Country

Assessment

Section 20 of the preceding case study, on US federal offshore production, covers national environmental regulations with performance requirements applicable to flares. For onshore operations, Title 43 CFR § 3179 required operators to find and repair leaks at least twice a year. However, a court vacated Subpart 3179 in 2020. One of the litigants’ concerns was that the cost of adding equipment for leak detection would be too high for many small operators. The proposed rule reinstates Subpart 3179, which has performance requirements with respect to safe operation of flares, limits on flared and vented volumes under various circumstances such as well completions. Subpart 3179.301 of the proposed rule requires operators to maintain a leak detection and repair program, which will be subject to annual (or more frequent) inspections. Any leak must be repaired as soon as practicable but no later than 30 days after its discovery (Subpart 3179.302). Operators must provide a report on each inspection as well as an annual report (Subpart 3179.303).

According to NTL-4A , unavoidably lost production (see section 9 of this case study) is exempt from royalty calculations. BLM officers may determine that lost production was caused by failure to comply fully with the applicable lease terms and regulations, or appropriate provisions of the approved operating plan. Avoidable losses are subject to royalty. Set by law in 1920, the minimum royalty rate on federal onshore is 12.5 percent. The BLM’s 2016 Waste Prevention Rule  introduced several conditions that create additional incentives. For example, it detailed the economic justification necessary for operators to demonstrate that capture is uneconomic and introduced a limit of 10 mmcf per well a month. Above this limit, the BLM may determine that gas is avoidably lost and hence subject to royalty. The 2016 rule also required that an action plan show how the operator will minimize the flaring or venting of the oil-well gas within one year. An operator may apply for approval of an extension of the one-year limit. If the operator fails to implement the action plan, the entire volume of gas vented or flared during the time covered by the action plan is subject to royalty. The BLM rescinded these requirements in 2018. Under the proposed rule, with the APD requirement (see section 11 of this case study), qualification as unavoidably lost production is expected to be more difficult.

No evidence regarding the use of market-based principles to reduce flaring, venting, or associated emissions could be found in the sources consulted. See section 22 of the case study on US federal offshore production.

For a description of the US natural gas market and infrastructure development, see section 24 of the case study on US federal offshore production. For onshore operations, the BLM’s proposed waste minimization plan (see section 11 of this case study) was intended to guide operators to work with midstream companies to identify sufficient pipeline and processing capacity near the planned drilling site so that associated gas can be captured from the first day of production. The previous US administration rescinded this requirement. The current one may reintroduce it or something similar.

In the early 2010s, the North Dakota Petroleum Council’s Flaring Task Force targeted capturing 74 percent of associated gas in 2014, gradually increasing to 90 percent by late 2020; it proposed 95 percent as a potential target beyond 2020. The North Dakota Industrial Commission (NDIC) Order 24665, 2014, operationalized these targets, raising the 2020 target to 91 percent in 2018.

The Oil and Gas Division of the North Dakota Department of Mineral Resources regulates the drilling and production of oil and gas in the state (including drilling permits and gas capture plan), but the NDIC has jurisdiction over flaring and venting. DAQ , regulates emissions from upstream, midstream, and downstream oil and gas operations. The BLM and the EPA, and, in some cases, tribal authorities have authority over oil and gas operations on federal and Indian lands.

North Dakota Century Code Section 38-08-06.4, allows gas flaring from oil wells up to one year from first production. The venting of casinghead gas is not allowed under any circumstances; instead, operators must have equipment in place to flare.

According to North Dakota Century Code Section 38-08-06.4 , after the first year of production, flaring must cease. The operator can cap the well, connect it to a gathering system, increase the use of associated gas, or use the gas in any other beneficial action approved by the NDIC. Operators may apply for a flaring exemption if the connection of a well to a natural gas gathering line is economically infeasible. DAQ has an independent permit application for flares associated with air quality and the control of pollutants for oil or gas production facilities classified as a major stationary source or a major modification.

Order 24665, 2014 , requires upstream operators to submit a gas capture plan with every drilling permit application to the NDIC. Gas capture plans must include information on area gathering system connections and processing plants, the rate and duration of planned flowback, current system capacity, and a timeline for connecting the well. They must also include a signed affidavit verifying that the plan has been shared with area midstream companies. The NDIC allows production from horizontal wells in Bakken and Three Forks Pools for up to 90 days (one year in noncore areas) at the maximum efficiency rate irrespective of flaring volumes. After 90 days, the operator should either meet gas capture goals or limit production. NDIC Order 24665, 2014, provides flexibility in the form of temporary exemptions from production restrictions for up to one year if an operator files a request and provides the necessary documentation. The NDIC may consider further flexibility under other extenuating circumstances after notifying the operator and hearing whether the exemption is expected to result in a significant net increase in gas capture within a year. The NDIC has also implemented a gas capture credit system (see section 22 of this case study).

According to Order 24665, 2014 , well payouts and economics should not be used to determine the production restrictions imposed on operators that do not comply with gas capture plans. At the same time, the order allows for the maximum efficient rate of oil production in many circumstances. The NDIC tries to distinguish between operators that are connected to gathering systems but flare and those that flare because of midstream bottlenecks. Over the years, the NDIC policy and regulation have shifted toward encouraging investment in midstream infrastructure. Nevertheless, the comparison of the value of oil and the value of associated gas if captured remains central to operators’ decisions to invest in capture infrastructure and the NDIC’s assessment of drilling applications and flaring exemptions.