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Determinations/Other as amended, taking into account amendments up to National Greenhouse and Energy Reporting (Measurement) Amendment Determination 2011 (No. 1)
This Determination provides for the Minister to determine methods, or criteria for methods, for the measurement of greenhouse gas emissions, the production of energy and the consumption of energy.
Administered by: Climate Change and Energy Efficiency
Registered 19 Jul 2011
Start Date 01 Jul 2011
End Date 30 Jun 2012
Table of contents.
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Collapse Chapter 1 General 
Chapter 1 General
Collapse Part 1.1 Preliminary 
Part 1.1 Preliminary
1.1 Name of Determination [see Note 1]
1.2 Commencement
Expand Division 1.1.1 Overview 
Division 1.1.1 Overview
Expand Division 1.1.2 Definitions and interpretation 
Division 1.1.2 Definitions and interpretation
Expand Part 1.2 General 
Part 1.2 General
Expand Part 1.3 Method 4 — Direct measurement of emissions 
Part 1.3 Method 4 — Direct measurement of emissions
Expand Chapter 2 Fuel combustion 
Chapter 2 Fuel combustion
Expand Chapter 3 Fugitive emissions 
Chapter 3 Fugitive emissions
Expand Chapter 4 Industrial processes emissions 
Chapter 4 Industrial processes emissions
Expand Chapter 5 Waste 
Chapter 5 Waste
Expand Chapter 6 Energy 
Chapter 6 Energy
Expand Chapter 7 Scope 2 emissions 
Chapter 7 Scope 2 emissions
Expand Chapter 8 Assessment of uncertainty 
Chapter 8 Assessment of uncertainty

National Greenhouse and Energy Reporting (Measurement) Determination 2008

as amended

made under subsection 10 (3) of the

This compilation was prepared on 1 July 2011
taking into account amendments up to National Greenhouse and Energy Reporting (Measurement) Amendment Determination 2011 (No. 1)

The text of any of those amendments not in force
on that date is appended in the Notes section

Prepared by the Office of Legislative Drafting and Publishing,
Attorney-General’s Department, Canberra

 


Contents

Chapter 1             General                                                                                              

Part 1.1                      Preliminary                                                                                     

                      1.1      Name of Determination [see Note 1]                                                   19

                      1.2      Commencement                                                                                19

Division 1.1.1             Overview                                                                                            

                      1.3      Overview — general                                                                          19

                      1.4      Overview — methods for measurement                                              20

                      1.5      Overview — energy                                                                           20

                      1.6      Overview — scope 2 emissions                                                         20

                      1.7      Overview — assessment of uncertainty                                              20

Division 1.1.2             Definitions and interpretation                                                             

                      1.8      Definitions                                                                                        20

                      1.9      Interpretation                                                                                     26

                    1.10      Meaning of source                                                                            27

Part 1.2                      General                                                                                            

                    1.11      Purpose of Part                                                                                29

Division 1.2.1             Measurement and standards                                                               

                    1.12      Measurement of emissions                                                                29

                    1.13      General principles for measuring emissions                                        29

                    1.14      Assessment of uncertainty                                                                29

                    1.15      Units of measurement                                                                       29

                    1.16      Rounding of amounts                                                                        30

                    1.17      Status of standards                                                                          30

Division 1.2.2             Methods                                                                                             

                    1.18      Method to be used for a source                                                         30

                    1.19      Temporary unavailability of method                                                    31

Division 1.2.3             Requirements in relation to carbon capture and storage                     

                  1.19A      Meaning of captured for permanent storage                                         31

                  1.19B      Deducting carbon dioxide that is captured for permanent storage       32

                  1.19C      Capture from facility with multiple sources jointly generated                32

                 1.19D      Capture from a source where multiple fuels consumed                        33

                  1.19E      Measure of quantity of carbon dioxide captured                                 33

                  1.19F      Volume of carbon dioxide stream — criterion A                                  34

                 1.19G      Volume of carbon dioxide stream — criterion AAA                             34

                  1.19H      Volumetric measurement — carbon dioxide stream not super‑compressed    35

                   1.19I      Volumetric measurement — supercompressed carbon dioxide stream 36

                  1.19J      Gas measuring equipment — requirements                                         36

                  1.19K      Flow devices — requirements                                                            37

                  1.19L      Flow computers — requirements                                                        37

                 1.19M      Gas chromatographs                                                                         38

                  1.19N      Volume of carbon dioxide stream — criterion BBB                             38

Part 1.3                      Method 4 — Direct measurement of emissions                   

Division 1.3.1             Preliminary                                                                                        

                    1.20      Overview                                                                                          39

Division 1.3.2             Operation of method 4 (CEM)                                                             

Subdivision 1.3.2.1      Method 4 (CEM)                                                                                                                

                    1.21      Method 4 (CEM) — estimation of emissions                                       39

Subdivision 1.3.2.2      Method 4 (CEM) — use of equipment                                                                         

                    1.22      Overview                                                                                          40

                    1.23      Selection of sampling positions for CEM equipment                           40

                    1.24      Measurement of flow rates by CEM                                                   41

                    1.25      Measurement of gas concentrations by CEM                                      41

                    1.26      Frequency of measurement by CEM                                                  41

Division 1.3.3             Operation of method 4 (PEM)                                                             

Subdivision 1.3.3.1      Method 4 (PEM)                                                                                                                

                    1.27      Method 4 (PEM) — estimation of emissions                                       42

                    1.28      Calculation of emission factors                                                          42

Subdivision 1.3.3.2      Method 4 (PEM) — use of equipment                                                                          

                    1.29      Overview                                                                                          43

                    1.30      Selection of sampling positions for PEM equipment                           43

                    1.31      Measurement of flow rates by PEM equipment                                   43

                    1.32      Measurement of gas concentrations by PEM                                      44

                    1.33      Representative data for PEM                                                             44

Division 1.3.4             Performance characteristics of equipment                                          

                    1.34      Performance characteristics of CEM or PEM equipment                     44

Chapter 2             Fuel combustion                                                                             

Part 2.1                      Preliminary                                                                                     

                      2.1      Outline of Chapter                                                                             45

Part 2.2                      Emissions released from the combustion of solid fuels   

Division 2.2.1             Preliminary                                                                                        

                      2.2      Application                                                                                       46

                      2.3      Available methods for estimating emissions of carbon dioxide, methane and nitrous oxide    46

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

                      2.4      Method 1 — solid fuels                                                                     47

Division 2.2.3             Method 2 — emissions from solid fuels                                             

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

                      2.5      Method 2 — estimating carbon dioxide using oxidation factor             47

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

                      2.6      Method 2 — estimating carbon dioxide using an estimated oxidation factor  49

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

                      2.7      General requirements for sampling solid fuels                                    50

                      2.8      General requirements for analysis of solid fuels                                  51

                      2.9      Requirements for analysis of furnace ash and fly ash                         51

                    2.10      Requirements for sampling for carbon in furnace ash                          51

                    2.11      Sampling for carbon in fly ash                                                           52

Division 2.2.4             Method 3 — Solid fuels                                                                      

                    2.12      Method 3 — solid fuels using oxidation factor or an estimated oxidation factor         52

Division 2.2.5             Measurement of consumption of solid fuels                                       

                    2.13      Purpose of Division                                                                          54

                    2.14      Criteria for measurement                                                                    54

                    2.15      Indirect measurement at point of consumption — criterion AA             55

                    2.16      Direct measurement at point of consumption — criterion AAA             55

                    2.17      Simplified consumption measurements — criterion BBB                     56

Part 2.3                      Emissions released from the combustion of gaseous fuels  

Division 2.3.1             Preliminary                                                                                        

                    2.18      Application                                                                                       57

                    2.19      Available methods                                                                            57

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

                    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 

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

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

                    2.22      Calculation of emission factors from combustion of gaseous fuel       59

Subdivision 2.3.3.2      Sampling and analysis                                                                                                    

                    2.23      General requirements for sampling under method 2                             61

                    2.24      Standards for analysing samples of gaseous fuels                             61

                    2.25      Frequency of analysis                                                                       65

Division 2.3.4             Method 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     66

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

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

Division 2.3.6             Measurement of quantity of gaseous fuels                                          

                    2.28      Purpose of Division                                                                          68

                    2.29      Criteria for measurement                                                                    68

                    2.30      Indirect measurement at point of consumption — criterion AA             69

                    2.31      Direct measurement at point of consumption — criterion AAA             69

                    2.32      Volumetric measurement — general                                                   70

                    2.33      Volumetric measurement — super‑compressed gases                        71

                    2.34      Gas measuring equipment — requirements                                         71

                    2.35      Flow devices — requirements                                                            72

                    2.36      Flow computers — requirements                                                        72

                    2.37      Gas chromatographs                                                                         73

                    2.38      Simplified consumption measurements — criterion BBB                     73

Part 2.4                      Emissions released from the combustion of liquid fuels  

Division 2.4.1             Preliminary                                                                                        

                    2.39      Application                                                                                       74

                  2.39A      Definition of petroleum based oils  for Part 2.4                                    74

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

                    2.40      Available methods                                                                            74

Subdivision 2.4.1.2      Liquid fuels — petroleum based oils and greases                                                  

                  2.40A      Available methods                                                                            75

Division 2.4.2             Method 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 75

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

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

                    2.42      Method 2 — emissions of carbon dioxide from the combustion of liquid fuels          76

                    2.43      Calculation of emission factors from combustion of liquid fuel           77

Subdivision 2.4.3.2      Sampling and analysis                                                                                                    

                    2.44      General requirements for sampling under method 2                             77

                    2.45      Standards for analysing samples of liquid fuels                                 78

                    2.46      Frequency of analysis                                                                       80

Division 2.4.4             Method 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           81

Division 2.4.5             Method 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     83

Division 2.4.5A          Methods 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      83

                  2.48B      Method 2 — estimating emissions of carbon dioxide using an estimated oxidation factor      84

                  2.48C      Method 3 — estimating emissions of carbon dioxide using an estimated oxidation factor      84

Division 2.4.6             Measurement of quantity of liquid fuels                                              

                    2.49      Purpose of Division                                                                          85

                    2.50      Criteria for measurement                                                                    85

                    2.51      Indirect measurement at point of consumption — criterion AA             85

                    2.52      Direct measurement at point of consumption — criterion AAA             86

                    2.53      Simplified consumption measurements — criterion BBB                     86

Part 2.5                      Emissions released from fuel use by certain industries    

                    2.54      Application                                                                                       87

Division 2.5.1             Energy — petroleum refining                                                             

                    2.55      Application                                                                                       87

                    2.56      Methods                                                                                           87

Division 2.5.2             Energy — manufacture of solid fuels                                                  

                    2.57      Application                                                                                       87

                    2.58      Methods                                                                                           87

Division 2.5.3             Energy — petrochemical production                                                  

                    2.59      Application                                                                                       91

                    2.60      Available methods                                                                            91

                    2.61      Method 1 — petrochemical production                                               91

                    2.62      Method 2 — petrochemical production                                               93

                    2.63      Method 3— petrochemical production                                                94

Part 2.6                      Blended fuels                                                                                

                    2.64      Purpose                                                                                           96

                    2.65      Application                                                                                       96

                    2.66      Blended solid fuels                                                                           96

                    2.67      Blended liquid fuels                                                                          96

Part 2.7                      Estimation of energy for certain purposes                            

                    2.68      Amount of fuel consumed without combustion                                   97

                    2.69      Apportionment of fuel consumed as carbon reductant or feedstock and energy        97

                    2.70      Amount of energy consumed in a cogeneration process                     98

                    2.71      Apportionment of energy consumed for electricity, transport and for stationary energy          98

Chapter 3             Fugitive emissions                                                                         

Part 3.1                      Preliminary                                                                                     

                      3.1      Outline of Chapter                                                                             99

Part 3.2                      Coal mining — fugitive emissions                                           

Division 3.2.1             Preliminary                                                                                        

                      3.2      Outline of Part                                                                                 100

Division 3.2.2             Underground mines                                                                           

Subdivision 3.2.2.1      Preliminary                                                                                                                        

                      3.3      Application                                                                                     100

                      3.4      Available methods                                                                           100

Subdivision 3.2.2.2      Fugitive emissions from extraction of coal                                                              

                      3.5      Method 1 — extraction of coal                                                         101

                      3.6      Method 4 — extraction of coal                                                         102

                      3.7      Estimation of emissions                                                                  103

                      3.8      Overview — use of equipment                                                         103

                      3.9      Selection of sampling positions for PEM                                         103

                    3.10      Measurement of volumetric flow rates by PEM                                 103

                    3.11      Measurement of concentrations by PEM                                          104

                    3.12      Representative data for PEM                                                           104

                    3.13      Performance characteristics of equipment                                        104

Subdivision 3.2.2.3      Emissions released from coal mine waste gas flared                                          

                    3.14      Method 1 — coal mine waste gas flared                                           104

                    3.15      Method 2 — coal mine waste gas flared                                           105

                    3.16      Method 3 — coal mine waste gas flared                                           105

Subdivision 3.2.2.4      Fugitive emissions from post‑mining activities                                                       

                    3.17      Method 1 — post‑mining activities related to gassy mines                 105

Division 3.2.3             Open cut mines                                                                                  

Subdivision 3.2.3.1      Preliminary                                                                                                                        

                    3.18      Application                                                                                     106

                    3.19      Available methods                                                                           106

Subdivision 3.2.3.2      Fugitive emissions from extraction of coal                                                              

                    3.20      Method 1 — extraction of coal                                                         107

                    3.21      Method 2 — extraction of coal                                                         107

                    3.22      Total gas contained by gas bearing strata                                        108

                    3.23      Estimate of proportion of gas content released below pit floor          109

                    3.24      General requirements for sampling                                                   109

                    3.25      General requirements for analysis of gas and gas bearing strata        110

                    3.26      Method 3 — extraction of coal                                                         110

Subdivision 3.2.3.3      Emissions released from coal mine waste gas flared                                          

                    3.27      Method 1 — coal mine waste gas flared                                           110

                    3.28      Method 2 — coal mine waste gas flared                                           110

                    3.29      Method 3 — coal mine waste gas flared                                           110

Division 3.2.4             Decommissioned underground mines                                                

Subdivision 3.2.4.1      Preliminary                                                                                                                        

                    3.30      Application                                                                                     111

                    3.31      Available methods                                                                           111

Subdivision 3.2.4.2      Fugitive emissions from decommissioned underground mines                         

                    3.32      Method 1 — decommissioned underground mines                            112

                    3.33      Emission factor for decommissioned underground mines                 112

                    3.34      Measurement of proportion of mine that is flooded                           113

                    3.35      Water flow into mine                                                                        113

                    3.36      Size of mine void volume                                                                114

                    3.37      Method 4 — decommissioned underground mines                            114

Subdivision 3.2.4.3      Fugitive emissions from coal mine waste gas flared                                            

                    3.38      Method 1 — coal mine waste gas flared                                           114

                    3.39      Method 2 — coal mine waste gas flared                                           114

                    3.40      Method 3 — coal mine waste gas flared                                           114

Part 3.3                      Oil and natural gas — fugitive emissions                              

Division 3.3.1             Preliminary                                                                                        

                  3.40A      Definition of natural gas for Part 3.3                                                 115

                    3.41      Outline of Part                                                                                 115

Division 3.3.2             Oil or gas exploration                                                                         

Subdivision 3.3.2.1      Preliminary                                                                                                                        

                    3.42      Application                                                                                     115

Subdivision 3.3.2.2      Oil or gas exploration (flared) emissions                                                                  

                    3.43      Available methods                                                                           116

                    3.44      Method 1 — oil or gas exploration                                                   116

                    3.45      Method 2 — oil or gas exploration                                                   117

                    3.46      Method 3 — oil or gas exploration                                                   117

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

                  3.46A      Available methods                                                                           118

Division 3.3.3             Crude oil production                                                                          

Subdivision 3.3.3.1      Preliminary                                                                                                                        

                    3.47      Application                                                                                     118

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

                    3.48      Available methods                                                                           119

                    3.49      Method 1 — crude oil production (non‑flared) emissions of methane 119

                    3.50      Method 2 — crude oil production (non‑flared) emissions of methane 120

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

                    3.51      Available methods                                                                           121

                    3.52      Method 1 — crude oil production (flared) emissions                          121

                    3.53      Method 2 — crude oil production                                                     122

                    3.54      Method 3 — crude oil production                                                     122

                    3.55      Method 1 — crude oil production (flared) emissions of methane and nitrous oxide    123

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

                  3.56A      Available methods                                                                           123

Division 3.3.4             Crude oil transport                                                                             

                    3.57      Application                                                                                     123

                    3.58      Available methods                                                                           123

                    3.59      Method 1 — crude oil transport                                                        123

                    3.60      Method 2 — fugitive emissions from crude oil transport                    124

Division 3.3.5             Crude oil refining                                                                               

                    3.61      Application                                                                                     124

                    3.62      Available methods                                                                           125

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

                    3.63      Method 1 — crude oil refining and storage tanks for crude oil           126

                    3.64      Method 2 — crude oil refining and storage tanks for crude oil           126

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

                    3.65      Method 1 — fugitive emissions from deliberate releases from process vents, system upsets and accidents                                                                                        127

                    3.66      Method 4 — deliberate releases from process vents, system upsets and accidents   127

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

                    3.67      Method 1 — gas flared from crude oil refining                                  127

                    3.68      Method 2 — gas flared from crude oil refining                                  128

                    3.69      Method 3 — gas flared from crude oil refining                                  128

Division 3.3.6             Natural gas production or processing, other than emissions that are vented or flared      

