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EXTRA Vol. 152, No. 1

Canada Gazette

Part Ⅱ

OTTAWA, THURSDAY, APRIL 26, 2018

Registration

SOR/2018-66 April 4, 2018

CANADIAN ENVIRONMENTAL PROTECTION ACT, 1999

P.C. 2018-396 April 3, 2018

Whereas, pursuant to subsection 332(1) footnote a of the Canadian Environmental Protection Act, 1999 footnote b , the Minister of the Environment published in the Canada Gazette ,

Part I, on May 27, 2017, a copy of the proposed Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) , substantially in the annexed form, and persons were given an opportunity to file comments with respect to the proposed Regulations or to file a notice of objection requesting that a board of review be established and stating the reasons for the objection;

Whereas, pursuant to subsection 93(3) of that Act, the National Advisory Committee has been given an opportunity to provide its advice under

section 6 footnote c of that Act;

And

whereas, in accordance with subsection 93(4) of that Act, the Governor in Council is of the opinion that the proposed Regulations do not regulate an aspect of a substance that is regulated by or under any other Act of Parliament in a manner that provides, in the opinion of the Governor in Council, sufficient protection to the environment and human health;

Therefore, Her Excellency the Governor General in Council, on the recommendation of the Minister of the Environment and the Minister of Health, pursuant to subsection 93(1),

section 286.1 footnote d and subsection 330(3.2) footnote e of the Canadian Environmental Protection Act, 1999 footnote b , makes the annexed Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) .

Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector)

Purpose and Overview

Protection of environment and reduction of harmful effects

1 For the purpose of protecting the environment on which life depends and of reducing the immediate or long-term harmful effects of the emission of methane and certain volatile organic compounds on the environment or its biological diversity, these Regulations

(

a) impose certain requirements on the oil and gas sector in order to reduce emissions of methane and certain volatile organic compounds; and

(

b) designate the contravention of certain of its provisions as serious offences by adding them to the

schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) .

Interpretation

Definitions

(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 their 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 another entity, an individual who is authorized to act on its behalf. ( agent autorisé )

combustion device means a device in which gaseous fuel is combusted to produce useful heat or energy. ( appareil à combustion )

completion means the process of making a well ready for production, including such a process that involves hydraulic fracturing. ( complétion )

deliver means to transport hydrocarbon gas from an upstream oil and gas facility for a purpose other than to dispose of the gas as waste. ( livrer )

design bleed rate means the rate, expressed in standard m 3 /h, at which gas is expected, according to the manufacturer of a pneumatic controller, to be continuously emitted from the pneumatic controller while it operates at a given operational setting specified by the manufacturer. ( taux de purge nominal )

destroy means to convert hydrocarbons contained in hydrocarbon gas to carbon dioxide and other molecules for a purpose other than to produce useful heat or energy, and includes the flaring of hydrocarbon gas. ( détruire )

Dominion Lands Survey system means the system for the survey of public lands referred to in sections 54 to 70 of the Dominion Lands Act ,

chapter 55 of the Revised Statutes of Canada, 1906 that is used in Manitoba, Saskatchewan and Alberta under the name the Dominion Lands Survey system. ( système d’arpentage des terres fédérales )

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

Part 60 of Title 40,

chapter I of the Code of Federal Regulations of the United States. ( méthode 21 de l’EPA )

equipment component means a component of equipment at an upstream oil and gas facility that comes into contact with hydrocarbons and that has the potential to emit fugitive emissions of hydrocarbon gas. ( composant d’équipement )

flowback means the process of recovering fluids, or fluids mixed with solids, that were injected into a well during hydraulic fracturing in order

(

a) to prepare for further hydraulic fracturing;

(

b) to prepare for cleanup of the well; or

(

c) to initiate or resume production from the well. ( reflux )

fugitive , in relation to emissions of hydrocarbon gas, means the emission of hydrocarbon gas from an upstream oil and gas facility in an unintentional manner. ( fugitive )

gas-to-oil ratio means the ratio of the volume of hydrocarbon gas produced, expressed in standard m 3 , to the volume of hydrocarbon liquid produced, expressed in standard m 3 . ( rapport gaz-pétrole )

hydraulic fracturing means the process of injecting fluids, or fluids mixed with solids, under pressure into a well in order to create fractures in an underground geological reservoir through which hydrocarbons and other fluids can migrate toward the well and includes hydraulic refracturing, namely, hydraulic fracturing at a well that has previously undergone hydraulic fracturing. ( fracturation hydraulique )

hydrocarbon means methane, which has the molecular formula CH 4 , or a volatile organic compound referred to in item 65 of the List of Toxic Substances in

Schedule 1 to the Canadian Environmental Protection Act, 1999 . ( hydrocarbure )

hydrocarbon gas conservation equipment means equipment used to recover hydrocarbon gas for use as fuel, for delivery or for injection for a purpose other than to dispose of the gas as waste into an underground geological deposit. ( équipment de conservation de gaz d’hydrocarbures )

legal subdivision means a unit of land consisting of one quarter of a quarter-section and having an area of approximately 16 ha or 400 m by 400 m that is described in the Dominion Lands Survey system. ( subdivision officielle )

natural gas gathering and boosting station means equipment that is located within a facility and that is used for the transportation of natural gas to a processing plant or natural gas transmission pipeline. ( station de collecte et de surpression de gaz naturel )

natural gas processing plant means a plant used for the separation of

(

a) natural gas liquids (NGLs) or non-methane gases from produced natural gas; or

(

b) NGLs into two or more mixtures, each of which consists of only those NGLs. ( usine de traitement de gaz naturel )

natural gas transmission compressor station means equipment that is located within a facility and that is used for the transportation of natural gas through a natural gas transmission pipeline. ( station de compression de gaz naturel )

operator means a person who has the charge, management or control of an upstream oil and gas facility. ( exploitant )

pneumatic controller means a device that uses pressurized gas to generate mechanical energy for the purpose of controlling or maintaining the conditions under which a process is carried out. ( régulateur pneumatique )

pneumatic pump means a device that uses pressurized gas to generate mechanical energy for the purpose of pumping liquid. ( pompe pneumatique )

ppmv means parts per million by volume. ( ppmv )

primary processing means any processing of hydrocarbons that is for the principal purpose of removing any of, or any combination of, the following:

(

a) water;

(

b) hydrocarbon liquids;

(

c) sulphur compounds; and

(

d) contaminants. ( traitement primaire )

produce , in relation to hydrocarbon gas or liquid, means to extract hydrocarbon gas or liquid from an underground geological deposit or reservoir. ( produire )

receive , in relation to hydrocarbon gas, means to receive at an upstream oil and gas facility, other than from a natural source, hydrocarbon gas that is raw or has undergone primary processing without having been subject to additional processing. ( recevoir )

standard conditions means a temperature of 15°C and a pressure of 101.325 kPa. ( conditions normalisées )

standard m 3 means a cubic metre of fluid at standard conditions. ( m 3 normalisé )

upstream oil and gas facility means the buildings, other structures and stationary equipment — that are located on a single site, on contiguous or adjacent sites or on sites that form a network in which a central processing site is connected by gathering pipelines with one or more well sites — for the purpose of

(

a) the extraction of hydrocarbons from an underground geological deposit or reservoir;

(

b) the primary processing of those hydrocarbons; or

(

c) the transportation of hydrocarbons — including their storage for transportation purposes — other than for local distribution.

It includes a gathering pipeline, transmission pipeline, natural gas gathering and boosting station, natural gas transmission compressor station and natural gas processing plant. ( installation de pétrole et de gaz en amont )

venting , in relation to emissions of hydrocarbon gas, means the emission of hydrocarbon gas from an upstream oil and gas facility in a controlled manner, other than the emission of gas arising from combustion, due to

(

a) the design of equipment or operational procedures at the facility; or

(

b) the occurrence of an event that pressurizes the gas beyond the capacity of the equipment at the facility to retain the gas. ( évacuation )

well includes a well drilled to allow for the injection of fluids or fluids mixed with solids. ( puits )

Interpretation of documents incorporated by reference

(2) For the purpose of interpreting any document that is incorporated by reference into these Regulations, “should” must be read to mean “must” and any recommendation or suggestion must be read as an obligation, unless the context requires otherwise. For greater certainty, the context of the accuracy or repeatability of a measurement can never require otherwise.

Inconsistency

(3) In the event of an inconsistency between a provision of these Regulations and any document incorporated by reference into these Regulations, that provision prevails to the extent of the inconsistency.

Documents incorporated by reference

(4) Any document that is incorporated by reference into these Regulations is incorporated as amended from time to time.

Responsibility

Operator

3 An operator for an upstream oil and gas facility must ensure that a requirement set out in these Regulations in respect of the facility or equipment at the facility — along with any related requirement in respect of recording information, keeping documents and providing reports — is complied with.

PART 1

Onshore Upstream Oil and Gas Facilities

Application

Onshore facilities

4 This Part applies in respect of upstream oil and gas facilities other than those located offshore.

General Requirements

Hydrocarbon Gas Conservation and Destruction Equipment

Hydrocarbon gas conservation equipment

(1) Hydrocarbon gas conservation equipment that is used at an upstream oil and gas facility must

(

a) be operated in such a manner that at least 95% of the hydrocarbon gas that is routed to the equipment — based on a calculation of the volumetric flow rates at standard conditions — is captured and conserved;

(

b) be operating continuously, other than during periods when it is undergoing normal servicing or timely repairs; and

(

c) be operated and maintained in accordance with the applicable recommendations of its manufacturer.

Exception to paragraph (1)(c)

(2) Despite paragraph (1)(c), no recommendation referred to in that paragraph need be treated as a requirement and complied with if the operator for a facility has a record that establishes that without that compliance the hydrocarbon gas conservation equipment’s ability to respect paragraph (1)(

a) is unaffected.

Records — conservation equipment

6 A record in respect of any hydrocarbon gas conservation equipment used at an upstream oil and gas facility must be made that indicates

(

a) for each month during which the equipment is used, the percentage, at any given moment, of the hydrocarbon gas routed to the equipment that is captured and conserved, along with a calculation of the volumetric flow rates on which that percentage is based, with supporting documents; and

(

b) how the equipment was operated and maintained, along with an indication of any recommendations of its manufacturer for its operation and maintenance, with supporting documents.

Conserved gas — use

7 Hydrocarbon gas that has been captured and conserved in hydrocarbon gas conservation equipment must be conserved until it is

(

a) used at the facility as fuel in a combustion device that releases at most 5% of the combusted hydrocarbon gas to the atmosphere as hydrocarbon gas;

(

b) delivered; or

(

c) injected into an underground geological deposit for a purpose other than to dispose of the gas as waste.

Records — conserved gas used as fuel

8 A record in respect of any hydrocarbon gas that is combusted as fuel in a combustion device referred to in paragraph 7(

a) must be made that indicates for each month during which the device is used, the percentage, at any given moment, of the combusted hydrocarbon gas that is released as hydrocarbon gas, with supporting documents, based on

(

a) tests conducted when the device operates under conditions recommended by the manufacturer for determining this percentage; or

(

b) measurements taken when the device operates under those conditions.

Hydrocarbon gas destruction equipment

9 Hydrocarbon gas destruction equipment that is used at an upstream oil and gas facility must satisfy the requirements related to the destruction of hydrocarbon gas set out in

(

a) Sections 3.6 and 7 of Version 4.5 of the guideline entitled Flaring and Venting Reduction Guideline , published by the Oil and Gas Commission of British Columbia in June 2016, if the facility is located in British Columbia;

(

b) section 3 of the directive entitled Directive S-20: Saskatchewan Upstream Flaring and Incineration Requirements , published by the Government of Saskatchewan on November 1, 2015, if the facility is located in Manitoba or Saskatchewan; and

(

c) sections 3.6 and 7 of the directive entitled Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting , published by the Alberta Energy Regulator on March 22, 2016, in any other case.

