Vol. 151, No. 21 — May 27, 2017

Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector)

  • Statutory authority
    • Canadian Environmental Protection Act, 1999
  • Sponsoring departments
    • Department of the Environment
      Department of Health

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the regulations.)

Executive summary

Issues: The releases of volatile organic compounds (VOCs), which include petroleum and refinery gases (PRGs), from facilities in the petroleum and petrochemical sectors pose health and environmental risks to Canadians. The primary source of fugitive VOC releases is leaks from processing equipment components.

Volatile organic compounds are primary precursors to the formation of ground-level ozone (O3) and particulate matter (PM), which are the main constituents of smog. Smog is known to have adverse effects on human health and the environment. In addition, PRGs can potentially contain carcinogenic (cancer-causing) substances such as 1,3-butadiene, benzene and isoprene. Volatile organic compounds, PRGs and those carcinogenic substances are all on the List of Toxic Substances in Schedule 1 to the Canadian Environmental Protection Act, 1999 (CEPA).

A number of regulatory and non-regulatory measures are already in place in some Canadian provinces to limit fugitive VOC releases from facilities in the petroleum and petrochemical sectors. Generally, these measures institute leak detection and repair (LDAR) programs that mainly focus on large leaks and require annual inspections for most equipment components. This approach could allow large leaks to continue for long periods of time before they are detected and repaired. Timely detection and repair of large and small leaks is critical, because even low concentrations of the carcinogenic components of PRGs can cause harm to human health. Therefore, the existing measures are deemed inadequate to minimize human exposure to the greatest extent practicable.

Description: The proposed Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector) [the proposed Regulations] would require the implementation of comprehensive LDAR programs at Canadian petroleum refineries, upgraders and certain petrochemical facilities. The operators of these facilities would also be required to modify certain equipment components to prevent leaks and to monitor the level of certain VOCs at facility perimeters.

Cost-benefit statement: The proposed Regulations are expected to reduce VOC releases by approximately 102 kilotonnes (kt) and greenhouse gas (GHG) emissions by 43 kt of carbon dioxide equivalent (CO2e) for the years 2017 to 2035. The present value (PV) of the benefits is estimated at $313 million (M), largely due to improved human health. The PV of the costs is estimated at $254M, largely due to the inspection and repair of leaking equipment components. Overall, the proposed Regulations are expected to yield a net benefit of $59M with a benefit-cost ratio of 1.2:1. The proposed Regulations are not expected to impact the competitive positions of the affected facilities.

“One-for-One” Rule and small business lens: This regulatory proposal is expected to result in annualized administrative burden costs of approximately $179,664 for all affected facilities for the years 2018 to 2027, or $6,910 per facility, and would be new regulations. Therefore, it is an “IN” under the “One-for-One” Rule. (see footnote 1) These costs are associated with activities that are necessary to ensure the overall effectiveness of the proposed Regulations, such as reporting and record keeping. Measures such as single-window reporting are being considered in an attempt to further reduce the administrative burden. No small business is expected to be affected by the proposed Regulations.

Domestic and international coordination and cooperation: The proposed Regulations unify Canada’s current patchwork of measures in a single modernized framework. They are broadly aligned with U.S. regulations, while giving due consideration to circumstances that are specific to Canada, such as inclement winter weather. To ensure that the competitive positions of regulated facilities are not compromised, while still delivering significant air quality improvements to Canadians, CEPA authorizes provinces to enter into equivalency agreements where appropriate. The proposed Regulations would also support the objectives of the Canada–United States Air Quality Agreement.

1 Background

Petroleum and refinery gases are released as part of mixed streams of VOCs in fugitive leaks from processing equipment components in the petroleum and petrochemical sectors. (see footnote 2) Reducing VOC releases in those sectors will result in fewer releases of PRGs and carcinogenic substances.

1.1 Petroleum and refinery gases and carcinogens

The Chemicals Management Plan (CMP) is a Government of Canada initiative aimed at reducing the risks posed by chemicals to Canadians and the environment. One such group of chemicals consists of PRGs, which are a category of light hydrocarbons produced by facilities such as refineries and upgraders. In 2013, the Government of Canada (the Government) conducted a peer-reviewed screening assessment of PRGs and found that they can potentially contain known carcinogenic substances such as 1,3-butadiene, benzene and isoprene (substances that were assessed by the Government and determined to be harmful to human health (see footnote 3), (see footnote 4)). The National Pollutant Release Inventory reports that Canadian refineries, upgraders and petrochemical facilities are known to release components of PRGs into the surrounding environment, including the carcinogens 1,3-butadiene, benzene and isoprene. It is expected that increased releases of carcinogenic substances from these facilities would increase cancer risks for Canadians in the vicinity of those facilities.

1,3-Butadiene can damage the genetic information (e.g. DNA) within a cell and cause mutations, which may lead to cancer (genotoxicity). As well, 1,3-butadiene has been found to be a carcinogen in rodents, and epidemiological studies have provided further evidence for an association between exposure to 1,3-butadiene and leukemia in humans. The assessment of 1,3-butadiene indicated that the investigation of options to reduce exposure for those in the vicinity of industrial sources should be a high priority.

Benzene is known to cause cancer, based on evidence from studies in both people and laboratory animals. Studies examining the link between benzene and cancer have largely focused on leukemia and other cancers of blood cells. The assessment of benzene indicated that the examination of options to reduce exposure should be a high priority and that such exposure should be reduced wherever possible.

Similarly, on the basis of carcinogenicity, it was concluded that isoprene was toxic to human health. The risk management objective for isoprene is to reduce exposure to isoprene from industrial emissions to the extent practicable.

Using 1,3-butadiene as a high-hazard component to characterize potential exposure to the general population, the assessment concluded that PRGs were toxic to human health. It was recognized that a small portion of the general population may be exposed to these gases and their carcinogenic components in the vicinity of certain petroleum facilities. The proposed human health objective for the management of PRGs is to minimize human exposure to the greatest extent practicable.

1.2 Volatile organic compounds

Petroleum and refinery gases belong to the broader category of VOCs, which are precursors to the formation of ground-level O3 and PM, the main constituents of smog. Both ground-level O3 and PM, in particular fine particulate matter smaller than or equal to 2.5 micrometers in diameter (PM2.5), have been shown to be detrimental to human health, and exposure to these pollutants increases the risks for a wide range of health problems.

Exposure to ground-level O3 is associated with a variety of health effects, including premature mortality. Medical evidence is especially persuasive for the harmful effects of ground-level O3 on lung function and its contribution to respiratory symptoms and inflammation. There exists a significant association between short-term exposure to ground-level O3 and emergency room and hospital visits related to respiratory system problems (especially asthma-related) and premature mortality. Exposure to ground-level O3 could also result in some cardiac effects, adverse long-term respiratory impacts and chronic-exposure mortality.

Ground-level O3 may also interfere with the ability of sensitive plants to produce and store food, and increase their vulnerability to certain diseases, insects, harsh weather and other pollutants.

Epidemiologic evidence continues to confirm earlier observations of harm from PM and PM2.5. This includes confirmation of mortality from long-term exposure to PM2.5 and the link to adverse cardiac outcomes, both from acute and chronic exposures. Additionally, there is a robust relationship between PM2.5 and lung cancer mortality. Research suggests that PM2.5 is linked to morbidity through a range of adverse effects, including respiratory symptoms, bronchitis (both acute and chronic), asthma exacerbation and respiratory impacts. This results in a greater number of restricted activity days, emergency room visits, hospital admissions and premature mortality.

Several population groups are particularly susceptible to adverse effects following exposure to ground-level O3 and PM2.5. These include individuals who are more active outdoors, children, the elderly (especially those with a pre-existing respiratory or cardiac condition) and individuals who are hypersensitive to respiratory irritants. It is likely that the entire population is at some degree of risk even at the lowest concentration levels of ground-level O3 and PM2.5.

Particulate matter may also accumulate on surfaces and alter their optical characteristics. It can also reduce visibility by blocking and scattering the direct passage of sunlight through the atmosphere.

1.3 Affected facilities in the petroleum and petrochemical sectors

Twenty-six facilities are expected to be affected by the proposed Regulations. These facilities produce liquid petroleum products by means of processing (using distillation) crude oil or bitumen, or partially refined feedstock derived from crude oil or bitumen. They include 18 petroleum refineries, 6 upgraders and 2 petrochemical facilities.

Eighteen refineries are expected to be affected by the proposed Regulations, one of which is scheduled to begin operations in 2017. They are located in seven provinces, with the majority in Alberta and Ontario. These refineries produce transportation fuels, with gasoline being the major product, by processing conventional crude oil or synthetic crude oil (SCO). They also produce home heating oils, lubricants, heavy fuel oil, asphalt for roads and feedstocks for petrochemical plants. Most of these refined products serve the domestic market, but some are exported, mainly to the United States.

There are six upgraders in Canada, five of which are located in Alberta and one in Saskatchewan. One facility in Alberta shut down its upgrading capacity due to an explosion in January 2016. It is not clear when this facility will resume its activities. Nonetheless, it is assumed that all six upgraders would be affected by the proposed Regulations. Upgraders convert bitumen or heavy oil mainly into synthetic crude oil, but also into refined petroleum products such as diesel and kerosene. (see footnote 5) Most facilities are integrated or associated with oil sands extraction processes. The majority of SCO is exported to the United States, although some is transported to domestic refineries. (see footnote 6)

Two integrated petrochemical facilities, one in Ontario and one in Alberta, are expected to be affected by the proposed Regulations. Petrochemical facilities convert refined petroleum feedstock, natural gas, or natural gas liquids into primary petrochemical products that are used to manufacture a variety of industrial and consumer products such as plastics. Petrochemical products include ethylene, styrene, propylene, benzene and butadiene. These products are either sold to domestic chemical manufacturing plants, or are exported (mainly to the United States).

1.4 Control of fugitive VOC releases in Canada (see footnote 7)

Leak detection and repair programs constitute the best practice for effectively controlling fugitive VOC releases from petroleum and petrochemical facilities, according to industry experience and the experience of other regulatory agencies. Most facilities affected by the proposed Regulations have already implemented LDAR programs in some form.

In order to address VOCs as smog precursors, the Canadian Council of Ministers of the Environment (CCME) published a voluntary code of practice in 1993 (the CCME Code). (see footnote 8) This Code aimed at establishing a consistent method for the control of fugitive VOCs from leaking equipment components through LDAR programs. It recommends one inspection per year for most equipment components, such as valves and pumps, and four inspections per year for compressors, which have a greater likelihood of leaks. The CCME Code also recommends that portable monitoring instruments (“sniffers”) be used for inspection in accordance with the U.S. Environmental Protection Agency (U.S. EPA) Method 21. (see footnote 9) Under the CCME Code, a “significant leak” consists of the detection of a VOC concentration greater than or equal to 10 000 parts per million by volume (ppmv), measured at the source. The CCME Code recommends repair for significant leaks within 15 days of detection.

A number of provincial and municipal regulators, as well as an industry association, have subsequently used the CCME Code as a basis to develop their own control measures. For example, the Greater Vancouver Regional District has the same inspection requirements as the CCME Code, except that equipment components leaking at 1 000 ppmv or above must be repaired within 90 days of detection.

The Quebec Clean Air Regulation requires quarterly inspections during the months of April to December for pumps, agitators and compressors, but annual inspections for other equipment components, with some exceptions. (see footnote 10) The significant leak threshold is 1 000 ppmv for equipment components containing any level of benzene or butadiene and 10 000 ppmv otherwise. If a leak contains 10% or more benzene or butadiene, then it must be repaired within 15 days of detection; for a leak containing less than 10% of those substances, it must be repaired within 45 days.

The Ontario industry standards (see footnote 11) require three inspections per year for equipment components that are in contact with fluid containing certain levels of benzene or 1,3-butadiene. The threshold levels of benzene or 1,3-butadiene will be lowered over time, which will result in more equipment components being subject to inspection. The permitted time for repairing leaks of 1 000 ppmv or more depends on the leak concentration and is shortened over time. In addition, a sniffer must be used for at least one inspection per year, while optical gas imaging (OGI) cameras are permitted to be used for other inspections. Sampling locations along the facility perimeters (i.e. fenceline monitoring) must be installed and samples collected at these sampling locations in accordance with the U.S. EPA’s Method 325A. Samples must be analyzed to determine the concentrations of benzene (for petroleum refineries) or benzene and 1,3-butadiene (for petrochemical facilities) in the air at the facilities in accordance with the U.S. EPA’s Method 325B. (see footnote 12), (see footnote 13)

The Canadian Fuels Association (CFA) developed a voluntary code of practice for its members. It recommends an annual inspection of equipment components, with a few exceptions, and the repair of any equipment components leaking at 10 000 ppmv or above within 90 days of detection.

1.5 Control of fugitive VOC releases in the United States

The U.S. EPA introduced LDAR requirements under the Clean Air Act in the mid-1980s. These requirements have been updated periodically and were revised significantly in 2007. (see footnote 14)

Generally, U.S. petroleum refineries and petrochemical facilities (see footnote 15) are required to conduct monthly inspections, with significant leak thresholds ranging from 500 ppmv (for most valves, connectors and pressure relief devices) to 2 000 ppmv (for most pumps). For certain types of equipment components, the inspection frequency (number of inspections) can be reduced if the number of leaks detected is consistently low. Repairs are required to be started within 5 days and completed within 15 days, unless the repair is not feasible without a process unit shutdown.

Beginning in 2018, U.S. refineries will be required to implement a “fenceline monitoring” program to measure the concentration of benzene around the perimeter of the facility and to take corrective action if the concentration exceeds a defined threshold. The procedures for collecting and analyzing samples to determine the benzene concentration are set out in U.S. EPA Methods 325A and 325B.

In addition to coming under the federal regulations, approximately 112 U.S. refineries are covered by consent decrees under the U.S. EPA’s Petroleum Refinery Initiative. (see footnote 16) These consent decrees include additional facility-specific measures to address VOC releases, including LDAR requirements that are more stringent than the federal regulations. Many states (including California, Texas and Louisiana) have also implemented their own regulations.

2 Issues

Releases of VOCs, including PRGs, from processing equipment components in the petroleum and petrochemical sectors contribute to the formation of smog, and thus air pollution in Canada. Air pollution has been shown to have a significant adverse impact on human health, including premature deaths, hospital admissions and emergency room visits. Studies indicate that air pollution is associated with an increased risk of lung cancer and heart disease. In addition to smog formation, PRGs can contain carcinogenic VOC substances such as 1,3-butadiene, benzene and isoprene.

Most existing mandatory or voluntary measures for managing VOC releases focus on controlling large leaks from certain types of equipment components. However, smaller leaks are also an issue, because even low concentrations of the carcinogenic components of PRGs can cause harm to humans.

3 Objectives

The objectives of the proposed Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector) are to

  • reduce fugitive VOC releases from equipment leaks at petroleum refineries, upgraders and certain petrochemical facilities in Canada;
  • provide protection for human health by minimizing, to the greatest extent practicable, exposure to carcinogenic components contained in PRGs;
  • improve human health and environmental quality by reducing smog formation;
  • promote a level playing field through nationally consistent VOC and PRG risk management measures; and
  • harmonize these measures, to the extent possible, with existing measures in other jurisdictions (e.g. provinces, municipalities and the United States).

4 Description

In general, the proposed Regulations would apply to petroleum refineries, upgraders and certain petrochemical facilities. The proposed Regulations would require that the operator of each affected facility

  • implement an LDAR program;
  • put in place preventive equipment requirements;
  • monitor the concentration of certain VOCs at the facility perimeter; and
  • undertake record-keeping and reporting activities.

Concurrently with the proposed Regulations, the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) [the Designation Regulations] would be amended. (see footnote 17) The amendment would designate certain provisions in the proposed Regulations that refer to an increased fine regime for successfully prosecuted offenses involving harm, or risk of harm, to the environment, or obstruction of authority.

4.1 LDAR program

The proposed Regulations would require that facility operators implement an LDAR program, which would include maintaining an inventory of equipment components, undertaking inspections and repairing leaks.

  • Inventory of equipment components: Operators would be required to maintain an up-to-date inventory of all equipment components in a system, if any part of the system comes into contact with a fluid that contains 10% or more VOCs by weight.
  • Inventory exclusions: Certain equipment components would be excluded from the inventory, given low likelihoods of VOC releases, including certain leakless equipment components and equipment components that operate under vacuum conditions.
  • Inspection frequency: Operators would be required to complete three inspections per year of all equipment components in the inventory, except for equipment components that are designated as “unsafe to inspect” and certain pumps that are equipped with a dual mechanical seal system. Operators would also be required to complete weekly visual inspections of all pumps in their inventory.
  • Leak detection: Operators would be required to conduct inspections using sniffers in accordance with U.S. EPA Method 21 or using optical gas imaging (OGI) cameras.
  • Training: Inspectors would be required to complete training in the use of leak detection instruments and in conducting leak inspections using those instruments, prior to conducting inspections.
  • Leak repair: Operators would be required to quantify any identified leak, using a sniffer, before any repairs are made. Any leak that is considered a “significant leak” (based on the thresholds below) would be required to be repaired within specified timelines.
  • Significant leak: Operators would be required to identify leaks as significant leaks if
    • • for compressors, the leak results in a VOC concentration of 1 000 ppmv or more; and
    • • for all other equipment components, the leak results in a VOC concentration of 10 000 ppmv or more until December 31, 2024, and of 1 000 ppmv or more thereafter.
  • Permitted repair time: Operators would be required to repair significant leaks within 15 days of detection, within 60 days if the repair cannot be completed within 15 days, or during the next facility shutdown if the repair requires a full or partial facility shutdown.
  • Replacement of equipment components with repeated significant leaks: Replacement of equipment components with three significant leaks in a period of 24 consecutive months would be required, rather than repairing them. If the equipment component is a valve, other than a control valve, replacement with a certified low-leaking valve or repacking with certified low-leaking valve packing, would be required.
  • Coming into force: The proposed LDAR program requirements would come into force on July 1, 2019. In 2019, only one inspection would be required for equipment components in the inventory (rather than three), in order to allow companies time to implement the more comprehensive program beginning in 2020.
4.2 Preventive equipment requirements

The proposed Regulations would require that facility operators ensure that certain equipment components meet design and operating requirements in order to minimize releases into the environment.

