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Determinations/Other as amended, taking into account amendments up to National Greenhouse and Energy Reporting (Measurement) Amendment Determination 2012 (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: Industry, Innovation, Climate Change, Science, Research and Tertiary Education
Registered 17 Jul 2012
Start Date 01 Jul 2012
End Date 30 Jun 2013
Table of contents.

National Greenhouse and Energy Reporting (Measurement) Determination 2008

as amended

made under subsection 10 (3) of the

This compilation was prepared on 1 July 2012
taking into account amendments up to National Greenhouse and Energy Reporting (Measurement) Amendment Determination 2012 (No. 1)

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]                                                   21

                      1.2      Commencement                                                                                21

Division 1.1.1             Overview                                                                                            

                      1.3      Overview — general                                                                          21

                      1.4      Overview — methods for measurement                                              22

                      1.5      Overview — energy                                                                           22

                      1.6      Overview — scope 2 emissions                                                         22

                      1.7      Overview — assessment of uncertainty                                              23

Division 1.1.2             Definitions and interpretation                                                             

                      1.8      Definitions                                                                                        23

                      1.9      Interpretation                                                                                     30

                    1.10      Meaning of source                                                                            30

Part 1.1A                  Potential greenhouse gas emissions embodied in an amount of natural gas                                                                                                          

Division 1.1A.1          Preliminary                                                                                        

                  1.10A      Purpose of Part                                                                                32

Division 1.1A.2          Available methods                                                                              

Subdivision 1.1A.2.1   Default method                                                                                                                 

                  1.10B      Default method                                                                                 32

Subdivision 1.1A.2.2   Prescribed alternative method                                                                                    

                  1.10C      Prescribed alternative method                                                            33

                 1.10D      General requirements for sampling and analysis—prescribed alternative method        36

                  1.10E      Standards for analysing samples of natural gas supplied using natural gas supply pipeline   37

                  1.10F      Frequency of analysis—prescribed alternative method                        38

Part 1.2                      General                                                                                            

                    1.11      Purpose of Part                                                                                40

Division 1.2.1             Measurement and standards                                                               

                    1.12      Measurement of emissions                                                                40

                    1.13      General principles for measuring emissions                                        40

                    1.14      Assessment of uncertainty                                                                40

                    1.15      Units of measurement                                                                       40

                    1.16      Rounding of amounts                                                                        41

                    1.17      Status of standards                                                                          41

Division 1.2.2             Methods                                                                                             

                    1.18      Method to be used for a source                                                         41

                  1.18A      Conditions—persons preparing report must use same method            42

                    1.19      Temporary unavailability of method                                                    43

Division 1.2.3             Requirements in relation to carbon capture and storage                     

                  1.19A      Meaning of captured for permanent storage                                         44

                  1.19B      Deducting carbon dioxide that is captured for permanent storage       44

                  1.19C      Capture from facility with multiple sources jointly generated                45

                 1.19D      Capture from a source where multiple fuels consumed                        45

                  1.19E      Measure of quantity of carbon dioxide captured                                 45

                  1.19F      Volume of carbon dioxide stream — criterion A                                  46

                 1.19G      Volume of carbon dioxide stream — criterion AAA                             46

                  1.19H      Volumetric measurement — carbon dioxide stream not super‑compressed    47

                   1.19I      Volumetric measurement — supercompressed carbon dioxide stream [see Note 3]   48

                  1.19J      Gas measuring equipment — requirements                                         49

                  1.19K      Flow devices — requirements [see Note 3]                                         49

                  1.19L      Flow computers — requirements                                                        50

                 1.19M      Gas chromatographs [see Note 3]                                                      50

                  1.19N      Volume of carbon dioxide stream — criterion BBB                             50

Part 1.3                      Method 4 — Direct measurement of emissions                   

Division 1.3.1             Preliminary                                                                                        

                    1.20      Overview                                                                                          51

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                                       51

Subdivision 1.3.2.2      Method 4 (CEM) — use of equipment                                                                         

                    1.22      Overview                                                                                          52

                    1.23      Selection of sampling positions for CEM equipment                           52

                    1.24      Measurement of flow rates by CEM                                                   53

                    1.25      Measurement of gas concentrations by CEM                                      53

                    1.26      Frequency of measurement by CEM                                                  53

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                                       54

                    1.28      Calculation of emission factors                                                          54

Subdivision 1.3.3.2      Method 4 (PEM) — use of equipment                                                                          

                    1.29      Overview                                                                                          55

                    1.30      Selection of sampling positions for PEM equipment                           55

                    1.31      Measurement of flow rates by PEM equipment                                   55

                    1.32      Measurement of gas concentrations by PEM                                      56

                    1.33      Representative data for PEM                                                             56

Division 1.3.4             Performance characteristics of equipment                                          

                    1.34      Performance characteristics of CEM or PEM equipment                     56

Chapter 2             Fuel combustion                                                                             

Part 2.1                      Preliminary                                                                                     

                      2.1      Outline of Chapter                                                                             57

Part 2.2                      Emissions released from the combustion of solid fuels   

Division 2.2.1             Preliminary                                                                                        

                      2.2      Application                                                                                       58

                      2.3      Available methods for estimating emissions of carbon dioxide, methane and nitrous oxide    58

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

                      2.4      Method 1 — solid fuels                                                                     59

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             59

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  61

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                                    62

                      2.8      General requirements for analysis of solid fuels                                  63

                      2.9      Requirements for analysis of furnace ash and fly ash                         63

                    2.10      Requirements for sampling for carbon in furnace ash                          63

                    2.11      Sampling for carbon in fly ash                                                           64

Division 2.2.4             Method 3 — Solid fuels                                                                      

                    2.12      Method 3 — solid fuels using oxidation factor or an estimated oxidation factor         64

Division 2.2.5             Measurement of consumption of solid fuels                                       

                    2.13      Purpose of Division                                                                          66

                    2.14      Criteria for measurement                                                                    66

                    2.15      Indirect measurement at point of consumption — criterion AA             67

                    2.16      Direct measurement at point of consumption — criterion AAA             67

                    2.17      Simplified consumption measurements — criterion BBB                     68

Part 2.3                      Emissions released from the combustion of gaseous fuels  

Division 2.3.1             Preliminary                                                                                        

                    2.18      Application                                                                                       69

                    2.19      Available methods                                                                            69

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 70

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     71

                    2.22      Calculation of emission factors from combustion of gaseous fuel       71

Subdivision 2.3.3.2      Sampling and analysis                                                                                                    

                    2.23      General requirements for sampling under method 2                             73

                    2.24      Standards for analysing samples of gaseous fuels                             74

                    2.25      Frequency of analysis                                                                       78

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     78

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    81

Division 2.3.6             Measurement of quantity of gaseous fuels                                          

                    2.28      Purpose of Division                                                                          81

                    2.29      Criteria for measurement                                                                    81

                    2.30      Indirect measurement at point of consumption — criterion AA             82

                    2.31      Direct measurement at point of consumption — criterion AAA             82

                    2.32      Volumetric measurement—all natural gases                                        83

                    2.33      Volumetric measurement—super‑compressed gases                          84

                    2.34      Gas measuring equipment — requirements                                         85

                    2.35      Flow devices — requirements                                                            85

                    2.36      Flow computers—requirements                                                          86

                    2.37      Gas chromatographs—requirements                                                  86

                    2.38      Simplified consumption measurements — criterion BBB                     87

Part 2.4                      Emissions released from the combustion of liquid fuels  

Division 2.4.1             Preliminary                                                                                        

                    2.39      Application                                                                                       88

                  2.39A      Definition of petroleum based oils  for Part 2.4                                    88

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

                    2.40      Available methods                                                                            88

Subdivision 2.4.1.2      Liquid fuels — petroleum based oils and greases                                                  

                  2.40A      Available methods                                                                            89

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 89

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          90

                    2.43      Calculation of emission factors from combustion of liquid fuel           91

Subdivision 2.4.3.2      Sampling and analysis                                                                                                    

                    2.44      General requirements for sampling under method 2                             91

                    2.45      Standards for analysing samples of liquid fuels                                 92

                    2.46      Frequency of analysis                                                                       94

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           95

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     97

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      97

                  2.48B      Method 2 — estimating emissions of carbon dioxide using an estimated oxidation factor      98

                  2.48C      Method 3 — estimating emissions of carbon dioxide using an estimated oxidation factor      98

Division 2.4.6             Measurement of quantity of liquid fuels                                              

                    2.49      Purpose of Division                                                                          99

                    2.50      Criteria for measurement                                                                    99

                    2.51      Indirect measurement at point of consumption — criterion AA             99

                    2.52      Direct measurement at point of consumption — criterion AAA           100

                    2.53      Simplified consumption measurements — criterion BBB                    100

Part 2.5                      Emissions released from fuel use by certain industries    