Records — hydrocarbon gas destruction equipment

10 A record in respect of any hydrocarbon gas destruction equipment used at an upstream oil and gas facility must be made that demonstrates, with supporting documents, that the requirements related to the destruction of hydrocarbon gas set out in the applicable document referred to in

section 9 are satisfied.

Well Completion involving Hydraulic Fracturing

Application

(1) This

section applies in respect of an upstream oil and gas facility that includes a well that undergoes hydraulic fracturing and whose production has a gas-to-oil ratio of at least 53:1, based on the most recent determination of the gas-to-oil ratio prior to the hydraulic fracturing.

No venting

(2) Hydrocarbon gas associated with flowback at a well at an upstream oil and gas facility must not be vented during flowback but must instead be captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment.

Exception

(3) Subsection (2) does not apply if all the gas associated with flowback at the well does not have sufficient heating value to sustain combustion.

Records — hydraulic fracturing

12 A record in respect of each well at an upstream oil and gas facility that undergoes hydraulic fracturing must be made

(

a) that indicates the gas-to-oil ratio, based on the most recent determination of the gas-to-oil ratio prior to the hydraulic fracturing;

(

b) if that gas-to-oil ratio is at least 53:1, that demonstrates, with supporting documents, that the hydrocarbon gas associated with flowback was captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment; and

(

c) if hydrocarbon gas associated with flowback at the well is vented, the heating value of that gas.

Non-application — British Columbia and Alberta

13 Sections 11 and 12 do not apply in respect of an upstream oil and gas facility that is located in

(

a) British Columbia, if the facility is subject to the requirements with respect to well completion involving hydraulic fracturing that are set out in the guideline entitled Flaring and Venting Reduction Guideline , published by the Oil and Gas Commission of British Columbia in June 2016; and

(

b) Alberta, if the facility is subject to the requirements with respect to well completion involving hydraulic fracturing that are set out in the directive entitled Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting , published by the Alberta Energy Regulator on March 22, 2016.

Compressors

Capture or venting of emissions

14 The emissions of hydrocarbon gas from the seals of a centrifugal compressor, or from the rod packings and distance pieces of a reciprocating compressor, that has a rated brake power of 75 kW or more at an upstream oil and gas facility must be

(

a) captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment; or

(

b) routed to vents that release those emissions to the atmosphere.

Measurement of flow rate

15 The flow rate of emissions of hydrocarbon gas released from the vents referred to in paragraph 14(

b) of a compressor must be measured by means of

(

a) a flow meter, other than a calibrated bag, in accordance with

section 16; or

(

b) a continuous monitoring device in accordance with

section 17.

Flow meters

(1) The flow meter must be calibrated in accordance with the manufacturer’s recommendations such that its measurements have a maximum margin of error of ±10%.

Measurements by flow meters

(2) Those measurements must be made

(

a) in accordance with the recommendations set out in the manufacturer’s manual, if any;

(

b) in the case of a measurement made without the use of negative pressure or a vacuum, while there is a tight seal over the vent;

(

c) in the case of a measurement on a centrifugal compressor, when the compressor is operating under conditions that are representative of the conditions during the previous seven days; and

(

d) in the case of a measurement on a reciprocating compressor, when the compressor is pressurized.

Initial and subsequent measurements

(3) The flow rate must be measured within the following periods:

(

a) initially, the period that ends on

(

i) January 1, 2021, if the compressor is installed at the facility before January 1, 2020, and

(ii) the 365th day after the day on which the compressor was installed at the facility, in any other case; and

(

b) subsequently, the period that ends on the 365th day after the day on which a previous measurement was taken.

Measurements — maximum or average

(4) The initial and each subsequent measurement of the flow rate must be based on measurements made by the flow meter over a continuous period of at least five minutes and is

(

a) the maximum of the flow rates measured, if the measurements are made over a continuous period of at least five minutes and less than 15 minutes; or

(

b) the average of the flow rates measured, if the measurements are made over a continuous period of at least 15 minutes.

Extension — not operating or not pressurized

(5) Despite subsection (3), if no measurement has been made by the last day of a period referred to in that subsection — but, on that day, the compressor is not operating, in the case of a centrifugal compressor, or the compressor is not pressurized, in the case of a reciprocating compressor — the measurement must be made under that subsection on or before the 30th day after the day on which the compressor is next operating or pressurized, as the case may be.

Extension — pressurized for < 1,314 hours per 3 years

(6) Despite subsection (3), a period referred to in that subsection is extended by 365 days if the operator for the facility makes a record that demonstrates that, during the three calendar years immediately before the end of the period, the compressor was pressurized for less than 1,314 hours, as determined by an hour meter or as recorded in a log of operations.

Continuous monitoring devices

17 A continuous monitoring device must

(

a) be calibrated in accordance with the recommendations of the manufacturer of the device such that its measurements have a maximum margin of error of ±10%;

(

b) be operated continuously, other than during periods when it is undergoing normal servicing or timely repairs; and

(

c) be equipped with an alarm that is triggered when the applicable flow rate limit referred to in subsection 18(2) or (3) for the vents of the compressor is reached.

Corrective action

(1) If the flow rate of emissions of hydrocarbon gas released from vents referred to in paragraph 14(

b) of a compressor, measured in accordance with subsection 16(2), is greater than the applicable flow rate limit set out in subsection (2) or (3) or if the alarm referred to in paragraph 17(

c) is triggered, corrective action must be taken to reduce that flow rate to below or equal to that limit, as demonstrated by a remeasurement that results,

(

a) when a flow meter is used for the remeasurement, in a reading that is below or equal to that limit; or

(

b) when a continuous monitoring device is used for the remeasurement, in the absence of an alarm when the compressor resumes operation following the taking of the corrective action.

Flow rate limit — centrifugal compressors

(2) For emissions that are from the seals of a centrifugal compressor, the flow rate limit is

(

a) if the compressor is installed on or after January 1, 2023, 0.14 standard m 3 /min; and

(

b) if the compressor is installed before January 1, 2023 and has a rated brake power of

(

i) greater than or equal to 5 MW, 0.68 standard m 3 /min, and

(ii) less than 5 MW, 0.34 standard m 3 /min.

Flow rate limit — reciprocating compressors

(3) For emissions that are from the rod packings and distance pieces of a reciprocating compressor, the flow rate limit is

(

a) if the compressor is installed on or after January 1, 2023, the product of 0.001 standard m 3 /min and the number of pressurized cylinders that the compressor has; and

(

b) if the compressor is installed before January 1, 2023, the product of 0.023 standard m 3 /min and the number of those pressurized cylinders.

Remeasurement

(4) The remeasurement referred to in paragraph (1)(

a) or (

b) must be taken in accordance with

section 15 on or before the later of

(

a) the 90th day after the day on which, as the case may be, the most recent measurement is taken under subsection 16(3) or the alarm referred to in paragraph 17(

c) is triggered, and

(

b) if the estimated volume of hydrocarbon gas, expressed in standard m 3 , that would, beginning from the day on which the applicable day described in paragraph (a), be emitted until that next planned shutdown if no corrective action were taken is equal to or less than the volume of hydrocarbon gas, expressed in standard m 3 , that would be emitted due to the purging of hydrocarbon gas in order to take the corrective action,

(

i) the day on which the compressor begins to operate after the next planned shutdown, in the case of a centrifugal compressor, and

(ii) the day on which the compressor is first pressurized after the next planned shutdown, in the case of a reciprocating compressor.

Estimated volume

(5) The estimated volume of hydrocarbon gas must be based on the most recent flow rate of emissions of hydrocarbon gas released from vents referred to in paragraph 14(

b) of the compressor, as determined by a flow meter or a continuous monitoring system in accordance with

section 15.

Records — compressors and vents

(1) A record must be made that indicates for each compressor referred to in

section 14

(

a) its serial number;

(

b) its make and model;

(

c) its rated brake power;

(

d) the date on which it was installed at the facility, if it was installed on or after January 1, 2020, or a demonstration, with supporting documents, that it was installed at the facility before January 1, 2020;

(

e) if applicable, the type of hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment to which the emissions of hydrocarbon gas from the its seals or rod packing and distance pieces, as the case may be, are captured and routed, namely

(

i) a vapour recovery unit,

(ii) a vent gas capture system,

(iii) a flare,

(iv) an enclosed combustor, or

(

v) another type, and if so, a description of the type;

(

f) for each centrifugal compressor for which emissions from its seals are routed to vents that release those emissions to the atmosphere, whether the seals are dry or wet;

(

g) for each reciprocating compressor from which emissions from its rod packings and distance pieces are routed to vents that release those emissions to the atmosphere, the number of those rod packings; and

(

h) for each compressor for which the period within which a measurement by a flow meter must be made has been extended under subsection 16(6), the number of hours during which it was pressurized during the three calendar years referred to in that subsection.

Records — flow meters

(2) A record must be made that indicates, for each measurement, including a remeasurement, the flow rate of emissions from a vent referred to in paragraph 14(

b) made by means of a flow meter referred to in paragraph 15(a),

(

a) the make and model of the flow meter;

(

b) the maximum flow rate referred to in paragraph 16(4)(

a) or the average flow rate referred to in paragraph 16(4)(b), as the case may be;

(

c) the date on which the measurement was taken;

(

d) the recommendations of the manufacturer for the calibration of the flow meter referred to in subsection 16(1), along with a demonstration, with supporting documents, that the measurements taken with that calibration have a maximum margin of error of ±10%;

(

e) any recommendation for the taking of the measurement, along with supporting documents;

(

f) the duration of the continuous period referred to in paragraph 16(4)(

a) or (b), as the case may be; and

(

g) the name of the person who took the measurement and, if that person is a corporation, the name of the individual who took it.

Records — continuous monitoring devices

(3) A record must be made that indicates, for each measurement, including a remeasurement, of the flow rate of emissions from a vent referred to in paragraph 14(

b) made by means of a continuous monitoring device referred to in paragraph 15(b),

(

a) a description of the device;

(

b) if applicable, its serial number, make and model; and

(

c) the recommendations of the manufacturer for the calibration of the continuous monitoring device referred to in paragraph 17(

a) along with a demonstration, with supporting documents, that the measurements taken with that calibration have a maximum margin of error of ±10%.

Records — corrective actions taken

(4) A record must be made that indicates, for each corrective action taken,

(

a) a description of the corrective action, including a description of each step of the corrective action;

(

b) the dates on which that corrective action was taken, along with the dates on which each of its steps was taken;

(

c) for each remeasurement taken under paragraph 18(4)(b), the volume and estimated volume, determined for the purpose of that paragraph, along with supporting calculations; and

(

d) if the corrective action was taken as a result of a measurement by means of a continuous monitoring device, the date on which the alarm was triggered.

Conditional Requirements

Conditions

Application of sections 26 to 45

(1) Sections 26 to 45 apply in respect of an upstream oil and gas facility as of the first day of the month that begins after the facility produces or receives — or is expected to produce or receive — a combined volume of more than 60 000 standard m 3 of hydrocarbon gas for a period of 12 months, determined as follows:

(

a) if the facility has operated during at least 12 months, whether consecutive or not, with at least one day of operation in each of those months, the combined volume of hydrocarbon gas, expressed in standard m 3 , produced or received based on records, for the most recent 12 of those months of operation;

(

b) if the facility has operated during at least one month and less than 12 months, whether consecutive or not, with at least one day of operation in each of those months, the combined volume of hydrocarbon gas, expressed in standard m 3 , that the facility is expected to produce or receive for a 12-month period determined by prorating the combined volume, based on records, produced or received during those months of operation; and

(

c) in any other case, the combined volume of hydrocarbon gas, expressed in standard m 3 , that the facility is expected to produce or receive during the 12-month period that begins after its first month of operation, as determined in accordance with the applicable method set out in

section 23.

