Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere
Environment Quality Act
(chapter Q-2, ss. 2.2, 46.2, 115.27, 115.34 and 124.1)1. This Regulation applies to every operator whose enterprise, facility or establishment emits a contaminant listed in Schedules A and A.1 into the atmosphere at a level that is equal to or greater than the reporting threshold prescribed for the contaminant.
The provisions of this Regulation apply in a reserved area or an agricultural zone established under the Act respecting the preservation of agricultural land and agricultural activities (chapter P-41.1).
M.O. 2007-09-26, s. 1; M.O. 2010-12-06, s. 1.
2. In the perspective of ensuring supervision of the quality of the environment in relation to phenomena that increase the greenhouse effect, acid rain, smog and toxic pollution, and of drawing up an inventory of certain contaminants emitted into the atmosphere, this Regulation determines the thresholds over which enterprises, facilities or establishments are required to report their emissions in relation to the contaminants associated with those phenomena. It also determines the information to be provided, including confidential information that is necessary to calculate the quantity of the contaminants emitted, such as data pertaining to production, fuels, raw materials, equipment and processes.
M.O. 2007-09-26, s. 2; M.O. 2010-12-06, s. 2.
(0.1) “biomass fuels” means any fuel whose entire heat generating capacity is derived from biomass;
(0.2) “biomass” means a non-fossilized plant or part of a plant, an animal carcass or part of an animal, manure or liquid manure, a micro-organism and any other product derived from such matters;
(0.3) “standard conditions” means a temperature of 20 °C and a pressure of 101.325 kPa;
(0.4) “flexigas” means a gaseous fuel with a low calorific value produced through the gasification of coke;
(1) “total fluorides” means the sum of fluorides emitted as gases and fluorides emitted as particles;
(1.1) “associated gas” means a natural gas which is found in association with crude oil, either dissolved in crude oil or as a cap of free gas above the crude oil;
(2) “Minister” means the Minister of Sustainable Development, Environment and Parks;
(3) “process” means any method, reaction or operation through which the matter treated undergoes a physical or chemical change in the same production line and includes all successive operations on a single matter bringing about the same type of physical change;
(4) “reporting threshold” means the quantity of a contaminant or a category of contaminants emitted by an enterprise, facility or establishment, expressed in reference to certain parameters, in excess of which the operator of the enterprise, facility or establishment must report its emission level.
For the application of Division II.1,
(1) “CO2 emissions attributable to fixed processes” means the CO2 emissions resulting form a fixed chemical process reaction producing CO2 from carbon in a chemical bond in the raw material and carbon used to withdraw an unwanted component of the raw material where there is no substitutable raw material;
(2) “greenhouse gas emissions attributable to combustion” means greenhouse gas emissions related to an exothermic reaction of a fuel;
(3) “other category greenhouse gas emissions” means greenhouse gas emissions other than emissions attributable to fixed processes and emissions attributable to combustion.
Last, for the application of this Regulation to a closed landfill site, a person or municipality is considered to operate the site until such time as it is released from its environmental monitoring and maintenance obligations under section 85 of the Regulation respecting the landfilling and incineration of residual materials (chapter Q-2, r. 19).
M.O. 2007-09-26, s. 3; M.O. 2010-12-06, s. 3; M.O. 2011-12-16, s. 1; M.O. 2012-12-11, s. 1.
DIVISION II
STANDARDS FOR THE MANDATORY REPORTING OF EMISSIONS OF CERTAIN CONTAMINANTS RESPONSIBLE FOR TOXIC POLLUTION, ACID RAIN AND SMOG INTO THE ATMOSPHERE
STANDARDS FOR THE MANDATORY REPORTING OF EMISSIONS OF CERTAIN CONTAMINANTS RESPONSIBLE FOR TOXIC POLLUTION, ACID RAIN AND SMOG INTO THE ATMOSPHERE
M.O. 2007-09-26, Div. II; M.O. 2010-12-06, s. 4.
4. Every person or municipality operating establishment that emits a contaminant listed in Part I of Schedule A into the atmosphere in a quantity that reaches or exceeds the reporting threshold set out in that Schedule for the contaminant or category of contaminants must, not later than 1 June of each year, communicate to the Minister by electronic means, using the form available on-line on the website of the Ministère du Développement durable, de l'Environnement, de la Faune et des Parcs, the quantity of each of the contaminants listed in Part I of Schedule A that the establishment emitted into the atmosphere in the preceding calendar year.
The operator must also identify the activities, processes or equipment that are the source of contaminant emissions, by specifying separately for each of them the emissions attributable to them, the quantity of fuel and raw materials used and the volume of production that have been used in calculating the quantities of contaminants.
Furthermore, the operator must provide the Minister with the methods of calculation or assessment referred to in the second paragraph of section 6 that were used as well as any information relevant to the calculations, including the factors and emission rates used, their source and, if they originate in published documents, the applicable reference.
For the purposes of the second paragraph, fuels integral to a process or used to supply transportation machinery integral to a process must be taken into account, as must fuels used to heat facilities.
For the purposes of this section, if an establishment has more than one facility, the data pertaining to each facility must be identified separately. In all cases, the operator must identify the activities, processes or equipment that are the source of contaminant emissions by indicating separately.
In addition, when an facility or an establishment changes operator during a year, the report must be made by the new operator. The previous operator must provide the new operator with all the data required for the report for the period of the year for which the facility or establishment was under his or her responsibility.
M.O. 2007-09-26, s. 4; M.O. 2010-12-06, s. 5; M.O. 2011-12-16, s. 2; M.O. 2012-12-11, s. 2; M.O. 2013-12-11, s. 1.
5. If the operator of the facility or establishment is required, under a public notice given pursuant to section 46 of the Canadian Environmental Protection Act (1999) (S.C. 1999, c. 33), to report to the Minister of the Environment of Canada for a contaminant listed in Part II of Schedule A, the operator must, not later than 1 June each year, transmit to the Minister by electronic means, using the form available on-line on the website of the Ministère du Développement durable, de l'Environnement, de la Faune et des Parcs, the quantity of any of those contaminants that the facility or establishment emitted into the atmosphere in the preceding calendar year.
The operator must also identify the activities, processes or equipment that are the source of contaminant emissions, by specifying separately for each of them the emissions attributable to them, the quantity of fuel and raw materials used and the volume of production that have been used in calculating the quantities of contaminants reported to the Minister of the Environment of Canada.
Furthermore, the operator must provide the Minister with the methods of calculation or assessment referred to in the second paragraph of section 6 that were used as well as any information relevant to the calculations, including the factors and emission rates used, their origin and, if they originate in published documents, the applicable reference.
M.O. 2007-09-26, s. 5; M.O. 2010-12-06, s. 6; M.O. 2011-12-16, s. 3; M.O. 2012-12-11, s. 3; M.O. 2013-12-11, s. 2.
5.1. The operator referred to in section 4 or 5 must include the following information with the information referred to in those sections:
(1) the name of and contact information for the enterprise, facility or establishment as well as the name of and contact information for its representative;
(2) the business number assigned to the operator when registered under the Act respecting the legal publicity of enterprises (chapter P-44.1) as well as the ID number assigned under the National Pollutant Release Inventory of the Government of Canada;
(3) the type of enterprise, facility or establishment operated, the activities pursued and processes and equipment used as well as, where applicable, the 6-digit code under the North American Industry Classification System (NAICS Canada);
(4) the name of and contact information for the person responsible for the contaminants emissions report for the enterprise, facility or establishment.
M.O. 2012-12-11, s. 4.
5.2. When the emissions of contaminants from an establishment reported in accordance with section 4 or 5 fall below the reporting threshold the following year, the operator of the establishment must, not later than 1 June following the first year in which the emissions are below the threshold, send a notice to the Minister including the following information and documents:
(1) the information referred to in section 5.1;
(2) an attestation that the emissions of contaminants referred to in Schedule A are below the reporting threshold;
(3) the reason for the reduction in emissions of contaminants;
(4) the signature of the person responsible for the declaration at the establishment.
M.O. 2012-12-11, s. 4.
6. The information communicated pursuant to section 4 or the second paragraph of section 5 must be based on the best data and best information the operator of the facility or establishment has, may reasonably be expected to have or may obtain by means of appropriate data processing.
The information may be based on one of the following methods of calculation or assessment:
(1) a continuous emission monitoring and recording system;
(2) a mass balance which, in the case of greenhouse gas emissions, must calculate or assess the emissions attributable to matters that contribute 0.5% or more of the total carbon introduced in the process at the facility or establishment;
(3) a technical calculation using an emission factor published in scientific documents;
(4) a technical calculation using an emission rate resulting from an emissions sampling; or
(4.1) a model for the estimation of emissions;
(5) (paragraph replaced);
(6) (paragraph replaced).
In addition, unless otherwise indicated, the data required under this Regulation must be in metric units.
An emissions report made under section 4 or 5 must be signed by the person responsible for the report at the enterprise, facility or establishment, who must also attest to the veracity of the information communicated.
M.O. 2007-09-26, s. 6; M.O. 2010-12-06, s. 7; M.O. 2011-12-16, s. 4; M.O. 2012-12-11, s. 5.
DIVISION II.1
STANDARDS FOR THE MANDATORY REPORTING OF CERTAIN EMISSIONS OF GREENHOUSE GASES INTO THE ATMOSPHERE
STANDARDS FOR THE MANDATORY REPORTING OF CERTAIN EMISSIONS OF GREENHOUSE GASES INTO THE ATMOSPHERE
M.O. 2010-12-06, s. 8.
6.1. Every person or municipality operating an establishment that, during a calendar year, emits into the atmosphere greenhouse gases mentioned in Schedule A.1 in a quantity equal to or greater than 10,000 metric tons CO2 equivalent must report those emissions to the Minister in accordance with this Division until such time as the emissions have been below the reporting threshold for 4 consecutive years.
Every person or municipality operating an enterprise that purchases electricity produced outside Québec for its own consumption or for sale in Québec must also report the emissions attributable to the production of that electricity, under the first paragraph. For such an emitter, and for an emitter that exports, transports or distributes electricity, an enterprise that transports or distributes natural gas, or an enterprise that carries on gas or oil exploration or production, the reporting threshold provided for in the first paragraph applies to the enterprise as a whole.
Every person or municipality operating an enterprise that, during a calendar year, distributes fuel and is referred to in part QC.30.1 of protocol QC.30 in Schedule A.2 and for which greenhouse gas emissions attributable to their use, are equal to or exceed 25,000 metric tons CO2 equivalent, to report the emissions to the Minister in accordance with this Division until the emissions have been below the reporting threshold for 4 consecutive years.
For the purposes of this Division, an enterprise operated by an emitter referred to in the second and third paragraphs is considered to be an establishment.
When an establishment referred to in the first paragraph has more than one facility, the data for each facility must be identified separately.
In addition, when an enterprise, a facility or an establishment changes operator during a year, the declaration must be made by the new operator. The previous operator must provide the new operator with all the data required for the report for the period of the year for which the enterprise, facility or establishment was under his or her responsibility.
When an emitter referred to in the first, second or third paragraph permanently closes an establishment for which the greenhouse gas emissions reached or exceeded the reporting threshold during the preceding calendar year, it must, within 6 months of closing the establishment, send to the Minister an emissions report for the period during which the establishment was operating but was not covered by such a report.
M.O. 2010-12-06, s. 8; M.O. 2011-12-16, s. 5; M.O. 2012-09-05, s. 1; M.O. 2012-12-11, s. 6; M.O. 2013-12-11, s. 3.
6.2. An emitter referred to in section 6.1 must, not later than 1 June each year, communicate to the Minister by electronic means, using the form available on-line on the website of the Ministère du Développement durable, de l'Environnement, de la Faune et des Parcs, a greenhouse gas emissions report for the preceding calendar year, including
(1) the total quantity of the emitter's greenhouse gas emissions in metric tons CO2 equivalent, excluding greenhouse gas emissions captured, stored, re-used, eliminated or transferred out of the establishment and emissions reported in accordance with protocols QC.17 and QC.30 of Schedule A.2, calculated using the following equation:
Where:
CO2e = Total Annual greenhouse gas emissions, in metric tons of carbon dioxide equivalent;
GHGi = Total Annual emissions of each greenhouse gas emitted, in metric tons;
GWPi = Global warming potential indicated in Schedule A.1 for each greenhouse gas emitted;
n = Number of greenhouse gases emitted;
i = Type of greenhouse gas emitted.
The total quantity of CO2 equivalent calculated pursuant to this subparagraph must be rounded up to the next highest whole number;
(2) the total quantity of emissions of each type of greenhouse gas referred to in Schedule A.1, in metric tons, excluding greenhouse gas emissions captured, stored, re-used, eliminated or transferred out of the establishment, and emissions reported in accordance with protocols QC.17 and QC.30 of Schedule A.2;
(2.1) in the case of a person or municipality operating an establishment that distributes fuel, the quantity of greenhouse gas emissions attributable to the combustion or use of the fuel distributed in metric tons CO2 equivalent;
(2.2) in the case of a person or municipality operating an enterprise that purchases electricity produced outside Québec for its own consumption or for sale in Québec, the quantity of greenhouse gas emissions attributable to the production of that electricity, in metric tons CO2 equivalent;
(2.3) for establishments in the sectors referred to in Appendix A to the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1), the total quantity of the emitter's greenhouse gas emission in metric tons CO2 equivalent, excluding emissions captured, stored, re-used or transferred out of the establishment, emissions referred to in the second paragraph of section 6.6 and emissions calculated in accordance with protocols QC.17 and QC.30 of Schedule A.2;
(3) all information prescribed in Schedule A.2 concerning the type of the emitter's enterprise, facility or establishment and, where applicable, the type of activity pursued and the type of process or equipment used;
(4) the total quantity of CO2 emissions attributable to the combustion of biomass and biofuels in metric tons;
(4.1) the total quantity of CO2 emissions attributable to the use of biomass and biomass fuels for purposes other than combustion, in metric tons;
(4.2) the quantity and description of biomass used, for each of the following categories:
(a) forest biomass, specifying the quantity and description of each of the following types of waste:
(i) primary forest waste, namely waste from forest management activities such as parts of trees, residual trees, commercial and non-commercial tree sections, branches and foliage;
(ii) secondary forest waste, namely waste from industrial process and related products such as woodchips, sawdust, shavings and bark;
(iii) tertiary forest waste, namely waste from construction, demolition and packing processes;
(b) agricultural biomass, specifying the quantity and description of each of the following types of waste:
(i) animal waste;
(ii) plant waste;
(c) municipal biomass;
(d) any other type of biomass not referred to in subparagraphs a to c;
(5) the total quantity of emissions of each greenhouse gas that is captured, stored, re-used, eliminated or transferred out of the establishment and the quantity of emissions generated by each operation, in metric tons, along with the contact information of each operating or transfer site;
(6) the calculation methods used in accordance with section 6.3;
(7) in the case of types of enterprise, facility or establishment or types of activity, process or equipment not covered by a specific protocol in Schedule A.2 or for which greenhouse gas emissions have been calculated in accordance with the second paragraph of section 6.3:
(a) the quantity of emissions of each type of greenhouse gas referred to in Schedule A.1 attributable to each type of activity or the use or each type of process or equipment in metric tons, excluding greenhouse gas emissions captured, stored, re-used, eliminated or transferred out of the establishment;
(b) the CO2 emissions attributable to the combustion or use of biomass or biomass fuels, in metric tons;
(c) the emission factors or rates used and their origin, reference or method of determination;
(8) in the case of an emitter referred to in section 6.6:
(a) the total annual quantity of benchmark units relating to the emitter's activities;
(b) for each benchmark unit, the total greenhouse gas emissions for each type of emission, excluding emissions referred to in the second paragraph of section 6.6 and the emissions calculated in accordance with protocols QC.17 and QC.30 of Schedule A.2, namely:
(i) the fixed process CO2 emissions, in metric tons;
(ii) the annual greenhouse gas combustion emissions, in metric tons CO2 equivalent;
(iii) the annual other category greenhouse gas emissions, in metric tons CO2 equivalent;
(9) (subparagraph revoked).
When the facility or establishment is equipped with a continuous CO2 monitoring system and when the emitter must, in accordance with this Regulation, indicate emissions by type, whether combustion, fixed process or “other”, the emitter must, for each type of emission,
(1) estimate the greenhouse gas combustion emissions and the “other” category emissions using the emission factors in tables 1-1 to 1-8 in QC.1.7 of Schedule A.2. If no factor is indicated in the tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA), the Intergovernmental Panel on Climate Change (IPCC), the National Council for Air and Stream Improvement (NCASI) or the World Business Council for Sustainable Development (WBCSD);
(2) determine the annual fixed process greenhouse gas emissions by subtracting from the data measured by the continuous CO2 monitoring system the greenhouse gas combustion emissions and the “other” category emissions estimated in accordance with subparagraph 1.
The greenhouse gas emissions report referred to in the first paragraph must be signed by the person responsible for the report at the enterprise, facility or establishment, who must also attest to the veracity of the information communicated.
M.O. 2010-12-06, s. 8; M.O. 2011-12-16, s. 6; M.O. 2012-09-05, s. 2; M.O. 2012-12-11, s. 7; M.O. 2012, s. 7; M.O. 2013-12-11, s. 4.
6.3. The quantities of greenhouse gas emissions reported under the first paragraph of section 6.2 must be calculated using the protocols prescribed in Schedule A.2 corresponding to the type of enterprise, facility or establishment operated and, where applicable, the type of activity pursued and the process or equipment used.
Notwithstanding the first paragraph, an emitter may use one of the calculation or assessment methods referred to in the second paragraph of section 6
(1) to calculate the greenhouse gas emissions from one or more sources of emissions when the emissions attributable to them represent no more than 3% of total emissions from the establishment in CO2 equivalent, up to a maximum of 20,000 metric tons CO2 equivalent; or
(2) if no protocol is prescribed in Schedule A.2 for the type of enterprise, facility or establishment operated, for the type of activity pursued, for the type of process or equipment used or for the type of greenhouse gas emitted.
The emitter must use the same calculation method and perform 100% of the data sampling and measurement in accordance with that method for each report year. However, as soon as an emitter's situation no longer corresponds to one of the cases referred to in the second paragraph, the emitter must change the calculation method for the protocols referred to in the first paragraph.
Notwithstanding the second and third paragraphs, when the emitter's enterprise, facility or establishment is equipped with a continuous emission monitoring and recording system to measure the parameters needed to calculate greenhouse gas emissions or when such a system is installed during their operation, the emitter must used use the calculation methods applicable to that system.
M.O. 2010-12-06, s. 8; M.O. 2012-09-05, s. 3; M.O. 2012-12-11, s. 8; M.O. 2013-12-11, s. 5.
6.3.1. When an emitter, as part of its sampling activities, is unable to obtain analytical data, it must replace the missing data.
For that purpose, the emitter must apply the applicable method for the estimation of missing data specified in the calculation method prescribed by the applicable protocol in Schedule A.2 or, if the emitter uses a method of calculation or assessment referred to in the second paragraph of section 6, the emitter must demonstrate that everything has been done to capture 100% of the data and then apply the following method:
(1) when the missing data concern carbon content, temperature, pressure or any other data that is sampled or analyzed, the emitter must analyze again, using the prescribed method, the original sample, a backup sample or a replacement sample for the same measurement and sampling period. If it is not possible to obtain valid data, the emitter must use replacement data established
(a) by determining the sampling or measurement rate using the following equation:
R = QSAct/QSRequired
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QSAct = Quantity of actual samples or measurements obtained by the emitter using the calculation or assessment method used by the emitter;
QSRequired = Quantity of samples or measurements required to be obtained by the emitter using that method;
(b) for data that require sampling or analysis, the emitter must
(i) if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data is available from before that period, the emitter must use the first available data from after the period for which the data is missing;
(ii) if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
(iii) if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(2) when the missing data concern a quantity of raw materials, such as fuel consumption, a quantity of material, a production quantity or a quantity of reference units, the replacement data must be estimated on the basis of all the data relating to the processes used;
(3) when the missing data are data from a continuous emission monitoring and recording system, the emitter must determine the replacement data using the procedure indicated in protocol SPE 1/PG/7 entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or applying to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6 of Schedule A.2.
M.O. 2012-09-05, s. 4.
6.4. An emitter referred to in section 6.1 must submit, with the information communicated pursuant to section 6.2, the following information:
(1) the name of and contact information for the enterprise, facility or establishment as well as the name of and contact information for its representative;
(2) (pargraph revoked);
(3) the business number assigned to the emitter when registered under the Act respecting the legal publicity of enterprises (chapter P-44.1) as well as the ID number assigned under the National Pollutant Release Inventory of the Government of Canada;
(4) the type of enterprise, facility or establishment operated and, where applicable, the activities pursued and processes and equipment used as well as, where applicable, the 6-digit code under the North American Industry Classification System (NAICS Canada);
(5) the name of and contact information for the person responsible for the greenhouse gas emissions report for the enterprise, facility or establishment.
M.O. 2010-12-06, s. 8; M.O. 2012-12-11, s. 9.
6.5. An emitter whose annual greenhouse gas emissions report includes one or more errors or omissions must, as soon as possible, communicate a notice of correction to the Minister containing the following information:
(1) a description of the corrections to be made to the initial report;
(2) the circumstances that led to the errors or omissions and, where application, the corrections made;
(3) where applicable, an estimate of the quantity of greenhouse gas emissions represented by the errors or omissions.
M.O. 2010-12-06, s. 8; M.O. 2012-12-11, s. 10.
6.6. An emitter referred to in section 2 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1) who, in accordance with section 6.2, reports annual greenhouse gas emissions equal to or greater than 25,000 metric tons CO2 equivalent, excluding emissions referred to in the second paragraph, must, not later than 1 June, send to the Minister a verification report on the emissions report, carried out by an organization accredited to ISO 14065, by a member of the International Accreditation Forum and in compliance with an ISO-17011 program, for the emitter's sector of activity.
For the purposes of the verification threshold referred to in the first paragraph, the following emissions are excluded and do not need to be verified:
(1) CO2 emissions attributable to the combustion or use of biomass and biomass fuels;
(2) CH4 emissions attributable to coal storage and referred to in QC.5.3 in Schedule A.2;
(3) CO2, CH4 and N2O emissions attributable to mobile equipment on the site of an establishment and referred to in QC.27 in Schedule A.2;
(3.1) CO2, CH4 and N2O emissions attributable to residual materials landfill;
(4) until 31 December 2014, CH4 emissions attributable to petroleum refinery operations and referred to in QC.9.3.6, QC.9.3.9 and QC.9.3.12 in Schedule A.2;
(5) until 31 December 2014, CH4 and N2O emissions attributable to the anaerobic treatment of wastewater, including those and referred to in Schedule A.2, specifically in QC.9.3.7 in the case of a petroleum refinery, QC.10.2.7 in the case of a pulp and paper plant, and QC.12.3.7 in the case of petrochemical product manufacturing;
(6) until 31 December 2014, CO2, CH4 and N2O emissions attributable to the transmission and distribution of natural gas and referred to in QC.29.3.1, QC.29.3.2, QC.29.3.7, QC.29.3.8, QC.29.3.9 and QC.29.3.11 in Schedule A.2;
(7) until 31 December 2014, CO2, CH4 and N2O emissions attributable to oil and gas exploration and production and natural gas processing, as referred to in QC.33.3.1, QC.33.3.2, QC.33.3.8, QC.33.3.16, QC.33.3.17 and QC.33.3.20 in Schedule A.2.
The emitter must have the annual report verified by a verifying organization and a verifier designated by that organization that also meets the following requirements:
(1) this organization and this verifier have not acted as consultants for the emitter for the quantification or greenhouse gas emissions report or have not provided a service referred to in subparagraph 3 of the first paragraph of section 6.10 during the 3 preceding years;
(2) this organization and this verifier have not verified more than 6 of the emitter’s consecutive annual reports since the 2012 emissions report; and
(3) where the emitter wishes to have the verification of the annual report done by a verifying organization or verifier other than the organization or verifier that verified the report the preceding year, the verifying organization or verifier must not have verified the emissions report for that establishment during the 3 previous years.
An emitter must have the emitter’s annual report verified until such time as the emitter’s greenhouse gas emissions fall below the verification threshold provided for in the first paragraph for 4 consecutive years.
Despite the first paragraph, the verification report on the emissions report for 2012 may be sent to the Minister not later than 1 September 2013.
Despite the first paragraph, the verification report on the emissions report for 2012 or 2013 may be made by a verification organization in the process of being accredited so long as this organization receives its accreditation not later than 31 December of the year in which the emitter's verification report is sent.
If the organization fails to receive its accreditation within the time period specified in the sixth paragraph, the emitter must, not later than 1 April following the end of that period, send to the Minister a new verification report of its emissions report made by an organization accredited in accordance with the first paragraph.
M.O. 2010-12-06, s. 8; M.O. 2011-12-16, s. 7; M.O. 2012-09-05, s. 5; M.O. 2012-12-11, s. 11; M.O. 2013-12-11, s. 6; I.N. 2014-08-01.
6.7. An emitter referred to in section 6.6 who communicates a notice of correction for the emitter's emissions report in accordance with section 6.5 must include a verification report where any of the following relative importance thresholds is reached:
(1) where errors or omissions, calculated using the equation below, represent 5% or more of the total emissions of the establishment or correspond to emissions equal to or greater than 25,000 metric tons CO2 equivalent:
Where:
PE = Percentage of error;
SEO = Sum of CO2 equivalent greenhouse gas emissions erroneously calculated or omitted, in metric tons;
TER = Total greenhouse gas emissions initially reported and referred to in subparagraph 2.3 of the first paragraph of section 6.2, in metric tons CO2 equivalent;
(2) where errors or omissions in the total annual quantity of benchmark units declared in accordance with subparagraph a of subparagraph 8 of the first paragraph of section 6.2, calculated using the equation below, represent 0.1% or more:
Where:
PE = Percentage of error;
BUEO = Quantity of benchmark units erroneously calculated or omitted, on the basis of the benchmark unit used;
BUD = Quantity of benchmark units initially declared, on the basis of the benchmark unit used.
Where the errors or omissions calculated in accordance with subparagraphs 1 and 2 of the first paragraph are less than the relative importance threshold provided for by those subparagraphs, the emitter must provide an attestation to that effect.
M.O. 2010-12-06, s. 8; M.O. 2012-12-11, s. 12; M.O. 2012-12-11, s. 12; M.O. 2013-12-11, s. 7.
(1) be carried out in accordance with the ISO 14064-3 standard and using procedures that allow a reasonable level of assurance within the meaning of that standard;
(2) include at least 1 visit of each establishment covered by the report by the verifier designated by the verification organization;
(3) be performed by using the relative importance thresholds provided for in subparagraphs 1 and 2 of the first paragraph of section 6.7.
In the case of an emitter who transports or distributes electricity or natural gas, the visit referred to in subparagraph 2 of the first paragraph must allow a representative sampling of the emitter's facilities.
M.O. 2010-12-06, s. 8; M.O. 2011-12-16, s. 8; M.O. 2012-12-11, s. 13; M.O. 2013-12-11, s. 8.
6.9. In addition to the information prescribed by the standards ISO 14064-3 and ISO 14065, the verification report must include
(1) the name of and contact information for the verification organization and its representative, as well as the name of and contact information for the chief verifier, the person assigned to the internal review of the verification process and the other members of the verification team designated by the organization to carry out the verification;
(2) the name of and contact information for the member of the International Accreditation Forum that accredited the verification organization, and the date of the accreditation;
(3) the dates of the period during which the verification took place and the date of any visit to the enterprise, facility or establishment;
(4) a description of any error or omission observed in the emissions report or relating to the data, information or methods used;
(5) (paragraph revoked);
(6) where applicable, the corrections made to the emissions report following the verification;
(7) the total quantity of greenhouse gas emissions referred to in Schedule A.1, in metric tons, excluding greenhouse gas emissions that have been captured, stored, re-used, eliminated or transferred out of the establishment, emissions referred to in the second paragraph of section 6.6 and emissions reported using protocols QC.17 and QC.30 of Schedule A.2;
(7.1) the total quantity of reference units relating to the emitter's activities for the report year;
(7.2) for each benchmark unit, the total quantity of greenhouse gas emissions for each type of emissions, excluding emission referred to in the second paragraph of section 6.6, namely:
(a) annual CO2 emissions attributable to fixed processes, in metric tons;
(b) annual emissions of greenhouse gas attributable to combustion, in metric tons CO2 equivalent;
(c) other annual greenhouse gas emissions, in metric tons CO2 equivalent; and
(7.3) the total quantity of greenhouse gas emissions attributable to the use of fuel distributed for consumption in Québec, in metric tons CO2 equivalent, calculated in accordance with subparagraph 1 of the first paragraph of part QC.30.2 of protocol QC.30 in Schedule A.2;
(8) the conclusions of the verification, in particular regarding accuracy and reliability, of the emissions report;
(9) a conflict of interest declaration, including
(a) the name, contact information and sector and sub-sector of activity falling under the scope of the accreditation of the verification organization, as well as the name and contact information of the chief verifier, the person assigned to the internal review of the verification process and the other members of the verification team designated by the organization to carry out the verification;
(b) a copy of the organization chart for the verification organization, as well as the names of and contact information for any subcontractors who took part in the verification;
(c) an attestation signed by the representative of the verification organization that the requirements of section 6.10 have been met and that the risk of conflict of interest is acceptable.
M.O. 2010-12-06, s. 8; M.O. 2012-09-05, s. 6; M.O. 2012-12-11, s. 14; M.O. 2013-12-11, s. 9.