                    3.70      Application                                                                                     129

                    3.71      Available methods                                                                           129

                    3.72      Method 1 — natural gas production and processing (other than emissions that are vented or flared)                                                                                             129

                    3.73      Method 2— natural gas production and processing (other than venting and flaring)    130

Division 3.3.7             Natural gas transmission                                                                    

                    3.74      Application                                                                                     131

                    3.75      Available methods                                                                           131

                    3.76      Method 1 — natural gas transmission                                               131

                    3.77      Method 2 — natural gas transmission                                               132

Division 3.3.8             Natural gas distribution                                                                      

                    3.78      Application                                                                                     132

                    3.79      Available methods                                                                           133

                    3.80      Method 1 — natural gas distribution                                                 133

                    3.81      Method 2 — natural gas distribution                                                 134

Division 3.3.9             Natural gas production or processing (emissions that are vented or flared)          

                    3.82      Application                                                                                     135

                    3.83      Available methods                                                                           135

Subdivision 3.3.9.1      Fugitive emissions that result from deliberate releases from process vents, system upsets and accidents                                                                                                                           

                    3.84      Method 1 — emissions from system upsets, accidents and deliberate releases from process vents                                                                                              136

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

                    3.85      Method 1 — gas flared from natural gas production and processing  136

                    3.86      Method 2 — gas flared from natural gas production and processing  137

                    3.87      Method 3 — gas flared from natural gas production and processing  138

Part 3.4                      Carbon capture and storage — fugitive emissions            

Division 3.4.1             Preliminary                                                                                        

                    3.88      Outline of Part                                                                                 139

Division 3.4.2             Transport of captured carbon dioxide                                                 

Subdivision 3.4.2.1      Preliminary                                                                                                                        

                    3.89      Application                                                                                     139

                    3.90      Available methods                                                                           139

Subdivision 3.4.2.2      Emissions from transport of carbon dioxide captured for permanent storage involving transfer    

                    3.91      Method 1 — emissions from transport of carbon dioxide involving transfer   140

Subdivision 3.4.2.2      Emissions from transport of carbon dioxide captured for permanent storage not involving transfer                                                                                                                                              

                    3.92      Method 1 — emissions from transport of carbon dioxide not involving transfer         140

Chapter 4             Industrial processes emissions                                                  

Part 4.1                      Preliminary                                                                                     

                      4.1      Outline of Chapter                                                                           142

Part 4.2                      Industrial processes — mineral products                             

Division 4.2.1             Cement clinker production                                                                 

                      4.2      Application                                                                                     143

                      4.3      Available methods                                                                           143

                      4.4      Method 1 — cement clinker production                                             143

                      4.5      Method 2 — cement clinker production                                             144

                      4.6      General requirements for sampling cement clinker                             145

                      4.7      General requirements for analysing cement clinker                            145

                      4.8      Method 3 — cement clinker production                                             145

                      4.9      General requirements for sampling carbonates                                  147

                    4.10      General requirements for analysing carbonates                                 147

Division 4.2.2             Lime production                                                                                 

                    4.11      Application                                                                                     147

                    4.12      Available methods                                                                           147

                    4.13      Method 1 — lime production                                                            148

                    4.14      Method 2 — lime production                                                            148

                    4.15      General requirements for sampling                                                   149

                    4.16      General requirements for analysis of lime                                         150

                    4.17      Method 3 — lime production                                                            150

                    4.18      General requirements for sampling                                                   151

                    4.19      General requirements for analysis of carbonates                               151

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

                    4.20      Application                                                                                     151

                    4.21      Available methods                                                                           152

                    4.22      Method 1 — product other than cement clinker, lime or soda ash [see Note 2]           152

                    4.23      Method 3 — product other than cement clinker, lime or soda ash       153

                    4.24      General requirements for sampling carbonates                                  154

                    4.25      General requirements for analysis of carbonates                               155

Division 4.2.4             Soda ash use and production                                                             

                    4.26      Application                                                                                     155

                    4.27      Outline of Division                                                                           155

Subdivision 4.2.4.1      Soda ash use                                                                                                                    

                    4.28      Available methods                                                                           155

                    4.29      Method 1 — use of soda ash                                                           156

Subdivision 4.2.4.2      Soda ash production                                                                                                       

                    4.30      Available methods                                                                           156

                    4.31      Method 1 — production of soda ash                                                156

                    4.32      Method 2 — production of soda ash                                                158

                    4.33      Method 3 — production of soda ash                                                161

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

                    4.34      Purpose of Division                                                                        161

                    4.35      Criteria for measurement                                                                  162

                    4.36      Indirect measurement at point of consumption or production — criterion AA  162

                    4.37      Direct measurement at point of consumption or production — criterion AAA 163

                    4.38      Acquisition or use or disposal without commercial transaction — criterion BBB         163

                    4.39      Units of measurement                                                                      163

Part 4.3                      Industrial processes — chemical industry                            

Division 4.3.1             Ammonia production                                                                         

                    4.40      Application                                                                                     164

                    4.41      Available methods                                                                           164

                    4.42      Method 1 — ammonia production                                                    164

                    4.43      Method 2 — ammonia production                                                    165

                    4.44      Method 3 — ammonia production                                                    165

Division 4.3.2             Nitric acid production                                                                         

                    4.45      Application                                                                                     166

                    4.46      Available methods                                                                           166

                    4.47      Method 1 — nitric acid production                                                    166

                    4.48      Method 2 — nitric acid production                                                    167

Division 4.3.3             Adipic acid production                                                                       

                    4.49      Application                                                                                     167

                    4.50      Available methods                                                                           167

Division 4.3.4             Carbide production                                                                            

                    4.51      Application                                                                                     167

                    4.52      Available methods                                                                           167

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

                    4.53      Application                                                                                     168

                    4.54      Available methods                                                                           168

                    4.55      Method 1 — chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode                                                               168

                    4.56      Method 2 — chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode                                                               170

                    4.57      Method 3 — chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode                                                               171

Part 4.4                      Industrial processes — metal industry                                   

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

                    4.63      Application                                                                                     172

                    4.64      Purpose of Division                                                                        172

                    4.65      Available methods for production of a metal from an integrated metalworks  172

                    4.66      Method 1 — production of a metal from an integrated metalworks     173

                    4.67      Method 2 — production of a metal from an integrated metalworks     174

                    4.68      Method 3 — production of a metal from an integrated metalworks     175

Division 4.4.2             Ferroalloys production                                                                       

                    4.69      Application                                                                                     176

                    4.70      Available methods                                                                           176

                    4.71      Method 1 — ferroalloy metal                                                            177

                    4.72      Method 2 — ferroalloy metal                                                            177

                    4.73      Method 3 — ferroalloy metals                                                          177

Division 4.4.3             Aluminium production (carbon dioxide emissions)                            

                    4.74      Application                                                                                     178

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

                    4.75      Available methods                                                                           178

                    4.76      Method 1 — aluminium (carbon anode consumption)                        178

                    4.77      Method 2 — aluminium (carbon anode consumption)                        179

                    4.78      Method 3 — aluminium (carbon anode consumption)                        179

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

                    4.79      Available methods                                                                           180

                    4.80      Method 1 — aluminium (baked carbon anode production)                 180

                    4.81      Method 2 — aluminium (baked carbon anode production)                 181

                    4.82      Method 3 — aluminium (baked carbon anode production)                 181

Division 4.4.4             Aluminium production (perfluoronated carbon compound emissions)     

                    4.83      Application                                                                                     181

Subdivision 4.4.4.1      Aluminium — emissions of tetrafluoromethane in aluminium production        

                    4.84      Available methods                                                                           181

                    4.85      Method 1 — aluminium (tetrafluoromethane)                                     182

                    4.86      Method 2 — aluminium (tetrafluoromethane)                                     182

                    4.87      Method 3 — aluminium (tetrafluoromethane)                                     182

Subdivision 4.4.4.2      Aluminium — emissions of hexafluoroethane in aluminium production           

                    4.88      Available methods                                                                           182

                    4.89      Method 1 — aluminium production (hexafluoroethane)                       183

                    4.90      Method 2 — aluminium production (hexafluoroethane)                       183

                    4.91      Method 3 — aluminium production (hexafluoroethane)                       183

Division 4.4.5             Other metals production                                                                     

                    4.92      Application                                                                                     183

                    4.93      Available methods                                                                           183

                    4.94      Method 1 — other metals                                                                 184

                    4.95      Method 2 — other metals                                                                 184

                    4.96      Method 3 — other metals                                                                 185

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

                    4.97      Application                                                                                     186

                    4.98      Available method                                                                            186

                    4.99      Meaning of hydrofluorocarbons                                                         186

                  4.100      Meaning of synthetic gas generating activities                                   186

                  4.101      Reporting threshold                                                                         187

                  4.102      Method 1                                                                                        187

                  4.103      Method 2                                                                                        188

                  4.104      Method 3                                                                                        188

Chapter 5             Waste                                                                                                 

Part 5.1                      Preliminary                                                                                     

                      5.1      Outline of Chapter                                                                           189

Part 5.2                      Solid waste disposal on land                                                    

Division 5.2.1             Preliminary                                                                                        

                      5.2      Application                                                                                     190

                      5.3      Available methods                                                                           190

Division 5.2.2             Method 1 — emissions of methane released from landfills                 

                      5.4      Method 1 — methane released from landfills (other than from flaring of methane)      191

                      5.5      Criteria for estimating tonnage of total solid waste                            192

                      5.6      Criterion A                                                                                       193

                      5.7      Criterion AAA                                                                                  193

                      5.8      Criterion BBB                                                                                  193

                      5.9      Composition of solid waste                                                             193

                    5.10      Waste streams                                                                                193

                    5.11      Waste mix types                                                                             194

                  5.11A      Certain waste to be deducted from waste received at landfill when estimating waste disposed in landfill                                                                                            197

                    5.12      Degradable organic carbon content                                                  197

                    5.13      Opening stock of degradable organic carbon                                   198

                    5.14      Methane generation constants — (k values)                                      199

                  5.14A      Fraction of degradable organic carbon dissimilated (DOCF)               199

Division 5.2.3             Method 2 — emissions of methane released from landfills                 

Subdivision 5.2.3.1      methane released from landfills                                                                                  

                    5.15      Method 2 — methane released from landfills (other than from flaring of methane)      200

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

                    5.16      Procedures for selecting representative zone                                    201

                    5.17      Preparation of site plan                                                                   201

                  5.17A      Representative zone                                                                        201

                  5.17B      Independent verification                                                                   202

                  5.17C      Estimation of waste and degradable organic content in representative zone  202

                 5.17D      Estimation of gas collected at the representative zone                      202

                  5.17E      Estimating methane generated but not collected in the representative zone    203

                  5.17F      Walkover survey                                                                              203

                 5.17G      Installation of flux boxes in representative zone                                203

                  5.17H      Flux box measurements                                                                   204

                   5.17I      When flux box measurements must be taken                                    205

                  5.17J      Restrictions on taking flux box measurements                                  205

                  5.17K      Frequency of measurement                                                              206

                  5.17L      Calculating the methane generation constant (k)                                206

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

                    5.18      Method 3 — methane released from solid waste at landfills (other than from flaring of methane)                                                                                                      207

Division 5.2.5             Solid waste at landfills — Flaring                                                       

                    5.19      Method 1 — landfill gas flared                                                         207

                    5.20      Method 2 — landfill gas flared                                                         208

                    5.21      Method 3 — landfill gas flared                                                         208

Division 5.2.6             Biological treatment of solid waste                                                     

                    5.22      Method 1 — biological treatment of solid waste at the landfill            208

Part 5.3                      Wastewater handling (domestic and commercial)              

Division 5.3.1             Preliminary                                                                                        

                    5.23      Application                                                                                     209

                    5.24      Available methods                                                                           209

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

                    5.25      Method 1 — methane released from wastewater handling (domestic and commercial)            210

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

                    5.26      Method 2 — methane released from wastewater handling (domestic and commercial)            213

                    5.27      General requirements for sampling under method 2                           213

                    5.28      Standards for analysis                                                                     214

                    5.29      Frequency of sampling and analysis                                                214

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

                    5.30      Method 3 — methane released from wastewater handling (domestic and commercial)            214

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

                    5.31      Method 1 — nitrous oxide released from wastewater handling (domestic and commercial)     214

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

                    5.32      Method 2 — nitrous oxide released from wastewater handling (domestic and commercial)     216

                    5.33      General requirements for sampling under method 2                           217

                    5.34      Standards for analysis                                                                     217

                    5.35      Frequency of sampling and analysis                                                217

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

                    5.36      Method 3 — nitrous oxide released from wastewater handling (domestic and commercial)     217

Division 5.3.8             Wastewater handling (domestic and commercial) — Flaring               

                    5.37      Method 1 — Flaring of methane in sludge biogas from wastewater handling (domestic and commercial)                                                                                    218

                    5.38      Method 2 — flaring of methane in sludge biogas                              218

                    5.39      Method 3 — flaring of methane in sludge biogas                              218

Part 5.4                      Wastewater handling (industrial)                                             

Division 5.4.1             Preliminary                                                                                        

                    5.40      Application                                                                                    219

                    5.41      Available methods                                                                           219

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

                    5.42      Method 1 — methane released from wastewater handling (industrial)  220

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

                    5.43      Method 2 — methane released from wastewater handling (industrial)  224

                    5.44      General requirements for sampling under method 2                           224

                    5.45      Standards for analysis                                                                     224

                    5.46      Frequency of sampling and analysis                                                225

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

                    5.47      Method 3 — methane released from wastewater handling (industrial)  225

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

                    5.48      Method 1 — flaring of methane in sludge biogas                              225

                    5.49      Method 2 — flaring of methane in sludge biogas                              226

                    5.50      Method 3 — flaring of methane in sludge biogas                              226

Part 5.5                      Waste incineration                                                                       

                    5.51      Application                                                                                     227

                    5.52      Available methods — emissions of carbon dioxide from waste incineration   227

                    5.53      Method 1 — emissions of carbon dioxide released from waste incineration   227

Chapter 6             Energy                                                                                               

Part 6.1                      Production                                                                                     

                      6.1      Purpose                                                                                          229

                      6.2      Quantity of energy produced                                                           229

                      6.3      Energy content of fuel produced                                                      230

Part 6.2                      Consumption                                                                                

                      6.4      Purpose                                                                                          231

                      6.5      Energy content of energy consumed                                                231

Chapter 7             Scope 2 emissions                                                                         

                      7.1      Outline of Chapter                                                                           233

                      7.2      Method 1 — purchase of electricity from main electricity grid in a State or Territory    233

                      7.3      Method 1 — purchase of electricity from other sources                     234

Chapter 8             Assessment of uncertainty                                                          

Part 8.1                      Preliminary                                                                                     

                      8.1      Outline of Chapter                                                                           235

Part 8.2                      General rules for assessing uncertainty                                

                      8.2      Range for emission estimates                                                          236

                      8.3      Uncertainty to be assessed having regard to all facilities                   236

Part 8.3                      How to assess uncertainty when using method 1              

                      8.4      Purpose of Part                                                                              237

                      8.5      General rules about uncertainty estimates for emissions estimates using method 1    237

                      8.6      Assessment of uncertainty for estimates of carbon dioxide emissions from combustion of fuels                                                                                                      237

                      8.7      Assessment of uncertainty for estimates of methane and nitrous oxide emissions from combustion of fuels                                                                        240

                      8.8      Assessment of uncertainty for estimates of fugitive emissions          241

                      8.9      Assessment of uncertainty for estimates of emissions from industrial process sources         242

                    8.10      Assessment of uncertainty for estimates of emissions from waste    243

                    8.11      Assessing uncertainty of emissions estimates for a source by aggregating parameter uncertainties                                                                                    243

                    8.12      Assessing uncertainty of emissions estimates for a facility               244

                    8.13      Assessing uncertainty of emissions estimates for a registered corporation    244

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

                    8.14      Purpose of Part                                                                              245

                    8.15      Rules for assessment of uncertainty using method 2, 3 or 4              245

Schedule 1                  Energy content factors and emission factors                                  246

Part 1                             Fuel combustion — solid fuels and certain coal‑based products        246

Part 2                             Fuel combustion — gaseous fuels                                                   247

Part 3                             Fuel combustion — liquid fuels and certain petroleum‑based products for stationary energy purposes                                                                                        248

Part 4                             Fuel combustion — fuels for transport energy purposes                   249

Part 5                             Consumption of fuels for non‑energy product purposes                    251

Part 6                             Indirect (scope 2) emission factors from consumption of purchased electricity from grid       252

Part 7                             Fuel combustion — other fuels                                                        252

Schedule 2                  Standards and frequency for analysing energy content factor etc for solid fuels    253

Schedule 3                  Carbon content factors                                                                   257

Part 1                             Solid fuels and certain coal‑based products                                     257

Part 2                             Gaseous fuels                                                                                 258

Part 3                             Liquid fuels and certain petroleum‑based products                           258

Part 4                             Petrochemical feedstocks and products                                           259

Part 5                             Carbonates                                                                                     260

Notes                                                                                                                            261

 


Chapter 1    General

Part 1.1              Preliminary

1.1           Name of Determination [see Note 1]

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

1.2           Commencement

                This Determination commences on 1 July 2008.

