Chapter 4: Fugitive Emissions

CHAPTER 4

FUGITIVE EMISSIONS

2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

4.1

Volume 2: Energy

Authors
Christian Boettcher (Germany), Amit Garg (India), Paul Nzomo Mbuthi (Kenya), Steven J. Oliver (Australia),
Roberta Quadrelli (Italy), Cynthia Ann Randles (USA/Australia), Raquel Rodrigues de Souza (Brazil),
Ajay Kumar Singh (India), Michael Strogies (Germany), Kostyantyn Tadlya (Ukraine), Nina Uvarova (Russia),
John D. Watterson (UK), Melissa M. Weitz (USA), Francis Davison Yamba (Zambia), Shengmin Yu (China),
and Songli Zhu (China)

Contributing Authors
Laura E. Dawidowski (Argentina), Oleksandra Kolmogortseva (Ukraine), Teruo Okazaki (Japan),Ingrid Person Rocha e Pinho (Brazil), Steven C. Smyth (Canada) and Jongikhaya Witi (South Africa)

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Chapter 4: Fugitive Emissions

Contents
4

Fugitive Emissions ....................................................................................................................................... 4.10
4.1

Fugitive emissions from mining, processing, storage and transportation of coal .............................. 4.10
4.1.1 Overview and description of sources ........................................................................................... 4.10
4.1.1.1

Coal mining and handling ................................................................................................ 4.10

4.1.1.2

Summary of sources ......................................................................................................... 4.12

4.1.2 Methodological issues ................................................................................................................. 4.13
4.1.3 Underground coal mines .............................................................................................................. 4.14
4.1.3.1

Choice of method ............................................................................................................. 4.15

4.1.3.2

Choice of emission factors for underground mines .......................................................... 4.18

4.1.3.3

Choice of activity data...................................................................................................... 4.21

4.1.3.4

Completeness for underground coal mines ...................................................................... 4.21

4.1.3.5

Developing a consistent time series ................................................................................. 4.21

4.1.3.6

Uncertainty assessment .................................................................................................... 4.22

4.1.4 Surface coal mining ..................................................................................................................... 4.23
4.1.4.1

Choice of method ............................................................................................................. 4.23

4.1.4.2

Emission factors for surface mining ................................................................................. 4.24

4.1.4.3

Activity data ..................................................................................................................... 4.26

4.1.4.4

Completeness for surface mining ..................................................................................... 4.26

4.1.4.5

Developing a consistent time series ................................................................................. 4.26

4.1.4.6

Uncertainty Assessment in emissions .............................................................................. 4.26

4.1.5 Abandoned underground coal mines ........................................................................................... 4.27
4.1.5.1

Choice of method ............................................................................................................. 4.27

4.1.5.2

Choice of emission factors ............................................................................................... 4.27

4.1.5.3

Choice of activity data...................................................................................................... 4.32

4.1.5.4

Completeness ................................................................................................................... 4.32

4.1.5.5

Developing a consistent time series ................................................................................. 4.32

4.1.5.6

Uncertainty assessment .................................................................................................... 4.32

4.1.6 Completeness for coal mining ..................................................................................................... 4.32
4.1.7 Inventory Quality Assurance/Quality Control (QA/QC) ............................................................. 4.33
4.2

Fugitive Emissions from Oil and Natural Gas Systems .................................................................... 4.34
4.2.1 Overview and description of sources ........................................................................................... 4.35
4.2.2 Methodological issues ................................................................................................................. 4.38
4.2.2.1

Choice of method, decision trees, tiers ............................................................................. 4.39

4.2.2.2

Choice of method ............................................................................................................. 4.43

4.2.2.3

Choice of emission factor ................................................................................................. 4.47

4.2.2.4

Choice of activity data...................................................................................................... 4.84

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4.2.2.5

Completeness ................................................................................................................... 4.91

4.2.2.6

Developing consistent time series .................................................................................... 4.92

4.2.2.7

Uncertainty assessment .................................................................................................... 4.92

4.2.3 Inventory Quality Assurance/Quality Control (QA/QC) ............................................................. 4.93
4.2.4 Reporting and Documentation ..................................................................................................... 4.94
4.3

Fugitive Emissions from Fuel Transformation .................................................................................. 4.98
4.3.1 Overview and description of sources ........................................................................................... 4.98
4.3.2 Methodological issues ................................................................................................................. 4.99
4.3.2.1

Solid to solid transformation processes ............................................................................ 4.99

4.3.2.2

Gasification transformation processes ............................................................................ 4.117

4.3.3 Completeness ............................................................................................................................. 4.123
4.3.4 Developing consistent time series ............................................................................................. 4.123
4.3.5 Inventory Quality Assurance/Quality Control (QA/QC) ........................................................... 4.124
4.3.6 Reporting and Documentation ................................................................................................... 4.124
Annex 4A.1

Standard Conditions ....................................................................................................... 4.125

Annex 4A.2

Disaggregation of Tier 1 factors presented in Section 4.2.2.3........................................ 4.127

Annex 4A.3

Definition of terminologies used in Section 4.2 ............................................................. 4.137

Appendix 4A.1

Fugitive emissions from mining, processing, storage and transportation of coal: Basis for
Future Methodological Development ............................................................................. 4.143

Appendix 4A.1.1

Abandoned Surface Mines ............................................................................................. 4.143

Appendix 4A.1.2

Coal Exploration ............................................................................................................ 4.143

Appendix 4A.2

Fugitive Greenhouse Gas Emissions from Wood Pellet production: Basis for Future
Methodological Development ........................................................................................ 4.150

Appendix 4A.3

Fugitive Emissions from Biomass to Liquid and Biomass to Gas: Basis for Future
Methodological Development ........................................................................................ 4.155

References........................................................................................................................................ 4.158

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Chapter 4: Fugitive Emissions

Equations
Equation 4.1.0 (New)

Example equation for estimating fugitive emissions from Coal Exploration....... 4.14

Equation 4.1.1

Estimating emissions from underground coal mines for Tier 1 and Tier 2 without
adjustment for methane utilisation or flaring ........................................................ 4.14

Equation 4.1.2 (Updated)

Estimating emissions from underground coal mines for Tier 1 and Tier 2 withadjustment for methane utilisation or flaring ........................................................ 4.15

Equation 4.1.3 (Updated)

Tier 1: global average method – underground mining – methane – before adjustment
for any methane utilisation or flaring .................................................................... 4.18

Equation 4.1.3a (New)

Tier 1: global Average method – underground mining – Carbon dioxide ............ 4.19

Equation 4.1.4

Tier 1: global average method – post-mining emissions – underground mines .... 4.20

Equation 4.1.5

Emissions of CO2 and CH4 from drained methane flared or catalytically oxidised.............................................................................................................................. 4.21

Equation 4.1.6 (Updated)

General equation for estimating fugitive emissions from surface coal mining ..... 4.23

Equation 4.1.7 (Updated)

Tier 1: global average method – surface mines – methane ................................... 4.25

Equation 4.1.7a (New)

Tier 1: global average method – surface mines – carbon dioxide ......................... 4.25

Equation 4.1.8

Tier 1: global average method – post-mining emissions – surface mines ............. 4.26

Equation 4.1.11

Tier 2: approach for abandoned underground mines without methane recovery andutilization .............................................................................................................. 4.30

Equation 4.1.12

Tier 2: abandoned underground coal mines emission factor ................................. 4.31

Equation 4.1.13

Example of Tier 3 emissions calculation – abandoned underground mines ......... 4.31

Equation 4.2.1

Tier 1: estimating fugitive emissions from an industry segment........................... 4.43

Equation 4.2.2

Tier 1: total fugitive emissions from industry segments ....................................... 4.43

Equation 4.2.3

Alternative Tier 2 approach (emissions due to venting) ....................................... 4.45

Equation 4.2.4

Alternative Tier 2 approach (CH4 emissions due to flaring) ................................. 4.45

Equation 4.2.5

Alternative Tier 2 approach (CO2 emissions due to flaring) ................................. 4.45

Equation 4.2.6

CH4 emissions from flaring and venting ............................................................... 4.45

Equation 4.2.7

CO2 emissions from venting and flaring ............................................................... 4.46

Equation 4.2.8

N2O emissions from flaring .................................................................................. 4.46

Equation 4.2.9 (New)General equation for estimating fugitive emissions from Exploration................. 4.49

Equation 4.2.10 (New)General equation for estimating fugitive emissions from Oil Production andUpgrading ............................................................................................................. 4.53

Equation 4.2.11 (New)General equation for estimating fugitive emissions from Oil Transportation ....... 4.56

Equation 4.2.12 (New)General equation for estimating fugitive emissions from Distribution of Oil Products............................................................................................................................ ..4.60

Equation 4.2.13 (New)General equation for estimating fugitive emissions from Exploration.................. 4.65

Equation 4.2.14 (New)General equation for estimating fugitive emissions from Gas Production andGathering............................................................................................................... 4.69

Equation 4.2.15 (New)General equation for estimating fugitive emissions from Gas Processing ............ 4.72

Equation 4.2.16 (New)General equation for estimating fugitive emissions from Gas Transmission andStorage ................................................................................................................. 4.75

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Equation 4.2.17 (New)General equation for estimating fugitive emissions from Gas Distribution .......... 4.78

Equation 4.2.18 (New)General equation for estimating fugitive emissions from Post-meter Leakage..... 4.81

Equation 4.3.1 (New)

Fugitive GHG emissions from charcoal (or Biochar) production on annual basis............................................................................................................................ 4.102

Equation 4.3.2 (New)

Fugitive GHG emission from coke production ................................................... 4.110

Equation 4.3.3 (New)

Fugitive CO2 emissions from the Flaring of Coke Oven Gas ............................. 4.115

Equation 4.3.4 (New)

Fugitive CH4 and N2O emission from The Flaring of Coke Oven Gas ............... 4.115

Equation 4.3.5 (New)

Fugitive GHG emissions from gasification processes ........................................ 4.121

Equation 4A.1.1 (New)Conversion of oil density at 15°C ....................................................................... 4.125

Equation 4A.1.2 (New)Conversion of relative oil density at 15.556°C (60°F) ........................................ 4.125

Equation 4A.1.3 (New)Conversion of API density .................................................................................. 4.125

Equation 4A.1.4 (New)Conversion of gas volume................................................................................... 4.126

Equation 4Ap.1.1 (New)

Tier 1: global average method – fugitive emission from coal exploration boreholes............................................................................................................................ 4.144

Equation 4Ap.1.2 (New)

Tier 2: basin-specific method .............................................................................. 4.145

Equation 4Ap.3.1 (New)

Fugitive GHG emissions from gasification processes ........................................ 4.156

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Chapter 4: Fugitive Emissions

FiguresFigure 4.1.1 (Updated)

Decision tree for methane from underground coal mines ..................................... 4.17

Figure 4.1.1a (New)

Decision tree for carbon dioxide from underground coal mines ........................... 4.18

Figure 4.1.2

Decision tree for surface coal mining ................................................................... 4.24

Figure 4.2.0 (New)Key segments included in oil and natural gas systems.......................................... 4.36

Figure 4.2.1 (Updated)

Decision tree for oil and natural gas systems ........................................................ 4.42

Figure 4.3.1 (New)

Decision tree for Charcoal (and biochar) production .......................................... 4.101

Figure 4.3.2 (New)

Typical flow diagram of a coke oven plant showing emissions sources ............. 4.105

Figure 4.3.3 (New)

Decision tree for estimating fugitive emissions from coke production processes4.109

Figure 4.3.4 (New)

Decision tree for estimating CO2 emissions from coke oven gas flaring ............ 4.113

Figure 4.3.5 (New)

Decision tree for estimating fugitive emissions of CH4 and N2O from cokeproduction process .............................................................................................. 4.114

Figure 4.3.6 (New)Gasification transformation process of biomass, coal and gas ............................ 4.118

Figure 4.3.7 (New)

Decision tree for estimating emissions of CO2, CH4 and N2O from Gasification
Transformation processes ................................................................................... 4.120

Figure 4Ap.1.1 (New)

Decision tree for coal exploration ....................................................................... 4.146

Figure 4Ap.2.1 (New)

Flow diagram of wood pellet production process ............................................... 4.151

Figure 4Ap.2.2 (New)

Emissions Diagram for a Typical Pellet Plant (Two Dryers) .............................. 4.151

Figure 4Ap.2.3 (New)

Proposed decision tree for estimating fugitive emissions from wood pellet
production ........................................................................................................... 4.153

TablesTable 4.1.1 (Updated)

Detailed sector split for emissions from mining, processing, storage and transport ofcoal ........................................................................................................................ 4.12

Table 4.1.2 (Updated)

Estimates of uncertainty for underground mining for Tier 1 and Tier 2 approaches.............................................................................................................................. 4.22

Table 4.1.3

Estimates of uncertainty for underground coal mining for a Tier 3 approach ...... 4.23

Table 4.1.4 (Updated)

Estimates of uncertainty for surface mining for Tier 1 and Tier 2 approaches ..... 4.27

Table 4.1.5

Tier 1 – abandoned underground mines - Default values - percentage of coal minesthat are gassy ......................................................................................................... 4.28

Table 4.1.6 (Updated)

Tier 1 – abandoned underground mines - emission factor, million m3 methane / mine.............................................................................................................................. 4.29

Table 4.1.7 (Updated)

Tier 1 – abandoned underground mines - Example Calculation ........................... 4.30

Table 4.1.8

Tier 2 – abandoned underground coal mines - Default values for active mineemissions prior to abandonment............................................................................ 4.31

Table 4.1.9

Coefficients for Tier 2 – abandoned underground coal mines .............................. 4.31

Table 4.2.2 (Updated)

Major categories and subcategories in the oil and gas industry ............................ 4.40

Table 4.2.3

Typical ranges of gas-to-oil ratios for different types of production ................... 4.44

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Table 4.2.4 (Updated)

Tier 1 Emission Factors for Oil Exploration, 1.B.2.a.i ......................................... 4.50

Table 4.2.4a (New)

Tier 1 Emission Factors for Oil Production, 1.B.2.a.ii .......................................... 4.54

Table 4.2.4b (New)

Tier 1 Emission Factors for Oil Transport, 1.B.2.a.iii........................................... 4.57

Table 4.2.4c (New)

Tier 1 Emission Factors for Oil Refining, 1.B.2.a.iv ............................................ 4.59

Table 4.2.4d (New)

Tier 1 Emission Factors for Distribution of Oil Products, 1.B.2.a.v ..................... 4.61

Table 4.2.4e (New)

Tier 1 Emission Factors for Abandoned Oil Wells, 1.B.2.a.vii............................. 4.63

Table 4.2.4f (New)

Tier 1 Emission factors for Natural Gas Exploration Segment, 1.B.2.b.i ............. 4.66

Table 4.2.4g (New)

Tier 1 Emission factors for Natural Gas Production Segment, 1.B.2.b.ii.............. 4.70

Table 4.2.4h (New)

Tier 1 Emission factors for Gas Processing Segment, 1.B.2.b.iii.......................... 4.73

Table 4.2.4i (New)

Tier 1 Emission factors for Gas Transmission and Storage Segment, 1.B.2.b.iv .. 4.76

Table 4.2.4j (New)

Tier 1 Emission factors for Distribution Segment, 1.B.2.b.v ................................ 4.79

Table 4.2.4k (New)

Tier 1 Emission factors for Post-Meter Segment, 1.B.2.b.vi ................................ 4.82

Table 4.2.6 (Updated)

Typical activity data requirements for each assessment approach for fugitive
emissions from oil and gas systems by type of primary source ............................ 4.84

Table 4.2.7 (Updated)

Activity Data Values Required for Use in the Tier 1 Approach to Estimate Fugitive
Emissions from Oil and Gas Systems ................................................................... 4.86

Table 4.2.9 (Updated)

Format for summarizing the applied methodology and basis for estimated emissions
from oil and natural gas systems showing sample entries..................................... 4.96

Table 4.3.1 (New)

Detailed sector split for emissions from fuel transformation ................................ 4.98

Table 4.3.2 (New)

Estimation and reporting of fugitive emissions from fuel transformation ............ 4.99

Table 4.3.3 (New)

Default Emission factors for charcoal and biochar production (g GHG / kg ofcharcoal (or biochar) produced) .......................................................................... 4.103

Table 4.3.4 (New)

Sources of fugitive greenhouse gas emissions from coke production according toprocessing stage and reporting of emissions ....................................................... 4.107

Table 4.3.5 (New)

Default Emission factors for fugitive emissions from coke production .............. 4.111

Table 4.3.6 (New)

Default uncertainty assessment for emission factors from Coke Production ...... 4.111

Table 4.3.7 (New)

Default factors for fugitive emissions from flaring of coke oven gas ................. 4.116

Table 4.3.8 (New)

Default uncertainty assessment for emission factors from coke oven gas flaring 4.117

Table 4.3.9 (New)

Summary of GHG emissions from gasification transformation processes.......... 4.118

Table 4.3.10 (New)

Emission factors for gasification processes of CtL ............................................. 4.122

Table 4.3.11 (New)

Emission factor for gasification processes of GtL .............................................. 4.122

Table 4.3.12 (New)

Default uncertainty assessment for emission factors from Gasification
Transformation Processes ................................................................................... 4.123

Table 4A.1.1 (New)

Correction of gas volumes to the required temperature conversion factors (CFt)4.126

Table 4A.2.1 (New)Disaggregation of Tier 1 Emission factors for Oil Exploration, 1.B.2.a.i ........... 4.128

Table 4A.2.2 (New)Disaggregation of Tier 1 Emission factors for Oil Production Segment, 1.B.2.a.ii............................................................................................................................ 4.129

Table 4A.2.3 (New)Disaggregation of Tier 1 Emission factors for Oil Refining, 1.B.2.a.iv .............. 4.131

Table 4A.2.4 (New)Disaggregation of Tier 1 Emission factors for Gas Exploration, 1.B.2.b.i.......... 4.131

Table 4A.2.5 (New)Disaggregation of Tier 1 Emission factors for Gas Production, 1.B.2.b.ii .......... 4.132

Table 4A.2.6 (New)Disaggregation of Tier 1 Emission factors for Gas Processing Segment, 1.B.2.b.iii............................................................................................................................ 4.133

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Chapter 4: Fugitive Emissions

Table 4A.2.7 (New)Disaggregation of Tier 1 Emission factors for Gas Transmission Segment, 1.B.2.b.iv............................................................................................................................ 4.134

Table 4Ap.3.1 (New)

Emission factors for gasification processes of BtG and BtL ............................... 4.156

Boxes
Box 4.2.1 (New)Hydrogen Production. Fugitive Emissions and Refineries.................................... 4.58

Box 4.2.2 (New)

Notes on catalyst regeneration and calcination ..................................................... 4.58

Box 4.3.1 (New)

Flaring activities in metallurgical coke and iron and steel production ................ 4.112

Box 4A.2.1 (New)

Example of Calculation of Disaggregated Emission Estimates for Oil Production............................................................................................................................ 4.136

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4

FUGITIVE EMISSIONS

Users are expected to go to Mapping Tables in Annex 2, before reading this chapter. This is required to correctly
understand both the refinements made and how the elements in this chapter relate to the corresponding chapter
in the 2006 IPCC Guidelines.
Intentional or unintentional release of greenhouse gases may occur during the extraction, processing,transformation and delivery of fossil fuels to the point of final use. These are known as fugitive emissions. Certain
fugitive emissions from biomass are included here as well, such as fugitives of biogas from natural gas systems(e.g. distribution pipelines), and fugitives during fuel transformation for charcoal.

4.1

FUGITIVE EMISSIONS FROM MINING,
PROCESSING, STORAGE AND
TRANSPORTATION OF COAL

4.1.1

Overview and description of sources

Fugitive emissions associated with coal can be considered in terms of the following broad categories. 1
0F

4.1.1.1 C OAL MINING AND HANDLI NG
The geological processes of coal formation also produce methane (CH4), and carbon dioxide (CO2) may also bepresent in some coal seams. These are known collectively as seam gas, and remain trapped in the coal seam until
the coal is exposed and broken during mining. CH4 is the major greenhouse gas emitted from coal mining andhandling.
The major stages for the emission of greenhouse gases for both underground and surface coal mines are:
• Mining emissions – These emissions result from the liberation of stored gas during the breakage of coal, andthe surrounding strata, during mining operations.
• Post-mining emissions – Not all gas is released from coal during the process of coal breakage during mining.
Emissions, during subsequent handling, processing and transportation of coal are termed post-mining
emissions. Therefore coal normally continues to emit gas even after it has been mined, although more slowly
than during the coal breakage stage.
• Low temperature oxidation - These emissions arise because once coal is exposed to oxygen in air, the coaloxidizes to produce CO2. However, the rate of formation of CO2 by this process is low.
• Uncontrolled combustion – On occasions, when the heat produced by low temperature oxidation is trapped,
the temperature rises and an active fire may result. This is commonly known as uncontrolled combustion andis the most extreme manifestation of oxidation. Uncontrolled combustion is characterised by rapid reactions,sometimes visible flames and rapid CO2 formation, and may be natural or anthropogenic. It is noted that
uncontrolled combustion only due to coal exploitation activities is considered here.
• Exploration emissions – These emissions result from boreholes drilled through carbonaceous strata for the
purposes of coal exploration. This is distinct from gas drainage boreholes which form part of a degasification
system.
After mining has ceased left over coals in, abandoned coal mines may also continue to emit methane.
A brief description of some of the major processes that need to be accounted for in estimating emissions for thedifferent types of coal mines follows:
UN DE RG RO U ND MI N E S
Active Underground Coal Mines
The following potential source categories for fugitive emissions for active underground coal mines are consideredin this document:
1 Methods for determining emissions from peat extraction are described in Volume 4 AFOLU Chapter 7 ‘Wetlands’.

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Chapter 4: Fugitive Emissions• Seam gas emissions vented to the atmosphere from coal mine ventilation air and degasification systems;• Post-mining emissions;• Low temperature oxidation;• Uncontrolled combustion.
Coal mine ventilation air and degasification systems arise as follows:
Coal Mine Ventilation Air
Underground coal mines are normally ventilated by flushing air from the surface, through the underground tunnels
in order to maintain a safe atmosphere. Ventilation air picks up the CH4 and CO2 released from the coal formations
and transports these to the surface where they are emitted to atmosphere. The concentration of CH4 in theventilation air is normally low, but the volume flow rate of ventilation air is normally large and therefore themethane emissions from this source can be very significant.
Coal Mine Degasification Systems
Degasification systems comprise wells drilled before, during, and after mining to drain gas (mainly CH4) from thecoal seams that release gas into the mine workings. During active mining the major purpose of degasification is tomaintain a safe working atmosphere for the coal miners, although the recovered gas may also be utilised as anenergy source. Degasification systems can also be used at abandoned underground coal mines to recover methane.
The amount of methane recovered from coal mine degasification systems can be very significant and is accounted
for, depending on its final use, as described in Section 4.1.3.2 of this chapter.
Abandoned Underground Mines
After closure, coal mines that were significant CH4 emitters during mining operations continue to emit methane
unless there is flooding that cuts off the emissions. Even if the mines have been sealed, methane may still beemitted to the atmosphere as a result of gas migrating through natural or manmade conduits such as old portals,
vent pipes, or cracks and fissures in the overlying strata. Emissions quickly decline until they reach a near-steadyrate that may persist for an extended period of time.
Abandoned mines may flood as a result of intrusion of groundwater or surface water into the mine void. These
mines typically continue to emit gas for a few years before the mine becomes completely flooded and the water
prevents further methane release to the atmosphere. Emissions from completely flooded abandoned mines can betreated as negligible. Mines that remain partially flooded can continue to produce methane emissions over a long
period of time, as with mines that do not flood.
A further potential source of emissions occurs when some of the coal from abandoned mines ignites through themechanism of uncontrolled combustion. However, there are currently no methodologies for estimating potential
emissions from uncontrolled combustion at abandoned underground mines.
SU RFA C E CO A L M I N E S
Active Surface Mines
The potential source categories for surface mining considered in this chapter are:
• Methane and CO2 emitted during mining from breakage of coal and associated strata and leakage from the pit
floor and highwall• Post-mining emissions• Low temperature oxidation• Uncontrolled combustion in waste dumps
Emissions from surface coal mining occur because the mined and surrounding seams may also contain CH4 andCO2. Although the gas contents are generally less than for deeper underground coal seams, the emission of seamgas from surface mines needs to be taken into account, particularly for countries where this mining method is
widely practised. In addition to seam gas emissions, the waste coal that is dumped into overburden or reject dumps
may generate CO2, either by low temperature oxidation or by uncontrolled combustion.
Abandoned Surface Mines
After closure, abandoned or decommissioned surface mines may continue to emit methane as the gas leaks fromthe coal seams that were broken or damaged during mining. There are at present no methods for estimating
emissions from this source.

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CO A L E XP LO RA T IO N
This source category includes emissions arising from boreholes drilled for coal mining exploration purposes. It
does not include coal gas drainage wells used to collect gas prior to, or as a part of coal mining activities. Fugitive
emissions from coal seam gas drainage wells are included in Underground and Surface Mining Activities. Gas
drainage or production boreholes that consist of a coal seam gas exploration aspect exclusively, are not to be
counted as coal exploration boreholes, and are instead included under 1.B.2.
The overall coal exploration process involves drilling of vertical boreholes from the surface of the Earth to detect
the presence of coal seams, their depth of occurrence, thickness and other geological structures, resource andchemical characteristics such as ash, moisture, volatile matter (VM) and fixed carbon (FC). A small fraction of themethane gas retained by the coal seams may be released during borehole drilling and escape to the atmosphere.
Emissions will occur only if the borehole drilling penetrates some gas bearing strata such as coal and carbonaceous
shale.
Boreholes and wells associated with coal gas drainage and coal bed methane/natural gas exploration are focusedon determining gas flow, and gas bearing strata are often stimulated to increase gas flow. Coal exploration
boreholes are focused on obtaining core samples for resource estimation and investigation of various chemical andgeo-mechanical parameters essential for designing the resource recovery, and therefore the coal fracture systems
are not artificially stimulated. Thus, the gas flow from coal exploration boreholes and coal bed methane/natural
gas boreholes are not comparable.

4.1.1.2 S UMMARY OF SOURCES
The major sources are summarised in Table 4.1.1 below.
TABLE 4.1.1 (UPDATED)DETAILED SECTOR SPLIT FOR EMISSIONS FROM MINING, PROCESSING, STORAGE AND TRANSPORT OF COAL
IPCC code

Category/subcategory

1B

Fugitive emissions from fuels

1B1

Includes all intentional and unintentional emissions fromthe extraction, processing, storage and transport of fuelto the point of final use.
Includes all intentional and unintentional emissions fromthe extraction, processing, storage and transport of solid
fuel to the point of final use.

Solid Fuels

1B1a

Coal mining and handling

Includes all fugitive emissions from coal

1B1ai

Underground mines

Includes all emissions arising from mining, post-mining,abandoned mines and flaring of drained methane.

1B1ai1MiningIncludes all seam gas emissions vented to atmospherefrom coal mine ventilation air and degasification
systems.

1B1ai2

Post-mining
seam gasemissions

Includes methane and CO2 emitted after coal has been
mined, brought to the surface and subsequently
processed, stored and transported.

1B1ai3Abandoned
undergroundmines

Includes methane emissions from abandoned
underground mines

1B1ai4

Flaring ofdrained methaneor conversion of
methane to CO2

Methane drained and flared, or ventilation gas converted
to CO2 by an oxidation process should be included here.
Methane used for energy production should be included
in Volume 2, Energy, Chapter 2 ‘Stationary
Combustion’.

1 B 1 a ii

Surface mines

Includes all seam gas emissions arising from surface coalmining1 B 1 a ii 1

MiningIncludes methane and CO2 emitted during mining frombreakage of coal and associated strata and leakage fromthe pit floor and highwall

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Chapter 4: Fugitive Emissions

TABLE 4.1.1 (UPDATED) (CONTINUED)
DETAILED SECTOR SPLIT FOR EMISSIONS FROM MINING, PROCESSING, STORAGE AND TRANSPORT OF COAL
IPCC code

Category/subcategory

1 B 1 a ii 2

Post-mining
seam gasemissions

Includes methane and CO2 emitted after coal has been
mined, subsequently processed, stored and transported.

1 B 1 a ii 3

Abandoned
surface mines

Includes methane emissions from abandoned surface
mines.

1 B 1 a iii

Coal exploration

1B1b

Uncontrolled combustion
and burning coal dumps

4.1.2

Includes methane emissions from boreholes drilled forthe purposes of coal exploration.
Includes emissions of CO2 from uncontrolled
combustion due to coal exploitation activities.

Methodological issues

The following sections focus on methane emissions, as this gas is the most important fugitive emission for coalmining. Methods for estimating carbon dioxide emissions from underground and surface mining are also provided.
Carbon dioxide emissions from other coal mining sources such as post-mining and abandoned mines should also
be included in the inventory where data are available.
UN DE RG RO U ND MI N ING
Fugitive emissions from underground mining arise from both ventilation and degasification systems. Theseemissions are normally emitted at a small number of centralised locations and can be considered as point sources.
They are amenable to standard measurement methods.
SU RFA C E M IN I NG
For surface mining the emissions of greenhouse gases are generally dispersed over sections of the mine and are
best considered area sources. These emissions may be the result of seam gases emitted through the processes ofbreakage of the coal and overburden, low temperature oxidation of waste coal or low quality coal in dumps, anduncontrolled combustion. Measurement methods for low temperature oxidation and uncontrolled combustion are
still being developed and therefore estimation methods are not included in this chapter.
AB AN DO N ED M I NE S
Abandoned underground mines present difficulties in estimating emissions, although a methodology forabandoned underground mines is included in this chapter. Methodologies do not yet exist for abandoned or
decommissioned surface mines, and therefore they are not included in this chapter.
EX P LO R A TI O N
Tier 1 default emission factors could not be developed in the 2019 Refinement process due to a lack of scientificinformation. A methodology and emission factors are not presented here for coal exploration. If coal exploration
activities are present and expected to result in significant emissions, a compiler should make appropriate effort toestimate emissions for this source under 1.B.1a.iii.
It may be necessary to generate new data since emission factors, activity data or other estimation parameters do
not exist, or cannot be estimated from existing sources. In most cases generating new source data will be limitedby the resources available and prioritisation will be needed, taking account of the results of key category analysis
set out in Volume 1, Chapter 4, Methodological Choice and Identification of Key Categories. In these cases, it isgood practice to make an initial estimate of the source and/or sink emissions or removals and compare this to themagnitude of key categories in order to assess and prioritize the effort required. Such initial estimates can be very
rough and may be based on expert judgement as they are intended to guide resource use. If a new source or sinkis estimated to be on a scale similar to the key categories then it is good practice to use Tier 2 or 3 methods, anddata collection should be planned accordingly. Generation of new data is best undertaken by those with appropriate
expertise (e.g., measurements carried out by competent organisations using appropriately calibrated equipment or
surveys and censuses by any national statistical authority). These activities are often resource intensive and aremost appropriately considered when the category is key and there are no other options. Compilers may refer toVolume 1, Chapter 2, Approaches to Data Collection.
The inventory compilers, while estimating these emissions for tier 2/3 level, could collect relevant activity datasuch as the number of coal exploration boreholes drilled each year in different geographies. The compiler could

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consult with national statistic or mining agencies and industry sources for the relevant data. For a tier 3 approach,each borehole could be measured. For a tier 2 approach, appropriate emission factors could be developed using
emissions data collected from a representative number of coal exploration boreholes. The activity data andemission factors could then be multiplied separately for each coal borehole and aggregated to the national level so
as to arrive at the national fugitive emission estimation from coal exploration, using equation 4.1.0 below for
example.
EQUATION 4.1.0 (NEW)EXAMPLE EQUATION FOR ESTIMATING FUGITIVE EMISSIONSFROM COAL EXPLORATION

Eexploration = Anumber of coal boreholes • EFcoal borehole
Where:
Eexploration= Total amount of GHG gas emitted due to all relevant coal exploration activities

Anumber of coal boreholes= Activity data on coal exploration

EFcoal boreholes= Emission factor for coal exploration

M E TH AN E R ECO V ER Y A ND U T I LI S AT IO N
Methane recovered from drainage, ventilation air, or abandoned mines may be mitigated in two ways: (1) direct
utilization as a natural gas resource or (2) by flaring to produce CO2, which has a lower global warming potential
than methane.
T I ER S
Use of appropriate tiers to develop emissions estimates for coal mining in accordance with good practice depends
on the quality of data available. For instance, if limited data are available and the category is not key, then Tier 1
is good practice. The Tier 1 approach requires that countries choose from a global average range of emission
factors and use country-specific activity data to calculate total emissions. Tier 1 is associated with the highest levelof uncertainty. The Tier 2 approach uses country- or basin-specific emission factors that represent the averagevalues for the coals being mined. These values are normally developed by each country, where appropriate. The
Tier 3 approach uses direct measurements on a mine-specific basis and, properly applied, has the lowest level of
uncertainty.

4.1.3

Underground coal mines

The general form of the equation for estimating emissions for Tier 1 and 2 approaches, based on coal production
activity data from underground coal mining and post-mining emissions is given by Equation 4.1.1 below. Methods
to estimate emissions from abandoned underground mines are described in detail in Section 4.1.5.
Equation 4.1.1 represents emissions before adjustment for any utilisation or flaring of recovered gas:
EQUATION 4.1.1
ESTIMATING EMISSIONS FROM UNDERGROUND COAL MINES FOR TIER 1 AND TIER 2 WITHOUT
ADJUSTMENT FOR METHANE UTILISATION OR FLARING

Greenhouse gas emissions= Raw coal production • Emission Factor • Units conversion factor

The definition of the Emission Factor used in this equation depends on the activity data used. For Tier 1 and Tier
2, the Emission Factor for underground, surface and post-mining emissions has units of m3 tonne-1, the same units
as in situ gas content. This is because these Emission Factors are used with activity data on raw coal production
which has mass units (i.e. tonnes). However, the Emission Factor and the in situ gas content are not the same andshould not be confused. The Emission Factor is always larger than the in situ gas content, because the gas released
during mining draws from a larger volume of coal and adjacent gas-bearing strata than simply the volume of coalproduced. For abandoned underground mines, the Emission Factor has different units, because of the different
methodologies employed, see Section 4.1.5 for greater detail.
The equation to be used along with Equation 4.1.1 in order to adjust for methane utilisation and flaring for Tier 1
and Tier 2 approaches is shown in Equation 4.1.2.

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Chapter 4: Fugitive Emissions

EQUATION 4.1.2 (UPDATED)ESTIMATING EMISSIONS FROM UNDERGROUND COAL MINES FOR TIER 1 AND TIER 2 WITH
ADJUSTMENT FOR METHANE UTILISATION OR FLARING

CH 4 emissions from underground mining activities = Emissions from underground mining CH 4
+ Post -mining emission of CH 4 – CH 4 recovered and utilized for energy production or flared

CO2 emissions from underground mining activities = Emissions from underground mining CO2− the amount of CO2 contained in the gasrecovered for energy production+ Emissions of CO2 from methane flared or catalytically oxidised

Emissions of CH4 from underground mines in Equations 4.1.1 and 4.1.2 include abandoned mines (see Section
4.1.5) and both go into the total for 1.B.1.a.i (Underground mines). Theoretically, Equations 4.1.1 and 4.1.2 should
also include CO2 emissions from post-mining activities and abandoned mines. However, considering that Section
4.1.3.2 and 4.1.5 below provides no methods or emission factors for neither of those two CO2 emission sources,
therefore the general equations for CO2 here are simply the emissions from underground mining operations.
Equation 4.1.2 is used for Tiers 1 and 2 because they use Emission Factors to account for emissions from coalmines on a national or coal-basin level. The emission factors already include all the methane likely to be released
from mining activities. Thus, any methane recovery and utilization must be explicitly accounted for by thesubtraction term in Equation 4.1.2.
Similarly, where gas from coal seams is recovered for fuel combustion, the amount of CO2 contained in therecovered gas, which could be determined in a similar way as how the volume of methane recovery and utilizationin Equation 4.1.2 is obtained (for example, being estimated based on national total amount of gas recovered andaverage CO2/CH4 concentration representative of national circumstances, or coal basin-level or even minespecific calculations which take into account the gas drained and recovered from individual mines), should also
be accounted for by the subtraction term in Equation 4.1.2. That CO2 will be eventually accounted for in the
categories where the gas from coal seam are consumed under Chapter 2 Stationary Combustion.
If the gas recovered from coal seams is flared or catalytically oxidised with no useful energy, then the amount of
CO2 contained in that recovered gas is accounted as fugitive emissions under 1 B 1 a i 4, using Equation 4.1.5.
Tier 3 methods involve mine-specific calculations which take into account the methane drained and recoveredfrom individual mines rather than emission factors, and therefore Equation 4.1.2 is not appropriate for Tier 3
methods.

4.1.3.1 C HOICE OF METH OD
UN DE RG RO U ND MI N ING
Figures 4.1.1 and 4.1.1a shows the methane and carbon dioxide decision trees for underground coal mining
activities. For countries with underground mining, and where mine-specific measurement data are available it isgood practice to use a Tier 3 method. Mine-specific CH4 and CO2 data, based on ventilation air measurements anddegasification system measurements, reflect actual emissions on a mine-by-mine basis, and therefore produce amore accurate estimate than using Emission Factors.
Hybrid Tier 3 - Tier 2 approaches are appropriate in situations when mine-specific measurement data are available
only for a subset of underground mines. For example, if only mines that are considered gassy report data, emissions
from the remaining mines can be calculated with Tier 2 emission factors. The definition of what constitutes agassy mine will be determined by each country. For instance, in the United States, gassy mines refers to coal mines
with average annual ventilation emissions exceeding the range of 2 800 to 14 000 cubic meters per day. Emission
factors can be based on specific emission rates derived from Tier 3 data if the mines are operating within the samebasin as the Tier 3 mines, or on the basis of mine-specific properties, such as the average depth of the coal mines.
When no mine-by-mine data are available, but country- or basin-specific data are, it is good practice to employ
the Tier 2 method.
Where no data (or very limited data) are available, it is good practice to use a Tier 1 approach, provided
underground coal mining is not a key sub source category. If it is, then it is good practice to obtain emissions data
to increase the accuracy of these emissions estimates (see Figures 4.1.1 and 4.1.1a). A reliable relationship between
CH4 and CO2 emissions levels from underground coal mining is not able to be established as of now for the
purposes of emission estimation. Therefore emission methods based on correlation between CH4 and CO2 are notprovided.

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PO S T- M IN I NG
Direct measurement (Tier 3) of all post-mining emissions is not feasible, so an emission factor approach must be
used. The Tier 2 and Tier 1 methods described below represent good practice for this source, given the difficultyof obtaining better data.
LO W T E MP ER A TU R E O X ID A TIO N
Oxidation of coal when it is exposed to the atmosphere by coal mining releases CO2. Low temperature oxidationof coal is one among other sources of CO2 during mining activity. Tier 1 approach uses emission factors that cover
all fugitive sources of CO2 including low temperature oxidation.
AB AN DO N ED UN D ER G RO U ND MI N ES
Fugitive methane emissions from abandoned underground mines should be reported in Underground Mines in
IPCC Category 1.B.1.a.i.3, using the methodology presented in Section 4.1.5.

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Chapter 4: Fugitive Emissions

Figure 4.1.1 (Updated) Decision tree for methane from underground coal mines
Start

Are mine-specificmeasurements available
from all mines?

Estimate emissions
using a Tier 3 method.

Yes

Box 1: Tier 3NoIs
undergroundmining a key
category?

No

Estimate emissions
using Tier 1 methods.
Box 2: Tier 1

Yes

Are
mine-specific data
available for gassy
mines?

Yes
Estimate emissions using a Tier 3
method for gassy mines with direct
measurements and Tier 2 for mines
without direct measurements.
Box 4: Hybrid Tier 2/Tier 3NoArebasin-specificemission factors
available?

Yes

No

Collect
measurement
data.

Estimate emissions
using a Tier 2 method.
Box 3: Tier 2

Note: See Volume 1 Chapter 4, “Methodological Choice and Key Categories” (noting Section 4.1.2 on limited resources) for discussion of key
categories and use of decision trees

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Figure 4.1.1a (New) Decision tree for carbon dioxide from underground coal mines
Start

Are mine-specificmeasurements available
from all mines?

Estimate emissions
using a Tier 3
method.
Box 1: Tier 3

Yes

No

Is
undergroundmining a key
category?

YesAre
mine-specific data
available?

No

No

Yes

Estimate emissions
using Tier 1 methods.

Estimate emissions using a Tier 3
method for mines with direct
measurement and Tier 2 for mines
without direct measurements.

Box 2: Tier 1

Box 4: Hybrid Tier 2/Tier 3

Arebasin-specificemission factor
availabe?

Yes

No

Collect
measurement
data.

Estimate emissions
using a Tier 2
method.
Box 3: Tier 2

Note: See Volume 1 Chapter 4, “Methodological Choice and Key Categories” (noting Section 4.1.2 on limited resources) for discussion of key
categories and use of decision trees

4.1.3.2

C HOICE OF EMISSI ON FACTORS FO R UNDERGROUND MI NES

M IN I NG
MethaneTier 1 Emission Factors for underground mining are shown below. The emission factors are the same as thosedescribed in the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (BCTSRE, 1992; Bibler
et al., 1991; Lama, 1992; Pilcher et al., 1991; US EPA, 1993a,b and Zimmermeyer, 1989).
EQUATION 4.1.3 (UPDATED)TIER 1: GLOBAL AVERAGE METHOD – UNDERGROUND MINING – METHANE – BEFORE
ADJUSTMENT FOR ANY METHANE UTILISATION OR FLARING

CH 4 emissions =CH 4 Emission Factor • Underground Coal Production • Conversion Factor

Where units are:Methane Emissions (Gg year-1)
CH4 Emission Factor (m3 tonne-1)
Underground Coal Production (tonne year-1)
Emission Factor:

4.18

Low CH4 Emission Factor= 10 m3 tonne-1

Average CH4 Emission Factor= 18 m3 tonne-1

High CH4 Emission Factor= 25 m3 tonne-1

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Chapter 4: Fugitive Emissions

Conversion Factor:
This is the density of CH4 and converts volume of CH4 to mass of CH4. The density is taken at 20˚C and 1
atmosphere pressure and has a value of 0.67 ● 10-6 Gg m-3.
Countries using the Tier 1 approach should consider country-specific variables such as the depth of major coalseams to determine the emission factor to be used. As gas content of coal usually increases with depth, the low
end of the range should be chosen for average mining depths of <200 m, and for depths of > 400 m the high value
is appropriate. For intermediate depths, average values can be used.
For countries using a Tier 2 approach, basin-specific emission factors may be obtained from sample ventilation air
data or from a quantitative relationship that accounts for the gas content of the coal seam and the surrounding strata
affected by the mining process, along with raw coal production. For a typical longwall operation, the amount ofgas released comes from the coal being extracted and from any other gas-bearing strata that are located within 150
m above and 50 m below the mined seam (Good Practice Guidance, 2000).
Carbon dioxide
Tier 1 Emission Factors for underground mining are shown below. The emission factors have been derived from
National Inventory Reports, scientific literature and data reported to national reporting programs of the following
countries: Australia, China, Czech Republic, India, Japan, Slovakia, Slovenia, South Africa, Russia and Ukraine.
The average emission factor is taken from the mean of the latest implied emission factors from each of thesecountries.
(Moscow Geological Prospecting Institute 1979; Moscow Geological Prospecting Institute 1980; China State
Administration of Coal Mine Safety 2012; Department of Environmental Affairs 2014; Central Institute of Mining
and Fuel Research 2016; Commonwealth of Australia 2017; Czech Hydrometeorological Institute 2017; Ministryof the Environment and Spatial Planning of the Republic of Slovenia 2017; Slovak Hydrometeorological Institute2017; Geological Survey of India 2017; Ministry of the Environment Japan 2017; Yu et al., 2018)
EQUATION 4.1.3A (NEW)
TIER 1: GLOBAL AVERAGE METHOD – UNDERGROUND MINING – CARBON DIOXIDECO2 emissions =CO2 Emission Factor • Underground Coal Production • Conversion Factor
Where units are:Carbon dioxide Emissions (Gg year-1)
CO2 Emission Factor (m3 tonne-1)
Underground Coal Production (tonne year-1)
Emission Factor:
Low CO2 Emission Factor= 0.05 m3 tonne-1

Average CO2 Emission Factor= 5.9 m3 tonne-1

High CO2 Emission Factor= 12.3 m3 tonne-1

Conversion Factor:
This is the density of CO2 and converts volume of CO2 to mass of CO2. The density is taken at 20˚C and 1
atmosphere pressure and has a value of 1.84 ● 10-6 Gg m-3 (GOST 2015).
Countries should use the Average CO2 Emission Factor unless there is country-specific evidence to support use ofan alternative factor within the low/high range. Countries may consider country-specific circumstances such as
geological location/basis/depth to determine the emission factor to be used. Where CO2 outbursts have beenfrequently observed as a safety concern in mining, then a country should consider the use of the high end CO2
emission factor.
For countries using a Tier 2 approach, basin-specific emission factors may be obtained from analysis of ventilation
air data. When assessing CO2 gas volumes in mine ventilation systems, care needs to be taken to exclude CO2 fromnon-fugitive sources such as;• ambient carbon dioxide present in the air that was drawn into the mine ventilation intake - to take into accountthe atmospheric CO2 constant of the air drawn into the intake of the ventilation system;• fuel combustion CO2 emissions arising from the use of machinery, while the machinery is in the undergroundmine.