6.10. In addition to the requirements of the standards ISO 14064-3 and ISO 14065 concerning conflicts of interest, the emitter must ensure that none of the following situations exists between the emitter, its officers, the verification organization and the members of the verification team:
(1) during the 3 years preceding the year of the declaration, one of the members of the verification team was employed by the emitter;
(2) a member of the verification team or a close relative of that member has personal ties with the emitter or one of its officers;
(3) during the 3 years preceding the year of the declaration, one of the members of the verification team or one of the subcontractors who took part in the verification provided the emitter with one of the following services:
(a) the design, development, commissioning or maintenance of a data inventory or data management system for greenhouse gas emissions from the establishment or facility of the emitter or, where applicable, for data on electricity or fuel transactions;
(b) the development of greenhouse gas emission factors or other data that were used for the quantification or the greenhouse gas emissions report and required under this Regulation;
(c) consultation concerning greenhouse gas emissions reductions, and in particular the design of an energy efficiency or renewable energy project and the assessment of assets relating to greenhouse gas sources;
(d) the preparation of manuals, guides or procedures connected with the emitter's greenhouse gas emissions reports;
(e) consultation in connection with a greenhouse gas emission allowances market, including
(i) brokerage, with or without registration, while acting as a promoter or subscriber on behalf of the emitter;
(ii) advice concerning the suitability of a greenhouse gas emissions transaction;
(iii) the holding, purchase, sale, negotiation or withdrawal of emission allowances referred to in the second paragraph of section 46.6 of the Environment Quality Act (chapter Q-2);
(f) a consultation in the field of health and safety and environmental management, including the consultation leading to ISO 14001 certification;
(g) actuarial consulting, bookkeeping or other consulting services relating to accounting documents or financial statements;
(h) a service connected with the process data management systems covered by the greenhouse gas emissions verification process;
(i) an internal audit of greenhouse gas emissions;
(j) a service provided in connection with litigation or an inquiry into greenhouse gas emissions;
(k) a consultation for a greenhouse gas emissions reduction project or an offset credit project in accordance with the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1);
(4) the person at the verification organization responsible for carrying out an internal review of the verification process, in accordance with the standards ISO 14065 and ISO 14064-3, has previously provided a verification or other service referred to in subparagraph 3 to the emitter during the report year or the current year.
The existence of one of the situations described in the first paragraph is considered to be a conflict of interest that invalidates the verification report.
For the purposes of this section, a close relative of a member of the verification team is that person's spouse, child, spouse's child, mother or father, mother's or father's spouse, child's spouse or spouse's child's spouse.
M.O. 2012-12-11, s. 15.
M.O. 2010-12-06, s. 8.
7. The persons or municipalities to which the provisions of this Regulation apply must retain the required information and the calculations, assessments, measurements and other data on which emission data are based for a minimum of 7 years from the date on which they were produced and submit them to the Minister on request.
M.O. 2007-09-26, s. 7; M.O. 2010-12-06, s. 9; M.O. 2012-12-11, s. 16.
7.1. Any device, system or equipment required under this Regulation must be maintained in good working order and operate optimally during operating hours.
In addition, unless otherwise provided for in one of the protocols in Schedule A.2, the equipment of an emitter referred to in section 6.6 used to measure the parameters required to calculate greenhouse gas emissions subject to the verification or the calculation of the quantity of reference units must be calibrated according to the manufacturer's instructions in order to maintain accuracy of plus or minus 5%.
M.O. 2010-12-06, s. 10; M.O. 2012-09-05, s. 7; M.O. 2013-12-11, s. 10.
M.O. 2007-09-26, Div. III; M.O. 2012-12-11, s. 17.
8. A monetary administrative penalty of $250 in the case of a natural person or $1,000 in all other cases may be imposed on any person who
(1) contravenes the third paragraph of section 6.2;
(2) fails to keep any information, calculation, assessment, measurement or data for the time prescribed in section 7;
(3) in contravention of this Regulation, refuses or neglects to provide any other notice or other information, any study, research or expert report, or any information, report, calculation, plan or other document, or fails to comply with the time limit for providing them, if no monetary administrative penalty is otherwise provided for.
M.O. 2007-09-26, s. 8; S.Q. 2011, c. 20, s. 56; M.O. 2012-12-11, s. 17.
9. A monetary administrative penalty of $350 in the case of a natural person or $1,500 in all other cases may be imposed on any person who fails to communicate, in the prescribed conditions, any information, notice, attestation or report, as prescribed in one of sections 4, 5, 5.1 or 5.2, the fourth paragraph of section 6, section 6.1, the first or second paragraph of section 6.2 or section 6.4 or 6.5.
M.O. 2007-09-26, s. 9; M.O. 2012-12-11, s. 17.
9.1. A monetary administrative penalty of $500 in the case of a natural person or $2,500 in all other cases may be imposed on any person who fails
(1) to base any information communicated on the best data and best information, in accordance with the first or second paragraph of section 6;
(2) to calculate the quantities of greenhouse gas emissions reported using once of the methods in section 6.3;
(3) to carry out a verification referred to in section 6.8 in accordance with the standard prescribed by that section or to include in the verification report the information prescribed by section 6.9.
M.O. 2012-12-11, s. 17.
9.2. A monetary administrative penalty of $750 in the case of a natural person or $3,500 in all other cases may be imposed on any person who fails
(1) to send to the Minister, within the prescribed time, the verification report referred to in section 6.6 or 6.7, in accordance with those sections;
(2) to ensure that none of the situations described in section 6.10 exist, in accordance with that section;
(3) to maintain any device, system or equipment referred to in section 7.1 in good working order, or to ensure that it operates optimally during operating hours.
M.O. 2012-12-11, s. 17.
M.O. 2012-12-11, s. 17.
9.3. Any person who contravenes the third paragraph of section 6 or 6.2 or section 7 is guilty of an offence and liable to a fine of
(1) $1,000 to $100,000, in the case of a natural person;
(2) $3,000 to $600,000, in all other cases.
Any person who, in contravention of this Regulation, refuses or neglects to provide any other notice or other information, any study, research or expert report, or any information, report, calculation, plan or other document, or fails to comply with the time limit for providing them, is guilty of an offence and liable to the same fines, if no monetary administrative penalty is otherwise provided for.
M.O. 2012-12-11, s. 17.
9.4. Any person who contravenes section 4, 5, 5.1 or 5.2, the fourth paragraph of section 6, section 6.1, the first or second paragraph of section 6.2, or section 6.4 or 6.5 is guilty of an offence and liable to a fine of
(1) $2,000 to $100,000, in the case of a natural person;
(2) $6,000 to $600,000, in all other cases.
M.O. 2012-12-11, s. 17.
9.5. Any person who contravenes the first or second paragraph of section 6, or section 6.3, 6.8 or 6.9, is guilty of an offence and liable to a fine of
(1) $2,500 to $250,000, in the case of a natural person;
(2) $7,500 to $1,500,000, in all other cases.
M.O. 2012-12-11, s. 17.
9.6. Any person who contravenes section 6.6, 6.7, 6.10 or 7.1 is guilty of an offence and liable to a fine of
(1) $4,000 to $250,000, in the case of a natural person;
(2) $12,000 to $1,500,000, in all other cases.
M.O. 2012-12-11, s. 17.
9.7. Whoever communicates false or inaccurate information to the Minister for the purposes of this Regulation is guilty of an offence and liable to a fine of
(1) $5,000 to 500,000, in the case of a natural person or, notwithstanding section 231 of the Code of penal procedure (chapter C-25.1), a term of imprisonment not exceeding 18 months, or both;
(2) $15,000 to $3,000,000, in all other cases.
M.O. 2012-12-11, s. 17.
10. As of the date on which a contaminant listed in Part I of Schedule A is the subject of a public notice given pursuant to section 46 of the Canadian Environmental Protection Act (1999) (S.C. 1999, c. 33), that contaminant becomes governed by the provisions of section 5 of this Regulation. The reporting threshold applicable for that contaminant is then the reporting threshold provided for in the public notice.
M.O. 2007-09-26, s. 10.
M.O. 2007-09-26, s. 11.
(ss. 1, 4, 5, 10)
Part I
Types Contaminants Reporting ____________________________________________ thresholds Identification CAS(1)
- total fluorides 10 tons ____________________________________________ - polycyclic aromatic hydrocarbons (PAHs): - Fluorene 86-73-7 ____________________________________________ - Phenanthrene 85-01-8 ____________________________________________ - Anthracene 120-12-7 ____________________________________________ - Pyrene 129-00-0 ____________________________________________ - Fluoranthene 206-44-0 ____________________________________________ - Chrysene 218-01-9 ____________________________________________ Contaminants - Benzo (a) anthracene 56-55-3 50 kg that cause ____________________________________________ on an annual toxic pollution - Benzo (a) pyrene 50-32-8 basis for all the ____________________________________________ contaminants in - Benzo (e) pyrene 192-97-2 the PAH category ____________________________________________ - Benzo (b) fluoranthene 205-99-2 ____________________________________________ - Benzo (j) fluoranthene 205-82-3 ____________________________________________ - Benzo (k) fluoranthene 207-08-9 ____________________________________________ - Benzo (g, h, i) perylene 191-24-2 ____________________________________________ - Indeno (1,2,3-cd) pyrene 193-39-5 ____________________________________________ - Dibenzo (a,h) anthracene 53-70-3 _______________________________________________________________ - total reduced sulphur 10 tons on an compounds: annual basis for ____________________________________________ all the - hydrogen sulphide (H2S) 7783-06-4 contaminants in ____________________________________________ the category of - methyl mercaptan (CH3SH) 74-93-1 total reduced ____________________________________________ sulphur compounds - dimethyl sulphide ((CH3)2)S) 75-18-3 ____________________________________________ - dimethyl disulphide (S2(CH3)2) 624-92-0
Part II
Types Contaminants Reporting ____________________________________________ thresholds (2) Identification CAS(1)
- sulphur dioxide (SO2) 7446-09-5 ____________________________________________ - nitrogen oxides (NOX) 11104-93-1 Contaminants ____________________________________________ that cause acid - volatile organic compounds rain and smog ____________________________________________ - carbon monoxide (CO) 630-08-0 ____________________________________________ - total particulate matter - particulate matter <10 microns - particulate matter <2.5 microns - ammonia (NH3)
- mercury (Hg) and its compounds - lead (Pb) and its compounds - cadmium (Cd) and its compounds Contaminants - polychlorodibenzo-p-dioxines that cause toxic - polychlorinated dibenzofurans pollution ____________________________________________ - benzene 71-43-2 ____________________________________________ - hexachlorobenzene 118-74-1 ____________________________________________ - formaldehyde 50-00-0 ____________________________________________ - arsenic and its compounds - hexavalent chromium compounds
(1) The numbers entered in respect of the contaminants listed in this Schedule correspond to the identification code assigned by the Chemical Abstract Services division of the American Chemical Society.
(2) The reporting threshold applicable for a contaminant in Part II of this Schedule is the reporting threshold provided for that contaminant in the public notice given by the Minister of the Environment of Canada pursuant to section 46 of the Canadian Environmental Protection Act (1999)(S.C. 1999, c. 33).
M.O. 2007-09-26, Sch. A; M.O. 2010-12-06, s. 11; M.O. 2011-12-16, ss. 9 and 10; M.O. 2012-12-11, s. 18; M.O. 2012-12-11, s. 18; M.O. 2013-12-11, s. 11.
(ss. 1, 6.1 and 6.2)
Greenhouse gases and global warming potentials
_________________________________________________________________________________
| | | |
| Greenhouse gas - identification | CAS1 | Global warming |
| | | potential (GWP) |
|_______________________________________|___________|_____________________________|
| | | |
| - Carbon dioxide (CO2) | 124-38-9 | 1 |
|_______________________________________|___________|_____________________________|
| | | |
| - Methane (CH4) | 74-82-8 | 21 |
|_______________________________________|___________|_____________________________|
| | | |
| - Nitrous oxide (N2O) |10024-97-2 | 310 |
|_______________________________________|___________|_____________________________|
| | | |
| - Sulphur hexafluoride (SF6) | 2551-62-4 | 23 900 |
|_______________________________________|___________|_____________________________|
| |
| - Hydrofluorocarbons (HFCs): |
|_________________________________________________________________________________|
| | | |
| • HFC-23 (CHF3) | 75-46-7 | 11 700 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-32 (CH2F2) | 75-10-5 | 650 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-41 (CH3F) | 593-53-3 | 150 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-43-10mee (C5H2F10) |138495-42-8| 1 300 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-125 (C2HF5) | 354-33-6 | 2 800 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-134 (CHF2CHF2) | 359-35-3 | 1 000 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-134a (CH2FCF3) | 811-97-2 | 1 300 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-143 (CHF2CH2F) | 430-66-0 | 300 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-143a (CF3CH3) | 420-46-2 | 3 800 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-152a (CH3CHF2) | 75-37-6 | 140 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-161 (C2H5F) | 353-36-6 | 12 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-227ea (C3HF7) | 431-89-0 | 2 900 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-236cb (C3H2F6) | 677-56-5 | 1 300 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-236ea (C3H2F6) | 431-63-0 | 1 200 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-236fa (C3H2F6) | 690-39-1 | 6 300 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-245ca (C3H3F5) | 679-86-7 | 560 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-245fa (C3H3F5) | 460-73-1 | 950 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-365mfc (C4H5F5) | 406-58-6 | 890 |
|_______________________________________|___________|_____________________________|
| |
| - Perfluorocarbons (PFCs) |
|_________________________________________________________________________________|
| | | |
| • Perfluoromethane (CF4) | 75-73-0 | 6 500 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluoroethane (C2F6) | 76-16-4 | 9 200 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluoropropane (C3F8) | 76-19-7 | 7 000 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluorobutane (C4F10) | 355-25-9 | 7 000 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluorocyclobutane (c-C4F8) | 115-25-3 | 8 700 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluoropentane (C5F12) | 678-26-2 | 7 500 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluorohexane (C6F14) | 355-42-0 | 7 400 |
|_______________________________________|___________|_____________________________|
| | | |
| - Nitrogen trifluoride (NF3) | 7783-54-2 | 17 200 |
|_______________________________________|___________|_____________________________| 1. The numbers entered in respect of the contaminants listed in this Schedule correspond to the identification code assigned by the Chemical Abstract Services division of the American Chemical Society
M.O. 2010-12-06, s. 12; M.O. 2011-12-16, s. 11; M.O. 2012-12-11, s. 19.
(ss. 1, 6.1 and 6.3)
Information to be communicated and methods to be used in calculating greenhouse gas emissions depending on the type of enterprise, facility or establishment operated, the type of activity pursued, and the type of process or equipment used
PROTOCOLS
QC.1. STATIONARY COMBUSTION
QC.1.1. Covered sources
The covered sources are stationary combustion units such as boilers, combustion turbines, engines, incinerators, process heaters, acid gas scrubbing equipment, portable equipment, and any other stationary combustion unit for which this Schedule prescribes no specific requirements.
However, emergency generators and other equipment used in an emergency are not covered.
QC.1.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) the annual greenhouse gas emissions attributable to the combustion of fossil fuels and biomass fuels, in metric tons, indicating:
(a) CO2 emissions for each type of fuel;
(b) CH4 emissions for each type of fuel; and
(c) N2O emissions for each type of fuel;
(1.1) in the case of emitters referred to in section 6.6, for each benchmark unit, the annual greenhouse gas emissions attributable to each type of fuel, excluding CO2 emissions attributable to the combustion of biomass, in metric tons CO2 equivalent;
(2) the annual consumption of each type of fuel, expressed
(a) in bone dry metric tons, when the quantity is expressed as a mass;
(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
(c) in kilolitres, when the quantity is expressed as a volume of liquid;
(d) in metric tons collected, in the case of municipal solid waste;
(3) where carbon content is used to calculate CO2 emissions, the average annual carbon content of each type of fuel;
(3.1) where the molecular weight is used to calculate CO2 emissions, the annual average molecular weight of each type of fuel;
(4) where high heat value is used to calculate CO2 emissions, the average annual high heat value of each type of fuel, expressed
(a) in gigajoules per bone dry metric ton, when the quantity is expressed as a mass;
(b) in gigajoules per thousand cubic metres, when the quantity is expressed as a volume of gas;
(c) in gigajoules per kilolitre, when the quantity is expressed as a volume of liquid;
(d) in gigajoules per metric ton collected, in the case of municipal solid waste;
(5) for stationary combustion units that burn biomass fuels or municipal solid waste, the annual steam generation in metric tons, where it is used to calculate emissions;
(6) in the case of acid gas scrubbing equipment for fluidized bed boilers, the annual quantity of sorbent used, in metric tons;
(7) the annual CO2 emissions attributable to acid gas scrubbing equipment for fluidized bed boilers, in metric tons;
(8) the number of times that the methods for estimating missing data provided for in QC.1.6 were used.
QC.1.3. Calculation methods for CO2 emissions
The annual CO2 emissions attributable to the combustion of fuels in stationary units must be calculated, for each type of fuel, using one of the five calculation methods specified in QC.1.3.1 to QC.1.3.5. However, in the case of an emitter who uses acid gas scrubbing equipment for fluidized bed boilers, the CO2 emissions attributable to that equipment must be calculated using the calculation method specified in QC.1.3.6.
In addition, when a fuel is not specified in one of Tables 1-1 to 1-8 of QC.1.7, the CO2 emissions attributable to that fuel do not need to be calculated provided they do not exceed 0.5% of the total emissions of the establishment.
QC.1.3.1. Calculation method using the fuel-specific default CO2 emission factor, the default high heat value and the annual fuel consumption
The annual CO2 emissions attributable to the combustion of fuels in stationary units may be calculated using equation 1-1 or 1-1.1
(1) in the case of an emitter not referred to in section 6.6 who uses any type of fuel for which an emission factor is specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6 in QC.1.7 and a high heat value is specified in Table 1-1 or 1-2;
(2) in the case of an emitter referred to in section 6.6 who uses
(a) natural gas with a high heat value that is equal to or greater than 36.3 GJ per thousand cubic metres but less than or equal to 40.98 GJ per thousand cubic metres, with the exception of an emitter using a stationary unit with a design rated heat input capacity that is greater than 264 GJ/h and that has operated for more than 1,000 hours during at least one of the 3 preceding years;
(b) a fuel in Table 1-2;
(c) municipal solid waste when no steam is generated;
(d) a biomass fuel specified in Table 1-3 except if it is targeted by another protocol specified in this Schedule.
However, this method cannot be used by an emitter who determines the high heat value of the fuels used using measurements carried out by the emitter in accordance with QC.1.5.4 or using data indicated by the fuel supplier, obtained at the frequency prescribed by QC.1.5.1.
Equation 1-1
CO2 = Fuel × HHV × EF × 0.001
Where:
CO2 = Annual CO2 emissions attributable to the combustion of each type of fuel, in metric tons;
Fuel = Mass or volume of the fuel combusted during the year, expressed
- in bone dry metric tons, when the quantity is expressed as a mass;
- in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
- in kilolitres, when the quantity is expressed as a volume of liquid;
- in metric tons collected, in the case of municipal solid waste;
HHV = High heat value of the fuel specified in Tables 1-1 and 1-2, expressed
- in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;
- in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;
- in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;
- in gigajoules per metric ton collected, in the case of municipal solid waste;
EF = CO2 emission factor for the fuel specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6, in kilograms of CO2 per gigajoule;
0.001 = Conversion factor, kilograms to metric tons;
Equation 1-1.1
CO2 = Fuel × OEF
Where:
CO2 = Annual CO2 emissions attributable to the combustion of each type of fuel, in metric tons;
Fuel = Mass or volume of the fuel combusted during the year, expressed
- in bone dry metric tons, when the quantity is expressed as a mass;
- in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
- in kilolitres, when the quantity is expressed as a volume of liquid;
- in metric tons collected, in the case of municipal solid waste;
OEF = Overall CO2 emission factor for the fuel, as specified in Table 1-3, 1-4 or 1-5, expressed
- in kilograms of CO2 per bone dry kilogram, in the case of a fuel whose quantity is expressed as a mass;
- in kilograms of CO2 per cubic metres at standard conditions, in the case of a fuel whose quantity is expressed as a volume of gas;
- in kilograms of CO2 per litre, in the case of a fuel whose quantity is expressed as a volume of liquid;
- in kilograms of CO2 per kilogram collected, in the case of municipal solid waste.
QC.1.3.2. Calculation method using the fuel-specific default CO2 emission factor and the high heat value indicated by the fuel supplier or determined by the emitter
The annual CO2 emissions attributable to the combustion of fuels in stationary units may be calculated
(1) in the case of an emitter not referred to in section 6.6 who uses
(a) any type of fuel other than municipal solid waste, for which an emission factor is specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6 in QC.1.7, using equation 1-2;
(b) municipal solid waste and any biomass solid fuel specified in Table 1-3 in QC.1.7, when the combustion of the fuel produces steam, using equation 1-3;
(2) in the case of an emitter referred to in section 6.6 who uses natural gas with a high heat value that is equal to or greater than 36.3 GJ per thousand cubic metres but less than or equal to 40.98 GJ per thousand cubic metres or who uses a fuel in Table 1-2 or a biomass fuel, using equation 1-2.
Equation 1-2
Where:
CO2 = Annual CO2 emissions attributable to the combustion of each type of fuel, in metric tons;
n = Number of measurements of high heat value required annually, as specified in QC.1.5.1;
i = Measurement period;
Fueli = Mass or volume of fuel combusted during measurement period i, expressed
- in bone dry metric tons, when the quantity is expressed as a mass;
- in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
- in kilolitres, when the quantity is expressed as a volume of liquid;
HHVi = High heat value of the fuel for measurement period i, expressed
- in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;
- in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;
- in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;
EF = CO2 emission factor for the fuel as specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6, in kilograms of CO2 per gigajoule;
0.001 = Conversion factor, kilograms to metric tons;
Equation 1-3
CO2 = Steam × B × EF × 0.001
Where:
CO2 = Annual CO2 emissions attributable to the combustion of each type of biomass solid fuel or municipal solid waste, in metric tons;
Steam = Total quantity of steam produced during the year by the combustion of biomass solid fuel or municipal solid waste, in metric tons;
B = Ratio of the boiler’s design rated heat input capacity to its design rated steam output capacity, in gigajoules per metric ton of steam;
EF = CO2 emission factor for biomass solid fuel or municipal solid waste specified in Table 1-3 or 1-6, or an establishment-specific factor determined in accordance with QC.1.5.3, in kilograms of CO2 per gigajoule;
0.001 = Conversion factor, kilograms to metric tons.
QC.1.3.3. Calculation method using the quantity of fuel combusted and the carbon content indicated by the fuel supplier or measured by the emitter
The annual CO2 emissions may be calculated using the following methods:
(1) for fuels whose quantity is expressed as a mass, other than municipal solid waste, the emitter must use equation 1-4 and, for biomass solid fuel if steam is generated, equation 1-4 or 1-5:
Equation 1-4
Where:
CO2 = Annual CO2 emissions attributable to the combustion of each type of solid fuel, in metric tons;
n = Number of measurements of carbon content required annually as specified in QC.1.5.1;
i = Measurement period;
Fueli = Bone dry mass of solid fuel combusted during measurement period i, in metric tons;
CCi = Average carbon content of the fuel whose quantity is expressed as a mass, from the fuel analysis results for the measurement period i indicated by the fuel supplier or measured by the emitter in accordance with QC.1.5.5, in kilograms of carbon per kilogram of fuel;
3.664 = Ratio of molecular weights, CO2 to carbon.
(2) for municipal solid waste if steam is generated, the emitter must use equation 1-5:
Equation 1-5
CO2 = Stream × B × EF × 0.001
Where:
CO2 = Annual CO2 emissions attributable to the combustion of each type of biomass solid fuel or municipal solid waste, in metric tons;
Steam = Total quantity of steam produced during the year by the combustion of biomass solid fuel or municipal solid waste, in metric tons;
B = Ratio of the boiler’s design rated heat input capacity to its design rated steam output capacity, in gigajoules per metric ton of steam;
EF = CO2 emission factor of biomass solid fuel or municipal solid waste indicated by the fuel supplier, established by the emitter in accordance with QC.1.5.3 or specified in Table 1-3 or 1-6 in QC.1.7, in kilograms of CO2 per gigajoule;
0.001 = Conversion factor, kilograms to metric tons.
(3) for fuels whose quantity is expressed as a volume of liquid, the emitter must use equation 1-6:
Equation 1-6
Where:
CO2 = Annual CO2 emissions attributable to the combustion of each type of fuel whose quantity is expressed as a volume of liquid, in metric tons;
n = Number of measurements of carbon content required annually as specified in QC.1.5.1;
i = Measurement period;
Fueli = Volume of fuel combusted during the measurement period i, in kilolitres;
CCi = Average carbon content of the liquid fuel, from the fuel analysis results for the measurement period i indicated by the fuel supplier or measured by the emitter in accordance with QC.1.5.5, in metric tons of carbon per kilolitre of fuel;
3.664 = Ratio of molecular weights, CO2 to carbon.
(4) for fuels whose quantity is expressed as a volume of gas, the emitter must use equation 1-7:
Equation 1-7
Where:
CO2 = Annual CO2 emissions attributable to the combustion of each type of fuel whose quantity is expressed as a volume of gas, in metric tons;
n = Number of measurements of carbon content and molecular weight required annually, as specified in QC.1.5.1;
i = Measurement period;
Fueli = Volume of gaseous fuel combusted during measurement period i, in thousands of cubic metres at standard conditions;
CCi = Average carbon content of the gaseous fuel, from the fuel analysis results for the measurement period i indicated by the fuel supplier or measured by the emitter in accordance with QC.1.5.5, in kilograms of carbon per kilogram of fuel;
MW = Molecular weight of the gaseous fuel, established in accordance with QC.1.5.5 from the fuel analysis results, in kilograms per kilomole or, when a mass flowmeter is used to measure the flow in kilograms per unit of time, replace
_ _
| |
| MW |
|----| by 1;
|MVC |
|_ _| MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
3.664 = Ratio of molecular weights, CO2 to carbon;
1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres;
(5) in the case of a mixture of fuels, the emitter may use equations 1-4 to 1-6, using the average carbon content of the mixture of fuels measured by the emitter in accordance with QC.1.5, but the emitter must declare annual emissions of CO2 per type of fuel in accordance with QC.1.2.
QC.1.3.4. Calculation method using data from a continuous emission monitoring and recording system
The annual CO2 emissions attributable to the combustion any type of fuel used in stationary combustion units may be calculated using data from a continuous emission monitoring and recording system including a stack gas volumetric flow rate monitor and a CO2 concentration monitor, in accordance with the EPS 1/PG/7 protocol entitled “Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation” published in November 2005 by Environment Canada, or, in the case of an emitter not referred to in section 6.6, in accordance with the manufacturer's specifications.
An oxygen concentration monitor may, however, be used instead of a CO2 concentration monitor if the following conditions are met:
(1) the continuous emission monitoring and recording system was installed before 1 January 2012;
(2) the gas effluent contains only the products of combustion;
(3) only the following fuels, that are not waste-derived fuels, are combusted: coal, petroleum coke, light or heavy oil, natural gas, propane, butane or wood waste.
When a continuous emission monitoring and recording system is used in connection with a stationary combustion unit, the CO2 emissions of all the fuels combusted must be calculated using data from the system.
The use of a continuous emission monitoring and recording system must take into account the particularities of each type of fuel used and meet the following requirements:
(1) for units that combust fossil fuels or biomass fuels, the emitter must
(a) use CO2 or, if applicable, oxygen concentrations and stack gas flow rate measurements to determine hourly CO2 emissions;
(b) report annual CO2 emissions, in metric tons, based on the sum of hourly CO2 emissions over the year;
(c) if the emitter combusts biomass fuels in the units and uses oxygen concentrations to calculate CO2, concentrations, demonstrate that the CO2 concentrations calculated correspond to the CO2 concentrations measured after verification of their relative accuracy in accordance with the SPE 1/PG/7 protocol;
(2) for units that combust waste-derived fuels and units that combust both fossil fuels and biomass fuels or waste-derived fuels that are partly biomass, the emitter must
(a) use CO2 concentrations and stack gas flow rate measurements to determine hourly CO2 emissions;
(b) report annual CO2 emissions, in metric tons, based on the sum of hourly CO2 emissions over the year;
(c) determine separately the portion of total CO2 emissions attributable to the combustion of biomass contained in the fuel using the calculation methods in QC.1.3.5;
(3) when the facility or establishment is equipped with a continuous CO2 monitoring system and when the emitter must, in accordance with this Regulation, report emissions by type, namely combustion, fixed process or “other” category, the emitter must, for each type of emission,
(a) estimate the greenhouse gas emissions attributable to combustion and the “other” category emissions using the emission factors in tables 1-1 to 1-8 in QC.1.7. If no factor is indicated in the tables, the emitter may use a factor published by Environment Canada, the U.S. Environmental Protection Agency (USEPA), the Intergovernmental Panel on Climate Change (IPCC), the National Council for Air and Stream Improvement (NCASI) or the World Business Council for Sustainable Development (WBCSD);
(b) determine the annual greenhouse gas emissions attributable to the fixed process by subtracting from the data measured by the continuous CO2 monitoring system the greenhouse gas emissions attributable to combustion and the “other” category emissions estimated in accordance with subparagraph a.
