[Editor's note: A version of this story appears in the August 2020 edition of Oil and Gas Investor. Subscribe to the magazine here.]
When the dust settles from one of the most devastating downturns the oil and gas industry has seen in recent years, the push toward reducing emissions will still be there.
Fortunately, industry players are maintaining their commitment to reduce emissions along the entire supply chain as industry groups bring companies together to achieve common goals, and while regulators aim to bring order and checks to the process.
Upstream oil and gas companies participating in The Environmental Partnership recently welcomed the midstream sector, more than tripling its membership to 83 participants. Working with API, the partnership comprises companies of all sizes across the U.S. each aiming to lower emissions of methane and volatile organic compounds (VOCs). Their efforts, some of which are required by existing regulations, have included stepping up monitoring, implementing leak detection and repair programs, and replacing high-bleed pneumatic controllers.
“Using EPA [Environmental Protection Agency] estimates, we know that finding and fixing leaks can achieve a 60% emission reduction, and replacing high-bleed controllers is at least a similar cut in emissions—60%—and likely significantly greater based on recent emissions studies at investigating controller emissions,” Matthew Todd, director of The Environmental Partnership, said on a media call July 15. “Many of the actions taken by the companies, removing gas-driven controllers from operations, are eliminating emissions entirely.”
Data show efforts demonstrated by participating companies are working, he added. Companies taking part in the partnership’s Leak Detection and Repair Program in 2019 carried out more than 184,000 leak surveys at more than 87,000 production sites. The work included an estimated 116 million inspections of components such as valves, flanges and connectors—typically places where leaks can occur.
“Of these components, operators identified a leak occurrence rate of just 0.08%,” Todd said, explaining that is less than one leak for every 1,000 components. That was an improvement from about two leaks for every 1,000 components in 2018.
Other results, which were shared in an annual report, included replacing, retrofitting or removing from service more than 3,300 highbleed pneumatic controllers, removing from service more than 10,500 additional gas-driven controllers and installing more than 2,800 zero-emitting controllers.
“Similar to our current environmental performance programs and informed by EPA reporting data, midstream companies will take additional steps to further reduce emissions associated with pipeline blowdowns and compressor operations,” said Vanessa Ryan, manager of the carbon reduction team at Chevron Corp. and chair of The Environmental Partnership.
The work is underway as the industry continues to endure unfavorable market conditions, massive spending cuts and widespread layoffs. The COVID-19 pandemic, which has slowed demand, also adds uncertainty.
“Of course, unforeseen public health and economic challenges have presented new hurdles to America’s natural gas and oil industry. But nothing has moved energy operators away from their continued commitment to leading the world in energy development and environmental performance,” said Mike Sommers, president and CEO of API. “In fact, the pandemic has brought a new level of urgency to operationalize our mission to learn, collaborate and take action to responsibly develop our nation’s essential energy resources.” Their efforts also target flaring, and they are not the only ones on a mission.
Texas Tackles Flaring
A matrix identifying when flaring is necessary with a shortened time line for administrative action, best practices and new reports to provide greater accountability are among the suggestions from a coalition of oil and gas industry groups to help reduce flaring in Texas.
The report by the Texas Methane & Flaring Coalition was discussed in June during the Railroad Commission of Texas (RRC) meeting. It came as commissioners reached out to oil and gas industry players, environmental groups and other stakeholders as they sought ways to lessen the amount of natural gas flared from Texas oil fields.
Texas Takes Steps to Reduce Flaring in Oil Sector
Rising levels of flared gas have been driven mainly by higher oil production as operators drilled new wells prior to the latest downturn. Lower oil prices in recent months may have reduced production, bringing down flaring; however, concerns remain.
While flaring is needed at times for safety reasons, some companies routinely flare gas more than others when economics or other factors are at play. Texas law prohibits flaring of associated gas from initial completion beyond 10 producing days. Companies may request exemptions.
Certain operators have made it a priority to reduce flaring, putting gas to use, utilizing technology and making sure infrastructure is in place before bringing a well online.
The matrix, seen as a key component of the plan, gives companies several options based on their situations, guiding the application of Statewide Rule 32. The rule prohibits flaring of associated gas from initial completion beyond 10 producing days.
