The oil and gas industry is being pushed by regulators, third parties and investors to better identify and mitigate its methane emissions, especially the few “super-emitter” sites that make outsize contributions to overall emissions. But while operators are ramping up capital spending on new technology, one thing has become clear: There is no silver bullet when it comes to reducing emissions, and each option includes one or more drawbacks, including source attribution, costs, quantification, and detection limits. In today’s RBN blog, we’ll break down the advantages and disadvantages of the different measurement technologies.
In Part 1 of this series we discussed how operators can begin to address key environmental goals while protecting — even improving — their bottom line. We also explained why the push to reduce methane emissions is so urgent. In Part 2, we detailed the mounting external pressures to control methane emissions and how the industry’s regulatory outlook, its non-governmental quasi-oversight and its access to capital are changing in ways that make understanding sometimes inconsistent emissions data vitally important.
Discussions about the technology needed to detect methane emissions tend to include a long list of options with every possible combination of instrument, approach and analysis, but we think that can be simplified into two key metrics: (1) the distance between the measurement device and the emission source, and (2) the frequency of measurement. The greater the distance between a measurement device and the source of emissions (vertical axis in Figure 1), the larger a leak must be to be detected by the monitoring technology. Conversely, the cost per site is generally much higher for hardware deployed on-site relative to aerial measurements further from the source. Airplane monitoring typically costs $10,000-$15,000 per day, for example, but an operator that has enough scale and concentration of assets can visit hundreds of sites per day in regions like the Permian Basin.
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