Global Methane
Tracker
DOCUMENTATION
2022 VERSION
Last updated: 23 February 2022

Global Methane Tracker 2022

Documentation

Table of contents
Background............................................................................................................................... 4
Methane emission estimates................................................................................................... 5
Upstream and downstream oil and gas .................................................................................. 5
Incomplete combustion of flares ............................................................................................. 9
Coal mine methane ............................................................................................................... 10
Emissions from fuel combustion (end use)........................................................................... 11
Waste and agriculture .......................................................................................................... 12
Marginal abatement cost curves for oil and gas ................................................................ 13
Well-head prices used in net present value calculation ....................................................... 17
Projections of energy-related methane emissions and assessed temperature rises .... 20
Glossary of mitigation options ............................................................................................. 22

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References .............................................................................................................................. 29

Global Methane Tracker 2022

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Background
The IEA’s estimates of methane emissions are produced within the framework of
the World Energy Model (WEM). Since 1993, the International Energy Agency(IEA) has provided medium- to long-term energy projections using this large-scale
simulation model designed to replicate how energy markets function and generatedetailed sector-by-sector and region-by-region projections for the World Energy
Outlook (WEO) scenarios. Updated every year, the model consists of three main
modules: final energy consumption (covering residential, services, agriculture,industry, transport and non-energy use); energy transformation including power
generation and heat, refinery and other transformation (such as hydrogenproduction); and energy supply (oil, natural gas and coal). Outputs from the model
include energy flows by fuel, investment needs and costs, greenhouse gas
emissions and end-user prices.
The WEM is a very data-intensive model covering the whole global energy system.
Much of the data on energy supply, transformation and demand, as well as energy
prices is obtained from the IEA’s own databases of energy and economic statistics(http://www.iea.org/statistics) and through collaboration with other institutions. For
example, for the Net Zero by 2050: A Roadmap for the Global Energy Sector
publication, results from both the WEO and Energy Technology Perspectives(ETP) models have been combined with those from the International Institute forApplied Systems Analysis (IIASA) – in particular the Greenhouse Gas - Air
Pollution Interactions and Synergies (GAINS) model – to evaluate air pollutant
emissions and resultant health impacts. And, for the first time, results werecombined with the IIASA’s Global Biosphere Management Model (GLOBIOM) to
provide data on land use and net emissions impacts of bioenergy demand. The
WEM also draws data from a wide range of external sources which are indicatedin the relevant sections of the WEM documentation.

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The current version of WEM covers energy developments up to 2050 in 26
regions. Depending on the specific module of the WEM, individual countries arealso modelled: 12 in demand; 102 in oil and natural gas supply; and 19 in coalsupply (see Annex 1 of the WEM documentation).

Global Methane Tracker 2022

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Methane emission estimates
The Global Methane Tracker covers all sources of methane from human activity.
For the energy sector, these are IEA estimates for methane emissions from the
supply or use of fossil fuels (coal, oil and natural gas) and from the use of
bioenergy (such as solid bioenergy, liquid biofuels and biogases). For non-energy
sectors – waste, agriculture and other sources – reference values based on
publicly available data sources are provided to enable a fuller picture of methane
sources.

Upstream and downstream oil and gas
Our approach to estimating methane emissions from global oil and gas operations
relies on generating country-specific and production type-specific emission
intensities that are applied to production and consumption data on a country-bycountry basis. Our starting point is to generate emission intensities for upstream
and downstream oil and gas in the United States (Table 1). The 2021 US
Greenhouse Gas Inventory (US EPA, 2021) is used along with a wide range ofother publicly-reported, credible data sources. The hydrocarbon-, segment- andproduction-specific emission intensities are then further segregated into fugitive,
vented and incomplete flaring emissions to give a total of 19 separate emission
intensities.

Hydrocarbon

Segment

Oil

Upstream

Oil

Upstream

Oil
Oil

Production type

Emissions type

Intensity(massmethane/mass oilor gas)

Vented0.39%

Fugitive

0.03%

Upstream

Onshoreconventional
Onshoreconventional
Offshore

Vented0.39%

Upstream

Offshore

Fugitive

0.03%

Oil

Upstream

Unconventional oil

Vented0.59%

Oil

Upstream

Unconventional oil

Fugitive

0.05%

Oil

Downstream

Vented

0.004%

Oil

Downstream

Fugitive

0.001%

Incomplete-flare

0.08%

Incomplete-flare

0.02%

Incomplete-flare

0.09%

Vented0.40%

Onshoreconventional
Offshore

Oil
Oil
Oil
Natural gas

Upstream

Unconventional
Onshoreconventional

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Categories of emission sources and emissions intensities in the UnitedStatesGlobal Methane Tracker 2022

Documentation

Hydrocarbon

Segment

Natural gas

Upstream

Natural gas

Upstream

Natural gas

Upstream

Natural gas

Upstream

Natural gas

Upstream

Natural gas

Downstream

Natural gas

Downstream

Production type
Onshoreconventional
Offshore
Offshore
Unconventional
gas
Unconventionalgas

Emissions type

Intensity(massmethane/mass oilor gas)Fugitive

0.18%

Vented0.40%

Fugitive

0.18%

Vented0.67%

Fugitive

0.31%

Vented0.14%

Fugitive

0.26%

The US emissions intensities are scaled to provide emission intensities in all othercountries. This scaling is based upon a range of auxiliary country-specific data.
For the upstream emission intensities, the scaling is based on the age ofinfrastructure, types of operator within each country (namely international oil
companies, independent companies or national oil companies) and averageflaring intensity (flaring volumes divided by oil production volumes). For
downstream emission intensities, country-specific scaling factors were based
upon the extent of oil and gas pipeline networks and oil refining capacity andutilisation.
Methodological approach for estimating methane emissions from oil andgas operations

IEA. All rights reserved.