  • Open-ended lines: Operators would be required to plug any segment of pipe that opens to the atmosphere.
  • Sampling systems: Operators would be required to properly design and use any system that allows the operator to extract a sample of the process fluid from a pipe. These systems would be required to be designed and used in a manner that minimizes to the extent possible the release of VOCs into the environment.
  • Pressure relief devices: Operators would be required to properly design and use any device that is capable of venting excess pressure. These devices would be required to be designed and used in a manner that minimizes to the extent possible the release of VOCs into the environment, and to be reset within six days of a pressure release.
  • Compressors: Operators would be required to equip compressors with either a mechanical seal system with a barrier fluid system or a closed-vent system to capture leakage.
  • Coming into force: The proposed preventive equipment requirements would come into force on July 1, 2019.
4.3 Fenceline monitoring

The proposed Regulations would require that facility operators establish sampling locations around the perimeter of the facility and perform sampling according to specific methods and timing. The proposed requirements for quantity and location of the sampling locations, sample collection frequency and the sampling and laboratory analysis align with specific elements of U.S. EPA Methods 325A and 325B.

  • Sampling locations: Facility operators would be required to establish sampling locations along the perimeter of the facility, depending on the size and shape of the facility, with at least 12 sampling locations per facility, as specified in U.S. EPA Method 325A.
  • Collection of samples: Operators would be required to collect samples every 14 days, from April to December, at the sampling locations.
  • Analysis of samples: Operators would be required to analyze the samples to determine the concentration of benzene and 1,3-butadiene, as well as the total concentration of all retainable VOCs, at each monitoring station.
  • Exceptions: Operators would be able to decrease the analysis frequency for 1,3-butadiene from every 14 days to every six months, if 19 consecutive results are obtained that are below the applicable detection limit.
  • Coming into force: The proposed fenceline monitoring requirements would come into force on January 1, 2018, and the collection and analysis of samples would be required as of July 1, 2018. This would enable the establishment of a base year for monitoring facility emissions that are not yet subject to the LDAR requirements of the proposed Regulations.
4.4 Other requirements

The proposed Regulations would require that facility operators carry out certain additional activities including record keeping, reporting and auditing.

  • Record keeping: Operators would be required to keep records related to the LDAR, preventive equipment and fenceline monitoring requirements noted above.
  • Reporting and third-party auditing: Operators would be required to submit a summary report on their LDAR and fenceline monitoring activities, and a third-party audit report, annually to the Minister of the Environment. Reporting methods are still under consideration and will be discussed with stakeholders (see footnote 18) to ensure alignment with other jurisdictions and the use of single-window reporting tools, where available and appropriate.
  • Coming into force: The proposed record-keeping requirements for fenceline monitoring would come into force on January 1, 2018. The proposed record-keeping requirements for LDAR and preventive equipment requirements would come into force on July 1, 2019. Annual reports would be required beginning in 2019, and third-party audit reports would be required beginning in 2021.

5 Regulatory and non-regulatory options considered

The Department of the Environment (the Department) reviewed and assessed various regulatory and non-regulatory instruments to determine the best instrument to achieve the objectives of the proposed Regulations. The assessment was based on a variety of criteria such as environmental effectiveness, economic efficiency, distributional impact, stakeholder acceptability and jurisdictional compatibility. A summary of conclusions is presented below.

5.1 Status quo

As indicated above, most facilities have an LDAR program in place. However, many existing LDAR programs were developed based on the CCME Code published in 1993, which aims to reduce VOCs from large fugitive leaks. As well, the Code only focuses on certain types of equipment components and requires annual inspections for most of them, which could allow large leaks to continue for a long period of time before they are detected and repaired. Timely detection and repair of both small and large leaks is critical, because even low concentrations of the carcinogenic components of PRGs can cause harm to human health. Hence, fugitive releases of VOCs, including PRGs, at those facilities must be further reduced. Therefore, maintaining the status quo is not a preferred option, because it does not effectively address the risks of PRGs for Canadians in the vicinity of those facilities.

5.2 Code of practice

A code of practice was not considered as a potential instrument to further reduce fugitive VOC and PRG releases as it is voluntary and not enforceable. It is not expected that all facilities would adopt a code of practice if it were to be developed, as evidence shows that some facilities do not follow the existing CCME Code. Two facilities have confirmed that they do not have an LDAR program in place. Therefore, it has been concluded that a code of practice would not result in the reductions of VOC and PRG releases that would be necessary to adequately protect the health of Canadians.

5.3 Pollution prevention planning notice

Persons subject to a pollution prevention (P2) planning notice must prepare and implement a P2 plan that meets the requirements of the notice, must have their plan available on site and must carry out the actions identified in their plan. The implementation of P2 plans is enforceable, but their contents can vary because each plan is developed by an individual facility. Consequently, a P2 planning notice does not foster national consistency. As well, it does not guarantee the implementation of measures that are needed to minimize exposure to carcinogenic components present in PRGs to the greatest extent practicable, such as frequent inspections (e.g. three inspections per year) and equipment modifications. Therefore, the Department concluded that a P2 planning notice was not the best instrument to achieve the objectives of the proposed Regulations.

5.4 Market-based instruments

The Department considered market-based instruments such as cap and trade programs, as well as fees and charges.

A cap and trade system was not considered, as setting a cap may suggest that there is a safe or acceptable amount of releases of carcinogens, which is not the case. The assessment of 1,3-butadiene indicated a high priority for investigation of options to reduce exposure for those in the vicinity of industrial sources. With a cap and trade system, it is not possible to control where the emission reductions will take place. It is determined by the markets; thus, the objective of protecting Canadians in the vicinity of the affected facilities cannot be achieved by the cap and trade system.

Alternatively, fees and charges could be levied on facilities that emit VOCs above a threshold level. However, it would require a significant amount of time to configure them so that they provide the best incentive to industry. Furthermore, it would be costly and time-consuming to revise the fee structure as technology evolves. This approach was therefore also rejected.

5.5 Regulation

National regulatory requirements were considered to be the most practical and effective way to reduce fugitive VOC releases, and thereby reduce exposure to PRGs and their carcinogenic components and protect human health. Being mandatory and uniform, regulatory measures would provide consistent fugitive VOC release control measures across affected facilities in the Canadian petroleum and petrochemical sectors, thereby achieving the objectives of the proposed Regulations.

6 Benefits and costs

The proposed Regulations would reduce fugitive VOC releases from the affected facilities by about 102 kt and GHG emissions by about 43 kt of CO2e, for the years 2017 to 2035. Reducing VOC releases would improve air quality by reducing primary precursors of smog (ground-level O3 and PM2.5). Better air quality results in improved human health, including reduced risks of premature mortalities and decreased cardiovascular system-related emergency room visits, valued by Health Canada at around $240M. Environmental benefits due to the reduction of VOC releases, such as increased agricultural productivity, reduced home cleaning expenditures and improved visibility, are valued at $4M.

Other benefits include reduced human exposure to carcinogenic substances, GHG emission reduction and recovered products. Due to lack of data, the benefits associated with reductions in releases of carcinogenic substances are not quantified and monetized. However, a qualitative analysis is provided below. The benefit from GHG (primarily as methane) emission reduction is valued at $3M. Methane is a component of many process streams at petroleum and petrochemical facilities; thus, reducing fugitive VOC releases from these streams would also result in the reduction of methane emissions.

Fugitive leaks result in the release of liquid hydrocarbons (e.g. crude oil and gasoline) to the atmosphere as VOC vapours. Consequently, facilities encounter economic losses of liquid hydrocarbon products when VOCs are released into the atmosphere. The inspection and repair of leaking equipment components would allow such products to be recovered for production or sale. The benefit of recovered fuel products is estimated to be $69M.

In total, the benefits associated with the proposed Regulations are estimated at $313M.

To achieve these outcomes, facilities would need to implement an LDAR program, implement preventive equipment requirements, monitor the concentration of certain VOCs at the facility perimeter and undertake record-keeping and reporting activities. For the years 2017 to 2035, these actions would result in a total compliance cost of $253M, including $204M for LDAR, $22M for equipment modification and maintenance and $14M for fenceline monitoring. The Government would incur a total cost of $1M for compliance promotion and enforcement.

Overall, the proposed Regulations would result in a net benefit to Canadians of about $59M, with a benefit-cost ratio of 1.2:1.

6.1 Analytic framework

A benefit-cost analysis (BCA) was conducted to assess the incremental impacts of the proposed Regulations by comparing two scenarios. The business-as-usual (BAU) scenario assumes that facilities would continue to meet existing regulatory requirements or continue voluntary practices for controlling fugitive VOC releases. The regulatory scenario assumes that facilities would take the actions required by the proposed Regulations. The differences in impact between the regulatory scenario and the BAU scenario are the incremental impacts of the proposed Regulations.

The impacts of each scenario were assessed and quantified to the extent possible and are discussed in detail below. Benefits and costs are assessed for the 2017 to 2035 period. Dollar values are expressed in 2015 Canadian dollars and are discounted using a social discount rate of 3%. Unless otherwise specified, all results are presented cumulatively for the 2017 to 2035 period.

6.1.1 Assumptions, data and uncertainties

The modelling of benefits, costs and emissions was informed by extensive research and consultation with stakeholders. Data were collected from a variety of Canadian and international government publications, databases, academic papers and submissions from industry sources. For example, industry stakeholders were consulted on key assumptions and data, and input was incorporated into the analysis to improve estimates for equipment component inventories, as well as inspection, repair and administration costs.

The BCA was based on the best available information. However, it presents only one possibility, which is subject to a set of assumptions and uncertainties associated with data estimation and projections. The Department, despite its best efforts to provide a picture that is as comprehensive as possible, had to make assumptions, in some instances, to accommodate a lack of supporting data. For example, detailed information pertaining to the fraction of equipment components that is leaking (leak fractions) and emission rates (the quantity of VOCs released to the atmosphere through the leak source, in terms of total kilograms per hour) at Canadian facilities for equipment components subject to an LDAR program was not available. Consequently, the Department estimated these data using the U.S. EPA Protocol for Equipment Leak Emission Estimates (the U.S. EPA Protocol), a U.S. EPA report entitled Emission Factors and Frequency of Leak Occurrence for Fittings in Refinery Process Units and the Department’s technical expertise. (see footnote 19) Industry stakeholders were consulted on these estimates and provided leak fraction and emissions rate data; however, these data were incomplete.

6.1.2 Models

As indicated above, a BCA model was developed to quantify and monetize benefits and costs, and to estimate fugitive VOC releases (further detailed below) in the BAU and regulatory scenarios. Once fugitive VOC releases were estimated, the Department’s Energy, Emissions and Economy Model for Canada (E3MC) and A Unified Regional Air-Quality Modelling System (AURAMS) were used to determine changes in ambient air concentrations between the two scenarios. The Air Quality Benefits Assessment Tool (AQBAT) model of Health Canada was then used to estimate the health impacts of these changes. Similarly, the Department’s Air Quality Valuation Model 2 (AQVM2) was used to estimate the environmental benefits. These models are peer-reviewed.

6.1.3 Facilities and equipment components

The proposed Regulations would affect 26 Canadian facilities (both existing and new) in the petroleum and petrochemical sectors. This includes 18 petroleum refineries, 6 upgraders and 2 petrochemical facilities. One facility in Alberta shut down its upgrading capacity due to an explosion in January 2016, but it is assumed that this facility would resume operation in 2018. One new refinery in Alberta is expected to begin operations in 2017.

The LDAR program set out in the proposed Regulations applies to all equipment components in a system, if any part of the system comes into contact with a fluid that contains 10% or more of VOCs by weight (subject to certain exceptions). This analysis considers the following categories of equipment component:

  1. Pumps in light liquid and heavy liquid services;
  2. Valves, connectors, sampling connections and pressure relief devices (PRDs) in gas or vapour, light liquid and heavy liquid services;
  3. Compressors; and
  4. Open-ended lines (OELs).

The inventory of equipment components varies depending on production capacity complexity of process units and the type of facility. For facilities that did not submit equipment component counts in response to the Department’s 2016 survey, the analysis used average equipment component counts based on a memo from RTI International to the U.S. EPA (the RTI Memo). (see footnote 20) Equipment component inventories for upgraders are assumed to be the same as those for refineries. Equipment component counts submitted by facilities were adjusted for data gaps. A summary of inventory estimates is presented in Table 1. The RTI Memo classifies refineries based on their production capacity and classifies petrochemical facilities based on their “complexity” (an approach that takes into consideration the range of different process units present in the facilities).

  • Table 1: Average equipment component counts

Sector

Production Capacity (barrel/day)

Complexity of Process Units

Average Equipment Component Count

Number of Facilities

Location

Refinery

≥50 000

-

46 545

14

4 in Alta., 4 in Ont., 2 in Que., 1 each in B.C., N.B., N.L. and Sask.

<50 000

-

17 024

4

1 each in Alta., B.C., Ont. and Sask.

Upgrader

≥50 000

-

42 661

6

5 in Alta., 1 in Sask.

Petrochemical

-

Complex

12 747

1

1 in Alta.

-

Medium

4 594

1

1 in Ont.

Source: Estimation based on the RTI Memo and stakeholder input.

The number of equipment components for existing facilities are assumed to remain unchanged over time, because existing facilities are not expected to expand their production capacity. For the new facility in Alberta, it is assumed that the production capacity would be fully established during the first construction phase.

6.2 Business-as-usual scenario
6.2.1 Current LDAR programs

In the BAU scenario, affected facilities would continue to adhere to the LDAR programs currently in place. The determination of an individual facility’s current LDAR program is based on whether the facility is subject to LDAR requirements under operating permits, provincial regulations, or municipal by-laws. If no such information is available, it is assumed that existing facilities would follow a code of practice published by the Canadian Fuels Association (the CFA code). (see footnote 21) However, the new facility in Alberta is assumed to be subject to an operating permit that references the LDAR program based on the CCME Code, given that most facilities in the province are operating under similar permits. The Department received confirmation that no LDAR program is in place at two facilities. Table 2 provides a summary of LDAR programs at affected facilities and subsection 1.4 above describes specific LDAR program requirements.

  • Table 2: LDAR programs under the BAU scenario by province

Reference for LDAR Program

Province

Number of Facilities

CCME Code referred to in operating permits

(14 in total)

B.C.

1

Alta.

10

Sask.

1

N.B.

1

N.L.

1

CFA code

(1 in total)

Alta.

1

Municipal by-laws or provincial regulations and standards

(9 in total)

B.C.

1

Que.

2

Ont.

6

No LDAR

(2 in total)

-

2

6.2.2 Leak detection and measurement

Industry stakeholders have indicated that, in most cases, inspections are conducted by contracted LDAR technicians. Based on the information collected, technicians use a variety of methods to detect leaks. Some inspect equipment components using a sniffer, while others use an OGI camera to detect leaks and then a sniffer to measure leak concentrations.

Optical gas imaging cameras are equipped with special filters that allow inspectors to detect and display methane and VOC gas plumes, which are invisible to the naked eye. The cameras are capable of scanning large areas in real time and identifying the source of a leak within a short time frame. Various expert sources indicated that OGI cameras can scan between 1 800 and 2 300 equipment components per hour. In field use, OGI cameras are currently capable of detecting the majority of leaks of 10 000 ppmv or more. They are also capable of detecting smaller leaks in ideal weather conditions. With technology advancement and user training and experience, it is expected that, by 2024, cameras would be able to detect the majority of leaks of 1 000 ppmv or more. In addition, given the rapid improvements in capability and reliability, it is expected that OGI cameras will be a widely used monitoring instrument in the future.

In this analysis, it is assumed that inspection would be conducted by LDAR technicians using an OGI camera to detect leaks, followed by the use of a sniffer to measure leak concentrations. It is also assumed that a technician with an OGI camera could inspect 30 equipment components per minute, while a sniffer would require around two minutes per equipment component.

For facilities in Ontario, Quebec and the Greater Vancouver Regional District, where the significant leak threshold is 1 000 ppmv for certain equipment components, inspections are assumed to be conducted using a sniffer for those equipment components for the years 2019 to 2024, even though OGI cameras are permitted in these jurisdictions. Starting in 2025, it is assumed that inspections at these facilities would be conducted using an OGI camera, when permitted.

It should be noted that, for the purpose of simplicity, it is assumed that significant leaks are repaired as soon as they are detected. In the analysis, there is no time lag between leak detection and repair.

6.2.3 Performance incentive programs

The CCME Code recommends that, if the leak frequency (leak fraction) for a type of equipment component (e.g. flanges) is less than 2% in two or more successive inspections, a statistical sampling method may be used for that type of equipment component to demonstrate compliance. As a result, a smaller number of equipment components would require inspection.

The Ontario industry standards for petroleum refineries and petrochemical facilities allow reduced inspection frequency to be reduced from three times to once per calendar year, if the combined annual percentage of leaking valves in the previous calendar year is less than 1.0% and the annual average concentration of VOCs from leaking equipment components is less than 10 000 ppmv.

There is evidence to suggest that some facilities are conducting inspections with statistical sampling. However, the Department’s estimated leak fractions are greater than 2% for all types of equipment components, except for connectors. For this reason, it is assumed that the statistical sampling method will not be used in the future. Had the statistical sampling method been incorporated into the analysis, the reduction of VOC releases and the costs would be lower.

6.2.4 Significant leaks

The quantity of significant leaks, by type of equipment component, is determined by multiplying the equipment component count by the fraction of equipment components expected to be leaking at or above the significant leak threshold.

It is estimated that a total of 282 200 significant leaks would be detected and repaired over the period of analysis.

6.2.5 Fugitive VOC releases

For each type of equipment component, the fugitive VOC releases are estimated by multiplying the equipment component count by the average emission rate for that type of equipment component.

In the United States, the Refinery Emissions Protocol states that methane constitutes up to 10% of VOCs emitted by leaking equipment components in refineries. (see footnote 22) Based on the Department’s technical expertise, it is assumed that methane constitutes 5% of the VOCs emitted from all types of facilities. One unit of methane is considered equivalent to 25 units of CO2 in terms of 100-year global warming potential (GWP). (see footnote 23) Thus, in the BAU scenario, it is estimated that a total of 136 kt of VOCs and 175 kt CO2e of GHG emissions would be emitted by all affected facilities for the years 2019 to 2035. Annual VOC releases in the BAU and the regulatory scenarios are shown in Figure 1.