                    2.54      Application                                                                                     101

Division 2.5.1             Energy — petroleum refining                                                             

                    2.55      Application                                                                                     101

                    2.56      Methods                                                                                         101

Division 2.5.2             Energy — manufacture of solid fuels                                                  

                    2.57      Application                                                                                     101

                    2.58      Methods                                                                                         101

Division 2.5.3             Energy — petrochemical production                                                  

                    2.59      Application                                                                                     105

                    2.60      Available methods                                                                           105

                    2.61      Method 1 — petrochemical production                                             105

                    2.62      Method 2 — petrochemical production                                             107

                    2.63      Method 3— petrochemical production                                              108

Part 2.6                      Blended fuels                                                                                

                    2.64      Purpose                                                                                          110

                    2.65      Application                                                                                     110

                    2.66      Blended solid fuels                                                                         110

                    2.67      Blended liquid fuels                                                                         110

Part 2.7                      Estimation of energy for certain purposes                            

                    2.68      Amount of energy consumed without combustion                             111

                    2.69      Apportionment of fuel consumed as carbon reductant or feedstock and energy        111

                    2.70      Amount of energy consumed in a cogeneration process                   112

                    2.71      Apportionment of energy consumed for electricity, transport and for stationary energy          112

Chapter 3             Fugitive emissions                                                                         

Part 3.1                      Preliminary                                                                                     

                      3.1      Outline of Chapter                                                                           113

Part 3.2                      Coal mining — fugitive emissions                                           

Division 3.2.1             Preliminary                                                                                        

                      3.2      Outline of Part                                                                                 114

Division 3.2.2             Underground mines                                                                           

Subdivision 3.2.2.1      Preliminary                                                                                                                        

                      3.3      Application                                                                                     114

                      3.4      Available methods                                                                           114

Subdivision 3.2.2.2      Fugitive emissions from extraction of coal                                                              

                      3.5      Method 1 — extraction of coal                                                         115

                      3.6      Method 4 — extraction of coal                                                         116

                      3.7      Estimation of emissions                                                                  117

                      3.8      Overview — use of equipment                                                         117

                      3.9      Selection of sampling positions for PEM                                         117

                    3.10      Measurement of volumetric flow rates by PEM                                 117

                    3.11      Measurement of concentrations by PEM                                          118

                    3.12      Representative data for PEM                                                           118

                    3.13      Performance characteristics of equipment                                        118

Subdivision 3.2.2.3      Emissions released from coal mine waste gas flared                                          

                    3.14      Method 1 — coal mine waste gas flared                                           118

                    3.15      Method 2 — coal mine waste gas flared                                           119

                    3.16      Method 3 — coal mine waste gas flared                                           119

Subdivision 3.2.2.4      Fugitive emissions from post‑mining activities                                                       

                    3.17      Method 1 — post‑mining activities related to gassy mines                 119

Division 3.2.3             Open cut mines                                                                                  

Subdivision 3.2.3.1      Preliminary                                                                                                                        

                    3.18      Application                                                                                     120

                    3.19      Available methods                                                                           120

Subdivision 3.2.3.2      Fugitive emissions from extraction of coal                                                              

                    3.20      Method 1 — extraction of coal                                                         121

                    3.21      Method 2 — extraction of coal                                                         121

                    3.22      Total gas contained by gas bearing strata                                        122

                    3.23      Estimate of proportion of gas content released below pit floor          123

                    3.24      General requirements for sampling                                                   124

                    3.25      General requirements for analysis of gas and gas bearing strata        124

                  3.25A      Method of working out base of the low gas zone                              124

                  3.25B      Further requirements for estimator                                                    125

                  3.25C      Default gas content for gas bearing strata in low gas zone                126

                 3.25D      Requirements for estimating total gas contained in gas bearing strata 126

                    3.26      Method 3 — extraction of coal                                                         126

Subdivision 3.2.3.3      Emissions released from coal mine waste gas flared                                          

                    3.27      Method 1 — coal mine waste gas flared                                           127

                    3.28      Method 2 — coal mine waste gas flared                                           127

                    3.29      Method 3 — coal mine waste gas flared                                           127

Division 3.2.4             Decommissioned underground mines                                                

Subdivision 3.2.4.1      Preliminary                                                                                                                        

                    3.30      Application                                                                                     127

                    3.31      Available methods                                                                           127

Subdivision 3.2.4.2      Fugitive emissions from decommissioned underground mines                         

                    3.32      Method 1 — decommissioned underground mines                            128

                    3.33      Emission factor for decommissioned underground mines                 129

                    3.34      Measurement of proportion of mine that is flooded                           129

                    3.35      Water flow into mine                                                                        130

                    3.36      Size of mine void volume                                                                130

                    3.37      Method 4 — decommissioned underground mines                            130

Subdivision 3.2.4.3      Fugitive emissions from coal mine waste gas flared                                            

                    3.38      Method 1 — coal mine waste gas flared                                           130

                    3.39      Method 2 — coal mine waste gas flared                                           130

                    3.40      Method 3 — coal mine waste gas flared                                           131

Part 3.3                      Oil and natural gas — fugitive emissions                              

Division 3.3.1             Preliminary                                                                                        

                  3.40A      Definition of natural gas for Part 3.3                                                 131

                    3.41      Outline of Part                                                                                 131

Division 3.3.2             Oil or gas exploration                                                                         

Subdivision 3.3.2.1      Preliminary                                                                                                                        

                    3.42      Application                                                                                     131

Subdivision 3.3.2.2      Oil or gas exploration (flared) emissions                                                                  

                    3.43      Available methods                                                                           132

                    3.44      Method 1 — oil or gas exploration                                                   132

                    3.45      Method 2 — oil or gas exploration                                                   133

                    3.46      Method 3 — oil or gas exploration                                                   133

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                                                                           134

Division 3.3.3             Crude oil production                                                                          

Subdivision 3.3.3.1      Preliminary                                                                                                                        

                    3.47      Application                                                                                     134

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

                    3.48      Available methods                                                                           135

                    3.49      Method 1 — crude oil production (non‑flared) emissions of methane 135

                    3.50      Method 2 — crude oil production (non‑flared) emissions of methane 136

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

                    3.51      Available methods                                                                           137

                    3.52      Method 1 — crude oil production (flared) emissions                          137

                    3.53      Method 2 — crude oil production                                                     138

                    3.54      Method 3 — crude oil production                                                     139

                    3.55      Method 1 — crude oil production (flared) emissions of methane and nitrous oxide    139

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

                  3.56A      Available methods                                                                           139

Division 3.3.4             Crude oil transport                                                                             

                    3.57      Application                                                                                     139

                    3.58      Available methods                                                                           140

                    3.59      Method 1 — crude oil transport                                                        140

                    3.60      Method 2 — fugitive emissions from crude oil transport                    140

Division 3.3.5             Crude oil refining                                                                               

                    3.61      Application                                                                                     141

                    3.62      Available methods                                                                           141

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           142

                    3.64      Method 2 — crude oil refining and storage tanks for crude oil           142

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                                                                                        143

                    3.66      Method 4 — deliberate releases from process vents, system upsets and accidents   143

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                                  144

                    3.68      Method 2 — gas flared from crude oil refining                                  144

                    3.69      Method 3 — gas flared from crude oil refining                                  145

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

                    3.70      Application                                                                                     145

                    3.71      Available methods                                                                           145

                    3.72      Method 1 — natural gas production and processing (other than emissions that are vented or flared)                                                                                             146

                    3.73      Method 2— natural gas production and processing (other than venting and flaring)    147

Division 3.3.7             Natural gas transmission                                                                    

                    3.74      Application                                                                                     147

                    3.75      Available methods                                                                           147

                    3.76      Method 1 — natural gas transmission                                               148

                    3.77      Method 2 — natural gas transmission                                               148

Division 3.3.8             Natural gas distribution                                                                      

                    3.78      Application                                                                                     149

                    3.79      Available methods                                                                           149

                    3.80      Method 1 — natural gas distribution                                                 149

                    3.81      Method 2 — natural gas distribution                                                 150

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

                    3.82      Application                                                                                     151

                    3.83      Available methods                                                                           151

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                                                                                              152

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  153

                    3.86      Method 2 — gas flared from natural gas production and processing  153

                    3.87      Method 3 — gas flared from natural gas production and processing  154

Part 3.4                      Carbon capture and storage — fugitive emissions            

Division 3.4.1             Preliminary                                                                                        

                    3.88      Outline of Part                                                                                 155

Division 3.4.2             Transport of captured carbon dioxide                                                 

Subdivision 3.4.2.1      Preliminary                                                                                                                        

                    3.89      Application                                                                                     155

                    3.90      Available methods                                                                           155

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   156

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         156

Chapter 4             Industrial processes emissions                                                  

Part 4.1                      Preliminary                                                                                     

                      4.1      Outline of Chapter                                                                           158

Part 4.2                      Industrial processes — mineral products                             

Division 4.2.1             Cement clinker production                                                                 

                      4.2      Application                                                                                     160

                      4.3      Available methods                                                                           160

                      4.4      Method 1 — cement clinker production                                             160

                      4.5      Method 2 — cement clinker production                                             161

                      4.6      General requirements for sampling cement clinker                             162

                      4.7      General requirements for analysing cement clinker                            162

                      4.8      Method 3 — cement clinker production                                             162

                      4.9      General requirements for sampling carbonates                                  164

                    4.10      General requirements for analysing carbonates                                 164

Division 4.2.2             Lime production                                                                                 

                    4.11      Application                                                                                     164

                    4.12      Available methods                                                                           164

                    4.13      Method 1 — lime production                                                            165

                    4.14      Method 2 — lime production                                                            165

                    4.15      General requirements for sampling                                                   166

                    4.16      General requirements for analysis of lime                                         167

                    4.17      Method 3 — lime production                                                            167

                    4.18      General requirements for sampling                                                   168

                    4.19      General requirements for analysis of carbonates                               168

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

                    4.20      Application                                                                                     169

                    4.21      Available methods                                                                           169

                    4.22      Method 1 — product other than cement clinker, lime or soda ash [see Note 2]           170

                  4.22A      Method 1A—product other than cement clinker, lime or soda ash for use of carbonates in clay materials                                                                                         171

