Daily GPI / NGI The Weekly Gas Market Report / Regulatory / NGI All News Access

Industry Says BLM NatGas Flaring, Venting Rules Will Hit Independent Producers Hardest

The U.S. Department of Interior's (DOI) Bureau of Land Management (BLM) revealed more details of its proposed rules governing flaring and venting of associated natural gas on public and tribal lands in the Federal Register on Monday.

The BLM first unveiled the proposed rules in January (see Daily GPI,Jan. 22). As proposed, operators would be required to deploy equipment and processes to limit the amount of flaring gas at oil wells on public and tribal lands, and to periodically inspect their wells for leaks. They would also be required to limit venting from storage tanks. The rules also clarify when operators owe the government royalties, and give the BLM the option of setting certain royalty rates higher than 12.5%.

A 60-day public comment on the proposed rule ends on April 8.

Costs and Benefits

According to the BLM, the proposed rules would incur costs ranging from $125-161 million/year when the capital costs of equipment are annualized with a 7% discount rate, or from $117-134 million/year at a 3% discount rate. But the bureau added that monetized benefits from the rules would range from $255-357 million/year, and reduce methane emissions from 164,000-169,000 tons per year (tpy), depending upon the aforementioned discount rates, and volatile organic compound emissions (VOC) would decline by 391,000-410,000 tpy.

"Adoption of the proposed rule would also have numerous ancillary benefits," the BLM said. "These include improved quality of life for nearby residents, who note that flares are noisy and unsightly at night; reduced release of VOCs, including benzene and other hazardous air pollutants; and reduced production of nitrogen oxides and particulate matter, which can cause respiratory and heart problems."

Net benefits are estimated to range from $115-118 million/year or $138-232 million/year, depending on the discount rate.

Venting and Flaring

The BLM estimates that in 2013, operators vented about 22 Bcf and flared at least 76 Bcf of natural gas from BLM-administered leases. The agency said the flaring estimate was a 109% increase from the levels observed in 2009, and that more than 90% of the flaring came from wells in New Mexico, North Dakota and South Dakota.

The proposed rules would set a limit for the amount of gas that can be flared, and operators would be prohibited from venting natural gas, except in rare circumstances and emergencies. Specifically, BLM wants to set a 1.8 MMcf/month/well flaring limit, averaged across all producing wells on a lease. The new flaring limit is similar to those enacted in Wyoming and Utah, which limit flaring to 60 Mcf/day and 1.8 MMcf/month, respectively, unless the operator obtains permission from the state to flare more. BLM also proposes creating a two-year renewable exemption from the flaring limit, but only for certain existing leases near gas processing facilities, and flaring at a rate well above the proposed flaring limit.

The BLM said it estimates the new flaring rule would reduce the activity by up to 74%, but conceded that "there is substantial uncertainty" over the estimate. It added that the flaring limits, including the three-year phase-in period, would affect between 433 and 885 leases in any given year.

"Holders of these leases have, until now, had no prior notice of the proposed flaring limit," the BLM said. "Given the significant distance from these leases to the nearest gas capture facilities, and the leases' high rates of gas flaring, operators at these sites might have few options to meet the proposed flaring limit other than shutting in the wells.

"The BLM anticipates the number of leases eligible for this two-year exemption would decline over time, as production of oil and associated gas from existing leases naturally declines."

The exemption would allow an operator to flare 7.2 MMcf per month, per well. In the second year the limit would be reduced to 3.6 MMcf/month/well, and in the third and subsequent years the limit would be 1.8 MMcf/month/well.

The flaring rule will also require operators to install meters at flare stacks or manifolds when flared volumes exceed 50 Mcf/d. The BLM estimated that compliance costs would range from $1.0-1.8 million per year when the capital costs of equipment are annualized with a 7% discount rate, or $0.9-1.6 million per year at a 3% rate.

The agency said it estimates the flaring rule overall would cost operators either $32-68 million/year or $23-43 million/year, with the 7% and 3% discount rates, respectively. But the value of the captured gas is projected to offset the cost by either $40-58 million/year (7%) or $40-64 million/year (3%). The BLM also estimates that natural gas production would increase 2.0-5.0 Bcf/year under the flaring rule, and natural gas liquid (NGL) production would also increase, by 36-51 million gallons/year.

"The net benefits of these [flaring] requirements are estimated to range from negative $10 to positive $8 million/year (7% discount rate) or $13-30 million/year (3% discount rate)," the BLM said.