The strength of regulation and oversight, incorporating government effectiveness,regulatory quality and the rule of law as given by the Worldwide GovernanceIndicators compiled by the World Bank (2021), affects the scaling of all intensities.
Some adjustments were made to the scaling factors in a limited number ofcountries to take into account other data that were made available (where this wasconsidered to be sufficiently robust), such as comprehensive measurement

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Figure 1

Global Methane Tracker 2022

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studies. This includes data on satellite-detected large emitters and basin-levelemissions, based on data processing by Kayrros, an earth observation firm (seeBox 1.6). It also includes specific policy efforts to control methane emissions fromthe oil and gas sectors, as tracked in the IEA Policies Database.
Table 2 provides the resultant scaling factors in the top oil and gas producers (thecountries listed cover 95% of global oil and gas production). These scaling factors
are directly used to modify the emissions intensities in Table 1. For example, thevented emission intensity of onshore conventional gas production in Russia istaken as 0.40%×1.6 = 0.64%. These intensities are finally applied to the
production (for upstream emissions) or consumption (for downstream emissions)of oil and gas within each country.
Scaling factors applied to emission intensities in the United States
Oil & gas
production in
2021

Oil

Gas

mtoe

Upstream

United States

1 516

1.0

Downstrea
m
1.0

1.0

Downstream
1.0

Russia

1 170

2.1

1.4

1.6

1.2

Saudi Arabia

619

1.0

0.6

0.8

0.6

Canada

418

0.8

0.5

0.9

0.5

Upstream

Iran

355

2.9

1.0

1.6

1.0

China

352

1.2

0.8

0.9

0.7

Iraq
United ArabEmirates
Qatar

222

1.8

0.8

1.1

0.8

224

1.2

0.6

1.1

0.6

221

1.0

0.6

1.0

0.6

Norway

195

0.0

0.0

0.0

0.0

Kuwait

147

1.1

0.7

0.8

0.7

Brazil

173

1.4

1.3

1.4

1.3

Algeria

143

4.2

1.3

1.7

1.3

Nigeria

120

3.8

1.8

2.0

1.7

Mexico

125

1.7

0.9

1.1

0.8

Kazakhstan

120

2.8

1.4

2.5

1.4

Australia

138

0.9

0.5

0.5

0.5

Indonesia

88

2.4

1.3

1.6

1.3

Malaysia

87

1.2

0.6

0.7

0.6

United Kingdom

69

0.5

0.3

0.4

0.3

Egypt

86

2.7

1.0

1.3

1.0

Oman

88

1.6

0.7

1.1

0.7

Venezuela

46

9.0

1.8

2.4

1.8

Turkmenistan

84

17.3

5.0

6.3

5.0

Angola

65

1.5

1.3

0.7

1.3

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CountryGlobal Methane Tracker 2022

Box 1.1

Documentation

Integrating emissions estimates from satellites

The Global Methane Tracker integrates results from all publicly-reported,credible sources where data has become available. This includes emissions
detected by satellites. Changes in the atmospheric concentration of methane
can be used to estimate the rate of emissions from a source that would havecaused such a change. This is done based on data processing by Kayrros,
an earth observation firm, to convert readings of concentrations to identify
large sources of emissions from oil and gas operations. Reported emissions
encompass individual methane sources above 5 tonnes per hour as well asclusters of smaller sources in dense areas (e.g. shale plays). Estimates arealso provided using “basin-level inversions”, which use satellite readings toassess methane emissions across a wider oil and gas production region; thesame approach is also used to measure the methane footprint of coal basins.
Emissions detected by satellites are reported as a separate item within the
Methane Tracker. These estimates are based on a conservative scaling up ofemission events directly detected in order to take into account that considers
the period within the year when observations could be made. This is carriedout for all regions where observations were possible for at least 15 days in
the year.



Existing satellites do not provide measurements over equatorial regions,
northern areas or for offshore operations. This means that there are alarge number of major production areas (e.g. in areas that are often
covered with snow) where emissions cannot be directly detected bysatellites.



Existing satellites should be able to provide methane readings globally ona daily basis but this is not always possible because of cloud cover andother weather conditions. During 2021 there were around 70 countries
where methane emissions from oil and gas operations could be detected
for at least 15 days. Large emission events were observed in 15 of thesecountries in 2021. Coverage tends to be best in the Middle East, where a
direct measurement could be made every 3-5 days. On the remaining
days, cloud coverage or other interference prevented measurement
operations.



The satellite readings included in the Global Methane Tracker currently
provide data only for large emitting sources. They may fail to capturesmall-scale emissions sources such as faulty components, which could
add up to a large overall amount of emissions.

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The increasing amount of data and information from satellites will continue toimprove global understanding of methane emissions levels and theopportunities to reduce them. However, satellites do have some limitations:Global Methane Tracker 2022

Documentation

The process of using changes in the atmospheric concentration of
methane to estimate emissions from a particular source can rely on a large
level of auxiliary data and be subject to a high degree of uncertainty.



Accounting for the level of satellite coverage, very large emitting events
detected by satellite are estimated to have been responsible for around 3.5
Mt of emissions from oil and gas operations in 2021 (6% of our estimate of oil
and gas emissions in the 15 countries where events were detected). This is,of course, subject to a high degree of uncertainty, but ensures that countryby-county estimates provide a comprehensive picture of all methane
emissions sources. As additional data becomes available from measurement
campaigns – whether recorded from ground or aerial processes or bysatellites – these will be incorporated into the Global Methane Tracker andestimates adjusted accordingly.

Incomplete combustion of flares
Our approach to estimating methane emissions from flaring relies on generating
country-specific and production type-specific combustion efficiencies that are
applied to flaring data on a country-by-country basis. Global estimates of flared
volumes of natural gas are based on reported data from the World Bank’s Global
Gas Flaring Reduction Partnership. These data are taken from the National
Oceanic and Atmospheric Administration (NOAA) and the Payne Institute (World
Bank, 2021).



Oil production type (unconventional onshore, conventional onshore and offshore),company type and production start-up year, based on Rystad Energy UCube data.
Company type is grouped in Majors (ExxonMobil, Chevron, BP, Royal Dutch Shell,
Eni SpA, TotalEnergies, and ConocoPhillips), National Oil Companies (NOCs)
and Other (e.g. Independent, Private Equity). Maintenance levels to improve
flaring combustion efficiencies were applied separately by company typeassuming that more scrutiny from investors and the public is placed on the Majors
as compared to NOCs or Other.



Flaring design standards API 521 and API 537 were considered gauge flare stacksizes, assuming best-case design and optimal flare parameters during early
production time (API, 2014; API, 2017).



