National Greenhouse and Energy Reporting (Measurement) Amendment (2021 Update) Determination 2021

I, Angus Taylor, Minister for Energy and Emissions Reduction, make the following instrument.

Dated: 15 June 2021    

Angus Taylor

Minister for Energy and Emissions Reduction

Contents

1  Name ..................................................3

2  Commencement............................................3

3  Authority................................................3

4  Schedules................................................3

Schedule 1—Amendments 4

National Greenhouse and Energy Reporting (Measurement) Determination 2008 4

1  Name

  This is the National Greenhouse and Energy Reporting (Measurement) Amendment (2021 Update) Determination 2021.

2  Commencement

 (1) Each provision of this instrument specified in column 1 of the table commences, or is taken to have commenced, in accordance with column 2 of the table. Any other statement in column 2 has effect according to its terms.

Note: This table relates only to the provisions of this instrument as originally made. It will not be amended to deal with any later amendments of this instrument.

 (2) Any information in column 3 of the table is not part of this instrument. Information may be inserted in this column, or information in it may be edited, in any published version of this instrument.

3  Authority

  This instrument is made under subsection 10(3) of the National Greenhouse and Energy Reporting Act 2007.

4  Schedules

  Each instrument that is specified in a Schedule to this instrument is amended or repealed as set out in the applicable items in the Schedule concerned, and any other item in a Schedule to this instrument has effect according to its terms.

Schedule 1—Amendments

National Greenhouse and Energy Reporting (Measurement) Determination 2008

[1] At the end of section 1.4

Add:

 (3) Data points relevant to the implementation of particular methods are set out in column 3 of the tables in Schedule 4 as ‘matters to be identified’. 

Note: Regulations 4.10, 4.11, 4.13, 4.14, 4.15 and 4.17 of the Regulations require these matters to be identified to be included in reports under the Act.

[2] Section 1.8 (subparagraph (d)(i) of the definition of appropriate unit)

Omit “including crude oil condensates,”, substitute “plant condensate”.

[3] Section 1.8

Insert in the appropriate alphabetical position:

captured for enhanced oil recovery: a greenhouse gas is captured for enhanced oil recovery if it is captured and transferred to the holder of an enhanced oil recovery authority for injection into a geological formation, such as a natural reservoir, to further oil or gas production activities and is not captured for permanent storage. 

city gate means a distribution hub where gas is reduced in pressure before it enters the lower pressure, smaller diameter, distribution pipeline network.

CO2 stimulation means using carbon dioxide as a fluid in well stimulation treatment which enhances oil and gas production or recovery by increasing the permeability of the formation.

crude oil has the meaning given by the Regulations.

enhanced oil recovery authority means a licence, lease or approval by or under a law of the Commonwealth, State or Territory which authorises the injection of one or more greenhouse gases into one or more geological formations, such as a natural reservoirs, to further oil or gas production activities.

equivalent leak detection standard, means a standard or documented approach that:

 (i) 60 grams per hour in accordance with paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America; or

 (ii) 10,000 parts per million or greater in accordance with 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.

Leak Detection and Repair Program or LDAR program means a system of procedures used at a facility to monitor, locate and repair leaking components in order to minimize emissions.

leaker, in relation to a component subject to an LDAR program, means:

Note: Under the definition of equivalent leak detection standard, the sensitivity must be equivalent or higher than the approaches in paragraph (a) or (b).

liquefied natural gas station means the plant and equipment used in the natural gas liquefaction, storage and transfer of liquefied natural gas, and includes:

 (a) all onshore or offshore equipment that receives natural gas, liquefies and stores liquefied natural gas, and transfers the liquefied natural gas to a transportation system; and

 (b) equipment that receives imported or transported liquefied natural gas, stores liquefied natural gas, re-gasifies liquefied natural gas, and delivers re-gasified natural gas to a natural gas transmission or distribution system.

natural gas distribution pipelines mean pipelines for the conveyance of pipeline natural gas that:

 (a) are identified as a distribution pipeline in an access arrangement applicable to the pipeline; or

 (b) meet both of the following:

 (i) have a maximum design pressure of 1,050 kPa or less; and

 (ii) are not natural gas gathering and boosting pipelines.

natural gas liquefaction, storage and transfer means the activity to collect and liquefy natural gas and to store and transfer liquefied natural gas to a transportation system.

natural gas production includes offshore natural gas production and onshore natural gas production.

natural gas processing means one or both of the following activities:

 (a) the separation of natural gas liquids or non-methane gases from unprocessed natural gas or coal seam methane; 

 (b) the separation of natural gas liquids into one or more component mixtures.

Note: The separation includes one or more of the following: forced extraction of natural gas liquids, sulphur and carbon dioxide removal, fractionation of natural gas liquids, or the capture of CO2 separated from natural gas streams.

natural gas storage means the activity to store unprocessed natural gas, coal seam methane or natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas).

natural gas storage station means the plant and equipment used in natural gas storage, and includes:

 (a) subsurface storage, such as depleted gas or oil reservoirs that store gas; and

 (b) the equipment to undertake natural gas underground storage processes and operations (including compression, dehydration and flow measurement, but excluding natural gas transmission pipelines); and

 (c) all the wellheads connected to the compression units located at the station that inject and recover natural gas into and from the underground reservoirs.             

natural gas transmission pipeline means a pipeline for the conveyance of pipeline natural gas or plant condensate that:

 (a) is licensed as a transmission pipeline under a Commonwealth, State or Territory law; and

 (b) has a maximum design pressure exceeding 1,050 kPa; and

 (c) is not a natural gas distribution pipeline or a natural gas gathering and boosting pipeline.

oil or gas exploration and development means the activity to explore for oil and gas resources and test, appraise, drill, develop and complete wells for oil and gas resources and includes the following actions:

 (a) oil well drilling;

  (b) gas well drilling;

 (c) drill stem testing;

 (e) well appraisals;

 (f) development drilling;

 (g) well completions;

 (h) well workovers associated with the actions in the paragraphs above.

offshore natural gas production means the activity to produce, extract, recover, lift, stabilise, separate or treat unprocessed natural gas, condensate or coal seam methane on offshore submerged lands, including well workovers.

offshore platform includes:

 (a) any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses plant and equipment to do either or both of the following:

 (i) extract unprocessed natural gas and condensate from the ocean or lake floor;

 (ii) transfers such unprocessed natural gas and condensate to storage, transport vessels, or onshore; and

 (b) secondary platform structures connected to the platform structure via walkways, and

 (c) storage tanks associated with the platform structure; and

 (d) floating production and storage offloading equipment; and

 (e) submerged wellhead production structures.

offshore platform (shallow water) means an offshore platform standing in less than 200 metres of water.

offshore platform (deep water) means an offshore platform standing in at least 200 metres of water.

onshore natural gas production means the activity to produce, extract, recover, lift, stabilise, separate or treat unprocessed natural gas, condensate or coal seam methane on land, including well workovers.

onshore natural gas wellhead means the gas wellhead.

plant condensate has the meaning given by the Regulations.

pipeline natural gas means natural gas that is suitable for market consumption.

