August 2023, Vol. 250, No. 8


Bakken Success Boosts Need for Gas Capture Innovations

By Richard Nemec, Contributing Editor, North America                   

(P&GJ) — While one of North Dakota’s top energy officials, Justin Kringstad, readily leads the cheers for his state’s success with industry in curbing the economic and environmentally harmful practice of flaring associated gas at well sites. 

He is also quick to remind listeners that without additional pipeline capacity in the prolific Bakken shale play, flaring could become an increasing problem again.  

In recent years, North Dakota operators have exceeded state-set targets by capturing up to 95% of production from month-to-month in the Williston Basin. 

North Dakota’s legislature this year passed legislation (SB 2089) to provide continued incentives for gas capture. And the North Dakota Industrial Commission (NDIC) so far has not given any indications of changing current gas capture targets. 

Nationally, the U.S. Energy Information Administration (EIA) statistics indicate flaring and venting are only a major issue in a few states where there is robust oil/associated gas production, such as Texas, North Dakota, New Mexico, and Wyoming.

The flaring of associated gas at the endpoint of a pressure relief system at an oil facility.

In 2021, the most recent year for full EIA statistics, those four states accounted for 87% of the nation’s 286 Bcf of flared gas. There was nearly 80 Tcf produced overall onshore in 2021 with more than half (43.3 Tcf) coming from supplies associated with oil production. 

Early in 2023, Exxon Mobil Corp announced that it stopped routine flaring of natural gas from production in the top U.S. shale basin and would press for stronger regulations for rivals to do the same. Nevertheless, as the largest U.S. oil producer, Exxon is facing lawsuits accusing it and other oil companies of contributing to global warming and rising sea levels.  

At the same time, the company has moved to cut its own emissions and supported government efforts to crack down on oil and gas operators to do more to find and fix gas leaks. 

Exxon officials have set a goal of halting all flaring by 2030, and other global majors have set similar goals, including Chevron Corp., BP plc, and London-based Royal Dutch Shell, which sold the bulk of its U.S. shale assets, and aims to halt most of its global routine flaring by 2025. 

Understandably, Texas has the most associated gas production, exceeding several Tcf annually, and the largest flaring volumes (93 Bcf, annually), followed by North Dakota (76 Bcf), Wyoming (65 Bcf), and New Mexico (16.7 Bcf). 

EIA calculates marketed gas statistics total gross supplies, minus “gas used for repressuring, quantities vented and flared, and nonhydrocarbon gases removed in treating or processing operations, including all quantities of gas used in field and processing plant operations,” said W. Taylor Colson, an EIA survey statistician.  

Gross supplies are full well-stream volumes, including natural gas liquids (NGL) and all nonhydrocarbon gases, but they exclude lease condensate, according to Colson. “It also includes amounts delivered as royalty payments or consumed in field operations,” he added. 

The calculations are complex, and states may vary somewhat from the EIA’s approach. North Dakota compiles flaring statistics or amounts of captured gas as total production, minus sales, minus lease use (heat treater, etc.), Kringstad said. Further affecting what eventually gets counted is the availability of takeaway midstream infrastructure and the degree of robustness in U.S. gas markets. 

“Current pipeline capacity will not be sufficient for future production levels,” Kringstad said. “I am forecasting the need for additional processing and transmission capacity around the 2026-27 time frame.” 

Wyoming state energy officials and EIA have differences regarding what the federal data-reporting agency has recorded for the state’s flaring venting most recently for 2021. Wyoming’s Oil/Gas Supervisor Tom Kropatsch dug out some more current data from 2022 to help support his point. EIA statistics have the state flaring leaping from 4.5 Bcf in 2020 to 65 Bcf the following year, but EIA’s Colson subsequently told P&GJ that he was re-evaluating the Wyoming numbers to determine if the agency needs to revise them.

Gas flares horizontally at an installation.

“The method used to publish EIA’s 2021 Wyoming venting/flaring data was to aggregate both wellhead and gas plant data obtained from the Wyoming Oil and Gas Conservation Commission” [WOGCC], which is headed by Kropatsch, according to Colson.  

From his initial review, he noted that it appears exclusions prior to 2021 were being made by EIA for the state’s largest gas plant (LaBarge Shute Creek). “That facility vents and flares a considerably large volume of nonhydrocarbons.” In 2022, the total flared supplies were 3.7 Bcf, according to Wyoming statistics. 

In the dynamic Permian Basin, officials report that flaring is receding, but there remains a thirst for added takeaway infrastructure and higher gas prices to boost greater capture percentages. 

“Tight takeaway space is expected to continue to create volatility in the Waha Hub market, but we are starting to hear and read about additional pipelines in the early permitting stages,” said Stephen Robertson, executive vice president of the Permian Basin Petroleum Association (PBPA), responding to P&GJ’s inquiry in the spring. “If these pipelines become reality, additional takeaway capacity absolutely will help with further reduction of flaring.” 

Like in the Bakken, operators are continuing to find ways to capture more gas so it can be marketed and reduce environmental impacts, Robertson said. He thinks the operators’ approach to flaring is the same in both the New Mexico and Texas portions of the Permian, although New Mexico has established state targets and Texas has not. Generally, capture rates remain above 90% throughout the basin, he said. 

New Mexico’s Oil Conservation Division (OCD) has established a mandatory gas capture rate of 98% by 2026 under new rules effective in 2021. In 2022, the state announced that companies accounting for the vast majority (99%) of New Mexico’s gas production and more than 85% of its wells are all abiding by the new requirements and reporting their emissions. “Among those reporting, most companies recorded capture rates greater than 90%,” Robertson said. 