The impact of wind speed was incorporated using NASA’s Prediction of Worldwide
Energy Resources (POWER) Meteorology Data Access Viewer (NASA, 2021).
Onshore wind speeds were assessed at 10m and offshore wind speeds at 50m to

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Combustion efficiencies can reduce as a result of lower production rates, high andvariable winds, and poor maintenance resulting from lack of regulatory policy,
enforcement or company policy (Johnson, 2001; Kostiuk, 2004). We estimate
combustion based upon a range of auxiliary country-specific data:Global Methane Tracker 2022

Documentationreflect closest height of flare stacks in actual facility design. Wind speed variability
and its impact on combustion efficiency was incorporated corresponding to thelocation of production.



The World Bank’s Worldwide Governance Indicators database (2021) was used as thebasis to assess the general strength of regulatory oversight.

Adjustments are made to consider data on satellite-detected large emitters andspecific policy efforts to control methane emissions from the oil and gas sectors,
as tracked in the IEA Policies Database. Countries with stronger flaring regulationand strong regulatory oversight are calibrated assuming companies weremandated to quickly inspect and repair any malfunctioning or poor performing flaresites. Countries with weak flaring regulation and low levels of oversight are
assumed to perform little to no additional maintenance.

Coal mine methane
Estimates for coal mine methane (CMM) emissions are derived from mine-specificemissions intensities for three major coal producing countries. The starting point
is to generate emission intensities for coal mines in the United States using the
US Environmental Protection Agency’s Greenhouse Gas Reporting Program andUS Greenhouse Gas Inventory (US EPA, 2021). This is supplemented by data
sources that provided disaggregated CMM data for China (Wang et al., 2018; Zhu
et al., 2017) and India (Singh A. K. and Sahu J. N., 2018) (India Ministry of Coal,
2018).
The mine-level CMM estimates generated in this way were then aggregated andverified against the country-level estimates taken from satellite based
measurements (Deng et al., 2021; Miller et al., 2019). Based on these data, coalquality (e.g. the ash content or fixed carbon content of coal produced by individual
mines), mine depth and regulatory oversight were used as key factors to estimate
CMM emission intensities for mines in other countries for which there are no
reliable direct estimates.

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An important factor in estimating CMM emissions is the depth and age of thevarious mines in operation. Deeper coal seams tend to contain more methane
than shallower seams, while older seams have higher methane content than
younger seams. In the absence of any mitigation measures, methane emissions
to the atmosphere will therefore tend to be higher for underground mines than forsurface mines. Regulations can also affect emissions, limiting the amount ofmethane that can be vented or ensuring that these emissions are captured andput to use (e.g. mandating the application of drainage technologies and thedevelopment of capacity to support gas use, such as pipelines networks, gaspowered electricity generation).

Global Methane Tracker 2022

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Emissions from abandoned mines are not included in these estimates as related
measurement studies cover a limited number of facilities and regions, and data on
abandoned mines and wells is not available for most countries. Nevertheless,these sources can represent significant shares of emissions. For example, theUnited States Environmental Protection Agency indicates they are responsible forclose to 5% of energy-related methane in the United States (US EPA, 2021).

Emissions from fuel combustion (end use)
Methane emissions are associated with fuel use, either due to incomplete
combustion or as fugitive emissions. Methane can leak from storage vessels,
pipelines or end use appliances (e.g. stovetops). It can also escape without
combustion from mobile applications (e.g. natural gas fuelled vehicles) or
stationary applications (e.g. power generators).
We estimate that around 9 Mt of methane emissions comes during the incomplete
combustion of traditional use of biomass for cooking in emerging market anddeveloping economies. With regards to fossil fuels, we estimate that about 4 Mt
(3% of energy-related methane emissions) comes from the end use of coal, oil
products and natural gas. This estimate is based on the emissions factors
published by the Intergovernmental Panel on Climate Change (IPCC) for energy
consumption in homes, industries and in the transport sector.
Estimates for methane emissions from the use of fuels in stationary and mobile
applications are from the IEA Greenhouse Gas Emissions from Energy 2021, forthe base year 2019. The Tier 1 methodology from the 2006 IPCC Guidelines for
GHG inventories have been adopted for the purpose of estimating the non-CO2
emissions from fuel combustion. Unlike CO2, the non-CO2 greenhouse gas
emissions from fuel combustion are strongly dependent on the technology used.
Since the set of technologies, applied in each sector vary considerably, theguidelines do not provide default emission factors for these gases on the basis offuels only. Sector-specific Tier 1 default emission factors can provide a reasonableestimate for these emissions.

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Some measurement campaigns have suggested that these emissions factors
could significantly underestimate actual emissions across different end-use
environments, including in industries (Zhou et al., 2019), cities (Sargent et al.,2021) and households (Lebel et al., 2022). Emission levels might also havechanged from 2019 to 2021, for example, the covid-19 pandemic might have led
to an increase in the traditional use of biomass for cooking or heating. These areareas with very high levels of uncertainty and our estimates will continue to be
updated as the evidence base grows.

Global Methane Tracker 2022

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For estimating the emissions corresponding to stationary combustion, the default
Tier 1 non-CO2 emission factors provided in the 2006 IPCC guidelines assume
effective combustion in high temperature. The emission factors provided for CH4
are based on the 1996 IPCC Guidelines and have been established by a large
group of inventory experts. However, due to the absence of sufficientmeasurements and since the concept of conservation of carbon does not apply inthe case of non-CO2 gases, the uncertainty range associated with these estimates
are set at a factor of three.
Similarly and for mobile combustion, the non-CO2 emission factors are moredifficult to estimate accurately than those for CO2, as they will depend on vehicle
technology, fuel and operating characteristics, mainly the combustion andemission control system of the vehicles. As a result, default fuel-based emission
factors are highly uncertain. However, the Tier 1 method does allow using fuelbased emission factors if it is not possible to estimate fuel consumption by vehicle
type.
For more details on the underlying methodology and assumptions please refer tothe IEA GHG emissions from energy documentation.