[4] Section 1.8

Repeal the following definitions:

[5] Section 1.8 (definition of fugitive emissions)

Repeal the definition, substitute:

fugitive emissions means greenhouse gas emissions that are:

[6] Section 1.8 (definition of natural gas distribution)

Repeal the definition, substitute:

natural gas distribution means the transport of pipeline natural gas over a combination of natural gas distribution pipelines from a city gate to customer delivery points.

[7] Section 1.8 (definition of natural gas transmission)

Repeal the definition, substitute:

natural gas transmission means transmission of natural gas or plant condensate through one or more natural gas transmission pipelines from a natural gas processing station or a natural gas gathering and boosting network to any of the following:

  (a) a natural gas distribution network;

 (b) another natural gas processing station;

 (c) a liquefied natural gas station;

 (d) a large industrial facility, such as a power station.

[8] Section 1.8 (definition of well workover)

Repeal the definition, substitute:

well workover means activities performed to restore or increase production which can include any or all of the following processes:

 (a) well venting;

  (b) tubing maintenance;

 (c) air clean out;

 (d) hydraulic fracturing and recovery;

 (e) well unloading.

[9] Subsection 1.9(4)

Omit “1 July 2014”, substitute “1 January 2020”.

[10] Subsection 1.10(1)

Repeal the subsection, substitute:

 (1) A thing mentioned in the column headed ‘Source of emissions’ of the following table is a source.

[11] Subsection 2.27(1)

After “subsection (2)”, insert “and (3)”.

[12] Subsection 2.27(2)

Repeal the subsection, substitute:

 (2) In applying method 1 under section 2.20, the emission factor EFijoxec is to be one of the following:

 (a) obtained by using the equipment type emission factors set out in Volume 2, section 2.3.2.3 of the 2006 IPCC Guidelines corrected to gross calorific values;

 (b) estimated based on the manufacturer’s specification for the specific equipment type under relevant operational conditions, including the effect of any supplementary equipment technologies that modify methane emitted to the atmosphere;

 (c) if an equipment type (k) in column 2 of the following table is used—the factor in column 3 of the following table for the equipment type in column 2 of the table:

 (3) If applicable to the facility, the method described in section A.2.2 of Appendix A of the API Compendium may be used as method 2.

Note: In 2021, the API Compendium could be accessed at www.api.org.

[13] Subsection 2.45(1) (table items 3 and 4)

Repeal the items, substitute:

[14] Subsection 2.47(3) (table items 3 and 4)

Repeal the items, substitute:

[15] Part 3.3

Repeal the Part, substitute:

Part 3.3—Oil and natural gas—fugitive emissions

Division 3.3.1—Preliminary

3.41  Outline of Part

 (1) This Part provides for fugitive emissions from the following:

 (a) oil or gas exploration and development (see Division 3.3.2);

 (b) crude oil production (see Division 3.3.3);

 (c) crude oil transport (see Division 3.3.4);

 (d) crude oil refining (see Division 3.3.5);

 (e) onshore natural gas production, other than emissions that are vented or flared (see Division 3.3.6A);

 (f) offshore natural gas production, other than emissions that are vented or flared (see Division 3.3.6B);

 (g) natural gas gathering and boosting, other than emissions that are vented or flared (see Division 3.3.6C);

 (h) produced water from oil and gas exploration and development, crude oil production, natural gas production or natural gas gathering and boosting, other than emissions that are vented or flared (see Division 3.3.6D);

 (i) natural gas processing, other than emissions that are vented or flared (see Division 3.3.6E);

 (j) natural gas transmission, other than emissions that are flared (see Division 3.3.7);

 (k) natural gas storage, other than emissions that are vented or flared (see Division 3.3.7A);

 (l) natural gas liquefaction, storage and transfer, other than emissions that are vented or flared (see Division 3.3.7B);

 (m) natural gas distribution, other than emissions that are flared (see Division 3.3.8);

 (n) natural gas production (emissions that are vented or flared) (see Division 3.3.9A);

 (o) natural gas gathering and boosting (emissions that are vented or flared) (see Division 3.3.9B);

 (p) natural gas processing (emissions that are vented or flared) (see Division 3.3.9C);

 (q) natural gas transmission (emissions that are flared) (see Division 3.3.9D);

 (r) natural gas storage (emissions that are vented or flared) (see Division 3.3.9E);

 (s) natural gas liquefaction, storage or transfer (emissions that are vented or flared) (see Division 3.3.9F);

 (t) natural gas distribution (emissions that are flared) (see Division 3.3.9G).

 (2) The activities at a facility should be classified in accordance with the relevant definitions to apply the calculations in this Part to comprehensively cover the emissions from the facility, but not count the emissions more than once.

3.41A  Interpretation

 (1) Terms relating to the oil and gas industry in this Part are to be interpreted:

 (a) consistently with their accepted meaning in the oil and gas industry; and

 (b) where the term is relevant to methods in the API Compendium—taking into account the meaning and scope of the term in that compendium.

Note: In 2021, the API Compendium could be accessed at www.api.org.

 (2) If a method in this Part allows for the use of component or equipment emissions factors from the manufacturer of the component or equipment, those factors must not be used if they are likely to result in estimates of emissions inconsistent with the principles in section 1.13.

Division 3.3.2—Oil or gas exploration and development

Subdivision 3.3.2.1—Preliminary

3.42  Application

  This Division applies to fugitive emissions from venting or flaring from oil or gas exploration and development activities, including emissions from:

 (a) oil well drilling; and

 (b) gas well drilling; and

 (c) oil well completions; and

(d) gas well completions; and

(e) well workovers; and

(f)  well blowouts; and

(g)  cold process vents.

Subdivision 3.3.2.2—Oil or gas exploration and development (emissions that are flared)

3.43  Available methods

 (1) Subject to section 1.18, for estimating emissions released by oil or gas flaring during the year from the operation of a facility that is constituted by oil or gas exploration and development:

 (a) if estimating emissions of carbon dioxide released—one of the following methods must be used:

 (i) method 1 under section 3.44;

 (ii) method 2 under section 3.45;

 (iii) method 3 under section 3.46; and

 (b) if estimating emissions of methane released—one of the following methods must be used:

 (i) method 1 under section 3.44;

 (ii) method 2A under section 3.45A; and

 (c) if estimating emissions of nitrous oxide released—one of the following methods must be used:

 (i) method 1 under section 3.44;

 (ii) method 2A under section 3.45A.

Note: There is no method 4 under paragraph (a) and no method 2, 3 or 4 under paragraph (b) or (c).

 (2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

3.44  Method 1—oil or gas exploration and development

 (1) Method 1 is:

  Eij  = Qi  ×  EFij

where:

Eij is the fugitive emissions of gas type (j) from a fuel type (i) flared in the oil or gas exploration and development during the year measured in CO2‑e tonnes.

Qi is the quantity of fuel type (i) flared in the oil or gas exploration and development during the year measured in tonnes.

Note: This quantity includes all of the fuel type, not just hydrocarbons within the fuel type.

EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of the fuel type (i) flared.

 (2) For EFij in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor, for gas type (j), for each fuel type (i) specified in column 2 of that item.