A recent research report involving aircraft emissions measurements from 85% of the production in the Permian concluded that nearly half of the two-state basin’s operators increased their gas capture by more than 50% between 2019 and 2021.  

Seven researcher/co-authors writing in Environmental Research Letters (Vol. 18, No. 2) published Jan. 31 outlined their findings on “empirical quantification of methane emission intensity from oil and gas producers in the Permian,” noting that they expect greater amounts of public emissions data to be available in the future, and they have new methodological insights and “cautions” that should help in the development of advanced operator metrics that can be derived from these additional datasets. 

North Dakota remains an industry and national success story. Through fits and starts when flaring volumes were exceeding 30% of production, the state established industry-supported annual targets measured monthly by the Department of Mineral Resources (DMR) and its long-standing director Lynn Helms, calling for capturing 74% of production starting at the end of 2014. A commonly held belief at the time was that many operators would not be able to meet the first target. Flash forward to today and the capture rates now exceed the state targets and have remained in the mid-90% range. 

Before 2014, production in the Bakken Shale play surged from under 330,000 bpd to 1.1 MMbpd, and midstream infrastructure build-out struggled mightily to keep up with the rapid growth. Growth in flaring was a natural outcome of the boom period, and both the industry through the North Dakota Petroleum Council (NDPC) and the state through its governor-headed industrial commission separately convened task forces to confront the issue. 

In setting the eventual targets with help from industry input, state officials also established penalties to help incent action by operators in the oil patch. So, failure to meet the targets carried the prospect of production limits of 200 bpd well at a time when average Bakken wells were producing more than 1,500 bpd.  

Additionally, producers could have future drilling permits delayed if they failed to meet the flaring reduction goals.  

State regulators perform monthly audits, and DMR Director Helms gives monthly reports on gas capture and other production statistics in regularly held press conferences. 

Many operators have internal environmental-social-governance (ESG) programs that are influencing their activities, such as increasing gas capture, said DMR spokesperson Michael Ziesch.  

“The gas capture targets established by the NDIC have also encouraged operators to meet goals to keep from restrictions being placed upon them,” he said, noting that NDIC has also encouraged greater collaboration among parties, such as operators having continual conversations with gathering system operators, gas processing plants, et al.  

“Bakken operators have done a fantastic job of increasing gas capture, exceeding the state’s regulatory requirements of 91%; statewide gas capture is now 95% and operators seem determined to not stop there,” said Ron Ness, NDPC president. “We are working on various solutions to ensure redundancy or other capture technologies are available, so that when a gas processing plant is down, oil production can continue. I couldn’t be prouder of what the industry has achieved in the past few years.”   

Total elimination of flared gas is a stretching goal; it has not been achieved yet, according to officials, such as Kringstad. “I don’t know if that’s a realistic target, but I know there is the ability to bring it down even further in the future,” he said. “We have a number of producers who have gone to zero routine flaring, while there may be flaring during upsets or safety situations.” 

Generally, a number of potential scenarios could occur for wellsite production operators in which diverting the gas stream to flare is the safest and most appropriate action. This could occur if an unexpected system pressure buildup develops and it becomes necessary to protect health, environment, and equipment. 

“The commitments by producers, along with investments by midstream operators, is what is going to drive the capture rate even higher,” said Kringstad, adding that “routine” production should keep volumes within pipeline takeaway capacity limits with flaring only being done for safety reasons, or during workovers and other nonroutine operations. 

Technology advances continue to help up the ante in the flaring mitigation, and officials in both the Permian and Bakken underscore that. In the Permian, operators are experiencing advances in the monitoring arena – both aerial and on the ground. That applies to both intermittent and continuous measurements that are helping identify and fix various leaks and faulty equipment.  

“As that technology continues to grow and become more widespread that will only continue to help reduce flaring,” said PBPA’s Robertson. 

ExxonMobil is starting with 700 Permian sites to end routine flaring globally by 2030. It installed acoustic sensors, optical gas imaging cameras, additional pipelines and is expanding technology to quickly shut down operations remotely if needed.  

Most of its U.S. shale operations are in New Mexico, and Exxon reached a flaring intensity of 0.4% at the end of 2022 in the Permian, still behind rivals like Norway's Equinor and Brazil's Petrobras, which face stricter local regulations, according to reports from Reuters international news service. 

In North Dakota, Kringstad sees the most successful wellhead technologies relating to natural gas liquids [NGL], propane, ethane, etc., for which operators can deploy mobile units at the wellhead to knock out the higher-value heavy liquids so only methane is flared. The NGLs are trucked away for commercial processing.  

“That is one way operators are attempting to reduce the flare intensity,” Kringstad said. “The other way is either in combination with that or solely using compressed natural gas (CNG) trucks and re-injecting the gas for use in drilling rig and hydraulic fracturing fleets in lieu of diesel.” 

Kringstad sees the North Dakota efforts on flaring as highly successful, noting that “it did not happen overnight and has taken massive amounts of investment and effort by all the industry participants [midstream and operators], but we’re now in a really strong place. I think folks in the industry and the state are quite pleased with how it has turned out.” 

Since 2014, more than $20 billion has been invested in reducing flaring in North Dakota, according to Kringstad, who calls the dollar estimate widely accepted. It is more difficult pinpointing the market value of the captured gas that otherwise would have been lost, he said. 

Richard Nemec is a contributing editor to P&GJ based in Los Angeles. He can be reached at: 

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