Leaks

In January, the BLM said it would require operators to establish an instrument-based leak detection program, using BLM-approved equipment such as infrared cameras. Smaller operators (fewer than 500 wells) will have the alternative of using portable analyzers, coupled with audio, visual and olfactory inspection.

Operators would initially be required to conduct their leak inspections twice a year, but if they consistently find few leaks they could be allowed to conduct one inspection annually. Conversely, if operators consistently find many leaks they could be required to perform the inspections quarterly.

In Monday's Federal Register, the BLM said it estimates the proposed rules governing leak detection would impact up to 36,700 existing well sites, and cost about $69-70 million/year, using the 3% or 7% discounted rates. The leak rules would also result in a projected $12-15 million/year in cost savings (at the 7% discount rate) or $15-17 million/year (3%), increase gas production by 3.9 Bcf/year, and reduce VOC emissions by 18,600 tpy.

"We estimate [the leak rules] would reduce methane emissions by 67,000 tpy, producing monetized benefits of $73 million/year in 2017-2019, $87 million/year in 2020-2024, and $100 million in 2025 and 2026," the BLM said. "Thus, we estimate that these provisions would result in net benefits of $19-21 million/year in 2017-2019, $31-35 million/year in 2020-2024, and $43-48 million in 2025 and 2026."

Pneumatic Controllers and Pneumatic Pumps

The BLM said it will require operators to replace high-bleed pneumatic controllers with low-bleed or no-bleed controllers within one year of the final rule's enactment. The agency said that meshes with a general prohibition against high-bleed controllers by the U.S. Environmental Protection Agency (EPA), and with rules enacted by Colorado and Wyoming that high-bleed controllers be replaced with low-bleed ones. The BLM said it estimates the pneumatic controller requirements would impact up to about 15,600 existing low-bleed devices, and pose total costs of about $6 million/year or $5 million/year, with the 7% and 3% discount rates, respectively. But gas production would increase 2.9 Bcf/year, resulting in cost savings of about $9-11 million/year (7%) or $11-12 million/year (3%).

"These requirements are also projected to reduce methane emissions by 43,000 tpy, producing monetized benefits of $48 million/year in 2017-2019, $56 million/year in 2020-2024, and $65 million in 2025 and 2026," the BLM said. "The resulting net benefits of $53-68 million/year (using a 7% discount rate for costs and cost savings) or net benefits of $54-73 million/year (using a 3% discount rate for costs and cost savings), along with a reduction in VOC emissions of about 200,000 tpy."

For pneumatic pumps, the BLM will require that operators either replace a pneumatic chemical injection or diaphragm pump with a zero-emissions pump, or route the pneumatic chemical injection or diaphragm pump to a flare. The agency said it estimates up to 8,775 existing pumps would be affected, and pose total costs of about $2.5 million/year. An estimated 0.46 Bcf/year in increased gas production would help offset the cost by either $1.5-1.9 million/year or $1.75-2.15 million year, with the 7% and 3% discount rates, respectively.

According to the BLM, the pneumatic pump rule would reduce methane emissions by about 16,000 tpy, "producing monetized benefits of $18 million/year in 2017-2019, $21 million/year in 2020-2024, and $24 million in 2025 and 2026. This would result in net benefits of $17 million/year in 2017-2019, $20 million/year in 2020-2024, and $23 million in 2025 and 2026, as well as reducing VOC emissions by about 4,000 tpy."

The BLM estimates that on leases it administered in 2013, about 5.4 Bcf of natural gas was lost from pneumatic controllers, and about 2.5 Bcf was lost from all pneumatic pumps.

Storage Vessels

Operators would be required to route VOC emissions from existing storage vessels to combustion devices, continuous flares or sales lines within six months of the rule's effective date. The BLM said it would grant an exception to this requirement "if the operator submits an economic analysis demonstrating -- and the BLM agrees -- that compliance would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease."

The BLM said it estimates about 300 existing storage facilities would be affected, and cost operators about $6 million/year, but gas production would increase by 0.04 Bcf/year, resulting in cost savings of $100,000-200,000/year, and reduce methane emissions by 7,000 tpy.

"Rather than establishing new and separate standards for venting from existing vessels, we have been informed by operators that it would be easier to comply if we simply require existing vessels on BLM-administered leases to meet standards that are the same as the EPA standards that already apply to new and modified vessels on those leases," the BLM said. It added that it estimates 2.77 Bcf of natural gas was lost from storage tank venting on federal and tribal lands in 2013.

