy) Determination 2017.................................................................................. 381

9.11  Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2018 Update) Determination 2018.................................................................................. 381

9.12  Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2019 Update) Determination 2019.................................................................................. 381

9.13  Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2020 Update) Determination 2020.................................................................................. 381

9.14  Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2021 Update) Determination 2021.................................................................................. 382

Schedule 1—Energy content factors and emission factors           383

Part 1—Fuel combustion—solid fuels and certain coal‑based products              383

Part 2—Fuel combustion—gaseous fuels                                                                385

Part 3—Fuel combustion—liquid fuels and certain petroleum‑based products for stationary energy purposes                                                                                                      386

Part 4—Fuel combustion—fuels for transport energy purposes                          388

Division 4.1—Fuel combustion—fuels for transport energy purposes              388

Division 4.2—Fuel combustion—liquid fuels for transport energy purposes for post‑2004 vehicles   389

Division 4.3—Fuel combustion—liquid fuels for transport energy purposes for certain trucks          389

Part 5—Consumption of fuels for non‑energy product purposes                        390

Part 6—Indirect (scope 2) emission factors from consumption of electricity purchased or lost from grid                                                                                                                     391

Part 7—Energy commodities                                                                                   392

Schedule 2—Standards and frequency for analysing energy content factor etc for solid fuels                                                                             393

Schedule 3—Carbon content factors                                             397

Part 1—Solid fuels and certain coal‑based products                                             397

Part 2—Gaseous fuels                                                                                              398

Part 3—Liquid fuels and certain petroleum‑based products                                399

Part 4—Petrochemical feedstocks and products                                                    400

Part 5—Carbonates                                                                                                  401

Schedule 4—Matters to be identified for sources                          402

Part 1—Coal mining                                                                                                 402

Part 2—Oil or gas                                                                                                     404

Part 3—Mineral products                                                                                        415

Part 4—Chemical products                                                                                      418

Part 5—Metal products                                                                                            421

Part 6—Waste                                                                                                           425

Endnotes                                                                                                                    431

Endnote 1—About the endnotes                                                                          431

Endnote 2—Abbreviation key                                                                             432

Endnote 3—Legislation history                                                                          433

Endnote 4—Amendment history                                                                         435


Chapter 1General

Part 1.1Preliminary

1.1  Name of Determination

                   This Determination is the National Greenhouse and Energy Reporting (Measurement) Determination 2008.

Division 1.1.1Overview

1.3  Overview—general

             (1)  This determination is made under section 10 of the National Greenhouse and Energy Reporting Act 2007. It provides 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.

Note:          Facility has the meaning given by section 9 of the Act.

             (2)  This determination deals with scope 1 emissions and scope 2 emissions.

Note:          Scope 1 emission and scope 2 emission have the meaning given by section 10 of the Act (also see, respectively, regulations 2.23 and 2.24 of the Regulations).

             (3)  There are 4 categories of scope 1 emissions dealt with in this Determination.

Note:          This Determination does not deal with emissions released directly from land management.

             (4)  The categories of scope 1 emissions are:

                     (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 (see Chapter 3); and

                     (c)  industrial processes emissions, which deals with emissions released from the consumption of carbonates and the use of fuels as feedstock 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 other facilities, or wastewater handling facilities (see Chapter 5).

             (5)  Each of the categories has various subcategories.

1.4  Overview—methods for measurement

             (1)  This Determination provides methods and criteria for the measurement of the matters mentioned in subsection 1.3(1).

             (2)  For scope 1 emissions or scope 2 emissions:

                     (a)  method 1 (known as the default method) is derived from the National Greenhouse Accounts methods and is based on national average estimates; and

                     (b)  method 2 is generally a facility specific method using industry practices for sampling and Australian or equivalent standards for analysis; and

                     (c)  method 3 is generally the same as method 2 but is based on Australian or equivalent standards for both sampling and analysis; and

                     (d)  method 4 provides for facility specific measurement of emissions by continuous or periodic emissions monitoring.

Note:          Method 4, that applies as indicated by provisions of this Determination, is as set out in Part 1.3.

             (3)  Data points relevant to the implementation of particular methods are set out in column 3 of the tables in Schedule 4 as ‘matters to be identified’. 

Note:          Regulations 4.10, 4.11, 4.13, 4.14, 4.15 and 4.17 of the Regulations require these matters to be identified to be included in reports under the Act.

1.5  Overview—energy

                   Chapter 6 deals with the estimation of the production and consumption of energy.

1.6  Overview—scope 2 emissions

                   Chapter 7 deals with scope 2 emissions.

1.7  Overview—assessment of uncertainty

                   Chapter 8 deals with the assessment of uncertainty.

Division 1.1.2Definitions and interpretation

1.8  Definitions

                   In this Determination:

2006 IPCC Guidelines means the 2006 IPCC Guidelines for National Greenhouse Gas Inventories published by the IPCC.

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.

accredited laboratory means a laboratory accredited by the National Association of Testing Authorities or an equivalent member of the International Laboratory Accreditation Cooperation in accordance with AS ISO/IEC 17025:2005, and for the production of calibration gases, accredited to ISO Guide 34:2000.

Act means the National Greenhouse and Energy Reporting Act 2007.

active gas collection means a system of wells and pipes that collect landfill gas through the use of vacuums or pumps.

alternative waste treatment activity means an activity that:

                     (a)  accepts and processes mixed waste using:

                              (i)  mechanical processing; and

                             (ii)  biological or thermal processing; and

                     (b)  extracts recyclable materials from the mixed waste.

alternative waste treatment residue means the material that remains after waste has been processed and organic rich material has been removed by physical screening or sorting by an alternative waste treatment activity that produces compost, soil conditioners or mulch in accordance with:

                     (a)  State or Territory legislation; or

                     (b)  Australian Standard AS 4454:2012.

ANZSIC industry classification and code means an industry classification and code for that classification published in the Australian and New Zealand Standard Industrial Classification (ANZSIC), 2006.

APHA followed by a number means a method of that number issued by the American Public Health Association and, if a date is included, of that date.

API Compendium means the document entitled Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry, published in August 2009 by the American Petroleum Institute.

Note:          The API Compendium is available at www.api.org.

applicable State or Territory legislation, for an underground mine, means a law of a State or Territory in which the mine is located that relates to coal mining health and safety, including such a law that prescribes performance‑based objectives, as in force on 1 July 2008.

Note:          Applicable State or Territory legislation includes:

·      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).

appropriate standard, for a matter or circumstance, means an Australian standard or an equivalent international standard that is appropriate for the matter or circumstance.

appropriate unit of measurement, in relation to a fuel type, means:

                     (a)  for solid fuels—tonnes; and

                     (b)  for gaseous fuels—metres cubed or gigajoules, except for liquefied natural gas which is kilolitres; and

                     (c)  for liquid fuels other than those mentioned in paragraph (d)—kilolitres; and

                     (d)  for liquid fuels of one of the following kinds—tonnes:

                              (i)  crude oil, plant condensate other natural gas liquids;

                             (ii)  petroleum coke;

                            (iii)  refinery gas and liquids;

                            (iv)  refinery coke;

                             (v)  bitumen:

                            (vi)  waxes;

                           (vii)  carbon black if used as petrochemical feedstock;

                          (viii)  ethylene if used as a petrochemical feedstock;

                            (ix)  petrochemical feedstock mentioned in item 57 of Schedule 1 to the Regulations.

