Monitoring Methane – Meeting the Methane Pledge

Rod Robinson reviews the techniques available for monitoring methane emissions

METHANE emissions are an important and current concern. The methane pledge made at COP26 in Glasgow, to reduce methane emissions by 30% by 2030 certainly made the news. The need to measure and control methane emissions from industrial processes is not new, but the challenges remain.

In this review I look at the reasons to measure methane, what this renewed focus on methane means for industry, and what the considerations are when selecting a measurement approach. I will also look at the role that standards and the national measurement institutes such as the National Physical Laboratory (NPL) have in supporting industry.

I’ve been working on the measurement of methane emissions since I joined NPL in 1990. That year we made measurements of methane emissions from cattle in a field, and measurements of methane emissions from landfills. Those are still current topics and illustrate the wide variation in potential methane sources. In the intervening years I have increasingly been involved in the development and validation of measurement methods for identifying and quantifying methane emissions from industrial processes.

Background

Methane is a strong greenhouse gas (GHG) with, depending on the measure used, up to 86 times the warming effect of CO2 over a 20-year timeframe. It has a relatively short lifetime in the atmosphere, ~12 years, compared to the CO2 lifetime of more than a hundred years. Without going deep into the science (the IPCC’s Assessment Reports are the definitive resource), methane’s strong greenhouse effect coupled with its shorter lifetime mean there’s a really good argument to cut methane emissions now, to get an immediate reduction in global warming. To quote an often-used analogy, it is akin to turning off the tap on an overflowing bath. The ambition to decarbonise the energy industry will clearly take time and there will be significant planned use of natural gas (a key methane source) in the meantime. During that period the short-term effect of methane on global warming will be significant, and reducing industrial methane emissions now will avoid a significant amount of global heating.

Methane is emitted into the atmosphere from many human activities including significant industrial emissions of from the oil and gas and gas supply industry. Methane is also generated from biological processes in agriculture and in the waste industry, and from natural sources such as wetlands. Unlike biologically-derived CO2, emissions of this methane still have significant impact on global warming. This means reducing leaks from renewable methane sources such as biogas is also important. Dealing with non-industrial sources of methane is difficult. There is therefore an immediate focus on dealing with industrial emissions, as these are often caused by leaks and unintended losses which can be fixed. Methane is also explosive above 5% by volume and of course methane as natural gas is a commodity and so these are additional drivers to stop emissions.

Detecting and fixing methane leaks is only one aspect, however, and methane emissions are challenging to quantify at site level. Figure 1 gives an idea of estimated volumes per year for different sources, although it should be noted that these numbers are fit for purpose only at the annualised nationally aggregated level.  CO2 is the GHG with the greatest impact due to human activities, but it is also relatively simple to calculate CO2 emissions from fuel use.  Determining methane emissions is more complicated, as emissions can arise from many different causes that are hard to estimate, including leaks, planned and unplanned process emissions and incomplete combustion. One significant issue with unplanned methane emissions is that, very often, a few rare events or leaks will account for the majority of the mass emissions for a site, and this makes predicting or calculating emissions very difficult. Many papers have been published on the impact of these short-term events, and those in the oil and gas industry, particularly those of you in the upstream sector,  will be aware of these so called "fat tail" emissions reported in a number of  papers from US and Canadian studies. The Climate and Clean Air Coalition’s (CCAC) global methane science studies are producing further information on emissions from different parts of the oil and gas supply chain. Detecting and quantifying emissions therefore requires knowledge of the potential sources on your site, and the specific characteristics that these emissions could have.

Reasons to measure and report methane emissions

Safety

One long-established reason to detect methane emissions is for safety monitoring. The requirement is to detect concentration levels at a point or area where, for example works are being carried out, or to detect a hazardous cloud of gas within an area. The requirement is for rapid response and sensors may be portable to screen an area or fixed in place to act as an alarm. Remote scanning may be required to provide coverage of an area or facility. Instrumentation can consist of handheld point sensors, fixed or portable point sensors, or optical sensors using path integral measurements or optical gas imagers to detect emissions over a wide area. These technologies are mature and have been in use for many years. They generally do not provide information on emission rates. There may be some possibility to repurpose site safety monitoring infrastructure to support measurements for emission reporting.

