Federal Register of Legislation - Australian Government

Primary content

Determinations/Other as made
This instrument amends the National Greenhouse and Energy Reporting (Measurement) Determination 2008 to ensure greenhouse gas reporting rules reflect best available measurement techniques.
Administered by: Industry, Science, Energy and Resources
Registered 17 Jun 2021
Tabling HistoryDate
Tabled HR21-Jun-2021
Tabled Senate21-Jun-2021
Date of repeal 31 Aug 2021
Repealed by Division 1 of Part 3 of Chapter 3 of the Legislation Act 2003

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.

 

Commencement information

Column 1

Column 2

Column 3

Provisions

Commencement

Date/Details

1.  The whole of this instrument

1 July 2021.

1 July 2021

Note:          This table relates only to the provisions of this instrument as originally made.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 1Amendments

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:

                     (a)  has equivalent or higher integrity than 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 or optical gas imaging in accordance with paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America; and

                     (b)  has equivalent or higher sensitivity for detecting leaks than:

                              (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:

(a) if optical gas imaging is used, a leaker is detected at a sensitivity of 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; and

(b) if 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 is used, a leaker is detected if 10,000 parts per million or greater is measured consistent with that method; and

(c)  if an equivalent leak detection standard is used, a leaker is detected at the sensitivity set for that standard.

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:

                     (a)  definition of crude oil condensates;

                     (b)  definition of technical guidelines.

[5]           Section 1.8 (definition of fugitive emissions)

Repeal the definition, substitute:

fugitive emissions means greenhouse gas emissions that are:

                     (a)  released in connection with, or as a consequence of, the extraction, processing, storage or delivery of fossil fuel; and

                     (b)  not released from the combustion of fuel for the production of useable heat or electricity.

[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.

 

Item

Category of source

Source of emissions

1

Fuel combustion

 

1A

 

Fuel combustion

2

Fugitive emissions

 

2A

 

Underground mines

2B

 

Open cut mines

2C

 

Decommissioned underground mines

2D

 

Oil or gas exploration and development—flaring

2E

 

Oil or gas exploration and development (other than flaring)

2F

 

Crude oil production

2G

 

Crude oil transport

2H

 

Crude oil refining

2I

 

Onshore natural gas production (other than emissions that are vented or flared)

2J

 

Offshore natural gas production (other than emissions that are vented or flared)

2K

 

Natural gas gathering and boosting (other than emissions that are vented or flared)

2L

 

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)

2M

 

Natural gas processing (other than emissions that are vented or flared)

2N

 

Natural gas transmission (other than flaring)

2O

 

Natural gas storage (other than emissions that are vented or flared)

2P

 

Natural gas liquefaction, storage and transfer (other than emissions that are vented or flared)

2Q

 

Natural gas distribution (other than flaring)

2R

 

Onshore natural gas production—venting

2S

 

Offshore natural gas production—venting

2T

 

Onshore natural gas production—flaring

2U

 

Offshore natural gas production—flaring

2V

 

Natural gas gathering and boosting—venting

2W

 

Natural gas gathering and boosting—flaring

2X

 

Natural gas processing—venting

2Y

 

Natural gas processing—flaring

2Z

 

Natural gas transmission—flaring

2ZA

 

Natural gas storage—venting

2ZB

 

Natural gas storage—flaring

2ZC

 

Natural gas liquefaction, storage and transfer—venting

2ZE

 

Natural gas liquefaction, storage and transfer—flaring

2ZF

 

Natural gas distribution—flaring

2ZG

 

Carbon capture and storage

2ZH

 

Enhanced oil recovery

3

Industrial processes

 

3A

 

Cement clinker production

3B

 

Lime production

3C

 

Use of carbonates for the production of a product other than cement clinker, lime or soda ash

3D

 

Soda ash use

3E

 

Soda ash production

3F

 

Ammonia production

3G

 

Nitric acid production

3H

 

Adipic acid production

3I

 

Carbide production

3J

 

Chemical or mineral production, other than carbide production, using a carbon  reductant or carbon anode

3JA

 

Sodium cyanide production

3JB

 

Hydrogen production

3K

 

Iron, steel or other metal production using an integrated metalworks

3L

 

Ferroalloys production

3M

 

Aluminium production

3N

 

Other metals production

3O

 

Emissions of hydrofluorocarbons and sulphur hexafluoride gases

4

Waste

 

4A

 

Solid waste disposal on land

4AA

 

Biological treatment of solid waste

4B

 

Wastewater handling (industrial)

4C

 

Wastewater handling (domestic or commercial)

4D

 

Waste incineration

[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:

Item

Equipment type (k)

Emission factor for gas type  (j)



 

 

CH4

Units

1

Gas-fired reciprocating engines –

4-stroke lean burn

13.8

kg CO2-e /GJ

2

Gas-fired reciprocating engines –

4-stroke rich burn

1.2

kg CO2-e /GJ

3

Gas-fired reciprocating engines –

2-stroke lean burn

17.5

kg CO2-e /GJ

4

Gas turbines

0.1

kg CO2-e /GJ

             (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:

3

Crude oil

ASTM D 240‑02 (2007)

ASTM D 4809‑06

ASTM D 5291‑02 (2007)

ASTM D 1298 – 99 (2005) 

ASTM D 5002 – 99 (2005)

4

Plant condensates and other natural gas liquids not covered by another item in this table

ASTM D 240‑02 (2007)

ASTM D 4809‑06

ASTM D 5291‑02 (2007)

ASTM D 1298 – 99 (2005)

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

Repeal the items, substitute:

3

Crude oil

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

4

Plant condensates and other natural gas liquids not covered by another item in this table

ISO 3170:2004

ISO 3171:1988

ASTM D 4057 – 06

ASTM D 4177 – 95 (2005)

ASTM D1265 – 05

[15]         Part 3.3

Repeal the Part, substitute:

 

Part 3.3Oil and natural gas—fugitive emissions

Division 3.3.1Preliminary

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 3.3.2Oil or gas exploration and development

Subdivision 3.3.2.1Preliminary

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 3.3.2.2Oil 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  = Q×  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.

Item

Fuel type (i)

Emission factor for gas type (j) (tonnes CO2‑e/tonnes of fuel flared)

 

CO2

CH4

N2O

1

Gas

2.80

0.933

0.026

2

Crude oil and liquids

3.20

0.009

0.06

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 3.3.2.3Oil 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 3.3.2.3.1Fugitive 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:

Item

Equipment type (k)

Emission factor for gas type (j)

 

CH4

CO2

 

1

Well completion without hydraulic fracturing

5.5

1.1 × 10-2

tonnes CO2‑e per well completion event

2

Well completion with hydraulic fracturing and venting (no flaring)

1031

4.2

tonnes CO2‑e per well completion event

3

Well completion with hydraulic fracturing with capture (no flaring)

90.8

0.37

tonnes CO2‑e per well completion event

4

Well completion with hydraulic fracturing and flaring

136.6

0.56

tonnes CO2‑e per well completion event

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 3.3.3Crude oil production

Subdivision 3.3.3.1Preliminary

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 3.3.3.2Crude 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:

Item

Equipment type (k)

Emission factor for gas type (j) (tonnes CO2‑e/tonnes fuel throughput)

 

CH4

1

Internal floating tank

1.12 × 10-6

2

Fixed roof tank

5.60 × 10-6

3

Floating tank

4.27 × 10-6

             (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.

3.51  Method 3—crude oil production (non-flared) emissions of methane

             (1)  Method 3 is:

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:

 

Item

Component type (k)

Emission factor for gas type (j) (tonnes CO2‑e/component-hour)

 

CH4

1

Valves – heavy crude production

3.64 × 10-7

2

Valves – light crude production

3.70 × 10-5

3

Connectors – heavy crude production

2.23 × 10-7

4

Connectors – light crude production

4.59 × 10-6

5

Flanges – heavy crude production

6.13 × 10-7

6

Flanges – light crude production

2.15 × 10-6

7

Open-ended lines – heavy crude production

4.34 × 10-6

8

Open-ended lines – light crude production

3.39 × 10-5

9

Pump Seals – light crude production

8.90 × 10-6

10

Others – heavy crude production

1.96 × 10-6

11

Others – light crude production

2.10 × 10-4

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 3.3.3.3Crude 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.

Item

Fuel type (i)

Emission factor for gas type (j) (tonnes CO2‑e/tonnes of fuel flared)

 

CO2

CH4

N2O

1

Gas

2.80

0.933

0.026

2

Crude oil and liquids

3.20

0.009

0.06

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 3.3.3.4Crude 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.

Item

Emission process

API Compendium section

1

Gas treatment processes

Section 5.1

2

Cold process vents

Section 5.3

3

Storage tanks - vented emissions

Section 5.4

4

Other venting sources—gas driven pneumatic devices

Section 5.6.1

5

Other venting sources—gas driven chemical injection pumps

Section 5.6.2

6

Non‑routine activities—production related non‑routine emissions

Section 5.7.1 and 5.7.2

             (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 3.3.4Crude 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 3.3.5Crude 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 3.3.5.1Fugitive 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.

3.66  Method 3—crude oil refining and storage tanks for crude oil

             (1)  Method 3 is:                                              

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 3.3.5.2Fugitive 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 3.3.5.3Fugitive 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:

Item

fuel type (i)

Emission factor of gas type (j) (tonnes CO2‑e/tonnes fuel flared)

 

CO2

CH4

N2O

1

Gas

2.7

0.133

0.026

2

Crude oil and liquids

3.2

0.009

0.06

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 1onshore 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:

Item

Equipment type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Onshore natural gas wellheads

1.32 × 10-3

2.60 × 10-6

tonnes CO2-e/t gas throughput

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:

Item

Equipment type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Gas wellheads

5.04 × 10-4

1.25 × 10-6

tonnes CO2-e /equipment - hour

2

Gas separators

1.24 × 10-3

3.08 × 10-6

tonnes CO2-e /equipment - hour

3

Gas heaters

1.29 × 10-3

3.20 × 10-6

tonnes CO2-e /equipment - hour

4

Reciprocating compressor

4.60 × 10-2

1.14 × 10-4

tonnes CO2-e /equipment - hour

5

Screw compressor

2.88 × 10-2

7.15 × 10-5

tonnes CO2-e /equipment - hour

6

Metering installation and associated piping

9.86 × 10-4

2.45 × 10-6

tonnes CO2-e /equipment - hour

7

Dehydrators

2.00 × 10-3

4.96 × 10-6

tonnes CO2-e /equipment - hour

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

3.73C  Method 3—onshore natural gas production, other than emissions that are vented or flared—wellheads

             (1)  Method 3 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 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:

Item

Component type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Valves – gas production

7.36 × 10-5

1.83 × 10-7

tonnes CO2-e /component - hour

2

Connectors – gas production

8.99 × 10-6

2.23 × 10-8

tonnes CO2-e / component - hour

3

Flanges – gas production

3.30 × 10-6

8.22 × 10-9

tonnes CO2-e / component - hour

4

Open-ended lines – gas production

1.92 × 10-5

4.78 × 10-8

tonnes CO2-e / component - hour

5

Pump Seals – gas production

5.46 × 10-6

1.36 × 10-8

tonnes CO2-e / component - hour

6

Others – gas production

2.57 × 10-4

6.40 × 10-7

tonnes CO2-e / component - hour

                          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:

Item

Component and leaker/non leaker type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Valves—non leaker