Well completion

(2) For the purpose of subsection (1), if a well at the facility undergoes well completion during a given month, the portion of the combined volume referred to in that subsection that corresponds to the production of hydrocarbon gas from the well must be based on the volume of hydrocarbon gas expected to be produced by the well for the 12-month period after the given month, as determined in accordance with the applicable method set out in

section 23.

Records — non-application

21 If none of sections 26 to 45 apply, for a given month, in respect of an upstream oil and gas facility, a record, with supporting documents, must be made that indicates

(

a) the gas-to-oil ratio and the volume of the hydrocarbon liquid produced or expected to be produced, expressed in standard m 3 , during the given month;

(

b) the combined volume of hydrocarbon gas produced and received, expressed in standard m 3 , during the given month; and

(

c) for a well at the facility that undergoes well completion during the given month, the volume expected to be produced by the well referred to in subsection 20(2).

Records — application

22 A record must be made that indicates the following information for the first month that begins after the facility produces or receives — or is expected to produce or receive — a combined volume of more than 60 000 standard m 3 of hydrocarbon gas for a period of 12 months as determined in accordance with subsection 20(1):

(

a) that first month and the calendar year that includes that first month; and

(

b) the combined volume, along with an indication as to which of paragraphs 20(1)(

a) to (

c) was used to determine that volume.

Determination of Volume of Gas

Applicable methods

(1) For the purpose of sections 20 and 26, the volume of hydrocarbon gas produced, received, vented or destroyed at, or delivered from, an upstream oil and gas facility must be determined in accordance with the applicable method set out in

(

a) the document entitled Measurement Guideline for Upstream Oil and Gas Operations , published by the Oil and Gas Commission of British Columbia on March 1, 2017, if the facility is located in British Columbia;

(

b) the document entitled Measurement Requirements for Oil and Gas Operations and commonly referred to as Directive PNG017, published by the Government of Saskatchewan on August 1, 2017 (version 2.1), if the facility is located in Manitoba or Saskatchewan; and

(

c) the document entitled Measurement Requirements for Oil and Gas Operations and commonly referred to as AER Directive 017, published by the Alberta Energy Regulator on March 31, 2016, in any other case.

Directive PNG017 and AER 017

(2) Despite paragraphs (1)(

b) and (c), for the purpose of sections 12.2.2.1 and 12.2.2.2 of the Saskatchewan Directive PNG017 and of the AER Directive 017, the gas production per well per day is to be determined

(

a) if the expected gas production is greater than 2 000 standard m 3 per day, by direct measurement; and

(

b) in any other case,

(

i) by direct measurement, or

(ii) by means of an estimate based on a gas-to-oil ratio determined

(

A) in accordance with

section 24, or

(

B) by the formula

−0.5P w + 150

where

P w is the average volume, expressed in standard m 3 , of oil produced by the well for a day during the most recent month of production.

Determination of gas-to-oil ratio

(1) The determination of a gas-to-oil ratio for the purpose of clause 23(2)(b)(ii)(

A) is made using the formula

G/O

where

G is the average volume of gas produced by the well measured over a continuous period — of at least 72 hours or at least 24 hours, determined, as the case may be, in accordance with subsection (2) or (3) — under conditions, in particular in respect of flow rate and operating conditions, that are representative of the conditions that occurred during the most recent month of production; and

O is the average volume of oil produced by the well over the period that is used for the determination of G, based on measurements taken in accordance with subsection (4) as prorated to that period and under conditions, in particular in respect of flow rate and operating conditions, that are representative of the conditions during the most recent month of production.

Determination of value of G

(2) The measurements to determine the value of G must be taken over a continuous period of at least 72 hours with a continuous measuring device or using a flow meter with at least one reading taken every 20 minutes.

Exception

(3) Despite subsection (2), the measurements to determine the value of G may be taken over a continuous period of at least 24 hours, if

(

a) the flow rate of gas from the well is greater than 100 standard m 3 per day; and

(

b) the measurement is taken

(

i) with a continuous measuring device and the variation of flow rate in that continuous period is such that the average flow rate for any 20-minute period is within ±5% of the average flow rate, or

(ii) using a flow meter with at least one reading taken every 20 minutes within that continuous period and the variation of flow rate in that continuous period is such that 95% of the readings taken are within ±5% of the average flow rate.

Determination of the value of O

(4) The measurements to determine the value of O must be taken after the water has been separated from the liquid produced from the well and taken

(

a) over the continuous period used to determine the value of G with a continuous measuring device that has a maximum margin of error of ±0.1 standard m 3 ; or

(

b) over a continuous period of at least 10 days that includes the continuous period used to measure G with a continuous measuring device that has a maximum margin of error of ±1 standard m 3 and with the variation of flow rate in that continuous period such that the measured volume of oil produced for any day is within ±5% of the measured volume of oil produced for any other day in that continuous period.

Steady state

(5) A measurement taken under any of subsections (2) to (4) must be taken while the well is operating in a steady state, that is, it must be taken only if no adjustment that could result in a change to the oil or gas production rates has been made to the production parameters for at least 48 hours before the measurement is taken.

Measuring equipment — directives

(6) The continuous measuring device or flow meter used to determine the gas-to-oil ratio must meet the requirements of

section 2 of the Saskatchewan Directive PNG017 or

section 2 of the AER Directive 017.

Frequency of determination

(7) A determination of the gas-to-oil ratio must be made

(

a) at least once per year and at least 90 days after a previous determination, if

(

i) in the case of an initial determination, the expected flow rate of the gas is at most 500 standard m 3 per day, and

(ii) in any other case, the flow rate of the gas according to the most recent determination was at most 500 standard m 3 per day;

(

b) at least once every six months and at least 45 days after a previous determination, if

(

i) in the case of an initial determination, the expected flow rate of the gas is greater than 500 standard m 3 per day and at most 1 000 standard m 3 per day, and

(ii) in any other case, the flow rate of the gas according to the most recent determination was greater than 500 standard m 3 per day and at most 1 000 standard m 3 per day; and

(

c) at least once every month and at least seven days after a previous determination, if

(

i) in the case of an initial determination, the expected flow rate of the gas is greater than 1 000 standard m 3 per day and at most 2000 standard m 3 per day, and

(ii) in any other case, the flow rate of the gas according to the most recent determination was greater than 1 000 standard m 3 per day and at most 2 000 standard m 3 per day.

Records

25 A record must be made that indicates

(

a) all of the readings from a continuous measuring device and each reading taken using a flow meter;

(

b) the flow rate over each period during which measurements were taken for each determination of the value of G and O;

(

c) the dates, time and duration of each of those periods;

(

d) the production parameters during each of those periods and the 48 hours before each of those periods begins; and

(

e) whether the type of equipment used to take each measurement was a continuous measuring device or a flow meter and its make and model.

Venting Limit

15 000 standard m 3 per year

(1) An upstream oil and gas facility must not vent more than 15 000 standard m 3 of hydrocarbon gas during a year.

Excluded volumes

(2) The volumes of hydrocarbon gas vented that arose from the following activities are excluded from the determination of the volume vented for the purpose of subsection (1):

(

a) liquids unloading, that is, the removal of accumulated liquids from a gas well;

(

b) a blowdown, that is, the temporary depressurization of equipment or pipelines;

(

c) glycol dehydration, that is, the use of a liquid desiccant system to remove water from natural gas or natural gas liquids;

(

d) the use of a pneumatic controller, pneumatic pump or compressor;

(

e) the start-up and shutdown of equipment;

(

f) well completion; and

(

g) venting in order to avoid serious risk to human health or safety arising from an emergency situation.

Non-application of subsection (1)

(3) Subsection (1) does not apply in respect of a facility, as of a given month, if the combined volume of hydrocarbon gas that was vented or destroyed at, or delivered from, the facility was less than 40 000 standard m 3 for the 12 consecutive months before that given month.

Re-application of subsection (1)

(4) Despite subsection (3), subsection (1) does apply in respect of a facility referred to in subsection (3), as of a subsequent month, if the combined volume of hydrocarbon gas that was vented or destroyed at, or delivered from, the facility was equal to or greater than 40 000 standard m 3 for the 12 consecutive months before that subsequent month.

Records — volumes of hydrocarbon gas

27 For each month that an upstream oil and gas facility operates, a record, with supporting documents, must be made that indicates

(

a) the volume of hydrocarbon gas that was vented, expressed in standard m 3 ;

(

b) the volume of hydrocarbon gas vented that arose from the activities referred to in each of paragraphs 26(2)(

a) to (g);

(

c) the volume of hydrocarbon gas destroyed at the facility, expressed in standard m 3 ; and

(

d) the volume of hydrocarbon gas delivered from the facility, expressed in standard m 3 .

Leak Detection and Repair Program

Establishment of Program

Non-application to certain equipment components

(1) Sections 29 to 36 do not apply in respect of

(

a) an equipment component used on a wellhead at a site at which there is no other wellhead or equipment except for gathering pipelines or a meter connected to the wellhead;

(

b) a pair of isolation valves on a transmission pipeline if no other equipment is located on the segment of the pipeline that may be isolated by closing the valves; and

(

c) an equipment component used at an upstream oil and gas facility whose inspection would pose a serious risk to human health or safety.

Record

(2) A record must be made that indicates whether an equipment component is an equipment component referred to in any of paragraphs (1)(

a) to (c).

Regulatory or alternative LDAR programs

(1) An operator for a facility must — in order to limit fugitive emissions containing hydrocarbon gas from equipment components at the facility — establish and carry out at the facility

(

a) a regulatory leak detection and repair program that satisfies the requirements of sections 30 to 33; or

(

b) an alternative leak detection and repair program referred to in subsection 35(1) that results in at most the same quantity of those fugitive emissions as would result from a regulatory program referred to in paragraph (a), as demonstrated in a record, with supporting documents, made by the operator before the program is established and, at least once per year and at least 90 days after a previous demonstration, while the program is being carried out.

Notice to Minister

(2) An operator for a facility that establishes a leak detection and repair program referred to in paragraph (1)(

b) must, without delay, notify the Minister to that effect.

Regulatory LDAR Programs

Obligation to inspect

(1) An equipment component at an upstream oil and gas facility must be inspected, during the periods referred to in subsection (3), for the release of hydrocarbons by means of an eligible leak detection instrument.

Eligible leak detection instruments

(2) The following leak detection instruments are eligible:

(

a) a portable monitoring instrument if it

(

i) meets the specifications set out in

Section 6 of EPA Method 21,

(ii) is operated in accordance with the requirements of

Section 8.3 of EPA Method 21 to the extent that those requirements are consistent with its manufacturer’s recommendations,

(iii) is calibrated in accordance with Sections 7, 8.1, 8.2 and 10 of EPA Method 21 before it is used, for each day on which it is used, and

(iv) undergoes a calibration drift assessment after its last use on each of those days in accordance with the requirements set out in

Section 60.485a(b)(2) of Subpart VVa, entitled Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for which Construction, Reconstruction, or Modification Commenced After November 7, 2006 , in

Part 60 of Title 40,

Chapter I of the Code of Federal Regulations of the United States; and

(

b) an optical gas-imaging instrument if it is capable of imaging gas that is

(

i) in the spectral range for the compound of highest concentration in the hydrocarbon gas to be measured,

(ii) half methane and half propane at a total concentration of at most 500 ppmv and at a flow rate of at least 60 g/h leaking from an orifice that is 0.635 cm in diameter, and

(iii) at the viewing distance determined in accordance with the requirements of the alternative work practice of the Environmental Protection Agency of the United States set out in Sections 60.18(h)(7)(i)(2)(

i) to (

v) of

Section 60.18, entitled General control device and work practice requirements , in

Part 60 of Title 40,

Chapter I of the Code of Federal Regulations of the United States.