3.45  Method 2—oil or gas exploration and development (flared carbon dioxide emissions)

Combustion of gaseous fuels (flared) emissions

 (1) For subparagraph 3.43(1)(a)(ii), method 2 for combustion of gaseous fuels is:

where:

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in oil or gas exploration and development during the year, measured in CO2‑e tonnes.

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in oil or gas exploration and development during the year, measured in tonnes in accordance with Division 2.3.3.

EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in oil or gas exploration and development during the year, measured in CO2‑e tonnes per tonne of the fuel type (i) flared, estimated in accordance with Division 2.3.3.

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.

QCO2 is the quantity of CO2 within fuel type (i) in oil or gas exploration and development during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.

Combustion of liquid fuels (flared) emissions

 (2) For subparagraph 3.43(1)(a)(ii), method 2 for combustion of liquid fuels is the same as method 1 under section 3.44, but the carbon dioxide emissions factor EFij must be determined in accordance with method 2 in Division 2.4.3.

3.45A  Method 2A—oil or gas exploration and development (flared methane or nitrous oxide emissions)

  For subparagraphs 3.43(1)(b)(ii) and (c)(ii), method 2A is:

where:

EFhij is the emission factor of gas type (j), being methane or nitrous oxide, for the total hydrocarbons (h) within the fuel type (i) in oil or gas exploration and development during the year, mentioned for the fuel type in the table in subsection 3.44(2) and measured in CO2‑e tonnes per tonne of the fuel type (i) flared.

Eij is the fugitive emissions of gas type (j), being methane or nitrous oxide, from fuel type (i) flared from oil or gas exploration and development during the year, measured in CO2‑e tonnes.

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in oil or gas exploration and development during the year, measured in tonnes in accordance with Division 2.3.3 for gaseous fuels or Division 2.4.3 for liquid fuels.

3.46  Method 3—oil or gas exploration and development

Combustion of gaseous fuels (flared) emissions

 (1) For subparagraph 3.43(1)(a)(iii), method 3 for the combustion of gaseous fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.3.4.

Combustion of liquid fuels (flared) emissions

 (2) For subparagraph 3.43(1)(a)(iii), method 3 for the combustion of liquid fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.4.4.

Subdivision 3.3.2.3—Oil or gas exploration and development—fugitive emissions from system upsets, accidents and deliberate releases

3.46A  Available methods

 (1) Subject to section 1.18, the methods mentioned in subsections (2) and (3) must be used for estimating fugitive emissions that result from system upsets, accidents and deliberate releases during a reporting year from the operation of a facility that is constituted by oil or gas exploration and development.

 (2) To estimate emissions for methane and carbon dioxide that result from deliberate releases from process vents, systems upsets and accidents at a facility during a year, for each oil or gas exploration and development activity one of the following methods must be used:

 (a) method 1 under:

 (i) section 3.46AB (natural gas well completions); and 

 (ii) section 3.56B (emissions from system upsets, accidents and deliberate releases from process vents); and

 (iii) section 3.85B (cold process vents); and

 (iv) section 3.85P (well workovers);

 (b) method 4 under:

 (i)  for emissions of methane and carbon dioxide from natural gas well completions activities, well workovers, cold process vents and well blowouts—section 3.46B; and

 (ii) for emissions and activities not mentioned in subparagraph (i)—Part 1.3.

 (3) For estimating incidental emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, another method may be used that is consistent with the principles mentioned in section 1.13.

Note: There is no method 2 or 3 for this Subdivision.

Subdivision 3.3.2.3.1—Fugitive emissions that result from deliberate releases from process vents, system upsets and accidents–well completions

3.46AB  Method 1—vented emissions from natural gas well completions  

 (1)  Method 1 is:

  Eij  = Σk   Qik   ×  EFijk  × Sij / SDij

where:

Eij is the fugitive emissions of gas type (j), being methane or carbon dioxide, vented from the natural gas exploration and development during the year measured in CO2‑e tonnes.

Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e and estimated by summing up the emissions released from all of the equipment of type (k) specified in column 2 of the table in subsection (2), if the equipment is used in the natural gas exploration and development.

Qik is the total of the number of well completion events for equipment of type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the natural gas exploration and development.

Note: Consistent with subsection 3.41(2), a well completion event should be reported for a single reporting year and not separately in two consecutive years.

EFijk is the emission factor for gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e per well completion event using equipment type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the natural gas exploration and development.

Sij  is the measured share of gas type (j), being methane or carbon dioxide, in the unprocessed natural gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.

SDij is the default share of gas type (j) in the unprocessed natural gas (i), for methane SD is 0.832 and for carbon dioxide SD is 0.0345.

 (2) For EFijk mentioned in subsection (1), column 3 of an item in the following table specifies the emission factor for methane for an equipment of type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide for an equipment of type (k) specified in column 2 of that item:

3.46B  Method 4—vented emissions from natural gas well completions, well workovers, cold process vents and well blowouts

  Method 4 is, for natural gas well completion activities, well workovers, cold process vents and well blowouts, as described in section 5.7.1 of the API Compendium.

Division 3.3.3—Crude oil production

Subdivision 3.3.3.1—Preliminary

3.47  Application

 (1) This Division applies to fugitive emissions from crude oil production activities, including emissions from flaring, from:

 (a) an oil wellhead; and

 (b) well servicing; and

 (c) oil sands mining; and

 (d) shale oil mining; and

 (e) the transportation of untreated production to treating or extraction plants; and

 (f) activities at extraction plants or heavy oil upgrading plants, and gas reinjection systems; and

 (g) activities at upgrading plants and associated gas reinjection systems.

 (2) For paragraph (1)(e), untreated production includes:

 (a) well effluent; and

 (b) emulsion; and

 (c) oil shale; and

 (d) oil sands.

Subdivision 3.3.3.2—Crude oil production (non‑flared)—fugitive leak emissions of methane

3.48  Available methods

 (1) Subject to section 1.18, for estimating fugitive emissions of methane, other than fugitive emissions of methane specified in subsection (1A), during a year from the operation of a facility that is constituted by crude oil production, one of the following methods must be used:

 (a) method 1 under section 3.49;

 (b) method 2 under section 3.50;

 (c) method 3 under section 3.51.

Note: There is no method 4 for this Division.

 (1A) For subsection (1), the following fugitive emissions of methane are specified:

 (a) fugitive emissions from oil or gas flaring;

 (b) fugitive emissions that result from system upsets, accidents or deliberate releases from process vents.

 (2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

3.49  Method 1—crude oil production (non‑flared) emissions of methane

 (1) Method 1 is:

where:

Eij is the fugitive emissions of methane (j) from the crude oil production during the year measured in CO2‑e tonnes.

Σk is the total emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions released from all of the equipment of type (k) specified in column 2 of the table in subsection (2), if the equipment is used in the crude oil production.

Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment of type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the crude oil production.

EFijk is the emission factor for methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes through each equipment of type (k) specified in column 2 of the table in subsection (2) during the year, if the equipment is used in the crude oil production.

Qi is the total quantity of crude oil (i) measured in tonnes that passes through the crude oil production.