7.56 × 10-6

1.88 × 10-8

tonnes CO2-e /component - hour

2

Values—leaker

5.60 × 10-3

1.39 × 10-5

tonnes CO2-e / component - hour

3

Pumps—non leaker

4.20 × 10-6

1.04 × 10-8

tonnes CO2-e / component - hour

4

Pumps—leaker

9.80 × 10-3

2.44 × 10-5

tonnes CO2-e / component - hour

5

Flanges—non leaker

3.92 × 10-7

9.75 × 10-10

tonnes CO2-e / component - hour

6

Flanges—leaker

3.36 × 10-3

8.36 × 10-6

tonnes CO2-e / component - hour

7

Other—non leaker

2.27 × 10-6

5.64 × 10-9

tonnes CO2-e / component - hour

8

Other—leaker

5.88 × 10-3

1.46 × 10-5

tonnes CO2-e / component - hour

             (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:

(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 3.3.6B—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:

Item

Equipment type (k)

emission factor for gas type  (j)

 

 

CH4

CO2

Units

1

Offshore platforms (shallow water)

1,747.1

7.10

tonnes CO2-e /platform

2

Offshore platforms (deep water)

18,422.6

75.0

tonnes CO2-e/ platform

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:

Item

Equipment type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Gas wellheads

5.04 × 10-4

1.25 × 10-6

tonnes CO2-e /equipment - hour

2

Gas separators

1.24 × 10-3

3.08 × 10-6

tonnes CO2-e /equipment - hour

3

Gas heaters

1.29 × 10-3

3.20 × 10-6

tonnes CO2-e /equipment - hour

4

Reciprocating compressor

4.60 × 10-2

1.14 × 10-4

tonnes CO2-e /equipment - hour

5

Screw compressor

2.88 × 10-2

7.15 × 10-5

tonnes CO2-e /equipment - hour

6

Metering installation and associated piping

9.86 × 10-4

2.45 × 10-6

tonnes CO2-e /equipment - hour

7

Dehydrators

2.00 × 10-3

4.96 × 10-6

tonnes CO2-e /equipment - hour

8

Gathering pipelines

7.45 × 10-4

1.85 × 10-6

tonnes CO2-e /kilometre - hour

3.73H  Method 3—offshore natural gas production (other than emissions that are vented or flared)

             (1)  Method 3 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 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:      

Item

Component type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Valves

1.44 × 10-5

3.58 × 10-8

tonnes CO2-e /component - hour

2

Pump Seals

5.46 × 10-6

1.36 × 10-8

tonnes CO2-e / component - hour

3

Others

1.94 × 10-4

4.83 × 10-7

tonnes CO2-e / component - hour

4

Connectors

3.02 × 10-6

7.52 × 10-9

tonnes CO2-e / component - hour

5

Flanges

5.52 × 10-6

1.37 × 10-8

tonnes CO2-e / component - hour

6

Open-ended lines

2.83 × 10-5

7.03 × 10-8

tonnes CO2-e / component - hour

                          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:

Item

Component and leaker/non leaker type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Valves—non leaker

7.56 × 10-6

1.88 × 10-8

tonnes CO2-e /component - hour

2

Values—leaker

5.60 × 10-3

1.39 × 10-5

tonnes CO2-e / component - hour

3

Pumps—non leaker

2.10 × 10-5

5.22 × 10-8

tonnes CO2-e / component - hour

4

Pumps—leaker

9.80 × 10-3

2.44 × 10-5

tonnes CO2-e / component - hour

5

Flanges—non leaker

3.92 × 10-7

9.75 × 10-10

tonnes CO2-e / component - hour

6

Flanges—leaker

3.36 × 10-3

8.36 × 10-6

tonnes CO2-e / component - hour

7

Other—non leaker

2.27 × 10-6

5.64 × 10-9

tonnes CO2-e / component - hour

8

Other—leaker

5.88 × 10-3

1.46 × 10-5

tonnes CO2-e / component - hour

             (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:

(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 3.3.6C—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:

Item

Equipment type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Onshore gas gathering and boosting pipelines

6.52

2.65 × 10-2

tonnes CO2-e /kilometres of pipeline

             (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.  

3.73LA  Method 2—natural gas gathering and boosting, other than emissions that are vented or flared—natural gas gathering and boosting stations

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

                Eijs = ∑k (Tik × Nik ×EFijk) × 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.

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 natural gas gathering and boosting station.

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 natural gas gathering and boosting station during the year.

Nik is the total number of equipment units of each equipment type (k), if the equipment type is used in the natural gas gathering and boosting station 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.

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

Sij  is the measured share of each gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, passing through the gathering and boosting station measured in accordance 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:

Item

Equipment type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Gas separators

1.24 × 10-3

3.08 × 10-6

tonnes CO2-e /equipment - hour

2

Gas heaters

1.29 × 10-3

3.20 × 10-6

tonnes CO2-e /equipment - hour

3

Reciprocating compressor

4.60 × 10-2

1.14 × 10-4

tonnes CO2-e /equipment - hour

4

Screw compressor

2.88 × 10-2

7.15 × 10-5

tonnes CO2-e /equipment - hour

5

Metering installation and associated piping

9.86 × 10-4

2.45 × 10-6

tonnes CO2-e /equipment - hour

6

Dehydrators

2.00 × 10-3

4.96 × 10-6

tonnes CO2-e /equipment - hour

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

3.73LB Method 2—onshore natural gas production, other than emissions that are vented or flared—onshore gas gathering and boosting pipelines

             (1)  For section 3.73L and subsection 3.73M(1), Eijp is given by the following formula:

               Eijp = ∑k Tik × 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.

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 natural gas gathering and boosting.

Tik is the average hours of operation during the year of the equipment of each equipment type (k) specified in column 2 of the table in subsection (2), if the equipment is used in natural gas gathering and boosting during the year.

Pk is the length of the system of gathering and boosting pipelines of type (k) during the year measured in kilometres and used in 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 kilometre-hour of pipeline type (k), if the equipment is used in natural gas gathering and boosting.

Sij  is the measured share of each gas type (j), being methane or carbon dioxide, in the unprocessed gas (i), by volume, that passes though the equipment 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:

Item

Equipment type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Onshore gas gathering and boosting pipelines (cast iron)

7.72 × 10-3

3.14 × 10-5

tonnes CO2-e /kilometres of pipeline hour

2

Onshore gas gathering and boosting pipelines (plastic)

6.99 × 10-4

2.85 × 10-6

tonnes CO2-e /kilometres of pipeline hour

3

Onshore gas gathering and boosting pipelines (protected steel)

1.31 × 10-4

5.34 × 10-7

tonnes CO2-e /kilometres of pipeline hour

4

Onshore gas gathering and boosting pipelines (unprotected steel)

4.64 × 10-3

1.89 × 10-5

tonnes CO2-e /kilometres of pipeline hour

3.73M  Method 3—natural gas gathering and boosting (other than venting and flaring)

(1)     Method 3 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 subsection (2).

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.  

             (2)  For subsection (1), Eijs is given by the following formula:

  Eijs = ∑k (Tik × Nik × EFijk) × 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 station 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 natural gas gathering and boosting stations (s).

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 (3) or (4), if the component is used in the natural gas gathering and boosting station.

Tik is:

                     (a)  if subsection (3) applies—the average hours of operation during the year of the component of each component type (k), if the component is used in natural gas gathering and boosting;

                     (b)  if subsection (4) 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), if the component type is used in natural gas gathering and boosting.

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.

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.

             (3)  Unless subsection (4) 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:

Item

Component type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Valves – gas production

7.36 × 10-5

1.83 × 10-7

tonnes CO2-e /component - hour

2

Connectors – gas production

8.99 × 10-6

2.23 × 10-8

tonnes CO2-e / component - hour

3

Flanges – gas production

3.30 × 10-6

8.22 × 10-9

tonnes CO2-e / component - hour

4

Open-ended lines – gas production

1.92 × 10-5

4.78 × 10-8

tonnes CO2-e / component - hour

5

Pump Seals – gas production

5.46 × 10-6

1.36 × 10-8

tonnes CO2-e / component - hour

6

Others – gas production

2.57 × 10-4

6.40 × 10-7

tonnes CO2-e / component - hour

                          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.              

             (4)  If an LDAR program has been carried out at the facility in relation to natural gas gathering and boosting components in accordance with subsection (5) 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:

Item

Component and leaker/non leaker type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Valves—non leaker

7.56 × 10-6

1.88 × 10-8

tonnes CO2-e /component - hour

2

Values—leaker

5.60 × 10-3

1.39 × 10-5

tonnes CO2-e / component - hour

3

Pumps—non leaker

4.20 × 10-6

1.04 × 10-8

tonnes CO2-e / component - hour

4

Pumps—leaker

9.80 × 10-3

2.44 × 10-5

tonnes CO2-e / component - hour

5

Flanges—non leaker

3.92 × 10-7

9.75 × 10-10

tonnes CO2-e / component - hour

6

Flanges—leaker

3.36 × 10-3

8.36 × 10-6

tonnes CO2-e / component - hour

7

Other—non leaker

2.27 × 10-6

5.64 × 10-9

tonnes CO2-e / component - hour

8

Other—leaker

5.88 × 10-3

1.46 × 10-5

tonnes CO2-e / component - hour

             (5)  For subsection (4) the LDAR program must survey each component used in natural gas gathering and boosting 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.

             (6)    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 3.3.6D—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)

3.73N  Available methods

             (1)  Subject to section 1.18, one of the following methods must be used for estimating fugitive emissions of methane (other than emissions that are vented or flared) released during a year from produced water relating to the operation of a facility that is constituted by a relevant activity:

                     (a)  method 1 under section 3.73NA;

                     (b)  method 2 under section 3.73NB.

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)  In this Division, a relevant activity is oil or gas exploration and development, crude oil production, natural gas gathering and boosting and onshore or offshore natural gas production.

3.73NA  Method 1—produced water (other than emissions that are vented or flared)

                   Method 1 is:

               Eij  = Wi ×  EFijw × Sij /SDij

where:

Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j) being methane from the produced water during the year measured in CO2‑e tonnes.

Wi is the total quantity of produced water during the year associated with the relevant activity measured in megalitres of produced water.

EFijw is the emission factor for gas type (j), being methane, of 7.99 tonnes of CO2-e per megalitre of produced water associated with relevant activity during the year.

Sij  is the measured share of gas type (j) being methane 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.

3.73NB  Method 2—produced water (other than emissions that are vented or flared)

             (1)  Method 2 is:

                   Eij  = Wi × EFijw × Sij /SDij   

where:

Eij is the fugitive emissions (other than emissions that are vented or flared) of gas type (j) being methane from the produced water from the relevant activity during the year measured in CO2‑e tonnes.

Wi is the total quantity of produced water during the year associated with the relevant activity measured in megalitres of produced water.

EFijw is the emission factor for gas type (j), being methane, measured in CO2‑e tonnes per megalitre of produced water associated with the relevant activity during the year as determined under subsection (2).

Sij  is the measured share of gas type (j) being methane 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.