Period for inspections

(3) The period for inspections is as follows:

(

a) for the first inspection, on or before the later of May 1, 2020 and the day that occurs 60 days after the day on which production at the facility first began; and

(

b) for subsequent inspections, at least three times per year and at least 60 days after a previous inspection.

Operation and maintenance

(4) An eligible leak detection instrument must be operated and maintained in accordance with the recommendations, if any, of its manufacturer.

Training

(5) The inspection must be conducted by an individual who, not more than five years before the inspection, has received training in

(

a) the operation and maintenance, in accordance with subsection (4), of eligible leak detection instruments; and

(

b) the calibration requirements set out in subparagraphs (2)(a)(iii) and (iv), if an eligible portable monitoring instrument is used.

Leaks

(1) A release of hydrocarbons from an equipment component is a leak if

(

a) the release consists of at least 500 ppmv of hydrocarbons, as determined by an inspection conducted by means of an eligible portable monitoring instrument in accordance with EPA Method 21; or

(

b) the release is detected

(

i) during an inspection conducted by means of an eligible optical gas-imaging instrument, or

(ii) by means of an auditory method, an olfactory method or a visual method, including the observation of the dripping of hydrocarbon liquids from the equipment component.

Release not considered a leak

(2) A release that is detected under paragraph (1)(

b) is no longer considered to be a leak if the equipment component undergoes an inspection conducted by means of an eligible portable monitoring instrument in accordance with EPA Method 21 and the release is determined to consist of less than 500 ppmv of hydrocarbons.

Period for repair

(1) A leak from an equipment component that is detected, whether as a result of an inspection or otherwise, must be repaired

(

a) if the repair can be carried out while the equipment component is operating, within 30 days after the day on which it was detected; and

(

b) in any other case, within the period before the end of the next planned shutdown unless that period is extended under

section 33.

Next planned shutdown

(2) The next planned shutdown must be scheduled not later than the date on which the estimated volume of hydrocarbon gas, expressed in standard m 3 , that, beginning from the day on which the leak is detected, would if no repairs are made be emitted from the leaking equipment component in question and from all other equipment components that are also leaking as of that day is equal to the volume of hydrocarbon gas, expressed in standard m 3 , that would be emitted due to purging of hydrocarbon gas from equipment components in order to carry out the repair.

Repair

(3) A leak in an equipment component is considered to be repaired if the release is determined to consist of less than 500 ppmv of hydrocarbons based on an inspection of the equipment component by means of an eligible portable monitoring instrument in accordance with EPA Method 21 that is capable of measuring hydrocarbon concentrations in ppmv.

Extension up to six months for repair

(1) An operator for an upstream oil and gas facility that must repair an equipment component on or before the end of a period referred to in paragraph 32(1)(

b) may, not later than 45 days before the end of the period, apply to the Minister to extend the period for up to six months.

Granting of extension

(2) The Minister must grant the application and extend the period for up to six months if the application contains the information set out in

Schedule 1 and

(

a) documents that establish that, as of the making of the application, there are reasonable grounds to conclude that it is not technically feasible to complete the repair of the equipment component before the end of the next planned shutdown;

(

b) documents that establish that the applicant has a plan to repair the equipment component that sets out

(

i) the expected date for the completion of the repair,

(ii) the steps to be taken to ensure completion of the repair on or before that date,

(iii) a justification, with supporting documents, for the belief that that date is the earliest feasible date to complete the repair, and

(iv) measures to be taken to minimize, if not eliminate, any harmful effect on the environment or human health from the emission of hydrocarbon gas before the completion of the repair; and

(

c) a statement that the implementation of the plan is to begin within 30 days after the day on which the extension is granted.

Renewal

(3) The period granted under subsection (2) may be further extended by application made under subsection (1). At most two applications for a further extension may be made.

Refusal of application

(4) The Minister must refuse the application if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in the application.

Revocation of extension

(1) The Minister must revoke the extension granted under subsection 33(2) if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in their application for the extension.

Conditions for revocation

(2) The Minister must not revoke the extension unless the Minister has provided the applicant with

(

a) written reasons for the proposed revocation; and

(

b) an opportunity to be heard, by written representation, in respect of the proposed revocation.

Alternative LDAR Programs

Requirements for alternative program

(1) The alternative leak detection and repair program must include measures respecting

(

a) the inspection for leaks;

(

b) the operation, maintenance and calibration of leak detection instruments, if applicable; and

(

c) the repair of leaks detected.

Reversion to regulatory program

(2) An operator for a facility that has not made a demonstration required by paragraph 29(1)(

b) must establish and carry out a regulatory leak detection and repair program.

Records

Regulatory LDAR programs

(1) A record, with supporting documents, must be made of the following information related to the carrying out of a regulatory leak detection and repair program:

(

a) for each calibration of an eligible leak detection instrument,

(

i) the dates of the calibration,

(ii) the result of each calibration drift assessment, and

(iii) the name, job title, if any, and address of the individual who carried out the calibration;

(

b) for each inspection of an equipment component,

(

i) the date of the inspection, along with the name of the individual who conducted it,

(ii) the type of equipment component,

(iii) the location of the equipment component within the facility or the Global Positioning System (GPS) coordinates, to five decimal places, of the equipment component,

(iv) the type of leak detection instrument used to conduct the inspection, including, if any, its make and model,

(

v) in the case that an optical gas-imaging instrument referred to in subparagraph 31(1)(b)(

i) was used to conduct the inspection, the images recorded with an embedded indication of the date and time when they were recorded, along with the location of the place where they were recorded within the facility or the GPS coordinates, to five decimal places, of the place, and

(vi) in the case that an inspection resulted in the detection of a leak, an indication of the means, among those set out in subsection 31(1), by which the leak was detected and, in the case of a leak detected by a means set out in paragraph 31(1)(b), an indication as to whether the release was determined in accordance with subsection 31(2) to consist of less than 500 ppmv and, if so, the date of that determination, the name of the person who made that determination — and if that person is a corporation, the name of the individual who made it — and its result, expressed in ppmv, along with the make and model, if any, of the instrument used to make that determination;

(

c) for each leak detected by means of a method set out in paragraph 31(1)(

b) that was not as a result of an inspection,

(

i) an indication of whether the method was auditory, olfactory or visual,

(ii) the date on which the leak was detected, along with the name of the individual who detected it,

(iii) the type of equipment component,

(iv) the location of the equipment component within the facility or its GPS coordinates, to five decimal places, and

(

v) an indication as to whether the release was determined in accordance with subsection 31(2) to consist of less than 500 ppmv and, if so, the date of that determination, the name of the person who made that determination — and if that person is a corporation, the name of the individual who made it — and its result, expressed in ppmv, along with the make and model, if any, of the instrument used to make that determination;

(

d) for each individual who conducted an inspection and who received training in the operation and maintenance or in the calibration of leak detection instruments,

(

i) their name, along with the name and business address of their employer, if their employer is not the operator,

(ii) the name and business address of the entity that provided the training, along with the name and job title of the individuals who provided it,

(iii) the dates on which the training was provided and, for each of those dates, the number of hours of training, and

(iv) a description of the training;

(

e) for each repair of a leak from an equipment component,

(

i) a description of the steps that were taken to repair the leak, along with the dates on which those steps were taken, and

(ii) the result, expressed in ppmv, obtained following an inspection by means of an eligible portable monitoring system in accordance with EPA Method 21, along with the date on which that result was obtained; and

(

f) for each repair that was not carried out within 30 days after the detection of the leak:

(

i) an indication as to why the equipment component could not be repaired while it was operating, and

(ii) if applicable, the date determined in accordance with subsection 32(2), along with the information and calculation on which that determination was based.

Alternative LDAR programs

(2) A record, with supporting documents, must be made of the following information related to the carrying out of an alternative leak detection and repair program:

(

a) the date on which each inspection was conducted and, if applicable, the name of the person who conducted it;

(

b) the type of equipment component that was inspected, along with its location within the facility or its GPS coordinates, to five decimal places;

(

c) a description as to the means by which the leak was identified;

(

d) if applicable, for each leak detection instrument used, a description of the operation, maintenance and calibration measures in relation to that instrument, along with the dates of its maintenance and calibrations and the names of the persons who carried out the maintenance and calibrations;

(

e) for each repair of a leak from an equipment component,

(

i) a description of the steps that were taken to repair the leak, along with the dates on which those steps were taken, and

(ii) the result obtained after the repair following an inspection, along with a description of the means by which that inspection was conducted, its date and, if applicable, the name of the person who conducted it; and

(

f) the demonstrations referred to in paragraph 29(1)(b).

Document-keeping

(3) A copy of each recommendation of the manufacturer for the operation and maintenance, if any, of each eligible leak detection instrument that is used must be kept.

Pneumatic Controllers and Pneumatic Pumps

Pneumatic controllers — bleed rate

(1) A pneumatic controller at an upstream oil and gas facility must not operate using hydrocarbon gas, other than propane, unless

(

a) it is operated at an operational setting such that its bleed rate for that operational setting is less than or equal to 0.17 standard m 3 /h according to the manufacturer’s operating manual or according to a written demonstration, with supporting documents, made by the operator for the facility; or

(

b) the hydrocarbon emissions from it are captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment.

Exception — control of production processes

(2) Despite paragraph (1)(a), a pneumatic controller at an upstream oil and gas facility may operate using hydrocarbon gas, other than propane, at an operational setting such that its bleed rate for that operational setting is more than 0.17 standard m 3 /h if the operator for the facility has a written record, with supporting documents, that demonstrates that the pneumatic controller must operate at that operational setting because of the need for the pneumatic controller to have a sufficient response time to control a process in the facility’s production activities.

Records — pneumatic controllers

38 A record in respect of each pneumatic controller used at an upstream oil and gas facility that operates using hydrocarbon gas must be made that indicates

(

a) the identifier for the pneumatic controller;

(

b) whether the pneumatic controller is used

(

i) for controlling pressure or flow rate,

(ii) for controlling liquid levels,

(iii) for controlling temperature,

(iv) as a transducer,

(

v) as a positioner, or

(vi) as an emergency response device, or

(vii) for another purpose or as another device and, if so, the purpose or type of device; and

(

c) the design bleed rate for the pneumatic controller’s operational setting, including its supply pressure and, if any, its band setting, or its bleed rate according to a written demonstration, with supporting documents, made by the operator for the facility at which the controller is used.

Pneumatic pumps

(1) Unless an operator for an upstream oil and gas facility has a permit issued in accordance with subsection 40(2), a pneumatic pump or a group of pneumatic pumps, used at the facility that pumps methanol into a common stream or an equipment component — must not operate using hydrocarbon gas if the pump or the group of pumps has, in a month, pumped more than 20 L of methanol per day on average over the month.

Demonstration of quantity of liquid pumped

(2) An operator for the facility must, for each pump or group of pumps referred to in subsection (1) that operates during a month at the facility, demonstrate the quantity of liquids that it pumped, on average, per day over the month by means of

(

a) a record that indicates the quantity of liquid pumped during that month; or

(

b) documents that establish that the pump or the group of pumps could not have pumped more than 20 L of liquid per day on average over the month.