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A Tier 3 approach is based on direct measurement of gas composition. For countries using a Tier 3 approach anassessment of CO2 gas volumes in mine ventilation systems needs to be taken to exclude CO2 of above mentioned
non-fugitive sources. Basin-specific emission factors may be obtained from analysis of ventilation air data.
PO S T- M IN I NG E M IS S IO N S
For a Tier 1 approach the post-mining emissions factors are shown below together with the estimation method:
EQUATION 4.1.4
TIER 1: GLOBAL AVERAGE METHOD – POST-MINING EMISSIONS – UNDERGROUND MINES
Methane emissions =CH 4 Emission Factor • Underground Coal Production • Conversion Factor
Where units are:Methane Emissions (Gg year-1)
CH4 Emission Factor (m3 tonne-1)
Underground Coal Production (tonne year-1)
Emission Factor:
Low CH4 Emission Factor= 0.9 m3 tonne-1

Average CH4 Emission Factor= 2.5 m3 tonne-1

High CH4 Emission Factor= 4.0 m3 tonne-1

Conversion Factor:
This is the density of CH4 and converts volume of CH4 to mass of CH4. The density is taken at 20˚C and 1
atmosphere pressure and has a value of 0.67●10-6 Gg m-3.
Tier 2 methods to estimate post-mining emissions take into account the in situ gas content of the coal.
Measurements on coal as it emerges on a conveyor from an underground mine without degasification prior tomining indicate that 25-40 percent of the in situ gas remains in the coal (Williams and Saghafi, 1993). For minesthat practice pre-drainage, the amount of gas in coal will be less than the in situ value by some unknown amount.
For mines with no pre-drainage, but with knowledge of the in situ gas content, the post-mining emission factor
can be set at 30 percent of the in situ gas content. For mines with pre-drainage, an emission factor of 10 percent of
the in situ gas content is suggested.
Tier 3 methods are not regarded as feasible for post-mining operations.
E M IS S IO N S FRO M DR AI N ED M E TH AN E
Methane drained from working (or abandoned) underground (or surface) coal mines can be vented directly to theatmosphere, recovered and utilised, or converted to CO2 through combustion (flaring or catalytic oxidation)
without any utilisation. The manner of accounting for drained methane varies, depending on the final use of themethane.
In general:• Tier 1 represents an aggregate emissions estimate using emission factors. In general, it is not expected thatemissions associated with drained methane would be applicable for Tier 1. Presumably, if methane were being
drained, there would be better data to enable use of Tier 2 or even Tier 3 methods to make emissions estimates.
However, Tier 1 has been included in the discussion below, in case Tier 1 methods are being used to estimate
national emissions where there are methane drainage operations.
• When methane is drained from coal seams as part of coal mining and subsequently flared or used as a fuel, it
is good practice to subtract this amount from the total estimate of methane emissions for Tier 1 and Tier 2(Equation 4.1.2). Data on the amount of methane that is flared or otherwise utilised should be obtained frommine operators with the same frequency of measurement as pertains to underground mine emissions generally.
• For Tiers 1 and 2, if methane is drained and vented to the atmosphere rather than utilized, it should not be recounted as it already forms part of the emissions estimates for these approaches.
• For Tier 3, methane recovered from degasification systems and vented to the atmosphere prior to mining should
be added to the amount of methane released through ventilation systems so that the total estimate is complete.
In some cases, because degasification system data are considered confidential, it may be necessary to estimate
degasification system collection efficiency, and then subtract known reductions to arrive at the net
degasification system emissions.

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Chapter 4: Fugitive Emissions• All methane emissions associated with coal seam degasification related to coal mining activities should be
accounted for in the inventory year in which the emissions and recovery operations occur. Thus, the total
emissions from all ventilation shafts and from all degasification operations that emit methane to the atmosphere
are reported for each year, regardless of when the coal seam is mined through, as long as the emissions areassociated with mining activities.
• When coal bed methane is extracted from coal seams and is delivered into a natural gas system, then the fugitive
emissions associated with the exploration, production, processing, transmission and storage are dealt with inthe oil and natural gas source category (Section 4.2). Tier 1 fugitive emission factors for coal bed methane
production are provided under 1B 2 b iii 2 Production and Gathering in Table 4.2.10.
When recovered methane is utilized as an energy source:• Any emissions resulting from use of recovered coal mine methane as an energy source should be accounted
for based on its final end-use, for example in the Energy Volume, Chapter 2, ‘Stationary Combustion’ whenused for stationary energy production.
• Where recovered methane from coal seams is fed into a natural gas system and used as natural gas, the fugitive
emissions occurring as part of those natural gas systems are dealt with in the oil and natural gas source category(Section 4.2).
When recovered methane is flared:• When the methane is simply combusted with no useful energy, as in flaring or catalytic oxidation to CO2, thecorresponding CO2 production should be added to the total greenhouse gas emissions (expressed as CO2
equivalents) from coal mining activities. Such emissions should be accounted for as shown by Equation 4.1.5,
below. Amounts of nitrous oxide and non-methane volatile organic compounds emitted during flaring will besmall relative to the overall fugitive emissions and need not be estimated.
EQUATION 4.1.5
EMISSIONS OF CO2 AND CH4 FROM DRAINED METHANE FLARED OR CATALYTICALLY OXIDISED(a) Emissions of CO2 from CH 4 combustion =0.98 • Volume of methane flared • Conversion Factor• Stoichiometric Mass Factor(b) Emissions of unburnt methane =0.02 • Volume of methane flared • Conversion Factor
Where units are:Emissions of CO2 from methane combustion (Gg year-1)
Volume of methane flared (m3 year-1)
Stoichiometric Mass Factor is the mass ratio of CO2 produced from full combustion of unit mass of methane
and is equal to 2.75
Note: 0.98 represents the combustion efficiency of natural gas that is flared (Compendium of Greenhouse
Gas Emission Methodologies for the Oil and Gas Industry, American Petroleum Institute, 2004)
Conversion Factor:
This is the density of CH4 and converts volume of CH4 to mass of CH4. The density is taken at 20˚C and 1
atmosphere pressure and has a value of 0.67●10-6 Gg m-3.

4.1.3.3 C HOICE OF ACTIVITY DATA
No refinement.

4.1.3.4 C OMPLETENESS FOR UNDERGROUND COAL MINESNo refinement.

4.1.3.5 D EVELOPING A CO NSISTENT TIME SERIESNo refinement.

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4.1.3.6 U NCERTAINTY ASSESSMENTE M IS S IO N FA C TO R U NC ER T A IN T I ES

Emission Factors for Tiers 1 and 2
The major sources of uncertainty for a Tier 1 approach arise from two sources. These are:
• The applicability of global emission factors to individual countries;• Inherent uncertainties in the emission factors themselves.
The uncertainty due to the first point above is difficult to quantify, but could be significant. The inherent
uncertainty in the emission factor is also difficult to quantify because of natural variability within the same coalregion is known to occur.
For a Tier 2 approach, the same broad comments apply, although basin-specific data will reduce the inherent
uncertainty in the Emission Factor compared with a Tier 1 approach. With regard to the inherent variability in the
Emission Factor, ‘Expert Judgement’ in the Good Practice Guidance (2000) suggested that this was likely to beat least ±50 percent.
Table 4.1.2 shows the Tier 1 and Tier 2 uncertainties associated with emissions from underground coal mining.
The uncertainties for these Tiers are based on expert judgement.
TABLE 4.1.2 (UPDATED)ESTIMATES OF UNCERTAINTY FOR UNDERGROUND MINING FOR TIER 1 AND TIER 2 APPROACHES
Likely uncertainties of coal mine methane Emission factors (Expert judgment - GPG, 20001)
MethodMiningPost-Mining

Tier 2± 50-75%± 50%

Tier 1

Factor of 2 greater or smaller

Factor of 3 greater or smaller

GPG, 2000 IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories(2000)

1

Likely uncertainties of coal mine carbon dioxide emission factors 2
MethodMiningPost-Mining

Tier 2± 50-75%

Not applicable

Tier 1-50% to +100%

Not applicable

Uncertainties set to be consistent with methane emission factors given that measurement practices are likely to be
similar2

Tier 3
Methane emissions from underground mines have a significant natural variability due to variations in the rate ofmining and drainage of gas. For instance, the gas liberated by longwall mining can vary by a factor of up to twoduring the life of a longwall panel. Frequent measurements of underground mine emissions can account for suchvariability and also reduce the intrinsic errors in the measurement techniques. As emissions vary over the courseof a year due to variations in coal production rate and associated drainage, good practice is to collect measurement
data as frequently as practical, preferably biweekly or monthly to smooth out variations. Daily measurements
would ensure a higher quality estimate. Continuous monitoring of emissions represents the highest stage ofemission monitoring, and is implemented in some modern longwall mines.
Spot measurements of methane concentration in ventilation air are probably accurate to ±20 percent depending on
the equipment used. Time series data or repeat measurements will significantly reduce the uncertainty of annual
emissions to ±5 percent for continuous monitoring, and 10-15 percent for monitoring conducted every two weeks.
Ventilation airflows are usually fairly accurately known (±2 percent). When combining the inaccuracies inemissions concentration measurements with the imprecision due to measurement and calculation of instantaneous
measurements, overall emissions for an individual mine may be under-represented by as much as 10 percent orover-represented by as much as 30 percent (Mutmansky and Wang, 2000).
Spot measurement of methane concentration in drained gas (from degasification systems) is likely to be accurate
to ±2 percent because of its higher concentration. Measurements should be made with a frequency comparable tothose for ventilation air to obtain representative sampling. Measured degasification flow rates are probably known

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Chapter 4: Fugitive Emissions

to be ±5 percent. Degasification flow rates that are estimated based on gas sales are also likely to have an
uncertainty of at least ±5 percent due to the tolerances in pipeline gas quality.
For a single longwall operation, with continuous or daily emission measurements, the accuracy of monthly or
annual average emissions data is probably ±5 percent. The accuracy of spot measurements performed every two
weeks is ±10 percent, at 3-monthly intervals: ±30 percent. Aggregating emissions from mines based on the lessfrequent type of measurement procedures will reduce the uncertainty caused by fluctuations in gas production.
However, as fugitive emissions are often dominated by contributions from only a small number of mines, it isdifficult to estimate the extent of this improvement.
The uncertainty estimates for underground mines are shown in Table 4.1.3.
TABLE 4.1.3
ESTIMATES OF UNCERTAINTY FOR UNDERGROUND COAL MINING FOR A TIER 3 APPROACH
SourceDrainage gas

Ventilation gas

Details

Uncertainty

Reference

Spot measurements of CH4 for drainage gas± 2%

Expert judgment (GPG,
2000* )

Degasification flows± 5%

Expert judgment (GPG,
2000)

Continuous or daily measurements± 5%

Expert judgment (GPG,
2000)

Spot measurements every 2 weeks± 10%

Mutmansky and Wang,
2000

Spot measurements every 3 months± 30%

Mutmansky and Wang,
2000

GPG, 2000 - IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (GPG2000)*

AC T IV I TY D A TA UN C ER T A IN T I ES
Coal production: Country-specific tonnages are likely to be known to 1-2 percent, but if raw coal data are notavailable, then the uncertainty will increase to about ±5 percent, when converting from saleable coal production
data. The data are also influenced by moisture content, which is usually present at levels between 5-10 percent,and may not be determined with great accuracy.
Apart from measurement uncertainty, there can be further uncertainties introduced by the nature of the statistical
databases that are not considered here. In countries with a mix of regulated and unregulated mines, activity data
may have an uncertainty of ±10 percent

4.1.4

Surface coal mining

The fundamental equation to be used in estimating emissions from surface mining is as shown in Equation 4.1.6.
EQUATION 4.1.6 (UPDATED)GENERAL EQUATION FOR ESTIMATING FUGITIVE EMISSIONS FROM SURFACE COAL MINING=
CH 4 emissions
Surface mining emissions of CH 4 + Post -mining emission of CH 4=
CO2 emissions

4.1.4.1

Surface mining emissions of CO2 + Post -mining emission of CO2

C HOICE OF METH OD

It is not yet feasible to collect mine-specific Tier 3 measurement data for surface mines. The alternative is to collectdata on surface mine coal production and use emission factors. For countries with significant coal production andmultiple coal basins, disaggregation of data and emission factors to the coal basin level will improve accuracy.
Given the uncertainty of production-based emission factors, choosing emission factors from the range specified
within these guidelines can provide reasonable estimates for a Tier 1 approach.
As with underground mining, direct measurement of post-mining emissions is infeasible so an emission factor
approach is recommended. Tier 2 and Tier 1 methods should be reasonable for this source, given the difficulty ofobtaining better data. A reliable relationship between CH4 and CO2 emissions levels from surface coal mining is

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not able to be established for the purposes of emission estimation. Therefore emission methods based on correlation
between CH4 and CO2 are not provided.
Oxidation of coal in the atmosphere to produce CO2 is known to occur at surface mines, but emissions from thisare not expected to be significant, especially taking into account the effects of rehabilitation of the waste dumps.
Rehabilitation practices, which involve covering the dumps with topsoil and re-vegetation, act to reduce oxygen
fluxes into the dump and hence reduce the rate of CO2 production. While no default method is provided for
estimating Post-mining emissions of CO2, countries may choose to provide their own country-specific emission
estimate.
Uncontrolled combustion in waste piles is a feature for some surface mines. However, these emissions, where theyoccur, are extremely difficult to quantify and it is infeasible to include a methodology.
Figure 4.1.2

Decision tree for surface coal mining
Start

Are country
or coal basin specificemission factors
available?

Yes

Use a Tier 2 method.
Box 2: Tier 2NoIs surface
coal mining a key
category?

No

Use a Tier 1 method.
Box 1: Tier 1

Yes
Collect data to provide
Tier 2 method.
Note: See Volume 1 Chapter 4, “Methodological Choice and Key Categories” (noting Section 4.1.2 on limited resources) for discussion of key
categories and use of decision trees

4.1.4.2

E MISSION FACTORS FOR SURFACE MI NING

Although measurements of methane and carbon dioxide emissions from surface mining are increasingly available,
they are difficult to make and at present no routine widely applicable methods exist. Data on in situ gas contents
before overburden removal are also scarce for many surface mining operations.
The Tier 1 methane emission factors are shown together with the estimation method in Equation 4.1.7.

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Chapter 4: Fugitive Emissions

EQUATION 4.1.7 (UPDATED)TIER 1: GLOBAL AVERAGE METHOD – SURFACE MINES – METHANE
Methane emissions =CH 4 Emission Factor • Surface Coal Production • Conversion Factor
Where units are:Methane Emissions (Gg year-1)
CH4 Emission Factor (m3 tonne-1)
Surface Coal Production (tonne year-1)
Emissions Factor:
Low CH4 Emission Factor= 0.3 m3 tonne-1

Average CH4 Emission Factor= 1.2 m3 tonne-1

High CH4 Emission Factor= 2.0 m3 tonne-1

Conversion Factor:
This is the density of CH4 and converts volume of CH4 to mass of CH4. The density is taken at 20˚C and 1
atmosphere pressure and has a value of 0.67 ● 10-6 Gg m-3.
For the Tier 1 approach, it is good practice to use the low end of the specific emission range for those mines withaverage overburden depths of less than 25 meters and the high end for overburden depths over 50 meters. Forintermediate depths, average values for the emission factors may be used. In the absence of data on overburden
thickness, it is good practice to use the average emission factor, namely 1.2 m3/tonne.
The Tier 1 carbon dioxide emission factors are shown together with the estimation method in Equation 4.1.7.a
The emission factors are based on data reported to the Australian National Greenhouse and Energy Reporting
program for years 2009-2017, measurements of gas in Kazakhstan surface mines and Japan National Inventory
Report 2017. (RGE "Kaz NIIEK" MOOS RK 2010; Commonwealth of Australia 2017; Ministry of theEnvironment Japan 2017; Ministry of Energy of the Republic of Kazakhstan 2017). The average emission factor
is taken from the mean of the latest implied emission factors from each of these countries.
EQUATION 4.1.7A (NEW)
TIER 1: GLOBAL AVERAGE METHOD – SURFACE MINES – CARBON DIOXIDECarbon dioxide emissions =CO2 Emission Factor • Surface Coal Production • Conversion Factor
Where units are:Carbon dioxide Emissions (Gg year-1)
CO2 Emission Factor (m3 tonne-1)
Surface Coal Production (tonne year-1)
Emissions Factor:
Low CO2 Emission Factor= 0.01 m3 tonne-1

Average CO2 Emission Factor= 0.44 m3 tonne-1

High CO2 Emission Factor= 0.94 m3 tonne-1

Conversion Factor:
This is the density of CO2 and converts volume of CO2 to mass of CO2. The density is taken at 20˚C and 1
atmosphere pressure and has a value of 1.84 ● 10-6 Gg m-3 (GOST 2015).
For the Tier 1 approach, it is good practice to use the low end of the specific emission range for those mines withaverage overburden depths of less than 25 meters and the high end for overburden depths over 50 meters.
Otherwise countries should use the average CO2 emission factor of 0.44 m3/tonne unless there is country-specificevidence to support use of an alternative factor within the low/high range.
The Tier 2 method uses the same equation as for Tier 1, but with data disaggregated to country-specific, or coalbasin level. For countries using a Tier 2 approach, carbon dioxide emission factors may be obtained from sampling
and analysis of gas content within carbonaceous strata of surface mines, prior to undertaking mining activities.
The sampling and analysis of in-situ gas within rock strata should be undertaken according to relevant standards

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and procedures. Care needs to be taken to account for any degassing of the sample occurring between obtaining
the sampling and the analysis of gas content.
PO S T- M IN I NG E M IS S IO N S – S URF AC E MI N ING
For a Tier 1 approach the post-mining emissions can be estimated using the emission factors shown in Equation
4.1.8.
EQUATION 4.1.8
TIER 1: GLOBAL AVERAGE METHOD – POST-MINING EMISSIONS – SURFACE MINES
Methane emissions =CH 4 Emission Factor • Surface Coal Production • Conversion Factor
Where units are:Methane Emissions (Gg year-1)
CH4 Emission Factor (m3 tonne-1)
Surface Coal Production (tonne year-1)
Emission Factor:
Low CH4 Emission Factor= 0 m3 tonne-1

Average CH4 Emission Factor= 0.1 m3 tonne-1

High CH4 Emission Factor= 0.2 m3 tonne-1

Conversion Factor:
This is the density of CH4 and converts volume of CH4 to mass of CH4. The density is taken at 20˚C and 1
atmosphere pressure and has a value of 0.67 ● 10-6 Gg m-3.
The average emission factor should be used unless there is country-specific evidence to support use of the low orhigh emission factor.

4.1.4.3 A CTIVITY DATA
No refinement.

4.1.4.4 C OMPLETENESS FOR SURFACE MINI NG
No refinement.

4.1.4.5 D EVELOPING A CO NSISTENT TIME SERIESNo refinement.

4.1.4.6 U NCERTAINTY A SSESSMENT I N EMI SSIONSE M IS S IO N FA C TO R U NC ER T A IN T Y
Uncertainties in the emissions from surface mines are less well quantified than for underground mining. Briefly,
the sources of the uncertainty are the same as described in Section 4.1.3.6 for underground coal mines. However,the variability in the emission factors for large surface mines may be expected to be greater than for undergroundcoal mines, because surface mines can show significant variability across the extent of the mine as a result of local
geological features.
Table 4.1.4 shows the Tier 1 and Tier 2 uncertainties associated with surface mining emissions.

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Chapter 4: Fugitive Emissions

TABLE 4.1.4 (UPDATED)ESTIMATES OF UNCERTAINTY FOR SURFACE MINING FOR TIER 1 AND TIER 2 APPROACHES
Likely Uncertainties of Coal Mine Methane Emission Factors for Surface Mining (Expert Judgement1)

1

MethodSurfacePost-Mining

Tier 2

Factor of 2 greater or lower± 50%

Tier 1

Factor of 3 greater or lower

Factor of 3 greater or lower

GPG, 2000 - IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (2000)

Likely Uncertainties of Coal Mine Carbon Dioxide Emission Factors for Surface Mining 2

2

MethodSurfacePost-Mining

Tier 2-50% to +100%

Not applicable

Tier 1-67% to +200%

Not applicable

Uncertainties set to be consistent with methane emission factors

AC T IV I TY D A TA UN C ER T A IN T Y
The comments made for underground mining in Section 4.1.3.6 also apply to surface mining.

4.1.5

Abandoned underground coal mines

No refinement except Section 4.1.5.2.

4.1.5.1 C HOICE OF METH OD
No refinement.

4.1.5.2 C HOICE OF EMISSI ON FACTORS
Tier 1: Global Average Approach – Abandoned Underground Mines
A Tier 1 approach for determining emissions from abandoned underground mines is described below and is largely
based on methods developed by the US Environment Protection Agency (US EPA) (Franklin et al., 2004). It
incorporates a factor to account for the fraction of those mines that, when they were actively producing coal, wereconsidered gassy. Thus, this methodology is based on the total number of coal mines abandoned, adjusted for thefraction considered gassy, as described below. Abandoned mines that were considered non-gassy when they wereactively mined are presumed to have negligible emissions. In the US methodology, the term gassy mines refers tocoal mines that, when they were active, had average annual ventilation emissions that exceeded the range of 2 800
to 14 000 cubic meters per day (m3/d), or 0.7 to 3.4 Gg per year.
The Tier 1 – approach for abandoned underground coal mines is as follows:
1. Determine the approximate time (year interval) from the following time intervals when gassy coal mines wereabandoned:
a.
b.
c.
d.
e.

1901 – 1925
1926 – 1950
1951 – 1975
1976 – 2000
2001 – present

2. Multiple intervals may be used where appropriate. It is recommended that the number of gassy coal minesabandoned during each time interval be estimated using the smallest time intervals possible based on available
data. Ideally, for more recent periods, time intervals will decrease (e.g., intervals of ten years prior to 1990;
annual intervals since 1990). Information for different coal mine-clusters abandoned during different time
periods should be considered, since multiple time periods may be combined in the Tier 1 approach.
3. Estimate the total number of abandoned mines in each time band since 1901 remaining unflooded. If there is
no knowledge on the extent of flooding it is good practice to assume that 100 percent of mines remain
unflooded. For the purposes of estimating the number of abandoned mines, prospect excavations and hand cart
mines of only a few acres in size should be disregarded.

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4. Determine the percentage of coal mines that would be considered gassy at the time of mine closure. Based on
the time intervals selected above, choose an estimated percentage of gassy coal mines from the high and low
default values listed in Table 4.1.5. Actual estimates can range anywhere from 0 to 100 percent. When choosing
within the high and low default values listed in Table 4.1.5, a country should consider all available historicalinformation that may contribute to the percentage of gassy mines, such as coal rank, gas content, and depth ofmining. Countries with recorded instances of gassy mines (e.g., methane explosions or outbursts) shouldchoose the high default values in the early part of the century. From 1926 to 1975, countries where mines wererelatively deep and hydraulic equipment was used should choose the high default value. Countries with deep
longwall mines or with evidence of gassiness should choose the high values for the time periods after 1975.
The low range of the default values may be appropriate for a given time interval for specific regions, coalbasins, or nations, based on geologic conditions or known mining practices.
5. For the inventory year of interest (between 1990 and the present), select the appropriate emissions factor from
Table 4.1.6. For example, for mines abandoned in the interval 1901 to 1925 and for the inventory reporting
year 2005, the Emission Factor for these mines would have a value of 0.256 million m3 of methane per mine.
6. Calculate for each time band the total methane emissions from Equation 4.1.10 to the inventory year of interest.
7. Sum the emissions for each time interval to derive the total abandoned mine emissions for each inventory year.
TABLE 4.1.5
TIER 1 – ABANDONED UNDERGROUND MINES DEFAULT VALUES - PERCENTAGE OF COAL MINES THAT ARE GASSY

4.28

Time Interval

Low

High

1900-1925

0%

10%

1926-1950

3%

50%

1951-1975

5%75%

1976-2000

8%

100%

2001-Present

9%

100%

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Chapter 4: Fugitive Emissions

TABLE 4.1.6 (UPDATED)TIER 1 – ABANDONED UNDERGROUND MINES - EMISSION FACTOR, MILLION M3 METHANE / MINEInterval of mine closure
Inventory Year

1901 – 1925

1926 – 1950

1951 - 1975

1976 – 2000

2001 – 2025

2026 - 2050

1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050

0.281
0.279
0.277
0.275
0.273
0.272
0.270
0.268
0.267
0.265
0.264
0.262
0.261
0.259
0.258
0.256
0.255
0.253
0.252
0.251
0.249
0.248
0.247
0.246
0.244
0.243
0.242
0.241
0.239
0.238
0.237
0.236
0.235
0.234
0.233
0.232
0.23
0.229
0.228
0.227
0.226
0.225
0.224
0.223
0.223
0.222
0.221
0.220
0.219
0.218
0.217
0.216
0.215
0.214
0.214
0.213
0.212
0.211
0.210
0.210
0.209

0.343
0.340
0.336
0.333
0.330
0.327
0.324
0.322
0.319
0.316
0.314
0.311
0.308
0.306
0.304
0.301
0.299
0.297
0.295
0.293
0.290
0.288
0.286
0.284
0.283
0.281
0.279
0.277
0.275
0.273
0.272
0.270
0.268
0.267
0.265
0.264
0.262
0.261
0.259
0.258
0.256
0.255
0.253
0.252
0.251
0.249
0.248
0.247
0.246
0.244
0.243
0.242
0.241
0.239
0.238
0.237
0.236
0.235
0.234
0.233
0.232

0.478
0.469
0.461
0.453
0.446
0.439
0.432
0.425
0.419
0.413
0.408
0.402
0.397
0.392
0.387
0.382
0.378
0.373
0.369
0.365
0.361
0.357
0.353
0.350
0.346
0.343
0.340
0.336
0.333
0.330
0.327
0.324
0.322
0.319
0.316
0.314
0.311
0.308
0.306
0.304
0.301
0.299
0.297
0.295
0.293
0.290
0.288
0.286
0.284
0.283
0.281
0.279
0.277
0.275
0.273
0.272
0.270
0.268
0.267
0.265
0.264

1.561
1.334
1.183
1.072
0.988
0.921
0.865
0.818
0.778
0.743
0.713
0.686
0.661
0.639
0.620
0.601
0.585
0.569
0.555
0.542
0.529
0.518
0.507
0.496
0.487
0.478
0.469
0.439
0.432
0.425
0.419
0.413
0.408
0.402
0.397
0.392
0.387
0.382
0.378
0.373
0.369
0.365
0.361
0.357
0.353
0.350
0.346
0.343
0.340
0.336
0.333
0.330
0.327
0.324
0.322
0.319
0.316
0.314
0.311
0.308
0.306

NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
5.735
2.397
1.762
1.454
1.265
1.133
1.035
0.959
0.896
0.845
0.801
0.763
0.730
0.701
0.675
0.652
0.625
0.604
0.586
0.569
0.555
0.542
0.529
0.518
0.507
0.496
0.487
0.478
0.469
0.439
0.432
0.425
0.419
0.413
0.408
0.402
0.397
0.392
0.387
0.382
0.378
0.373
0.369
0.365
0.361
0.357
0.353
0.350
0.346
0.343

NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
5.735
2.397
1.762
1.454
1.265
1.133
1.035
0.959
0.896
0.845
0.801
0.763
0.730
0.701
0.675
0.652
0.625
0.604
0.586
0.569
0.555
0.542
0.529
0.518
0.507

As abandoned underground mines are included for the first time an example calculation has been included in Table
4.1.7.

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TABLE 4.1.7 (UPDATED)TIER 1 – ABANDONED UNDERGROUND MINES EXAMPLE CALCULATIONInterval of mine closure
1901 –
1925

1926 –
1950

1951 1975

1976 –
2000

2001 –
Present

Number of mines closed per time
band

20

15

10

5

1

Fraction of gassy mines

0.1

0.5

0.75

1.0

1.0

Emission factor for Inventory year,
2005 (from Table 4.1.6)

0.256

0.301

0.382

0.601

1.265

Total emissions (Gg CH4 per year
from Equation 4.1.10)

0.34

1.51

1.92

2.07

0.85

Total forinventory
year 2005

6.64

Tier 2 – Country- or Basin-Specific Approach
The Tier 2 approach for developing an abandoned mine methane emission inventory follows a similar approach toTier 1, but it incorporates country- or basin-specific data. The methodology presented below is intended to utilize
coal basin-specific or country-specific data wherever possible (for example, for active mine emissions prior toabandonment, for basin-specific parameters for emissions factors, etc.).
In some cases, default parameters have been provided for these values but these should be used only if countryspecific or basin-specific data are not available.
Calculate emissions for a given inventory year using Equation 4.1.11:
EQUATION 4.1.11
TIER 2: APPROACH FOR ABANDONED UNDERGROUND MINES WITHOUT METHANE RECOVERYAND UTILIZATION

Methane Emissions

Number of Coal Mines Abandoned Remaining Unflooded • Fraction of

Gassy Mines • Average Emissions Rate • Emission Factor • Conversion Factor

Where units are:Emissions of methane (Gg year-1)
Emission Rate (m3 year-1 )Emission Factor (dimensionless, see Equation 4.1.11)
Conversion Factor:
This is the density of CH4 and converts volume of CH4 to mass of CH4. The density is taken at 20˚C and 1
atmosphere pressure and has a value of 0.67●10-6 Gg m-3
If individual mines are known to be completely flooded, they may be assigned an emissions value of zero. Methane
emissions reductions due to recovery projects that utilize or flare methane at abandoned mines should be subtracted
from the emissions estimate. For either of these cases, it is recommended that a hybrid Tier 2 – Tier 3 approach beused to incorporate such mine-specific information (see the discussion of methane recovery and utilization projects
from abandoned mines, Sections 4.1.5.1 and 4.1.5.3).
The basic steps in the Tier 2 approach for abandoned underground coal mines are as follows:• Determine the approximate time interval(s) when significant numbers of gassy coal mines were closed.
Multiple intervals may be used where appropriate. It is recommended that the number of gassy coal minesabandoned during each time interval be estimated using the smallest time intervals possible based on available
data. Ideally, for more recent periods, time intervals will decrease (e.g., intervals of ten years prior to 1990;
annual intervals since 1990).
• Estimate the total number of abandoned mines in each time interval selected remaining unflooded. If there is
no available information on the flooded status of the abandoned mines, assume 100 percent remain unflooded.
• Determine the number (or percentage) of coal mines that would be considered gassy at the time of mine closure.

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Chapter 4: Fugitive Emissions• For each time interval, determine the average emissions rate. If country or basin-specific data do not exist, low
and high estimates for active mine emissions prior to abandonment can be selected from Table 4.1.8.
• For each time interval, calculate an appropriate emissions factor using Equation 4.1.12, based on the differencein years between the estimated data of abandonment and the year of the emissions inventory. Note that default
values for this emissions factor equation are provided in Table 4.1.9, but these default values should be used
only where country- or basin-specific information are not available.
• Calculate the emissions for each time interval using Equation 4.1.11.
• Sum the emissions for each time interval to derive the total abandoned mine emissions for each inventory year.
TABLE 4.1.8
TIER 2 – ABANDONED UNDERGROUND COAL MINES -DEFAULT VALUES FOR ACTIVE MINE EMISSIONS PRIOR TO ABANDONMENT
Parameter

Emissions, million m3/yr

Low

1.3

High

38.8

EQUATION 4.1.12
TIER 2: ABANDONED UNDERGROUND COAL MINES EMISSION FACTORb
Emission Factor= (1 + aT )Where:a and b are constants determining the decline curve. Country or basin-specific values should be used
wherever possible. Default values are provided in Table 4.1.9, below.
T = years elapsed since abandonment (difference of the mid point of the time interval selected and theinventory year) .
A separate emission factor must be calculated for each time interval selected. This emission factor isdimensionless.
TABLE 4.1.9
COEFFICIENTS FOR TIER 2 – ABANDONED UNDERGROUND COAL MINES
Coal RankabAnthracite

1.72

-0.58

Bituminous

3.72

-0.42

Sub-bituminous

0.27

-1.00

Tier 3-Mine-Specific Approach
Tier 3 provides a great deal of flexibility. Directly measured emissions, where available, can be used in place of
estimates and calculations. Models may be used in conjunction with measured data to estimate time series
emissions. Each country may generate their own decline curves or other characterizations based on measurements,
known basin-specific coal properties, and/or hydrological models. Equation 4.1.13 describes one possible,
approach.
EQUATION 4.1.13
EXAMPLE OF TIER 3 EMISSIONS CALCULATION – ABANDONED UNDERGROUND MINES
Methane Emissions= ( Emission rate at closure • Emission Factor • Conversion Factor )– Methane Emissions Reductions from Recovery and Utilisation
Where units are:Methane Emissions (Gg year-1)
Emission Rate at Closure (m3 year-1)

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Emission Factor (dimensionless, see Franklin et al., 2004)
Conversion Factor:
This is the density of CH4 and converts volume of CH4 to mass of CH4. The density is taken at 20˚C and 1
atmosphere pressure and has a value of 0.67 ● 10-6 Gg m-3.
The basic steps in the Tier 3 methodology involve the following:• Determine a database of mine closures with relevant geological and hydrological information and theapproximate abandonment dates (when all active mine ventilation ceased) consistently for all mines in the
country’s inventory.
• Estimate emissions based on measured emissions and/or an emissions model. This may be based on the average
emission rate at time of mine closure, determined by the last measured emission rate (or preferably, an averageof several measurements taken the year prior to abandonment), or estimated methane reserves susceptible torelease.
• If actual measurements have not been taken at a given mine, emissions may be calculated using an appropriate
decline curve or modelling approach for openly vented mines, sealed mines, or flooded mines. Use the selected
decline equation or modelling approach for the mine and the number of years between abandonment and theinventory year to calculate emissions or an appropriate emission factor for each mine.
• Sum abandoned mine emissions to develop an annual inventory.

4.1.5.3 C HOICE OF ACTIVITY DATA
No refinement.

4.1.5.4 C OMPLETENESS
No refinement.

4.1.5.5 D EVELOPING A CO NSISTENT TIME SERIESNo refinement.

4.1.5.6 U NCERTAINTY ASSESSMENT
No refinement.

4.1.6

Completeness for coal mining

Several sources have been identified with potential emissions, but are not included with a methodology in theseguidelines. These are abandoned surface mines and uncontrolled combustion and burning coal deposits.
AB AN DO N ED SU RF A CE MI N ES
After closure, emissions from abandoned surface mines may include the following:• The standing highwall• Leakage from the pit floor• Low temperature oxidation• Uncontrolled combustion
At present, no comprehensive methods to quantify these emissions have been developed and therefore they havenot been included in these guidelines. They remain subjects for further research.
E M IS S IO N S FRO M UN CO N T RO L L ED CO M B US T IO N A ND B UR N IN G CO AL
DE PO SI T S
While emissions from this source may be significant for an individual coal mine, it is unclear as to how significant
these emissions may be for an individual country. In some countries where such fires are widespread, the emissions

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Chapter 4: Fugitive Emissions

may be very significant. There are no clear methods available at present to systematically measure or precisely
estimate the activity data, though where countries have data on amounts of coal burned, the CO2 should be
estimated on the basis of the carbon content of the coal and reported in the relevant subcategory of 1.B.1.b. It isnoted that uncontrolled combustion only due to coal exploration activities is considered here. Care should be taken
to avoid double counting with fugitive CH4 and low oxidation CO2 emissions.

4.1.7

Inventory Quality Assurance/Quality Control(QA/QC)No refinement.

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4.2

FUGITIVE EMISSIONS FROM OIL AND
NATURAL GAS SYSTEMSThis section is an update of Section 4.2 in Vol.2 of the 2006 IPCC Guidelines. Fugitive emissions from oil andnatural gas systems are accounted for in IPCC subcategory 1.B.2 of the energy sector. For reporting purposes, thiscategory is subdivided as shown in Figure 4.2.0. The main distinction is made between oil and natural gas systems,with each being subdivided into the different parts (or segments) of the oil or gas system according to the type ofactivity 2. Fuel gases other than natural gas, such as town gas 3 and biogas, are often handled in natural gas systems(such as transmission and distribution systems), and are discussed here as well. Where coalbed methane isdelivered into a natural gas system, any associated fugitive emissions should be reported under the appropriate
natural gas exploration and production categories.
1F

2F

The term fugitive emissions is broadly applied here to mean all greenhouse gas emissions from oil and gassystems
except contributions from fuel combustion. Fugitive emissions include vented emissions, leak emissions, andflaring emissions. Oil and natural gas systems comprise all infrastructure required to produce, collect, process orrefine and deliver natural gas and petroleum products to market, and includes abandoned oil and gas wells. The
system begins during the exploration process, which includes all fugitive emissions associated with activities suchas prospecting and/or exploratory drilling, well testing, field development and well development (construction tocompletion, fracture stimulation), and ends at the consumer (including fugitive emissions between gas meters andappliances, but not from appliance start-stop losses or appliance combustion). Emissions excluded from thiscategory are as follows:• Fuel combustion for the production of useful heat or energy by stationary or mobile sources (see Chapters 2
and 3 of the Energy Volume).
• Fugitive emissions from carbon capture and storage projects, the transport and disposal of acid gas from oil
and gas facilities by injection into secure underground formations, or the transport, injection and sequesteringof CO2 as part of enhanced oil recovery (EOR), enhanced gas recovery (EGR) or enhanced coal bed methane(ECBM) projects (see Chapter 5 of the Energy Volume on carbon dioxide capture and storage systems). Notethat fugitive emissions from the oil and gas production portions of EOR, EGR and ECBM projects are part ofCategory 1.B.2.
• Fugitive emissions that occur at industrial facilities other than oil and gas facilities (see the Industrial Processes
and Product Use Volume).
• Fugitive emissions from waste disposal activities that occur outside the oil and gas industry (see the Waste
Volume).
• Where a coal formation is degassed for coal exploration or coal mining and handling, the associated emissions
should be allocated to the coal sector under the appropriate section of IPCC category 1.B.1.
When determining fugitive emissions from oil and natural gas systems, it may be necessary to apply greater
disaggregation than is shown in Figure 4.2.0 to better account for local factors affecting the amount of emissions(i.e., reservoir conditions, processing/treatment requirements, design and operating practices, age of the industry,market access, regulatory requirements and the level of regulatory enforcement), and to account for changes in
activity levels in progressing through the different parts of the system. The percentage contribution by eachcategory in Figure 4.2.0 to total fugitive emissions by the oil and gas sector will vary according to the amount ofoil and gas produced, consumed, imported and exported, and according to technologies and practices in place indifferent segments that may increase or decrease emissions. Some examples of the potential distribution of fugitive
emissions by subcategory are provided in American Petroleum Institute (API) 2009.

2 Definitions for oil wells versus gas wells can vary from country to country and organization to organization.

making this distinction when applying tier 1 factors is available in Section 4.2.2.3 below.

Guidance for

3 Town gas (also called coal gas) is a manufactured gaseous fuel produced for sale to commercial and residential consumers.

The guidelines assume that town gas contains hydrogen (around 50%), carbon monoxide (around 10%), methane (around35%) and volatile hydrocarbons (around 5%) together with carbon dioxide and nitrogen (each less than 1%). It was used inEurope until the end of the last millennium and is still used in China (Zheng et al. 2010).

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4.2.1

Overview and description of sources

The sources of fugitive emissions on oil and gas systems include, but are not limited to, equipment leaks,
evaporation and flashing losses, venting, flaring and accidental releases (e.g., pipeline dig-ins, well blow-outs andspills). Venting and flaring emission sources are engineered or intentional (e.g., vents from tanks, seal and process
vents and flare systems), while leak emissions (e.g. working losses from tanks, and leaks from other equipment)
are unintentional (or uncontrolled). Some emissions are relatively well-characterized, with use of measurement
systems in certain cases, where losses or flows are tracked as part of routine production accounting procedures, orwhere engineering estimates are made. Uncertainties associated with such estimates include those due to an
inability to cover the wide range of flows and variations in composition that may occur, and inconsistencies in theactivities that are included. A lack of data on activities and practices in place in a country can also contribute touncertainty. Throughout this chapter, an effort is made to state the precise type of fugitive emission source being
discussed, and to only use the term fugitive emissions or fugitive emission sources when discussing theseemissions or sources at a higher, more aggregated, level.
Streams containing pure or high concentrations of CO2 may occur at oil production facilities where CO2 is being
injected into an oil reservoir for EOR, ECBM or EGR. They may also occur at gas processing, oil refining andheavy oil upgrading facilities as a by-product of gas treating to meet sales or fuel gas specifications, and at
refineries and heavy oil upgraders as a by-product of hydrogen production. Where CO2 occurs as a process byproduct it is usually vented to the atmosphere, injected into a suitable underground formation for disposal or
supplied for use in EOR projects. Fugitive CO2 emissions from these streams should be accounted for under theappropriate subcategories of 1.B.2. Fugitive CO2 emissions from CO2 capture should be accounted for in theindustry where capture occurs, while the fugitive CO2 emissions from transport, injection and storage activities
shall be accounted for separately in category 1.C (refer to Chapter 5).
EOR is the recovery of oil from a reservoir by means other than using the natural reservoir pressure. It can begin
after a secondary recovery process or at any time during the productive life of an oil reservoir. EOR generally
results in increased amounts of oil being removed from a reservoir in comparison to methods using natural pressure
or pumping alone. The three major types of enhanced oil recovery operations are chemical flooding (alkaline
flooding or micellar-polymer flooding), miscible displacement (CO2 injection or hydrocarbon injection), andthermal recovery (steamflood or in-situ combustion).
Emissions from oil and gas exploration are disaggregated to reflect that unconventional completions (e.g.,
conducted with hydraulic fracturing 4 ) have a different emissions profile than conventional completions (e.g.,
conducted without hydraulic fracturing). Conventional reservoirs are those in which hydrocarbons are sealed
below a capstone (or caprock) and from which hydrocarbons readily flow due to natural buoyant forces.
Unconventional reservoirs, such shale and tight gas, are those for which their characteristics (e.g. porosity,
permeability) differ from conventional reservoirs. In the case of unconventional resources, additional techniques,
such as hydraulic fracturing, are required to stimulate the release and flow of oil and gas from low-permeability
unconventional formations such as shale. Tier 1 emission factors and methods for calculating emissions from oil
and gas exploration are differentiated by whether or not hydraulic fracturing is conducted, regardless of formation
type. Different hydraulic fracturing practices can greatly impact emissions levels. For example, hydraulicfracturing completions with flaring or reduced emissions completions (REC) technologies will have lower
emissions than completions without those practices. In this chapter, unconventional exploration refers to
exploration that includes well completions with hydraulic fracturing and conventional exploration refers to
exploration that does not include well completions with hydraulic fracturing.
3F

4 There are potential other types of unconventional exploration (e.g. hydrates) but currently hydraulic fracturing is the mostcommon type of unconventional exploration. Emission factors for unconventional exploration were developed from datafrom hydraulic fracturing.

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Figure 4.2.0 (New) Key segments included in oil and natural gas systems
For a detailed description of each segment, please see Section 4.2.2.3, Choice of Emission Factors, below.
Note: this diagram provides examples of activities included in the segments of oil systems; it is not intended as a flow chart or supply chain diagram.

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Chapter 4: Fugitive Emissions

Figure 4.2.0 (New) (Continued) Key segments included in oil and natural gas systems
For a detailed description of each segment, please see Section 4.2.2.3, Choice of Emission Factors, below.
Note: this diagram provides examples of activities included in the segments of natural gas systems; it is not intended as a flow chart or supply chain diagram.

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4.2.2

Methodological issues

Fugitive emissions are a direct source of greenhouse gases due to the release of CH4 and formation CO2 (i.e., CO2
present in the produced oil and gas when it leaves the reservoir), plus some CO2 and nitrous oxide (N2O) from
non-productive combustion activities (primarily waste gas flaring). In this chapter, fugitive emissions include
emissions from venting, flaring, and leaks.
Venting comprises all engineered or intentional discharges of waste gas streams and process by-products to theatmosphere, including emergency discharges. These releases may occur on either a continuous or intermittent
basis, and may include the following:• Use of pressurized natural gas instead of compressed air as the supply medium for pneumatic devices (e.g.,chemical injection pumps, starter motors on compressor engines and instrument control loops);• Pressure relief and disposal of off-specification product during process upsets;• Purging and blowdown events related to maintenance and tie-in activities;• Disposal of off-gas streams from oil and gas treatment units (e.g., still-column off-gas from glycol dehydrators,
emulsion treater overheads and stabilizer overheads);• Gas releases from drilling, well-testing and pipeline pigging activities;• Disposal of waste associated gas at oil production facilities and casing-head gas at heavy oil wells where there
is no gas conservation, re-injection, or flaring;• Solution gas emissions from storage tanks, evaporation losses from process sewers, API separators, dissolved
air flotation units, tailings ponds and storage tanks, and biogenic gas formation from tailings ponds;• Discharge of CO2 extracted from the produced natural gas or produced as a process by product.
Some or all of the vented gas may be captured for storage or utilization. In this instance, the inventory of vented
emissions should include only the net emissions to the atmosphere.
Flaring means broadly all burning of waste natural gas and hydrocarbon liquids by flares or incinerators as adisposal option rather than for the production of useful heat or energy. The decision on whether to vent or flaredepends largely on the amount and energy content of gas to be disposed of and the specific circumstances (e.g.,
public, environmental and safety issues as well as local regulatory requirements). Normally, waste gas is only
vented if it is non-odorous and non-toxic, and even then may often be flared. Flaring is most common at production,
processing, upgrading and refining facilities but may occur in other segments as well. Waste gas volumes areusually vented on gas transmission systems and may be vented on gas distribution systems, depending on thecircumstances and the company’s policies. Sometimes fuel gas may be used to enrich a waste gas stream so it will
support stable combustion during flaring. Fuel gas may also be used for other purposes where it may ultimately bevented or flared, such as purge or blanket gas and supply gas for gas-operated devices (e.g., for instrument
controllers). The emissions from these types of fuel uses should be reported under the appropriate venting andflaring subcategories rather than under Category 1.A (Fuel Combustion Activities).
Formation CO2 removed from natural gas by the sweetening units at gas processing plants (i.e., for acid gas
removal) and released to the atmosphere is a fugitive emission and should be reported under subcategory 1.B.2.b.iii
The CO2 resulting from the production of hydrogen at refineries and heavy oil/bitumen upgraders should bereported under subcategory 1.B.2.a.iv. Care should be taken to ensure that the feedstock for the hydrogen plant is
not also reported as fuel in these cases.
Leak emissions occur in all segments of the oil and natural gas systems and consist of unintentional (i.e., not vented
or flared) emissions from equipment components such as valves, connectors, open ended lines, and flanges.
Fugitive emissions from oil and natural gas systems are often difficult to quantify accurately. This is largely due
to the diversity of the industry, the large number and variety of potential emission sources, the wide variations inemission-control levels and the limited availability of emission-source data. The main emission assessment issues
are:• The use of simple production-based emission factors introduces large uncertainty;• The application of rigorous bottom-up approaches requires expert knowledge and detailed data that may bedifficult and costly to obtain;• Measurement programmes are time consuming and very costly to perform;• Certain emissions, such as those from tanks, can be difficult to access or dangerous for direct measurement.

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Chapter 4: Fugitive Emissions

It is good practice to involve technical representatives from the industry and others with expert knowledge in thedevelopment of the inventory for the use of technology- or practice-specific Tier 1 emission factors and/or for
input on Tier 2 or 3 approaches.