AS or Australian standard followed by a number (for example, AS 4323.1—1995) means a standard of that number issued by Standards Australia Limited and, if a date is included, of that date.

ASTM followed by a number (for example, ASTM D6347/D6347M‑99) means a standard of that number issued by ASTM International and, if a date is included, of that date.

Australian legal unit of measurement has the meaning given by the National Measurement Act 1960.

base of the low gas zone means the part of the low gas zone worked out in accordance with section 3.25A.

basin means a geological basin named in the Australian Geological Provinces Database.

Note:          The Australian Geological Provinces Database is available at www.ga.gov.au.

biogenic carbon fuel means energy that is:

                     (a)  derived from plant and animal material, such as wood from forests, residues from agriculture and forestry processes and industrial, human or animal wastes; and

                     (b)  not embedded in the earth for example, like coal oil or natural gas.

biological treatment of solid waste:

                     (a)  means an alternative waste treatment activity consisting of a composting or anaerobic digestion process in which organic matter in solid waste is broken down by microorganisms; but

                     (b)  does not include solid waste disposal in a landfill.

Note:          Chapter 5 (waste) deals with solid waste disposal in a landfill as well as the biological treatment of solid waste (whether at a landfill or at a facility elsewhere).

blended fuel means fuel that is a blend of fossil and biogenic carbon fuels.

briquette means an agglomerate formed by compacting a particulate material in a briquette press, with or without added binder material.

calibrated to a measurement requirement, for measuring equipment, means calibrated to a specific characteristic, for example a unit of weight, with the characteristic being traceable to:

                     (a)  a measurement requirement provided for under the National Measurement Act 1960 or any instrument under that Act for that equipment; or

                     (b)  a measurement requirement under an equivalent standard for that characteristic.

captured for enhanced oil recovery: a greenhouse gas is captured for enhanced oil recovery if it is captured and transferred to the holder of an enhanced oil recovery authority for injection into a geological formation, such as a natural reservoir, to further oil or gas production activities and is not captured for permanent storage. 

captured for permanent storage, in relation to a greenhouse gas, has the meaning given by section 1.19A.

CEM or continuous emissions monitoring means continuous monitoring of emissions in accordance with Part 1.3.

CEN/TS followed by a number (for example, CEN/TS 15403) means a technical specification (TS) of that number issued by the European Committee for Standardization and, if a date is included, of that date.

city gate means a distribution hub where gas is reduced in pressure before it enters the lower pressure, smaller diameter, distribution pipeline network.

CO2‑e means carbon dioxide equivalence.

CO2 stimulation means using carbon dioxide as a fluid in well stimulation treatment which enhances oil and gas production or recovery by increasing the permeability of the formation.

coal seam methane has the same meaning as in the Regulations.

COD or chemical oxygen demand means the total material available for chemical oxidation (both biodegradable and non‑biodegradable) measured in tonnes.

compressed natural gas has the meaning given by the Regulations.

core sample means a cylindrical sample of the whole or part of a strata layer, or series of strata layers, obtained from drilling using a coring barrel with a diameter of between 50 mm and 2 000 mm.

crude oil has the meaning given by the Regulations.

crude oil transport means the transportation of marketable crude oil to heavy oil upgraders and refineries by means that include the following:

                     (a)  pipelines;

                     (b)  marine tankers;

                     (c)  tank trucks; 

                     (d)  rail cars.

decommissioned underground mine has the meaning given by the Regulations.

detection agent has the same meaning as in the Offshore Petroleum and Greenhouse Gas Storage Act 2006.

documentary standard means a published standard that sets out specifications and procedures designed to ensure that a material or other thing is fit for purpose and consistently performs in the way it was intended by the manufacturer of the material or thing.

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.

dry wood has the meaning given by the Regulations.

efficiency method has the meaning given by subsection 2.70(2).

EN followed by a number (for example, EN 15403) means a standard of that number issued by the European Committee for Standardization and, if a date is included, of that date.

enclosed composting activity means a semi‑enclosed or enclosed alternative waste or composting technology where the composting process occurs within a reactor that:

                     (a)  has hard walls or doors on all 4 sides; and

                     (b)  sits on a floor; and

                     (c)  has a permanent positive or negative aeration system.

energy content factor, for a fuel, means gigajoules of energy per unit of the fuel measured as gross calorific value.

enhanced oil recovery authority means a licence, lease or approval by or under a law of the Commonwealth, State or Territory which authorises the injection of one or more greenhouse gases into one or more geological formations, such as a natural reservoirs, to further oil or gas production activities.

equivalent leak detection standard, means a standard or documented approach that:

                     (a)  has equivalent or higher integrity than the method outlined in USEPA Method 21—Determination of organic volatile compound leaks, as set out in Appendix A‑7 of Title 40, Part 60 of the Code of Federal Regulations, United States of America or optical gas imaging in accordance with paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America; and

                     (b)  has equivalent or higher sensitivity for detecting leaks than:

                              (i)  60 grams per hour in accordance with paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America; or

                             (ii)  10,000 parts per million or greater in accordance with the method outlined in USEPA Method 21—Determination of organic volatile compound leaks, as set out in Appendix A‑7 of Title 40, Part 60 of the Code of Federal Regulations, United States of America.

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.

extraction area, in relation to an open cut mine, is the area of the mine from which coal is extracted.

feedstock has the meaning given by the Regulations.

ferroalloy has the meaning given by subsection 4.69(2).

flaring means the combustion of fuel for a purpose other than producing energy.

Example:    The combustion of methane for the purpose of complying with health, safety and environmental requirements.

fuel means a substance mentioned in column 2 of an item in Schedule 1 to the Regulations other than a substance mentioned in items 58 to 66.

fuel oil has the meaning given by the Regulations.

fugitive emissions means greenhouse gas emissions that are:

                     (a)  released in connection with, or as a consequence of, the extraction, processing, storage or delivery of fossil fuel; and

                     (b)  not released from the combustion of fuel for the production of useable heat or electricity.

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.

gaseous fuel means a fuel mentioned in column 2 of items 17 to 30 of Schedule 1 to the Regulations.

gas stream means the flow of gas subject to monitoring under Part 1.3.

gassy mine means an underground mine that has at least 0.1% methane in the mine’s return ventilation.

Global Warming Potential means, in relation to a greenhouse gas mentioned in column 2 of an item in the table in regulation 2.02 of the Regulations, the value mentioned in column 4 for that item.

