Ledes from the Land of Enchantment

Natural gas recapturing process promises waste reduction — but questions linger

A trio of major oil and gas producers are testing a new-to-New Mexico process to keep natural gas in the ground when it can’t be transported, sold or otherwise shipped through a pipeline.

Instead of flaring or venting natural gas or completely shutting down wells when a midstream pipeline operator has an issue, the three producers — EOG Resources, Inc., Occidental Petroleum Corp. and Chevron Corp. — can now re-route backed-up gas into closed-loop gas capture systems, or CLGC, where it is re-injected into an active oil well. It then can be taken out later when a pipeline again has enough capacity.

The New Mexico Oil Conservation Division regulates the state’s oil and gas field operations and issued the orders allowing the state’s pilot CLGC wells. Dylan Fuge, the division’s director, said he expects the process will help reduce venting and flaring. “Overall, CLGC systems result in less waste due to an increase [in] an operator’s gas capture,” he said.

Producers want to capture this gas rather than flare it because they can sell it later. Plus, Fuge said, flaring the captured gas would not make sense given the cost and effort to set up the wells.

Occidental was the only one of the three companies to respond to questions about CLGC systems. “CLGC is part of Oxy’s overall strategy to reduce greenhouse gas emissions,” said Jennifer Brice, the company’s director of communications and public affairs. She said the process minimizes flaring when third parties are unable to handle the gas [i.e. during mechanical breakdowns], and “keeps production online, and conserves natural resources when produced gas is stored rather than flared.”

So far, New Mexico’s CLGC projects are small, and their promise hasn’t panned out in the oil and gas fields.

EOG, Occidental and Chevron operate nine pilot CLGC projects in New Mexico. A review of venting and flaring records the three companies submitted to OCD showed that flaring amounts for EOG rose nearly twentyfold in the past year. Occidental and Chevron reported flaring nothing at all.

At the same time, the “waste” Fuge referred to — natural gas lost in production, often due to leaks between a wellhead and a pipeline — spiked for all three companies in recent months, though inconsistencies in Chevron’s numbers leave that somewhat inconclusive. (Chevron reported processing more gas than it pulled from the ground in January and April.) EOG reported losing enough natural gas in June alone to equal the greenhouse gas emissions of 100 cars driven for a year. That’s four times what it burned in emergency flaring the previous year and far more dangerous to the climate.

Given that murky picture, it’s not clear how much the pilot CLGC systems may be helping reduce emissions, much less mitigate contributions to climate change. Fuge at OCD said, “Operators are subject to robust reporting requirements under the CLGC order.

OCD reviews the information submitted by the operator for any anomalies.”

Even so, he said, his agency hasn’t aggregated the data filed from the nine pilot sites to see how much gas has been injected and re-produced by the three companies. Plus, CLGC data collection is complicated by the fact that the injected gas went through the state’s royalty and taxation system when it was pulled from the ground the first time. “We cannot use the standard reporting system,” Fuge said, “as it would result in double counting of production.”

That raises the question: Can OCD effectively monitor a new oilfield process when the agency has struggled for funding to meet the enforcement obligations it already has? New Mexico’s already massive greenhouse gas emissions make the answer a matter of vital importance.

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The Environmental Defense Fund has been tracking and tallying emissions in New Mexico and finds that the state is falling well short of its climate targets.

According to a report released earlier this month: “The state is on track to reduce emissions by less than one-third of what is necessary to meet 2030 commitments made by Gov. [Michelle] Lujan Grisham.”

EDF said that to reach its goals, the state must (among other things) increase oilfield pollution enforcement by OCD and the New Mexico Environment Department, since more than half of the state’s greenhouse gas emissions come from oil and gas production.

And each time someone looks, the number and volume of those emissions rise.

Earlier this year, GHGSat, a private company with a network of satellites that scan for methane (methane comprises up to 90% of natural gas), reported that more than half of the oil- and gas-based emission events it found in the U.S. were in the Permian Basin, while the frequency of observations with those emissions rose from 43% in 2021 to 56% in 2022. Another EDF study from a year ago showed that gathering pipelines (which connect wells to processing facilities) in the Permian Basin leaked 14 times more natural gas than EPA estimates.

The problems of excess natural gas, leaky systems and overburdened midstream pipelines have grown as oil production has rocketed in the Permian Basin. The Permian, which straddles the border between New Mexico and Texas, is the country’s most productive oil field, but that oil also brings up vast volumes of produced water and natural gas.

Produced water has its own disposal problems and controversy, and natural gas production rates now often exceed midstream pipeline capacity to carry it to market. When too much gas is produced or a pipeline shuts down for maintenance or because of an emergency, companies can shut down wells (which they are loath to do) or they can flare or vent the gas to get rid of it. But leaks, venting and flaring are growing increasingly expensive — and illegal.