4.2.2.1 C HOICE OF METH OD , DECI SION TREES , TI ERSThere are three methodological tiers for determining fugitive emissions from oil and natural gas systems, as set
out in Section 4.2.2.2. It is good practice to disaggregate the activities into the segments in Oil Systems, andseparately, in Natural Gas Systems (see Figure 4.2.0 in Section 4.2.1, and Table 4.2.2 below), and then evaluate
the emissions separately for each of these. The methodological tier applied to each segment should becommensurate with the amount of emissions and the available resources. Consequently, it may be appropriate toapply different methodological tiers to different segments and sub-segments, and possibly even include actual
emission measurement or monitoring results for some larger sources. The overall approach, over time, should be
one of progressive refinement to address the areas of greatest uncertainty and consequence, and to capture theimpact of control measures.
Figure 4.2.1 provides a general decision tree for selecting an appropriate approach for a given segment of thenatural gas industry. The decision tree is intended to be applied successively to each segment within the natural
gas system (e.g., gas exploration, gas production, then gas processing, then gas transmission, then gas storage,
then gas distribution, abandoned wells, post-meter emissions, and other), and then separately, to each segment
within the oil system (e.g., oil production, transport systems, refineries, abandoned wells, and other).
The basic decision process is as follows:• check if the detailed data needed to apply a Tier 3 approach are readily available, and if so, then apply a Tier
3 approach (i.e., regardless of whether the category is key and the segment is significant), otherwise, if thesedata are not readily available;• check if the detailed data needed to apply a Tier 2 approach are readily available, and if so, then apply a Tier
2 approach, otherwise, if these data are not readily available;• check to see if the category is key and the specific segment being considered is significant based on the IPCC
definitions of key and significant, and if so, go back and gather the data needed to apply a Tier 3 or Tier 2
approach, otherwise, if the segment is not significant;• apply a Tier 1 approach.
The ability to use a Tier 3 approach will depend on the availability of detailed production statistics andinfrastructure data (e.g., information regarding the numbers and types of facilities and the amount and type ofequipment used at each site), and it may not be possible or appropriate to apply it under all circumstances. As
noted above, oil and gas systems can show significant variability across regions and over time. Compilers shouldmake efforts to ensure that emission factors are nationally and temporally appropriate. A Tier 1 approach is thesimplest method to apply but is susceptible to substantial uncertainties and may easily be in error by an order-ofmagnitude or more. For this reason, it should only be used as a last resort option. Where a Tier 3 approach is usedin one year and the results are used to develop Tier 2 emission factors for use in other years, the applied
methodology should be reported as Tier 2 in those other years.
Where a country has estimated fugitive emissions from oil and gas systems based on a compilation of estimatesreported by individual oil and gas companies, this may either be a Tier 2 or Tier 3 approach, depending on theactual approaches applied by individual companies and facilities. In both cases, care needs to be taken to ensure
there is no omitting or double counting of emissions.
It is likely that most countries will estimate emissions from oil and natural gas systems using a combination oftiers across and even within segments and subsegments. Tier 1 EFs disaggregated by segment are provided in
Section 4.2.2.3. The Tier 1 factors presented in this section are aggregates of venting, flaring, and leak emissions.
To develop separate estimates for venting, flaring, and leak emissions, default fractions of emissions for venting,flaring, and leaks for relevant emission factors are provided in Annex 4A.2.

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TABLE 4.2.2 (UPDATED)MAJOR CATEGORIES AND SUBCATEGORIES IN THE OIL AND GAS INDUSTRY
Industry Segment

Activities/Emission Sourcesa

Oil Exploration
1B.2.a.i

Includes fugitive emissions associated with field activities prior to
production: prospecting and or exploratory drilling, field development
and well development (construction/drilling, testing, completion, any
fracture stimulation).

Oil Production andUpgrading
1.B.2.a.ii

Onshore Production
Offshore Production
Crude Bitumen or Heavy Oil Upgrading to Synthetic Crude Oil (FromOil Sands or Oil Shales)

Oil Transport
1.B.2.a.iii

MarinePipelines
Tanker Trucks and Rail Cars

Oil Refining
1.B.2.a.iv

Heavy OilDistribution of Oil
Products
1.B.2.a.v

Gasoline

Conventional and Synthetic Crude Oil

DieselAviation Fuel
Jet Kerosene
Gas Oil (Intermediate Refined Products)

Other
1.B.2.a.vi

Anomalous leak events can occur across segments of Oil Systems

Abandoned Oil Wells
1.B.2.a.vii

Unplugged and plugged abandoned wells

Gas Exploration
1.B.2.b.i

Includes fugitive emissions associated with field activities prior to
production: prospecting and or exploratory drilling, field development
and both conventional and unconventional well development(construction/drilling, testing, completion, any fracture stimulation).

Gas Production andGathering
1.B.2.b.ii

Onshore gas production
Offshore gas production
Gathering and boosting stations (with multiple emission sources on site,
such as compressors, pneumatic controllers and tanks) and gathering
pipelines

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Chapter 4: Fugitive Emissions

TABLE 4.2.2 (UPDATED) (CONTINUED)MAJOR CATEGORIES AND SUBCATEGORIES IN THE OIL AND GAS INDUSTRY
Industry Segment

Gas Processing
1.B.2.b.iii

Gas Transmission andStorage
1.B.2.b.iv

Activities/Emission Sourcesa

Gas Processing Plants without Acid Gas Removal
Sour Gas or Acid Gas Removal Plants
Transmission pipeline Systems, compressor stations
Storage Facilities
Liquefied Natural Gas System import stations, export stations, storage
stations, and transport

Gas Distribution
1.B.2.b.v

Pipelines, metering and regulating stations

Gas Post-Meter
1.B.2.b.vi

Consumer appliances, power plants, and natural gas-fueled vehicles

Other
1.B.2.b.vii

Anomalous leak events can occur across natural gas systems. Examples
of such events include leakage of storage wells (such as the 2015-2016
Aliso Canyon leak eventb), emergency pressure releases, andunintentional gas spills (e.g. after prospecting).

Abandoned Gas Wells
1.B.2.b.viii

Unplugged and plugged abandoned wellsa

See Annex 4A.3 Definition of terminologies used in Section 4.2.

b

For more information on the Aliso Canyon leak event, please see (California Air Resources Board 2016)2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

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Figure 4.2.1 (Updated) Decision tree for oil and natural gas systems
Start

Is there activities of thesegment in the country?

No

Report “Not Occurring”

Yes

Report measurement results
or estimate emissions using
rigorous emission source
models (Tier 3).

Yes

Are actual
measurements or sufficient
data available to estimate emissions
using rigorous emission
source models?

Box 3

No

Are
national Tier 2 emissions
factors available?

Yes

Estimate emissions using a
Tier 2 approach.
Box 2

No

If emissions
from the category area key category, are contributions
from the segment
significant?

No

Estimate emissions using a
Tier 1 approach.
Box 1

Yes
Collect detailed activity andinfrastructure data to apply
either a Tier 2 or Tier 3 approach,depending on the effort required.
* For oil production segment: is it possible to perform alternative mass balance approach

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Chapter 4: Fugitive Emissions

4.2.2.2

C HOICE OF METH OD

The three methodological tiers for estimating fugitive emissions from oil and natural gas systems are described
below.

TIER 1
Tier 1 comprises the application of appropriate default emission factors to a representative activity parameter(usually throughput) for each applicable segment or subsegment of a country’s oil and natural gas industry andshould only be used as specified in the decision trees. The application of a Tier1 approach is illustrated with
Equations 4.2.1 and 4.2.2 presented below. More detailed equations and guidance can be found in Section 4.2.2.3.
EQUATION 4.2.1
TIER 1: ESTIMATING FUGITIVE EMISSIONS FROM AN INDUSTRY SEGMENT

Egas ,=
Aindustry segment • EFgas , industry segment
industry segment

EQUATION 4.2.2
TIER 1: TOTAL FUGITIVE EMISSIONS FROM INDUSTRY SEGMENTS

Egas =∑

industry segments

Egas , industry segment

Where:
Egas,industry segement= Annual emissions of CO2, CH4, or N2O (tonnes)

EFgas,industry segement= emission factor for CO2, CH4, or N2O (tonnes/unit of activity)

A industry segement= activity value (units of activity)

The industry segments to be considered are listed in Table 4.2.2. Not all segments will necessarily apply to all
countries. For example, a country that only imports natural gas and does not produce any will probably only havegas transmission and distribution emissions. The available Tier 1 default emission factors are presented in Table
4.2.4 through 4.2.4k in Section 4.2.2.3. Several options for activity data are available for many of the factors. For
each segment, at least one factor option has been related to throughput, because production, imports and exports,
and consumption are the only national oil and gas statistics that are consistently available. Throughput emission
factors are applicable to throughput at standard conditions of 15°C and 101.325 kPa. For more information on
standard temperature and pressure conditions, and conversions from different conditions, see Annex 4A.1.
In addition, for many segments, technology- or practice-specific emission factors are available. Information on theappropriate use of each factor is included in Section 4.2.2.3 for each technology-specific factor.
Compilers are to assess which Tier 1 factors are most appropriate and should consider other sources or a moredisaggregated EF (by emission type; see Annex 4A.2) if the emission factors presented here are expected to varysignificantly from national circumstances.
Fugitive greenhouse gas emissions from oil and gas related CO2 capture and injection activities (e.g., acid gas
injection and EOR projects involving CO2 floods) will normally be small compared to the amount of CO2 being
injected (e.g., less than 1 percent of the injection volumes). At the Tier 1 or 2 methodology levels they are
indistinguishable from fugitive greenhouse gas emissions by the associated oil and gas activities. The emission
contributions from CO2 capture and injection were included in the original data from which the presented Tier 1
factors were developed (i.e., through the inclusion of acid gas injection and EOR activities, along withconventional oil and gas activities, with consideration of CO2 concentrations in the leaked, vented and flared
natural gases, vapours and acid gases). Losses from CO2 capture should be accounted for in the industry where
capture occurs, while losses from, transport, injection and storage activities are assessed separately in Chapter 5.
T I ER 2
Tier 2 consists of using Tier 1 equations (4.2.1 and 4.2.2) with country-specific, instead of default, emission
factors. It should be applied to significant segments in key categories where the use of a Tier 3 approach is notpracticable. The country-specific values may be developed from studies and measurement programmes, or bederived by initially applying a Tier 3 approach and then back-calculating Tier 2 emission factors using Equations
4.2.1 and 4.2.2. For example, some countries have been applying Tier 3 approaches for particular years and havethen used these results to develop Tier 2 factors for use in subsequent years until the next Tier 3 assessment is2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

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performed. In general, all emission factors (including Tier 1 and Tier 2 values) should be periodically re-affirmed
or updated. The frequency at which such updates are performed shall be commensurate with the rates at which
new technologies, practices, standards and other relevant factors (e.g., changes in the types of oil and gas activities,
aging of the fields and facilities, etc.) are penetrating the industry. New data shall be assessed to determine whether
the data are representing different practices, equipment, or conditions, or if it is an additional data point to be
included in the emission factor applied across all time series years. A survey of operations for information on
practices over time could be used to make such an assessment. If new emission factors developed in this manner
account for real changes within the industry, they should not be applied backwards through the time series.
An alternative Tier 2 approach that may be applied to estimate the amount of venting and flaring emissions fromthe production segment of oil systems consists of performing a mass balance using country-specific production
volumes, gas-to-oil ratios (GORs), gas compositions and information regarding the level of gas conservation. Thisapproach may be applied using Equations 4.2.3 to 4.2.8 below and is appropriate where reliable venting and flaring
values are unavailable but representative GOR data can be obtained and venting and flaring emissions are expected
to be the dominant sources of fugitive emissions (i.e., most of the associated gas production is not being
captured/conserved or utilized). Under these circumstances, the alternative Tier 2 approach may also be used toestimate fugitive greenhouse gas emissions from EOR activities provided representative associated gas and vapour
analyses are available and contributions due to fugitive emissions from the CO2 transport and injection systems
are small in comparison (as would normally be expected). Where the alternative Tier 2 approach is applied, any
reported venting or flaring data that may be available for the target sources should not also be accounted for as thiswould result in double counting. However, it is good practice to compare the estimated gas vented and flared
volumes determined using the GOR data to the available reported vented and flared data to identify and resolve
any potential anomalies (i.e., the calculated volumes should be comparable to the available reported data, or greater
if these latter data are believed to be incomplete). In the case that Tier 2 vented and flared data are applied forcertain segments, leak emissions should be calculated separately using other data, for example, disaggregated Tier
1 emissions factors (see Annex 4A.2)
Table 4.2.3 shows examples of typical GOR values for oil wells from selected locations. Actual GOR values mayvary from 0 to very high values depending on the local geology, state of the producing reservoir and the rate ofproduction. Notwithstanding this, average GOR values for large numbers of oil wells tend to be more predictable.
A review of limited data for a number of countries and regions indicates that average GOR values for conventional
oil production would usually be in the range of about 100 to 350 m3/m3, depending on the location. When countryspecific GORs are used, care should be taken to ensure that GOR measurements are performed with enoughfrequency to ensure representative results.
TABLE 4.2.3
TYPICAL RANGES OF GAS-TO-OIL RATIOS FOR DIFFERENT TYPES OF PRODUCTION
Type of Crude Oil
Production

Location

Conventional Oil

Alaska (Prudhoe Bay)

142 to 6,2342, 3

NACanada0 to 2,000+ 1, 2

Not Available (NA)

Qatar (Onshore, 1 Oil Field)

167 to 1844

173

Qatar (Offshore, 3 Oil Fields)

316 to 3864

333

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Range6

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Chapter 4: Fugitive Emissions

TABLE 4.2.3 (CONTINUED)TYPICAL RANGES OF GAS-TO-OIL RATIOS FOR DIFFERENT TYPES OF PRODUCTION
Primary Heavy Oil

Canada0 to 325+ 1, 5

NA

Thermal Heavy Oil

Canada0 to 901

NA

Crude Bitumen

Canada0 to 201NA

1

Source: Based on unpublished data for a selection of wells in Canada.

2

Appreciably higher GOR values may occur, but these wells are normally either classified as gas wells or there is asignificant gas cap present and the gas would normally be reinjected until all the recoverable oil had been produced.

3

Source: Mohaghegh, S.D., L.A. Hutchins and C.D. Sisk. 2002. Prudhoe Bay Oil Production Optimization: Using Virtual
intelligence Techniques, Stage One: Neural Model Building. Presented at the SPE Annual Technical Conference andExhibition held in San Antonio, Texas, 29 September–2 October 2002.

4

Source: Corporate HSE, Qatar Petroleum, Qatar-Doha 2004.

5

Values as high as 7,160 m3/m3 have been observed for some wells where there is a significant gas cap present. Gas
reinjection is not done in these applications. The gas is conserved, vented or flared.

6

Referenced at standard conditions of 15°C and 101.325 kPa.

To apply a mass balance method in the alternative Tier 2 approach, it is necessary to consider the fate of all of the
produced gas and vapour. This is done, in part, through the application of a conservation efficiency (CE) factor
which expresses the amount of the produced gas and vapour that is captured and used for fuel, produced into gas
gathering systems or re-injected. A CE value of 1.0 means all gas is conserved, utilized or re-injected and a valueof 0 means all of the gas is either vented or flared. Values may be expected to range from about 0.1 to 0.95. The
lower limit applies where only process fuel is drawn from the produced gas and the rest is vented or flared. A valueof 0.95 reflects circumstances where there is, generally, good access to gas gathering systems and local regulations
emphasize vent and flare gas reduction.
EQUATION 4.2.3
ALTERNATIVE TIER 2 APPROACH (EMISSIONS DUE TO VENTING)

Egas ,oil prod , venting= GOR • QOIL • (1 − CE ) • (1 − X Flared ) • M gas • ygas • 42.3 × 10−6

EQUATION 4.2.4
ALTERNATIVE TIER 2 APPROACH (CH4 EMISSIONS DUE TO FLARING)ECH 4 , oil prod , flaring= GOR • QOIL • (1 − CE ) • X Flared • (1 − FE ) • M CH 4 • yCH 4 • 42.3 × 10−6

EQUATION 4.2.5
ALTERNATIVE TIER 2 APPROACH (CO2 EMISSIONS DUE TO FLARING)

ECO2 , oil prod , flaring= GOR • QOIL • (1 − CE ) • X Flared • M CO2• [ yCO2 + ( NcCH 4 • yCH 4 + NcNMVOC • yNMVOC )(1 − X Soot )] • 42.3 ×10−6

EQUATION 4.2.6
CH4 EMISSIONS FROM FLARING AND VENTING=ECH 4 , oil prod ECH 4 , oil prod , venting + ECH 4 , oil prod , flaring

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EQUATION 4.2.7
CO2 EMISSIONS FROM VENTING AND FLARING=ECO2 , oil prod ECO2 , oil prod , venting + ECO2 , oil prod , flaring

EQUATION 4.2.8
N2O EMISSIONS FROM FLARING

EN2O , oil prod , flaring =GOR • QOIL (1 − CE ) X Flared EFN2O
Where:
Ei, oil prod, venting= Direct amount (Gg/y) of GHG gas i emitted due to venting at oil production facilities

Ei, oil prod, flaring= Direct amount (Gg/y) of GHG gas i emitted due to flaring at oil production facilities

GOR= Average gas-to-oil ratio (m3/m3) referenced at 15ºC and 101.325 kPa

QOIL= Total annual oil production (103 m3/y)

Mgas= Molecular weight of the gas of interest (e.g., 16.043 for CH4 and 44.011 for CO2)

Nc,i

= Number of moles of carbon per mole of compound i (i.e., 1 for CH4, 2 for C2H6, 3
for C3H8, 1 for CO2, 2.1 to 2.7 for the NMVOC fraction in natural gas and 4.6 for the
NMVOC fraction of crude oil vapours)yi= Mol or volume fraction of the associated gas that is composed of substance i (i.e.,
CH4, CO2 or NMVOC)

CE= Gas conservation efficiency factor

XFlared= Fraction of the waste gas that is flared rather than vented. With the exception ofprimary heavy oil wells, usually most of the waste gas is flared.

FE= flaring destruction efficiency (i.e., fraction of the gas that leaves the flare partiallyor fully burned). Typically, a value of 0.995 is assumed for flares at refineries and avalue 0.98 is assumed for those used at production and processing facilities.

Xsoot= fraction of the non-CO2 carbon in the input waste gas stream that is converted tosoot or particulate matter during flaring. In the absence of any applicable data thisvalue may be assumed to be 0 as a conservative approximation.

EFN2O= emission factor for N2O from flaring (Gg/103 m3 of associated gas flared). Refer tothe IPCC emission factor database (EFDB), manufacturer’s data or other appropriate
sources for the value of this factor.

42.3x10-6= is the number of kmol per m3 of gas referenced at 101.325 kPa and 15ºC (i.e.
42.3x10-3 kmol/m3) times a unit conversion factor of 10-3 Gg/Mg which brings theresults of each applicable equation to units of Gg/y.

The values of ECH4, oil prod, venting and ECO2, oil prod, venting in Equations 4.2.6 and 4.2.7 are estimated using Equation
4.2.3.
It should be noted that Equation 4.2.5 accounts for emissions of CO2 using a similar approach to what is done forfuel combustion in Section 1.3 of the Introduction chapter of the Energy Volume. The term yCO2 in this equation
effectively accounts for the amount of raw (or formation CO2) present in the waste gas being flared. The terms
NcCH4 ● yCH4 and NcNMVOC ● yNMVOC in Equation 4.2.5 account for the amount of CO2 produced per unitof CH4 and NMVOC oxidized.

TIER 3Tier 3 comprises the application of a rigorous bottom-up assessment by primary type of source (e.g., venting,flaring, equipment leaks, evaporation losses and accidental releases) at the individual facility level with appropriate
accounting of contributions from temporary and minor field or well-site installations. It should be used for key
categories where the necessary activity and infrastructure data are readily available or are reasonable to obtain.
Tier 3 should also be used to estimate emissions from surface facilities where EOR, EGR and ECBM are being
used in association with CCS. Approaches that estimate emissions at a less disaggregated level than this (e.g.,
relate emissions to the number of facilities or the amount of throughput) are deemed to be equivalent to a Tier 1

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Chapter 4: Fugitive Emissions

approach if the applied factors are taken from the general literature, or a Tier 2 approach if they are countryspecific values.
The key types of data that would be utilized in a Tier 3 assessment would include the following:• Facility inventory, including an assessment of the type and amount of equipment or process units at each facility,
and major emission controls (e.g., vapour recovery, waste gas incineration, etc.);• Inventory of wells and minor field installations (e.g., field dehydrators, line heaters, well site metering, etc.);• Country-specific flare, vent and process gas analyses for each subcategory;• Facility-level acid gas production, analyses and disposition data;• Reported atmospheric releases due to well blow-outs and pipeline ruptures;.
• Country-specific emission factors for fugitive equipment leaks, unaccounted/unreported venting and flaring,
flashing losses at production facilities, evaporation losses, etc.;• The amount and composition of acid gas that is injected into secure underground formations for disposal.
Oil and gas projects that involve CO2 injection as a means of enhancing production (e.g., EOR, EGR and ECBM
projects) or as a disposal option (e.g., acid gas injection at sour gas processing plants) should distinguish between
the CO2 capture, transport, injection and sequestering part of the project, and the oil and gas production portion of
the project. The net amount of CO2 sequestered and the fugitive emissions from the CO2 systems should bedetermined based on the criteria specified in Chapter 5 for CO2 capture and storage. Any fugitive emissions fromthe oil and gas systems in these projects should be assessed based on the guidance provided here in Chapter 4 andwill exhibit increasing concentrations of CO2 over time in the emitted natural gas and hydrocarbon vapours.
Accordingly, the applied emission factors may need to be periodically updated to account for this fact. Also, careshould be taken to ensure that proper total accounting of all CO2 between the two portions of the project occurs.

4.2.2.3 C HOICE OF EMISSI ON FACTOR
Oil and gas technologies and practices and therefore, emissions, can vary greatly from country to country and overtime. Data availability may also vary between countries and change over time. Tier 1 emission factors are listed in
the tables below by segment. Tier 2 and 3 emission factors are also discussed below. It is likely that many countries
will use a combination of tiers to calculate emissions across petroleum and natural gas systems.
T I ER 1
Tier 1 default emission factors for each segment of oil and natural gas systems are presented in tables below. Eachfactor represents emissions per year.
Several options for activity data are available for many of the factors. For each segment, at least one factor option
has been related to throughput, because production, imports and exports, and consumption are often the only
national oil and gas statistics that are consistently available in many countries. However, fugitive emissions may
be more dependent on other factors. An improved basis for estimating emissions for many sources might use otheractivity data (e.g. length of pipeline). The tables in Section 4.2.2.3 provide options for emission factors to be
applied to other activity data where possible, and where appropriate. In addition, for many segments, technologyor practice-specific emission factors are available. Information on the appropriate use of each factor is included
for each technology-specific factor. Compilers are to assess which Tier 1 factors are most appropriate and should
consider other sources or a more disaggregated EF (see Annex 4A.2) if the emission factors presented here are
expected to vary significantly from national circumstances.
The Tier 1 factors presented in this section are aggregates of venting, flaring, and leak emissions. To develop
separate estimates for venting, flaring, and leak emissions, default fractions of emissions in each category forrelevant emission factors are provided in Annex 4A.2.
It should be noted that the default EFs listed in Tables 4.2.4 to 4.2.4k are sensitive to temperature and pressure.
Activity data must be consistent with the EFs standard conditions. For more information on conversions to standard
temperature and pressure, please see Annex 4A.1.
The factors in Tables 4.2.4 to 4.2.4k are derived using detailed emission inventory results from the United States,
Canada, Australia, Germany, and other countries, and, where possible, have been updated from the values
previously presented in the 2006 IPCC Guidelines to reflect the results of more current and refined emissions
inventories. In many cases, technology- and practice-specific emission factors are presented, so that an inventory
compiler may select factors that best represent industry practices in the country. While the emission factor options
are meant to cover technologies and practices that are common in the oil and gas industries, technologies and2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

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practices can vary significantly. In addition, the accuracy of factors is dependent on the uncertainty of underlying
data. A country should periodically assess changes in technologies and practices, and changes in available
emissions data, and consider updating estimates using at least a Tier 2 approach, per good practice.
Oil Systems
1 B 2 a i Exploration 5
4FThis segment includes fugitive emissions (including equipment leaks, venting and flaring) from all field activities
prior to production (e.g. prospecting and exploratory well drilling, well/drill stem testing and completions). 6 In
this segment, factors are not disaggregated to drilling, testing and servicing operation; EFs are applied to the wholesegment.
5F

In Table 4.2.4, several options for onshore exploration emission factors inclusive of venting, flaring, and leaks arepresented. Each technology/practice-specific emission factor is presented in units of tonne per oil well drilled,tonne per active oil well, and in tonnes per thousand cubic meter oil produced. The count of wells drilled is thought
to best reflect emissions from exploration and if available should be applied. However, the inventory compiler
should assess which activity data are available and which activity data basis best reflects emissions in that segment
for that country.
Emission factors are available for both onshore unconventional and onshore conventional oil exploration.
Offshore exploration emissions data are unavailable, and these emissions are thought to be negligible; therefore,
emission factors are not included for offshore exploration. Here, unconventional oil exploration refers to
exploration where hydraulic fracturing well completion practices are used, and conventional oil exploration refers
to exploration where hydraulic fracturing well completion practices are not used.
The extent of any hydraulic fracturing activities in the country should be assessed. Unconventional completions(i.e., conducted with hydraulic fracturing) have a different emissions profile than conventional completions (i.e.,
conducted without hydraulic fracturing). This is reflected in the emission factors below. Where possible, thecompiler should separate national activity data into conventional and unconventional categories and apply therelevant emission factors. If only total oil wells or total oil production data are available, the compiler should
develop an estimate of the annual split between conventional and unconventional wells or conventional andunconventional production in the country to develop the activity data. Unconventional factors are to be applied tothe unconventional activity data basis. Where wells drilled are completed with hydraulic fracturing and flaring andgas recovery is not practiced, or where the extent of flaring or recovery practices is unknown, the first set of factors(“Unconventional without flaring or recovery”) should be used and applied to the relevant activity data (i.e.
unconventional wells drilled, total unconventional well population, or unconventional production). Where wells
drilled are completed with hydraulic fracturing and flaring and gas recovery is used, the fraction of the relevant
activity data that uses flaring and/or gas recovery should be determined. The second set of factors(“Unconventional with flaring”) is used for that fraction, while the first set of factors is applied to the wells or
production that are not using flaring or recovery. Conventional factors (“Conventional”) are to be applied to theconventional activity data basis. As technologies and practices change over time, it is possible that one EF will be
used in some years and another in other years. A compiler should assess the time frame over which changes took
place, and consider linear interpolation or other techniques to incorporate the trend from one emission factor toanother over the time series.
Factors presented are inclusive of venting, flaring, and leak emissions. For cases where country-specific data are
available for a subcomponent of the factor (e.g. venting and flaring emissions), disaggregated Tier 1 EF that could
be applied to estimate the remaining emission types are available—see Annex 4A.2 for information (including
examples) on how to calculate disaggregated emissions.
Definitions for oil wells versus gas wells can vary from country to country and organization to organization. The
Tier 1 EFs in the table below were developed from emissions occurring in U.S. basins identified as having
predominantly oil production. Emission factors were developed using data on exploration emissions (drilling,
testing, and completions) for wells with a gas oil ratio of </= 17,000 cubic meters gas to cubic meters oil. If national
criteria defines oil and gas wells, follow the national criteria or national documentation to make the distinction.
What is most important is that all emissions are transparently allocated to either oil or gas systems, withoutomission.
For each sub-segment listed in Table 4.2.4 below that is occurring in the country, compilers must calculate
emissions, and sum them according to Equation 4.2.9. It is recognized that not all countries will have all sub5 Some countries expressed several technical concerns with the validity and reliability of the newly added equations and default

emission factors for fugitive emissions from oil exploration. The countries expressed that the newly added guidance ispremature and needs further work before it can be used.

6 Refracturing and redrilling emissions are to be included in 1.B.2.a.ii (Production and Upgrading).

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Chapter 4: Fugitive Emissions

segments (i.e. technologies or practices) occurring. Factors listed in Table 4.2.4 apply to onshore exploration.
Emissions data are unavailable for offshore exploration.
EQUATION 4.2.9 (NEW)GENERAL EQUATION FOR ESTIMATING FUGITIVE EMISSIONSFROM EXPLORATION

Eexploration = Aunconventional oil without flaring or recovery • EFunconventional oil without flaring or recovery+ Aunconventional oil with flaring or recovery • EFunconventional oil with flaring or recovery+ Aconventional oil • EFconventional oil
Where:
Eexploration= Total amount of GHG gas emitted due to all relevant oil exploration
activities

Aunconventional oil without flaring or recovery= Activity data on exploration of unconventional oil without flaring
or recover

EFunconventional oil without flaring or recovery = Emission factor for exploration of unconventional oil without flaring
or recovery
Aunconventional oil with flaring or recovery= Activity data on exploration of unconventional oil with flaring or
recoveryEFunconventional oil with flaring or recovery= Emission factor for exploration of unconventional oil with flaring or
recoveryAconventional oil= Activity data on exploration of conventional oil

EFconventional oil= Emission factor for exploration of conventional oil

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TABLE 4.2.4 (UPDATED)TIER 1 EMISSION FACTORS FOR OIL EXPLORATION, 1.B.2.A.I
CO2

CH4Segment

Oil
exploration

Oil
exploration

Oil
exploration

4.50

Sub-segment

Onshoreunconventional without
flaring or
recoverya, dOnshoreunconventional withflaring or
recoveryb, dOnshoreConventionalc

Emissionsource

All

All

All

NMVOC

N2O

Value

Uncertainty (%of value)

Value

Uncertainty (%of Value)

Value

Uncertainty (%of value)

Value

Uncertainty (%of value)

6.63-30% to
+30%

14.35

-30% to+30%

0.99-12.5% to
+800%

NA

NA

Tonnes/unconventional onshore
oil wells drilled in a year,
without flaring or recovery

0.46-30% to+30%

0.97-30% to+30%

0.07-12.5% to
+800%

NA

Tonnes/total unconventional
onshore oil well population
where exploration occurs without
flaring or recovery

1.64-30% to+30%

3.49-30% to+30%

0.25-12.5% to
+800%

NA

NA

Tonnes/thousand cubic meters
onshore unconventional oil
production where exploration
occurs without flaring or
recovery

0.81-30% to
+30%

11.25

-30% to+30%

0.12-12.5% to+800%

8.2E-05-10% to+1000%

Tonnes/unconventional onshore
oil wells drilled in a year, withflaring or recovery

0.07-30% to+30%

1.03-30% to+30%

0.01-12.5% to+800%

7.5E-06-10% to+1000%

Tonnes/total unconventional
onshore oil well population
where exploration occurs withflaring or recovery

0.06-30% to+30%

0.86-30% to+30%

0.01-12.5% to+800%

6.3E-06-10% to+1000%

Tonnes/thousand cubic meters
onshore unconventional oil
production where exploration
occurs with flaring or recovery

0.53-30% to
+30%

12.44

-30% to+30%

0.08-12.5% to+800%

9.0E-05-10% to+1000%

Tonnes/onshore conventional oil
wells drilled in a year

0.01

-30% to+30%

0.22-30% to+30%

1.4E-03-12.5% to+800%

1.6E-06-10% to+1000%

Tonnes/total conventional
onshore oil well population

0.02-30% to+30%

0.44-30% to+30%

2.8E-03-12.5% to+800%

3.2E-06-10% to+1000%

Tonnes/thousand cubic meters
onshore conventional oil
production

NA

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Chapter 4: Fugitive Emissions

TABLE 4.2.4 (UPDATED) (CONTINUED)TIER 1 EMISSION FACTORS FOR OIL EXPLORATION, 1.B.2.A.I
NA – Not Applicablea.

Emission factors for CH4 and CO2 developed from United States Environmental Protection Agency (2016a) for unconventional oil well completions, (Radian International LLC 1999) for drilling emissions, andU.S. Greenhouse Gas Reporting Program (GHGRP) (United States Environmental Protection Agency (EPA) 2017) data on well testing, as applied in the 2018 U.S. GHG Inventory (United States Environmental
Protection Agency (EPA) 2018a); factor is an average of 2006-2010 calculated implied emission factors for emissions from well drilling, well testing, and from well completions with hydraulic fracturing that do
not flare or use gas capture. The time period of 2006-2010 was selected as it represents a time when hydraulic fracturing is occurring, but before state or federal regulations were in place to control gas emissions.
NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table.

b.

Emission factors for CH4 and CO2 developed from (United States Environmental Protection Agency (EPA) 2016a) for unconventional oil well completions, from (Radian International LLC 1999) for drillingemissions, and GHGRP (United States Environmental Protection Agency (EPA) 2017) data on well testing, as applied in the 2018 U.S. GHG Inventory. Factor is the average of 2012-2016 calculated impliedemission factors for emissions from well drilling, well testing, and from well completions with hydraulic fracturing that flare or use gas capture. The time period of 2013-2016 was selected as it represents a time
when hydraulic fracturing is occurring and state or federal regulations were in place to control gas emissions. NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to
CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table. N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to CO2 from 2006
IPCC Guidelines, which was then applied to corresponding CO2 values in this table.

c.

Emission factors for CH4 and CO2 developed from EPA/GRI, Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996) for conventional oil well completions, GHGRP (United States
Environmental Protection Agency (EPA) 2017) for well testing, and (Radian International LLC 1999) for drilling emissions, as applied in the 2018 U.S. GHG Inventory. Factor is the average of 2006-2016
calculated implied emission factors for emissions from well drilling, well testing and from conventional completions. The time period of 2006-2016 was selected to cover the time frame of the other exploration
factors. NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table.
N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to CO2 from 2006 IPCC Guidelines, which was then applied to corresponding CO2 values in this table.

d.

Unconventional oil exploration refers to exploration that includes well completions with hydraulic fracturing. Conventional oil exploration emission factors should be applied where hydraulic fracturing wellcompletion practices are not used.

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1 B 2 a ii Production and UpgradingThis segment includes fugitive emissions from oil production (including leaks, venting, and flaring) from the oilwellhead or at the oil sands or shale oil mine through to the start of the oil transmission system. On-site crude oilprocessing (i.e. removing water and gases contained in crude oil) is also included in this segment. Emissions arise
from the wells themselves (e.g., as wellhead leaks and from well workovers and refractures), and well-siteequipment such as pneumatic controllers, dehydrators and separators. This includes fugitive emissions related tooil sands or shale oil mining, transport of untreated production (i.e. well effluent, emulsion, oil shale and oil sands)
to treating or extraction facilities, activities at extraction and upgrading facilities, associated gas re-injection
systems and produced water disposal systems. Fugitive emissions from upgraders are grouped with those fromproduction rather than those from refining since the major product from upgraders (i.e. synthetic crude oil) requires
further processing at refineries. Upgraders are often integrated with extraction facilities and may also be integrated
with refineries, co-generation plants or other industrial facilities, making their relative contributions difficult toestablish.
Table 4.2.4a presents factors for onshore oil production, and offshore oil production.
Countries with onshore oil production should apply a factor for onshore production to the relevant activity datafor onshore production. Factors for onshore production (other than for oil sands) are presented both in units oftonne per active oil well, and in tonnes per thousand cubic meter oil produced. The count of wells is thought tobest reflect emissions from oil production, and if complete and accurate well count data are available, they should
be applied. However, the inventory compiler should assess which activity data are available and which activity
data basis best reflects emissions in that segment for that country. The types of technologies and practices in use
in the country should be assessed, including the extent of associated gas venting and flaring, and use of controls attanks. Where this information is unknown, or where more than 5 percent of associated gas is vented, or more than
30 percent of tank throughput is uncontrolled (e.g. without flaring or vapour recovery units (VRUs)), the first setof emission factors for oil production (“Most activities occurring with higher-emitting technologies and practices”)
should be used. Where lower-emitting technologies are used extensively (e.g. associated gas is used or flaredinstead of vented, most tanks are controlled), the second set of emission factors (“Most activities occurring withlower-emitting technologies and practices”) for oil production should be used. The emission factors for onshore
production were developed from data sets that included a mix of production from wells in conventional formations
and wells in unconventional formations and are considered to be applicable to both. As technologies and practices
change over time, it is possible that one EF will be used in some years and another in other years. A compiler
should assess the time frame over which changes took place, and consider linear interpolation or other techniques
to incorporate the trend from one emission factor to another over the time series.
Countries with offshore oil production should apply a factor for offshore oil production. If no data are available toestimate the share of oil production that occurs offshore, the EF for onshore production should be applied to thetotal quantity of oil production.
Production from oil sands is treated separately and should use emission factors for “Oil Sands Mining and Ore
Processing” and “Oil Sands Upgrading” to calculation emissions for that subset of oil production.
Oil sands are a type of unconventional petroleum deposit made of up a mixture of sand, clay, and water, saturated
with a highly viscous form of petroleum called crude bitumen. Crude bitumen is an extra-heavy oil with an API
gravity below 10°API. In its natural state, it is not usually recoverable at commercial rates through a well because
it is too thick to flow. There are two methods that are used to recover crude bitumen, depending on the depth ofthe deposit. Bitumen that occurs near the surface can be recovered by open-pit mining. In this method, overburden
is removed, oil sands ore is mined, and bitumen is recovered from the mined material in large facilities using hot
water and solvents. When the resource is located too deep to make surface mining economical, in situ extraction
methods are utilized. In situ extraction takes place both through primary extraction methods, similar toconventional crude oil, and enhanced extraction. The two main methods of enhanced recovery are cyclic steam
stimulation (CSS) and steam-assisted gravity drainage (SAGD). Both methods use steam to heat the reservoir
allowing the bitumen to flow to a vertical or horizontal wellbore. Due to the large quantities of both hot water andsteam needed to extract the bitumen, co-generation plants are often co-located with the extraction facilities.
Once the bitumen is produced using surface mining or in situ methods, it can be upgraded to synthetic crude oil(SCO) or lighter hydrocarbon products at an upgrader and then transported to a refinery for further processing.
Upgraders improve the quality of the crude bitumen by adding hydrogen, removing carbon, or both. During the
upgrading process, most of the sulphur and other impurities are removed. The produced bitumen can also be mixed
with a less viscous material (referred to as diluent), such as SCO or condensate, allowing the mixture to flow
through a pipeline.
Fugitive emissions from in situ extraction include leaks, venting and flaring that occur at the well pad through tothe start of the oil transmission system. Open pit mining extraction of crude bitumen also includes fugitive
emissions from leaks, venting and flaring. Additional methane present in the oil sands ore is released during

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Chapter 4: Fugitive Emissions

mining, mine dewatering, and ore transport, crushing and handling activities. Waste tailings are created during theextraction process consisting of unrecovered solvent, bitumen, water, sand, clay and other impurities. Fugitive
emissions from tailings ponds occur as microbial and bacterial degradation of hydrocarbons and vegetation present
at the bottom of the ponds produces methane gas. The upgrading process produces fugitive emissions of leaks,
venting and flaring, including CO2 venting from sulphur recovery operations and the hydrogen production process.
Factors presented are inclusive of venting, flaring, and leak emissions. For cases where country-specific data are
available for a subcomponent of the factor (e.g. venting and flaring emissions), disaggregated Tier 1 EF that could
be applied to estimate the remaining emission types are available—see Annex 4A.2 for information (including
examples) on how to calculate disaggregated emissions.
Definitions for oil wells versus gas wells can vary from country to country and organization to organization. The
onshore production (other than oil sands) Tier 1 EFs in the table below were developed from emissions occurringin U.S. basins identified as having predominantly oil production. Emission factors were developed using data on
production emissions for wells with a gas oil ratio of </= 17,000 cubic meters gas to cubic meters oil. If national
criteria defines oil and gas wells, follow the national criteria or national documentation to make the distinction.
What is most important is that all emissions are transparently allocated to either oil or gas systems, withoutomission.
For each segment/sub-segment listed in Table 4.2.4a below that is occurring in the country, compilers must
calculate emissions, and sum them according to Equation 4.2.10. It is recognized that not all countries will haveall segments and sub-segments occurring.
EQUATION 4.2.10 (NEW)GENERAL EQUATION FOR ESTIMATING FUGITIVE EMISSIONS FROM OIL PRODUCTION AND
UPGRADING
Eoil production = Aonshore oil production • EFonshore oil production+ Aoffshore oil production • EFoffshore oil production+ Aoil sands processing • EFoil sands processing+ Aoil sands upgrading • EFoil sands upgrading

Where:
Eoil production= Total amount of GHG gas emitted due to all relevant oil production activities

Aonshore oil production= Volume of onshore oil produced or number of onshore active wells

EFonshore oil production= Emission factor for onshore oil production

Aoffshore oil production= Volume of offshore oil produced

EFoffshore oil production= Emission factor for offshore oil production

Aoil sands processing= Volume of crude bitumen produced from surface mining

EFoil sands processing= Emission factor for processing of oil sands

Aoil sands upgrading= Volume of synthetic crude oil produced

EFoil sands upgrading= Emission factor for upgrading of oil sands

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TABLE 4.2.4A (NEW)
TIER 1 EMISSION FACTORS FOR OIL PRODUCTION, 1.B.2.A.II
CH4
Segment

Oil
Production

Sub-segment

Onshore: Most
activities occurringwith higher- emitting
technologies andpracticesa

EmissionsourceCO2

Value

Uncertainty(% ofvalue)

3.43

NMVOC

Value

Uncertainty(% ofValue)

±30%

12.40

2.35

±30%

2.91

Value

Uncertainty(% ofvalue)

±30%

1.48

8.47

±30%

±30%

44.99

2.19

±30%

N2O
Units of measure

Value

Uncertainty(% ofvalue)-100% to+800%

1.9E-04-10% to+1000%

Tonnes/thousand cubic meters
onshore oil production

1.01-100% to+800%

1.3E-04-10% to+1000%

Tonnes per active onshore oil well

±30%

1.25

-100% to+800%

6.7E-04-10% to+1000%

Tonnes/thousand cubic meters
onshore oil production

33.83

±30%

0.94

-100% to+800%

5.1E-04-10% to+1000%

Tonnes per active onshore oil wellAll

Onshore: Most
activities occurringwith lower-emitting
technologies andpracticesb

All

Oil
Production

Onshore: Oil Sands
Mining and Ore
Processingc

All

0.74

±30%

7.56

±25%

0.65

-30% to+95%

1.1E-05-30% to+520%

Tonnes/thousand cubic meters
crude bitumen production fromsurface mining

Oil
Production

Onshore: Oil Sands
Upgradingd

All

0.13

-35% to
+120%

90.73

±15%

0.07

-60% to+75%

2.8E-05-25% to+315%

Tonnes/thousand cubic meterssynthetic crude oil production

Oil
Production

Offshoree

All

2.46

±30%

4.08

±30%

1.06

-100% to+800%

1.6E-05-10% to+1000%

Tonnes/thousand cubic meters
offshore oil production

Oil
Production

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TABLE 4.2.4A (NEW) (CONTINUED)TIER 1 EMISSION FACTORS FOR OIL PRODUCTION, 1.B.2.A.II
a.

Emission factors for CH4 and CO2 developed from EPA/GRI, Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996), and data reported to the U.S. Greenhouse Gas Reporting Program(GHGRP) (United States Environmental Protection Agency (EPA) 2017), as applied in the 2018 U.S. GHG Inventory (United States Environmental Protection Agency (EPA) 2018a) to calculate emissions forthe year 1992 (when EPA/GRI study was conducted). Examples of higher-emitting technologies and practices include venting of associated gas and uncontrolled tanks. NMVOC values were developed from2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table. N2O values were developed from 2006 IPCC
Guidelines by calculating a ratio of N2O to CO2 from 2006 IPCC Guidelines, which was then applied to corresponding CO2 values in this table.

b.

Emission factors for CH4 and CO2 developed from data reported to the GHGRP (United States Environmental Protection Agency (EPA) 2017), and EPA/GRI, Methane Emissions from the Natural Gas Industry(Gas Research Institute 1996), as applied in the 2018 U.S. GHG Inventory to calculate emissions for the year 2016 (the most recent year of GHGRP data availability). Examples of lower-emitting technologies
and practices include limited venting or flaring of associated gas, and tanks with controls. NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006
IPCC Guidelines, which was then applied to corresponding CH4 values in this table. N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to CO2 from 2006 IPCC Guidelines,
which was then applied to corresponding CO2 values in this table.

c.

Emission factors developed from An Inventory of GHG, CAC and Other Priority Emissions by the Canadian Oil Sands Industry: 2015, prepared by Clearstone Engineering Ltd. for Environment and Climate
Change Canada (Clearstone Engineering Ltd 2017) and production data from the Alberta Energy Regulator (AER) (Alberta Energy Regulator 2018), ST39: Alberta Mineable Oil Sands Plant Statistics. Includes
fugitive emissions from tailings ponds and the exposed oil sands mine surface.

d.

Emission factors developed from An Inventory of GHG, CAC and Other Priority Emissions by the Canadian Oil Sands Industry: 2015, prepared by Clearstone Engineering Ltd. for Environment and Climate
Change Canada (Clearstone Engineering Ltd 2017) and production data from the Alberta Energy Regulator (AER) (Alberta Energy Regulator 2018), ST39: Alberta Mineable Oil Sands Plant Statistics.

e.

Emission factors for CH4 and CO2 developed from U.S. Bureau of Ocean Energy Management’s (BOEM) Gulf Offshore Activity Data System (GOADS) (United States Bureau of Ocean Energy Management(BOEM) 2017), as applied in the 2018 U.S. GHG Inventory, to estimate emissions for 2011 (the year of the BOEM survey), with U.S. GHG Inventory flaring data adjusted to use GOADS data and separate
between oil and gas based on relative CH4 emissions. NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was thenapplied to corresponding CH4 values in this table. N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to CO2 from 2006 IPCC Guidelines, which was then applied tocorresponding CO2 values in this table.