When subsection (2) no longer applies

(3) Subsection (2) no longer applies in respect of a pump or group of pumps as of the end of a month during which it operated at the facility and records establish that it pumped, or could have pumped, more than 20 L of liquid per day on average over the month.

Non-application of subsections (1) and (2)

(4) Subsections (1) and (2) do not apply in respect of any pneumatic pump if hydrocarbon emissions from it are captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment.

Permit — pneumatic pumps

(1) An operator for an upstream oil and gas facility may, on or before June 30, 2022, apply to the Minister for a permit to have a pneumatic pump at the facility operate using hydrocarbon gas while its hydrocarbon emissions are not captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment.

Issuance of permit

(2) The Minister must issue the permit if the application contains the information set out in

Schedule 2 and documents that establish that

(

a) there are reasonable grounds to conclude that it is not feasible, technically or economically, for the applicant to have the pneumatic pump operate at the facility without using hydrocarbon gas or to have the pneumatic pump function using hydrocarbon gas while its hydrocarbon emissions are captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment, including grounds based on

(

i) the capital, operating and maintenance costs of any modifications at the facility to achieve that objective, and

(ii) the avoided costs and any economic benefits arising from the incurring of those capital, operating and maintenance costs; and

(

b) the applicant has a plan that

(

i) involves taking steps to minimize the emission of hydrocarbon gas from the pneumatic pump, including steps such as adjusting the capacity of the pump or its operational settings so as to achieve the desired rate of injection of chemicals from the pump with the least possible emissions, along with a

schedule to implement the plan, and

(ii) can reasonably be regarded as feasible for the purpose of permitting the facility to comply with subsection 39(1) on or before January 1, 2026.

Duration

(3) A permit takes effect on January 1, 2023 and expires on the earliest of

(

a) the day on which the pneumatic pump ceases to function using hydrocarbon gas,

(

b) the day on which the hydrocarbon emissions from the pneumatic pump begin to be captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment, and

(

c) December 31, 2025.

Refusal of application

(4) The Minister must refuse the application if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in the application.

Tagging

(1) A pneumatic controller that is referred to in subsection 37(2) or a pneumatic pump referred to in a permit issued under subsection 40(2) must be tagged to indicate that it is not subject to subsection 37(1) or 39(1) or an entry to that effect must be made in an electronic tracking system.

Identifier

(2) The tag or the entry must also include an identifier for the pneumatic controller or the pneumatic pump.

Other Equipment

Pipes and hatches

42 A hatch and the open end of a pipe at an upstream oil and gas facility must be closed — other than during an operation at the facility that requires the hatch or pipe to be open — in such a way as to minimize the emission of hydrocarbon gas.

Sampling systems and pressure relief devices

43 A sampling system or a pressure relief device used at an upstream oil and gas facility must be installed and operated in such a way as to minimize the emission of hydrocarbon gas from the system or the pressure relief device.

Records — hatches, pipes, systems and devices

44 A record must be made that indicates whether an upstream oil and gas facility has a hatch, a pipe with an open end or uses a sampling system or pressure relief device.

Revocation of Permit

Subsection 40(2)

(1) The Minister must revoke a permit issued under subsection 40(2) if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in their application for the permit.

Conditions for revocation

(2) The Minister must not revoke a permit unless the Minister has provided the applicant with

(

a) written reasons for the proposed revocation; and

(

b) an opportunity to be heard, by written representation, in respect of the proposed revocation.

PART 2

Offshore Upstream Oil and Gas Facilities

Application

Offshore facilities

(1) This Part applies in respect of upstream oil and gas facilities located offshore.

Non-application

(2) Despite subsection (1), this Part does not apply in respect of an offshore facility if

(

a) a regulation is made under the Canada–Newfoundland and Labrador Atlantic Accord Implementation Act or the Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation Act that applies in respect of the offshore facility and imposes requirements that are at least as stringent as those set out in sections 47 to 53; and

(

b) the title of the regulation is published in the environmental registry established under

section 12 of the Canadian Environmental Protection Act, 1999 for the purpose of this subsection.

Venting Limit

15 000 standard m 3 per year

(1) An offshore facility must not vent more than 15 000 standard m 3 of hydrocarbon gas during a year.

Excluded volume — health or safety

(2) Any volume of hydrocarbon gas that is vented from the offshore facility in order to avoid serious risk to human health or safety arising from an emergency situation is excluded from the determination of the volume vented for the purpose of subsection (1).

Records — annual volume vented

(1) For each year that an offshore facility operates, a record, with supporting documents, must be made that indicates the volume of hydrocarbon gas that was vented, expressed in standard m 3 .

Records — emergency situation

(2) For each volume of vented hydrocarbon gas arising from an emergency situation referred to in subsection 47(2), a record must be made that indicates:

(

a) the name of the offshore facility;

(

b) the volume of hydrocarbon gas that was vented, expressed in standard m 3 ; and

(

c) a description of the emergency situation.

Compressors

Capture or venting of emissions

49 The emissions of hydrocarbon gas from the seals of a centrifugal compressor at an offshore facility must be

(

a) captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment; or

(

b) routed to vents that release those emissions to the atmosphere.

Continuous monitoring devices

(1) The flow rate of emissions of hydrocarbon gas from vents referred to in paragraph 49(

b) must be measured by means of a continuous monitoring device.

Requirements

(2) A continuous monitoring device must

(

a) be calibrated in accordance with the manufacturer’s recommendations such that its measurements have a maximum margin of error of ±10%;

(

b) be operated continuously, other than during periods when it is undergoing normal servicing or timely repairs; and

(

c) be equipped with an alarm that is triggered when the applicable flow rate limit referred to in subsection (3) for the vents of the compressor is reached.

Flow rate limit

(3) The flow rate limit of emissions of hydrocarbon gas from the vents of a compressor is

(

a) for a compressor that was installed before January 1, 2023,

(i) 0.68 standard m 3 /min, if the compressor has a rated brake power of greater than or equal to 5 MW, and

(ii) 0.34 standard m 3 /min, if the compressor has a rated brake power of less than 5 MW; and

(

b) for a compressor that was installed on or after January 1, 2023, 0.14 standard m 3 /min.

Corrective action

(4) If the alarm is triggered, corrective action must be taken to reduce the flow rate to below or equal to the applicable flow rate limit, as demonstrated by the absence of an alarm when the compressor begins to operate following the taking of that action.

Records

51 A record must be made that indicates the following information concerning centrifugal compressors:

(

a) for each compressor referred to in

section 49,

(

i) its serial number,

(ii) its make and model,

(iii) whether it was installed at the facility before January 1, 2023 or on or after January 1, 2023,

(iv) if it was installed at the facility before January 1, 2023, its rated brake power, and

(

v) an indication of the manufacturer’s recommendations for the calibration of the continuous monitoring device, along with a demonstration, with supporting documents, that the measurements taken with that calibration have a maximum margin of error of ±10%;

(

b) for each compressor for which an alarm referred to subsection 50(4) was triggered,

(

i) its serial number, make and model,

(ii) the date on which the alarm was triggered,

(iii) the flow rate indicated by the continuous monitoring device when the alarm was triggered, and

(iv) a description of the corrective action that was taken, along with the dates on which that action was taken.

Gas Detection System and Repair of Leaks

Requirements

(1) An offshore facility must be equipped with a gas detection system that satisfies the requirements of

section 32 of the Newfoundland Offshore Petroleum Installations Regulations and

section 32 of the Nova Scotia Offshore Petroleum Installations Regulations .

Repair

(2) A leak must be repaired within 730 days after the day on which it is detected by the gas detection system or is detected by means of an auditory method, an olfactory method or a visual method, including the observation of the dripping of hydrocarbon liquids from the equipment component.

Records

53 A record must be made that indicates the following information concerning the detection and repair of leaks:

(

a) the date on which each leak was detected;

(

b) the type of equipment that was leaking, along with its location within the facility or its identifier;

(

c) the means by which the leak was identified; and

(

d) the steps that were taken to repair each leak detected, along with the dates on which those steps were taken.

PART 3

Administration

Registration

Registration report

(1) An upstream oil and gas facility in respect of which any of sections 5, 9, 11, 14 and 15 apply or in respect of which sections 26 to 45 apply and an offshore facility in respect of which

section 46 applies must be registered by providing the Minister with a registration report for the facility that contains the information set out in

Schedule 3.

Date of registration

(2) The facility must be registered not later than 120 days after the later of

(

a) January 1, 2020, and

(

b) the earlier of

(

i) the first day on which any of sections 5, 9, 11, 14, 15 and 46 apply in respect of the facility, and

(ii) the first day of the month referred to in subsection 20(1) as of which sections 26 to 45 apply in respect of the facility.

Updated information

(3) If there is a change such that the information provided in the facility’s registration report is no longer accurate, a notice to that effect that contains the updated information, along with the information referred to in item 4 of

Schedule 3, must be sent to the Minister not later than 90 days after the change.

Provision of information

(1) Information that is required under

section 54 to be in a registration report provided to the Minister may be provided to the Minister via an approved entity.

Deemed provision of registration report

(2) If all of the information required to be in a registration report is provided to the Minister via an approved entity, the operator for that facility must notify the Minister to that effect. The registration report is deemed to have been provided to the Minister on the day on which the Minister receives that notice.

Approval of entity

(3) The Minister may approve an entity for the purpose of subsection (1) if the Minister concludes an arrangement with the entity under which information referred to in

section 54 that is provided to the entity is accessible to the Minister.

Publication of approved entities

(4) The Minister must publish a list of approved entities in the Environmental Registry established under

section 12 of the Canadian Environmental Protection Act, 1999 .

Withdrawal of approval

(5) The Minister may withdraw the approval of an entity and publish a notice to that effect in the Environmental Registry.

Record-making and Updating and Keeping of Documents

Record-making and updates

(1) A record that is required to be made under these Regulations must be made within 30 days after the day on which the information to be recorded becomes available. The record must be updated within 30 days after the information to be updated becomes available.

Record-keeping — indefinite

(2) A record, along with supporting documents, of information that applies on an ongoing basis must be kept indefinitely until an update is required.

Record-keeping — five years

(3) If an update referred to in subsection (2) is required, the record of the information, along with its supporting documents, as recorded before the updating must be kept for five years after the updating.

Record-keeping — five years

(4) A record, along with supporting documents, of information that applies only in respect of a given day, must be kept for five years after that given day.

Document-keeping

(5) A document that is required to be kept under these Regulations must be kept for five years.

Place kept

(6) The records and documents must be kept at the upstream oil and gas facility to which they relate or at another place in Canada where they can be inspected.

Provision of records

(7) On the Minister’s request, the operator must, within 60 days after the day on which the request was made, provide any of the records or documents kept to the Minister.

Consequential Amendment to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999)

57 The

schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) footnote 1 is amended by adding the following in numerical order:

Item

Column 1

Regulations

Column 2

Provisions

Regulations Respecting Reduction in the Release of Methane

and Certain Volatile Organic Compounds (Upstream Oil and

Gas Sector)

(a) subsection 5(1)

(

b) section 6

(

c) section 7

(

d) section 8

(

e) section 9

(

f) section 10

(g) subsection 11(2)

(

h) section 12

(

i) section 14

(

j) section 15

(k) paragraphs 19(1)(a), (c), (d), (f), (

g) and (h), subsection 19(2) and paragraphs 19(4)(

b) and (c)

(

l) section 20

(

m) section 21

(

n) section 22

(

o) section 25

(p) subsection 26(1)

(

q) section 27

(r) subsection 30(1) and (3)

(s) subsection 32(1)

(t) subsection 35(1)

(

u) section 36

(v) subsections 37(1) and (2)

(

w) section 38

(x) subsections 39(1) and (2)

(

y) section 42

(

z) section 43

(z.1) subsection 47(1)

(z.2)

section 48

(z.3)

section 49

(z.4) subsection 50(3)

(z.5)

section 51

(z.6)

section 52

(z.7)

section 53

Coming into Force

January 1, 2020

(1) Subject to subsection (2), these Regulations come into force on January 1, 2020.