                    4.23      Method 3 — product other than cement clinker, lime or soda ash       172

                  4.23A      Method 3A—product other than cement clinker, lime or soda ash for use of carbonates in clay materials                                                                                         173

                  4.23B      General requirements for sampling clay material                                173

                  4.23C      General requirements for analysing clay material                               173

                    4.24      General requirements for sampling carbonates                                  174

                    4.25      General requirements for analysis of carbonates                               174

Division 4.2.4             Soda ash use and production                                                             

                    4.26      Application                                                                                     174

                    4.27      Outline of Division                                                                           175

Subdivision 4.2.4.1      Soda ash use                                                                                                                    

                    4.28      Available methods                                                                           175

                    4.29      Method 1 — use of soda ash                                                           175

Subdivision 4.2.4.2      Soda ash production                                                                                                       

                    4.30      Available methods                                                                           175

                    4.31      Method 1 — production of soda ash                                                176

                    4.32      Method 2 — production of soda ash                                                178

                    4.33      Method 3 — production of soda ash                                                180

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

                    4.34      Purpose of Division                                                                        181

                    4.35      Criteria for measurement                                                                  181

                    4.36      Indirect measurement at point of consumption or production — criterion AA  182

                    4.37      Direct measurement at point of consumption or production — criterion AAA 182

                    4.38      Acquisition or use or disposal without commercial transaction — criterion BBB         183

                    4.39      Units of measurement                                                                      183

Part 4.3                      Industrial processes — chemical industry                            

Division 4.3.1             Ammonia production                                                                         

                    4.40      Application                                                                                     184

                    4.41      Available methods                                                                           184

                    4.42      Method 1 — ammonia production                                                    184

                    4.43      Method 2 — ammonia production                                                    185

                    4.44      Method 3 — ammonia production                                                    185

Division 4.3.2             Nitric acid production                                                                         

                    4.45      Application                                                                                     186

                    4.46      Available methods                                                                           186

                    4.47      Method 1 — nitric acid production                                                    186

                    4.48      Method 2 — nitric acid production                                                    187

Division 4.3.3             Adipic acid production                                                                       

                    4.49      Application                                                                                     187

                    4.50      Available methods                                                                           187

Division 4.3.4             Carbide production                                                                            

                    4.51      Application                                                                                     187

                    4.52      Available methods                                                                           187

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

                    4.53      Application                                                                                     188

                    4.54      Available methods                                                                           188

                    4.55      Method 1 — chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode                                                               188

                    4.56      Method 2 — chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode                                                               190

                    4.57      Method 3 — chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode                                                               191

Division 4.3.6             Sodium cyanide production                                                               

                    4.58      Application                                                                                     192

                    4.59      Available methods                                                                           192

Part 4.4                      Industrial processes — metal industry                                   

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

                    4.63      Application                                                                                     193

                    4.64      Purpose of Division                                                                        193

                    4.65      Available methods for production of a metal from an integrated metalworks  193

                    4.66      Method 1 — production of a metal from an integrated metalworks     194

                    4.67      Method 2 — production of a metal from an integrated metalworks     195

                    4.68      Method 3 — production of a metal from an integrated metalworks     196

Division 4.4.2             Ferroalloys production                                                                       

                    4.69      Application                                                                                     197

                    4.70      Available methods                                                                           197

                    4.71      Method 1 — ferroalloy metal [see Note 3]                                         198

                    4.72      Method 2 — ferroalloy metal                                                            199

                    4.73      Method 3 — ferroalloy metal                                                            200

Division 4.4.3             Aluminium production (carbon dioxide emissions)                            

                    4.74      Application                                                                                     201

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

                    4.75      Available methods                                                                           201

                    4.76      Method 1 — aluminium (carbon anode consumption)                        201

                    4.77      Method 2 — aluminium (carbon anode consumption)                        202

                    4.78      Method 3 — aluminium (carbon anode consumption)                        202

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

                    4.79      Available methods                                                                           203

                    4.80      Method 1 — aluminium (baked carbon anode production)                 203

                    4.81      Method 2 — aluminium (baked carbon anode production)                 204

                    4.82      Method 3 — aluminium (baked carbon anode production)                 204

Division 4.4.4             Aluminium production (perfluoronated carbon compound emissions)     

                    4.83      Application                                                                                     204

Subdivision 4.4.4.1      Aluminium — emissions of tetrafluoromethane in aluminium production        

                    4.84      Available methods                                                                           204

                    4.85      Method 1 — aluminium (tetrafluoromethane)                                     205

                    4.86      Method 2 — aluminium (tetrafluoromethane)                                     205

                    4.87      Method 3 — aluminium (tetrafluoromethane)                                     205

Subdivision 4.4.4.2      Aluminium — emissions of hexafluoroethane in aluminium production           

                    4.88      Available methods                                                                           205

                    4.89      Method 1 — aluminium production (hexafluoroethane)                       206

                    4.90      Method 2 — aluminium production (hexafluoroethane)                       206

                    4.91      Method 3 — aluminium production (hexafluoroethane)                       206

Division 4.4.5             Other metals production                                                                     

                    4.92      Application                                                                                     206

                    4.93      Available methods                                                                           206

                    4.94      Method 1 — other metals [see Note 3]                                              207

                    4.95      Method 2 — other metals                                                                 208

                    4.96      Method 3 — other metals                                                                 210

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

                    4.97      Application                                                                                     211

                    4.98      Available method                                                                            211

                    4.99      Meaning of hydrofluorocarbons                                                         211

                  4.100      Meaning of synthetic gas generating activities                                   211

                  4.101      Reporting threshold                                                                         212

                  4.102      Method 1                                                                                        212

                  4.103      Method 2                                                                                        213

                  4.104      Method 3                                                                                        213

Chapter 5             Waste                                                                                                 

Part 5.1                      Preliminary                                                                                     

                      5.1      Outline of Chapter                                                                           215

Part 5.2                      Solid waste disposal on land                                                    

Division 5.2.1             Preliminary                                                                                        

                      5.2      Application                                                                                     216

                      5.3      Available methods                                                                           216

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)      217

                   5.4A      Estimates for calculating CH4gen                                                        218

                   5.4B      Equation—change in quantity of particular opening stock at landfill for calculating CH4gen       219

                   5.4C      Equation—quantity of closing stock at landfill in particular reporting year      219

                   5.4D      Equation—quantity of methane generated by landfill for calculating CH4gen    220

                      5.5      Criteria for estimating tonnage of total solid waste                            222

                      5.6      Criterion A                                                                                       222

                      5.7      Criterion AAA                                                                                  222

                      5.8      Criterion BBB                                                                                  222

                      5.9      Composition of solid waste                                                             223

                    5.10      Waste streams                                                                                223

                    5.11      Waste mix types                                                                             224

                  5.11A      Certain waste to be deducted from waste received at landfill when estimating waste disposed in landfill                                                                                            227

                    5.12      Degradable organic carbon content                                                  227

                    5.13      Opening stock of degradable organic carbon for the first reporting period    227

                    5.14      Methane generation constants—(k values)                                        228

                  5.14A      Fraction of degradable organic carbon dissimilated (DOCF)               231

                  5.14B      Methane correction factor (MCF) for aerobic decomposition              232

                  5.14C      Fraction by volume generated in landfill gas that is methane (F)         232

                 5.14D      Number of months before methane generation at landfill commences 232

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 by landfill (other than from flaring of methane) 232

                  5.15A      Equation—change in quantity of particular opening stock at landfill for calculating CH4gen       235

                  5.15B      Equation—quantity of closing stock at landfill in particular reporting year      236

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

                    5.16      Procedures for selecting representative zone                                    236

                    5.17      Site plan—preparation and requirements                                           237

               5.17AA      Sub‑facility zones—maximum number and requirements                    237

                  5.17A      Representative zones—selection and requirements                           237

                  5.17B      Independent verification                                                                   238

                  5.17C      Estimation of waste and degradable organic content in representative zone  239

                 5.17D      Estimation of gas collected at the representative zone                      239

                  5.17E      Estimating methane generated but not collected in the representative zone    240

                  5.17F      Walkover survey                                                                              240

                 5.17G      Installation of flux boxes in representative zone                                241

                  5.17H      Flux box measurements                                                                   242

                   5.17I      When flux box measurements must be taken                                    243

                  5.17J      Restrictions on taking flux box measurements                                  243

                  5.17K      Frequency of measurement                                                              244

                  5.17L      Calculating the methane generation constant (ki) for certain waste mix types  244

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)                                                                                                      246

Division 5.2.5             Solid waste at landfills — Flaring                                                       

                    5.19      Method 1 — landfill gas flared                                                         247

                    5.20      Method 2 — landfill gas flared                                                         247

                    5.21      Method 3 — landfill gas flared                                                         247

Division 5.2.6             Biological treatment of solid waste                                                     

                    5.22      Method 1 — biological treatment of solid waste at the landfill            247

Division 5.2.7             Legacy waste and non‑legacy waste                                                   

                  5.22A      Legacy waste estimated using particular method—sub‑facility zone options  248

                  5.22B      Legacy waste—formula and unit of measurement                              248

                  5.22C      How to estimate quantity of methane captured for combustion from legacy waste for each sub‑facility zone                                                                              249

                 5.22D      How to estimate quantity of methane in landfill gas flared from legacy waste in the sub‑facility zone                                                                                               250

                  5.22E      How to estimate quantity of methane captured for transfer out of landfill from legacy waste for each sub‑facility zone                                                                      250

                  5.22F      How to calculate the quantity of methane generated from legacy waste for a sub‑facility zone (CH4genlw z)                                                                                       251