GPA followed by a number means a standard of that number issued by the Gas Processors Association and, if a date is included, of that date.

green and air dried wood has the meaning given by the Regulations.

greenhouse gas stream means a stream consisting of a mixture of any or all of the following substances captured for injection into, and captured for permanent storage in, a geological formation:

                     (a)  carbon dioxide, whether in a gaseous or liquid state;

                     (b)  a greenhouse gas other than carbon dioxide, whether in a gaseous or liquid state;

                     (c)  one or more incidental greenhouse gas‑related substances, whether in a gaseous or liquid state, that relate to either or both of the greenhouse gases mentioned in paragraph (a) and (b);

                     (d)  a detection agent, whether in a gaseous or liquid state;

so long as:

                     (e)  the mixture consists overwhelmingly of either or both of the greenhouse gases mentioned in paragraphs (a) and (b); and

                      (f)  if the mixture includes a detection agent—the concentration of the detection agent in the mixture is not more than the concentration prescribed in relation to the detection agent for the purposes of subparagraph (vi) of paragraph (c) of the definition of greenhouse gas substance in section 7 of the Offshore Petroleum and Greenhouse Gas Storage Act 2006.

Note:          A greenhouse gas is captured for permanent storage in a geological formation if the gas is captured by, or transferred to, the holder of a licence, lease or approval mentioned in section 1.19A, under a law mentioned in that section, for the purpose of being injected into a geological formation (however described) under the licence, lease or approval.

GST group has the same meaning as in the Fuel Tax Act 2006.

GST joint venture has the same meaning as in the Fuel Tax Act 2006.

GWPmethane means the Global Warming Potential of methane.

higher method has the meaning given by subsection 1.18(5).

hydrofluorocarbons has the meaning given by section 4.99.

ideal gas law means the state of a hypothetical ideal gas in which the amount of gas is determined by its pressure, volume and temperature.

IEC followed by a number (for example, IEC 17025:2005) means a standard of that number issued by the International Electrotechnical Commission and, if a date is included, of that date.

incidental, for an emission, has the meaning given by subregulation 4.27(5) of the Regulations.

incidental greenhouse gas‑related substance, in relation to a greenhouse gas that is captured from a particular source material, means:

                     (a)  any substance that is incidentally derived from the source material; or

                     (b)  any substance that is incidentally derived from the capture; or

                     (c)  if the captured greenhouse gas, whether in a pure form or in a mixture with other substances, is transported—any substance that is incidentally derived from the transportation; or

                     (d)  if the captured greenhouse gas, whether in a pure form or in a mixture with other substances, is injected into a part of a geological formation—any substance that is incidentally derived from the injection; or

                     (e)  if the captured greenhouse gas, whether in a pure form or in a mixture with other substances, is stored in a part of a geological formation—any substance that is incidentally derived from the storage.

independent expert, in relation to an operator of a landfill, means a person who:

                     (a)  is independent of the operator of the landfill; and

                     (b)  has relevant expertise in estimating or monitoring landfill surface gas.

inert waste means waste materials that contain no more than a negligible volume of degradable organic carbon and includes the following waste:

                     (a)  concrete;

                     (b)  metal;

                     (c)  plastic;

                     (d)  glass;

                     (e)  asbestos concrete;

                      (f)  soil.

integrated metalworks has the meaning given by subsection 4.64(2).

invoice includes delivery record.

IPCC is short for Intergovernmental Panel on Climate Change established by the World Meteorological Organization and the United Nations Environment Programme.

ISO followed by a number (for example, ISO 10396:2007) means a standard of that number issued by the International Organization of Standardization and, if a date is included, of that date.

Leak Detection and Repair Program or LDAR program means a system of procedures used at a facility to monitor, locate and repair leaking components in order to minimize emissions.

leaker, in relation to a component subject to an LDAR program, means:

(a) if optical gas imaging is used, a leaker is detected at a sensitivity of 60 grams per hour in accordance with paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America; and

(b) if the method outlined in USEPA Method 21—Determination of organic volatile compound leaks, as set out in Appendix A‑7 of Title 40, Part 60 of the Code of Federal Regulations, United States of America is used, a leaker is detected if 10,000 parts per million or greater is measured consistent with that method; and

(c)  if an equivalent leak detection standard is used, a leaker is detected at the sensitivity set for that standard.

Note:          Under the definition of equivalent leak detection standard, the sensitivity must be equivalent or higher than the approaches in paragraph (a) or (b).

legacy emissions has the same meaning as in the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015.

legacy waste means waste deposited at a landfill before 1 July 2016.

liquefied natural gas has the same meaning as in the Regulations.

liquefied natural gas station means the plant and equipment used in the natural gas liquefaction, storage and transfer of liquefied natural gas, and includes:

                     (a)  all onshore or offshore equipment that receives natural gas, liquefies and stores liquefied natural gas, and transfers the liquefied natural gas to a transportation system; and

                     (b)  equipment that receives imported or transported liquefied natural gas, stores liquefied natural gas, re-gasifies liquefied natural gas, and delivers re-gasified natural gas to a natural gas transmission or distribution system.

liquefied petroleum gas has the same meaning as in the Regulations.

liquid fuel means a fuel mentioned in column 2 of items 31 to 54 of Schedule 1 to the Regulations.

lower method has the meaning given by subsection 1.18(6).

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.

main electricity grid has the meaning given by subsection 7.2(4).

marketable crude oil includes:

                     (a)  conventional crude oil; and

                     (b)  heavy crude oil; and

                     (c)  synthetic crude oil; and

                     (d)  bitumen.

method means a method specified in this determination for estimating emissions released from the operation of a facility in relation to a source.

municipal materials has the meaning given by the Regulations.

municipal solid waste class I means waste from domestic premises, council collections and other municipal sources where:

                     (a)  the collection of organic waste on a regular basis in a dedicated bin is not provided to residents of the municipality as a standard practice; or

                     (b)  the collection of organic waste on a regular basis in a dedicated bin provided to residents of the municipality cannot be confirmed as standard practice.

municipal solid waste class II means waste from domestic premises, council collections and other municipal sources where a bin dedicated for garden waste is:

                     (a)  provided to residents of the municipality as a standard practice; and

                     (b)  collected on a regular basis.

N/A means not available.

National Greenhouse Accounts means the set of national greenhouse gas inventories, including the National Inventory Report 2005, submitted by the Australian government to meet its reporting commitments under the United Nations Framework Convention on Climate Change and the 1997 Kyoto Protocol to that Convention.

natural gas has the meaning given by the Regulations.

natural gas distribution means the transport of pipeline natural gas over a combination of natural gas distribution pipelines from a city gate to customer delivery points.

natural gas distribution pipelines mean pipelines for the conveyance of pipeline natural gas that:

                     (a)  are identified as a distribution pipeline in an access arrangement applicable to the pipeline; or

                     (b)  meet both of the following:

                              (i)  have a maximum design pressure of 1,050 kPa or less; and

                             (ii)  are not natural gas gathering and boosting pipelines.

natural gas gathering and boosting means the activity to collect unprocessed natural gas or coal seam methane from gas wellheads and to compress, dehydrate, sweeten, or transport the gas through natural gas gathering and boosting pipelines to a natural gas processing station, a natural gas transmission pipeline or a natural gas distribution pipeline.

natural gas gathering and boosting pipeline means a pipeline for the conveyance of gas that:

                     (a)  contains unprocessed natural gas or coal seam methane; and

                     (b)  pertains to the activity of natural gas gathering and boosting.