QC.1.3.5. Calculation method for the CO2 emissions attributable to the biomass portion of a fuel or mixture of fuels
An emitter who uses stationary combustion units that combust fuels or mixtures of fuels containing biomass must calculate the CO2 emissions of the biomass portion as follows:
(1) when the biomass portion is known and the mixture does not contain waste-derived fuels that are partly biomass, an emitter who
(a) does not use a continuous emission monitoring and recording system to measure the concentration of CO2, must use the applicable equations in QC.1.3.1 to QC.1.3.3 to calculate the CO2 emissions attributable to the combustion of biomass;
(b) uses a continuous emission monitoring and recording system to measure the concentration of CO2, must use the applicable equations in QC.1.3.1 to QC.1.3.3 to calculate the CO2 emissions attributable to the combustion of fossil fuels, and subtract the portion of CO2 emissions attributable to the combustion of fossil fuels from the total emissions in order to determine the emissions attributable to the combustion of biomass;
(2) when the biomass portion is not known, or when no emission factor is specified in Table 1-2 in QC.1.7, the emitter must, except for fuels containing less than 5% of biomass by weight or waste-derived fuels making up less than 30% by weight of the fuels combusted during the year:
(a) use the applicable equations in QC.1.3.1 to QC.1.3.4 to calculate the total CO2 emissions;
(b) determine the biomass portion of the fuels in accordance with the most recent version of ASTM D6866 “Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis”, or using any other analysis method published by an organization listed in QC.1.5;
(c) conduct, at least every 3 months, an analysis on a representative fuel or exhaust gas sample in accordance with the most recent version of ASTM D6866 or using any other analysis method published by an organization listed in QC.1.5, the analysis being conducted on the exhaust gas stream when waste-derived fuels are combusted;
(c.1) when the exhaust gas stream is sampled, collect samples over a period of at least 24 consecutive hours in accordance with the most recent version of ASTM D7459 “Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from Stationary Emissions Sources”, or using any other analysis method published by an organization listed in QC.1.5;
(d) divide total CO2 emissions between CO2 emissions attributable to the combustion of biomass fuels and CO2 emissions attributable to the combustion of nonbiomass fuels using the average proportions of the samples analyzed during the year;
(e) make the measurements in accordance with the most recent version of ASTM D6866 on the stationary combustion unit of the emitter's choice if there is a common fuel source for multiple units or using any other analysis method published by an organization listed in QC.1.5;
(3) when equation 1-1 or 1-1.1 is used to calculate the CO2 emissions attributable to the combustion of biomass solid fuels, equation 1-8 may be used to quantify the consumption of biomass solid fuels:
Equation 1-8
__ __ | | | Hi × Steami | - Ei |__ __| Biomass fuel1 = ____________________ HHV × Eff
Where:
Biomass fueli = Quantity of biomass fuel combusted during measurement period i, in metric tons;
Hi = Average enthalpy of the boiler for measurement period i, in gigajoules per metric ton of steam;
Steami = Total quantity of steam produced during measurement period i, in metric tons;
Ei = Total energy input of all fuels other than biomass fuels combusted during measurement period i, in gigajoules;
hhv = High heat value of the biomass fuel specified in Table 1-1 or determined by the emitter, in gigajoules per metric ton;
Eff = Energy efficiency of the biomass fuel, expressed as a percentage;
(4) when the emitter is a municipality, the biomass portion of the waste may be established using an alternative method such as waste characterization.
QC.1.3.6. Calculation method for CO2 emissions attributable to acid gas scrubbing equipment for fluidized bed boilers
The annual CO2 emissions attributable to acid gas scrubbing equipment for fluidized bed boilers must be calculated using a continuous emission monitoring and recording system in accordance with QC.1.3.4 or using equation 1-9:
Equation 1-9
_ _ | 44 | CO2 = QS × R × |_____| | MMS | |_ _|
Where:
CO2 = Annual CO2 emissions attributable to the acid gas scrubbing equipment for fluidized bed boilers, in metric tons;
QS = Annual quantity of sorbent used, in metric tons;
R = Ratio of moles of CO2 released upon capture of 1 mole of acid gas;
44 = Molecular weight of CO2, in kilograms per kilomole;
MMs = Molecular weight of sorbent, in kilograms per kilomole or, in the case of calcium carbonate, a value of 100.
QC.1.4. Calculation methods for CH4 and N2O emissions
The annual CH4 and N2O emissions attributable to the combustion of fuels in stationary units must be calculated, for each type of fuel, using the methods in QC.1.4.1 to QC.1.4.5.
However, when a fuel is not specified in one of Tables 1-1 to 1-8 of QC.1.7, the CH4 and N2O emissions attributable to that fuel do not need to be calculated.
QC.1.4.1. Calculation method using a default CH4 and N2O emission factor and the default high heat value for the fuel
The annual CH4 and N2O emissions attributable to the combustion of a fuel whose high heat value is not determined by the measurements made by the emitter or the data provided by the fuel supplier for the purpose of calculating CO2 emissions may be calculated using equation 1-10 or 1-10.1:
(1) in the case of an emitter not referred to in section 6.6 who uses any type of fuel for which an emission factor is specified in Table 1-3, 1-6 or 1-7 in QC.1.7 and a high heat value is specified in Table 1-1 or 1-2;
(2) in the case of an emitter referred to in section 6.6 who uses either
(a) natural gas with a high heat value that is equal to or greater than 36.3 GJ per thousand cubic metres but less than or equal to 40.98 GJ per thousand cubic metres; or
(b) a fuel in Table 1-2 or a biomass fuel.
In the case of any emitter, the emissions attributable to the combustion of coal must be calculated using equation 1-11.
Equation 1-10
CH4 or N2O = Fuel × HHV × EF × 0.000001
Where:
CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of each type of fuel, in metric tons;
Fuel = Mass or volume of the fuel combusted during the year, expressed
- in bone dry metric tons, when the quantity is expressed as a mass;
- in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
- in kilolitres, when the quantity is expressed as a volume of liquid;
- in metric tons collected, in the case of municipal solid waste;
HHV = High heat value of the fuel specified in Table 1-1 and 1-2, expressed
- in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;
- in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;
- in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;
- in gigajoules per metric ton collected, in the case of municipal solid waste;
EF = CH4 or N2O emission factor for the fuel established by the emitter in accordance with QC.1.5.3, emission factor for the fuel as specified in Table 1-3, 1-6 or 1-7, or emission factor from the document “AP-42, Compilation of Air Pollutant Emission Factors” published by the U.S. Environmental Protection Agency (USEPA), in grams of CH4 or N2O per gigajoule;
0.000001 = Conversion factor, grams to metric tons;
Equation 1-10.1
CH4 or N2O = Fuel × OEF × 0.001
Where:
CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of each type of fuel, in metric tons;
Fuel = Mass or volume of the fuel combusted during the year, expressed
- in bone dry metric tons, when the quantity is expressed as a mass;
- in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
- in kilolitres, when the quantity is expressed as a volume of liquid;
- in metric tons collected, in the case of municipal solid waste;
OEF = Overall CH4 or N2O emission factor for the fuel, as specified in Table 1-3, 1-7 or 1-8, expressed
- in grams of CH4 or N2O per kilogram, in the case of a fuel whose quantity is expressed as a mass;
- in grams of CH4 or N2O per cubic metre at standard conditions, in the case of a fuel whose quantity is expressed as a volume of gas;
- in grams of CH4 or N2O per litre in the case of a fuel whose quantity is expressed as a volume of liquid;
0.001 = Conversion factor, kilograms to metric tons;
Equation 1-11
CH4 or N2O = Fuel × EFc × 0.001
Where:
CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of coal, in metric tons;
Fuel = Mass of coal combusted during the year, in metric tons;
EFc = CH4 or N2O emission factor for the coal established by the emitter in accordance with QC.1.5.3 or emission factor for the coal specified in Table 1-8, in grams of CH4 or N2O per kilogram of coal;
0.001 = Conversion factor, kilograms to metric tons.
QC.1.4.2. Calculation method using a high heat value determined from data provided by the fuel supplier or measurements made by the emitter
When the high heat value of the fuel is determined from data provided by the fuel supplier or measurements made by the emitter in order to estimate CO2,the annual CH4 or N20 emissions for the fuels must be calculated using equation 1-12, subject to the emissions attributable to the combustion of coal which must be calculated using equation 1-13:
Equation 1-12
Where:
CH4 or N2O = Annual CH4 or N2O emissions attributable to each type of fuel, in metric tons;
n = Number of measurements of high heat value required annually, as specified in QC.1.5.1;
i = Measurement period;
Fueli = Mass or volume of fuel combusted during measurement period i, expressed
- in bone dry metric tons, when the quantity is expressed as a mass;
- in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
- in kilolitres, when the quantity is expressed as a volume of liquid;
- in metric tons collected, in the case of municipal solid waste;
HHVi = High heat value determined from data provided by the fuel supplier or measurements made by the emitter for the measurement period i in accordance with QC.1.5.4, for each type of fuel, expressed
- in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;
- in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;
- in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;
- in gigajoules per metric ton collected, in the case of municipal solid waste;
EF = CH4 or N2O emission factor for the fuel established by the emitter in accordance with QC.1.5.3, emission factor for the fuel as specified in Table 1-3 or 1-7 in QC.1.7, or emission factor from the document “AP-42, Compilation of Air Pollutant Emission Factors” published by the U.S. Environmental Protection Agency (USEPA), in grams of CH4 or N2O per gigajoule;
0.000001 = Conversion factor, grams to metric tons;
Equation 1-13
Where:
CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of coal, in metric tons;
n = Number of measurements required annually, as specified in QC.1.5.1;
i = Measurement period;
Fueli = Mass of coal combusted during measurement period i, in metric tons;
EFc = CH4 or N2O emission factor for the coal indicated by the fuel supplier or established by the emitter in accordance with QC.1.5.3, in grams of CH4 or N2O per kilogram of coal;
0.001 = Conversion factor, grams to metric tons.
QC.1.4.3. Calculation method for emissions attributable to the combustion of biomass, biomass fuels or municipal solid waste
The annual CH4 ou N2O emissions attributable to the combustion of biomass, biomass fuels or municipal solid waste must be calculated using equation 1-14 when CO2 emissions are calculated using equations 1-3 and 1-5:
Equation 1-14
CH4 or N20 = Steam × B × EF × 0.000001
Where:
CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of biomass, biomass fuels or municipal solid waste, in metric tons;
Steam = Total quantity of steam produced during the year by the combustion of biomass, biomass fuels or municipal solid waste, in metric tons;
B = Ratio of the boiler’s design rated heat input capacity to its design rated steam output capacity, in gigajoules per metric ton of steam;
EF = CH4 or N2O emission factor for the biomass, biomass fuel or municipal solid waste established by the emitter in accordance with QC.1.5.3 or emission factor for the fuel specified in Table 1-3, 1-6 or 1-7 specified in QC.1.7, in grams of CH4 or N2O per gigajoule;
0.000001 = Conversion factor, grams to metric tons.
QC.1.4.4. Calculation method using a default CH4 and N2O emission factor and the energy input of the fuel determined by the emitter
The annual CH4 and de N2O emissions attributable to the combustion of a fuel must be calculated using equation 1-15 when the CO2 emissions for that fuel are calculated using a continuous emission monitoring and recording system in accordance with QC.1.3.4 and the energy input for the fuel is determined by the emitter using data from the system:
Equation 1-15
CH4 or N2O = E × EF × 0.000001
Where:
CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of each fuel, in metric tons;
E = Energy input of each fuel determined using data from a continuous emission monitoring and recording system, in gigajoules;
EF = CH4 or N2O emission factor for the fuel specified in Table 1-3, 1-7 or 1-8 in QC.1.7, in grams of CH4 or N2O per gigajoule;
0.000001 = Conversion factor, grams to metric tons.
QC.1.4.5. Calculation method using data from a continuous emission monitoring and recording system
The annual CH4 or N2O emissions attributable to the combustion of any type of fuel used in stationary combustion units may be calculated using data from a continuous emission monitoring and recording system including a gas volumetric flow rate monitor and a CH4 or N2O concentration monitor, in accordance with the EPS 1/PG/7 protocol entitled “Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation” published in November 2005 by Environment Canada or, in the case of an emitter not referred to in section 6.6, in accordance with the manufacturer's specifications.
QC.1.5. Sampling, analysis and measurement requirements
In the cases provided for in this protocol, the emitter may use the analysis methods published by the following organizations:
(1) American Society for Testing and Materials (ASTM);
(2) Centre d'Expertise en Analyse Environnementale du Québec (CEAEQ);
(3) Environment Canada;
(4) U.S. Environmental Protection Agency (USEPA);
(5) International Organization for Standardization (ISO);
(6) Technical Association of the Pulp and Paper Industry: Industry Standards & Regulations (TAPPI);
(7) Canadian Standards Association;
(8) Measurement Canada;
(9) American Association of State Highway and Transportation Officials (AASHTO);
(10) Association française de normalisation (AFNOR);
(11) Association of Fertilizer and Phosphate Chemists (AFPC);
(12) American Petroleum Institute (API);
(13) ASM International (ASM);
(14) British Standard Institution (BS);
(15) Gas Processors Association (GPA).
QC.1.5.1. Frequency of fuel sampling
When a calculation method requires an emitter to determine the carbon content, high heat value or emission factor of a fuel, the emitter must sample the fuel or obtain sampling results from the supplier for the fuel
(1) annually, for biomass fuels and waste-derived fuels for which the CO2 emissions are calculated using equations 1-2 and 1-4;
(2) semi-annually, for natural gas;
(3) quarterly, for fuels specified in Table 1-2 in QC.1.7, liquid fuels, gaseous fuels, gases derived from biomass and biogas produced from landfill gas or from wastewater treatment or agricultural processes;
(4) monthly, for solid fuels except coal and waste-derived fuels, as specified below:
(a) the sample is a monthly composite of four weekly samples of equal mass, collected each week during the month of operation, which samples are taken after all fuel treatment operations but before fuel mixing to ensure that the samples are representative of the chemical and physical characteristics of the fuel immediately prior to combustion;
(b) the monthly composite sample is homogenised and well mixed prior to withdrawal and analysis;
(c) one in twelve monthly composite samples is randomly selected for additional analysis of its discrete constituent samples to ensure the homogeneity of the composite sample;
(4.1) monthly, in accordance with subparagraphs a to c of paragraph 4, or at each delivery in the case of coal;
(5) at each delivery in the case of any fuel that is not referred to in paragraphs 1 to 4.1;
(6) monthly, in accordance with subparagraphs a to c of paragraph 4, in the case of a mixture of fuels.
Despite subparagraphs 4, 4.1, 5 and 6 of the first paragraph, in the case of solid fuels or mixtures of fuels used in an electric arc furnace or a clinker kiln, the emitter may do the fuel sampling or use the sampling results of the supplier provided that the sampling is composed of at least 3 representative samples per year.
QC.1.5.2. Fuel consumption
An emitter who operates a facility or establishment where a stationary combustion unit is used must
(1) calculate fuel consumption by fuel type
(a) by measuring it directly;
(b) using recorded fuel purchases or sales invoices for each type of combustible measuring any stock change, in megajoules, litres, millions of cubic metres at standard conditions, metric tons or bone dry metric tons, using the following equation:
Fuel Consumption in a given Report Year = Total Fuel Purchases – Total Fuel Sales + Amount Stored at Beginning of Year – Amount Stored at Year End
(c) for fuel oil when no purchase took place during the year, tank drop measurements may also be used;
(d) in the case of an emitter that uses equation 1-3 or 1-5 to calculated CO2 emissions, by using equation 1-8;
(2) convert fuel consumption in megajoules into one of the measurement units given in subparagraph b of paragraph 1 using the high heat value of the fuel determined using measurements carried out in accordance with QC.1.5.4, the high heat value indicated by the supplier or the high heat value specified in Table 1-1 specified in QC.1.7;
(3) calibrate, before the first emissions report using the calculation methods in QC.1 and thereafter annually or at the minimum frequency specified by the manufacturer, all flowmeters for liquid and gaseous fuels, except those used to bill gas, using one of the flow meter tests listed in Table 1-9 or the calibration procedures specified by the flow meter manufacturer.
Fuel flow meters that measure mass flow rates may be used for liquid fuels, provided that the fuel density is used to convert the readings to volumetric flow rates. The density must in such cases be measured at the same frequency as the carbon content using the most recent version of method ASTM D1298, “Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method”, or any other analysis method published by an organization listed in QC.1.5. An emitter using one of the methods specified in QC.1.3.1 or QC.1.3.2 may, however, use the mass flow specified in Table 1-10 in QC.1.7.
QC.1.5.3. Fuel emission factors
The emitter must establish emission factors using the following methods:
(1) when CO2 emissions are calculated using the method in QC.1.3.3 (2), the emission factor must be established in kilograms of CO2 per gigajoule and adjusted at least every 3 years through a stack test measurement of CO2 and use of the applicable ASME Performance Test Code published by the American Society of Mechanical Engineers (ASME) to determine heat input from all heat outputs, including the steam, exhaust gas streams, ash and losses;
(2) when CH4 or N2O emissions are calculated using emission factors based on source tests, the source test procedures must be repeated in subsequent years to update the emissions factors for the stationary combustion unit.
QC.1.5.4. High heat value of the fuel
The emitter must determine the average annual high heat value using equation 1-16:
Equation 1-16
Where:
HHVa = Average annual high heat value, expressed
- in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;
- in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;
- in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;
- in gigajoules per metric ton collected, in the case of municipal solid waste;
n = Number of measurements of high heat value;
i = Measurement period;
HHVi = High heat value for the measurement period i, expressed
- in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;
- in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;
- in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;
- in gigajoules per metric ton collected, in the case of municipal solid waste;
Fueli = Mass or volume of fuel combusted during measurement period i, expressed
- in bone dry metric tons, when the quantity is expressed as a mass;
- in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
- in kilolitres, when the quantity is expressed as a volume of liquid;
- in metric tons collected, in the case of municipal solid waste.
The emitter must determine high heat value using the sampling and analysis results indicated by the fuel supplier or the results of the sampling conducted by the emitter and using one of the following methods:
(1) for gases:
(a) in accordance with the most recent version of ASTM D1826 “Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter”, ASTM D3588 “Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels”, and ASTM D4891 “Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion”, and GPA 2261 “Analysis for natural gas and similar gaseous mixtures by gas chromatography” published by the Gas Processors Association (GPA), or using any other analysis method published by an organization listed in QC.1.5;
(b) by determining high heat value to within ± 5% using a continuous emission monitoring and recording system;
(c) when the continuous emission monitoring and recording system provides only low heat value, by converting the value to high heat value using equation 1-17:
Equation 1-17
HHV = LHV × CF
Where:
HHV = High heat value of the fuel or fuel mixture, in gigajoules per thousand cubic metres at standard conditions;
LHV = Low heat value of the fuel or fuel mixture, in gigajoules per thousand cubic metres at standard conditions;
CF = Conversion factor for converting low heat value to high heat value, established as follows:
(a) for natural gas, the emitter must use a CF of 1.11;
(b) for refinery fuel gas, flexigas, associated gas or gas mixtures, the emitter must establish the weekly average FC as follows:
- using the low heat value measurements and the high heat value obtained by the continuous emission monitoring and recording system or by laboratory analysis as part of the daily carbon content determination;
- using the HHV/LHV ratio obtained from the laboratory analysis of the daily samples;
(2) for middle distillates, fuel oil and liquid waste-derived fuels, in accordance with the most recent version of ASTM D240 “Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter”, or ASTM D4809 “Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method)”, or using any other analysis method published by an organization listed in QC.1.5;
(3) for biomass solid fuel, in accordance with the most recent version of ASTM D5865 “Standard Test Method for Gross Calorific Value of Coal and Coke”, or using any other analysis method published by an organization listed in QC.1.5;
(4) for waste-derived fuels, in accordance with the most recent version of ASTM D5865 or ASTM D5468 “Standard Test Method for Gross Calorific and Ash Value of Waste Materials”, or using any other analysis method published by an organization listed in QC.1.5 and, when the waste-derived fuels are not pure biomass fuels, by calculating the biomass fuel portion of CO2 emissions in accordance with subparagraph 2 of the fifth paragraph of QC.1.3.4.
QC.1.5.5. Carbon content, molecular weight and molar fraction of fuel
The emitter must determine the average annual carbon content using equation 1-18:
Equation 1-18
Where:
CCa = Average annual carbon content, expressed
- in kilograms of carbon per bone dry kilogram, in the case of a fuel whose quantity is expressed as a mass;
- in kilograms of carbon per kilogram, in the case of a fuel whose quantity is expressed as a volume of gas;
- in metric tons of carbon per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;
n = Number of measurements of carbon content;
i = Measurement period;
CCi = Carbon content of the fuel for the measurement period i, expressed
- in kilograms of carbon per bone dry kilogram, in the case of a fuel whose quantity is expressed as a mass;
- in kilograms of carbon per kilogram, in the case of a fuel whose quantity is expressed as a volume of gas;
- in metric tons of carbon per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;
Fueli = Mass or volume of fuel combusted during measurement period i, expressed
- in bone dry metric tons, when the quantity is expressed as a mass;
- in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
- in kilolitres, when the quantity is expressed as a volume of liquid.
The carbon content and molecular weight or molar fraction must be determined using the sampling and analysis results indicated by the fuel supplier or the results of the sampling conducted by the emitter using one of the following methods:
(1) for solid fuels, namely coal, coke, biomass solid fuels and waste-derived fuels, in accordance with the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”, or using any other analysis method published by an organization listed in QC.1.5;
(2) for petroleum-based liquid fuels and liquid waste-derived fuels, using one of the following methods:
(a) in accordance with the most recent version of ASTM D5291 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”;
(b) by applying the elementary analysis method;
(c) in accordance with the most recent version of ASTM D3238 “Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by n-d-M Method” and the most recent version of either ASTM D2502 “Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mas(s) of Petroleum Oils From Viscosity Measurements” or ASTM D2503 “Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurements of Vapor Pressure”;
(d) using any other analysis method published by an organization listed in QC.1.5;
(3) for gaseous fuels, in accordance with the most recent version of ASTM D1945 “Standard Test Method for Analysis of Natural Gas by Gas Chromatography”, ASTM D1946 “Standard Practice for Analysis of Reformed Gas by Gas Chromatography”, or ASTM D2163 “Standard Test Method for Determination of Hydrocarbons in Liquefied Petroleum (L(P) Gases and Propane/Propene Mixtures by Gas Chromatography”, in accordance with any other analysis method published by an organization listed in QC.1.5, or by measuring the carbon content of the fuel to within ± 5% using data from a continuous emission monitoring and recording system, at the following frequency:
(a) weekly, for natural gas and biogas;
(b) daily, for all other types of gaseous fuel;
(4) in the case of a mixture of fuels, in accordance with an analysis method published by a body referred to in QC.1.5.
QC.1.5.6. Measurements and data collection for fuel sampling
When the emission calculation methods require the periodic measurement or collection of data for an emissions source, the emitter must obtain a measurement and data collection rate of 100% for each report year, subject to the following:
(1) when, in sampling fuels, an emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period;
(2) when it is not possible to obtain valid data, the emitter must use replacement data established using the calculation method in QC.1.6.
QC.1.5.7. (Revoked).
QC.1.6. Methods for estimating missing data
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods specified in QC.1.3.1 to QC.1.3.3, QC.1.3.5, QC.1.3.6, QC.1.4.1, QC.1.4.2 and QC.1.4.3 must,
(a) when the missing data concern high heat value, carbon content, molecular mass, CO2 concentration, water content or any other data sampled to calculate greenhouse gas emissions,
(i) determine the sampling or measurement rate using the following equation:
Equation 1-19
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.1.5;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern stack gas flow rate, fuel consumption or the quantity of sorbent used, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses one of the calculation methods specified in QC.1.3.4, QC.1.4.4 and QC.1.4.5 must determine the replacement data for the CO2, CH4, and N2O concentration using the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or applying to the missing parameters the following method:
(a) when the missing data are data measured by the continuous emission monitoring and recording system, determine the sampling or measurement rate using the following equation:
Equation 1-20
R = HS Act/HS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
HS Act = Hours of actual samples or measurements obtained by the emitter during the year;
HS Required = Quantity of samples or measurements required under QC.1.5;
(b) for data that require sampling or analysis,
(i) if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data from before that period are available, the emitter must use the first available data from after the period for which the data is missing;
(ii) if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
(iii) if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
QC.1.7. Tables
Table 1-1. High heat value by fuel type
(QC.1.3.1(1), QC.1.4.1(1), QC.1.5.2(2), QC.17.3.1(2))
_________________________________________________________________________________
| | |
| Liquid fuels |High heat value (GJ/kl)|
|_________________________________________________________|_______________________|
| | |
| Asphalt & Road Oil | 44.46 |
|_________________________________________________________|_______________________|
| | |
| Aviation Gasoline | 33.52 |
|_________________________________________________________|_______________________|
| | |
| Diesel | 38.30 |
|_________________________________________________________|_______________________|
| | |
| Aviation Turbo Fuel | 37.40 |
|_________________________________________________________|_______________________|
| | |
| Kerosene | 37.68 |
|_________________________________________________________|_______________________|
| | |
| Propane | 25.31 |
|_________________________________________________________|_______________________|
| | |
| Ethane | 17.22 |
|_________________________________________________________|_______________________|
| | |
| Butane | 28.44 |
|_________________________________________________________|_______________________|
| | |
| Lubricants | 39.16 |
|_________________________________________________________|_______________________|
| | |
| Motor Gasoline | 34.87 |
|_________________________________________________________|_______________________|
| | |
| Light Fuel Oil No. 1 | 38.78 |
|_________________________________________________________|_______________________|
| | |
| Light Fuel Oil No. 2 | 38.50 |
|_________________________________________________________|_______________________|
| | |
| Residual Fuel Oil (#5 & 6) | 42.50 |
|_________________________________________________________|_______________________|
| | |
| Crude Oil | 39.16 |
|_________________________________________________________|_______________________|
| | |
| Naphtha | 35.17 |
|_________________________________________________________|_______________________|
| | |
| Petrochemical Feedstocks | 35.17 |
|_________________________________________________________|_______________________|
| | |
| Petroleum Coke | 46.35 |
|_________________________________________________________|_______________________|
| | |
| Ethanol (100%) | 23.41 |
|_________________________________________________________|_______________________|
| | |
| Biodiesel (100%) | 35.67 |
|_________________________________________________________|_______________________|
| | |
| Rendered animal fat | 34.84 |
|_________________________________________________________|_______________________|
| | |
| Vegetable Oil | 33.44 |
|_________________________________________________________|_______________________|
| | |
| Solid fuels | High heat value (GJ/t)|
|_________________________________________________________|_______________________|
| | |
| Antracite Coal | 27.70 |
|_________________________________________________________|_______________________|
| | |
| Bituminous Coal | 26.33 |
|_________________________________________________________|_______________________|
| | |
| Foreign Bituminous Coal | 29.82 |
|_________________________________________________________|_______________________|
| | |
| Sub-Bituminous Coal | 19.15 |
|_________________________________________________________|_______________________|
| | |
| Lignite | 15.00 |
|_________________________________________________________|_______________________|
| | |
| Coal Coke | 28.83 |
|_________________________________________________________|_______________________|
| | |
| Wood Waste (dry basis) | 19.2 |
|_________________________________________________________|_______________________|
| | |
| Spent Puling Liquor (dry basis) | 14.2 |
|_________________________________________________________|_______________________|
| | |
| Municipal solid waste | 11.57 |
|_________________________________________________________|_______________________|
| | |
| Peat | 9.30 |
|_________________________________________________________|_______________________|
| | |
| Tires | 31.18 |
|_________________________________________________________|_______________________|
| | |
| Agricultural By-products1 | 9.59 |
|_________________________________________________________|_______________________|
| | |
| Biomass By-products2 | 30.03 |
|_________________________________________________________|_______________________|
| | |
| Gaseous fuels | High heat value |
| | (GJ/103 m3) |
|_________________________________________________________|_______________________|
| | |
| Natural Gas | 38.32 |
|_________________________________________________________|_______________________|
| | |
| Coke Oven Gas | 19.14 |
|_________________________________________________________|_______________________|
| | |
| Still Gas | 36.08 |
|_________________________________________________________|_______________________|
| | |
| Landfill Gas (methane portion) | 39.82 |
|_________________________________________________________|_______________________|
| | |
| Biogas (methane portion) | 31.50 |
|_________________________________________________________|_______________________| 1. By-products not destined for consumption.
