Texas Could See $440 Million From Reduction in Fugitive Natural Gas Emissions
Oil companies could make millions if required to capture natural gas
Paul Takahashi Jan. 26, 2021 houstonchronicle.com
Requiring oil and gas companies to capture 98 percent of natural gas produced in Texas could yield $440 million of additional revenue from increased gas production by 2025, according to a new report.
If Texas were to adopt a 98 percent gas-capture policy, it would nearly eliminate routine flaring in the Permian Basin of West Texas, according to a Rystad Energy report commissioned by the Environmental Defense Fund and released Tuesday. The policy would sharply reduce greenhouse gas emissions, but also allow operators to capitalize on the increased natural gas production.
“We’re talking about stopping the release of something with value,” said Colin Leyden, director of regulatory and legislative affairs with the Environmental Defense Fund. “There’s significant value creation to be had with a 98 percent gas capture metric.”
The oil industry has long battled the issue of flaring, the burning of excess natural gas that's produced during crude production. Flaring releases greenhouse gases such as methane, which is 84 times more capable of trapping heat than carbon dioxide, according to the Environmental Defense Fund. A trillion cubic feet of natural gas in the Permian Basin of West Texas has been flared since 2013, according to the Energy Information Administration.
Flaring has fallen to the lowest level in nearly a decade after the lockdowns during the coronavirus pandemic slashed crude demand and oil and gas production. Rystad estimates that 390 million cubic feet per day of natural gas — representing 1.6 percent of production — was flared in the fourth quarter of 2020, the lowest since 2012. For comparison, more than 4 percent of the natural gas produced in the Permian Basin was flared in 2018 and 2019.
As oil production rebounds from the pandemic, however, flaring is expected to rise.
“In terms of whether that large reduction is sticky or not, the jury is out,” said Mike McCormick, a principal at Rystad. “We haven’t seen an uptick in flaring yet.”
Still, the Environmental Defense Fund is pushing ahead to keep flaring at historically low levels. The environmental advocacy group is proposing that Texas implement gas capture requirements similar to ones enacted recently in North Dakota and New Mexico. Some Democrat legislators in Texas are also calling for a tax on flaring.
Complying with a 98 percent gas capture rule is estimated to cost oil and gas companies about $50 million by 2025. Less than a fifth of oil and gas companies would incur costs of about $100,000 a year to meet a prospective gas-capture rule, according to Rystad.
Several major oil and gas companies have already made a concerted effort to reduce flaring as investors and political leaders have grown increasingly concerned about climate change. More companies are expected to implement flaring reduction measures after French utility giant Engie last year canceled a $7 billion deal to buy liquefied natural gas from South Texas because of concerns about flaring.
The Texas Oil and Gas Association’s methane flaring commission, a group of 40 oil and gas companies, is working on improving operations and environmental practices to minimize flaring, such as using robots and drones to detect leaks. In November, the Texas Railroad Commission, which oversees oil and gas companies in the state, required operators to provide more details and reasons for flaring in an effort to bring more transparency to the issue.
Railroad Commissioner Jim Wright on Tuesday said flaring must be allowed until the commission starts to require proper natural gas connections before starting crude production, but added that flaring must be regulated. He suggested that the commission ask oil companies to seek greater details on their need to flare and ask for a timeline for pipelines to transport the associated natural gas coming out of the well.
"My aim is to require any applicant who applies for authority to flare during my term, to show how and when their production of natural gas will be transported correctly for marketing," Wright said. "I am amenable to allowing fair time for flaring to occur in certain circumstances, but limits must be set.”
Todd Staples, president of the Texas Oil and Gas Association, this month said no one is investing more than U.S. oil and gas companies to minimize flaring through carbon capture technology and automation.
“The fact that 99.5 percent of gas is being captured speaks volumes to the commitment of this industry,” Staples said. “Any new tax will hurt this product that is responsible for the cleanest air in the nation.”
Leyden acknowledged there will be situations where flaring is inevitable to maintain worker health and safety, but reducing flaring as close to zero ought to be the ultimate goal, he said. In Norway, which has restrictive flaring regulations, oil and gas companies flared just 0.2 percent of their natural gas production in 2019. Some of the top-performing U.S. oil and gas companies flare just 0.4 percent of their natural gas production, Rystad said.