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1 B 2 a iii TransportThis segment includes venting and leakage emissions related to the transport of marketable crude oil (including
conventional, heavy and synthetic crude oil and bitumen), etc. to upgraders and refineries. The transportation
systems may comprise pipelines, tank trucks and rail cars, tanks, and tanker ships. Evaporation losses from storage,
filling and unloading activities and fugitive equipment leaks are the primary sources of these emissions. Two sets
of factors are available for tanker ships. Where tanker ship use of VRU is infrequent or unknown, the factor for“Loading of offshore production on tanker ships without VRU” should be used. Where tanker ship use of VRU is
common, the factor for “Loading of offshore production on tanker ships with VRU” should be used. It is important
to note that the emissions might vary greatly from loading to loading and are strongly influenced by several factors,
including composition and temperature of the crude oil, how the loading system is designed and operated, whether
the cargo tanks on the vessel contain hydrocarbon gases, inert gases or a mixture of these when the loading
operation starts, and weather conditions and wave heights during loading.
For each segment/sub-segment listed in Table 4.2.4b below that is occurring in the country, compilers must
calculate emissions, and sum them according to Equation 4.2.11. It is recognized that not all countries will haveall segments and sub-segments occurring.
EQUATION 4.2.11 (NEW)GENERAL EQUATION FOR ESTIMATING FUGITIVE EMISSIONS FROM OIL TRANSPORTATION

Eoil=
Apipelines • EFpipelinestransport+ Atanker trucks and rail cars • EFtanker trucks and rail cars
+ Atanks • EFtanks + Atanker ships • EFtanker ships
Where:
Eoil transport= Total amount of GHG gas emitted due to all relevant oil transport activities

Apipelines= Volume of oil transported by pipelines

EFpipelines= Emission factor for oil transported by pipelines

Atanker trucks and rail cars

= Volume on oil transported by tanker trucks and rail cars

EFtanker trucks and rail cars = Emission factor for oil transported by tanker trucks and rail cars

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Atanks= Volume of crude oil feed

EFtanks= Emission factor for tanks

Atanker ships= Volume of oil loaded onto tanker ships

EFtanker ships= Emission factor for oil transported by tanker ships

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Chapter 4: Fugitive Emissions

TABLE 4.2.4B (NEW)
TIER 1 EMISSION FACTORS FOR OIL TRANSPORT, 1.B.2.A.III
CH4
Segment

Sub-segment

EmissionsourceOil
Transport

Pipelinesa

OilTransport

Value

Uncertainty(% ofvalue)

All

0.0054

Tanker Trucks andRail Carsb

All

Oil
Transport

TankscOil
Transport

Oil
Transport

CO2

NMVOC

Value

Uncertainty(% ofValue)±100%

0.00049

0.025

±50%

All

0.002

Loading of offshore
production ontanker ships
without VRUd

All

Loading of offshore
production ontanker ships with
VRUe

All

Value

Uncertainty(% ofvalue)

±100%

0.054

0.0023

±50%

±50%

NA

0.065

±50%

0.040

±50%

N2O

Value

Uncertainty(% ofvalue)

Units of measure-50% to
+200%

NA

NA

Tonne per thousand cubic meters oil transported
by pipeline

0.25-50% to
+200%

NA

NA

Tonne per thousand cubic meters oil transported
by tanker truck or rail car

NA

NA

NA

NA

NA

Tonne per thousand cubic meters crude oil feed

ND

ND

1.10

ND

ND

ND

Tonne per thousand cubic meters oil loaded onto
tanker ship

ND

ND

0.16

ND

ND

ND

Tonne per thousand cubic meters oil loaded onto
tanker ship

NA – Not Applicable, ND – Not Determined
a. From 2006 IPCC Guidelines values for both developed and developing and economies in transition.
b. From 2006 IPCC Guidelines values for both developed and developing and economies in transition.
c. Emission factors for CH4 developed from Radian International LLC, 1999, as applied in the 2018 U.S. GHG Inventory (United States Environmental Protection Agency (EPA) 2018a) for all years.
d. Emission factors for CH4 and NMVOC are averages of reported data for tanker ships without VRU from 2015-2016 reports from Norwegian VOC Industrial Cooperation (VOCIC) (2015-2017).
e. Emission factors for CH4 and NMVOC are averages of reported data for tanker ships with VRU from 2015-2016 reports from Norwegian VOC Industrial Cooperation (VOCIC) (2015-2017).

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1 B 2 a iv Refining
This segment includes fugitive emissions (including leaks, venting, and flaring) at petroleum refineries. Refineries
process crude oils, natural gas liquids and synthetic crude oils to produce final refined products (e.g., primarily
fuels and lubricants) and in some plants even hydrogen (see Box 4.2.1 below). Methane emission sources include
storage tanks, blowdowns, asphalt blowing, equipment leaks, vents, loading operations, wastewater treating,cooling towers, catalytic cracking/reforming/fluid cracking, flares, delayed coking, and coke calcining. Carbon
dioxide emissions included under 1.B.2.a.iv include asphalt blowing, calcination, anode production, process vents,and flaring. For additional information on catalyst regeneration and calcination, see Box 4.2.2. Where refineries
are integrated with other facilities (for example, upgraders or co-generation plants) their relative emission
contributions can be difficult to establish in measurement studies. The emission factors presented in Table 4.2.4c
represent petroleum refinery emissions only.
BOX 4.2.1 (NEW)HYDROGEN PRODUCTION. FUGITIVE EMISSIONS AND REFINERIESThe Tier 1 method for refinery fugitives already accounts for emissions associated with Hydrogenproduction. Where a Tier 2 or Tier 3 method is applied to estimate emissions from the refinery sector,
it is good practice for compilers to check whether the method already accounts for emissions from
Hydrogen production on the refinery:If applying a Tier 2 method for refinery GHG emissions, does the country-specific emission factor
already account for emissions from hydrogen production? If applying a Tier 3 method for refinery
GHG emissions, does the method (e.g. country-specific model, aggregated installation-level
estimates or directly reported emissions estimates) already account for the emission from hydrogenproduction?
Where they do not, then an appropriate method from the IPPU sector, as presented in the IPPU
Hydrogen chapter (Ch. 3.11, Vol. 3 IPPU), may be applied to account for GHG emissions from theHydrogen production within the refinery.

BOX 4.2.2 (NEW)NOTES ON CATALYST REGENERATION AND CALCINATION

The process-related coke deposit at the catalyst leads to less effectiveness. With the coke burn-off,the catalyst is regenerated. The controlled burn-off of the catalyst coke takes place within therefinery and the thermal energy is usually re-used. Carbon dioxide emissions from this process arereported under 1.A.1.b. It is good practice to develop a country specific emission factor. As activity
data, the relevant quantity of petroleum coke could be obtained from the national petroleum statisticor the emission trading system (ETS), as applicable. If this information is not available, a default
emission factor of 28.3 kg CO2/t crude oil input 7 can be used.
6F

During calcination, the hydrocarbons contained in the petroleum coke are burned at hightemperatures in order to obtain calcine (calcined coke). The emissions arising in this process arereported under 1.B.2.a.iv. The default factor specified in Table 4.2.4c includes calcination.

7 Emission factor developed as an average of (German Government 2018) GHG Inventory data (2005 to 2016) with a range of

25.7 to 31.0 kg CO2/tonne.

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TABLE 4.2.4C (NEW)
TIER 1 EMISSION FACTORS FOR OIL REFINING, 1.B.2.A.IV

Segment

Oil Refininga.

Sub-segment

Alla

Emissionsource

All

CH4

CO2

Value

Uncertainty(% of value)

Value

Uncertainty(% of Value)

0.03-50% to
+130%

5.85

-50% to
+130%

NMVOC

N2O

Value

Uncertainty(% of value)

Value

Uncertainty(% of value)

0.26

±100%

8.77E-05±100%

Units of measure

Tonnes/thousand cubic
meters oil refined

Emission factors for CH4, NMVOC, and CO2 developed as an average of (German Government 2018) GHG Inventory data (1990 to 2016) with a range of 0.016 to 0.065 tonnes CH4/thousand cubic meters, 0.151 to
0.584 tonnes NMVOC/thousand cubic meters and 5.437 to 6.143 tonnes CO2/thousand cubic meters. N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to CO2 from oil production(N2O values from refineries were unavailable) in 2006 IPCC Guidelines, which was then applied to corresponding CO2 values for refineries in this table. The factors include fugitive equipment leaks, flaring, storageof crude oil, handling and calcination.

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1 B 2 a v Distribution of Oil ProductsThis segment includes fugitive emissions (including leaks and venting) from the transport and distribution ofrefined products, including those at bulk terminals and retail facilities. Evaporation losses from storage, filling andunloading activities and equipment leaks are the primary sources of these emissions. Many products are directly
used in the chemical industry and should be considered in the appropriate subcategory (e.g. Volume 3 Chapter 3).
Table 4.2.4d below provides emission factors for major fuel types. The emission factors consider emissions fromrefinery dispatch or border dispatch stations, to depots and further distribution to end-users (e.g. gas stations andairports). It is assumed that a fractional distillation in the refinery separated gaseous components from fuels.
Therefore, only NMVOC emissions factors are provided. Tier 1 emission factors are currently available for only
a subset of the total types of oil products distributed.
For each sub-segment listed in Table 4.2.4d below that is occurring in the country, compilers must calculate
emissions, and sum them according to Equation 4.2.12. It is recognized that not all countries will have all segments
and sub-segments occurring.
EQUATION 4.2.12 (NEW)GENERAL EQUATION FOR ESTIMATING FUGITIVE EMISSIONS FROM DISTRIBUTION OF OILPRODUCTS
Edistribution=Aof oil producs
gasoline distribution • EFgasoline distribution+ Aother distribution • EFother distribution
Where:
Edistribution of oil products = Total amount of GHG gas emitted due to all relevant activities on distribution of oil
products

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Agasoline distribution= Volumes of gasoline consumed

EFgasoline distribution= Emission factor for gasoline distribution

Aother distribution= Volumes of other oil products consumed (e.g. diesel, aviation fuel, jet kerosene)

EFother distribution= Emission factor for other oil products distribution (e.g. diesel, aviation fuel, jetkerosene)

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Chapter 4: Fugitive Emissions

TABLE 4.2.4D (NEW)
TIER 1 EMISSION FACTORS FOR DISTRIBUTION OF OIL PRODUCTS, 1.B.2.A.V
CO2

CH4Subsegment

EmissionsourceRefinedProduct
Distribution

Gasolinea

All

RefinedProduct
Distribution

Other (e.g.
diesel,aviationfuel, jetkerosene)b

Segment

All

Value

Uncertainty(% ofvalue)

NA

NA

NA

NA

NMVOC

Value

Uncertainty(% ofValue)

NA

NA

NA

NA

N2O
Units ofmeasureValue

Uncertainty(% ofvalue)

Value

Uncertainty(% ofvalue)

2.27

±20%

NA

NA

Tonnes per
thousand cubic
meters productconsumedNA

Tonnes per
thousand cubic
meters productconsumed

0.15

±20%

NA

NA – Not Applicablea.

The NMVOC emission factors are developed from the (German Government 2018) inventory values for 2016 for unabated distribution of fuels and include transhipping from tanker to tanks,
refuelling of cars, permeation in refuelling hoses and dripping losses. Several techniques like vapour-balancing and vapour-recovery along with use of automatic monitoring systems will have asignificant influence on the factor, in which country-specific EFs should be developed to reflect reduction efficiency and level of application of such techniques.

b.

Note from 2006 IPCC Guidelines: “Estimated based on assumed average evaporation losses of 0.15 percent of throughput at the distribution terminal and additional losses of 0.15 percent ofthroughput at the retail outlet. These values will be much lower where Stage 1 and Stage 2 vapour recovery occurs and may be much greater in warmer climates.”2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

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1 B 2 a vi OtherThis segment includes fugitive emissions (leaks, venting and flaring) from oil systems that are not otherwise
accounted for in the other categories. This includes fugitive emissions from spills and other accidental releases,
waste oil treatment facilities and oilfield waste disposal facilities.
Anomalous leak events can occur across oil systems and can have highly variable emissions. Examples of such
events include releases from emergency pressure relieving equipment such as emergency shutdowns (ESD),
emergency safety blowdowns (ESB) and breakout/surge tanks (American Petroleum Institute (API) 2009). It isgood practice to quantify and report such emissions whenever possible under 1 B 2 a vi (“Other”). There is no
Tier 1 method available for such events, which need to be evaluated on a case-by-case basis, often using a
combination of emission factors and engineering calculations. An example of calculating emissions during
emergency conditions though an engineering calculation approach is given in (American Petroleum Institute (API)2009).
1 B 2 a vii Abandoned Oil Wells
When production activities are completed, oil wells may be abandoned. Several reasons of well abandonment
exist: if wells have fulfilled their purpose; after the surrender of a production license; due to geological reasons;due to technical reasons; due to technological, ecological and other reasons. Countries with a long history of oil
and gas production may have a significant abandoned well population and should estimate emissions for thissource.
For onshore wells ending production in recent decades, the abandonment process is often covered by national (orregional) well abandonment regulations. Regulated wells are often treated with plugging and other practices prior
to abandonment/decommissioning to prevent leakage from the wells and migration of oil, gas or brine tosurrounding strata. That process can be generally described as follows. The wells are plugged (with the use ofplugging materials, e.g. cement) and sealed according to the regulations and considering reasons ofdecommissioning, geological conditions, and other well specifics. If these steps are implemented effectively andthe long-term integrity of the well does not fail over time, it is unlikely that the well will leak substantial amountsof methane. However, in practice integrity failure of some abandoned wells may occur and the well may startleaking methane to the atmosphere. This is consistent with findings of recent studies in the U.S. and U.K., whichhave found that the majority of effectively plugged wells are not leaking, but a small number will have someemissions (e.g., Townsend-Small et al. 2016, Kang et al. 2016, Boothroyd et al. 2016).
Tier 1 default emission factors are presented in Table 4.2.4e. All of the presented emission factors are expressedin units of mass of emissions per abandoned well. Available information on abandoned wells do not indicate aclear distinction between abandoned oil and abandoned gas wells regarding practices or emission rates. Thus, all
the EFs are developed from data for both abandoned oil and gas wells. It should be noted that factors provided forabandoned wells have high uncertainty, which is reflected in the uncertainty ranges provided in the table. The EFsof abandoned wells are split into either “plugged” (or, properly decommissioned per regulations) and “unplugged”
well sub-segments. The distinction requires the number of each type of abandoned well (plugged or unplugged).
Existing data on abandoned oil and gas wells as well as practices for their plugging status may be limited and/or
difficult to collect. If insufficient data on plugging practices is available to disaggregate activity data in such away, the default EF for all type wells is to be used. More limited data are available on offshore wells anddisaggregated (i.e. plugged versus unplugged) factors for offshore abandoned wells are developed from onshore
wells data considering that most methane (around 98 percent) from offshore abandoned wells is dissolved inmarine water.
Based on available data, emission factors (and leak frequency) do not vary over the time series per well; according
to the latest research, well integrity failure rate shows no significant trend over time. If failures do exist, they more
likely occur early on in the decommissioned life of a well (Boothroyd et al. 2016). Based on the latest research,gas well emission rates may be higher than oil well emissions rates. However, due to limited data points in thecurrently available data, Tier 1 EFs were not disaggregated into oil-specific and gas-specific factors. In cases
where national circumstances are different from listed above, a country should consider using a Tier 2 or Tier 3
approach.
Activity data for this source are counts of abandoned onshore and offshore wells in each year of the time series,
and for onshore wells, the fraction of wells that are effectively plugged. It may be challenging to compile a total
national count of abandoned wells and to assess whether wells are plugged or unplugged. The compiler should
review national, local, or regional records and consult with industry to develop an estimate. There is also likely
significant variation between post-well closure practices internationally and even within countries.

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TABLE 4.2.4E (NEW)
TIER 1 EMISSION FACTORS FOR ABANDONED OIL WELLS, 1.B.2.A.VII
CO2

CH4
Segment

Abandoned
wells

Abandoned
wells

Value

Uncertainty(% ofvalue)

Leaks

2.0E-05

Onshore: Unpluggeda

Leaks

Onshore: All wells (plugged
and unplugged)a, b

NMVOC

Value

Uncertainty(% ofValue)-87% to+130%NA

8.8E-02-99% to
+150%

Leaks

1.2E-02

Offshore: Pluggedc

Leaks

Offshore: Unpluggedc

Offshore: All wells (plugged
and unplugged)c

N2O

Value

Uncertainty(% ofvalue)

Value

Uncertainty(% ofvalue)

NA

NA

NA

NA

NA

Tonnes CH4/
onshore plugged
abandoned well

NA

NA

NA

NA

NA

NA

Tonnes CH4/
onshoreunplugged
abandoned well

-83% to
+124%

NA

NA

NA

NA

NA

NA

Tonnes CH4/
onshoreabandoned well

3.5E-07-87% to
+130%

NA

NA

NA

NA

NA

NA

Tonnes CH4/
offshore plugged
abandoned wellLeaks

1.8E-03-99% to
+150%

NA

NA

NA

NA

NA

NA

Tonnes CH4/
offshore
unplugged
abandoned wellLeaks

2.4E-04-83% to
+124%

NA

NA

NA

NA

NA

NA

Tonnes CH4/
offshoreabandoned wellSub-segment

EmissionsourceOnshore: Pluggeda

Units ofmeasureNA – Not Applicablea.

From Townsend-Small et al. 2016, which includes data collected from wells across the U.S.

b.

It should be noted that the emission factors for “All wells (plugged and unplugged)” uses Townsend-Small et al. 2016 data set plugging rate of 86.2%.

c.

Developed by using the onshore abandoned wells emission factors in this table, and applying a factor of 0.02 to reflect that most methane from such wells is dissolved in marine water. Factor of
0.02 based on Vielstädte et al. 2015.

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Natural Gas Systems
1 B 2 b i Exploration 8
7FThis segment includes fugitive emissions (including equipment leaks, venting and flaring) from gas field activities
prior to production (e.g., prospecting and exploratory well drilling, well/drill stem testing, and well completions). 9
In this segment, factors are not disaggregated to drilling, testing and servicing operation; EFs are applied to thewhole segment.
8F

In Table 4.2.4f several options for onshore exploration emission factors inclusive of venting, flaring and leaks arepresented. Each technology/practice-specific emission factor is presented in units of tonne per gas well drilled,tonne per active gas well, and in tonnes per million cubic meter gas produced. The count of wells drilled is thought
to best reflect emissions from exploration and if available should be applied. However, the inventory compiler
should assess which activity data are available and which activity data basis best reflects emissions in that segment
for that country.
Emission factors are available for both onshore unconventional and onshore conventional gas exploration.
Offshore exploration emissions data are unavailable, and these emissions are thought to be negligible; therefore,
emission factors are not included for offshore exploration. Here, unconventional gas exploration refers to
exploration where hydraulic fracturing well completion practices are used, and conventional gas exploration refers
to exploration where hydraulic fracturing well completion practices are not used.
The extent of any hydraulic fracturing activities in the country should be assessed. A potential data source for thisassessment is the International Energy Agency’s database for unconventional gas production (International Energy
Agency (IEA) 2018). Unconventional completions (i.e., conducted with hydraulic fracturing) have a different
emissions profile than conventional completions (i.e., conducted without hydraulic fracturing). This is reflected in
the emission factors below. Where possible, the compiler should separate national activity data into conventional
and unconventional and apply the relevant emission factors. If only total gas wells or total gas production data are
available, the compiler should develop an estimate of the annual split between conventional and unconventional
wells or conventional and unconventional production in the country to develop the activity data.
Unconventional factors are to be applied to the unconventional activity data basis. Where wells drilled arecompleted with hydraulic fracturing and flaring and gas recovery is not practiced, or where the extent of flaring or
recovery practices is unknown, the first set of factors (“Unconventional gas exploration without flaring or gas
capture”) should be used and applied to the relevant activity data (i.e. unconventional wells drilled, total
unconventional well population, or unconventional production). Where wells drilled are completed with hydraulicfracturing and flaring and gas recovery is used, the fraction of the relevant activity data that uses flaring and/or gas
recovery should be determined. The second set of factors (“Unconventional gas exploration with flaring or gas
capture”) is used for that fraction, while the first set of factors is applied to the wells or production that is not using
flaring or recovery. Conventional factors (“Conventional Gas exploration”) are to be applied to the conventional
activity data basis. As technologies and practices change over time, it is possible that one EF will be used in someyears and another in other years. A compiler should assess the time frame over which changes took place, andconsider linear interpolation or other techniques to incorporate the trend from one emission factor to another over
the time series. For each segment/sub-segment listed in Table 4.2.4f below that is occurring in the country,
compilers must calculate emissions, and sum them according to Equation 4.2.13. It is recognized that not all
countries will have all segments and sub-segments occurring. Factors listed in Table 4.2.4f apply to onshore
exploration. Emissions data are unavailable for offshore exploration.
Factors presented are inclusive of venting, flaring, and leak emissions. For cases where country-specific data are
available for a subcomponent of the factor (e.g. venting and flaring emissions), disaggregated Tier 1 EF that could
be applied to estimate the remaining emission types are available—see Annex 4A.2 for information (including
examples) on how to calculate disaggregated emissions.
Definitions for oil wells versus gas wells can vary from country to country and organization to organization. The
Tier 1 EFs in the table below were developed from emissions occurring in U.S. basins identified as having
predominantly gas production. Emission factors were developed using data on exploration emissions (drilling,
testing, and completions) for wells with a gas oil ratio of >17,000 cubic meters gas to cubic meters oil. If national
criteria defines oil and gas wells, follow the national criteria or national documentation to make the distinction.
What is most important is that all emissions are transparently allocated to either oil or gas systems, withoutomission.
8 Some countries expressed several technical concerns with the validity and reliability of the newly added equations and default

emission factors for fugitive emissions from gas exploration. The countries expressed that the newly added guidance ispremature and needs further work before it can be used.

9 Refracturing and redrilling emissions are to be included in 1.B.2.a.ii (Production and Upgrading).

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For each sub-segment listed in Table 4.2.4f below that is occurring in the country, compilers must calculate
emissions, and sum them according to Equation 4.2.13. It is recognized that not all countries will have all subsegments (i.e. technologies or practices) occurring. Factors listed in Table 4.2.4f apply to onshore exploration.
Emissions data are unavailable for offshore exploration.
EQUATION 4.2.13 (NEW)GENERAL EQUATION FOR ESTIMATING FUGITIVE EMISSIONS FROM EXPLORATION

Eexploration = Aunconventional gas without flaring or recovery • EFunconventional gas without flaring or recovery+ Aunconventional gas with flaring or recovery • EFunconventional gas with flaring or recovery+ Aconventional gas • EFconventional gas
Where:
Eexploration= Total amount of GHG gas emitted due to all relevant natural gas
exploration activities

Aunconventional gas without flaring or recovery= Activity data on exploration of unconventional natural gas without
flaring or recovery

EFunconventional gas without flaring or recovery = Emission factor for exploration of unconventional natural gas without
flaring or recovery
Aunconventional gas with flaring or recovery= Activity data on exploration of unconventional natural gas withflaring or recovery

EFunconventional gas with flaring or recovery= Emission factor for exploration of unconventional natural gas withflaring or recovery

Aconventional gas= Activity data on exploration of conventional natural gas

EFconventional gas= Emission factor for exploration of conventional natural gas

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Volume 2: Energy

TABLE 4.2.4F (NEW)
TIER 1 EMISSION FACTORS FOR NATURAL GAS EXPLORATION SEGMENT, 1.B.2.B.I
CO2CH4Segment

Gas
Exploration

Sub-segment

Onshoreunconventional
gas exploration
without flaringor gas capturea,

EmissionsourceAll

Value

Uncertainty(% ofvalue)

20.1

±20%

4.35

±20%

NMVOC

Value

Uncertainty(% ofValue)

1.50

±20%

0.32

±20%

N2O

Value

Uncertainty(% ofvalue)

Value

Uncertainty(% ofvalue)

3.01-12.5%
to +800%

NA

NA

Tonnes/unconventional onshore gas
wells drilled in a year, without
flaring or recovery

0.65-12.5%
to +800%

NA

Tonnes/total unconventional onshore
gas well population where
exploration occurs without flaring or
recoveryNA

Tonnes/million cubic meters onshore
unconventional onshore gas
production where exploration occurs
without flaring or recovery

NA

d

Gas
Exploration

Onshoreunconventional
gas exploration
with flaring or
gas captureb, d

All

2.52

±20%

0.19

±20%

0.38

-12.5%
to +800%

1.30

±20%

47.0

±20%

0.19

-12.5%
3.4E-04
to +800%-10% to+1000%

Tonnes/unconventional onshore gas
wells drilled in a year, with flaring or
recovery

0.0071-12.5%
1.4E-05
to +800%-10% to+1000%

Tonnes/total unconventional onshore
gas well population where
exploration occurs with flaring or
recovery

0.013-12.5%
2.3E-05
to +800%-10% to+1000%

Tonnes/million cubic meters onshore
unconventional gas production
where exploration occurs withflaring or recovery

0.05

0.08

4.66

Units of measure

±20%

±20%

1.93

3.16

±20%

±20%

NA

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Chapter 4: Fugitive Emissions

TABLE 4.2.4F (NEW) (CONTINUED)TIER 1 EMISSION FACTORS FOR NATURAL GAS EXPLORATION SEGMENT, 1.B.2.B.I
CO2CH4Segment

Gas
Exploration

Sub-segment

OnshoreconventionalGas
explorationc

EmissionsourceAll

Value

Uncertainty(% ofvalue)

5.78

NMVOC

Value

Uncertainty(% ofValue)

Value

Uncertainty(% ofvalue)

±20%

4.72

±20%

0.03

±20%

0.03

0.06

±20%

0.05

N2O
Units of measure

Value

Uncertainty(% ofvalue)

0.87-12.5%
3.4E-05
to +800%-10% to+1000%

Tonnes/onshore conventional gas
wells drilled in a year±20%

5.2E-03-12.5%
2.2E-07
to +800%-10% to+1000%

Tonnes/total conventional onshore
gas well population±20%

8.6E-03-12.5%
3.6E-07
to +800%-10% to+1000%

Tonnes/million cubic meters onshore
conventional gas production

NA – Not Applicablea.

Emission factors for CH4 and CO2 developed from data reported to the U.S. Greenhouse Gas Reporting Program (GHGRP) (United States Environmental Protection Agency (EPA) 2017) for
unconventional completions and well testing, and (Radian International LLC 1999), for drilling emissions, as applied in the 2018 U.S. GHG Inventory (United States Environmental Protection Agency(EPA) 2018a). Factor is the average of 2006-2010 calculated implied emission factors for emissions from well drilling, well testing, and from well completions with hydraulic fracturing that do not flare
or use gas capture. The time period of 2006-2010 was selected as it represents a time when hydraulic fracturing is occurring, but before state or federal regulations were in place to control gas emissions.
NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table.

b.

Emission factors for CH4 and CO2 developed from data reported to the GHGRP (United States Environmental Protection Agency (EPA) 2017) for unconventional completions and well testing, and from
(Radian International LLC 1999) for drilling emissions, as applied in the 2018 U.S. GHG Inventory. Factor is the average of 2013-2016 calculated implied emission factors for emissions from welldrilling, well testing, and from well completions with hydraulic fracturing that flare or use gas capture. The time period of 2013-2016 was selected as it represents a time when hydraulic fracturing isoccurring and state or federal regulations were in place to control gas emissions. NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC
Guidelines, which was then applied to corresponding CH4 values in this table. N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to CO2 from 2006 IPCC Guidelines,
which was then applied to corresponding CO2 values in this table.

c.

Emission factors for CH4 and CO2 developed from GHGRP (United States Environmental Protection Agency (EPA) 2017) for conventional completions and well testing, and (Radian International LLC
1999), for drilling emissions, as applied in the 2018 U.S. GHG Inventory. Factor is the average of 2006-2016 calculated implied emission factors for emissions from well drilling and from conventional
completions. The time period of 2006-2016 was selected to cover the time frame of the other exploration factors. NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of
NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table. N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to
CO2 from 2006 IPCC Guidelines, which was then applied to corresponding CO2 values in this table.

d.

Unconventional gas exploration refers to exploration that includes well completions with hydraulic fracturing. Conventional gas exploration emission factors should be applied where hydraulic fracturing
well completion practices are not used.

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Volume 2: Energy

1 B 2 b ii Production and Gathering
This segment includes fugitive emissions (including leaks, venting and flaring) from the gas wellhead through tothe inlet of gas processing plants, or, where processing is not required, to the tie-in points on gas transmission
systems. In the production stage, wells are used to withdraw raw gas from underground formations. Emissions
arise from the wells themselves (e.g., as wellhead leaks and from well workovers and refractures), and well-siteequipment such as pneumatic controllers, dehydrators and separators. Gathering and boosting emission sources
are included within the production sector. The gathering and boosting sources include gathering and boostingstations (with multiple emission sources on site, such as compressors, pneumatic controllers and tanks) andgathering pipelines. The gathering and boosting stations receive natural gas from production sites and transfer it,
via gathering pipelines, to processing facilities or transmission pipelines.
The Table 4.2.4g below presents factors for onshore gas production, onshore coal bed methane production,gathering systems, and offshore gas production 10.
9F

Countries with onshore gas production should apply a factor for onshore production and the factor for gatheringto the quantity of onshore gas produced in each year.
Factors for onshore gas production (other than coal bed methane) are presented both in units of tonne per active
gas well, and in tonnes per million cubic meter gas produced. The count of wells is thought to best reflect emissions
from gas production, and if complete and accurate well count data are available, they should be applied. However,
the inventory compiler should assess which activity data are available and which activity data basis best reflects
emissions in that segment for that country. The types of technologies and practices in use in the country should beassessed, including extent of lower-emitting liquids unloading practices for any liquids unloading occurring, andextent of leak detection and repair (LDAR) practices. Where this information is unknown, or where there is limited
use of lower-emitting technologies (i.e., more than 60 percent of any liquids unloading is conducted without
venting or with lower-emitting plunger lifts or LDAR is not used extensively), the first set of emission factors(“Most activities occurring with higher-emitting technologies and practice”) for onshore gas production should be
used. Where lower-emitting technologies are used extensively, the second set of emission factors (“most activities
occurring with lower-emitting technologies and practices”) for gas production should be used. As technologies
and practices change over time, it is possible that one EF will be used in some years and another in other years. A
compiler should assess the time frame over which changes took place, and consider linear interpolation or othertechniques to incorporate the trend from one emission factor to another over the time series.
The emission factors for onshore production were developed from data sets that included a mix of production fromwells in conventional formations and wells in unconventional formations and are considered to be applicable toboth. However, if data on coal bed methane production are available, the factor for coal bed methane production
may be applied to the portion of gas production that is from coal bed methane.
Countries with offshore gas production should apply a factor for offshore gas production. If no data are available
to estimate the share of gas production that occurs offshore, the EF for onshore production should be applied tothe total quantity of gas production.
Factors presented are inclusive of venting, flaring, and leak emissions. For cases where country-specific data are
available for a subcomponent for the factor (e.g. venting and flaring emissions), disaggregated Tier 1 EF that could
be applied to estimate the remaining emission types are available—see Annex 4A.2 for information (including
examples) on how to calculate disaggregated emissions.
Definitions for gas wells versus oil wells can vary from country to country and organization to organization. The
onshore production (other than coal bed methane) Tier 1 EFs in the table below were developed from emissions
occurring in U.S. basins identified as having predominantly gas production. Emission factors were developed using
data on production emissions for wells with a gas oil ratio of >17,000 cubic meters gas to cubic meters oil. If
national criteria defines gas and oil wells, follow the national criteria or national documentation to make thedistinction. What is most important is that all emissions are transparently allocated to either gas or oil systems,
without omission.
For each sub-segment listed in Table 4.2.4g below that is occurring in the country, compilers must calculate
emissions, and sum them according to Equation 4.2.14. It is recognized that not all countries will have all segments
and sub-segments occurring.

10 While the emission factor options are meant to cover technologies and practices that are common in the oil and gas industries

internationally, technologies and practices can vary significantly between regions and over time. A country should
periodically assess changes in technologies and practices, and changes in available emissions data, and consider updating
estimates using a Tier 2 approach, per good practice.

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Chapter 4: Fugitive Emissions

EQUATION 4.2.14 (NEW)GENERAL EQUATION FOR ESTIMATING FUGITIVE EMISSIONS FROM GAS PRODUCTION AND
GATHERING

E production = Aonshore gas production • EFonshore gas production+ Aonshore coal bed production • EFonshore coal bed production+ Agathering • EFgathering+ Aoffshore gas production • EFoffshore gas production
Where:
Eproduction= Total amount of GHG gas emitted due to all relevant natural gas production
activities

Aonshore gas production= Volume of onshore gas produced/active gas wellEFonshore gas production= Emission factor for onshore gas produced

Aonshore coal bed production= Volume of onshore coal bed methane produced

EFonshore coal bed production= Emission factor for onshore coal bed methane production

Agathering= Volume of onshore gas produced

EFgathering= Emission factor for gathering of natural gas produced

Aoffshore gas production= Volume of offshore gas produced

EFoffshore gas production= Emission factor for offshore gas produced

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Volume 2: Energy

TABLE 4.2.4G (NEW)
TIER 1 EMISSION FACTORS FOR NATURAL GAS PRODUCTION SEGMENT, 1.B.2.B.II
CO2

CH4Segment

Gas
Production

Onshore: Most
activities
occurring withhigher-emitting
technologies andpracticesa

EmissionsourceValue

Uncertainty(% ofvalue)

4.09

Value

Uncertainty(% ofValue)

±20%

1.45

7.07

±20%

2.54

N2O

Value

Uncertainty(% ofvalue)

Value

Uncertainty(% ofvalue)±20%

0.98-75% to+250%

2.5E-05-10% to+1000%

Tonnes/million cubic
meters onshore gas
production

2.51

±20%

1.70

-75% to+250%

4.3E-05-10% to+1000%

Tonnes/active gas
well

±20%

3.60

±20%

0.61

-75% to+250%

6.1E-05-10% to+1000%

Tonnes/million cubic
meters onshore gas
production

4.37

±20%

6.21

±20%

1.05

-75% to+250%

1.1E-04-10% to+1000%

Tonnes per active gas
well

All

Units of measure

Onshore: Most
activities
occurring withlower-emitting
technologies andpracticesb

All

Gas
Production

Onshore Coal
Bed Methanec

All

1.95

±20%

19.57

±20%

0.47

-75% to+250%

3.3E-04-10% to+1000%

Tonnes/million cubic
meters onshore gas
production

Gas
Production

Gatheringd

All

3.20

±10%

0.35

±10%

0.77

-75% to+250%

6.0E-06-10% to+1000%

Tonnes/million cubic
meters onshore gas
production

Gas
Production

Offshoree

All

2.94

±20%

4.80

±20%

0.70

-75% to+250%

8.2E-05-10% to+1000%

Tonnes/million cubic
meters offshore gas
production

Gas
Production

4.70

Sub-segment

NMVOC

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Chapter 4: Fugitive Emissions

TABLE 4.2.4G (NEW) (CONTINUED)TIER 1 EMISSION FACTORS FOR NATURAL GAS PRODUCTION SEGMENT, 1.B.2.B.II
a.

Emission factors for CH4 and CO2 developed from EPA/GRI, Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996), and data reported to the U.S. Greenhouse Gas
Reporting Program (GHGRP) (United States Environmental Protection Agency (EPA) 2017), as applied in the 2018 U.S. GHG Inventory (United States Environmental Protection Agency (EPA)
2018a) to calculate emissions for the year 1992 (when EPA/GRI study was conducted). Examples of higher-emitting technologies and practices include venting for liquids unloading without
plunger lifts, unconventional workovers that vent, and use of high-bleed pneumatic controllers. NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to
CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table. N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to CO2
from 2006 IPCC Guidelines, which was then applied to corresponding CO2 values in this table.

b.

Emission factors for CH4 and CO2 developed from EPA/GRI, Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996), and data reported to the GHGRP, as applied in the2018 U.S. GHG Inventory to calculate emissions for the year 2016 (the most recent year of GHGRP (United States Environmental Protection Agency (EPA) 2017) data availability). Examples oflower-emitting technologies and practices include venting for liquids unloading with plunger lifts, unconventional workovers using reduced emission completion technologies, and low-bleed
pneumatic controllers. NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied tocorresponding CH4 values in this table. N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to CO2 from 2006 IPCC Guidelines, which was then applied tocorresponding CO2 values in this table.

c.

Emission factors for CH4 and CO2 developed from data reported to the Australian National Greenhouse and Energy Reporting program (NGER) (Australian Government Clean Energy Regulator2017), as applied in Australian National Inventory (Australian Government 2018). The value for CH4 is the average of emissions for the years 2014-2017, and the value for CO2 is the average ofemissions for the years 2016-17. NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied tocorresponding CH4 values in this table. N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to CO2 from 2006 IPCC Guidelines, which was then applied tocorresponding CO2 values in this table.

d.

Emission factors for CH4 and CO2 developed from EPA/GRI, Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996), and Marchese et al. 2015, as applied in the 2018
U.S. GHG Inventory (United States Environmental Protection Agency (EPA) 2018a) to calculate emissions for the year 2012 (when the measurements used in Marchese were conducted).
NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in thistable. N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to CO2 from 2006 IPCC Guidelines, which was then applied to corresponding CO2 values in thistable.

e.

Emission factors for CH4 and CO2 developed from U.S. Bureau of Ocean Energy Management’s (BOEM) Gulf Offshore Activity Data System (GOADS) (United States Bureau of Ocean Energy
Management (BOEM) 2017), as applied in the 2018 U.S. GHG Inventory, to estimate emissions for 2011 (the year of the BOEM survey), with U.S. GHG Inventory flaring data adjusted to use
GOADS data directly and separation of CO2 from flaring between oil and gas based on relative CH4 emissions. NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratioof NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table. N2O values were developed from 2006 IPCC Guidelines by calculating a ratioof N2O to CO2 from 2006 IPCC Guidelines, which was then applied to corresponding CO2 values in this table.

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Volume 2: Energy

1 B 2 b iii Processing
This segment includes fugitive emissions (including leaks, venting and flaring) from gas processing facilities. In
this stage, natural gas liquids (NGLs) and various other constituents (e.g. sulphur) from the raw gas are removed,
resulting in “pipeline quality” gas, which is injected into the transmission system. Emission sources include
compressors, equipment leaks, pneumatic controllers, uncombusted gas from engines and flaring, and CO2 fromflaring and sour gas removal. In the Table 4.2.4h below, several options for emission factors are presented. For
some emission factors, the factors are presented both in units of tonne per million cubic meter gas processed, andin tonnes per million cubic meter gas produced. The volume of gas processed is thought to best reflect emissions
from gas processing, and if gas processing data are available, they should be applied. However, the inventory
compiler should assess which activity data are available and which activity data basis best reflects emissions inthat segment for that country. The extent of any LDAR programs, and the use of dry seals in centrifugal
compressors in the country should be assessed. Where this information is unknown, or where there are limited orno LDAR programs or less than 50 percent of centrifugal compressors have dry seals, the “without LDAR, andless than 50 percent of centrifugal compressors have dry seal” emission factors for Natural Gas Processing should
be used. Where leak detection and repair programs are in use and around 50 percent of more of centrifugal
compressors have dry seals, use the “Extensive LDAR, and around 50 percent or more of centrifugal compressors
have dry seals” emission factors for Natural Gas Processing. As technologies and practices change over time, it ispossible that one EF will be used in some years and another in other years. A compiler should assess the timeframe over which changes took place, and consider linear interpolation or other techniques to incorporate the trend
from one emission factor to another over the time series. Where sour gas (or “acid gas”) removal is occurring, thefactor for that source should also be applied to the portion of gas processed with sour gas removal, and added tothe overall gas processing total.
Factors presented are inclusive of venting, flaring, and leak emissions. Information for disaggregating the Tier 1
EFs for processing into leak, vent, and flare emissions is available in Annex 4A.2.
Town gas originates from outgassing of hard coal under air exclusion in retort furnace or chamber kilns. A
methodology for this source is not currently available. If a method should become available, emissions from theseprocesses could be reported under 1.B.1.c.iv Gasification Transformation.
For each segment/sub-segment listed in Table 4.2.4h below that is occurring in the country, compilers must
calculate emissions, and sum them according to Equation 4.2.15. It is recognized that not all countries will haveall segments and sub-segments occurring. The emissions from gas processing (Eprocessing) are computed bymultiplying the appropriate emission factor from Table 4.2.4h by the amount of gas processed (units of millionsof cubic meter of gas). If sour gas is removed, this emission should be added to the overall processing emissions,where the emissions from sour gas removal is computed as the product of the emission factor for sour gas removalfrom Table 4.2.4h and the amount of sour gas that is processed (in units of millions of cubic meters of sour gas).
The compiler should attempt to determine the fraction of the gas processed that is sour gas using nationallyavailable statistics or industry information on the characteristics of processing plants. If no data is available, it isgood practice to assume the fraction, for example by considering the study of Burgers et al. 2011 or comparing to
adjacent countries. If none of the proposals works, a value of 32 percent sour gas 11 can be applied.
10F

EQUATION 4.2.15 (NEW)GENERAL EQUATION FOR ESTIMATING FUGITIVE EMISSIONS FROM GAS PROCESSING

E processing = Agas processed • EFLDAR or no LDAR
+ Asour gas processed • EFsour gas removal
Where:
Eprocessing= Total amount of GHG gas emitted due to all relevant natural gas processing
activities

Agas processed= Volume of natural gas processed or produced

EFLDAR or no LDAR

= Emission factor for gas processed with or without LDAR programs

Asour gas processed= Volume of sour gas processed

EFsour gas removal= Emission factor for sour gas processing

11 Developed as an unweighted mean value from Germany (40%) and Austria (25%), from German Government 2018 andAustrian Government 2018 NIRs.

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Chapter 4: Figitive Emissions

TABLE 4.2.4H (NEW)
TIER 1 EMISSION FACTORS FOR GAS PROCESSING SEGMENT, 1.B.2.B.III
CO2

CH4
Segment

Processing

Processing

Processing

Sub-segment

Without LDAR, orwith limited LDAR,or less than 50% of
centrifugal
compressors havedry sealsa

EmissionsourceValue

Uncertainty(% ofvalue)

1.83

Value

Uncertainty(% ofValue)

±10%

0.12

1.65

±10%

0.75

NMVOC

Value

Uncertainty(% ofvalue)

±10%

0.15

0.11

±10%

±10%

9.45

0.57

±10%

0.1

±100%

Units of measure

Value

Uncertainty(% ofvalue)-75% to+250%

1.3E-06-10% to+1000%

Tonnes/million cubic meters gas
processed

0.13-75% to+250%

1.2E-06-10% to+1000%

Tonnes/million cubic meters gas
produced

±10%

0.06

-75% to+250%

1.0E-04-10% to+1000%

Tonnes/million cubic meters gas
processed

7.21

±10%

0.05

-75% to+250%

7.9E-05-10% to+1000%

Tonnes/million cubic meters gas
produced

66.6

±100%

0.1

-75% to+250%

5.4E-05-10% to+1000%

Tonnes/million cubic meters sour
gas processedAll

Extensive LDAR,
and around 50% ormore of centrifugal
compressors havedry sealsb

All

Sour gas (acid gas
removal)c

All

N2O

a.

Emission factors for CH4 and CO2 developed from EPA/GRI, Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996), as applied in the 2018 U.S. GHG Inventory to calculate
emissions for the year 1992 (when EPA/GRI study was conducted). Emissions from acid gas removal were deducted prior to EF development. NMVOC values were developed from 2006 IPCC
Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table. N2O values were developed from 2006 IPCC
Guidelines by calculating a ratio of N2O to CO2 from 2006 IPCC Guidelines, which was then applied to corresponding CO2 values in this table.

b.

Emission factors for CH4 and CO2 developed from data reported to the U.S. Greenhouse Gas Reporting Program (GHGRP) (United States Environmental Protection Agency (EPA) 2017), and from
EPA/GRI, Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996), as applied in the 2018 U.S. GHG Inventory to calculate emissions for the year 2016 (most recent year of
GHGRP data availability). Emissions from acid gas removal were deducted prior to EF development. NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to
CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table. N2O values were developed from 2006 IPCC Guidelines by calculating a ratio of N2O to CO2 from2006 IPCC Guidelines, which was then applied to corresponding CO2 values in this table.

c.

Emission factors from the 2006 IPCC Guidelines, Table 4.2.4.

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1 B 2 b iv Transmission and Storage
This segment includes fugitive emissions (including leaks, venting and flaring) from systems used to transport
processed natural gas to market (i.e., to industrial consumers and natural gas distribution systems), including
natural gas storage systems. Natural gas transmission involves high pressure, large diameter pipelines that transport
gas long distances from field production and processing areas to distribution systems or large volume customers
such as power plants or chemical plants. Compressor station facilities are used to move the gas throughout thetransmission system. Emissions from natural gas liquids extraction plants on gas transmission systems should bereported as part of natural gas processing (Sector 1.B.2.b.iii). Fugitive emissions related to the transmission ofnatural gas liquids should be reported under 1.B.2.b.iv. Emissions sources include compressors, pneumatic
controllers, storage wells, leaks and venting from transmission lines, and equipment leaks from compressor
stations. This source also includes Liquified Natural Gas (LNG) stations and import and export terminals; further
details on the LNG sector can be found in Liquified Natural Gas (LNG) Operations: Consistent Methodology for
estimating Greenhouse Gas Emissions (American Petroleum Institute (API) 2015). In Table 4.2.4i below, several
options for emission factors are presented.
Factors for transmission are presented both in units of tonne per million cubic meter gas consumption, and in
tonnes per km transmission pipeline. The length of transmission pipeline is thought to best reflect emissions fromtransmission, and if pipeline data are available, they should be applied. However, the inventory compiler should
assess which activity data are available and which activity data basis best reflects emissions in that segment forthat country. The extent of any LDAR programs, and the use of dry seals in centrifugal compressors in the country
should be assessed. Where this information is unknown, or where there are limited or no LDAR programs or lessthan 50 percent of centrifugal compressors have dry seals, the “Limited LDAR or less than 50 percent of centrifugal
compressors have dry seals” emission factors for transmission should be used. Where leak detection and repair
programs are in use and around 50 percent of more of centrifugal compressors have dry seals, use the “Extensive
LDAR, and around 50 percent or more of centrifugal compressors have dry seals” emission factors fortransmission. Factors for gas storage are presented both in units of tonne per million cubic meter gas consumption,
as this is the most commonly available data point relevant to gas storage. If other activity data are available (suchas quantity of gas stored or number of storage stations), the compiler could determine whether a Tier 2 or 3 method
incorporating the storage data might better represent emissions. For gas storage, the extent of any leak detection
and repair programs should be assessed. Where this information is unknown, or LDAR is not extensively practiced,
the first set of emission factors for gas storage (“Limited LDAR or most activities occurring with higher-emitting
technologies and practices”) should be used. Where there are extensive LDAR programs, the second set ofemission factors for gas storage (“Extensive LDAR and most activities occurring with lower-emitting technologies
and practices”) should be used.
Where LNG imports and exports or storage occur, the number of stations should be determined, and the emission
factors for LNG should be used. See (American Petroleum Institute (API) 2015) for further elaboration of emission
estimation methods for the LNG sector (e.g. Tiers 2 and 3).
As technologies and practices change over time, it is possible that one EF will be used in some years and anotherin other years. A compiler should assess the time frame over which changes took place, and consider linear
interpolation or other techniques to incorporate the trend from one emission factor to another over the time series.
Factors presented are inclusive of venting, flaring, and leak emissions. Information for disaggregating the Tier 1
EF for transmission and storage into leak, vent, and flare emissions is available in Annex 4A.2.
For each sub-segment listed in Table 4.2.4i below that is occurring in the country, compilers must calculate
emissions, and sum them according to Equation 4.2.16. It is recognized that not all countries will have all segments
and sub-segments occurring.

