There’s a lot of talk about tackling climate change these days. If you listen to the media, you’d think that the solution is to electrify everything, but that’s meaningless if you do not have access to a clean, efficient, sustainable, low-cost way of generating electricity. However, not everywhere has adequate wind or sun resources, and with over 315 wind project rejections since 2015, and neither of those two being “available on demand”, natural gas is the only viable option for the foreseeable future. The goal, then, is to produce natural gas as cleanly as possible.
One long-proposed solution for reducing CO2 emissions in the United States is setting a price on carbon. But efforts to create a national carbon cap-and-trade or tax regime have proved fruitless, although there is a vocal and powerful activist movement intended to force coal plants to close, and many have. Of course, the actors most responsible for discharging CO2 are easily identified and widely known: planes, trains, and automobiles; power plants; heavy industry; commercial and light industrial operations; and agriculture, in that order, using US EPA 2020 figures. There’s truth here; recent estimates from the US EPA are that CO2 accounts for up to 80% of all greenhouse gas emissions. But, there’s a vastly more potent greenhouse gas contributing to climate change that gets much less notice or discussion: methane.
Methane, in fact, has a Global Warming Potential (GWP) of up to ~25x that of CO2 over 100 years according to the EPA, and 86x over 20 years. And while there’s some disagreement over which sector is the larger methane contributor—many databases claim agriculture is the worst, followed by emissions from the oil and gas sectors—there’s no avoiding that methane is an issue. Ironically, though, while the White House is ostensibly “laser-focused” on curbing rampant inflation, and President Biden recently signed into law the Inflation Reduction Act (IRA), many large provisions and considerable funding within the bill are directed solely toward fighting climate change. One such provision is the first-ever federal fee on “excess” methane emissions. This fee will take place on or after January 1, 2024, based on certain baseline calculations and allowable exemptions. Within the oil and gas sector, using 2019 figures, EPA lists the largest methane emitters as gas production at 41%; oil production at 19%; transmission and storage at 19%; distribution at 7%; processing at 6%; post-meter emissions at 5%; and abandoned wells, 3%.
As for the fees themselves, the IRA methane emissions charge starts at $900 per metric ton of methane, increasing to $1,200 in 2025, and to $1,500 in 2026 and beyond. Notably, the IRA also “fixes” difficulties arising from the Supreme Court’s June 30 ruling that nullified the Obama-era Clean Power Plan, and codifies greenhouse gasses as “pollutants.”
These excess emission fees will apply only to methane emissions from specific types of oil and gas facilities required to report their emissions under EPA’s Greenhouse Gas Emissions Reporting Program (GHGRP). And fees would apply specifically to petroleum and natural gas system facilities required to report GHG emissions under 40 CFR Part 98, Subpart W, or facilities emitting 25,000 metric tons of CO2 equivalent or more each year. Among others, facility types will include off- and onshore petroleum and natural gas production and compression for transmission; LNG storage as well as import and export equipment; underground natural gas storage; and onshore natural gas transmission and petroleum gathering and boosting. Interestingly, the emission thresholds depend on the type of facility, and some details have yet to be worked out, but EPA plans to issue a supplemental Notice of Proposed Rulemaking (NOPR) shortly and a final rule in May 2023.
Meanwhile, the EPA will have to finalize the methane emission rule proposed last year to provide a safe harbor for exemption from the requirements that the rule would have imposed, in favor of the new rules. The EPA will also examine greenhouse gas reporting rules specifically for petroleum and natural gas systems. This is to ensure they are based on verifiable “empirical data.” The Act even includes $850 million in funding for grants, rebates, and loans to support facilities in preparing and submitting monitoring reports and provide assistance with acquiring technologies that reduce methane emissions from petroleum and natural gas systems.
Of course, what constitutes “empirical data” here is key in both understanding and complying with the new rules, and in determining the extent of methane emissions to which the rules will start applying to in 2024. Although methane rules proposed last year will [almost certainly] be superseded by the final rules in the Inflation Reduction Act, new technologies based on the principles of continuous monitoring, accurate detection and quantification, root cause analysis, and augmented-reality imaging, already are making a world of difference.
And there is no paucity of targets. Last year, the EPA estimated that a massive number of facilities would fall under the then-proposed rules: about 280,000 oil and gas wells, including central processing facilities and tank batteries; more than 3,500 gathering and boosting stations; 2,000 natural gas processing plants; and 1,900 transmission and storage compressor stations. Parallel rules from Pipeline and Hazardous Materials Safety Administration (PHMSA) would cover thousands of transmission and distribution pipelines, and associated pipeline facilities, as well as some gathering pipelines. Expectations for VRU (Vapor Recovery Units) capable of reliably handling peak production capacity are promising, given that initial production rates at new wells are typically far higher than in subsequent months.
Optical Gas Inspection (OGI) requirements and intervals for upstream sites are currently based on expected production volumes but as anticipated previously, EPA rules will likely focus on the number of pieces of equipment installed on a site, regardless of production volumes. That is because surveys show that site emissions are primarily correlated to the number and type of equipment that can potentially fail and emit, not to the production volume. So, the most accurate approach is to calculate the “potential to emit” for every site, based on equipment counts and emissions factors. In practice, almost all sites that consist of more than a wellhead will fall under one of the several OGI inspection requirements. The EPA estimated this to be about 300,000 upstream sites—with the remainder being marginal production sites with single wellheads. To meet the number of inspections anticipated, the oil and gas industry will likely have to hire and train thousands of additional OGI inspectors to meet the requirements of the final rules, as well as identify and adopt best-in-class methane detection technologies to meet the new regulatory requirements, including aerial surveys, continuous point sensors, and continuous OGI cameras. A focus on finding and fixing big leaks faster is what counts most to reduce emissions.
Many publicly-traded companies, including those in the oil and gas industries, have adopted aggressive slates of related ESG (Environmental, Social, and Governance) philosophies, goals, and KPIs. By complying with ESG standards, they are positioning themselves as methane reduction leaders. And in a little more than one year, they’ll have a robust new set of rules to follow, and potentially significant fees to pay for methane emissions. But new cost-scalable, IoT-based, SCADA-compatible continuous-OGI technologies are available today that will minimize emissions and costs of deployment while making reporting and compliance as painless as possible.
The significance of continuous-OGI is that the EDF and EPA suggest 70% of all emissions are intermittent, and the only way to determine the operational root cause and achieve subsequent mitigation is with continuous monitoring. Cost-scalable, continuous and optical is a fantastic combination. As we like to say, you have to see it to solve it.
A native of Texas, Robert has been part of the oil & gas industry for ~30 years, focusing on problem solving and various technology initiatives in the realm of measurement operations, production optimization, enterprise SCADA, telemetry, and connectivity. He spent over a decade where he pioneered the introduction and adoption of Control Microsystems’ SCADAPack as well as solutions from Accutech Wireless, Trio DataCom and ClearSCADA. Since 2016, Robert has been active in accelerating adoption of several newer technologies ranging from cellular based autonomous instruments to WiFi in hazardous areas to connected operator initiatives, Edge computing platforms, and expansive connectivity networks with integrated components that leverage LoRaWAN and LTE. Having consulted to Kuva Systems since Dec 2020 and getting a feel for the potential of the offer, Robert joined Kuva full time in Oct 2022 as Vice President of Business Development where he is now focused on helping Oil & Gas Operators attain their ESG goals with a low-cost methane imaging camera that provides visual evidence of the leak origin so it can quickly be repaired as well as emissions quantifications.
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