EF(l) ij is 1.6 × 10‑3, which is the emission factor for methane (j) from general leaks in the crude oil production, measured in CO2‑e tonnes per tonne of crude oil that passes through the crude oil production.

 (2) For EFijk mentioned in subsection (1), column 3 of an item in the following table specifies the emission factor for an equipment of type (k) specified in column 2 of that item:

 (3) For EF(l) ij in subsection (1), general leaks in the crude oil production comprise the emissions (other than vent emissions) from equipment listed in sections 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production.

3.50  Method 2—crude oil production (non‑flared) emissions of methane

 (1) Method 2 is:

where:

Eij is the fugitive emissions of methane (j) from the crude oil production during the year measured in CO2‑e tonnes.

Σk is the total emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions released from each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment type is used in the crude oil production.

Qik is the total of the quantities of crude oil that pass through each equipment type (k), or the number of equipment units of type (k), listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil production, measured in tonnes.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per tonne of crude oil that passes through each equipment type (k) listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium as determined under subsection (2), if the equipment is used in the crude oil production.

 (2) For EFijk, the emission factors for methane (j), as crude oil passes through an equipment type (k), are:

 (a) as listed in sections 5.4.1, 5.4.2, 5.4.3, 5.6.4, 5.6.5 and 6.1.2 of the API Compendium, for the equipment type; or

 (b) if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type—those factors.

Eij = ∑k (EFijk × Tik × Nk)

where:

Eij is the fugitive emissions of methane (j) from the crude oil production during the year measured in CO2‑e tonnes.

Σk is the total emissions of methane (j) measured in tonnes of CO2‑e and estimated by summing up the emissions released from each component type (k) listed in section 6.1.3 of the API Compendium, if the component type is used in the crude oil production.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per component-hour that passes through each component type (k) listed in section 6.1.3 of the API Compendium as determined under subsection (2), if the component is used in the crude oil production.

Tik is the average hours of operation during the year of the components of each component type (k) listed in section 6.1.3 of the API Compendium, if the component type is used in the crude oil production, measured in hours per year.

Nk is the total number of each component type (k) listed in section 6.1.3 of the API Compendium, if the component type is used in the crude oil production, measured in components.

 (2) For EFijk, the emission factors for methane (j), as crude oil passes through a component type (k), are:

 (a) column 3 of an item in the following table, which specifies the emission factor for a component of type (k) specified in column 2 of that item:

Note:   API Publication 4615 defines light crude as oil with an API gravity of 20 or more, and heavy crude as oil with an API gravity of less than 20.

 (b) if the manufacturer of the component supplies component‑specific emission factors for the component type—those factors.                     

Subdivision 3.3.3.3—Crude oil production (flared)—fugitive emissions of carbon dioxide, methane and nitrous oxide

3.52  Available methods

 (1) Subject to section 1.18, for estimating emissions released by oil or gas flaring during a year from the operation of a facility that is constituted by crude oil production:

 (a) if estimating emissions of carbon dioxide released—one of the following methods must be used:

 (i) method 1 under section 3.53;

 (ii) method 2 under section 3.54;

 (iii) method 3 under section 3.55; and

 (b) if estimating emissions of methane released—one of the following methods must be used:

 (i) method 1 under section 3.53;

 (ii) method 2A under section 3.54A; and

 (c) if estimating emissions of nitrous oxide released—one of the following methods must be used:

 (i) method 1 under section 3.53;

 (ii) method 2A under section 3.54A.

Note: There is no method 4 under paragraph (a) and no method 2, 3 or 4 under paragraph (b) or (c).

 (2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

3.53  Method 1—crude oil production (flared) emissions

 (1) For subparagraph 3.52(a)(i), method 1 is:

where:

Eij is the emissions of gas type (j) measured in CO2‑e tonnes from a fuel type (i) flared in crude oil production during the year.

Qi is the quantity of fuel type (i) measured in tonnes flared in crude oil production during the year.

Note: This quantity includes all of the fuel type, not just hydrocarbons within the fuel type.

EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of the fuel type (i) flared.

 (2) For EFij mentioned in subsection (1), columns 3, 4 and 5 of an item in following table specify the emission factor for each fuel type (i) specified in column 2 of that item.

3.54  Method 2—crude oil production

Combustion of gaseous fuels (flared) emissions of carbon dioxide

 (1) For subparagraph 3.52(1)(a)(ii), method 2 for combustion of gaseous fuels is:

where:

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in crude oil production during the year, measured in CO2‑e tonnes.

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil production during the year, measured in tonnes in accordance with Division 2.3.3.

EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in crude oil production during the year, measured in CO2‑e tonnes per tonne of fuel type (i) flared, estimated in accordance with method 2 in Division 2.3.3.

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.

QCO2 is the quantity of CO2 within the fuel type (i) in crude oil production during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.

Combustion of liquid fuels (flared) emissions of carbon dioxide

 (2) For subparagraph 3.51(1)(a)(ii), method 2 for combustion of liquid fuels is the same as method 1, but the carbon dioxide emissions factor EFh must be determined in accordance with method 2 in Division 2.4.3.

3.54A  Method 2A—crude oil production (flared methane or nitrous oxide emissions)

  For subparagraphs 3.52(1)(b)(ii) and (c)(ii), method 2A is:

where:

EFhij is the emission factor of gas type (j), being methane or nitrous oxide, for the total hydrocarbons (h) within the fuel type (i) in crude oil production during the year, mentioned for the fuel type in the table in subsection 3.53(2) and measured in CO2‑e tonnes per tonne of the fuel type (i) flared.

Eij is the fugitive emissions of gas type (j), being methane or nitrous oxide, from fuel type (i) flared from crude oil production during the year, measured in CO2‑e tonnes.

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil production during the year, measured in tonnes in accordance with Division 2.3.3 for gaseous fuels or Division 2.4.3 for liquid fuels.

3.55  Method 3—crude oil production

Combustion of gaseous fuels (flared) emissions of carbon dioxide

 (1) For subparagraph 3.52(1)(a)(iii), method 3 for the combustion of gaseous fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.3.4.

Combustion of liquid fuels (flared) emissions of carbon dioxide

 (2) For subparagraph 3.52(1)(a)(iii), method 3 for the combustion of liquid fuels is the same as method 2, but the carbon dioxide emissions factor EFh must be determined in accordance with method 3 in Division 2.4.4.

Subdivision 3.3.3.4—Crude oil production (non‑flared)—fugitive vent emissions of methane and carbon dioxide

3.56A  Available methods

 (1) Subject to section 1.18, the methods mentioned in subsections (2) and (3) must be used for estimating fugitive emissions that result from system upsets, accidents and deliberate releases from process vents during a year from the operation of a facility that is constituted by crude oil production.

 (2) To estimate emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, one of the following methods must be used:

 (a) method 1 under section 3.56B;

 (b) method 4 under Part 1.3.

 (3) For estimating incidental emissions that result from deliberate releases from process vents, system upsets and accidents during a year from the operation of the facility, another method may be used that is consistent with the principles mentioned in section 1.13.

Note: There is no method 2 or 3 for this Subdivision.