Leak detection and repair

Readers who work in the oil and gas sector will be aware of the common requirement to identify individual components that require repair. Leak detection and repair (LDAR) programmes are an established approach in the oil industry and are increasingly used across the wider gas industries. There are a number of standardised methods, one, is the European CEN standard EN 15446^1. An LDAR survey is based on screening components (“sniffing”) using portable instruments to detect elevated methane concentrations near leaking components. Other approaches do not directly detect methane, such as detecting pressure drops in closed systems such as pipework, or the acoustic detection of the leaks, an approach particularly applicable to subsea leak detection.

Sniffing-based surveys only address components that can be accessed, and therefore for do not cover all potential sources such as elevated cold vents in process areas. An emerging alternative approach for LDAR surveys is to use an optical gas imaging (OGI) camera to identify methane plumes and this can cover some non-accessible sources. I have recently proposed the development of a new CEN standard within CEN TC 264 as a companion to EN 15446, on the use of OGI within LDAR programmes. OGI can scan individual components and can also screen wider areas for larger emissions.

Component level – emission rate determination

There are methods to derive an emission rate based on the screening levels observed during an LDAR survey. These use correlation factors derived during measurement studies which have a relatively high level of uncertainty, for example the correlation factors in EPA Method 21 which are used in EN 15446, were developed over 20 years ago and do not necessarily reflect current operations. Generally, LDAR surveys are periodic and relatively infrequent, and while they are critical in finding and controlling emissions do not, in my opinion represent the best approach for reporting emission rates.

Direct measurements of the emission rate of identified leaks at component scale can be made using instruments such as the Bacharach hi-flow. In this technique the entire leak is “bagged” and the emission rate determined by measuring concentration and flow rate. This provides a direct measurement of each individual leak at the time they are identified and can also be used to derive emission factors. This approach only quantifies those leaks which were identified during the LDAR survey and so provides good information on the emission rates which have been identified and fixed, but not a comprehensive measurement of the total site emissions.

Methane mass emission reporting – calculation based

Current reporting of methane emissions mostly requires reporting of total mass emissions, typically annually, at facility, site or asset scale. This usually uses a combination of calculation approaches to sum up emissions for different source types – often referred to as a bottom-up determination. This can include calculations using activity data and emission factors based on varying levels of abstraction. Other calculations may use models, process information or engineering calculations to estimate emissions from activities such as venting during maintenance.

There are increasing requirements for more measurement-based reporting and the use of site-specific emission factors. Direct measurement of emissions can capture emissions that are not expected,  ie those not within the usual range of emissions covered by calculations, or are from sources that have not been considered. For example, the Oil and Gas Methane Partnership’s (OGMP 2.0) framework for reporting emissions requires, at its highest tier, reporting based on site specific emission factors and reconciliation of these reported emissions against site level direct measurements. CEN TC234 Gas Infrastructure is currently developing a framework approach for quantifying and reporting emissions from gas transmission, distribution storage and LNG terminals. Some industries or individual companies (such as BP’s Aim 4) are going further, and are committing to introducing continuous emission measurement to provide either monitoring to rapidly identify leaks or continuous quantification of emissions.

Site area (functional element) scale mass emission determination

While many requirements for reporting are at facility-/site- scale, there are strong drivers for understanding emissions with finer granularity.

Different activities on a site give rise to methane emissions with widely varying characteristics and it is very hard to define a single measurement approach able to measure all of these. Therefore, breaking your site down to smaller areas can help in specifying measurement requirements. This can also help to interpret emission measurements and relate these to more localised operations and site activities. It is also easier to identify the causes of any significant emissions that have been measured.

