Colorado air regulators and oil industry engineers have been on the hunt for fugitive chemical emissions from drill sites and storage facilities for years, and they are now closing in on what may be “the last of the low-hanging fruit” – pneumatic controllers.
The Air Quality Control Commission is set to take up a proposed rule in February to require non-emitting or no-bleed controllers on all new oil and gas projects and at existing sites being upgraded.
“This is the largest remaining source of emissions for us to address … the last of the low-hanging fruit,” said Michael Paules, associate director of API Colorado, an industry trade group.
The ubiquitous devices manage temperatures, pressure and liquid levels at oil and gas facilities and drill pads. The controllers run on natural gas from the well itself and every time they open and close a valve or other mechanism, they release a little bit of gas.
The methane released contributes to Front Range ozone pollution and is a powerful greenhouse gas.
While it is only a smidge of gas – an average 2.8 standard cubic feet of methane an hour (scf/hr), according to one study – there are an estimated 56,000 controllers chugging away in the Front Range oil fields of the Denver-Julesburg or DJ Basin.
“They are the very largest contributor to ground level ozone and methane emissions after tanks,” said Matt Sura, attorney for Conservation Colorado and other environmental groups. “Eliminating them going forward is a huge step.”
The proposed rule has also drawn support from major Colorado oil and gas companies and industry trade groups.
Environmental groups, while applauding the proposal for non-emitting controllers on future or renovated projects, are pressing for the AQCC to also address the controllers already in the field.
Conservation Colorado, along with the League of Oil and Gas Impacted Coloradans and the Western Colorado Alliance for Community Action, has asked the commission to consider requiring non-emitting controllers for any equipment within 1,000 feet of a home.
The Sierra Club and the environmental action group Earthworks have called for the non-polluting devices at any site with four wells or more.
In 2014, the commission issued a rule requiring that new installations use low-bleed controllers, and where possible no-bleed devices.
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Chevron Corp. said in an email to The Sun that since the rule was adopted, its methane emissions from pneumatic controllers have dropped by 60% at its DJ Basin operations as equipment has been replaced. Chevron acquired Noble Energy, one of the largest drillers in Colorado, in July.
“Improving technology in pneumatic controllers is one of the lowest-cost solutions for reducing methane emissions,” Chevron said.
Still, a 2018 study of 3,800 controllers in the DJ Basin discovered that 5% were operating improperly and sending more gas into the air.
Another 2018 study of 31 Colorado oil and gas facilities by federal and state environmental regulators found 11% of the controllers, designed for intermittent releases, were continuously releasing gas.
The largest leak was 31 standard cubic feet per hour – big enough that within days it could supply the average 6,625 cubic feet of gas used monthly by an Xcel residential customer.
“They often malfunction and emit more than they should,” said David McCabe, a senior scientist with the Boston-based Clean Air Task Force, a public health and environmental advocacy group. “It is difficult to get a good handle on how many are malfunctioning.”
Instead of operating on compressed natural gas, the no-bleed controllers use compressed air or electronic mechanisms to open and close equipment. This requires a ready source of electricity and installation of heavy duty air compressors on site.
This can create both technical and financial challenges depending upon the site, Paules said. “Bringing electricity from miles away can be costly,” he said.
McCabe said that in Canada remote operations have effectively been using a system of electronic controllers paired with solar panels and batteries. Paules questions whether such a system used on smaller, remote operations would be effective at the big well pads in Colorado.
“In general, the cost effectiveness of retrofitting facilities depends on whether the value of production from the facility exceeds the cost of the retrofit,” Chevron wrote in its email. “Older stripper wells nearing the end of their economic life may only produce a few barrels of oil per day – meaning they could take years or may never recover the cost of the retrofit.”
Nevertheless, environmental groups are pressing for a broader rule. “Just looking at new sources and not at retrofits is not going to get the job done,” said Dan Grossman, senior director of state advocacy for the Environmental Defense Fund’s energy program.
Paules said the industry does not oppose increasing the scope of the rule and is working with EDF and other groups to develop a proposal to take to the commission that would increase the population of controllers under the rule and at the same time give industry flexibility in implementing it.