Figure 1: Fugitive VOC releases (excluding methane) in the BAU and regulatory scenarios

Chart - Detailed information can be found in the surrounding text.

6.3 Regulatory scenario
6.3.1 Proposed LDAR program

Under the regulatory scenario, facilities would be required to comply with the LDAR requirements described in section 4.1. The proposed Regulations would require three inspections per year for all equipment components in the inventory (with some exceptions), beginning on July 1, 2019.

For the period beginning on July 1, 2019, and ending on December 31, 2024, the proposed Regulations would consider a significant leak as having a concentration of 1 000 ppmv or more for compressors and 10 000 ppmv or more for other equipment components. Beginning on January 1, 2025, the leak threshold would be 1 000 ppmv for all equipment components.

6.3.2 Leak detection and measurement

It is assumed that facilities would continue to contract LDAR technicians to implement their LDAR programs, and that technicians would use OGI cameras to detect leaks and sniffers to measure the concentration of detected leaks. The higher inspection frequency would lead to more purchases of OGI cameras, which have substantially faster detection speeds than sniffers.

Just as in the BAU scenario, it is assumed that existing OGI cameras are not able to detect leaks at a concentration below 10 000 ppmv. However, by 2024, imaging technology is assumed to have improved to the point where OGI cameras will be able to detect leaks as low as 1 000 ppmv. Considering that the regulatory leak threshold would drop in 2025, it is assumed that improved OGI cameras would be purchased for all facilities at that time.

6.3.3 Equipment modification and other requirements

The proposed Regulations would impose preventive requirements for the design and operation of certain types of equipment components, including compressors, PRDs, OELs and sampling connections. Many of these equipment components already meet these requirements, but some would need to be modified. With such modification, equipment components are assumed to leak at a concentration less than 500 ppmv.

The modifications, combined with more frequent inspections and repairs, are expected to reduce the total releases in the regulatory scenario.

6.3.4 Significant leaks and fugitive VOC releases

Approximately 1.2 million leaks would be detected and repaired in the regulatory scenario over the period of analysis, mainly as a result of the higher inspection frequency, the lower significant leak threshold and the broader range of types of equipment components in the proposed Regulations.

It is estimated that a total of 34 kt of VOC releases and 50 kt CO2e of GHG emissions would be emitted by all affected facilities for the years 2019 to 2035, as shown in Figure 1 under the regulatory scenario.

6.4 Incremental impacts of the proposed Regulations
6.4.1 Incremental benefits

The proposed Regulations would reduce fugitive VOC releases by a total of about 102 kt. Releases from refineries would be reduced by 73 kt, from upgraders by 27 kt and from petrochemical facilities by 2 kt.

Health benefits from reductions of VOC releases

Over the period of analysis, it is estimated that air quality improvements from the proposed Regulations would result in 43 fewer premature deaths. In addition, better air quality is expected to result in 9 100 fewer days of asthma symptoms among asthmatics and 44 000 fewer days of reduced activity and breathing difficulty among non-asthmatics. The total present value of health benefits resulting from air quality improvements under the proposed Regulations is estimated at about $240M.

As shown in Table 3, aggregate health benefits of the proposed Regulations would be most significant in British Columbia, Alberta, Ontario and Quebec. Provincial health benefits reflect not only emission reductions, but also atmospheric conditions and population exposure to these pollutants. The provinces that experience the largest health benefits, in absolute terms, are the provinces with the largest populations and the highest levels of population exposure. Additionally, wind direction and atmospheric conditions play a critical role in smog formation and human exposure. Emission reductions at facilities that are located upwind of large population centres (e.g. Vancouver) can have a greater health impact than similar emission reductions at facilities in more remote locations, or in locations that are downwind of major population centres. As a result, health benefits by province are not directly proportionate to emission reductions by province.

Approximately 63% of the health benefits resulting from reducing VOC releases are associated with lower ambient levels of PM2.5 and 37% are a result of reductions in ground-level O3. Less than 1% is due to the reduction in levels of other pollutants captured in Health Canada’s model (AQBAT), including nitrogen dioxide (NO2).

  • Table 3: Cumulative health benefits associated with air quality improvements (2019–2035)

Region

Estimated Number of Selected Negative Health Outcomes Prevented by the Proposed Regulations

Economic Value of Health Benefits, by Pollutant ($M)

Premature Mortalities

Asthma Symptom Days

Days of Restricted Activity in Non-Asthmatics

PM2.5-related

Annual and Summer Ground-Level O3

Total, All Pollutants

Newfoundland and Labrador

-

4

13

0.01

0.12

0.14

Prince Edward Island

-

2

12

0.06

0.03

0.08

Nova Scotia

-

10

54

0.24

0.17

0.40

New Brunswick

-

46

230

0.96

0.91

1.87

Quebec

10

1 400

9 200

44.74

10.14

54.64

Ontario

8

1 900

8 600

25.81

19.35

45.71

Manitoba

-

42

140

0.36

0.76

1.11

Saskatchewan

-

130

580

2.08

1.47

3.54

Alberta

12

2 800

14 000

46.38

18.15

64.73

British Columbia

12

2 800

14 000

28.92

36.51

65.62

Yukon

-

-

-

-

-

-

Northwest Territories

-

-

4

0.01

-

0.02

Nunavut

-

-

-

-

-

-

Canada

43

9 100

44 000

149.6

87.6

237.9

Totals may not add up due to rounding. The (-) symbol indicates that benefit estimates are below $10,000.

Health benefits of reductions in carcinogenic substances

The proposed Regulations would reduce human exposure to toxic substances such as PRGs, 1,3-butadiene, benzene and isoprene. As noted in the assessments, Health Canada recommends reducing exposure to carcinogens like 1,3-butadiene and benzene wherever feasible. Therefore, although the benefits of these reductions were not quantified, they are expected to increase the overall health benefits estimated above.

Environmental benefits

Better air quality may result in increased crop yields and reduced soiling of surfaces from particulate deposition, as well as improvement in visibility, which may positively impact the general welfare of Canadians. As shown in Table 4, the quantified environmental benefits resulting from the proposed Regulations are estimated to be about $4M. Higher crop yields and avoided household cleaning costs account for $1M and $0.7M, respectively. The welfare of residential households associated with improvement in visibility is valued at $2M. Alberta would receive the largest portion of these benefits, which is consistent with its larger reduction in VOC releases and the higher population density around the release sources. At the same time, environmental benefits in some provinces may be partly attributable to reductions of VOC releases from adjacent provinces, because pollutants can travel over longer distances.

  • Table 4: Cumulative environmental benefits by impact and province or territory (2017–2035, $M)

Environmental Impact

Agriculture

Soiling

Visibility

Total

Economic Indicator

Change in Sales Revenues for Crop Producers

Avoided Costs for Households

Change in Welfare for Households

Newfoundland and Labrador

-

-

-

-

Prince Edward Island

-

-

-

-

Nova Scotia

-

-

-

-

New Brunswick

-

-

0.02

0.02

Quebec

0.05

0.18

0.56

0.78

Ontario

0.29

0.11

0.42

0.82

Manitoba

0.04

-

0.01

0.06

Saskatchewan

0.31

-

0.06

0.38

Alberta

0.33

0.23

0.62

1.2

British Columbia

-

0.12

0.27

0.40

Yukon

-

-

-

-

Northwest Territories

-

-

-

-

Nunavut

-

-

-

-

Canada

1.0

0.65

2.0

3.7

Totals may not add up due to rounding. The (-) symbol indicates that benefit estimates are below $10,000.

The above estimate for total environmental benefits should be considered to be conservative, because several benefits could not be quantified. The reduction in concentrations of ground-level O3 and PM may benefit the health of forest ecosystems and may reduce the risks of illness or premature death within sensitive wildlife or livestock populations, which would potentially result in reduced treatment costs and economic losses for the agri-food industry. However, due to limitations in data and methodology, these benefits could not be quantified in the AQVM2 model.

Economic benefits from recovered products

When liquid hydrocarbons leak from petroleum and petrochemical facilities, they are transformed by changes in temperature and pressure into vapours. If the hydrocarbons had not leaked, the facility owners would receive profits from the sale of those hydrocarbons as final products. Therefore, repairing and modifying the equipment components that process VOCs would mitigate some of the economic losses associated with such leaks.

To assess the economic benefits from minimizing leaks, it is assumed that petroleum refineries would recover crude oil and gasoline, upgraders would recover diluted bitumen and synthetic crude oil and petrochemical facilities would recover propane and ethylene. It is further assumed that a reduction in releases of VOCs of one tonne would result in the recovery of 1 000 L of liquid products.

Using forecasted prices of recovered feedstock and fuel products provided by the E3MC model, the gross economic benefit from recovered products is estimated to be $69M.

GHG emissions reduction benefits

The proposed Regulations would reduce GHG emissions by 134 kt CO2e through the repair of leaking equipment components and the modification of equipment components. However, the combustion of recovered products would contribute to GHG emissions and air pollution. Due to limited data, only GHG emissions from the combustion of recovered gasoline were estimated. Approximately 90 kt CO2e of GHG emissions would be generated. Therefore, the net reduction of GHG emissions would be about 43 kt CO2e.

Using the Department’s Technical Update to Environment and Climate Change Canada’s Social Cost of Greenhouse Gas Estimates, (see footnote 24) the benefits associated with this net reduction are valued at $3M.

6.4.2 Incremental costs

The total incremental costs of the proposed Regulations are estimated to be $254M. These costs would occur largely as a result of more frequent inspections and repairs to equipment components.

Costs to industry

OGI cameras

Based on stakeholder feedback and other information, it is assumed that an OGI camera costs about $100,000 to purchase and that it has an annual maintenance cost of $2,000. For staff training, a one-time cost of $2,500 per camera would be carried by LDAR operators. It is assumed that there are 13 OGI cameras currently in use and that 13 additional OGI cameras would be purchased in 2019 to meet the higher inspection frequency requirements. A replacement set of 26 new cameras is expected to be purchased in 2024, which would be capable of detecting leaks at the reduced significant leak threshold of 1 000 ppmv. The cumulative costs of purchasing and maintaining OGI cameras, including staff training, are estimated to be $3M.

Equipment modification

Facilities would incur a one-time cost in 2019 to modify compressors, sampling connections, PRDs and OELs that were not designed and operated in a manner that minimizes releases into the environment. Most types of equipment components already meet this requirement. Assumptions about the percentages of equipment components that require modification and the associated costs are presented in Table 5.

Equipment Component Category

Percentage of Equipment Component Requiring Modification

Additional Parts Needed

Capital Costs of Additional Parts ($)

Labour Time (Hours)

Labour Cost ($/Hour)

AB and SK

Rest of Canada

Compressors

30%

A mechanical seal system with a barrier fluid system, or a
closed-vent system

6,493

78.00

123.00

105.00

Sampling connections

50%

One 6-m pipe and 3-ball valves

640

2.40

PRDs

30%

One rupture disk, gate valve, tee, elbow, rupture disk holder, pressure gauge, bleed valve and steel body/trim

4,981

36.00

OELs

10%

One 2.5 cm gate valve

58

1.40

The total incremental cost for modifying equipment components is estimated to be $14M. Refineries would carry about $10M, upgraders $3M and petrochemical facilities $0.4M.

Inspection

Inspection costs would include the cost of inspecting equipment components using an OGI camera where it is capable of detecting significant leaks, and the cost of quantifying leaks using a sniffer. For many facilities, the inspection frequency would increase from once per year to three times per year, resulting in increased inspection costs.

Some equipment components affected by the proposed Regulations, such as OELs and equipment components in heavy liquid service, are not inspected under most existing LDAR programs. Initial inspections for these equipment components would take longer than subsequent inspections, as the initial inspections would require identifying those equipment components in the field and tagging them.

The incremental inspection costs are estimated to be $9M in total. Refineries would carry $7M, upgraders $2M and petrochemical facilities $0.1M.

Leak repair

It is assumed that significant leaks are repaired immediately after detection. Most leaks can be repaired quickly and without replacing equipment components (e.g. by tightening the packing gland of a valve). In these cases, for each type of equipment component, repair costs are estimated as the product of the number of significant leaks, the time required to repair an equipment component of that type and the wage rates of technicians. However, it is assumed that leaking pumps would be repaired by replacing the pump seals and that the cost of purchasing a replacement pump seal would be $390 per leaking pump.

The repair time depends on the category of equipment component. Some repairs can be completed while a process unit remains online, but others may require the unit to go off-line. Table 6 lists the assumptions for repair hours by the type of equipment component.

  • Table 6: Assumptions for repair times

Type of Equipment Component

Percent Repaired Online

Hours Required for Online Repair

Percent Repaired Off-line

Hours Required for
Off-line Repair

Pumps

100%

16.00

0%

0.00

Valves

50%

0.17

50%

4.00

Connectors

75%

0.17

25%

2.00

Compressors

0%

0.00

100%

16.00

PRDs / OELs / Sampling Connections

75%

0.17

25%

4.00

Source: RTI Memo and stakeholder feedback.

A follow-up inspection of repaired leaks using a sniffer to verify that the equipment component is no longer leaking above the significant leak threshold is also required by the proposed Regulations. While this verification would be conducted under both the BAU and regulatory scenarios, facilities would incur additional repair verification costs as a result of more frequent repairs required by the proposed Regulations.

The incremental repair costs are estimated to be $192M in total. Refineries would carry $136M, upgraders $52M and petrochemical facilities $4M.

Maintenance

Certain categories of equipment component would require regular maintenance to ensure continued compliance with the proposed Regulations. Equipment components subject to preventive requirements would need additional maintenance to ensure that the additional parts or systems function properly.

The incremental costs for maintenance are estimated to be $8M in total. Refineries would carry $6M, upgraders $2M and petrochemical facilities $0.1M.

Fenceline monitoring

The proposed Regulations would require fenceline sampling locations, established in accordance with the requirements in U.S. EPA Methods 325A and 325B, at the property boundary of a facility or at an internal monitoring perimeter. This would result in a one-time cost of $80,000 for all facilities for site selection, technician training and the purchase and installation of sampling equipment. Facilities would also carry annual data collection and analysis costs of $1M.

The incremental costs of fenceline monitoring are estimated to be $14M in total. Refineries would carry $9M, upgraders $4M and petrochemical facilities $0.8M.

Administrative costs

The proposed Regulations would result in an increase in administrative costs for affected facilities. Regulatees would need to become familiar with the proposed administrative requirements and to keep records regarding LDAR activities and fenceline monitoring data. Facilities would also need to submit reports to the Department annually and assist auditors with the annual audits. The incremental administrative costs are estimated to be $4M. Refineries would carry $2M, upgraders $1M and petrochemical facilities $0.3M.

Other compliance costs

Facilities would need to review their equipment component inventory when the proposed Regulations come into effect. Employee time would be spent on contracting and managing LDAR technicians and auditors. These costs are estimated to be $9M in total. Refineries would carry $6M, upgraders $2M and petrochemical facilities $1M.

Costs to government

The proposed Regulations would result in compliance promotion and enforcement costs for the federal government. The total government costs are estimated to be approximately $1M.

Compliance promotion

Compliance promotion activities include developing, posting and sending (email/mail out to stakeholders when an instrument is published in the Canada Gazette) promotional materials such as frequently asked questions and factsheets, holding information sessions, responding to information or clarification requests, tracking inquiries, sending reminder letters, advertising in trade and association magazines and attending trade association conferences. These activities would be intended to encourage the regulated community to achieve compliance with the proposed Regulations. As the subject community is comprised only of large enterprises, compliance promotion activities would be minimal, as those enterprises have the resources and capacity to develop a good understanding of their legal obligations on their own.

The total compliance promotion cost for the years 2017 to 2035 is expected to be approximately $92,000.

Enforcement

The federal government would also incur costs related to training, inspections, investigations and measures to deal with any alleged violations of the proposed Regulations.

A one-time cost of $154,000 would be required for the training of enforcement officers, along with $54,000 to meet information management requirements, in 2020. Annual enforcement costs are estimated to be approximately $63,000 for inspections (including operation and maintenance costs, transportation and sampling costs), investigations, measures to deal with alleged violations (including warnings, environmental protection compliance orders and injunctions) and prosecutions. The total enforcement cost is estimated at approximately $857,000.

6.5 Cost-benefit statement

The results of the benefit-cost analysis are summarized in Table 7. The net present-value of the proposed Regulations is estimated to be $59M. The benefits are estimated to be $313M. The costs are estimated to be $254M. The largest quantified benefit (about $240M) corresponds to the human health gains from reducing VOC releases. The largest quantified cost ($204M) is for the implementation of the LDAR program set out in the proposed Regulations. The benefit from reducing exposure to carcinogenic VOCs cannot be quantified due to a lack of data. However, it is expected to reduce risk to human health.

Incremental Benefits and Costs

2017–2020

2021–2025

2026–2030

2031–2035

Total 2017–2035

Annualized

Quantified impacts

Benefits to Canadians

Health

24.2

76.6

70.5

66.5

237.9

16.6

Environmental (see footnote b)

0.6

2.1

2.0

1.8

6.5

0.5

Subtotal

24.9

78.7

72.5

68.3

244.4

17.1

Benefits to Industry

Recovered products

6.8

22.6

20.6

18.5

68.6

4.8

Total benefits

31.7

101.3

93.1

86.8

313.0

21.8

Costs to Industry

LDAR (see footnote c)

16.8

46.3

75.7

65.3

204.1

14.3

Equipment modification and maintenance

14.6

1.9

2.9

2.5

21.9

1.5

Fenceline monitoring

2.9

4.2

3.7

3.2

14.0

1.0

Other compliance costs

0.1

3.5

3.0

2.6

9.2

0.6

Administrative

0.3

1.3

1.1

0.9

3.6

0.3

Subtotal

34.8

57.2

86.4

74.5

252.9

17.7

Costs to Government

Enforcement, compliance and promotion

0.2

0.3

0.2

0.2

0.9

0.1

Total costs

35.1

57.4

86.6

74.7

253.9

17.7

Net benefits

59.1

4.1

Benefit-to-cost ratio

1.2:1

 

Emission Reductions (kt)

VOCs

       

101.5

6.0

GHGs (CO2e)

       

43.4

2.6

Qualified impacts

Health benefits from reduced releases of carcinogens (e.g. 1,3-butadiene, benzene and isoprene).