There are many highly innovative approaches which have been developed to measure and quantify methane emissions at this scale, each with their own strengths, limitations and performance characteristics. These techniques are currently available at various levels of technical and commercial maturity and are appropriate for different source types. Some techniques are focused on a particular need (eg flare measurement), others can fulfil several requirements. For example, NPL’s differential absorption lidar (DIAL²) can provide high resolution concentration mapping over a site, enabling individual methane plumes to be mapped and emission rate determination at site, functional element and smaller scales. 

At NPL we have been developing two concepts which help to provide some structure to the selection of appropriate techniques:

• A taxonomy approach to characterise measurement requirements and measurement technique capabilities. This helps distil the requirements for monitoring and match them to different available measurement methods and identify where there are gaps in current capability. For example this takes into account the range of sources on your site, and the expected characteristics of the emissions, eg their size or extent and behaviour over time. For example, this could include whether you have low level plant with fugitive leaks from valves and stems or high level flare stacks and also the area of the site to be monitored and other requirements which come from the purpose of the monitoring, ie data quality targets. Equally, technologies can be characterised by their abilities to identify, quantify or locate emissions, and by their performance characteristics. This will also give you a common frame of reference to simplify a complex market when discussing requirements with suppliers. A concept for breaking a site down into areas with similar methane emission profiles, which provides a means to simplify the identification of measurement requirements and solutions. We call these functional elements (FEs). The concept of the FEs is that they represent a practical level of dis-aggregation of sources which have common emission characteristics, meaning they have similar measurement challenges and could be addressed by similar solutions. Knowing the FEs on a site is a good first step towards understanding the potential monitoring requirements and therefore the potential solutions. For example, if your site has product loading, whether to road tanker or marine, that area will be expected to have emissions which are periodic and relate to loading operations. Similarly, emissions from compressor units will have similar characteristics – with vented casing emissions and blowdown stacks giving elevated sources with periodic emissions.
• Most techniques measure concentration or path-average concentration of methane in the atmosphere and then use a calculation or model to combine this with wind data to determine emission rates. Generally, the less spatial information in the concentration measurements, the more assumptions are made about the dispersion of the methane plume. How a technique determines emission rate from concentration data should be considered an integral part of the method. One approach which does not need to combine concentration with wind data is tracer gas correlation. Here a known rate of tracer gas (eg acetylene) is released in a location that is representative of the methane source. Measurements are made downwind of both the tracer and methane concentration. So long as the transport and dispersion of the tracer matches the methane then an emission rate can be derived.

Some techniques such as fenceline open-path optical monitoring systems require installation of equipment such as arrays of sensors and optical reflectors, others are mobile and require no installed equipment. The different levels of infrastructure, operational complexity and installation or deployment requirements of different techniques provides another means to differentiate between them, in addition to performance and cost.

In general, current methods provide periodic measurements of emissions and so provide a snapshot of the emissions at FE or site level. Methods are starting to be developed to provide continuous time series emissions data including distributed sensor arrays, optical scanning (including for flare sources) and multiplexed sampling systems. Currently there are few reliable low-cost sensor solutions so this is one area where, in my opinion, technology innovation is still needed.

Site and wider area scale mass emission determination

Some more remote or mobile approaches are able to locate or quantify site emissions without providing finer details of the sources. These can often be deployed without needing access to a site. Ground and airborne mobile platforms are also being used to provide measurements at site scale, such as EPA Other Test Method OTM 33A. Satellite measurements of site-scale methane emissions are currently restricted to the larger emission sources, but this is a growing area with a number of new and existing satellites offering or developing emission quantification capabilities. Satellite operators such as GHG Sat offer targeted measurements of methane emissions, which, weather and visibility permitting, provide a remote means to detect and quantify larger emission sources. Future planned missions such as EDF’s MethaneSat will offer more routine global scanning with the intention of identifying and locating sources of methane emission.