“The point is that operations are different and operators are different. But these steps will lead to reduced flaring,” Todd Staples, president of the Texas Oil and Gas Association (TxOGA), told commissioners. “Importantly, a part of that is to embrace emerging technology. We believe that innovation and technology is what has made Texas the energy capital of the world, and we think that will drive environmental progress in everything that we do.”
The coalition also recommended:
- Changes to the Statewide Rule 32 dataset to improve commission oversight and data collection;
- A proposed new report to follow up on the duration and actual volumes of flared gas, providing the commission with clear and usable data; and
- Adding another code in production report forms for flaring to enable operators to better account for flared and vented gas.
Among the best practices are setting reduction goals and continuous gas capturing planning, working with midstream, assessing facility designs to enhance gas-oil separation, improving gas quality for pipeline specifications and evaluating potentially beneficial technologies—all aimed to reduce flared volumes.
When flaring is necessary, recommended best practices are to minimize emissions via auto igniters, remote or onsite monitoring, automation, redundant ignition and maintenance programs, according to the report.
“We believe that we can get to the end of routine flaring,” Staples said. “We believe that more data are better data. It will enable the commission to do its job easier and more efficiently.”
He added that technology and innovation should be part of the process, pointing out companies that have seen positive results.
RRC Chairman Wayne Christian sees the need for a place for new technology ideas at the commission. He mentioned a program in North Dakota in which new technologies and techniques are pitched with the most promising ones getting state funding that are matched by the industry.
“This is [an] opportune time to implement meaningful reforms to reduce flaring before oil and gas production climbs back to previous highs,” Christian said.
Kirk Edwards, president of Latigo Petroleum, suggested commissioners study limiting production in areas without plant capacity to take gas from newly drilled wells.
“This allowable mechanism would last until the plant has room,” for the gas wells, he said, noting this would apply to operators not drilling the first well on a new field.
For new wells drilled in an existing field with no immediate gas plant access, Edwards proposed commissioners allow the operator to flare natural gas production for no more than 90 days. No extensions would be given.
“The operator must then shut in the well until an adequate market is found for the well to produce into,” he said. Wells permitted before July 1, and those completed and producing before Oct. 1, would be grandfathered to flare as current statutes allow, he added.
Setting, Reaching Goals
Environmental groups also had ideas to share. The Environmental Defense Fund (EDF) urged commissioners to develop a plan to eliminate routine flaring in Texas by 2025.
“We know this can be done because many of the leading operators are either already doing it or quickly working to achieve it,” said Colin Leyden, director of regulatory and legislative affairs with EDF.
Parsley Energy Inc. flared less than 3% of its total produced volumes in 2019. That dropped to less than 1% of its pro forma produced volumes in June following the acquisition of a company that had been flaring about 20% of its volumes, according to Stephanie Reed, senior vice president of corporate development, land and midstream with Parsley.
“This did not happen by accident, but rather it required a methodical approach to reduce the flared volumes, including spending millions of dollars in necessary infrastructure,” she said.
Parsley’s road map includes an “aggressive corporate goal” tied to corporate compensation, reports detailing incidents to increase transparency and securing takeaway capacity before new wells start production.
Occidental Petroleum Corp. aims to have no routine flaring by 2030.
“The process to reduce flaring requires executive commitment and employee buy-in and ownership to reach our goal,” said Mike Starrett, vice president of HSE with Occidental’s domestic oil and gas operations.
Occidental’s approach involves site-specific planning, including identifying and evaluating gas takeaway and facility design options; routine surveillance, maintenance and repair of well operations, and emissions control equipment; training for engineers and operations personnel, and accurate and timely reporting of flare events.
Sharing, Using Best Practices
Parsley and Occidental are among the companies known for putting best practices to use. Their efforts—alongside Chevron Corp., EOG Resources Inc. and Pioneer Natural Resources Co.—were highlighted in research on how leading Permian Basin operators are keeping flaring levels in check, prepared on behalf of the EDF in a study by Gaffney, Cline & Associates. The companies have natural gas flaring rates ranging from less than 1% to 2.6% in the Permian Basin, which is below the basin’s average of 3.7%.
Neither size, geographical footprint nor classification as an independent or integrated matter when it comes to reducing the amount of natural gas flared. It comes down to governance and leadership from the boardroom to the field, commitment and best-in-class practices, according to the study.