Note:          Such pipelines can operates at high or low pressures

natural gas gathering and boosting station means one or more pieces of plant and equipment used in natural gas gathering and boosting at a single location that operates as a unit in the natural gas gathering and boosting activity. The plant and equipment may include any of the following:

                     (a)  compressors;

                     (b)  generators;

                     (c)  dehydrators;

                     (d)  storage vessels;

                     (e)  acid gas removal units;

                      (f)  engines;

                     (g)  boilers;

                     (h)  heaters;

                      (i)  flares;

                      (j)  separation and processing equipment;

                     (k)  associated storage or measurement vessels;

                      (l)  equipment on, or associated with, an enhanced oil recovery well pad using CO2 or gas injection.

Note:          The single location that operates as a unit will generally be known as a facility, station or node for operational purposes. It is not expected that stations will be defined differently for operational purposes and emissions accounting purposes.

natural gas liquefaction, storage and transfer means the activity to collect and liquefy natural gas and to store and transfer liquefied natural gas to a transportation system.

natural gas liquids has the meaning given by the Regulations.

natural gas processing station means the plant and equipment used in the natural gas processing in a single location, and includes:

                     (a)  liquids recovery plant and equipment where the separation of natural gas liquids or non-methane gases from unprocessed natural gas or coal seam methane occurs; and

                     (b)  liquids recovery plant and equipment where the separation of natural gas liquids into one or more component mixtures occur; and

                     (c)  gas separation trains where the removal of acidic gases from unprocessed natural gas or coal seam methane occurs;

Note:          The separation includes one or more of the following: forced extraction of natural gas liquids, sulphur and carbon dioxide removal, fractionation of natural gas liquids, or the capture of CO2 separated from unprocessed natural gas and coal seam methane streams.

natural gas processing means one or both of the following activities:

                     (a)  the separation of natural gas liquids or non-methane gases from unprocessed natural gas or coal seam methane; 

                     (b)  the separation of natural gas liquids into one or more component mixtures.

Note:          The separation includes one or more of the following: forced extraction of natural gas liquids, sulphur and carbon dioxide removal, fractionation of natural gas liquids, or the capture of CO2 separated from natural gas streams.

natural gas production includes offshore natural gas production and onshore natural gas production.

natural gas storage means the activity to store unprocessed natural gas, coal seam methane or natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas).

natural gas storage station means the plant and equipment used in natural gas storage, and includes:

                     (a)  subsurface storage, such as depleted gas or oil reservoirs that store gas; and

                     (b)  the equipment to undertake natural gas underground storage processes and operations (including compression, dehydration and flow measurement, but excluding natural gas transmission pipelines); and

                     (c)  all the wellheads connected to the compression units located at the station that inject and recover natural gas into and from the underground reservoirs.        

natural gas transmission means transmission of natural gas or plant condensate through one or more natural gas transmission pipelines from a natural gas processing station or a natural gas gathering and boosting network to any of the following:

                     (a)  a natural gas distribution network;

                     (b)  another natural gas processing station;

                     (c)  a liquefied natural gas station;

                     (d)  a large industrial facility, such as a power station.

natural gas transmission pipeline means a pipeline for the conveyance of pipeline natural gas or plant condensate that:

                     (a)  is licensed as a transmission pipeline under a Commonwealth, State or Territory law; and

                     (b)  has a maximum design pressure exceeding 1,050 kPa; and

                     (c)  is not a natural gas distribution pipeline or a natural gas gathering and boosting pipeline.

non‑gassy mine means an underground mine that has less than 0.1% methane in the mine’s return ventilation.

non‑legacy waste means waste deposited at a landfill on or after 1 July 2016.

offshore natural gas production means the activity to produce, extract, recover, lift, stabilise, separate or treat unprocessed natural gas, condensate or coal seam methane on offshore submerged lands, including well workovers.

offshore platform includes:

                     (a)  any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses plant and equipment to do either or both of the following:

                              (i)  extract unprocessed natural gas and condensate from the ocean or lake floor;

                             (ii)  transfers such unprocessed natural gas and condensate to storage, transport vessels, or onshore; and

                     (b)  secondary platform structures connected to the platform structure via walkways, and

                     (c)  storage tanks associated with the platform structure; and

                     (d)  floating production and storage offloading equipment; and

                     (e)  submerged wellhead production structures.

offshore platform (shallow water) means an offshore platform standing in less than 200 metres of water.

offshore platform (deep water) means an offshore platform standing in at least 200 metres of water.

oil or gas exploration and development means the activity to explore for oil and gas resources and test, appraise, drill, develop and complete wells for oil and gas resources and includes the following actions:

                     (a)  oil well drilling;

                     (b)  gas well drilling;

                     (c)  drill stem testing;

                     (e)  well appraisals;

                      (f)  development drilling;

                     (g)  well completions;

                     (h)  well workovers associated with the actions in the paragraphs above.

onshore natural gas production means the activity to produce, extract, recover, lift, stabilise, separate or treat unprocessed natural gas, condensate or coal seam methane on land, including well workovers.

onshore natural gas wellhead means the gas wellhead.

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.

PEM or periodic emissions monitoring means periodic monitoring of emissions in accordance with Part 1.3.

Perfluorocarbon protocol means the Protocol for Measurement of Tetrafluoromethane (CF4) and Hexafluoroethane (C2F6) Emissions from Primary Aluminium Production published by the United States Environmental Protection Agency and the International Aluminium Institute.

petroleum based greases has the meaning given by regulation 1.03 of the Regulations.

petroleum based oils has the meaning given by the Regulations.

petroleum coke has the meaning given by the Regulations.

phytocap means an evapotranspiration landfill capping system that makes use of soil and vegetation to store and release surface water.

pipeline natural gas means natural gas that is suitable for market consumption.

plant condensate has the meaning given by the Regulations.

post‑mining activities, in relation to a mine, is the handling, stockpiling, processing and transportation of coal extracted from the mine.

primary wastewater treatment plant:

                     (a)  means a treatment facility at which wastewater undergoes physical screening, degritting and sedimentation; and

                     (b)  does not include a treatment facility at which any kind of nitrification or denitrification treatment process occurs.

principal activity, in relation to a facility, means the activity that:

                     (a)  results in the production of a product or service that is produced for sale on the market; and

                     (b)  produces the most value for the facility out of any of the activities forming part of the facility.

produced water means the water that is either:

                     (a)  pumped from coal seams or unprocessed gas reservoirs during natural gas production or natural gas gathering and boosting; or

                     (b)  pumped from wells during crude oil production or oil and gas exploration and development.

pyrolysis of coal means the decomposition of coal by heat.

raw sugar has the meaning given by Chapter 17 of Section IV of Schedule 3 to the Customs Tariff Act 1995.

reductant:

                     (a)  means a reducing agent or substance:

                              (i)  that causes another substance to undergo reduction; and

                             (ii)  that is oxidised while causing the substance to undergo reduction; and

                     (b)  does not include fuels that are combusted only to produce energy.

refinery gases and liquids has the meaning given by the Regulations.