4.74

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Chapter 4: Fugitive Emissions

EQUATION 4.2.16 (NEW)GENERAL EQUATION FOR ESTIMATING FUGITIVE EMISSIONS FROM GAS TRANSMISSION AND
STORAGE

Etransmission and storage = Atransmission • EFtransmission+ Astorage • EFstorage+ ALNG import / export • EFLNG import / export+ ALNG storage • EFLNG storage
Where:
Etransmissin and storage= Total amount of GHG gas emitted due to all relevant natural gas transmission andstorage activities

Atransmission= Volume of natural gas consumed/Length of transmission pipeline

EFtransmission= Emission factor for gas transmitted

Astorage= Volume of natural gas consumed

EFstorage= Emission factor for gas consumed

ALNG import/export= Number of export/import LNG stations

EFLNG import/export= Emission factor for LNG imports and exports

ALNG storage= Number of storage LNG stations

EFLNG storage= Emission factor for LNG storage

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TABLE 4.2.4I (NEW)
TIER 1 EMISSION FACTORS FOR GAS TRANSMISSION AND STORAGE SEGMENT, 1.B.2.B.IV
CO2

CH4
Segment

4.76

Sub-segment

EmissionsourceValue

Uncertainty(% ofvalue)

3.36

Value

Uncertainty(% ofValue)-20% to
+30%

0.23

4.10

-20% to
+30%

1.29

NMVOC

N2O

Value

Uncertainty(% ofvalue)

Value

Uncertainty(% ofvalue)-20% to+30%

0.05-100% to
+250%

NA

NA

Tonnes/ million cubic
meter gas
consumption

0.28-20% to+30%

0.06-100% to
+250%

NA

NA

Tonnes/ kilometre
pipeline-20% to+30%

0.15-20% to+30%

0.02-100% to
+250%

NA

NA

Tonnes/ million cubic
meter gas
consumption

2.08-20% to+30%

0.25-20% to+30%

0.03-100% to
+250%

NA

NA

Tonnes/ kilometre
pipeline

Units of measure

Gas
Transmission andStorageTransmission: Limited
LDAR or less than 50% of
centrifugal compressors havedry sealsa

Gas
Transmission andStorageTransmission: Extensive
LDAR, and around 50% ormore of centrifugal
compressors have dry sealsb

All

Gas
Transmission andStorage

Storage: Limited LDAR or
most activities occurring withhigher- emitting technologies
and practicesc

All

0.67

-20% to+30%

0.06-20% to+30%

0.0094-20% to
+500%

NA

NA

Tonnes/ million cubic
meter gas
consumption

Gas
Transmission andStorage

Storage: Extensive LDAR
and lower-emitting
technologies and practicesd

All

0.29

-20% to+30%

0.04-20% to+30%

0.0040-20% to
+500%

NA

NA

Tonnes/ million cubicgas consumption

Gas
Transmission andStorage

LNG: Import/Exporte

All

1,660

-20% to+30%

14,687-20% to
+30%

NA

NA

NA

NA

Tonnes/ stationAll2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 4: Fugitive Emissions

TABLE 4.2.4I (NEW) (CONTINUED)TIER 1 EMISSION FACTORS FOR GAS TRANSMISSION AND STORAGE SEGMENT, 1.B.2.B.IV
CO2

CH4
Segment

Gas Transmission and Storage

Sub-segment

LNG: Storagef

EmissionsourceAll

Value

Uncertainty(% ofvalue)

22-20% to
+30%

Value

Uncertainty(% ofValue)

277-20% to
+30%

NMVOC

N2O

Value

Uncertainty(% ofvalue)

Value

Uncertainty(% ofvalue)

NA

NA

NA

NA

Units of measure

Tonnes/ station

NA – Not Applicablea.

Emission factors for CH4 and CO2 developed from EPA/GRI, Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996), and the Greenhouse Gas Reporting Program(GHGRP) (United States Environmental Protection Agency (EPA) 2017), as applied in the 2018 U.S. GHG Inventory (United States Environmental Protection Agency (EPA) 2018a) to
calculate emissions for the year 1992 (when EPA/GRI study was conducted, and when LDAR practices were limited, and most centrifugal compressors had wet seals). NMVOC values weredeveloped from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table.

b.

Emission factors for CH4 and CO2 developed from data reported to the GHGRP (United States Environmental Protection Agency (EPA) 2017), , and from EPA/GRI, Methane Emissions fromthe Natural Gas Industry (Gas Research Institute 1996), as applied in the 2018 U.S. GHG Inventory to calculate emissions for the year 2016 (most recent year of GHGRP data availability, andwhen LDAR practices were prevalent and most centrifugal compressors had dry seals). NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4
from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table.

c.

Emission factors for CH4 and CO2 developed from EPA/GRI, Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996), and the GHGRP (United States Environmental
Protection Agency (EPA) 2017), as applied in the 2018 U.S. GHG Inventory to calculate emissions for the year 1992 (when EPA/GRI study was conducted, and when LDAR practices werelimited). NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4
values in this table.

d.

Emission factors for CH4 and CO2 developed from data reported to the GHGRP (United States Environmental Protection Agency (EPA) 2017), Zimmerle et al. 2015, and from EPA/GRI,
Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996), as applied in the 2018 U.S. GHG Inventory to calculate emissions for the year 2016 (most recent year of
GHGRP data availability, when LDAR practices were prevalent). NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC
Guidelines, which was then applied to corresponding CH4 values in this table.

e.

Emission factors for CH4 and CO2 developed from GHGRP (United States Environmental Protection Agency (EPA) 2017) data for years 2015 and 2016 (most recent years of data availability).
LNG terminal sizes are found in Table 5 of United States Environmental Protection Agency (EPA 2018b) https://www.epa.gov/sites/production/files/201810/documents/ghgi_2018stakeholders_segment.pdf

f.

Emission factors for CH4 and CO2 developed from GHGRP (United States Environmental Protection Agency (EPA) 2017) data for years 2015 and 2016 (most recent years of data availability).

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1 B 2 b v Distribution
This segment includes fugitive emissions (including leaks, venting, and any flaring) from the distribution of naturalgas. Distribution pipelines take the high-pressure gas from the transmission system at “city gate” stations, reduce
the pressure and distribute the gas through primarily underground mains and service lines to individual end users.
Emission sources include leaks from pipelines, metering and regulating stations, meters and short-term surface
storage.
For natural gas distribution, the factors are presented both in units of tonne per million cubic meter gas
consumption, and in tonnes per km pipeline. The length of distribution pipeline is thought to best reflect emissions
from distribution, and if pipeline data are available, they should be applied. However, the inventory compiler
should assess which activity data are available and which activity data basis best reflects emissions in that segment
for that country. The mix of pipeline materials and extent of any leak detection and repair programs in the country
should be assessed. Where this information is unknown, or where distribution pipelines are less than 50 percent
plastic, or where there are limited or no leak detection or repair programs, the first set of emission factors for gas
distribution should be used (“Less than 50 percent plastic pipelines, or limited or no leak detection and repair
programs”). Where greater than 50 percent of distribution pipelines are plastic, and leak detection and repair
programs are in use, use the second set of emission factors for gas distribution (“Greater than 50 percent plastic
pipelines, and leak detection and repair programs are in use”). As technologies and practices change over time, it
is possible that one EF will be used in some years and another in other years. A compiler should assess the timeframe over which changes took place, and consider linear interpolation or other techniques to incorporate the trend
from one emission factor to another over the time series. Distribution system methane emissions from biogas areto be calculated here, and can be calculated using the provided emission factors, provided that methane content of
the distributed gas is not expected to significantly differ from distributed natural gas. Fugitive emissions of carbon
dioxide from biogas distribution are considered to be biogenic and are not reported under 1.B.2.
Short term surface storage means a man-made above-ground storage facilities, for storage of medium-sized
quantities of natural gas, help meet and balance rapid fluctuations in demand. Spherical and pipe storage tanks,and other types of low-pressure containers, are used for this purpose.
The composition of town gas differs from natural gas (see explanation in introduction to Chapter 4.2) and therefore
emissions are estimated for town gas using distinct emission factors.
For each category/subcategory listed in Table 4.2.4j below that is occurring in the country, compilers must
calculate emissions, and sum them according to Equation 4.2.17. It is recognized that not all countries will haveall categories and subcategories occurring.
EQUATION 4.2.17 (NEW)GENERAL EQUATION FOR ESTIMATING FUGITIVE EMISSIONS FROM GAS DISTRIBUTION

Edistribution = Agas distribution • EFgas distribution+ Asurface storage • EFsurface storage+ Adistribution of town gas • EFdistribution of town gas
Where:

4.78

Edistribution= Total amount of GHG gas emitted due to all relevant natural gas distribution
activities

Agas distribution= Volume of natural gas consumed or length of distribution pipeline

EFgas distribution= Emission factor for gas distribution

Asurface storage= Volume of natural gas stored (in surface storage) or consumed

EFsurface storage= Emission factor for surface storage

Adistribution of town gas= Length of town gas distribution pipeline

EFdistribution of town gas= Emission factor for town gas distribution

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Chapter 4: Fugitive Emissions

TABLE 4.2.4J (NEW)
TIER 1 EMISSION FACTORS FOR DISTRIBUTION SEGMENT, 1.B.2.B.V
CO2CH4Segment

Gas
Distribution

Gas
Distribution

Sub-segment

Less than 50% plastic
pipelines, or limited or noleak detection and repair
programsa

Greater than 50% plastic
pipelines, and leak detection
and repair programs are in
useb

Gas
Distribution

Short term surface storagec

Gas
Distribution

Town gas distribution: Alld

EmissionsourceValue

Uncertainty(% ofvalue)

2.92

Value

Uncertainty(% ofValue)-20% to
+120%

0.09

1.17

-20% to
+120%

0.62

NMVOC

N2O

Value

Uncertainty(% ofvalue)

Value

Uncertainty(% ofvalue)-20% to
+120%

0.041

-20% to
+500%

NA

NA

Tonnes/ million cubic
meter gas
consumption

0.03-20% to
+120%

0.016

-20% to
+500%

NA

NA

Tonnes/kilometre ofpipeline-20% to
+120%

0.02

-20% to
+120%

0.009

-20% to
+500%

NA

NA

Tonnes/ million cubic
meter gas
consumption

0.23-20% to
+120%

0.01

-20% to
+120%

0.003

-20% to
+500%

NA

NA

Tonnes/ kilometre ofpipelineAll

5-50% to
+100%

0.05

-50% to
+100%

0.16

-70% to
+140%

NA

NA

Tonnes/million cubic
meter of gas stored

All

0.003

±100%

3.0E-05±100%

9.3E-05-100% to
+170%

NA

NA

Tonnes/ million cubic
meter gas consumed

All

0.58

±25%

1.8E-02

±25%

NA

NA

NA

NA

Tonnes/ kilometre ofpipelineAll

All2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

Units of measure

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TABLE 4.2.4J (NEW) (CONTINUED)TIER 1 EMISSION FACTORS FOR DISTRIBUTION SEGMENT, 1.B.2.B.V
NA – Not Applicable

4.80

a.

Emission factors for CH4 and CO2 developed from EPA/GRI, Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996), as applied in the 2018 U.S. GHG Inventory(United States Environmental Protection Agency (EPA) 2018a) to calculate emissions for the year 1992 (when EPA/GRI study was conducted). NMVOC values were developed from 2006
IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which was then applied to corresponding CH4 values in this table.

b.

Emission factors for CH4 and CO2 developed from data reported to the U.S. Greenhouse Gas Reporting Program (GHGRP) (United States Environmental Protection Agency (EPA) 2017), Lambet al. 2015, and from EPA/GRI, Methane Emissions from the Natural Gas Industry (Gas Research Institute 1996), as applied in the 2018 U.S. GHG Inventory to calculate emissions for the year
2016 (most recent year of GHGRP data availability). NMVOC values were developed from 2006 IPCC Guidelines by calculating a ratio of NMVOC to CH4 from 2006 IPCC Guidelines, which
was then applied to corresponding CH4 values in this table.

c.

CH4 values from (Bender & Langer 2012) – CO2 and NMVOC developed from the assumption of a CH4 content of 90%, CO2 content of 0.9% and a NMVOC content of 2.8%.

d.

Mean emission factors for CH4 and CO2 from German inventory (German Government 2018) data (1990-1997). Data for the years 1990-1997 were selected because town gas supply was
discontinued after 1997 in Germany.

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Chapter 4: Fugitive Emissions

1 B 2 b vi Post-Meter Emissions
This segment includes fugitive emissions beyond gas meters and from natural gas-fueled vehicles. The emission
factors for appliances and power plants include leakage emissions beyond gas meters, such as internal piping andthe end of pipe appliances (e.g. home heating, water heating, stoves, barbecues). Emissions from start-stop-losses
of appliances and combustion of gas are not included in the methodology. If the number of appliances using natural
gas is unknown the number of gas meters or the number of house connections should be used instead multiplied
by a typical number of appliances (e.g., 2 for countries with heaters and stoves; 1 in warm countries without
heaters). The emission factor for natural gas-fueled vehicles include releases from dead volumes during fueling,
emptying of gas cylinders of high-pressure interim storage units, for execution of pressure tests and relaxation ofresidual pressure from vehicles' gas tanks, for pressure tests or decommissioning.
For each category/subcategory listed in Table 4.2.4k below that is occurring in the country, compilers must
calculate emissions, and sum them according to Equation 4.2.18. It is recognized that not all countries will haveall categories and subcategories occurring.
EQUATION 4.2.18 (NEW)GENERAL EQUATION FOR ESTIMATING FUGITIVE EMISSIONS FROM POST-METER LEAKAGE

E post − meter leakage = Anatural gas vehicles • EFnatural gas vehicles+ Anatural gas appliances • EFnatural gas appliances+ Anatural gas power plants • EFnatural gas power plants
Where:
Epost-meter leakage= Total amount of GHG gas emitted due to all relevant post-meter leakages of naturalgas

Anatural gas vehicles= Number of natural gas-fueled vehicles

EFnatural gas vehicles= Emission factor for natural gas-fueled vehicles

A natural gas appliances= Number of natural gas appliances in commercial and residential sector

EF natural gas appliances= Emission factor for appliances in commercial and residential sector

A natural gas power plants= Volume of gas consumption at industrial plants and power stations

EF natural gas power plants = Emission factor for leakages at industrial plants and power stations

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TABLE 4.2.4K (NEW)
TIER 1 EMISSION FACTORS FOR POST-METER SEGMENT, 1.B.2.B.VI
CO2

CH4

Segment

Sub-segment

EmissionsourcePost-meter

Natural gas-fuelled vehiclesa

Post-meter

Appliances in commercial
and residential sectorb

Post-meter

Leakage at industrial
plants and power
stationsc

Value

Uncertainty(% ofvalue)

All

3.0E-04All

3.2E-03

All

6.1

Value

Uncertainty(% ofValue)-50% to+100%

3.0E-06±60%

3.2E-05±60%

6.1E-02

NMVOC

N2O

Value

Uncertainty(% ofvalue)

Value

Uncertainty(% ofvalue)-50% to+100%

9.3E-06-70% to
+140%

NA

NA

Tonnes/ car±60%

1.0E-04

±60%

NA

NA

Tonnes/ applianceNA

Tonnes/million cubic
meter Non-residential
and commercial gas
consumed±60%

1.9E-01±60%

NA

Units of measure

NA – Not Applicable

4.82

a.

CH4 values from (Bender & Langer 2012), CO2 and NMVOC developed using assumption of a CH4 content of 90%, CO2 content of 0.9% and a NMVOC content of 2.8%b.

Medium value of table 4.2.8 of 2006 IPCC Guidelines (g) (appliances) – conversion with density of 0.72 kg/m3, a CH4 content of 90%, a CO2 content of 0.9% and a NMVOC content of 2.8%c.

Value from the Revised 1996 IPCC Guidelines, Volume 3, table 1-58 (leakage at industrial plants and power stations) - conversion of 175,000 kg/PJ value with factor 35 MJ/m3, a CH4 content of
90%, a CO2 content of 0.9%, and a NMVOC content of 2.8%.

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Chapter 4: Fugitive Emissions

1 B 2 b vii Other
Fugitive emissions (including leaks, venting and flaring) from natural gas systems not otherwise accounted for in
the above categories. This may include emissions from well blowouts and pipeline ruptures or dig-ins, accidents,and emergency pressure releases. It is good practice to quantify and report such emissions as part of category
1.B.2.b.vii whenever possible. There is no Tier 1 method available for such events, which need to be evaluated ona case-by-case basis, often using a combination of emission factors and engineering calculations. An example ofcalculating emissions during emergency conditions though an engineering calculation approach is given in(American Petroleum Institute (API) 2009). Other examples of quantifying anomalous leak events include
CARB’s Aliso Canyon report (California Air Resources Board 2016).
1 B 2 b viii Abandoned Gas Wells
Available information on abandoned oil and gas wells do not indicate a clear distinction between abandoned oil
and abandoned gas wells regarding practices or emission factors. As such, please refer to the discussion for
1.B.2.a.vii for background and guidance on abandoned oil wells. The emission factors are presented in Table
4.2.4e. In the future, as additional data on this source become available, distinct emission factors for oil and gas
may be possible.
T I ER 3 A ND 2
Emission factors for conducting Tier 3 and Tier 2 assessments are not provided in the IPCC Guidelines due to thelarge amount of such information and the fact these data are continually being updated to include additional
measurement results and to reflect development and penetration of new control technologies and requirements.
Rather, the IPCC has developed an EFDB which will be periodically updated and is available at www.ipccnggip.iges.or.jp/EFDB/main.php. In addition, regular reviews of the literature and country-specific data available
through inventories of countries with similar circumstances should still be conducted to ensure that the best
available factors are being used. The references for the chosen values should be clearly documented. Typically,
emission factors are developed and published by environmental agencies, industry associations and academic
literature. It may be necessary to develop inventory estimates in consultation with these organizations. For
example, the API maintains a Compendium of Emissions Estimating Methodologies for the Oil and Gas Industry,
most recently updated in 2009. The API Compendium is available at (American Petroleum Institute (API) 2009).
Guidance for estimating greenhouse gas emissions has also been developed by a number of national oil and gas
industry associations. Such documents may be useful supplemental references and often provide tiered sourcespecific calculation procedures. Guidance on inventory accounting principles as they apply to the oil and gas
industry, and boundary definitions is available in the Petroleum Industry Guidelines for Reporting Greenhouse
Gas Emissions (International Petroleum Industry Environmental Conservation Association (IPIECA) et al. 2011).
When selecting emission factors, the chosen values must be valid for the given application and be expressed on
the same basis as the activity data. It also may be necessary to apply other types of factors to correct for site andregional differences in operating conditions and design and maintenance practices, for example:• Composition profiles of gases from particular oil and gas fields to correct for the amount of CH4, formation
CO2 and other target emissions;• Annual operating hours to correct for the amount of time a source is in active service;• Efficiencies of the specific control measures used.
The following are additional matters to consider in choosing emission factors:• It is important to assess the applicability of the selected factors for the target application to ensure similar orcomparable source behaviour and characteristics.
• In the absence of better data, it may sometimes be necessary to apply factors reported for other regions thatpractice similar levels of emission control and feature comparable types of equipment.
• Where measurements are performed to develop new emission factors, only recognised or defensible test
procedures should be applied. The method and quality assurance (QA)/quality control (QC) procedures should
be documented, the sampled sources should be representative of typical variations in the overall source
population and a statistical analysis should be conducted to establish the 95 percent confidence interval on the
average results.
• Whether and how the emission factors may change over time due to changes in technologies or practices.

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4.2.2.4

C HOICE OF ACTIVITY DATA

The activity data required to estimate fugitive emissions from oil and gas activities includes production statistics,
infrastructure data (e.g., inventories of facilities/installations, process units, pipelines, and equipment
components), and reported emissions from spills, accidental releases, and third-party damages. The basic activity
data required for each tier and each type of primary source are summarized in Table 4.2.6, Typical Activity Data
Requirements for each Assessment Approach by Type of Primary Source Category. Production statistics provided
by national bureaux should be used in favour of those available from international bodies, such as the IEA or theUN, due to their generally better reliability and disaggregation. Regional, provincial/state and industry reportinggroups may offer even more disaggregation.

TIER 1
The activity data required at the Tier 1 level has been limited to information that may either be obtained directlyfrom typical national oil and gas statistics or easily estimated from this information. Table 4.2.7 below lists therelevant activity data for each of the Tier 1 emission factors presented in Tables 4.2.4 to 4.2.4k, and gives
appropriate guidance for obtaining or estimating each of the required activity values.

TIER 2
The activity data required for the standard Tier 2 methodological approach is the same as that required for the Tier
1 approach. If the alternative Tier 2 approach described in Section 4.2.2.2 for crude oil systems is used, thenadditional, more detailed, information is required including average GOR values, information on the extent of gas
conservation and factors for apportioning waste associated gas volumes between venting and flaring. Thisadditional information should be developed based on input from the industry.
TABLE 4.2.6 (UPDATED)TYPICAL ACTIVITY DATA REQUIREMENTS FOR EACH ASSESSMENT APPROACH FOR FUGITIVE EMISSIONS FROM OIL AND GASSYSTEMS BY TYPE OF PRIMARY SOURCE

Assessment Tier
1

Primary Source

Activity DataAll

See Table 4.2.7 below.

Venting and Flaring from Oil
Production

Gas to Oil Ratios
Flared and Vented Volumes
Conserved Gas Volumes
Re-injected Gas Volumes
Utilised Gas Volumes
Gas Compositions

All Others

See Table 4.2.7, which is relevant to Tier 2 as wellas Tier 1.

2

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Chapter 4: Fugitive Emissions

TABLE 4.2.6 (UPDATED) (CONTINUED)TYPICAL ACTIVITY DATA REQUIREMENTS FOR EACH ASSESSMENT APPROACH FOR FUGITIVE EMISSIONS FROM OIL
AND GAS SYSTEMS BY TYPE OF PRIMARY SOURCE

Assessment Tier
3

Primary Source

Activity Data

Process Venting/Flaring

Reported Volumes
Gas Compositions
Proration Factors for Splitting Venting from
Flaring

Storage Losses

Solution Gas Factors
Liquid Throughputs
Tank Sizes
Vapour Compositions

Equipment Leaks

Facility/Installation Counts by Type
Processes Used at Each Facility
Equipment Component Schedules by Type ofProcess Unit
Gas/Vapour Compositions

Gas-Operated Devices

Schedule of Gas-operated Devices by Typeof Process Unit
Gas Consumption Factors
Type of Supply Medium
Gas Composition

Accidental Releases & Third-Party
Damages

Incident Reports/Summaries

Gas Migration to the Surface & Surface
Casing Vent Blows

Average Emission Factors & Numbers of
Wells

Drilling

Number of Wells Drilled
Reported Vented/Flared Volumes from Drill
Stem Tests
Typical Emissions from Mud Tanks

Well Servicing

Tally of Servicing Events by Types

Pipeline Leaks

Type of Piping Material
Length of Pipeline

Exposed Oils ands/Oil Shale

Exposed Surface Area
Average Emission Factors

Abandoned wells

Number of leaking abandoned wells
Total annual methane volumes fromabandoned wells

Table 4.2.7 below provides a list of the activity data values used in calculating emissions with a Tier 1 approach.
In general, values should be directly referenced from national statistics. Note that not all values present in the table
will be needed to calculate emissions. For most calculations, several emission factors are provided to correspondwith different activity data options. The inventory compiler should assess which activity data are available andwhich activity data basis best reflects emissions in that segment for that country.

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TABLE 4.2.7 (UPDATED)ACTIVITY DATA VALUES REQUIRED FOR USE IN THE TIER 1 APPROACH TO ESTIMATE FUGITIVE EMISSIONS FROM OIL
AND GAS SYSTEMS
Segment

Sub-segment

Activity Data Values•

Oil Exploration
1B.2.a.i
Onshore: Unconventional
without flaring or recovery•••
Onshore: Unconventionalwith flaring or recovery

Onshore: Conventional

Oil Production
and Upgrading
1.B.2.a.ii

Onshore: Most activities
occurring with higheremitting technologies andpractices

Onshore: Most activities
occurring with loweremitting technologies andpractices

4.86

•
•

Unconventional onshore oil wells drilled in a year, without
flaring or recovery, or
Total unconventional onshore oil well population where
exploration occurs without flaring or recovery, orThousand cubic meters onshore unconventional onshore oil
production where exploration occurs without flaring or
recoveryUnconventional onshore oil wells drilled in a year, withflaring or recovery, or
Total unconventional onshore oil well population where
exploration occurs with flaring or recovery, orThousand cubic meters onshore unconventional oil
production where exploration occurs with flaring or
recovery•••Onshore conventional oil wells drilled in a year, or
Total conventional onshore oil well population, orThousand cubic meters onshore conventional oil production•

Thousand cubic meters onshore oil production (where
production occurs with higher-emitting technologies andpractices), or
Active oil wells (where production occurs with higheremitting technologies and practices)

•

•

•

Thousand cubic meters onshore oil production (where
production occurs with lower-emitting technologies andpractices), or
Active oil wells (where production occurs with loweremitting technologies and practices)

Oil Sands Mining and Ore
Processing•

Thousand cubic meters crude bitumen production fromsurface mining

Oil Sands Upgrading•

Thousand cubic meters synthetic crude oil production

Offshore: All•

Thousand cubic meters offshore oil production

Oil Upgrading•

Thousand cubic meters oil upgraded2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

Chapter 4: Fugitive Emissions

TABLE 4.2.7 (UPDATED) (CONTINUED)ACTIVITY DATA VALUES REQUIRED FOR USE IN THE TIER 1 APPROACH TO ESTIMATE FUGITIVE EMISSIONS FROM OIL
AND GAS SYSTEMS
Segment

Sub-segment

Oil Transport
1.B.2.a.iii

Pipelines•

Thousand cubic meters oil transported by pipeline

Tanker Trucks and RailCars•

Thousand cubic meters oil transported by Tanker Truck orrail car

Tanks•

Thousand cubic meters crude oil feed•

Thousand cubic meters oil transported by Tanker Ship
without VRU•

Thousand cubic meters oil transported by Tanker Ship with
VRU

All

•

Thousand cubic meters oil refined.

Gasoline•

Thousand cubic meters product distributed.

Other

•

Thousand cubic meters (e.g. diesel, aviation fuel, jetkerosene) transported.

•

Number of abandoned wells, onshore and offshore,plugged and unplugged.

•

Unconventional onshore gas wells drilled in a year, without
flaring or recovery, or
Total unconventional onshore gas well population where
exploration occurs without flaring or recovery, orLoading of Off-shore
Production on Tanker Ships
without VRU
Loading of Off-shore
Production on Tanker Ships
with VRU
Oil Refining
1.B.2.a.iv
Distribution of
Oil Products
1.B.2.a.v

Other
1.B.2.a.vi

All

Abandoned Oil
Wells
1.B.2.a.vii

All

Gas Exploration
1.B.2.b.i

Onshore: Unconventional
without flaring or gas
captureOnshore: Unconventionalwith flaring or gas capture

Onshore: Conventional

Activity Data Values••

Million cubic meters onshore unconventional onshore gas
production where exploration occurs without flaring or
recovery•Unconventional onshore gas wells drilled in a year, withflaring or recovery, or•

Total unconventional onshore gas well population where
exploration occurs with flaring or recovery, or•Million cubic meters onshore unconventional gas
production where exploration occurs with flaring or
recovery•Onshore conventional gas wells drilled in a year, or•

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TABLE 4.2.7 (UPDATED) (CONTINUED)ACTIVITY DATA VALUES REQUIRED FOR USE IN THE TIER 1 APPROACH TO ESTIMATE FUGITIVE EMISSIONS FROM OIL
AND GAS SYSTEMS
Segment
Gas Production
and Gathering
1.B.2.b.ii

Sub-segment•

Million cubic meters onshore gas production (where
production occurs with higher-emitting technologies andpractices), or•

Active gas wells (where production occurs with higheremitting technologies and practices)•

Million cubic meters onshore gas production (where
production occurs with lower-emitting technologies andpractices), or•

Active gas wells (where production occurs with loweremitting technologies and practices)

Onshore Production – Coal
Bed Methane•

Million cubic meters onshore CBM production

Gathering•

Million cubic meters onshore gas production

Offshore production•

Million cubic meters offshore gas production•

Million cubic meters gas processed (where gas is processed•

Million cubic meters gas produced (where gas is processed

Onshore: Most activities
occurring with higheremitting technologies andpracticesa

Onshore: Most activities
occurring with loweremitting technologies andpracticesb

Gas Processing
1.B.2.b.iii

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Activity Data Values

Without LDAR, less than
50% of centrifugal
compressors have dry seals

without LDAR, and less than 50% of centrifugal compressors havedry seals), or
without LDAR, and less than 50% of centrifugal compressors havedry seals)•

Million cubic meters gas processed (where gas is processedWith LDAR, 50% or moreof centrifugal compressors
have dry seals•

Million cubic meters gas produced (where gas is processed

Sour Gas Plants•

Million cubic meters sour gas processed

without LDAR, and 50% or more of centrifugal compressors havedry seals), or
without LDAR, and 50% or more of centrifugal compressors havedry seals)

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TABLE 4.2.7 (UPDATED) (CONTINUED)ACTIVITY DATA VALUES REQUIRED FOR USE IN THE TIER 1 APPROACH TO ESTIMATE FUGITIVE EMISSIONS FROM OIL
AND GAS SYSTEMS
Segment

Sub-segment

Gas
Transmission andStorage
1.B.2.b.iv

Transmission: Most
activities occurring withhigher- emitting
technologies and practices•

Kilometre of transmission pipeline (where transmission
occurs with higher-emitting technologies and practices), or•

Million cubic meters of gas consumption pipeline (wheretransmission occurs with higher-emitting technologies andpractices)•

Kilometre of transmission pipeline (where transmission
occurs with lower-emitting technologies and practices), or•

Million cubic meters of gas consumption pipeline (wheretransmission occurs with lower-emitting technologies andpractices)•

Million cubic meters of gas consumption (where storage
occurs with higher-emitting technologies and practices)•

Million cubic meters of gas consumption (where storage
occurs with lower-emitting technologies and practices)

LNG Import/Export•

Number of LNG Import/Export stations

LNG Storage•

Number of LNG Storage stations

Less than 50% plastic
pipelines, and limited or noleak detection and repair
programs•

Kilometre of distribution pipeline (where distribution
occurs with less than 50% plastic pipelines, and limited or
no leak detection and repair programs), or•

Million cubic meters gas consumption

Greater than 50% plastic
pipelines, and leakdetection and repair
programs are in use•

Kilometre of distribution pipeline (where distribution
occurs with greater than 50% plastic pipelines, and leakdetection and repair program), or•

Million cubic meters gas consumption

Short term surface storage•

Million cubic meters of gas stored in short term surface
storage

Distribution of town gas•

Kilometre of pipeline distributing town gas

Transmission: Most
activities occurring withlower-emitting technologies
and practices
Storage: Most activities
occurring with higheremitting technologies andpractices
Storage: Most activities
occurring with loweremitting technologies andpractices

Gas Distribution
1.B.2.b.v

Activity Data Values

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TABLE 4.2.7 (UPDATED) (CONTINUED)ACTIVITY DATA VALUES REQUIRED FOR USE IN THE TIER 1 APPROACH TO ESTIMATE FUGITIVE EMISSIONS FROM OIL
AND GAS SYSTEMS
Segment

Sub-segment

Activity Data Values

Gas Post-Meter
1.B.2.b.vi

Natural Gas Vehicles•

Total natural gas vehicles

Appliances in commercial
and residential sector•

Total appliances•Million cubic meters non-residential and commercial gas
consumed•

Number of abandoned wells, onshore and offshore,plugged and unplugged

Industrial plants and power
plantsOther
1.B.2.b.vii

All

Abandoned Gas
Wells
1.B.2.b.viii

All

TIER 3
Approaches and level of disaggregation for Tier 3 estimates can vary widely. In the case of Tier 3, Table 4.2.6 lists
examples of some activity data that might be used for Tier 3 estimates.
Specific matters to consider in compiling the detailed activity data required for use in a Tier 3 approach include
the following:• Production statistics should be disaggregated to capture changes in throughputs (e.g., due to imports, exports,
reprocessing, withdrawals, etc.) in progressing through oil and gas systems.
• Production statistics provided by national bureaux should be used in favour of those available frominternational bodies, such as the IEA or the UN, due to their generally better reliability and disaggregation.
Regional, provincial/state and industry reporting groups may offer even more disaggregation.
• Production data used in estimating fugitive emissions should be corrected, where applicable, to account for any
net imports or exports. It is possible that import and export data may be available for a country while production
data are not; however, it is unlikely that the opposite would be true.
• Where coalbed methane is produced into a natural gas gathering system, any associated fugitive emissions
should be reported under the appropriate natural gas exploration and production categories. This will occur by
default since the produced gas becomes a commodity once it enters the gas gathering system and automaticallygets accounted for the same way gas from any other well does when it enters the gathering system. The factthat gas is coming from a coal formation would only be discernible at a very disaggregated level. Where a coalformation is degassed for the purposes of coal exploration or coal mining and handling, the associatedemissions should be allocated to the coal sector under the appropriate section of IPCC category 1.B.1.
• Vented and flared volumes from oil and gas statistics may be highly suspect since these values are usuallyestimates and not based on actual measurements. Additionally, the values are often aggregated and simply
reported as flared volumes. Operating practices of each segment of the industry should be reviewed withindustry representatives to determine if the reported volumes are actually vented or flared, or to develop
appropriate apportioning of venting relative to flaring. Audits or reviews of each industry segment should also
be conducted to determine if all vented and flared volumes are actually reported (for example, solution gas
emissions from storage tanks and treaters, emergency flaring/venting, leakage into vent/flare systems, andblowdown and purging volumes may not necessarily be accounted for).
• Infrastructure data are more difficult to obtain than production statistics. Information concerning the numbers
and types of major facilities and the types of processes used at these facilities may often be available from
regulatory agencies and industry groups, or directly from the actual companies.
• Information on minor facilities (e.g., numbers of field dehydrators and field compressors) usually is notavailable, even from oil and gas companies. Consequently, assumptions must be made, based on local design

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practices, to estimate the numbers of these facilities. This may require some fieldwork to develop appropriate
estimation factors or correlations.
• Many companies use computerised inspection-and-maintenance information management systems. Thesesystems can be a very reliable means of counting major equipment units (e.g., compressor units, process heaters
and boilers, etc.) at selected facilities. Also, some departments within a company may maintain databases ofcertain types of equipment or facilities for various internal reasons (e.g., tax accounting, production accounting,insurance records, quality control programmes, safety auditing, license renewals, etc.). Efforts should be madeto identify these potentially useful sources of information.
• Component counts by type of process unit may vary dramatically between facilities and countries due todifferences in design and operating practices. Thus, while initially it may be appropriate to use values reported
in the general literature, countries should strive to develop their own values.
• Use of consistent terminology and clear definitions is critical in developing counts of facilities and equipment
components, and to allow any meaningful comparisons of the results with others.
• Some production statistics may be reported in units of energy (based on their heating value) and will need tobe converted to a volume basis, or vice versa, for application of the available emission factors. Typically, where
production values are expressed in units of energy, it is in terms of the gross (or higher) heating value of the
product. However, where emission factors are expressed on an energy basis it is normally in terms of the net(or lower) heating value of the product. To convert from energy data on a gross calorific value (GCV) basis toa net calorific value (NCV) basis, the International Energy Agency assumes a difference of 5 percent for oiland 10 percent for natural gas. Individual natural gas streams that are either very rich or high in impurities may
differ from these average values. Emission factors and activity data must be consistent with each other.
• Oil and gas imports and exports will change the activity levels in corresponding downstream portions of thesesystems.
• Production activities will tend to be the major contributor to fugitive emissions from oil and gas activities incountries with low import volumes relative to consumption and export volumes. Gas transmission anddistribution and petroleum refining will tend to be the major contributors to these emissions in countries withhigh relative import volumes. Overall, net importers will tend to have lower specific emissions than net
exporters.

4.2.2.5 C OMPLETENESS
Completeness is a significant issue in developing an inventory of fugitive emissions for the oil and gas industry.
It can be addressed through direct comparisons with other countries and, for refined inventories, throughcomparisons between individual companies in the same industry segment and subcategory. This requires the useof consistent definitions and classification schemes. For example, in Canada, the upstream petroleum industry has
adopted a benchmarking scheme that compares the emission inventory results of individual companies in terms of
production-energy intensity and production-carbon intensity. Such benchmarking allows companies to assess theirrelative environmental performance. It also flags, at a high level, anomalies or possible errors that should be
investigated and resolved.
The Tier 1 EF and their associated uncertainty ranges presented in Tables 4.2.4 to 4.2.4k may be used to assess
reasonableness of Tier 2 and Tier 3 factors. If emissions from specific segments are appreciably less than the low
end or greater than the high end of the uncertainty range, this should be explained; otherwise, it may be anindication of possible missed or double counted contributions, respectively.
Where emission inventories are developed based on a compilation of individual company-level inventories, careshould be taken to ensure that all companies are included. Appropriate extrapolations may be needed to accountfor any non-reporting companies.
Smaller individual sources, when aggregated nationally over the course of a year, may often be significant total
contributors. Therefore, good practice is not to disregard them. Once a thorough assessment has been done, a basis
exists for simplifying the approach and better allocating resources in the future to best reduce uncertainties in the
results.
Where a country has estimated its fugitive emissions from part or all of its oil and natural gas system based on aroll-up of estimates reported by individual oil and gas companies, it is good practice to document the steps taken
to ensure that these results are complete, transparent and consistent across the time series. Corrections made toaccount for companies or facilities that did not report, and measures taken to avoid missed or double counting(particularly where ownership changes have occurred) and to assess uncertainties should be highlighted.

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Where Tier 2 or Tier 3 approaches are used to calculate a subset of emissions (e.g. flaring), care should be taken
to ensure that all remaining emissions (e.g. venting and fugitives) are accounted (e.g. using disaggregated Tier 1
factors in Appendix 4A.2).

4.2.2.6 D EVELOPING CONSISTENT TIME SERIES
Ideally, emission estimates will be prepared for the base year and subsequent years using the same method. The
aim is to have emission estimates across the time series reflect true trends in greenhouse gas emissions. Emission
or control factors that change over time (e.g., due to changes in source demographics or the penetration of control
technologies) should be regularly updated and, each time, only applied to the period for which they are valid. For,
example, if an emission control device is retrofit to a source then a new emission factor will apply to that sourcefrom then onwards; however, the previously applied emission factor reflecting conditions before the retrofit shouldstill be applied for all previous years in the time series. If an emission factor has been refined through further
testing and now reflects a better understanding of the source or source category, then all previous estimates should
be updated to reflect the use of the improved factor and be reported in a transparent manner.
Tier 1 emission factors provided in Tables 4.2.4 to 4.2.4k are technology/practice-specific to the extent possible.
A country should assess which technologies and practices are generally in place in the country and apply thecorresponding emission factor. As technologies and practices change over time, it is possible that a country will
use one EF in some years and another in other years. A compiler should assess the time frame over which changes
took place, and consider linear interpolation or other techniques to incorporate the trend from one emission factor
to another over the time series.
Where some historical data are missing, it should still be possible to use source-specific measurement results
combined with back-casting techniques to establish an acceptable relationship between emissions and activity datain the base year. Approaches for doing this will depend on the specific situation, and are discussed in general termsin Volume 1 Chapter 5 of the 2006 IPCC Guidelines.
If emission estimates are developed based on a roll-up of individual company estimates, greater effort will be
required to maintain time series consistency, particularly where frequent facility ownership changes occur anddifferent methodologies and emission factors are applied by each new owner without also carrying these changes
back through the time series.

4.2.2.7 U NCERTAINTY ASSESSMENT
Sources of error that may occur include the following:• Measurement errors;• Extrapolation errors;• Inherent uncertainties of the selected estimation techniques;• Missing or incomplete information regarding the source population and activity data;• Poor understanding of temporal and seasonal variations in the sources;• Over or under accounting due to confusion or inconsistencies in category divisions and source definitions;• Misapplication of activity data or emission factors (including due to incomplete information for assigningtechnology- and practice-specific emission factors);• Errors in reported activity data;• Missed accounting of intermediate transfer operations and reprocessing activities (for example, re-treating ofslop oil, treating of foreign oil receipts and repeated dehydration of gas streams: in the field, at the plant, andthen following storage);• Differences in the effectiveness of control devices, potential deterioration of their performance over time andmissed accounting of control measures.
Guidance regarding the assessment of uncertainties in emission factors and activity data are presented in thesubsections below.

4.2.2.7.1 EMISSION FACTOR UNCERTAINTIESThe uncertainty in an emission factor will depend both on the accuracy of the measurements upon which it is based
and the degree to which these results reflect the average behaviour of the target source population, including

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whether the measurements capture any high-emitting subpopulations (e.g., malfunctions) and episodic sources andwhether these have been incorporated into the average factors in a way that does not over- or under-estimate total
emissions. Accordingly, emission factors developed based on data measured in one country may have one set of
uncertainties when the factors are applied in that country and another set of uncertainties when they are applied
similarly in a different country. Thus, while it is difficult to establish one set of uncertainties that will always apply,
a set of default values has been provided for the default factors provided in Tables 4.2.4 through 4.2.4k. These
uncertainties are estimated based on expert judgement and reflect the level of uncertainty that may be expected
when the corresponding emission factors are used to develop emission estimates at the national level. Use of thepresented factors to estimate emissions from individual facilities or sources would be expected to result in muchgreater uncertainties.

4.2.2.7.2 ACTIVITY DATA UNCERTAI NTI ES
The percentages cited in this section are based on expert judgement and aim to approximate the 95 percent
confidence interval around the central estimate. Gas compositions are usually accurate to within ±5 percent on
individual components. Flow rates typically have errors of ±3 percent or less for sales volumes and ±15 percent ormore for other volumes. Production statistics or disposition analyses may not agree between different reporting
agencies even though they are based on the same original measurement results (e.g. due to possible differences interminology and potential errors in summarising these data). These discrepancies may be used as an indication of
the uncertainty in the data. Additional uncertainty will exist if there is any inherent bias in the original measurement
results (for example, sales meters are often designed to err in favour of the customer, and liquid handling systems
will have a negative bias due to evaporation losses). Random metering and accounting errors may be assumed tobe negligible when aggregated over the industry.
Where available, counts of major facilities (e.g., gas plants, refineries and transmission compressor stations) may
be known with little error (e.g., less than 5 percent). Where errors in these counts occur it is usually due to someuncertainties regarding the number of new facilities built and old facilities decommissioned during the time period.
Counts of well site facilities, minor field installations and gas gathering compressor stations, as well as the typeand amount of equipment at each site, will be much less accurately known, if known at all (e.g., at least ±25 percent
uncertainty or more).
Estimates of emission reductions from individual control actions may be accurate to within a few percent to ±25
percent depending on the number of subsystems or sources considered.

4.2.3

Inventory Quality Assurance/Quality Control(QA/QC)

It is good practice to conduct quality control checks as outlined in Volume 1 Chapter 6 of the 2006 IPCC
Guidelines, Tier 1 General Inventory Level QC Procedures, and expert review of the emission estimates.
Additional quality control checks, as outlined in Volume 1 Chapter 5 of the 2006 IPCC Guidelines, and quality
assurance procedures may also be applicable, particularly if higher tier methods are used to determine emissions
from this source category. Inventory compilers are encouraged to use higher tier QA/QC for key categories as
identified in Volume 1 Chapter 4 of the 2006 IPCC Guidelines.
In addition to the guidance in Volume 1 Chapter 6 of the 2006 IPCC Guidelines, specific procedures of relevanceto this source category are outlined below.
RE V I EW O F DI R EC T E M IS S IO N M EA SU R E M EN T S
If direct measurements are used to develop country-specific emission factors, the inventory compiler should
establish whether measurements at the sites were made according to recognised standard methods. If themeasurement practices fail this criterion, then the use of these emissions data should be carefully evaluated,
estimates reconsidered and qualifications documented. The compiler should also assess key backgroundinformation in the study, such as, what activities are occurring and what equipment is in place (including controls)at the time of measurement and whether the measurements are representative of average conditions for that activity
and may be applied as an average factor, or if it should be adjusted for different operating practices, etc. The
compiler should confirm that the categorizations (e.g. for equipment and practices) used in the study are the sameas used in the inventory, and should make adjustments if not. The national representativeness of the factors should
also be assessed. As applicable, the attribution of measured emissions to the specific equipment or broader category
should also be assessed.
AC T IV I TY D A TA CH E CK
Several different types of activity data may be required for this source category, depending on which
methodological tier is used to estimate the emissions. Where activity data are available from multiple sources (i.e.

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from national statistics and industry organisations) these data sets should be checked against each other to assess
reasonableness. Significant differences in data should be explained and documented. Trends in the main emission
drivers and activity data over time should be checked and any anomalies investigated.

EXTERNAL REVIEW AND STAK EHOLDER INVOLVEMENT
Emission inventories for large, complex oil and gas industries may be susceptible to errors due to missed or
unaccounted for sources, or due to customization of average emission factors taken from a data source that
represents estimates from another country or region with operating characteristics different from those in the
country where the emission factor is being applied. To minimise such errors, it is important to obtain active
involvement of industry and other technical experts in the preparation and refinement of these inventories. This
will be especially important in the selection of appropriate technology- and practice-specific emission factors.

4.2.4

Reporting and Documentation

It is good practice to document and archive all information required to produce the national emissions inventory
estimates, as outlined in Volume 1 Chapter 8 of the 2006 IPCC Guidelines.
It may not be practical to include all supporting documentation in the inventory report. However, at a minimum,
the inventory report should include summaries of the methods used and references to source data such that thereported emissions estimates are transparent and the steps in their calculation may be retraced. For segments wherea technology- or practice-specific Tier 1 emission factor is used, the rationale for selecting that factor and themethod for applying the factors over the time series must be clearly documented. It is expected that many countries
will use a combination of methodological tiers to evaluate the amount of fugitive greenhouse gas emissions fromthe different parts of their oil and natural gas systems. The specific choices should reflect the relative importanceof the different subcategories and the availability of the data and resources needed to support the corresponding
calculations. Table 4.2.9 is a sample template, with some example data entries, that may be used to conveniently
summarize the applied methodologies and sources of emission factors and activity data. Tier 1 EF are inclusive ofventing, flaring, and leak emissions. For calculations, compilers may separate their emissions into the separate
categories of venting, flaring and leaks if data are available. Emissions reported for each segment should be
inclusive of venting, flaring, and leak emissions (i.e., should represent the total emissions for that segment). If a
compiler choses to report disaggregated data on venting and flaring, they may do so as information items. The best
global data available to develop technology-specific tier 1 emission factors currently does not have a clear
distinction between leaks, venting, and flaring, although we make a best estimate of this split in the annex. To
maintain consistent reporting between the tiers, the worksheet 1.B.2 has been appropriately revised.
Since emission factors and estimation procedures are continually being improved and refined, it is possible forchanges in reported emissions to occur without any real changes in actual emissions. Accordingly, the basis forany changes in results between inventory recalculations should be clearly discussed and those due strictly tochanges in methods and factors should be highlighted.
The issue of confidential business information will vary from region to region depending on the number of firms
in the market and the nature of the business. The significance of this issue tends to increase in progressing
downstream through the oil and gas industry. A common means to address such issues where they do arise is toaggregate the data using a reputable independent third party.
Where inventory data may be considered confidential, fugitive emissions can be reported based on the level ofaggregation at which information can still be reported while protecting confidentiality. For more guidance on data
aggregation and other approaches for use of confidential data, see Volume 1, Section 2.2 “Restricted data andconfidentiality”.
The above reporting and documentation guidance is applicable to all methodological choices. Where Tier 3
approaches are employed, it is important to ensure that either the applied procedures are detailed in the inventory
report or that available references for these procedures are cited since the IPCC Guidelines do not describe astandard Tier 3 approach for the oil and gas sector. There is a wide range in what potentially may be classified asa Tier 3 approach, and correspondingly, in the amount of uncertainty in the results. If available, summary
performance and activity indicators should be reported to help put the results in perspective (e.g. total productionlevels and transportation distances, net imports and exports, and specific energy, carbon and emission intensities).
Reported emission results should also include a trend analysis to show changes in emissions, activity data andemission intensities (i.e., average emissions per unit of activity indicator) over time. The expected accuracy of theresults should be stated and the areas of greatest uncertainty clearly noted.
The current trend by some government agencies and industry associations is to develop detailed methodology
manuals and reporting formats for specific segments and subcategories of the industry. This is perhaps the mostpractical means of maintaining, documenting and disseminating the subject information. However, all such

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initiatives must conform to the common framework established in the IPCC Guidelines so that the emission results
can be compared across countries.