2. Animal and vegetable waste, excluding wood waste and spent pulping liquor.
Table 1-2. Emission factor and high heat factor by fuel type
(QC.1.3.1, QC.1.3.2, QC.1.3.5(2), QC.1.4.1(1), QC.1.5.1(3))
________________________________________________________________________________
| | | |
| Fuels | CO2 emission factor | High heat value |
| | kg CO2/GJ) | (GJ/kl) |
|________________________________|________________________|______________________|
| | | |
| Light fuel oil no. 1 | 69.37 | 38.78 |
|________________________________|________________________|______________________|
| | | |
| Light fuel oil no. 2 | 70.05 | 38.50 |
|________________________________|________________________|______________________|
| | | |
| Heavy fuel oil no. 4 | 71.07 | 40.73 |
|________________________________|________________________|______________________|
| | | |
| Kerosene | 67.25 | 37.68 |
|________________________________|________________________|______________________|
| | | |
| Liquefied petroleum gas (LPG) | 59.65 | 25.66 |
|________________________________|________________________|______________________|
| | | |
| Pure propane | 59.66 | 25.31 |
|________________________________|________________________|______________________|
| | | |
| Propylene | 62.46 | 25.39 |
|________________________________|________________________|______________________|
| | | |
| Ethane | 56.68 | 17.22 |
|________________________________|________________________|______________________|
| | | |
| Ethylene | 63.86 | 27.90 |
|________________________________|________________________|______________________|
| | | |
| Isobutane | 61.48 | 27.06 |
|________________________________|________________________|______________________|
| | | |
| Isobutylene | 64.16 | 28.73 |
|________________________________|________________________|______________________|
| | | |
| Butane | 60.83 | 28.44 |
|________________________________|________________________|______________________|
| | | |
| Butene | 64.15 | 28.73 |
|________________________________|________________________|______________________|
| | | |
| Natural gasoline | 63.29 | 30.69 |
|________________________________|________________________|______________________|
| | | |
| Gasoline | 65.40 | 34.87 |
|________________________________|________________________|______________________|
| | | |
| Aviation gasoline | 69.87 | 33.52 |
|________________________________|________________________|______________________|
| | | |
| Aviation-type kerosene | 68.40 | 37.66 |
|________________________________|________________________|______________________| Table 1-3. Emission factors by fuel type
(QC.1.3.1(1), QC.1.3.2, QC.1.4.1(1), QC.1.4.4, QC.17.3.1(2))
_________________________________________________________________________________
| | | | | | | |
|Liquid fuels and biofuels | CO2 | CO2 | CH4 | CH4 | N2O | N2O |
| |(kg/l) |(kg/GJ)|(g/l) |(g/GJ)|(g/l) |(g/GJ)|
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Aviation Gasoline |2.342 |69.87 |2.200 |65.630|0.230 |6.862 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Diesel |2.663 |69.53 |0.133 |3.473 |0.400 |10.44 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Aviation Turbo Fuel |2.534 |67.75 |0.080 |2.139 |0.230 |6.150 |
|_____________________________________|_______|_______|______|______|______|______|
| |
|Kerosene |
|_________________________________________________________________________________|
| | | | | | | |
|- Electric Utilities |2.534 |67.25 |0.006 |0.159 |0.031 |0.823 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|- Industrial |2.534 |67.25 |0.006 |0.159 |0.031 |0.823 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|- Producer Consumption |2.534 |67.25 |0.006 |0.159 |0.031 |0.823 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|- Forestry, Construction and |2.534 |67.25 |0.026 |0.690 |0.031 |0.823 |
| Commercial | | | | | | |
|- Institutional | | | | | | |
|_____________________________________|_______|_______|______|______|______|______|
| |
|Propane |
|_________________________________________________________________________________|
| | | | | | | |
|- Residential |1.510 |59.66 |0.027 |1.067 |0.108 |4.267 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|- All other uses |1.510 |59.66 |0.024 |0.948 |0.108 |4.267 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Ethane |0.976 |56.68 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Butane |1.730 |60.83 |0.024 |0.844 |0.108 |3.797 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Lubricants |1.410 |36.01 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Motor Gasoline |2.289 |65.40 |2.700 |77.140|0.050 |1.429 |
|_____________________________________|_______|_______|______|______|______|______|
| |
|Light Fuel Oil |
|_________________________________________________________________________________|
| | | | | | | |
|- Electric Utilities |2.725 |70.23 |0.180 |4.639 |0.031 |0.799 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|- Industrial |2.725 |70.23 |0.006 |0.155 |0.031 |0.799 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|- Producer Consumption |2.643 |68.12 |0.006 |0.155 |0.031 |0.799 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|- Forestry, Construction, and |2.725 |70.23 |0.026 |0.670 |0.031 |0.799 |
| Commercial | | | | | | |
|- Institutional | | | | | | |
|_____________________________________|_______|_______|______|______|______|______|
| |
|Residual Fuel Oil (#5 & 6) |
|_________________________________________________________________________________|
| | | | | | | |
|- Electric Utilities |3.124 |73.51 |0.034 |0.800 |0.064 |1.506 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|- Industrial |3.124 |73.51 |0.12 |2.824 |0.064 |1.506 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|- Producer Consumption |3.158 |74.31 |0.12 |2.824 |0.064 |1.506 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|- Forestry, Construction, and |3.124 |73.51 |0.057 |1.341 |0.064 |1.820 |
| Commercial | | | | | | |
|- Institutional | | | | | | |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Naphtha |0.625 |17.77 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Petrochemical Feedstocks |0.556 |14.22 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Petroleum Coke |3.826 |82.55 |0.12 |2.589 |0.0265|0.572 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Ethanol (100%) |1.519 |64.9 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Biodiesel (100%) |2.497 |70 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Rendered Animal Fat |2.348 |67.4 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Vegetable Oil |2.585 |77.3 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Biomass and other solid fuels | CO2 | CO2 | CH4 | CH4 | N2O | N2O |
| |(kg/kg)|(kg/GJ)|(g/kg)|(g/GJ)|(g/kg)|(g/GJ)|
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Wood Waste (dry basis) |1.799 |93.7 |0.576 |30 |0.077 |4 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Spent Puling Liquor (dry basis) |1.304 |91.8 |0.041 |2.9 |0.027 |1.9 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Agricultural By-products1 |1.074 |112 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Biomass By-products2 |3.000 |100 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Coal coke |2.480 |86.02 |0.03 |1.041 |0.02 |0.694 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Tires |2.650 |80.8 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Gaseous fuels and biofuels | CO2 | CO2 | CH4 | CH4 | N2O | N2O |
| |(kg/m3)|(kg/GJ)|(g/m3)|(g/GJ)|(g/m3)|(g/GJ)|
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Coke Oven Gas |0.879 |45.92 |0.037 |1.933 |0.0350|1.829 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Still Gas |1.75 |48.50 | N/A | N/A |0.0222|0.615 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Landfill Gas |2.175 |54.63 |0.040 |1.0 |0.004 |0.1 |
|_____________________________________|_______|_______|______|______|______|______|
| | | | | | | |
|Biogas (methane portion) |1.556 |49.4 | N/A | N/A | N/A | N/A |
|_____________________________________|_______|_______|______|______|______|______| 1. By-products not destined for consumption.
2. Animal and vegetable waste, excluding wood waste and spent pulping liquor.
Table 1-4. CO2 emission factors for natural gas
(QC.1.3.1(1), QC.1.3.2(1), QC.17.3.1(2))
_________________________________________________________________________________
| | |
| Marketable gas | Marketable gas |
| (kg CO2/m3) | (kg CO2/GJ) |
|___________________________________________________|_____________________________|
| | |
| 1.878 | 49.01 |
|___________________________________________________|_____________________________| Table 1-5. CO2 emission factors for coal
(QC.1.3.1(1), QC.1.3.2(1), QC.17.3.1(2))
__________________________________________________________________________________
| | | |
| Source | Emission factor | Emission factor |
| | (kg CO2/ kg) | (kg CO2/GJ) |
|___________________________|________________________|_____________________________|
| | | |
| - Canadian bituminous | 2.25 | 85.5 |
|___________________________|________________________|_____________________________|
| | | |
| - U.S. bituminous | 2.34 | 88.9 |
|___________________________|________________________|_____________________________|
| | | |
| - Anthracite | 2.39 | 86.3 |
|___________________________|________________________|_____________________________| Table 1-6. Other emission factors
(QC.1.3.1(1), QC.1.3.2(1), QC.17.3.1(2))
_________________________________________________________________________________
| | | | |
| Source | CO2 emission | CH4 emission | N2O emission |
| | factor | factor | factor |
| | (kg/GJ) | (g/GJ) | (g/GJ) |
|_______________________|___________________|__________________|__________________|
| | | | |
| Municipal Solid Waste | 85.6 | 30 | 4.0 |
|_______________________|___________________|__________________|__________________|
| | | | |
| Peat | 103.0 | 1.0 | 1.5 |
|_______________________|___________________|__________________|__________________| Table 1-7. CH4 and N2O emission factors for natural gas by use
(QC.1.4.1(1), QC.1.4.4)
________________________________________________________________________________
| | | | | |
| Uses | CH4 (g/m3) | CH4 (g/GJ) | N2O (g/ m3) | N2O (g/GJ) |
|______________________|______________|______________|______________|____________|
| | | | | |
| Electric Utilities | 0.490 | 12.790 | 0.049 | 1.279 |
|______________________|______________|______________|______________|____________|
| | | | | |
| Industrial | 0.037 | 0.966 | 0.033 | 0.861 |
|______________________|______________|______________|______________|____________|
| | | | | |
| Producer Consumption | | | | |
| (Non-marketable) | 6.500 | 169.600 | 0.060 | 1.566 |
|______________________|______________|______________|______________|____________|
| | | | | |
| Pipelines | 1.900 | 49.580 | 0.050 | 1.305 |
|______________________|______________|______________|______________|____________|
| | | | | |
| Cement | 0.037 | 0.966 | 0.034 | 0.887 |
|______________________|______________|______________|______________|____________|
| | | | | |
| Manufacturing | | | | |
| Industries | 0.037 | 0.966 | 0.033 | 0.861 |
|______________________|______________|______________|______________|____________|
| | | | | |
| Residential, | | | | |
| Construction, | | | | |
| Commercial/ | | | | |
| Institutional, | | | | |
| Agriculture | 0.037 | 0.966 | 0.035 | 0.913 |
|______________________|______________|______________|______________|____________| Table 1-8. CH4 and N2O emission factors for coal by use
(QC.1.4.1(1))
_________________________________________________________________________________
| | | |
| Uses | Emission factor | Emission factor |
| | (g CH4/ kg coal) | (g N2O/kg coal) |
|___________________________|___________________________|_________________________|
| | | |
| - Electric utilities | 0.022 | 0.032 |
|___________________________|___________________________|_________________________|
| | | |
| - Industry and heat and | | |
| Steam Plants | 0.030 | 0.020 |
|___________________________|___________________________|_________________________|
| | | |
| - Residential, Public | | |
| Administration | 4.000 | 0.020 |
|___________________________|___________________________|_________________________| Table 1-9. Flow meter tests
(QC.1.5.2(3))
_________________________________________________________________________________
| | |
| Standardization | Method |
| organization |__________________________________________________________|
| | | |
| | Number | Title |
|______________________|______________________|___________________________________|
| | | |
| American Society of | ASME MFC-3M-2004 | Measurement of Fluid Flow in Pipes|
| Mechanical Engineers | | Using Orifice, Nozzle, and Venturi|
| (ASME) |______________________|___________________________________|
| | | |
| | ASME MFC-4M-1986 | Measurement of Gas Flow by Turbine|
| | (Reaffirmed 2008) | Meters |
| |______________________|___________________________________|
| | | |
| | ASME MFC-5M-1985 | Measurement of Liquid Flow in |
| | (Reaffirmed 2006) | Closed |
| | | Conduits Using Transit-Time |
| | | Ultrasonic |
| | | Flowmeters |
| |______________________|___________________________________|
| | | |
| | ASME MFC-6M-1998 | Measurement of Fluid Flow in Pipes|
| | (Reaffirmed 2005) | Using Vortex Flowmeters |
| |______________________|___________________________________|
| | | |
| | ASME MFC-7M-1987 | Measurement of Gas Flow by Means |
| | (Reaffirmed 2006) | of Critical Flow Venturi Nozzles |
| |______________________|___________________________________|
| | | |
| | ASME MFC-9M-1988 | Measurement of Liquid Flow in |
| | (Reaffirmed 2006) | Closed |
| | | Conduits by Weighing Method |
|______________________|______________________|___________________________________|
| | | |
| International | ISO 8316: 1987 | Measurement of Liquid Flow in |
| Organization for | | Closed |
| Standardization(ISO) | | Conduits - Method by Collection of|
| | | the Liquid in a Volumetric Tank |
|______________________|______________________|___________________________________|
| | | |
| American Gas | AGA Report No. 3 | Orifice Metering of Natural Gas |
| Association (AGA) | | Part 1: |
| | | General Equations & Uncertainty |
| | | Guidelines (1990) |
| |______________________|___________________________________|
| | | |
| | AGA Report No. 3 | Orifice Metering of Natural Gas |
| | | Part 2: |
| | | Specification and Installation |
| | | Requirements (2000) |
| |______________________|___________________________________|
| | | |
| | AGA Report No. 7 | Measurement of Natural Gas by |
| | | Turbine |
| | | Meter (2006) |
|______________________|______________________|___________________________________|
| | | |
| American Society of | ASHRAE 41.8-1989 | Standard Methods of Measurement of|
| Heating, | | Flow of Liquids in Pipes Using |
| Refrigerating and | | Orifice |
| Air-Conditioning | | Flowmeters |
| Engineers (ASHRAE) | | |
|______________________|______________________|___________________________________| Table 1-10. Density
(QC.1.5.2)
_________________________________________________________________________________
| | |
| Fuel | Density |
| | (kg/l) |
|_______________________________________|_________________________________________|
| | |
| Light fuel oil no. 1 | 0.81 |
|_______________________________________|_________________________________________|
| | |
| Light fuel oil no. 2 | 0.86 |
|_______________________________________|_________________________________________|
| | |
| Heavy fuel oil no. 6 | 0.97 |
|_______________________________________|_________________________________________| QC.2. REFINERY FUEL GAS COMBUSTION
QC.2.1. Covered sources
The covered sources are stationary combustion units that combust gaseous fuels such as refinery fuel gas, flexigas or associated gas.
Notwithstanding the first paragraph, emissions attributable to the combustion of gas fuels at a flare must be calculated in accordance with QC.9.3.5.
QC.2.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information for each type of gaseous fuel (refinery fuel gas, flexigas and associated gas):
(1) the annual CO2, CH4 and N2O emissions, in metric tons;
(1.1) the emissions attributable to the combustion of gas fuels at a flare, calculated in accordance with QC.9.3.5, in metric tons CO2 equivalent;
(2) the annual consumption of gaseous fuel, in thousands of cubic metres at standard conditions;
(3) the average annual carbon content of each gaseous fuel when used to calculate CO2 emissions, in kilograms of carbon per kilogram of gaseous fuel;
(4) (subparagraph revoked);
(5) the average annual molecular weight of each gaseous fuel when used to calculate CO2 emissions, in kilograms per kilomole;
(6) the number of times that the methods for estimating missing data provided for in QC.2.5 were used.
Subparagraphs 3 and 5 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.
QC.2.3. Calculation methods for CO2, CH4 and N2O emissions
The annual CO2 emissions attributable to stationary units that combust gaseous fuels must be calculated by adding together the daily CO2 emissions for each supply system for refinery fuel gas, flexigas and associated gas, which emissions must be calculated using one of the calculation methods in QC.2.3.1 to QC.2.3.4.
The annual CH4 and N2O emissions attributable to stationary units that combust gaseous fuels must be calculated using the calculation method in QC.2.3.5.
QC.2.3.1. Use of a continuous emission monitoring and recording system
The annual CO2 emissions attributable to the combustion of gaseous fuels may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.
QC.2.3.2. Calculation of CO2 emissions for each supply system for refinery fuel gas and flexigas
The annual CO2 emissions for each supply system for refinery fuel gas and flexigas must be calculated based on the carbon content and molecular weight of the refinery fuel gas or flexigas, using equation 2-1:
Equation 2-1
Where:
CO2 = Annual CO2 emissions attributable to the combustion of refinery gas or flexigas, in metric tons;
n = Number of days of operation in the year;
m = Number of supply systems;
i = Day;
j = Supply system;
RFGij = Consumption of refinery gas or flexigas in supply system j for day i, in thousands of cubic metres at standard conditions;
CCij = Carbon content of the sample of refinery gas or flexigas in supply system j for day i, measured in accordance with QC.2.4.2, in kilograms of carbon per kilogram of fuel;
MWij = Molecular weight of the sample of refinery gas or flexigas in supply system j for day i, in kilograms per kilomole;
MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
3.664 = Ratio of molecular weights, CO2 to carbon;
1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres.
QC.2.3.3. Calculation of CO2 emissions for associated gas
The annual CO2 emissions for associated gas may be calculated using the calculation method in QC.1.3.2, with the exception of an emitter to whom section 6.6 of this Regulation applies, or using the method in QC.1.3.3.
QC.2.3.4. Calculation of CO2 emissions for gases mixed prior to combustion
In addition to the methods in QC.2.3.1 and QC.2.3.2, for gases mixed prior to combustion, the emitter may calculate the annual CO2 emissions for each gas before mixing. In this case, the emitter must
(1) measure the flow rate of each fuel stream;
(2) determine the carbon content of each fuel stream before mixing;
(3) calculate the CO2 emissions for each fuel stream using the following methods:
(a) for natural gas and associated gas, in accordance with QC.1.3.2, with the exception of an emitter to whom section 6.6 of this Regulation applies, or in accordance with QC.1.3.3;
(b) for flexigas, refinery fuel gas and low heat content gas, in accordance with QC.2.3.2;
(4) add together the CO2 emissions for each stream to determine the total emissions for the mixture.
QC.2.3.5. Calculation of CH4 and N2O emissions attributable to the combustion of gaseous fuels
The annual CH4 and N2O emissions attributable to the combustion of gaseous fuels must be calculated in accordance with QC.1.4.
QC.2.4. Sampling, analysis and measurement requirements
QC.2.4.1. Consumption of gaseous fuels
The consumption of gaseous fuels must be calculated daily using the methods in QC.1.5.2.
QC.2.4.2. Carbon content and molecular weight of gaseous fuels
When the calculation method in QC.2.3.2 is used, the emitter must measure the carbon content and molecular weight of the gaseous fuels daily, using one of the following methods:
(1) in accordance with QC.1.5.5;
(2) using the chromatographic analysis of gaseous fuels, provided that the gas chromatograph is maintained and calibrated according to the manufacturer’s instructions.
QC.2.4.3. (Revoked).
QC.2.4.4. (Revoked).
QC.2.5. Methods for estimating missing data
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods specified in QC.2.3.2 must,
(a) when the missing data concern high heat value, carbon content, molecular mass or any other data sampled to calculate greenhouse gas emissions,
(i) determine the sampling or measurement rate using the following equation:
Equation 2-2
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.2.4;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern gas consumption, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.3. ALUMINUM PRODUCTION
QC.3.1. Covered sources
The covered sources are all the processes used for primary aluminum production.
QC.3.2. Reporting requirements for greenhouse gas emissions
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) the annual CO2 emissions attributable to anode consumption from prebaked and Søderberg electrolysis cells, in metric tons;
(2) the annual CO2 emissions attributable to anode and cathode baking, in metric tons;
(3) the annual CF4 and C2F6 emissions attributable to anode effects, in metric tons;
(4) the annual CO2 emissions attributable to green coke calcination, in metric tons;
(5) the annual SF6 emissions attributable to cover gas consumption, in metric tons;
(6) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;
(7) the annual liquid aluminum production, in metric tons;
(8) for the use of the prebaked anodes process, the annual net prebaked anode consumption for liquid aluminum production, in metric tons of anodes per metric ton of liquid aluminum;
(9) for the use of the Søderberg anodes process, the annual anode paste consumption, in metric tons of paste per metric ton of liquid aluminum;
(10) for the use of the baking process for prebaked anodes or cathodes, the annual quantity of baked anodes or cathodes removed from furnace, in metric tons;
(11) for the use of the coke calcination process:
(a) the annual consumption of green coke, in metric tons;
(b) the annual quantity of calcinated coke produced, in metric tons;
(c) the annual quantity of under-calcinated coke produced, in metric tons;
(12) for CF4 or C2F6 emissions:
(a) the slope determined in accordance with the method in QC.3.6.1, in metric tons of CF4 per metric ton of liquid aluminum, per anode effect minute, per pot-day for each series of pots using the same technology, and the date on which the slope is determined for each series of pots;
(b) (subparagraph revoked);
(c) (subparagraph revoked);
(d) (subparagraph revoked);
(e) (subparagraph revoked);
(f) the overvoltage coefficient determined in accordance with the method in QC.3.6.1, in metric tons of CF4 per metric ton of aluminum, per millivolt for each series of pots using the same technology;
(g) (subparagraph revoked);
(h) (subparagraph revoked);
(13) (subparagraph revoked);
(14) the number of times that the methods for estimating missing data provided for in QC.3.7 were used;
(15) (subparagraph revoked);
(16) the annual quantity of aluminum hydrate produced, calculated at the precipitation stage, in metric tons of aluminum hydrate (Al2O3) equivalent.
Subparagraph f of subparagraph 12 of the first paragraph does not apply to the CF4 or C2F6 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraphs 1, 2 and 4 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraph 6 of the first paragraph are emissions attributable to combustion;
(3) the emissions referred to in subparagraphs 3 and 5 of the first paragraph are other emissions.
QC.3.3. Calculation methods for CO2 emissions
QC.3.3.1. Calculation of CO2 emissions attributable to the consumption of prebaked anodes
The annual CO2 emissions attributable to the consumption of prebaked anodes must be calculated using equation 3-1:
Equation 3-1
Where:
CO2 = Annual CO2 emissions attributable to the consumption of prebaked anodes, in metric tons;
i = Month;
NAC = Net anode consumption for liquid aluminum production for month i, in metric tons of anodes per metric ton of liquid aluminum;
MP = Production of liquid aluminum for month i, in metric tons;
Sa = Sulphur content in the prebaked anodes for month i, in kilograms of sulphur per kilogram of prebaked anodes;
Asha = Ash content in the prebaked anodes for month i, in kilograms of ash per kilogram of prebaked anodes;
3.664 = Ratio of molecular weights, CO2 to carbon.
QC.3.3.2. Calculation of CO2 emissions attributable to anode consumption from Søderberg electrolysis cells
The annual CO2 emissions attributable to anode consumption from Søderberg electrolysis cells must be calculated using equation 3-2:
Equation 3-2
Where:
CO2 = Annual CO2 emissions attributable to anode consumption from Søderberg electrolysis cells, in metric tons;
i = Month;
PC = Anode paste consumption for month i, in metric tons of paste per metric ton of liquid aluminum;
MP = Production of liquid aluminum for month i, in metric tons;
CSM = Emissions of cyclohexane-soluble matter (CSM) or the International Aluminium Institute factor used, in kilograms of CSM per metric ton of liquid aluminum;
BC = Average content of pitch or other binding agent in paste for month i, in kilograms of pitch or other binding agent per kilogram of paste;
Sp = Sulphur content in pitch or other binding agent for month i, in kilograms of sulphur per kilogram of pitch or other binding agent;
Ashp = Ash content in pitch or other binding agent, in kilograms of ash per kilogram of pitch or other binding agent;
Hp = Hydrogen content in pitch or other binding agent, in kilograms of hydrogen per kilogram of pitch or other binding agent or the International Aluminium Institute factor used;
Sc = Sulphur content in calcinated coke, in kilograms of sulphur per kilogram of calcinated coke;
Ashc = Ash content in calcinated coke, in kilograms of ash per kilogram of calcinated coke;
CP = Monthly reported carbon present in the dust from Søderberg electrolysis cells, in kilograms of carbon per kilogram of liquid aluminum produced, or a value of 0;
3.664 = Ratio of molecular weights, CO2 to carbon.
QC.3.3.3. Calculation of CO2 emissions attributable to anode and cathode baking
The annual CO2 emissions attributable to anode and cathode baking must be calculated using the following calculation methods:
(1) for annual CO2 emissions, using equation 3-3:
Equation 3-3
CO2 = CO2 PM + CO2 P
Where:
CO2 = Annual CO2 emissions attributable to anode and cathode baking, in metric tons;
CO2 PM = Annual CO2 emissions attributable to packing material calculated in accordance with equation 3-4, in metric tons;
CO2 P = Annual CO2 emissions attributable to the coking of pitch or another binding agent, calculated in accordance with equation 3-5, in metric tons;
(2) for emissions of CO2 attributable to packing material, using equation 3-4:
Equation 3-4
Where:
CO2 PM = Annual CO2 emissions attributable to packing material, in metric tons;
i = Month;
CPM = Consumption of packing material for month i, in metric tons of packing material per metric ton of baked anodes or cathodes;
BAC = Quantity of baked anodes or cathodes removed from furnace for month i, in metric tons;
Ashpm = Ash content of packing material for month i, in kilograms of ash per kilogram of packing material;
Spm = Sulphur content of packing material for month i, in kilograms of sulphur per kilogram of packing material;
3.664 = Ratio of molecular weights, CO2 to carbon;
(3) for emissions of CO2 attributable to the coking of pitch or another binding agent, using equation 3-5:
Equation 3-5
Where:
CO2 P = Annual CO2 emissions attributable to the coking of pitch or another binding agent, in metric tons;
i = Month;
GAC = Quantity of green anodes or cathodes put into furnace during month i, in metric tons;
BAC = Quantity of baked anodes or cathodes removed from furnace for month i, in metric tons;
Hp = Hydrogen content in pitch or other binding agent for month i or the International Aluminium Institute factor used, in kilograms of hydrogen per kilogram of pitch or other binding agent;
PC = Pitch or other binding agent content of green anodes or cathodes for month i, in kilograms of pitch or other binding agent per kilogram of green anodes or cathodes;
RT = Recovered tar for month i, in metric tons;
3.664 = Ratio of molecular weights, CO2 to carbon.
QC.3.3.4. Calculation of CO2 emissions attributable to green coke calcination
The annual CO2 emissions attributable to green coke calcination must be calculated using equation 3-6:
Equation 3-6
Where:
CO2 = Annual CO2 emissions attributable to green coke calcination, in metric tons;
i = Month;
GC = Consumption of green coke for month i, in metric tons;
H2Ogc = Humidity content of green coke for month i, in kilograms of water per kilogram of green coke;
Vgc = Volatiles content of green coke for month i, in kilograms of volatiles per kilogram of green coke;
Sgc = Sulphur content of green coke for month i, in kilograms of sulphur per kilogram of green coke;
CC = Calcinated coke produced for month i, in metric tons;
UCC = Under-calcinated coke produced for month i, in metric tons;
ED = Emissions of coke dust for month i, in metric tons;
Scc = Sulphur in calcinated coke, in kilograms of sulphur per kilogram of calcinated coke;
3.664 = Ratio of molecular weights, CO2 to carbon;
0.035 = CH4 and tar content in coke volatiles contributing to CO2 emissions;
2.75 = Conversion factor, CH4 to CO2.
QC.3.4. Calculation method for CF4 and C2F6 emissions
Annual CF4 and C2F6 emissions must be calculated using one of the calculation methods in QC.3.4.1 and QC.3.4.2.
QC.3.4.1. Use of a continuous emission monitoring and recording system
The annual CF4 and C2F6 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.3.6.1.
QC.3.4.2. Annual CF4 and C2F6 emissions
The annual CF4 and C2F6 emissions must be calculated for each series of pots using the same technology, using the following methods:
(1) for CF4 emissions, using equation 3-7 or equation 3-8:
Equation 3-7
Where:
CF4 = Annual CF4 emissions, in metric tons;
i = Month;
slopeCF4 = Slope for series of pots j, determined in accordance with the method in QC.3.6.1, in metric tons of CF4 per metric ton of liquid aluminum, per anode effect minute, per pot-day, for month i;
AED = Anode effect duration, in anode effect minutes per pot-day, calculated for month i and obtained by multiplying the anode effects frequency, in number of anode effects per pot-day, by the average duration of anode effects, in minutes;
MP = Monthly production of liquid aluminum, in metric tons;
Equation 3-8
Where:
CF4 = Annual CF4 emissions attributable to anode effects, in metric tons;
m = Number of series of pots;
j = Series of pots;
i = Month;
OVCCF4 = Overvoltage coefficient determined in accordance with the method in QC.3.6.1, in metric tons of CF4 per metric ton of liquid aluminum per millivolt;
AEO = Monthly anode effect overvoltages, in millivolts per pot;
CE = Current efficiency of the aluminum production process, expressed as a fraction;
MP = Monthly production of liquid aluminum, in metric tons;
(2) for C2F6 emissions, using equation 3-8.1:
Equation 3-8.1
Where:
C2F6 = Annual C2F6 emissions, in metric tons;
i = Month;
CF4 = CF4 emissions for month i, in metric tons;
F = C2F6/CF4 weight fraction, determined by the emitter or selected from Table 3-1 in QC.3.8, in kilograms of C2F6 per kilogram of CF4.
QC.3.4.3. (Replaced);
QC.3.5. Calculation method for emissions of SF6 used as a cover gas
The annual emissions of SF6used as a cover gas must be calculated using one of the calculation methods in QC.3.5.1 and QC.3.5.2.
QC.3.5.1. Calculation based on change in inventory
The annual SF6 emissions may be calculated based on the change in inventory using equation 3-9:
Equation 3-9
SF6 = SInv-Begin -SInv-End + SPurchased -SShipped
Where:
SF6 = Annual emissions of SF6 used as a cover gas, in metric tons;
SInv-Begin = Quantity of SF6 in storage at the beginning of the year, in metric tons;
SInv-End = Quantity of SF6 in storage at the end of the year, in metric tons;
SPurchased = Quantity of SF6 purchases for the year, in metric tons;
SShipped = Quantity of SF6 shipped out of the establishment during the year, in metric tons.
QC.3.5.2. Calculation based on direct measurement
The annual SF6emissions may be calculated based on direct measurement using equation 3-10:
Equation 3-10
Where:
SF6 = Annual emissions of SF6 used as a cover gas, in metric tons;
i = Month;
QInput = Quantity of cover gas entering the electrolysis cells for month i, in metric tons;
CInput = Concentration of SF6 in the cover gas entering the electrolysis cells for month i, in metric tons of SF6 per metric ton of input gas;
QOutput = Quantity of gas containing SF6 collected and shipped out of the establishment for month i, in metric tons;
COutput = Concentration of SF6 in the gas collected and shipped out of the establishment for month i, in metric tons of SF6 per metric ton of gas collected and shipped out of the establishment.
QC.3.6. Sampling, analysis and measurement requirements
An emitter who operates a facility or establishment that produces aluminum must measure all parameters monthly, subject to the following exceptions:
(1) for the emissions of cyclohexane-soluble matter used in the calculation in equation 3-2 in QC.3.3.2, the emitter may measure the emissions monthly or use International Aluminium Institute factors;
(2) for the carbon present in dust from Söderberg electrolysis cells used in the calculation in equation 3-2 in QC.3.3.2, the emitter may measure the carbon monthly or use the value of 0;
(3) for the hydrogen content in pitch used in the calculation in equation 3-2 in QC.3.3.2 and equation 3-5 in QC.3.3.3, the emitter may measure the content monthly or use the International Aluminium Institute factors;
(4) for the parameters relating to CF4 and C2F6 emissions attributable to anode effects and referred to in QC.3.4, the emitter must measure the parameters in accordance with QC.3.6.1;
(5) for the parameters concerning the use of SF6 and referred to in QC.3.5, the emitter must measure the parameters in accordance with QC.3.6.2;
(6) in the case of the quantity of calcinated coke, the emitter may directly measure that quantity or determine it by multiplying the recovery factor by the quantity of green coke consumed, in accordance with equation 3-10-1:
Equation 3-10.1
CCPM = RF × CGC
Where:
CCPM = Calcinated coke produced and measured during the measurement campaign, in metric tons;
RF = Recovery factor determined yearly during a measurement campaign, in metric tons of calcinated coke per metric ton of green coke;
CGC = Consumption of green coke measured during the measurement campaign, in metric tons.