Regulations means the National Greenhouse and Energy Reporting Regulations 2008.

relevant person means a person mentioned in paragraph 1.19A(a), (b), (c), (d), (e) or (f).

run‑of‑mine coal means coal that is produced by mining operations before screening, crushing or preparation of the coal has occurred.

scope 1 emissions has the same meaning as in the Regulations.

scope 2 emissions has the same meaning as in the Regulations.

separate instance of a source has the meaning given by section 1.9A.

separate occurrence of a source has the meaning given by section 1.9B.

shale gas means a substance that:

                     (a)  consists of:

                              (i)  naturally occurring hydrocarbons; or

                             (ii)  a naturally occurring mixture of hydrocarbons and non‑hydrocarbons; and

                     (b)  consists mainly of methane; and

                     (c)  is drained from shale formations.

shredder flock means the residual waste generated from the process of scrap metal processing that ends up in landfill.

sludge biogas has the meaning given by the Regulations.

sludge lagoon means a component of a wastewater treatment system that:

                     (a)  is used to stabilise and dry excess or wasted sludge from the liquid or solid phase treatment train of a wastewater treatment plant; and

                     (b)  involves biodegradation of COD in the form of sludge and the use of ambient climatic factors to reduce the moisture content of the sludge.

solid fuel means a fuel mentioned in column 2 of items 1 to 16 of Schedule 1 to the Regulations.

source has the meaning given by section 1.10.

specified taxable fuel has the meaning given by regulation 3.30 of the Clean Energy Regulations 2011.

standard includes a protocol, technical specification or USEPA method.

standard conditions has the meaning given by subsection 2.32(7).

sulphite lyes has the meaning given by the Regulations.

supply means supply by way of sale, exchange or gift.

synthetic gas generating activities has the meaning given by subsections 4.100(1) and (2).

tight gas means a substance that:

                     (a)  consists of:

                              (i)  naturally occurring hydrocarbons; or

                             (ii)  a naturally occurring mixture of hydrocarbons and non‑hydrocarbons; and

                     (b)  consists mainly of methane; and

                     (c)  is drained from low permeability sandstone and limestone reservoirs.

uncertainty protocol means the publication known as the GHG protocol guidance on uncertainty assessment in GHG inventories and calculating statistical parameter uncertainty (September 2003) v1.0 issued by the World Resources Institute and the World Business Council for Sustainable Development.

underground mine means a coal mine that allows extraction of coal by mining at depth, after entry by shaft, adit or drift, without the removal of overburden.

USEPA followed by a reference to a method (for example, Method 3C) means a standard of that description issued by the United States Environmental Protection Agency.

waxes has the meaning given by the Regulations.

well completion means the period that:

                     (a)  begins on the initial gas flow in the well; and

                     (b)  ends on whichever of the following occurs first:

                              (i)  well shut in; or

                             (ii)  continuous gas flow from the well to a flow line or a storage vessel for collection.

well workover means activities performed to restore or increase production which can include any or all of the following processes:

                     (a)  well venting;

                     (b)  tubing maintenance;

                     (c)  air clean out;

                     (d)  hydraulic fracturing and recovery;

                     (e)  well unloading.

year means a financial year.

Note:          The following expressions in this Determination are defined in the Act:

·      carbon dioxide equivalence

·      consumption of energy (see also regulation 2.26 of the Regulations)

·      energy

·      facility

·      greenhouse gas

·      group

·      industry sector

·      operational control

·      potential greenhouse gas emissions

·      production of energy (see also regulation 2.25 of the Regulations)

·      registered corporation

·      scope 1 emission (see also regulation 2.23 of the Regulations)

·      scope 2 emission (see also regulation 2.24 of the Regulations).

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 January 2020.

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

             (1)  A thing mentioned in the column headed ‘Source of emissions’ of the following table is a source.

 

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 and development—flaring

2E

 

Oil or gas exploration and development (other than flaring)

2F

 

Crude oil production

2G

 

Crude oil transport

2H

 

Crude oil refining

2I

 

Onshore natural gas production (other than emissions that are vented or flared)

2J

 

Offshore natural gas production (other than emissions that are vented or flared)

2K

 

Natural gas gathering and boosting (other than emissions that are vented or flared)

2L

 

Produced water from oil and gas exploration and development, crude oil production, natural gas production or natural gas gathering and boosting (other than emissions that are vented or flared)

2M

 

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

2N

 

Natural gas transmission (other than flaring)

2O

 

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

2P

 

Natural gas liquefaction, storage and transfer (other than emissions that are vented or flared)

2Q

 

Natural gas distribution (other than flaring)

2R

 

Onshore natural gas production—venting

2S

 

Offshore natural gas production—venting

2T

 

Onshore natural gas production—flaring

2U

 

Offshore natural gas production—flaring

2V

 

Natural gas gathering and boosting—venting

2W

 

Natural gas gathering and boosting—flaring

2X

 

Natural gas processing—venting

2Y

 

Natural gas processing—flaring

2Z

 

Natural gas transmission—flaring

2ZA

 

Natural gas storage—venting

2ZB

 

Natural gas storage—flaring

2ZC

 

Natural gas liquefaction, storage and transfer—venting

2ZE

 

Natural gas liquefaction, storage and transfer—flaring

2ZF

 

Natural gas distribution—flaring

2ZG

 

Carbon capture and storage

2ZH

 

Enhanced oil recovery

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 or carbon anode

3JA

 

Sodium cyanide production

3JB

 

Hydrogen production

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

4

Waste

 

4A

 

Solid waste disposal on land

4AA

 

Biological treatment of solid waste

4B

 

Wastewater handling (industrial)

4C

 

Wastewater handling (domestic or commercial)

4D

 

Waste incineration

             (2)  The extent of the source is as provided for in this Determination.

Part 1.2General

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 energy and also deals with standards;

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

                     (c)  Division 1.2.3 provides requirements in relation to carbon capture and storage.

Division 1.2.1Measurement and standards

1.12  Measurement of emissions and energy

             (1)  The measurement of emissions released from the operation of a facility is to be done by estimating the emissions in accordance with this Determination.

             (2)  The measurement of the production and consumption of energy from the operation of a facility is to be done by estimating the production and consumption of energy in accordance with this Determination.

1.13  General principles for measuring emissions and energy

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

                     (a)  transparency—emission and energy estimates must be documented and verifiable;

                     (b)  comparability—emission and energy estimates using a particular method and produced by a registered corporation or registered person in an industry sector must be comparable with emission and energy estimates produced by similar corporations or persons in that industry sector using the same method and consistent with the emission and energy 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 registered person and the requirements of this Determination, uncertainties in emission and energy 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 and production and consumption of all identifiable fuels and energy commodities listed in Schedule 1 of the Regulations must be accounted for, subject to any applicable reporting thresholds.

