Recent field studies have shown that measurements taken with aerial light detection and ranging (LiDAR) are more effective in discovering various sources of methane emissions than onsite optical gas imaging (OGI) and that policy and regulations that rely on OGI surveys alone risk missing a significant portion of total emissions.
While emissions reduction depends on the frequency, distribution, and magnitudes of source types, recent field studies have shown that a small proportion of sources or sites is responsible for most methane emissions and that measured emissions significantly exceed estimates, often by 50% or more. A recent paper published by Environmental Science & Technology presents how researchers are using the disparity in these estimates to sharpen inventory estimates at upstream oil and gas sites.
Traditionally, the differences between estimated and actual emissions have been attributed to what are called “fugitive” emissions from leaking components detected by optical gas imaging (OGI) cameras.
Some disagreement exists, however, as to what constitutes fugitive vs. vented sources and, if the source is vented, what is considered normal vs. abnormal venting.
Secondly, traditional OGI approaches may not be as effective as once thought. OGI surveys of facilities in Alberta, Canada, have found that fugitive leaks composed just 15% of the total methane emissions.
So, what exactly is leaking and how much?
The BC Oil and Gas Methane Emissions Research Collaborative (MERC) directed an aerial survey of 167 diverse oil and gas production and processing infrastructure sites in northern British Columbia using Bridger Photonics’ Gas Mapping LiDAR (GML) technology. Results of the survey showed that the sites accounted for 96% of upstream oil and gas sector methane emissions in the updated inventory.
The LiDAR high-resolution aerial photographs were combined with facility schematics provided by the BC Oil and Gas Commission and compared with inventories taken when OGI was used to detect and manually count onsite process equipment and pneumatic devices responsible for the emissions.
Together, the methods determined the distributions and breakdown of methane sources and the equipment most responsible for onsite emissions. The sources seen in aerial LiDAR measurements vs. ground survey data were interpreted in the context of sensitivity limits and compared by types, distributions, and magnitudes.
The studies revealed a gaping difference in source distributions. The aerial survey found far fewer but much larger sources (39 vs. 357 sources) and 18 times greater total emissions than the prior OGI survey, which suggests that emissions were 1.6–2.2 times greater than estimates.
Overall, LiDAR-measured emissions were greater than those from venting alone (as reported) and even higher than the sum of emissions from reported venting and OGI-detected sources. This implies that OGI methods are not capturing all sources of upstream oil and gas sector methane emissions.
After investigating discrepancies among different measurement approaches, the researchers used the data to create a revised, more-accurate inventory estimate of upstream oil and gas methane emissions.
Because aerial LiDAR measurements and OGI survey data detect different sources of methane at the same sites, this study has important implications for inventories based on OGI survey data alone and further implications for the effectiveness of methane regulations based on current inventories as measured by OGI.
The study concludes that, to detect the true distribution and magnitudes of total methane emissions, direct measurements and estimates from both bottom-up and top-down survey methods must be used.
Download the complete paper here.
For Further Reading
ExxonMobil Field Tests New Methane Leak Detection Systems
Is Optical Gas Imaging the New Solution for Methane Detection?