Division 1.1.1        Overview

1.3           Overview — general

         (1)   This Determination is made under subsection 10 (3) of the National Greenhouse and Energy Reporting Act 2007. It provides for the measurement of the following arising from the operation of facilities:

                (a)    greenhouse gas emissions;

               (b)    the production of energy;

                (c)    the consumption of energy.

Note   For the meaning of facility, see section 9 of the Act.

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

Note   Scope 1 and scope 2 emissions are defined in subregulation 2.23 (2) 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 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)   Generally:

                (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 a facility specific method using industry practices for sampling and Australian or equivalent standards for analysis; and

                (c)    method 3 is 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.

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 1.1.2        Definitions 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.

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.

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 known as the Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry, 2004, published by the American Petroleum Institute.

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, 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, including crude oil condensates, 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.

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.

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 permanent storage, in relation to carbon dioxide, has the meaning given by section 1.19A.

carbon dioxide stream means a stream of gaseous substances that consists overwhelmingly of carbon dioxide that is captured for permanent storage.

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.

CO2‑e means carbon dioxide equivalence.

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 condensates 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.

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.

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.

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

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 the release of emissions that occur during the extraction, processing and delivery of fossil fuels.

gas bearing strata is a layer of rock that contains quantities of gas.

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.

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.

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.

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.

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).

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

municipal materials has the meaning given by the Regulations.

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 distribution is distribution of natural gas through low‑pressure pipelines with pressure of 1 050 kilopascals or less.

natural gas liquids has the meaning given by the Regulations.

natural gas transmission is transmission of natural gas through high‑pressure pipelines with pressure greater than 1 050 kilopascals.

non‑gassy mine means an underground mine that has less than 0.1% methane in the mine’s return ventilation.

open cut mine means a mine in which the overburden is removed from coal seams to allow extraction by mining that is not underground mining.

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.

post‑mining activities, in relation to a mine, is the handling, stockpiling, processing and transportation of coal extracted from the mine.

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.

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 means a fuel that is used for its chemical properties other than its property as a source of 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 meaning given by paragraph 2.23 (2) (a) of the Regulations.

scope 2 emissions has the meaning given by paragraph 2.23 (2) (b) of the Regulations.

Note   Regulation 2.23 provides that emissions of greenhouse gases, in relation to a facility, means releases of greenhouse gases as a result of:

(a)   activities that constitute the facility (scope 1 emissions); and

(b)   activities that generate electricity, heating, cooling or steam that are consumed by the facility but do not form part of the facility (scope 2 emissions).

sludge biogas means the gas derived from the anaerobic fermentation of biomass and solid waste from sewage and animal slurries and combusted to produce heat and electricity.

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.

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.

synthetic gas generating activities has the meaning given by subsections 4.100 (1) and (2).

technical guidelines means the document published by the Department and known as the National Greenhouse Energy and Reporting (Measurement) Technical Guidelines 2009.

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.

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 subregulation 2.23 (4) of the Regulations)

·      emission of greenhouse gas (see also subregulation 2.23 (2) of the Regulations)

·      energy

·      facility

·      group

·      greenhouse gas

·      industry sector

·      operational control

·      production of energy (see also subregulation 2.23 (3) of the Regulations)

·      registered corporation.

1.9           Interpretation

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

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

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

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

         (4)   In this Determination, a reference to a standard, instrument or other writing (other than a Commonwealth Act or Regulations) however described, is a reference to that standard, instrument or other writing as in force on 1 July 2010.

1.10        Meaning of source

         (1)   A thing mentioned in column 3 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

2E

 

Crude oil production

2F

 

Crude oil transport

2G

 

Crude oil refining

2H

 

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

2I

 

Natural gas transmission

2J

 

Natural gas distribution

2K

 

Natural gas production or processing — flaring

2L

 

Natural gas production or processing — venting

2M

 

Carbon capture and storage

3

Industrial processes

 

3A

 

Cement clinker production

3B

 

Lime production

3C

 

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

3D

 

Soda ash use

3E

 

Soda ash production

3F

 

Ammonia production

3G

 

Nitric acid production

3H

 

Adipic acid production

3I

 

Carbide production

3J

 

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

3K

 

Iron, steel or other metal production using an integrated metalworks

3L

 

Ferroalloys production

3M

 

Aluminium production

3N

 

Other metals production

3O

 

Emissions of hydrofluorocarbons and sulphur hexafluoride gases

4

Waste

 

4A

 

Solid waste disposal on land

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 1.2              General

1.11        Purpose of Part

                This Part provides for general matters as follows:

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

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

Division 1.2.1        Measurement and standards

1.12        Measurement of emissions

                The measurement of emissions released from the operation of a facility is to be done by estimating the emissions in accordance with this Determination.

1.13        General principles for measuring emissions

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

                (a)    transparency — emission estimates must be documented and verifiable;

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

                (c)    accuracy — having regard to the availability of reasonable resources by a registered corporation and the requirements of this Determination, uncertainties in emission estimates must be minimised and any estimates must neither be over nor under estimates of the true values at a 95% confidence level;

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

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 1.2.2        Methods

1.18        Method to be used for 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 source, from the operation of a facility.

         (2)   Subject to subsection (3), one method for the 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 source; and

               (b)    in the preceding 4 reporting years before that time, only that method has been used to estimate the emissions from the source;

then a lower method may be used to estimate emissions in relation to the source from that time.

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

         (6)   Lower method, in relation to a method (the original method) being used to estimate emissions in relation to a source, is a method for the source with a lower number than the number of the original method.

1.19        Temporary unavailability of method

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

         (2)   For each day or part of a day during the down time, emissions must be calculated based on the average daily emissions estimated for the year.

         (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)   Use of this procedure for a maximum of 6 weeks in a year is not a change of method for the purposes of section 1.18.

Division 1.2.3        Requirements in relation to carbon capture and storage

1.19A      Meaning of captured for permanent storage

                For this Determination, carbon dioxide 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 carbon dioxide that is captured for permanent storage

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

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

               (b)    the amount of carbon dioxide 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 carbon dioxide 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 carbon dioxide captured by the relevant person;

                         (ii)    the volume of the carbon dioxide stream containing the captured carbon dioxide;

                        (iii)    the concentration of carbon dioxide in the stream; or

               (b)    if the carbon dioxide is transferred to the relevant person — the following information:

                          (i)    the amount of carbon dioxide that was transferred to the relevant person;

                         (ii)    the volume of the carbon dioxide stream containing the transferred carbon dioxide;

                        (iii)    the concentration of carbon dioxide in the stream.

         (3)   The amount of carbon dioxide 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 carbon dioxide, the total amount of carbon dioxide that may be deducted in relation to the facility is to be attributed:

                (a)    if it is possible to determine the amount of carbon dioxide that is captured for permanent storage from each source — to each source from which the carbon dioxide is captured according to the amount captured from the source; or

               (b)    if it is not possible to determine the amount of carbon dioxide captured for permanent storage from each source — to the main source that generated the carbon dioxide 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 carbon dioxide that is captured for permanent storage, the total amount of carbon dioxide 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 carbon dioxide captured

         (1)   For paragraph 1.19B (1) (b), the amount of captured carbon dioxide must be estimated in accordance with this section.

         (2)   The volume of the carbon dioxide stream containing the captured carbon dioxide must be estimated:

                (a)    if the carbon dioxide 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 carbon dioxide 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 1.19N.

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

         (4)   The concentration of carbon dioxide in the carbon dioxide 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 carbon dioxide stream must be expressed in cubic metres.

         (6)   The carbon dioxide stream must be analysed for concentration of carbon dioxide on at least a monthly basis.

1.19F      Volume of carbon dioxide stream — criterion A

         (1)   For subparagraph 1.19E (2) (a) (i), criterion A is the volume of the carbon dioxide 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 carbon dioxide 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 carbon dioxide stream from the operation of a facility at the point of capture.

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

                (a)    using volumetric measurement in accordance with:

                          (i)    for a carbon dioxide stream that is not supercompressed — section 1.19H; and

                         (ii)    for a supercompressed carbon dioxide 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 carbon dioxide 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.

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

Item

Gas measuring equipment category

Maximum daily quantity of carbon dioxide 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%

1.19H     Volumetric measurement — carbon dioxide stream not super‑compressed

         (1)   For subparagraph 1.19G (2) (a) (i), volumetric measurement of a carbon dioxide stream that is not super-compressed must be in cubic metres at standard conditions.

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

                (a)    if the carbon dioxide 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 carbon dioxide stream; or

               (b)    if the carbon dioxide stream is transferred to a relevant person — at the point of transfer of the carbon dioxide 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 — the publication entitled American Gas Report No. 3 published by the American Gas Association or Parts 1 to 4 of the publication entitled API 14.3 published by the American Petroleum Institute;

               (b)    for turbine measuring systems — the publication entitled American Gas Association Transmission Measurement Committee Report No. 7 published by the American Gas Association;

                (c)    for positive displacement measuring systems — ANSI B109.3—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 units of measurement required by or under the National Measurement Act 1960.

1.19I       Volumetric measurement — supercompressed carbon dioxide stream

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

         (2)   If, in determining volume in relation to the supercompressed carbon dioxide 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 American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility published by the American Gas Association.

         (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 American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility published by the American Gas Association.

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 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 American Gas Association Report No. 3, published by the American Gas Association, 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 American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility, published by the American Gas Association, 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   ANSI B109.3—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 units of measurement required by or under the National Measurement Act 1960; 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.

1.19N     Volume of carbon dioxide stream — criterion BBB

                For subparagraph 1.19E (2) (b) (ii), criterion BBB is the estimation of the volume of the captured carbon dioxide 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 carbon dioxide stream does not meet the requirements of criterion AAA.

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

Part 1.3              Method 4 — Direct measurement of emissions

Division 1.3.1        Preliminary

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 1.3.2        Operation of method 4 (CEM)

Subdivision 1.3.2.1     Method 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 CO2e 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.

Subdivision 1.3.2.2     Method 4 (CEM) — use of equipment

1.22        Overview

                The following apply to the use of equipment for CEM:

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

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

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

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

1.23        Selection of sampling positions for CEM equipment

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

Note   Appropriate standards include:

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

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

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

·         ISO 10012:2003 Measurement management systems ‑ Requirements for measurement processes and measuring equipment.

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

1.24        Measurement of flow rates by CEM

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

Note   Appropriate standards include:

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

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

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

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

1.25        Measurement of gas concentrations by CEM

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

Note   Appropriate standards include:

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

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

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

1.26        Frequency of measurement by CEM

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

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

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

Example

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

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

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

Division 1.3.3        Operation of method 4 (PEM)

Subdivision 1.3.3.1     Method 4 (PEM)

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.

1.28        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 1.3.3.2     Method 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 1.3.4        Performance characteristics of equipment

 

1.34        Performance characteristics of CEM or PEM equipment

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

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

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

                (a)    undertaken by an accredited laboratory; or

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

                (c)    undertaken in accordance with applicable State or Territory legislation.

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

Chapter 2    Fuel combustion

Part 2.1              Preliminary

  

2.1           Outline of Chapter

                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 2.2              Emissions released from the combustion of solid fuels

Division 2.2.1        Preliminary

2.2           Application

                This Part applies to solid fuels.

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 megawatt hours of electricity in a reporting year.

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

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

2.4           Method 1 — solid fuels

                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 2.2.3        Method 2 — emissions from solid fuels

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

2.5           Method 2 — estimating carbon dioxide using oxidation factor

         (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:

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

               (b)    in any other case — 0.98.

         (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 2.2.3.2     Method 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 2.2.3.3     Sampling 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 2.2.4        Method 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

Black coal (other than that used to produce coke)

AS 4264.1—1995

2

Brown coal

AS 4264.3—1996

3

Coking coal (metallurgical coal)

AS 4264.1—1995

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 2.2.5        Measurement of consumption of solid fuels

2.13        Purpose of Division

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

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)   The volume of solid fuel in the stockpile may be measured using aerial or general survey in accordance with industry practice.

         (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.

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 2.3              Emissions released from the combustion of gaseous fuels

Division 2.3.1        Preliminary

2.18        Application

                This Part applies to gaseous fuels.

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 megawatt hours of electricity in a reporting year.

Division 2.3.2        Method 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 2.3.3        Method 2 — emissions of carbon dioxide from the combustion of gaseous fuels

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

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

         (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 0.995 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) obtained under section 2.21.

Ci is the density of fuel type (i) expressed in kilograms of fuel per cubic metre as obtained under subsection 2.24 (4).

Subdivision 2.3.3.2     Sampling and analysis

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)

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)   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 by an accredited laboratory or by a laboratory that meets requirements that are equivalent to the requirements in AS ISO/IEC 17025:2005.

         (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

Monthly

Energy content

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 certifies in writing that such frequency of analysis will cause significant hardship or expense in which case the analysis may be undertaken at a frequency that will allow an unbiased estimate to be obtained

Note   The table in section 2.31 sets out the categories of gas measuring equipment.

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

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 2.3.5        Method 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), method 2 for estimating emissions of methane is the same as method 1 under section 2.20.

         (2)   In applying method 1 under section 2.20, the emission factor EFijoxec is to be obtained by using the equipment type emission factors set out in Volume 2, section 2.3.2.3 of the 2006 IPCC Guidelines corrected to gross calorific values.

Division 2.3.6        Measurement of quantity of gaseous fuels

2.28        Purpose of Division

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

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 at point of consumption — 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 at point of consumption — 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 at the point of combustion.

         (2)   In measuring the quantity of gaseous fuel at the point of combustion, the quantities of gas must be measured:

                (a)    using volumetric measurement in accordance with:

                          (i)    for gases generally — section 2.32; and

                         (ii)    for supercompressed gases — section 2.33; and

               (b)    using gas measuring equipment that complies with section 2.34.

         (3)   The measurement must be either:

                (a)    carried out using 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 specified in column 3 for that item from the operation of the facility; and

                         (ii)    is in a category specified in column 2 of an item in the table and complies with the transmitter and accuracy requirements for that equipment specified in column 4 for that item; 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 — general

         (1)   For paragraph 2.31 (2) (a), volumetric measurement must be in cubic metres at standard conditions.

         (2)   The volumetric measurement is to be calculated using a flow computer that measures and analyses flow signals, relative density and gas composition at the delivery location of the gaseous fuel.

         (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 — the publication entitled American Gas Report No. 3 published by the American Gas Association or Parts 1 to 4 of the publication entitled API 14.3 published by the American Petroleum Institute;

               (b)    for turbine measuring systems — the publication entitled American Gas Association Transmission Measurement Committee Report No. 7 published by the American Gas Association;

                (c)    for positive displacement measuring systems — ANSI B109.3 — 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.

Note   New Zealand standard NZS 5259:1999 is an example of an appropriate internationally recognised code.

         (6)   Measurements must comply with units of measurement required by or under the National Measurement Act 1960.

         (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)   This section applies for subparagraph 2.31 (2) (a) (ii).

         (2)   If, in determining volume in relation to super‑compressed gases, 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 American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility published by the American Gas Association.

         (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 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 American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility published by the American Gas Association.

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 chromatographs set out in section 2.37.

2.35        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 American Gas Association Report No. 3, published by the American Gas Association, 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 American Gas Association Transmission Measurement Committee Report No. 8 (1992) Super‑compressibility, published by the American Gas Association, 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   ANSI B109.3 — 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 section 2.31 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.

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 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.

2.37        Gas chromatographs

                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 produced by gravimetric methods and traceable to Australian units of measurement required by or under the National Measurement Act 1960; and

               (b)    perform gas composition analysis with an accuracy of ±0.15% for use in calculation of gross calorific value and ±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 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 2.4              Emissions released from the combustion of liquid fuels

Division 2.4.1        Preliminary

2.39        Application

                This Part applies to liquid fuels.

2.39A      Definition of petroleum based oils  for Part 2.4

                In this Part:

petroleum based oils means petroleum based oils (other than petroleum based oils used as fuel).

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

2.40        Available methods

         (1)   Subject to section 1.18, for estimating emissions released from the combustion of a liquid fuel, other than petroleum based oils and petroleum based greases, consumed from the operation of a facility during a year:

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

                                  (i)    method 1 under section 2.41;

                         (ii)    method 2 under section 2.42;

                        (iii)    method 3 under section 2.47;

                        (iv)    method 4 under Part 1.3; and

               (b)    one of the following methods must be used for estimating emissions of methane and nitrous oxide:

                          (i)    method 1 under section 2.41;

                         (ii)    method 2 under section 2.48.

         (2)   Under paragraph (1) (b), the same method must be used for estimating emissions of methane and nitrous oxide.

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

Note   The combustion of liquid fuels releases emissions of carbon dioxide, methane and nitrous oxide. Method 1 may be used to estimate emissions of each of these gases. There is no method 3 or 4 for emissions of methane or nitrous oxide.

Subdivision 2.4.1.2     Liquid fuels — petroleum based oils and greases

2.40A      Available methods

         (1)   Subject to section 1.18, for estimating emissions of carbon dioxide released from the consumption, as lubricants, of petroleum based oils or petroleum based greases, consumed from the operation of a facility during a year, one of the following methods must be used:

                (a)    method 1 under section 2.48A;

               (b)    method 2 under section 2.48B;

                (c)    method 3 under section 2.48C.

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

Note   The consumption of petroleum based oils and greases, as lubricants, releases emissions of carbon dioxide.  Emissions of methane and nitrous oxide are not estimated directly for this fuel type.