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.

1.15  Units of measurement

             (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 1.2.2Methods

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 registered person 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 source must 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 registered person 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 person 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 registered person 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 1.2.3Requirements 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

             (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 supercompressed 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 supercompressed 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 1.3Method 4—Direct measurement of emissions

Division 1.3.1Preliminary

1.20  Overview

             (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 1.3.2Operation of method 4 (CEM)

Subdivision 1.3.2.1Method 4 (CEM)

1.21  Method 4 (CEM)—estimation of emissions

             (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:

                  

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 16.0410‑3; or

                     (b)  for carbon dioxide is 44.0110‑3; or

                     (c)  for nitrous oxide is 44.0110‑3.

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.

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.

Subdivision 1.3.2.2Method 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.

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 1.3.3Operation of method 4 (PEM)

Subdivision 1.3.3.1Method 4 (PEM)

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.

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.

1.28  Calculation of emission factors

             (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.

Subdivision 1.3.3.2Method 4 (PEM)—use of equipment

1.29  Overview

                   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 1.3.4Performance 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 2Fuel combustion

Part 2.1Preliminary

  

2.1  Outline of Chapter

                   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).

Part 2.2Emissions released from the combustion of solid fuels

Division 2.2.1Preliminary

2.2  Application

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

2.4  Method 1—solid fuels

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

                  

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.

ECis 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.

Division 2.2.3Method 2—emissions from solid fuels

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

2.5  Method 2—estimating carbon dioxide using oxidation factor

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

                  

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.

ECis 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:

                  

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:

                  

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:

                  

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.

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

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

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

                  

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.

ECis 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:

                  

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:

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:

                  

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.

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

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

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

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

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 2.2.4Method 3—Solid fuels

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

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 2.2.5Measurement 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.

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.

          (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.

             (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.

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 2.3Emissions released from the combustion of gaseous fuels

Division 2.3.1Preliminary

2.18  Application

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

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:

                  

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.

ECis 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.

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

Subdivision 2.3.3.1Method 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

             (1)  For subparagraph 2.19(1)(a)(ii), method 2 for estimating emissions of carbon dioxide is:

                  

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.

ECis 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:

                  

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:

                  

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:

                  

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 2.3.3.2Sampling and analysis

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)

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

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

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)

part 6 (2002)

part 5 (2000)

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

2

All other gases (including fugitive emissions)

Gas composition

Energy content

Monthly, unless the reporting corporation or registered person 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 2.3.4Method 3—emissions of carbon dioxide released from the combustion of gaseous fuels

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

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)

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 2.3.5Method 2—emissions of methane from the combustion of gaseous fuels

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) and (3), 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 one of the following:

                     (a)  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;

                     (b)  estimated based on the manufacturer’s specification for the specific equipment type under relevant operational conditions, including the effect of any supplementary equipment technologies that modify methane emitted to the atmosphere;

                     (c)  if an equipment type (k) in column 2 of the following table is used—the factor in column 3 of the following table for the equipment type in column 2 of the table:

Item

Equipment type (k)

Emission factor for gas type  (j)



 

 

CH4

Units

1

Gas-fired reciprocating engines –

4-stroke lean burn

13.8

kg CO2-e /GJ

2

Gas-fired reciprocating engines –

4-stroke rich burn

1.2

kg CO2-e /GJ

3

Gas-fired reciprocating engines –

2-stroke lean burn

17.5

kg CO2-e /GJ

4

Gas turbines

0.1

kg CO2-e /GJ

             (3)  If applicable to the facility, the method described in section A.2.2 of Appendix A of the API Compendium may be used as method 2.

Note:          In 2021, the API Compendium could be accessed at www.api.org.

Division 2.3.6Measurement 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.

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 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 2.4Emissions released from the combustion of liquid fuels

Division 2.4.1Preliminary

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 2.4.1.1Liquid 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.

Subdivision 2.4.1.2Liquid 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 2.4.2Method 1—emissions of carbon dioxide, methane and nitrous oxide from liquid fuels other than petroleum based oils or greases

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:

                  

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.

ECis 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.

Division 2.4.3Method 2—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases

Subdivision 2.4.3.1Method 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:

                  

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:

                  

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:

                  

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 2.4.3.2Sampling and analysis

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

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

Plant condensates and other natural gas liquids not covered by another item in this table

ASTM D 240‑02 (2007)

ASTM D 4809‑06

ASTM D 5291‑02 (2007)

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)

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 internal combustion engine

N/A

N/A

N/A

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

Division 2.4.4Method 3—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases

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

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

4

Plant condensates and other natural gas liquids not covered by another item in this table

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

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)

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:

(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 3170:2004

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 2.4.5Method 2—emissions of methane and nitrous oxide from liquid fuels other than petroleum based oils or greases

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.

Division 2.4.5AMethods for estimating emissions of carbon dioxide from petroleum based oils or greases

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:

                  

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:

                           

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:

                  

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 2.4.6Measurement 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.

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 2.5Emissions 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 2.5.1Energy—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 2.5.2Energy—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:

where:

Si 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:

where:

Sp 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.

Step 3

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:

where:

Sr 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.

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:

where:

Si 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.

Sp 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.

 

Sr 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:

where:

Si 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.

Sp 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.

Sr 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.

 

α is the factor  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.

Division 2.5.3Energy—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:

 

where:

Si 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.

Step 2

Calculate the carbon content in products (p) leaving the activity during the year as follows:

 

where:

Sp 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:

 

where:

Sr 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.

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:

 

where:

Si 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.

Sp 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.

 

Sr 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:

 

where:

Si 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.

 

Sp 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.

 

Sr 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 byproducts (r) produced by the activity and held within the boundary of the activity during the year measured in tonnes.

 

α is the factor  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:

 

where:

Si 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.

Sp 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.

 

Sr 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 byproducts (r) produced by the activity and held within the boundary of the activity during the year measured in tonnes.

 

α is the factor  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 2.6Blended 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.

Part 2.7Estimation 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 at the facility—that each generating unit has a maximum capacity to produce at least 0.5 megawatts of electricity and produces over 100 000 kilowatt hours of electricity in a reporting year; or

                             (v)  for electricity consumed that was not generated by a generating unit at the facility—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.

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).

2.70  Amount of energy consumed in a cogeneration process

             (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

                   Subject to section 2.70, the amount of fuel type (i) consumed by a reporting corporation or registered person 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 registered person if the records are based on the measurement equipment used by the corporation or the registered person to measure consumption of the fuel types.

Chapter 3Fugitive emissions

Part 3.1Preliminary

  

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 3.2Coal mining—fugitive emissions

Division 3.2.1Preliminary

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 3.2.2Underground mines

Subdivision 3.2.2.1Preliminary

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.