QC.3.6.1. CF4 and C2F6 emissions from anode effects
An emitter who uses a continuous emission monitoring and recording system for CF4 and C2F6 emissions attributable to anode effects must comply with the guidelines in the document “Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories” published by the Intergovernmental Panel on Climate Change.
An emitter who uses the slope method or the Péchiney method specified in QC.3.4.2 must conduct performance tests to calculate the slope or overvoltage coefficients for each technology used in a series of pots using the Protocol for Measurement of Tetrafluoromethane and Hexafluoroethane Emissions from Primary Aluminum Production published in April 2008 by the U.S. Environmental Protection Agency (USEPA) and the International Aluminum Institute. The tests must be conducted again whenever
(1) 36 months have passed since the last tests;
(2) a change occurs in the control algorithm that affects the intensity or duration of the anode effects or the nature of the anode effect termination routine; or
(3) changes occur in the distribution or duration of anode effects, for example when the percentage of manual kills changes or when, over time, the number of anode effects decreases and results in anode effects of shorter duration, or when the algorithm for bridge movements and anode effect overvoltage accounting changes.
QC.3.6.2. Emissions of SF6 used as a cover gas
An emitter who uses the direct measurement method in QC.3.5.2 to calculate SF6 emissions attributable to the consumption of cover gas must measure monthly the quantity of SF6 entering the electrolysis cells and the quantity and SF6 concentration of any residual gas collected and shipped out of the establishment.
QC.3.7. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, reanalyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern carbon content, sulphur content, ash content, hydrogen content, water content, CSM emissions, pitch content, carbon present in skimmed dust from electrolysis cells, volatiles content, data for slope calculations, frequency and duration of anode effects, overvoltage, SF6 concentration or data to calculate current efficiency,
(i) determine the sampling or measurement rate using the following equation:
Equation 3-11
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.3.6;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern net anode consumption, anode paste consumption, packing material consumption, green anode or cathode consumption, quantity of tar recovered, green coke consumption, liquid aluminum production, aluminum hydrate production, baked anode or cathode production, calcinated and under-calcinated coke production, coke dust quantity or SF6 quantity, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.3.8 Table
Table 3-1. C2F6/CF4 weight fractions based on the technology used
(QC.3.4.2)
________________________________________________________________
| | |
| Technology used | Weight fraction |
| | (kg C2F6/kg CF4) |
|_____________________________________|__________________________|
| | |
| Centre-worked prebaked anodes | 0.121 |
| (CWPB) | |
|_____________________________________|__________________________|
| | |
| Side-worked prebaked anodes | 0.252 |
| (SWPB) | |
|_____________________________________|__________________________|
| | |
| Vertical stud Söderberg (VSS) | 0.053 |
|_____________________________________|__________________________|
| | |
| Horizontal stud Söderberg (HSS) | 0.085 |
|_____________________________________|__________________________| QC.4. CEMENT PRODUCTION
QC.4.1. Covered sources
The covered sources are all the processes used to produce Portland, natural, masonry, pozzolanic, or other hydraulic cements.
QC.4.2. Greenhouse gas emissions reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular,
(1) (subparagraph revoked);
(2) the annual CO2 emissions attributable to the calcination process, in metric tons;
(3) for each cement kiln:
(a) the monthly CO2 emission factors, in metric tons of CO2 per metric ton of clinker;
(b) the annual quantity of clinker produced, in metric tons;
(c) (subparagraph revoked);
(d) (subparagraph revoked);
(d.1) (subparagraph revoked);
(d.2) (subparagraph revoked);
(e) (subparagraph revoked);
(f) (subparagraph revoked);
(g) (subparagraph revoked);
(h) the quarterly CO2 emission factors for the dust collected that is not recycled to the cement kiln, in metric tons of CO2 per metric ton of dust;
(h.1) (subparagraph revoked);
(h.2) (subparagraph revoked);
(i) the annual quantity of dust collected that is not recycled to the cement kiln, in metric tons;
(4) (subparagraph revoked);
(5) the annual CO2 emissions attributable to the oxidation of organic carbon, in metrictons;
(6) for each type of carbon-containing raw material that contributes 0.5% or more of the total carbon in the process:
(a) the quantity of raw material consumed during the year, in metric tons;
(b) the total organic carbon content of the raw material, in metric tons of organic carbon per metric ton of raw material;
(7) (subparagraph revoked);
(8) annual CO2, CH4 and N2O emissions attributable to the use of all fixed combustion equipment, calculated and reported in accordance with QC.1 in metric tons;
(9) the number of times that the methods for estimating missing data in QC.4.5 were used;
(10) (subparagraph revoked);
(11) the annual quantities of gypsum and limestone added to the clinker produced by the establishment, in metric tons.
Subparagraphs a and h of subparagraph 3 and subparagraph b of subparagraph 6 of the first paragraph do not apply to the emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraphs 2 and 5 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraph 8 of the first paragraph are emissions attributable to combustion.
QC.4.3. Calculation method for CO2, CH4 and N2O emissions from the use of cement kilns
The annual CO2 emissions attributable to the use of cement kilns, other than combustion emissions, must be calculated in accordance with one of the 2 calculation methods in QC.4.3.1 and QC.4.3.2.
The annual CO2, CH4 and N2O emissions attributable to the combustion of fuels in all cement kilns must be calculated in accordance with QC.4.3.3.
QC.4.3.1. Use of a continuous emission monitoring and recording system
The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4. In addition, the CO2 emissions attributable to the combustion of fuels in all cement kilns must be calculated in accordance with QC.4.3.3.
QC.4.3.2. Calculation by mass balance
The CO2 emissions attributable to the use of each cement kiln must be calculated by adding together the CO2 emissions attributable to calcination and the CO2 emissions attributable to the oxidation of the organic carbon present in the raw materials, calculated in accordance with the following methods:
(1) the CO2 emissions attributable to calcination must be calculated, for each cement kiln, using equations 4-1 to 4-3:
Equation 4-1
Where:
CO2 - C = CO2 emissions attributable to calcination, in metric tons;
i = Month;
Cli = Monthly production of clinker, in metric tons;
EFCli = Monthly CO2 emission factor for the clinker, established using equation 4-2, in metric tons of CO2 per metric ton of clinker;
j = Quarter;
QCKD = Quarterly quantity of dust collected that is not recycled to the cement kiln, in metric tons;
EFCKD = Quarterly CO2 emission factor for the dust collected that is not recycled to the cement kiln, established using equation 4-3, in metric tons of CO2 per metric ton of dust;
Equation 4-2
EFCli = (CaOCli - CaONCC) × 0.785 + (MgOCli - MgONCC) × 1.092
Where:
EFCli = Monthly CO2 emission factor for the clinker, in metric tons of CO2 per metric ton of clinker;
CaOCli = Monthly content of calcium oxide in the clinker, determined in accordance with paragraph 1 of QC.4.4, in metric tons of calcium oxide per metric ton of clinker;
CaONCC = Monthly content of non-calcined calcium oxide in the clinker, in metric tons of non-calcined calcium oxide per metric ton of clinker.
The non-calcined calcium oxide content in the clinker is the sum of the CaO content present as a non-carbonate species in the raw materials entering the kiln and the non-transformed CaCO3 content remaining in the clinker after oxidation, expressed as CaO; these values must be determined, respectively, in accordance with paragraphs 4 and 5 of QC.4.4, or a value of 0 must be used;
0.785 = Ratio of molecular weights, CO2 to calcium oxide;
MgOCli = Monthly content of magnesium oxide in the clinker, determined in accordance with paragraph 1 of QC.4.4, in metric tons of magnesium oxide per metric ton of clinker;
MgONCC = Monthly content of non-calcined magnesium oxide in the clinker, in metric tons of noncalcined magnesium oxide per metric ton of clinker.
The non-calcined magnesium oxide content in the clinker is the sum of the MgO content present as a non-carbonate species in the raw materials entering the kiln and the non-transformed MgCO3 content remaining in the clinker after oxidation, expressed as MgO; these values must be determined, respectively, in accordance with paragraphs 4 and 5 of QC.4.4, or a value of 0 must be used;
1.092 = Ratio of molecular weights, CO2 to magnesium oxide;
Equation 4-3
EFCKD = (CaOCKD - CaONCD) × 0.785 + (MgOCKD - MgONCD) × 1.092
Where:
EFCKD = Quarterly CO2 emission factor for the dust collected that is not recycled to the cement kiln, in metric tons of CO2 per metric ton of dust;
CaOCKD = Quarterly content of calcium oxide in the dust collected that is not recycled to the cement kiln, determined in accordance with paragraph 6 of QC.4.4, in metric tons of calcium oxide per metric ton of dust;
CaONCD = Quarterly content of non-calcined calcium oxide in the dust collected that is not recycled to the cement kiln, in metric tons of non-calcined calcium oxide per metric ton of dust.
The non-calcined calcium oxide content in the dust is the sum of the CaO content present as a non-carbonate species in the raw materials entering the kiln and the non-transformed CaCO3 content remaining in the kiln dust collected that is not recycled after oxidation, expressed as CaO; these values must be determined, respectively, in accordance with paragraphs 7 and 8 of QC.4.4, or a value of 0 must be used;
0.785 = Ratio of molecular weights, CO2 to calcium oxide;
MgOCKD = Quarterly content of magnesium oxide in the kiln dust collected that is not recycled in the cement kiln, determined in accordance with paragraph 6 of QC.4.4, in metric tons of magnesium oxide per metric ton of dust;
MgONCD = Quarterly content of non-calcined magnesium oxide in the dust collected that is not recycled to the cement kiln, in metric tons of noncalcined magnesium oxide per metric ton of dust.
The non-calcined magnesium oxide content in the dust is the sum of the magnesium oxide that enters the kiln as a non-carbonate species and the non-transformed MgCO3 content remaining in the kiln dust collected that is not recycled after oxidation, expressed as MgO; these values must be determined, respectively, in accordance with paragraphs 7 and 8 of QC.4.4, or a value of 0 must be used;
1.092 = Ratio of molecular weights, CO2 to magnesium oxide;
(2) the CO2 emissions attributable to the oxidation of the organic carbon present in the raw material must be calculated using equation 4-4:
Equation 4-4
Where:
CO2,RMm = CO2 emissions resulting from the oxidation of the raw material, in metric tons;
n = Number of raw materials;
m = Raw material;
TOCRMm = Total organic carbon content in raw material, determined in accordance with paragraph 10 of QC.4.4 or using a default value of 0.2% metric tons of total organic carbon content per metric ton of raw material;
RMm = Quantity of raw material, in metric tons;
3.664 = Ratio of molecular weights, CO2 to carbon.
QC.4.3.3. Calculation of the emissions attributable to the combustion of the fuels used in cement kilns
The CO2, CH4 and N2O emissions attributable to fuel combustion in each cement kiln must be calculated and reported using the calculation methods in QC.1. When pure biomass fuels, in other words fuels constituted of the same substance for at least 97% of their total weight, are combusted only during start-up, shut-down, or malfunction operating periods for the apparatus or units, the emitter may calculate CO2 emissions using the calculation method in QC.1.3.1.
QC.4.4. Sampling, analysis and measurement requirements
When using the calculation method in QC.4.3.2, an emitter who operates a facility or establishment that produces cement must
(1) determine monthly the calcium oxide and magnesium oxide content of the clinker, in accordance with the most recent version of ASTM C114 “Standard Test Methods for Chemical Analysis of Hydraulic Cement”, or using any other analysis method published by an organization listed in QC.1.5; the measurements being made daily from clinker drawn from the clinker cooler or monthly from clinker drawn from bulk storage;
(2) determine monthly the quantity of clinker produced using one of the following methods:
(a) direct weight measurement using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders;
(b) direct measurement of raw kiln feed applying a kiln-specific feed-to-clinker conversion factor, the accuracy of the factor being verified by the emitter on an annual basis and whenever a major change to the process may affect the factor;
(3) determine monthly the quantity of raw materials consumed by direct weight measurement using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders, or using a material balance;
(4) determine monthly the calcium oxide and magnesium oxide content of the raw material entering the kiln as a non-carbonate species, in accordance with the most recent version of ASTM C114 or in accordance with any other analysis method published by an organization listed in QC.1.5, or use the value of 0;
(5) determine monthly the non-transformed CaCO3 content and the non-transformed MgCO3, expressed an MgO, remaining in the clinker after oxidation in accordance with the most recent version of ASTM C114, or in accordance with any other analysis method published by an organization listed in QC.1.5, or use the value of 0;
(6) determine quarterly the calcium oxide and magnesium oxide content in the kiln dust collected that is not recycled to the cement kiln in accordance with the most recent version of ASTM C114, or using any other analysis method published by an organization listed in QC.1.5; the measurements being made daily at the exit of the kiln or quarterly if the dust is in bulk storage;
(7) determine quarterly the calcium oxide and magnesium oxide content in the kiln dust collected that is not recycled that enters the kiln as a non-carbonate species in accordance with the most recent version of ASTM C114 or in accordance with any other analysis method published by an organization listed in QC.1.5, or use the value of 0;
(8) determine quarterly the calcium oxide and magnesium oxide content remaining in the kiln dust collected that is not recycled after oxidation in accordance with the most recent version of ASTM C114 or in accordance with any other analysis method published by an organization listed in QC.1.5, or use the value of 0;
(9) determine quarterly the quantity of kiln dust collected that is not recycled to the cement kiln by direct weight measurement using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders, or using a material balance;
(10) take samples annually of each category of raw materials in bulk storage and determine the total organic carbon content of the raw materials in accordance with the most recent version of ASTM C114 or in accordance with any other analysis method published by an organization listed in QC.1.5, or use the value of 0.2%.
QC.4.5. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern carbon content, calcium oxide content or magnesium oxide content,
(i) determine the sampling or measurement rate using the following equation:
Equation 4-5
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.4.4;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern clinker production, the emitter must use the first data estimated after the period for which the data is missing or use the maximum daily production capacity and multiply it by the number of days in the month;
(c) when the missing data concern raw material consumption, the emitter must use the first data estimated after the period for which the data is missing or use the maximum rate of raw materials entering the kiln and multiply by the number of days in the month;
(d) when the missing data concern the quantity of dust, the quantity of gypsum or the quantity of limestone, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.5. COAL STORAGE
QC.5.1. Covered sources
The covered sources are all activities involving coal storage, in other words all post-mining activities such as preparation, handling, processing, transportation and storage.
QC.5.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) the annual CH4 emissions in metric tons;
(2) the annual coal purchases, in metric tons;
(3) the source of coal purchases:
(a) name of coal basin;
(b) source province or state;
(c) coal mine type (surface or underground);
(4) the number of times that the methods for estimating missing data provided for in QC.5.5 were used;
(5) (subparagraph revoked).
QC.5.3. Calculation methods for CH4 emissions
The annual CH4 emissions from coal storage must be calculated in accordance with the following calculation methods:
(1) CH4 emissions from coal storage must be calculated using equation 5-1:
Equation 5-1
Where:
CH4 = Annual CH4 fugitive emissions from coal storage, for each type of coal i, in metric tons;
n = Total number of types of coal;
i = Type of coal;
PCi = Annual purchases of coal, for each type of coal i, in metric tons;
EFi = CH4 emission factor for type of coal i, established in accordance with paragraph 2, in cubic metres of CH4 per metric ton of coal;
0.6772 = Conversion factor, cubic metres to kilograms of CH4;
0.001 = Conversion factor, kilograms to metric tons;
(2) the CH4 emission factor (EFi) must be based on the location and mine type where the coal was mined, in accordance with the following requirements:
(a) when the coal comes from a location in the United States, the emission factor is provided in Table 5-1 in QC.5.6;
(b) when the coal comes from a location in Canada, the emission factor is provided in Table 5-2 in QC.5.6;
(c) when the coal comes from a location outside Canada and the United States, the emission factor must be the factor determined in Table 5-3 in QC.5.6;.
QC.5.4. Sampling, analysis and measurement requirements
An emitter who operates a facility or establishment that stores coal must determine the total quantity of coal purchased
(1) by using invoices for coal purchases; or
(2) by weighing the coal using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders.
QC.5.5. Methods for estimating missing data
The emitter must demonstrate that everything has been done to capture 100% of the data.
When data relating to the total quantity of carbon purchased is missing, the replacement data must be estimated using all the data relating to the processes used.
QC.5.6. Tables
Table 5-1. CH4 emission factors for post-mining activities involving the storage or handling of coal from the United States
(QC.5.3(2)(a))
________________________________________________________________________________
| | |
| | CH4 emission factor by coal |
| Coal origin | mine type (cubic metres |
| | /metric ton) |
|_____________________________________________|__________________________________|
| | | | |
| State | Coal basin | Surface | Underground |
| | | mine | mine |
|_______________________|_____________________|_________________|________________|
| | | | |
| Maryland, Ohio, | Northern Appalachia | | |
| Pennsylvania, | | | |
| West virginia North | | 0.6025 | 1.4048 |
|_______________________|_____________________|_________________|________________|
| | | | |
| Tennessee, West | Central Appalachia | | |
| Virginia South | Appalachia (WV) | 0.2529 | 1.3892 |
|_______________________|_____________________|_________________|________________|
| | | | |
| Virginia | Central | | |
| | Appalachia (VA) | 0.2529 | 4.0490 |
|_______________________|_____________________|_________________|________________|
| | | | |
| East Kentucky | Central | | |
| | Appalachia (EKY) | 0.2529 | 0.6244 |
|_______________________|_____________________|_________________|________________|
| | | | |
| Alabama, Mississippi | Warrior | 0.3122 | 2.7066 |
|_______________________|_____________________|_________________|________________|
| | | | |
| Illinois, Indiana, | Illinois | | |
| Kentucky West | | 0.3465 | 0.6525 |
|_______________________|_____________________|_________________|________________|
| | | | |
| | Rockies | | |
| | (Piceance Basin) | 0.3372 | 1.9917 |
| |_____________________|_________________|________________|
| | | | |
| | Rockies | | |
| Arizona, California, | (Uinta Basin) | 0.1623 | 1.0083 |
| Colorado, New Mexico, |_____________________|_________________|________________|
| Utah | | | |
| | Rockies | | |
| | (San Juan Basin) | 0.0749 | 1.0645 |
| |_____________________|_________________|________________|
| | | | |
| | Rockies | | |
| | (Green River Basin) | 0.3372 | 2.5068 |
| |_____________________|_________________|________________|
| | | | |
| | Rockies | | |
| | (Raton Basin) | 0.3372 | 1.2987 |
|_______________________|_____________________|_________________|________________|
| | | | |
| Montana, North Dakota,| N. Great Plains | | |
| Wyoming | | 0.0562 | 0.1592 |
|_______________________|_____________________|_________________|________________|
| | | | |
| | West Interior | | |
| | (Forest City, | | |
| | Cherokee Basins) | 0.3465 | 0.6525 |
| |_____________________|_________________|________________|
| | | | |
| Arkansas, Iowa, | West Interior | | |
| Kansas, Louisiana, | (Arkoma Basin) | 0.7555 | 3.3591 |
| Missouri, Oklahoma, |_____________________|_________________|________________|
| Texas | | | |
| | West Interior | | |
| | (Gulf coast Basin) | 0.3372 | 1.2987 |
|_______________________|_____________________|_________________|________________|
| | | | |
| Alaska | Northwest (AK) | 0.0562 | 1.6233 |
|_______________________|_____________________|_________________|________________|
| | | | |
| Washington | Northwest (WA) | 0.0562 | 0.5900 |
|_______________________|_____________________|_________________|________________| Table 5-2. CH4 emission factors for post-mining activities involving the storage or handling of coal from Canada
(QC.5.3(2)(b))
_________________________________________________________________________________
| | CH4emission factor by |
| Coal origin | mine type (cubic |
| | metres/ metric ton) |
|____________________________________________________|____________________________|
| | | | |
| Province | Coal basin | Surface | Underground |
| | | mine | mine |
|_________________________|__________________________|______________|_____________|
| | | | |
| British Colombia | Comox | 0.500 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Crowness | 0.169 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Elk Valley | 0.900 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Peace River | 0.361 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Province average | 0.521 | N/A |
|_________________________|__________________________|______________|_____________|
| | | | |
| Alberta | Battle River | 0.067 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Cadomin-Luscar | 0.709 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Coalspur | 0.314 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Obed Mountain | 0.238 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Sheerness | 0.048 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Smokey River | 0.125 | 0.067 |
| |__________________________|______________|_____________|
| | | | |
| | Wabamun | 0.176 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Province average | 0.263 | 0.067 |
|_________________________|__________________________|______________|_____________|
| | | | |
| Saskatchewan | Estavan | 0.055 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Willow Bunch | 0.053 | N/A |
| |__________________________|______________|_____________|
| | | | |
| | Province average | 0.054 | N/A |
|_________________________|__________________________|______________|_____________|
| | | | |
| New Brunswick | Province average | 0.060 | N/A |
|_________________________|__________________________|______________|_____________|
| | | | |
| Nova Scotia | Province average | N/A | 2.923 |
|_________________________|__________________________|______________|_____________| Table 5-3. CH4 emission factors for post-mining activities involving the storage or handling of coal from the outside the United States and Canada
(QC.5.3(2)(c))
_________________________________________________________________
| |
| CH4 emission factor by coal mine type |
| (cubic metres/metric ton) |
|_________________________________________________________________|
| | |
| Surface mine | Underground mine |
|________________________________|________________________________|
| | |
| 0.279 | 1.472 |
|________________________________|________________________________| QC.6. HYDROGEN PRODUCTION
QC.6.1. Covered sources
The covered sources are all the processes used to produce hydrogen.
QC.6.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) the annual CO2 emissions attributable to hydrogen production processes, in metric tons;
(2) the annual feedstock consumption by feedstock type, including petroleum coke, expressed
(a) in bone dry metric tons, when the quantity is expressed as a mass;
(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
(c) in kilolitres, when the quantity is expressed as a volume of liquid;
(d) in bone dry metric tons, for biomass-derived solid fuels;
(3) the annual hydrogen produced, in thousands of cubic metres at standard conditions;
(4) the average annual carbon content of each feedstock type;
(5) the annual CO2, CH4 and N2O emissions attributable to combustion, calculated and reported in accordance with QC.1, in metric tons;
(6) the number of times that the methods for estimating missing data provided for in QC.6.5 were used;
(7) (subparagraph revoked).
Subparagraph 4 of the first paragraph does not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraph 1 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraph 5 of the first paragraph are emissions attributable to combustion.
QC.6.3. Calculation methods for CO2 emissions
CO2 emissions from the production of hydrogen must be calculated using one of the calculation methods in QC.6.3.1 and QC.6.3.2.
QC.6.3.1. Use of a continuous emission monitoring and recording system
The annual CO2 emissions from the production of hydrogen may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.
QC.6.3.2. Calculation by feedstock material balance
The annual CO2 emissions attributable to the production of hydrogen may be calculated by feedstock material balance using equations 6-1 to 6-3, depending on the type of feedstock:
(1) in the case of feedstocks for which the quantity is expressed as a volume of gas, the emitter must use equation 6-1:
Equation 6-1
Where:
CO2 = Annual CO2 emissions attributable to the production of hydrogen, in metric tons;
j = Month;
Qj = Quantity of gaseous feedstock consumed in month j, in thousands of cubic metres at standard conditions, or in metric tons when a mass flowmeter is used;
CCj = Average carbon content of the feedstock based on the analysis results for month j and measured by an emitter in accordance with QC.6.4, in kilograms of carbon per kilogram of feedstock;
MW = Molecular weight of the feedstock, in kilograms per kilomole or, when a mass flowmeter is used to measure the flow, in metric tons per unit of time, replace
_ _
| |
| MW |
|----| by 1;
|MVC |
|_ _| MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
3.664 = Ratio of molecular weights, CO2 to carbon;
1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres;
(2) in the case of feedstocks for which the quantity is expressed as a volume of liquid, the emitter must use equation 6-2:
Equation 6-2
Where:
CO2 = Annual CO2 emissions attributable to the production of hydrogen, in metric tons;
j = Month;
Qj = Quantity of raw material consumed in month j, in kilolitres;
CFj = Average carbon content of feedstock based on the analysis results for month j and measured by an emitter in accordance with QC.6.4, in metric tons of carbon per kilolitre of feedstock;
3.664 = Ratio of molecular weights, CO2 to carbon;
(3) in the case of feedstocks for which the quantity is expressed as a mass, the emitter must use equation 6-3:
Equation 6-3
Where:
CO2 = Annual CO2 emissions attributable to the production of hydrogen, in metric tons;
j = Month;
Qj = Quantity of raw material consumed in month j, in metric tons;
CCj = Average carbon content of the feedstock based on the analysis results for month j and measured by an emitter in accordance with QC.6.4, in kilograms of carbon per kilogram of feedstock;
3.664 = Ratio of molecular weights, CO2 to carbon.
QC.6.4. Sampling, analysis and measurement requirements
An emitter who uses the calculation method in QC.6.3.2 must
(1) measure the feedstock consumption rate daily;
(2) collect samples of each type of feedstock consumed and analyze each sample for average carbon content using the methods specified in paragraph 5,
(a) daily, for all feedstocks except natural gas, by collecting the sample from a location that provides samples representative of the feedstock consumed in the hydrogen production process;
(b) monthly, when natural gas is used as a feedstock and not mixed with another feedstock prior to consumption;
(3) determine the hydrogen produced daily;
(4) determine, quarterly, the quantity of CO2 and of carbon monoxide transferred off-site;
(5) to measure the average carbon content of each type of feedstock, use an analysis method published by an organization listed in QC.1.5 or one of the following analysis methods:
(a) for solid feedstocks, the most recent version of ASTM D2013/D2013M “Standard Practice for Preparing Coal Samples for Analysis”, ASTM D2234/D2234M “Standard Practice for Collection of a Gross Sample of Coal”, ASTM D3176 “Standard Practice for Ultimate Analysis of Coal and Coke”, ASTM D6609 “Standard Guide for Part-Stream Sampling of Coal”, ASTM D6883 “Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles” or ASTM D7430 “Standard Practice for Mechanical Sampling of Coal”;
(b) for liquid feedstocks, the most recent version of ASTM D2597 “Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography”, ASTM D4057 “Standard Practice for Manual Sampling of Petroleum and Petroleum Products”, ASTM D4177 “Standard Practice for Automatic Sampling of Petroleum and Petroleum Products”, ISO 3170 “Petroleum Liquids—Manual sampling” or ISO 3171 “Petroleum liquids—Automatic pipeline sampling”;
(c) for gaseous feedstocks, the most recent version of UOP539 “Refinery Gas Analysis by Gas Chromatography” or GPA 2261 “Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography”.
QC.6.5. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern carbon content or molecular mass,
(i) determine the sampling or measurement rate using the following equation:
Equation 6-4
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.6.4;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern raw material consumption or hydrogen production, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.7. IRON AND STEEL PRODUCTION
QC.7.1. Covered sources
The covered sources are primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet firing processes.