In 2021, New Mexico implemented a rule that requires producers to capture at least 98% of gas that comes out of all of their wells in aggregate. The rule also prohibits all routine venting and flaring. Companies report this data to the OCD, and most larger companies — including EOG, Occidental and Chevron — claim to have already reached that goal (though several small companies remain off target).

But the total reported natural gas vented and flared in New Mexico has actually risen more than 50% over the year and a half leading up to June (the latest fully reported month available), paralleling the increase in oil production.

In addition, venting and flaring spiked across the Permian Basin last December when a cold snap shut down midstream pipelines that carry natural gas. Many questioned whether cold weather constituted an emergency: Jeremy Nichols, until recently the director of the climate and energy program at WildEarth Guardians, said at the time, “News flash: Winter happens in the Permian Basin every year.”

Either way, gas line shutdowns led to a 39% increase in flared gas and a 161% increase in vented gas in New Mexico’s portion of the basin compared to the month before. In theory, companies using a CLGC system would have been able to store gas that would have been flared or vented in that event.

Starting in 2024, companies will be charged for emitting methane — i.e. venting and leaking natural gas — as part of last year’s Inflation Reduction Act. The charge starts at $900 per metric ton of methane, increasing to $1,500 per ton in 2026. A report by the Congressional Research Service said, “This charge is the first time the federal government has directly imposed a charge, fee, or tax on GHG emissions.”

CLGC could be a way to reduce those emissions, and Jon Goldstein, senior director of regulatory and legislative affairs at the Environmental Defense Fund, said, “Reinjection of natural gas is a proven safe alternative to the routine flaring that is happening far too much in the Permian.” But, he cautioned, “It needs to be closely monitored and verified like anything in the oil and gas industry.”

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New Mexico is neither the first nor the only state with CLGC systems, but such systems remain uncommon.

Matt Skinner, a public information manager with the Oklahoma Corporation Commission, which oversees oil production in the state, said, “Wow, really? I have to say that’s news to me,” when CLGC systems were described to him.

Patty Ramon, a spokesperson for the Texas Railroad Commission, which oversees oil and gas production in that state, said that an EOG pilot project was the extent of CLGC there.

Allen Christensen, production auditing and gas measurement supervisor at the North Dakota Oil and Gas Division, said, “It hasn’t taken hold up here,” though EOG tested it on a well a few years ago.

The one place in the country where CLGC is happening on a wide scale — and has been for years — is the Alaska North Slope. Dave Roby, senior reservoir engineer with the Alaska Oil and Gas Conservation Commission, said that natural gas injection began on the North Slope in 1962. “Reinjecting the gas for enhanced oil recovery purposes is in the best interest of not only the state but also the operators,” Roby said, “as doing such has allowed them to produce billions of barrels more oil than would’ve been possible had the gas not been reinjected.” Because of that financial incentive, “over 108 trillion cubic feet of gas has been reinjected in Alaska.”

That incentive exists everywhere, but there are two reasons that it makes particular sense in Alaska. One is that Alaska’s North Slope oil sits shallow under the ground and is under less natural pressure than oil in other places.

Natural gas is pumped into those formations to force the oil out, one of the processes in so-called enhanced oil recovery. The process is common in many oil producing regions — including the Permian Basin — but it is usually done with carbon dioxide. The second reason gas injection is popular on the North Slope: There are no natural gas pipelines to take the gas to market.

“It’s just so expensive to get another 800-mile pipeline” like the Trans-Alaska Pipeline System, which takes crude oil from the North Slope south to the port city of Valdez, said Lois Epstein, a civil and environmental engineer in Anchorage, Alaska. She monitors oil production in the state and said that the hurdle to selling Alaskan natural gas is finding a market. She said that’s why many in Alaska want to “get the folks in Asia to think it’s a good idea to get Alaskan gas.”

That also has a parallel in New Mexico and surrounding states, where the state, tribal and industry group Western States and Tribal Nations works to entice Asian markets with natural gas from the region.

Natural gas facilities in Alaska vent, flare and leak as do facilities anywhere else, and Epstein questioned North Slope operators’ incentive to do anything about it given the North Slope’s harsh conditions and distance from oversight.

“Stopping an operation to fix it,” she said, “is going to probably be more costly than the amount of gas that they would be collecting and injecting.” Geography enhances the problem. “A lot of us have tried to get a handle on how much flaring … and venting is actually happening in Alaska,” she said. “It’s so remote that, you know, there isn’t a lot of regulatory presence there.”

Epstein wondered about similar regulatory problems in New Mexico. She credited the state for its nationally recognized methane rules, but when it comes to CLGC, she asked, “How are they going to be monitoring it?”

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