Waste and agriculture
The 2022 update of the Global Methane Tracker includes emissions estimatesfrom non-energy sectors – waste, agriculture and other sources – based on
publicly available data sources, to provide a fuller picture of methane sources fromhuman activity. Reference estimates are taken as an average of estimatesavailable for the most recent year from 2018 or 2019, based on the following
sources.
United Nations Framework Convention on Climate Change (UNFCCC) – National
greenhouse gas inventories submitted to the Climate Change secretariat. Thesesubmissions are made in accordance with pertaining reporting requirements, suchas the UNFCCC reporting guidelines on annual greenhouse gas inventories. The
inventory data are provided in the annual greenhouse gas inventory submissions
by Annex I Parties and in the national communications and biennial update reports
by non-Annex I Parties. Data available here.

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Emissions Database for Global Atmospheric Research (EDGAR v6.0) – EDGAR
is a global database of anthropogenic emissions of greenhouse gases and air
pollution. EDGAR provides independent emission estimates compared to what isreported by Parties under the UNFCCC, using international statistics and aconsistent IPCC methodology. Additional information can be found in Crippa etal. (2021). Data available here.

Global Methane Tracker 2022

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Community Emissions Data System (CEDS v_2021_04_21) – CEDS producesconsistent estimates of global air emissions species over the industrial era (1750- present). It uses a variety of data to do so, from population and energy statistics
to emissions inventories and a variety of auxiliary data. Note that EDGAR isamong the sources used to establish emissions factors for non-combustion
sources, further information on CEDS methodology and sources can be found in
Hoesly et al. (2018) and here. Data available here.
Climate Watch (CAIT) – CAIT draws on climate-relevant data from research
centres, government agencies, and international bodies, including the U.N. Foodand Agriculture Organization (FAO, 2021) and the U.S. Environmental Protection
Agency. The CAIT Historical GHG Emissions data contains sector-levelgreenhouse gas emissions data for 194 countries for the period 1990-2018,
including emissions of the six major greenhouse gases from most major sources
and sinks. Further information can be found here. Data available here.
These datasets were aligned with the categories and regions shown in the Global
Methane Tracker by considering individually all major emitters and anthropogenic
emissions sources included in each database.

Marginal abatement cost curves for oil andgas
To construct the marginal abatement cost curves presented in the Methane
Tracker Database, the 19 emissions sources listed in Table 1 were further
separated into 91 equipment-specific emissions sources (Table 3). 1 The allocationof emissions from each of the 19 emissions sources to these 91 equipmentspecific sources was generally based on proportions from the United States.
However a number of modifications were made for countries based on other data
sources and discussions with relevant stakeholders. Some of the largest changes
made were for the proportion of emissions from: pneumatic controllers (which areless prevalent in many countries outside North America), LNG liquefaction (whichwere assumed to be larger in LNG exporting countries), and associated gas
venting.
Equipment-specific emissions sources in the marginal abatement cost
curvesEquipment source
Large Tanks w/Flares
Large Tanks w/VRU

Hydrocarbon
Oil
Oil

Segment
Upstream
Upstream

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1
To aid visualisation of the marginal abetment cost curves, the costs and savings from multiple technologies are generally
aggregated together. Within each country, the abatement options that could be applied to each of the 19 emission sources
are aggregated into three cost steps. These steps roughly represent the cheapest 50% of reductions, the next 30% of
reductions and the final of 20% reductions.

Equipment source
Large Tanks w/o Control
Small Tanks w/Flares
Small Tanks w/o Flares
Heaters
Boilers
Malfunctioning Separator Dump
ValvesPneumatic Devices, High Bleed
Pneumatic Devices, Low Bleed
Pneumatic Devices, Int Bleed
Chemical Injection Pumps
Vessel Blowdowns
Compressor Blowdowns
Compressor Starts
Associated Gas Venting
Associated Gas Flaring
Well Completion Venting (less HF
Completions)
Well Workovers
HF Well Completions,
Uncontrolled
HF Well Completions, Controlled
Pipeline Pigging
Tanks
Truck Loading
Marine Loading
Rail Loading
Pump Station Maintenance
Pipeling Pigging
Uncontrolled Blowdowns
Asphalt Blowing
Process Vents
CEMS
Glycol Dehydrator
Production Compressor Vented
Gas Well Completions without
Hydraulic Fracturing
Gas Well Workovers without
Hydraulic Fracturing
Hydraulic Fracturing Completionsand Workovers that ventHydraulic Fracturing Completionsand Workovers with RECs
Well Drilling
Pneumatic Device Vents (Low
Bleed)
Pneumatic Device Vents (High
Bleed)
Pneumatic Device Vents(Intermittent Bleed)
Chemical Injection Pumps
Kimray Pumps
Dehydrator Vents
Large Tanks w/VRU
Large Tanks w/o Control
Small Tanks w/o Flares
Malfunctioning Separator Dump
ValvesGas Engines
Well Clean Ups (LP Gas Wells) Vent Using Plungers

Documentation

Hydrocarbon
Oil
Oil
Oil
Oil
Oil

Segment
Upstream
Upstream
Upstream
Upstream
Upstream

Oil

Upstream

Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil

Upstream
Upstream
Upstream
Upstream
Upstream
Upstream
Upstream
Upstream
Upstream

Oil

Upstream

Oil

Upstream

Oil

Upstream

Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Gas
Gas

Upstream
Upstream
Downstream
Downstream
Downstream
Downstream
Downstream
Downstream
Downstream
Downstream
Downstream
Downstream
Upstream
Upstream

Gas

Upstream

Gas

Upstream

Gas

Upstream

Gas

Upstream

Gas

Upstream

Gas

Upstream

Gas

Upstream

Gas

Upstream

Gas
Gas
Gas
Gas
Gas
Gas

Upstream
Upstream
Upstream
Upstream
Upstream
Upstream

Gas

Upstream

Gas

Upstream

Gas

Upstream

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Global Methane Tracker 2022

Global Methane Tracker 2022

Equipment source
Well Clean Ups (LP Gas Wells) Vent Without Using Plungers
Vessel BD
Pipeline BD
Compressor BD
Compressor Starts
Gathering and Boosting Stations
Pressure Relief Valves
Mishaps
Recip. Compressors
Centrifugal Compressors (wetseals)
Centrifugal Compressors (dryseals)
Dehydrators
AGR Vents
Pneumatic Devices
Blowdowns/Venting
Produced water from Coal Bed
Methane Wells
Reciprocating Compressor
Centrifugal Compressor (wetseals)
Centrifugal Compressor (dryseals)
Reciprocating Compressor
Dehydrator vents (Transmission)
Dehydrator vents (Storage)
Pneumatic Devices (High Bleed)
Pneumatic Devices (Intermittent
Bleed)
Pneumatic Devices (Low Bleed)
Pneumatic Devices (High Bleed)
Pneumatic Devices (Intermittent
Bleed)
Pneumatic Devices (Low Bleed)
Pipeline venting
Station Venting Transmission
Station Venting Storage
LNG Reciprocating Compressors
VentedLNG Centrifugal Compressors
VentedLNG Station venting
LNG Reciprocating Compressors
VentedLNG Centrifugal Compressors
VentedLNG Station venting
Pressure Relief Valve Releases
Pipeline Blowdown
Mishaps (Dig-ins)

