Methane Tracker 2020

Reducing the environmental impact of oil and gas supply is a pivotal element of global energy transitions

Improving methane data

Emissions levels and abatement potentials are based on sparse and sometimes conflicting data, and there is a wide divergence in estimated emissions at the global, regional and country levels.

The estimates shown represent our best understanding of emissions from oil and gas operations based on currently available data. They are designed to help governments and other stakeholders understand the magnitude of the issue, but given the uncertainty that exists, they are clearly not the last word. We aim to update these estimates as new and improved data become available. (See the World Energy Model documentation [PDF] for further information on how these estimates are produced). You are welcome to let us know of relevant reports or studies by mail at weo@iea.org.

The analysis below outlines the state of play in emissions data, and the measurement strategies that will be key to driving down oil and gas sector methane emissions. It highlights how measurement campaigns feed through into the IEA estimates, as was the case in the 2020 update for Norway and the Netherlands.

Any jurisdiction or company’s ability to tackle its methane emissions is to a certain extent limited by the data available. At present, the most readily available emissions information available in most countries are periodic emissions inventories submitted to the United Nations Framework Convention for Climate Change (UNFCCC). Reporting content and frequency requirements depend on the country’s party status to the Convention and the Kyoto Protocol. Forty-three countries designated as Annex 1 countries—comprised mostly of advanced economies that are subject to caps on their emissions—submit annual GHG inventories. Emissions data from Non-Annex 1 countries, which do not submit regular inventories, are available through national periodic reports.

In all cases, inventory estimates are generated through a ‘bottom-up’ approach. The sophistication of the calculation depends on how accurately each country’s inventory system can estimate emissions. At the simplest level, Tier 1 methodology relies on default emission factors provided by the IPCC. Tier 2 uses relatively aggregate and readily available information on emitting activities and emission factors based on national measurements. The highest tier, Tier 3, is based on complex emissions modelling. For the oil and gas sector, this detailed approach is based on equipment-specific emission sources from facility-level assessments. The upper two tiers also take into account emissions uncertainty. While the IPCC issues guidance documents—which suggest, for example, sources that are best estimated with country-specific emission factors versus direct measurements—countries are largely left to determine independently how to arrive at their estimates.

While valuable in their own right, UNFCCC inventories do not provide sufficiently detailed and accurate information needed by policymakers who are looking to tackle emissions. Moreover, scientific studies suggest that national inventories often significantly underestimate emissions. One major reason for this is calculations in many countries rely on default emissions intensities from antiquated data sets. The freedom for countries to select which intensities to use also impacts the accuracy of estimates.

Recognising the importance of more reliable, detailed information, many jurisdictions have developed regulatory frameworks that go beyond minimum inventory requirements. The features of these schemes vary, but they typically feature mandatory data gathering and reporting elements that require operators to submit regular batches of information. Types of information gathered include inventories of emitting components and calculations of facility-wide emissions. A smaller number of jurisdictions have more extensive reporting requirements—for example, results of leak detection and repair programs, and frequency and volume of emitting operational activities (e.g. instances of emergency venting).

Reporting requirements may not have universal application and may be limited to facilities over a threshold size, based on volumes of product flowing through the facility, or overall annual emissions. The information reported by operators may be available only to the regulator or publicly published, either in its original format or aggregated across the industry.

Many rules allow operators to choose among a set of methodologies for making emissions measurements or estimations. Often, operators calculate emissions using standard emission factors that are recognised by industry. In this method, companies assume a certain amount of leakage from each component, typically based on tests of equipment models in controlled settings. Emission factors are scaled up by multiplying by the number of components to arrive at an estimate for facility emissions.

There can be some interplay between company estimates and national inventories. In the U.S. and U.K., for example, information provided in industry estimates can be used to revise inventories by informing improvements to activity data or assumed emission factors. While this process of inventory revision is generally constructive, it does not always lead to an improved level of emissions accuracy, as company estimates too display a number of concerns.

Many operators’ standard emission factors are outdated, or do not reflect leakage that occurs during abnormal operating conditions. While some companies augment calculations with direct measurements of emitting devices, the scope and frequency of this practice varies widely. Furthermore, calculations in some regions are based on application of factors that were developed by the American Petroleum Institute and may not be suitable when applied elsewhere.