             (2)  For EFijw, in subsection (1):

                     (a)  if the average pressure for a water stream entering the separator during the year (WP) is less than 345 kilopascals and:

                              (i)  the average salinity content of the water is less than or equal to 20,000 milligrams per litre during the year—0.8707 tonnes of CO2‑e tonnes per megalitre of produced water associated with the relevant activity; or

                             (ii)  the average salinity content of the water is less than or equal to 100,000 milligrams per litre and greater than or equal to 20,000 milligrams per litre during the year—0.7439 tonnes of CO2‑e tonnes per megalitre of produced water associated with the relevant activity; or

                            (iii)  the average salinity content of the water is greater than 100,000 milligrams per litre during the year—0.3212 tonnes of CO2‑e tonnes per megalitre of produced water associated with the relevant activity; or

                     (b)  if the average pressure for a water stream entering the separator during the year (WP) is equal to or greater than 345 kilopascals—is calculated under subsection (3); and

             (3)  For paragraph (2)(b):

                     (a)  if the average salinity content of the water is less than or equal to 20,000 milligrams per litre during the year—EFijw, is given by the following formula:

                      Eijw  = WP × 0.0016 + 0.4342

                     (b)  if the average salinity content of the water is less than or equal to 100 000 milligrams per litre and greater than or equal to 20,000 milligrams per litre during the year—EFijw, is given by the following formula:

                      Eijw  = WP × 0.0013 + 0.3695

                     (c)  if the average salinity content of the water is greater than 100,000 milligrams per litre during the year—EFijw, is given by the following formula:

                      Eijw  = WP × 0.0009 + 0.0507

where:

EFijw is the emission factor for gas type (j), being methane, measured in CO2‑e tonnes per megalitre of produced water associated with the relevant activity during the year.

WP is the average pressure for a water stream entering the separator during the year measured in kilopascals.

             (4)  For subsection (2) and (3), if there is no separator the water pressure must be measured at an equivalent point in the process.

 

Division 3.3.6ENatural gas processing (other than emissions that are vented or flared)

3.73O  Application

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

3.73P  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 processing:

                     (a)  method 1 under section 3.73Q;

                     (b)  method 2 under section 3.73R;

                       (c)        method 3 under section 3.73S.

                   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, 3.3.6C, 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, 3.3.6C, 3.3.7A and 3.3.7B if those Divisions are applicable to the facility.

3.73Q  Method 1—natural gas processing (other than emissions that are vented or flared)

             (1)  Method 1 is:

 

Eij  = Σjs(Qis × EFijs) × 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 natural gas processing 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 processing station (s).

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

EFijs is the emission factor for gas type (j), being methane or carbon dioxide, for the unprocessed natural gas (i) that passes through the natural gas processing station (s) during the year as determined under subsection (2) or (3), measured in tonnes of gas (leakage) per tonne of gas throughput.

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 0.832 and for carbon dioxide SD is 0.0345.

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

EFijs = GWPmethane × 0.6369 × Qi-0.4801

where:

EFijs is the emission factor for methane (j) measured in CO2‑e tonnes per tonne of natural gas that passes through the natural gas processing station (s) during the year.

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

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

EFijs  = 0.6369 ×  Qi-0.4801 × SDij=carbon dioxide / SDij=methane

where:

EFijs 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 (s) 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.

3.73R  Method 2—natural gas processing (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 natural gas processing 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 natural gas processing.

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 natural gas processing during the year.

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

EFijk is the emission factor (A) 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 natural gas processing.

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 0.868 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:

Item

Equipment type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Reciprocating compressors

7.66 × 10-2

1.91 × 10-4

tonnes CO2-e /equipment - hour

2

Centrifugal compressors (wet seals)

1.54 

5.99 × 10-3

tonnes CO2-e /equipment - hour

3

Centrifugal compressors (dry seals)

0.194

7.54 × 10-4

tonnes CO2-e /equipment - hour

4

Screw compressors

2.97 × 10-2

1.16 × 10-4

tonnes CO2-e /equipment - hour

3.73S  Method 3—natural gas processing (other than venting and flaring)

             (1)  Method 3 is:                                              

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

where:

Eij is the fugitive emissions (other than venting and flaring) of gas type (j), being methane or carbon dioxide, from the natural gas processing 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 natural gas processing.

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 natural gas processing; or

                     (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) if the component type is used in the natural gas processing 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 natural gas processing.

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 0.868 and for carbon dioxide SD is 0.0345.

             (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: or

Item

Component type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Valves

1.08 × 10-4

4.21 × 10-7

tonnes CO2-e /component - hour

2

Pump Seals

3.22 × 10-4

1.25 × 10-6

tonnes CO2-e / component - hour

3

Others

1.36 × 10-4

5.30 × 10-7

tonnes CO2-e / component - hour

4

Connectors

7.67 × 10-6

2.99 × 10-8

tonnes CO2-e / component - hour

5

Flanges

1.23 × 10-5

4.78 × 10-8

tonnes CO2-e / component - hour

6

Open-ended lines

2.88 × 10-5

1.12 × 10-7

tonnes CO2-e / component - hour

                     (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 natural gas processing 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:

Item

Component and leaker/non leaker type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Valves—non leaker

7.56 × 10-6

2.94 × 10-08

tonnes CO2-e /component - hour

2

Values—leaker

5.60 × 10-3

2.18 × 10-05

tonnes CO2-e / component - hour

3

Pumps—non leaker

2.10 × 10-5

8.18 × 10-08

tonnes CO2-e / component - hour

4

Pumps—leaker

9.80 × 10-3

3.82 × 10-05

tonnes CO2-e / component - hour

5

Flanges—non leaker

3.92 × 10-7

1.53 × 10-09

tonnes CO2-e / component - hour

6

Flanges—leaker

3.36 × 10-3

1.31 × 10-05

tonnes CO2-e / component - hour

7

Other—non leaker

2.27 × 10-6

8.83 × 10-09

tonnes CO2-e / component - hour

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 3.3.7Natural 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 = ∑k (Qk × Nk ×EFjk)

where:

Ej is the fugitive emissions (other than flaring) of gas type (j) measured in CO2‑e tonnes from the natural gas transmission through the system of pipelines during the year.

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

Qk is the total of the quantities of natural gas or plant condensate measured in tonnes that pass through each equipment type (k) or the number of equipment units of type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas transmission during the year.

Nk is the total number of equipment units of each equipment type (k) listed in section 6.1.2 of the API Compendium if the equipment type is used in the natural gas transmission during the year.

EFjk is the emission factor of gas type (j) measured in CO2‑e tonnes for each equipment type (k) listed in sections 5 and 6.1.2 of the API Compendium as determined under subsection (2), where the equipment is used in the natural gas transmission.

             (2)  For EFjk, the emission factors for a gas type (j) as the natural gas or plant condensate passes through the equipment type (k) are:

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

                     (b)  as listed in that Compendium for the equipment type with emission factors adjusted for variations in estimated gas composition, in accordance with that Compendium’s sections 5 and 6.1.2, and the requirements of Division 2.3.3; or

                     (c)  as listed in that Compendium for the equipment type with emission factors adjusted for variations in the type of equipment material estimated in accordance with the results of published research for the crude oil industry and the principles of section 1.13; or

                     (d)  if the manufacturer of the equipment supplies equipment‑specific emission factors for the equipment type—those factors; or

                     (e)  estimated using the engineering calculation approach in accordance with sections 5 and 6.1.2 of the API Compendium.

3.78  Method 3—natural gas transmission (other than flaring)

      (1)  Method 3 is:

Ej = ∑k (Tk × Nk ×EFjk)

where:

Eij is the fugitive emissions (other than flaring) of gas type (j) measured in CO2‑e tonnes from the natural gas transmission through the system of pipelines during the year.

Σk is the total emissions of gas type (j) measured in CO2‑e tonnes 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 is used in the natural gas transmission.

Tk 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 is used in the natural gas transmission during the year.

Nk is the total number of components of each component type (k) listed in section 6.1.3 of the API Compendium if the component type is used in the natural gas transmission during the year.

EFjk is the emission factor of gas type (j) measured in CO2‑e tonnes for each component type (k) listed in 6.1.3 of the API Compendium as determined under subsection (2), where the component is used in the natural gas transmission.

             (2)  For EFjk, the emission factors for gas type (j), as natural gas or plant condensate passes through a component type (k), are:

                     (a)  as listed in Table 6-18 in section 6.1.3 of the API Compendium, for the component type; or

                     (b)  as listed in that Compendium for the component type with emission factors adjusted for variations in estimated gas composition, in accordance with that Compendium’s Table 6-18 in section 6.1.3, and the requirements of Division 2.3.3; or

                     (c)  as listed in that Compendium for the component type with emission factors adjusted for variations in the type of component material estimated in accordance with the results of published research for the crude oil industry and the principles of section 1.13; or

                     (d)  if the manufacturer of the component supplies component‑specific emission factors for the component type—those factors; or

                     (e)  estimated using the engineering calculation approach in accordance with section 6.1.3 of the API Compendium.

Division 3.3.7ANatural gas storage (other than emissions that are vented or flared)

3.78A  Application

                   This Division applies to fugitive emissions (other than emissions that are vented or flared) from natural gas storage.

3.78B  Available methods

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

                     (a)  method 1 under section 3.78C;

                     (b)  method 2 under section 3.78D;

                     (c)  method 3 under section 3.78E.

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, 3.3.6C, 3.3.6E 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, 3.3.6C, 3.3.6E and 3.3.7B if those Divisions are applicable to the facility.

 3.78C  Method 1—natural gas storage (other than emissions that are vented or flared)

             (1)  Method 1 is:

               Eij = ∑k (Qik × EFijk)

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 storage 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 natural gas storage.

Qik is the total number of each equipment type (k) specified in column 2 of the table in subsection (2).

EFijk is the emission factor for gas type (j), being methane or carbon dioxide, measured in tonnes of gas type (j) per equipment type (k) during the year, as determined under subsection (2), if the equipment is used in the natural gas storage.

             (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:

Item

Equipment type (k)

Emission factor for gas type  (j)

 

 

CH4

CO2

Units

1

Natural gas storage station

10,336

20.7

tonnes CO2-e per station

3.78D  Method 2—natural gas storage (other than emissions that are vented or flared

             (1)  Method 2 is:

                Eij = ∑k (Tik × Nik ×EFijk)

where:

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

Σk is the total emissions of methane or carbon dioxide (j) 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 natural gas storage.

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

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

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

             (2)  For EFijk in subsection (1), column 3 of an item in the following table specifies the emission factor for methane or carbon dioxide (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:

Item

Equipment type (k)

Emission factor for gas type  (j)

 

 

CH4

CO2

Units

1

Natural gas storage station

0.482

1.01 × 10-3

tonnes CO2-e per equipment – hour

2

Reciprocating compressor

0.473

9.93 × 10-4

tonnes CO2-e per equipment – hour

3

Centrifugal compressor

0.683

1.43 × 10-3

tonnes CO2-e per equipment – hour

4

Screw compressor

2.88 × 10-2

6.03 × 10-5

tonnes CO2-e per equipment – hour

3.78E  Method 3—natural gas storage (other than emissions that are vented or flared)

             (1)  Method 3 is:

  Ej = ∑k (Tk × EFjk × Nk)

where:

Ej is the fugitive emissions (other than emissions that are vented or flared) of gas type (j) measured in CO2‑e tonnes from the natural gas storage during the year.

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

EFjk is the emission factor of gas type (j) measured in tonnes of CO2‑e per component-hour that passes through each component type (k) as determined under subsection (2) or (3), if the component is used in the natural gas storage.

Tk 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 storage; or

                     (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 each component type (k) listed in section 6.1.3 of the API Compendium if the component type is used in the natural gas storage during the year.