                 5.22G      How to calculate total methane generated from legacy waste             251

                  5.22H      How to calculate total methane captured and combusted from methane generated from legacy waste                                                                                              251

                   5.22I      How to calculate total methane captured and transferred offsite from methane generated from legacy waste                                                                                   252

                  5.22J      How to calculate total methane flared from methane generated from legacy waste     252

                  5.22K      How to calculate methane generated in landfill gas from nonlegacy waste    253

                  5.22L      Calculating amount of total waste deposited at landfill                      253

Part 5.3                      Wastewater handling (domestic and commercial)              

Division 5.3.1             Preliminary                                                                                        

                    5.23      Application                                                                                     254

                    5.24      Available methods                                                                           254

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)            255

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)            258

                    5.27      General requirements for sampling under method 2                           258

                    5.28      Standards for analysis                                                                     259

                    5.29      Frequency of sampling and analysis                                                259

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)            259

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)     259

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)     262

                    5.33      General requirements for sampling under method 2                           263

                    5.34      Standards for analysis                                                                     263

                    5.35      Frequency of sampling and analysis                                                263

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)     263

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)                                                                                    264

                    5.38      Method 2 — flaring of methane in sludge biogas                              264

                    5.39      Method 3 — flaring of methane in sludge biogas                              264

Part 5.4                      Wastewater handling (industrial)                                             

Division 5.4.1             Preliminary                                                                                        

                    5.40      Application                                                                                    265

                    5.41      Available methods                                                                           265

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

                    5.42      Method 1 — methane released from wastewater handling (industrial)  266

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

                    5.43      Method 2 — methane released from wastewater handling (industrial)  270

                    5.44      General requirements for sampling under method 2                           270

                    5.45      Standards for analysis                                                                     270

                    5.46      Frequency of sampling and analysis                                                271

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

                    5.47      Method 3 — methane released from wastewater handling (industrial)  271

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

                    5.48      Method 1 — flaring of methane in sludge biogas                              271

                    5.49      Method 2 — flaring of methane in sludge biogas                              272

                    5.50      Method 3 — flaring of methane in sludge biogas                              272

Part 5.5                      Waste incineration                                                                       

                    5.51      Application                                                                                     273

                    5.52      Available methods — emissions of carbon dioxide from waste incineration   273

                    5.53      Method 1 — emissions of carbon dioxide released from waste incineration   273

Chapter 6             Energy                                                                                               

Part 6.1                      Production                                                                                     

                      6.1      Purpose                                                                                          275

                      6.2      Quantity of energy produced                                                           275

                      6.3      Energy content of fuel produced                                                      276

Part 6.2                      Consumption                                                                                

                      6.4      Purpose                                                                                          277

                      6.5      Energy content of energy consumed                                                277

Chapter 7             Scope 2 emissions                                                                         

                      7.1      Outline of Chapter                                                                           279

                      7.2      Method 1 — purchase of electricity from main electricity grid in a State or Territory    279

                      7.3      Method 1 — purchase of electricity from other sources                     280

Chapter 8             Assessment of uncertainty                                                          

Part 8.1                      Preliminary                                                                                     

                      8.1      Outline of Chapter                                                                           281

Part 8.2                      General rules for assessing uncertainty                                

                      8.2      Range for emission estimates                                                          282

                      8.3      Uncertainty to be assessed having regard to all facilities                   282

Part 8.3                      How to assess uncertainty when using method 1              

                      8.4      Purpose of Part                                                                              283

                      8.5      General rules about uncertainty estimates for emissions estimates using method 1    283

                      8.6      Assessment of uncertainty for estimates of carbon dioxide emissions from combustion of fuels                                                                                                      283

                      8.7      Assessment of uncertainty for estimates of methane and nitrous oxide emissions from combustion of fuels                                                                        286

                      8.8      Assessment of uncertainty for estimates of fugitive emissions          287

                      8.9      Assessment of uncertainty for estimates of emissions from industrial process sources         288

                    8.10      Assessment of uncertainty for estimates of emissions from waste    289

                    8.11      Assessing uncertainty of emissions estimates for a source by aggregating parameter uncertainties                                                                                    289

                    8.12      Assessing uncertainty of emissions estimates for a facility               290

                    8.13      Assessing uncertainty of emissions estimates for a registered corporation    290

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

                    8.14      Purpose of Part                                                                              291

                    8.15      Rules for assessment of uncertainty using method 2, 3 or 4              291

Schedule 1                  Energy content factors and emission factors                                  292

Part 1                             Fuel combustion — solid fuels and certain coal‑based products        292

Part 2                             Fuel combustion — gaseous fuels                                                   293

Part 3                             Fuel combustion — liquid fuels and certain petroleum‑based products for stationary energy purposes                                                                                        294

Part 4                             Fuel combustion — fuels for transport energy purposes                   295

Division 4.1                  Fuel combustion — fuels for transport energy purposes                   295

Division 4.2                  Fuel combustion — liquid fuels for transport energy purposes for post‑2004 vehicles            296

Division 4.3                  Fuel combustion — liquid fuels for transport energy purposes for certain trucks        297

Part 5                             Consumption of fuels for non‑energy product purposes                    297

Part 6                             Indirect (scope 2) emission factors from consumption of purchased electricity from grid       298

Part 7                             Fuel combustion — other fuels                                                        298

Schedule 2                  Standards and frequency for analysing energy content factor etc for solid fuels    299

Schedule 3                  Carbon content factors                                                                   303

Part 1                             Solid fuels and certain coal‑based products                                     303

Part 2                             Gaseous fuels                                                                                 304

Part 3                             Liquid fuels and certain petroleum‑based products                           304

Part 4                             Petrochemical feedstocks and products                                           306

Part 5                             Carbonates                                                                                     306

Notes                                                                                                                            307

 


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 section 7B and subsection 10 (3) of the National Greenhouse and Energy Reporting Act 2007. It provides for the measurement of the following:

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

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

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

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

         (2)   This determination deals with scope 1 emissions, scope 2 emissions and potential greenhouse gas emissions embodied in an amount of natural gas.

Note 1   Facility has the meaning given by section 9 of the Act.

Note 2   Potential greenhouse gas emissions embodied in an amount of designated fuel has the meaning given by section 7B of the Act.

Note 3   Natural gas has the meaning given by the Regulations.

Note 4   Scope 1 emission and scope 2 emission have the meaning given by section 10 of the Act (also see, respectively, regulations 2.23 and 2.24 of the Regulations).

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

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

         (4)   The categories of scope 1 emissions are:

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

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

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

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

         (5)   Each of the categories has various subcategories.

1.4           Overview — methods for measurement

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

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

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

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

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

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

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

         (3)   For potential greenhouse gas emissions embodied in an amount of natural gas:

                (a)    the default method set out in section 1.10B is based on national average estimates; and

               (b)    the prescribed alternative method set out in Subdivision 1.1A.2.2 uses Australian or equivalent standards for analysis.

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.

ACARP Guidelines means the document entitled Guidelines for the Implementation of NGER Method 2 or 3 for Open Cut Coal Mine Fugitive GHG Emissions Reporting (C20005), published by the Australian Coal Association Research Program in December 2011.

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

Act means the National Greenhouse and Energy Reporting Act 2007.

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

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

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

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

applicable State or Territory legislation, for an underground mine, means a law of a State or Territory in which the mine is located that relates to coal mining health and safety, 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.

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

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

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.

domain, of an open cut mine, means an area, volume or coal seam in which the variability of gas content and the variability of gas composition in the open cut mine have a consistent relationship with other geological, geophysical or spatial parameters located in the area, volume or coal seam.

dry wood has the meaning given by the Regulations.

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

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

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

estimator, of fugitive emissions from an open cut mine using method 2 under section 3.21 or method 3 under section 3.26, means:

                (a)    an individual who has the minimum qualifications of an estimator set out in the ACARP Guidelines; or

               (b)    individuals who jointly have those minimum qualifications.

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

feedstock has the meaning given by the Regulations.

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

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

Example

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

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

fuel oil has the meaning given by the Regulations.

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

gas bearing strata is coal and carbonaceous rock strata:

                (a)    located in an open cut mine; and

               (b)    that has a relative density of less than 1.95 g/cm3.

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

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

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

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

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

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

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.

legacy waste means waste deposited at a landfill before 1 July 2012.

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

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

low gas zone means the part of the gas bearing strata of an open cut mine:

                (a)    that is located immediately below the original surface of the mine and above the base of the low gas zone; and

               (b)    the area of which is worked out by working out the base of the low gas zone.

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

marketable crude oil includes:

                (a)    conventional crude oil; and

               (b)    heavy crude oil; and

                (c)    synthetic crude oil; and

               (d)    bitumen.

method, 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 has the meaning given by the Regulations.

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 supply pipeline has the meaning given by the Clean Energy Act 2011.

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.

non‑legacy waste means waste deposited at a landfill on or after 1 July 2012.

open cut mine:

                (a)    means a mine in which the overburden is removed from coal seams to allow coal extraction by mining that is not underground mining; and

               (b)    for method 2 in section 3.21 or method 3 in section 3.26—includes a mine of the kind mentioned in paragraph (a):

                          (i)    for which an area has been established but coal production has not commenced; or

                         (ii)    in which coal production has commenced.

PEM or periodic emissions monitoring means periodic monitoring of emissions in accordance with Part 1.3.

Perfluorocarbon protocol means the Protocol for Measurement of Tetrafluoromethane (CF4) and Hexafluoroethane (C2F6) Emissions from Primary Aluminium Production published by the United States Environmental Protection Agency and the International Aluminium Institute.

petroleum based greases has the meaning given by regulation 1.03 of the Regulations.

petroleum based oils has the meaning given by the Regulations.

petroleum coke has the meaning given by the Regulations.