Subdivision 3.2.2.2Fugitive emissions from extraction of coal

3.5  Method 1—extraction of coal

                   For subsection 3.32(1), method 1 is:

                  

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—0.407;

                     (b)  for a non‑gassy mine—0.011.

3.6  Method 4—extraction of coal

             (1)  For subsections 3.4(2) and (3), method 4 is:

                  

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 × GWPmethane; 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.

3.7  Estimation of emissions

             (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 3.2.2.3Emissions released from coal mine waste gas flared

3.14  Method 1—coal mine waste gas flared

                   For subparagraph 3.4(4)(a)(i) and paragraphs 3.4(4)(b) and (c), method 1 is:

                  

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

                   For subparagraph 3.4(4)(a)(ii), method 2 is:

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:

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

             (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.

Subdivision 3.2.2.4Fugitive emissions from post‑mining activities

3.17  Method 1—post‑mining activities related to gassy mines

             (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 0.019, 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 3.2.3Open cut mines

Subdivision 3.2.3.1Preliminary

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.

Subdivision 3.2.3.2Fugitive emissions from extraction of coal

3.20  Method 1—extraction of coal

                   For paragraph 3.19(2)(a), method 1 is:

                  

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—0.061;

                     (b)  for a mine in Victoria—0.0003;

                     (c)  for a mine in Queensland—0.023;

                     (d)  for a mine in Western Australia—0.023;

                     (e)  for a mine in South Australia—0.0003;

                      (f)  for a mine in Tasmania—0.019.

3.21  Method 2—extraction of coal

             (1)  For paragraph 3.19(2)(b) and subsection 3.19(3), method 2 is:

                  

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 × GWPmethane;

                     (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:

                  

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 ∑Qijtrquantities 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:

                            ;

                     (b)  equation 2:

                            .

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

                   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:

                              (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 3.2.3.3Emissions 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

                   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

                   For subparagraph 3.19(5)(a)(iii), method 3 is the same as method 3 under section 3.16.

Division 3.2.4Decommissioned underground mines

Subdivision 3.2.4.1Preliminary

3.30  Application

                   This Division applies to fugitive emissions from decommissioned underground mines from the time that they became a decommissioned underground coal mine, other than mines which have been a decommissioned underground coal mine for a continuous period of 20 years or more.

3.31  Available methods

             (1)  Subject to sections 1.18 and 3.30, for estimating emissions released during a year from the operation of a facility that is constituted by a decommissioned underground mine 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 during the year, method 1 in subsection (2) must not be used.

Subdivision 3.2.4.2Fugitive emissions from decommissioned underground mines

3.32  Method 1—decommissioned underground mines

             (1)  For paragraph 3.31(2)(a), method 1 is:

                  

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 12 month period before the mine became a decommissioned underground coal mine, measured in CO2‑e tonnes and estimated under section 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

                   For section 3.32, EFdm is the integral under the curve of:

                  

for the period between T and T-N,

where:

A is:

                     (a)   for a gassy mine—; or

                     (b)   for a non‑gassy mine—.

T is the number of whole months since the mine became a decommissioned underground coal mine, at the end of the reporting year.

N is:

                     (a)   if T is less than 12—the value for T; or

                     (b)  if T is 12 or greater—12.

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.

3.34  Measurement of proportion of mine that is flooded

                   For subsection 3.32(1), Fdm is:

                   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.

months is the number of whole months since the mine became a decommissioned underground coal mine, at the end of the reporting year.

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 3.2.4.3Fugitive emissions from coal mine waste gas flared

3.38  Method 1—coal mine waste gas flared

             (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 3.3Oil and natural gas—fugitive emissions

Division 3.3.1Preliminary

3.41  Outline of Part

             (1)  This Part provides for fugitive emissions from the following:

                     (a)  oil or gas exploration and development (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)  onshore natural gas production, other than emissions that are vented or flared (see Division 3.3.6A);

                      (f)  offshore natural gas production, other than emissions that are vented or flared (see Division 3.3.6B);

                     (g)  natural gas gathering and boosting, other than emissions that are vented or flared (see Division 3.3.6C);

                     (h)  produced water from oil and gas exploration and development, crude oil production, natural gas production or natural gas gathering and boosting, other than emissions that are vented or flared (see Division 3.3.6D);

                      (i)  natural gas processing, other than emissions that are vented or flared (see Division 3.3.6E);

                      (j)  natural gas transmission, other than emissions that are flared (see Division 3.3.7);

                     (k)  natural gas storage, other than emissions that are vented or flared (see Division 3.3.7A);

                      (l)  natural gas liquefaction, storage and transfer, other than emissions that are vented or flared (see Division 3.3.7B);

                    (m)  natural gas distribution, other than emissions that are flared (see Division 3.3.8);

                     (n)  natural gas production (emissions that are vented or flared) (see Division 3.3.9A);

                     (o)  natural gas gathering and boosting (emissions that are vented or flared) (see Division 3.3.9B);

                     (p)  natural gas processing (emissions that are vented or flared) (see Division 3.3.9C);

                     (q)  natural gas transmission (emissions that are flared) (see Division 3.3.9D);

                      (r)  natural gas storage (emissions that are vented or flared) (see Division 3.3.9E);

                      (s)  natural gas liquefaction, storage or transfer (emissions that are vented or flared) (see Division 3.3.9F);

                      (t)  natural gas distribution (emissions that are flared) (see Division 3.3.9G).

             (2)  The activities at a facility should be classified in accordance with the relevant definitions to apply the calculations in this Part to comprehensively cover the emissions from the facility, but not count the emissions more than once.

3.41A  Interpretation

             (1)  Terms relating to the oil and gas industry in this Part are to be interpreted:

                     (a)  consistently with their accepted meaning in the oil and gas industry; and

                     (b)  where the term is relevant to methods in the API Compendium—taking into account the meaning and scope of the term in that compendium.

Note:          In 2021, the API Compendium could be accessed at www.api.org.

             (2)  If a method in this Part allows for the use of component or equipment emissions factors from the manufacturer of the component or equipment, those factors must not be used if they are likely to result in estimates of emissions inconsistent with the principles in section 1.13.

Division 3.3.2Oil or gas exploration and development

Subdivision 3.3.2.1Preliminary

3.42  Application

                   This Division applies to fugitive emissions from venting or flaring from oil or gas exploration and development activities, including emissions from:

                     (a)  oil well drilling; and

                     (b)  gas well drilling; and

                     (c)  oil well completions; and

(d)  gas well completions; and

(e)           well workovers; and

(f) well blowouts; and

(g) cold process vents.

Subdivision 3.3.2.2Oil or gas exploration and development (emissions that are flared)

3.43  Available methods

             (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 and development:

                     (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.

3.44  Method 1—oil or gas exploration and development

             (1)  Method 1 is:

                Eij  = Q×  EFij

where:

Eij is the fugitive emissions of gas type (j) from a fuel type (i) flared in the oil or gas exploration and development during the year measured in CO2‑e tonnes.

Qi is the quantity of fuel type (i) flared in the oil or gas exploration and development during the year measured in tonnes.