             (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)  as listed in Table 6-18 in section 6.1.3 of the API Compendium, for the component type; or

                     (b)  as listed in that Compendium for the component type with emission factors adjusted for variations in estimated gas composition, in accordance with that Compendium’s Table 6-18 in section 6.1.3, and the requirements of Division 2.3.3; or

                     (c)  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 natural gas storage 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:

Item

Component and leaker/non leaker type (k)

Emission factor for gas type  (j)



 

 

CH4

CO2

Units

1

Valves—non leaker

7.56 × 10-6

2.94 × 10-08

tonnes CO2-e /component - hour

2

Values—leaker

5.60 × 10-3

2.18 × 10-05

tonnes CO2-e / component - hour

3

Pumps—non leaker

2.10 × 10-5

8.18 × 10-08

tonnes CO2-e / component - hour

4

Pumps—leaker

9.80 × 10-3

3.82 × 10-05

tonnes CO2-e / component - hour

5

Flanges—non leaker

3.92 × 10-7

1.53 × 10-09

tonnes CO2-e / component - hour

6

Flanges—leaker

3.36 × 10-3

1.31 × 10-05

tonnes CO2-e / component - hour

7

Other—non leaker

2.27 × 10-6

8.83 × 10-09

tonnes CO2-e / component - hour

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 storage 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 3.3.7B—Natural gas liquefaction, storage and transfer (other than emissions that are vented or flared)

3.78F  Application

                   This Division applies to fugitive emissions from natural gas liquefaction, storage and transfer (other than emissions that are vented or flared).

3.78G  Available methods

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

                     (a)  method 1 under section 3.78H;

                     (b)  method 2 under section 3.78I;

                     (b)  method 3 under section 3.78J.

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, 3.3.6C, 3.3.6E and 3.3.7A 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, 3.3.6C, 3.3.6E and 3.3.7A if those Divisions are applicable to the facility.

3.78H  Method 1—natural gas liquefaction, storage and transfer (other than emissions that are vented or flared)

             (1)  Method 1 is:                                                  

                    

where:

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

Σk is the total emissions of gas type (j) being methane, 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 natural gas liquefaction, storage and transfer.

Qik is the total of each equipment type (k) specified in column 2 of the table in subsection (2).

EFijk is the emission factor for gas type (j) measured in CO2‑e tonnes per equipment type (k) during the year if the equipment is used in the natural gas liquefaction, storage and transfer.

             (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:

Item

Equipment type (k)

Emission factor for gas type  (j)

 

 

CH4

Units

1

Liquefied natural gas station

25,700

tonnes CO2-e per station

3.78I  Method 2—natural gas liquefaction, storage and transfer (other than emissions that are vented or flared)

             (1)  Method 2 is:

                   Eij = ∑k (Tik × Nik ×EFijk)

where:

Eij is the fugitive emissions (other than venting and flaring) of methane (j) from the natural gas liquefaction, storage and transfer during the year measured in CO2‑e tonnes.

Σk is the total emissions of methane (j) measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) listed in section 6.1.2 of the API Compendium, if the equipment is used in the natural gas liquefaction, storage and transfer.

Tik is the average hours of operation during the year of each equipment type (k) listed in section 6.1.2 of the API Compendium, if the equipment is used in the natural gas liquefaction, storage and transfer.

Nik is the total number of equipment units of each equipment type (k) listed in section 6.1.2 of the API Compendium if the equipment type is used in the natural gas liquefaction, storage and transfer during the year.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per equipment type (k) – hour listed in section 6.1.2 of the API Compendium as determined under subsection (2), if the equipment is used in the natural gas liquefaction, storage and transfer.

             (2)  For EFijk, the emission factors for methane (j) as the natural gas passes through the equipment types (k) are:

                     (a)  as listed in Table 6-6 of section 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.

3.78J  Method 3—natural gas liquefaction, storage and transfer (other than venting and flaring)

             (1)  Method 3 is:                                              

               Eij = ∑k (Tik × Nik ×EFijk)

where:

Eij is the fugitive emissions (other than venting and flaring) of methane (j) from the natural gas liquefaction, storage and transfer 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), if the component type is used in the natural gas liquefaction, storage and transfer.

Tik is:

                     (a)  if subsection (2) applies—the average hours of operation during the year of the components of each component type (k) listed in table 13 in section 4.3.1 of the API LNG Operations Consistent Methodology for Estimating Greenhouse Gas Emissions published by the American Petroleum Institute, if the component is used in the natural gas liquefaction, storage and transfer during the year; or

                     (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), if the component type is used in the natural gas liquefaction, storage and transfer during the year.

EFijk is the emission factor of methane (j) measured in tonnes of CO2‑e per component type (k) – hour, if the component is used in the natural gas liquefaction, storage and transfer.

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

Item

Component type (k)

Emission factor for gas type  (j)



 

 

CH4

 

Units

1

Valve

6.40 × 10-4

 

tonnes CO2-e /hour/component

2

Pump Seal

2.15 × 10-3

 

tonnes CO2-e /hour/component

3

Connectors (flanges and threaded fittings)

1.83 × 10-4

 

tonnes CO2-e /hour/component

4

Other

9.52 × 10-4

 

tonnes CO2-e /hour/compressor

5

Vapour Recovery Compressors

2.24 × 10-3

 

tonnes CO2-e /hour/compressor

                     (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 natural gas liquefaction, storage and transfer components in accordance with subsection (4) and this subsection elected for all components under this method, EFijk, the emission factors for methane (j), for component type (k), are set out in column 3 of an item in the following table for a component and leaker/non-leaker type (k) specified in column 2 of that item:

Item

Component and leaker/non leaker type (k)

Emission factor for gas type  (j)



 

 

CH4

 

Units

1

Valves—non leaker

7.56 × 10-6

 

tonnes CO2-e /component - hour

2

Values—leaker

5.60 × 10-3

 

tonnes CO2-e / component - hour

3

Pumps—non leaker

2.10 × 10-5

 

tonnes CO2-e / component - hour

4

Pumps—leaker

9.80 × 10-3

 

tonnes CO2-e / component - hour

5

Flanges—non leaker

3.92 × 10-7

 

tonnes CO2-e / component - hour

6

Flanges—leaker

3.36 × 10-3

 

tonnes CO2-e / component - hour

7

Other—non leaker

2.27 × 10-6

 

tonnes CO2-e / component - hour

8

Other—leaker

5.88 × 10-3

 

tonnes CO2-e / component - hour

             (4)  For subsection (3), the LDAR program must survey each component used in natural gas liquefaction, storage and transfer 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 3.3.8Natural gas distribution (other than emissions that are flared)

3.79  Application

                   This Division applies to fugitive emissions from natural gas distribution activities.

3.80  Available methods

             (1)  Subject to section 1.18 and subsections (2) and (3), one of the following methods must be used for estimating fugitive emissions (other than emissions that are flared) of each gas type, being carbon dioxide and methane, released during a year from the operation of a facility that is constituted by natural gas distribution through a system of pipelines:

                     (a)  method 1 under section 3.81;

                     (b)  method 2 under section 3.82;

                     (c)  method 3 under section 3.82A.

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)  Method 3 may only be used if the percentage of unaccounted for gas for a facility is calculated or determined during a reporting year in accordance with gas market rules or procedures applicable to the facility.

Note:          A percentage of unaccounted for gas is generally worked out under procedures made by the Australian Energy Market Operator and available on their website: www.aemo.com.au

3.81  Method 1—natural gas distribution

             (1)  Method 1 is:

                  

where:

Ejp is the fugitive emissions of gas type (j) that result from natural gas distribution through a system of pipelines with sales of gas in a State or Territory (p) during the year, measured in CO2‑e tonnes.

Sp is the total sales during the year from the pipeline system in a State or Territory (p), measured in terajoules.

%UAGp is the percentage of unaccounted for gas in the pipeline system in a State or Territory, relative to the amount of gas issued annually by gas utilities in that State or Territory.

Note:          The value 0.55 following the variable %UAGp in method 1 represents the proportion of gas that is unaccounted for and released as emissions.

Cjp is the natural gas composition factor for gas type (j) for the natural gas supplied from the pipeline system in a State or Territory (p), measured in CO2‑e tonnes per terajoule.

             (2)  For %UAGp in subsection (1), column 3 of an item in the following table specifies the percentage of unaccounted for gas in the pipeline system in a State or Territory specified in column 2 of that item.

             (3)  For Cjp in subsection (1), columns 4 and 5 of an item in the following table specify the natural gas composition factor for carbon dioxide and methane for a pipeline system in a State or Territory specified in column 2.

 

Item

State

Unaccounted for gas (a)%

Natural gas composition factor (a)(tonnes CO2‑e/TJ)

 

UAGp

CO2

CH4

1

NSW and ACT

2.2

0.8

437

2

VIC

3.0

0.9

435

3

QLD

1.7

0.8

423

4

WA

2.9

1.1

408

5

SA

4.9

0.8

437

6

TAS

0.2

0.9

435

7

NT

2.2

0.0

352

3.82  Method 2—natural gas distribution

             (1)  Method 2 is:

                  

where:

Ej is the fugitive emissions of gas type (j) that result from the natural gas distribution during the year measured in CO2‑e tonnes.

Σk is the total of emissions of gas type (j) measured in CO2‑e tonnes 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 natural gas distribution.

Qk is the total of the quantities of natural gas measured in tonnes that pass through each equipment type (k) or the number of equipment units of type (k) listed in sections 5 and 6.1.2 of the API Compendium, if the equipment is used in the natural gas distribution.

EFjk is the emission factor for gas type (j) measured in CO2‑e tonnes for 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 natural gas distribution.

             (2)  For EFjk, the emission factors for gas type (j) as the natural gas passes through the equipment type (k) are:

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

                     (b)  as listed in that Compendium for the equipment type with emission factors adjusted for variations in estimated gas composition, in accordance with that Compendium’s Sections 5 and 6.1.2, and the requirements of Division 2.3.3; or

                     (c)  as listed in that Compendium for the equipment type with emission factors adjusted for variations in the type of equipment material using adjusted factors; or

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

             (3)  In paragraph 3.82(2)(c), a reference to factors adjusted is a reference to the factors in Table 5‑3 of the publication entitled Greenhouse Gas Emission Estimation Methodologies, Procedures and Guidelines for the Natural Gas Distribution Sector, American Gas Association, April 2008, that are adjusted for variations in estimated gas composition in accordance with:

                     (a)  section 5.2.1 of that publication; and

                     (b)  Division 2.3.3.

3.82A  Method 3—natural gas distribution

             (1)  Method 3 is:

                  

where:

Ejp is the fugitive emissions (other than emissions that are flared) of gas type (j) that result from natural gas distribution through a system of pipelines with sales of gas in a State or Territory (p) during the year, measured in CO2‑e tonnes.

Sp is the total sales during the year from the pipeline system in a State or Territory (p), measured in terajoules.

%UAGp is the percentage of unaccounted for gas in the pipeline system in a State or Territory (p), relative to the amount of gas issued annually by gas utilities to that system.

Cjp is the natural gas composition factor for gas type (j) for the natural gas supplied from the pipeline system in a State or Territory (p), measured in CO2‑e tonnes per terajoule.

             (2)  For %UAGp in subsection (1):

                     (a)  if at the time of reporting the percentage of unaccounted for gas for the reporting year has been calculated or determined in accordance with gas market rules or procedures applicable to the facility—the percentage calculated or determined in accordance with those rules or procedures; or

                     (b)  if at the time of reporting the percentage of unaccounted for gas for the reporting year has not been calculated or determined in accordance with gas market rules or procedures applicable to the facility—the percentage applicable to the most recent 12 month period for which the percentage of unaccounted for gas has been calculated or determined.

             (3)  For Cjp in subsection (1), columns 3 and 4 of an item in the following table specify the natural gas composition factor for carbon dioxide and methane for a pipeline system in a State or Territory specified in column 2.