January 1, 2023

(2) Sections 26, 27 and 37 to 41 of these Regulations and paragraphs 32(p), (q), (v), (

w) and (

x) of the

schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) , as enacted by

section 57 of these Regulations, come into force on January 1, 2023.

SCHEDULE 1

(Subsection 2(1) and 33(2))

Information for Extension of Period for Repair of Equipment Component

1 The name and civic address of the operator.

2 The name, job title, civic and postal addresses, telephone number and email address of the operator’s authorized official.

3 The name, job title, civic and postal addresses, telephone number and email address of a contact person, if different from the authorized official.

4 The name of the facility and the federal and provincial identification numbers for the facility, if any, and its civic address or, if the civic address is not available,

(

a) its latitude and longitude to the third decimal place;

(

b) its location expressed to the nearest unit of the National Topographic System produced by the Department of Natural Resources; or

(

c) the legal subdivision within which the facility is located, if it is located in Manitoba, Saskatchewan or Alberta.

5 The date on which the next planned shutdown of the facility is to end.

6 The following information in respect of the equipment component for which the extension to the period by which it must be repaired is applied for:

(

a) the identifier for the equipment component, along with its make and model, if that information is available;

(

b) the name of its manufacturer, along with the manufacturing location;

(

c) a description of the equipment component, including an explanation of its functions within the production processes of the facility and how those functions are carried out; and

(

d) any other information that is relevant to determine whether it is technically feasible to complete the repair of the equipment component before the end of the next planned shutdown.

SCHEDULE 2

(Subsection 40(2))

Information for Permit for Pneumatic Pumps

1 The name and civic address of the operator.

2 The name, job title, civic and postal addresses, telephone number and email address of the operator’s authorized official.

3 The name, job title, civic and postal addresses, telephone number and email address of a contact person, if different from the authorized official.

4 The name of the facility and the federal and provincial identification numbers for the facility, if any, and its civic address or, if the civic address is not available,

(

a) its latitude and longitude to the third decimal place;

(

b) its location expressed to the nearest unit of the National Topographic System produced by the Department of Natural Resources; or

(

c) the legal subdivision within which the facility is located, if it is located in Manitoba, Saskatchewan or Alberta.

5 The identifier for the pneumatic pump, along with its make and model and the name of its manufacturer, if that information is available.

SCHEDULE 3

(Subsections 54(1) and (3))

Information for Registration of a Facility

1 The name and civic address of the operator.

2 The name, job title, civic and postal addresses, telephone number and email address of the operator’s authorized official.

3 The name, job title, civic and postal addresses, telephone number and email address of a contact person, if different from the authorized official.

4 The name of the facility, all provincial identification numbers that are related to the facility and used for reporting to provincial authorities, along with the facility’s civic address or, if the civic address is not available,

(

a) its latitude and longitude to the third decimal place;

(

b) its location expressed to the nearest unit of the National Topographic System produced by the Department of Natural Resources; or

(

c) the legal subdivision within which the facility is located, if it is located in Manitoba, Saskatchewan or Alberta.

5 If records, along with supporting documents, that are required to be made under these Regulations are not kept at the upstream oil and gas facility to which they relate, the civic address of the place where they are kept or, if the civic address is not available

(

a) its latitude and longitude to the third decimal place;

(

b) its location expressed to the nearest unit of the National Topographic System produced by the Department of Natural Resources; or

(

c) the legal subdivision within which the facility is located, if it is located in Manitoba, Saskatchewan or Alberta.

6 For a facility that provides information to the Minister for its registration report by way of an approved entity, an indication of any type or subtype of the facility that is used by the entity for the purpose of classifying the facility.

REGULATORY IMPACT ANALYSIS STATEMENT

( This statement is not part of the Regulations .)

Executive

summary

Issues: Greenhouse gas (GHG) emissions are contributing to a global warming trend that is associated with climate change. Oil and gas facilities account for 26% of Canada’s total GHG emissions. These facilities are also Canada’s largest emitters of methane, a potent GHG and a short-lived climate pollutant (SLCP) with a global warming potential more than 25 times that of carbon dioxide (CO 2 ).

Description: The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) [the Regulations] will introduce control measures (facility and equipment standards) to reduce fugitive and venting emissions of hydrocarbons, including methane, from the upstream oil and gas sector.

Cost-benefit statement: Between 2018 and 2035, the cumulative GHG emission reductions attributable to the Regulations are estimated to be approximately 232 megatonnes of carbon dioxide equivalent (Mt CO 2 e). Avoided climate change damages associated with these reductions are estimated at $11.6 billion. In addition, cumulative volatile organic compound (VOC) emission reductions are estimated to be 773 kt, with resulting health and environmental benefits estimated to be about $240 million.

The total cost of the Regulations is estimated to be $3.9 billion, which will be offset in part by the recovery of 351 petajoules (PJ) footnote 2 of natural gas, with an estimated value of $1.0 billion, resulting in expected net benefits of $8.9 billion.

The small business lens applies and various flexibilities have been incorporated into the Regulations to address the concerns of small businesses. The Regulations will result in cumulative costs of approximately $30 million for small businesses, or $53,000 per small business.

Background

Methane (CH 4 ) is a hydrocarbon gas that is the main component of natural gas. In its pure state, methane is a colourless, odourless flammable gas and is considered a toxic substance listed under

Schedule 1 of the Canadian Environmental Protection Act, 1999 (CEPA). It is a greenhouse gas (GHG) with a global warming potential 25 times greater than that of carbon dioxide (CO 2 ) over a 100-year period. Oil and gas facilities account for 26% of Canada’s total GHG emissions and are Canada’s largest industrial emitters of methane. footnote 3 The majority of these emissions are released by fugitive (unintentional release) and venting (intentional release) sources.

GHG emissions are contributing to a global warming trend that is associated with climate change, which is projected to lead to changes in average climate conditions and extreme weather events. The impacts of climate change are expected to worsen as the global average surface temperature becomes increasingly warmer. Climate change impacts are of major concern for society: changes in temperature and precipitation can impact natural habitats, agriculture and food supplies, and rising sea levels can threaten coastal communities.

Methane is a short-lived climate pollutant, which has a relatively short lifespan in the atmosphere compared to CO 2 and other longer-lived GHGs. Considered over a 20-year period, methane has a global warming potential more than 70 times that of CO 2 (compared to 25 times over a 100-year period). Atmospheric levels of methane thus respond relatively quickly to changes in emissions since they are removed quickly from the atmosphere. As a result of the potency and short lifespan of methane, reducing emissions has the potential to bring significant near-term climate benefits.

International and domestic commitments

At the United Nations Framework Convention on Climate Change (UNFCCC) conference in December 2015, the international community, including Canada, adopted the Paris Agreement, an accord intended to reduce global greenhouse gas emissions with a long-term goal of limiting the rise in global average temperature well below 2°C above pre-industrial levels and to aim to limit the temperature increase to 1.5°C. As part of its Nationally Determined Contribution (NDC) commitment under the Paris Agreement, Canada pledged to reduce national GHG emissions by 30% below 2005 levels by 2030.

In March 2016, Canada adopted a target to reduce emissions of methane from its oil and gas sectors by 40% to 45% below 2012 levels by 2025. footnote 6 To achieve this target, Canada committed to introducing federal regulations to reduce methane emissions from oil and gas facilities. footnote 7 This commitment was reaffirmed in the Pan-Canadian Framework.

Hydrocarbons, natural gas and crude oil

Natural gas and crude oil are blends of various hydrocarbons extracted from deposits or reservoirs found beneath the surface of the earth and ocean floors. Hydrocarbons are molecules in various combinations of carbon and hydrogen. Hydrocarbons can be gas or liquid depending on their physical properties. Crude oil facilities extract liquid hydrocarbons, which can then be refined into gasoline, diesel, fuel oils, kerosene, jet fuel and other fuels, in addition to asphalt and road oil. Natural gas is a mixture consisting mostly of methane and is often used as fuel or to make materials and chemicals.

Natural gas facilities extract, process and transport hydrocarbon gas. Natural gas and crude oil can often be found in association with each other in the same reservoir. As a result, crude oil facilities may also produce some natural gas, while natural gas facilities may also extract certain liquid hydrocarbons.

Emission sources in the oil and gas sector

The oil and gas industry encompasses many activities, from “upstream” activities, such as exploration, drilling, production and field processing, to “downstream” activities, such as petroleum refining and bulk storage and distribution of refined petroleum products. In 2014, close to 90% of methane emissions from the oil and gas sector originated from upstream activities. Major sources of hydrocarbon gas emissions from the upstream oil and gas sector are described below.

Facility production venting : General venting emissions from oil and gas facilities occur during the production process. This includes emissions from wellhead casings, processing equipment, and storage tanks. Releasing methane directly into the atmosphere has significant climate change consequences in comparison to flaring (burning) methane due to methane’s elevated global warming potential. Flaring converts methane into carbon dioxide, which has a much lower global warming potential.

Fugitive equipment leaks : Fugitive leaks may occur as a result of poor maintenance or regular wear and tear of equipment at all stages of production and processing of oil and gas. Leaks of gas or vapour may originate from equipment piping components such as valves, flanges, and connectors.

Well completion involving hydraulic fracturing : Well completion is the process of making a new well ready for production or stimulating an existing well to improve production, often through the use of hydraulic fracturing (or refracturing) techniques. Involving hydraulic fracturing, the well bore and formation must be cleaned of debris and fracturing fluid, a process that involves sending the well flowback material to an open pit or tank for disposal. Natural gas that is extracted along with the flowback material during this process is sometimes directly vented into the atmosphere.

Pneumatic controllers and pumps : Pneumatic controllers are used in the oil and gas industry to maintain and control parameters in the operations process, such as temperature, pressure, flow or liquid level, while pneumatic pumps are used to pump chemicals. It is common practice to use high-pressure field gas to operate these pneumatic devices. footnote 8 In gas-driven pneumatic devices, natural gas may be released into the atmosphere with every instrument actuation, or continuously from the device.

Compressors : Compressors are mechanical devices that increase the pressure of natural gas and allow it to be transported from the well site where it is produced, through a system of smaller flow lines and field processing facilities to a larger pipeline system for eventual delivery to the consumer. Compressors can vent gas during regular use and venting increases as internal components wear.

Domestic emission control measures

Presently, there are no federal regulations established to regulate GHG emissions from the upstream oil and gas sector. Existing provincial instruments have the effect of controlling some methane emissions in British Columbia, Alberta and Saskatchewan, where the majority of onshore oil and gas activities occur. There are joint federal and provincial instruments for the offshore oil and gas sector in place for Nova Scotia and Newfoundland and Labrador. The Canadian Association of Petroleum Producers (CAPP) also has guidelines for flaring. However, these provincial instruments are not consistent across jurisdictions and do not cover all sources of fugitive and venting emissions.

In British Columbia, the Flaring and Venting Reduction Guideline applies to the flaring, incineration and venting of natural gas at well sites, facilities and pipelines. Other requirements exist for industry reporting of GHG emissions. To date, sources of venting and fugitive emissions in the oil and gas sector in British Columbia have not been subject to the provincial government’s carbon tax.

