Document ID: chunk:federal_register_of_legislation:F2024C00833:reg:8:p1
Version: federal_register_of_legislation:F2024C00833
Segment Type: reg
Provision Reference: reg 8 (pt 1/4)
Character Range: 409385–412126

8     Other—leaker                              5.88 × 10‑3                         2.29 × 10‑05  tonnes CO2‑e / component ‑ hour

 (4) For subsection (3), the LDAR program must survey each component used in natural gas processing at the facility at least once in a reporting year in accordance with:
         (a)  paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America using optical gas imaging with a sensitivity of 60 grams per hour; or
         (b) the method outlined in USEPA Method 21—Determination of organic volatile compound leaks, as set out in Appendix A‑7 of Title 40, Part 60 of the Code of Federal Regulations, United States of America where a leaker is detected if 10,000 parts per million or greater is measured consistent with that method; or
         (c) an equivalent leak detection standard.
 (5) To determine whether a component is a leaker or non leaker at a period of time:
         (a)  if a leak is detected in a survey the component is assumed to leak from the later of the beginning of the reporting year or last survey where it was a non leaker; and
         (b)  after a leak is detected in a survey the component is assumed to leak until the earlier of the end of the reporting year or the next survey where it is a non leaker.

Division 3.3.7—Natural gas transmission (other than emissions that are flared)

3.74  Application
  This Division applies to fugitive emissions from natural gas transmission activities.

3.75  Available methods
 (1) Subject to section 1.18 and subsection (2), one of the following methods must be used for estimating fugitive emissions (other than flaring) of each gas type, being carbon dioxide and methane, released from the operation of a facility that is constituted by natural gas transmission through a system of pipelines during a year:
 (a) method 1 under section 3.76;
 (b) method 2 under section 3.77;
 (c) method 3 under section 3.78.
Note: There is no method 4 for this Division.
 (2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

3.76  Method 1—natural gas transmission (other than flaring)
  Method 1 is:

  Eij = (Li × EFij)

where:
Eij is the fugitive emissions (other than flaring) of gas type (j) from natural gas transmission through a system of pipelines of length (i) during the year measured in CO2‑e tonnes.
Li is the length of the system of pipelines (i) measured in kilometres.
EFij is the emission factor for gas type (j), which is 0.02 for carbon dioxide and 11.6 for methane, measured in tonnes of CO2‑e emissions per kilometre of pipeline (i).

3.77  Method 2—natural gas transmission (other than flaring)
 (1) Method 2 is:

   Ej