Item

State

Natural gas composition factor (a)(tonnes CO2‑e/TJ)

 

CO2

CH4

1

NSW and ACT

0.8

437

2

VIC

0.9

435

3

QLD

0.8

423

4

WA

1.1

408

5

SA

0.8

437

6

TAS

0.9

435

7

NT

0.0

352

 

Division 3.3.9ANatural gas production (emissions that are vented or flared)

3.83  Application

                   This Division applies to fugitive emissions from venting or flaring from natural gas production activities, including emissions from:

                     (a) the venting of natural gas; and

                     (b)  the venting of waste gas and vapour streams at facilities that are constituted by natural gas production; and

                     (c)  the flaring of natural gas, waste gas and waste vapour streams at those facilities.

Note:          This Division covers the four sources of offshore natural gas production—venting, onshore natural gas production—venting, offshore natural gas production—flaring and onshore natural gas production—flaring.

Subdivision 3.3.9A.1—Natural gas production—emissions that are vented—gas treatment processes

3.84  Available methods

             (1)  Subject to section 1.18, for estimating emissions relating to gas treatment processes (emissions that are vented) released during a year from the operation of a facility that is constituted by natural gas production the methods as set out in this section must be used.

             (2)  One of the following methods must be used for estimating fugitive emissions that result from deliberate releases from process vents, system upsets and accidents:

                     (a)  method 1 under section 3.85;

                     (b)  method 4 under Part 1.3.

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

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

3.85  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas treatment processes

                   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.

Item

Emission process

API Compendium section

1

Gas treatment processes

Section 5.1

Subdivision 3.3.9A.2—Natural gas production—emissions that are vented—cold process vents

3.85A  Available methods

             (1)  Subject to section 1.18, for estimating emissions relating to cold process vents (emissions that are vented) released during a year from the operation of a facility that is constituted by natural gas production the methods as set out in this section must be used.

             (2)  One of the following methods must be used for estimating fugitive emissions that result from deliberate releases from process vents, system upsets and accidents:

                     (a)  method 1 under section 3.85B;

                     (b)  method 4 under Part 1.3.

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

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

3.85B  Method 1—emissions from system upsets, accidents and deliberate releases from process vents

                   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.

Item

Emission process

API Compendium section

1

Cold process vents

Section 5.3

Subdivision 3.3.9A.3—Natural gas production—emissions that are vented—natural gas blanketed tanks and condensate storage tanks

3.85C  Available methods

             (1)  Subject to section 1.18, for estimating emissions relating to natural gas blanketed tanks and condensate storage tanks (emissions that are vented) released during a year from the operation of a facility that is constituted by natural gas production the methods as set out in this section must be used.

             (2)  One of the following methods must be used for estimating fugitive emissions that result from deliberate releases from process vents, system upsets and accidents:

                     (a)  method 1 under section 3.85D;

                     (b)  method 4 under Part 1.3.

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

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

3.85D  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—natural gas blanketed tanks and condensate storage tanks

                   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.

Item

Emission process

API Compendium section

1

Natural gas blanketed tanks

Section 5.4.4

2

Condensate storage tanks

Section 5.4.1

Subdivision 3.3.9A.4—Natural gas production—emissions that are vented—gas driven pneumatic devices

3.85E  Available methods

             (1)  Subject to section 1.18, for estimating emissions relating to gas driven pneumatic devices (emissions that are vented) released during a year from the operation of a facility that is constituted by natural gas production the methods as set out in this section must be used.

             (2)  One of the following methods must be used for estimating fugitive emissions that result from deliberate releases from process vents, system upsets and accidents:

                     (a)  method 1 under section 3.85F;

                     (b)  method 4 under Part 1.3.

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

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

3.85F  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas driven pneumatic devices

                   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.

Item

Emission process

API Compendium section

1

Other venting sources—gas driven pneumatic devices

Section 5.6.1

Subdivision 3.3.9A.5—Natural gas production—emissions that are vented—gas driven chemical injection pumps

3.85G  Available methods

             (1)  Subject to section 1.18, for estimating emissions relating to gas driven chemical injection pumps (emissions that are vented) released during a year from the operation of a facility that is constituted by natural gas production the methods as set out in this section must be used.

             (2)  One of the following methods must be used for estimating fugitive emissions that result from deliberate releases from process vents, system upsets and accidents:

                     (a)  method 1 under section 3.85H;

                     (b)  method 4 under Part 1.3.

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

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

3.85H  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas driven chemical injection pumps

                   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.

 

Item

Emission process

API Compendium section

1

Other venting sources—gas driven chemical injection pumps

Section 5.6.2

Subdivision 3.3.9A.6—Natural gas production—emissions that are vented—well blowouts

3.85K  Available methods

             (1)  Subject to section 1.18, for estimating emissions relating to well blowouts (emissions that are vented) released during a year from the operation of a facility that is constituted by natural gas production the methods as set out in this section must be used.

             (2)  One of the following methods must be used for estimating fugitive emissions that result from deliberate releases from process vents, system upsets and accidents:

                     (a)  method 1 under section 3.85L;

                     (b)  method 4 under Part 1.3.

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

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

3.85L  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—production related non-routine emissions—well blowouts

                   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.

Item

Emission process

API Compendium section

1

Non‑routine activities—production related non‑routine emissions

Section 5.7.1

Subdivision 3.3.9A.7—Natural gas production—emissions that are vented—CO2 stimulation

3.85M  Available methods

             (1)  Subject to section 1.18, for estimating emissions relating to CO2 stimulation (emissions that are vented) released during a year from the operation of a facility that is constituted by natural gas production the methods as set out in this section must be used.

             (2)  One of the following methods must be used for estimating fugitive emissions that result from deliberate releases from process vents, system upsets and accidents:

                     (a)  method 1 under section 3.85N;

                     (b)  method 4 under Part 1.3.

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

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

3.85N  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—production related non-routine emissions—CO2 stimulation

                   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.

Item

Emission process

API Compendium section

1

Non‑routine activities—production related non‑routine emissions

Section 5.7.1

Subdivision 3.3.9A.8—Natural gas production—emissions that are vented—well workovers

3.85O  Available methods

             (1)  Subject to section 1.18, for estimating emissions relating to well workovers (emissions that are vented) released during a year from the operation of a facility that is constituted by natural gas production the methods as set out in this section must be used.

             (2)  One of the following methods must be used for estimating fugitive emissions that result from deliberate releases from process vents, system upsets and accidents:

                     (a)  method 1 under section 3.85P;

                     (b)  method 4 under Section 3.85Q.

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

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

3.85P  Method 1—vented emissions from well workovers

             (1) Subject to subsection (3), Method 1 is:

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

where:

Eij is the fugitive (vented) emissions of gas type (j), being methane or carbon dioxide, from the 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 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 production.

Qik is the total of the number of well workover 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 production.

Note:          Consistent with subsection 3.41(2), a well workover 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 workover 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 production.

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 0.825 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:

Item

Equipment type (k)

Emission factor for gas type (j)

 

CH4

CO2

 

1

Well workover without hydraulic fracturing

5.5

1.1 × 10-2

tonnes CO2‑e per well workover event

2

Well workover with hydraulic fracturing and venting (no flaring)

1,031

4.2

tonnes CO2‑e per well workover event

3

Well workover with hydraulic fracturing with capture (no flaring)

90.8

0.37

tonnes CO2‑e per well workover event

4

Well workover with hydraulic fracturing with flaring

136.6

0.56

tonnes CO2‑e per well workover event

             (3)  If the well workover includes a well unloading, the fugitive (vented) emissions of gas type (j), being methane or carbon dioxide, for the well unloading must be calculated by applying section 5.7.1 of the API Compendium.

3.85Q  Method 4—vented emissions from gas well workovers

                   Method 4 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.

Item

Emission process

API Compendium section

1

Engineering calculation approach

Section  5.7.1

Subdivision 3.3.9A.9—Natural gas production—emissions that are vented—vessel blowdowns, compressor starts and compressor blowdowns

3.85R  Available methods

             (1)  Subject to section 1.18, for estimating emissions relating to vessel blowdowns, compressor starts and compressor blowdowns (emissions that are vented) released during a year from the operation of a facility that is constituted by natural gas production the methods as set out in this section must be used.

             (2)  One of the following methods must be used for estimating fugitive emissions that result from deliberate releases from process vents, system upsets and accidents:

                     (a)  method 1 under section 3.85S;

                     (b)  method 4 under Part 1.3.

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

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

3.85S  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—production related non-routine emissions—vessel blowdowns, compressor starts and compressor blowdowns

                   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.

Item

Emission process

API Compendium section

1

Non‑routine activities—production related non‑routine emissions—vessel blowdowns

Section 5.7.1 and 5.7.2

2

Non‑routine activities—production related non‑routine emissions—compressor starts

Section 5.7.1 and 5.7.2

3

Non‑routine activities—production related non‑routine emissions—compressor blowdowns

Section 5.7.1 and 5.7.2

Subdivision 3.3.9A.10Natural gas production (emissions that are flared)

3.85T  Available methods

             (1)  For estimating emissions released from gas flared from natural gas production:

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2 under section 3.87;

                            (iii)  method 3 under section 3.88; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A.

Note:          The flaring of gas from natural gas production and processing releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 in section 3.85 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.

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

3.86  Method 1—gas flared from natural gas production

             (1)  Method 1 is:

                  

where:

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

Qi is the quantity of fuel type (i) measured in tonnes of gas flared 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 CO2‑e tonnes of emissions per tonne of gas flared in the natural gas production during the year as determined under subsection (2).

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

 

Item

fuel type (i)

Emission factor of gas type (j) (tonnes CO2‑e/tonnes fuel flared)

 

CO2

CH4

N2O

1

Gas

2.7

0.133

0.026

2

Crude oil and liquids

3.20

0.009

0.06

3.87  Method 2—gas flared from natural gas production

                   Method 2 is:

where:

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

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

EFhi is the carbon dioxide emission factor for the total hydrocarbons (h) within the fuel type (i) in the natural gas production during the year, measured in CO2‑e tonnes per tonne of 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 the fuel type (i) in the natural gas production and processing during the year, measured in CO2‑e tonnes in accordance with Division 2.3.3.

3.87A  Method 2A—natural gas production (flared methane or nitrous oxide emissions)

                   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 natural gas production during the year, mentioned for the fuel type in the table in subsection 3.85(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 natural gas 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 natural gas production during the year, measured in tonnes in accordance with Division 2.3.3.

3.88  Method 3—gas flared from natural gas production

                   Method 3 is the same as method 2 under section 3.86, 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 3.3.9BNatural gas gathering and boosting (emissions that are vented or flared)

3.88A  Application

                   This Division applies to fugitive emissions from venting or flaring from natural gas gathering and boosting, including emissions from:

                     (a) the venting of natural gas; and

                     (b)  the venting of waste gas and vapour streams at facilities that are constituted by natural gas gathering and boosting; and

                     (c)  the flaring of natural gas, waste gas and waste vapour streams at those facilities.

Subdivision 3.3.9B.1—Natural gas gathering and boosting (emissions that are vented)

3.88B  Available methods

             (1)  Subject to section 1.18, method 1 under section 3.88C must be used for estimating fugitive emissions from gas vented during natural gas gathering and boosting.

Note:          There is no method 2, 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.

3.88C  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas gathering and boosting emissions

                   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.