Note:  Methods to estimate vented emissions from condensate storage tanks are available at section 3.85D.

3.56B  Method 1—emissions from system upsets, accidents and deliberate releases from process vents

 (1) Method 1 is, for a process mentioned in column 2 of an item in the following table, as described in the section of the API Compendium mentioned in column 3 for the item.

 (2) However, emissions from well workovers may use method 1 under section 3.85P (as if that method referred to crude oil production instead of natural gas production).

Division 3.3.4—Crude oil transport

3.57  Application

  This Division applies to fugitive emissions from crude oil transport activities, other than emissions that are flared.

3.58  Available methods

 (1) Subject to section 1.18, one of the following methods must be used for estimating fugitive emissions of methane released during a year from the operation of a facility that is constituted by crude oil transport:

 (a) method 1 under section 3.59;

 (b) method 2 under section 3.60.

Note: There is no method 3 or 4 for this Division.

 (2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

3.59  Method 1—crude oil transport

  Method 1 is: 

where:

Eij is the fugitive emissions of methane (j) from the crude oil transport during the year measured in CO2‑e tonnes.

Qi is the quantity of crude oil (i) measured in tonnes and transported during the year.

EFij is the emission factor for gas type (j), being methane, which is 9.74 × 10‑4 tonnes CO2‑e per tonnes of crude oil transported during the year.

3.60  Method 2—fugitive emissions from crude oil transport

 (1) Method 2 is:

  Eij = ∑k (Qik × EFijk)

where:

Eij is the fugitive emissions of gas type (j), being methane, from the crude oil transport during the year measured in CO2‑e tonnes.

Σk is the total emissions of gas type (j), being methane, measured in tonnes of CO2‑e and estimated by summing up the emissions from each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport.

Qik is the total of the quantities of crude oil measured in tonnes that pass through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil transport.

EFijk is the emission factor of gas type (j), being methane, measured in tonnes of CO2‑e per tonne of crude oil that passes through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium as determined under subsection (2), if the equipment is used in the crude oil transport.

 (2) For EFijk, the emission factors for gas type (j), being methane, as crude oil passes through equipment type (k), are:

 (a) as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or

 (b) if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type—those factors.

Division 3.3.5—Crude oil refining

3.62  Application

  This Division applies to fugitive emissions from crude oil refining activities, including emissions from flaring at petroleum refineries.

3.63  Available methods

 (1) Subject to section 1.18, for estimating emissions released during a year from the operation of a facility that is constituted by crude oil refining the methods as set out in this section must be used.

Crude oil refining and storage tanks

 (2) One of the following methods must be used for estimating fugitive emissions of methane that result from crude oil refining and from storage tanks for crude oil:

 (a) method 1 under section 3.64;

 (b) method 2 under section 3.65;

 (c) method 3 under section 3.66.

Note: There is no method 4 for subsection (2).

Process vents, system upsets and accidents

 (3) One of the following methods must be used for estimating fugitive emissions of each type of gas, being carbon dioxide, methane and nitrous oxide, that result from deliberate releases from process vents, system upsets and accidents:

 (a) method 1 under section 3.67;

 (b) method 4 under section 3.68.

Note: There is no method 2 or 3 for subsection (3).

Flaring

 (4) For estimating emissions released from gas flared from crude oil refining:

 (a) one of the following methods must be used for estimating emissions of carbon dioxide released:

 (i) method 1 under section 3.69;

 (ii) method 2 under section 3.70;

 (iii) method 3 under section 3.71; and

 (b) if estimating emissions of methane released—one of the following methods must be used:

 (i) method 1 under section 3.69;

 (ii) method 2A under section 3.70A; and

 (c) if estimating emissions of nitrous oxide released—one of the following methods must be used:

 (i) method 1 under section 3.69;

 (ii) method 2A under section 3.70A.

Note: The flaring of gas from crude oil refining releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 under section 3.69 is a reference to these gases. The same formula is used to estimate emissions of each of these gases. There is no method 4 for emissions of carbon dioxide and no method 2, 3 or 4 for emissions of nitrous oxide or methane.

 (5) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.

Subdivision 3.3.5.1—Fugitive emissions from crude oil refining and from storage tanks for crude oil

3.64  Method 1—crude oil refining and storage tanks for crude oil

  Method 1 is:

where:

Eij is the fugitive emissions of gas type (j), being methane or carbon dioxide, from fuel type (i) being crude oil refined or stored in tanks during the year measured in CO2‑e tonnes.

∑i is the sum of emissions of gas type (j), being methane or carbon dioxide, released during refining and from storage tanks during the year.

Qi is the quantity of crude oil (i) refined or stored in tanks during the year measured in tonnes.

EFij is the emission factor for gas type (j), being methane or carbon dioxide, being 9.47 × 10‑4 tonnes CO2‑e per tonne of crude oil refined and 1.73 × 10‑4 tonnes CO2‑e per tonne of crude oil stored in tanks.

3.65  Method 2—crude oil refining and storage tanks for crude oil

 (1) Method 2 is:

where:

Eij is the fugitive emissions of gas type (j), being methane, from the crude oil refining and from storage tanks during the year measured in CO2‑e tonnes.

Σk is the total emissions of gas type (j), being methane, measured in tonnes of CO2‑e estimated by summing up the emissions released from each equipment types (k) listed in sections 5 and 6.1.2 of the API Compendium as determined under subsection (2), if the equipment is used in the crude oil refining and in the storage tanks.

Qik is the total of the quantities of crude oil (i) measured in tonnes that pass through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks.

EFijk is the emission factor for gas type (j), being methane, measured in tonnes of CO2‑e per tonne of crude oil that passes through each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the crude oil refining and in the storage tanks.

 (2) For EFijk, the emission factors for gas type (j), being methane, as the crude oil passes through an equipment type (k) are:

 (a) as listed in sections 5 and 6.1.2 of the API Compendium, for the equipment type; or

 (b) if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type—those factors.

Eij = ∑k (Qik × EFijk)

where:

Eij is the fugitive emissions of gas type (j), being methane, from the crude oil refining and from storage tanks during the year measured in CO2‑e tonnes.

Σk is the total emissions of gas type (j), being methane, measured in tonnes of CO2‑e and estimated by summing up the emissions released from each component type (k) listed in section 6.1.3 of the API Compendium, if the component type is used in the crude oil refining and from storage tanks.

Qik is the total of the quantities of crude oil (i) that pass through each component type (k), or the number of components of each component type (k), listed in section 6.1.3 of the API Compendium , if the component is used in the crude oil refining and from storage tanks, measured in tonnes.

EFijk is the emission factor of gas type (j), being methane, measured in tonnes of CO2‑e per tonne of crude oil that passes through each component type (k) listed in section 6.1.3 of the API Compendium as determined under subsection (2), if the component is used in the crude oil refining and from storage tanks.

 (2) For EFijk, the emission factors for gas type (j), being methane or carbon dioxide, as crude oil passes through a component type (k), are:

 (a) as listed in section 6.1.3 of the API Compendium, for the component type; or

 (b) if the manufacturer of the component supplies component‑specific emission factors for the component type—those factors.             