Alberta’s Directive 060 imposes gas conservation requirements by setting restrictions on incineration and venting in the province at all petroleum industry wells and facilities. Venting reduction through solution gas conservation or gas flaring is based on reported vented emissions from the entire facility. footnote 9 Reported vented volumes include volumes from process vents, tank vents, and surface casing vents, but exclude venting from pneumatic instrumentation and pneumatic pumps.

Further, Alberta has implemented the Carbon Competitiveness Incentive Regulation (CCIR) to replace the Specified Gas Emitters Regulations (SGER) which applies a system of output-based allocations to large emitters. These regulations will be phased in over a three-year period beginning in 2018.

Saskatchewan’s Directive S-10 sets out requirements for the reduction of flaring and venting of associated gas, applicable to oil wells, associated gas processing plants, and any wells that vent, flare, or incinerate associated gas. Likewise, Saskatchewan’s Directive S-20 provides performance requirements and specification for equipment spacing and setback distance specifications for oil and gas flaring and incineration, applicable to licensed wells and facilities. The S-10 and S-20 directives set out the main provincial requirements governing venting and flaring emissions.

In Canada’s offshore areas, venting and flaring are regulated through the Drilling and Production Regulations made under Canada Oil and Gas Operations Act , as well as the following Accord Acts: the Canada-Newfoundland and Labrador Atlantic Accord Implementation Act , and the Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation Act . Venting, flaring and total emissions limits and related mitigation measures are determined on a project by project basis and outlined in the project’s resource management plan and environmental protection plan. These limits are approved by the relevant offshore regulator as part of the project authorization process.

The Canadian Standards Association (CSA) develops voluntary codes some of which apply to the oil and gas sector. The Fugitive Emissions and Venting code specifies criteria to address fugitive and vented emissions from point sources from pipelines, wells and facilities in the upstream oil and gas sector. These standards specify criteria to develop emission reduction practices and programs.

Issues

GHGs, including methane and CO 2 , are contributing to a global warming trend that is associated with climate change. The largest source of GHG emissions in Canada is the extraction and processing of fossil fuels. The latest emissions data available indicate that GHG emissions from the oil and gas sector in Canada amounted to 189 Mt CO 2 e in 2015, accounting for 26% of total GHG emissions. footnote 10 The oil and gas sector is also the largest contributor to methane emissions in Canada. Methane emissions from the oil and gas sector make up approximately 6% of Canada’s total GHG emissions.

Methane is also a short-lived climate pollutant with a global warming impact more than 70 times greater than CO 2 over a 20-year time period, making methane emissions a significant contributor to near-term global warming.

Current measures do not sufficiently control fugitive and venting methane emissions from the oil and gas sector. Without immediate action, it is expected that these fugitive and venting methane emissions in Canada will continue to be released at high levels of about 45 Mt CO 2 e per year between 2018 and 2035. footnote 11

Objectives

The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) [the Regulations] aim to meet Canada’s commitment to reduce methane emissions from the oil and gas sector by 40–45% of 2012 levels by 2025. By meeting this objective, the Regulations will achieve significant reductions in GHG emissions through reductions in fugitive and venting emissions of hydrocarbon gases from the upstream oil and gas sector, thereby reducing future methane releases to the environment.

This will reduce Canadian GHG emissions and help limit increases in global average temperatures, contributing to Canada’s international obligations to combat climate change. In addition, as methane is a short-lived climate pollutant with significant near-term climate impacts, these reductions will contribute to slowing the rate of near-term global warming.

Description

The Regulations will impose both general facility standards and standards that depend on a facility producing and receiving (potential to emit) at least 60 000 m 3 of hydrocarbon gas in a year. The standards relate to production processes and equipment and will result in the reduction of methane and targeted VOCs emissions from the upstream oil and gas sector. These provisions will directly impact oil and gas facilities that contain equipment covered by the Regulations, such as:

Oil and gas wells : Sites where a hole is drilled in the earth designed to produce crude oil or natural gas as part of extraction operations.

Oil and gas batteries : A system or arrangement of tanks or other surface equipment receiving oil or gas from one or more wells.

Natural gas processing plants : A plant where produced gas is processed by separating the various hydrocarbons and fluids from pure natural gas to produce gas that is ready for sale.

Compressor stations : These stations have equipment that is used to increase the pressure of the gas received from a well, battery, gathering system or transmission pipeline for delivery of natural gas to processing, storage or markets.

Pipelines : A network of pipes used to transport gases and liquids other than for local distribution purposes.

The following standards apply to facilities with a potential to emit above 60 000 m 3 :

Facility production venting : As of January 1, 2023, upstream oil and gas facilities exceeding the potential to emit threshold in the previous 12 months will be required to meet the venting requirements. These requirements do not apply to non-routine activities such as emergencies or blowdowns; however, records must be kept for this non-routine venting.

In situations where the total amount of gas vented, flared and sold at a facility (excluding that used on site as fuel) is less than 40 000 m 3 per year (termed the surplus gas threshold), the facility will not be required to implement any venting reduction measures. However if the surplus gas threshold of 40 000 m 3 per year is exceeded, venting of hydrocarbons is limited to an average of 1 250 m³ per month.

Facilities subject to the venting limit will be required to capture the gas and either use it on site, reinject it underground, send it to a sales pipeline, or route it to a destruction device such as a flare. Operators of conventional heavy oil production facilities who estimate, rather than directly measure, their gas production volumes will be required to adhere to a more robust gas estimation protocol.

Leak detection and repair : Upstream oil and gas facilities, except single wellheads (both with and without metering on the wellhead), and valve sites on transmission pipelines will be required to implement leak detection and repair (LDAR) programs as of January 1, 2020. Inspections will be required three times per year, and corrective action will be required if leaks are discovered. Leaks will need to be repaired within 30 days (if repairs are possible without shutting down the equipment). If it is not possible to conduct repairs without shutting down the equipment, the facility operator will be required to

schedule a shutdown to take corrective action before the volume of gas from all leaks is larger than the volume of gas that will be released by shutting down the equipment. If the facility is located offshore and the equipment cannot be repaired while operating, corrective action will need to be taken within 730 days. A renewable permit, if granted by the Minister of the Environment (the Minister), can allow additional time for repairs to be completed.

Pneumatic controllers : Facilities will be required to use pneumatic controllers that emit below 0.17 m³ per hour. This is not applicable when emissions are routed to control equipment or when the need for a higher-emitting controller is demonstrated as of January 1, 2023.

Pneumatic pumps : Pumps will be prohibited from emitting hydrocarbon gas at sites where liquid pumping exceeds 20 L per day as of January 1, 2023.

The following standards apply to all facilities:

Well completion involving hydraulic fracturing : These sites will be required to conserve or destroy gas instead of venting as of January 1, 2020. This standard will not apply to British Columbia or Alberta, where existing provincial measures cover these activities, and will not apply in cases where the gas does not have sufficient heating value to support combustion.

Compressors: All compressors with a rated brake power over 75 kW will be required to conserve, destroy, or meet the applicable limits. Emissions from compressor vents will require either measurement at least once per year or continuous monitoring of the flow rate of hydrocarbon gas emissions will be required from sealing systems, as of January 1, 2020. Corrective action will be required if those emissions exceed the limit applicable to the compressor, which depends on the installation date, the type of compressor and rated brake power.

All upstream oil and gas facilities will be required to register and keep records to demonstrate compliance with the Regulations. Facilities will also be required to submit reports at the request of the Minister.

The Department made notable modifications to the proposed Regulations in response to extensive consultation with stakeholders and departmental analysis of their feedback. The revisions are summarized in Table 1. Further information and analysis of these changes can be located in the Consultation

section below.

Table 1:

Summary of modifications from the proposed Regulations

Standard

Modifications made from proposed Regulations

Facility production venting

The facility venting limit was increased from 250 m³ to 1 250 m³ per month.

A method has been added to enhance quantification of estimated gas volumes.

Leak detection and repair

An allowance was added for alternate leak detection methods and instruments for LDAR if their use results in emission reductions equivalent to the reductions that would be achieved with the required inspection program.

Exemptions have been added for valve stations on pipelines and single wellheads with metering.

Additional time to complete repairs may now be granted through a permit.

A requirement has been added for LDAR at abandoned wells if they are part of a covered facility.

Well completion involving hydraulic fracturing

An allowance was added for venting when the gas cannot sustain combustion.

Pneumatic controllers and pumps

An exemption was added for sites when propane for use in pneumatics is brought on-site.

Zero-bleed pneumatic controllers are no longer required at any facility. Instead, a bleed rate limit of 0.17 m³ per hour must be met.

The chemical use threshold for pumps is now set at the site, not pump, level.

Compressors

An exemption has been added for compressors with a rated brake power less than 75 kW.

Time limits for repairs to reciprocating compressors have been extended from 30 days to 90 days.

The vent limit for large centrifugal compressors with a power rating above > 5 MW has been increased from 0.34 m³ per minute to 0.68 m³ per minute per compressor.

Vent limit of 0.001 m 3 per minute for new reciprocating compressors will now be required, as opposed to conservation requirement.

General

Timeline for potential to emit calculations changed from largest of past five years to previous calendar year.

Offshore

A new

section in the Regulations has been added for requirements specific to offshore operations.

Additional time to complete repairs in the offshore environment may now be granted through a permit.

Registration

Registration requirements have been modified and reduced to require facility level registrations only when a facility is not already registering to an approved entity.

The timeline for submitting registration has been extended to 120 days from the first day of production.

Accompanying the Regulations are consequential amendments to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) [the Designation Regulations]. The Designation Regulations designate the various provisions of regulations made under the Canadian Environmental Protection Act, 1999 (CEPA) that are linked to a fine regime following the successful prosecution of an offence involving harm or risk of harm to the environment or obstruction of authority. The Regulations will be listed in the Designation Regulations, which will require amendment.

Regulatory and non-regulatory options considered

When considering how to address the public policy issue, the Department considered five options: maintaining the status quo, using voluntary instruments, implementing a market-based approach, implementing regulatory emission control requirements that are closely aligned with the U.S. New Source Performance Standards (NSPS), or implementing Canada-specific regulatory emission control requirements.

Status quo approach

While British Columbia, Alberta, and Saskatchewan have measures to address venting methane emissions, there is no existing federal requirement in Canada to reduce GHG emissions from existing upstream oil and gas facilities. These provinces currently have some instruments in place for some aspects of the upstream oil and gas sector, such as British Columbia’s Flaring and Venting Reduction Guideline , Alberta’s Directive 060 and Saskatchewan’s directives S-10 and S-20. However, these instruments are not consistent across jurisdictions and do not cover all sources of emissions.

Therefore, current provincial measures alone would not deliver significant and achievable reductions in GHG emissions from the oil and gas sector, and may compromise Canada’s ability to meet its international commitments. Therefore, maintaining the status quo was not an acceptable option.

Voluntary approach

Voluntary instruments, such as pollution prevention plans, environmental release guidelines, and codes of practice were considered as options for methane mitigation. Voluntary instruments provide flexibility for stakeholders in meeting the objectives of the policy; however, they require a large degree of stakeholder participation and support.

The large number and diversity of facilities in the upstream oil and gas sector make it difficult to develop voluntary instruments capable of ensuring significant emission reductions. Uncertainty regarding buy-in by competitors under a voluntary measure may cause reluctance by firms to participate. While a voluntary program may result in some emission reductions, given its non-enforceable nature, it will not likely result in the emission reductions required to meet Canada’s GHG targets. Voluntary approaches were ultimately rejected for these reasons.