Item

Emission process

API Compendium section

1

Gas treatment processes

Section 5.1

2

Cold process vents

Section 5.3

3

Natural gas blanketed tanks

Section 5.4.4

4

Other venting sources—gas driven pneumatic devices

Section 5.6.1

5

Other venting sources—gas driven chemical injection pumps

Section 5.6.2

6

Non‑routine activities—gas production related non‑routine emissions – gas gathering pipeline blowdowns

Section 5.7.1 and 5.7.2

7

Condensate storage tanks

Section 5.4.1

Subdivision 3.3.9B.2Natural gas gathering and boosting (emissions that are flared)

3.88D  Available methods

             (1)  For estimating emissions released from gas flared from natural gas gathering and boosting:

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2 under section 3.87;

                            (iii)  method 3 under section 3.88; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A.

Note:          The flaring of gas from natural gas production and processing releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 in section 3.86 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.

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

 

Division 3.3.9CNatural gas processing (emissions that are vented or flared)

3.88E  Application

                   This Division applies to fugitive emissions from venting or flaring from natural gas processing activities, including emissions from:

                     (a) the venting of natural gas; and

                     (b)  the venting of waste gas and vapour streams at facilities that are constituted by natural gas processing; and

                     (c)  the flaring of natural gas, waste gas and waste vapour streams at those facilities.

Subdivision 3.3.9C.1—Natural gas processing (emissions that are vented)

3.88F  Available methods

             (1)  Subject to section 1.18, method 1 under section 3.88G must be used for estimating fugitive emissions from gas vented during natural gas processing.

Note:          There is no method 2, 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.

3.88G  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas processing

                   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.

Item

Emission process

API Compendium section

1

Gas treatment processes

Section 5.1

2

Cold process vents

Section 5.3

3

Natural gas blanketed tanks

Section 5.4.4

4

Other venting sources—gas driven pneumatic devices

Section 5.6.1

5

Other venting sources—gas driven chemical injection pumps

Section 5.6.2

6

Non‑routine activities—gas processing related non‑routine emissions

Section 5.7.1 and 5.7.3

7

Condensate storage tanks

Section 5.4.1

Subdivision 3.3.9C.2Natural gas processing (emissions that are flared)

3.88H Available methods

             (1)  For estimating emissions released from gas flared from natural gas processing:

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2 under section 3.87;

                            (iii)  method 3 under section 3.88; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A.

Note:          The flaring of gas from natural gas production and processing releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 in section 3.86 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.

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

 

Division 3.3.9DNatural gas transmission (emissions that are flared)

3.88I  Application

                   This Division applies to fugitive emissions from venting or flaring from natural gas transmission activities, including emissions from the flaring of natural gas, waste gas and waste vapour streams at those facilities.

Note: Vented emissions from Natural gas transmission are estimated under Division 3.3.7.

3.88J Available methods

             (1)  For estimating emissions released from gas flared from natural gas transmission:

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2 under section 3.87;

                            (iii)  method 3 under section 3.88; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A.

Note:          The flaring of gas releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 in section 3.86 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.

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

 

 

Division 3.3.9ENatural gas storage (emissions that are vented or flared)

3.88K Application

                   This Division applies to fugitive emissions from venting or flaring from natural gas storage, including emissions from:

                     (a) the venting of natural gas; and

                     (b)  the venting of waste gas and vapour streams at facilities that are constituted by natural gas production or processing; and

                     (c)  the flaring of natural gas, waste gas and waste vapour streams at those facilities.

Subdivision 3.3.9E.1——Natural gas storage (emissions that are vented)

3.88L  Available methods

             (1)  Subject to section 1.18, method 1 under section 3.88M must be used for estimating fugitive emissions from gas vented during natural gas storage.

Note:          There is no method 2, 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.

3.88M  Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas storage related non‑routine emissions

                   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.

Item

Emission process

API Compendium section

1

Gas treatment processes

Section 5.1

2

Cold process vents

Section 5.3

3

Natural gas blanketed tanks

Section 5.4.4

4

Other venting sources—gas driven pneumatic devices

Section 5.6.1

5

Other venting sources—gas driven chemical injection pumps

Section 5.6.2

6

Non‑routine activities—gas storage related non‑routine emissions

Section 5.7.1 and 5.7.4 a

7

Condensate storage tanks

Section 5.4.1

a  The emission factor at Table 5-26 ‘Gas storage station venting’ must be used for each instance of a natural gas storage station if emissions are estimated according to section 5.7.4.

Subdivision 3.3.9E.2—Natural gas storage (emissions that are flared)

3.88N Available methods

             (1)  For estimating emissions released from gas flared from natural gas storage:

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2 under section 3.87;

                            (iii)  method 3 under section 3.88; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.86A.

Note:          The flaring of gas from natural gas storage releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 in section 3.86 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.

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

 

Division 3.3.9F— Natural gas liquefaction, storage and transfer (emissions that are vented or flared)

3.88O  Application

                   This Division applies to fugitive emissions from venting or flaring from natural gas liquefaction, storage and transfer activities, including emissions from:

                     (a) the venting of natural gas; and

                     (b)  the venting of waste gas and vapour streams at facilities that are constituted by natural gas liquefaction, storage and transfer activities; and

                     (c)  the flaring of natural gas, waste gas and waste vapour streams at those facilities.

Subdivision 3.3.9F.1—Natural gas liquefaction, storage and transfer (emissions that are vented)

3.88P  Available methods

             (1)  Subject to section 1.18, method 1 under section 3.88Q must be used for estimating fugitive emissions from gas vented from natural gas liquefaction, storage and transfer (emissions that are vented) activities.

Note:          There is no method 2, 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.

3.88Q  Method 1—emissions from system upsets, accidents and deliberate releases from process vents— natural gas liquefaction, storage and transfer

                   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.

Item

Emission process

API Compendium section

1

Gas treatment processes

Section 5.1

2

Cold process vents

Section 5.3

3

Natural gas blanketed tanks

Section 5.4.4

4

Other venting sources—gas driven pneumatic devices

Section 5.6.1

5

Other venting sources—gas driven chemical injection pumps

Section 5.6.2

6

Non‑routine activities— natural gas liquefaction, storage and transfer related non‑routine emissions

Section 5.7.1 and 5.7.4 a

7

Condensate storage tanks

Section 5.4.1

a The emission factor at Table 5-26 ‘Gas storage station venting’ must be used for each instance of an LNG station if emissions are estimated according to section 5.7.4. 

Subdivision 3.3.9F.2—Natural gas liquefaction, storage and transfer (emissions that are flared)

3.88R Available methods

             (1)  For estimating emissions released from gas flared from natural gas liquefaction, storage and transfer:

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2 under section 3.87;

                            (iii)  method 3 under section 3.88; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A.

Note:          The flaring of gas releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 in section 3.86 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.

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

 

Division 3.3.9G—Natural gas distribution (emissions that are flared)

3.88S  Application

                   This Division applies to fugitive emissions from flaring from natural gas distribution activities, including emissions from the flaring of natural gas, waste gas and waste vapour streams at those facilities.

3.88T  Available methods

             (1)  For estimating emissions released from gas flared from natural gas distribution:

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2 under section 3.87;

                            (iii)  method 3 under section 3.88; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A; and

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

                              (i)  method 1 under section 3.86;

                             (ii)  method 2A under section 3.87A.

Note:          The flaring of gas releases emissions of carbon dioxide, methane and nitrous oxide. The reference to gas type (j) in method 1 in section 3.86 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.

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


 

 

[16]         Heading to Part 3.4

After “capture and storage”, insert “and enhanced oil recovery”.

[17]         Section 3.88

After “capture and storage”, insert “and enhanced oil recovery”.

[18]         Divisions 3.4.2 and 3.4.3

Repeal the Divisions, substitute:

Division 3.4.2Transport of greenhouse gases

Subdivision 3.4.2.1Preliminary

3.89  Application

                   This Division applies to fugitive emissions from the transport of a greenhouse gas captured for permanent storage or captured for enhanced oil recovery.

Note:          Section 1.19A defines when a greenhouse gas is captured for permanent storage.

Note:          Section 1.8 defines enhanced oil recovery.

3.90  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 the transport of a greenhouse gas captured for permanent storage or for injection as part of enhanced oil recovery, the methods as set out in this section must be used.

Emissions from transport of a greenhouse gas involving transfer

             (2)  If the greenhouse gas is transferred to a relevant person for injection by the person in accordance with a licence, lease or approval mentioned in section 1.19A or an enhanced oil recovery authority, one of the following methods must be used for estimating fugitive emissions of the greenhouse gas that result from the transport of the greenhouse gas stream for that injection:

                     (a)  method 1 under section 3.91 (which deals with injection);

                     (b)  method 2 under section 3.77 (which deals with transport), applied in relation to the greenhouse gas as if it were a type of natural gas.

Note 1:       There is no method 3 or 4 for subsection (2).

Note 2:       The same emissions cannot be counted under both the method mentioned in paragraph (2)(a) (injection) and the method mentioned in paragraph (2)(b) (transport).

Emissions from transport of a greenhouse gas not involving transfer

          (2A)  Subsection (3) applies if:

                     (a)  the greenhouse gas is captured by a relevant person for injection in accordance with a licence, lease or approval mentioned in section 1.19A or an enhanced oil recovery authority; and

                     (b)  the greenhouse gas is not transferred to another person for the purpose of injection.

             (3)  One of the following methods must be used for estimating fugitive emissions of the greenhouse gases that result from the transport of the greenhouse gas stream for that injection:

                     (a)  method 1 under section 3.92 (which deals with injection);

                     (b)  method 2 under section 3.77 (which deals with transport), applied in relation to the greenhouse gas as if it were a type of natural gas.

Note 1:       There is no method 3 or 4 for subsection (3).

Note 2:       The same emissions cannot be counted under both the method mentioned in paragraph (3)(a) (injection) and the method mentioned in paragraph (3)(b) (transport).

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

Subdivision 3.4.2.2Emissions from transport of greenhouse gases involving transfer

3.91  Method 1—emissions from transport of greenhouse gases involving transfer

                   For subsection 3.90(2), method 1 is:

where:

Ej is the emissions of gas type (j), during the year from transportation of greenhouse gas captured for permanent storage, or captured for enhanced oil recovery, to the storage or injection site, measured in CO2‑e tonnes.

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes, being:

                     (a)  for methane—6.784 × 10‑4 × GWPmethane; and

                     (b)  for carbon dioxide—1.861 × 10‑3; and

                     (c)  for any other gas type—the appropriate conversion factor for the gas type.

Qinj is the quantity of greenhouse gas injected into the storage or injection site during the year and measured in cubic metres at standard conditions of pressure and temperature.

RCCSj is the quantity of gas type (j) captured during the year worked out under Division 1.2.3 and measured in cubic metres at standard conditions of pressure and temperature. If the injection is part of enhanced oil recovery, Division 1.2.3 must be applied to enhanced oil recovery as if it was capture for permanent storage.

Eij is the fugitive emissions (j) from the injection of a greenhouse gas into a geological formation during the reporting year, measured in CO2‑e tonnes and calculated in accordance with Subdivision 3.4.3.2.

Subdivision 3.4.2.3Emissions from transport of greenhouse gases not involving transfer

3.92  Method 1—emissions from transport of greenhouse gases not involving transfer

                   For subsection 3.90(3), method 1 is:

where:

Ej is the emissions of gas type (j), during the year from transportation of greenhouse gas captured for permanent storage, or captured for enhanced oil recovery, to the storage or injection site, measured in CO2‑e tonnes.