Subdivision 3.3.5.2—Fugitive emissions from deliberate releases from process vents, system upsets and accidents

3.67  Method 1—fugitive emissions from deliberate releases from process vents, system upsets and accidents

  Method 1 is:

where:

Ei is the fugitive emissions of carbon dioxide during the year from deliberate releases from process vents, system upsets and accidents in the crude oil refining measured in CO2‑e tonnes.

Qi is the quantity of refinery coke (i) burnt to restore the activity of the catalyst of the crude oil refinery (and not used for energy) during the year measured in tonnes.

CCFi is the carbon content factor for refinery coke (i) as mentioned in Schedule 3.

3.664 is the conversion factor to convert an amount of carbon in tonnes to an amount of carbon dioxide in tonnes.

3.68  Method 4—deliberate releases from process vents, system upsets and accidents

 (1) Method 4 is:

 (a) is as set out in Part 1.3; or

 (b) uses the process calculation approach in section 5.2 of the API Compendium.

 (2) For paragraph (1)(b), all carbon monoxide is taken to fully oxidise to carbon dioxide and must be included in the calculation.

Subdivision 3.3.5.3—Fugitive emissions released from gas flared from the oil refinery

3.69  Method 1—gas flared from crude oil refining

 (1) Method 1 is:

where:

Eij is the emissions of gas type (j) released from the gas flared in the crude oil refining during the year measured in CO2‑e tonnes.

Qi is the quantity of gas for the fuel type (i) flared during the year measured in tonnes.

Note: This quantity includes all of the fuel type, not just hydrocarbons within the fuel type.

EFij is the emission factor for gas type (j) measured in tonnes of CO2‑e emissions per tonne of gas type (j) flared in the crude oil refining during the year.

 (2) For EFij in subsection (1), columns 3, 4 and 5 of an item in the following table specify the emission factor for gas type (j) for the fuel type (i) specified in column 2 of that item:

3.70  Method 2—gas flared from crude oil refining

  For subparagraph 3.63(4)(a)(ii), method 2 is:

where:

EiCO2 is the fugitive emissions of CO2 from fuel type (i) flared in crude oil refining during the year, measured in CO2‑e tonnes.

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, measured in tonnes in accordance with Division 2.3.3.

EFh is the emission factor for the total hydrocarbons (h) within the fuel type (i) in the crude oil refining during the year, measured in CO2‑e tonnes per tonne of fuel type (i) flared, estimated in accordance with method 2 in Division 2.3.3.

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.

QCO2 is the quantity of CO2 within the fuel type (i) in the crude oil refining during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.

3.70A   Method 2A—crude oil refining (flared methane or nitrous oxide emissions)

  For subparagraphs 3.63(4)(b)(ii) and (c)(ii), method 2A is:

where:

EFhij is the emission factor of gas type (j), being methane or nitrous oxide, for the total hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, mentioned for the fuel type in the table in subsection 3.69(2) and measured in CO2‑e tonnes per tonne of the fuel type (i) flared.

Eij is the fugitive emissions of gas type (j), being methane or nitrous oxide, from fuel type (i) flared from crude oil refining during the year, measured in CO2‑e tonnes.

OFi is 0.98, which is the destruction efficiency of fuel type (i) flared.

Qh is the total quantity of hydrocarbons (h) within the fuel type (i) in crude oil refining during the year, measured in tonnes in accordance with Division 2.3.3.

3.71  Method 3—gas flared from crude oil refining

  For subparagraph 3.63(4)(a)(iii), method 3 is the same as method 2 under section 3.70, but the emission factor EFij must be determined in accordance with method 3 for the consumption of gaseous fuels as specified in Division 2.3.4.

Division 3.3.6A—Onshore natural gas production (other than emissions that are vented or flared)

3.72  Application 

  This Division applies to fugitive emissions from onshore natural gas production activities, other than emissions that are vented or flared, including emissions from onshore natural gas wellheads.

Subdivision 3.3.6A.1—Onshore natural gas production, other than emissions that are vented or flared—wellheads 

3.73  Available methods

 (1) Subject to section 1.18 and subsections (3) and (4), one of the following methods must be used for estimating fugitive emissions of methane and carbon dioxide (other than emissions that are vented or flared) released during a year from the operation of a facility that is constituted by onshore natural gas production:

 (a) method 1 under section 3.73A;

 (b) method 2 under section 3.73B;

                       (c)   method 3 under section 3.73C.

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) If method 2 is used for a facility, all other available methods 2 must be used in Divisions 3.3.6B, 3.3.6C, 3.3.6E, 3.3.7A and 3.3.7B if those Divisions are applicable to the facility.

 (4) If method 3 is used for a facility, all other available methods 3 must be used in Divisions 3.3.6B, 3.3.6C, 3.3.6E, 3.3.7A and 3.3.7B if those Divisions are applicable to the facility.

3.73A Method 1—onshore natural gas production, other than emissions that are vented or flared—wellheads

 (1) Method 1 is:

  Eij  = Σk (Qik  ×  EFijk  × Sij / SDij)

where:

Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the onshore natural gas production during the year measured in CO2‑e tonnes.

Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) specified in column 2 of an item in the table in subsection (2), if the equipment is used in the onshore natural gas production.

Qik is the total of the quantities of unprocessed natural gas (i) that pass through each equipment type (k) specified in column 2 of the table in subsection (2), during the year measured in tonnes in accordance with Division 2.3.6.

EFijk is the emission factor for gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes per tonne of unprocessed natural gas (i) that passes through each equipment type (k), if the equipment is used in the onshore natural gas production during the year.

Note: Consistent with subsection 3.41(2), emissions associated with any piece of equipment included in this definition should not be counted under this section if those emissions are also counted as equipment emissions under another section within this Part.

Sij  is the measured share of each gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.

SDij is the default share of gas type (j) in the unprocessed gas (i), for methane SD is 0.98 and for carbon dioxide SD is 0.02.

 (2) For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor for gas type (j) being methane for an equipment type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for an equipment type (k) specified in column 2 of that item:

3.73B  Method 2—onshore natural gas production, other than emissions that are vented or flared—wellheads

 (1) Method 2 is:

  Eij  = Σk (Tik   ×  Nik ×EFijk) × Sij/SDij

where:

Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the onshore natural gas production during the year measured in CO2‑e tonnes.

Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) specified in column 2 of an item in the table in subsection (2), if the equipment is used in the onshore natural gas production.

Tik is the average hours of operation during the year of the equipment of each equipment type (k), if the equipment is used in the onshore natural gas production during the year.

Nik is the total number of equipment units of each equipment type (k), if the equipment type is used in the onshore natural gas production during the year.

EFijk is the emission factor of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e per equipment type (k) – hour as determined under subsection (2), if the equipment is used in the onshore natural gas production.

Note: Consistent with subsection 3.41(2), emissions associated with any piece of equipment included in this definition should not be counted under this section if those emissions are also counted as equipment emissions under another section within this Part.

Sij  is the measured share of each gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.

SDij is the default share of gas type (j) in the unprocessed gas (i), for methane SD is 0.788 and for carbon dioxide SD is 0.02.