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TABLE 4.2.9 (UPDATED)FORMAT FOR SUMMARIZING THE APPLIED METHODOLOGY AND BASIS FOR ESTIMATED EMISSIONS FROM OIL AND NATURAL GAS SYSTEMS SHOWING SAMPLE ENTRIES
Activity Data
IPCC
Code

Category, Sub-category or
Segment

1.B.2

Oil and Natural Gas

1.B.2.aOil

1.B.2.a.i

Exploration

1.B.2.a.ii

Production and Upgrading

1.B.2.a.iii

Transport

1.B.2.a.iv

Refining

1.B.2.a.v

Distribution of Oil Products

1.B.2.a.vi

Other

1.B.2.a.vii

Abandoned Oil Wells

1.B.2.b

Sub-segment(if applicable)

Source Type
(all, vent,flare, leak)

MethodEmission Factors
Basis/Reference 12
11F

Type

Basis

Year

CH4

CO2

N2O

Date
Country
Specific
ValuesUpdatedNatural Gas

12 Include here information on basis for selecting technology/practice-specific factors, as applicable.

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TABLE 4.2.9 (UPDATED) (CONTINUED)
FORMAT FOR SUMMARIZING THE APPLIED METHODOLOGY AND BASIS FOR ESTIMATED EMISSIONS FROM OIL AND NATURAL GAS SYSTEMS SHOWING SAMPLE ENTRIES
Activity Data
Sub-segment(if applicable)

Source Type
(all, vent,flare, leak)

MethodProduction andGatheringGas Production

All

1.B.2.b.iii

Processing

All

1.B.2.b.iv

Transmission andStorage

Gas Transmission

1.B.2.b.v

Distribution

1.B.2.b.vi

Post-Meter

1.B.2.b.vii

Other

1.B.2.b.viii

Abandoned Gas Wells

IPCC
Code

Category, Sub-category or
Segment

1.B.2.b.i

Exploration

1.B.2.b.ii

1.B.3

Emission Factors
Basis/Reference

Type

Basis

Year

CH4

CO2

N2O

Date
Country
Specific
ValuesUpdatedTier 1Throughput

National
Statistics

2005

D

D

D

---

All

Tier 1Throughput

National
Statistics

2005

D

D

D

---

All

Tier 2

Number of
facilities

Industry
Survey

2005

CS

CS

-----

2005

Other emissions from Energy
Production

D– IPCC Default Emission Factors

CS– Country-Specific Emission Factors

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4.3

FUGITIVE EMISSIONS FROM FUEL
TRANSFORMATION

Fuel transformation occurs when energy products are transformed into other energy products more suitable for
their end use. Transformation occurs by physical or chemical conversion into a product whose intrinsic properties
differ from those of the original product (e.g. charcoal production; or coke oven carbonization of coal); or byaggregation and blending of products, sometimes involving a change of the physical shape (e.g. briquetting ofbrown coal) (UNSD, 2018).

4.3.1

Overview and description of sources

This section is a new guidance. It clarifies how fugitive emissions from fuel transformation should be estimated.
Emissions from these fuel transformation activities link to the Energy, IPPU and AFOLU sectors and crossreferences are provided to the relevant sections in the guidelines. Inventory compilers should ensure all emissions
from specific fuel transformation activities are captured in their inventories but are not double counted.
Fugitive emissions from two groups of transformation process have been included in this section:• Solid to solid transformation processes (charcoal production; coke production). The organisation of thissection is based on the transformation of the physical state of the fuel;• Gasification transformation processes (coal to liquids; gas to liquids). The organisation of this section isbased on the technologies used.
The boundaries for all these transformation activities are the respective transformation process boundaries, andfugitive emissions in upstream and downstream supply chains are to be estimated using appropriate methodologies
elsewhere in these guidelines, including in other volumes.
Other transformation processes (e.g. patent fuel, coal briquetting, town gas production) are not explicitly
addressed. If parties have country specific methodologies available, they may report emissions in these categories.
Hydrogen production is considered in Volume 3, Chapter 3.11; refineries are considered in Chapter 4.2 in thisvolume.
The major sources are summarised in Table 4.3.1 below.
TABLE 4.3.1 (NEW)DETAILED SECTOR SPLIT FOR EMISSIONS FROM FUEL TRANSFORMATIONIPCC code

Category/subcategory

Definition

1B1c

Fuel transformation

Fugitive emissions arising during the
manufacture of secondary and tertiary products
from fuels.

1B1ci

Charcoal and Biochar Production

Fugitive emissions arising during the productionof charcoal and biochar.

1 B 1 c ii

Coke Production

Fugitive emissions arising during the productionof coke.

1 B 1 c iii

Solid to Solid Fuel Production

Fugitive emissions arising during the productionof wood pellets.

1 B 1 c iv

Gasification Transformation

Fugitive emissions from the transformation of
biomass, coal or natural gas into syngas,
composed by H2, CO, CO2 and CH4, and, then,into a liquid hydrocarbons fuels.

Table 4.3.2 provides cross references to the locations in the guidelines for the methods for estimating fugitive
emissions from the transformation, and, shows the categories where emissions should be reported. Compilers
should note carefully the differences in reporting of CO2 from biomass and fossil feedstock. For more information
on treatment of biomass emissions, please see Section 2.3.3.4 of Volume 2, Chapter 2.

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TABLE 4.3.2 (NEW)ESTIMATION AND REPORTING OF FUGITIVE EMISSIONS FROM FUEL TRANSFORMATION
Methods for estimating fugitive
emissions from the transformationof this fuel are set out in thefollowing section of the Guidelines

Fugitive emissions from thetransformation of this fuel should bereported under the following category

Charcoal and biochar
production

4.3.2.1

Coke production (including
flaring)aCH4, N2O in 1.B.1.c.i
CO2 as a memo item
“CO2 emissions from biomass”

4.3.2.1

CO2, CH4, N2O in 1.B.1.c.ii

Wood pellet production

Appendix 4A.2

Gasificationtransformation processes
Coal to liquids

CH4, N2O in 1.B.1.c.iii
CO2 as a memo item “CO2 emissions
from biomass”

4.3.2.2

CH4, N2O in 1.B.1.c.iv

Gas to liquids

4.3.2.2

CH4, N2O in 1.B.1.c.iv

Biomass to liquids

Appendix 4A.3

CH4, N2O in 1.B.1.c.iv

Biomass to gas

Appendix 4A.3

CH4, N2O in 1.B.1.c.iv

Fuel transformation
Solid to solidtransformation processes

Notes:aFurther details about reporting of emissions from coke production are given in Table 4.3.4

4.3.2

Methodological issues

4.3.2.1 S OLID TO SOLI D TRANSFORMATIO N PROCESSESCHARCOAL AND BI OCHAR PRODUCTI ON
About half the wood extracted worldwide from forests is used to produce energy, mostly for cooking and heating.
Some of the wood is used to make charcoal. The share of energy use from harvested wood is as high as 90 percent
in Africa and more than 60 percent in Asia. An estimated 17 per cent of wood extracted from forests was converted
to charcoal (FAO, 2016), natural forest and forest plantation as wood for energy may differ in its production, andmost of the remainder was used in the form of fuelwood. Charcoal production can be on very small scales(domestic) to larger scales (industrial), and is normally poorly regulated with little or no emission control.
Emissions from harvested wood energy use are due largely to unsustainable forest management, inefficientcharcoal manufacture and woodfuel combustion (FAO, 2017; AFREA, 2011). Of these sources, the solid to solidtransformation process only covers emission from inefficient charcoal manufacture.
Charcoal is produced by the carbonization of wood. Carbonization of fuel is the thermal decomposition in theabsence of oxygen at a temperature above 300○C. The carbonization of wood produces charcoal, volatilecompounds and a range of gases. The gases produced include direct greenhouse gases (CO2, CH4 and N2O), indirect
greenhouse gases (CO) and other gases, including H2. Emissions of biogenic CO2 from charcoal production arereported here as an information item, and are covered under Agriculture, Land Use Change and Forestry (AFOLU).
Fugitive emissions of CH4 and N2O are reported here.
Some biochar is also produced from harvested wood, which is mainly applied in soils (please refer to AFOLU
Chapter for details) and also some biochar produced could be used for making biochar briquettes that are used forenergy purposes. Charcoal and biochar are produced by the pyrolysis method but under different conditions.
Traditional kiln technologies for charcoal production are slow and without treatment of the pyrolysis gases,
resulting in emissions of gases (mainly methane and carbon monoxide) and aerosols that are both toxic andcontribute to greenhouse gas emissions. In retort kilns normally used for biochar production, pyrolysis gases are
led back to a combustion chamber and these pyrolytic gases are recirculated and combusted internally to produce
around 75% lower deleterious gas emissions (mainly CO, CH4, aerosols) and higher conversion efficiencies of 30–
45% than traditional systems.
Emissions of biogenic CO2 from biochar production are reported here as an information item, and are covered
under AFOLU. Fugitive emissions of CH4 and N2O are reported here.

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CHOICE OF METHODS, DECISION TREES, TIERS
Figure 4.3.1 shows the decision tree for estimating fugitive emissions from charcoal production activities. For
countries with kiln-level charcoal production data, or kiln type data, and who have kiln efficiency or emission
factor data available, a Tier 3 estimation could be applied. For countries where country level charcoal production
data is available, a country specific EF may be estimated and applied in a Tier 2 approach. However, if fugitive
emissions from fuel transformation are a key category, and charcoal production is a significant source within thatcategory, estimate emissions using higher tiers. If fugitive emissions are not a significant source, then emissions
can be estimated using a Tier 1 method. A similar approach should to be followed for biochar production.

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Chapter 4: Fugitive Emissions

Figure 4.3.1 (New) Decision tree for Charcoal (and biochar) production

Start

Are kiln-level
efficiency or emission
factors, and corresponding
activity data
available?

Yes

Estimate emissions
using these emission stage
specific emission factors
and detailed activity data.
Box 3: Tier 3NoAre
country-specificemission factors
available?

Estimate emissions using
the national level activity
data and country-specificemission factors.

Yes

Box 2: Tier 2
No

Are fugitives fromfuel transformation a key
category, and is charcoal (or biochar)production significant source
within that category?

No

Estimate emissions using
national level production
data and default
emission factors.
Box 1: Tier 1

Yes
Collect data to develop
country-specific emission
factors for Tier 2.

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Tier 1
The general form of the equation for estimating emissions for Tier 1 approach, based on charcoal production
activity data is given by Equation 4.3.1 below.
EQUATION 4.3.1 (NEW)FUGITIVE GHG EMISSIONS FROM CHARCOAL (OR BIOCHAR) PRODUCTION ON ANNUAL BASIS

Emissions=
Chacoal (or biochar ) produced • Emission FactorGHG
GHG , charcoal ( or biochar ) produced
Where:
Emissions GHG, charcoal (or biochar) produced = emissions of a given GHG (g GHG)
Charcoal (or biochar) produced= amount of charcoal (or biochar) produced (kg)

Emission Factor GHG= emission factor GHG (g GHG/kg of charcoal (or biochar) produced)

Tier 1 emission factors are given in Table 4.3.3.
Inventory compliers should note that compressed lignite briquettes might be added to charcoal, and compilers
could check to see if this occurs and the extent to which it occurs. If lignite briquettes are manufactured, fugitive
emissions from the manufacture might occur. These emissions should be estimated if country specific emission
factors are available. Default emission factors are not available for lignite briquette production.

Tier 2The Tier 2 approach uses Equation 4.3.1, but inventory compilers should use country specific EFs.

CHOICE OF EMISSI ON FACTOR
Table 4.3.3 provides default emission factors calculated as median from various studies and the lower limit andupper limits of charcoal production. Kilns with lower efficiency tend to have a higher emission factor, and viceversa.
Default emission factors for fugitive emissions from lignite briquette production are not available.

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TABLE 4.3.3 (NEW)DEFAULT EMISSION FACTORS FOR CHARCOAL AND BIOCHARPRODUCTION(g GHG / kg of charcoal (or biochar) produced)
Gas

Default Emission Factor

Uncertainty (% of value)

Charcoal production a
CO2 c

1,570

-38% to +60%

CH4

40.3

-68% to +121%

N2O

0.08

-75% to +163%

CO

220

-52% to +53%

NOx

0.07

±57%
Biochar production b

CO2 c

4,300

±40%

CH4

30

-100% to +200%

NOx

0.4

±75%

CO

54

±65%

Notes:a

Source of data: calculated as a median of data from Bailis (2009); Taccini (2010);
Chidumayo et al. (2013); Müller et al. (2011); Pennise et al. (2001); Smith et al. (1999);
and Basu et al. (2013).

b

For flame curtain biochar kilns. Source of data: Cornelissen et al. (2016)c

CO2 emissions are reported as memo items since carbon released from charcoal (or biochar)production is biogenic in origin

CHOICE OF ACTIVITY DATA
Preference must be given to sourcing accurate charcoal production data. Charcoal production might be available
in national energy balances. The quantities of charcoal produced might be recorded by statistical agencies, andcould be estimated from the weight or volume of wood used to make charcoal or biochar. Total charcoal production
can be estimated by measuring the charcoal produced in each kiln countrywide each year. Measurement is done
by weighing the bags of charcoal produced at each site. If gravimetric production activity is not available,
quantities of charcoal produced can be approximately estimated from the product of the number of charcoal bags
filled assuming the weight of each bag is known. Estimates of production made in this way should not be used for
an inventory, but could be used to help verify production data from other sources. A similar approach can befollowed for biochar production. Biochar production data should include the total national value of biochar
production.
If no country specific charcoal production data are available, wood charcoal production according to country
maybe available at http://www.fao.org/faostat/.

UNCERTAINTY ASSESSMENT
The uncertainty associated with charcoal (or biochar) production is high as the use of this fuel is typically notaccurately recorded at national level, and, most of the traditional charcoal (or biochar) makers do not measure thequantities of charcoal produced. Uncertainties associated with the charcoal production data might be available
from statistical data. If such data are not available, then expert elicitation and expert judgement can be used. The
uncertainties associated with the emission factors are very high. The emission factors depend on the type of kiln
and corresponding efficiency. Since most of the charcoal (or biochar) is produced by traditional mound methods,
which are not standardized, the emission factors will necessarily be highly uncertain. Emission factors are notavailable by kiln type.

COKE PRO DUCTIO N
To ensure the estimates of total fugitive GHG emissions from coke production are complete, emissions should be
estimated from unintentional leakage during the coke production process and from any venting or flaring of cokeoven gases.

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Please refer to Section 4.2, Volume 3 for the methods to estimate process emissions from metallurgical cokeproduction. Figure 4.3.2 provides a simplified diagram of a coke oven plant showing the possible types and sourcesof fugitive emissions.

FUGITIVE EMISSIO NS FROM UNINTENTIONAL LEAK AGE
Coke is produced by the pyrolysis of coal. This is a managed thermal treatment of the coal which limits combustionor oxidation of the coal or coke product. Coal pyrolysis at high temperature is called carbonisation. The process
produces coke, volatile compounds and a range of other gases. In the coke production process, the coal is heatedindirectly up to 1 000 – 1 100°C for 14 – 28 hours (JRC, 2013).
Coke is the most important reducing agent used in primary metal production. Other uses of coke include as aheating fuel and feedstock.
Globally the production of coking coal and associated coke oven gas (COG) is significant. Coke oven gas is a byproduct of production of coke oven coke in coke ovens, mainly from coking coal. In 2016, coking coal production
was 1 040 Mt, derived coke oven coke production was 668 Mt, and coke oven gas production was 3129 PJ (IEA,
2016).
Only certain coals, for example coking or bituminous coals, with the right properties, can be converted to coke
and a coking plant may blend several types to improve coke production and extend coke battery life. Other
materials which contain carbon can also be included in small quantities (e.g. petroleum coke, shredded tyres). Oilor oil residues can also be added.
Older technologies include comparatively simple coke kilns or retorts which represent a low capacity basic
technology with varying levels of pollution control and energy efficiency. This type of coking technology has
been largely phased out in most countries (Huo et al., 2012). Since the 1940s, the coke production process has
been mechanised and the materials used in the construction of the ovens have been improved without significant
design modifications. Horizontal chamber coking is the most common type of coke oven. A horizontal coke ovenbattery may contain up to 70 ovens as large as 14 m long and 6 m high. Because of heat transfer considerations,oven widths have remained at between 0.3 and 0.6 m. Each oven in the battery holds up to 30 tonnes of coal. Some
recently constructed coke oven plants have increased dimensions further.
The technology used in coke ovens can be simplified into 2 main types (AISTech, 2010):
1.

Heat recovery, with no by-product recovery
By-products released from the coking process are combusted within the oven. This provides the heatrequired for the coke-making process. The oven is a horizontal design and operates under negative pressure
which means fugitive emissions from the coke oven during operation should be negligible. Primary
combustion air is introduced though ports in the oven doors which partially combusts the volatiles in theoven chamber. Secondary air is introduced to complete the combustion process in flues which run under thecoal bed. Heat can still be recovered from hot exhaust gases and be used for the production of heat andelectricity – in such arrangements the system is called heat recovery coke making. As most of the byproducts are combusted in the oven this technique eliminates the need for costly flue gas and wastewater
treatment infrastructure. Heat recovery coking has a smaller output of blast furnace coke compared toconventional coke-making systems, but, it provides more flexibility for coal selection than conventional slot
ovens. Flaring of COG is very unlikely.

2.

Non-heat recovery, with by-product recovery
By product coke making is so called because the volatile matter evolved during the coking process iscollected and refined into by-product chemicals. The coking process is performed in narrow, tall slot ovens
which operate under a non-oxidizing atmosphere. A positive pressure within the oven cavity prevents air
ingress and subsequent combustion of the volatile matter. However this positive pressure may increase
fugitive emissions, particularly if the door seals are not fully effective. Ovens typically range in height from4 m up to 8 m in the latest plants. Taller ovens allow greater amounts of coke to be produced per oven,
therefore minimizing the number of charges and pushes and related emissions to make the needed tonnage.
Volatiles driven off during the coking process pass through a collector main to the by-product chemicalplant. Flaring of COG is possible.

Heat recovery coke making has gained importance during recent years, although this technique is not applied inEurope to date. Only approximately 5 percent of worldwide coke making facilities are operated as heat recovery
plants. There are relevant plants in the US, South America, Asia and Australia. (JRC, 2013). Heat recovery cokemaking needs oven systems which differ in design when comparing with conventional horizontal chamber systems(JRC, 2013).
Figure 4.3.2 shows a typical flow diagram of a coke oven plant showing all sources of emissions. The processes
in the diagram have been generalized, and apply to both heat recovery and non-heat recovery plants.

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Chapter 4_Volume 2 (Energy)
Subject to final copyedit and layout

Figure 4.3.2 (New) Typical flow diagram of a coke oven plant showing emissions sources

Coalstockingarea

Coal
unloading

Recalaimer

Runoff waterCoalstorageservicebunker?
Release toatmosphereMake-upwater

Cokequenchtower

Recalaimer

Blended coal
beddingarea

CoalstoragebunkerRecalaimer

Runoff water

Runoff water

Surface watercollection

Note: Coal may also be stored in bunkers prior to blending

Hammermill

Legend?
Release toatmospherecharging
emissions

Battery
top
storagebunkerLikely significant source of GHG emissions

V
Release toatmosphere ofwaste flue-gas

F
Emergency
vent/flareTopleakage

Coke oven gas
to treatment
and by-products
recovery plant?

Possible sources of GHG emissions

V

Venting of GHG emissions

F

Flaring / Venting of GHG emissions

Chargingcar< ------- Coke ovens ------- >Combustion
air

Pond
water

Coal
blending
area

Coke fines(recovered)

BF/BOF gas forunderfiring

To blast furnace
Door leakage

COG forunderfiring
Battery surface
water collection2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

Release toatmosphereof pushingemissions

Coke wharf

Cokescreeningplant?

To sinter plant
To export

Wharfside spray
quenchSource: Modified from JRC (2013), Figure 5.2, page 208. Original
source: UK Coke, Chief Inspector’s Guidance Note, Series 2 (S2) Processes Subject to Integrated Pollution Control, 1995.

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Subject to final copyedit and layout
The coke-making process can be subdivided into several stages. Fugitive emissions of varying intensities are
possible at each of these stages:• coal handling and preparation;• battery operation (coal charging, heating/firing, coking, coke pushing, coke quenching);• coke oven gas (COG) treatment with recovery and treatment of by-products in the case of a conventional coking
plant; recovery of the heat of the coking and treatment of the flue gas in the case of a heat recovery coking
plant.

METHODOLOGICAL ISSUESCHOICE OF METHODS, DECISION TREES, TIERSThere are many potential sources of fugitive emissions from the coking process. Table 4.3.4 provides a summaryof emissions sources and reporting location according to coke production processing stage.
Inventory compilers who are using a carbon mass balance approach to estimate emissions from the iron and steel
sector, and are including fugitive emissions in this balance, should not use the methods in this section to estimate
emissions of CO2 to avoid double counting.

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TABLE 4.3.4 (NEW)
SOURCES OF FUGITIVE GREENHOUSE GAS EMISSIONS FROM COKE PRODUCTION ACCORDING TO PROCESSING STAGE AND REPORTING OF EMISSIONS••

coke pushing•

Fully-carbonised coke is pushed outof the oven into a container by theram of the pusher machine usuallyin less than one minute•

Fugitive emissions could occur
through leakage of unburnt COG
because of poor sealing in the cokebatteries, particularly around thedoor seals, and, from any flaring of
the COG produced (COG flaring iscovered in a separate line below)
The magnitude of the emissions
could vary from insignificant toperhaps 5% (upper limit) of the
COG produceda•

Possibility of very small emissionsof CH4 as the coke is pushed out of
the batteries from residual COG in
the coke batteries•

2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories•

If the heating walls are notcompletely gas-tight because ofcracks, coke oven gas produced
during coking will reach the fluegas and will cause incomplete
combustion resulting in emissions
at the stack
Emissions from the fuel used toheat the coke batteries should bereported in the energy sector using
the methodologies set out in thestationary combustion chapter
Coke yield and COG production
and composition depend, to a large
extent, on coal composition andcoking time

Fugitive emissions from thisactivity will be very small relative
to the other likely fugitive
emissions from coke production

NO

NO

NO

NA

NO

NO

NO

Flaring

Non-flaring
Fugitives

The complete coking process takes
around 14 – 28 hours, depending
e.g. on the width of the oven (incase of heating by the side), thedensity of coal and on the quality ofthe desired coke (e.g. use infoundries or blast furnaces)•NO

1.B.1.c••CH4 emissions could occur,
especially from very gassy coal
Emissions might occur if theheating walls are not completely
gas-tightNO

1.B.1.ccoking••Emissions of CH4 from very gassy
coal in storage prior to use in the
coking ovens are not considered aspart of this methodology
These emissions should beconsidered as part of coal handlingand storage under 1.B.1.a.i.2

1.B.1.c•

The individual coke oven chambers
are separated by heating walls
In order to improve energy
efficiency, regenerators are locateddirectlyundertheovens,
exchanging heat from flue-gaseswith combustion air and/or processgases (COG)•

1.B.1.c••CH4 emissions might occur,
especially from very gassy coalCH4 emissions release possible
from introducing the coal into thewarm oven or displacement of any
COG in the empty oven

FugitiveemissionsCombustion
emissions

heating and firing of the chambers•

Reporting

1.A.1.c•

The coke ovens are charged withprepared coal
Stamp charging might be used tocompact the coking coalNotes

1.A.1.c•

Source and significance of fugitive
emissions

Carbonisation
process emissions
coal handling and preparation, andcharging

Summary of activity (operation)

1.A.1.cCoke production processing stage

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TABLE 4.3.4 (NEW) (CONTINUED)SOURCES OF FUGITIVE GREENHOUSE GAS EMISSIONS FROM COKE PRODUCTION ACCORDING TO PROCESSING STAGE AND REPORTING OF EMISSIONS
Source and significance of fugitive
emissions

Notes

Reporting

Surplus coke oven gas may beflared if no other economic uses
have been found for it, or for
operational safety reasons•

Emissions of N2O and CH4 fromflaring are likely to be higher thanthose from combustion

•

NO

NO

NO

NO

1.B.1.c••

Non-flaring
Fugitives

Flaring of COG

Possibility of very small emissionsof CH4 from residual COG as thecoke is quenched with water. Somereactions of the hot coke with thequenching water are likely

1.B.1.c••

1.B.1.c•

Wet quenching and dry quenching
techniques can be used
Wet quenching consumes large
volumes of water. The temperatureof the coke is reduced from 1 100 to
80 °C to avoid combustion
For dry quenching, the quenching
car takes the hot coke to a verticalquenchingchamber.
Inert
quenching gas circulates around thechamber, which is isolated from theatmosphere, preventing combustion
whilst cooling the coke. The gas iscooled by a heat exchanger in orderto recover thermal energy

Combustion
emissions•1.A.1.ccoke quenching

Fugitiveemissions

Flaring

Summary of activity (operation)

Carbonisation
process emissions

Coke production processing stage

Fugitive emissions from thisactivity will be very small relative
to the other likely fugitive
emissions from coke production

Flaring emissions are counted as
fugitive emissions

Notes:
Routine flaring of large percentages of the COG produced is very unlikely, as it valuable as a fuel. Of the three by-product or derived gases (BFG, COG, Oxygen Steel Furnace Gas) produced in an integrated iron andsteel works, COG has the highest caloric value.

a

NO Emissions Not Occurring

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Chapter 4: Fugitive Emissions

Figure 4.3.3 (New) Decision tree for estimating fugitive emissions from coke production
processes
Start

Are sufficientmeasurements with satisfactory
quality control, or verified modellingstudies available to estimate
emissions accurately?

Yes

Report measurement results,
or report modelling estimates.
Box 4: Tier 3b

No

Are plant-specificcoke activity production data andplant specific fugitive emission
factors available?

Yes

Use plant-specific activity dataand emission factors as a basis
to estimate emissions.
Box 3: Tier 3aNoDocountry-specificemission factors
exist?

Yes

Calculate emissions using country
specific emission factors andnational activity data.
Box 2: Tier 2

No

Is this a
key category?

Yes

No

Estimate emissions using default
emission factors and national
activity data.
Box 1: Tier 1

Collect data for Tier 3
or Tier 2 method.

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Fugitive emissions can occur during coking operations from leakages at the battery, for example, because ofleakage from vessels, oven doors, flanges, or at the by-product plant. Fugitive emissions occur also from theascension pipe and charging hole sealings. The magnitude of these emissions will depend on the coke oventechnology and the level of maintenance. The variability in the magnitude of fugitive emissions will be large.
Specific door emissions vary widely depending upon the type of doors, the size of ovens and the quality ofmaintenance. Maintenance can be a determining factor. Examples of good results with traditional (knife-edged)
doors on well-maintained small ovens and poor results with modern flexible sealing doors on poorly maintainedlarge ovens can be found (Eurofer, 2007).
Because of the high costs of leakage monitoring, there is very little actual data available for fugitive emissions
caused by battery operation.
Coking coal in storage prior to being used in coke batteries may degas and release CH4. The guidance in thissection does not cover the release of CH4 from gassy coal. Inventory compilers should be aware of the possibilityof emissions from this source and estimate and report emissions following the guidance in Section 4.1 of thischapter.

Tier 1
The general form of the equation for estimating emissions for a Tier 1 approach, based on coke production activity,
is given by Equation 4.3.2 below.
EQUATION 4.3.2 (NEW)FUGITIVE GHG EMISSION FROM COKE PRODUCTION=
EmissionsGHG Activitycoke production • Emission FactorGHG
Where:
Emissions GHG= emissions of a given GHG by coke production (kg GHG)

Activity coke production= amount of coke produced (tonnes)

Emission Factor GHG= default emission factor for each GHG (kg GHG/tonne of coke produced)

Tier 2
In a Tier 2 methodology, inventory compilers can use the amount of coke produced, in combination with country
specific emission factors for each GHG.

Tier 3
There are a range of possible Tier 3 approaches. All methodologies used should be transparently documented.
In a Tier 3 methodology, inventory compilers can use the amount of coke produced by each plant in combination
with emission factors, for each GHG, according to coke production processing stage. A Tier 3 approach for one
or more plants could be combined with lower Tier approaches for other plants to derive a national estimate.
It is often the case that coverage of plant level data does not correspond exactly to coverage of classifications
within the national energy statistics, and this can give rise to difficulties in combining the various sources of
information. Methods for combining data are discussed in Chapter 2 of Volume 1 on General Guidance andReporting.
Inventory compilers may also use fugitive emission measurement data for one or more of the coke processing
stages, or, possibly use a model. Ensure that only fugitive emissions are measured, and that combustion or process
emissions are not included in any measurements.
If measurements of fugitive emissions are used, it is good practice for inventory compilers to explain the rationale
behind the emission measurement campaign, how measurements were made, and, if the measurements areapplicable to individual coke batteries only, or, can be applied more widely to other batteries in the country also.
Inventory compilers should present supporting information to justify that the measurement results reflect plant
performance, such as information on the frequency and duration of the measurements and whether the plant was
operating under normal conditions. Any measurement campaigns should focus on the sources in Table 4.3.4
associated with the greatest likelihood of emissions.
Any models used should be verified. Volume 1, Chapter 6 provides guidance on verification approaches that canbe used.

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CHOICE OF EMISSI ON FACTOR
Table 4.3.5 provides default emission factors for fugitive emissions from coke production for use with the Tier 1
methodology.
TABLE 4.3.5 (NEW)DEFAULT EMISSION FACTORS FOR FUGITIVE EMISSIONS FROM COKE PRODUCTION
Gas

Emission Factor

SourceCH40.049 kg / tonne(Hensmann, Haardt, & Ebert, 2011)

Notes:* Factor for “hard-coal-coke production (coking plants)” using horizontal coke batteries. Non-heat recovery ovens* Hensmann, Haardt, & Ebert, 2011. "Emissionsfaktoren zur Eisen- und Stahlindustrie für die Emissionsberichterstattung".
BFI 2011 "Emissionsfaktoren zur Eisen- und Stahlindustrie für die Emissionsberichterstattung“, im Auftrag desUmweltbundesamtes, BFI 2011, FKZ 3707 42 301.

CHOICE OF ACTIVITY DATA
The quantities of coke produced may form the input to methods used to estimate fugitive emissions. Cokeproduction data is normally available in national energy balance data. Plant specific coke production data may also
be available.

UNCERTAINTY ASSESSMENT
The quantities of coke produced are likely to be well known. Uncertainty estimates of production may be available
from energy balance data, or, from plant operators. Fugitive emissions of CH4 and N2O will be highly uncertain,
and, order of magnitude uncertainties on emissions are likely and can be assumed as a first approximation.
Table 4.3.6 provides the uncertainties associated with coke production.
TABLE 4.3.6 (NEW)DEFAULT UNCERTAINTY ASSESSMENT FOR EMISSION FACTORS FROM COKE PRODUCTION
Oven technology

CH4

Overall assessment for alltechnologies-90% to +900%a

Note:
a

Having an uncertainty range from one-tenth of the mean value to ten times the mean value.

Source: Expert judgement

FLARING OF COKE OVEN GAS EMISSI ONS
Surplus coke oven gas may be flared if no other economic uses have been found for it, or for operational safety
reasons and equipment maintenance purposes. Box 4.3.1 provides a summary of flaring activities in metallurgicalcoke and iron and steel production.

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BOX 4.3.1 (NEW)FLARING ACTIVITIES IN METALLURGICAL COKE AND IRON AND STEEL PRODUCTION

Gaseous products from metallurgical coke and iron and steel production are mainly used for the
production of heat and electricity, and in some cases, as reducing agents. A minor proportion of thetotal gas produced, usually less than 5%, is lost from the production stream and then flared. This
flaring occurs mainly during emergencies or during maintenance activities.
Integrated iron and steel facilities usually flare a mix of the gases produced, including coke oven gas(COG), blast furnace gas (BFG) and Oxygen Steel Furnace Gas, at the same stacks. This situation
represents a challenge for the GHGs emissions reporting, because:• GHGs emissions from COG flaring should be reported in the energy sector, category 1.B.1.c.ii.
• GHGs emissions from BFG and Oxygen Steel Furnace Gas flaring should be reported under IPPU.
In an integrated steelworks if there are flares of combined gases where the estimates for COG, BFG
and Oxygen Steel Furnace Gas cannot be determined, then it is considered good practice to report
the emissions in IPPU and seek to minimise the risk of double-counting of emissions reported
elsewhere in the inventory. To minimise this risk, it is important to consider the methods used for
estimating emissions from coke ovens and the other emission sources in the integrated works.
In typical operation of an integrated steelworks, flaring and other losses of COG are minimised due
to its high energy content. BFG is also generally used but in some cases the percentage flared rate is
up to 20%. Typically, Oxygen Steel Furnace Gas is totally or partially flared; however, in somecases it is directly discharged into the atmosphere. Typical ranges for gas flared rates are:GAS FLARED (%)
COKE OVEN GAS (COG)

0.3 TO 2

BLAST FURNACE GAS (BFG)

0.5 TO 20OXYGEN STEEL FURNACE GAS

5.0 TO 100

METHODOLOGICAL ISSUESCHOICE OF METHODS, DECISION TREES, TIERSFor coke oven gas flaring, there are three tiers than can be used to calculate CO2 emissions and two tiers to calculate
CH4 and N2O emissions.
The decision tree in Figure 4.3.4 will help select the Tier to use to estimate CO2 emissions. To select the Tier forCH4 and N2O, use the decision tree in Figure 4.3.5.
When estimating the emissions of CO2 from flaring of coke oven gas, it is important to ensure there is no double
counting of emissions that might have been made as part of carbon balance calculations made in the iron and steel
sector.

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Chapter 4: Fugitive Emissions

Figure 4.3.4 (New) Decision tree for estimating CO 2 emissions from coke oven gas flaring
Start

Are sufficientmeasurements withsatisfactory quality control available
to estimate emissions
accurately?
Yes
Are measurements available at all flare
stacks for all existing
plants?

Use measurements.

Yes

Box 5: Tier 3b

NoNo

Are plantspecific coke oven gas
flared data available for theunmeasured part of thesource category?

Yes

Are plantspecific carbon contents
available for the unmeasured
part of the source
category?

Yes

Use measurements
combined with a carbon
balance approach byplant for the rest of
the sources.
Box 4: Tier 3a

NoNo

Are national
data on quantities ofcoke oven gas flaredavailable?

Are
country-specificcarbon contents
available?

Yes

Yes

Box 3: Tier 2No

No

Is this a
key category?
Is this a
key category?

Yes

Obtainquantities ofcoke ovengas flared.

Use national data oncoke gas flared andcountry-specific cokeoven gas carbon
contents(Equation 4.3.3).

Yes

Get countryspecific carbon
contents of cokeoven gas.

No

Use national data oncoke gas flared anddefault carbon contents(Equation 4.3.3).
Box 2: Hybrid Tier 1/Tier 2No

Is nationalcoke oven gas
production data
available?

No

Use default coke ovengas production data,
percentage flaring
assumption, anddefault carbon contents(Equation 4.3.3).

Yes

Get national coke ovengas production data.

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Box 1: Tier 1

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Figure 4.3.5 (New) Decision tree for estimating fugitive emissions of CH 4 and N 2 O from cokeproduction process
Start

Are sufficientmeasurements withsatisfactory quality control available
to estimate emissions
accurately?
Collect data
for theTier 3 method.

Yes

Use measurement
results.
Box 2: Tier 3

No

Yes

Is this a
key category?
No
Are nationalcoke oven gas production
data available?

No
Get national
production data.

Yes

Use default EFs from
Table 4.3.7 withnational
production data
(Equation 4.3.4).
Box 1: Tier 1

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Chapter 4: Fugitive Emissions

Tier 1 / Tier 2– CO 2
The general form of the equation for estimating emissions for a Tier 1 approach, based on coke production activity,
is given by Equation 4.3.3 below.
EQUATION 4.3.3 (NEW)FUGITIVE CO2 EMISSIONS FROM THE FLARING OF COKE OVEN GAS

Emissions( Activitycoke oven gas produced • RCOG flared • CCcoke oven gas ) •
=
CO2

44
12

Where:
Emissions CO2= emissions of CO2 by coke oven gas flared (kg CO2)

Activity coke oven gas produced= amount of coke oven gas produced (Gj)

R COG flared= fraction of coke oven gas removed from the production stream and thenflared. If this data is not available, a default value of 0.02 can be assumed (seeBox 4.3.1).

CC coke oven gas= Carbon content of coke oven gas (kg of carbon per GJ of coke oven gas)

A default carbon content for coke oven gas should be used, taken from Table 1.3, Volume 2, Chapter 1, 2006
IPCC Guidelines, as shown in Table 4.3.7. For the Tier 1 approach, inventory compilers could assume that therange of COG production per unit of coke production is 360-518 Nm3 COG per tonne coke produced (JRC 2013).
The Tier 2 approach for CO2 requires knowledge of the amount of coke oven gas flared in the country, and the useof country specific carbon content of the coke oven gas produced. If country specific carbon contents for cokeoven gas are not available, default carbon contents could be used. In this case the methodology is a hybrid between
Tier 1 and Tier 2, and is not appropriate to use this if flaring of coke oven gas is a key category.

Tier 3– CO 2
The Tier 3 method requires the collection, compilation and aggregation of facility-specific measured emissions
data. It is good practice for inventory compilers to explain the rationale behind the emission measurement
campaign and how measurements were made. If monitoring data are not available, the Tier 3 method can be
estimated by applying Equation 4.3.3, based on facility-specific data of coke oven gas flared and coke oven gas
carbon content. The total national emissions will equal the sum of emissions estimated for each facility.

Tier 1– CH 4 and N 2 O
The Tier 1 approach for CH4 and N2O from coke oven gas removed from the production stream and then flared isgiven by Equation 4.3.4 below.
EQUATION 4.3.4 (NEW)FUGITIVE CH4 AND N2O EMISSION FROM THE FLARING OF COKE OVEN GAS

Emissions
Activitycoke oven gas produced • RCOG flared • Emission FactorCH 4 , N2O=
CH 4 , N 2 O
Where:
Emissions CH4, N2O= emissions of CH4 and N2O from coke oven gas flaring (Gg GHG)

Activity coke oven gas produced = amount of coke oven gas produced (Gj)
R COG flared= rate of coke oven gas removed from the production stream and then flared. If
this data is not available, a default value of 0.02 can be assumed (2%).

Emission Factor CH4, N2O = emission factor for CH4 and N2O (Gg of greenhouse gas per m3 of coke ovengas produced), taken from Table 4.3.7

Tier 3–CH 4 and N 2 O
The Tier 3 method requires collection, compilation and aggregation of facility-specific measured emissions data.
It is good practice for inventory compilers to explain the rationale behind the emission measurement campaign
and how measurements were made. The total national emissions will equal the sum of emissions estimated foreach facility.

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CHOICE OF EMISSI ON FACTOR
The default carbon content of COG, and, emission factors of CH4 and N2O from coke oven gas flaring are provided
in Table 4.3.7 below.
The CH4 emission factor has been estimated according with the expression indicated in Table 4.3.7, assuming that
2 percent (by volume) of the coke oven gas produced is removed from the production stream and then flared,
considering an average coke oven gas composition, and a default efficiency in flaring.
In flaring waste gases containing nitrogen compounds, N2O is formed either by the fixation of atmospheric nitrogenor by the oxidation of nitrogen compounds in the fuel. Considering that the proportion of nitrogen in coke ovengas is highly variable, but the range is similar to those of the gases flared in oil and gas operation facilities, forTier 1 approach it is assumed that the rate between CO2 and N2O emissions from flaring of coke oven gas is thesame that those used to calculate N2O emission factors in, Table 4.2.4g. With this assumption, N2O emission
factor has been estimated according with the expression indicated in Table 4.3.7.
TABLE 4.3.7 (NEW)DEFAULT FACTORS FOR FUGITIVE EMISSIONS FROM FLARING OF COKE OVEN GAS
GasFactor(kg C/GJ COG flared)

CO2

12.1

Gas

Emission Factor(kg/ GJ COG production
flared)SourceVolume 2, Chapter 1 of 2006 IPCC Guidelines. Table 1.3. Default carbon
content of COG
Source=EFCH 4 FvolCH 4 in COG • (1 − η flaring )Where:
Fvol CH4 in COG: is the volume fraction of CH4 in COG, set as 0.28 (JRC, 2013; Manet al., 2016; Nishifuji et al., 2011) which corresponds to 8.8 kg CH4/Gj COG.
CH4

0.18

The unit conversion has been made using:••

0.716 kg/m3 for CH4 and 0.589 kg/m3 for COG, and38.7 Tj/Gg for COG.

η𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓 : flare efficiency, set as 0.98 (EPA, CFR Title 40, Chapter I, Subchapter
C, Part 98, Subpart W).

 EFN2O
=( EFN2O )COG flaring ( EFCO2 ) COG flaring • (
)Oil and gas production  EFCO2
Where:
N2O

4.9 E-04

4412= 44.4 kg CO2 / GJ COG( EFCO2 ) COG flaring 12.1 kg C / GJ COG •=EFCO2 and EFN2O are set as 3.0 E-03 and 3.3 E-08 Gg gas per 106 m3 gas
produced.

CHOICE OF ACTIVITY DATA
The amount and types of COG produced could be obtained from one, or a combination, of the sources in the list
below:• national energy statistics agencies (national energy statistics agencies may collect data on the amount and typesof COG produced from individual enterprises that produce fuels);• reports provided by enterprises to national energy statistics agencies (these reports are most likely to be
produced by the operators or owners of large plants);

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Chapter 4: Fugitive Emissions• reports provided by enterprises to regulatory agencies (for example, reports produced to demonstrate howenterprises are complying with emission control regulations);• periodic surveys, by statistical agencies of the types and quantities of COG produced by a sample of enterprises.

UNCERTAINTY ASSESSMENT
If direct measurements of COG flared are used, inventory compilers should estimate and report uncertainties
associated with the measurements.
Table 4.3.8 provides the uncertainties associated with the COG carbon contents and the emission factors of CH4
and N2O.
TABLE 4.3.8 (NEW)DEFAULT UNCERTAINTY ASSESSMENT FOR EMISSION FACTORS FROM COKE OVEN GAS FLARING
CO2

CH4

N2O

±75%

±75%

±75%

Note:
Uncertainties reproduced from Volume 2, Chapter 4, 2006 IPCC Guidelines. Table 4.2.5. Default weighted total

Table 1.3 of Volume 2, Chapter 4, 2006 IPCC Guidelines provides lower (10.3 kg/GJ) and upper (15.0 kg/GJ) default
carbon contents of COG. This equates to a 95 percent uncertainty range, in percentage terms with respect to thedefault factor, of -12 to +19 (see Box 3.0b, Chapter 3, Volume 1 of the 2019 Refinement).

COMPLETENESS
When estimating the emissions of CO2 from flaring of coke oven gas, it is important to ensure there is no double
counting of the emissions accounted for non-fugitive emissions from coke production, whose methodology is
described in Chapter 4, Volume 3 of the 2006 IPCC Guidelines and in Chapter 4 Volume 3 of the 2019 Refinement.
Care should be taken with any adjustments for COG used in the energy fuel combustion calculations.
If non-fugitive emissions are estimated using Tier1b approach, it is assumed that all the coke oven gas produced
is burned on site for energy recovery, and therefore CO2 emissions from flaring are equal to zero. If Tier 2 or Tier
3 approaches are applied to estimate emissions from non-fugitive sources, double counting is avoided if theemissions from flaring are deducted in the carbon balance (see Equation 4.2, Chapter 4, Volume 3 of the 2019
Refinement).

4.3.2.2

G ASIFI CATION TRANSFORMATION PROCESSES

Gasification transformation processes are related to the transformation of biomass, coal or natural gas into syngas,
composed of H2, CO, CO2 and CH4, and, then, into a liquid hydrocarbons fuels. These processes are called biomass
to gaseous (BtG), biomass to liquid (BtL), coal to liquid (CtL) and gas to liquid (GtL).
The syngas can be used as a fuel to generate electricity through a gas turbine or as a chemical feedstock (Van derDrift and Boerrigter, 2006; OECD/IEA, 2007). The liquid fuels production is obtained through the Fischer-Tropsch
process, where the syngas, after cleaned to remove CO2, CH4, impurities such as sulphur bearing compounds (inparticular H2S), and heavy metal bearing compounds, is transformed into high-quality fuels like gasoline, diesel
and aviation fuels. Figure 4.3.6 shows the process of gasification transformation.

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Figure 4.3.6 (New) Gasification transformation process of biomass, coal and gas

O2 + steam
Biomass
Coal
Gas

Gasification(Syngas generation)

CO2 + CH4 + impurities

Syngas(H2 + CO +CO2 + CH4)

Syngas Cleaning

CO + H2

Gasoline
DieselAviation Fuels

Product Recovery(higher hydrocarbons)Fischer-Tropsch Synthesis

BtG and BtL are still emerging technologies, and there are currently very few large-scale plants worldwide.
However, considering that they are likely to become more widely adopted, methodologies to estimate the fugitive
emissions of these processes are provided in Appendix 4A.3 as indicative methodologies. It is important tohighlight, however, that current data are inconsistent and improved methods and data may be available in the future.
CtL and GtL fugitive emissions estimation methodologies are provided below. Table 4.3.9 shows GHGs emissions
from CtL and GtL processes.
TABLE 4.3.9 (NEW)SUMMARY OF GHG EMISSIONS FROM GASIFICATION TRANSFORMATION PROCESSES
Synthetic fuel production Process

GHGs

CtL

CO2, CH4, N2O

GtL

CO2

COAL TO LIQUI DS
Synthesis gas from CtL is generated by feeding coal into a gasification process. This synthesis gas containing a
mixture of CO, H2, CO2 and CH4 is fed into a gas cleaning process where impurities such as sulphur bearing
compounds (in particular H2S), and heavy metal bearing compounds are removed from the synthesis gas. Aftercleaning, the synthesis gas composition is adjusted in a process called water-gas shift conversion. Here the ratioof H2 to CO is adjusted to produce a synthesis gas which is optimal for Fischer-Tropsch synthesis. After water-gas
shift conversion the modified synthesis gas is fed to the Fischer-Tropsch synthesis process where it reacts to
produce liquid hydrocarbons. A significant fraction of CtL plant CO2 is generated in the gasification process whichneeds to be separated before the syngas is fed into the FT reactor (Mantripragada and Rubin, 2011). Current
production levels mainly from CtL plants are estimated at over 300,000 Barrels Per Day (BPD) with a conservative
annual estimate of 120 million tons of CO2 equivalent (Childress, 2008).