Improved forest ecosystem and reduced risks of illness within wildlife or livestock from the reduction in concentrations of ground-level O3 and PM.

6.6 Distributional analysis

Among the provinces, the greatest share of the costs would be carried by Alberta (44%), followed by Ontario (16%), Saskatchewan (13%), Quebec (12%), British Columbia (8%), New Brunswick (1%) and Newfoundland and Labrador (1%).

The greatest reductions in VOC releases would be in Alberta (42%), followed by Ontario (18%), Saskatchewan (18%), Quebec (9%), British Columbia (4%), New Brunswick (4%) and Newfoundland and Labrador (4%).

Among the various types of facility, most costs would occur at refineries (71%), followed by upgraders (27%) and petrochemical facilities (2%). At the same time, the benefits from recovered liquid products would accrue directly to the same facilities that pay for VOC emission reduction measures. The greatest share of reductions in VOC releases would be in refineries (72%), followed by upgraders (26%) and petrochemical facilities (2%).

6.7 Competitive analysis

6.7.1 Petroleum refining

In general, petroleum refineries have little scope to pass additional compliance costs on to consumers in most Canadian markets because they purchase feedstocks (e.g. crude oil) and sell products that are largely based on posted benchmark prices set at various points globally. In addition, much of the refined product competes for market share with comparable products from other petroleum refineries, thus minimizing the ability of producers to pass on costs through higher prices.

The Department’s financial modelling shows that compliance costs associated with the proposed Regulations are small relative to other capital and operating costs; after-tax cash flow per litre of refined product (see footnote 25) is not expected to decrease by more than 0.04 cents/L at any refinery, with a production-weighted average impact in the sector of around 0.01 cents/L estimated as an impact of less than 0.5% of after-tax profits. In addition, since the Canadian market for refined petroleum products is highly integrated with that of the United States, the proposed Regulations are not expected to adversely affect the competitive position of any affected refinery, as their competitors in the United States face similar requirements (see section 1.5).

6.7.2 Upgrading

It is expected that upgraders would also have little scope to pass compliance costs on to consumers. Prices for inputs (e.g. heavy oil and bitumen) are based on North American heavy oil benchmarks, leaving little scope for upgraders to influence the prices. Synthetic crude oil (SCO) prices are based on North American light crude oil prices, with a slight price differential based on crude oil quality. It is expected that the potential for competition from substitutes, namely other types of light crude oil, would reduce the ability of upgraders to pass additional costs on to purchasers of SCO.

Despite challenges facing new upgrading investment in recent years, the proposed Regulations are not expected to have a meaningful impact on the profitability of the upgrading sector. The additional cost per barrel of SCO due to the proposed Regulations is expected to be below $0.01/barrel, which represents less than 0.1% of historical quarterly after-tax profits for any affected upgrader, based on quarterly data from 2009 to the first quarter of 2016.

6.7.3 Petrochemical manufacturing

It is less clear whether regulatory compliance costs from the petrochemical sector could be passed on to consumers, because such facilities produce and sell a wide range of petrochemical products to various markets. While many of these products may be fairly homogenous and open to competition from substitutes, this may not be the case with all petrochemicals produced at these facilities.

In general, the fact that costs associated with the proposed Regulations are low would mitigate concerns about competitiveness.

6.8 Sensitivity analysis

A sensitivity analysis is conducted to examine the impact of risk and uncertainty on costs and benefits, by changing one variable at a time while holding other variables constant. The key variables considered are equipment component counts, the discount rate and the conversion factor between VOC release reductions and recovered liquid products.

6.8.1 Equipment component inventory

The average equipment component counts presented in the memo from RTI International to the U.S. EPA were applied to most facilities in this analysis. However, the actual equipment component counts at individual facilities can vary significantly from these average estimates. A sensitivity analysis was conducted on equipment component inventory and the results show that an increase (decrease) of 30% in equipment component inventory would lead to an increase (decrease) of 22% in total costs and 28% in emission reductions.

6.8.2 Conversion factor between reduced VOCs and recovered liquid products

The central analysis assumes that one tonne of reduction in VOC releases would result in 1 000 L of recovered liquid products. However, it is uncertain how many litres of liquid products would be recovered from each tonne of reduced VOC releases. A sensitivity analysis was conducted on the conversion factor and the results show that an increase (decrease) of 30% in conversion factor would lead to an increase (decrease) of 30% in net economic benefit of recovered products.

6.8.3 Discount rate

In the central case for this analysis, the discount rate of 3% is used to calculate the PV of costs and benefits. Table 8 shows total benefits and total costs when there is no discounting (undiscounted values) and when the discount rate is 7%.

  • Table 8: Discount rate ($M)
 

Undiscounted

3%

7%

Total costs

356.76

253.86

168.85

Total benefits

436.18

312.96

210.05

Net benefits

79.42

59.10

41.20

Benefit-cost ratio

1.3:1

1.2:1

1.2:1

7 “One-for-One” Rule

This regulatory proposal would be new regulations and would result in an increase in administrative burden costs for regulated parties. The proposed Regulations would therefore be considered an “IN” under the “One-for-One” Rule. Following Treasury Board of Canada Secretariat’s guide on the “One-for-One” Rule, (see footnote 26) and using a 7% discount rate and 10-year time frame beginning in 2018, it is estimated that the proposed Regulations would result in an increase in annualized administrative burden costs of $179,664 (in 2012 Canadian dollars) for all affected facilities for the years 2018 to 2027, or $6,910 per facility.

7.1 One-time costs

Senior management at each facility would spend an average of one hour to become familiar with the administrative requirements of the proposed Regulations in 2018. Based on the feedback received from industry stakeholders, it is assumed that the wage rate is $120/hour for senior managers in Alberta and Saskatchewan, and $45/hour for the rest of Canada.

A chemical engineer or an employee with training in natural or applied science at each facility would need an average of

  • 0.5 hours to register facility information (e.g. name, address and contact information for the facility and representatives) with the Department in 2018;
  • 4 hours to learn the emission calculation methodology in 2018; and
  • 0.5 hours to prepare and submit an initial fenceline monitoring plan in 2018, and another 10 hours to prepare and submit an initial fenceline monitoring report to the Department in 2019.

Based on feedback from stakeholders, the assumed wage rate is $58/hour for chemical engineers in Alberta and Saskatchewan, and $35/hour for the rest of Canada.

7.2 Ongoing costs

A chemical engineer or an employee with training in natural or applied science (with the same wage rate assumptions as above) at each facility would need, on an annual basis, an average of

  • 4 hours to review fenceline monitoring results for the years 2018 to 2035;
  • 6.5 hours to maintain fenceline monitoring data for the years 2018 to 2035, 80 hours to maintain LDAR records for the years 2019 to 2035 and 8 hours to maintain emission results for the years 2019 to 2035;
  • 30 hours to prepare and submit annual reports to the Department for the years 2020 to 2035, and another 2 hours to prepare and submit a corrective action report to the Department, if needed, for the years 2021 to 2035; and
  • 75 hours to assist auditors for the years 2021 to 2035.

8 Small business lens

No small businesses (see footnote 27) would be affected by the proposed Regulations, as all facilities that would be subject to the proposed Regulations are considered large businesses, with more than 100 employees or annual gross revenues exceeding $5M. The small business lens therefore does not apply to the proposed Regulations.

9 Consultation

Over many years, stakeholders and federal, provincial and municipal governments have engaged extensively in the development of measures to control the fugitive releases of VOCs and provided input during the assessment of PRGs under the Chemicals Management Plan (CMP).

9.1 Early consultations — 2003 to 2015

In 2003, a detailed consultation to review and update the CCME Code was undertaken. Extensive consultation programs engaged representatives from the federal and provincial governments, industry associations, petroleum and petrochemical facilities and non-governmental organizations. These efforts led to suggested improvements to the existing CCME Code, which would further reduce fugitive VOC releases and better align the Code with the U.S. EPA’s regulatory measures. However, CCME did not revise the Code to include these recommendations.

From January 2011 to March 2012, a multi-stakeholder working group worked intensively to develop a set of requirements to reduce VOC releases from the petroleum and petrochemical sectors. This effort was part of the Air Quality Management System (AQMS) Base-Level Industrial Emission Requirements (BLIERs) process for major industrial emitters. In October 2012, the federal, provincial and territorial ministers of the environment, with the exception of the one from Quebec, agreed to implement the AQMS.

In March 2011, the Department and Health Canada published a draft screening assessment and a risk management scope document for site-restricted PRGs. Two non-governmental organizations (NGOs) submitted feedback, seeking mandatory emission monitoring and reporting in the vicinity of facilities releasing PRGs. In June 2013, the final screening assessment and a risk management approach document (see footnote 28) for site-restricted PRGs were published. Written comments that were received focused on avoiding an administratively complex approach.

In spring 2015, the Department consulted with industry stakeholders on an early version of the proposed VOC requirements. In general, industry associations were supportive of implementing a “smart” LDAR program that allows the use of OGI cameras to detect leaks. Two major comments were made:

  • it would be challenging to conduct leak detection during winter, given increased risk of injury and increased risk to safety; and
  • a significant leak threshold of 500 ppmv, under consideration by the Department at that time, would provide relatively small VOC release reductions (relative to a significant leak threshold of 1 000 ppmv), but would result in significantly higher repair costs.

To address these comments, the Department modified two elements of the proposed regulatory approach: the frequency of inspections was changed from quarterly to three times per year so that inspections would not be required during the winter and the significant leak threshold was revised from 500 ppmv to 1 000 ppmv.

The Department also consulted industry stakeholders on BCA-related assumptions and data in spring 2015. A document containing various compliance and administrative cost assumptions and key data (e.g. equipment component inventory, leak fractions and emission rates) was shared for comments. A questionnaire was also circulated to solicit information from facilities, such as their equipment component inventory and a detailed description of their current LDAR programs. Comments and some inventory data were received. After in-depth review, the Department incorporated relevant feedback (e.g. wage rates and time required for administrative activities and costs associated with OGI cameras) into the analysis and recognized the need to solicit more details on equipment component inventory. The Department also started reviewing the methodology of estimating leak fractions and emission rates.

9.2 Prepublication consultations — 2016

The Department conducted prepublication consultations during the months of April to September 2016 to support the finalizing of the proposed Regulations. In April 2016, the Department released a discussion document to approximately 120 individuals, representing 70 organizations. The purpose of that consultation was to provide information on the proposed Regulations and to seek input from Indigenous peoples, provincial and municipal governments and stakeholders. The Department also distributed a BCA document containing assumptions for requirements (e.g. fenceline monitoring, record keeping, reporting and third-party auditing) developed after the spring 2015 consultations and key data, such as revised estimates of leak fractions and emission rates. A questionnaire was sent to industry stakeholders and provincial and municipal governments in order to collect more detailed information on equipment component inventory, leak fractions and emission rates, for the preceding three years, in order to assist in improving the Department’s estimates.

The Department held information sessions with approximately 50 participants in April 2016 to provide Indigenous peoples, provincial and municipal governments and stakeholders with an overview of the proposed Regulations and the BCA materials, and to solicit their feedback. The Department received written comments from one First Nation and from provincial and municipal governments, industry and associations — 9 of which were on the proposed Regulations and 10 on the BCA. In addition, the Department received three completed questionnaires from industry stakeholders. No written comments were received from NGOs.

Upon request from industry, the Department committed to taking into consideration written comments submitted after the initial submission deadline. Also on request, the Department held additional teleconference sessions with industry and with Indigenous peoples.

Key areas that required further discussion and consideration included the scope of the proposed Regulations, the significant leak threshold, fenceline monitoring, federal-provincial alignment, inspection safety and performance incentive programs.

Based on specific stakeholder feedback, the Department made adjustments to the policy elements of the proposed Regulations taking into account the comments and the Department’s responses below.

9.3 Comments received and responses from the Department

Provincial and municipal governments were supportive of the regulatory framework. While some industry stakeholders were supportive of the Department implementing national regulations, other industry feedback was more critical and sought changes. Industry also submitted technical parameters (e.g. inspection records from their existing LDAR programs) for the Department’s consideration. One First Nation emphasized the importance of the proposed Regulations in addressing the environmental challenges of their community and submitted specific feedback for consideration on the proposed technical requirements.

The changes outlined below, as well as others, were incorporated into the proposed Regulations.

9.3.1 Proposed regulations

Comment No. 1: Affected facilities and sources

One First Nation, several provinces and industry asked why some facilities (e.g. chemical production facilities) were not subject to the proposed Regulations. The First Nation, an NGO and industry also inquired about addressing sources of VOC releases other than equipment leaks.

Response No. 1

The proposed Regulations target specific facilities (those that are expected to release PRGs, based on the CMP screening assessments) and specific sources of releases (leaking equipment components). One of the objectives of the proposed Regulations is to address risks of PRGs, specifically 1,3-butadiene, to Canadians in the vicinity of these facilities. Natural gas processing facilities can also release PRGs, but these PRGs are not expected to contain 1,3-butadiene. Therefore, these facilities are beyond the scope of the proposed Regulations.

Canada’s planned action to reduce methane releases and to contribute to Canada’s climate change commitments would also reduce harmful VOC releases from other petroleum-sector facilities (not covered by the proposed Regulations) since VOCs and methane are typically released together.

Future regulatory initiatives could expand the scope to include other facilities and sources, in order to address additional VOC releases. For example, additional VOC release sources, including storage tanks and certain loading and unloading operations, have been identified in screening assessments for other petroleum substances under the CMP (such as natural gas condensates). (see footnote 29) The risk management scope document for natural gas condensates proposed a regulation under CEPA for reducing fugitive and evaporative air emissions from petroleum facilities. (see footnote 30)

Comment No. 2: Scope of equipment components covered by the proposed Regulations, frequency of inspections and the significant leak threshold

Industry stakeholders and one First Nation proposed that equipment components in contact with a fluid containing 2% or more benzene should be inspected three times per year with a leak threshold of 1 000 ppmv, but all other equipment components should only be inspected once per year with a leak threshold of 10 000 ppmv. Following further discussions with the Department, industry stakeholders suggested that all equipment components be inspected three times per year, with a significant leak threshold of 1 000 ppmv for equipment components in contact with a fluid containing 2% or more benzene, and a significant leak threshold of 10 000 ppmv for all other equipment components. The First Nation suggested that an inspection frequency of three times per year was appropriate; however, the First Nation also recommended that the flexibility for winter months (i.e. no requirement for inspections during the winter) be removed.

Response No. 2

The Department revised the proposed Regulations to include three inspections per year for all equipment components, starting with a higher significant leak threshold of 10 000 ppmv for most equipment components. This threshold would then be reduced to 1 000 ppmv after 5.5 years to encourage continuous improvement and the use of low-emission equipment components. This approach would address a large percentage of fugitive releases from equipment leaks and would also provide facilities with more lead time to prepare for the lower significant leak threshold through equipment upgrades, improved operational procedures, etc.

Comment No. 3: Fenceline monitoring

Industry stakeholders proposed that a voluntary pilot project should be considered as an alternative to the regulated fenceline monitoring requirement. They argued that fenceline monitoring will not accurately depict releases from facilities due to local vehicle and neighbouring facility releases, biogenic VOCs, the effect of wind, etc. As well, industry did not support fenceline monitoring for VOCs other than benzene, because the U.S. EPA only requires monitoring for benzene. Some argued that the monitoring equipment components do not effectively capture VOCs other than benzene. In addition, industry stakeholders argued that the Department should not require fenceline monitoring in the winter due to the questionable accuracy of the monitors and the difficulty of collecting results during that season.

Response No. 3

Indigenous peoples and NGOs are seeking full transparency regarding toxic substances being emitted near populated areas. Fenceline monitoring using passive diffusive tubes is a proven technology and is already implemented as a regulated approach by the United States and Ontario and through an operating permit for the New Brunswick refinery. Fenceline monitoring equipment components can capture benzene, 1,3-butadiene and retainable VOCs — all of which are on the List of Toxic Substances in Schedule 1 to CEPA. While going beyond testing for benzene, the Department’s approach to monitoring would generally align with requirements in the United States, Ontario and New Brunswick.

The Department consulted with U.S. EPA officials and laboratory experts. Both indicated that the monitoring technologies have been validated for the temperature range of −15 oC to 40 oC. In response to industry concerns regarding the impact of winter, the Department revised the proposed Regulations to reduce the mandatory fenceline monitoring requirement from 12 months to 9 months of the year (April to December). The Department is also conducting further research on the impact of extreme weather conditions on fenceline monitoring.

Comment No. 4: Federal-provincial alignment

Some provinces and one municipality indicated their support for the proposed Regulations and are seeking alignment of the federal and provincial requirements and collaboration to minimize the administrative burden where possible.

Response No. 4

Currently, fugitive VOC releases from petroleum refineries, upgraders and certain petrochemical facilities are controlled by various provincial and municipal regulations, as well as voluntary measures implemented by industry (see section 1.4). The proposed Regulations are designed to bring Canada’s regulatory framework in line with best practices in place in Canadian jurisdictions, as well as in the United States. For example, the proposed fenceline monitoring program would be generally aligned with the existing requirements in Ontario and the United States. The Department will continue to work with provincial and municipal governments to ensure coordination with existing requirements, to the extent possible. In order to reduce duplication, the Department will also consider equivalency agreements with provinces and single-window reporting, as appropriate.

Comment No. 5: Inspection safety

Industry stakeholders argued that some equipment components should be exempt from LDAR inspections due to safety or accessibility concerns (e.g. some equipment components may be difficult to reach with a sniffer). Furthermore, one First Nation referenced the Ontario industry standards, which exclude equipment components that are unsafe to monitor.

Response No. 5

The Department revised the proposed Regulations to include certain flexibilities in addressing safety concerns on the part of industry and other stakeholder feedback. Equipment components can be exempted from inspection if the facility operator considers them “unsafe to inspect” with both a sniffer and an OGI camera. However, it is expected that for most equipment components, OGI technology would enable imaging from various safe vantage points.