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

primary wastewater treatment plant:

                (a)    means a treatment facility at which wastewater undergoes physical screening, degritting and sedimentation; and

               (b)    does not include a treatment facility at which any kind of nitrification or denitrification treatment process occurs.

principal activity, in relation to a facility, means the activity that:

                (a)    results in the production of a product or service that is produced for sale on the market; and

               (b)    produces the most value for the facility out of any of the activities forming part of the facility.

pyrolysis of coal means the decomposition of coal by heat.

raw sugar has the meaning given by Chapter 17 of Section IV of Schedule 3 to the Customs Tariff Act 1995.

reductant:

                (a)    means a reducing agent or substance:

                          (i)    that causes another substance to undergo reduction; and

                         (ii)    that is oxidised while causing the substance to undergo reduction; and

               (b)    does not include fuels that are combusted only to produce energy.

refinery gases and liquids has the meaning given by the Regulations.

Regulations means the National Greenhouse and Energy Reporting Regulations 2008.

relevant person means a person mentioned in paragraph 1.19A (a), (b), (c), (d), (e) or (f).

run‑of‑mine coal means coal that is produced by mining operations before screening, crushing or preparation of the coal has occurred.

scope 1 emissions has the 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 has the meaning given by the Regulations.

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.

supply has the meaning given by the Clean Energy Act 2011.

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 regulation 2.26 of the Regulations)

·      energy

·      facility

·      greenhouse gas

·      group

·      industry sector

·      operational control

·      potential greenhouse gas emissions

·      production of energy (see also regulation 2.25 of the Regulations)

·      registered corporation

·      scope 1 emission (see also regulation 2.23 of the Regulations)

·      scope 2 emission (see also regulation 2.24 of the Regulations).

1.9           Interpretation

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

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

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

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

         (4)   In this Determination, a reference to a standard, instrument or other writing (other than a Commonwealth Act or Regulations) however described, is a reference to that standard, instrument or other writing as in force on 1 July 2012.

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

3P

 

Sodium cyanide production

4

Waste

 

4A

 

Solid waste disposal on land

4B

 

Wastewater handling (industrial)

4C

 

Wastewater handling (domestic or commercial)

4D

 

Waste incineration

         (2)   The extent of the source is as provided for in this Determination.

Part 1.1A            Potential greenhouse gas emissions embodied in an amount of natural gas

Division 1.1A.1     Preliminary

1.10A      Purpose of Part

                This Part provides for:

                (a)    the measurement of potential greenhouse gas emissions embodied in an amount of natural gas in accordance with the default method set out in section 1.10B; and

               (b)    the ascertainment of potential greenhouse gas emissions embodied in an amount of natural gas in accordance with the prescribed alternative method set out in Subdivision 1.1A.2.2.

Division 1.1A.2     Available methods

Subdivision 1.1A.2.1  Default method

1.10B     Default method

                For subsection 7B (2) of the Act, the amount of greenhouse gas that would be released into the atmosphere as a result of the combustion of an amount of natural gas is determined to be the amount that results from using the following formula:

where:

E is the amount of greenhouse gas that would be released into the atmosphere as a result of the combustion of an amount of natural gas, measured in CO2‑e tonnes.

Q is taken to be the amount of natural gas supplied using a natural gas supply pipeline by a person in a reporting year, measured in:

                (a)    cubic metres, corrected to standard conditions; or

               (b)    gigajoules.

A is the value specified for subsection 7B (2) of the Act, worked out using the following formula:

where:

EC is the energy content factor, which:

                (a)    for natural gas measured in gigajoules, is equal to 1; or

               (b)    for natural gas measured in cubic metres, corrected to standard conditions, is:

                          (i)    mentioned in column 3 of item 17 of Part 2 of Schedule 1; or

                         (ii)    estimated by analysis in accordance with sections 1.10D, 1.10E and 1.10F.

EFCO2ox,ec is the emission factor for CO2 mentioned in column 4 of item 17 of Part 2 of Schedule 1.

EFCH4 is the emission factor for CH4 mentioned in column 5 of item 17 of Part 2 of Schedule 1.

EFN2O is the emission factor for N2O mentioned in column 6 of item 17 of Part 2 of Schedule 1.

Note   For a provision that:

(a)   specifies pipelines that are not natural gas supply pipelines, see regulation 1.8 of the Clean Energy Regulations 2011; and

(b)   describes when the supply of natural gas occurs, see section 6 of the Clean Energy Act 2011 and regulation 1.10 of the Clean Energy Regulations 2011.

Subdivision 1.1A.2.2  Prescribed alternative method

1.10C     Prescribed alternative method

         (1)   For subsections 7B (3) and 7B (4) of the Act, this Subdivision specifies the prescribed alternative method for ascertaining the potential greenhouse gas emissions embodied in an amount of natural gas.

         (2)   For subsection (1), work out the potential greenhouse gas emissions embodied in an amount of natural gas using the following formula:

where:

E is the potential greenhouse gas emissions embodied in an amount of natural gas, measured in CO2‑e tonnes.

Q is the amount of natural gas supplied using a natural gas supply pipeline by a person in a reporting year, measured in:

                (a)    cubic metres, corrected to standard conditions; or

               (b)    gigajoules.

EC is the energy content factor, which:

                (a)    for natural gas measured in gigajoules, is equal to 1; or

               (b)    for natural gas measured in cubic metres, corrected to standard conditions is:

                          (i)    mentioned in column 3 of item 17 of Part 2 of Schedule 1; or

                         (ii)    estimated by analysis in accordance with sections 1.10D, 1.10E and 1.10F.

EFCH4 is the emission factor for CH4 mentioned in column 5 of item 17 of Part 2 of Schedule 1.

EFN2O is the emission factor for N2O mentioned in column 6 of item 17 of Part 2 of Schedule 1.

EFCO2ox,ec is the carbon dioxide emission factor for natural gas supplied using a natural gas supply pipeline by a person in a reporting year, measured in kilograms CO2‑e per gigajoule and calculated in accordance with subsection (3).

         (3)   For subsection (2), work out the emission factor EFCO2ox,ec using the following steps:

Step 1

Estimate EFCO2ox,kg in accordance with the following formula:

where:

EFCO2ox,kg is the carbon dioxide emission factor for natural gas supplied using a natural gas supply pipeline by a person in a reporting year, incorporating the effects of a default oxidation factor expressed as kilograms of carbon dioxide per kilogram of natural gas.

Σy is sum for all component gas types.

moly%, for each component gas type (y) mentioned in the table in subsection (5), is that gas type’s share of:

   (a)  1 mole of natural gas supplied using a natural gas supply pipeline, expressed as a percentage; or

  (b)  the total volume of natural gas supplied using a natural gas supply pipeline, expressed as a percentage.

mwy, for each component gas type (y) mentioned in the table in subsection (5), 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, which is 23.6444 cubic metres.

dy, total is worked out in accordance with subsection (4).

fy for each component gas type (y) mentioned in the table in subsection (5), is the number of carbon atoms in a molecule of the component gas type (y).

OFg is the oxidation factor 0.995 applicable to natural gas supplied using a natural gas supply pipeline.

Step 2

Work out the emission factor EFCO2ox,ec from the combustion of natural gas supplied using a natural gas supply pipeline, expressed in kilograms of carbon dioxide per gigajoule, using information on the composition of each component gas type (y) mentioned in the table in subsection (5), in accordance with the following formula:

where:

EFCO2ox,kg is the carbon dioxide emission factor for natural gas supplied using a natural gas supply pipeline by a person in a reporting year, incorporating the effects of a default oxidation factor expressed as kilograms of carbon dioxide per kilogram of natural gas, worked out under step 1.

EC is the energy content factor, measured in GJ/m3:

    (a)     mentioned in column 3 of item 17 of Part 2 of Schedule 1; or

   (b)     estimated by analysis in accordance with sections 1.10D, 1.10E and 1.10F.

C is the density of natural gas supplied using a natural gas supply pipeline, expressed in kilograms of natural gas per cubic metre, analysed in accordance with a standard mentioned in subsection 1.10E (3).

         (4)   For subsection (3), dy, total is worked out using the following formula:

where:

Σy is sum for all component gas types.

moly%, for each component gas type (y) mentioned in the table in subsection (5), is that gas type’s share of:

                (a)    1 mole of natural gas supplied using a natural gas supply pipeline, expressed as a percentage; or

               (b)    the total volume of natural gas supplied using a natural gas supply pipeline, 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, which is 23.6444 cubic metres.

         (5)   For subsection (3) and (4), 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 set out in columns 3 and 4, respectively, for the item.

Item

Component gas type (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

Note   For a provision that:

(a)   specifies pipelines that are not natural gas supply pipelines, see regulation 1.8 of the Clean Energy Regulations 2011; and

(b)   describes when the supply of natural gas occurs, see section 6 of the Clean Energy Act 2011 and regulation 1.10 of the Clean Energy Regulations 2011.

1.10D     General requirements for sampling and analysis—prescribed alternative method

         (1)   Natural gas supplied using a natural gas supply pipeline must be sampled in accordance with:

                (a)    one of the standards mentioned in subsection (2) or a standard that is equivalent to one of those standards; or

               (b)    the requirements mentioned in subsections (3), (4) and (5).