Well Maintenance and Liquids Unloading

Another issue the BLM wants to tackle is the loss of natural gas volumes from liquids unloading operations, such as when operators allow bottom-hole pressure to increase and then blow down, or purge, the well. Those activities resulted in the loss of 3.26 Bcf of natural gas on federal and Indian lands in 2013, the agency estimates.

"There are a wide variety of methods for liquids unloading, and technological developments, such as automated plunger lifts, now allow liquids to be unloaded with minimal loss of gas," the BLM said, adding that it "believes that it is reasonable to expect operators to use these available technologies to minimize gas losses, and we believe that failure to minimize losses of gas from liquids unloading now constitutes waste."

Under the new rules, the BLM would prohibit unloading liquids through purging the well, except under some specific circumstances. The ban would affect up to 1,550 existing wells and about 25 new wells per year, and cost $5-6 million/year. Gas production would increase by about 2 Bcf/year and result in cost savings of $7-8 million/year or $7-10/million year, with the 7% and 3% discount rates, respectively. Methane emissions would be reduced by 30,000-34,000 tpy.

Reduction of Waste From Drilling, Completions

The BLM wants to require that operators either flare the natural gas generated during drilling operations, capture and sell the gas, use the gas in operations on the lease, or inject it into the well. According to the BLM, 2.1 Bcf of natural gas was lost during drilling, completion or refracturing operations performed on federal and tribal lands in 2013.

"The EPA currently requires new hydraulically fractured [fracked] and refractured gas wells to capture or flare gas that otherwise would be released during drilling and completion operations, and EPA has announced that it plans to extend these requirements to new fracked and refractured oil wells," the BLM said. "Nonetheless, the BLM believes that it is appropriate for the BLM to adopt its own requirements to minimize the waste of gas during well drilling and well completion and post-completion operations at fracked or refractured wells and wells that are not fractured. The BLM has an independent statutory obligation to minimize waste of oil and gas resources on BLM-administered leases."

The BLM said it believes about 3,000 wells/year would be affected by the rule, but added that "based on our experience in the field...[we believe] that operators are already controlling gas from drilling operations as a matter of safety and operating practice. Thus, we do not estimate costs associated with this requirement.

"Similarly, based on our professional experience in the field, we believe that operators are already controlling gas from workover operations on conventional wells as a matter of safety and operating practice, and there should be no compliance costs for this requirement."

Royalty Provisions For New Competitive Leases

Currently, the royalty rate for onshore oil and gas leases is 12.5%, and the BLM has no discretion to raise the rate as conditions change. The new proposal would set the royalty rate for new competitive leases at or above 12.5%.

"Although the BLM does not currently propose to raise royalty rates, the proposed rule would allow the BLM to set a royalty rate for oil and gas produced from competitive oil and gas leases issued after the effective date of this rule of 'not less than' 12.5%," the BLM said. It added that it "is not proposing any further changes to the royalty provisions governing new competitive oil and gas wells, but we are requesting comment on the use of a fluctuating royalty rate to incentivize reductions in flaring from new competitive leases."

Reaction

On Monday, the American Petroleum Institute (API) and the Independent Petroleum Association of America (IPAA) referred to comments each organization made last month, when the rules were first unveiled.

“Federal data show crude oil production remained flat between 2009 and 2014 on federally controlled land while natural gas production declined 35%,” said Erik Milito, API’s director of upstream and industry operations. “By contrast, on private and state lands, where development does not need permission from the federal government, production increased 88% for crude and 43% for natural gas. These dramatically different trend lines are in large part a function of failed energy policy, not geology.”

Dan Naatz, IPAA’s senior vice president for government relations and political affairs, concurred.

“This is the latest in the string of bad policies released by this administration showing a lack of knowledge of how the oil and gas industry truly works,” Naatz said. “Imposing these new regulations will make it more expensive and harder for independent producers to operate, reducing America’s total energy production and preventing additional receipts from going back to the United States Treasury.

“Making matters worse, lifting the royalty rate ceiling simply leaves the door open for the federal government to increase rates on producers down the road. This will change the predictability and certainty for operators on federal lands, making it harder to plan and commit to long-term projects. With oil and natural gas prices currently at their lowest in decades, now is the worst time to raise fees on America’s independent producers.”

ISSN © 2577-9877 | ISSN © 1532-1231 | ISSN © 1532-1266

Recent Articles by Charlie Passut

Comments powered by Disqus