Comment No. 6: Performance incentive program

Industry stakeholders requested that the Department put in place a performance incentive program that would enable regulatees to move to less frequent inspections (once per year) in return for demonstrated low leak rates over time. They also requested that regulatees be exempt from fenceline monitoring where detection of VOCs is repeatedly low.

Response No. 6

The Department adjusted the significant leak threshold in order to provide more flexibility to facilities. The Department’s analysis shows that reducing inspections from three to one per year would significantly decrease the effectiveness of the LDAR program and could allow leaks to continue for up to one year. The Department remains open to exploring appropriately designed incentives that would not increase the risk of undetected leaks.

In response to industry comments on fenceline monitoring, the Department revised the proposed Regulations so that the monitoring frequency for 1,3-butadiene can be reduced from 14 days to 6 months if repeated results that are below the applicable detection limit are obtained.

9.3.2 Benefit-cost analysis

Comment No. 7: Leak fractions and emission rates

Industry stakeholders commented that the Department’s estimates of leak fractions (i.e. the number of leaking equipment components divided by the total number of equipment components of that type) were much higher than their experience would suggest.

Several stakeholders also sought further clarification on the Department’s estimated emission rates. Estimates for some equipment components indicated little or no emission reductions after changing the significant leak threshold from 10 000 ppmv to 1 000 ppmv, or increasing the inspection frequency from once per year to three times per year.

Response No. 7

The Department conducted an in-depth review of leak fraction data submitted by three individual facilities. It was concluded that, for the same LDAR programs, the Department’s estimated leak fractions were within a ±10% range of submitted data for most types of equipment components and could therefore reasonably be applied to all affected facilities in the analysis.

To assess the incremental impacts of the proposed Regulations, it was necessary to estimate emission rates for the two LDAR programs that would be instituted by the proposed Regulations: one with a significant leak threshold of 10 000 ppmv and the other with a significant leak threshold of 1 000 ppmv. For each LDAR program, the Department estimated emission rates for each type of equipment component, using the U.S. EPA Protocol for Equipment Leak Emission Estimates. Adjustments were made to key parameters in the U.S. EPA Protocol (e.g. occurrence rate and recurrence rate) so that they could be applied to Canadian facilities. The resulting emission rates were summarized and presented in the 2016 BCA consultation document.

For a few types of equipment components, the estimation method did not imply a difference in emissions rates between LDAR programs. However, for most types, the results show that the emission rates associated with a more stringent LDAR program (1 000 ppmv threshold) are lower than those associated with a less stringent LDAR program (10 000 ppmv threshold). During the 2016 consultation, the Department solicited industry stakeholders for submissions on emission rates achieved under existing LDAR practices. Insufficient data was provided to inform the Department’s estimates; therefore, the Department relied on the emission rates estimated using the U.S. EPA Protocol for the analysis.

Comment No. 8: Compliance and administrative costs

Several stakeholders commented that some compliance and administrative costs were not considered, such as time spent tracking leaking equipment components for repair purposes, the cost of purchasing an OGI camera and related training and maintenance, as well as the cost of managing and coordinating LDAR programs.

Response No. 8

During consultations with industry stakeholders in spring 2015, the Department had presented various assumptions for compliance and administrative burden costs and received feedback. The Department did not seek further feedback on some of these costs in the spring 2016 consultation document, but these costs were incorporated into the analysis and are presented in the BCA above.

Comment No. 9: Fenceline monitoring costs

Several stakeholders commented that the estimated fenceline monitoring costs were low. For example, compared to the Department’s estimates, a facility would spend more time collecting samples and it would cost more to analyze them in a laboratory.

Response No. 9

During summer 2016, the Department received a report from the Ontario Ministry of the Environment and Climate Change entitled Collaborative Project, Property Line Monitoring Implementation Plan, dated September 30, 2016, for petroleum refineries and petrochemical facilities that would be affected by the Ontario industry standards. The report includes fenceline monitoring cost estimates. Ontario drafted this report based on the discussions of a working group composed of experts and representatives from industry facilities and their associations, laboratories, the Department, the Ontario Ministry of the Environment and Climate Change, Indigenous peoples and the U.S. EPA. The Department incorporated these cost estimates in the analysis.

10 Regulatory cooperation

As described in sections 1.4 and 1.5, fugitive VOC releases in Canada are currently managed under a patchwork of voluntary codes of practice, facility permits, municipal by-laws and provincial regulations. The proposed Regulations would modernize the current Canadian regime and would better align with current U.S. regulations. The U.S. EPA was consulted on various aspects of the proposed Regulations, in the context of the Canada–United States Workplan on Oil and Gas Emission under the Canada–United States Air Quality Agreement. (see footnote 31)

The structure of the proposed Regulations is similar to the U.S. EPA regulatory regime, with modifications to reflect Canadian conditions (including existing requirements in various Canadian jurisdictions) and input from stakeholders. Some key areas are highlighted below. In addition to these harmonized requirements, the Department would also consider equivalency agreements and single-window reporting, as appropriate.

Inspection frequency

The U.S. EPA requires monthly or quarterly inspections for many equipment components, but Canadian jurisdictions generally require inspections three times per year (Ontario, Quebec) or annually (Vancouver, CCME Code, CFA code). Under the proposed Regulations, equipment components would be inspected three times per year. This would avoid requiring inspections during winter, while still ensuring that equipment components are inspected regularly throughout the rest of the year.

Significant leak threshold

In the United States, significant leak thresholds range from 500 ppmv to 10 000 ppmv. In Canada, leak thresholds from 1 000 ppmv (Vancouver, Ontario, Quebec) to 10 000 ppmv (CCME Code, CFA code) are used in various jurisdictions. Under the proposed Regulations, the significant leak threshold for most equipment components would be 10 000 ppmv until December 31, 2024, and 1 000 ppmv thereafter. This approach recognizes the importance of controlling small and large leaks of PRGs, while also providing facilities with lead time to prepare for the 1 000 ppmv significant leak threshold through equipment upgrades and improved operational procedures.

Leak inspection technology

The United States and Ontario allow the use of OGI cameras for most inspections, but require that each equipment component be inspected using a sniffer once per year. Other Canadian jurisdictions generally refer to the CCME Code, which recommends the use of a sniffer but does not rule out other technologies (OGI technology was not widely used when the CCME Code was published in 1993). Under the proposed Regulations, most inspections can be conducted using either a sniffer or an OGI camera. This approach recognizes the continuing development of OGI technology, which was highlighted in comments from industry and other stakeholders. The faster pace of inspections using OGI cameras allows for a larger number of equipment components to be included in the LDAR program.

Fenceline monitoring

The United States, Ontario and New Brunswick require refineries to conduct year-round fenceline monitoring for benzene, using the methodology specified in U.S. EPA Methods 325A and 325B. (see footnote 32) Under the proposed Regulations, the same EPA methods would be used, but fenceline monitoring would be required only for the months of April to December. This approach would avoid the need to collect samples during winter and would also respond to stakeholder concerns about the accuracy of the monitoring technology at extremely low temperatures. In addition to benzene, the proposed Regulations would require all affected facilities to monitor for 1,3-butadiene and the total of retainable VOCs. These additional measurements would allow the Department to better evaluate the performance of the Regulations over time and to inform neighbouring communities about the concentrations of these toxic substances in the air.

11 Rationale

Volatile organic compounds are a precursor pollutant to the formation of ground-level O3 and PM, the main constituents of smog. Exposure to ground-level O3 and PM has harmful effects on human health, causing respiratory and cardiac symptoms, in some cases leading to premature mortality. Higher levels of ground-level O3 can also reduce crop productivity. Releases of VOCs from leaking equipment components in petroleum and petrochemical facilities include PRGs. These gas mixtures may contain carcinogenic components (e.g. 1,3-butadiene, benzene and isoprene) that pose risks to Canadians in the vicinity of these facilities.

An LDAR program is acknowledged as constituting the best practice for controlling fugitive VOC releases from these facilities. Most facilities have implemented LDAR programs based on the voluntary CCME Code, with the focus on reducing VOC releases from equipment components leaking at high concentrations. However, significant areas of improvement have been identified. Furthermore, even low concentrations of the carcinogens in PRGs can have harmful effects on human health.

The proposed Regulations were developed to address these issues. Facility operators would conduct more frequent inspections on a broader range of equipment components and would repair equipment components leaking at lower VOC concentrations. Additionally, certain equipment components would need to be designed and operated in a manner that minimizes VOC releases. These actions would further reduce releases of VOCs, including PRGs. Facility operators would also be required to collect samples at sampling locations along the facility perimeter and to analyze the samples to determine the concentrations of benzene and 1,3-butadiene, as well as the total concentrations of all retainable VOCs.

As a result of the proposed Regulations, VOC releases would be reduced by 102 kt and GHG emissions would be reduced by 43 kt of CO2e for the years 2017 to 2035, which would result in improvements in human health and environmental quality, as well as benefits to businesses from recovered products. These benefits are valued at $313M, while the total costs to industries and the Government would be $253M and $1M, respectively. The costs to businesses are not expected to affect their competitiveness in petroleum and petrochemical markets.

The proposed Regulations are designed to harmonize, where possible, with the regulatory requirements of other jurisdictions, including provinces and the United States. The proposed Regulations would also adopt a single-window reporting approach, where possible, to minimize the administrative burden on facilities.

11.1 Strategic environmental assessment

A strategic environmental assessment (SEA) of the CMP was completed. (see footnote 33) The SEA concluded that activities under the CMP would support the goal of the Federal Sustainable Development Strategy (FSDS) to minimize the threat to air quality so that the air Canadians breathe is clean and supports healthy ecosystems. An SEA has also been conducted for the proposed Regulations that confirms that this regulatory initiative supports the FSDS goal to reduce threats to air quality.

12 Implementation, enforcement and service standards

12.1 Compliance promotion

Compliance promotion activities are intended to encourage the regulated community, composed solely of large enterprises, to achieve compliance. Immediately after publication of the final Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector), and with the coming into force of new requirements in 2018 (fenceline monitoring), 2019 (LDAR and preventive equipment requirements) and 2021 (third-party audits), compliance promotion activities could include

  • posting of information (e.g. frequently asked questions) on the Department website;
  • emailing and mailing out notices to stakeholders to highlight the dates by which facilities must take certain actions (e.g. submitting a fenceline monitoring plan);
  • arranging conference calls or webinars to review the regulatory requirements and reporting forms with stakeholders; and
  • responding to information or clarification requests.

For subsequent years, compliance promotion activities would possibly be kept at a maintenance level and be limited to responding to and tracking inquiries. Additional compliance promotion may be required if, following an assessment of the promotional activities, compliance with the Regulations is found to be low.

12.2 Enforcement

The proposed Regulations would be made under CEPA, so enforcement officers would, when verifying compliance with the Regulations, once they are in force, apply the Compliance and Enforcement Policy for CEPA. (see footnote 34) That Policy sets out the range of possible responses to alleged violations, including warnings, directions, environmental protection compliance orders, tickets, ministerial orders, injunctions, prosecution and environmental protection alternative measures (which are an alternative to a court prosecution after the laying of charges for a CEPA violation). In addition, the Policy explains when the Department would resort to civil suits by the Crown for cost recovery.

To verify compliance, enforcement officers may carry out an inspection. An inspection may identify an alleged violation, and alleged violations may also be identified by the Department’s technical personnel, or through complaints received from the public. Whenever a possible violation of any regulations is identified, enforcement officers may carry out investigations.

If, following an inspection or an investigation, an enforcement officer discovers an alleged violation, the officer would choose the appropriate enforcement action based on the following factors:

  • Nature of the alleged violation: This includes consideration of the damage, the intent of the alleged violator, whether it is a repeat violation and whether an attempt has been made to conceal information or otherwise subvert the objectives and requirements of CEPA;
  • Effectiveness in achieving the desired result with the alleged violator: The desired result is compliance within the shortest possible time and with no further repetition of the violation. Factors to be considered include the violator’s history of compliance with CEPA, willingness to cooperate with enforcement officers and evidence of corrective action already taken; and
  • Consistency: Enforcement officers would consider how similar situations have been handled in determining the measures to be taken to enforce CEPA.

The proposed Regulations would also require related changes to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999). Those Regulations designate the various regulatory provisions in various CEPA regulations that refer to an increased fine regime following a successful prosecution of an offense involving harm or risk of harm to the environment, or obstruction of authority.

12.3 Service standards

The Department, in its administration of the proposed Regulations, will respond to submissions and inquiries from the regulated community in a timely manner taking into account the complexity and completeness of the request.

In addition, the Department intends to develop information sheets and/or a technical guidance document describing the required information and format to be followed when submitting a plan or report.

13 Performance measurement and evaluation

The expected outcomes of the proposed Regulations are related to domestic priorities to reduce fugitive releases of VOCs, including PRGs, from petroleum refineries, upgraders and certain petrochemical facilities. The performance of the proposed Regulations in achieving these outcomes will be measured and evaluated.

Clear and quantified performance indicators will be defined for each outcome. These indicators include facility registration, compliance with the regulatory requirements, repair or replacement of leaking equipment components and reported emission data (including calculated emissions from leaking equipment components, as well as fenceline monitoring results for 1,3-butadiene, benzene and the total of retainable VOCs). Achievement of the performance indicators will be tracked through annual or on-demand reporting requirements, as well as through enforcement activities.

Regular review and evaluation of these performance indicators will allow the Department to determine the impacts of the proposed Regulations on the affected facilities and to evaluate the performance of the proposed Regulations in reaching the intended targets.

Contacts

Mr. Pierre Boucher
Manager
Downstream Oil and Gas Section
Oil, Gas and Alternative Energy Division
Environment and Climate Change Canada
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: ec.covsecteurpetrolier-vocpetroleumsector.ec@canada.ca

Mr. Matt Watkinson
Director
Regulatory Analysis and Valuation Division
Environment and Climate Change Canada
200 Sacré-Cœur Boulevard
Gatineau, Quebec
K1A 0H3
Email: ec.darv-ravd.ec@canada.ca

PROPOSED REGULATORY TEXT

Notice is given, pursuant to subsection 332(1) (see footnote d) of the Canadian Environmental Protection Act, 1999 (see footnote e), that the Governor in Council proposes, pursuant to subsection 93(1) of that Act, to make the annexed Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector).

Any person may, within 60 days after the date of publication of this notice, file with the Minister of the Environment comments with respect to the proposed Regulations or a notice of objection requesting that a board of review be established under section 333 of that Act and stating the reasons for the objection. All comments and notices must cite the Canada Gazette, Part I, and the date of publication of this notice, and be sent to Helen Ryan, Director General, Energy and Transportation Directorate, Environmental Protection Branch, Department of the Environment, Gatineau, Quebec K1A 0H3 (fax: 819-420-7410; email: ec.covsecteurpetrolier-vocpetroleumsector.ec@canada.ca).

A person who provides information to the Minister of the Environment may submit with the information a request for confidentiality under section 313 of that Act.

Ottawa, April 13, 2017

Jurica Čapkun
Assistant Clerk of the Privy Council

TABLE OF PROVISIONS

Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector)

Interpretation

1 Definitions

Application

2 Facilities

Leak Detection and Repair Requirements

3 Leak detection and repair program

4 Contents of inventory

5 Portable monitoring instruments

6 Inspection — equipment components

7 Required training

8 Repairs

9 Record-keeping requirements

10 Retention period

Requirements for Certain Equipment Components

11 Responsibilities of operator

12 Pipes

13 Sampling systems

14 Pressure relief devices

15 Compressors

16 Record-keeping requirements

Fenceline Monitoring Requirements

17 Establishment of fenceline monitoring program

18 Selection of sampling equipment and supplies

19 Placement of sampling tubes

20 Sampling and analysis

21 Collection of sampling tubes

22 Meteorological station

23 Quality control procedures

24 Total concentration of retainable VOCs

25 Record-keeping requirements

Reporting Requirements

26 Information to be provided on request

27 Information to be submitted by existing facility

28 Fenceline monitoring plan to be submitted by existing facility

29 Fenceline monitoring report to be submitted in 2019

30 Equipment components inspected under subsection 6(1) or (2)

31 Equipment components in inventory

32 Reasons for no inspection

33 Significant leak not repaired within 15 days

34 Fenceline monitoring data

35 Auditor’s report

36 Corrective action plan

37 Audit by individual or firm

38 Different auditor required

39 Format of reports and plans

Coming into Force

40 January 1, 2018

SCHEDULE 1

SCHEDULE 2

Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector)

Interpretation

Definitions

1 (1) The following definitions apply in these Regulations.

authorized official means

  • (a) in respect of an operator who is an individual, that individual or another individual who is authorized to act on the operator’s behalf;
  • (b) in respect of an operator that is a corporation, an officer of the corporation who is authorized to act on its behalf; and
  • (c) in respect of an operator that is an entity other than a corporation, an individual who is authorized to act on its behalf. (agent autorisé)

certified low-leaking valve means a valve for which the manufacturer has issued a written warranty, based on the results of testing conducted in accordance with generally-accepted engineering practices, that the valve will not leak above 100 ppmv for five years and that if it does leak above that level at any time during the first five years, the manufacturer will replace the valve. (soupape certifiée à faibles fuites)

certified low-leaking valve packing means valve packing for which the manufacturer has issued a written warranty, based on the results of testing conducted in accordance with generally-accepted engineering practices, that the valve packing will not leak above 100 ppmv during the first five years and that if it does leak above that level during that time, the manufacturer will replace the valve packing. (garniture certifiée à faibles fuites)

control device means an enclosed combustion device, a vapour recovery system or any other device used to control the release of VOCs into the environment. (dispositif de contrôle)

EPA Method 21 means the method of the Environmental Protection Agency of the United States, entitled Method 21 — Determination of Volatile Organic Compound Leaks, set out in Appendix A–7 to Title 40, chapter I, part 60, of the Code of Federal Regulations of the United States. (méthode 21 de l’EPA)

EPA Method 325A means the method of the Environmental Protection Agency of the United States, entitled Method 325A — Volatile Organic Compounds from Fugitive and Area Sources: Sampler Deployment and VOC Sample Collection, set out in Appendix A to Title 40, chapter I, part 63, of the Code of Federal Regulations of the United States. (méthode 325A de l’EPA)

EPA Method 325B means the method of the Environmental Protection Agency of the United States, entitled Method 325B — Volatile Organic Compounds from Fugitive and Area Sources: Sampler Preparation and Analysis, set out in Appendix A to Title 40, chapter I, part 63, of the Code of Federal Regulations of the United States. (méthode 325B de l’EPA)

equipment component means any piece of equipment that is part of a system that comes into contact with a fluid containing hydrocarbons. (pièce d’équipement)

facility means the buildings, other structures and stationary equipment that are located on a single site or on adjacent sites that function as a single integrated site. (installation)

leak detection instrument means a portable monitoring instrument or an optical gas-imaging instrument. (instrument de détection des fuites)

liquid petroleum product means any of the following:

  • (a) naphtha;
  • (b) gasoline;
  • (c) aviation turbine fuel;
  • (d) kerosene;
  • (e) diesel fuel;
  • (f) light fuel oil;
  • (g) heavy fuel oil;
  • (h) naval distillate, bunker fuel or any other marine fuel;
  • (i) gas oil;
  • (j) lubricant basestock or petroleum-based lubricant;
  • (k) asphalt; or
  • (l) synthetic crude oil. (produit pétrolier liquide)

operator, in respect of a facility, means the person who operates or has the charge, management or control of the facility. (exploitant)

pipe means any pipe, regardless of whether it is rigid or flexible. (conduite)

ppmv means parts per million by volume. (ppmv)

retainable VOC means a VOC that is capable of being collected and retained by the sorbent in a sampling tube. (COV conservable)

sampling tube means a passive diffusive tube that contains a sorbent used for collecting VOCs. (tube d’échantillonnage)

volatile organic compound or VOC means a compound that participates in atmospheric photochemical reactions and that is not excluded under item 65 of Schedule 1 to the Canadian Environmental Protection Act, 1999. (composé organique volatil ou COV)

Incorporation by reference

(2) Any standard or method that is incorporated by reference in these Regulations is incorporated as amended from time to time.