GAS TO LIQUIDSNatural gas is combined with steam and pure oxygen from a cryogenic air separation unit before it is heated andfed into an autothermal reformer (ATR). Syngas, a mixture of H2 and CO, leaves the ATR and enters the FischerTropsch (FT) synthesis reactor, where it is converted to a hydrocarbon wax. The wax exiting the FT reactor is
upgraded in the product work-up unit to yield approximately 70 percent diesel and 30 percent naphtha liquid
products. A steam-methane reforming hydrogen plant is required to provide hydrogen for the product upgrading
as well as inlet natural gas pre-treatment. The GtL plant CO2 is generated from several sources (Heimel & Lowe,2009):• Entering with the inlet natural gas (feed gas assumed to contain 1.6 mol percent CO2);• Forming during syngas generation;• Forming in the FT reactor;• Forming in the hydrogen plant;• Forming in the process heating furnaces.

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Chapter 4: Fugitive Emissions

All these sources are considered in the quantification of fugitive CO2 emissions from a GtL plant. GtL technology
in particular as alternative to petroleum based diesel is considered to be one of the less carbon-intensive technicaloptions to reduce petroleum consumption in the on-road transportation sector (Hao et al, 2010). The worldwide
syngas database produced by the Gasification and Syngas Technologies Council (GSTC) shows that there are morethan thirty (30) projects that are either in operation or under development (GSTC, 2014). Hao et al estimated GtL
capacity to be 35,000 BPD in the year 2010 and projected an increase in capacity to 1-2 million BPD by 2015
(Hao et al, 2008).

METHODOLOGICAL ISSUES
The choice of method will depend on the technologies that are operational in countries, including whether thetechnologies analysed in this section are key categories in the country, and to what extent country and plantspecific information is available or can be gathered.
The most accurate estimates for fugitive emissions, can be developed by determining the emissions on a plant-byplant basis and/or differentiated for each feedstock category (e.g., type of biomass, coal or gas). The methods for
estimating CO2, CH4 and N2O fugitive emissions from these technologies vary because of the different factors that
influence emission levels. N2O emissions from coal gasification are negligible and depends on the nitrogen content
of the coal.
The general approach to calculate greenhouse gas emissions from those technologies is to obtain the amount offeedstock used and to investigate the related greenhouse gas emission factors, preferably from country-specificinformation on the carbon content. In the case of CtL, the resultant syngas produced from gasification of coal isused as activity data.

CHOICE OF METHODS, DECISION TREES, TIERSThere is limited information about gasification transformation technologies and, therefore, it was considered thatfugitive emissions occur only at the gasification stage. The fugitive emissions resulting from the syngastransformation at the Fischer-Tropsch (FT) stage was considered negligible, as most emissions at FT stage are
related to combustion processes to produce heat.
The method for estimating fugitive emissions from GtL technologies is based on an estimate of the carbon content
in the feedstock used and converting the product to greenhouse gases emissions. The activity data are the feedstock
inputs into the gasification stage, and the emission factors are based on the carbon content of the feedstock.
The CtL process produces the bulk volume of greenhouse gas emissions during the production and treatment ofsyngas. This, the method for estimating fugitive emissions from CtL technologies is based on the amounts ofsyngas produced in terajoules.
The choice of method depends on the country specific information available, and is given in the decision tree in
Figure 4.3.7.

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Figure 4.3.7 (New) Decision tree for estimating emissions of CO2, CH4 and N2O from Gasification Transformation
processes
Start

Do gasification
processes occur in the
country?

No

There are no fugitive-related
emissions from gasification
processes. Report emissions
as not occurring.
Box 4: Emissions not occurringYes

Are detailed
carbon content, carbon flows
and process stream component
speciation data available
for each plant?

Yes

Collect plant-specific activity
data on carbon content,carbon flows and process
stream component speciationas basis to estimate emissions
using a Tier 3 method.
Box 3: Tier 3NoDo
country-specificemission factors
exist?

Yes

Calculate emissions fromgasification process using
country-specific emission
factors and activity data.
Box 2: Tier 2

No
Is this a
key category?
YesNo

Calculate emissions fromgasification process using
default emission factors.
Box 1: Tier 1

Collect data for
the Tier 3 or the
Tier 2 method.

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Chapter 4: Fugitive Emissions

Tier 1The Tier 1 method is a simple method that can be used when fugitive emissions from CtL and GtL technologies
are not significant.
Fugitive emissions of CO2, CH4 and N2O can be estimated from the amount of syngas (CtL) or natural gas (GtL)
and the emission factor of fugitive emission. The application of a Tier1 approach is done using Equation 4.3.5
presented below.
EQUATION 4.3.5 (NEW)FUGITIVE GHG EMISSIONS FROM GASIFICATION PROCESSES

Egas i = ( FS j • EFi ) • 10−6
Where:
Egas i = direct amount (Gg/yr) of GHG gas i emitted at gasification station of CtL and GtL facilities (CO2,CH4 and N2O)
FSj

= total amount of feedstock of type j (TJ) in the case of GtL and total amount of syngas produced(TJ) in the case of CtLEFi= gas i emission factor, kg gas i/TJ of feedstock j (GtL) or gas i emission factor, kg gas i/TJ of syngas
produced (CtL)

10-6= conversion factor from kilogram to Gg

Tier 2
CtL and GtL plants are versatile and depending on their process unit arrangement downstream, they are able toproduce a wide range of products. Some CtL/GtL plants are able to produce a combination of liquid fuels andchemicals (e.g. Ammonia (NH3), Nitric Acid (HNO3), methanol (CH3OH), etc.). This in turn affects the rate at
which syngas is produced upstream. The quality of coal used determines the quality of syngas and the effort needed
to treat syngas. Hence, it is good practice to develop a Tier 2 emission factor based on plant-specific emission
factors as opposed to country-specific emission factors that are developed by aggregating plant-level emission
factors for a country in question.

Tier 3The most appropriate Tier 3 approach is a material balance methodology. This is largely because, the CtL process
in particular is a very versatile process. Depending on the type and volume of downstream products (chemicals or
liquid fuels), the amount of syngas to be processed via the Fischer-Tropsch process can be varied. That in turn,affects the amount of syngas that needs to be produced upstream. Variation in the production of syngas affects theamount of Greenhouse Gas emissions released in the atmosphere. Secondly, the syngas production and treatment
processes release a large volume of flue gas stream that is almost impossible to measure. Hence, a direct
measurement methodology is not ideal for CtL and GtL processes. Preferable a Tier 3 stoichiometric/mass-balancemethodology should be followed.

CHOICE OF EMISSI ON FACTOR
Coal to liqui ds
Higman and van der Burgt (2008) presents process-specific CO2, CH4 and N2O emission factors as a function ofsyngas production and by process type. It is worth noting that for the CtL process, the bulk volume of greenhousegas emissions are released during the production and treatment of syngas. Table 4.3.10 presents emission factors
reported by Higman and van der Burgt. These emission factors have been developed for typical current
international values and ranges of coal qualities (20.7 -27.3 kJ/kg HHV). Coal Gasification systems considered
are the Air Separation Unit (ASU), Oxygen blown fixed-bed BGL 1000 gasifier, acid gas removal (Rectisol).

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TABLE 4.3.10 (NEW)EMISSION FACTORS FOR GASIFICATION PROCESSES OF CTL
System Output

SyngasSyngas/H2SNGa

CO2 emissions, kg CO2/TJ
total outputb

55 00055 00078 000CH4 emissions, kg CH4/TJ
total outputb

6.1

6.1

6.1

N2O emissions, kg N2O/TJ
total outputb

0

0

0

a Synthetic Natural Gas.
b

Higman, van der Burgt: “Gasification”, 2nd edition (2008).

Gas to liquids
Jaramillo et al. analysed CO2 emissions released during syngas production in CtL and GtL plants (Jaramillo et al,2008). The study by Jaramillo et al (2008) assumes that slightly more diesel is produced than gasoline. This
assumption is plausible given that a conventional GtL plant produces 62 percent Diesel, 44 percent gasoline and 3
percent propane (Jaramillo et al, 2008). The CO2 emission factor is therefore derived from the inputs and outputsof a conventional GtL plant by dividing the amount of carbon lost (assuming 100 percent oxidation) with thevolume of natural gas input to produce syngas. CO2 is the most dominant GHG in the GtL process and therefore,
it is a conservative approach to assume that 100 percent of carbon lost to the atmosphere is CO2. Table 4.3.11
presents CO2 emission factors of GtL gasification process.
TABLE 4.3.11 (NEW)EMISSION FACTOR FOR GASIFICATION PROCESSES OF GTL
Process

EF CO2 (kgCO2/TJ natural gas input)

Gas to liquidsa12,730aJaramillo et al. 2008. Converted from mass units for natural gas to energy units

CHOICE OF ACTIVITY DATA
Coal to liqui ds
The activity data required for a Tiers 1 and 2 are the amounts of syngas produced in terajoules (TJ). Since this data
is monitored continuously at individual plant level, it is good practice to collect syngas production data from eachplant.
For the Tier 3 method, carbon mass flow and species composition data is required to accurately quantify the amountof GHGs in the flue gas streams. Even though the amount of syngas produced is not necessary as activity data fora Tier 3 method, it is good practice to collect and report these data in comparing the results of the Tier 3 method(material balance) against the Tier 1 method.

Gas to liquids
The activity data required for Tiers 1 and 2 is the amounts of natural gas inputs into the GtL process in terajoules(TJ). Natural gas may be used upstream of the GtL plant for heat and electricity production during production.
Therefore, it is good practice to ensure that the amount of natural gas used for electricity and heat during natural
gas production is separated from the amount of natural gas used as a feedstock in the GtL plant. Inventory
compilers have to use default density at standard temperature and pressure for natural gas to convert the amountof natural gas inputs from volumetric basis to mass basis.
For a Tier 3 method, carbon flows and species composition are required to quantify the amount of carbon in eachprocess stream and process unit inside a GtL plant. This information is monitored continuously during processcontrol and therefore should be readily available from each plant.

UNCERTAINTY ASSESSMENT
Gasification Transformation Processes
Estimates of fugitive emissions from gasification transformation processes can be highly uncertain due to lack of
information about these technologies. More research and development is needed on these technologies, especiallydirect measurement on all stages to confirm which ones present fugitive emissions.

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Chapter 4: Fugitive Emissions

Activity data uncertainties
The quantities of feedstocks used (e.g. in the cased of GtL or biomass) or syngas produced (e.g. in the case of CtL)
are likely to be well known. Uncertainty estimates of production may be available from energy balance data, or,from plant operators. Fugitive emissions of CO2, CH4 and N2O will be highly uncertain, and, order of magnitudeuncertainties on emissions are likely and can be assumed as a first approximation.

Emission factor uncertainties
Considering the minimal literature and the absence of large scale fuel transformation processes, fugitive emission
factors provided in these guidelines were estimated based on a very few data, resulting in a high level of
uncertainty. Table 4.3.12 provides the uncertainties associated with the emission factors of CO2, CH4 and N2O.
TABLE 4.3.12 (NEW)DEFAULT UNCERTAINTY ASSESSMENT FOR EMISSION FACTORS FROM GASIFICATION TRANSFORMATION PROCESSES
Gasificationtransformation process
technology

CO2

CH4

N2O

Overall assessment for alltechnologies-90% to +900% a-90% to +900% a-90% to +900% a

Note:
a

Having an uncertainty range from one-tenth of the mean value to ten times the mean value.

Source: Expert judgement

4.3.3

CompletenessThis section of the GLs is currently not able to provide a set of methods to estimate fugitive emissions from all thepossible parts of each of the sources. But it is good practice for inventory compliers to ensure completeness andto try and estimate emissions if possible. But resources should be prioritised according to the key category analysis
results.
Where a country has estimated its fugitive emissions based on an aggregation of estimates reported by individual
plants, it is good practice to document the steps taken to ensure that these results are complete, transparent andconsistent across the time series. Corrections made to account for companies or facilities that did not report, andmeasures taken to avoid missed or double counting (particularly where ownership changes have occurred) and toassess uncertainties should be highlighted. Care should be taken to ensure that CO2 emissions from coal combusted
for production of syngas are counted separately from CO2 emissions arising from syngas production through coalgasification. Production of town gas is also considered a gasification process. Town gas originates from outgassingof hard coal under air exclusion in retort furnace or chamber kilns. A methodology for this source is not currently
available. If a method should become available, emissions from these processes could be reported under 1.B.1.c.iv
Gasification Transformation.

4.3.4

Developing consistent time series

Ideally, emission estimates will be prepared for the base year and subsequent years using the same method. The
aim is to have emission estimates across the time series reflect true trends in greenhouse gas emissions. Emission
or control factors that change over time (e.g., due to changes in source demographics or the penetration of control
technologies) should be regularly updated and, each time, only applied to the period for which they are valid. For,
example, if an emission control device is retrofit to a source then a new emission factor will apply to that sourcefrom then onwards; however, the previously applied emission factor reflecting conditions before the retrofit shouldstill be applied for all previous years in the time series. If an emission factor has been refined through further
testing and now reflects a better understanding of the source or source category, then all previous estimates should
be updated to reflect the use of the improved factor and be reported in a transparent manner.
A country should assess which technologies and practices are generally in place in the country and apply thecorresponding emission factor. As technologies and practices change over time, it is possible that a country will
use one EF in some years and another in other years. A compiler should assess the time frame over which changes
took place, and consider linear interpolation or other techniques to incorporate the trend from one emission factor
to another over the time series.
Where some historical data are missing, it might still be possible to use source-specific measurement results
combined with back-casting techniques to establish an acceptable relationship between emissions and activity data

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in the base year. Approaches for doing this will depend on the specific situation, and are discussed in general termsin Volume 1 Chapter 5 of the 2006 IPCC Guidelines.
If emission estimates are developed based on an aggregation of individual company estimates, greater effort will
be required to maintain time series consistency, particularly where frequent facility ownership changes occur anddifferent methodologies and emission factors are applied by each new owner without also carrying these changes
back through the time series.

4.3.5

Inventory Quality Assurance/Quality Control(QA/QC)Specific QA/QC procedures to optimise the quality of estimates of emissions are given in Chapter 6 of Volume 1,
General Guidance and Reporting.
The bullet point list below identifies good practice in estimating fugitive emissions from the sources included inthis section of the guidance:• Charcoal and biochar production: it is good practice to ensure that emissions from charcoal and biochar
production are based on activity data that are mass- or energy-based measurements of charcoal and biochar
produced. Note that in many countries it is common practice to report the production of these products basedon the number of bags of fuel produced, so these data will need to be converted to fuel mass estimates.
• Coke production: it is good practice to to conduct checks on the total reported fugitive emissions from cokeproduction against emissions from other source categories in the iron and steel sector. Fugitive emissions are
typically only a very small fraction of the total emissions in the iron steel sector.
• For fugitive emissions from CtL and GtL, it is good practice to ensure that the quantity of feedstocks used (e.g.
natural gas for GtL and coal used to produce syngas in the case of CtL) is comparable to the amount of natural
gas and coal reported as feedstock for these fuel transformation industries which is subtracted in the reference
approach for CO2 under stationary combustion.
• Biomass to liquids and biomass to gas: it is good practice to consult with industrial operators to confirm thescope and origin of fugitive emissions, i.e. to confirm at which stage(s) of the transformation processes thatfugitive emissions arise, and to document the findings in the annual submission.

4.3.6

Reporting and Documentation

It is good practice to document and archive all information required to produce the national emissions inventory
estimates, as outlined in Volume 1 Chapter 8 of the 2006 IPCC Guidelines.
It may not be practical to include all supporting documentation in the inventory report. However, at a minimum,
the inventory report should include summaries of the methods used and references to source data such that thereported emissions estimates are transparent and the steps in their calculation may be retraced. For segments wherea technology- or practice-specific Tier 1 emission factor is used, the rationale for selecting that factor and themethod for applying the factors over the time series must be clearly documented. It is expected that many countries
will use a combination of methodological tiers to evaluate the amount of fugitive greenhouse gas emissions. The
specific choices should reflect the relative importance of the different subcategories and the availability of the data
and resources needed to support the corresponding calculations.
Recalculations should be clearly documented, explaining changes that have been made to emission factors, or
methodologies. The steps taken to ensure time series consistency should be documented.
The above reporting and documentation guidance is applicable to all methodological choices. Where Tier 3
approaches are employed, it is important to ensure that either the applied procedures are detailed in the inventory
report or that available references for these procedures are cited since the IPCC Guidelines do not describe astandard Tier 3 approach.

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Chapter 4: Fugitive Emissions

Annex 4A.1

Standard Conditions

Standard conditions

The Tier 1 EFs listed in the Tables 4.2.4 – 4.2.4k are sensitive to temperature and pressure. Activity data must be
consistent with the EFs standard conditions. The EFs are given at the most commonly used standard conditions:15°С and 101.325 kPa (1 atm). If activity data are derived at reference conditions, which are different from thoseused by the Tier 1 EFs, the inventory compiler should harmonize activity data with 15°С and 101.325 kPa. Pressure
is normally fixed for most of the standard conditions at the level of 101.325 kPa (1 atm). Thus, in general, probablevariations of reference temperature should be considered as a priority.
Along with the physical state, activity data can be split into liquids (oil) and gases (natural gas and associatedpetroleum gas). Different correction approaches of gases and liquids are required.

Liquids (oil)

Liquids may be referenced at 20°C and 15°C. In order to harmonize oil units referenced at 20°C to the Tier 1 EFs,
correction can be made with the use of international standard tables of conversion factors (CFs) and densities basedon detailed data on oil properties. Standard tables can be found in internationally recognized sources as follows:•

ASTM D 1250-8 Standard Guide for Use of the Petroleum Measurement Tables issued by American Society
for Testing and Material (ASTM International 2013);•

API MPMS 11.1:2004. American Petroleum Institute. Manual of Petroleum Measurement Standards Chapter
11 - Physical Properties Data Section 1 - Temperature and Pressure Volume Correction Factors for
Generalized Crude Oils, Refined Products, and Lubricating Oils (American Petroleum Institute (API) 2004).

As follows from the standard, the correction approach is based on the equations listed below (Equations 4A.1.1 to
4A.1.3) ((GOST 2012) R 8.595-2010):
EQUATION 4A.1.1 (NEW)CONVERSION OF OIL DENSITY AT 15°C

ρ15 = ρ 20 • K15

EQUATION 4A.1.2 (NEW)CONVERSION OF RELATIVE OIL DENSITY AT 15.556°C (60°F)

ρ60/60 = ρ 20 • K 60/60

EQUATION 4A.1.3 (NEW)CONVERSION OF API DENSITY

ρ API = ρ 20 • K API
Where:
ρ15= oil density at 20°C, kg/m3;

ρ20= oil density at 15°C, kg/m3;

K15= oil density at 20°C to oil density at 15°C conversion factor;

ρ60/60 = relative oil density at 60°F (15.556°C);
ρAPI= API oil density, °API;

K60/60 = oil density at 20°C to relative oil density at 60°F conversion factor 103(kg/m3);
KAPI= oil density at 20°C to relative oil API density conversion factor, °АРI/(kg/m3);

Uncertainties of correction approach are less than 0.01kg/m or 0.01°API, less than 0.01 percent of oil volume.

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Gaseous ( natural gas and APG)

Since for the most cases the pressure fixed at the 101.325 kPa (1 atm), the temperature correction can be performed
as follows (Equation 4A.1.4).
EQUATION 4A.1.4 (NEW)CONVERSION OF GAS VOLUME

V=
Vg • CFtstWhere:
Vst = gas volume at the required reference conditions, m3;
Vg= gas volume at the given reference conditions, m3;

CFt = conversion factor, dimensionless.
According to the equation, initial gas volume should be multiplied by the conversion factor to obtain the gas
volume at the required temperature. The factors are derived by means of ideal gas equation at the pressure fixedat the level of 101.325 kPa (1 atm). The conversion factors are shown at Table 4A.1.1.
TABLE 4A.1.1 (NEW)CORRECTION OF GAS VOLUMES TO THE REQUIRED TEMPERATURE CONVERSION FACTORS (CFT)
To
From

15°C

0°C

1.055

20°C

0.983

The difference between ideal and real volumes of APG and natural gas is within 0.55 percent. This difference canbe used to calculate uncertainty of the correction.

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Chapter 4: Fugitive Emissions

Annex 4A.2

Disaggregation of Tier 1 factors presented in
Section 4.2.2.3

This Annex presents the percent of emissions that are leaked, vented, and flared in the data sets used for the Tier
1 emission factors. To disaggregate the aggregate Tier 1 EF in the 2019 Refinements into emissions “leaked,”“vented,” and “flared,” apply the percent below to the corresponding aggregated value presented in Section 4.2.
For an example of this calculation, see Box 4A.2.1 below.
The disaggregation was developed by reviewing the underlying data sets for the emission factors, assigningemission sources to leaked (e.g., emissions leaked from a pipeline), vented (e.g., emissions from venting for liquids
unloading), and flared (e.g., emissions from flaring at well completions) emissions, and calculating the percent of
total emissions in each category of leak, vent, and flare. Note likely that the fraction of emissions in each category
may vary considerably from country to country and over time.

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TABLE 4A.2.1 (NEW)DISAGGREGATION OF TIER 1 EMISSION FACTORS FOR OIL EXPLORATION, 1.B.2.A.I
Category

Oil Exploration

Oil Exploration

Oil Exploration

4.128

Sub-category

Onshore unconventional
without flaring or recovery

Onshore unconventionalwith flaring or recovery

Onshore conventional

Emission source

CH4

CO2

NMVOC

N2O

Leaks

0%

0%

0%

0%

Vents

98%

2%

98%

0%

Flares

2%

98%

2%

100%

Leaks

0%

0%

0%

0%

Vents

48%

0%

48%

0%

Flares

52%

100%

52%

100%

Leaks

0%

0%

0%

0%

Vents

79%

0%

79%

0%

Flares

21%

100%

21%

100%

Application
Apply percentages to applicable
EF (EF based on wells drilled,
active oil wells, or onshore oil
production)

Apply percentages to applicable
EF (EF based on wells drilled,
active oil wells, or onshore oil
production)

Apply percentages to applicable
EF (EF based on wells drilled,
active oil wells, or onshore oil
production)

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Chapter 4: Fugitive Emissions

TABLE 4A.2.2 (NEW)DISAGGREGATION OF TIER 1 EMISSION FACTORS FOR OIL PRODUCTION SEGMENT, 1.B.2.A.II
Category

Onshore Production

Onshore Production

Oil Sands Mining
and Ore Processing

Sub-category

Most activities occurring withhigher- emitting technologies
and practices

Most activities occurring withlower-emitting technologies
and practices

All

Emission source

CH4

CO2

NMVOC

N2O

Leaks

7%

0%

7%

0%

Vents

83%

3%

83%

0%

Flares

10%

97%

10%

100%

Leaks

9%

0%

9%

0%

Vents

78%

1%

78%

0%

Flares

13%

99%

13%

100%

Leaks

2%

0%

21%

0%

Tailings Ponds

91%

47%

46%

-

Exposed Mine Surface

6%

30%

33%

-

Vents

0%

3%

-

-

Flare

0%

19%

0%

100%

2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

Application
Apply percentages toapplicable EF (EF based oneither onshore oil production,or active oil well)

Apply percentages toapplicable EF (EF based oneither onshore oil production,or active oil well)

Apply percentages toapplicable EF (EF based on
crude bitumen production
from surface mining)

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TABLE 4A.2.2 (NEW) (CONTINUED)DISAGGREGATION OF TIER 1 EMISSION FACTORS FOR OIL PRODUCTION SEGMENT, 1.B.2.A.II
Category

Oil Sands
Upgrading

Offshore Oil
Production

4.130

Sub-category

All

All

Emission source

CH4

CO2

NMVOC

N2O

Leaks

8%

0%

39%

0%

Vents

82%

82%

53%

-

Flare

11%

18%

8%

100%

Leaks

20%

0%

20%

0%

Vents

80%

3%

80%

0%

Flare

0%

97%

0%

100%

Application
Apply percentages toapplicable EF (EF based onsynthetic crude oil
production)
Apply percentages to applicable
EF (EF based on offshore oil
production)

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Chapter 4: Fugitive Emissions

TABLE 4A.2.3 (NEW)DISAGGREGATION OF TIER 1 EMISSION FACTORS FOR OIL REFINING, 1.B.2.A.IV
Category

Sub-category

Oil Refining

All

Emission source

CH4

CO2

NMVOC

N2O

Application

Leaks

99%

45%

98%

1%

Flares

1%

55%

2%

99%

Apply percentages to applicable EF (EFbased on thousand cubic meters oil
refined)TABLE 4A.2.4 (NEW)DISAGGREGATION OF TIER 1 EMISSION FACTORS FOR GAS EXPLORATION, 1.B.2.B.I
Category

Gas Exploration

Gas Exploration

Gas Exploration

Sub-category

Unconventional
without flaring or
recoveryOnshoreunconventional gas
exploration withflaring or gas
captureOnshoreconventional Gas
exploration

Emission source

CH4

CO2

NMVOC

N2O

Leaks

0%

0%

0%

0%

Vents

100%

90%

100%

0%

Flares

0%

10%

0%

100%

Leaks

0%

0%

0%

0%

Vents

8%

0%

8%

0%

Flares

92%

100%

92%

100%

Leaks

0%

0%

0%

0%

Vents

99%

0%

99%

0%

Flares

1%

100%

1%

100%

2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

Application

Apply percentages to applicable EF (EFbased on wells drilled, active gas wells, oronshore gas production)

Apply percentages to applicable EF (EFbased on wells drilled, active gas wells, oronshore gas production)

Apply percentages to applicable EF (EFbased on wells drilled, active gas wells, oronshore gas production)

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TABLE 4A.2.5 (NEW)DISAGGREGATION OF TIER 1 EMISSION FACTORS FOR GAS PRODUCTION, 1.B.2.B.II*
Category

Sub-category

Emission source

CH4

CO2

NMVOC

N2O

Leaks

11%

4%

11%

0%

Onshoreproduction

Onshore: Most
activities
occurring withhigher-emitting
technologies
and practices

Vents

89%

31%

89%

0%

Flare

0%

65%

0%

100%

Onshore: Most
activities
occurring withlower-emitting
technologies
and practices

Leaks

15%

2%

15%

0%

Vents

84%

6%

84%

0%

Flare

0%

92%

0%

100%

Leaks

53%

0%

53%

0%

Vents

44%

3%

44%

0%

Flare

3%

97%

3%

100%

Leaks

23%

0%

23%

0%

Vents

77%

1%

77%

0%

Flare

0%

99%

0%

100%

OnshoreProduction

OnshoreProduction –Coal Bed
MethaneOffshore Gas
production

All

All

Application

Apply percentages to applicable EF (EFbased on either gas production or gas
wells)

Apply percentages to applicable EF (EFbased on either gas production or gas
wells)

Apply percentages to applicable EF (EFbased on coal bed methane production)

Apply percentages to EF (EF based on
offshore gas production)*Values may not sum due to rounding.

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Chapter 4: Fugitive Emissions

TABLE 4A.2.6 (NEW)DISAGGREGATION OF TIER 1 EMISSION FACTORS FOR GAS PROCESSING SEGMENT, 1.B.2.B.III
Category

Sub-category

Emission source

CH4

CO2

NMVOC

N2O

Leaks

5%

0%

5%

0%

Gas Processing

Without LDAR,
or with limited
LDAR, or less
50% ofcentrifugal
compressors
have dry seals

Vents

95%

1%

95%

0%

Flare

0%

99%

0%

100%

Extensive
LDAR, andaround 50% ormore ofcentrifugal
compressors
have dry seals

Leaks

4%

0%

4%

0%

Vents

91%

1%

91%

0%

Flare

5%

99%

5%

100%

Vents

100%

100%

100%

100%

Gas Processing

Gas processing

Sour gas (acidgas removal)

2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

Application

Apply percentages to applicable EF (EFbased on either gas processed or gas
produced)

Apply percentages to applicable EF (EFbased on either gas processed or gas
produced)

Apply percentages to applicable EF (EFbased on either gas processed or gas
produced)

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TABLE 4A.2.7 (NEW)DISAGGREGATION OF TIER 1 EMISSION FACTORS FOR GAS TRANSMISSION SEGMENT, 1.B.2.B.IV
Category

Sub-category

Emission source

CH4

CO2

NMVOC

N2O

Leaks

62%

27%

67%

NA

Gas
Transmission

Limited LDARor less than
50% ofcentrifugal
compressors
have dry seals

Vents

38%

12%

33%

NA

Flare

0%

61%

0%

NA

Leaks

67%

17%

46%

NA

Vents

33%

9%

54%

NA

Flare

0%

74%

0%

NA

Leaks

72%

22%

72%

NA

Vents

28%

7%

28%

NA

Flare

0%

71%

0%

NA

Leaks

69%

14%

69%

NA

Vents

31%

6%

31%

NA

Flare

0%

79%

0%

NA

Gas
Transmission

Gas Storage

Gas Storage

4.134

Extensive
LDAR, andaround 50% ormore ofcentrifugal
compressors
have dry seals
Limited LDAR
or mostactivities
occurring withhigher-emitting
technologies
and practices
Extensive
LDAR andlower-emitting
technologies
and practices

Application

Apply percentages to applicable EF (EFbased on either gas consumption or
kilometre pipeline)

Apply percentages to applicable EF (EFbased on either gas consumption or
kilometre pipeline)

Apply percentages to EF (EF based on gas
consumption)

Apply percentages to EF (EF based on gas
consumption)

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Chapter 4: Fugitive Emissions

TABLE 4A.2.7 (NEW) (CONTINUED)DISAGGREGATION OF TIER 1 EMISSION FACTORS FOR GAS TRANSMISSION SEGMENT, 1.B.2.B.IV
Category

LNG: Import/
Export

LNG: Storage

Sub-category

All

All

Emission source

CH4

CO2

Leaks

6%

0%

Vents

91%

0%

Flare

3%

100%

Leaks

91%

0%

Vents

0%

0%

Flare

9%

100%

2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

NMVOC

N2O

Application

Apply percentages to EF (EF based on
number of stations)

Apply percentages to EF (EF based on
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BOX 4A.2.1 (NEW)EXAMPLE OF CALCULATION OF DISAGGREGATED EMISSION ESTIMATES FOR OIL PRODUCTION

Oil production in Country A occurs entirely onshore. The compiler has assessed available data on
technologies and practices and determined that the most appropriate factor is the one for “mostactivities are occurring with higher-emitting technologies and practices” (i.e., the compiler either
does not have information to assess that low-emitting technologies are prevalent, or has assessedthat more than 5 percent of associated gas is vented, or more than 30 percent of tank throughput isuncontrolled (e.g. without flaring or VRUs), and that the best available activity data is active onshore
oil well counts. In year 2017, country A had 100,000 active onshore oil wells. The table below
demonstrates how Country A would use a Tier 1 approach to calculate total emissions for oil
production in 2017, and disaggregated emissions for oil production in 2017.
EXAMPLE CALCULATION OF DISAGGREGATED EMISSION ESTIMATE FOR OIL PRODUCTION

CH4

CO2

NMVOC

N 2O

Calculation of Total Emissions
EF (tonnes per well) (from Table 4.2.4a)

2.35

8.57

1.01

1.30E-04

Number of wells

100,000

100,000

100,000

100,000

Total tonnes of gas (EF x wells)

235,000

857,000

101,000

13

0%

7%

0%

Disaggregation Percent (from Table 4A.2.2)
Leaks

7%

Vents

83%

3%

83%

0%

Flares

10%

97%

10%

100%

Disaggregated EF (in Tonnes per well)
Leaks

0.16

0.00

0.07

0.00

Vents

1.95

0.26

0.84

0.00

0.24

8.31

0.10

0.00

FlaresDisaggregated Emission Estimate, in Tonnes

4.136

Leaks

16,450

-

7,070

-

Vents

195,050

25,71083,830-

Flares23,500831,290

10,10013

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Chapter 4: Fugitive Emissions

Annex 4A.3

Definition of terminologies used in Section 4.2

abandoned well: a well no-longer in production or being actively explored; such wells may be unplugged orplugged. Wells plugged according to regulations and abandoned are also known as decommissioned wells. Wells
that are not regularly inspected or repaired and remain unplugged are abandoned but not decommissioned.
acid gas: gas that, when mixed with water, forms an acidic solution (e.g. hydrogen sulphide (H2S) and carbon
dioxide (CO2) - both obtained after sweeting sour gas); see also sour gas.
API: the American Petroleum Institute, the primary trade association representing the oil and natural gas industry
in the United Status.
API gravity: gravity scale developed by the American Petroleum Institute that expresses the relative density of
petroleum liquids as API degrees; most values fall between 10 and 70 degrees API gravity, and the lower the API
gravity, the higher the density of a hydrocarbon.
appliance: see gas appliance.
asphalt: solid or nearly solid bitumen with impurities (nitrogen, oxygen, sulphur) that can melt upon heating;forms when light components or volatiles of petroleum have been removed or evaporated; see also bitumen.
associated petroleum gas (APG): gas produced along with oil.
bitumen: typically solid hydrocarbon with high density (API < 10 degrees; e.g. asphalt); see also asphalt.
blow-down: venting for safety precautions during maintenance, or emergency or upset conditions, occurring
across segments, and including vented condensate and gas produced simultaneously at the outset of production orwhen re-starting a well that has been shut down for a period of time, maintenance venting at a processing plant, or
pipeline venting
blow out: when well pressure exceeds the wellhead valves’ ability to control it and oil and gas are released at thesurface; uncontrolled, possibly catastrophic, flow of reservoir fluids into wellbore that may consist of salt water,oil, gas, or a mixture thereof.
bore hole: the hole drilled by the drill bit; the wellbore including open hole or uncased portion of the well.
cap rock: relatively impermeable rock (e.g. shale, anhydrite, salt) that forms a seal above a reservoir rock andprevents fluids from migrating out of the reservoir.
carbon dioxide capture and storage (CCS): a process in which a relatively pure stream of carbon dioxide (CO2)from industrial and energy-related sources is separated (captured), conditioned, compressed, and transported to a
storage location for long-term isolation from the atmosphere.
CO2 injection: an enhanced oil recovery (EOR) method whereby CO2 gas is injected into a reservoir to reduce
viscosity and increase production.
carbon intensity: average emission rate of carbon dioxide (CO2) from a source per unit of activity (e.g. g CO2 per
MJ of energy produced).
casing: cement pipe lowered down a borehole meant to prevent fluids from escaping and/or the borehole fromcollapsing.
Casing head: the adapter between the first casing and the wellhead.
centrifugal compressor: centrifugal compressors are widely used in production, processing, and transmission ofnatural gas. Seals on the rotating shafts prevent the high-pressure natural gas from escaping the compressor casing.
Traditionally, these seals, termed “wet” seals, used high pressure oil as a barrier against escaping gas. An
alternative to the traditional wet (oil) seal system is the mechanical dry seal system. This seal system does not use
any circulating seal oil. Dry seals operate mechanically under the opposing force created by hydrodynamic grooves
and static pressure. Replacing “wet” (oil) seals with dry seals significantly reduces operating costs and methane
emissions (United States Environmental Protection Agency (EPA) 2016b).
chemical flooding: a type of enhanced oil recovery (EOR) that utilizes alkaline or micellar-polymer flooding.
coal bed methane (CBM): natural gas (methane/CH4, mainly) generated during coal formation and absorbed incoal. Originally extracted as a safety measure to reduce explosion hazards in mines, today CBM is captured andused as a source of energy. For deeper coal formations, hydraulic fracturing may be needed to release the naturalgas (https://www.epa.gov/uog/process-unconventional-natural-gas-production).
completion: process of initiating flow of petroleum or natural gas from a newly drilled well prior to production(a) For conventional well completion a reservoir is connected to the wellbore during this process, allowing the2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

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flowback of drilling and reservoir fluids (gas, oil, water, mud, etc.) to the surface. While there is flowback, there
may be flaring or venting of produced gas from the reservoir. (b) For unconventional well completions, if hydraulicfracturing is employed, there may be a higher rate of flowback of water, fracking fluids, reservoir gas and fracturing
proppant (e.g. sand) that can release greater amounts of methane and hydrocarbons to the atmosphere whencompared to conventional well completions. (c) In a green completion or reduced emissions completion (REC),
produced gas following hydraulic fracturing is captured, offsetting the loss of methane and other hydrocarbons
during flowback from the well completion.
compressor: a device that raises pressure of air or natural gas so the gas can flow into pipelines or other facilities;
see also centrifugal compressor and reciprocating compressor.
compressor station: facility with many compressors, auxiliary treatment equipment, and pipeline installations topump natural gas under pressure over long distances.
condensate: a low-density, high API (50-120 degrees) hydrocarbon associated with natural gas that is in the gas
phase under reservoir conditions (temperature, pressure) but becomes liquid when the reservoir, pipeline, or
surface facility pressure drops below the dew point. It is mainly composed of propane, butane pentane and heavierhydrocarbon fractions.
conservation efficiency (CE): a factor that expresses the amount of produced gas and vapour captured and used
for fuel, produced into gas gathering systems, or re-injected (1.0 = all gas is conserved, utilized or re-injected; 0 =gas is vented or flared).
conventional oil: oil produced from a conventional reservoir
conventional reservoir: a reservoir where buoyant forces maintain hydrocarbons beneath a sealing cap stone andwhose properties usually allow oil or natural gas to flow readily into well bores; this is distinct from shale orunconventional reservoirs, where gas may be distributed throughout the reservoir at basin scale and where
additional buoyant forces or the influence of a water column is not significant.
crude oil: liquid petroleum as it arises from the ground, distinguished from refined oils that are manufactured fromit.
cyclic steam stimulation (CSS): a method of in situ oil sand extraction that uses steam to heat the reservoir,
allowing bitumen to flow into a vertical or horizontal wellbore; see also steam-assisted gravity drainage (SAGD).
decommissioned well: an abandoned well no longer in production that has been isolated according to current
regulatory requirements and best practices (e.g. cut-off, sealed, and possibly buried); such wells may still
deteriorate over time, and may require inspection and repair when necessary, though the regulatory requirements
to do so may vary considerably.
directional drilling: the intentional deviation of a well bore from the path it would have naturally taken by using
specialized, steerable drilling equipment; commonly used in shale reservoirs to allow producers to place theborehole in contact with the most productive reservoir rock.
distribution: for oil systems, the segment of the system that includes the transport and distribution of refined
products, including bulk and retail facilities; for natural gas systems, this segment includes high-pressure gas
pipelines that transfer natural gas to the “city gate” and then to end users through underground main and service
pipelines, distribution of town gas, and short term surface storage.
emission control device: a device used to regulate the amount of gasses or air pollutants emitted from a source.
Emissions Trading System (ETS): a greenhouse gas emissions trading scheme in the European Union plus
Norway, Iceland, and Liechtenstein.
enhanced coal bed methane (ECBM): increased methane (CH4) recovery produced by the injection of CO2 into
coal seams.
enhanced gas recovery (EGR): increased recovery of natural gas by injection of inert gases (e.g. N2, CO2) toincrease well pressure.
enhanced oil recovery (EOR): recovery of oil from a reservoir by means other than using the natural reservoirpressure; can begin after a secondary recovery process or at any time during the productive life of an oil reservoir;an oil recovery enhancement method that uses sophisticated techniques that restores formation pressure andimproves oil displacement or fluid flow in a reservoir; there are three major types: chemical flooding (alkaline
flooding or micellar-polymer flooding), miscible displacement (CO2 injection or hydrocarbon injection) andthermal recovery (steam flood or in situ combustion).
exploration: the part of oil and natural gas systems that includes well drilling, stem testing, and well completion;
the process of trying to find accumulations of oil and natural gas under the surface of the Earth.

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flaring destruction efficiency (FE): the fraction of gas that leaves the flare partially or fully burned.
flow-back: gas, crude oil and water (including water injected during hydraulic fracturing) that are produced froma well until the flow of gas and liquid hydrocarbon is steady; occurs after a treatment or in preparation for returninga well to production.
formation carbon dioxide: CO2 present in the produced oil and gas when it leaves the reservoir.
gas appliances: end of pipe equipment such as home heating equipment, water heaters, saunas, stoves, andbarbecues that use natural gas.
gathering system: the network of flow lines and process facilities that transport and control the flow of oil or gas
from wells to a main storage facility, processing plant, or shipping point (includes pumps, headers, separators,
emulsion treaters, tanks, regulators, compressors, dehydrators, valves).
gas injection: the process of pumping associated gas into a reservoir for conservation or to maintain reservoirpressure.
gas-to-oil ratio (GOR): volume of gas at atmospheric pressure produced per unit of oil produced.
gas well: a well with natural gas as the primary product, but can also produce natural gas liquids (e.g. propane andbutane) and water.
gross calorific value (GCV): conversion factor to convert a fuel quantity between natural units (e.g. mass orvolume) and energy units (energy content), in this case gross energy content (IEA;
https://www.iea.org/media/training/alumni/CheatSheet.pdf).
hydraulic fracturing: a method of enhanced oil or gas recovery in which fluids are pumped into a rock formation
at very high pressures in order to fracture the rock and stimulate the flow of natural gas or oil, increasing thevolumes that can be recovered. Wells may be drilled vertically hundreds to thousands of feet below the surface
and may include horizontal or directional sections extending thousands of feet away from the well.
hydrogen sulphide (H2S): a poisonous gas present in some subsurface formations.
in situ combustion: a method of thermal recovery where fire, generated inside a reservoir by injecting oxygen/air,burns heavy hydrocarbons and vaporizes lighter hydrocarbons, pushing out hot combustion gases, steam and oilwater while also reducing oil viscosity.
leak: unintentional (i.e., not vented or flared) emissions from equipment components such as valves, connectors,
open ended lines, and flanges; can occur in all segments of oil and natural gas systems.
leak detection and repair (LDAR): determination of a leak in a pipeline or piece of equipment using various
detection methods followed by repair.
light hydrocarbons: low molecular weight hydrocarbons (e.g. methane, ethane, butane)
liquid hydrocarbons: light liquid compounds extracted from gas flow stream (e.g. propane, butane, pentane
liquids unloading: see unloadingliquefied natural gas (LNG): oilfield or naturally occurring gas (mostly methane and ethane), liquefied atcryogenic temperatures for transportation.
methane (CH4): the lightest and most abundant hydrocarbon gas and main component of natural gas.
miscible displacement: a type of enhanced oil recovery (EOR) that uses CO2 injection or hydrocarbon injection.
natural gas: a gas that occurs naturally and often in association with crude petroleum; a mixture of hydrocarbon
gases that is highly compressible and expansible (consists primarily of methane, but also ethane, propane, butane,and pentane; impurities such as CO2, He, N, and H2S may also be present).
natural gas liquids (NGLs): liquid natural gas components including condensate (low vapor pressure NGL),
natural gasoline (intermediate vapor pressure NGL), and liquified petroleum gas (high vapor pressure NGL).
NGLs include: propane, butane, pentane, hexane, heptane but NOT methane and ethane.
net calorific value (NCV): conversion factor to convert a fuel quantity between natural units (e.g. mass or volume)andenergyunits(energy
content),
in
this
case
net
energycontent(IEA;
https://www.iea.org/media/training/alumni/CheatSheet.pdf
oil: a mixture of liquid hydrocarbons of different molecular weights.
oil sand: are a type of unconventional petroleum deposit made of up a mixture of sand, clay, and water, saturated
with a highly viscous form of petroleum called crude bitumen. In the context of Canadian oil sands, the API is <10 degrees, and in situ recovery and mining methods are used to extract the resource.

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oil shale: a sedimentary rock containing organic matter in the form of kerogen, a waxy hydrocarbon-rich material
regarded as a precursor to petroleum. Oil shale may be burned directly or processed by, for example, heating to
extract shale oil (United Nations Department of Economic and Social Affairs Statistics Division 2018).
oil well: a producing well that has oil as its primary product; such a well always produces some associated gas andfrequently water as well.
permeability: the property of a geologic formation that quantifies the flow of fluid through pore spaces and into
the well bore.
petroleum: a generic term for hydrocarbons that includes crude oil, natural gas liquids, natural gas, and theirproducts; a complex mixture of naturally occurring hydrocarbon compounds found in rock which range from solid
to gas, but usually refers to liquid crude oil. Impurities such as sulphur, oxygen and nitrogen are common and there
is considerable variation in colour, gravity, odour, sulphur content and viscosity in petroleum from different areas.
pipeline: a tube or system of tubes used to transport crude oil and natural gas from the field or gathering system
to the refinery.
pipeline gas: gas that is sufficiently dry that it will not precipitate out natural gas liquids (NGLs) at pressure andthat has enough pressure to enter high-pressure gas pipelines.
porosity: the percent of void in a porous rock compared to solid.
pneumatic devices: chemical injection pumps, starter motors on compressor engines, instrument control loops,
liquid level controllers, pressure regulators, and valve controllers that use pressurized natural gas or compressed
air as the supply medium.
primary fuels: fuels extracted directly from natural resources; examples include crude oil, natural gas, coals, etc.
processing: the segment of natural gas systems where natural gas liquids (NGLs) and other constituents (e.g.
sulphur) from raw gas are removed to prepare “pipeline quality” gas.
production: the segment of Oil Systems that includes the process of recovering oil from the wellhead or at the oilsands/oil shale mine to delivery at the start of the oil transmission system; also included in this segment are any
on-site upgrading activities. For Natural Gas systems this segment includes recovering gas from the wellhead anddelivery of that gas to either the inlet of a gas processing facility or a tie-in point of a gas transmission system; also
included in this section is gathering and boosting stations.
reciprocating compressor: a compressor that uses pistons driven by a crankshaft to deliver gases at high pressure.
refining: the segment of Oil Systems where refineries process crude oils, natural gas liquids (NGLs) and synthetic
crude oils into final products (e.g. primary fuels and lubricants).
secondary recovery: the recovery of oil or gas by artificially maintaining or enhancing reservoir pressure by
injection gas, water or other substances into the reservoir rock.
sector: greenhouse gas emission and removal estimates are divided into main sectors (Energy, Industrial Process
and Product Use (IPPU), Agriculture Forestry and Other Land Use (AFOLU), Waste and Other), which aregroupings of related processes, sources and sinks.
segment: a sub-division of the Fugitive Emissions from Oil Systems (1 B 2 a) and Fugitive Emissions from Natural
Gas Systems (1 B 2 b) sub-categories that refers to the type of activity within the system. For example, 1 B 2 b iii
1 Exploration and 1 B 2 b iii 2 Production are segments of 1 B 2 b.
shale: a fine grained impervious sedimentary rock of clays and other minerals (including high percentage ofquartz).
shale gas: natural gas produced from low-permeability deep shale formations; shale that is thermally mature
enough and has sufficient natural gas content to produce economic quantities of natural gas.
shale oil: an unconventional oil produced from oil shale rock fragments by pyrolysis, hydrogenation, or thermal
dissolution.
sour: oil or gas contaminated with sulphur or sulphur compounds (especially hydrogen sulphide).
sour gas: natural gas that must be treated to satisfy sales gas restrictions on H2S content; see also sweet gas.
standard temperature and pressure (STP): 15 degrees Celsius and 101.325 kPa (1 atm) atmospheric pressure.
steam assisted gravity drainage (SAGD): a method of in situ oil sand extraction that uses steam to heat thereservoir, allowing bitumen to flow into a vertical or horizontal wellbore; see also cyclic steam stimulation (CSS).

