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Assessment
Flaring or venting are permitted without BSEE’s approval under a limited number of circumstances, listed in Title 30 CFR § 250.1160(a) . when natural gas is used to operate production facilities or as an additive to burn waste products during the restart of a facility that had been shut in because of weather conditions, such as a hurricane during the blow-down of transport pipelines downstream of the royalty meter during the unloading or cleaning of a well, drill-stem testing, production testing, other well-evaluation testing, or the blow-down necessary to perform these procedures when equipment fails to work correctly during equipment maintenance and repair or when system pressure must be relieved when the equipment works properly but there is a temporary upset condition.
An operator must receive approval from the BSEE regional supervisor to flare or vent natural gas, except in the circumstances specified above. Following the recommendations of the 2010 GAO report, the BSEE tightened the approval process, as communicated in NTL No. 2012-N04. This tightening led to a significant decrease in flare or vent approvals. NTL 2020-N04 supersedes previous NTLs on flaring and venting requests and states that the BSEE may approve flaring or venting on a case-by-case basis, with the following exceptions: The exception is in the national interest, such as when a major hurricane causes infrastructure damage. Bureau Interim Directive 2015-G070 requires that top BSEE management grant this exception. The operator claims that production from the well completion would likely be permanently lost if the well were to be shut in. According to Bureau Interim Directive 2015-G070, the BSEE’s resource conservation personnel must analyze necessary data from wells to confirm all such claims. The operator claims that short-term flaring or venting would likely yield a smaller volume of lost natural gas than if the facility were shut in and restarted later. According to Bureau Interim Directive 2015-G070, the BSEE’s resource conservation personnel must analyze necessary data from wells to confirm all such claims. According to Title 30 CFR § 250.1161, approval for an extended period is possible but cannot exceed one year. The BSEE may approve requests for extended periods of flaring if the operator can demonstrate actions that will eliminate flaring and venting or demonstrates that lease economics do not support investment in eliminating flaring or venting. According to the proposed EPA NSPS rule, flaring would be allowed only to eliminate venting of associated gas and only if the operator can demonstrate, as certified by a qualified third party, that it cannot access the market or use the associated gas in beneficial ways due to technical or safety reasons.
According to Title 30 CFR § 250.1160(b) , regardless of the exceptions, operators must not exceed the volume approved for flaring or venting in the Development Operations Coordination Document submitted to BOEM.
Following the recommendations of the 2010 GAO report , the BSEE implemented pilot studies with infrared cameras and, jointly with BOEM, conducted a study on the economic viability of further reductions by adopting various technologies. As a result, the agencies decided not to extend capture requirements to lease-use gas sources, pending further studies. The BSEE and BOEM also analyzed data from Gulfwide Offshore Activity Database System. They concluded that “flaring currently vented methane and replacing high-bleed pneumatic controllers with zero- or low-bleed pneumatic controllers would likely provide the greatest opportunities for meaningful and cost-effective emission reductions.” According to NTL No. 2020-N04 , the BSEE does not consider the avoidance of lost revenue as a justification for approving flaring or venting. For example, if gas production or transport infrastructure needs to be repaired and a well must be shut in during repairs, the BSEE will not allow operators to flare or vent gas to avoid shutting in the well and maintain the same pace of oil sales. Violations can result in civil or criminal penalties (see sections 18 and 19 of this case study).
According to Title 30 CFR § 250.1163, offshore facilities processing more than an average of 2,000 barrels of oil a day must install flare or vent meters. NTL No. 2012-N03 provides guidance on the BSEE procedures and requirements for installing meters. Measurements must be within 5 percent accuracy. Operators must use and maintain meters for the facility’s life. Meters must be calibrated regularly according to the manufacturer’s recommendation, or at least once every year, whichever is more frequent. All hydrocarbons produced from a well completion, including all gas flared or vented and liquid hydrocarbons burned, must be reported to the ONRR on Form ONRR-4054 (Oil and Gas Operations Report [OGOR]), per Title 30 CFR § 1210.102. Since September 15, 2010, leaseholders must specify the volumes of gas flared and vented separately in OGOR Part B. They must use different disposition codes for flared oil-well gas, flared gas-well gas, vented oil-well gas, and vented gas-well gas. The 2016 GAO report found that the ONRR’s guidance on reporting emissions from lost gas, whether flared or vented, lacked specificity. In reports, operators may classify gas used to operate lease equipment as lease-use gas. Where required, the amounts of gas flared and vented at each facility must be reported separately from that of facilities that do not require meters and separately from other facilities with meters. Flaring and venting from multiple facilities on a single lease or unit may be reported together.