Application

Facilities

2 These Regulations apply in respect of facilities that produce liquid petroleum products by means of the processing, using distillation, of

  • (a) crude oil or bitumen;
  • (b) mixtures of crude oil or bitumen and other hydrocarbon compounds; or
  • (c) partially refined feedstock derived from crude oil or bitumen.

Leak Detection and Repair Requirements

Leak detection and repair program

3 The operator of a facility must establish and maintain a leak detection and repair program to control the release of volatile organic compounds from equipment components at the facility and, for that purpose, must

  • (a) establish and keep up to date an inventory of equipment components in accordance with section 4;
  • (b) operate, maintain and calibrate leak detection instruments that are used in the detection of leaks of volatile organic compounds in accordance with section 5;
  • (c) conduct inspections in accordance with section 6 of equipment components that are listed in the inventory;
  • (d) ensure that inspections conducted under subsections 6(1) and (2) are conducted by an individual who has received the training described in subsection 7(1);
  • (e) repair any leaking equipment components in accordance with section 8; and
  • (f) keep records in accordance with sections 9 and 10.
  • Contents of inventory
  • 4 (1) Subject to subsection (2), the inventory of equipment components must contain all of the following information in respect of each component:
  • (a) its type from the list set out in Schedule 1;
  • (b) an indication of whether the VOC in the fluid with which the system that the component forms a part of comes into contact is a light liquid, a heavy liquid or a gas;
  • (c) the GPS coordinates of its location;
  • (d) its identification number;
  • (e) the processing activity for which it is used; and
  • (f) a designation of unsafe to inspect if an authorized official is of the opinion that the component cannot be inspected using a leak detection instrument that meets the requirements of subsection 5(1) or (2), as applicable, without exposing any individual to immediate danger.

Excluded equipment components

(2) The following equipment components are not to be included in the inventory:

  • (a) equipment components that are not part of a system that comes into contact with a fluid that contains 10% or more VOCs by weight, as measured in accordance with the ASTM International standard E260-96 (Reapproved 2011), Standard Practice for Packed Column Gas Chromatography, or E169-16, Standard Practices for General Techniques of Ultraviolet-Visible Quantitative Analysis;
  • (b) equipment components that operate continuously at an internal pressure that is at least 5 kPa below ambient pressure;
  • (c) seal-less pumps, including canned-motor pumps and diaphragm pumps;
  • (d) bellows seal valves;
  • (e) diaphragm valves; and
  • (f) equipment components that are equipped with a system to capture releases of VOCs that prevents the release of any VOCs into the environment.

Establishing and updating

(3) The inventory is to be established and then updated annually, using any method that results in an accurate inventory, including

  • (a) an on-site survey of the facility; and
  • (b) an examination of the process diagrams and instrumentation diagrams of the facility, if those diagrams are accurate and complete.

Portable monitoring instruments

5 (1) A portable monitoring instrument must meet all of the following requirements:

  • (a) it must meet the specifications set out in sections 6.0 to 6.6 of EPA Method 21;
  • (b) it must be operated and maintained in accordance with
    • (i) the manufacturer’s specifications for that instrument, if any, and in accordance with sections 8.3 to 8.3.2.2 of EPA Method 21, to the extent of the consistency of that section with those specifications, and
    • (ii) sections 8.3. to 8.3.2.2 of EPA Method 21, if there are no manufacturer’s specifications for that instrument;
  • (c) it must, on each day on which it is used, be calibrated in accordance with sections 7.0 to 8.2, 10.0 and 10.1 of EPA Method 21 before it is first used on that day; and
  • (d) it must undergo a calibration drift assessment at the end of each day on which it is used, in accordance with the requirements set out in section 485a(b)(2), Title 40, chapter I, part 60, subpart VVa, of the Code of Federal Regulations of the United States, as amended from time to time.

Optical instruments

(2) An optical gas-imaging instrument must meet the following requirements:

  • (a) it must meet the specifications set out in section 18(h)(7)(i)(1), Title 40, chapter I, part 60, subpart A, of the Code of Federal Regulations of the United States, as amended from time to time;
  • (b) it must be operated and maintained in accordance with the manufacturer’s specifications for that instrument, if any; and
  • (c) it must, on each day on which it is used, be checked in accordance with sections 18(h)(7)(i)(2)(i) to (v), Title 40, chapter I, part 60, subpart A, of the Code of Federal Regulations of the United States, as amended from time to time, before it is first used on that day.

Inspection — equipment components

6 (1) Subject to subsections (2) and (3), all equipment components at a facility that are listed in its inventory must be inspected for leaks using a leak detection instrument that meets the requirements of subsection 5(1) or (2) three times per calendar year, but at least three months after any previous inspection.

Inspection in 2019

(2) Subject to subsection (3), all equipment components at a facility that are listed in its inventory must be inspected for leaks once during 2019 using a leak detection instrument that meets the requirements of subsection 5(1) or (2).

  • Exception
  • (3) The following components are exempt from the inspection required by subsections (1) and (2):
  • (a) a pump that has a dual mechanical seal system with a barrier fluid system and that meets the following requirements:
    • (i) the dual mechanical seal system is
      • (A) operated with a barrier fluid system in which the fluid is at all times at a pressure that is greater than the stuffing box pressure,
      • (B) equipped with a barrier fluid degassing reservoir that is connected by a closed-vent system to a process gas system, a fuel gas system or a control device, or
      • (C) equipped with a system that purges the barrier fluid into a process gas system and prevents the release of any VOCs into the environment;
    • (ii) the barrier fluid contains less than 10% VOCs by weight, as measured in accordance with the ASTM International standard E260-96 (Reapproved 2011), Standard Practice for Packed Column Gas Chromatography, or E169-16, Standard Practices for General Techniques of Ultraviolet-Visible Quantitative Analysis; and
    • (iii) the barrier fluid system is equipped with a sensor that is intended to detect any failure of the system; and
  • (b) a component that is designated in the inventory as unsafe to inspect under paragraph 4(1)(f).

Pumps — visual inspection

(4) Pumps that are listed in the inventory must also be inspected visually for leaks at least once a week.

Sensor check

(5) A sensor referred to in subparagraph (3)(a)(iii) must be checked daily to determine whether there has been a failure of the barrier fluid system unless the sensor is equipped with an audible alarm for the purpose of indicating such a failure.

Required training

7 (1) The inspections referred to in subsections 6(1) and (2) must be carried out by an individual who, not more than one year before the first time that they conduct an inspection, has received training in operating, maintaining and calibrating leak detection instruments, in accordance with section 5, and conducting leak inspections using those instruments.

Record of training

(2) The operator must keep a record of the training that was completed by the individual carrying out the inspections, including

  • (a) the name, title and business address of the individual and the name of their employer;
  • (b) the dates on which the training was completed;
  • (c) the name of the entity that provided the training; and
  • (d) a description of the training.

Retention period

(3) The operator must retain the record referred to in subsection (2), as well as any supporting documents, for at least five years. The record and documents must be kept at the facility.

Repairs

8 (1) An equipment component that has a significant leak must be repaired not later than 15 days after the day on which the leak is detected, unless it has been flagged for repair under subsection (4).

Presumed significant leak

(2) A leak in an equipment component that is detected by using a leak detection instrument or by using sensory methods, including auditory, visual or olfactory methods, or that is detected as a result of an indication from a sensor that the component’s barrier fluid system has failed, is considered to be a significant leak unless

  • (a) the leak is in a compressor and, as measured using a portable monitoring instrument that meets the requirements of subsection 5(1), is less than 1,000 ppmv; or
  • (b) the leak is in an equipment component other than a compressor and, as measured using a portable monitoring instrument that meets the requirements of subsection 5(1), is less than
    • (i) 10,000 ppmv, if the date on which the leak is detected is on or before December 31, 2024, and
    • (ii) 1,000 ppmv, if the date on which the leak is detected is after December 31, 2024.

Inspection before repair

(3) If a leak in an equipment component is detected by a means other than a portable monitoring instrument, the equipment component must, before it is repaired, be inspected, using a portable monitoring instrument that meets the requirements of subsection 5(1).

Flagging for repair

(4) An equipment component that is identified as having a significant leak and that cannot be repaired within 15 days after the day on which the leak is detected must be flagged for repair as follows, either by attaching a tag to the component or by noting the need for the repair in an electronic tracking system:

  • (a) if the repair does not require a full or partial shutdown of the facility, the tag or note must indicate that the equipment component is to be repaired within 60 days after the day on which the leak is detected; and
  • (b) if the repair requires a full or partial shutdown of the facility, the tag or note must indicate that the equipment component is to be repaired before the end of the next shutdown, whether full or partial.

Repairs — time requirements

(5) An equipment component that is identified as having a significant leak and flagged for repair under subsection (4) must be repaired

  • (a) within 60 days after the day on which the leak is detected, if it is flagged in accordance with paragraph (4)(a); and
  • (b) before the end of the next shutdown, whether full or partial, if it is flagged in accordance with paragraph (4)(b).

Equipment component with three significant leaks

(6) Subject to subsection (7), an equipment component that is identified as having three significant leaks in any period of 24 consecutive months must be replaced with a new component within the time required by subsection (1).

Valve other than a control valve

(7) Subject to subsection (8), if the equipment component referred to in subsection (6) is a valve, other than a control valve, it must be replaced with a certified low-leaking valve or re-packed with certified low-leaking valve packing within the time required by subsection (1).

Exception

(8) Subsection (7) does not apply in respect of a valve for which no certified low-leaking valve and no certified low-leaking valve packing is commercially available.

Completed repairs and replacements

(9) The repair or replacement of the equipment component is considered to be completed when, following the repair or replacement, as applicable, an inspection of the component using a portable monitoring instrument that meets the requirements of subsection 5(1) indicates that there is no longer any significant leak in the component.

Record-keeping requirements

9 (1) The operator must, for each calendar year, keep a record of the following information:

  • (a) in respect of each portable monitoring instrument,
    • (i) the manufacturer’s specifications for that instrument, if any,
    • (ii) the days on which it was calibrated in accordance with paragraph 5(1)(c), as well as the name, title and business address of the individual who carried out the calibration and the name of their employer,
    • (iii) for each calibration gas used to carry out the calibration, the identification number of the cylinder in which the gas is stored, the certified concentration of the gas and the date on which the concentration of the gas was certified, and
    • (iv) the results of the calibration drift assessment referred to in paragraph 5(1)(d);
  • (b) in respect of each optical gas-imaging instrument,
    • (i) the manufacturer’s specifications for that instrument, if any,
    • (ii) the days on which the instrument was checked in accordance with paragraph 5(2)(c), as well as the name, title and business address of the individual who checked the instrument and the name of their employer, and
    • (iii) a description of the analysis used to determine the mass flow rate of the gas during the instrument check;
  • (c) in respect of each inspection of equipment components referred to in section 6,
    • (i) the day on which the inspection was carried out, as well as the name, title and business address of the individual who carried out the inspection and the name of their employer,
    • (ii) the identification number of each equipment component that was inspected,
    • (iii) the method used to inspect each equipment component,
    • (iv) if the inspection of an equipment component was carried out using a portable monitoring instrument, the resulting reading for that equipment component, and
    • (v) if the inspection of an equipment component was carried out visually, the results of the inspection;
  • (d) in respect of each pump that is exempt from inspection under paragraph 6(3)(a),
    • (i) an indication that the dual mechanical seal system on the pump meets the criteria referred to in clause 6(3)(a)(i)(A), (B) or (C), as applicable,
    • (ii) the composition of the barrier fluid referred to in subparagraph 6(3)(a)(ii), and
    • (iii) an indication that the pump is equipped with the sensor referred to in subparagraph 6(3)(a)(iii);
  • (e) in respect of each daily sensor check referred to in subsection 6(5),
    • (i) the day on which the sensor check was carried out,
    • (ii) the identification number of the pump that is equipped with the sensor that was checked, and
    • (iii) the results of the sensor check;
  • (f) in respect of each equipment component that was identified as having a leak by a means other than a portable monitoring instrument,
    • (i) the reading resulting from the inspection referred to in subsection 8(3),
    • (ii) the day on which the inspection was carried out, and
    • (iii) the name, title and business address of the individual who carried out the inspection and the name of their employer;
  • (g) in respect of each equipment component that was identified as having a significant leak whose repair was possible within 15 days after the the day on which the leak was detected,
    • (i) the day on which the repair was completed,
    • (ii) the reading resulting from the inspection referred to in subsection 8(9) establishing that the component was repaired, and
    • (iii) the name, title and business address of the individual who carried out the inspection and the name of their employer;
  • (h) in respect of each equipment component that was flagged for repair under subsection 8(4), the day on which the repair was flagged, as well as
    • (i) in the case of a repair referred to in paragraph 8(4)(a),
      • (A) the reasons why the equipment component could not be repaired within 15 days after the day on which the leak was detected in the component,
      • (B) the day on which the repair was completed,
      • (C) the reading resulting from the inspection referred to in subsection 8(9) establishing that the component was repaired, and
      • (D) the name, title and business address of the individual who carried out the inspection and the name of their employer, and
    • (ii) in the case of a repair referred to in paragraph 8(4)(b),
      • (A) the reasons why a shutdown was required in order to carry out the repair,
      • (B) the days on which the shutdown began and ended,
      • (C) the day on which the repair was completed,
      • (D) the reading resulting from the inspection referred to in subsection 8(9) establishing that the component was repaired, and
      • (E) the name, title and business address of the individual who carried out the inspection and the name of their employer;
  • (i) in respect of each equipment component that was replaced as required by subsection 8(6),
    • (i) the day on which the replacement was completed,
    • (ii) the reading resulting from the inspection referred to in subsection 8(9), and
    • (iii) the name, title and business address of the individual who carried out the inspection and the name of their employer;
  • (j) in respect of a valve that was replaced with a certified low-leaking valve or re-packed with certified low-leaking valve packing as required by subsection 8(7),
    • (i) the manufacturer’s written warranty for that certified valve or packing,
    • (ii) the day on which the replacement or re-packing was completed,
    • (iii) the reading resulting from the inspection referred to in subsection 8(9), and
    • (iv) the name, title and business address of the individual who carried out the inspection and the name of their employer;
  • (k) in respect of a valve referred to in subsection 8(8), a description of the operator’s analysis used to determine that no certified low-leaking valve and no certified low-leaking valve packing was commercially available; and
  • (l) in respect of each component designated in the inventory as unsafe to inspect under paragraph 4(1)(f),
    • (i) the name, title, and business address of the authorized official who provided the opinion referred to in paragraph 4(1)(f),
    • (ii) the date that the authorized official provided that opinion, and
    • (iii) the reasons for the authorized official’s opinion.

Requirement to keep video recordings

(2) The operator must, in addition to the records described in subsection (1), keep the following records for each calendar year:

  • (a) a video recording of the instrument check of each optical gas-imaging instrument referred to in subparagraph (1)(b)(ii) that contains an embedded indication of the date and time of the recording in respect of the instrument as well as of the GPS coordinates of the place of the recording; and
  • (b) a video recording — with an embedded indication of the date and time of the recording as well as of the GPS coordinates of the place of the recording — of the inspection of each equipment component referred to in paragraph (1)(c) that was inspected using an optical gas-imaging instrument.

Retention period

10 The operator of a facility must retain the inventory of equipment components and the records referred to in section 9, as well as any supporting documents, for at least five years after the inventory is established or updated or the records are created. The inventory, records and documents must be kept at the facility.

Requirements for Certain Equipment Components

Responsibilities of operator

11 The operator of a facility must ensure that the equipment components at the facility meet the requirements set out in sections 12 to 15.

Pipes

12 The ends of a pipe must be plugged at all times in a manner that minimizes to the extent possible the release of VOCs into the environment except during operations that require the ends of the pipe to be open.

Sampling systems

13 Every sampling system that is connected to a pipe must be designed and used in a manner that minimizes to the extent possible the release of VOCs into the environment.

Pressure relief devices

14 (1) Every pressure relief device must be designed and used in a manner that minimizes to the extent possible the release of VOCs into the environment.

Exception

(2) If a pressure release occurs, the pressure relief device must, not more than six days after the day on which it occurs, be returned to a condition that minimizes to the extent possible the release of VOCs into the environment.

Compressors

15 (1) Every compressor must be equipped with a mechanical seal system that has a barrier fluid system.

