Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (SOR/2018-66)

Marginal note: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 m³, during the given month;

• (b) the combined volume of hydrocarbon gas produced and received, expressed in standard m³, 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).

Marginal note: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 m³ 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

Marginal note:Applicable methods

• 23 (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.

• Marginal note: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 m³ 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 m³, of oil produced by the well for a day during the most recent month of production.

Marginal note:Determination of gas-to-oil ratio

• 24 (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.

• Marginal note: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.

• Marginal note: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 m³ 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.

• Marginal note: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 m³; 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 m³ 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.

• Marginal note: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.

• Marginal note: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.

• Marginal note: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 m³ 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 m³ 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 m³ per day and at most 1 000 standard m³ 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 m³ per day and at most 1 000 standard m³ 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 m³ per day and at most 2 000 standard m³ 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 m³ per day and at most 2 000 standard m³ per day.

Marginal note: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

Marginal note:15 000 standard m³ per year

• 26 (1) An upstream oil and gas facility must not vent more than 15 000 standard m³ of hydrocarbon gas during a year.

• Marginal note: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.

• Marginal note: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 m³ for the 12 consecutive months before that given month.

• Marginal note: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 m³ for the 12 consecutive months before that subsequent month.

Marginal note: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 m³;

• (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 m³; and

• (d) the volume of hydrocarbon gas delivered from the facility, expressed in standard m³.

Leak Detection and Repair Program

Establishment of Program

Marginal note:Non-application to certain equipment components

• 28 (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.

• Marginal note: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).

Marginal note:Regulatory or alternative LDAR programs

• 29 (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.

• Marginal note: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

Marginal note:Obligation to inspect

• 30 (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.

• Marginal note: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.

• Marginal note: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.

• Marginal note:Operation and maintenance

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

• Marginal note: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.