Regional measurements

At the larger scale, measurements of the atmospheric concentration of methane, for example using tall tower networks, can be used to validate regional or national emission inventories, as is done in the UK under the  Deriving Emissions linked to Climate Change network (DECC) which is used to provide independent assessment of the UK emissions of GHGs and assess trends. Improved modelling and the addition of tracer compound and isotopic measurements (able to discriminate between fossil and biogenic sources of methane) will provide more localised and industry specific validation of inventory data.

Current issues and future needs

The use of a particular technology is not sufficient to ensure the quality in reporting data. Standardised procedures are needed to ensure emission rate data are produced which are fit for purpose and comparable. Plant operators can then specify measurements to be made in accordance with this method and measurement providers can be accredited to show they are able to undertake them.

Independent validation data on the performance the methods is vital in understanding their potential roles. This is the case for the measurement methods developed by CEN TC264, "Air Quality", which is responsible for EN 15446 and prEN 17628 described below.

To date, few standardised methods exist for methane; the US EPA has developed the OTM 33 series and the EN 15446 defines LDAR. The draft CEN method prEN 17628 provides standardised, and validated, methods including Differential Absorption Lidar (DIAL), Solar Occultation Flux (SOF), reverse dispersion modelling (RDM), tracer gas correlation (TC) and OGI together with the means to select between them. This standard was developed to measure volatile organic compounds but most of the methods are applicable to methane. It provides a performance-based toolkit of methods and is a good model for future development of methane measurement methods. There is currently a proposal in TC264 to develop methane-specific standard for fugitive and diffuse emissions. The DIAL technique in particular, as it is able to provide comprehensive data on methane plume location, cross sections and emission rate determination provides a detailed snapshot of emissions which can be used to validate other approaches.

As the requirements for methane monitoring become established there are a number of areas where the national measurement infrastructure and measurement institutes such as NPL can provide support. Some areas already mentioned include defining measurement requirements and capabilities, and supporting the development of standardised methods. These will support industry in selecting methods and improve the reliability and comparability of reported data. In addition, the capability to validate methods using both comparison to standardised reference techniques such as DIAL and controlled traceable emission sources will enable independent performance verification. Taking the more mature area of regulatory point source emission monitoring as an example, a number of quality control elements could also be implemented for methane monitoring, including certification of measurement systems, accreditation of measurement service providers and the development of accredited proficiency testing schemes. 

There are many new advances in methane measurement currently in development, including for example quantification of emissions using optical gas imaging (Q-OGI), the previously-mentioned quantification of site emissions from satellite platforms, novel sensor deployment platforms such as unmanned aerial vehicles (UAVs or drones) and continuous time-resolved monitoring using distributed sensor systems (such as NPL’s FEDS system). These new technologies offer the novel new measurement capabilities. There is however a need for independent validation and the development of standardised methods to fully enable these promising technologies to meet their full potential.

Conclusions

In this brief review I’ve tried to give an overview of the reasons for monitoring methane, the range and complexity of the sources of methane that need to be monitored and a brief summary of the range of methane measurement technologies. It is hopefully clear that there is no one size fits all method, that when selecting measurement approaches it is important to clearly define the needs. I’ve tried to show how a means to describe and characterise the requirements for measurements, the types of potential sources and the capabilities of measurement methods, provides a useful approach to select monitoring solutions. The methane measurement problem remains complex and tools to monitor and report emissions exist or are being developed. The next step will be to develop a framework of standardised and validated methods, with defined performance targets, to provide consistent and comparable measurements.

References

1. EN 15446:2008 Fugitive and diffuse emissions of common concern to industry sectors. Measurement of fugitive emission of vapours generating from equipment and piping leaks. CEN TC 264

2. Robinson, R, et al, Infrared differential absorption Lidar (DIAL) measurements of hydrocarbon emissions, 2011, Journal of Environmental Monitoring, Vol 13, pp2213-2220