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

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

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

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

         (1)   For subparagraph 2.40 (1) (a) (ii), method 2 for estimating emissions of carbon dioxide is:

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 0.99 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 2.4.3.2     Sampling 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 including crude oil condensates

ASTM D 240‑02 (2007)

ASTM D 4809‑06

ASTM D 5291‑02 (2007)

ASTM D 1298 – 99 (2005) ASTM D 5002 – 99 (2005)

4

Other natural gas liquids

N/A

N/A

ASTM D 1298 – 99 (2005)

5

Gasoline (other than for use as fuel in an aircraft)

ASTM D 240‑02 (2007)

ASTM D 4809‑06

N/A

ASTM D 1298 – 99 (2005)

6

Gasoline for use as fuel in an aircraft

ASTM D 240‑02 (2007)

ASTM D 4809‑06

N/A

ASTM D 1298 – 99 (2005)

7

Kerosene (other than for use as fuel in an aircraft)

ASTM D 240‑02 (2007)

ASTM D 4809‑06

N/A

ASTM D 1298 – 99 (2005) ASTM D 4052 – 96 (2002) e1

8

Kerosene for use as fuel in an aircraft

ASTM D 240‑02 (2007)

ASTM D 4809‑06

N/A

ASTM D 1298 – 99 (2005) ASTM D 4052 – 96 (2002) e1

9

Heating oil

ASTM D 240‑02 (2007)

ASTM D 4809‑06

ASTM D 5291‑02 (2007)

ASTM D 1298 – 99 (2005)

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 2.4.4        Method 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 including crude oil condensates

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

4

Other natural gas liquids

ASTM D1265 – 05

5

Gasoline (other than for use as fuel in an aircraft)

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

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 2.4.5        Method 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 — column 4 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 2 of the table in Division 4.3 of Part 4 of Schedule 1 — column 4 of the table in that Division.

Division 2.4.5A     Methods 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 2.4.6        Measurement of quantity of liquid fuels

2.49        Purpose of Division

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

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 at point of consumption — 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 at point of consumption — 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 at the point of combustion.

         (2)   The measurement must be carried out:

                (a)    at the point of combustion at ambient temperatures and converted to standard temperatures, using measuring equipment calibrated to a measurement requirement; or

               (b)    at ambient temperatures and converted to standard temperatures, at the point of sale of the liquid fuel, using measuring equipment calibrated to a measurement requirement.

         (3)   Paragraph (2) (b) only applies if:

                (a)    the change in the stockpile of fuel for the facility for the year is less than 1% of total combustion on average for the facility during the year; and

               (b)    the stockpile of the fuel for the facility at the beginning of the year is less than 5% of total combustion from the operation of the facility for the year.

2.53        Simplified consumption measurements — criterion BBB

                For paragraph 2.50 (4) (b), criterion BBB is the estimation of the combustion of a liquid fuel for the year using accepted industry measuring devices or, in the absence of such measuring devices, in accordance with industry practice if the equipment used to measure consumption of the fuel is not calibrated to a measurement requirement.

Part 2.5              Emissions released from fuel use by certain industries

2.54        Application

                This Part applies to emissions from petroleum refining, solid fuel transformation (coke ovens) and petrochemical production.

Division 2.5.1        Energy — petroleum refining

2.55        Application

                This Division applies to petroleum refining.

2.56        Methods

         (1)   If:

                (a)    the operation of a facility is constituted by petroleum refining; and

               (b)    the refinery combusts fuels for energy;

then the methods for estimating emissions during a year from that combustion are as provided in Parts 2.2, 2.3 and 2.4.

         (2)   The method for estimating emissions from the production of hydrogen by the petroleum refinery must be in accordance with the method set out in section 5 of the API Compendium.

         (3)   Fugitive emissions released from the petroleum refinery must be estimated using methods provided for in Chapter 3.

Division 2.5.2        Energy — manufacture of solid fuels

2.57        Application

                This Division applies to solid fuel transformation through the pyrolysis of coal or the coal briquette process.

2.58        Methods

         (1)   One or more of the following methods must be used for estimating emissions during the year from combustion of fuels for energy in the manufacture of solid fuels:

                (a)    if a facility is constituted by the manufacture of solid fuel using coke ovens as part of an integrated metalworks — the methods provided in Part 4.4 must be used; and

               (b)    in any other case — one of the following methods must be used:

                          (i)    method 1 under subsection (3);

                         (ii)    method 2 under subsections (4) to (7);

                        (iii)    method 3 under subsections (8) to (10);

                        (iv)    method 4 under Part 1.3.

         (2)   These emissions are taken to be emissions from fuel combustion.

Method 1

         (3)   Method 1, based on a carbon mass balance approach, is:

Step 1

Work out the carbon content in fuel types (i) or carbonaceous input material delivered for the activity during the year, measured in tonnes of carbon, as follows:

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 2.5.3        Energy — petrochemical production

2.59        Application

                This Division applies to petrochemical production (where fuel is consumed as a feedstock).

2.60        Available methods

         (1)   Subject to section 1.18 one of the following methods must be used for estimating emissions released during a year from the operation of a facility that is constituted by an activity that is petrochemical production:

                (a)    method 1 under section 2.61;

               (b)    method 2 under section 2.62;

                (c)    method 3 under section 2.63;

               (d)    method 4 under Part 1.3.

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

2.61        Method 1 — petrochemical production

                Method 1, based on a carbon mass balance approach, is:

 

Step 1

Calculate the carbon content in all fuel types (i) delivered for the activity during the year as follows:

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 by-products (r) produced by the activity and held within the boundary of the activity during the year measured in tonnes.

α is the factor  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 by-products (r) produced by the activity and held within the boundary of the activity during the year measured in tonnes.

α is the factor  for converting the mass of carbon dioxide to a mass of carbon.

 

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

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

 

Part 2.6              Blended fuels

  

2.64        Purpose

                This Part sets out how to determine the amounts of each kind of fuel that is in a blended fuel.

2.65        Application

                This Part sets out how to determine the amount of each fuel type (i) that is in a blended fuel if that blended fuel is a solid fuel or a liquid fuel.

2.66        Blended solid fuels

         (1)   In determining the amounts of each kind of fuel that is in a blended solid fuel, a person may adopt the outcome of the sampling and analysis done by the manufacturer of the fuel if:

                (a)    the sampling has been done in accordance with subsections 2.12 (3) and (4); and

               (b)    the analysis has been done in accordance with one of the following standards or a standard that is equivalent to one of those standards:

                          (i)    CEN/TS15440:2006;

                         (ii)    ASTM D6866—10.

         (2)   The person may use his or her own sampling and analysis of the fuel if the sampling and analysis complies with the requirements of paragraphs (1) (a) and (b).

2.67        Blended liquid fuels

                The person may adopt the manufacturer’s determination of each kind of fuel that is in a blended liquid fuel or adopt the analysis arrived at after doing both of the following:

                (a)    sampling the fuel in accordance with a standard mentioned in subsections 2.47 (3) and (4);

               (b)    analysing the fuel in accordance with ASTM: D6866—10 or a standard that is equivalent to that standard.

Part 2.7              Estimation of energy for certain purposes

  

2.68        Amount of fuel 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

               (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.

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 that is apportioned between electricity generation, transport (excluding international bunker fuels) and other stationary energy purposes may be determined using the corporation’s records if the records are based on the measurement equipment used by the corporation to measure consumption of the fuel types.

Chapter 3    Fugitive emissions

Part 3.1              Preliminary

  

3.1           Outline of Chapter

                This Chapter provides for fugitive emissions from the following:

                (a)    coal mining (see Part 3.2);

               (b)    oil and natural gas (see Part 3.3);

                (c)    carbon capture and storage (see Part 3.4).

Part 3.2              Coal mining — fugitive emissions

Division 3.2.1        Preliminary

3.2           Outline of Part

                This Part provides for fugitive emissions from coal mining, as follows:

                (a)    underground mining activities (see Division 3.2.2);

               (b)    open cut mining activities (see Division 3.2.3);

                (c)    decommissioned underground mines (see Division 3.2.4).

Division 3.2.2        Underground mines

Subdivision 3.2.2.1     Preliminary

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)    method 1 under section 3.14 must be used for estimating emissions of methane released;

                (c)    method 1 under section 3.14 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 reference to gas type (j) in method 1 under section 3.14 is a reference to these gases. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide, 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

         (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 3.2.2.2     Fugitive emissions from extraction of coal

3.5           Method 1 — extraction of coal

                For paragraph 3.4 (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, as follows:

                (a)    for a gassy mine — 0.305;

               (b)    for a non‑gassy mine — 0.008.

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 × 21; 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 3.12.

         (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 measured in accordance with section 1.34.

Subdivision 3.2.2.3     Emissions 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 0.98/0.995, which is the correction factor for the oxidation of coal mine waste gas (i) flared.

3.15        Method 2 — 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.

Qj is the quantity of methane (j) within the fuel type from the mine during the year, measured in cubic metres in accordance with Division 2.3.3.

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.

EFj is the emission factor for the methane (j) within the fuel type from the mine during the year, measured in kilograms of CO2‑e per gigajoule, estimated in accordance with any of the standards in Division 2.3.3.

OFi is 0.98/0.995, which is the correction factor for the oxidation of coal mine waste gas (i) flared.

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.

3.16        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 EFh must be determined in accordance with the procedure for determining EFiCO2oxec in Division 2.3.4.

Subdivision 3.2.2.4     Fugitive 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 0.014, which is the emission factor for methane (j), measured in CO2‑e tonnes per tonne of run‑of‑mine coal extracted from the mine.

Division 3.2.3        Open cut mines

Subdivision 3.2.3.1     Preliminary

3.18        Application

                This Division applies to fugitive emissions from open cut mining activities.

3.19        Available methods

         (1)   Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by an open cut mine the methods as set out in this section must be used.

Methane from extraction of coal

         (2)   Subject to subsection (7), one of the following methods must be used for estimating fugitive emissions of methane that result from the extraction of coal from the mine:

                (a)    method 1 under section 3.20;

               (b)    method 2 under section 3.21;

                (c)    method 3 under section 3.26.

Note   There is no method 4 for subsection (2).

Carbon dioxide from extraction of coal

         (3)   If method 2 under section 3.21 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from the open cut mine.

         (4)   If method 3 under section 3.26 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from the open cut mine.

Note   There is no method 1 or 4 for estimating fugitive emissions of carbon dioxide that result from the extraction of coal from an open cut mine.

Flaring

         (5)   For estimating emissions released from coal mine waste gas flared from the open cut mine:

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

                          (i)    method 1 under section 3.27;

                         (ii)    method 2 under section 3.28;

                        (iii)    method 3 under section 3.29; and

               (b)    method 1 under section 3.27 must be used for estimating emissions of methane released; and

                (c)    method 1 under section 3.27 must be used for estimating emissions of nitrous oxide released.

Note   The flaring of coal mine waste gas releases emissions of carbon dioxide, methane and nitrous oxide. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide, no method 2, 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide.

Venting or other fugitive release before extraction of coal

         (6)   Method 4 under Part 1.3 must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, that result from venting or other fugitive release of gas from the mine before coal is extracted from the mine.

Note   There is no method 1, 2 or 3 for subsection (6).

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

Subdivision 3.2.3.2     Fugitive 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 — 0.045;

               (b)    for a mine in Victoria — 0.0007;

                (c)    for a mine in Queensland — 0.017;

               (d)    for a mine in Western Australia — 0.017;

                (e)    for a mine in South Australia — 0.0007;

                (f)    for a mine in Tasmania — 0.014.

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 × 21;

               (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 and 3.25.

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.

β is the proportion of the gas content of the gas bearing strata (z) that is released by extracting coal from the extraction area of the mine during the year, as follows:

(a)    if the gas bearing strata is at or above the pit floor — 1;

(b)    in any other case — as estimated under section 3.23.

GCjz is the content of gas type (j) contained by the gas bearing strata (z) before gas capture, flaring or venting is undertaken at the extraction area of the mine during the year, measured in cubic metres per tonne of gas bearing strata at standard conditions.

Qij,cap,z is the total quantity of gas type (j) in coal mine waste gas (i) captured for combustion from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres.

∑Qij,flared,z is the total quantity of gas type (j) in coal mine waste gas (i) flared from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres.

∑Qijtr is the total quantity of gas type (j) in coal mine waste gas (i) transferred out of the mining activities at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres.

∑Ej,vented,z is the total emissions of gas type (j) vented from the gas bearing strata (z) at any time before coal is extracted from the extraction area of the mine during the year, measured in cubic metres and estimated under subsection 3.19 (6).

         (2)   For ∑Qij,cap,z, ∑Qij,flared,z and ∑Qijtr in subsection (1), the quantity of gas type (j) must be estimated in accordance with Division 2.3.6 as if a reference in that Division to quantities of gaseous fuels combusted from the operation of a facility was a reference to the following:

                (a)    for ∑Qij,cap,z — quantities of gaseous fuels captured from the operation of a facility;

               (b)    for tQij,flared,z — quantities of gaseous fuels flared from the operation of a facility;

                (c)    for ∑Qijtr — quantities of gaseous fuels transferred out of the operation of a facility.

         (3)   In subsection (1), ∑Qijtr applies to carbon dioxide only if the carbon dioxide is captured for permanent storage.

Note   Division 1.2.3 contains a number of requirements in relation to deductions of carbon dioxide captured for permanent storage.

3.23        Estimate of proportion of gas content released below pit floor

                For paragraph (b) of the factor β in subsection 3.22 (1):

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.

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 an appropriate standard.

Note 1   An appropriate standard for analysis of a gas includes AS 3980—1999 Guide to the determination of gas content of coal—Direct desorption method.

Note 2   An appropriate standard for analysis of a gas bearing strata includes AS 2519—1993 Guide to the technical evaluation of higher rank coal deposits.

3.26        Method 3 — extraction of coal

         (1)   For paragraph 3.19 (2) (c) and subsection 3.19 (4), method 3 is the same as method 2 under section 3.21

         (2)   In applying method 2 under section 3.21 a sample of gas bearing strata must be collected in accordance with an appropriate standard, including:

                (a)    AS 2617—1996 Sampling from coal seams or an equivalent standard; and

               (b)    AS 2519—1993 Guide to the technical evaluation of higher rank coal deposits or an equivalent standard.

Subdivision 3.2.3.3     Emissions released from coal mine waste gas flared

3.27        Method 1 — coal mine waste gas flared

         (1)   For subparagraph 3.19 (5) (a) (i) and paragraph 3.19 (5) (b) and paragraph (5) (c), method 1 is the same as method 1 under section 3.14.

         (2)   In applying method 1 under section 3.14, a reference to an underground mine is taken to be a reference to an open cut mine.

3.28        Method 2 — coal mine waste gas flared

                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 3.2.4        Decommissioned underground mines

Subdivision 3.2.4.1     Preliminary

3.30        Application

                This Division applies to fugitive emissions from decommissioned underground mines that have been closed for a continuous period of at least 1 year but less than 20 years.

3.31        Available methods

         (1)   Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by a decommissioned underground mine that has been closed for a continuous period of at least 1 year but less than 20 years the methods as set out in this section must be used.

Methane from decommissioned mines

         (2)   One of the following methods must be used for estimating fugitive emissions of methane that result from the mine:

                (a)    subject to subsection (6), method 1 under section 3.32;

               (b)    method 4 under section 3.37.

Note   There is no method 2 or 3 for subsection (2).

Carbon dioxide from decommissioned mines

         (3)   If method 4 under section 3.37 is used under subsection (2), that method must be used for estimating fugitive emissions of carbon dioxide that result from the mine.

Note   There is no method 1, 2 or 3 for subsection (3).

Flaring

         (4)   For estimating emissions released from coal mine waste gas flared from the mine:

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

                          (i)    method 1 under section 3.38;

                         (ii)    method 2 under section 3.39;

                        (iii)    method 3 under section 3.40; and

               (b)    method 1 under section 3.38 must be used for estimating emissions of methane released.

                (c)    method 1 under section 3.38 must be used for estimating emissions of nitrous oxide released.

Note   The flaring of coal mine waste gas releases emissions of carbon dioxide, methane and nitrous oxide. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide, no method 2, 3 or 4 for emissions of methane and no method 2, 3 or 4 for nitrous oxide.

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

         (6)   If coal mine waste gas from the decommissioned underground mine is captured for combustion during the year, method 1 in subsection (2) must not be used.

Subdivision 3.2.4.2     Fugitive 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 full year that the mine was in operation measured in CO2‑e tonnes and estimated under section 3.5 or 3.6.

EFdm is the emission factor for the mine calculated under section 3.33.

Fdm is the proportion of the mine flooded at the end of the year, as estimated under section 3.34, and must not be greater than 1.

         (2)   However, if, under subsection (1), the estimated emissions in CO2‑e tonnes for the mine during the year is less than 0.02 ´ Etdm, the estimated emissions for the mine during the year is taken to be 0.02 ´ Etdm.

3.33        Emission factor for decommissioned underground mines

                For section 3.32, EFdm is the integral under the curve of:

for the period between T and T‑1,

where:

A is:

                (a)    for a gassy mine — 0.23; or

               (b)    for a non‑gassy mine — 0.35.

T is the number of years since the mine was decommissioned.

b is:

                (a)    for a gassy mine — ‑1.45; or

               (b)    for a non‑gassy mine — ‑1.01.

C is:

                (a)    for a gassy mine — 0.024; or

               (b)    for a non‑gassy mine — 0.088.

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.

years is the number of years since the mine was decommissioned.