Documentation

Hydrocarbon

Segment

Gas

Upstream

Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas

Upstream
Upstream
Upstream
Upstream
Upstream
Upstream
Upstream
Upstream

Gas

Upstream

Gas

Upstream

Gas
Gas
Gas
Gas

Upstream
Upstream
Upstream
Upstream

Gas

Upstream

Gas

Downstream

Gas

Downstream

Gas

Downstream

Gas
Gas
Gas
Gas

Downstream
Downstream
Downstream
Downstream

Gas

Downstream

Gas
Gas

Downstream
Downstream

Gas

Downstream

Gas
Gas
Gas
Gas

Downstream
Downstream
Downstream
Downstream

Gas

Downstream

Gas

Downstream

Gas

Downstream

Gas

Downstream

Gas

Downstream

Gas
Gas
Gas
Gas

Downstream
Downstream
Downstream
Downstream

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The abatement options included in the marginal abatement cost curves to reduce
emissions from these sources are listed in Table 4. We are unable to provide thespecific costs and applicability factors for these as it is based on proprietary
information gathered by ICF (although see (ICF, 2016a) and (ICF, 2016b) for datathat has made available publically). Every abatement option has a specific capitalGlobal Methane Tracker 2022

Documentation

cost, which is annualised based on the number of years it is expected to last.
These are added to yearly operational costs, which entail wages, maintenanceand related expenditures. Costs were again based upon information from theUnited States. However labour costs, whether the equipment is imported or
manufactured domestically (which impacts the capital costs and whether or notimport taxes are levied), and capital costs were modified based on country-specificor region-specific information. Similarly the applicability factors are modified basedon other data that is available publically (for example that solar-powered electric
pumps cannot be deployed as widely in high-latitude countries).
Leak detection and repair (LDAR) programmes are the key mechanism to mitigate
fugitive emissions from the production, transmission or distribution segments ofthe value chain. The costs of inspection differ depending on the segment inquestion since it takes longer to inspect a compressor on a transmission pipeline
than in a production facility. It is assumed that inspections can be carried out
annually, twice a year, quarterly or monthly, with each option included as aseparate mitigation option in the marginal abatement cost curves. We also
consider the option of a continuous monitoring system, either based on remote or
facility-based sensors (Daily LDAR), which abates emissions from large leaks that
occur sporadically such as those detected by satellites. Annual inspections are
assumed to mitigate 40% of fugitive emissions, biannual inspections mitigate an
additional 20%, quarterly inspections mitigate an additional 10%, and monthly
inspections mitigate an additional 5%. Implementing a monthly LDAR programme
therefore reduces fugitive emissions by 85%; the remaining 15% cannot be
avoided. As the frequency of implementing each programme increases, so does
the cost per unit of methane saved. For example, while the incremental cost of abiannual inspection programme is the same as that of an annual inspection, theincremental volume of methane saved is lower (20% rather than 40%).
Nevertheless, LDAR programmes remain some of the most cost-effective
mitigation options available, i.e. they tend to comprise a large proportion of thepositive net present value options in countries.
Abatement options for methane emissions from oil and gas operations
Abatement option

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Blowdown Capture and Route to Fuel System (per Compressor)
Blowdown Capture and Route to Fuel System (per Plant)
Early replacement of high-bleed devices with low-bleed devices
Early replacement of intermittent-bleed devices with low-bleed devices
Install Flares-Completion
Install Flares-Portable
Install Flares-Portable Completions Workovers WO HF
Install Flares-Portable WO Plunger Lifts
Install Flares-Stranded Gas Venting
Install Flares-Venting
Install New Methane Reducing Catalyst in Engine

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Abatement option
Install Non Mechanical Vapor Recovery Unit
Install Plunger Lift Systems in Gas Wells
Install small flare
Install Vapor Recovery UnitsLDAR Gathering
LDAR LDC - Large
LDAR LDC - MRR
LDAR Processing
LDAR Reciprocating Compressor Non-seal
LDAR Transmission
LDAR Wells
Mechanical Pumping for Liquids Unloading
Pipeline Pump-Down Before Maintenance
Redesign Blowdown Systems and Alter ESD Practices
Reduced Emission Completion
Replace Kimray Pumps with Electric Pumps
Replace Pneumatic Chemical Injection Pumps with Electric Pumps
Replace Pneumatic Chemical Injection Pumps with Solar Electric Pumps
Replace with Instrument Air Systems
Replace with Electric Motor
Replace with Servo Motors
Replace with Solenoid Controls
Replacement of Reciprocating Compressor Rod Packing Systems
Route to existing flare - Large Dehydrators
Route to existing flare - Large Tanks
Route to flare - Small Dehydrators
Route to existing flare - Small Tanks
Route Vent Vapors to tank
Wet Seal Degassing Recovery System for Centrifugal Compressors
Wet Seal Retrofit to Dry Seal Compressor
Microturbine
Mini-LNG
Mini-GTL
Mini-CNG

In our marginal abatement cost curve, we have grouped these abatement options
into several categories. We have also associated each abatement option with
policy measures that target those actions. The abatement and policy options thatappear in the marginal abatement cost curves are described in further detail in theglossary below.
Box 1.2

Policies Database and Policy Explorer

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The Global Methane Tracker incorporates information from the IEA’s Policies
Database. This cross-agency database brings together information on past,
existing or planned government policies and measures covering many topics
across the energy sector, including energy efficiency, renewables, technology
innovation and methane abatement.