Estimates across several jurisdictions have also been shown to contain gaps in coverage of emissions sources, be it through regulatory exemptions of certain types of fugitive and vented emissions, or omission of other difficult sources, such as abandoned oil and gas wells and “super-emitters”. The latter refer to a small number of sources that contribute the majority of emissions. While super-emitters have been studied in the U.S., they are likely to exist globally. Their exclusion risks severe underestimation.

There are several emerging technologies and approaches to measurement that appear promising to elevate data available on oil and gas methane emissions—among them are satellites and other aerial detection instruments utilised during measurement campaigns.

An increasing number of government and commercial actors have recently launched satellites that allow for aerial detection and measurement of oil and gas methane. Early analytical results suggest satellites are a promising method to conduct global scans, in order to pick up and estimate emissions from large point sources—i.e. super-emitters. For example, two methane-capable instruments—GHGSat-D, aboard Canadian commercial satellite GHGSat, and Tropospheric Monitoring Instrument (TROPOMI), aboard a European Space Agency satellite—were used to detect and estimate emission from a voluminous leak from a gas compressor station in Central Asia. TROPOMI also detected and quantified emissions from a 2018 gas well blowout in the mid-western United States.

Yet, more progress is needed before satellites can generate a comprehensive and reliable picture of methane emissions of from oil and gas activities worldwide. Numerous challenges persist, such as time delays in converting atmospheric measurements to useful intelligence about surface-level activities, and proper attribution of detected emissions to the oil and gas sector. Researchers are hopeful that some of these issues will be resolved in forthcoming instruments and accompanying methodologies, such as Environmental Defense Fund’s MethaneSat scheduled for launch in 2022.

Even in a future scenario where aerial detection instruments are able to provide high-resolution data in formats that are regularly updated and publicly accessible, bottom-up estimates for oil and gas methane will not be rendered obsolete. For one, the resolution of the current generation of satellites cannot detect consistent, low-level sources of methane emissions. Even if resolution continues to improve, satellites will not be able to pinpoint specific equipment sources within a site that contains multiple pieces of equipment. For this, it will continue to be necessary to estimate emissions based on source-specific quantification methods.

Confirming and reconciling bottom-up estimates with direct emissions measurements, via aerial instruments or otherwise, is the best option to hone accurate emissions information and overcome shortcomings associated with any single approach. In this regard, using stationary monitors, ground vehicles, or aerial instruments such as satellites, drones, and planes, can reduce the risk that bottom-up estimates significantly underestimate emissions from a site. In order to have the greatest impact on improving estimation techniques, site-level studies should be sufficiently representative geographically and temporally, publicly reported, and independently verified.

The IEA has stayed abreast of instances of these emerging measurement strategies and worked to integrate results from credible sources into the Methane Tracker where data has become available. The 2020 Tracker update reflects major downward revisions to emissions levels in a handful of jurisdictions—notably Norway and the Netherlands. This was the result of a series of measurement campaigns of methane emissions from oil and gas production in the North Sea—these efforts yielded improvements to the process of inventorying emissions and confirmed estimates generated and reported by Norwegian and Dutch industry operators.

An increasing number of countries are moving towards regulatory solutions to drive reductions in methane emissions from the oil and gas sector. Although existing data and estimates can serve as a basis for action to reduce methane emissions, improved data will lead to a more efficient allocation of resources and better confidence in specific emissions reduction efforts.

For jurisdictions examining this issue in earnest for the first time, getting a sound grasp on baseline emissions is essential. This goes beyond a simple emissions profile—early in the process of regulation development, policymakers will likely want to know a breakout of emissions sources, including what are the largest sources that should be prioritised, what portion of emissions can feasibly be abated, and at what cost. Once a regulatory system is in place, provisions for regular measuring and reporting are necessary for regulators to determine whether operators are compliant with emissions requirements. These measurements can then also serve as a yardstick to track progress on industry or countrywide reduction targets over time.

Such data points are also interesting for industry. A better understanding of where and how much valuable product is leaking can improve operations efficiency and potentially increase corporate profits. For companies committed to reducing their emissions, awareness of the size and sources of emissions can better allocate internal resources to address problem areas. Trustworthy estimates based on sound measurement techniques can help operators demonstrate progress towards methane reduction commitments.

Public reporting of data can serve a number of purposes. Transparent measurement methodologies and reporting can boost public trust in industry, which faces ever-increasing demands by society and investors for proof of sustainable operations. Allowing third-party auditing groups to conduct independent verification of emissions increases confidence in reported figures. Moreover, if made available to other interested parties, better estimates will also contribute to the collective body of scientific knowledge of methane emissions, helping to drive solutions to emissions monitoring and mitigation challenges.