         (2)   For paragraph (1) (a), the standards are the following:

                (a)    ISO 10715:1997;

               (b)    ASTM D 5287–97 (2002);

                (c)    ASTM F 307–02 (2007);

               (d)    ASTM D 5503–94 (2003);

                (e)    GPA 2166–05.

         (3)   Samples of natural gas supplied using a natural gas supply pipeline must:

                (a)    be derived from a composite of amounts of the natural gas in the natural gas supply pipeline; and

               (b)    be collected on enough occasions to produce a representative sample; and

                (c)    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 be used for the delivery period, usage period or consignment of the natural gas supplied using a natural gas supply pipeline for which it was intended to be representative.

Note   For a provision that:

(a)   specifies pipelines that are not natural gas supply pipelines, see regulation 1.8 of the Clean Energy Regulations 2011; and

(b)   describes when the supply of natural gas occurs, see section 6 of the Clean Energy Act 2011 and regulation 1.10 of the Clean Energy Regulations 2011.

1.10E      Standards for analysing samples of natural gas supplied using natural gas supply pipeline

         (1)   Samples of natural gas supplied using a natural gas supply pipeline must be analysed:

                (a)    for analysis of energy content—in accordance with one of the following standards or a standard that is equivalent to one of the following standards:

                          (i)    ASTM D 1826—94 (2003);

                         (ii)    ASTM D 7164—05;

                        (iii)    ASTM 3588—98 (2003);

                        (iv)    ISO 6974, part 1 (2000);

                         (v)    ISO 6974, part 2 (2001);

                        (vi)    ISO 6974, part 3 (2000);

                       (vii)    ISO 6974, part 4 (2000);

                      (viii)    ISO 6974, part 5 (2000);

                        (ix)    ISO 6974, part 6 (2002);

                         (x)    ISO 6976:1995;

                        (xi)    GPA 2172—96; and

               (b)    for analysis of gas composition—in accordance with one of the following standards or a standard that is equivalent to one of the following standards:

                          (i)    ASTM D 1945—03;

                         (ii)    ASTM D 1946—90 (2006);

                        (iii)    ISO 6974, part 1 (2000);

                        (iv)    ISO 6974, part 2 (2001);

                         (v)    ISO 6974, part 3 (2000);

                        (vi)    ISO 6974, part 4 (2000);

                       (vii)    ISO 6974, part 5 (2000);

                      (viii)    ISO 6974, part 6 (2002);

                        (ix)    GPA 2145 – 03;

                         (x)    GPA 2261 – 00.

         (2)   The analysis of samples of natural gas supplied using a natural gas supply pipeline must be undertaken:

                (a)    by an accredited laboratory; or

               (b)    by a laboratory that meets requirements that are equivalent to the requirements in AS ISO/IEC 17025:2005; or

                (c)    using an online analyser if:

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

                         (ii)    the online analysis is undertaken in accordance with this section.

Note   An example of an appropriate standard is ISO 10723: 1995 Natural gas—Performance evaluation of on‑line analytical systems.

         (3)   The density of natural gas supplied using a natural gas supply pipeline must be analysed in accordance with ISO 6976:1995 or in accordance with a standard that is equivalent to that standard.

Note   For a provision that:

(a)   specifies pipelines that are not natural gas supply pipelines, see regulation 1.8 of the Clean Energy Regulations 2011; and

(b)   describes when the supply of natural gas occurs, see section 6 of the Clean Energy Act 2011 and regulation 1.10 of the Clean Energy Regulations 2011.

1.10F      Frequency of analysis—prescribed alternative method

                Samples of natural gas supplied using a natural gas supply pipeline must be analysed:

                (a)    for gas composition—monthly; and

               (b)    for energy content:

                          (i)    if the samples are analysed using gas measuring equipment that is in category 1 or 2 of the following table—monthly; or

                         (ii)    if the samples are analysed using gas measuring equipment that is in category 3 or 4 of the following table—continuously.

Item

Gas measuring equipment category

Maximum daily quantity of natural gas supplied using a natural gas supply pipeline (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%

Note   For a provision that:

(a)   specifies pipelines that are not natural gas supply pipelines, see regulation 1.8 of the Clean Energy Regulations 2011; and

(b)   describes when the supply of natural gas occurs, see section 6 of the Clean Energy Act 2011 and regulation 1.10 of the Clean Energy Regulations 2011.

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.

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

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

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

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

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

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

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

         (2)   Subject to subsection (3), 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.

1.18A      Conditions—persons preparing report must use same method

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

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

                (a)    the person must, before 31 August in the year immediately following the reporting year, notify any other person required, under a reporting provision, to provide a report to the Regulator for the same facility of the method the person will use in the report; and

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

         (3)   If the persons mentioned in paragraph (2) (b) do not agree on a method before 31 October in the year immediately following the reporting year, each report provided to the Regulator for the facility and for the reporting period must use the method:

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

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

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

Note 1   Reporting year has the meaning given by the Regulations.

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

Note 3   An example of options included within a method is paragraphs 3.36 (a) and (b), which provide 2 options of ways to measure the size of mine void volume.

Note 4   An example of options included within an available alternative method is the options for identifying the value of the oxidation factor (OFs) in subsection 2.5 (3).

1.19        Temporary unavailability of method

         (1)   The procedure set out in this section applies if, during a reporting year, a method for a source or potential greenhouse gas emissions embodied in an amount of natural gas 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 from the source or potential greenhouse gas emissions embodied in an amount of natural gas must be calculated based on:

                (a)    the average daily emissions from the source estimated for the reporting year; or

               (b)    the average daily potential greenhouse gas emissions embodied in an amount of natural gas estimated for the reporting 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 or 1.18A.

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:

                          (i)    the publication entitled AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 3: Natural Gas Applications, published by the American Gas Association in August 1992; or

                         (ii)    Parts 1 to 4 of the publication entitled ANSI/API MPMS Chapter 14.3 Part 2 (R2011) Natural Gas Fluids Measurement: Concentric, Square-Edged Orifice Meters - Part 2: Specification and Installation Requirements, 4th edition, published by the American Petroleum Institute on 30 April 2000;

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

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

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

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

1.19I       Volumetric measurement — supercompressed carbon dioxide stream [see Note 3]

         (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 gas chromatographs set out in section 1.19M.

1.19K     Flow devices — requirements [see Note 3]

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

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

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

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

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

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

1.19L      Flow computers — requirements

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

                (a)    instantaneous corrected volumetric flow;

               (b)    cumulative corrected volumetric flow;

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

               (d)    for turbine and positive displacement metering systems — cumulative uncorrected volumetric flow;

                (e)    super‑compressibility factor.

1.19M     Gas chromatographs [see Note 3]

                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 50 000 megawatt hours of electricity in a reporting year.

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

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

2.4           Method 1 — solid fuels

                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 50 000 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), measured in gigajoules per cubic metre that is:

                (a)    mentioned in column 3 of Part 2 of Schedule 1; or

               (b)    estimated by analysis under Subdivision 2.3.3.2.

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

Subdivision 2.3.3.2     Sampling and analysis

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:

                (a)    by an accredited laboratory; or

               (b)    by a laboratory that meets requirements that are equivalent to the requirements in AS ISO/IEC 17025:2005; or

                (c)    using an online analyser if:

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

                         (ii)    the online analysis is undertaken in accordance with this section.

Note   An example of an appropriate standard is ISO 6975:1997—Natural gas—Extended analysis—Gas‑chromatographic method.

         (4)   The density of a gaseous fuel mentioned in column 2 of an item in the table in subsection (1) must be analysed in accordance with ISO 6976:1995 or in accordance with a standard that is equivalent to that standard.

2.25        Frequency of analysis

                Gaseous fuel of a type mentioned in column 2 of an item in the following table must be analysed for the parameter mentioned in column 3 for that item at least at the frequency mentioned in column 4 for that item.

 

Item

Fuel

Parameter

Frequency

1

Pipeline quality gases

Gas composition

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 other than super‑compressed gases—section 2.32; and

                         (ii)    for super‑compressed gases—sections 2.32 and 2.33; and

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

         (3)   The measurement must be either:

                (a)    carried out using gas measuring equipment that:

                          (i)    is in a category specified in column 2 of an item in the table in subsection (4) according to the maximum daily quantity of gas combusted from the operation of the facility specified, for the item, in column 3 of the table; and

                         (ii)    complies with the transmitter and accuracy requirements specified, for the item, in column 4 of the table; or

               (b)    carried out at the point of sale of the gaseous fuels using measuring equipment that complies with paragraph (a).

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

 

Item

Gas measuring equipment category

Maximum daily quantity of gas combusted (GJ/day)

Transmitter and accuracy requirements (% of range)

1

1

0–1750

Pressure <±0.25%

Diff. pressure <±0.25%

Temperature <±0.50%

2

2

1751–3500

Pressure <±0.25%

Diff. pressure <±0.25%

Temperature <±0.50%

3

3

3501–17500

Smart transmitters:

Pressure <±0.10%

Diff. pressure <±0.10%

Temperature <±0.25%

4

4

17501 or more

Smart transmitters:

Pressure <±0.10%

Diff. pressure <±0.10%

Temperature <±0.25%

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

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

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

2.32        Volumetric measurement—all natural gases

         (1)   For subparagraph 2.31 (2) (a) (i) and (ii), volumetric measurement must be calculated at standard conditions and expressed in cubic metres.

         (2)   The volumetric measurement must be calculated using a flow computer that measures and analyses the following at the delivery location of the gaseous fuel:

                (a)    flow symbols;

               (b)    relative density;

                (c)    gas composition.

         (3)   The volumetric flow rate must be:

                (a)    continuously recorded; and

               (b)    continuously integrated using an integration device.