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The entries in the Policies Database related to methane abatement are
categorised by policy type and by sector. For each entry, we have included abrief description, links to original source material and other information about
the measure. This information is based on a broad review of policy andregulatory measures in place across the world. We have identified different
measures through desktop research and through discussions withgovernments. As of the release of the Global Methane Tracker 2022, thisdatabase has over 350 entries including in-depth information on policies inplace in 25 countries plus the European Union and more limited information
on many more. We welcome feedback regarding any updates to existing
policies or on additional policies that are missing from the database.
The Global Methane Tracker includes a new policy explorer tool that provides
a snapshot of the different policies and regulations in already in place in 25
countries. The policy explorer shows 16 different types of policies, which are
categorised by the primary regulatory approach: prescriptive, performancebased, economic, or information-based. Detailed definitions for thesecategories and policy types can be found in the glossary.

Well-head prices used in net present value
calculation
Since natural gas is a valuable product, the methane that is recovered can often
be sold. This means that deploying certain abatement technologies can result inoverall savings if the net value received for the methane sold is greater than thecost of the technology. Well-head prices are used in each country to determine
the value of the methane captured. As described in WEO-2019, the marginal
abatement cost curves examine this issue from a global, societal perspective. The
credit obtained for selling the gas is therefore applied regardless of the contractual
arrangements necessary and the prices assume that there are no domestic
consumption subsidies (as the gas could be sold on the international market at agreater price). The well-head gas prices used could therefore be substantiallydifferent from subsidised domestic gas prices.

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Representative average natural gas import prices seen from 2017 to 2021 are thestarting point for the well-head prices within each country. To estimate well-headprices over time, each country is assigned to be either an importer or an exporter
based on the trends seen in the Stated Policies Scenario. For importing countries,
any gas that would be saved from avoiding leaks would displace imports. The wellhead price is therefore taken as the import price minus the cost of local transportand various taxes that may be levied (assumed to be around 15% of the importprice). For exporting countries, the relevant well-head price is taken as the importGlobal Methane Tracker 2022

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price in their largest export market net-backed to the emissions source. For the
net-back, allowance is made for transport costs (including liquefaction andshipping or pipeline transport), fees and taxes. For example, in Russia the export
price is taken as the import price in Europe ($7.4/MBtu based on average 20172021 prices). Export taxes are then subtracted along with a further $0.5/MBtu tocover the cost of transport by pipeline. This gives a well-head gas price in Russia
of about $4.7/MBtu. In the United States and Canada, the well-head price is taken
as the Henry Hub price minus 15% (to cover the cost of local transportation andfees).

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The costs and revenue for each technology or abatement measure are converted
into net present value using a discount rate of 10% and divided by the volume ofemissions saved to give the cost in dollars per million British thermal units (MBtu).

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Projections of energy-related
methane emissions and assessed
temperature rises
We have carried out analysis using the Model for the Assessment of Greenhouse
Gas Induced Climate Change (“MAGICC”) to assess the impacts of different
emissions trajectories on the average global surface temperature rise. MAGICC
climate models have been used extensively in assessment reports written by theIntergovernmental Panel on Climate Change. MAGICC 7, the version used in thisanalysis, is one of the models used for scenario classification in the IPCC’s 6th
Assessment Report (IPCC, 2021). Emissions of all energy-related GHG from the
WEO-2021 scenarios are supplemented with commensurate changes in nonenergy-related emissions based on the scenario database published as part of the
IPCC Special Report on Global Warming of 1.5 °C (IPCC, 2018). All changes intemperatures are relative to 1850-1900 and match the IPCC 6th Assessment
Report definition of warming of 0.85 °C between 1995-2014.
An important consideration in assessing temperature rises is the date to examine.
If the aim of climate policy is to limit peak warming, then the key factor is the time
when the global temperature rise will reach a peak (Allen et al., 2016). In the IEA’s
Net Zero Emissions by 2050 Scenario, global CO2 emissions drop to zero in 2050
and this is approximately the date when the global temperature rise peaks. We
therefore choose to focus our analysis on the temperature rise in 2050.
The Stated Policies and Net-Zero Emissions by 2050 scenarios project methane
emissions from fossil fuel operations to 2050. Changes in other non-energy
sources of methane are introduced via a process of “infilling” based on the most
relevant Shared Socioeconomic Pathway-Representative Concentration Pathway(SSP-RCP) and a quantile rolling windows method from Silicone (Lamboll et al.
2020). For the Stated Policies Scenario, non-energy sources of methane are
initially based on SSP 2-4.5.

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Differences are then examined in the temperature rise in 2050 between the Stated
Policies Scenario and the Stated Policies Scenario with the full achievement of
the Global Methane Pledge (a 30% reduction in all human sources of methane by2030). After 2030, the difference in methane emissions between these two cases
is assumed to close slightly. All other variables, including the other greenhousegases (such as CO2, N2O, HFCs etc.), are kept constant to isolate the impact ofthe methane abatement policies on the median temperature rise in 2050. Full

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implementation of the Global Methane Pledge reduces the temperature rise in theStated Policies Scenario by around 0.12 °C in 2050.

Mt

Figure 2

400

Total methane emissions with and without implementation of the Global
Methane Pledge in the Stated Policies Scenario and difference intemperature in 2050

Total methane emissions

0.12

Temperature difference (°C)

0.10

300

0.08

200

0.06
0.04

100

0.02
2015 2020 2025 2030 2035 2040 2045 2050
STEPS

2050

STEPS+GMP
IEA. All rights reserved.

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Source: IEA analysis based on outputs of MAGICC 7.5.3.

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Glossary
Abatement technologies
A wide variety of technologies and measures are available to reduce methane
emissions from oil and gas operations. The options deployed vary by country,
depending on the prevailing emissions sources, gas prices and capital and labourcosts. For the purposes of the marginal abatement cost curve, we have grouped
the different abatement technologies into the following categories:

Replace existing devices
Many pieces of equipment in the oil and natural gas value chains emit natural gas
in their regular course of operation, including valves, and gas-driven pneumatic
controllers and pumps. Retrofitting these devices or replacing them with loweremitting versions can reduce emissions.
Early replacement of devices. Pneumatic devices are used throughout
production sites and compression facilities to control and operate valves andpumps with changes in pressure. Gas-driven automatic pneumatics release asmall amount of natural gas as part of their control functions. Devices can be
categorised as low-, intermittent- or high-bleed, based on the rate of gas thatescapes. Intermittent-bleed devices release gas only when actuating. Replacing
higher-bleed devices with lower-bleed devices reduces emissions. The earlier
devices are swapped out, the more emissions will be avoided.
Replace pumps. Pneumatic pumps that use pressurised natural gas as a powersource also vent natural gas in the ordinary course of their operation: theseemissions can be eliminated through replacement with electrical pumps poweredby solar or other generators, or connected to the grid.
Replace with electric motor. Gas-driven pneumatic devices continuously
release small amounts of gas, even when specified as "low-bleed." These devices
can be replaced with "zero-bleed" technologies that use electrical power tooperate, instead of pressurised natural gas. An electric motor can also replace adiesel or gas engine used onsite during drilling and well completion.