The Norwegian Environmental Agency (NEA) works with Statistics Norway on its emission inventories, employing a combination of Tier 2 and Tier 3 methodologies. In 2016, the NEA completed a two-year study with a consultancy group to assess its emissions status, working closely with industry and other relevant government agencies. The study resulted in revisions to and a more detailed breakdown of emissions by source, as well as recommendations for improvements to the existing quantification methodology for its emissions inventory. Previously, the inventory was established with a set of predefined emissions sources and factors more than two decades old.

The extensive quantification project of Norwegian oil and gas activities comprised several ‘modules.’ In the first module, all permanent offshore oil and gas facilities on the Norwegian Continental Shelf were surveyed to identify potential methane emission sources. This step revealed several emissions sources not covered in the prior estimation method. Another important outcome of the study was further subdivision of sources—estimates from the old method were based on 13 potential emission sources; following the study, there were 48 sources and sub-sources, confirming that the previous method was insufficient.1

In the second module, the study reviewed and revised the quantification methodology for future reporting. In the revised estimation method, all methane sources are reported and assigned a general or facility-specific quantification method. Facility-specific methods must be established by operating companies. Generic quantification methodologies remain the proposed method for a significant amount of emission sources, to ensure consistency and allow simplification in calculations among operators.

Further examination was carried out for small gas leaks, which have high emissions uncertainty. Due to their small size, small leaks are likely to go undetected during regular inspection with stationary monitors or portable gas detectors. Ultimately, the study proposed that a small mark-up be added to emissions estimates to account for sources too small to have significant impact on total emissions.

Finally, the study also assessed emission abatement opportunities and best available techniques for reducing methane emissions from offshore activities. It estimated reduction potential at 10 percent from existing installations.

The Norwegian regulator utilised the study results and recommendations in setting its guidelines for quantifying and reporting. The reporting is mandatory and regulated by the Norwegian Pollution Control Act. Where facilities have flow meters on vent heads, these actual measurements are used instead of calculating emissions from individual contributing sources. Today, around two-thirds of emissions are accounted for by these measurements. Non-metered volumes represent the other one-third—the quantification models and methods for non-metered sources are published in a handbook for all operators to use in computing direct methane and other volatile organic compound emissions. 

Estimates based on the revised, thorough bottom-up calculation method were found to be lower than previous estimates. These lower emission levels were confirmed by top-down measurements gathered during fly-over campaigns over the Norwegian Shelf.

Although Norway was able to improve their emissions estimate quickly and effectively, it is possible that this approach may not be appropriate for other jurisdictions because there are some specific characteristics of the Norwegian context that made this approach feasible to implement. 

In Norway’s case, production is dominated by offshore oil and gas extraction, so too its methane emissions—around 95 percent of emissions stem from upstream offshore sources. Roughly thirty exploration and production operators are active on the Shelf. Norway’s largest petroleum company Equinor, in which the state owns two-thirds share, constitutes the majority of Norwegian production.

The relatively limited number of industry players and close links between state and industry facilitated Norwegian regulators in homing in on the targeted emitting sector. Consistency in the types of resources produced and equipment found on installations likely lends itself to simplified, more reliable calculation methods. Moreover, the consolidated nature of Norway’s industry can make even-handed application of reporting and emissions quantification more likely.

Countries with industry or industry segments akin to Norway, including the United Kingdom, United States, Canada and Australia, may be able to more easily adopt parts of this approach. Regulators that already provide technical guidance for estimating emissions may look to the process undertaken by the NEA to revise their methodologies. Some may even be able to draw upon emissions quantification methods put forth by the Norwegian authority for operators.

Importantly, Norway’s approach to emissions estimation is also well suited to its regulatory tactics for controlling methane emissions. One of the main drivers of emissions reductions in Norway is its mandatory greenhouse gas tax that applies to flared gas (taxed as carbon dioxide emissions) and vented and fugitive methane emissions on offshore oil and gas installations (taxed as natural gas emissions).[1] Operators on the Norwegian Continental Shelf must report all methane emissions from their activities and metered flare gas. They calculate, report, and pay the tax to the Norwegian Petroleum Directorate. The tax rates are roughly consistent with the relative greater impact of methane compared to carbon dioxide as a greenhouse gas. The 2019 tax rates were 1.08 Norwegian Krone per standard cubic metre (NOK/m3) of combusted gas (roughly 462 NOK per tonne of CO2, or 50 USD), and 7.41 NOK/m3 of natural gas (about 12250 NOK per tonne of CH4, or 1300 USD).

