Alberta equivalency with federal methane regulations: emissions reduction estimation

As part of the Pan-Canadian Framework on Clean Growth and Climate Change, the Government of Canada reaffirmed its commitment to reduce methane (CH₄) emissions from the oil and gas sector by 40% to 45% from 2012 levels by 2025.^{Footnote 1}  Methane is a potent greenhouse gas (GHG) that is at least 25 times more powerful than carbon dioxide (CO₂) over a 100-year period, and methane emissions constitute approximately 15% of Canada’s total GHG emissions. The oil and gas sector is the largest contributor to methane emissions in Canada.

In April 2018, Environment and Climate Change Canada (ECCC) published federal methane regulations to deliver on this commitment. The Regulatory Impact Analysis Statement (RIAS) assessed the impacts of the regulations, including GHG emissions reduction estimates.^{Footnote 2}  This analysis used Canada’s official GHG emissions projections as reported in Canada’s 2016 Greenhouse Gas Emissions Reference Case. ECCC has since updated its estimates of GHG emissions reductions to reflect departmental projections, as reported in Canada’s GHG and Air Pollutant Projections: 2018.^{Footnote 3}  A summary of the emissions estimation methodology and the resulting emission reduction estimates follows below.

Emissions estimation methodology - federal regulations

The analysis estimated methane emission reductions by first developing detailed engineering emissions estimates for the baseline and regulatory scenarios, and then scaling these to ECCC’s overall emission estimates for the oil and gas sector in order to ensure that the estimates are consistent.

To calculate venting and fugitive gas reductions, baseline and regulatory emission factors for the various standards and product types were multiplied by the total number of devices or facilities for the respective standard. This procedure calculates the total amount of gas that will be emitted with and without the regulations. The difference between the emissions in the baseline scenario and the regulatory scenario were used to estimate the incremental reductions.

The sources for the emission factors differ for each standard:

• for facility production venting requirements, provincial data on facility venting and flaring volumes were used to estimate the baseline emissions, and compared to the required reductions as per the regulations

• for leak detection and repair (LDAR), the emission factors were derived from the 2018 Clearstone Engineering emission factor study, and modified using a method described in the United States Environment Protection Agency (U.S. EPA) Protocol for Equipment Leak Emission Estimates^{Footnote 4}

• for pneumatic devices, emission factors were developed based on a 2013 engineering assessment of pneumatic devices by the Prasino Group in conjunction with supplemental information from the 2018 Clearstone Engineering emission factor study and a 2018 Spartan Controls report,^{Footnote 5}

• for reciprocating compressors, the emission factors were estimated using a dataset from Target Emission Services

• for centrifugal compressors, the emission factors were obtained from an engineering assessment of compressors undertaken in 2017 by the American Petroleum Institute,^{Footnote 6}   and

• for glycol dehydrators, the analysis used emission factors derived by the Alberta Energy Regulator

To determine emissions of the various pollutants contained in emitted gases, estimates of gas composition were obtained from a 2014 Clearstone Engineering report,^{Footnote 7}  with the exception of gas from facility production venting and flaring, as these composition ratios were obtained from a combination of reports from provinces.^{Footnote 8}  To obtain the amounts of CO₂, CH₄ or volatile organic compounds (VOCs) reduced, the natural gas reductions were multiplied by the composition ratios for each production type.

The engineering emission estimates were then scaled to align with the departmental baseline emissions forecasts. Departmental baseline emission projections for the oil and gas sector were determined using the production forecast of oil and gas from the Canada Energy Regulator, in combination with the national inventory report. These departmental projections were developed in the Energy, Emissions and Economy Model for Canada (E3MC), one of ECCC’s models for estimating GHG emission trends and regulatory impacts in Canada.

The engineering estimates were used to derive a baseline for all fugitive and venting emissions, which was calculated for 4 sectors: natural gas production, natural gas processing, heavy oil mining, and light oil mining. These baseline estimates were then compared to the departmental baseline emissions forecast for sectors to obtain a set of ratios, or scaling factors, as follows:

Scaling Factor_{sector.province} = E3MC Baseline Emissions_{sector.province} / Engineering Baseline Emissions_{sector.province}

These scaling factors were then applied to the engineering reduction estimates for each pollutant and for estimates of conserved gas to derive final incremental estimates for the regulations.

Emissions estimation methodology - Alberta regulations and directives

In December 2018, the Alberta Energy Regulator made amendments to Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting Directive and Directive 017: Measurement Requirements for Oil and Gas Operations (the Alberta directives), which put in place requirements for methane emissions reductions.^{Footnote 9}  These requirements are incorporated by reference in the Methane Emission Reductions Regulation (together with the Alberta directives referred to as the Alberta regulation), which was registered in December 2018.^{Footnote 10}  In May 2020, further amendments were made to the Alberta directives to increase the stringency and move forward the implementation dates of certain provisions.

Similar to the federal regulations, the Alberta regulation introduce control measures to reduce fugitive and venting emissions of methane from the upstream oil and gas sector. The Alberta regulation differs from the federal regulations in that control measures are more stringent for new facilities starting in 2022. Additionally, the Alberta regulation contain more stringent requirements for pneumatic controllers and introduce specific requirements for glycol dehydrators. The Alberta regulation allow a lower leak detection frequency at some facility types and contains less stringent routine venting and pneumatic pump requirements.

Emission reductions estimates

In order to demonstrate the equivalency of outcomes between the Alberta regulation and the federal regulations, ECCC has modelled the federal regulations using the departmental reference case as published in Canada’s GHG and Air Pollutant Projections: 2018 and has modelled the Alberta regulation using the same methodology and data.

ECCC estimated the methane emission levels that would occur under both the Federal Regulations and Alberta regulation. Table 1 shows the methane emission reduction estimates attributed to both the federal regulations and the Alberta regulation. Over the 5-year assessment period, this analysis determined that cumulative emission reductions are 18.60 Mt CO₂e for the Alberta regulation compared to 18.71 Mt of CO₂e for the federal regulations. These estimates differ by 0.6%, and are considered equivalent given the sensitivity range of modelled results.

Note: numbers may not add up due to rounding.

As illustrated in table 2, for the longer-term period of 10 years (January 1, 2020 to December 31, 2029), the Alberta regulation achieves methane emission reductions of 57.28 Mt CO₂e for the Alberta regulation compared to 56.48 Mt CO₂e for the federal regulations.

Note: numbers may not add up due to rounding.