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Replace compressor seal or rod. Different kinds of compressors are used
across the oil and natural gas supply chains to move product through the system,and the methane abatement cost curve include several activities that reduce thepossibilities for gas to escape.

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Replace with instrument air systems. Pumps and controllers that vent natural
gas by design can be replaced by instrument air systems, which pressurise
ambient air to perform the same functions without emitting methane.

Installing new devices
There are a number of opportunities across the supply chain to install new devices
that can reduce or avoid large sources of vented emissions.
Vapour Recovery Units (VRUs). VRUs are small compressors designed tocapture emissions that build up in pieces of equipment across the oil and natural
gas supply chains. For instance, VRUs can capture gases that accumulate in oil
storage tanks and that are otherwise periodically vented to the atmosphere toprevent explosion.
Blowdown capture. Gas blowdowns are conducted at wellheads or elsewhere
along the supply chain when equipment (e.g. vessels, compressors) must be
depressurised. Blowdowns can be triggered by emergency signals or routine startup or shut down procedures. When this happens, operators open up the well toremove the liquids and gas. Emissions are mitigated when excess gas isrecovered and used onsite or sent to the sales line, instead of being vented orflared.
Install flares. While still a source of CO2 and methane emissions, flaring ispreferable to direct release of the methane gas to the atmosphere. Flares can beinstalled at oil and gas production sites where gas production exceeds onsite
demand or nearby pipeline capacity, to combust methane emissions. Portableflares can expand a facility’s flare capacity and provide an outlet for gas captured
during well workovers or completions.
Install plunger. Periodically over the life of a producing well, downhole liquids
need to be removed to facilitate continued flow of product (often called "liquid
unloading"). Traditionally, a well operator opens the well and vents methane,relieving pressure and drawing liquids up through the wellbore. Plunger lifts may
be installed to extract liquids more efficiently, while limiting the escape of methane.
As pressure from accumulating fluids builds up, it pushes on the plunger. The
plunger draws up gas and liquids in its wake. If a certain threshold of reservoirpressure is achieved through withdrawal of the plunger, gas can go directly to thesales line with no venting.

Leak detection and repair (LDAR)PAGE | 23

IEA. All rights reserved.

Leak detection and repair (LDAR) refers to the process of locating and repairing
fugitive leaks. LDAR encompasses several techniques and equipment types. One
common approach is the use of infrared cameras, which make methane leaks

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visible. LDAR can be applied across the supply chain—to upstream activities(including well development, gathering, processing) and/or downstream activities(such as transmission or distribution lines).
In the cost curve, we include varying frequencies of these programmes, frommonthly to yearly—the more frequent LDAR programmes are, the less the amountof gas that tends to be saved as a result of each programme, while the costs
remain stable. This is what one would expect from effective programmes. We also
consider the option of a continuous monitoring system, either based on remote or
facility-based sensors (Daily LDAR), which abates emissions from large leaks that
occur sporadically such as those detected by satellites.
The cost of inspection differs depending on the value chain segment in question—
LDAR programmes tend to be more cost effective for upstream operations since
it takes longer to inspect compressors on transmission pipelines, relative to thoseconcentrated in a production facility.

Other
IEA analysis includes alternative and innovative technologies and techniques in
addition to the categories above. The “Other” label includes approaches such as:
installing methane-reducing catalysts; deploying microturbines or othertechnologies that allow for local productive use of associated gas in remotelocations: conducting a pipeline pump-down before maintenance; and reducedemission or "green" completions.

Policy options
Different types of regulatory measures can be applied to methane. For eachabatement technology described above, we have assigned a specific policy
measure that targets this technology. Thus, for the purposes of our estimates of
mitigation potential in the marginal abatement cost curve, we have grouped thedifferent abatement actions into the following policy options:

Tried and tested policies

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Certain policies have well-established precedents, as they have already been
applied in multiple settings. These measures have proven to be both effective andrelatively straightforward to administer. Policies in this category have the added
benefit of not requiring very advanced tools to verify compliance, although somebasic quantification and reporting mechanism is generally necessary. The
measures in this category also tend to fall on the lower end of the abatement cost
curve – and tend therefore to be the most cost-effective overall.

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Leak detection and repair (LDAR). This refers to policies that require companies
to establish programs for locating and repairing fugitive leaks. These policies often
specify the method and equipment required for leak detection, the frequency ofdetection campaigns, which facilities must undertake the inspections, and arequirement to fix leaks within a certain timeframe. Within the IEA methane
emissions model, this corresponds to both upstream and downstream abatement
options. The model assumes that leak detection and repair will apply to all facilities
and may be applied at different frequencies. In the policy marginal abatement cost
curve, this includes inspection requirements that are at least quarterly, as thisfrequency is common among current requirements.
Technology standards. This refers to policies that set specific guidelines forequipment, technologies or procedures. Generally, such requirements mandatethat certain equipment be replaced by a lower-emitting alternative. Within themethane model, this corresponds to the following abatement options: replacecompressor seal or rod; early replacement of devices; replace with instrument air
systems; and replace pumps.
Zero non-emergency flaring and venting. This refers to policies that either
prohibit all non-emergency flaring and venting or those that mandate specificprocesses and procedures which result in less flaring and venting. Within themethane model, this corresponds to the following abatement options: installplunger; install flares; blowdown capture; and vapour recovery units.

Additional measures
Robust measurement-based monitoring regimes combined with additional
regulations can encourage additional abatement. Within the IEA methane
emissions model, additional measures correspond to the following abatement
options: replace with electric motor; monthly leak detection and repair; daily leakdetection and repair; other. These actions can be driven by a combination ofdifferent policies, including enhanced technology standards, performancestandards, emissions pricing, financing instruments, and monitoring, reporting andverification regimes. More information about these additional measures can befound in Curtailing Methane Emissions from Fossil Fuel Operations.