γj is the factor for converting a quantity of gas type (j) from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes, being:

                     (a)  for methane—6.784 × 10‑4 × GWPmethane; and

                     (b)  for carbon dioxide—1.861 × 10‑3; and

                     (c)  for any other gas type—the appropriate conversion factor for the gas type.

Qinj is the quantity of greenhouse gas injected into the storage or injection site during the year and measured in cubic metres at standard conditions of pressure and temperature.

RCCSj is the quantity of gas type (j) captured during the year worked out under Division 1.2.3 and measured in cubic metres at standard conditions of pressure and temperature. If the injection is part of enhanced oil recovery, Division 1.2.3 must be applied to enhanced oil recovery as if it was capture for permanent storage.

Division 3.4.3Injection of greenhouse gases

Subdivision 3.4.3.1Preliminary

3.93  Application

                   This Division applies to fugitive emissions of greenhouse gases from the injection of a greenhouse gas captured for permanent storage, or captured for enhanced oil recovery, into a geological formation.

Note:          A greenhouse gas is captured for permanent storage in a geological formation if the gas is captured by, or transferred to, the holder of a licence, lease or approval mentioned in section 1.19A, under a law mentioned in that section, for the purpose of being injected into a geological formation (however described) under the licence, lease or approval.

Note:          Section 1.8 defines enhanced oil recovery.

3.94  Available methods

             (1)  For estimating fugitive emissions of greenhouse gases released during a year from the injection of a greenhouse gas captured for permanent storage, or captured for enhanced oil recovery, into a geological formation, the methods set out in this section must be used.

Process vents, system upsets and accidents

             (2)  Method 2 under section 3.95 must be used for estimating fugitive emissions of greenhouse gases that result from deliberate releases from process vents, system upsets and accidents.

Fugitive emissions of greenhouse gases other than from process vents, system upsets and accidents

             (3)  One of the following methods must be used for estimating fugitive emissions of greenhouse gases from the injection of a greenhouse gas captured for permanent storage,  or captured for enhanced oil recovery, into a geological formation that are not the result of deliberate releases from process vents, system upsets and accidents:

                     (a)  method 2 under section 3.96;

                     (b)  method 3 under section 3.97.

Note:          There is no method 1, 3 or 4 for subsection (2) and no method 1 or 4 for subsection (3).

Subdivision 3.4.3.2Fugitive emissions from deliberate releases from process vents, system upsets and accidents

3.95  Method 2—fugitive emissions from deliberate releases from process vents, system upsets and accidents

                   Method 2 is the same as the approach mentioned in section 5.3 or 5.7.1 of the API Compendium.

Subdivision 3.4.3.3Fugitive emissions from injection of greenhouse gases (other than emissions from deliberate releases from process vents, system upsets and accidents)

3.96  Method 2—fugitive emissions from injection of a greenhouse gas into a geological formation (other than deliberate releases from process vents, system upsets and accidents)

             (1)  Method 2 is:

where:

EFijk is the emission factor (j) measured in CO2‑e tonnes that passes through each equipment type (k) mentioned in section 6.1 of the API Compendium, if the equipment type was used in the injection of a greenhouse gas into the geological formation.

Eij is the fugitive emissions (j) from the injection of a greenhouse gas into a geological formation during the reporting year, measured in CO2‑e tonnes.

Σk is the emissions (j) measured in CO2‑e tonnes and estimated by summing up the emissions released from each equipment type (k) mentioned in section 6.1 of the API Compendium, if the equipment type was used in the injection of a greenhouse gas into the geological formation.

Qik is the total of the quantities of greenhouse gas measured in tonnes that pass through each equipment type (k) mentioned in section 6.1 of the API Compendium, if the equipment type was used in the injection of a greenhouse gas into the geological formation.

             (2)  For EFijk in subsection (1), the emission factors are:

                     (a)  the emission factors listed for the equipment type in section 6.1 of the API Compendium; or

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

3.97  Method 3—fugitive emissions from injection of greenhouse gases (other than deliberate releases from process vents, system upsets and accidents)

                   Method 3 is the same as an approach mentioned in Appendix C to the API Compendium.

Note:          For this method, any approach mentioned in Appendix C to the API Compendium may be used.

[19]         At the end of paragraph 4.1(2)(b)

Add:

                           (vii)  hydrogen production (see Division 4.3.7);

[20]         At the end of Part 4.3

Add:

 

Division 4.3.7Hydrogen production

4.60  Application

                   This Division applies to chemical industry hydrogen production if:

                     (a)  hydrogen is the main product at the facility; and

                     (b)  the hydrogen is for use outside the facility; and

                     (c)  the facility does not involve the production of ammonia with emissions reported under Division 4.3.1; and

                     (d)  the emissions from hydrogen production are not included under another method in this Determination applicable to one or more primary products from the facility.

4.61  Available methods

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

                     (a)  method 1 under section 4.62;

                     (b)  method 2 under section 4.62A;

                     (c)  method 3 under section 4.62B;

                     (d)  method 4 under Part 1.3.

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

4.62  Method 1—hydrogen production

             (1)  Method 1 is:

                  

where:

Eij is the emissions of carbon dioxide released from the production of hydrogen during the year measured in CO2‑e tonnes.

Qi is the quantity of each type of feedstock or type of fuel (i) consumed from the production of hydrogen during the year, measured in the appropriate unit and estimated using a criterion in Division 2.3.6 for gaseous fuels or Division 2.2.5 for solid fuels.

Note:          If more than one feedstock or type of fuel is used, the emissions of each feedstock or type of fuel are calculated and summed to determine the overall emissions.

ECi is the energy content factor for fuel type (i) used as a feedstock in the production of hydrogen during the year, estimated under section 6.5.

EFij is the carbon dioxide emission factor for each type of feedstock or type of fuel (i) used in the production of hydrogen during the year, including the effects of oxidation, measured in kilograms for each gigajoule according to source as mentioned in Part 1 or 2 of Schedule 1.

R is the quantity of carbon dioxide measured in tonnes derived from the production of hydrogen during the year, captured and transferred for use in the operation of another facility, estimated using an applicable criterion in Division 2.3.6 for gaseous fuels or Division 2.2.5 for solid fuels and in accordance with any other requirements of those Divisions.

             (2)  For the purposes of calculating R in subsection (1), if:

                     (a)  more than one fuel is consumed in the production of hydrogen; and

                     (b)  the carbon dioxide generated from the production of hydrogen is captured and transferred for use in the operation of another facility or captured for permanent storage;

the total amount of carbon dioxide that may be deducted in relation to the production of hydrogen is to be attributed to each fuel consumed in proportion to the carbon content of the fuel relative to the total carbon content of all fuel consumed in the production of hydrogen.

             (3)  However, if no fuel is used as a feedstock in the production of hydrogen the emissions of carbon dioxide released from the production of hydrogen during the year under this Division is taken to be zero.

Note:          Hydrogen can be produced by electrolysis without using fossil fuels as a feedstock. Other emissions from the combustion of fuels at the facility may need to be reported elsewhere under this Determination.

4.62A  Method 2hydrogen production

             (1)  Method 2 is:

                  

where:

Eij is the emissions of carbon dioxide released from the production of hydrogen during the year measured in CO2‑e tonnes.

Qi is the quantity of each type of feedstock or type of fuel (i) consumed from the production of hydrogen during the year, measured in the appropriate unit and estimated using an applicable criterion in Division 2.3.6 for gaseous fuels or Division 2.2.5 for solid fuels.

Note:          If more than one feedstock or type of fuel is used, the emissions of each feedstock or type of fuel are calculated and summed to determine the overall emissions.

ECi is the energy content factor for fuel type (i) used as a feedstock in the production of hydrogen during the year, estimated under section 6.5.

EFij is the carbon dioxide emission factor for each type of feedstock or type of fuel (i) used in the production of hydrogen during the year, including the effects of oxidation, measured in kilograms for each gigajoule according to source in accordance with subsection (2).

R is the quantity of carbon dioxide measured in tonnes derived from the production of hydrogen during the year, captured and transferred for use in the operation of another facility, estimated using an applicable criterion in Division 2.3.6 for gaseous fuels or Division 2.2.5 for solid fuels and in accordance with any other requirements of those Divisions.

γ is the factor 1.861 × 10‑3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes.

RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3.

             (2)  The method for estimating emission factors for gaseous fuels in Division 2.3.3, or for solid fuels in Division 2.2.3, apply for working out the factor EFij.

             (3)  For the purposes of calculating R in subsection (1), if:

                     (a)  more than one fuel is consumed in the production of hydrogen; and

                     (b)  the carbon dioxide generated from the production of hydrogen is captured and transferred for use in the operation of another facility or captured for permanent storage;

the total amount of carbon dioxide that may be deducted in relation to the production of hydrogen is to be attributed to each fuel consumed in proportion to the carbon content of the fuel relative to the total carbon content of all fuel consumed in the production of hydrogen.

4.62B  Method 3—hydrogen production

             (1)  Method 3 is the same as method 2 under section 4.62.

             (2)  In applying method 2 as method 3, the method for estimating emission factors for gaseous fuels in Division 2.3.4, or for solid fuels in Division 2.2.4, apply for working out the factor EFij.

[21]         Subsection 5.17(2)

Repeal the subsection, substitute:

             (2)  The site plan must:

                     (a)  be consistent with the provisions relating to landfill site plans included in the document entitled Landfill site plan and verification requirements (methods 2 and 3), published by the Clean Energy Regulator in June 2021; and

                     (b)  if the landfill has more than one sub‑facility zone—show the boundaries of each sub‑facility zone.

Note:         In 2021, the Landfill site plan and verification requirements (methods 2 and 3) were available at www.cleanenergyregulator.gov.au.

[22]         Subsection 5.17B(3)

Repeal the subsection, substitute:

             (3)  The report must include the details specified in the Landfill site plan and verification requirements (methods 2 and 3), published by the Clean Energy Regulator in June 2021, in relation to expert reports.

Note:         In 2021, the Landfill site plan and verification requirements (methods 2 and 3) were available at www.cleanenergyregulator.gov.au.

[23]         Subsection 8.6(1) (table items 33 and 34)

Repeal the items, substitute:

 

33

Crude oil

6

3

34

Plant condensate and other natural gas liquids not covered by another item in this table

7

9

 

[24]         Subsection 8.8(1) (table items 4 to 11)

Repeal the items, substitute:

 

4

Oil or gas exploration and development—flaring

25

5

Oil or gas exploration and development (other than flaring)

50

6

Crude oil production

50

7

Crude oil transport

50

8

Crude oil refining

50

9

Onshore natural gas production (other than emissions that are vented or flared)

50

10

Offshore natural gas production (other than emissions that are vented or flared)

50

11

Natural gas gathering and boosting (other than emissions that are vented or flared)

50

12

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)

50

13

Natural gas processing (other than emissions that are vented or flared)

50

14

Natural gas transmission (other than flaring)

50

15

Natural gas storage (other than emissions that are vented or flared)

50

16

Natural gas liquefaction, storage and transfer (other than emissions that are vented or flared)

50

17

Natural gas distribution (other than flaring)

50

18

Onshore natural gas production—venting

50

19

Offshore natural gas production—venting

50

20

Onshore natural gas production—flaring

25

21

Offshore natural gas production—flaring

25

22

Natural gas gathering and boosting—venting

50

23

Natural gas gathering and boosting—flaring

25

24

Natural gas processing—venting

50

25

Natural gas processing—flaring

25

26

Natural gas transmission—flaring

25

27

Natural gas storage—venting

50

28

Natural gas storage—flaring

25

29

Natural gas liquefaction, storage and transfer—venting

50

30

Natural gas liquefaction, storage and transfer—flaring

25

31

Natural gas distribution—flaring

25

[25]         After section 9.13

                   Insert:

9.14  Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2021 Update) Determination 2021

                   The amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2021 Update) Determination 2021 apply in relation to:

                     (a)  the financial year starting on 1 July 2021; and

                     (b)  later financial years.