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storage: natural gas kept temporarily on long-term in above ground tanks or below-ground formations. Crude oils
or refined products stored in above ground tanks.
sub-category: a division of a category. For example, subcategories of 1 B 2 (Fugitive Emissions from Oil andNatural Gas Systems) include 1 B 2 a Fugitive Emissions from Oil Systems and 1 B 2 b Fugitive Emissions fromNatural Gas Systems. Subcategories can be further divided into segments.
sub-segment: a division of a segment of Oil or Natural Gas Systems by technology or practice.
sweet: lacking appreciable amounts of sulphur or sulphur compounds.
sweet gas: natural gas that does not contain any appreciable amount of H2S (i.e. does not require treatment to meetrequirements for H2S content).
sweetening: the process that removes hydrogen sulphide or carbon dioxide from a gas stream.
synthetic crude oil (SCO): output from a bitumen or extra heavy oil upgrader, usually in connection with oil sandproduction or output from oil shale pyrolysis.
synthetic natural gas (SNG): gas obtained from heating coal or refining heavy hydrocarbons.
thermal recovery: a type of enhanced oil recovery (EOR) that uses stream flood or in situ combustion; a processthat introduces heat into a reservoir to produce viscous, thick oils (i.e. API < 20 degrees; oils that cannot flow
unless heated to reduce viscosity and allow flow toward producing well); encompasses hot fluid injection (steam
injection, stream flood or cyclic steam injection), hot water flooding, and in situ combustion processes
tight gas: gas produced from a relatively impermeable reservoir rock that is generally difficult to produce without
stimulation operations; generally used for reservoirs other than shale that fit this description.
town gas: a manufactured gaseous fuel produced for sale to commercial and residential consumers. Coal gas containshydrogen (around 50 percent), carbon monoxide (around 10 percent), methane (around 35 percent) and volatile hydrocarbons(around 5 percent) together with carbon dioxide and nitrogen (each less than 1 percent); also called coal gas.
transmission: gas transported in high pressure, large diameter pipelines from field production and processing
areas to distribution systems or large volume customers such as power plants or chemical plants.
transmission compressor station: stations placed within natural gas transmission systems to help maintain thepressure of the gas within a pipeline as it flows from the natural gas field to market.
transport: the segment of Oil Systems that is related to the transport of marketable crude (conventional, heavy,and synthetic crude oil and bitumen) to upgraders and refineries by pipeline, marine tankers, tank trucks, and rail
cars.
unconventional resource or reservoir: a term for oil and natural gas that is produced by means that do not meetthe criteria for conventional production; presently, used in reference to oil and gas resources whose porosity,
permeability fluid trapping mechanism, or other characteristics differ from conventional sandstone and carbonate
reservoirs (examples include coal bed methane, gas hydrates, shale gas, fractured reservoirs, tight gas, oil sands).
unload: to restore gas production by removing liquids (including oil, condensate, and water) that haveaccumulated in a gas well. Liquids can be removed without venting (e.g. with pumps or modified well tubing) orwith venting, such as by diverting the flow from the well to an atmospheric vent.
upgrader: a refinery unit that improves or upgrades heavy oil to produce higher-quality hydrocarbon liquids or
upgraded synthetic crude.
venting: emissions from venting of associated gas and waste gas/vapour streams and oil and natural gas facilities;
this includes all engineered or intentional discharges of waste gas streams and process by-products to theatmosphere, including emergency discharges, and the release may be continuous or intermittent.
vapour recovery unit (VRU): a system used to recover vapours formed inside sealed crude oil or condensate
tanks; consists of a switch that detects pressure variations within a tank and turns a compressor on and off. The
compressor sucks vapours through a scrubber that catches liquids and vapours for return to tanks or pipelines.
waste gas: gas stream containing hydrocarbons and/or other gases that are vented or flared and not used for otherpurposes (e.g. production of useful energy).
water flooding: a secondary oil recovery method where water is injected into a reservoir formation to displace
residual oil into adjacent production wells.
well blow-out: see blowout.
well bore: a drilled hole or borehole, including the open hole or uncased portion of the well.

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well completion: see completion.
well head: the system of spools, valves and assorted adapters that provide pressure control of a production well.
well integrity: the zonal isolation of liquids and gases.
well servicing: maintenance procedures performed on oil and gas wells after the have been completed andproduction has begun; these procedures maintain or enhance well productivity.
well testing: a series of activities and tests designed to understand and characterize the characteristics ofunderground reservoirs where hydrocarbons are trapped.
workover: repair or stimulation of an existing production well for the purpose of restoring, prolonging or
enhancing the production of hydrocarbons.

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Appendix 4A.1
Fugitive emissions from mining, processing,storage and transportation of coal: Basis for Future
Methodological Development
Based on the current state of research and data availability, methodologies for estimating emissions fromabandoned surface mining and from coal exploration have not yet been able to be developed. However, general
methodological issues for abandoned surface mine emissions, and a more detailed draft of elements of amethodology for coal exploration are below for countries to consider as a basis for future methodologicaldevelopment.

Appendix 4A.1.1 Abandoned Surface Mines
Closed, or abandoned, surface coal mines may continue to be a source of greenhouse gas emissions for some timeafter the mines have been closed or decommissioned. For the purpose of the emissions inventory compilation, afirst critical step is to ensure that each mine is classified in one and only one inventory database (e.g., active or
abandoned).
It is also important to consider sub-category allocation issues - to separate any emissions from abandoned surface
mines from those of uncontrolled combustion and burning of coal deposits, to avoid double counting. CO2
emissions can arise from both low-temperature oxidation of exposed coal-bearing rocks and uncontrolled
combustion. The CO2 emissions from uncontrolled combustion should be reported under 1.B.1.b Uncontrolled
Combustion, and Burning Coal Dumps.
Countries considering activity data for estimating emissions from abandoned surface mines may take into accountfactors such as the surface area of exposure coal, the degree of flooding and the extent and type of minerehabilitation that has taken place.
For CO2 and CH4 emission factors, consideration may be given to the type of coal mined, eg bituminous,
subbituminous, lignite etc., mine site management practices and how the emission factors are likely to change overtime since mine closure.
In general, more work needs to take place in order to build a basis for robust and representative Tier 1 methodology
development. This is particularly the case for developing appropriate emission factors, as well as understanding
the variability and uncertainty associated with emissions from this source.

Appendix 4A.1.2 Coal Exploration
A large fraction of the gas contained in coal seams is adsorbed on the coal surface inside the micropores and asmall fraction in the free state in the macro pores and cleats. The hydrostatic pressure that a coal seam is subjected
to prevents desorption of the gas from the coal matrix. Gas flow from exploration boreholes is not comparable tothe flow of gas in coalbed methane wells where the coal seams are stimulated by hydro fracturing anddepressurized by dewatering the coal seams. Emissions during exploratory borehole drilling may be largely
associated with the amount of coal or lignite added to the national resource (found as a result of exploration) during
the reporting period. This addition of resource is termed as augmentation of resource during the period.

4A.1.2.1

C HOICE OF METH OD

Fugitive methane emissions from exploration boreholes in a coalfield depend on the gas content, cumulative
thickness of the coal seams encountered during exploratory drilling, as well as stratigraphy, structure and natureof coal and associated sediments. A variety of geological and geophysical techniques such as generating ageological map of the area, carrying out geochemical and geophysical surveys, drilling of exploration boreholes
with or without coring, down-hole geophysical logging and comprehensive analysis and testing of core samples
are used to estimate the coal resources. While drilling for coal exploration programs involve core and/or non-coredrilling, core drilling is the only satisfactory means of obtaining representative samples (Ward, 2009), either ofcoal seams for thickness and quality assessment or of non-coal rocks for geotechnical tests. Emissions from coal
exploration covered here include those fugitive emissions from the drilling of exploration boreholes.
Emission of methane from exploratory boreholes directly depends on number of exploration boreholes drilled ina reporting period. When considering a borehole-specific approach, there is a need to ensure the source boundary
distinction between boreholes that are drilled as part of coal mine production (which are already included as partof Underground and Surface coal mining activities) and those drilled for coal exploration to avoid double counting.

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Field level desorption tests are carried out during exploratory drilling of some selected boreholes and important
CBM related data such as in situ gas content, sorption time etc. are generated (CMPDI, 2016). Gas desorption
curves are also prepared. Often adsorption isotherm curves are also constructed. National emission factors can beevaluated using the measured data in and mathematical models for gas flow rates from a well without any
stimulation. The emission factors so evaluated can be used for estimation of emission from every borehole drilled
in a coal block. Therefore, substantial research and development opportunities should be explored to find numberof exploratory boreholes drilled in a reporting period which may be obtained from geological reports on coal
exploration for numerous coal blocks. Emission factors may also be calculated for each of the blocks. Estimatesof fugitive methane emission should then be prepared with a high degree of accuracy. Nevertheless, exploration
involves many agencies in a country and geological reports on exploration are not usually readily available in
exploration reports or any other publication.
Because activity data that more directly relate to emissions from coal exploration are often unavailable, the method
presented here relies on year-to-year differences between annual national inventories of coal and lignite resources(augmentation of coal resources). Emissions based on this parameter solely may not be representative.. Annual
updating of the national quantity of coal and lignite resources is an integral part of exploration often used to update
the national quantity of coal and lignite resources. Annual national inventories of coal and lignite resources areoften prepared by a single ministry or nodal agency of the country. Therefore, augmentation of coal resources(GSI, 2017) in a reporting year over that of the preceding year can be easily obtained or calculated by subtracting
the resources of the current year from that of the preceding year. This annual change or augmentation may be used
as activity data for exploration boreholes if number of boreholes drilled in a reporting period is not available. It is
recognized that resources are categorized by various agencies into different sub-classes based on their technicaland economic levels of recoverability, making it difficult to develop one definition of “coal resources” that is
broadly applicable. However, drilling of exploration boreholes and other exploratory activities is necessary for
determining the total coal resources, regardless of their categorization.
While the required coal data is often available on a yearly basis for major coal producing countries, annual dataon “resource augmentation” may not be available or may be available on a decade by decade basis in the national
statistics. Global statistical publications like BP Statistical Review of World Energy may be referred to in suchcircumstances.
The augmentation of coal resources is the additional resource of coal and lignite found as a result of exploration
during a reporting year which, when added to the previous year’s resource, gives current resource. The entire
augmented resources are not the sources of greenhouse gas emission but they indirectly represent the number ofcoal exploration boreholes since the exploratory drilling is usually carried at known interval over coal bearing
areas for assessment of coal potentiality. The spacing of the boreholes depends on geological structure, deposit
character, nature of data required for mine planners etc. Although seismic exploration technology is very importantfor petroleum exploration, it is seldom used in exploration of solid minerals such as coal due to technological andeconomic limitations (National Research Council 2002). Instead, drilling of exploratory boreholes that yields aplethora of information on coal characteristics and resources is very common for exploration of coal.
Figure 4Ap.1.1 is a decision tree that shows how to determine which tier to use.

Tier 1 – Global Average Approach – Fugit ive Emission from Coal Exploration
Boreholes
For a Tier 1 approach the estimation method may be expressed in the form of an equation given below:
EQUATION 4AP.1.1 (NEW)
TIER 1: GLOBAL AVERAGE METHOD – FUGITIVE EMISSION FROM COAL EXPLORATION
BOREHOLES

Methane emissions from a coal seam at a depth = CH 4 Emission Factor for the depth• Augmentation of Resource for the depth• Conversion Factor
Methane emissions from Exploration =∑ Methane Emission from coal seams in three different ranges of depths
3

1

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Where units are:Methane Emissions (Gg year-1)
CH4 Emission Factor (m3 tonne-1)
Augmentation of Resource (tonne year-1)
All different categories of coal resources such as measured (or proved), indicated and inferred etc. (UNFC 2009),
should be taken into account for determining activity data of augmented resource. Care should be taken if there isa reduction in the coal resource quantity in a reporting period in which case the method may produce a negativeemission in that year. This should be treated as an undesirable outcome and unusual observation for which Tier 1
method should not be used. In such a situation, emission should be regarded as zero emission instead be negativeemission.

Tier 2 – Basin-Specific Approach
The Tier 2 approach for preparing a methane emission inventory from coal exploration boreholes is similar to theTier 1 method, but basin-specific borehole data are taken into consideration in a Tier 2 method. Coal basin-specificdata on methane emission from exploratory boreholes in a basin or coalfield should be collected. The averagevalue of such measured emissions from some boreholes, if available, should be considered as emission factor forthe basin under consideration. The emission factor so evaluated should be multiplied by number of boreholes
drilled in the basin under consideration to arrive at the emission from the basin. Similarly, methane emission fromother basins should also be estimated. Tier 1 method should be adopted for those basins where no measurement
has been done from any exploratory borehole. Summation of the emission values from each of the basins gives theemission estimate from exploratory boreholes for the country.
For a Tier 2 approach the exploration borehole emission estimation method is shown below:
EQUATION 4AP.1.2 (NEW)
TIER 2: BASIN-SPECIFIC METHOD

Methane emissions from a basin or coalfield = Number of boreholes drilled in the basin• CH 4 Emission Factor for the basin • Conversion factor

Methane emissions from Exploration = ∑1 Methane Emission from coal seams in the basinnWhere n = number of basins and units are:Methane Emissions (Gg year-1)
CH4 Emission Factor (m3 tonne-1)

Tier 3 – Borehole Specific Approach
Coal exploration companies often determine in situ gas content and other gas desorption characteristics such as
sorption time of coal seams encountered during exploratory drilling of boreholes, Langmuir volume, Langmuirpressure and permeability. Release of gas from a coal seam is highly dependent on these parameters. Models arealso available to calculate emissions if the gas desorption parameters are available. The impact of management
actions such as borehole capping etc. should be taken into consideration. A Tier 3 approach can be developed if
gas desorption parameters are available. When considering a borehole-specific approach, there is a need to ensure
the source boundary distinction between boreholes that are drilled as part of coal mine production (which are
already included as part of Underground and Surface coal mining activities) and those drilled for coal exploration
to avoid double counting.

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Figure 4Ap.1.1 (New) Decision tree for coal exploration
Start

Is borehole
level data available,
including desorption characteristic
and emission
factors?

Yes

Estimate fugitive
emissions using Tier 3
approach.
Box 3: Tier 3

No

Collect data.

Are emissions data
available to develop a basinspecific emission factor?

Yes

Estimate fugitive
emissions using Tier 2
approach.
Box 2: Tier 2

No

Yes

Is it akey category?

No

Is coal resource
augmentation data available
at national level, including
depth data?

Yes

Estimate fugitive
emissions using Tier 1
approach.
Box 1: Tier 1

No
No

Do emissions
fall below significancethresholds?

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Yes

Report emissions as NE.
Box 4

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4A.1.2.2

C HOICE OF EMISSI ON FACTORS

No information is found in the literature on measurement of fugitive methane emission specifically from coal
exploration boreholes. Therefore emission factors provided below are as per expert opinion. Since the exploration
boreholes are filled with water or mud, the hydrostatic pressure on the coal seams encountered will be significant.
Accordingly, emission factors for exploration boreholes are assumed to be small compared to those of other coalmining activities.

Tier 1 – Global Average Approach – Fugit ive Emission from Coal Exploration
Boreholes
Default emission factors for different depth ranges given below and activity data on augmented resource in therespective depth range should be used for calculation of emission estimates using Equation 4Ap.1.1. It should be
noted that the entire resource shall not emit methane but only a fraction of it will release the gas. Therefore,
emission factors for exploration boreholes are very less in comparison to the emission factors for undergroundmining and post mining activities prescribed in Equations 4.1.3 and 4.1.4. This will correspond to emission fromcoal very closed to the well bore.
CH4 Emission Factor= 0.01 m3 tonne-1 for depth range 0 – 600 m

CH4 Emission Factor= 0.03 m3 tonne-1 for depth range 600 – 1200 m

CH4 Emission Factor= 0.05 m3 tonne-1 for depth > 1200 m

Conversion Factor:
This is the density of CH4 and converts volume of CH4 to mass of CH4. The density is taken at 20˚C and 1
atmosphere pressure and has a value of 0.67●10-6 Gg m-3.
The basis of arriving at the above emission factors is expert judgment since information on fugitive methane
emission from coal exploration boreholes is not usually readily available. It is well known that in situ gas content
of coal seams increases with depth. Therefore, deeper coal horizons are likely to emit at higher rates. Hence,emission factor will be higher for deeper seams. Further, exploration boreholes are filled with water or mud which
does not allow coal seams to release gases adsorbed on coal surface at faster rates as in the case of coal faces inunderground or surface mines. The emission factors are only a fraction of the corresponding emission factors forsurface and underground coal mining.

Tier 2 – Basin-Specific Approach
For a Tier 2 approach the exploratory borehole emissions factors may be evaluated as described below:
Em i s sio n Fa ct o r:
Information about basins or coalfields wherever methane emission measurements from coal exploration
boreholes have been conducted, should be collected first. Average value of the emission (m3) fromaccessible data in the basin should be calculated to evaluate methane emission per exploration borehole(m3/exploratory borehole). This value of methane emission per exploration borehole should be used as
emission factor (m3/exploratory borehole) for the basin which should be multiplied by the number of
exploration boreholes drilled in the basin to obtain volume of fugitive methane emission (m3) from
exploratory boreholes drilled in the basin. Tier 1 emission default emission factors may be used for thebasins or coalfields wherever number of exploration boreholes drilled are unknown or emission factor as
described above cannot be evaluated.
Co nv er sio n Fa ct o r:
This is the density of CH4 and converts volume of CH4 to mass of CH4. The density is taken at 20˚C and 1
atmosphere pressure and has a value of 0.67●10-6 Gg m-3.

Tier 3 – Borehole Specific Approach
Coal exploration companies often determine in situ gas content and other desorption characteristics such as
sorption time of coal seams encountered during exploratory drilling of boreholes, Langmuir volume, Langmuirpressure and permeability etc. Release of gas from a coal seam is highly dependent on these parameters. Models
are also available to calculate emissions if the gas desorption parameters are available. A Tier 3 approach can be
developed if gas desorption parameters are available.

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4A.1.2.3

C HOICE OF ACTIVITY DATA

Augmentation of resources or new addition of resources in the year may be used as activity data, which may beavailable in the inventory of coal or lignite resources or can be easily obtained by subtracting the resources for ayear and the resources for the previous year as follows:
Augmentation or New Addition = Resource for a year – Resource for the previous year
The above activity data may be used for Tier 1 estimates. A precise value for activity data may be available fornet increase of depth-wise resource. Often coal resources are reported in the depth ranges such as 0-600 m and
600-1200 m and higher than 1200 m. Since gas content of coal seams generally increases with depth, emission
from deeper seams will be higher compared to the seams at shallow depths. These values of activity data
correspond to Tier 1 estimates.
Number of exploration boreholes drilled in a reporting period will be used as activity data for Tier 2 and Tier 3
methods.

4A.1.2.4

C OMPLETENESS

Exploration for coal is generally carried out in two broad categories, often called as Regional and Detailed
Exploration. During regional exploration, coal resources of inferred or indicated categories using data obtained
from boreholes few kilometres apart (typically 2 to 4 km) are estimated. Detailed exploration is carried out toarrive at measured or proved resource using data from boreholes normally drilled less than a kilometre apart(typically 400 m). The number and distribution of boreholes during detailed exploration are sufficient to allow a
realistic estimate of average coal thickness, areal extent, depth range, quality and mineable reserve of coal. The
estimate of fugitive methane emission from coal exploration boreholes should include all emissions from thefollowing:• Gas released from boreholes during regional exploration;• Emission of gas from boreholes during detailed exploration.

4A.1.2.5

D EVELOPING A CO NSISTENT TIME SERIESTime series consistency should be maintained in a manner consistent with guidance set out in Volume 1, Chapter
5.
A complete borehole specific data may not be available for the base year and also for the succeeding years. It may
be imperative, therefore, to prepare a combination of Tier 1, Tier 2 and Tier 3 estimates.
If Tier 2 or Tier 3 methods are used for exploration boreholes for certain inventory years, emissions should bescaled-up or scaled-down for the remaining years using an appropriate value (low, average or high) of Tier 1
emission factor.

4A.1.2.6

U NCERTAINTY ASSESSMENT

ACTIVITY DATA UNCERTAI NTI ES
The activity data of resource augmentation in Tier 1 method is reasonably accurately known (±5 percent).
However, there may be uncertainties on account of extrapolation techniques used for estimation of inferred andindicated categories of coal resources. Thus, combining the errors in estimation of different category of resources(such as proved, inferred and indicated), the activity data of resource augmentation may have an uncertainty of±10 percent. In borehole specific approach (Tier 3 method), where number of boreholes, number of coal seams
encountered, their thicknesses and in situ gas content etc. are known, uncertainty may be in the range of ±1 – 2
percent.

EMISSION FACTOR UNCERTAINTIES
Uncertainties in Tier 1 approach mainly arise because of use of global emission factors. There may be some
intrinsic uncertainties in the emission factors as well. As combination of these effects, the uncertainties in Tier 1
approach may be greater or smaller by a factor of 3, that is actual emissions are likely to be in the range of onethird to three times of the estimated value of fugitive methane emission.
Tier 2 estimates may also have liability to vary due to inherent uncertainties associated with basin level
characteristics. Uncertainties in Tier 2 approach may be ±75-100 percent.

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Chapter 4: Fugitive Emissions

Coal characteristics, in situ gas content and other gas desorption parameters are often determined for a selected
number of exploration boreholes. These parameters vary considerably in lateral directions in an exploration field.
Tier 3 estimates may be accurate to ±50 percent depending on number of boreholes tested for gas desorption
parameters.

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Appendix 4A.2 Fugitive Greenhouse Gas Emissions from Wood
Pellet production: Basis for Future Methodological Development
Fugitive emissions are likely from the wood pellet production. The quantities of emissions will be variable, anduncertain. At the time the 2019 Refinement was created, there was insufficient information available in thescientific literature to select emission factors suitable for estimating emissions and therefore a methodology is notprovided. If countries have developed country specific methods for estimating emissions from biomasstransformation process, they may estimate and report emissions. This appendix provides a basis for future
methodological development to estimate fugitive greenhouse gas emissions from wood pellet production.

BACKGROUND
Biomass is the fourth largest source of energy worldwide and provides basic energy requirements for cooking andheating of rural households in developing countries. Biomass densification has aroused a great deal of interest in
recent years as a technique to enhance the use of residues as energy source. The densified biomass produced ismostly in the form of briquettes in developing countries and in the form of pellets in developed countries.

Wood Pellets
Wood pellets are a type of wood fuel, usually produced as a by-product of sawmilling and other woodtransformation activities. Wood pellets are normally produced by compressing dry wood materials to a desired
size. First, raw wood materials are passed through a hammer mill and dryer to achieve consistent moisture content.
Then, the dry wood particles are fed to a press. In the press they are squeezed through a die having holes of therequired size. The high pressure causes the temperature of the wood to increase greatly, causing the lignin toplasticize slightly and form a natural ‘glue’ that holds the pellet together. The pellets are usually 6 to 8 mm indiameter and 2 cm in length.
According to Global Bionergy Statistics 2017 (WBA, 2018), 28 million tonnes of pellets are produced annually.
Pellets are thus contributing substantially to global bioenergy trade. Pelleting technology is also considered as amature technology. From environmental context, it is well documented that all biomass gradually decomposesover time, both chemically and biologically, slowly releasing toxic and oxygen-depleting gases such as CO, CO2
and CH4 (Kuang et al., 2008). Limited studies (Svedberg et al., 2004) have reported the composition of the offgas emissions from stored wood pellets. However, CO, CO2, CH4 and non-methane organic compounds arecommonly identified in the off-gases from biomass (Johansson et al., 2004). At the pellet production plant,emission of fugitive methane (CH4) gas may occur at the various stages of production. These include: Preprocessing where the raw material is chipped into small bits; Pelleting; Pellet drying; Pellet storage and pellet
drying (Figure 4Ap.2.2). The delivery, storage and processing of raw materials for pellet production andsubsequent handling of the pellets within the pelleting plant enhances the fugitive emissions over and above theemissions associated with natural decay.
Specifically, emissions to air may occur during the wood pellet manufacturing process from sources such as dryers,coolers, pelletizers, hammer mills, and conveyors. Fugitive emissions are also released during the handling, storage
and transportation of the materials. Fugitive emissions are unintentional or incidental releases. The significance offugitive emissions at wood pellet manufacturing facilities may vary depending on the type of raw material, methodof transportation and specific process used in the production of the wood pellets. Major sources of these emissions
include raw material handling, raw material storage piles, conveyor transfer points, yard dust, haul road dust andengine exhaust (British Columbia, Ministry of Environment, 2011).
The process of wood pellet production follows various distinct stages which include: receipt of the raw material,
storage, drying, grinding pelleting, cooling and packaging as illustrated in Figure 4Ap.2.1.

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Chapter 4: Fugitive Emissions

Figure 4Ap.2.1 (New) Flow diagram of wood pellet production process
Dry material
Powderymaterial
Raw material

StorageDryingGrinding

Bufferstorage

Wet material
Powdery material

Packaging

Pellets

Cooling

PelletingSource: Adapted from Grover and Mishra, 1996, Olsson, 2002

Fugitive Emissions from Pellet Production
The fugitive emissions arising during the pellet manufacture would be classified under category 1B1c of the 2006
IPCC Guidelines, as they are part of emissions from solid to solid fuel transformations. The possible sources offugitive emissions from pellet production are indicated in Figure 4Ap.2.2. Inventory compilers need consider
including only emissions arising within the pellet mill, namely from the receipt of the raw materials to the storageof pellets prior to transportation to end user.
Figure 4Ap.2.2 (New) Emissions Diagram for a Typical Pellet Plant (Two Dryers)

Fugitive
Emissions

LegendTrucking
Wet
Materials

Trucking Dry
Materials

Shavings
Storage

SawdustStorage

Shavings
InfeedSawdustInfeedHammermilles,
Conveying
Storage

Hammermilles,
Conveying
Storage

Shavings
Dryer

SawdustDryer

Solid Wood
Processing &Storage (opptional)

EmissionControls

Recirculation
gas
Dryer
CycloneSeparators

Heat
Dryer
BurnerDryer
BurnerPotential Emission Source
Process Flow
Dryer Fuel
Dryer Heat

Fugitive
Emissions

Fuel

Fuel Storage

Dryer Emissions
EmissionControls

Hammermills,
Conveying,
Storage,
Pelletizers
Fuel (Recycle
Dust or Pellets)

Hammermills,
Pelletizes,
Conveyors

PelletCoolers
Cyclones

Pelletizer
Coolers

Products
Conveyor &Screens

Product
Screens

Fuel Sizing

PelletStorage

Fuel Supply

PelletLoadout

Fugitive
Emissions

Source: British Columbia, Ministry of Energy, 20112019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

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METHODOLOGICAL ISSUESThe CO2 fugitive emissions from the biomass and the biomass part of MSW (municipal solid waste) are biogenic
emissions and should be estimated for inclusion as an information item in the Energy Sector, as those feedstocks
are combusted for energy purposes. For more information on reporting of biomass emissions, please see Section
2.3.3.4 in Volume 2, Chapter 2.
The choice of the method for estimating the fugitive emission depends on the nature and level of disaggregationof activity data and emission factors available in the country. Where there is no country or technology specificdata, a Tier 1 method could be developed to estimate emissions using default emission factors. In the case wherecountry specific emission factors are available but the activity data are not disaggregated by each transformation
technology, a Tier 2 method could be developed. Finally, where technology specific data and emission factors areavailable, a Tier 3 method could be used. A proposed decision tree for estimating emissions from solid biomass
fuel transformation is given in Figure 4Ap.2.3.

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Chapter 4: Fugitive Emissions

Figure 4Ap.2.3 (New) Proposed decision tree for estimating fugitive emissions from wood pellet
production
Start

Are
technology-specificemission factors for all pellet
production mills
available?

Yes

Estimate emissions
using Tier 3 method basedon technology-specific data.
Box 3: Tier 3NoAre
country-specificemission factors for woodpellet production
available?

Yes

Estimate emissions using
Tier 2 method based on
country-specific data.
Box 2: Tier 2

No

Are fugitives fromfuel transformation a key
category, and is wood pellet production
a significant source
within that category?

No

Estimate emissions using
Tier 1 and default
emission factors.
Box 1: Tier 1

Yes
Collect data to develop
country-specific emission
factors for Tier 2.

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CHOICE OF EMISSI ON FACTOR
The fugitive emissions from the pellet manufacture are confined to the milling plant but exclude the process energy
used for the compaction process. The available literature reviewed at the time of writing (Sjølie and Birger, 2011;
Agar et al, 2015; Murphy et al, 2015, Magelli et al, 2009; and Wang et al, 2017) provided emission factors forpellet production largely based on lifecycle analysis. No emission factors suitable for use in national GHG
inventories were found to allow the estimation of the fugitive emissions arising at pellet production operations.

Choice of activity dat a
The activity data required to enable for the estimation of fugitive emissions arising during the manufacture ofpellets from solid biomass materials. These include the:• Quantity of solid biomass input materials including biomass waste and cut wood, available for pelleting;• Quantity of the pellet and duration of storage prior to being transported to final end-use points.

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Appendix 4A.3
Fugitive Emissions from Biomass to Liquid andBiomass to Gas: Basis for Future Methodological Development
This Appendix provides a basis for future methodological development rather than complete guidance.
Biomass to gaseous (BtG) and biomass to liquid (BtL) gasification transformation processes are processes that use
as feedstock woody biomass, agricultural and forest residues and waste biomass (sorted municipal and commercial
waste), for example. Therefore, these feedstocks used in these processes does not have carbon of fossil origin,except from Municipal Solid Waste (MSW) that might include some carbon of fossil origin. The CO2 fugitive
emissions from the biomass and the biomass part of MSW are biogenic emissions and should be estimated forinclusion as an information item in the Energy Sector, as those feedstocks are combusted for energy purposes. For
more information on reporting of biomass emissions, please see Section 2.3.3.4 in Volume 2.
Currently, most BtG and BtL plants are either on demonstration or pilot scales and, hence, there is minimal
literature describing research into the emissions from these processes (Van der Drift & Boerrigter, 2006;
OECD/IEA, 2007; Ail & Dasappa, 2016; NETL/DOE, 2016).

METHODOLOGICAL ISSUES
The choice of method will depend on the technologies that are operational in countries, including whether thetechnologies analysed in this section are key categories in the country, and to what extent country and plantspecific information is available or can be gathered.
The most accurate fugitive emission estimates can be developed by determining the emissions on a plant-by-plantbasis and/or differentiated for each feedstock category (e.g., wood biomass, agricultural and forest residues and
MSW). The methods for estimating CO2, CH4 and N2O fugitive emissions from these technologies vary becauseof the different factors that influence emission levels.
The general approach to calculate greenhouse gas emissions from those technologies is to obtain the amount offeedstock used and to investigate the related greenhouse gas emission factors, preferably from country-specificinformation on the carbon content.
To estimate fugitive CO2 emissions, it will be necessary to:• Identify types of biomass used as feedstock (wood, agriculture and forest residue or waste biomass (sorted
municipal and/or commercial waste));• Compile data on the amount of feedstock used (e.g. amount of biomass or amount of syngas produced, when
MSW is the feedstock used in BtL or BtG plants).

CHOICE OF METHODS, DECISION TREES, TIERSThere is limited information about gasification transformation technologies. From the information available, it wasconsidered that fugitive emissions are most likely to occur at the gasification stage. The fugitive emissions resulting
from the syngas transformation at the Fischer-Tropsch stage were considered negligible, as it is an energy related
processes.
The method for estimating fugitive emissions from BtL and BtG technologies is based on an estimate of the carbon
content in the feedstock combusted and converting the product to greenhouse gas emissions.
As BtG and BtL are still emerging technologies, and there are currently very few large scale plants worldwide andmethodologies to calculate Tier 2 and Tier 3 are not provided. Inventory compilers could choose to use higher Tiermethods to estimate emissions, but they need to transparently document the approaches used and state how their
methods accurately and completely estimate emissions.
The activity data required is the amount of biomass inputs into BtL or BtG processes in terajoules (TJ) and thesyngas produced, when MSW is the feedstock input, and the emission factors are based on the carbon content of
the feedstock.
The choice of method depends on the country specific information available, and is given in the decision tree in
Figure 4.3.7, in the Subsection 4.3.2.2 Gasification Transformation Processes.

TIER 1The Tier 1 method is a simple method that can be used when fugitive emissions from BtG and BtL technologies
are not significant.
When biomass is the feedstock used in BtL and BtG plants, fugitive emissions of CO2, CH4 can be estimated fromthe amount of biomass (such as wood and agriculture and forest residues) used in BtL and BtG plants and the2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

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related emission factors. Fugitive Emissions of N2O at BtL or BtG gasification facilities can be considerednegligible.
If Municipal Solid Waste (MSW) is the feedstock used in BtL or BtG plants, fugitive emissions of CO2, CH4 andN2O can be estimated from the amount of syngas produced and the emission factor for fugitive emissions.
The application of a Tier1 approach is done using Equation 4Ap.3.1 presented below.
EQUATION 4AP.3.1 (NEW)FUGITIVE GHG EMISSIONS FROM GASIFICATION PROCESSES

Egas i = ( FS j • EFi ) • 10−6
Where:
Egas i= Emissions of gas i (CO2, CH4 and N2O) in inventory year (Gg/yr) emitted at gasification station of
BtL or BtG facilities

FSj= total amount of biomass or syngas produced (TJ)

EFi

= gas i emission factor, kg gas i/TJ of biomass or syngas

10-6= conversion factor from kilogram to gigagram

CHOICE OF EMISSI ON FACTOR
Biomass
The emission factors for gasification process of BtG and BtL are provided based on the carbon contents of biomass
used in a selection of plants and the composition of its syngas, as analysed by Asadullah (2014), and considering
1 percent of fugitive emissions are release in the gasification stage (Table 4Ap.3.1). It was also considered that all
the biomass is burned, and that there is no char formation. Asadullah (2014) provides information on gas
composition (H2, CO, CH4, CO2, N2) by volume percent of 15 biomass gasification plants that use as feedstocks
wood chip, eucalyptus wood, sawdust, sunflower seed pellet, corncob, olive kernel, wood, rice husk, poplar chips,
and seed corn.
TABLE 4AP.3.1 (NEW)EMISSION FACTORS FOR GASIFICATION PROCESSES OF BTG AND BTL
EF CO2 (kg CO2/TJa)
Biomass125

EF CH4 (kg CH4/TJa)
18.3

EF N2O (kg N2O/TJa)n.d.

Converted from kg CO2/ton C and kg CH4/ton C to kg CO2/TJ and kg CH4/TJ, respectively, based on the carbon content values ofbiomass in Table 1.3 of Chapter 1 Introduction of Volume 2 Energyan.d. – Not Determined
Source: estimated based on Asadullah (2014)

Municipal Solid Waste
There is no available information to estimate emission factor for fugitive emissions from BtG and BtL facilities
related to MSW feedstock.

CHOICE OF ACTIVITY DATA
The activity data required for Tier 1 and Tier 2 are the amount of biomass gasified at gasification stage in terajoules(TJ) or the amount of syngas produced in terajoules (TJ), when MSW is the feedstock used in BtG and BtL plants.
Countries that use these technologies should have plant-specific data on the amount of biomass gasified or thesyngas produced.

UNCERTAINTY ASSESSMENT
Biomass to gaseous and biomass to liquid technologies
Estimates of fugitive emissions from BtG and BtL facilities are likely to be highly uncertain due to lack of
information about fugitive emissions from these technologies. More research and development is needed on thesetechnologies, especially direct measurement on all stages to confirm which ones present fugitive emissions.

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Chapter 4: Fugitive Emissions

Emission factor uncertainties
There is minimal information in the literature from which to derive emission factors, and there are currently few
large scale BtG and BtL facilities. The fugitive emission factors provided in these guidelines were estimated basedon very few data and uncertainties are large.

Activity data uncertainties
Where activity data are obtained from plants, uncertainty estimates could be obtained from the plant operators.

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Zimmerle, D. J., Williams, L. L., Vaughn, T. L., Quinn, C., Subramanian, R., Duggan, G. P., Wilson, B., Opsomer,
J. D., Marchese, A. J., Martinez, D. M. & Robinson, A. L. (2015) Methane Emissions from the Natural Gas
Transmission and Storage System in the United States. Environmental Science and Technology 49(15): 93749383.

SECTION 4.3
Fuel transformation
UNSD (2018) International Recommendations for Energy Statistics (IRES), Statistical Papers Series M No. 93,
United Nations, New York. https://unstats.un.org/unsd/energy/ires/
Charcoal production
AFREA (2011) Wood-based biomass energy development for sub-Saharan Africa: Issues and approaches.
Bailis, R. (2009) Modeling climate change mitigation from alternative methods of charcoal production in Kenya.
Biomass and Bioenergy 33(11): 1491-1502.
Basu, A., Blodgett, C., Müller, N. & Soezer, A. (2013) Nationally appropriate mitigation action study onsustainable charcoal in Uganda. In: ed. E. Travers, pp. 1-88. New York, USA: United Nations Development
Programme (UNDP).
Chidumayo E.N. & Gumbo D.J. (2013) The environmental impacts of charcoal production in tropical ecosystemsof the world: A synthesis. Energy for Sustainable Development 17(2): 86-94.

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Cornelissen, G., Pandit, N. R., Taylor, P., Pandit, B. H., Sparrevik, M. & Schmidt, H. P. (2016) Emissions andChar Quality of Flame-Curtain "Kon Tiki" Kilns for Farmer-Scale Charcoal/Biochar Production. PLoS ONE
11(5): 1-16.
FAO (2016) Forestry for a low-carbon future. Integrating forests and wood products in climate change strategies,
Forestry paper 177. Rome, Food and Agriculture Organization of the United Nations.
FAO (2017) The charcoal transition: greening the charcoal value chain to mitigate climate change and improve
local livelihoods, ed. JV Dam. Rome: Food and Agriculture Organization of the United Nations.
Müller, N., Spalding-Fecher, R., Bryan, S., Battye, W., Kollmuss, A., Sutter, C., Tison, S., Hayashi, D.,
Michaelowa, A. & Marr, M. A. (2011) Piloting greater use of standardised approaches in the Clean
Development Mechanism.
Pennise, D. M., Smith, K. R., Kithinji, J. P., Rezende, M. E., Raad, T. J., Zhang, J. & Fan, C. (2001) Emissions ofgreenhouse gases and other airborne pollutants from charcoal making in Kenya and Brazil. Journal ofGeophysical Research: Atmospheres 106(D20): 24143-24155.
Smith, K. R., Pennise, D. M., Khummongkol, P., Chaiwong, V., Ritgeen, K., Zhang, J., Panyathanya, W.,
Rasmussen, R. A. & Khalil, M. A. K. (1999) Greenhouse Gases from Small-scale Combustion Devices in
Developing Countries. Charcoal-Making Kilns in Thailand. In: pp. 1-69. Office of Research and Development,
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regarding the assessment of greenhouse gases emissions on the charcoal production. In: pp. 1-87. Piracicaba,
2010: Escola Superior de Agricultura Luiz de Queiroz.
Coke production
AISTech (2010) Paul S. Towsey, Ian Cameron and Yakov Gordon. Comparison of by-product and heat-recovery
coke making technologies. Paper presented at AISTech 2010 — The Iron & Steel Technology Conference andExposition,
Pittsburgh,Pa.,andpublished
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Hensmann, M., Haardt, S. & Ebert, D. (2012) Emission factors for the iron and steel industry for emissions
reporting. In: pp. 1-69. Germany.
Huo, H., Lei, Y., Zhang, Q. & Zhao, L. (2012) China's coke industry: Recent policies, technology shift, andimplication for energy and the environment Energy Policy 51: 397-404.
IEA (2016) World Energy Statistics. https://www.iea.org/classicstats/relateddatabases/worldenergystatistics/
JRC (2013) Best Available Techniques (BAT) Reference Document for Iron and Steel Production. European
Commission, Joint Research Centre.
Man, Y., Yang, S. & Qian, Y. (2016) Integrated process for synthetic natural gas production from coal and cokeoven gas with high energy efficiency and low emission. Energy Conversion and management 117: 162-170.
Nishifuji, M., Fujioka, Y., Saito, K., Ishiharaguchi, Y. & Ueki, M. (2011) Characterization of Gas Generation
during Coking Reaction and Continuous Monitoring of COG Using Gas Monitoring System. Nippon SteelTechnical Report 100: 97-106.
Wood pellet production
Agar, D., Gil, J., Sanchez, D., Echeverria, I. & Wihersaari, M. (2015) Torrefied versus conventional pellet
production – A comparative study on energy and emission balance based on pilot-plant data and EU
sustainability criteria. Applied Energy 138(Supplement C): 621-630.
Grover, P. D. & Mishra, S. K. (1996) Biomass Briquetting: Technology and Practices In: FAO Regional woodenergy development Programme in Asia GCP/RAS/154/NET Field Document No.46 Bangkok, Thailand.
Johansson, L. S., Leckner, B., Gustavsson, L., Cooper, D., Tullin, C. & Potter, A. (2004) Emission characteristics
of modern and old-type residential boilers fired with wood logs and wood pellets. Atmospheric Environment
38(25): 4183-4195.
Kuang, X., Shankar, T. J., Bi, X. T., Sokhansanj, S., Jim Lim, C. & Melin, S. (2008) Characterization and Kinetics
Study of Off-Gas Emissions from Stored Wood Pellets. The Annals of Occupational Hygiene 52(8): 675-683.
Magelli, F., Boucher, K., Bi, H. T., Melin, S. & Bonoli, A. (2009) An environmental impact assessment of exported
wood pellets from Canada to Europe. Biomass and Bioenergy 33(3): 434-441.

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Ministry of Environment, British Columbia (2011) Wood Pellet Manufacturing Facilities: Fact sheet Air Emissions.
In: pp. 1-3. Ministry of Environment, British Columbia.
Murphy, F., Devlin, G. & McDonnell, K. (2015) Greenhouse gas and energy based life cycle analysis of products
from the Irish wood processing industry. Journal of Cleaner Production 92: 134-141.
Olsson, M. (2002) Wood pellets as low-emitting residential biofuel. In: Department of Chemical Environmental
Science, pp. 1-70. Göteborg, Sweden Chalmers University Of Technology, Göteborg, Sweden
Sjølie, H. K. & Solberg, B. (2011) Greenhouse gas emission impacts of use of Norwegian wood pellets: asensitivity analysis. Environmental Science & Policy 14(8): 1028-1040.
Svedberg, U. R. A., Högberg, H.-E., Högberg, J. & Galle, B. (2004) Emission of Hexanal and Carbon Monoxidefrom Storage of Wood Pellets, a potential Occupational and Domestic Health Hazard. Ann Occup Hyg 48(4):339-349.
Wang, C., Chang, Y., Zhang, L., Pang, M. & Hao, Y. (2017) A life-cycle comparison of the energy, environmental
and economic impacts of coal versus wood pellets for generating heat in China. Energy 120: 374-384.
World Bioenergy Association (2018) WBA Global Bioenergy Statistics 2017 (4th Edition). In: pp. 1-80.
Stockholm, Sweden: World Bioenergy Association.
Gasification transformation processes
OECD/IEA (2007) Bioenergy Project Development and Biomass Supply.
Van der Drift, A. & Boerrigter, H. (2006) Synthesis gas from biomass for fuels and chemicals (ECN-C-06-001).
BtL and BtG
Ail, S. S. & Dasappa, S. (2016) Biomass to liquid transportation fuel via Fischer Tropsch synthesis – Technology
review and current scenario. Renewable and Sustainable Energy Reviews 58(Supplement C): 267-286.
Asadullah, M. (2014) Biomass gasification gas cleaning for downstream applications: A comparative criticalreview. Renewable and Sustainable Energy Reviews 40: 118-132.
NETL/DOE (2016) Gasification Plant Databases. In: National Energy Technology Laboratory, US Department ofEnergy. Available at: https://www.netl.doe.gov/research/coal/energy-systems/gasification/gasification-plantdatabases.
CTL and GTL
Childress, J. (2008) Gasification Industry Overview: Addressing the “Dash to Gas”. In: Tulsa, Oklahoma, USA:
Gasification Technologies Council, Gasification Workshop.
GSTC (2014) Worldwide Syngas Database.
Hao, H., Wang, H., Song, L., Li, X. & Ouyang, M. (2010) Energy consumption and GHG emissions of GTL fuelby LCA: Results from eight demonstration transit buses in Beijing. Applied Energy 87: 3212-3217.
Hao, X., Djatmiko, M. E., Xu, Y. Y., Wang, Y. I., Chang, J. & Li, Y. W. (2008) Simulation Analysis of a GTL
Process Using Aspen Plus. Chemical Engineering & Technology 31(2): 188-196.
Heimel, S. & Lowe, C. (2009) Technology comparison of CO2 capture for a gas-to-liquids plant. Energy Procedia
1(1): 4039-4046.
Higman, C. & Van Der Burgt, M. (2008) Gasification (Second Edition). Gulf Professional Publishing.
Jaramillo, P., Griffin, W. M. & Matthews, H. S. (2008) Comparative Analysis of the Production Costs and LifeCycle GHG Emissions of FT Liquid Fuels from Coal and Natural Gas. Environmental Science & Technology
42(20): 7559-7565.
Mantripragada, H. C. & Rubin, E. S. (2011) CO2 reduction potential of coal-to-liquids (CTL) process: Effect ofgasification technology. Energy Procedia 4: 2700-2707.

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REFERENCES COPIED FROM THE 2006 IPCC GUIDELINESSECTION 4.1 COAL MINING
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SECTION 4.2 OIL AND GAS
Mohaghegh, S.D., L.A. Hutchins and C.D. Sisk. 2002. Prudhoe Bay Oil Production Optimization: Using Virtual
intelligence Techniques, Stage One: Neural Model Building. Presented at the SPE Annual TechnicalConference and Exhibition held in San Antonio, Texas, 29 September–2 October 2002.

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