3.35        Water flow into mine

                For MWI in section 3.34, the rate of water flow into the mine must be measured by:

                (a)    using water flow rates for the mine estimated in accordance with an appropriate standard; or

               (b)    using the following average water flow rates:

                          (i)    for a mine in the southern coalfield of New South Wales — 913 000 cubic metres per year; or

                         (ii)    for a mine in the Newcastle, Hunter, Western or Gunnedah coalfields in New South Wales — 450 000 cubic metres per year; or

                        (iii)    for a mine in Queensland — 74 000 cubic metres per year.

Note   An appropriate standard includes AS 2519—1993 Guide to the technical evaluation of higher rank coal deposits.

3.36        Size of mine void volume

                For MVV in section 3.34, the size of the mine void volume must be measured by:

                (a)    using mine void volumes for the mine estimated in accordance with industry practice; or

               (b)    dividing the total amount of run‑of‑mine coal extracted from the mine before the mine was decommissioned by 1.425.

3.37        Method 4 — decommissioned underground mines

         (1)   For paragraph 3.31 (2) (b) and subsection 3.31 (3), method 4 is the same as method 4 in section 3.6.

         (2)   In applying method 4 under section 3.6, a reference to an underground mine is taken to be a reference to a decommissioned underground mine.

Subdivision 3.2.4.3     Fugitive emissions from coal mine waste gas flared

3.38        Method 1 — coal mine waste gas flared

         (1)   For subparagraph 3.31 (4) (a) (i) and paragraphs 3.31 (4) (b) and (4) (c), method 1 is the same as method 1 under section 3.14.

         (2)   In applying method 1 under section 3.14, a reference to an underground mine is taken to be a reference to a decommissioned underground mine.

3.39        Method 2 — coal mine waste gas flared

                For subparagraph 3.31 (4) (a) (ii), method 2 is the same as method 2 under section 3.15.

3.40        Method 3 — coal mine waste gas flared

                For subparagraph 3.31 (4) (a) (iii), method 3 is the same as method 3 under section 3.16.

Part 3.3              Oil and natural gas — fugitive emissions

Division 3.3.1        Preliminary

3.40A      Definition of natural gas for Part 3.3

                In this Part:

natural gas includes coal seam methane that is captured for combustion where the production of coal is not intended to occur.

3.41        Outline of Part

                This Part provides for fugitive emissions from the following:

                (a)    oil or gas exploration (see Division 3.3.2);

               (b)    crude oil production (see Division 3.3.3);

                (c)    crude oil transport (see Division 3.3.4);

               (d)    crude oil refining (see Division 3.3.5);

                (e)    natural gas production or processing, other than emissions that are vented or flared (see Division 3.3.6);

                (f)    natural gas transmission (see Division 3.3.7);

               (g)    natural gas distribution (see Division 3.3.8);

               (h)    natural gas production or processing (emissions that are vented or flared) (see Division 3.3.9).

Division 3.3.2        Oil or gas exploration

Subdivision 3.3.2.1     Preliminary

3.42        Application

                This Division applies to fugitive emissions from venting or flaring from oil or gas exploration activities, including emissions from:

                (a)    oil well drilling; and

               (b)    gas well drilling; and

                (c)    drill stem testing; and

               (d)    well completions.

Subdivision 3.3.2.2     Oil or gas exploration (flared) emissions

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:

                (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 — method 1 under section 3.44 must be used; and

                (c)    if estimating emissions of nitrous oxide released — method 1 under section 3.44 must be used.

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

         (1)   Method 1 is:

where:

Eij is the fugitive emissions of gas type (j) from a fuel type (i) flared in the oil or gas exploration during the year measured in CO2‑e tonnes.

Qi is the quantity of fuel type (i) flared in the oil or gas exploration during the year measured in tonnes.

EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of the fuel type (i) flared.

         (2)   For EFij in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor, for gas type (j), for each fuel type (i) specified in column 2 of that item.

 

Item

Fuel type (i)

Emission factor for gas type (j) (tonnes CO2‑e/tonnes of fuel flared)

 

CO2

CH4

N2O

1

Unprocessed gas flared

2.8

0.7

0.03

2

Crude oil

3.2

0.007

0.07

3.45        Method 2 — oil or gas exploration

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 during the year, measured in CO2‑e tonnes.

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in oil or gas exploration during the year, measured in tonnes in accordance with Division 2.3.3.

EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in oil or gas exploration during the year, measured in CO2‑e tonnes per tonne of the fuel type (i) flared, estimated in accordance with Division 2.3.3.

OFi is 0.98/0.995, which is the correction factor for the oxidation of fuel type (i) flared.

QCO2 is the quantity of CO2 within fuel type (i) in oil or gas exploration during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.

Combustion of liquid fuels (flared) emissions

         (2)   For subparagraph 3.43 (1) (a) (ii), method 2 for combustion of liquid fuels is the same as method 1, but the carbon dioxide emissions factor EFh must be determined in accordance with method 2 in Division 2.4.3.

3.46        Method 3 — oil or gas exploration

Combustion of gaseous fuels (flared) emissions

         (1)   For subparagraph 3.43 (1) (a) (iii), method 3 for the combustion of gaseous fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.3.4.

Combustion of liquid fuels (flared) emissions

         (2)   For subparagraph 3.43 (1) (a) (iii), method 3 for the combustion of liquid fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.4.4.

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

3.46A      Available methods

                Subject to section 1.18, method 1 under section 3.84 must be used for estimating fugitive emissions that result from system upsets, accidents and deliberate releases from process vents during a year from the operation of a facility that is constituted by oil or gas exploration.

Note   There is no method 2, 3 or 4 for this Division.

Division 3.3.3        Crude oil production

Subdivision 3.3.3.1     Preliminary

3.47        Application

         (1)   This Division applies to fugitive emissions from crude oil production activities, including emissions from flaring, from:

                (a)    an oil wellhead; and

               (b)    well servicing; and

                (c)    oil sands mining; and

               (d)    shale oil mining; and

                (e)    the transportation of untreated production to treating or extraction plants; and

                (f)    activities at extraction plants or heavy oil upgrading plants, and gas reinjection systems and produced water disposal systems associated with the those plants; and

               (g)    activities at upgrading plants and associated gas reinjection systems and produced water disposal systems.

         (2)   For paragraph (1) (e), untreated production includes:

                (a)    well effluent; and

               (b)    emulsion; and

                (c)    oil shale; and

               (d)    oil sands.

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

3.48        Available methods

         (1)   Subject to section 1.18, for estimating fugitive emissions of methane, other than fugitive emissions of methane specified in subsection (1A), during a year from the operation of a facility that is constituted by crude oil production, one of the following methods must be used:

                (a)    method 1 under section 3.49;

               (b)    method 2 under section 3.50;

Note   There is no method 3 or 4 for this Division.

      (1A)   For subsection (1), the following fugitive emissions of methane are specified:

                (a)    fugitive emissions from oil or gas flaring;

               (b)    fugitive emissions that result from system upsets, accidents or deliberate releases from process vents.

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

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 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 1.2 x 10‑3, which is the emission factor for methane (j) from general leaks in the crude oil production, measured in CO2‑e tonnes per tonne of crude oil that passes through the crude oil production.

         (2)   For EFijk mentioned in subsection (1), column 3 of an item in the following table specifies the emission factor for an equipment of type (k) specified in column 2 of that item:

 

Item

Equipment type (k)

Emission factor for gas type (j) (tonnes CO2‑e/tonnes fuel throughput)

 

CH4

1

Internal floating tank

8.4 10‑7

2

Fixed roof tank

4.2  10‑6

3

Floating tank

3.2  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 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 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 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 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 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production.

         (2)   For EFijk, the emission factors for methane (j), as crude oil passes through an equipment type (k), are:

                (a)    as listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4 and 6.1.2 of the API Compendium, for the equipment type; or

               (b)    if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type — those factors.

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

3.51        Available methods

         (1)   Subject to section 1.18, for estimating emissions released by oil or gas flaring during a year from the operation of a facility that is constituted by crude oil production:

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

                          (i)    method 1 under section 3.52;

                         (ii)    method 2 under section 3.53;

                        (iii)    method 3 under section 3.54; and

               (b)    if estimating emissions of methane released — method 1 under section 3.55 must be used; and

                (c)    if estimating emissions of nitrous oxide released — method 1 under section 3.55 must be used.

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.

3.52        Method 1 — crude oil production (flared) emissions

         (1)   For subparagraph 3.51 (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.

EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of the fuel type (i) flared.

         (2)   For EFij mentioned in subsection (1), columns 3, 4 and 5 of an item in following table specify the emission factor for each fuel type (i) specified in column 2 of that item.

 

Item

Fuel type (i)

Emission factor for gas type (j) (tonnes CO2‑e/tonnes of fuel flared)

 

CO2

CH4

N2O

1

Unprocessed gas flared

2.8

0.7

0.03

2

Crude oil

3.2

0.007

0.07

3.53        Method 2 — crude oil production

Combustion of gaseous fuels (flared) emissions of carbon dioxide

         (1)   For subparagraph 3.51 (1) (a) (ii), method 2 for combustion of gaseous fuels is:

where:

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in crude oil production during the year, measured in CO2‑e tonnes.

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil production during the year, measured in tonnes in accordance with Division 2.3.3.

EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in crude oil production during the year, measured in CO2‑e tonnes per tonne of fuel type (i) flared, estimated in accordance with method 2 in Division 2.3.3.

OFi is 0.98/0.995, which is the correction factor for the oxidation of fuel type (i) flared.

QCO2 is the quantity of CO2 within the fuel type (i) in crude oil production during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.

Combustion of liquid fuels (flared) emissions of carbon dioxide

         (2)   For subparagraph 3.51 (1) (a) (ii), method 2 for combustion of liquid fuels is the same as method 1, but the carbon dioxide emissions factor EFh must be determined in accordance with method 2 in Division 2.4.3.

3.54        Method 3 — crude oil production

Combustion of gaseous fuels (flared) emissions of carbon dioxide

         (1)   For subparagraph 3.51 (1) (a) (iii), method 3 for the combustion of gaseous fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.3.4.

Combustion of liquid fuels (flared) emissions of carbon dioxide

         (2)   For subparagraph 3.51 (1) (a) (iii), method 3 for the combustion of liquid fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.4.4.

3.55        Method 1 — crude oil production (flared) emissions of methane and nitrous oxide

                For subparagraph 3.51 (b) (i) and paragraph 3.51 (c), method 1 is as provided for in section 3.52.

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

3.56A      Available methods

                Subject to section 1.18, method 1 under section 3.84 must be used for estimating fugitive emissions that result from system upsets, accidents and deliberate releases from process vents during a year from the operation of a facility that is constituted by crude oil production.

Note   There is no method 2, 3 or 4 for this Subdivision.

Division 3.3.4        Crude oil transport

3.57        Application

                This Division applies to fugitive emissions from crude oil transport activities, other than emissions that are flared.

3.58        Available methods

         (1)   Subject to section 1.18, one of the following methods must be used for estimating fugitive emissions of methane released during a year from the operation of a facility that is constituted by crude oil transport:

                (a)    method 1 under section 3.59;

               (b)    method 2 under section 3.60.

Note   There is no method 3 or 4 for this Division.

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

3.59        Method 1 — crude oil transport

                Method 1 is:

where:

Eij is the fugitive emissions of methane (j) from the crude oil transport during the year measured in CO2‑e tonnes.

Qi is the quantity of crude oil (i) measured in tonnes and transported during the year.

EFij is the emission factor for methane (j), which is 7.3 x 10‑4 tonnes CO2‑e per tonnes of crude oil transported during the year.

3.60        Method 2 — fugitive emissions from crude oil transport

         (1)   Method 2 is:

where:

Eij is the fugitive emissions of methane (j) from the crude oil transport during the year measured in CO2‑e tonnes.

Σk is the emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport .

Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes though each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport.

         (2)   For EFijk, the emission factors for methane (j), as crude oil passes through equipment type (k), are:

                (a)    as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or

               (b)    if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type — those factors.

Division 3.3.5        Crude oil refining

3.61        Application

                This Division applies to fugitive emissions from crude oil refining activities, including emissions from flaring at petroleum refineries.

3.62        Available methods

         (1)   Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by crude oil refining the methods as set out in this section must be used.

Crude oil refining and storage tanks

         (2)   One of the following methods must be used for estimating fugitive emissions of methane that result from crude oil refining and from storage tanks for crude oil:

                (a)    method 1 under section 3.63;

               (b)    method 2 under section 3.64.

Note   There is no method 3 or 4 for subsection (2).

Process vents, system upsets and accidents

         (3)   One of the following methods must be used for estimating fugitive emissions of each type of gas, being carbon dioxide, methane and nitrous oxide, that result from deliberate releases from process vents, system upsets and accidents:

                (a)    method 1 under section 3.65;

               (b)    method 4 under section 3.66.

Note   There is no method 2 or 3 for subsection (3).

Flaring

         (4)   For estimating emissions released from gas flared from crude oil refining:

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

                          (i)    method 1 under section 3.67;

                         (ii)    method 2 under section 3.68;

                        (iii)    method 3 under section 3.69; and

               (b)    method 1 under section 3.67 must be used for estimating emissions of methane released; and

                (c)    method 1 under section 3.67 must be used for estimating emissions of nitrous oxide released.

Note   The flaring of gas from crude oil refining releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 under section 3.67 is a reference to these gases. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide and no method 2, 3 or 4 for emissions of nitrous oxide or methane.

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

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

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

                Method 1 is:

where:

Eij is the fugitive emissions of methane (j) from fuel type (i) being crude oil refined or stored in tanks during the year measured in CO2‑e tonnes.

I is the sum of emissions of methane (j) released during refining and from storage tanks during the year.

Qi is the quantity of crude oil (i) refined or stored in tanks during the year measured in tonnes.

EFij is the emission factor for methane (j) being 7.1 x 10‑4 tonnes CO2‑e per tonne of crude oil refined and 1.3 x 10‑4 tonnes CO2‑e per tonne of crude oil stored in tanks.

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

         (1)   Method 2 is:

where:

Eij is the fugitive emissions of methane (j) from the crude oil refining and from storage tanks during the year measured in CO2‑e tonnes.

Σk is the emissions of methane (j) measured in tonnes of CO2‑e estimated by summing up the emissions released from each equipment types (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks.

Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks.

EFijk is the emission factor for methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes though each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks.

         (2)   For EFijk, the emission factors for methane (j) as the crude oil passes through an equipment type (k) are:

                (a)    as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or

               (b)    if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type — those factors.

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

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

                Method 1 is:

where:

Ei is the fugitive emissions of carbon dioxide during the year from deliberate releases from process vents, system upsets and accidents in the crude oil refining measured in CO2‑e tonnes.

Qi is the quantity of refinery coke (i) burnt to restore the activity of the catalyst of the crude oil refinery (and not used for energy) during the year measured in tonnes.

CCFi is the carbon content factor for refinery coke (i) as mentioned in Schedule 3.

3.664 is the conversion factor to convert an amount of carbon in tonnes to an amount of carbon dioxide in tonnes.

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

         (1)   Method 4 is:

                (a)    is as set out in Part 1.3; or

               (b)    uses the process calculation approach in section 5.2 of the API Compendium.

         (2)   For paragraph (1) (b), all carbon monoxide is taken to fully oxidise to carbon dioxide and must be included in the calculation.

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

3.67        Method 1 — gas flared from crude oil refining

         (1)   Method 1 is:

where:

Eij is the emissions of gas type (j) released from the gas flared in the crude oil refining during the year measured in CO2‑e tonnes.

Qi is the quantity of gas type (i) flared during the year measured in tonnes.

EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of gas type (i) flared in the crude oil refining during the year.

         (2)   For EFij in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor for gas type (j) for the fuel type (i) specified in column 2 of that item:

 

Item

fuel type (i)

Emission factor of gas type (j) (tonnes CO2‑e/tonnes fuel flared)

 

CO2

CH4

N2O

1

gas

2.7

0.1

0.03

3.68        Method 2 — gas flared from crude oil refining

                For subparagraph 3.62 (4) (a) (ii), method 2 is:

where:

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in crude oil refining during the year, measured in CO2‑e tonnes.

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, measured in tonnes in accordance with Division 2.3.3.

EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in the crude oil refining during the year, measured in CO2‑e tonnes per tonne of fuel type (i) flared, estimated in accordance with method 2 in Division 2.3.3.

OFi is 0.98/0.995, which is the correction factor for the oxidation of fuel type (i) flared.

QCO2 is the quantity of CO2 within the fuel type (i) in the crude oil refining during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.

3.69        Method 3 — gas flared from crude oil refining

                For subparagraph 3.62 (4) (a) (iii), method 3 is the same as method 2 under section 3.68, but the emission factor EFij must be determined in accordance with method 3 for the consumption of gaseous fuels as specified in Division 2.3.4.

Division 3.3.6        Natural gas production or processing, other than emissions that are vented or flared

3.70        Application

                This Division applies to fugitive emissions from natural gas production or processing activities, other than emissions that are vented or flared, including emissions from:

                (a)    a gas wellhead through to the inlet of gas processing plants; and

               (b)    a gas wellhead through to the tie-in points on gas transmission systems, if processing of natural gas is not required; and

                (c)    gas processing plants; and

               (d)    well servicing; and

                (e)    gas gathering; and

                (f)    gas processing and associated waste water disposal and acid gas disposal activities.

3.71        Available methods

         (1)   Subject to section 1.18, one of the following methods must be used for estimating fugitive emissions of methane (other than emissions that are vented or flared) released during a year from the operation of a facility that is constituted by natural gas production and processing:

                (a)    method 1 under section 3.72;

               (b)    method 2 under section 3.73.