QC.7.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) for all types of process:
(a) (subparagraph revoked);
(b) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;
(2) for metallurgical coke production:
(a) the annual CO2 and CH4 emissions attributable to the production of metallurgical coke, in metric tons;
(b) the annual consumption of coking coal used in the production of metallurgical coke, in metric tons;
(c) (subparagraph revoked);
(d) (subparagraph revoked);
(e) the annual production of metallurgical coke, in metric tons;
(f) the quantity of coke oven gas transferred out of the establishment during the year, in metric tons;
(g) the quantity of other coke oven by-products, such as coal tar and light oil, transferred out of the establishment during the year, in metric tons;
(g.1) the annual quantity of air pollution control residue collected, in metric tons;
(h) the average annual carbon content of the materials input for the production of metallurgical coke and of derivatives of those materials referred to in subparagraphs b to g.1, in metric tons of carbon per metric ton of material;
(h.1) the CH4 emission factors, as the case may be:
(i) determined by the emitter, including the methods that were used for estimating those factors;
(ii) indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);
(3) for steel production using a basic oxygen furnace:
(a) the annual CO2 and CH4 emissions attributable to steel production using a basic oxygen furnace, in metric tons;
(b) the annual consumption of molten iron and ferrous scrap, in metric tons;
(c) the annual consumption of each carbon-containing raw material that contributes 0.5% or more of the total carbon in the process, in metric tons;
(d) the annual production of steel, in metric tons;
(e) the quantity of slag produced, in metric tons;
(f) the quantity of basic oxygen furnace gas transferred off-site during the year, in metric tons;
(g) the annual quantity of air pollution control residue collected, in metric tons;
(h) the average annual carbon content of the materials and products referred to in subparagraphs b to g that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material and products;
(i) the CH4 emission factors, as the case may be:
(i) determined by the emitter, including the methods that were used for estimating those factors;
(ii) indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);
(4) for sinter production:
(a) the annual CO2 and CH4 emissions attributable to sinter production, in metric tons;
(b) the annual quantity of each carbonaceous material used in sinter production, in metric tons;
(c) the annual consumption of each raw material used in sinter production, other than carbonaceous materials that contribute 0.5% or more of the total carbon introduced in the process, in metric tons;
(d) the annual production of sinter, in metric tons;
(e) the annual quantity of air pollution control residue collected, in metric tons;
(f) the average annual carbon content of the materials and products referred to in subparagraphs b to e that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material and products;
(g) the CH4 emission factors, as the case may be:
(i) determined by the emitter, including the methods that were used for estimating those factors;
(ii) indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);
(5) for steel production using an electric arc furnace:
(a) the annual CO2 and CH4 emissions attributable to steel production using an electric arc furnace, in metric tons;
(b) the annual consumption of direct reduced iron pellets, in metric tons;
(c) the annual consumption of ferrous scrap, in metric tons;
(d) the annual consumption of each flux material, in metric tons;
(e) the annual consumption of carbon electrodes, in metric tons;
(f) the annual consumption of each carbon-containing raw material that contributes 0.5% or more of the total carbon in the process, in metric tons;
(g) the annual production of steel, in metric tons;
(h) the quantity of slag produced, in metric tons;
(i) the annual quantity of air pollution control residue collected, in metric tons;
(j) the average annual carbon content of the materials and products referred to in subparagraphs b to j that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material or product;
(k) the CH4 emission factors, as the case may be:
(i) determined by the emitter, including the methods that were used for estimating those factors;
(ii) indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);
(6) for the argon-oxygen decarburization of molten steel:
(a) the annual CO2 and CH4 emissions attributable to the oxygen decarburization or the vacuum degassing process using argon of molten steel, in metric tons;
(b) the annual quantity of molten steel charged to the process, in metric tons;
(c) the average annual carbon content of the molten steel before decarburization, in metric tons of carbon per metric ton of molten steel;
(d) the average annual carbon content of the molten steel after decarburization, in metric tons of carbon per metric ton of molten steel;
(e) the annual quantity of air pollution control residue collected, in metric tons;
(f) the average annual carbon content of the air pollution control residue collected, in metric tons of carbon per metric ton of residue;
(g) the CH4 emission factors determined by the emitter and the methods used to estimate them;
(7) for iron production using the direct reduction process:
(a) the annual CO2 and CH4 emissions attributable to iron production by direct reduction, in metric tons;
(b) the annual consumption of ore or pellets, in metric tons;
(c) the annual consumption of each carbon-containing raw material, other than ore or pellets, that contributes 0.5% or more of the total carbon in the process, in metric tons;
(d) the annual production of reduced iron pellets, in metric tons;
(e) the annual quantity of non-metallic by-products, in metric tons;
(f) the annual quantity of air pollution control residue collected, in metric tons;
(g) the average annual carbon content of the materials and products referred to in subparagraphs b to f that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material or product;
(h) the CH4 emission factors, as the case may be:
(i) determined by the emitter, including the methods that were used for estimating those factors;
(ii) indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);
(8) for iron production using a blast furnace:
(a) the annual CO2 and CH4 emissions attributable to iron production using a blast furnace, in metric tons;
(b) the annual consumption of ore or pellets, in metric tons;
(c) the annual consumption of each carbon-containing raw material, other than ore or pellets, that contributes 0.5% or more of the total carbon in the process, in metric tons;
(d) the annual consumption of each flux material, in metric tons;
(e) the annual production of iron, in metric tons;
(f) the annual quantity of non-metallic by-products, in metric tons;
(g) the annual quantity of air pollution control residue collected, in metric tons;
(h) the average annual carbon content of the materials and products referred to in subparagraphs b to g that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material and product;
(i) the CH4 emission factors, as the case may be:
(i) determined by the emitter, including the methods that were used for estimating those factors;
(ii) indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);
(9) for the indurating of iron ore pellets:
(a) the annual CO2 and CH4 emissions attributable to the indurating of iron ore pellets, for each type of pellets, in metric tons;
(b) the annual consumption of greenball pellets, in metric tons;
(c) the annual production of each type of fired pellets, in metric tons;
(d) the annual quantity of air pollution control residue collected, in metric tons;
(e) the average annual carbon content of the materials and products referred to in subparagraphs b to d and f that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material and product;
(f) the annual quantities of each raw material used, other than greenball pellets, in metric tons;
(g) (subparagraph revoked);
(9.1) in case a ladle furnace is used:
(a) the annual CO2 emissions attributable to the use of the ladle furnace, in metric tons;
(b) the annual quantity of liquid steel fed into the ladle furnace, in metric tons;
(c) the annual consumption of each additive that contributes 0.5% or more of the total carbon in the process, in metric tons;
(d) the annual consumption of carbon electrodes, in metric tons;
(e) the annual production of steel, in metric tons;
(f) the quantity of slag produced, in metric tons;
(g) the annual quantity of air pollution control residue, in metric tons;
(h) the annual quantity of residue other than those referred to in subparagraph g, in metric tons;
(i) the annual average carbon content of materials and products referred to in subparagraphs b to h that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of materials or products;
(10) the number of times that the methods for estimating missing data provided for in QC.7.6 were used;
(11) (subparagraph revoked);
(12) the annual quantity of steel exiting each rolling mill, in metric tons;
(13) the annual quantity of forged steel produced, that is the quantity of steel, in the form of ingot, being brought to the forging operation, excluding from the initial weight of the ingot the weight of the part of the cut steel when the head of the ingot is cut prior to forging, in metric tons;
(14) the annual quantity of steel slabs, billets or ingots produced at the steel mill, in metric tons.
Subparagraph h of subparagraph 2, subparagraph h of subparagraph 3, subparagraph f of subparagraph 4, subparagraph j of subparagraph 5, subparagraphs c, d and f of subparagraph 6, subparagraph g of subparagraph 7, subparagraph h of subparagraph 8 and subparagraph e of subparagraph 9 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.
Subparagraph h.1 of subparagraph 2, subparagraph i of subparagraph 3, subparagraph g of subparagraph 4, subparagraph k of subparagraph 5, subparagraph g of subparagraph 6, subparagraph h of subparagraph 7, subparagraph i of subparagraph 8, subparagraph e of subparagraph 9 and subparagraph i of subparagraph 9.1 of the first paragraph do not apply to the CH4 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraphs a of subparagraphs 2 to 9 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraph b of subparagraph 1 of the first paragraph are emissions attributable to combustion;
(3) the emissions referred to in subparagraphs a of subparagraphs 2 to 9 of the first paragraph are other emissions.
QC.7.3. Calculation methods for CO2 emissions
An emitter must calculate the annual CO2 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes using one of the calculation methods in QC.7.3.1 and QC.7.3.2.
QC.7.3.1. Use of a continuous emission monitoring and recording system
The annual CO2 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.
QC.7.3.2. Calculation by mass balance
The annual CO2 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes must be calculated using the methods in paragraphs 1 to 9 depending on the process used, expressed
(1) for primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes, using equation 7-1:
Equation 7-1
CO2 = CO2, COKE + CO2, BOF + CO2, SINTER + CO2, EAF + CO2, AOD + CO2, DR + CO2, BF + CO2, IP + CO2, LF
Where:
CO2 = Annual CO2 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet firing processes, in metric tons;
CO2, COKE = Annual CO2 emissions attributable to the production of metallurgical coke, calculated in accordance with equation 7-2, in metric tons;
CO2, BOF = Annual CO2 emissions attributable to steel production using a basic oxygen furnace, calculated in accordance with equation 7-3, in metric tons;
CO2, SINTER = Annual CO2 emissions attributable to sinter production, calculated in accordance with equation 7-4, in metric tons;
CO2, EAF = Annual CO2 emissions attributable to steel production using an electric arc furnace, calculated in accordance with equation 7-5, in metric tons;
CO2, AOD = Annual CO2 emissions attributable to oxygen decarburization or the vacuum degassing using argon, calculated in accordance with equation 7-6, in metric tons;
CO2, DR = Annual CO2 emissions attributable to iron production using the direct reduction process, calculated in accordance with equation 7-7, in metric tons;
CO2, BF = Annual CO2 emissions attributable to iron production using a blast furnace, calculated in accordance with equation 7-8, in metric tons;
CO2, IP = Annual CO2 emissions attributable to the indurating of iron ore pellets, calculated in accordance with equation 7-9, in metric tons;
CO2, LF = Annual CO2 emissions attributable to using a ladle furnace, calculated in accordance with equation 7-9.1, in metric tons;
(2) for the production of metallurgical coke, using equation 7-2:
Equation 7-2
Where:
CO2, COKE = Annual CO2 emissions attributable to the production of metallurgical coke, in metric tons;
CC = Annual consumption of coking coal, in metric tons;
CCC = Average annual carbon content of coking coal, in metric tons of carbon per metric ton of coking coal;
GOC = Quantity of coke oven gas transferred offsite during the year, in metric tons;
CGOC = Average annual carbon content of the coke oven gas transferred offsite during the year, in metric tons of carbon per metric ton of coke oven gas;
MC = Annual production of metallurgical coke, in metric tons;
CMC = Average annual carbon content of the metallurgical coke produced, in metric tons of carbon per metric ton of metallurgical coke;
R = Annual quantity of air pollution control residue collected, in metric tons;
CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;
COBi = Quantity of coke oven by-product i transferred offsite during the year, in metric tons;
CCOB, i = Average annual carbon content of coke oven by-product i transferred offsite during the year, in metric tons of carbon per metric ton of by-product i;
n = Number of coke oven by-products transferred offsite during the year;
i = Type of by-product;
3.664 = Ratio of molecular weights, CO2 to carbon;
(3) for steel production using a basic oxygen furnace, using equation 7-3:
Equation 7-3
Where:
CO2, BOF = Annual CO2 emissions attributable to steel production using a basic oxygen furnace, in metric tons;
MI = Annual consumption of molten iron, in metric tons;
CMI = Average annual carbon content of molten iron, in metric tons of carbon per metric ton of molten iron;
SC = Annual consumption of ferrous scrap, in metric tons;
CSC = Average annual carbon content of ferrous scrap, in metric tons of carbon per metric ton of ferrous scrap;
n = Number of flux materials;
i = Type of flux material;
FLi = Annual quantity of flux material i used, in metric tons;
CFL, i = Average annual carbon content of flux material i, in metric tons of carbon per metric ton of flux material;
m = Number of carbonaceous materials that contribute 0.5% or more of the total carbon in the process;
j = Type of carbonaceous material;
CARj = Annual consumption of carbonaceous material j that contributes 0.5% or more of the total carbon in the process, in metric tons;
CCAR, j = Average annual carbon content of carbonaceous material j, in metric tons of carbon per metric ton of carbonaceous material;
ST = Annual production of molten steel, in metric tons;
CST = Average annual carbon content of molten steel, in metric tons of carbon per metric ton of molten steel;
SL = Annual production of slag, in metric tons;
CSL = Average annual carbon content of slag or a default value of 0, in metric tons of carbon per metric ton of slag;
BOG = Annual quantity of basic oxygen furnace gas transferred off-site during the year, in metric tons;
CBOG = Average annual carbon content of basic oxygen furnace gas transferred off-site during the year, in metric tons of carbon per metric ton of basic oxygen furnace gas;
R = Annual quantity of air pollution control residue collected, in metric tons;
CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;
3.664 = Ratio of molecular weights, CO2 to carbon;
(4) for sinter production, using equation 7-4:
Equation 7-4
Where:
CO2, SINTER = Annual CO2 emissions attributable to sinter production, in metric tons;
CARi = Annual consumption of raw carbonaceous material j that contributes 0.5% or more of the total carbon in the process, in metric tons;
CCAR,i = Average annual carbon content of raw carbonaceous material i, in metric tons of carbon per metric ton of raw carbonaceous material;
n = Number of carbonaceous materials;
i = Type of carbonaceous materials;
m = Number of raw material, other than carbonaceous material;
j = Type of raw material, other than carbonaceous material;
RMj = Annual consumption of raw material j other than carbonaceous materials, required for sinter production, such as natural gas or fuel oil, and that contributes 0.5% or more of the total carbon in the process, in metric tons;
CRMj = Average annual carbon content of raw material j, other than raw carbonaceous materials, required for sinter production, and that contributes 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of raw material j;
SINTER = Sinter production, in metric tons;
CSINTER = Average annual carbon content of sinter, in metric tons of carbon per metric ton of sinter;
R = Annual consumption of air pollution control residue, in metric tons;
CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;
3.664 = Ratio of molecular weights, CO2 to carbon;
(5) for steel production using an electric arc furnace, using equation 7-5:
Equation 7-5
Where:
CO2, EAF = Annual CO2 emissions attributable to steel production using an electric arc furnace, in metric tons;
I = Annual consumption of direct reduced iron ore pellets, in metric tons;
CI = Average annual carbon content of direct reduced iron ore pellets, in metric tons of carbon per metric ton of direct reduced iron ore pellets;
SC = Annual consumption of ferrous scrap, in metric tons;
CSC = Average annual carbon content of ferrous scrap, in metric tons of carbon per metric ton of ferrous scrap;
m = Number of flux materials;
j = Type of flux material;
FLi = Annual quantity of flux material i used, in metric tons;
CFL, j = Average annual carbon content of flux material j used, in metric tons of carbon per metric ton of flux material;
EL = Annual consumption of carbon electrodes, in metric tons;
CEL = Average annual carbon content of carbon electrodes, in metric tons of carbon per metric ton of carbon electrodes;
n = Total number of carbonaceous materials;
i = Carbonaceous material;
CARi = Annual consumption of carbonaceous material i that contributes 0.5% or more of the total carbon in the process, in metric tons;
CCAR, i = Average annual carbon content of carbonaceous material i, in metric tons of carbon per metric ton of carbonaceous material;
ST = Annual production of molten steel, in metric tons;
CST = Average annual carbon content of molten steel, in metric tons of carbon per metric ton of molten steel;
SL = Annual production of slag, in metric tons;
CSL = Average annual carbon content of slag or a default value of 0, in metric tons of carbon per metric ton of slag;
R = Annual quantity of air pollution control residue collected, in metric tons;
CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;
3.664 = Ratio of molecular weights, CO2 to carbon;
(6) for the oxygen decarburization process or the argon vacuum degassing process, using equation 7-6:
Equation 7-6
_ _ | | CO2,AOD = |Steel × (CSteel,in - CSteel,out) - (R × CR)| × 3.664 |_ _|
Where:
CO2,AOD = Annual CO2 emissions attributable to the oxygen decarburization process or the argon vacuum degassing process, in metric tons;
Steel = Quantity of molten steel charted to the oxygen decarburization process or the argon vacuum degassing process, in metric tons;
CSteel,in = Average annual carbon content of molten steel before decarburization or degassing, in metric tons of carbon per metric ton of molten steel;
CSteel,out = Average annual carbon content of molten steel after decarburization or degassing, in metric tons of carbon per metric ton of molten steel;
R = Annual consumption of air pollution control residue, in metric tons;
CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;
3.664 = Ratio of molecular weights, CO2 to carbon;
(7) for iron production by direct reduction, using equation 7-7:
Equation 7-7
Where:
CO2, DR = Annual CO2 emissions attributable to iron production by direct reduction, in metric tons;
Ore = Annual consumption of ore or pellets, in metric tons;
COre = Average annual carbon content of ore or pellets, in metric tons of carbon per metric ton of ore or pellets;
n = Number of raw materials, other than carbonaceous materials and ore;
i = Type of raw material, other than carbonaceous materials and ore;
RMi = Annual consumption of raw material i other than carbonaceous materials and ore, such as natural gas or fuel oil and that contributes 0.5% or more of the total carbon in the process, in metric tons;
CRM, i = Average annual carbon content of raw material i other than carbonaceous materials and ore, in metric tons of carbon per metric ton of raw material i;
m = Number of carbonaceous materials;
j = Type of carbonaceous material;
CARj = Annual consumption of each carbonaceous material j that contributes 0.5% or more of total carbon in the process, in metric tons;
CCAR, j = Average annual carbon content of each carbonaceous material j, in metric tons of carbon per metric ton of carbonaceous material j;
I = Annual production of iron produced by direct reduction, in metric tons;
CI = Average annual carbon content of iron produced by direct reduction, in metric tons of carbon per metric ton of iron produced by direct reduction;
NM = Annual production of non-metallic by-products, in metric tons;
CNM = Average annual carbon content of non-metallic by-products, in metric tons of carbon per metric ton of non-metallic by-products;
R = Annual consumption of air pollution control residue, in metric tons;
CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;
3.664 = Ratio of molecular weights, CO2 to carbon;
(8) for iron production using a blast furnace, using equation 7-8:
Equation 7-8
Where:
CO2, BF = Annual CO2 emissions attributable to iron production using a blast furnace, in metric tons;
n = Number of raw materials, other than carbonaceous materials and ore;
i = Type of raw material other than carbonaceous materials and ore;
RMi = Annual consumption of raw material i other than carbonaceous materials and ore and that contributes 0.5% or more of the total carbon in the process, in metric tons;
CRM, i = Average annual carbon content of raw material i, other than carbonaceous materials or ore, that contributes 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of raw material i;
m = Number of carbonaceous materials;
j = Type of carbonaceous material;
CARj = Annual consumption of each carbonaceous material j that contributes 0.5% or more of total carbon in the process, in metric tons;
CCAR, j = Average annual carbon content of each carbonaceous material j, in metric tons of carbon per metric ton of carbonaceous material j;
p = Number of flux materials;
k = Type of flux material;
Fk = Annual quantity of each flux material k used, in metric tons;
CF,k = Average annual carbon content of each flux material k, in metric tons of carbon per metric ton of flux material k;
Ore = Annual consumption of ore or pellets, in metric tons;
COre = Average annual carbon content of ore or pellets, in metric tons of carbon per metric ton of ore or pellets;
I = Annual production of iron using a blast furnace, in metric tons;
CI = Average annual carbon content of iron produced using a blast furnace, in metric tons of carbon per metric ton of iron produced using a blast furnace;
NM = Annual production of non-metallic by-products, in metric tons;
CNM = Average annual carbon content of non-metallic by-products, in metric tons of carbon per metric ton of non-metallic by-products;
R = Annual consumption of air pollution control residue, in metric tons;
CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;
3.664 = Ratio of molecular weights, CO2 to carbon;
(9) for the indurating of iron ore pellets, using equation 7-9 or 7-9.01:
Equation 7-9
_ _ | | CO2,IP = |(GBP × CGBP) - (FP × CFP) - (R × CR)| × 3.664 |_ _|
Where:
CO2, IP = Annual CO2 emissions attributable to the indurating of iron ore pellets, in metric tons;
GBP = Annual consumption of greenball pellets, in metric tons;
CGBP = Average annual carbon content of greenball pellets, in metric tons of carbon per metric ton of greenball pellets;
FP = Annual quantity of fired pellets produced by the indurating process, in metric tons;
CFP = Average annual carbon content of fired pellets, in metric tons of carbon per metric ton of fired pellets;
R = Annual consumption of air pollution control residue, in metric tons;
CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;
3.664 = Ratio of molecular weights, CO2 to carbon;
Equation 7-9.01
Where:
CO2, IP = Annual CO2 emissions attributable to the indurating of iron ore pellets, in metric tons;
n = Number of additives;
j = Type of additive, such as limestone, dolomite or bentonite;
ADj = Annual consumption of additive j, in metric tons;
CADj = Annual average carbon content of the additive j, in metric tons of carbon per metric ton of additive;
IRC = Annual consumption of iron ore, in metric tons;
CIRC = Annual average carbon content of the iron ore, in metric tons of carbon per metric ton of iron ore;
FP = Annual quantity of fired pellets produced by the indurating process, in metric tons;
CFP = Average annual carbon content of fired pellets, in metric tons of carbon per metric ton of fired pellets;
R = Annual quantity of air pollution control residue, in metric tons;
CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;
3.664 = Ratio of molecular weights, CO2 to carbon;
(10) where using a ladle furnace, in accordance with equation 7-9.1:
Equation 7-9.1
Where:
CO2,LF = Annual CO2 emissions attributable to using a ladle furnace, in metric tons;
MSsup = Annual quantity of molten steel supplied to the ladle furnace, in metric tons;
CMSsup = Average annual carbon content of molten steel supplied to the ladle furnace, in metric tons of carbon per metric ton of molten steel;
m = Number of additives;
j = Additive;
ADj = Annual consumption of the additive j that contributes 0.5% or more of the total carbon in the process, in metric tons;
CADj = Annual average carbon content of additive j that contributes 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of additive j;
EL = Annual consumption of carbon electrodes, in metric tons;
CEL = Annual Average carbon content of carbon electrodes, in metric tons of carbon per metric ton of carbon electrodes;
MSprod = Annual production of molten steel produced in a ladle furnace, in metric tons;
CMSprod = Average annual carbon content of molten steel, in metric tons of carbon per metric ton of molten steel;
SL = Annual production of slag, in metric tons;
CSL = Average annual carbon content of slag or a default value of 0, in metric tons of carbon per metric ton of slag;
R = Annual quantity of air pollution control residue collected, in metric tons;
CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;
Rp = Annual quantity of other residue produced, in metric tons;
CRp = Average annual carbon content of other residue produced or a default value of 0, in metric tons of carbon per metric ton of residue;
3.664 = Ratio of molecular weights, CO2 to carbon;
QC.7.4. Calculation methods for CH4 emissions
An emitter must calculate the annual CH4 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes using one of the calculation methods in QC.7.4.1 to QC.7.4.3.
QC.7.4.1. Use of a continuous emission monitoring and recording system
The annual CH4 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and ore pellet indurating processes may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.4.5.
QC.7.4.2. Calculation using establishment-specific emission factors
The annual CH4 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes must be calculated using establishment-specific emission factors determined by the emitter.
QC.7.4.3. Calculation using published emission factors
Annual CH4 emissions attributable to the primary processes to produce iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet firing processes can be calculated using the emission factors in Tables 1-1 to 1-8 in Q.C.1.7. If no factor is indicated in the tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC).
QC.7.5. Sampling, analysis and measurement requirements
QC.7.5.1. Carbon content for materials other than ferrous scrap
When the calculation method in QC.7.3.2 is used, an emitter who operates a facility or establishment that produces iron or steel or who operates the indurating of iron ore pellets must, for materials that contribute 0.5% or more of the total carbon in the process, use the data provided by the supplier or determine the carbon content by analyzing a minimum of 3 representative samples per year, using an analysis method published by an organization listed in QC.1.5 or the following methods:
(1) for fossil fuels, in accordance with QC.1.5.5;
(2) for by-products needed in iron and steel production such as blast furnace gas, coke oven gas, coal tar, light oil, slag dust or sinter off gas, by measuring fuel carbon content to ±5% using data from a continuous monitoring and recording system or the methods in QC.1.5.1 and QC.1.5.5;
(3) for flux materials such as limestone or dolomite, using the most recent version of ASTM C25 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”;
(4) for coal, coke and the carbon electrodes used in electric arc furnaces, using the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal” or, for fuels, raw materials or liquid products, the most recent version of ASTM D7582 “Standard Test Methods for Proximate Analysis of Coal and Coke by Macro Thermogravimetric Analysis”;
(5) for iron and ferrous scrap, using the most recent version of ASTM E1019 “Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques”;
(6) for the steel produced, using one of the following methods:
(a) the most recent version of ASM CS-104 UNS G10460 “Carbon Steel of Medium Carbon Content” published by ASM International;
(b) the most recent version of ISO/TR 15349-1 “Unalloyed steel - Determination of low carbon content, Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation)”;
(c) the most recent version of ISO/TR 15349-3 “Unalloyed steel - Determination of low carbon content, Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating)”;
(d) the most recent version of ASTM E415 “Standard Test Method for Atomic Emission Vacuum Spectrometric Analysis of Carbon and Low-Alloy Steel”;
(7) for baked or greenball iron ore pellets, using the most recent version of ASTM E1915 “Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials for Carbon, Sulfur, and Acid-Base Characteristics”;
(8) for slag and air pollution control residue collected, in accordance with an analysis method published by an organization listed in QC.1.5 or using a default value of 0.
QC.7.5.2. Carbon content of ferrous scrap
When the calculation method in QC.7.5.2 is used, an emitter who operates a facility or establishment that produces iron or steel must use the data provided by the supplier or determine the carbon content by using the following method:
(1) separate the ferrous scrap into various classes according to carbon content;
(2) for each of the classes, determine the carbon content by analyzing a minimum of 5 representative samples in accordance with the most recent version of ASTM E1019 “Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques,” ASTM E415 “Standard Test Method for Atomic Emission Vacuum Spectrometric Analysis of Carbon and Low-Alloy Steel” or in accordance with an analysis method published by an organization listed in QC.1.5;
(3) calculate the characteristic carbon content for each class of ferrous scrap by taking the average of the measured content values, removing the highest and lowest value;
(4) calculate the average carbon content for ferrous scrap using equation 7-9.2:
Equation 7-9.2
Where:
CFS = Average annual carbon content of ferrous scrap, in metric tons of carbon per metric ton of ferrous scrap;
n = Number of classes of ferrous scrap;
i = Class of ferrous scrap;
CCFS,i = Carbon content of class i ferrous scrap, in metric tons of carbon per metric ton of ferrous scrap;
CFSi = Annual consumption of class i ferrous scrap, in metric tons.
QC.7.5.3. Consumption of process materials
The emitter must determine the quantity of solid, liquid and gaseous process inputs and outputs and the quantity of by-products used in the production of iron and steel using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders.
QC.7.6. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern carbon content or sampled data,
(i) determine the sampling or measurement rate using the following equation:
Equation 7-10
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.7.5;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern the consumption of carbon-containing raw material, consumption of ferrous scrap, annual consumption of molten iron, consumption of coking coal, consumption of flux material, consumption of direct reduced iron pellets, consumption of carbon electrodes, consumption of ore, quantity of slag produced, consumption of greenball pellets, production of fired pellets, production of coke oven gas, production of metallurgical coke, quantity of air pollution control residue collected, quantity of other coke oven by-products, the quantity of steel processed or produced, quantity of gas from basic oxygen furnaces transferred, the production of sinter, the production of iron or the quantity of non-metallic by-products, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.8. LIME PRODUCTION
QC.8.1. Covered sources
The covered sources are all the processes used for all types of lime production, except the lime kilns used in a pulp and paper plant and the processes used to process sludge containing calcium carbonate.
QC.8.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) (subparagraph revoked);
(2) the annual CO2 emissions attributable to the production process for each type of lime, in metric tons;
(3) for each type of lime produced:
(a) the monthly CO2 emission factor, in metric tons of CO2 per metric ton of lime;
(b) the annual production of each type of lime, in metric tons;
(c) (subparagraph revoked);
(d) (subparagraph revoked);
(4) for each type of calcined by-product or waste:
(a) the quarterly emission factors, in metric tons of CO2 per metric ton of calcined by-products or wastes;
(b) the annual production of calcined by-products or wastes, in metric tons;
(c) (subparagraph revoked);
(d) (subparagraph revoked);
(e) the annual quantity of calcined by-products and residue sold, in metric tons;
(5) (subparagraph revoked);
(6) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;
(7) the number of times that the methods for estimating missing data in section QC.8.5 were used to determine lime production as required by subparagraph 3 of the first paragraph;
(8) (subparagraph revoked).
Subparagraphs a of subparagraphs 3 and 4 of the first paragraph do not apply to the emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraph 6 of the first paragraph are emissions attributable to combustion.
QC.8.3. Calculation methods for CO2, CH4 and N2O emissions
The annual CO2 emissions, other than combustion emissions, attributable to the use of kilns must be calculated in accordance with one of the 2 calculation methods in QC.8.3.1 and QC.8.3.2.
The annual CO2, CH4 and N2O attributable to the combustion of fuels in kilns must be calculated in accordance with QC.8.3.3.
QC.8.3.1. Use of a continuous emission monitoring and recording system
The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.
QC.8.3.2. Calculation by mass balance
The annual CO2 emissions attributable to the use of kilns must be calculated, for each type of lime, using equations 8-1 to 8-3:
Equation 8-1
Where:
CO2 = CO2 emissions from kilns, in metric tons;
i = Month;
L = Production of lime j for the month i, in metric tons;
EFL = CO2 emission factor of lime j for the month i, calculated in accordance with equation 8-2, in metric tons of CO2 per metric ton of lime;
x = Quarter;
z = Total number of types of calcined by-products and wastes;
y = Type of calcined by-products and waste;
CBF = Production of calcined by-products and wastes y in quarter x, including lime kiln dust, scrubber sludge and other calcined wastes, in metric tons;
EFCBF = CO2 emission factor for calcined by-products and wastes y for quarter x, calculated in accordance with equation 8-3, in metric tons of CO2 per metric ton of calcined by-products and wastes;
Equation 8-2
EFL = (CaOL × 0.785) + (MgOL × 1.092)
Where:
EFL = Monthly CO2 emission factor for lime, in metric tons of CO2 per metric ton of lime;
CaOL = Monthly content of calcium oxide in the lime, in metric tons of calcium oxide per metric ton of lime;
0.785 = Ratio of molecular weights, CO2 to calcium oxide;
MgOL = Monthly content of magnesium oxide in the lime, in metric tons of magnesium oxide per metric ton of lime;
1.092 = Ratio of molecular weights, CO2 to magnesium oxide;
Equation 8-3
EFCBP = (CaOCBP × 0.785) + (MgOCBP × 1.092)
Where:
EFCBP = Quarterly CO2 emission factor for calcined by-products and wastes, in metric tons of CO2 per metric ton of calcined by-products and wastes;
CaOCBP = Quarterly content of calcium oxide in calcined by-products and wastes, in metric tons of calcium oxide per metric ton of calcined by-products and wastes;
0.785 = Ratio of molecular weights, CO2 to calcium oxide;
MgOCBP = Quarterly content of magnesium oxide in calcined by-products and wastes, in metric tons of magnesium oxide per metric ton of calcined by-products and wastes;
1.092 = Ratio of molecular weights, CO2 to magnesium oxide.
QC.8.3.3. Calculation of the emissions attributable to the combustion of fuels in kilns
The CO2, CH4 and N2O emissions attributable to the combustion of fuels in kilns must be calculated and reported in accordance with the calculation methods in QC.1. When pure biomass fuels, in other words fuels constituted of the same substance for at least 97% of their total weight, are consumed only during start-up, shut-down, or malfunction operating periods for the apparatus or units, the emitter may calculate CO2 emissions using the calculation method in QC.1.3.1.