[26]         Part 3 of Schedule 1 (table items 33 and 34)

Repeal the items, substitute:

33

Crude oil

45.3 GJ/t

69.6

0.08

0.2

34

Plant condensate and other natural gas liquids not covered by another item in this table

46.5 GJ/t

61.0

0.08

0.2

[27]         Part 6 of Schedule 1

Repeal the Part, substitute:

Part 6Indirect (scope 2) emission factors from consumption of electricity purchased or lost from grid

  

Indirect (scope 2) emissions factors from consumption of electricity purchased or lost from grid

Item

Column 1

State, Territory or grid description

Column 2

Emission factor
kg CO2‑e/kWh

77

New South Wales and Australian Capital Territory

0.79

78

Victoria

0.96

79

Queensland

0.80

80

South Australia

0.35

81

South West Interconnected System in Western Australia

0.68

82

Tasmania

0.16

83

Northern Territory

0.57

 

[28]         Part 3 of Schedule 3

Repeal the items, substitute:

33

Crude oil

0.861 tC/t fuel

34

Plant condensate and other natural gas liquids not covered by another item in this table

0.774 tC/t fuel

 

[29]         After Schedule 3

Add:

 

Schedule 4Matters to be identified for sources

(See subsection 1.4(3) and regulations 4.10, 4.11, 4.13, 4.14, 4.15 and 4.17 of the Regulations)

Part 1Coal mining

Source 2A—Underground mine

 

Item

Method

Matters to be identified

1

Method 1 for the source, as set out in sections 3.5 and 3.17

(a) the location of the mine by State or Territory

(b) whether the mine is a gassy mine or a non‑gassy mine

(c) the tonnes of raw coal produced

(d) the tonnes of coal mine waste gas (CO2‑e) flared

2

Method 4 for the source, as set out in section 3.6

(a) the location of the mine by State or Territory

(b) the tonnes of raw coal produced

(c) the tonnes of methane (CO2‑e) and the tonnes of carbon dioxide captured for energy production on site

 

 

(d) the tonnes of methane (CO2‑e) and the tonnes of carbon dioxide captured and transferred off site

(e) the tonnes of methane (CO2‑e) and the tonnes of carbon dioxide flared

 

Source 2B—Open cut mine

 

Item

Method

Matters to be identified

1

Method 1 for the source, as set out in section 3.20

(a) the location of the mine by State or Territory

(b) the tonnes of raw coal produced

(c) the tonnes of coal mine waste gas flared

2

Methods 2 and 3 for the source, as set out in sections 3.21 and 3.26

(a) the location of the mine by State or Territory

(b) the tonnes of raw coal produced

(c) the tonnes of methane (CO2‑e) and the tonnes of carbon dioxide captured for energy production on site

 

 

(d) the tonnes of methane (CO2‑e) and the tonnes of carbon dioxide captured and transferred off site

(e) the tonnes of methane (CO2‑e) and the tonnes of carbon dioxide flared

(f) the tonnes of methane (CO2‑e) and the tonnes of carbon dioxide vented

Source 2C—Decommissioned underground mine

 

Item

Method

Matters to be identified

1

Method 1 for the source, as set out in section 3.32

(a) the location of the mine by State or Territory

(b) whether the mine is a gassy mine or a non‑gassy mine

(c) the tonnes of methane emissions (CO2‑e) from the mine in the last 12 month period before the mine became a decommissioned underground coal mine

 

 

(d) the date that the mine was decommissioned

(e) the percentage of the mine void volume flooded

(f) the tonnes of coal mine waste gas (CO2‑e) flared

2

Method 4 for the source, as set out in section 3.37

(a) the location of the mine by State or Territory

(b) the tonnes of methane (CO2‑e) and the tonnes of carbon dioxide captured for energy production on site

 

 

(c) the tonnes of methane (CO2‑e) and the tonnes of carbon dioxide captured and transferred off site

(d) the tonnes of methane (CO2‑e) and the tonnes of carbon dioxide flared

Part 2Oil or gas

 

Source 2D—Oil or gas exploration and development—flaring

 

Item

Method

Matters to be identified

1

Method 1 for the source, as set out in section 3.44

(a) the tonnes of flared gas

(b) the tonnes of flared crude oil and liquids

2

Methods 2, 2A and 3 for the source, as set out in sections 3.45, 3.45A and 3.46

(a) the tonnes and megajoules of flared gas (hydrocarbon component)

(b) the tonnes and megajoules of flared crude oil and liquids (hydrocarbon component)

 

Source 2E—Oil or gas exploration and development (other than flaring)

 

Item

Method

Matters to be identified

1

Method 1 for the source, as set out in sections 3.46AB, 3.56B, 3.85B and 3.85P

(a) the tonnes and megajoules of vented gas for each gas type

(b) number of well completions of each type

 

 

Method 4 for the source, as set out in section 3.46B and Part 1.3

(a) the tonnes and megajoules of vented gas for each gas type

 

Source 2F—Crude oil production

 

Item

Method

Matters to be identified

1

Methods 1 and 2 for the source (leak emissions), as set out in sections 3.49 and 3.50

(a) the tonnes of crude oil throughput

 

2

Method 3 for the source (leak emissions), as set out in section 3.51

(a) the tonnes of crude oil throughput

(b) number of components of each component type

(c) average hours of operation of each component type

(d) total emissions of each gas type from each component type

3

Method 1 for the source (flaring), as set out in section 3.53

(a) the tonnes of flared gas

(b) the tonnes of flared crude oil and liquids

4

Methods 2, 2A and 3 for the source (flaring), as set out sections 3.54, 3.54A and 3.55

(a) the tonnes and megajoules of flared gas (hydrocarbon component)

(b) the tonnes and megajoules of flared crude oil and liquids (hydrocarbon component)

5

Method 1 for the source (venting), as set out in section 3.56B

(a) the tonnes and megajoules of vented gas for each gas type

(b) number workovers of each event type

6

Method 4 for the source (venting), as set out in Part 1.3

(a) the tonnes and megajoules of vented gas for each gas type

 

 

Source 2G—Crude oil transport

 

Item

Method

Matters to be identified

1

Methods 1 and 2 for the source, as set out in section 3.59 and 3.60

the tonnes of indigenous crude oil transported to Australian refineries

 

Source 2H—Crude oil refining

 

Item

Method

Matters to be identified

1

Methods 1, 2, and 3 for the source (refining and storage tanks), as set out in sections 3.64, 3.65 and 3.66

(a) the tonnes of crude oil refined

(b) the tonnes of crude oil stored

 

2

Method 4 for the source (vents, system upsets and accidents), as set out in section 3.68

(a) the quantity of refinery coke burnt

 

3

Method 1 for the source (flaring), as set out in section 3.69

(a) the tonnes of flared gas

(b) the tonnes of flared crude oil and liquids

4

Methods 2, 2A and 3 for the source (flaring), as set out in sections 3.70, 3.70A and 3.71.

(a) the tonnes and megajoules of flared gas (hydrocarbon component)

(b) the tonnes and megajoules of flared crude oil and liquids (hydrocarbon component)

 

Source 2I—Onshore natural gas production (other than emissions that are vented or flared)

 

Item

Method

Matters to be identified

1

Method 1 for the source, as set out in the section 3.73A

(a) the tonnes of onshore natural gas production throughput

(b) the total number of wells (including producing wells and suspended wells but not decommissioned wells)

2

Method 2 for the source, as set out in the section 3.73B

(a) the tonnes of onshore natural gas production throughput

(b) number of equipment units of each equipment type

(c) average hours of operation of each equipment type

(d) total emissions for each gas type (CO2-e) for each equipment type

3

Method 3 for the source, as set out in the section 3.73C

(a) the tonnes of onshore natural gas production throughput

(b) the total number of wells (including producing wells and suspended wells but not decommissioned wells)

(c) number of components of each component type (by leaker or non-leaker if LDAR factors are elected)

(d) average hours of operation of each component type (by leaker or non-leaker if LDAR factors are elected)

(e) total emissions for each gas type (CO2-e) for each component type (by leaker or non-leaker if LDAR factors are elected)

(f) if LDAR factors are elected—the standard used to detect leakers

 

Source 2J—Offshore natural gas production (other than emissions that are vented or flared)

 

Item

Method

Matters to be identified

1

Method 1 for the source, as set out in the section 3.73F

(a) the tonnes of offshore natural gas production throughput

(b) the total number of offshore platforms (shallow water)

(c) the total number of offshore platforms (deep water)

2

Method 2 for the source, as set out in section 3.73G

(a) the tonnes of offshore natural gas production throughput

(b) the total number of offshore platforms (shallow water)

(c) the total number of offshore platforms (deep water)

(d) number of equipment units of each equipment type

(e) average hours of operation of each equipment type

(f) total emissions for each gas type (CO2-e) for each equipment type

3

Method 3 for the source, as set out in section 3.73H

(a) the tonnes of offshore natural gas production throughput

(b) the total number of offshore platforms (shallow water)

(c) the total number of offshore platforms (deep water)

(d) number of components of each component type (by leaker or non-leaker if LDAR factors are elected)

(e) average hours of operation of each component type (by leaker or non-leaker if LDAR factors are elected)

(f) total emissions for each gas type (CO2-e) for each component type (by leaker or non-leaker if LDAR factors are elected)

(g) if LDAR factors are elected—the standard used to detect leakers

 

Source 2K—Natural gas gathering and boosting (other than emissions that are vented or flared)

 

Item

Method

Matters to be identified

1

Method 1 for the source, as set out in section 3.73K

(a) number of natural gas gathering and boosting stations

(b) the tonnes of natural gas gathering and boosting throughput for each station

 (c) kilometres of pipeline length

2

Method 2 for the source, as set out in section 3.73L

Stations

(a) number of natural gas gathering and boosting stations

(b) the tonnes of natural gas gathering and boosting throughput for each station

(c) number of equipment units of each equipment type

(d) average hours of operation of each equipment type

(e) total emissions for each gas type (CO2-e) for each equipment type

Pipelines

(f) kilometres of pipeline length of each material

(g) total emissions for each gas type (CO2-e) for each material

3

Method 3 for the source, as set out in section 3.73M

Stations

(a) number of natural gas gathering and boosting stations

(b) the tonnes of natural gas gathering and boosting throughput for each station

(c) number of components of each type (by leaker or non-leaker if LDAR factors are elected)

(d) average hours of operation of each component type (by leaker or non-leaker if LDAR factors are elected)

(e) total emissions for each gas type (CO2-e) for each component type (by leaker or non-leaker if LDAR factors are elected)

(f) if LDAR factors are elected—the standard used to detect leakers

Pipelines

(g) kilometres of pipeline length of each material

(h) total emissions for each gas type (CO2-e) for each material

 

Source 2L—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)

 

Item

Method

Matters to be identified

1

Method 1 for the source, as set out in section 3.73NA

megalitres of produced water

2

Method 2 for the source, as set out in section 3.73NB

(a) megalitres of produced water

(b) average pressure in kilopascals for a water stream entering the separator during the year (or equivalent if no separator)

(c) average salinity content of the water

 

Source 2M—Natural gas processing (other than emissions that are vented or flared)

 

Item

Method

Matter