Note   There is no method 3 or 4 for this Division.

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

3.72        Method 1 — natural gas production and processing (other than emissions that are vented or flared)

         (1)   Method 1 is:

where:

Eij is the fugitive emissions of methane (j) (other than emissions that are vented or flared) from the natural gas production and processing during the year measured in CO2‑e tonnes.

Σk is the total emissions of methane (j), measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) specified in column 2 of an item in the table in subsection (2), if the equipment is used in the natural gas production and processing.

Qik is the total of the quantities of natural gas that pass through each equipment type (k), or the number of equipment units of type (k) specified in column 2 of the table in subsection (2), measured in tonnes.

EFijk is the emission factor for methane (j) measured in CO2‑e tonnes per tonne of natural gas that passes through each equipment type (k) during the year if the equipment is used in the natural gas production and processing.

Qi is the total quantity of natural gas (i) that passes through the natural gas production and processing measured in tonnes.

EF(l) ij is 1.2 x 10‑3, which is the emission factor for methane (j) from general leaks in the natural gas production and processing, measured in CO2‑e tonnes per tonne of natural gas that passes through the natural gas production and processing.

         (2)   For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor for methane (j) for an equipment type (k) specified in column 2 of that item:

 

Item

Equipment type (k)

Emission factor for methane (j)
(tonnes CO2‑e/tonnes fuel throughput)

1

Internal floating tank

8.4 10‑7

2

Fixed roof tank

4.2  10‑6

3

Floating tank

3.2  10‑6

         (3)   For EF(l) ij in subsection (1), general leaks in the natural gas production and processing comprise the emissions (other than vent emissions) from equipment listed in sections 5.4.3, 5.6.4 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing.

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

         (1)   Method 2 is:

where:

Eij is the fugitive emissions of methane (j) from the natural gas production and processing during the year measured in CO2‑e tonnes.

Σk is the emissions of methane (j) measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing.

Qik is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per tonne of natural gas that passes through each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing.

         (2)   For EFijk, the emission factors for methane (j) as the natural gas passes through the equipment types (k) are:

                (a)    as listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4 and 6.1.2 of the API Compendium, for the equipment type; or

               (b)    if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type — those factors.

Division 3.3.7        Natural gas transmission

3.74        Application

                This Division applies to fugitive emissions from natural gas transmission activities.

3.75        Available methods

         (1)   Subject to section 1.18 and subsection (2), one of the following methods must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, released from the operation of a facility that is constituted by natural gas transmission through a system of pipelines during a year:

                (a)    method 1 under section 3.76;

               (b)    method 2 under section 3.77.

Note   There is no method 3 or 4 for this Division.

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

3.76        Method 1 — natural gas transmission

                Method 1 is:

where:

Eij is the fugitive emissions of gas type (j) from natural gas transmission through a system of pipelines of length (i) during the year measured in CO2‑e tonnes.

Qi is the length of the system of pipelines (i) measured in kilometres.

EFij is the emission factor for gas type (j), which is 0.02 for carbon dioxide and 8.7 for methane, measured in tonnes of CO2‑e emissions per kilometre of pipeline (i).

3.77        Method 2 — natural gas transmission

         (1)   Method 2 is:

where:

Ej is the fugitive emissions of gas type (j) measured in CO2‑e tonnes from the natural gas transmission through the system of pipelines during the year.

Σk is the total of emissions of gas type (j) measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas transmission.

Qk is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) or the number of equipment units of type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas transmission.

EFjk is the emission factor of gas type (j) measured in CO2‑e tonnes for each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, where the equipment is used in the natural gas transmission.

         (2)   For EFjk, the emission factors for a gas type (j) as the natural gas passes through the equipment type (k) are:

                (a)    as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or

               (b)    as listed in that Compendium for the equipment type with emission factors adjusted for variations in estimated gas composition, in accordance with that Compendium’s sections 5 and 6.1.2, and the requirements of Division 2.3.3; or

                (c)    as listed in that Compendium for the equipment type with emission factors adjusted for variations in the type of equipment material estimated in accordance with the results of published research for the crude oil industry and the principles of section 1.13; or

               (d)    if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type — those factors.

Division 3.3.8        Natural gas distribution

3.78        Application

                This Division applies to fugitive emissions from natural gas distribution activities.

3.79        Available methods

         (1)   Subject to section 1.18 and subsection (2), one of the following methods must be used for estimating fugitive emissions of each gas type, being carbon dioxide and methane, released during a year from the operation of a facility that is constituted by natural gas distribution through a system of pipelines:

                (a)    method 1 under section 3.80;

               (b)    method 2 under section 3.81.

Note   There is no method 3 or 4 for this Division.

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

3.80        Method 1 — natural gas distribution

         (1)   Method 1 is:

where:

Ejp is the fugitive emissions of gas type (j) that result from natural gas distribution through a system of pipelines with sales of gas in a State or Territory (p) during the year, measured in CO2-e tonnes.

Sp is the total sales during the year from the pipeline system in a State or Territory (p), measured in terajoules.

%UAGp is the percentage of unaccounted for gas in the pipeline system in a State or Territory, relative to the amount of gas issued annually by gas utilities in that State or Territory.

Note   The value 0.55 following the variable %UAGp in method 1 represents the proportion of gas that is unaccounted for and released as emissions.

Cjp is the natural gas composition factor for gas type (j) for the natural gas supplied from the pipeline system in a State or Territory (p), measured in CO2-e tonnes per terajoule.

         (2)   For %UAGp in subsection (1), column 3 of an item in the following table specifies the percentage of unaccounted for gas in the pipeline system in a State or Territory specified in column 2 of that item.

         (3)   For Cjp in subsection (1), columns 4 and 5 of an item in the following table specify the natural gas composition factor for carbon dioxide and methane for a pipeline system in a State or Territory specified in column 2.

 

Item

State

Unaccounted for gas (a)%

Natural gas composition factor (a)(tonnes CO2‑e/TJ)

 

UAGp

CO2

CH4

1

NSW and ACT

2.40

0.8

328

2

VIC

2.75

0.9

326

3

QLD

2.63

0.8

317

4

WA

2.55

1.1

306

5

SA

4.00

0.8

328

6

TAS

0.40

0.9

326

7

NT

0.10

0.0

264

3.81        Method 2 — natural gas distribution

         (1)   Method 2 is:

where:

Ej is the fugitive emissions of gas type (j) that result from the natural gas distribution during the year measured in CO2‑e tonnes.

Σk is the total of emissions of gas type (j) measured in CO2‑e tonnes and estimated by summing up the emissions from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas distribution.

Qk is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) or the number of equipment units of type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas distribution.

EFjk is the emission factor for gas type (j) measured in CO2‑e tonnes for each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas distribution.

         (2)   For EFjk, the emission factors for gas type (j) as the natural gas passes through the equipment type (k) are:

                (a)    as listed in sections 5 and 6.1.2 of the API Compendium; or

               (b)    as listed in that Compendium for the equipment type with emission factors adjusted for variations in estimated gas composition, in accordance with that Compendium’s Sections 5 and 6.1.2, and the requirements of Division 2.3.3; or

                (c)    as listed in that Compendium for the equipment type with emission factors adjusted for variations in the type of equipment material using adjusted factors; or

               (d)    if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type — those factors.

         (3)   In paragraph 3.81 (2) (c), a reference to factors adjusted is a reference to the factors in Table 5-3 of the publication entitled Greenhouse Gas Emission Estimation Methodologies, Procedures and Guidelines for the Natural Gas Distribution Sector, American Gas Association, April 2008, that are adjusted for variations in estimated gas composition in accordance with:

                (a)    section 5.2.1 of that publication; and

               (b)    Division 2.3.3.

Division 3.3.9        Natural gas production or processing (emissions that are vented or flared)

3.82        Application

                This Division applies to fugitive emissions from venting or flaring from natural gas production or processing activities, including emissions from:

                (a)    the venting of natural gas; and

               (b)    the venting of waste gas and vapour streams at facilities that are constituted by natural gas production or processing; and

                (c)    the flaring of natural gas, waste gas and waste vapour streams at those facilities.

3.83        Available methods

         (1)   Subject to section 1.18, for estimating emissions (emissions that are vented or flared) released during a year from the operation of a facility that is constituted by natural gas production and processing the methods as set out in this section must be used.

         (2)   One of the following methods must be used for estimating fugitive emissions that result from deliberate releases from process vents, system upsets and accidents:

                          (i)    method 1 under section 3.84; and

                         (ii)    method 4 under Part 1.3.

Note   There is no method 2 or 3 for subsection (2).

         (3)   For estimating emissions released from gas flared from natural gas production and processing:

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

                          (i)    method 1 under section 3.85;

                         (ii)    method 2 under section 3.86;

                        (iii)    method 3 under section 3.87; and

               (b)    method 1 under section 3.85 must be used for estimating emissions of methane released; and

                (c)    method 1 under section 3.85 must be used for estimating emissions of nitrous oxide released.

Note   The flaring of gas from natural gas production and processing releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 in section 3.85 is a reference to these gases. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide and no method 2, 3 or 4 for emissions of nitrous oxide or methane.

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

Subdivision 3.3.9.1     Fugitive emissions that result from deliberate releases from process vents, system upsets and accidents

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

                Method 1 is, for a process mentioned in column 2 of an item in the following table, as described in the section of the API Compendium mentioned in column 3 for the item.

Item

Emission process

API Compendium section

1

Gas treatment processes

Section 5.1

2

Cold process vents

Section 5.3

3

Natural gas blanketed tank emissions

Section 5.4.4

4

Other venting sources  — gas driven pneumatic devices

Section 5.6.1

5

Other venting sources — gas driven chemical injection pumps

Section 5.6.2

6

Other venting sources — exploratory drilling and well testing

Section 5.6.3

7

Non-routine activities — production related non-routine emissions

Section 5.7.1 or 5.7.2

8

Non-routine activities — gas processing related non-routine emissions

Section 5.7.1 or 5.7.3

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

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

         (1)   Method 1 is:

where:

Eij is the emissions of gas type (j) measured in CO2‑e tonnes that result from a fuel type (i) flared in the natural gas production and processing during the year.

Qi is the quantity measured in tonnes of gas flared during the year.

EFij is the emission factor for gas type (j) measured in CO2‑e tonnes of emissions per tonne of gas flared (i) in the natural gas production and processing during the year.

         (2)   For EFij mentioned in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor for fuel type (i) specified in column 2 of that item.

 

Item

fuel type (i)

Emission factor of gas type (j) (tonnes CO2‑e/tonnes fuel flared)

 

CO2

CH4

N2O

1

gas

2.7

0.1

0.03

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

                For subparagraph 3.83 (3) (a) (ii), method 2 is:

where:

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in the natural gas production and processing during the year, measured in CO2‑e tonnes.

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in the natural gas production and processing during the year, measured in tonnes in accordance with Division 2.3.3.

EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in the natural gas production and processing during the year, measured in CO2‑e tonnes per tonne of fuel type (i) flared, estimated in accordance with Division 2.3.3.

OFi is 0.98/0.995, which is the correction factor for the oxidation of fuel type (i) flared.

QCO2 is the quantity of CO2 within the fuel type (i) in the natural gas production and processing during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.

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

                For subparagraph 3.83 (3) (a) (iii), method 3 is the same as method 2 under section 3.86, but the emission factor (EFij) must be determined in accordance with method 3 for the consumption of gaseous fuels as specified in Division 2.3.4.

Part 3.4              Carbon capture and storage — fugitive emissions

Division 3.4.1        Preliminary

3.88        Outline of Part

                This Part provides for fugitive emissions from carbon capture and storage.

Division 3.4.2        Transport of captured carbon dioxide

Subdivision 3.4.2.1     Preliminary

3.89        Application

                This Division applies to fugitive emissions from the transport of carbon dioxide captured for permanent storage.

Note   Section 1.19A defines when carbon dioxide is captured for permanent storage.

3.90        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 the transport of carbon dioxide captured for permanent storage the methods as set out in this section must be used.

Emissions from transport of carbon dioxide involving transfer

         (2)   If the carbon dioxide is transferred to a relevant person for injection in accordance with the legislation mentioned in section 1.19A for the person, method 1 under section 3.91 must be used for estimating fugitive emissions of carbon dioxide that result from the transport of the carbon dioxide for that injection.

Emissions from transport of carbon dioxide not involving transfer

         (3)   If:

                (a)    the carbon dioxide is captured by a relevant person for injection in accordance with the legislation mentioned in section 1.19A for the person; and

               (b)    the carbon dioxide is not transferred to another person for the purpose of injection;

then method 1 under section 3.92 must be used for estimating fugitive emissions of carbon dioxide that result from the transport of the carbon dioxide for that injection.

Note   There is no method 2, 3 or 4 for subsections (2) and (3).

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

Subdivision 3.4.2.2     Emissions from transport of carbon dioxide captured for permanent storage involving transfer

3.91        Method 1 — emissions from transport of carbon dioxide involving transfer

                For subsection 3.90 (2), method 1 is:

where:

ECO2 is the emissions of carbon dioxide during the year from transportation of carbon dioxide captured for permanent storage to the storage site, measured in CO2‑e tonnes.

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 the quantity of carbon dioxide transferred during the year worked out under Division 1.2.3  and measured in cubic metres at standard conditions of pressure and temperature.

Qinj is the quantity of carbon dioxide injected into the storage site during the year and measured in cubic metres at standard conditions of pressure and temperature.

Subdivision 3.4.2.2     Emissions from transport of carbon dioxide captured for permanent storage not involving transfer

3.92        Method 1 — emissions from transport of carbon dioxide not involving transfer

                For subsection 3.90 (3), method 1 is:

where:

ECO2 is the emissions of carbon dioxide during the year from transportation of carbon dioxide captured for permanent storage to the storage site, measured in CO2‑e tonnes.

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 the quantity of carbon dioxide captured during the year worked out under Division 1.2.3  and measured in cubic metres at standard conditions of pressure and temperature.

Qinj is the quantity of carbon dioxide injected into the storage site during the year and measured in cubic metres at standard conditions of pressure and temperature.

Chapter 4    Industrial processes emissions

Part 4.1              Preliminary

  

4.1           Outline of Chapter

         (1)   This Chapter provides for emissions from:

                (a)    the consumption of carbonates; or

               (b)    the use of fuels as:

                          (i)    feedstock; or

                         (ii)    carbon reductants;

                        from sources that are industrial processes mentioned in subsection (2).

         (2)   For subsection (1), the industrial processes are as follows:

                (a)    in Part 4.2:

                          (i)    producing cement clinker (see Division 4.2.1);

                         (ii)    producing lime (see Division 4.2.2);

                        (iii)    using carbonate for the production of a product other than cement clinker, lime or soda ash (see Division 4.2.3);

                        (iv)    using and producing soda ash (see Division 4.2.4);

               (b)    in Part 4.3 — the production of:

                          (i)    ammonia (see Division 4.3.1);

                         (ii)    nitric acid (see Division 4.3.2);

                        (iii)    adipic acid (see Division 4.3.3);

                        (iv)    carbide (see Division 4.3.4);

                         (v)    a chemical or mineral product other than carbide using a carbon reductant or carbon anode (see Division 4.3.5);

                (c)    in Part 4.4 — the production of:

                          (i)    iron and steel (see Division 4.4.1);

                         (ii)    ferroalloy metals (see Division 4.4.2);

                        (iii)    aluminium (see Divisions 4.4.3 and 4.4.4);

                        (iv)    other metals (see Division 4.4.5).

         (3)   This Chapter, in Part 4.5, also applies to emissions released from the consumption of the following synthetic gases:

                (a)    hydrofluorocarbons;

               (b)    sulphur hexafluoride.

         (4)   This Chapter does not apply to emissions from fuel combusted for energy production.

Part 4.2              Industrial processes — mineral products

Division 4.2.1        Cement clinker production

4.2           Application

                This Division applies to cement clinker production.

4.3           Available methods

         (1)   Subject to section 1.18, one of the following methods must be used for estimating emissions of carbon dioxide released during a year from the operation of a facility that is constituted by the production of cement clinker:

                (a)    method 1 under section 4.4;

               (b)    method 2 under section 4.5;

                (c)    method 3 under section 4.8;

               (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.

4.4           Method 1 — cement clinker production

                Method 1 is:

where:

Eij is the emissions of carbon dioxide (j) released from the production of cement clinker (i) during the year measured in CO2‑e tonnes.

EFij is 0.534, which is the carbon dioxide (j) emission factor for cement clinker (i), measured in tonnes of emissions of carbon dioxide per tonne of cement clinker produced.

EFtoc,j is 0.010, which is the carbon dioxide (j) emission factor for carbon‑bearing non‑fuel raw material, measured in tonnes of emissions of carbon dioxide per tonne of cement clinker produced.

Ai is the quantity of cement clinker (i) produced during the year measured in tonnes and estimated under Division 4.2.5.

Ackd is the quantity of cement kiln dust produced as a result of the production of cement clinker during the year, measured in tonnes and estimated under Division 4.2.5.

Fckd is:

                (a)    the degree of calcination of cement kiln dust produced as a result of the production of cement clinker during the year, expressed as a decimal fraction; or

               (b)    if the information mentioned in paragraph (a) is not available — the value 1.

4.5           Method 2 — cement clinker production

         (1)   Method 2 is:

where:

Eij is the emissions of carbon dioxide (j) released from the production of cement clinker (i) during the year measured in CO2‑e tonnes.