Title 30 CFR Subpart N provides details on OCS civil penalties. The BSEE can impose such penalties if it determines that there is a violation (that is, a failure to comply with the Outer Continental Shelf Lands Act [see footnote 20] or its implementing regulations, any other applicable laws, or the terms of leases, licenses, permits, rights-of-way, or other approvals, including those for flaring or venting). The BSEE communicates the penalties, which are updated periodically, to operators. NTL 2023-N02 sets the maximum penalty of US$52,646 a day per violation, effective March 24, 2023. The NTL contains a matrix of three categories of violations from A to C, broadly increasing with the severity of safety or environmental impacts, resulting in three increasingly onerous government responses: warning, component shut-in, and facility shut-in. A warning for a category A violation has the lowest penalty, with an assessment starting point of US$19,685 a day per violation, but the actual penalty can drop below that. A facility shut-in enforcement for category C has the highest penalty, with an assessment starting point of US$48,640. If it is not paid, the facility can be shut in. Failure or refusal to permit inspections or audits may be penalized by a fine of up to US$10,000 a day per violation (Title 30 CFR § 250.1460). An appeal can be made within 60 days by providing a surety bond equal to the assessed penalty amount or higher. Delayed payments without an appeal will accrue interest, late payment, and other applicable fees (Title 30 CFR § 250.1409). The Methane Emissions Reduction Program includes a methane penalty as its central element , which starts at US$900 per tonne of methane in 2024 and increases to US$1,200 in 2025, and US$1,500 in 2026 and each year thereafter. The penalty applies to oil and gas facilities with annual methane emissions of at least 25,000 tonnes of carbon dioxide equivalent. Companies will start paying penalties in 2025 based on the previous year’s emissions. According to a report by the Congressional Research Service, Inflation Reduction Act Methane Emissions Charge: In Brief, 2,172 facilities that submit data to EPA’s Greenhouse Gas Reporting Program will be subject to the methane penalty.
Title 30 CFR § 250.1409 provides for further sanctions if penalties are not paid. They may include the cancellation of the lease, right-of-way, license, permit, or approval; the forfeiture of a bond; or the barring of the violator from doing further business with the federal government. The BSEE enforcement tools include component or facility shut-in if there is an immediate threat to safety and environment or operators fail to correct previously identified violations or pay assigned penalties.
US environmental law includes detailed requirements for flare design. Title 40 CFR § 60.18 provides general requirements for flares; other subparts include more details. Title 40 CFR § 63.987 requires a flare compliance assessment, provides certain technical details, and refers to other sections of the law for submitting flare compliance assessments (§ 63.999(a)(2)) and keeping records (§ 63.998(a)(1)). Title 40 CFR § 63.11 provides detailed performance requirements for flare design. For example, there should be no visible emissions, except for periods not to exceed a total of five minutes during any two consecutive hours; a flame should always be present; and the heat content of gas and the exit velocity must be calculated using the formulas provided in § 63.11. Taken together, environmental regulations require that flares be operated and maintained in a manner consistent with “good air pollution control practices,” typically interpreted to mean a combustion efficiency of 98 percent. Title 40 CFR § 63.11 also provides alternative practices for monitoring leaks. Standard practices for monitoring leaks are provided in other parts of Title 40, including § 60, which apply to any stationary source subject to the NSPS, and § 61 and § 63, which apply to hazardous air pollutants. Appendix A-7 of § 60 details calculation methodologies for all regulated emissions, including volatile organic compound leaks, that are applicable for a diverse set of facilities. The proposed EPA NSPS rule also has performance requirements such as continuous monitoring of the pilot flame. If a flare failure causes a “super-emitter” methane event, the operator is required to bring the flare into compliance promptly under the Super-Emitter Response Program.
If flaring or venting occurs without the required approval, or the BSEE regional supervisor determines that the operator was negligent or could have avoided flaring or venting, the hydrocarbons are considered avoidably lost or wasted and subject to royalties (12.5 percent in old leases, 16.67 percent in shallow waters, and 18.75 percent in deep water), according to Title 30 CFR § 1202. Operators must value any gaseous or liquid hydrocarbons avoidably lost or wasted under the provisions of Title 30 CFR § 1206. Fugitive emissions from valves, fittings, flanges, pressure relief valves, or similar components do not require approval under this subpart unless specifically required by the regional supervisor. The BSEE Resource Conservation Section is responsible for informing the ONRR about noncompliance with regulations resulting in a loss of hydrocarbons from flaring or venting that could have been avoided and the volumes involved. Section 50263 of the Inflation Reduction Act declares that, for all federal leases issued after August 16, 2022, royalty is due on all produced gas except “(1) gas vented or flared for not longer than 48 hours in an emergency situation that poses a danger to human health, safety, or the environment; (2) gas used or consumed within the area of the lease, unit, or communi̬tized area for the benefit of the lease, unit, or communi̬tized area; and (3) gas that is unavoidably lost.”
No evidence regarding the use of market-based principles to reduce flaring, venting, or associated emissions from the Gulf of Mexico could be found in the sources consulted. There is no national carbon tax or market in the United States. The carbon dioxide cap-and-trade market in California covers oil and gas operations there. An increasing number of states are pursuing cap-and-trade markets, but typically not in states with large oil and gas production. The petroleum industry supports a carbon tax but not if there are also new methane and other emissions regulations.