Seal system

(2) The mechanical seal system of the compressor must be

  • (a) operated with a barrier fluid system in which the barrier fluid is at all times at a pressure that is greater than the stuffing box pressure;
  • (b) equipped with a barrier fluid system degassing reservoir that is connected by a closed-vent system to a process gas system, a fuel gas system or a control device; or
  • (c) equipped with a system that purges the barrier fluid into a process gas system and prevents the release of any VOCs into the environment.

Barrier fluid

(3) The barrier fluid in the barrier fluid system must contain less than 10% VOCs by weight, as measured in accordance with the ASTM International standard E260-96 (Reapproved 2011), Standard Practice for Packed Column Gas Chromatography, or E169-16, Standard Practices for General Techniques of Ultraviolet-Visible Quantitative Analysis.

Sensor required

(4) The barrier fluid system must be equipped with a sensor that is intended to detect any failure of the system.

Sensor check

(5) The sensor must be checked daily to determine whether there has been a failure of the barrier fluid system unless the sensor is equipped with an audible alarm for the purpose of indicating such a failure.

Exception

(6) The requirements of this section do not apply in respect of a compressor that is equipped with a closed-vent system that is designed to capture any leakage from the compressor drive shaft and transport it to a process gas system, a fuel gas system or a control device.

Record-keeping requirements

16 (1) The operator must, for each calendar year, keep a record of the following information:

  • (a) in respect of an open-ended pipe, a description of the design considerations taken into account, and the control technologies and operating practices used, to ensure that the ends of the pipe are plugged in accordance with section 12;
  • (b) in respect of a sampling system that is connected to a pipe, a description of the design considerations taken into account, and the control technologies and operating practices used, to ensure that the sampling system is designed and used in accordance with section 13;
  • (c) in respect of a pressure relief device, a description of the design considerations taken into account, and the control technologies and operating practices used, to ensure that the pressure relief device is designed and used in accordance with section 14;
  • (d) in respect of a compressor, other than one referred to in subsection 15(6),
    • (i) an indication that the mechanical seal system on the compressor meets the criteria referred to in paragraph 15(2)(a), (b) or (c), as applicable,
    • (ii) the composition of the barrier fluid referred to in subsection 15(3), and
    • (iii) an indication that the compressor is equipped with the sensor referred to in subsection 15(4);
  • (e) in respect of each daily sensor check referred to in subsection 15(5),
    • (i) the day on which the sensor check was carried out,
    • (ii) the identification number of the compressor that is equipped with a barrier fluid system that has the sensor that was checked, and
    • (iii) the results of the sensor check; and
  • (f) in respect of a compressor referred to in subsection 15(6), a description of the closed-vent system referred to in that subsection.

Retention period

(2) The operator must retain the record referred to in subsection (1), as well as any supporting documents, for at least five years. The record and documents must be kept at the facility.

Fenceline Monitoring Requirements

Establishment of fenceline monitoring program

17 (1) The operator of a facility must, not later than July 1, 2018, establish and maintain for the facility a fenceline monitoring program, consisting of the collection and analysis of samples, in order to measure the concentrations of benzene and 1,3-butadiene, as well as the total concentration of all retainable VOCs taken together, at the fenceline in accordance with sections 18 to 25.

Selection of fenceline

(2) The operator may select either the property boundary of the facility or an internal monitoring perimeter as the fenceline for the purpose of the fenceline monitoring program. If an internal monitoring perimeter is to serve as the fenceline, it must be established in accordance with the requirements of sections 8.2 to 8.2.3.2 of EPA Method 325A.

Selection of sampling equipment and supplies

18 (1) The sampling equipment and supplies are to be selected in accordance with sections 6.1 to 6.4 of EPA Method 325A.

Sampling tubes

(2) Sampling tubes must meet the specifications set out in section 3.8 of EPA Method 325A.

Sorbent

(3) The sorbent used in the sampling tubes is to be selected in accordance with sections 7.1 to 7.1.6 of EPA Method 325B.

Placement of sampling tubes

19 (1) The number of sampling tubes and their placement at the fenceline are to be established in accordance with sections 8.1 to 8.2.3.2 of EPA Method 325A.

Deployment procedures

(2) The procedures described in sections 8.5 to 8.5.10 of EPA Method 325A are to be followed in deploying the sampling tubes and field blanks at the facility.

Sampling and analysis

20 (1) The collection and analysis of samples, including field blanks and duplicate samples, under the fenceline monitoring program must meet all of the following requirements:

  • (a) subject to subsection (2), samples must be collected every 14th day during the period beginning on April 1 and ending on December 22 of each year and must be analyzed within the time required by section 8.5.4 of EPA Method 325B;
  • (b) the gas chromatography and mass spectrometry equipment must meet the requirements set out in sections 6.8 to 6.10 of EPA Method 325B;
  • (c) the laboratory reagents and standard compounds used must meet the requirements of sections 7.2 to 7.6 of EPA Method 325B;
  • (d) the method detection limit of the gas chromatograph for benzene and 1,3-butadiene, as well as other retainable VOCs, is to be determined in accordance with section 9.6 of EPA Method 325B;
  • (e) the analytical bias, the analytical precision and the field replicate precision are to be determined in accordance with sections 9.7, 9.8 and 9.9, respectively, of EPA Method 325B;
  • (f) the sample desorption efficiency and the compound recovery and audit are to be in accordance with sections 9.10 to 9.11 of EPA Method 325B; and
  • (g) if the concentration of a sample is below the method detection limit referred to in paragraph (d), that method detection limit is to be used as the sampling result.

Exception — semi-annual sampling for 1,3-butadiene

(2) If the concentration of 1,3-butadiene in 19 consecutive samples collected at a location at the fenceline in accordance with subsection (1) remains below the method detection limit referred to in paragraph (1)(d), samples collected at that location must thereafter be analyzed for 1,3-butadiene only once in every six-month period.

Return to customary sampling frequency

(3) Despite subsection (2), if any sample collected at a location at the frequency referred to in subsection (2) is above the detection limit for 1,3-butadiene, samples at that location must thereafter be analyzed for 1,3-butadiene within the time referred to in paragraph (1)(a).

Collection of sampling tubes

21 (1) The sampling tubes and field blanks deployed at the fenceline must be collected in accordance with the procedures set out in sections 8.6 to 8.6.5 of EPA Method 325A.

Storage of sampling tubes

(2) Sampling tubes and field blanks must be stored in accordance with the procedures set out in sections 6.4 to 6.4.2 of EPA Method 325B.

Meteorological station

22 (1) A facility must be equipped with a meteorological station that is maintained and operated in accordance with sections 8.3 to 8.3.3 of EPA Method 325A.

Meteorological data

(2) The meteorological data referred to in section 8.3.4 of EPA Method 325A must be collected at the meteorological station in accordance with that section.

Calibration of instruments

(3) The calibration procedures set out in sections 2.5 to 2.5.2.6, 3.4 to 3.4.2, and 7.5 of the standard entitled Quality Assurance Handbook for Air Pollution Measurement Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final) (EPA-454/B-08-002) issued by the Environmental Protection Agency of the United States must be followed for the meteorological instruments at the meteorological station.

Quality control procedures

23 (1) All quality control procedures for sampling and analysis must be in accordance with those set out in sections 9.0 to 9.5 and 9.12 to 9.17 of EPA Method 325B.

Calibration and standardization protocols

(2) The calibration and standardization protocols for the gas chromatography and mass spectrometry equipment must be in accordance with those set out in sections 10.0 to 10.9.5.2 of EPA Method 325B.

Field blanks

(3) At least two field blanks are to be collected and processed in each sampling period in accordance with the procedures set out in sections 9.3 to 9.3.2 of EPA Method 325A.

Total concentration of retainable VOCs

24 (1) The total concentration of retainable VOCs is to be calculated by adding together the concentrations of all retainable VOCs.

Data analysis

(2) The annual average concentrations of benzene and 1,3-butadiene, as well as the annual average concentration of all retainable VOCs taken together, from each sampling location at the fenceline are to be calculated using the methodology set out in sections 12.0 and 12.1 of EPA Method 325A.

Record-keeping requirements

25 (1) The operator must, for each calendar year, keep a record of the following information:

  • (a) any changes made to the fenceline, the sampling locations at the fenceline or the number of those sampling locations during that year;
  • (b) a description of the analysis used to determine the changes referred to in paragraph (a);
  • (c) for each sampling period in that year,
    • (i) the measured concentrations of benzene and 1,3-butadiene, as well as the total concentration of all retainable VOCs taken together, at each sampling location, together with the measured concentrations of those substances from each field blank and duplicate sample, and
    • (ii) the meterological data collected in accordance with subsection 22(2); and
  • (d) the annual average concentrations of benzene and 1,3-butadiene, as well as the annual average total concentration of all retainable VOCs taken together, at each sampling location, calculated in accordance with section 24.

Retention period

(2) The operator must retain the record referred to in subsection (1), as well as any supporting documents, for at least five years. The record and documents must be kept at the facility.

Reporting Requirements

Information to be provided on request

26 The operator must, without delay, submit to the Minister, on the Minister’s request, a copy of any record required to be kept by the operator under these Regulations.

Information to be submitted by existing facility

27 (1) The operator of a facility that was operating before January 1, 2018 must, not later than January 31, 2018, submit the following information to the Minister:

  • (a) the name of the operator of the facility;
  • (b) the civic address and the name, if any, of the facility;
  • (c) the name, title, civic and postal addresses, telephone number and email address of a contact person;
  • (d) the facility’s National Pollutant Release Inventory identification number; and
  • (e) an indication of whether the primary activity in which the facility is engaged is petroleum refining, upgrading of heavy crude oil or bitumen or petrochemical production.

Information to be submitted by new facility

(2) The operator of a facility that begins operating on or after January 1, 2018 must, not later than 30 days after the day on which the facility begins operating, submit to the Minister, in respect of that facility, the information referred to in paragraphs (1)(a) to (e).

Fenceline monitoring plan to be submitted by existing facility

28 (1) The operator of a facility that was operating before January 1, 2018 must, not later than April 30, 2018, submit to the Minister a fenceline monitoring plan for the facility that contains

  • (a) a description of the fenceline selected under subsection 17(2) and of the analysis used to select the fenceline; and
  • (b) each sampling location, as well as the total number of sampling locations, established as required by subsection 19(1), and a description of the analysis used to determine those locations and their total number.

Fenceline monitoring plan to be submitted by new facility

(2) The operator of a facility that begins operating on or after January 1, 2018 must, not later than four months after the facility begins operating, submit to the Minister, in respect of that facility, a fenceline monitoring plan for the facility that contains the information referred to in paragraphs (1)(a) and (b).

Fenceline monitoring report to be submitted in 2019

29 (1) The operator of a facility must, not later than April 30, 2019, submit a fenceline monitoring report to the Minister that contains, for the period beginning on July 1, 2018 and ending on December 31, 2018, the information described in section 34 in respect of the facility.

Annual report to be submitted in 2020

(2) The operator of a facility must, not later than June 30, 2020, submit a report to the Minister that contains, in respect of that facility,

  • (a) for the period beginning on July 1, 2019 and ending on December 31, 2019, the information described in sections 30 to 33; and
  • (b) for the period beginning on January 1, 2019 and ending on December 31, 2019, the information described in section 34.

Annual report beginning in 2021

(3) The operator of a facility must, beginning in 2021, submit a report to the Minister on or before June 30 in each year, that contains the information described in sections 30 to 34 in respect of the facility for the preceding calendar year.

Information to be provided for each inspection

(4) For equipment components at the facility that are required by subsection 6(1) to be inspected three times per calendar year, the information required by subsection (3) must be provided in the annual report for each of those three inspections.

Equipment components inspected under subsection 6(1) or (2)

30 (1) The annual report must contain, with respect to the equipment components that are required to be inspected under subsection 6(1) or (2) and that are set out by type in Schedule 1, the number of each of those types of equipment components

  • (a) that were inspected using a portable monitoring instrument that meets the requirements of subsection 5(1);
  • (b) in which a leak was detected using a portable monitoring instrument that meets the requirements of subsection 5(1) and, as measured by that instrument, was
    • (i) greater than or equal to 500 ppmv and less than 1,000 ppmv,
    • (ii) greater than or equal to 1,000 ppmv and less than 10,000 ppmv, or
    • (iii) greater than or equal to 10,000 ppmv;
  • (c) that were inspected using an optical gas-imaging instrument that meets the requirements of subsection 5(2);
  • (d) in which a leak was detected using an optical gas-imaging instrument that meets the requirements of subsection 5(2) and, as measured by a portable monitoring instrument that meets the requirements of subsection 5(1), was
    • (i) greater than or equal to 500 ppmv and less than 1,000 ppmv,
    • (ii) greater than or equal to 1,000 ppmv and less than 10,000 ppmv, or
    • (iii) greater than or equal to 10,000 ppmv;
  • (e) that were not inspected using a leak detection instrument that meets the requirements of subsection 5(1) or (2);
  • (f) that were repaired
    • (i) within 15 days after the day on which a significant leak was detected in the equipment components,
    • (ii) more than 15 days but not more than 60 days after the day on which a significant leak was detected in the equipment components, or
    • (iii) more than 60 days after the day on which a significant leak was detected in the equipment components; and
  • (g) in which a significant leak was identified but not repaired as of the date of the report.
  • Total number of equipment components by type
  • (2) The annual report must contain the total number of each type of equipment component referred to in subsection (1).

Estimated VOC releases

(3) The annual report must contain, for the equipment components referred to in subsection (1), the estimated total annual quantity of VOCs, expressed in kilograms, that is released by the total number of each type of equipment component during the calendar year that is the subject of the report, calculated in accordance with the instructions set out in Schedule 2.

Equipment components in inventory

31 The annual report must contain, with respect to the equipment components that are included in the inventory referred to in subsection 4(1) and that are set out by type in Schedule 1, the number of each of those types of equipment components

  • (a) in which a leak was detected by using sensory methods, including auditory, visual or olfactory methods, or as a result of an indication from a sensor that the equipment component’s barrier fluid system had failed, and as measured by a portable monitoring instrument that meets the requirements of subsection 5(1), was
    • (i) greater than or equal to 500 ppmv and less than 1,000 ppmv,
    • (ii) greater than or equal to 1,000 ppmv and less than 10,000 ppmv, or
    • (iii) greater than or equal to 10,000 ppmv;
  • (b) in which a significant leak was detected by using sensory methods, including auditory, visual or olfactory methods,or as a result of an indication from a sensor that the equipment component’s barrier fluid system had failed, and that were repaired
    • (i) within 15 days after the day on which the significant leak was detected,
    • (ii) more than 15 days but not more than 60 days after the day on which the significant leak was detected, or
    • (iii) more than 60 days after the day on which the significant leak was detected;
  • (c) in which a significant leak was detected by using sensory methods, including auditory, visual or olfactory methods, or as a result of an indication from a sensor that the equipment component’s barrier fluid system had failed, but not repaired as of the date of the report;
  • (d) in which a significant leak was detected for the third time in 24 consecutive months;
  • (e) described in paragraph (d) that were replaced with a new component as required by subsection 8(6);
  • (f) that were replaced with a certified low-leaking valve or re-packed with certified low-leaking valve packing as required by subsection 8(7);
  • (g) for which it was determined that no certified low-leaking valve and no certified low-leaking valve packing referred to in subsection 8(8) was commercially available;
  • (h) that meet the requirements of paragraph 6(3)(a); and
  • (i) that are described in paragraph 6(3)(b).
  • Reasons for no inspection
  • 32 The annual report must contain, for each equipment component listed in the inventory that was not inspected using a leak detection instrument in accordance with subsection 6(1) or (2), as applicable, the reasons why it was not inspected in accordance with the applicable subsection.

Significant leak not repaired within 15 days

33 The annual report must contain, in respect of each equipment component that was not repaired within 15 days after the day on which a significant leak was detected in the equipment component,

  • (a) the day on which the significant leak was detected;
  • (b) an indication of whether the equipment component was flagged for repair under paragraph 8(4)(a) or (b) or not flagged for repair at all;
  • (c) the reasons why the equipment component could not be repaired within that period; and
  • (d) if the equipment component was repaired, the day on which the repair was completed.

Fenceline monitoring data

34 The fenceline monitoring report and the annual report must contain the following information in respect of the fenceline monitoring program:

  • (a) an indication of any changes made to the fenceline, the sampling locations at the fenceline or the number of those sampling locations;
  • (b) a description of the analysis used to determine the changes referred to in paragraph (a);
  • (c) for each sampling period,
    • (i) the measured concentrations of benzene and 1,3-butadiene, as well as the total concentration of all retainable VOCs taken together, at each sampling location, together with the measured concentrations of those substances from each field blank and duplicate sample, and
    • (ii) the meterological data collected in accordance with subsection 22(2); and
  • (d) the annual average concentrations of benzene and 1,3-butadiene, as well as the annual average concentration of all retainable VOCs taken together, at each sampling location, calculated in accordance with section 24.
  • Auditor’s report
  • 35 (1) The operator of a facility must, on or before June 30 in each year, beginning in 2021, submit to the Minister a report prepared by an auditor that assesses the compliance of the operator with these Regulations in respect of the facility during the preceding calendar year.

Assessment

(2) The auditor’s report must indicate whether the operator’s equipment, procedures and records are, in the auditor’s opinion, appropriate to ensure compliance by the operator with these Regulations.