EFij is as set out in subsection (2).

EFtoc,j is 0.010, which is the carbon dioxide (j) emission factor for carbon‑bearing non‑fuel raw material, measured in tonnes of emissions of carbon dioxide per tonne of cement clinker produced.

Ai is the quantity of cement clinker (i) produced during the year measured in tonnes and estimated under Division 4.2.5.

Ackd is the quantity of cement kiln dust produced as a result of the production of cement clinker during the year, measured in tonnes and estimated under Division 4.2.5.

Fckd is:

                (a)    the degree of calcination of cement kiln dust produced as a result of the production of cement clinker during the year, expressed as a decimal fraction; or

               (b)    if the information mentioned in paragraph (a) is not available — the value 1.

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 subsection (1), EFij is:

where:

FCaO is the estimated fraction of cement clinker that is calcium oxide derived from carbonate sources and produced from the operation of the facility.

FMgO is the estimated fraction of cement clinker that is magnesium oxide derived from carbonate sources and produced from the operation of the facility.

Note   The molecular weight ratio of carbon dioxide to calcium oxide is 0.785, and the molecular weight ratio of carbon dioxide to magnesium oxide is 1.092.

         (3)   The cement clinker must be sampled and analysed in accordance with sections 4.6 and 4.7.

4.6           General requirements for sampling cement clinker

         (1)   A sample of cement clinker must be derived from a composite of amounts of the cement clinker produced.

         (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.

Note   An appropriate standard is AS 4264.4—1996, Coal and coke – Sampling Part 4: Determination of precision and bias.

         (5)   The value obtained from the sample must only be used for the production period for which it was intended to be representative.

4.7           General requirements for analysing cement clinker

         (1)   Analysis of a sample of cement clinker, including determining the fraction of the sample that is calcium oxide or magnesium oxide, must be done in accordance with industry practice and must be consistent with the principles in section 1.13.

         (2)   The minimum frequency of analysis of samples of cement clinker must be in accordance with the Tier 3 method for cement clinker in section 2.2.1.1 in Chapter 2 of Volume 3 of the 2006 IPCC Guidelines.

4.8           Method 3 — cement clinker production

         (1)   Method 3 is:

Step 1

Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each pure carbonate calcined in the production of cement clinker during the year as follows:

where:

Eij is the emissions of carbon dioxide (j) released from the carbonate (i) calcined in the production of cement clinker during the year measured in CO2‑e tonnes.

 

EFij is the carbon dioxide (j) emission factor for the carbonate (i) measured in tonnes of emissions of carbon dioxide per tonne of pure carbonate, as follows:

   (a)  for calcium carbonate — 0.440; and

  (b)  for magnesium carbonate — 0.522; and

   (c)  for dolomite — 0.477; and

  (d)  for any other pure carbonate — the factor for the carbonate in accordance with section 2.1 of Chapter 2 of Volume 3 of the 2006 IPCC Guidelines.

Qi is the quantity of the pure carbonate (i) consumed in the calcining process for the production of cement clinker during the year measured in tonnes and estimated under Division 4.2.5.

Fcal is:

(a)    the amount of the carbonate calcined in the production of cement clinker during the year, expressed as a decimal fraction; or

(b)   if the information mentioned in paragraph (a) is not available — the value 1.

Ackd is the quantity of cement kiln dust lost from the kiln in the production of cement clinker during the year measured in tonnes and estimated under Division 4.2.5.

EFckd is 0.440, which is the carbon dioxide emission factor for calcined cement kiln dust lost from the kiln.

Fckd is:

   (a)  the fraction of calcination achieved for cement kiln dust lost from the kiln in the production of cement clinker during the year; or

  (b)  if the information mentioned in paragraph (a) is not available — the value 1.

Qtoc is the quantity of total carbon‑bearing non‑fuel raw material consumed in the production of cement clinker during the year measured in tonnes and estimated under Division 4.2.5.

EFtoc is 0.010, which is the emission factor for carbon‑bearing non‑fuel raw material, measured in tonnes of carbon dioxide produced per tonne 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.

Step 2

Add together the amount of emissions of carbon dioxide as measured in CO2‑e tonnes released for each pure carbonate calcined in the production of cement clinker during the year.

         (2)   For the factor EFckd in subsection (1), the carbon dioxide emission factor for calcined cement kiln dust is assumed to be the same as the emission factor for calcium carbonate.

         (3)   For the factor Qtoc in subsection (1), the quantity of carbon‑bearing non‑fuel raw material must be estimated in accordance with Division 4.2.5 as if a reference to carbonates consumed from the activity was a reference to carbon‑bearing non‑fuel raw material consumed from the activity.

         (4)   Method 3 requires carbonates to be sampled and analysed in accordance with sections 4.9 and 4.10.

4.9           General requirements for sampling carbonates

         (1)   Method 3 requires carbonates to be sampled in accordance with the procedure for sampling cement clinker specified under section 4.6 for method 2.

         (2)   In applying section 4.6, a reference in that section to cement clinker is taken to be a reference to a carbonate.

4.10        General requirements for analysing carbonates

         (1)   Analysis of samples of carbonates, including determining the quantity (in tonnes) of pure carbonate, must be done in accordance with industry practice or standards, and must be consistent with the principles in section 1.13.

         (2)   The minimum frequency of analysis of samples of carbonates must be in accordance with the Tier 3 method in section 2.2.1.1 of Chapter 2 of Volume 3 of the 2006 IPCC Guidelines.

Division 4.2.2        Lime production

4.11        Application

                This Division applies to lime production (other than the in‑house production of lime in the metals industry).

4.12        Available methods

         (1)   Subject to section 1.18, one of the following methods must be used for estimating emissions of carbon dioxide released during a year from the operation of a facility that is constituted by the production of lime (other than the in‑house production of lime in the ferrous metals industry):

                (a)    method 1 under section 4.13;

               (b)    method 2 under section 4.14;

                (c)    method 3 under section 4.17;

               (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.

4.13        Method 1 — lime production

         (1)   Method 1 is:

where:

Eij is the emissions of carbon dioxide (j) released from the production of lime (i) during the year, measured in CO2‑e tonnes.

Ai is the quantity of lime produced during the year, measured in tonnes and estimated under Division 4.2.5.

Alkd is the quantity of lime kiln dust lost as a result of the production of lime during the year, measured in tonnes and estimated under Division 4.2.5.

Flkd is:

                (a)    the fraction of calcination achieved for lime kiln dust in the production of lime during the year; or

               (b)    if the data mentioned in paragraph (a) is not available — the value 1.

EFij is the carbon dioxide (j) emission factor for lime, measured in tonnes of emission of carbon dioxide per tonne of lime produced, as follows:

                (a)    for commercial lime production — 0.675;

               (b)    for non‑commercial lime production — 0.730;

                (c)    for magnesian lime and dolomitic lime production — 0.860.

         (2)   In this section:

dolomitic lime is lime formed from limestone containing more than 35% magnesium carbonate.

magnesian lime is lime formed from limestone containing 5–35% magnesium carbonate.

4.14        Method 2 — lime production

         (1)   Method 2 is:

where:

Eij is the emissions of carbon dioxide (j) released from the production of lime (i) during the year, measured in CO2-e tonnes.

Ai is the quantity of lime produced during the year, measured in tonnes and estimated under Division 4.2.5.

Alkd is the quantity of lime kiln dust lost as a result of the production of lime during the year, measured in tonnes and estimated under Division 4.2.5.

Flkd is:

                (a)    the fraction of calcination achieved for lime kiln dust in the production of lime during the year; or

               (b)    if the data in paragraph (a) is not available — the value 1.

EFij is worked out using the following formula:

where:

FCaO is the estimated fraction of lime that is calcium oxide derived from carbonate sources and produced from the operation of the facility.

FMgO is the estimated fraction of lime that is magnesium oxide derived from carbonate sources and produced from the operation of the facility.

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 lime to be sampled and analysed in accordance with sections 4.15 and 4.16.

4.15        General requirements for sampling

         (1)   A sample of lime must be derived from a composite of amounts of the lime produced.

Note   Appropriate standards for sampling are:

·      ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime

·      ASTM C50-00 (2006), Standard Practice for Sampling, Sample Preparation, Packaging, and Marking of Lime and Limestone Products

·      AS 4489.0–1997 Test methods for limes and limestones — General introduction and list of methods.

         (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.

Note   An appropriate standard 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 production period for which it was intended to be representative.

4.16        General requirements for analysis of lime

         (1)   Analysis of a sample of lime, including determining the fractional purity of the sample, must be done in accordance with industry practice and must be consistent with the principles in section 1.13.

         (2)   The minimum frequency of analysis of samples of lime must be in accordance with the Tier 3 method in section 2.2.1.1 of Chapter 2 of Volume 3 of the 2006 IPCC Guidelines.

4.17        Method 3 — lime production

         (1)   Method 3 is:

Step 1

Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each pure carbonate calcined in the production of lime during the year as follows:

where:

Eij is the emissions of carbon dioxide (j) released from a carbonate (i) calcined in the production of lime during the year measured in CO2‑e tonnes.

 

EFij is the carbon dioxide (j) emission factor for the carbonate (i), measured in tonnes of emissions of carbon dioxide per tonne of pure carbonate as follows:

   (a)  for calcium carbonate — 0.440;

  (b)  for magnesium carbonate — 0.522;

   (c)  for dolomite — 0.477;

  (d)  for any other carbonate — the factor for the carbonate in accordance with section 2.1 of Chapter 2 of Volume 3 of the 2006 IPCC Guidelines.

 

Qi is the quantity of the pure carbonate (i) entering the calcining process in the production of lime during the year measured in tonnes and estimated under Division 4.2.5.

Fcal is:

(a)    the amount of the carbonate calcined in the production of lime during the year expressed as a decimal fraction; or

(b)   if the information mentioned in paragraph (a) is not available — the value 1.

Alkd is the quantity of lime kiln dust lost in the production of lime during the year, measured in tonnes and estimated under Division 4.2.5.

 

EFlkd is 0.440, which is the emission factor for calcined lime kiln dust lost from the kiln.

Flkd is:

   (a)  the fraction of calcination achieved for lime kiln dust in the production of lime during the year; or

  (b)  if the data in paragraph (a) is not available — the value 1.

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.

Step 2

Add together the amount of emissions of carbon dioxide for each pure carbonate calcined in the production of lime during the year.

         (2)   For the factor EFlkd in subsection (1), the emission factor for calcined lime kiln dust is assumed to be the same as the emission factor for calcium carbonate.

         (3)   Method 3 requires each carbonate to be sampled and analysed in accordance with sections 4.18 and 4.19.

4.18        General requirements for sampling

         (1)   For section 4.17, carbonates must be sampled in accordance with the procedure for sampling lime specified under section 4.15 for method 2.

         (2)   In applying section 4.15, a reference in that section to lime is taken to be a reference to carbonates.

4.19        General requirements for analysis of carbonates

         (1)   For section 4.17, samples must be analysed in accordance with the procedure for analysing lime specified under section 4.16 for method 2.

         (2)   In applying section 4.16, a reference in that section to lime is taken to be a reference to carbonates.

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

4.20        Application

                This Division applies to emissions of carbon dioxide from the consumption of a carbonate (other than soda ash) but does not apply to:

                (a)    emissions of carbon dioxide from the calcination of a carbonate in the production of cement clinker; or

               (b)    emissions of carbon dioxide from the calcination of a carbonate in the production of lime; or

                (c)    emissions of carbon dioxide from the calcination of a carbonate in the process of production of soda ash; or

               (d)    emissions from the consumption of carbonates following their application to soil.

Examples of activities involving the consumption of carbonates

1   Metallurgy.

2   Glass manufacture, including fibreglass and mineral wools.

3   Magnesia production.

4   Construction.

5   Environment pollution control.

6   Use as a flux or slagging agent.

7   In-house production of lime in the metals industry.

8   Phosphoric acid production from phosphate rock containing carbonates.

4.21        Available methods

         (1)   Subject to section 1.18 one of the following methods must be used for estimating emissions of carbon dioxide released during a year from the operation of a facility constituted by the calcination or any other use of carbonates that produces carbon dioxide (the industrial process) in an industrial process (other than cement clinker production or lime production):

                (a)    method 1 under section 4.22;

               (b)    method 3 under section 4.23;

                (c)    method 4 under Part 1.3.

Note   There is no method 2 for this Division.

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

4.22        Method 1 — product other than cement clinker, lime or soda ash [see Note 2]

                Method 1 is:

Step 1

Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each raw carbonate material consumed in the industrial process during the year as follows:

where:

 

Eij is the emissions of carbon dioxide (j) released from raw carbonate material (i) consumed in the industrial process during the year measured in CO2‑e tonnes.

Qi is the quantity of the raw carbonate material (i) consumed in the calcining process for the industrial process during the year measured in tonnes and estimated under Division 4.2.5.

EFij is the carbon dioxide (j) emission factor for the raw carbonate material (i) measured in tonnes of emissions of carbon dioxide per tonne of carbonate, that is:

   (a)  for calcium carbonate — 0.396; and

  (b)  for magnesium carbonate — 0.522; and

   (c)  for dolomite — 0.453; and

  (d)  for any other raw carbonate material — the factor for the raw carbonate material in accordance with section 2.1 of Chapter 2 of Volume 3 of the 2006 IPCC Guidelines.

 

Fcal is:

   (a)  the fraction of the raw carbonate material consumed in the industrial process during the year; or

  (b)  if the information in paragraph (a) is not available — the value 1.

Step 2

Add together the amount of emissions of carbon dioxide for each carbonate consumed in the industrial process during the year.

Note   For the factor Efij in step 1, the emission factor value given for a raw carbonate material is based on a method of calculation that ascribed the following content to the material:

(a)   for calcium carbonate — at least 90% calcium carbonate;

(b)   for magnesium carbonate — 100% magnesium carbonate;

(c)   for dolomite — at least 95% dolomite.

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

         (1)   Method 3 is:

Step 1

Measure the amount of emissions of carbon dioxide in CO2‑e tonnes released from each pure carbonate consumed in the industrial process during the year as follows:

where:

Eij is the emissions of carbon dioxide (j) from a pure carbonate (i) consumed in the industrial process during the year measured in CO2‑e tonnes.

 

EFij is the carbon dioxide (j) emission factor for the pure carbonate (i) in tonnes of emissions of carbon dioxide per tonne of pure carbonate, that is:

   (a)  for calcium carbonate — 0.440;

  (b)  for magnesium carbonate — 0.522;

   (c)  for dolomite — 0.477;

  (d)  for any other pure carbonate — the factor for the carbonate in accordance with Chapter 2 of Volume 3 of the 2006 IPCC Guidelines.

Qi is the quantity of the pure carbonate (i) entering the industrial process during the year measured in tonnes and estimated under Division 4.2.5.

 

Fcal is:

   (a)  the fraction of the pure carbonate consumed in the industrial process during the year; or

  (b)  if the information in paragraph (a) is not available — the value 1.

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.

Step 2

Add together the amount of emissions of carbon dioxide for each pure carbonate consumed in the industrial process during the year.

         (2)   Method 3 requires each carbonate to be sampled and analysed in accordance with sections 4.24 and 4.25.

4.24        General requirements for sampling carbonates

         (1)   A sample of a carbonate must be derived from a composite of amounts of the carbonate consumed.

         (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.

Note   An example of an appropriate standard is AS 4264.4—1996 – Coal and coke – sampling – Determination of precision and bias.

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

4.25        General requirements for analysis of carbonates

         (1)   Analysis of samples of carbonates must be in accordance with industry practice and must be consistent with the principles in section 1.13.

         (2)   The minimum frequency of analysis of samples of carbonates must be in accordance with the Tier 3 method of section 2.2.1.1 of Chapter 2 of Volume 3 of the 2006 IPCC Guidelines.

Division 4.2.4        Soda ash use and production

4.26        Application

                This Division applies to emissions from the use of soda ash and emissions of carbon dioxide from the chemical transformation of calcium carbonate, sodium chloride, ammonia and coke into sodium bicarbonate and soda ash.

Examples of uses of soda ash in industrial processes

1   Glass production.

2   Soap and detergent production.

3   Flue gas desulphurisation.

4   Pulp and paper production.

4.27        Outline of Division

                Emissions released from the use and production of soda ash must be estimated in accordance with:

                (a)    for the use of soda ash in production processes — Subdivision 4.2.4.1; or

               (b)    for the production of soda ash — Subdivision 4.2.4.2.

Subdivision 4.2.4.1     Soda ash use

4.28        Available methods

         (1)   Subject to section 1.18, one of the following methods must be used for estimating emissions of carbon dioxide released during a year from the operation of a facility constituted by the use of soda ash in a production process:

                (a)    method 1 under section 4.29;

               (b)    method 4 under Part 1.3.

Note   There is no method 2 or 3 for this Division.

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

4.29        Method 1 — use of soda ash

                Method 1 is:

where:

Eij is the emissions of carbon dioxide (j) from soda ash (i) consumed in the production process during the year measured in CO2‑e tonnes.

Qi is the quantity of soda ash (i) consumed in the production process during the year measured in tonnes and estimated under Division 4.2.5.

EFij is 0.415, which is the carbon dioxide (j) emission factor for soda ash (i) measured in tonnes of carbon dioxide emissions per tonne of soda ash.

Subdivision 4.2.4.2     Soda ash production

4.30        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 produces soda ash:

                (a)    method 1 under section 4.31;

               (b)    method 2 under section 4.32;

                (c)    method 3 under section 4.33;

               (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.