Market-based approach

Regulatory approach — Canada–United States alignment (new source performance standards)

Regulatory approach — industry proposal

Federal regulatory approach

The Regulations will create clear and consistent performance standards across the country. CEPA allows for flexibility via equivalency agreements with interested provinces and territories, as long as the requirements of CEPA are met. These equivalency agreements enable these jurisdictions to be front-line regulators where they have legally binding regimes that produce equal or better environmental outcomes.

The Regulations will exempt the provinces of British Columbia and Alberta from the well completion involving hydraulic fracturing requirements. These provinces already have regulatory measures in place that require operators to flare or incinerate gas during temporary activities and to search for opportunities to reduce their flaring and incinerating. The well completion involving hydraulic fracturing requirements under the Regulations will instead cover the rest of Canada, where similar provincial requirements are not in place.

Benefits and costs

Between 2018 and 2035, the cumulative GHG emission reductions attributable to the Regulations are estimated to be approximately 232 Mt CO 2 e. Avoided climate change damages associated with these reductions are valued at $11.6 billion. In addition, cumulative VOC emission reductions are estimated to be 773 kt, with resulting health and environmental benefits estimated to be $240 million. The total cost of the Regulations is estimated to be $3.9 billion, which will be offset in part by the recovery of 351 petajoules (PJ) footnote 12 of natural gas, with a market value of $1.0 billion, resulting in expected net benefits of $8.9 billion.

As shown in Figure 1 below, the most significant costs will be incurred in 2022 and 2023, as firms make significant capital investment in order to comply with requirements coming into force in 2023. Beyond 2023, it is expected that emissions of methane will be reduced by more than 16 Mt (in CO 2

e) annually. In 2025, the regulations will require actions that are estimated to result in total reductions of 20 Mt, of which 4 Mt have been attributed to voluntary industry action. In 2030, there will be net GHG emission reductions of about 16.5 Mt.

Figure 1: Methane emission reductions and compliance costs by year

Analytical framework

TBS guidance : The impacts of the Regulations have been assessed in accordance with the Treasury Board Secretariat (TBS) Canadian Cost-Benefit Analysis Guide. footnote 13 Regulatory impacts have been identified, quantified and monetized where possible, and compared incrementally to a non-regulatory scenario. The analysis has estimated these impacts over a sufficient time period to demonstrate whether there is likely to be a net benefit.

Key impacts : The expected key impacts of the Regulations are demonstrated in the logic model (Figure 2) below. Compliance with the Regulations will result in incremental capital and operating costs for industry, and administrative costs for both industry and Government. Compliance will also result in reduced releases of natural gas (a mixture consisting of mostly methane and VOCs), which will reduce releases of GHGs and VOCs footnote 14 to the atmosphere. Reductions in GHG emissions from the upstream oil and gas sector will contribute towards mitigating climate change impacts.

Reductions in VOCs will improve air quality which results in environmental and health co-benefits. Methane gas that would have otherwise been lost through fugitive leaks or venting will now be conserved as a potential energy source or flared.

Figure 2: Logic model for the analysis of the Regulations

Logic model for the analysis of the Regulations

Compliance with the Regulations

Reductions in GHG Emissions

Reduction in Climate Change Damages

Social Benefits

Reductions in VOC Emissions

Improved Air Quality

Conserved Gas

Increased Conservation

Compliance Costs

Social Costs

Administrative Costs

Baseline scenario : The baseline scenario assumes fugitive and venting emissions of methane and VOCs will be unchanged relative to projected levels in the absence of regulatory measures. In order to ensure a conservative assessment of benefits for the purposes of this analysis, independent industry action to reduce venting volumes has been incorporated into the baseline scenario. Existing provincial measures on limiting methane emissions from oil and gas facilities are included in the baseline.

Regulatory scenario : The analysis compares the expected impacts of the Regulations (the regulatory scenario) to a non-regulatory scenario that assumes these regulatory measures are not implemented (the baseline scenario). All benefits and costs presented below are incremental to the baseline scenario, unless otherwise specified.

Time frame of analysis : The time frame considered for this analysis is 2018 to 2035. Some early compliance at new facilities is expected starting in 2018. Incremental costs and benefits beyond 2023 are estimated to be correlated with oil and gas production forecasts from the National Energy Board (NEB), which are available up to 2035. Benefits exceed costs in any given year beyond 2023. Therefore, the 2018-2035 time frame was considered sufficient for estimating whether the Regulations will result in a net benefit. A longer time period of analysis will show a larger net benefit because most of the costs of the Regulations are upfront costs incurred in 2023, as shown in Figure 1 above.

Monetary results : All monetary results are shown in 2016 Canadian dollars, inflating non-2016 prices (using GDP Deflator data obtained from Finance Canada), and converting non-Canadian prices (2016 exchange rates). When shown as present values, future year impacts have been discounted at 3% per year to 2017 (the year of the analysis), as per TBS guidance.

Updates to the analysis following publication of the proposed Regulations in Canada Gazette,

Part I (CG-

I) Analytical updates

Comments received following the publication of the proposed Regulations included feedback from stakeholders regarding the Regulatory Impact Analysis Statement. In addition, following publication in CG-I, the Department engaged with provincial partners, industry stakeholders, and non-governmental organizations to review modelling assumptions used in the analysis of the proposed Regulations. In response, the following substantive changes have been made to the analysis:

Projected baseline emissions have been updated to align with the 2016 departmental reference case, while updating oil and gas production and price forecasts. footnote 15

The latest provincial production and venting data, which is used to determine facility counts and baseline venting emissions, has been incorporated into the analysis. Analysis of the latest reported venting data has led to some attribution of emission reductions to industry action. In addition, estimated facility counts have been revised upward based on this information.

Assumptions regarding the choice of compliance action to comply with the general facility venting requirements have been updated. These updates, combined with updated facility venting data, have resulted in a reduction in conserved gas attributable to these requirements.

Several cost assumptions have been updated based on feedback received from stakeholders, including:

a) assumed time per LDAR inspection has been revised upward;

b) assumed capital costs to comply with facility production venting requirements has been revised downward; and

c) rod-packing replacement costs have been revised upward.

In addition, price levels and exchange rates have been updated to align with the most up-to-date information, and the base year to discount costs and benefits to present value has been updated to 2017. In total, these analytical changes have led to an increase in estimated costs from $3.3 billion estimated in CG-I to $4.4 billion. Emission reductions attributable to the proposed Regulations have decreased from 282 Mt to 245 Mt, with 69 Mt now being attributed to industry action that is expected to occur in the absence of regulatory measures.

Regulatory updates

Based on the comments received following the publication of the proposed Regulations in Canada Gazette ,

Part I, minor modifications have been made to the Regulations, as outlined in the Description

section above. These modifications are estimated to result in a reduction of costs from $4.4 billion to $3.9 billion, while emissions reductions over the period of analysis are estimated to decrease from 245 Mt to 232 Mt.

Analysis of regulatory coverage and compliance

To estimate the incremental benefits and costs of the Regulations, the analysis considered who will be affected (regulatory coverage) and how they will most likely respond (their compliance strategies), as described below.

Regulatory coverage

The Regulations will target emissions from the upstream oil and gas sector by implementing facility and equipment level requirements. Facility level requirements will include emission limits on facility production venting and LDAR standards. At the equipment level, there will be requirements for well completion involving hydraulic fracturing, as well as limits on emissions from pneumatic devices (controllers and pumps) and compressors.

The Regulations will cover facilities that exceed the potential to emit threshold, defined as 60 000 m 3 of hydrocarbons produced and received in a period of 12 months, facilities with compressors subject to the standards, and those completing wells involving hydraulic fracturing (covered facilities). Currently, some facilities are expected to already meet the compliance requirements of the Regulations due to current provincial measures or voluntary action. Facilities that will need to take incremental action to comply with the Regulations are considered affected facilities. The cost-benefit analysis focuses on affected facilities when estimating incremental impacts of the Regulations.

In order to estimate affected and covered facilities in the oil and gas sector, 2016 Petrinex (Petroleum Information Network) footnote 16 upstream oil and gas facility counts for Alberta and Saskatchewan were used, and forecasted using the production forecasts of crude oil and natural gas from the NEB. footnote 17 Due to limited available information, the number of facilities in the rest of Canada was forecasted using production profiles calculated for Alberta and Saskatchewan. Feedback from British Columbia officials allowed the derived facility count for that province to be adjusted. Other producing regions reflect similar efforts.

Regulatory compliance

The Regulations do not prescribe unique actions to comply with the requirements. However, for modelling purposes, assumptions have been made regarding specific compliance actions in order to estimate costs and benefits. The compliance actions assumed to be adopted by the upstream oil and gas industry in order to meet the requirements for each standard under the Regulations are described below.

LDAR requirements

The Regulations will allow different leak detection instruments to be used for inspections at covered facilities. For portable monitoring instruments and optical gas imaging (OGI) cameras, inspections must take place three times per year. Other approaches must be shown to achieve emission reductions comparable to reductions achieved if portable monitoring or OGI instruments were used.

Based on industry consultation, it is expected that in the baseline scenario, facilities not covered by provincial regulatory measures will perform LDAR about once every four years. For facilities covered by provincial regulatory measures, gas plants are expected to perform LDAR every year, while all other facilities are expected to perform LDAR once every two years in the baseline scenario.

The analysis assumes that to comply with the Regulations, affected facilities will perform LDAR with an optical gas imaging (OGI) camera three times a year. Should a leak be detected, a facility will be required to repair the leak and reinspect the leak using a portable monitoring instrument.

Compressor requirements

For existing reciprocating and centrifugal compressors whose vented emissions are not being captured or destroyed, the Regulations will set emissions limits. Corrective action is required if those emissions exceed 0.023 m 3 per minute per rod packing for reciprocating compressors, or 0.34 m 3 per minute per compressor for centrifugal compressors. Large centrifugal compressors with a rated brake power over 5 MW power will be subject to an emission limit of 0.68 m 3 per minute per compressor. After corrective action is taken, the rate of emissions must be measured again.

In addition, any compressors installed after January 1, 2023, must meet a limit of 0.001 m 3 per minute per rod packing for reciprocating compressors and 0.14 m 3 per minute per compressor for centrifugal compressors.

It is expected that affected facilities with reciprocating compressors will, on average, replace rod packings every three years in the regulatory scenario compared to replacement every four years in the baseline scenario. It is expected that facilities with newly installed compressors, where a flare is not already present, will install a capture device and either route vented gas to engine as fuel or to an existing flare.

Affected facilities with centrifugal compressors with wet seals are expected to install recovery systems on their wet seal degassing units to recover and reroute vented gas. The degassing recovery system will allow facilities with wet seals to forego retrofitting their compressors with dry seals and still mitigate methane emissions with little downtime. It is assumed new centrifugal compressors would comply with the requirements in the absence of the Regulations.

Well completion involving hydraulic fracturing requirements

The Regulations will require hydraulic fracturing operations to conserve or destroy vented gas, except in British Columbia and Alberta (where equivalent provincial requirements exist). In the baseline scenario, it is expected that about 25% of covered wells are currently flaring emitted gas during this process while the rest are venting emitted gas. For the regulatory scenario, it is assumed that all well completions involving hydraulic fracturing wells will flare emitted gases to comply with the Regulations, although conservation remains a viable compliance option.

Facility production venting requirements

The Regulations will require covered facilities to limit vented gas to 15 000 m 3 per year. Affected facilities will comply with the Regulations either by destroying or conserving vented gas. It is assumed that it will be less costly for a facility to conserve its vented gas if its gas production minus on-site fuel use is greater than 750 000 m 3 per year. Also, if the facility is already selling more than 20 000 m 3 of gas per year, it is assumed that it will conserve gas. If neither of these conditions is met, it is assumed the facility will combust the gas. Installa