Country
Assessment
Chapter 10 of the Flaring and Venting Reduction Guideline states the requirements for measuring and reporting volumes of gas flared, incinerated, or vented. These requirements are in addition to the requirements specified in the Measurement Guideline for Upstream Oil and Gas Operations, 2020; Oil and Gas Activity Operations Manual, 2020; the Oil and Gas Royalty Handbook, 2014; and the Drilling and Production Regulation, 2010 . Permit holders of oil and natural gas production and processing facilities must report volumes of gas greater than or equal to 100 m³ a month that are flared, incinerated, or vented in Petrinex. For royalty calculation purposes, these volumes are also reported through the BC-S2 or BC-19 forms of the Ministry of Finance. All flaring, incinerating, and venting from routine operations; emergency conditions; and depressurizing pipelines, compressors, and processing systems must be disclosed. Gas used for a pilot, a purge, or a blanket must be reported as either flared or vented. The Greenhouse Gas Emissions Reporting Regulation, 2015, details the conditions and criteria for the mandatory reporting of GHG emissions by operators. Operators that emit more than 10,000 tCO2e a year must collect and report data on their emissions to the BCER. Submissions must be based on a process-flow diagram and include emissions from flaring, venting, and other fugitive emissions. The regulation also establishes verification bodies to evaluate reports from operators.
The cumulative volume of flaring authorized for well workover or maintenance operations cannot exceed 50,000 cubic meters (m³) in a year. There are also various limits on flared volumes that trigger different reporting. British Columbia’s new methane regulations are designed to reduce methane emissions by 10.9 million tonnes of carbon dioxide equivalent (tCO2e) over a 10-year period starting in 2020.
British Columbia’s Flaring and Venting Reduction Guideline does not allow routine venting except under “the most exceptional circumstances.” If gas volumes are sufficient to sustain stable combustion, the gas should be flared or conserved. If venting is the only feasible alternative, it should meet the following requirements, set out in chapter 7 of the guideline: All continuous and temporary venting and their sources must be evaluated using the vent evaluation decision tree. Permit holders must burn all nonconserved volumes of gas if volumes and flow rates are sufficient to support stable combustion. The quantity and duration of vented gas must be minimized. A permit holder must have an adequate program for managing fugitive emissions. According to Section 1.10 of the guideline, entitled “Approvals and Notifications for Non-Conserving Facilities,” nonroutine flaring (such as for maintenance and emergencies) does not require a specific approval but may be subject to limitations specified in the facility permit. Permit holders should notify residents and the BCER of nonroutine flaring at facilities.
Chapter 2 of the Flaring and Venting Reduction Guideline on temporary flaring approval for well testing, states that flaring for purposes other than those previously specified in Chapter 1, including well testing, must be approved in the facility permit. Approval to flare may be requested in the well permit application or by amending the well permit. The Drilling and Production Regulation, 2010 , authorizes flaring at wells if the flaring is in line with the well’s permit or is related to drilling operations and is necessary because of an emergency. Flaring is also authorized for well workover or maintenance operations and when the cumulative quantity of flared gas does not exceed 50,000 m³ a year. Section 43 of the Drilling and Production Regulation, 2010, on flaring notification and reporting, requires a permit holder to notify the BCER at least 24 hours before a planned flaring event if the quantity of gas to be flared exceeds 10,000 m³. If an unplanned flaring event occurs and the amount of flared gas exceeds 10,000 m³, the permit holder should notify the BCER within 24 hours.
No evidence regarding development plans could be found in the sources consulted.
Section 1.8 of the Flaring and Venting Reduction Guideline on economic evaluation of gas conservation, is similar to Section 2 of Alberta’s Directive 060 (see section 12 of the case study on Alberta). British Columbia’s guidance considers a solution gas conservation project with a net present value of less than Can$50,000 (about US$36,760 as of May 2023) uneconomic. The project economics should be reevaluated annually (within 12 months of the last evaluation) using updated prices, costs, and forecasts.
Most gas production in British Columbia is exported to other provinces or the United States via pipelines. Gas production increasingly comes from remote unconventional resource basins, such as the Montney and Horn River in the northeast corner of the province, which are far from consuming regions. The coordination of drilling activity with the development of sufficient midstream capacity can avoid bottlenecks in transport capacity and hence reduce flaring. The regulator encourages producers and third parties to pursue such coordination of midstream capacity and new production.
The Administrative Penalties Regulation, 2011 , establishes that a person who contravenes various responsibilities related to flaring and venting (Sections 42–44 of the Drilling and Production Regulation, 2010; see footnote 19) is subject to fines ranging from Can$20,000 (about US$16,000 as of September 2021) to Can$250,000 (about US$200,000 as of September 2021).
British Columbia has fiscal incentives in place to induce the lease use or marketing of associated gas. There are two broad classifications for calculating natural gas royalties: conservation gas and nonconservation gas. Conservation gas is natural gas that has been produced as part of oil production that is conserved and marketed instead of flared. All other gas is considered nonconservation gas. Section 5 of the Oil and Gas Royalty Handbook, 2014 , shows how royalties are calculated under various gas prices and well classifications. Royalties paid for conservation gas are often as low as 8 percent, compared with up to 27 percent for nonconservation gas. This difference in royalty rates creates an incentive for producers to capture and market associated gas. In addition, according to Section 5.9 of the handbook, natural gas or by-products used for production, drilling, or re-injection are exempt from royalties and production taxes. Gas lost is also exempt from royalty and tax if the regulator deems that the loss is not the fault of the producer and the producer does not receive any compensation for the loss (for example, insurance proceeds). The lost gas includes flared and vented volumes.
The BCER is the sole provincial regulatory agency responsible for overseeing oil, gas, and geothermal operations as defined by the Oil and Gas Activities Act, 2008 . It is governed by a board of directors that sets the strategic direction and establishes accountability and transparency, including corporate risks, as part of the strategic planning process. The board has the power to create regulations concerning oil and gas activities. The BCER, in consultation with stakeholders, monitors progress to reduce the volume of solution gas that is flared or vented. When BCOGC was renamed BCER in early 2023, new board positions were added for a total of five to seven directors (previously, there were three directors). The board must now include indigenous representation.