“0.4 percent is not the ultimate best that can be done,” Leyden said. “We’re moving toward a world pretty quickly where flaring and methane is not going to be tolerated. If you’re not doing this, you’re not going to have access to capital and you’re not going to be competitive. This is the price of admission for being a responsible operator.”
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Replies to This Discussion
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Permalink Reply by Curious Will on -
Thanks for posting this Skip. I wonder where Louisiana is regarding this concern.
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Permalink Reply by Skip Peel - Mineral Consultant on
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I don't know where Louisiana is with this, CW. I have occasionally posted articles that speak to the potential to offset the cost of reducing emissions with the gas saved. This is the first time that I have seen a dollar figure and it is significant. Currently there is more gas coming out of the Permian, the Eagle Ford and the Haynesville basins in Texas than the Haynesville/Cotton Valley here in Louisiana but even at a quarter of the savings that would be $110M in state coffers. The environmental aspect is certainly important but here it would be seen as secondary to the revenue. Louisiana always needs more money.
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Permalink Reply by Steve P on
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My understanding is that this issue is primarily related, maybe solely related, to associated gas produced from wells primarily producing oil. that does not seem to be an issue in most current Louisiana production. The Permian Basin is an oil producing field that also produces some NG as a by-product. This isn’t much of an issue for the HA production in NW LA and E-TX.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Yes, much of the fugitive gas in Texas is from oil wells, associated gas. The source of the fugitive emissions is basically irrelevant. It is the volume, whatever the source, that is important. Theoretically, It could take many Texas oil wells making modest volumes of associated gas to equal a single Haynesville well producing 15,000 mcf a day depending on the percentage of gas escaping. As far as I have read, no Haynesville operators are touting emission reduction programs. The individual sources of escaping gas are largely the same whether a well is producing oil and associated gas or just gas. The 98% reduction used as an example is not just the volume associated with flaring/venting.
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Permalink Reply by Skip Peel - Mineral Consultant on
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EQT Launches Pilot to ‘Responsibly’ Produce Appalachian Natural Gas for Global Market
By Jamison Cocklin January 28, 2021 naturalgasintel.com
EQT Corp., the Lower 48’s largest natural gas producer, has launched a pilot program to demonstrate that the fossil fuel can be produced in an environmentally responsible way as buyers across the world continue demanding higher standards.
EQT has partnered with environmental monitoring company Project Canary to continuously measure methane emissions and obtain certification that natural gas from two well pads in the Appalachian Basin is responsibly produced. The ultimate goal of the pilot, the company said, is to show that gas can be produced with both high environmental and social standards.
EQT CEO Toby Rice said the pilot would help confirm “the emerging domestic and international markets for this differentiated commodity and the important role that United States liquefied natural gas (LNG) will play in the future energy mix.”
Project Canary would provide an independent, third-party certification of responsibly sourced gas and provide methane monitoring. The terms of the project are confidential, but, EQT said a global energy company agreed to purchase a portion of the gas produced during the pilot. Costs associated with the pilot and the location of the wells were not disclosed.
Devices are to be installed on the two well pads to measure methane concentrations at the site level “every second” and communicate results to a cloud database “every minute,” EQT said. Social impacts on the nearby community also would be evaluated.
The TrustWell certification provides ratings for gas wells or entire asset bases. It measures several metrics to certify the conditions under which gas is produced to gauge impacts and risks, with a focus on water, air, land and community. The ultimate output is a rating similar to a Leadership in Energy and Environmental Design, aka LEED, rating for a building.
Project Canary, which provides emissions monitoring for the oil and gas industry, merged with Independent Energy Standards, the developer of the TrustWell certification program, in August. They came together to provide a more comprehensive “responsibly sourced gas” solution for the industry as environmental, social and governance (ESG) issues have become a top priority.
Prior to the merger, IES had certified the wells of other U.S. operators, including some West Virginia wells operated by Southwestern Energy Co.
EQT produces gas in Ohio, Pennsylvania and West Virginia. It produced 366 Bcfe in the third quarter and has churned out more than 1 Tcf annually in recent years. The producer’s decision to launch the pilot comes as governments and private companies are aiming to curb the impacts of climate change.