 (2) For EFijk in subsection (1):

 (a) column 3 of an item in the following table specifies the emission factor for methane (j) for an equipment type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for an equipment type (k) specified in column 2 of that item:

 (b) if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type—those factors are the relevant emissions factors.                     

Eij = ∑k (Tik × Nik ×EFijk ) × Sij /SDij

where:

Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the onshore natural gas production during the year measured in CO2‑e tonnes.

Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e and estimated by summing up the emissions released from each component type (k), if the component type is used in the onshore natural gas production during the year.

EFijk is the emission factor of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e per component-hour for each component type (k) as determined under subsection (2) or (3), if the component is used in the onshore natural gas production during the year.

Note: Consistent with subsection 3.41(2), emissions associated with any components included in this definition should not be counted under this section if those emissions are also counted as component emissions under another section within this Part.

Nik is the total number of components of each component type (k) if the component type is used in the onshore natural gas production during the year.

Tik is:

 (a) if subsection (2) applies—the average hours of operation during the year of the component of each component type (k), if the component is used in the onshore natural gas production;

 (b) if subsection (3) applies—an engineering estimate of the number of hours in the year the component type (k) was operational as a leaker or non leaker based on the best available data and subsection (4).

Sij  is the measured share of gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.

SDij is the default share of gas type (j) in the unprocessed gas (i), for methane SD is 0.788 and for carbon dioxide SD is 0.02.

 (2) Unless subsection (3) is elected and used for all components under this method, EFijk, the emission factors for methane or carbon dioxide (j), for component type (k), are:

 (a) column 3 of an item in the following table specifies the emission factor for methane (j) for a component type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for a component type (k) specified in column 2 of that item:

 Note:   These component types are listed in section 6.1.3 of the API Compendium.

 (b) if the manufacturer of the component supplies component‑specific emission factors for the component type—those factors.      

 (3) If an LDAR program has been carried out at the facility in relation to onshore natural gas production components in accordance with subsection (4) and this subsection elected for all components under this method, EFijk, the emission factors for methane or carbon dioxide (j), for component type (k), are:

 (a) column 3 of an item in the following table specifies the emission factor for methane (j) for a component and leaker/non-leaker type (k) specified in column 2 of that item; and

 (b) column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for a component and leaker/non-leaker type (k) specified in column 2 of that item:

             (4)  For subsection (3), the LDAR program must survey each component used in onshore gas production at the facility at least once in a reporting year in accordance with:

             (5)   To determine whether a component is a leaker or non leaker at a period of time:

Division 3.3.6B—Offshore natural gas production (other than emissions that are vented or flared)

3.73D  Application 

  This Division applies to fugitive emissions from offshore natural gas production activities, other than emissions that are vented or flared, including emissions from:

 (a) a gas wellhead through to the inlet of gas processing plants; and

 (b) a gas wellhead through to the tie‑in points on gas transmission systems, if processing of natural gas is not required.

Subdivision 3.3.6B.1—Offshore natural gas production, other than emissions that are vented or flared—offshore platforms

3.73E  Available methods

 (1) Subject to section 1.18 and subsections (3) and (4), one of the following methods must be used for estimating fugitive emissions of methane and carbon dioxide (other than emissions that are vented or flared) released during a year from the operation of a facility that is constituted by offshore natural gas production:

 (a) method 1 under section 3.73F;

 (b) method 2 under section 3.73G;

                       (c)  method 3 under section 3.73H.

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) If method 2 is used for a facility, all other available methods 2 must be used in Divisions 3.3.6A, 3.3.6C, 3.3.6E, 3.3.7A and 3.3.7B if those Divisions are applicable to the facility.

 (4) If method 3 is used for a facility all other available methods 3 must be used in Divisions 3.3.6A, 3.3.6C, 3.3.6E, 3.3.7A and 3.3.7B if those Divisions are applicable to the facility.

3.73F  Method 1—offshore natural gas production (other than emissions that are vented or flared)

 (1) Method 1 is:

  Eij = ∑k (Qik ×EFijk) × Sij/SDij

where:

Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the offshore natural gas production during the year measured in CO2‑e tonnes.

Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) specified in column 2 of an item in the table in subsection (2), if the equipment is used in the offshore natural gas production.

Qik is the number of platforms of each equipment type (k) specified in column 2 of the table in subsection (2), during the year.

EFijk is the emission factor for gas type (j) measured in CO2‑e tonnes per platform during the year as determined under subsection (2), if the equipment is used in the offshore natural gas production.

Note: Consistent with subsection 3.41(2), emissions associated with any piece of equipment included in this definition should not be counted under this section if those emissions are also counted as equipment emissions under another section within this Part.

Sij  is the measured share of gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.

SDij is the default share of gas type (j) in the unprocessed gas (i) where methane SD is 0.832 and carbon dioxide SD is 0.035.

 (2) For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor for methane (j) for an equipment type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for an equipment type (k) specified in column 2 of that item:

3.73G  Method 2—offshore natural gas production (other than venting and flaring)

 (1) Method 2 is:

  Eij = ∑k (Tik × Nik ×EFijk) × Sij/SDij

where:

Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the offshore natural gas production during the year measured in CO2‑e tonnes.

Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k), if the equipment is used in the offshore natural gas production.

Tik is the average hours of operation during the year of the equipment of each equipment type (k), if the equipment is used in the offshore natural gas production during the year.

Nik is the total number of equipment units of each equipment type (k), if the equipment type is used in the offshore natural gas production during the year.

EFijk is the emission factor of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e per equipment type (k) – hour as determined under subsection (2), if the equipment is used in the offshore natural gas production.

Note: Consistent with subsection 3.41(2), emissions associated with any piece of equipment included in this definition should not be counted under this section if those emissions are also counted as equipment emissions under another section within this Part.

Sij is the measured share of gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.

SDij is the default share of gas type (j) in the unprocessed gas (i), for methane SD is 0.788 and for carbon dioxide SD is 0.02.

 (2) For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor for methane (j) for an equipment type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for an equipment type (k) specified in column 2 of that item:

Eij = ∑k (Tik × Nik ×EFijk) × Sij /SDij

where:

Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the offshore natural gas production during the year measured in CO2‑e tonnes.

Σk is the total emissions of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e and estimated by summing up the emissions released from each component type (k), if the component type is used in the offshore natural gas production.

EFijk is the emission factor of gas type (j), being methane or carbon dioxide, measured in tonnes of CO2‑e per component-hour for each component type (k) as determined under subsection (2) or (3), if the component is used in the offshore natural gas production.

Note: Consistent with subsection 3.41(2), emissions associated with any components included in this definition should not be counted under this section if those emissions are also counted as component emissions under another section within this Part.

Tik is:

 (a) if subsection (2) applies—the average hours of operation during the year of the component of each component type (k), if the component is used in the offshore natural gas production; and

 (b) if subsection (3) applies—an engineering estimate of the number of hours in the year the component type (k) was operational as a leaker or non leaker based on the best available data and subsection (4).

Nik is the total number of components of each component type (k) listed if the component type is used in the offshore natural gas production during the year.

Sij is the measured share of gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.