      (3A)   The integration device must be isolated from the flow computer in such a way that, if the computer fails, the integration device will retain:

                (a)    the last reading that was on the computer immediately before the failure; or

               (b)    the previously stored information that was on the computer immediately before the failure.

         (4)   All measurements, calculations and procedures used in determining volume (except for any correction for deviation from the ideal gas law) must be made in accordance with:

                (a)    the instructions mentioned in subsection (5); or

               (b)    an internationally recognised standard or code that is equivalent to an instruction mentioned, for a system, in paragraph (5) (a), (b) or (c).

Note   An example of an internationally recognised equivalent standard is New Zealand standard NZS 5259:2004.

         (5)   For paragraph (4) (a), the instructions are those mentioned in:

                (a)    for orifice plate measuring systems:

                          (i)    the publication entitled AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 3: Natural Gas Applications, published by the American Gas Association in August 1992; or

                         (ii)    Parts 1 to 4 of the publication entitled ANSI/API MPMS Chapter 14.3 Part 2 (R2011) Natural Gas Fluids Measurement: Concentric, Square-Edged Orifice Meters - Part 2: Specification and Installation Requirements, 4th edition, published by the American Petroleum Institute on 30 April 2000;

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

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

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

         (7)   Standard conditions means, as measured on a dry gas basis:

                (a)    air pressure of 101.325 kilopascals; and

               (b)    air temperature of 15.0 degrees Celsius; and

                (c)    air density of 1.225 kilograms per cubic metre.

2.33        Volumetric measurement—super‑compressed gases

         (1)   For subparagraph 2.31 (2) (a) (ii), this section applies in relation to measuring the volume of super‑compressed natural gases.

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

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

                (a)    if the measuring equipment is category 3 or 4 equipment in accordance with the table in section 2.31—using gas composition data; or

               (b)    if the measuring equipment is category 1 or 2 equipment in accordance with the table in section 2.31—using an alternative method set out in the publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994.

2.34        Gas measuring equipment — requirements

                For paragraph 2.31 (2) (b), gas measuring equipment that is category 3 or 4 equipment in accordance with column 2 of the table in section 2.31 must comply with the following requirements:

                (a)    if the equipment uses flow devices — the requirements relating to flow devices set out in section 2.35;

               (b)    if the equipment uses flow computers — the requirement relating to flow computers set out in section 2.36;

                (c)    if the equipment uses gas chromatographs— the requirements relating to gas chromatographs set out in section 2.37.

2.35        Flow devices — requirements

      (1A)   This section is made for paragraph 2.34 (a).

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

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

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

Note   The publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994, sets out a manner of installation that ensures that the maximum uncertainty of the flow measurement is not greater than ±1.5%.

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

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

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

         (5)   All flow devices that are used by gas measuring equipment in a category specified in column 2 of an item in the table in section 2.31 must, wherever possible, be calibrated for pressure, differential pressure and temperature:

                (a)    in accordance with the requirements specified, for the item, in column 4 of the table; and

               (b)    taking into account the effects of static pressure and ambient temperature.

2.36        Flow computers—requirements

                For paragraph 2.34 (b), the requirement is that the flow computer that is used by the equipment for measuring purposes must record:

                (a)    the instantaneous values for all primary measurement inputs; and

               (b)    the following outputs:

                          (i)    instantaneous corrected volumetric flow;

                         (ii)    cumulative corrected volumetric flow;

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

                        (iv)    for turbine and positive displacement metering systems—cumulative uncorrected volumetric flow;

                         (v)    super‑compressibility factor.

2.37        Gas chromatographs—requirements

                For paragraph 2.34 (c), the requirements are that gas chromatographs used by the measuring equipment must:

                (a)    be factory tested and calibrated using a measurement standard:

                          (i)    produced by gravimetric methods; and

                         (ii)    that uses Australian legal units of measurement; and

               (b)    perform gas composition analysis with an accuracy of:

                          (i)    ±0.15% for use in calculation of gross calorific value; and

                         (ii)    ±0.25% for calculation of relative density; and

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

2.38        Simplified consumption measurements — criterion BBB

         (1)   For paragraph 2.29 (4) (b), criterion BBB is the estimation of gaseous fuel in accordance with industry practice if the measuring equipment used to estimate consumption of the fuel does not meet the requirements of criterion AAA.

         (2)   For sources of landfill gas captured for the purpose of combustion for the production of electricity:

                (a)    the energy content of the captured landfill gas may be estimated 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 —columns 5 and 6 of the table in Division 4.2 of Part 4 of Schedule 1; and

               (b)    for combustion of fuel by trucks that meet the design standards mentioned in column 3 of the table in Division 4.3 of Part 4 of Schedule 1 —columns 6 and 7 of the table in that Division.

Division 2.4.5A     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 energy consumed without combustion

                For paragraph 4.22 (1) (b) of the Regulations:

                (a)    the energy is to be measured:

                          (i)    for solid fuel—in tonnes estimated under Division 2.2.5; or

                         (ii)    for gaseous fuel—in cubic metres estimated under Division 2.3.6; or

                        (iii)    for liquid fuel—in kilolitres estimated under Division 2.4.6; and

                        (iv)    for electricity—in kilowatt hours:

                                   (A)     worked out using the evidence mentioned in paragraph 6.5 (2) (a); or

                                   (B)     if the evidence mentioned in paragraph 6.5 (2) (a) is unavailable—estimated in accordance with paragraph 6.5 (2) (b).

               (b)    the reporting threshold is:

                          (i)    for solid fuel—20 tonnes; or

                         (ii)    for gaseous fuel—13 000 cubic metres; or

                        (iii)    for liquid fuel—15 kilolitres; or

                        (iv)    for electricity consumed from a generating unit with a maximum capacity to produce less than 0.5 megawatts of electricity—100 000 kilowatt hours; or

                         (v)    for all other electricity consumption—0 kilowatt hours.

Example

A fuel is consumed without combustion when it is used as a solvent or a flocculent, or as an ingredient in the manufacture of products such as paints, solvents or explosives.

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

         (1)   This section applies, other than for Division 2.5.3, if:

                (a)    a fuel type as provided for in a method is consumed from the operation of a facility as either a reductant or a feedstock; and

               (b)    the fuel is combusted for energy; and

                (c)    the equipment used to measure the amount of the fuel for the relevant purpose was not calibrated to a measurement requirement.

Note   Division 2.5.3 deals with petrochemicals. For petrochemicals, all fuels, whether used as a feedstock, a reductant or combusted as energy are reported as energy.

         (2)   The amount of the fuel type consumed as a reductant or a feedstock may be estimated:

                (a)    in accordance with industry measuring devices or industry practice; or

               (b)    if it is not practicable to estimate as provided for in paragraph (a) — to be the whole of the amount of the consumption of that fuel type from the operation of the facility.

         (3)   The amount of the fuel type combusted for energy may be estimated as the difference between the total amount of the fuel type consumed from the operation of the facility and the estimated amount worked out under subsection (2).

2.70        Amount of energy consumed in a cogeneration process

         (1)   For subregulation 4.23 (3) of the Regulations and subject to subsection (3), the method is the efficiency method.

         (2)   The efficiency method is as described in the publication entitled Allocation of Emissions from a Combined Heat and Power (CHP) Plant Guide to calculation worksheets (September 2006) v1.0 issued by the World Resource Institute and World Business Council for Sustainable Development.

         (3)   Where heat is to be used mainly for producing mechanical work, the work potential method may be used.

         (4)   The work potential method is as described in the publication entitled Allocation of Emissions from a Combined Heat and Power (CHP) Plant Guide to calculation worksheets (September 2006) v1.0 issued by the World Resource Institute and World Business Council for Sustainable Development.

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

                Subject to section 2.70, the amount of fuel type (i) consumed by a reporting corporation 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, 3.25 and 3.25A.

3.22        Total gas contained by gas bearing strata

         (1)   For method 2 under subsection 3.21 (1), Sj,z for gas type (j) contained in a gas bearing strata (z) under the extraction area of the mine during the year, measured in cubic metres, is:

where:

Mz is the mass of the gas bearing strata (z) under the extraction area of the mine during the year, measured in tonnes.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

         (4)   For GCjz in subsection (1), the content of gas type (j) contained by the gas bearing strata (z) must be estimated in accordance with sections 3.24, 3.25, 3.25A and 3.25B.

3.23        Estimate of proportion of gas content released below pit floor

                For paragraph (b) of the factor βz in subsection 3.22 (1), estimate βz using one of the following equations:

                (a)    equation 1:

;

               (b)    equation 2:

.

where:

x is the depth in metres of the floor of the gas bearing strata (z) measured from ground level.

h is the depth in metres of the pit floor of the mine measured from ground level.

dh is 20, being representative of the depth in metres of the gas bearing strata below the pit floor that releases gas.

3.24        General requirements for sampling

         (1)   Core samples of a gas bearing strata must be collected to produce estimates of gas content that are representative of the gas bearing strata in the extraction area of the mine during the year.

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

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

         (4)   The value obtained from the samples must only be used for the open cut mine from which it was intended to be representative.

         (5)   Sampling must be carried out in accordance with:

                (a)    the minimum requirements for data collection and gas testing mentioned in section 2 of the ACARP Guidelines; and

               (b)    the data validation, analysis and interpretation processes mentioned in section 3 of the ACARP Guidelines.