“Stakeholders and investors continue to expect and demand more transparency, more verifiable trusted data and more overall ESG-related performance progress across the energy sector,” said Project Canary CEO Chris Romer. “This pilot project, which will utilize our differentiated technology to provide trusted and independent data, demonstrates continued responsiveness toward meeting and exceeding those growing stakeholder demands.”
As global demand for LNG has grown, so too are the measures aimed at ensuring the fuel is responsibly produced, liquefied and transported. Late last year, French energy company Engie SA ended negotiations to buy LNG from the proposed Rio Grande LNG terminal in Texas because of the French government’s concerns over emissions related to hydraulic fracturing.
Meanwhile, Total SE and Royal Dutch Shell plc have already delivered carbon-neutral LNG cargoes offset with credits from environmental and renewable energy projects. Plans for new LNG terminals, including Rio Grande, also call for using carbon capture and storage technology to reduce emissions.
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Permalink Reply by Chad Ellis on
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This article is poorly written. I cant say if its ignorance or apathy. It begins with the use of the term flaring. it is conflated with the term venting. Both are common in the oil and gas industry. Venting is allowing the vapors to escape into the atmosphere. When you vent, Methane, VOC's and any other vapors are let into the air. This volume is calculated and addressed in the permit for the facility. This is common at most well sites regardless of oil or gas production. There are many variables that increase or decrease the volume of emissions. Flaring on the other hand is the physical burning of all hydrocarbons and other vapors in the flare. This emits CO2, CO, and H2O vapor. This process eliminates the hydrocarbon and VOC (Volatile Organic Compounds) emissions. It is common on large treating and/or processing facilities. Flaring is also used on some gas wells during the flowback phase (too much water to send down the sales line). The most visible use may be on oil wells to burn off the excess natural gas. This is exasperated in the Permian because of the lack of takeaway capacity for the natural gas.
The other point that is dubious is the cost effectiveness of vapor capture. The cost for recovering vapors is very site specific. It is also dependent on having gas takeaway infrastructure. I have designed and built six such facilities in the Arklatex and looked at another 10 locations that were ultimately unsuitable. This is not a one size fits all solution.
Another point that can be misleading is comparing the Haynesville to the Permian. This is an apple to orange comparison. In a nutshell, the Haynesville is a closed system that is not open to the atmosphere in normal operations. The Permian, and any liquid play, has several stages that require the production(oil, condensate) to be open to the atmosphere. To clarify, the Haynesville is a dry gas play. There are little to no liquids produced. (The water used to frac is recovered and disposed of before the well goes to sales). This means that there is no venting at the well site through the production tanks. All of the produced product(gas) is contained within the production tubing and pipelines. The Permian is the exact opposite. Most of the well's production is captured on site in tanks. Depending on the volume produced, these vapors are either vented, or flared. Installing a VRU (vapor recovery unit) may or may not be applicable depending on a lot of variables.
We all want to capture as much of the product as possible. This leads to an improved bottom line. The ways to accomplish this are variable and site specific. Blanket regulations that do not take into account the variables are not helpful. And demonizing a relatively clean process such as flaring is also unproductive. The biggest drawback to flaring is when it is used to dispose of excess natural gas. This is production that is not sold and that hurts the producers, the mineral owners, and ultimately the tax collector.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Not sure which of the articles you are referring to, Chad. There have been numerous articles on the subject recently. Those articles covered such topics as "unit flare stacks" and monitoring which found that one in ten of the stacks was malfunctioning/unlit and therefore "venting". The super-major/major companies in the Permian are largely on board with plans to reduce flaring, venting and fugitive emissions of all kinds and the RRC is listening. The RRC has been struggling with the fact that they never turn down an application to flare. Larger Texas operators are for limitations/reductions while smaller operators are not.
Although there is considerably less flaring in the Haynesville as compared to the Permian, the volume of gas that is potentially lost to the atmosphere through fugitive emissions could be far greater on a per well basis. None of the Haynesville operators in the Louisiana portion of the fairway have programs to reduce fugitive emissions that has been publicized.
At this point the questions of monitoring and reduction of methane emissions is a state issue. I don't expect Louisiana to be a leader in crafting methane emissions regulation but think that where Texas goes, Louisiana often follows. The pros and cons of methane regulations are one of cost at this time. My interest in the article was the dollar figure for increased revenue. I'm skeptical of the 98% figure and thus also the $440M revenue figure. If Louisiana could realize an eighth of that amount, it would be significant for the state budget. Unfortunately, the climate impact is usually insufficient to get the attention of elected officials...but dollars they understand.