QC.8.4. Sampling, analysis and measurement requirements
An emitter who operates a facility or establishment that produces lime and who uses the method in QC.8.3.2 must:
(1) collect at least one sample each month for each type of lime produced during the month and determine the monthly content of calcium oxide and of magnesium oxide in each type of lime using the most recent version of ASTM C25 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime” or the most recent revision of the National Lime Association's “CO2 Emissions Calculation Protocol for the Lime Industry”, or using any other analysis method published by an organization listed in QC.1.5;
(2) collect at least one sample each quarter for each type of calcined by-products or wastes produced during the quarter and determine the quarterly content of calcium oxide and of magnesium oxide in each type of calcined by-products or wastes in accordance with the standards in subparagraph 1;
(3) complete a monthly estimate of the quantity of lime produced and sold using the data on lime sales for each type of lime; the quantity must be adjusted to take into account the difference in beginning and end-of-period inventories of each type of lime;
(4) complete a quarterly estimate of the quantity of calcined by-products and wastes sold, using the data on sales for each type of calcined by-products or wastes; the quantity must be adjusted to take into account the difference in beginning- and end-of-period inventories, over a maximum period of one year, for each type of calcined by-products and wastes;
(5) determine, at least quarterly, the quantity of calcined by-products and wastes not sold for each type of calcined by-products and wastes, using the sales data or the production rate for calcined by-products and wastes compared to lime production;
(6) follow the quality assurance/quality control procedures in the most recent revision of the National Lime Association's “CO2 Emissions Calculation Protocol for the Lime Industry” published by la National Lime Association.
QC.8.5. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern calcium oxide content or magnesium oxide content,
(i) determine the sampling or measurement rate using the following equation:
Equation 8-4
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.8.4;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern lime production or the production of calcined by-products and waste, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.9. PETROLEUM REFINERIES
QC.9.1. Covered sources
The covered sources are all the processes used to produce gasoline, aromatics, kerosene, distillate fuel oils, residual fuel oils, lubricants, bitumen, or other products through distillation of petroleum or through redistillation, cracking, rearrangement or reforming of unfinished petroleum derivatives.
Facilities that distill only pipeline transmix, in other words off-spec material created when different specification products mix during pipeline transportation, are excluded.
QC.9.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) the annual CO2, CH4 and N2O emissions attributable to the combustion of refinery fuel gas, flexigas or associated gas, calculated and reported in accordance with QC.2, in metric tons;
(2) the annual CO2 emissions attributable to catalyst regeneration, calculated in accordance with QC.9.3.1, in metric tons;
(2.1) the annual CH4 and N2O emissions attributable to catalyst regeneration, calculated in accordance with QC.9.3.1, in metric tons;
(3) the annual CO2, CH4 and N2O emissions from process vents, calculated in accordance with QC.9.3.2, in metric tons;
(4) the annual CO2 and CH4 emissions attributable to asphalt production, calculated in accordance with QC.9.3.3, in metric tons;
(5) the annual CO2 emissions from sulphur recovery units, calculated in accordance with QC.9.3.4, in metric tons;
(6) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units that are not referred to in paragraphs 1 and 7, calculated and reported in accordance with QC.1, in metric tons;
(6.1) the annual CO2 emissions attributable to hydrogen production processes, calculated and reported in accordance with QC.6, in metric tons;
(7) the annual CO2, CH4 and N2O emissions from flares and antipollution devices, calculated in accordance with QC.9.3.5, in metric tons;
(8) the annual CH4 emissions from storage tanks, calculated in accordance with QC.9.3.6, in metric tons;
(9) the annual CH4 and N2O emissions attributable to wastewater treatment, calculated in accordance with QC.9.3.7, in metric tons;
(10) the annual CH4 emissions from oil-water separators, calculated in accordance with QC.9.3.8, in metric tons;
(11) the annual CH4 emissions from equipment leaks, calculated in accordance with QC.9.3.9, in metric tons;
(12) the annual consumption of each type of feedstock that emits CO2, CH4 or N2O, including petroleum coke, expressed
(a) in bone dry metric tons, when the quantity is expressed as a mass;
(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
(c) in kilolitres, when the quantity is expressed as a volume of liquid;
(d) (subparagraph replaced);
(13) the annual consumption of each type of fuel that emits CO2, CH4 or N2O, expressed
(a) in bone dry metric tons, when the quantity is expressed as a mass;
(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
(c) in kilolitres, when the quantity is expressed as a volume of liquid;
(d) (subparagraph replaced);
(14) the annual CO2 emissions from coke calcining, calculated in accordance with QC.9.3.10, in metric tons;
(14.1) the annual CH4 and N2O emissions from coke calcining, calculated in accordance with QC.9.3.10, in metric tons;
(15) the annual CH4 emissions from purging systems, calculated in accordance with QC.9.3.11, in metric tons;
(16) the annual CH4 emissions from loading operations, calculated in accordance with QC.9.3.12, in metric tons;
(17) the annual CH4 emissions from delayed coking, calculated in accordance with QC.9.3.13, in metric tons;
(18) the number of times that the methods for estimating missing data provided for in QC.9.5 were used;
(19) (subparagraph revoked);
(20) the annual quantity of crude oil refined, in kilolitres;
(21) the annual total charge of the refinery feed, in kilolitres.
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraphs 2, 6.1 and 14 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraphs 1 and 6 of the first paragraph are emissions attributable to combustion;
(3) the emissions referred to in subparagraphs 2.1, 3 to 5, 7 to 11, 14.1 and 15 to 17 of the first paragraph are other emissions.
QC.9.3. Calculation methods for CO2, CH4 and N2O emissions
The annual CO2, CH4 and N2O emissions attributable to the operation of a petroleum refinery must be calculated in accordance with the calculation methods in QC.9.3.1 to QC.9.3.13.
QC.9.3.1. Calculation of CO2, CH4 and N2O emissions attributable to catalyst regeneration
The annual CO2, CH4 and N2O emissions attributable to catalyst regeneration for a facility equipped with a continuous emission monitoring and recording system must be calculated in accordance with QC.1.3.4 or, in the absence of such a system, in accordance with the following methods, depending on the process involved:
(1) for the continuous regeneration of catalyst material in fluid catalytic cracking units and fluid cokers:
(a) using the average coke consumption and equations 9-1, 9-2 and 9-3:
Equation 9-1
Where:
CO2 = Annual CO2 emissions attributable to the continuous regeneration of catalyst material in fluid catalytic cracking units and fluid cokers, in metric tons;
n = Number of hours of operation during the year;
j = Hour;
CBj = Hourly coke burn for hour j, calculated in accordance with equation 9-2 or determined by the emitter, in metric tons;
CC = Carbon content of coke burned, in kilograms of carbon per kilogram of coke burned;
3.664 = Ratio of molecular weights, CO2 to carbon;
Equation 9-2
Where:
CBj = Hourly coke burn, in metric tons;
K1, K2, K3 = Material balance and conversion factors (K1, K2 and K3) from Table 9-1 in QC.9.6;
Qr = Volumetric flow of regeneration gas before entering the antipollution system, calculated in accordance with equation 9-3 or measured continuously, in cubic metres per minute, at standard conditions and on a dry basis;
%CO2 = CO2 concentration in regenerator exhaust, in cubic metres of CO2 per cubic metre of regeneration gas on a dry basis, expressed as a percentage;
%CO = Concentration of carbon monoxide in regenerator exhaust, in cubic metres of carbon monoxide per cubic metre of regeneration gas on a dry basis, expressed as a percentage;
Qa = Volumetric flow of air to regenerator, in cubic metres per minute, at standard conditions and on a dry basis;
%O2 = Concentration of oxygen in regenerator exhaust, in cubic metres of oxygen per cubic metre of regeneration gas on a dry basis, expressed as a percentage;
Qoxy = Volumetric flow of oxygen to regenerator, in cubic metres per minute, at standard conditions and on a dry basis;
%O2,oxy = Concentration of oxygen in enriched air stream inlet to regenerator, expressed as a percentage per volume on a dry basis;
0.001 = Conversion factor, kilograms to metric tons;
Equation 9-3
[79 × Qa + (100-%O2,oxy)× Qoxy] Qr = ______________________________ [100 - %CO2 - %CO - %O2]
Where:
Qr = Volumetric flow of regeneration gas from regenerator before entering the antipollution system, in cubic metres per minute, at standard conditions and on a dry basis;
79 = Nitrogen concentration in air, expressed as a percentage;
Qa = Volumetric flow of air to regenerator, in cubic metres per minute, at standard conditions and on a dry basis;
%O2,oxy = Concentration of oxygen in enriched air stream inlet, in cubic metres of oxygen per cubic metre of air stream on a dry basis, expressed as a percentage;
Qoxy = Volumetric flow of oxygen in enriched air stream inlet, in cubic metres per minute, at standard conditions and on a dry basis;
%CO2 = CO2 concentration in regenerator exhaust, in cubic metres of CO2 per cubic metre of regeneration gas on a dry basis, expressed as a percentage;
%CO = Concentration of carbon monoxide in regenerator exhaust, in cubic metres of carbon monoxide per cubic metre of regeneration gas on a dry basis, expressed as a percentage.
When no auxiliary fuel is burned and the emitter does not use a continuous CO monitoring and recording system, the percentage is zero;
%O2 = Concentration of oxygen in regenerator exhaust, in cubic metres of oxygen per cubic metre of regeneration gas on a dry basis, expressed as a percentage;
(b) using the CO2 and carbon monoxide concentrations in the regenerator exhaust and equation 9-3.1:
Equation 9-3.1
Where:
CO2 = Annual CO2 emissions attributable to the continuous regeneration of catalyst material in fluid catalytic cracking units and fluid cokers, in metric tons;
n = Number of hours of operation during the year;
j = Hour;
Qr = Volumetric flow of regeneration gas from regenerator before entering the antipollution system, in cubic metres per minute, at standard conditions and on a dry basis;
%CO2 = CO2 concentration in regenerator exhaust, in cubic metres of CO2 per cubic metre of regeneration gas on a dry basis, expressed as a percentage;
%CO = Concentration of carbon monoxide in regenerator exhaust, in cubic metres of carbon monoxide per cubic metre of regeneration gas on a dry basis, expressed as a percentage or, if there is no post-combustion device, a percentage of 0;
60 = Conversion factor, minutes to hours;
44 = Molecular weight of CO2, in kilograms per kilomole;
MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
0.001 = Conversion factor, kilograms to metric tons;
(2) for periodic catalyst regeneration processes, using equation 9-4:
Equation 9-4
Where:
CO2 = Annual CO2 emissions attributable to periodic catalyst regeneration processes, in metric tons;
n = Number of regeneration cycles during the year;
i = Regeneration cycle;
CBi = Quantity of coke burned, in metric tons per regeneration cycle i;
C = Carbon content of coke burned, measured or estimated by the emitter, or using a default value of 0.94 kg of carbon per kilogram of coke burned;
3.664 = Ratio of molecular weights, CO2 to carbon;
(3) for continuous catalyst regeneration processes of catalysers used for operations other than fluid catalytic cracking and fluid coking, using equation 9-5:
Equation 9-5
CO2 = CRR × (CFspent - CFregen) × H × 3.664
Where:
CO2 = Annual CO2 emissions attributable to continuous catalyst regeneration processes of catalysers used for operations other than fluid catalytic cracking and fluid coking, in metric tons;
CRR = Average catalyst regeneration rate, in metric tons per hour;
CFspent = Carbon content of spent catalyst, in kilograms of carbon per kilogram of spent catalyst;
CFregen = Carbon content of the regenerated catalyst, in kilograms of carbon per kilogram of regenerated catalyst.
If no carbon content in the regenerated catalyst is detected, the carbon content of the catalyst is zero;
H = Number of hours of operation of regenerator during the year;
3.664 = Ratio of molecular weights, CO2 to carbon;
(4) the CH4 emissions attributable to catalyst regeneration must be calculated using equation 9-5.1:
Equation 9-5.1
EFCH4 CH4 = CO2 × _____ EFCO2
Where:
CH4 = Annual CH4 emissions from catalyst regeneration, in metric tons;
CO2 = Annual CO2 emissions from catalyst regeneration, calculated using equations 9-1, 9-3.1 or 9-4, in metric tons;
EFCH4 = CH4 emission factor, 2.8 × 10-3 kg per gigajoule;
EFCO2 = CO2 emission factor, namely 97 kg per gigajoule;
(5) the N2O emissions attributable to catalyst regeneration must be calculated using equation 9-5.2:
Equation 9-5.2
EFN2O N2O = CO2 × _____ EFCO2
Where:
N2O = Annual N2O emissions from catalyst regeneration, in metric tons;
CO2 = Annual CO2 emissions from catalyst regeneration, calculated using equation 9-1, in metric tons;
EFN2O = N2O emission factor, 5.7 × 10-4 kg per gigajoule;
EFCO2 = CO2 emission factor, 97 kg per gigajoule;
QC.9.3.2. Calculation of CO2, CH4 and N2O emissions from process vents
The annual CO2, CH4 and N2O emissions from process vents, other than emissions required for the process, must be calculated using equation 9-6, for each process vent with a CO2 flow of over 2% by volume, a CH4 flow of over 0.5% by volume, or an N2O flow of over 0.01% by volume:
Equation 9-6
Where:
Ex = Annual emissions of gas x from process vents, in metric tons;
x = CO2, CH4 or N2O;
m = Total number of vents;
j = Vent;
n = Number of venting events during the year;
i = Venting event;
VRi = Vent rate j for venting event i, in cubic metres per unit of time at standard conditions;
Fxi = Molar fraction of x in vent gas stream during venting event i, in kilomoles of x per kilomole of gas;
MWxi = Molecular weight of x in kilograms per kilomole or, when a mass flowmeter is used to measure the flow in kilograms per unit of time, replace
_ _
| |
|MWx |
|----| by 1;
|MVC |
|_ _| MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
VTi = Duration of venting event i of vent j, using the same units of time as for VRi;
0.001 = Conversion factor, kilograms to metric tons.
QC.9.3.3. Calculation of CO2 and CH4 emissions attributable to bituminous product blowing processes
The annual CO2 and CH4 emissions attributable to bituminous product blowing processes must be calculated using the method in QC.9.3.2, or in accordance with the following methods:
(1) for bituminous product blowing operations without antipollution equipments, or bituminous product blowing activities controlled by a steam gas purification system, using the following equations:
Equation 9-7
CO2 = QBP × EFBP,CO2
Where:
CO2 = Annual CO2 emissions attributable to uncontrolled bituminous product blowing operations, in metric tons;
QBP = Annual quantity of bituminous product blown, in millions of barrels;
EFBP,CO2 = CO2 emission factor for uncontrolled bituminous product blowing operations determined by the emitter, or a default value of 1,100 metric tons per million barrels;
Equation 9-8
CH4 = QBP × EFBP,CH4
Where:
CH4 = CH4 emissions attributable to uncontrolled bituminous product blowing operations, in metric tons;
QBP = Annual quantity of bituminous product blown, in millions of barrels;
EFBP,CH4 = CH4 emission factor for uncontrolled bituminous product blowing operations determined by the emitter, or a default value of 580 metric tons per million barrels;
(2) for bituminous product blowing operations controlled by thermal oxidizer or flare, using equations 9-8.1 and 9-8.2, except if the emissions have already been calculated in accordance with QC.9.3.5 or QC.1.3:
Equation 9-8.1
CO2 = QBP × CBP × 0.98 × 3.664
Where:
CO2 = Annual CO2 emissions attributable to controlled bituminous product blowing operations, in metric tons;
QBP = Annual quantity of bituminous products blown, in millions of barrels;
CBP = Carbon content of bituminous product blown determined by the emitter, or a default value of 2,750 metric tons per million barrels;
0.98 = Efficiency of thermal oxidizer or flare;
3.664 = Ratio of molecular weights, CO2 to carbon;
Equation 9-8.2
CH4 = QBP × EFBP,CH4 × 0.02
Where:
CH4 = Annual CH4 emissions attributable to controlled bituminous product blowing operations, in metric tons;
QBP = Annual quantity of bituminous product blown, in millions of barrels;
EFBP,CH4 = CH4 emission factor for bituminous product blowing operations without antipollution equipments determined by the emitter, or a default value of 580 metric tons per million barrels;
0.02 = Fraction of CH4 uncombusted in thermal oxidizer or flare, in percentage expressed in decimal form.
QC.9.3.4. Calculation of CO2 emissions from sulphur recovery units
The annual CO2 emissions from sulphur recovery units must be calculated using equation 9-9:
Equation 9-9
MW CO2 = FR × CO2 × MF × 0.001 MVC
Where:
CO2 = Annual CO2 emissions from sulphur recovery units, in metric tons;
FR = Annual volumetric flow of acid gas emitted to the sulphur recovery units, in cubic metres at standard conditions;
MWCO2 = Molecular weight of CO2 of 44 kg per kilomole or, when a mass flowmeter is used to measure gas flow in kilograms per year, replace
_ _
| |
| MWCO2 |
|--------| by 1;
| MVC |
|_ _| MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
MF = Molecular fraction of CO2 in the acid gas emitted to sulphur recovery units, obtained by sampling at source and analyzing annually, in a percentage expressed as a decimal, or as a factor of 20% or 0.20;
0.001 = Conversion factor, kilograms to metric tons.
QC.9.3.5. Calculation of CO2, CH4 and N2O emissions attributable to combustion of hydrocarbons in flares and other antipollution equipments
The annual CO2, CH4 and N2O emissions attributable to combustion of hydrocarbons in flares and other antipollution equipments must be calculated in accordance with the calculation methods in QC.1, except the CO2 emissions attributable to the combustion of hydrocarbons in flares that must be calculated, based on the type of equipment used, using the following methods:
(1) for a flare equipped with a continuous monitoring and recording system to measure the flow and the parameters used to determine the carbon content of the gas, or if the parameters are measured at least weekly, using equation 9-10:
Equation 9-10
Where:
CO2 = Annual CO2 emissions attributable to the combustion of hydrocarbons in flares, in metric tons;
n = Number of measurement periods; minimum of 52 for weekly measurements and maximum of 366 for daily measurements;
p = Measurement period;
Flarep = Volume of gas directed to flares during measurement period p, in thousands of cubic metres at standard conditions;
MWp = Average molecular weight of flare gas combusted during measurement period p, in kilograms per kilomole or, when a mass flowmeter is used to measure flare gas flow in kilograms per measurement period, replace
_ _
| |
| MWp |
|--------| by 1.
| MVC |
|_ _| If measurements are taken more frequently than daily, the arithmetic average of measurement values must be used;
MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
CCp = Average carbon content of flare gas combusted during measurement period p, in kilograms of carbon per kilogram of flare gas.
If measurements are taken more frequently than daily, the arithmetic average of measurement values must be used;
3.664 = Ratio of molecular weights, CO2 to carbon;
0.98 = Flare combustion efficiency;
1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres;
(2) for a flare equipped with a continuous monitoring and recording system to measure the flow and the parameters used to determine the high heat value of the gas, or if the parameters are measured at least weekly, using equation 9-11:
Equation 9-11
Where:
CO2 = Annual CO2 emissions attributable to the combustion of hydrocarbons in flares, in metric tons;
n = Number of measurement periods; minimum of 52 for weekly measurements and maximum of 366 for daily measurements;
p = Measurement period;
Flarep = Volume of gas directed to flares during measurement period p, in thousands of cubic metres at standard conditions;
If a mass flowmeter is used, the molecular weight must be measured and the molecular weight and mass flow must be converted to a volumetric flow using equation 9-12;
HHVp = High heat value of the gas combusted during the measurement period, in gigajoules per thousand cubic metres;
EF = Default CO2 emission factor of 57 kg per gigajoule;
0.98 = Combustion efficiency of flare;
0.001 = Conversion factor, kilograms to metric tons;
Equation 9-12
MVC Flarep = Flarep (kg) × ___ × 0.001 MWP
Where:
Flarep = Volume of gas directed to flares during measurement period p, in thousands of cubic metres;
Flarep (kg) = Mass of flare gas combusted during measurement period p, in kilograms;
MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
MWp = Average molecular weight of flare gas combusted during measurement period p, in kilograms per kilomole;
0.001 = Conversion factor, cubic metres to thousands of cubic metres;
(3) when it is not possible to measure the parameters required in equations 9-10 and 9-11 during startup, shutdown or equipment malfunction, the quantity of gas discharged to the flare must be calculated for each startup, shutdown or malfunction and the CO2 emissions must be calculated using equation 9-13:
Equation 9-13
Where:
CO2 = Annual CO2 emissions attributable to the combustion of hydrocarbons in flare during startup, shutdown or malfunctions, in metric tons;
n = Annual number of startups, shutdowns or malfunctions;
p = Startup, shutdown or malfunction period;
(FlareSSM)p = Volume of gas directed to flare during startup, shutdown or malfunction period p, in thousands of cubic metres at standard conditions;
MWp = Average molecular weight of flare gas combusted during measurement period p, in kilograms per kilomole;
MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
CCp = Average carbon content of flare gas combusted during measurement period p, in kilograms of carbon per kilogram of flare gas;
3.664 = Ratio of molecular weights, CO2 to carbon;
0.98 = Flare combustion efficiency;
1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres;
(4) the CH4 emissions attributable to the combustion of hydrocarbons in flares must be calculated using equation 9-14:
Equation 9-14
Where:
CH4 = Annual CH4 emissions attributable to the combustion of hydrocarbons in flares, in metric tons;
CO2 = Annual CO2 emissions attributable to the combustion of hydrocarbons in flares, calculated using equations 9-10 to 9-12 or in accordance with QC.1, in metric tons;
EFCH4 = CH4 emission factor of 2.8 × 10-3 kG per gigajoule;
EFCO2 = CO2 emission factor of 57 kG per gigajoule;
0.02/0.98 = Correction factor for flare combustion efficiency;
16/44 = Correction factor for the molecular weight ratio of CH4 to CO2;
fCH4 = Fraction of carbon in CH4 in flare gas prior to combustion, in kilograms of carbon in CH4 in flare gas per kilograms of carbon in flare gas, or default value of 0.4;
(5) the N2O emissions attributable to the combustion of hydrocarbons in flares must be calculated using equation 9-15:
Equation 9-15
EFN2O N20 = CO2 × _____ EFCO2
Where:
N2O = Annual N2O emissions attributable to the combustion of hydrocarbons in flares, in metric tons;
CO2 = Annual CO2 emissions attributable to the combustion of hydrocarbons in flares, calculated using equations 9-10 to 9-12 or in accordance with QC.1, in metric tons;
EFN2O = N2O emission factor of 5.7 × 10-4 kg per gigajoule;
EFCO2 = CO2 emission factor of 57 kg per gigajoule;
(6) when equipment or methods other than flares are used to destroy low Btu gases such as coker flue gas, gases from vapour recovery systems, casing vents and product storage tanks, the CO2 emissions must be calculated using equation 9-16:
Equation 9-16
Where:
CO2 = Annual CO2 emissions attributable to the combustion of low Btu gases, in metric tons;
n = Total number of low Btu gases;
p = Low Btu gas;
GVp = Annual volume of gas p, in thousands of cubic metres at standard conditions or in kilograms for a mass balance;
CCp = Carbon content of gas p, in kilograms of carbon per kilogram of gas;
MWp = Molecular weight of gas p in kilograms per kilomole or, when a mass flowmeter is used to measure the flow of gas p in kilograms, replace
_ _
| |
| MWp|
|----| by 1;
|MVC |
|_ _| MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
3.664 = Ratio of molecular weights, CO2 to carbon;
1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres.
QC.9.3.6. Calculation of CH4 emissions from storage tanks
The CH4 emissions of the following storage tanks do not have to be calculated: units permanently attached to conveyances such as trucks, trailers, rail cars, barges, or ships; pressure vessels designed to operate in excess of 204.9 kPa and without emissions to the atmosphere; bottoms receivers or sumps; vessels storing wastewater; and reactor vessels associated with a manufacturing process unit.
The annual CH4 emissions from all other storage tanks must be calculated using the following methods:
(1) for storage tanks other than those used for unstabilized crude oil that have a vapour-phase CH4 concentration of 0.5% volume percent or more by volume, the CH4 emissions must be calculated using the following methods:
(a) when the CH4 composition is known, according to the procedures provided for in section 7.1 of the AP-42: “Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Areas Sources”, including TANKS Model (version 4.09(D), published by the U.S. Environmental Protection Agency (USEPA);
(b) using equation 9-17:
Equation 9-17
CH4 = Qpb × 6.29 × 10-7
Where:
CH4 = Annual CH4 emissions from storage tanks, in metric tons;
Qpb = Annual quantity of crude oil and intermediate products received from off-site that are processed at the establishment, in kilolitres;
6.29 × 10-7 = Default emission factor for storage tanks, in metric tons of CH4 per kilolitre;
(2) for storage tanks for unstabilized crude oil, the CH4 emissions must be calculated using the following methods:
(a) when the CH4 concentration is known, by measuring directly the vapour generated;
(b) using equation 9-18:
Equation 9-18
Where:
CH4 = Annual CH4 emissions from storage tanks, in metric tons;
2.57 × 10-5 = Equation correlation factor, in thousands of cubic metres at standard conditions, per kilolitre per kilopascal;
Qun = Annual quantity of unstabilized crude oil, in kilolitres;
/\P = Pressure differential from storage pressure to atmospheric pressure, in kilopascals;
MFCH4 = Mole fraction of CH4 in vent gas from the unstabilized crude oil storage tank, measured by the emitter, in kilomoles of CH4 per kilomole of gas, or a value of 0.27;
16 = Molecular weight of CH4, in kilograms per kilomole;
MVC = Molar volume conversion factor (24.06 m2 per kilomole at standard conditions);
1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres.
QC.9.3.7. Calculation of CH4 and N2O emissions attributable to anaerobic wastewater treatment
The annual emissions attributable to anaerobic wastewater treatment must be calculated:
(1) for CH4 emissions, using equation 9-19 or equation 9-20:
Equation 9-19
CH4 = Q × CODqave × B × MCF × 0.001
Where:
CH4 = Annual CH4 emissions attributable to wastewater treatment, in metric tons;
Q = Quantity of wastewater treated annually, in cubic metres;
CODqave = Quarterly average chemical oxygen demand of the wastewater, in kilograms per cubic metre;
B = CH4 generation capacity of 0.25 kg of CH4 per kilogram of chemical oxygen demand;
MCF = Conversion factor for CH4 specified in Table 9-3 of QC.9.6, depending on the process;
0.001 = Conversion factor, kilograms to metric tons;
Equation 9-20
CH4 = Q × BOD5qave × B × MCF × 0.001
Where:
CH4 = Annual CH4 emissions attributable to wastewater treatment, in metric tons;
Q = Quantity of wastewater treated annually, in cubic metres;
BOD5qave = Average quarterly five-day biochemical oxygen demand of the wastewater, in kilograms per cubic metre;
B = CH4 generation capacity of 0.25 kg of CH4 per kilogram of chemical oxygen demand;
MCF = Conversion factor for CH4 specified in Table 9-3 of QC.9.6, depending on the process;
0.001 = Conversion factor, kilograms to metric tons;
(2) for anaerobic processes from which biogas is recovered and not emitted, the CH4 emissions must be calculated by subtracting the quantity recovered;
(3) for N2O emissions, using equation 9-21:
Equation 9-21
N2O = Q × Nqave × EFN2O × 1.571 × 0.001
Where:
N2O = Annual N2O emissions attributable to wastewater treatment, in metric tons;
Q = Quantity of wastewater treated annually, in cubic metres;
Nqave = Quarterly average nitrogen content in effluent, in kilograms per cubic metre;
EFN2O = N2O emission factor from discharged wastewater of 0.005 kg of nitrogen produced by the decomposition of nitrous oxide (N2O-N) per kilogram of total nitrogen;
1.571 = Conversion factor, kilograms of N2O-N to kilograms of N2O;
0.001 = Conversion factor, kilograms to metric tons.
QC.9.3.8. Calculation of CH4 emissions from oil-water separators
The annual CH4 emissions from oil-water separators must be calculated using equation 9-22:
Equation 9-22
CH4 = EFNMHC × Qwater × CFNMHC ×0.001
Where:
CH4 = Annual CH4 emissions from oil-water separators, in metric tons;
EFNMHC = Emission factor for hydrocarbons other than CH4 as specified in Table 9-4 in QC.9.6, in kilograms per cubic metre;
Qwater = Quantity of wastewater treated annually by the separator, in cubic metres;
CFNMHC = Conversion factor, non-methane hydrocarbons to CH4, obtained by sampling and analysis at each separator or, in the absence of such data, a factor of 0.6;
0.001 = Conversion factor, kilograms to metric tons.
QC.9.3.9. Calculation of fugitive emissions of CH4 from system components
Annual fugitive emissions of CH4 must be calculated using one of the two following methods:
(1) using process-specific CH4 composition data for each process and one of the emission estimation procedures provided for in the EPA-453/R-095-017, NTIS PB96-175401 “Protocol for Equipment Leak Emission Estimates” published by the U.S. Environmental Protection Agency (USEPA);
(2) using equation 9-23:
Equation 9-23
CH4 = (0.4 × Nc) + (0.2 × NPU,1) + (0.1 × NPU,2) + (4.3 × NH2) + (6 × Nrgc)
Where:
CH4 = Annual CH4 emissions attributable to fugitive emissions from system components, in metric tons;
Nc = Number of crude oil distillation columns;
NPU,1 = Cumulative number of catalytic cracking units, coking units (delayed or fluid), hydrocracking, and full-range distillation columns (including depropanizer and debutanizer distillation columns);
NPU,2 = Cumulative number of hydrotreating/hydrorefining units, catalytic reforming units, and visbreaking units;
NH2 = Total number of hydrogen production units;
Nrgc = Total number of fuel gas systems.