Note:          This quantity includes all of the fuel type, not just hydrocarbons within the fuel type.

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

Gas

2.80

0.933

0.026

2

Crude oil and liquids

3.20

0.009

0.06

3.45  Method 2—oil or gas exploration and development (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:

                  

where:

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in oil or gas exploration and development 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 and development 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 and development 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 and development 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 and development (flared methane or nitrous oxide emissions)

                   For subparagraphs 3.43(1)(b)(ii) and (c)(ii), method 2A is:

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 and development 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 and development 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 and development 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 and development

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 3.3.2.3Oil or gas exploration and development—fugitive emissions from system upsets, accidents and deliberate releases

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 during a reporting year from the operation of a facility that is constituted by oil or gas exploration and development.

             (2)  To estimate emissions for methane and carbon dioxide that result from deliberate releases from process vents, systems upsets and accidents at a facility during a year, for each oil or gas exploration and development activity one of the following methods must be used:

                     (a)  method 1 under:

                              (i)  section 3.46AB (natural gas well completions); and    

                             (ii)  section 3.56B (emissions from system upsets, accidents and deliberate releases from process vents); and

                            (iii)  section 3.85B (cold process vents); and

                            (iv)  section 3.85P (well workovers);

                     (b)  method 4 under:

                              (i) for emissions of methane and carbon dioxide from natural gas well completions activities, well workovers, cold process vents and well blowouts—section 3.46B; and

                             (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.

 

Subdivision 3.3.2.3.1Fugitive emissions that result from deliberate releases from process vents, system upsets and accidents–well completions

3.46AB  Method 1—vented emissions from natural gas well completions 

             (1) Method 1 is:

                   Eij  = Σk   Qik   ×  EFijk  × Sij / SDij

where:

Eij is the fugitive emissions of gas type (j), being methane or carbon dioxide, vented from the natural gas exploration and development during the year measured in CO2‑e tonnes.

Σk is the total emissions of gas type (j), being methane or carbon dioxide, 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 natural gas exploration and development.

Qik is the total of the number of well completion events for equipment of type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the natural gas exploration and development.

Note:          Consistent with subsection 3.41(2), a well completion event should be reported for a single reporting year and not separately in two consecutive years.

EFijk is the emission factor for gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e per well completion event using equipment type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the natural gas exploration and development.

Sij  is the measured share of gas type (j), being methane or carbon dioxide, in the unprocessed natural gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.

SDij is the default share of gas type (j) in the unprocessed natural gas (i), for methane SD is 0.832 and for carbon dioxide SD is 0.0345.

             (2)  For EFijk mentioned in subsection (1), column 3 of an item in the following table specifies the emission factor for methane for an equipment of type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide for an equipment of type (k) specified in column 2 of that item:

Item

Equipment type (k)

Emission factor for gas type (j)

 

CH4

CO2

 

1

Well completion without hydraulic fracturing

5.5

1.1 × 10-2

tonnes CO2‑e per well completion event

2

Well completion with hydraulic fracturing and venting (no flaring)

1031

4.2

tonnes CO2‑e per well completion event

3

Well completion with hydraulic fracturing with capture (no flaring)

90.8

0.37

tonnes CO2‑e per well completion event

4

Well completion with hydraulic fracturing and flaring

136.6

0.56

tonnes CO2‑e per well completion event

3.46B  Method 4—vented emissions from natural gas well completions, well workovers, cold process vents and well blowouts

                   Method 4 is, for natural gas well completion activities, well workovers, cold process vents and well blowouts, as described in section 5.7.1 of the API Compendium.

Division 3.3.3Crude oil production

Subdivision 3.3.3.1Preliminary

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

                     (g)  activities at upgrading plants and associated gas reinjection systems.

             (2)  For paragraph (1)(e), untreated production includes:

                     (a)  well effluent; and

                     (b)  emulsion; and

                     (c)  oil shale; and

                     (d)  oil sands.

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

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;

                     (c)  method 3 under section 3.51.

Note:          There is no method 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.

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

             (1)  Method 1 is:

                  

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 total 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 1.6 × 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

1.12 × 10-6

2

Fixed roof tank

5.60 × 10-6

3

Floating tank

4.27 × 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

             (1)  Method 2 is:

                  

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 total 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 as determined under subsection (2), 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.

3.51  Method 3—crude oil production (non-flared) emissions of methane

             (1)  Method 3 is:

Eij = ∑k (EFijk × Tik × Nk)

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 total emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions released from each component type (k) listed in section 6.1.3 of the API Compendium, if the component type is used in the crude oil production.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per component-hour that passes through each component type (k) listed in section 6.1.3 of the API Compendium as determined under subsection (2), if the component is used in the crude oil production.

Tik is the average hours of operation during the year of the components of each component type (k) listed in section 6.1.3 of the API Compendium, if the component type is used in the crude oil production, measured in hours per year.

Nk is the total number of each component type (k) listed in section 6.1.3 of the API Compendium, if the component type is used in the crude oil production, measured in components.

             (2)  For EFijk, the emission factors for methane (j), as crude oil passes through a component type (k), are:

                     (a)  column 3 of an item in the following table, which specifies the emission factor for a component of type (k) specified in column 2 of that item:

 

Item

Component type (k)

Emission factor for gas type (j) (tonnes CO2‑e/component-hour)

 

CH4

1

Valves – heavy crude production

3.64 × 10-7

2

Valves – light crude production

3.70 × 10-5

3

Connectors – heavy crude production

2.23 × 10-7

4

Connectors – light crude production

4.59 × 10-6

5

Flanges – heavy crude production

6.13 × 10-7

6

Flanges – light crude production

2.15 × 10-6

7

Open-ended lines – heavy crude production

4.34 × 10-6

8

Open-ended lines – light crude production

3.39 × 10-5

9

Pump Seals – light crude production

8.90 × 10-6

10

Others – heavy crude production

1.96 × 10-6

11

Others – light crude production

2.10 × 10-4

Note:                            API Publication 4615 defines light crude as oil with an API gravity of 20 or more, and heavy crude as oil with an API gravity of less than 20.

                     (b)  if the manufacturer of the component supplies component‑specific emission factors for the component type—those factors.

Subdivision 3.3.3.3Crude oil production (flared)—fugitive emissions of carbon dioxide, methane and nitrous oxide

3.52  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 3.53;

                             (ii)  method 2 under section 3.54;

                            (iii)  method 3 under section 3.55; and

                     (b)  if estimating emissions of methane released—one of the following methods must be used:

                              (i)  method 1 under section 3.53;

                             (ii)  method 2A under section 3.54A; and

                     (c)  if estimating emissions of nitrous oxide released—one of the following methods must be used:

                              (i)  method 1 under section 3.53;

                             (ii)  method 2A under section 3.54A.

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.

3.53  Method 1—crude oil production (flared) emissions

             (1)  For subparagraph 3.52(a)(i), method 1 is:

                  

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.

Note:          This quantity includes all of the fuel type, not just hydrocarbons within the fuel type.

EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of the fuel type (