The ability to apply an elevated methane tax obliges confidence and accuracy in emissions numbers. Norway’s realisation of this approach stands in contrast to other jurisdictions such as Canada, for example, where regulators considered the adoption of a carbon tax, but were unable to pursue it owing to a lack of an adequate way to track emissions. The Canadian government opted for a different approach to regulating methane in its rules rolled out this year, including several command-and-control style features that give way to overall emission limits at some facilities in future years.

Regardless of a country’s resemblance in industry or regulatory profile, however, there are also a handful of universal takeaways. For example, during the process of surveying industry on its emissions sources, Norwegian regulators had iterative exchanges with operators, helping to clarify inconsistencies in data gathering. This step was important to more accurately scope emissions sources and establish a reliable quantification methodology for future reporting. As illustrated in this case, no country will be able to entirely depart from generic estimation methods for some emissions sources. Nonetheless, prioritising the generation of specific emission factors and estimation methods true to country operations can greatly improve accuracy of estimates. Equally critical is the step of engaging research institutions or other actors capable of conducting studies to independently verify emissions through actual measurement campaigns.

Ultimately, each country will need to consider its incumbent methane regime and where it wants to go. Similar efforts to Norway’s to improve emissions estimates will serve some regulatory approaches better than others. Mexico’s 2018 methane law, for example, requires operators to meet facility-wide emission limits and relies on them to provide baseline and annual facility emissions estimates. This and analogous performance-based regulations would benefit from rigorous, vetted estimation methodologies.2

For the time being, the regulatory approaches to methane seen in jurisdictions across the globe are relatively restricted—of the limited number of countries that have established rules to directly control methane, most have opted for a prescriptive or command-and-control approach. This choice is largely driven by the relative ease and confidence associated with, for example, confirming that an emitting piece of equipment has been swapped out with a lesser emitting one, rather than confirming emissions that are highly unknown and require measurement technologies that may be expensive to implement.

However, given the urgent need to reduce emissions in line with what experts say is needed to avoid dangerous warming levels, a lack of perfect information cannot impede forward progress on abatement measures.

With this in mind, some policymakers are considering unique approaches whereby they are tackling both—getting better information while bringing down emissions—at the same time. In what can be categorised as an information-based approach, regulators can design rules that require operators to collect information from emitting sources. These frameworks can be particularly useful in getting a better understanding of the magnitude and nature of emissions from specific activities that have been historically understudied.

While it may not be immediately apparent how this drives emissions reduction, there are a few possible pathways. Heightened awareness of emissions may be sufficient for intrinsically motivated companies to act on emitting sources. Moreover, if emissions information is made public, companies may feel increased pressure from investors or the public to abate. For others, the time or cost burden of emissions detection and quantification may not be worth a simpler option of non-emitting equipment.

California’s Greenhouse Gas (GHG) Emissions Standards rule is a good example of this approach. Beginning in 2018, operators were required to collect vented natural gas from liquids unloading, or directly measure or calculate the amount of gas vented and report it to the regulator. Operators are also required to take direct measurements annually from well casing vents.

This provides some degree of flexibility in allowing the operator select how they will adapt operations to be compliant. From the regulator’s perspective, whatever outcome the operator chooses in regards to liquids unloading is a success—either reducing emissions vented to the atmosphere, or acquiring better information, which can feed into analysis of this emissions source and allow future mitigation solutions to be considered.

In addition to an information-based regulatory approach, there are other pathways policymakers are considering to achieve better emissions data. Some countries are boosting research and development funding with aims to reduce the cost of direct measurement through satellites and other technology development. As another example, the European Union is looking towards the development of a robust methodology to measure emissions from production of the gas flowing into and through its pipeline network. Better data is opening up new options to minimise oil and gas methane emissions.

References
  1. From the original survey findings, the number of sources and sub-sources were re-organised. In the latest reporting format, there are 32 emissions sources defined as potentially present on a facility.

  2. The carbon tax is not the only mechanism in place in Norway to control methane. Gas flaring other than for safety reasons requires a permit under the Petroleum Act. Norway limits gas flaring and venting in some permits issued by the Norwegian Petroleum Directorate on a case-by-case basis. Other factors, such as state ownership of resources in the Norwegian Continental Shelf and a culture of stewardship, safety and compliance also contribute to methane emissions control.