4.31        Method 1 — production of soda ash

                Method 1 is:

Step 1

Calculate the carbon content in fuel type (i) or carbonate material (j) delivered for the activity during the year measured in tonnes of carbon as follows:

 

where:

i means sum the carbon content values obtained for all fuel types (i).

CCFi is the carbon content factor mentioned in Schedule 3 measured in tonnes of carbon for each appropriate unit of fuel type (i) consumed during the year from the operation of the activity.

Qi is the quantity of fuel type (i) delivered for the activity during the year measured in an appropriate unit and estimated in accordance with Division 2.2.5, 2.3.6 and 2.4.6.

 

j means sum the carbon content values obtained for all pure carbonate material (j).

 

CCFj is the carbon content factor mentioned in Schedule 3 measured in tonnes of carbon for each tonne of pure carbonate material (j) consumed during the year from the operation of the activity.

Fj is the fraction of pure carbonate material (j) in the raw carbonate input material and taken to be 0.97 for calcium carbonate and 0.018 for magnesium carbonate.

L j is the quantity of raw carbonate input material (j) delivered for the activity during the year measured in tonnes and estimated in accordance with Division 4.2.5.

Step 2

Calculate the carbon content in products (p) leaving the activity during the year measured in tonnes of carbon as follows:

where:

p means sum the carbon content values obtained for all product types (p).

CCFp is the carbon content factor mentioned in Schedule 3 and measured in tonnes of carbon for each tonne of product type (p) produced during the year.

Fp is the fraction of pure carbonate material in the product type (p).

Ap is the quantity of product types (p) produced leaving the activity during the year measured in tonnes.

Step 3

Calculate the carbon content in waste by‑product types (r) leaving the activity, other than as an emission of greenhouse gas, during the year, measured in tonnes of carbon, as follows:

where:

Sr means sum the carbon content values obtained for all waste by‑product types (r).

CCFr is the carbon content factor mentioned in Schedule 3 measured in tonnes of carbon for each tonne of waste by‑product types (r).

Fr is the fraction of pure carbonate material in the 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

Calculate 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 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.

Sj has the same meaning as in step 1.

CCFj has the same meaning as in step 1.

ΔSqj is the change in stocks of pure carbonate material (j) 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

Calculate the emissions of carbon dioxide released from the operation of the activity during the year measured in CO2‑e tonnes as follows:

   (a)  add the amounts worked out under steps 2, 3 and 4 to work out a new amount (amount A);

  (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 a year.

4.32        Method 2 — production of soda ash

                Method 2 is:

Step 1

Calculate the carbon content in fuel types (i) or carbonate material (j) delivered for the activity during the year measured in tonnes of carbon as follows:

 

where:

i means sum the carbon content values obtained for all fuel types (i).

 

CCFi is the carbon content factor measured in tonnes of carbon for each appropriate unit of fuel type (i) consumed during the year from the operation of the activity.

 

Qi is the quantity of fuel type (i) delivered for the activity during the year measured in an appropriate unit and estimated in accordance with Divisions 2.2.5, 2.3.6 and 2.4.6.

 

j means sum the carbon content values obtained for all pure carbonate material (j).

CCFj is the carbon content factor measured in tonnes of carbon for each pure carbonate material (j) consumed during the year from the operation of the activity.

Lj is the quantity of pure carbonate material (j) delivered for the activity during the year measured in tonnes and estimated in accordance with Division 4.2.5.

Step 2

Calculate the carbon content in products (p) leaving the activity during the year measured in tonnes of carbon as follows:

where:

p means sum the carbon content values obtained for all product types (p).

CCFp is the carbon content factor measured in tonnes of carbon for each tonne of product 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

Calculate the carbon content in waste by‑product types (r) leaving the activity, other than as an emission of greenhouse gas, during the year, measured in tonnes of carbon, as follows:

where:

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 types (r).

Yr is the quantity of waste by‑product types (r) leaving the activity during the year measured in tonnes.

Step 4

Calculate 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 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.

Sj has the same meaning as in step 1.

CCFj has the same meaning as in step 1.

ΔSqj is the change in stocks of pure carbonate material (j) 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.

Step 5

Calculate the emissions of carbon dioxide released from the operation of the activity during the year measured in CO2‑e tonnes as follows:

   (a)  add the amounts worked out under steps 2, 3 and 4 to work out a new amount (amount A);

  (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 a year.

         (2)   If a fuel type (i) or carbonate material (j) 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 mentioned in Schedule 3, sampling and analysis of fuel type (i) or carbonate material (j) must be carried out to determine its carbon content.

         (3)   The sampling and analysis for fuel type (i) is to be carried out using the sampling and analysis provided for in Divisions 2.2.3, 2.3.3 and 2.4.3.

         (4)   The sampling for carbonate materials (j) is to be carried out in accordance with section 4.24.

         (5)   The analysis for carbonate materials (j) is to be carried out in accordance with ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime or an equivalent standard.

4.33        Method 3 — production of soda ash

         (1)   Subject to subsections (2) and (3), method 3 is the same as method 2.

         (2)   The sampling and analysis for fuel type (i) is to be carried out using the sampling and analysis provided for in Divisions 2.2.4, 2.3.4 and 2.4.4 or an equivalent sampling and analysis method.

         (3)   The sampling for carbonate material (j) is to be carried out in accordance with ASTM C50-00 (2006),  Standard Practice for Sampling, Sample Preparation, Packaging, and Marking of Lime and Limestone Products.

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

4.34        Purpose of Division

         (1)   This Division applies to the operation of a facility (the activity) that is constituted by:

                (a)    the production of cement clinker; or

               (b)    the production of lime; or

                (c)    the calcination of carbonates in an industrial process; or

               (d)    the use and production of soda ash.

         (2)   This Division sets out how the quantities of carbonates consumed from the operation of the activity, and the quantities of products derived from carbonates produced from the operation of the activity, are to be estimated for the following:

(a)    Ai and Ackd in section 4.4;

(b)    Qi and Qtoc in section 4.8;

(c)    Ai in section 4.13;

(d)    Qi and Alkd in section 4.17;

(e)    Qi in sections 4.22, 4.23, and 4.29.

4.35        Criteria for measurement

         (1)   Quantities of carbonates consumed from the operation of the activity, or quantities of products derived from carbonates produced from the operation of the activity, must be estimated in accordance with this section.

Acquisition  involves commercial transaction

         (2)   If the acquisition of the carbonates, or the dispatch of the products derived from carbonates, involves a commercial transaction, the quantity of the carbonates or products must be estimated using one of the following criteria:

                (a)    the quantity of the carbonates acquired or products dispatched for the facility during the year as evidenced by invoices issued by the vendor of the carbonates or products (criterion A);

               (b)    as provided in section 4.36 (criterion AA);

                (c)    as provided in section 4.37 (criterion AAA).

         (3)   If, during a year, criterion AA, or criterion AAA using paragraph 4.37 (2) (a), is used to estimate the quantity of carbonates acquired or products dispatched, then, in each year following that year, only criterion AA, or criterion AAA using paragraph 4.37 (2) (a), (respectively) is to be used.

Acquisition does not involve commercial transaction

         (4)   If the acquisition of the carbonates or the dispatch of the products does not involve a commercial transaction, the quantity the carbonates or products must be estimated using one of the following criteria:

                (a)    as provided in paragraph 4.37 (2) (a) (criterion AAA);

               (b)    as provided in section 4.38 (criterion BBB).

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

         (1)   For paragraph 4.35(b), criterion AA is the amount of carbonates consumed from the operation of the activity, or the amount of products derived from carbonates produced from the operation of the activity, during the year based on amounts delivered or dispatched during the year:

                (a)    as evidenced by invoices; and

               (b)    as adjusted for the estimated change in the quantity of the stockpiles of carbonates or the quantity of the stockpiles of products derived from carbonates during the year.

         (2)   The volume of carbonates, or products derived from carbonates, in the stockpile for the activity must be measured in accordance with industry practice.

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

         (1)   For paragraph 4.35 (c), criterion AAA is the direct measurement during the year of:

                (a)    the quantities of carbonates consumed from the operation of the activity; or

               (b)    the quantities of products derived from carbonates produced from the operation of the activity.

         (2)   The measurement must be:

                (a)    carried out using measuring equipment calibrated to a measurement requirement; or

               (b)    for measurement of the quantities of carbonates consumed from the operation of the activity — carried out 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 carbonates for the activity during the year is less than 1% of total consumption of the carbonates from the operation of the activity on average during the year; and

               (b)    the stockpile of the carbonates for the activity at the beginning of the year is less than 5% of total consumption of the carbonates from the operation of the activity during the year.

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

                For paragraph 4.35 (d), criterion BBB is the estimation of the consumption of carbonates, or the products derived from carbonates, during the year in accordance with industry practice if the equipment used to measure consumption of the carbonates, or the products derived from carbonates, is not calibrated to a measurement requirement.

4.39        Units of measurement

                Measurements of carbonates and products derived from carbonates must be converted to units of tonnes.

Part 4.3              Industrial processes — chemical industry

Division 4.3.1        Ammonia production

4.40        Application

                This Division applies to chemical industry ammonia production.

4.41        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 the production of ammonia:

                (a)    method 1 under section 4.42;

               (b)    method 2 under section 4.43;

                (c)    method 3 under section 4.44;

               (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.

4.42        Method 1 — ammonia production

         (1)   Method 1 is:

where:

Eij is the emissions of carbon dioxide released from the production of ammonia during the year measured in CO2‑e tonnes.

Qi is the quantity of each type of feedstock or type of fuel (i) consumed from the production of ammonia during the year, measured in the appropriate unit and estimated using a criterion in Division 2.3.6.

ECi is the energy content factor for fuel type (i) used as a feedstock in the production of ammonia during the year, estimated under section 6.5.

EFij is the carbon dioxide emission factor for each type of feedstock or type of fuel (i) used in the production of ammonia during the year, including the effects of oxidation, measured in kilograms for each gigajoule according to source as mentioned in Part 2 of Schedule 1.

R is the quantity of carbon dioxide measured in tonnes derived from the production of ammonia during the year, captured and transferred for use in the operation of another facility, estimated using an applicable criterion in Division 2.3.6 and in accordance with any other requirements of that Division.

4.43        Method 2 — ammonia production

         (1)   Method 2 is:

where:

Eij is the emissions of carbon dioxide released from the production of ammonia during the year measured in CO2‑e tonnes.

Qi is the quantity of each type of feedstock or type of fuel (i) consumed from the production of ammonia during the year, measured in the appropriate unit and estimated using an applicable criterion in Division 2.3.6.

ECi is the energy content factor for fuel type (i) used as a feedstock in the production of ammonia during the year, estimated under section 6.5.

EFij is the carbon dioxide emission factor for each type of feedstock or type of fuel (i) used in the production of ammonia during the year, including the effects of oxidation, measured in kilograms for each gigajoule according to source in accordance with subsection (3).

R is the quantity of carbon dioxide measured in tonnes derived from the production of ammonia during the year, captured and transferred for use in the operation of another facility, estimated using an applicable criterion in Division 2.3.6 and in accordance with any other requirements of that Division.

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)   The method for estimating emission factors for gaseous fuels in Division 2.3.3 applies for working out the factor EFij.

4.44        Method 3 — ammonia production

         (1)   Method 3 is the same as method 2 under section 4.43.

         (2)   In applying method 2 as method 3, the method for estimating emission factors for gaseous fuels in Division 2.3.4 applies for working out the factor EFij.

Division 4.3.2        Nitric acid production

4.45        Application

                This Division applies to chemical industry nitric acid production.

4.46        Available methods

         (1)   Subject to section 1.18 and this section, one of the following methods must be used for estimating emissions during a year from the operation of a facility that is constituted by the production of nitric acid at a plant:

                (a)    method 1 under section 4.47;

               (b)    method 2 under section 4.48;

                (c)    method 4 under Part 1.3.

Note   There is no method 3 for this Division.

         (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 if the plant has used measures to reduce nitrous oxide emissions.

4.47        Method 1 — nitric acid production

         (1)   Method 1 is:

where:

Eijk is the emissions of nitrous oxide released during the year from the production of nitric acid at plant type (k) measured in CO2‑e tonnes.

EFijk is the emission factor of nitrous oxide for each tonne of nitric acid produced during the year from plant type (k).

Aik is the quantity, measured in tonnes, of nitric acid produced during the year from plant type (k).

         (2)   For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor of nitrous oxide for each tonne of nitric acid produced from a plant type (k) specified in column 2 of that item.

Item

Plant type (k)

Emission factor of nitrous oxide
(tonnes CO2‑e per tonne of nitric acid production)

1

Atmospheric pressure plants

1.55

2

Medium pressure combustion plant

2.17

3

High pressure plant

2.79

Note   The emission factors specified in this table apply only to method 1 and the operation of a facility that is constituted by a plant that has not used measures to reduce nitrous oxide emissions.

4.48        Method 2 — nitric acid production

         (1)   Subject to this section, method 2 is the same as method 1 under section 4.47.

         (2)   In applying method 1 under section 4.47, to work out the factor EFijk:

                (a)    periodic emissions monitoring must be used and conducted in accordance with Part 1.3; and

               (b)    the emission factor must be measured as nitrous oxide in CO2‑e tonnes for each tonne of nitric acid produced during the year from the plant.

         (3)   For method 2, all data on nitrous oxide concentrations, volumetric flow rates and nitric acid production for each sampling period must be used to estimate the flow‑weighted average emission rate of nitrous oxide for each unit of nitric acid produced from the plant.

Division 4.3.3        Adipic acid production

4.49        Application

                This Division applies to chemical industry adipic acid production.

4.50        Available methods

         (1)   Subject to section 1.18, one of the methods for measuring emissions released in the production of adipic acid set out in section 3.4 of the 2006 IPCC Guidelines must be used for estimating emissions during a year from the operation of a facility that is constituted by the production of adipic acid.

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

Division 4.3.4        Carbide production

4.51        Application

                This Division applies to chemical industry carbide production.

4.52        Available methods

         (1)   Subject to section 1.18, one of the methods for measuring emissions from carbide production set out in section 3.6 of the 2006 IPCC Guidelines must be used for estimating emissions during a year from the operation of a facility that is constituted by carbide production.

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

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

4.53        Application

                This Division applies to emissions of carbon dioxide from activities producing a chemical or mineral product (other than carbide production), using a carbon reductant or carbon anode, including the following products:

                (a)    fused alumina;

               (b)    fused magnesia;

                (c)    fused zirconia;

               (d)    glass;

                (e)    synthetic rutile;

                (f)    titanium dioxide.

Note   Magnesia produced in a process that does not use an electric arc furnace must be reported under Division 4.2.3.

4.54        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 the production of a chemical or mineral product:

                (a)    method 1 under section 4.55;

               (b)    method 2 under section 4.56;

                (c)    method 3 under section 4.57;

               (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.

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

                Method 1 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.

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

         (1)   Subject to this section, method 2 is the same as method 1 under section 4.55.

         (2)   In applying method 1 as method 2, step 4 in section 4.55 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.

         (3)   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.

         (4)   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.

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

         (1)   Subject to this section, method 3 is the same as method 2 under section 4.56.

         (2)   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.

         (3)   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.

Part 4.4              Industrial processes — metal industry

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

4.63        Application

                This Division applies to emissions from production of the following:

                (a)    iron;

               (b)    steel;

                (c)    any metals produced using integrated metalworks.

4.64        Purpose of Division

         (1)   This Division applies to determining emissions released during a year from the operation of a facility that is constituted by an activity that produces a metal, for example, an integrated metalworks.

         (2)   An integrated metalworks means a metalworks that produces coke and a metal (for example, iron or steel).

         (3)   The emissions from the activity are to be worked out as a total of emissions released from the production of a metal and from all other emissions released from the operation of the activity (including the production of coke if the activity is an integrated metalworks).

         (4)   However, the amount of emissions to be determined for this source is only the amount of emissions from the use of coke as a carbon reductant in the metal production estimated in accordance with section 2.69.

Note   The amount of emissions to be determined for other activities is as provided for in other provisions of this Determination.

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

         (1)   Subject to section 1.18, one of the following methods must be used for estimating emissions released from the activity during a year:

                (a)    method 1 under section 4.66;

               (b)    method 2 under section 4.67;

                (c)    method 3 under section 4.68;

               (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.

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

                Method 1, based on a carbon mass balance approach, is:

 

Step 1

Calculate the carbon content in fuel types (i) or carbonaceous input material delivered for the activity during the year measured in tonnes of carbon as follows:

where:

Si means sum 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 Division 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 measured in tonnes of carbon 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 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

Calculate the carbon content in waste by‑product types (r) leaving the activity, other than as an emission of greenhouse gas, during the year, measured in tonnes of carbon, as follows:

where:

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 types (r).

Yr is the quantity of waste by‑product types (r) leaving the activity during the year measured in tonnes.

Step 4

Calculate 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 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

Calculate the emissions of carbon dioxide released from the operation of the activity during the year measured in CO2‑e tonnes as follows:

   (a)  add the amounts worked out under steps 2, 3 and 4 to work out a new amount (amount A);

  (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 a year.

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

         (1)   Subject to this section, method 2 is the same as method 1 under section 4.66.

      (1A)   In applying method 1 as method 2, step 4 in section 4.66 is to be omitted and the following step 4 substituted.

Step 4

Calculate 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 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.

         (2)   If a fuel type (