3.25        General requirements for analysis of gas and gas bearing strata

                Analysis of a gas and a gas bearing strata, including the mass and gas content of the strata, must be done in accordance with:

                (a)    the minimum requirements for data collection and gas testing mentioned in section 2 of the ACARP Guidelines; and

               (b)    the data validation, analysis and interpretation processes mentioned in section 3 of the ACARP Guidelines; and

                (c)    the method of applying the gas distribution model to develop an emissions estimate for an open cut mine mentioned in section 4 of the ACARP Guidelines.

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

         (1)   The estimator must:

                (a)    take all reasonable steps to ensure that samples of gas taken from the gas bearing strata of the open cut mine are taken in accordance with the minimum requirements for data collection and gas testing mentioned in section 2 of the ACARP Guidelines; and

               (b)    take all reasonable steps to ensure that samples of gas taken from boreholes are taken in accordance with the requirements for:

                          (i)    the number of boreholes mentioned in sections 2 and 3 of the ACARP Guidelines; and

                         (ii)    borehole spacing mentioned in section 2 of the ACARP Guidelines; and

                        (iii)    sample selection mentioned in section 2 of the ACARP Guidelines; and

                (c)    work out the base of the low gas zone by using the method mentioned in subsection (2); and

               (d)    if the base of the low gas zone worked out in accordance with subsection (2) varies, in a vertical plane, within:

                          (i)    a range of 20 metres between boreholes located in the same domain of the open cut mine—work out the base of the low gas zone using the method mentioned in subsection (3); or

                         (ii)    a range of greater than 20 metres between boreholes located in the same domain of the open cut mine—the method mentioned in subsection (4).

Preliminary method of working out base of low gas zone

         (2)   For paragraph (1) (c), the method is that the estimator must perform the following steps:

Step 1

For each borehole, identify the depth at which:

   (a)  the results of greater than 3 consecutive samples taken in the borehole indicate that the gas content of the gas bearing strata is greater than 0.5 m3/t; or

  (b)  the results of 3 consecutive samples taken in the borehole indicate that the methane composition of the gas bearing strata is greater than 50% of total gas composition by volume.

Step 2

If paragraph (a) or (b) of step 1 applies, identify, for each borehole, the depth of the top of the gas bearing strata at which the first of the 3 consecutive samples in the borehole was taken.

Note   The depth of the top of the gas bearing strata worked out under step 2 is the same as the depth of the base of the low gas zone.

Method of working out base of low gas zone for subparagraph (1) (d) (i)

         (3)   For subparagraph (1) (d) (i), the method is that the estimator must work out the average depth at which step 2 of the method in subsection (2) applies.

Method of working out base of low gas zone for subparagraph (1) (d) (ii)

         (4)   For subparagraph (1) (d) (ii), the method is that the estimator must construct a 3‑dimensional model of the surface of the low gas zone using a triangulation algorithm or a gridding algorithm.

3.25B     Further requirements for estimator

         (1)   This section applies if:

                (a)    the estimator constructs a 3-dimensional model of the surface of the base of the low gas zone in accordance with the method mentioned in subsection 3.25A (4); and

               (b)    the 3‑dimensional model of the surface of the low gas zone is extrapolated beyond the area modelled directly from boreholes in the domain.

         (2)   The estimator must:

                (a)    ensure that the extrapolated surface:

                          (i)    applies the same geological modelling rules that were applied in the generation of the surface of the base of the low gas zone from the boreholes; and

                         (ii)    represents the base of the low gas zone in relation to the geological structures located within the domain; and

                        (iii)    is generated using a modelling methodology that is consistent with the geological model used to estimate the coal resource; and

                        (iv)    the geological model used to estimate the coal resource meets the minimum requirements and the standard of quality mentioned in section 1 of the ACARP Guidelines.

               (b)    make and retain a record:

                          (i)    of the data and assumptions incorporated into the generation of the 3‑dimensional surface; and

                         (ii)    that demonstrates that the delineation of the 3‑dimensional surface complies with sections 1.13 and 3.24.

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

                A default gas content of 0.00023 tonnes of carbon dioxide per tonne of gas bearing strata must be assigned to all gas bearing strata located in the low gas zone.

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

         (1)   The total gas contained in gas bearing strata for an open cut coal mine must be estimated in accordance with the emissions estimation process mentioned in section 1 of the ACARP Guidelines.

         (2)   The gas distribution model used for estimating emissions must be applied in accordance with section 4.1 of the ACARP Guidelines; and

         (3)   The modelling bias must be assessed in accordance with section 4.2 of the ACARP Guidelines.

         (4)   The gas distribution model must be applied to the geology model in accordance with section 4.3 of the ACARP Guidelines.

3.26        Method 3 — extraction of coal

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

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

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

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

Subdivision 3.2.3.3     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

         (1)   Subject to section 1.18, the methods mentioned in subsections (2) and (3) must be used for estimating fugitive emissions that result from system upsets, accidents and deliberate releases from process vents during a reporting year from the operation of a facility that is constituted by oil or gas exploration.

         (2)   To estimate emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, one of the following methods must be used:

                (a)    method 1 under section 3.84;

               (b)    method 4 under Part 1.3.

         (3)   For estimating incidental emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, another method may be used that is consistent with the principles mentioned in section 1.13.

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

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

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

         (1)   Method 2 is:

where:

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

Σk is the emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions released from each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment type is used in the crude oil production.

Qik is the total of the quantities of crude oil that pass through each equipment type (k), or the number of equipment units of type (k), listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production, measured in tonnes.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes through each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production.

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

                (a)    as listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, for the equipment type; or

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

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

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

         (1)   Subject to section 1.18, the methods mentioned in subsections (2) and (3) must be used for estimating fugitive emissions that result from system upsets, accidents and deliberate releases from process vents during a year from the operation of a facility that is constituted by crude oil production.

         (2)   To estimate emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, one of the following methods must be used:

                (a)    method 1 under section 3.84;

               (b)    method 4 under Part 1.3.

         (3)   For estimating incidental emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, another method may be used that is consistent with the principles mentioned in section 1.13.

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

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, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing.

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

         (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, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing.

Qik is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per tonne of natural gas that passes through each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas production and processing.

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

                (a)    as listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, for the equipment type; or

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

Division 3.3.7        Natural gas transmission

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; or

                (e)    estimated using the engineering calculation approach in accordance with sections 5 and 6.1.2 of the API Compendium.

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

Division 3.3.8        Natural gas distribution

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—coal seam exploratory drilling, well testing and mud degassing

Section 5.6.3 and 5.6.6

7

Non-routine activities — production related non-routine emissions

Section 5.7.1 or 5.7.2

8

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

Section 5.7.1 or 5.7.3

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

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);

                        (vi)    sodium cyanide (see Division 4.3.6);

                (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.

9   Brick production.

10   Ceramic production.

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;

              (aa)    for use of carbonates in clay materials—method 1A under section 4.22A;

               (b)    method 3 under section 4.23;

              (ba)    for use of carbonates in clay materials—method 3A under section 4.23A;

                (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.

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

         (1)   Method 1A is measure the amount of emissions of carbon dioxide released from each clay material consumed in the industrial process during the reporting year, measured in CO2‑e tonnes, using the following formula:

where:

Ej is the emissions of carbon dioxide released from the clay material consumed in the industrial process during the reporting year in a State or Territory (j) mentioned in column 2 of an item in the table in subsection (2), measured in CO2-e tonnes.

Qj is the quantity of clay material consumed in the industrial process during the reporting year in a State or Territory (j) mentioned in column 2 of an item in the table in subsection (2), measured in tonnes and estimated under Division 4.2.5.

ICCj is the inorganic carbon content factor of clay material specified in column 3 of an item in the table in subsection (2) for each State or Territory (j) mentioned in column 2 of the item.

         (2)   For ICCj in subsection (1), column 3 of an item in the following table specifies the inorganic carbon content factor for a State or Territory (j) mentioned in column 2 of the item.

Item

State or Territory (j)

Inorganic carbon content factor

1

New South Wales

6.068  10-3

2

Victoria

2.333  10-4

3

Queensland

2.509  10-3

4

Western Australia

3.140  10-4

5

South Australia

5.170  10-4

6

Tasmania

1.050  10-3

7

Australian Capital Territory

6.068  10-3

8

Northern Territory

5.170  10-4

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.

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

                Method 3A is:

Step 1

Measure the amount of emissions of carbon dioxide released from each clay material consumed in the industrial process during the reporting year, measured in CO2‑e tonnes, using the following formula:

 

where:

E is the emissions of carbon dioxide released from the clay material consumed in the industrial process during the reporting year, measured in CO2-e tonnes.

Q is the quantity of clay material consumed in the industrial process during the reporting year, measured in tonnes and estimated under Division 4.2.5.

ICC is the inorganic carbon content factor of the clay material.

γ is the factor 1.861 Í 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

Identify the amount of emissions of carbon dioxide for each clay material consumed in the industrial process during the reporting year.

Step 3

Add together each amount identified under step 2.

4.23B     General requirements for sampling clay material

         (1)   A sample of clay material must:

                (a)    be derived from a composite of amounts of the clay material; and

               (b)    be collected on enough occasions to produce a representative sample; and

                (c)    be free from bias so that any estimates are neither over nor under estimates of the true value; and

               (d)    be tested for bias in accordance with an appropriate standard.

         (2)   The value obtained from the samples of the clay material must be used only for the delivery period or consignment of the clay material for which it was intended to be representative.

4.23C     General requirements for analysing clay material

         (1)   Analysis of samples of the clay material must be performed in accordance with:

                (a)    industry practice; and

               (b)    the general principles for measuring emissions mentioned in section 1.13.

         (2)   The minimum frequency of analysis of samples of clay material 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.

4.24        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.