Contents

(3) The auditor’s report must contain the following:

  • (a) the name, civic and postal addresses, telephone number, email address and qualifications of the auditor;
  • (b) details of how the auditor made the assessments required by subparagraphs (c)(i) to (xiv);
  • (c) the auditor’s assessment of
    • (i) whether the inventory of equipment components was established and maintained in accordance with subsection 4(3),
    • (ii) whether inspections of equipment components were carried out in accordance with subsections 6(1) and (4) and whether records in respect of those inspections were kept in accordance with paragraphs 9(1)(c) and (2)(b),
    • (iii) whether the leak detection instruments used to conduct the inspections referred to in subsection 6(1) were operated, maintained and calibrated in accordance with section 5, based on the auditor’s observation of the calibration and inspection techniques and practices used at the facility, and whether records in respect of those instruments were kept in accordance with paragraphs 9(1)(a) and (b) and (2)(a),
    • (iv) whether sensors were checked in accordance with subsection 6(5) and whether records in respect of those checks were kept in accordance with paragraph 9(1)(e),
    • (v) whether records of the training received by the individuals conducting inspections in accordance with subsection 6(1) were kept in accordance with subsection 7(2),
    • (vi) whether the records required under these Regulations, as well as any supporting documents, were retained at the facility in accordance with subsection 7(3), section 10, subsection 16(2) and subsection 25(2),
    • (vii) whether equipment components that had a significant leak were repaired or replaced in accordance with section 8 and whether records in respect of those repairs and replacements were kept in accordance with paragraphs 9(1)(g) to (k),
    • (viii) whether the ends of open-ended pipes were plugged in accordance with section 12 and whether the required records in respect of those pipes were kept in accordance with paragraph 16(1)(a),
    • (ix) whether sampling systems connected to a pipe were designed and used in accordance with section 13 and whether the required records in respect of those sampling systems were kept in accordance with paragraph 16(1)(b),
    • (x) whether pressure relief devices were designed and used in accordance with section 14 and whether the required records in respect of those pressure relief devices were kept in accordance with paragraph 16(1)(c),
    • (xi) whether compressors were equipped with mechanical seal systems in accordance with section 15 and whether the required records in respect of those compressors were kept in accordance with paragraph 16(1)(d),
    • (xii) whether the fenceline monitoring program was established and maintained in accordance with sections 17 to 25,
    • (xiii) whether the annual report contains the information required by sections 30 to 34 and whether it was submitted to the Minister in accordance with section 29, and
    • (xiv) if applicable, whether the corrective action plan submitted to the Minister in accordance with section 36 for the calendar year preceding 12the calendar year that is the subject of the auditor’s report was implemented;
  • (d) if, in the opinion of the auditor, the operator of the facility was in compliance with these Regulations, a statement to that effect;
  • (e) if, in the opinion of the auditor, the operator failed to comply with any requirements of these Regulations, an indication of those requirements; and
  • (f) a statement by the auditor that the auditor is independent of the operator of the facility that is the subject of the audit and has no conflict of interest with the operator or any contractor who carries out any activity required by these Regulations on behalf of the operator.

Signature

(4) The auditor’s report must be signed by a licensed member of an engineering or scientific professional organization who is

  • (a) if the auditor is an individual, the auditor; or
  • (b) if the auditor is a firm, a duly authorized representative of that firm.

Corrective action plan

36 If the auditor’s report identifies any requirements of these Regulations with which the operator failed to comply, the operator must, on or before June 30 of each year, submit to the Minister a corrective action plan that sets out the measures that the operator has already taken or plans to take in order to meet those requirements.

Audit by individual or firm

37 (1) The audit must be conducted by an individual or a firm that

  • (a) is independent of the operator of the facility that is the subject of the audit; and
  • (b) has no conflict of interest with the operator or any contractor who carries out any activity required by these Regulations on behalf of the operator.

Qualifications of auditing individual

(2) If the audit is conducted by an individual, including an individual who is a member of a firm, the individual must

  • (a) be a licensed member of an engineering or scientific professional organization;
  • (b) have technical expertise in leak detection and repair as well as in fenceline monitoring;
  • (c) have completed the training specified in subsection 7(1); and
  • (d) be certified by the International Register of Certificated Auditors, or by any other nationally or internationally recognized accreditation organization, for the purposes of carrying out assessments in accordance with the ISO 14001 standard of the International Organization for Standardization entitled Environmental Management Systems.

Qualifications of auditing members of a firm

(3) If the audit is conducted by two or more individuals who are members of a firm, those members must together meet the requirements set out in subsection (2).

Different auditor required

38 The operator of a facility must not have the facility audited under these Regulations

  • (a) by the same auditor more than twice in every three years; or
  • (b) by an individual or a firm that carried out any activity required by these Regulations on behalf of the operator at the facility during the calendar year for which the audit is being conducted or during the first six months of the following calendar year.

Format of reports and plans

39 (1) A report or plan that is required by these Regulations must be submitted electronically in the format specified by the Minister and must bear the electronic signature of an authorized official.

Non-electronic format for reports and plans

(2) If the Minister has not specified an electronic format, or if it is impractical to submit the report or plan electronically in accordance with subsection (1) because of circumstances beyond the operator’s control, the report or plan must be submitted on paper, signed by an authorized official, and in the form specified by the Minister. However, if no form has been specified, it may be in any form.

Coming into Force

  • January 1, 2018

  • 40 (1) These Regulations, except sections 3 to 16, come into force on January 1, 2018.

  • July 1, 2019

  • (2) Sections 3 to 16 come into force on July 1, 2019.

SCHEDULE 1

(Paragraph 4(1)(a), subsection 30(1) and section 31)

Types of Equipment Components for Inventory and Annual Report

1 Gas valves

2 Light-liquid valves

3 Heavy-liquid valves

4 Light-liquid pumps

5 Heavy-liquid pumps

6 Gas flanges

7 Light-liquid flanges

8 Heavy-liquid flanges

9 Gas connectors other than flanges

10 Light-liquid connectors other than flanges

11 Heavy-liquid connectors other than flanges

12 Gas pressure relief devices

13 Light-liquid pressure relief devices

14 Heavy-liquid pressure relief devices

15 Compressors

16 Gas open-ended pipes

17 Light-liquid open-ended pipes

18 Heavy-liquid open-ended pipes

19 Gas sampling connections

20 Light-liquid sampling connections

21 Heavy-liquid sampling connections

22 Gas agitators

23 Light-liquid agitators

24 Heavy-liquid agitators

25 Other gas equipment components

26 Other light-liquid equipment components

27 Other heavy-liquid equipment components

SCHEDULE 2

(Subsection 30(3))

Instructions for Calculating Estimated VOC Releases

1 The following definitions apply in this Schedule.

pegged, in respect of a portable monitoring instrument, describes a reading on the instrument that is above the highest concentration of VOCs that the instrument is capable of measuring. (arrimée)

screening value means the measured concentration of VOCs, expressed in ppmv, that is determined in the course of the inspection of an equipment component using a portable monitoring instrument. (concentration mesurée)

2 (1) Determine the hourly leak rate of an equipment component of a type set out in column 1 of the table to this Schedule by selecting the applicable hourly leak rate expressed in kilograms per hour (kg/hr) as follows:

  • (a) if the screening value is zero, or if the inspection was carried out using an optical gas-imaging instrument and no leak was detected, select the hourly default zero leak rate set out for that type of equipment component in column 2 of the table;
  • (b) if the reading on the portable monitoring instrument is pegged, select the hourly pegged leak rate set out for that type of equipment component in column 3 of the table;
  • (c) in any other case, insert the screening value (SV) in the correlation equation set out for that type of equipment component in column 4 of the table to arrive at the hourly correlation equation leak rate.

(2) For the purpose of subsection (1),

  • (a) for an equipment component located at a facility that is primarily engaged in activities classified under North American Industry Classification System (NAICS) code 325, select the corresponding hourly leak rate for that type of equipment component set out in one of items 1 to 8 of the table to this Schedule, as applicable;
  • (b) for an equipment component located at any other facility, select the corresponding hourly leak rate for that type of equipment component set out in one of items 9 to 14 of the table to this Schedule, as applicable.

3 Determine the estimated annual quantity of VOCs, expressed in kilograms, that is released by the equipment component during the calendar year that is the subject of the annual report, by adding together the hourly leak rates, selected for that equipment component in accordance with section 4, for every hour in the applicable calendar year.

4 (1) For the purpose of section 3, for every hour in the calendar year referred to in that section, select the applicable hourly leak rate determined under paragraph 2(1)(a), (b) or (c) that is based on the inspection closest to that hour, whether the inspection took place in that calendar year or in the preceding or subsequent calendar year.

(2) If the number of hours between the hour referred to in subsection (1) and the preceding and subsequent inspection is the same, select the applicable hourly leak rate referred to in subsection (1) that is based on the preceding inspection.

(3) Despite subsection (1), if an inspection indicates that there is a significant leak in the equipment component, select the hourly leak rate determined on the basis of that inspection for every hour from that inspection up to the hour when the equipment component is repaired.

5 For the purpose of subsection 30(3) of these Regulations, determine the estimated total annual quantity of VOCs, expressed in kilograms, that is released by the total number of each type of equipment component during the applicable calendar year by adding together the estimated annual quantity of VOCs released by each equipment component of that type determined in accordance with section 3.

Equipment Component Hourly Leak Rates

  Column 1 Column 2 Column 3 Column 4
Item Type of Equipment
Component
Hourly Default Zero Leak Rate (kg/hr per equipment component) Hourly Pegged Leak Rate
(kg/hr per equipment component)
Hourly Correlation Equation Leak Rate (kg/hr per equipment component)

Hourly Leak Rates for Facilities Primarily Engaged in Activities Under NAICS Code 325

1

Gas valve

6.60E-07

0.11

1.87E-06 × SV0.873

2

Light-liquid valve

4.90E-07

0.15

6.41E-06 × SV0.797

3

Heavy-liquid valve

4.90E-07

0.15

6.41E-06 × SV0.797

4

Pump, compressor, pressure relief device, agitator

7.50E-06

0.62

1.90E-05 × SV0.824

5

Connector (other than a flange)

6.10E-07

0.22

3.05E-06 × SV0.885

6

Flange

3.10E-07

0.084

4.61E-06 × SV0.703

7

Open-ended pipe

2.00E-06

0.079

2.20E-06 × SV0.704

8

Any equipment component other than one referred to in items 1 to 7

4.00E-06

0.11

1.36E-05 × SV0.589

Hourly Leak Rates for All Other Facilities

9

Valve

7.80E-06

0.14

2.29E-06 × SV0.746

10

Pump

2.40E-05

0.16

5.03E-05 × SV0.610

11

Connector (other than a flange)

7.50E-06

0.03

1.53E-06 × SV0.735

12

Flange

3.10E-07

0.084

4.61E-06 × SV0.703

13

Open-ended pipe

2.00E-06

0.079

2.20E-06 × SV0.704

14

Any equipment component other than one referred to in items 9 to 13

4.00E-06

0.11

1.36E-05 × SV0.589

[21-1-o]

  • Footnote 1
    Presented in present value terms using a 7% discount rate, in 2012 Canadian dollars, consistent with the Red Tape Reduction Regulations.
  • Footnote 2
    Fugitive leaks are also known as unintentional leaks and are typically characterized as unplanned releases due to spills or leaks from valves, piping, flanges, etc.
  • Footnote 3
    Assessments of 1,3-butadiene and benzene were conducted under the Priority Substances List (PSL) program and are available at http://www.hc-sc.gc.ca/ewh-semt/pubs/contaminants/psl2-lsp2/1_3_butadiene/index-eng.php and http://www.hc-sc.gc.ca/ewh-semt/pubs/contaminants/psl1-lsp1/benzene/index-eng.php, respectively. A screening assessment of isoprene was conducted under the Challenge program and is available at https://www.ec.gc.ca/ese-ees/default.asp?lang=En&n=07560A9B-1.
  • Footnote 4
    Screening assessments of three groups of PRGs were conducted under the Petroleum Sector Stream Approach. The final screening assessment of site-restricted PRGs is available at http://www.ec.gc.ca/ese-ees/default.asp?lang=En&n=08D395AD-1. The final screening assessment of industry-restricted PRGs is available at http://www.ec.gc.ca/ese-ees/default.asp?lang=En&n=D5D72B57-1. The draft screening assessment of PRGs that may be present in consumer products is available at http://www.ec.gc.ca/ese-ees/default.asp?lang=En&n=68B79EB3-1.
  • Footnote 5
    Bitumen, the primary product of the Alberta oil sands, needs to be upgraded into SCO or diluted with lighter hydrocarbons before being further processed or transported via pipeline.
  • Footnote 6
    National Energy Board, https://apps.neb-one.gc.ca/CommodityStatistics/Statistics.aspx?language=english.
  • Footnote 7
    A more detailed comparison of the proposed Regulations with existing programs is available upon request.
  • Footnote 8
    Environmental Code of Practice for the Measurement and Control of Fugitive VOC Emissions from Equipment Leaks. http://www.ccme.ca/files/Resources/air/emissions/pn_1106_e.pdf. October 1993.
  • Footnote 9
    Method 21 — Determination of Volatile Organic Compound Leaks, U.S. Code of Federal Regulations, Title 40, chapter I, part 60 (40 CFR part 60), Appendix A. https://www.gpo.gov/fdsys/pkg/CFR-2013-title40-vol8/pdf/CFR-2013-title40-vol8-part60-appA-id14.pdf.
  • Footnote 10
    Clean Air Regulation under the Quebec Environment Quality Act. http://legisquebec.gouv.qc.ca/en/ShowDoc/cr/Q-2,%20r.%204.1.
  • Footnote 11
    Petrochemical - Industry Standard (for selected contaminants) and Petroleum Refining - Industry Standard (for selected contaminants), under the Ontario Local Air Quality Regulation. https://www.ontario.ca/document/technical-standards-manage-air-pollution/petroleum-refining-industry-standard and https://www.ontario.ca/document/technical-standards-manage-air-pollution/petrochemical-industry-standard. July 27, 2016.
  • Footnote 12
    Method 325A — Volatile Organic Compounds from Fugitive and Area Sources: Sampler Deployment and VOC Sample Collection, U.S. Code of Federal Regulations, Title 40, chapter I, part 63 (40 CFR part 63), Appendix A. https://www.epa.gov/sites/production/files/2016-07/documents/m-325a.pdf.
  • Footnote 13
    Method 325B — Volatile Organic Compounds from Fugitive and Area Sources: Sampler Preparation and Analysis, U.S. Code of Federal Regulations, Title 40, chapter I, part 63 (40 CFR part 63), Appendix A. https://www.epa.gov/sites/production/files/2016-07/documents/m-325b.pdf.
  • Footnote 14
    The current regulatory regime includes measures under the Standards of Performance for New Stationary Sources (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) programs. Information on the NSPS program is available at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/new-source-performance-standards-and. Information on the NESHAP program is available at https://www.epa.gov/stationary-sources-air-pollution/national-emission-standards-hazardous-air-pollutants-neshap-9.
  • Footnote 15
    There are no upgraders in the United States.
  • Footnote 16
    Information on the Petroleum Refinery Initiative is available at https://www.epa.gov/enforcement/petroleum-refinery-national-case-results.
  • Footnote 17
    The Designation Regulations are available at https://www.ec.gc.ca/lcpe-cepa/eng/regulations/detailReg.cfm?intReg=206.
  • Footnote 18
    The term “stakeholders” refers to any organizations or individuals from industry and non-governmental organizations (NGOs).
  • Footnote 19
    The Department’s estimated leak fractions and emission rates for Canadian facilities are available upon request.
  • Footnote 20
    Analysis of Emissions Reduction Techniques for Equipment Leaks, prepared for the U.S. EPA by RTI International, December 2011, EPA Docket No. EPA-HQ-OAR-2010-0869. Available at https://www.regulations.gov/document?D=EPA-HQ-OAR-2015-0216-0034.
  • Footnote 21
    Guideline for Measurement and Control of Fugitive Hydrocarbons Emissions.
  • Footnote 22
    Emissions Estimation Protocol for Petroleum Refineries, version 3, pages 2–17, prepared for the U.S. EPA by RTI International, April 2015. https://www3.epa.gov/ttn/chief/efpac/protocol/Protocol%20Report%202015.pdf.
  • Footnote 23
    Intergovernmental Panel on Climate Change (IPCC), Fourth Assessment Report (AR4), 2007.
  • Footnote 24
    Technical Update to Environment and Climate Change Canada’s Social Cost of Greenhouse Gas Estimates. http://ec.gc.ca/cc/default.asp?lang=En&n=BE705779-1. March 2016.
  • Footnote 25
    After-tax cash flow is a cash-based (i.e. non-accrual) profit metric whereby operating costs, capital costs and taxes are subtracted from revenue. It is a metric commonly used in project-level financial analysis.
  • Footnote 26
    Controlling Administrative Burden That Regulations Impose on Business: Guide for the ‘One-for-One’ Rule. http://www.tbs-sct.gc.ca/rtrap-parfa/cabtrib-lfarie/cabtrib-lfarie07-eng.asp.
  • Footnote 27
    For the purposes of the small business lens, the Treasury Board of Canada Secretariat defines a small business as any business, including its affiliates, that has fewer than 100 employees or between $30,000 and $5M in annual gross revenue. Hardwiring Sensitivity to Small Business Impacts of Regulation: Guide for the Small Business Lens (http://www.tbs-sct.gc.ca/rtrap-parfa/guides-eng.asp).
  • Footnote 28
    Risk Management Approach: Petroleum and Refinery Gases [Site-Restricted]. http://www.ec.gc.ca/ese-ees/default.asp?lang=En&n=62D588DD-1. June 2013.
  • Footnote 29
    The final screening assessment report for natural gas condensates (December 2016) is available at http://www.ec.gc.ca/ese-ees/default.asp?lang=En&n=7933A3C7-1.
  • Footnote 30
    The risk management approach document for natural gas condensates (December 2016) is available at http://www.ec.gc.ca/ese-ees/default.asp?lang=En&n=BBE4B27E-1.
  • Footnote 31
    This agreement was established in 1991 to address transboundary air pollution, such as sulphur dioxides and nitrogen oxides, and was amended in 2000 to address ground-level O3 as a precursor of smog.
  • Footnote 32
    Ontario also requires petrochemical facilities to conduct year-round fenceline monitoring for benzene and 1,3-butadiene.
  • Footnote 33
    Information on the Strategic Environmental Assessment of the CMP is available at http://www.chemicalsubstanceschimiques.gc.ca/plan/sea-ees-eng.php.
  • Footnote 34
    Environment and Climate Change Canada’s Compliance and Enforcement Policy for the Canadian Environmental Protection Act, 1999 is available at http://www.ec.gc.ca/alef-ewe/default.asp?lang=en&n=AF0C5063-1.
  • Footnote *
    Source: RTI Memo and stakeholder feedback.
  • Footnote a
    Numbers may not add up due to rounding.
  • Footnote b
    Including net benefits from CO2e of GHG emission reduction.
  • Footnote c
    Including costs of OGI cameras, inspections and repairs.
  • Footnote d
    S.C. 2004, c. 15, s. 31
  • Footnote e
    S.C. 1999, c. 33