It matters not whether emissions come from flaring, venting or portions of the treating/ transportation system. Every mcf saved serves as a benefit to the climate, the operators, the state and the royalty owners.
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Permalink Reply by full name on
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Skip, See the following from the first post in this chain paragraph four. ( I added the bold). The article says flaring but actually means venting. The reporter is a business reporter not an O & G reporter.
The oil industry has long battled the issue of flaring, the burning of excess natural gas that's produced during crude production. Flaring releases greenhouse gases such as methane, which is 84 times more capable of trapping heat than carbon dioxide, according to the Environmental Defense Fund. A trillion cubic feet of natural gas in the Permian Basin of West Texas has been flared since 2013, according to the Energy Information Administration.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Thanks. You are correct that "flaring" should have been "venting". It was a revelation that one out of ten stacks were venting, not flaring, due to malfunction in the Permian. Venting of methane is the most significant emission source by far. With few exceptions however there have not been comprehensive monitoring of all sources of methane emissions. And since they are invisible to the naked eye, it is easy to overlook them. Since my focus is Louisiana, I would like to see an aerial study that provides a much more accurate measure of methane emissions from any and all point sources. The metric that is meaningful for the public and elected officials is the total mcfs lost to the atmosphere from all sources. If the cost to reduce that total significantly is equal to or less than the economic benefit to all stake holders, it is something that the state should mandate and that operators should embrace.
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Permalink Reply by Rock Man on
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Assuming wells are choked back or shut in to reduce flaring and related emissions, I wonder how much oil revenue will be reduced?
Ripple effect of reducing flaring will hit royalty owners in their wallets with reduced monthly checks - until the operators get all these wells hooked to gas sales line (which will not be easy or cheap).
Just my opinion as always
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Permalink Reply by Skip Peel - Mineral Consultant on
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Where formations are proven productive, as I think is the case in the majority of unconventional basins, how about building the gathering system before drilling the wells? In many cases, would this not be an extension to an existing system? There should be ways to automatically shut off flow to malfunctioning unit flare stacks that are venting. There are also on-site uses of natural gas from running drilling and completion equipment to operations as esoteric as mobile CNG storage units and mining bitcoin. Even the combination of facilities and technologies will not eliminate fugitive emissions entirely however any meaningful reduction saves mcfs and lessens the pressure on regulators and investors to take actions that make life tougher for producers. Operations as usual are no longer an option. Much better for the industry to take the lead on reduction of fugitive emissions than the alternative.
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Permalink Reply by Rock Man on
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Good points but here is counterpoint.................. (remember that TV segment on 60 Mintures?)
Using the Eagle Ford and Permian basin as examples, existing gas gathering systems in many areas tend to be low capacity and/or low pressure lines. No where near the abilty to take high pressure larger gas volumes.
Also in both areas, the capacity to take the sour gas that is associated with some new laterals is not there. And the ability to scrub the H2S out of the gas is not possible with surface equipment.
The construction of new lines and new processing plants and capacity is coming - the new big gas lines taking gas from Permian to Tx Gulf Coast are examples of that (e.g. Kinder Morgan's new line thru Hill Country carrying 2.1 Billion cubic feet of gas per day at 1400# pressure), but it will take time.
And gas pipeline companies don't help when they elect to charge HUGE fees for pipeline taps, gathering and transportation costs. This was the root of the lawsuit about flaring last year in S Tx (EXCO being charged such high fees that selling the gas to only pipeline in the area was losing them money).
Shutting off flow to malfunctioning flare stacks means shutting in wells - and associated oil production..
Can flare stack be created that will totally consume all emissions? Probably. And that is a good short term option. I believe that EOG used something like this in East Texas a few years ago. No flare. System just seemed to burn gas in closed system and consume any post burn particulate matter.
I will agree that the oil industry needs to adjust to the issues that are critical today - but this will not happen overnight. And definitely will not happen unless all groups tied to production work together. Gas pipeline companies cannot expect ultra high fees to take gas and ream over the operators.
JOINT EFFORT AND COOPERATION IS NEEDED.
And in the meantime, royalty owners could lose $$$$ due to shutting in wells or restricting production to cut emissions.
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