SDij is the default share of gas type (j) in the unprocessed gas (i), for methane SD is 0.788 and for carbon dioxide SD is 0.02.

 (2) Unless subsection (3) is elected and used for all components under this method,  EFijk, the emission factors for methane (j), for component type (k), are:

 (a) column 3 of an item in the following table specifies the emission factor for methane (j) for a component type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for a component type (k) specified in column 2 of that item:             

 Note:   These component types are listed in section 6.1.3 of the API Compendium.

 (b) if the manufacturer of the component supplies component‑specific emission factors for the component type—those factors.

 (3) If an LDAR program has been carried out at the facility in relation to offshore natural gas production components in accordance with subsection (4) and this subsection elected for all components under this method, EFijk, the emission factors for methane or carbon dioxide (j), for component type (k), are:

 (a) column 3 of an item in the following table specifies the emission factor for methane (j) for a component and leaker/non-leaker type (k) specified in column 2 of that item; and

 (b) column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for a component and leaker/non-leaker type (k) specified in column 2 of that item:

             (4)  For subsection (3), the LDAR program must survey each component used in offshore gas production at the facility at least once in a reporting year in accordance with:

             (5)   To determine whether a component is a leaker or non leaker at a period of time:

Division 3.3.6C—Natural gas gathering and boosting (other than emissions that are vented or flared)

3.73I  Application

  This Division applies to fugitive emissions from natural gas gathering and boosting, other than emissions that are vented or flared, including emissions from natural gas gathering and boosting stations and pipelines.

Note:  Division 3.3.6A applies to fugitive emissions from onshore natural gas production activities, other than emissions that are vented or flared, including emissions from wellheads.

3.73J  Available methods

 (1) Subject to section 1.18 and subsections (3) and (4), one of the following methods must be used for estimating fugitive emissions of methane and carbon dioxide (other than emissions that are vented or flared) released during a year from the operation of a facility that is constituted by natural gas gathering and boosting:

 (a) method 1 under section 3.73K;

 (b) method 2 under section 3.73L;

                       (c)   method 3 under section 3.73M.

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) If method 2 is used for a facility, all other available methods 2 must be used in Divisions 3.3.6A, 3.3.6B, 3.3.6E, 3.3.7A and 3.3.7B if those Divisions are applicable to the facility.

 (4) If method 3 is used for a facility, all other available methods 3 must be used in Divisions 3.3.6A, 3.3.6B, 3.3.6E, 3.3.7A and 3.3.7B if those Divisions are applicable to the facility.

3.73K  Method 1—natural gas gathering and boosting (other than venting and flaring)

  Method 1 is:

Eij = Eijs + Eijp

where:

Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the natural gas gathering and boosting during the year measured in CO2‑e tonnes.

Eijs  is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the natural gas gathering and boosting stations (s) during the year measured in CO2‑e tonnes, given by section 3.73KA.

Eijp  is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the natural gas gathering and boosting pipelines (p) during the year measured in CO2‑e tonnes, given by section 3.73KB.  

3.73KA Method 1—natural gas gathering and boosting, other than emissions that are vented or flared—natural gas gathering and boosting stations

 (1) For section 3.73K, Eijs is given by the following formula:

  Eijs  = Σjs(Qis × EFj) × Sij / SDij 

where:

Eijs is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the natural gas gathering and boosting stations during the year measured in CO2‑e tonnes.

Σjs is the total emissions of gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes and estimated by summing up the emissions released from each natural gas gathering and boosting station (s).

Qis is the quantity of unprocessed natural gas (i) that passes through the natural gas gathering and boosting station (s) during the year, measured in tonnes in accordance with Division 2.3.6.

EFj is the emission factor for gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes per tonne of unprocessed natural gas that passes through each natural gas gathering and boosting station (s) given by subsection (2) or (3).

Sij  is the measured share of each gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.

SDij is the default share of gas type (j) in the unprocessed gas (i), for methane SD is 0.832 and for carbon dioxide SD is 0.0345.

 (2) For EFj in subsection (1), EFj for methane is given by the following formula:

EFj  = GWPmethane × 2.386 ×  Qi-0.761

where:

EFj is the emission factor for methane (j) measured in CO2‑e tonnes per tonne of natural gas that passes through the natural gas gathering and boosting station during the year.

Qi is the quantity of unprocessed natural gas that passes through the natural gas gathering and boosting station during the year, measured in tonnes in accordance with Division 2.3.6.

 (3) For EFj in subsection (1), EFj for carbon dioxide is given by the following formula:

EFj  = 2.386 ×  Qi-0.761 × SDij=carbon dioxide / SDij=methane

where:

EFj is the emission factor for carbon dioxide (j) measured in CO2‑e tonnes per tonne of natural gas that passes through the natural gas gathering and boosting station during the year.

Qi is the quantity of unprocessed natural gas that passes through the natural gas gathering and boosting station during the year, measured in tonnes in accordance with Division 2.3.6.

SDij=carbon dioxide is the default share of carbon dioxide (j) in the unprocessed gas (i), which is 0.0345.

SDij=methane is the default share of methane (j) in the unprocessed gas (i), which is 0.832.

3.73KB Method 1—natural gas gathering and boosting, other than emissions that are vented or flared—natural gas gathering and boosting pipelines

 (1) For section 3.73K, subject to subsection (3), Eijp is given by the following formula:

  Eijp  = Pk ×  EFijk × Sij / SDij

where:

Eijp is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the natural gas gathering and boosting pipelines during the year measured in CO2‑e tonnes.

Pk is the length of the system of gathering and boosting pipelines of type (k) during the year measured in kilometres and used in the natural gas gathering and boosting.

EFijk is the emission factor for gas type (j), being methane or carbon dioxide, measured in CO2‑e tonnes per tonne of natural gas that passes through each equipment type (k), or CO2‑e tonnes per kilometre of pipeline if the equipment is used in the natural gas gathering and boosting pipelines during the year.

Sij  is the measured share of each gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, measured in accordance with Division 2.3.3 and the principles in section 1.13.

SDij is the default share of gas type (j) in the unprocessed gas (i), for methane SD is 0.832 and for carbon dioxide SD is 0.0345.

 (2) For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor for methane (j) for an equipment type (k) specified in column 2 of that item and column 4 of an item in the following table specifies the emission factor for carbon dioxide (j) for an equipment type (k) specified in column 2 of that item:

 (3) However, Eijp may also be calculated by the method in section 3.73LB.

Note: Calculating this parameter for method 1 under section 3.73LB does not trigger the requirements in subsection 3.73J(3) to use method 2 for other emissions sources.

3.73L  Method 2—natural gas gathering and boosting (other than venting and flaring)

  Method 2 is:

Eij = Eijs + Eijp

where:

Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the natural gas gathering and boosting during the year measured in CO2‑e tonnes.

Eijs   is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the natural gas gathering and boosting stations (s) during the year measured in CO2‑e tonnes given by section 3.73LA.

Eijp   is the fugitive emissions (other than emissions that are vented or flared) of gas type (j), being methane or carbon dioxide, from the natural gas gathering and boosting pipelines (p) during the year measured in CO2‑e tonnes, given by section 3.73LB.