“The silver bullet is to sell your gas. If your gas is going to sales, the dilemma on how to manage flaring goes away,” said Jennifer Stewart, carbon management strategy and policy lead with Gaffney Cline. “That’s not a one-and-done situation. That’s not an easy strategic leadership decision to make. It takes a lot of work and a lot of commitment. But these five companies have done it.”
The words, spoken during a mid-June webinar hosted by Rice University’s Baker Institute, came as natural gas flaring from the biggest oil field in the U.S. dips as operators slow activity amid weak prices. In recent years, the Permian has become notorious for its high flaring rates, which increased as producers— seeking oil—drove production to highs.
Reducing flaring requires commitment by companies to hook up gas wells only when infrastructure takeaway is in place; however, there must also be a willingness to shut in wells when infrastructure is not available, Stewart said.
Among the best operating practices shared by participating companies is using vapor recovery units on pad sites aiming to maximize emissions capture, frequently checking flares to ensure they are functioning properly, incorporating emissions monitors on facilities design and taking a strategic approach to manage operational upsets.
Nonroutine flaring is needed only when there are operational upsets, high gas line pressures or other safety reasons.
“There’s no easy fix to this issue. It’ll take a lot of work, but it is a fixable, manageable issue,” said Jeff Gustavson, vice president of Chevron North America E&P’s Midcontinent Business Unit. “Sharing best practices with all the operators is a great [and] easy step to take.”
Chevron, which has a more than 2 million-acre position in the Permian Basin, planned to produce about 600,000 boe/d this year and up to 1 MMbb/d by 2024, though Gustavson said those plans are being worked out in light of the current environment.
Industrywide curtailments are helping bring down amounts of flared gas, and the downturn is giving infrastructure time to catch up to production levels, Gustavson said. He pointed out positive economic signals from improved differential between Waha and Gulf Coast prices.
Energy research firm Rystad Energy said in April total gas flaring in the Permian dropped to an estimated 700 MMcf/d in the first quarter of 2020.
Chevron aims to reduce its global flaring intensity by 25% to 30% from 2016 levels by 2023.
The environmental and economic impacts are real, Gustavson said, before focusing on the latter.
“You’re burning a product that has value,” although prices went temporarily negative a few times last year, he said. Plus, he noted the market is watching, and there is heightened scrutiny on not just individual operators but the entire industry.
“Capital flows are changing because of this. That has a real economic impact,” he said.
When JP Morgan Asset Management analyzes energy stocks, sustainability factors are among the areas evaluated, according to David Maccarrone, a managing director with JP Morgan. The firm, he said, supports policymakers developing regulation to deliver on nonroutine flaring objectives in the Permian.
“The reality is climate change needs to be high among companies’ priorities because the world is changing,” Maccarrone said. “These changes will drive company operations and stock valuations and for us. … it impacts our ability to create value for our clients.”
EDF has been tracking flaring in the Permian Basin since the start of the shale boom. Its latest research revealed that some flares have major performance problems, contributing to methane emissions in the basin.
There is an incentive problem when it comes to flaring, said EDF’s Leyden.
“You’ve got low gas prices, rush to bring production online, a lack of meaningful regulatory limits,” he said. “That’s all a recipe for excessive waste and pollution, and that’s generally what we’ve seen in the Permian. Operators are primarily there for the liquids, and the dry gas can often end up essentially being a waste product.”
He called flaring a “huge unforced error” and a “question mark hanging over the oil and gas industry’s ability to compete in a low carbon economy.”
Hopes are for companies that routinely flare to be inspired by companies that don’t and for regulators to enact rules to make that happen.
Besides companies highlighted in the Gaffney Cline report, others of various sizes have taken steps to reduce flaring without stricter regulations. The problem is not every company is doing so.
“There’s an expression, ‘If you aim for nothing, you’ll hit it every time,’” Maccarrone said. “The voluntary operator actions we’ve seen have not delivered on the industrywide change we need to see in time, particularly in the Permian, given its size.”
It also helps to have goals, which Stewart pointed out creates transparency to stakeholders and accountability within and outside the organization. Some companies, including Chevron, have tied compensation to flaring goals.
“It starts with that strong governance and strong leadership from the top,” she said.
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