Policy explorer

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The Global Methane Tracker now includes a detailed country-by-country
breakdown of policies in place for certain countries. This tool is based on the IEA’s
Policies Database. The explorer tool categorises policies by type of policy(prescriptive, performance-based, economic, or information-based). Specificdefinitions used in the policy explorer tool are found below. Further details can beGlobal Methane Tracker 2022

Documentation

find in Driving Down Methane Leaks from the Oil and Gas Industry: A Regulatory
Roadmap and Toolkit.

Prescriptive
Regulations that direct regulated entities to undertake or not to undertake specificactions or procedures. This command-and-control approach focuses on setting
procedural, equipment or technological requirements such as the installation or
replacement of specific devices.
Leak detection and repair. Requirements to implement fugitive emissions
management plans that include the process of locating and repairing fugitive
leaks. Policies may address the type of equipment used, frequency of inspection,
the leak threshold that triggers repair requirements and the length of time allowed
to conduct the repairs.
Flaring or venting restrictions. Regulations that limit the amount of flaring or
venting allowed or that prescribe the equipment or process for flaring or venting.
This includes limitations on total volume, banning of such activities in routine
proceedings (allowed only for safety reasons or special conditions), the need torequest authorisations beforehand, or specifications of equipment or procedures.
Technology standards. Requirements that outline the equipment, technology orprocedure that must be employed in a regulated activity (e.g. requires the use ofno-bleed pneumatic devices; both high- and low-pressure gas-liquid separation
stages must be used to minimise vapour released from produced hydrocarbon
liquid; vented natural gas from liquids unloading must be collected). This includes
best available technology requirements, which refer to a benchmark technology
or procedure for reducing emissions that is considered reasonably practicable andevolves according to technological development.
Permitting requirements. Permits are a means of granting authorisation for
specific operations or procedures (e.g. pollution permits, drilling permits). Permits
also include conditions that limit their validity, which may be temporal,technological or spatial.

Performance
Regulations that establish a performance standard for regulated entities, but do
not dictate how the target must be achieved. An absolute or relative performancetarget can be applied at the national level, through economy- or sector-widetargets; at the company level; at the level of each facility; or even to individualtypes of equipment.

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Reduction targets. These refer to reduction goals, including the definition of
baselines, intermediate goals and means of assessing progress, reviewingGlobal Methane Tracker 2022

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objectives and achieving established targets. At national level or sectoral level(e.g. 50% methane reductions in the oil and gas industry in 2030 from the 2010
baseline), these generally serve as a strategic instrument and do not impose
specific requirements on companies.
Flaring or venting standards. Regulations that limit the amount of flaring or
venting for the purpose of disposal allowed through a performance metric (e.g.
minimum gas utilisation rates, admissible volume as a percentage of output) or
establish other performance requirements (e.g. flaring must be designed for 98%
efficiency). Regulations aimed primarily at fugitive emissions are not included inthis category.
Process or equipment emissions standards. Regulations that limit emissions
through a performance metric set at the process- or equipment-level (e.g. glycol
dehydration units must control emissions by 95%). They generally cover different
aspects related to atmospheric emissions, such as leak rates, discharge
characteristics (e.g. temperature) or means (e.g. minimum height of discharge).
Facility or company emissions standards. Regulations that limit emissions
through a performance metric set at the facility or company-level (e.g. eachcompany must reduce emissions by 20% on a per unit basis). They generally
cover different aspects related to atmospheric emissions, such as quantity (e.g.
volume) or characteristics (e.g. concentration). This includes company or facility
specific limits and associated reduction plans.

Economic
Regulations that use economic provisions to induce action by applying financial
penalties or incentives. This may include taxes, subsidies or market-based
instruments, such as tradeable emissions permits or credits, that allow firms tochoose among different strategies to address emissions (e.g. directly reduce
emissions or pay for offsets), effectively changing the cost curve of abatement.
Taxes or charges on emissions. Taxes, fees or other charges that are levied onemissions, including nationwide carbon taxes applied to methane or royalties andother charges imposed on fugitive emissions and methane emitted as result of
operation of equipment or certain processes (e.g. emissions from high- orintermittent-bleed pneumatic devices).
Taxes or charges on gas disposal (flaring or venting). This refers to taxes,
fees and charges that are levied when operators dispose of excess gas by flaring
or venting.

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Grants or other financial incentives. This includes all types of positive financial
incentives that governments provide to reduce emissions. This could include direct
provision of loans or grants to invest in reduction measures or other incentives

Global Methane Tracker 2022

Documentationsuch as allowing cost recovery for abatement costs via reductions in royalties,
taxes or fees.
Emissions trading schemes and certified reduction credits. Emissions trading
schemes typically define an emissions limit and allocate emissions allowancesamong the regulated community. These allowances can then be traded among
companies according to their needs and capabilities. Certified reduction credits
allow entities that go beyond established requirements to be accredited asvoluntary methane reductions, which may be traded. This item also includes any
requirement that allow companies to achieve emissions reduction requirements
by buying tradable credits.

Information
Regulations that are designed to improve the state of information about emissions,and may include requirements that regulated entities estimate, measure andreport their emissions to public bodies.
Measurement requirements. Mandatory data collection for activities, equipment
or production flows (e.g. volume of gas flared or vented, fugitive emissions leakrates from compressors), requiring operators to record, process and submit
requested information. They support the definition of activity or emission factorsthat are specific to measured devices, facilities and settings.
Reporting requirements. Regulated entities must record and report required
information. This can include reporting emissions monitoring data, key events (e.g.
accidents, flaring), state of facilities or operational data. Regulations can indicate
if information must be disclosed to the public or sent to regulatory authorities.
Emissions estimates and quantification. Requirements to estimate methane
emissions through the use of activity factors and emission factors.

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Public disclosure. Requirements for regulated entities to share specified
information related to methane emissions with the public (e.g. requirements topublish methane emission reports online, to undertake public information
campaigns, or to disclose information upon public request). This also includes
instruments that require public bodies to make specified information received from
regulated entities available to the public.

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