QC.9.3.10. Coke calcining
The annual CO2, CH4 and N2O emissions attributable to coke calcining must be calculated using the following methods:
(1) the CO2 emissions attributable to coke calcining must be calculated in accordance with QC.1.3.4 when the facility is equipped with a continuous emission monitoring and recording system or, in the absence of such a system, using equation 9-24:
Equation 9-24
CO2 = [Min × CGC - (Mout + MCBR) × CMPC] × 3.664
Where:
CO2 = Annual CO2 emissions attributable to coke calcining, in metric tons;
Min = Annual mass of green coke entering the coke calcining process, in metric tons;
CGC = Average mass fraction carbon content of the green coke, in metric tons of carbon per metric ton of green coke;
Mout = Annual mass of marketable coke, in metric tons of petroleum coke;
MCBR = Annual mass of petroleum coke breeze collected in the dust collection system of the coke calcining unit, in metric tons of dust per metric ton of calcined coke;
CMPC = Average mass fraction carbon content of marketable petroleum coke, in metric tons of carbon per metric ton of petroleum coke;
3.664 = Ratio of molecular weights, CO2 to carbon;
(2) the annual CH4 emissions attributable to coke calcining must be calculated using equation 9-25:
Equation 9-25
EFCH4 CH4 = CO2 × _____ EFCO2
Where:
CH4 = Annual CH4 emissions attributable to coke calcining, in metric tons;
CO2 = Annual CO2 emissions from coke calcining, calculated using equation 9-1, in metric tons;
EFCH4 = CH4 emission factor determined by the emitter or a default value of 2.8 × 10-3 kg per gigajoule;
EFCO2 = CO2 emission factor of 97 kg per gigajoule;
(3) the annual N2O emissions attributable to coke calcining must be calculated using equation 9-26:
Equation 9-26
EFN2O N20 = CO2 × _____ EFCO2
Where:
N2O = Annual N2O emissions attributable to coke calcining, in metric tons;
CO2 = Annual CO2 emissions attributable to coke calcining, calculated using equation 9-1, in metric tons;
EFN2O = N2O emission factor of 5.7 × 10-4 kg per gigajoule;
EFCO2 = CO2 emission factor of 97 kg per gigajoule.
QC.9.3.11. Uncontrolled blowdown systems
The annual CO2, CH4 and N2O emissions from uncontrolled blowdown systems must be calculated using the calculation methods in QC.9.3.2.
QC.9.3.12. Loading operations
The CH4 emissions attributable to crude oil, intermediate, or product loading operations must be calculated using equilibrium vapourphase CH4 composition data and the procedures in Section 5.2 of the AP-42: “Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources” published by the U.S. Environmental Protection Agency (USEPA). When the equilibrium vapour-phase concentration of CH4 is less than 0.5%, zero CH4 emissions may be assumed.
QC.9.3.13. Delayed coking processes
The CH4 emissions attributable to the depressurization of the vessels in each coking unit to the atmosphere must be calculated using one of the calculation methods in paragraphs 1 and 2, except in the case of an emitter who adds water or steam to the vessel once it is vented to the atmosphere, who must use the method in paragraph 1:
(1) the CH4 emissions attributable to the depressurization of the vessels in each coking unit to the atmosphere must be calculated using equation 9-6 and the CH4 emissions attributable to the subsequent opening of the vessel for coke cutting operations must be calculated, for each vessel with the same dimensions, using equation 9-27:
Equation 9-27
(2) the annual CH4 emissions from the depressurization vents and the subsequent opening of the vessels in each coking unit for coke cutting operations must be calculated using equation 9-27 and the manometric pressure of the coking vessel when the depressurization gases are first routed to the atmosphere.
QC.9.4. Sampling, analysis and measurement requirements
QC.9.4.1. Catalyst regeneration
For catalyst regeneration, the emitter must:
(1) for fluid catalytic cracking units and fluid cokers:
(a) measure the daily concentration of oxygen in the oxygen-enriched air stream inlet to the regenerator;
(b) measure the volumetric flow of air and oxygen-enriched air to the regenerator, on a continuous basis;
(c) measure the CO2, carbon monoxide and oxygen concentrations in the exhaust gas from the regenerator, on a continuous basis or weekly;
(d) when equation 9-1 is used, measure the daily carbon content of the coke combusted;
(e) measure the number of hours of operation;
(2) for periodic catalyst regeneration:
(a) measure the quantity of catalyst regenerated in each regeneration cycle;
(b) measure the carbon content of the catalyst prior to and after regeneration;
(3) for continuous catalyst regeneration in operations other than fluid catalytic cracking and fluid coking:
(a) measure the hourly catalyst regeneration rate;
(b) measure the carbon content of the catalyst, prior to and after regeneration;
(c) measure the number of hours of operation.
The values measured daily or weekly can be used to determine the minute or hourly data required for the corresponding equations.
QC.9.4.2. Process vents
For process vents, the emitter must, for each process venting event, measure the following parameters:
(1) the flow rate for each venting event;
(2) the molar fraction of CO2, CH4 and N2O in the vent gas stream during each venting event;
(3) the duration of each venting event.
QC.9.4.3. Asphalt production
For asphalt production, the emitter must measure the quantity of asphalt blown.
QC.9.4.4. Sulphur recovery
For sulphur recovery, the emitter must measure the volumetric flow rate of acid gas to the sulphur recovery units.
If using a source specific molecular faction value instead of the default factor, the emitter must conduct an annual test of the CO2 content in the acid gas emitted to sulphur recovery units.
QC.9.4.5. Flares and other antipollution equipments
For flares and other antipollution equipments, an emitter must:
(1) if using a continuous emission monitoring and recording system on the flare, use the measured flow rate when it is within the calibrated range of the measurement device, or, determine the flow rate according to a sector-recognized method when it is not measured by the system;
(2) if using equation 9-10 or 9-13, measure the parameters used to determine the carbon content of the flare gas daily;
(3) if using equation 9-11, measure the parameters used to determine the high heat value of the flare gas daily.
When the continuous monitoring and recording system does not provide the parameters used to determine the carbon content of the gas, the emitter must measure those parameters at least weekly.
QC.9.4.6. Storage tanks
For storage tanks, the emitter must determine the annual throughput of all types of products for each storage tank using one of the following methods:
(1) by measuring them directly using measurement devices;
(2) by using any other measured or collected data.
QC.9.4.7. Wastewater treatment
For wastewater treatment, the emitter must
(1) collect weekly samples to analyse the chemical oxygen demand and 5-day biochemical oxygen demand (DBO5) of the wastewater from the anaerobic treatment process following preliminary treatment;
(2) measure weekly the flow rate of wastewater entering the anaerobic wastewater treatment process, at the flow measurement location used to collect samples under paragraph 1 to analyse the chemical oxygen demand and 5-day biochemical oxygen demand (DBO5);
(3) determine quarterly the nitrogen content of the wastewater.
QC.9.4.8. Oil-water separators
For oil-water separators, the emitter must measure the daily volume of wastewater treated by the oil-water separators.
QC.9.4.9. Coke calcining
For coke calcining, the emitter must measure the mass and carbon content of the petroleum coke using one of the following methods:
(1) the most recent version of ASTM D3176 “Standard Practice for Ultimate Analysis of Coal and Coke”;
(2) the most recent version of ASTM D5291 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”;
(3) the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”;
(4) any other analysis method published by an organization listed in QC.1.5.
QC.9.5. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern carbon content, molecular mass, molar fraction, molecular fraction, high heat value, CO2 concentration, CO concentration, O2 concentration, temperature, pressure, nitrogen content or biochemical oxygen demand,
(i) determine the sampling or measurement rate using the following equation:
Equation 9-28
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.9.4;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern coke burn, volumetric gas flow, gas volume, number of hours of operation, quantity of bituminous product blown, quantity of crude oil and intermediate products, quantity of wastewater treated, quantity of coke, quantity of coke dust or number of vessels openings in a coking unit, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.9.6. Tables
Table 9-1. Coke burn rate material balance and conversion factors
(QC.9.3.1(1))
_________________________________________________________________________________
| | |
| Conversion factor | (kg min)/(h m3 (dry base) %) |
|________________________________________|________________________________________|
| | |
| K1 | 0.2982 |
|________________________________________|________________________________________|
| | |
| K2 | 2.0880 |
|________________________________________|________________________________________|
| | |
| K3 | 0.0994 |
|________________________________________|________________________________________| Table 9-2. (Revoked)
Table 9-3. CH4 conversion factors by type of industrial wastewater treatment process
(QC.9.3.7(1))
__________________________________________________________________________________
| | | | |
| Type of treatment and | Comments | Conversion | Range |
| discharge pathway or | | factor | |
| system | | (MCF) | |
|____________________________|___________________________|____________|___________|
| |
| Untreated |
|_________________________________________________________________________________|
| | | | |
| Sea, river and lake | Rivers with high organic | 0.1 | 0 - 0.2 |
| discharge1 | loading may turn | | |
| | anaerobic, however this | | |
| | is not considered here | | |
|____________________________|___________________________|____________|___________|
| |
| Treated |
|_________________________________________________________________________________|
| | | | |
| Aerobic treatment plant | Well maintained, some CH4 | 0 | 0 - 0.1 |
| | may be emitted from | | |
| | settling basins | | |
|____________________________|___________________________|____________|___________|
| | | | |
| Aerobic treatment plant | Not well maintained, | 0.3 | 0.2 - 0.4 |
| | overloaded | | |
|____________________________|___________________________|____________|___________|
| | | | |
| Anaerobic digester for | CH4 recovery not | 0.8 | 0.8 - 1.0 |
| sludge2 | considered here | | |
|____________________________|___________________________|____________|___________|
| | | | |
| Anaerobic reactor2 | CH4 recovery not | 0.8 | 0.8 - 1.0 |
| | considered here | | |
|____________________________|___________________________|____________|___________|
| | | | |
| Anaerobic shallow lagoon | Depth less than 2 meters | 0.2 | 0 - 0.3 |
|____________________________|___________________________|____________|___________|
| | | | |
| Anaerobic deep lagoon | Depth more than 2 meters | 0.8 | 0.8 - 1.0 |
|____________________________|___________________________|____________|___________|
| |
| For CH4 generation capacity (B) in kilograms of CH4 per kilogram of chemical |
| oxygen demand (COD), the emitter must use the default emission factor of |
| 0.25 kg CH4 per kilogram COD. |
| |
| The emission factor for N2O from discharged wastewater (EFN2O) is 0.005 kg |
| N2O-N per kg-N. |
| |
| MCF = CH4 conversion factor (the fraction of waste treated anaerobically). |
| |
| (1) The fact that rivers with high organic loading may turn anaerobic is not |
| taken into account. |
| |
| (2) CH4 recovery is not taken into account. |
|_________________________________________________________________________________| Table 9-4. Emission factors for oil-water separators
(QC.9.3.8)
_________________________________________________________________________________
| | |
| Type of separator | Emission factor (EFsep)a kg NMHC/m3 |
| | wastewater treated |
|________________________________________|________________________________________|
| | |
| Gravity type - uncovered | 1.11e-01 |
|________________________________________|________________________________________|
| | |
| Gravity type - covered | 3.30e-03 |
|________________________________________|________________________________________|
| | |
| Gravity type - covered and connected | 0 |
| to destruction device | |
|________________________________________|________________________________________|
| | |
| DAFb of IAFc - uncovered | 4.00e-03d |
|________________________________________|________________________________________|
| | |
| DAF or IAF - covered | 1.20e-04d |
|________________________________________|________________________________________|
| | |
| DAF or IAF - covered and connected | 0 |
| to a destruction device | |
|________________________________________|________________________________________|
| |
| a EFs do not include methane |
| |
| b DAF = dissolved air flotation type |
| |
| c IAF = induced air flotation device |
| |
| d EFs for these types of separators apply where they are installed as secondary |
| treatment systems. |
|_________________________________________________________________________________| Table 9-5. (Revoked)
QC.10. PULP AND PAPER MANUFACTURING
QC.10.1. Covered sources
The covered sources are all the processes used to manufacture pulp and paper products.
QC.10.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) the annual CO2 emissions attributable to the combustion of biomass, including black liquor, in recovery furnaces and lime kilns, calculated and reported in accordance with QC.1, in metric tons;
(2) the annual CH4 and N2O emissions attributable to the combustion of biomass, including black liquor, in recovery furnaces and lime kilns, calculated and reported in accordance with QC.1, in metric tons;
(3) the annual CO2 emissions attributable to the addition of carbonate materials in recovery furnaces and lime kilns, calculated and reported in accordance with QC.25.3, in metric tons;
(3.1) the annual CO2, CH4 and N2O emissions attributable to production of electricity, calculated and reported in accordance with QC.16, in metric tons;
(4) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;
(5) the annual consumption of carbonate materials, in metric tons;
(6) the annual production of black liquor, in metric tons;
(7) the annual CH4 and N2O emissions from anaerobic wastewater treatment, calculated and reported in accordance with QC.9.3.7, in metric tons;
(8) the number of times that the methods for estimating missing data provided for in QC.10.5 were used;
(9) (subparagraph revoked);
(10) the annual production of each pulp and paper product manufactured, in metric tons of air-dried at 10% humidity marketable products.
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraphs 1 and 3 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraphs 3.1 and 4 of the first paragraph are emissions attributable to combustion;
(3) the emissions referred to in subparagraphs 2 and 7 of the first paragraph are other emissions.
QC.10.3. Calculation methods for CO2, CH4 and N2O emissions
To calculate the CO2, CH4 and N2O emissions from biomass, the high heat value or carbon content of the biomass must be determined by the emitter in accordance with QC.10.4.
QC.10.3.1. Calculation of CO2, CH4 and N2O emissions attributable to the combustion of biomass
The annual CO2, CH4 and N2O emissions attributable to the combustion of biomass, including black liquor, in recovery furnaces and rotary lime kilns in sulphite pulp and soda pulp mills, in combustion units for recovered sulphites or bisulphites, or in independent combustion units for semi-chemical pulp process, must be calculated in accordance with QC.1.
QC.10.3.2. Calculation of CO2, CH4 and N2O emissions attributable to the addition of carbonate materials
The annual CO2, CH4 and N2O emissions attributable to the addition of carbonate materials in recovery furnaces and lime kilns must be calculated in accordance with QC.25.3.
QC.10.3.3. Calculation of CO2, CH4 and N2O emissions attributable to the production of electricity
The annual CO2, CH4 and N2O emissions attributable to the production of electricity must be calculated in accordance with QC.16.
QC.10.4. Sampling, analysis and measurement requirements
An emitter who manufactures pulp and paper must:
(1) determine the quantity of black liquor produced each year using one of the following methods:
(a) by measuring it in accordance with the most recent version of TAPPI T 650 om-09 “Solids content of black liquor” published by the Technical Association of the Pulp and Paper Industry;
(b) by measuring it using monthly data from a monitoring device installed on the process line;
(c) by determining it using equation 1-8;
(d) by using any other analysis method published by an organization listed in QC.1.5;
(1.1) determine the high heat value of the black liquor using the most recent version of TAPPI T 684 om-11 “Gross heating value of black liquor”, or using any other analysis method published by an organization listed in QC.1.5;
(2) measure the monthly carbon content of the black liquor using the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal” or ASTM 5291 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricant”, or using any other analysis method published by an organization listed in QC.1.5;
(3) (paragraph revoked);
(4) (paragraph revoked);
QC.10.5. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern carbonate content in raw materials or in carbonate-based material output, use the default value of 1.0;
(b) when the missing data concern carbon content or high heat value,
(i) determine the sampling or measurement rate using the following equation:
Equation 10-1
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.10.4;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(c) when the missing data concern the quantity of spent pulping liquor, the mass flow of spent pulping liquor, the annual production of each pulp and paper product manufactured or the quantity of carbonate material, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.11. SODIUM CARBONATE PRODUCTION
QC.11.1. Covered sources
The covered sources are all the processes used in the production of sodium carbonate by calcining trona or sodium sesquicarbonate, and all liquid alkaline feedstock processes that produce CO2.
QC.11.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) the annual CO2 emissions from sodium carbonate production, calculated in accordance with QC.11.3, in metric tons;
(2) the annual CO2, CH4 and N2O emissions attributable to fuel combustion in calcining kilns, calculated and reported in accordance with QC.1, in metric tons;
(3) the annual consumption of trona, sodium sesquicarbonate and liquid alkaline feedstock, in metric tons;
(4) the annual production of sodium carbonate, in metric tons;
(4.1) the number of times that the methods for estimating missing data specified in QC.11.5 were used;
(4.2) (subparagraph revoked);
(5) (subparagraph revoked);
(6) (subparagraph revoked);
(7) (subparagraph revoked);
(8) (subparagraph revoked);
(9) (subparagraph revoked).
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraph 1 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to combustion.
QC.11.3. Calculation methods for CO2 emissions
The annual CO2 emissions from sodium carbonate production unit must be calculated using one of the calculation methods in QC.11.3.1 to QC.11.3.3.
QC.11.3.1. Calculation method using data from a continuous emission monitoring and recording system
The annual CO2 emissions from a sodium carbonate production unit may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.
QC.11.3.2. Calculation method using inorganic carbon content
The annual CO2 emissions from a sodium carbonate production unit may be calculated using equation 11-1 or 11-2:
Equation 11-1
Where:
CO2 = Annual CO2 emissions attributable to sodium carbonate production, in metric tons;
i = Month;
CITR = Monthly inorganic carbon content of trona at kiln input for month i, in kilograms of carbon per kilogram of trona;
TR = Monthly quantity of trona input in month i, in metric tons;
0.097 = Ratio of CO2 emitted for each metric ton of trona, in metric tons of CO2 per metric ton of trona;
Equation 11-2
Where:
CO2 = Annual CO2 emissions attributable to sodium carbonate production, in metric tons;
i = Month;
CISC = Monthly inorganic carbon content of sodium carbonate at kiln output for month i, in kilograms of carbon per kilogram of sodium carbonate;
SC = Monthly quantity of sodium carbonate produced during month i, in metric tons;
0.138 = Ratio of CO2 emitted for each metric ton of sodium carbonate produced, in metric tons of CO2 per metric ton of sodium carbonate.
QC.11.3.3. Calculation method using site-specific emission factor
The annual CO2 emissions from a sodium carbonate production unit using liquid alkaline feedstock may be calculated using equations 11-3 to 11-5:
Equation 11-3
CO2 = EFCO2 × Va × H
Where:
CO2 = Annual CO2 emissions attributable to sodium carbonate production, in metric tons;
EFCO2 = CO2 emission factor, in metric tons of CO2 per metric ton of process vent flow from water stripper/evaporator, calculated using equation 11-4;
Va = Process vent mass flow of water stripper/evaporator, in metric tons per hour;
H = Number of hours of operation during the year;
Equation 11-4
ERCO2 EFCO2 = _____ Vtp
Where:
EFCO2 = CO2 emission factor, in metric tons of CO2 per metric ton of process vent flow from water stripper/evaporator;
ERCO2 = CO2 emission rate, in metric tons per hour, calculated using equation 11-5;
Vtp = Process vent mass flow of water stripper/evaporator, measured during performance test, in metric tons per hour;
Equation 11-5
ERCO2 = [(CCO2 × 10000 × 4,16 × 10-8 × 44) × (VF × 60)] × 0.001
Where:
ERCO2 = CO2 emission rate, in metric tons per hour;
CCO2 = Hourly concentration of CO2 in the gas, determined in accordance with QC.11.4, expressed as a percentage;
10000 = Conversion factor, percentage to ppm;
4.16 × 10-8 = Conversion factor, ppm to kilomoles per cubic metre at standard conditions;
44 = Molecular weight of CO2, kilograms per kilomole;
VF = Volumetric flow of gas, in cubic metres at standard conditions per minute;
60 = Conversion factor, minutes to hours;
0.001 = Conversion factor, kilograms to metric tons.
QC.11.4. Sampling, analysis and measurement requirements
An emitter who uses equation 11-1 or 11-2 in QC.11.3.2 must:
(1) determine the monthly inorganic carbon content of the trona or sodium carbonate from a weekly composite sample for each production unit using the most recent version of ASTM E359 e1 “Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate(e)”, or using any other analysis method published by an organization listed in QC.1.5;
(2) measure the quantity of trona or sodium carbonate for each production unit using the same plant instruments as those used for inventory purposes.
An emitter who uses equations 11-3 to 11-5 in QC.11.3.3 must conduct an annual performance test in normal operating conditions, during which the emitter must:
(1) conduct 3 emissions test runs of 1 hour each;
(2) determine the hourly CO2 concentration in accordance with Method 3A in appendix A-2 of Part 60 of Title 40 of the Code of Federal Regulations “Determination of Oxygen and Carbon Dioxide Concentrations in Emissions From Stationary Sources (Instrumental Analyzer Procedure)” published by the U.S. Environmental Protection Agency (USEPA);
(3) determine the stack gas volumetric flow rate using one of the methods published by the U.S. Environmental Protection Agency (USEPA):
(a) Method 2 in Appendix A-1 of Part 60 of Title 40 of the Code of Federal Regulations “Determination of Stack Gas Velocity and Volumetric Flow Rate (Type S Pitot Tube)”;
(b) Method 2A in Appendix A-1 of Part 60 of Title 40 of the Code of Federal Regulations “Direct Measurement of Gas Volumetric Through Pipes and Small Ducts”;
(c) Method 2C in Appendix A-1 of Part 60 of Title 40 of the Code of Federal Regulations “Determination of Gas Velocity and Volumetric Flow Rate in Small Stacks or Ducts (Standard Pitot Tube)”;
(d) Method 2D in Appendix A-1 of Part 60 of Title 40 of the Code of Federal Regulations “Measurement of Gas Volume Flow Rates in Small Pipes and Ducts”;
(e) Method 2F in Appendix A-1 of Part 60 of Title 40 of the Code of Federal Regulations “Determination of Stack Gas Velocity and Volumetric Flow Rate with Three-Dimensional Probes”;
(f) Method 2G in Appendix A-2 of Part 60 of Title 40 of the Code of Federal Regulations “Determination of Stack Gas Velocity and Volumetric Flow Rate With Two-Dimensional Probes”;
(4) prepare a CO2 emission factor determination report containing all the information needed to calculate the emission factor and the sample reports prepared pursuant to paragraph 1;
(5) determine the average process vent flow from the water stripper/evaporator;
(6) determine the annual vent flow rate from the mine water stripper/evaporator from monthly data using the same plant instruments as those used for inventory purposes, such as a volumetric flowmeter.
QC.11.5. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern the hourly concentration of CO2, the volumetric gas flow rate or the process vent average mass flow rate of gas in the water stripper/evaporator during a performance test, conduct a new performance test;
(b) when the missing data concern carbon content,
(i) determine the sampling or measurement rate using the following equation:
Equation 11-6
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.11.4;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(c) when the missing data concern the ore quantity, process vent mass flow rate of gas in the water stripper/evaporator or quantity of sodium carbonate, estimate the replacement data on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.12. MANUFACTURING OF PETROCHEMICAL PRODUCTS
QC.12.1. Covered sources
The covered sources are all the processes used in the production of petrochemical products from feedstocks derived from petroleum, or petroleum and natural gas liquids, but not from feedstocks derived from biomass.
The production of methanol, hydrogen, or ammonia from synthesis gas is also covered if the annual production of methanol exceeds the combined production of both hydrogen recovered as a product and ammonia. However, if the annual mass of hydrogen recovered exceeds the combined annual production of methanol and ammonia, the emissions must be calculated and reported in accordance with QC.6 with respect to hydrogen production. In addition, if the annual production of ammonia exceeds the combined annual production of both hydrogen recovered as a product and methanol, the emissions must be calculated and reported in accordance with QC.23 with respect to ammonia production.
A process that produces only a petrochemical by-product, and a direct chlorination process that is operated independently of an oxychlorination process to produce ethylene dichloride, is not covered.
QC.12.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include
(1) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;
(2) the annual CO2, CH4 and N2O emissions attributable to the combustion of refinery fuel gas, flexigas or associated gas, calculated and reported in accordance with QC.2, in metric tons;
(2.1) the annual CO2 emissions attributable to hydrogen production processes, calculated and reported in accordance with QC.6, in metric tons;
(3) the annual CO2 emissions attributable to each petrochemical process, in metric tons;
(4) the annual CO2 emissions attributable to catalyst regeneration calculated and reported in accordance with QC.9, in metric tons;
(4.1) the annual CH4 and N2O emissions attributable to catalyst regeneration calculated and reported in accordance with QC.9, in metric tons;
(5) the annual CO2, CH4 and N2O emissions attributable to flares and antipollution devices calculated and reported in accordance with QC.9, in metric tons;
(6) the annual CO2, CH4 and N2O emissions from process vents calculated and reported in accordance with QC.9, in metric tons;
(7) the annual CH4 emissions from leaks from equipment components calculated and reported in accordance with QC.9, in metric tons;
(8) the annual CH4 emissions from storage tanks calculated and reported in accordance with QC.9, in metric tons;
(9) the annual CH4 and N2O emissions attributable to wastewater treatment, calculated and reported in accordance with QC.9.3.7, in metric tons;
(10) the annual CH4 emissions attributable to oil-water separators, calculated and reported in accordance with QC.9.3.8, in metric tons;
(11) the annual consumption of each type of raw material that emits CO2, CH4 or N2O, expressed
(a) in metric tons, when the quantity is expressed as a mass;
(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
(c) in kilolitres, when the quantity is expressed as a volume of liquid;
(d) in bone dry metric tons, for biomass-derived solid fuels, when the quantity is expressed as a mass;
(11.1) the annual production of each petrochemical product, namely:
(a) in dry metric tons when the quantity is expressed in weight;
(b) in thousands of cubic metres at standard conditions when the quantity is expressed as a volume of gas;
(c) in kilolitres when the quantity is expressed as a volume of liquid;
(d) in dry metric tons in the case of biomass fuels when the quantity is expressed in weight;
(12) the average annual carbon content of the materials consumed or of the products, in kilograms of carbon per kilogram of materials consumed or products;
(13) the average annual molecular mass of the gas consumed or of the products, in kilograms per kilomole;
(14) the number of times that the methods for estimating missing data provided for in QC.12.5 were used;
(15) (subparagraph revoked).
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraph 2.1, 3 and 4 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraphs 1 and 2 of the first paragraph are emissions attributable to combustion;
(3) the emissions referred to in subparagraphs 4.1 and 5 to 10 of the first paragraph are other emissions.
QC.12.3. Calculation methods for CO2, CH4 and N2O emissions
The annual CO2, CH4 and N2O emissions attributable to the production of petrochemical products must be calculated in accordance with the calculation methods in QC.12.3.1 to QC.12.3.6.
QC.12.3.1. Calculation of CO2 emissions attributable to each petrochemical process
The annual CO2 emissions attributable to each petrochemical process must be calculated in accordance with the following methods:
(1) where the quantity of feedstock and the quantity of product are expressed as volumes of gas, using equation 12-1:
Equation 12-1
Where:
CO2 = Annual CO2 emissions attributable to each petrochemical process, in metric tons;
k = Month;
n = Number of feedstock materials;
m = Number of products;
i = Type of feedstock the quantity of which is expressed as a volume of gas;
j = Type of product the quantity of which is expressed as a volume of gas;
(VGI)i,k = Quantity of feedstock i consumed in month k, in thousands of cubic metres at standard conditions;
(CGI)i,k = Average carbon content of feedstock i in for month k, in kilograms of carbon per kilogram of feedstock;
(MMGI)i = Monthly average molecular mass of feedstock i, in kilograms per kilomole or, when a mass flowmeter is used to measure the flow of gas input in metric tons for month n, replace
_ _
| |
|MMGI |
|----| by 1;
|MVC |
|_ _| MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
(VGP)j,k = Volume of product j produced in month k, in thousands of cubic metres at standard conditions;
(CGP)j,k = Average carbon content of product j produced in month k, in kilograms of carbon per kilogram of product;
(MMGP)j = Monthly average molecular mass of gas j, in kilograms per kilomole;
3.664 = Ratio of molecular weights, CO2 to carbon;
1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres;
(2) where the quantity of feedstock and the quantity of product are expressed as a mass, using equation 12-2:
Equation 12-2
Where:
CO2 = Annual CO2 emissions attributable to each petrochemical process, in metric tons;
n = Month;
k = Number of feedstock materials;
m = Number of products;
i = Type of feedstock material the quantity of which is expressed as a mass;
j = Type of product the quantity of which is expressed as a mass;
(QF)i,n = Quantity of feedstock i consumed in month n, in metric tons;
(CF)i,n = Average carbon content of feedstock i for month n, in kilograms of carbon per kilogram of feedstock;
(QP)j,n = Quantity of product j for month n, in metric tons;
(CP)j,n = Average carbon content of product j for month n, in kilograms of carbon per kilogram of product;
3.664 = Ratio of molecular weights, CO2 to carbon.
QC.12.3.2. Calculation of CO2, CH4 and N2O emissions attributable to catalyst regeneration
The annual CO2 emissions attributable to catalyst regeneration at a facility equipped with a continuous emission monitoring and recording system must be calculated in accordance with QC.1.3.4 or, in the absence of such a system, in accordance with QC.9.3.1 according to the type of process.
QC.12.3.3. Calculation of CO2, CH4 and N2O emissions attributable to combustion in flares and other antipollution equipments
The annual CO2, CH4 and N2O emissions attributable to combustion in flares must be calculated in accordance with the calculation methods in QC.9.3.5.
The annual CO2, CH4 and N2O emissions attributable to combustion in other antipollution equipments must be calculated in accordance with the calculation methods in QC.1, except CH4 and N2O emissions attributable to process off-gas combustion which must be calculated using equation 1-12 in QC.1.4.2 with emission factors of 2.8 × 10-3 kg per gigajoule for CH4 and 5.7 × 10-4 kg per gigajoule for N2O.
QC.12.3.4. Calculation of CO2, CH4 and N2O emissions from process vents
For each process vent that contains over 2% CO2 by volume, over 0.5% CH4 by volume, or over 0.01% N2O by volume, the annual CO2, CH4 and N2O emissions from process vents, other than emissions required for the process, must be calculated in accordance with QC.9.3.2.
QC.12.3.5. Calculation of fugitive CH4 emissions from equipment components
The annual fugitive emissions of CH4 from all components in the natural gas or refinery gas supply system and from pressure swing adsorption (PSA) systems must be calculated in accordance with paragraph 1 of QC.9.3.9.
QC.12.3.6. Calculation of CH4 emissions from storage tanks
The annual CH4 emissions from storage tanks containing petroleum-derived products that are not equipped with pressure swing adsorption (PSA) systems must be calculated in accordance with QC.9.3.6.
QC.12.3.7. (Revoked).
QC.12.3.8. (Revoked).
QC.12.4. Sampling, analysis and measurement requirements
QC.12.4.1. Catalyst regeneration
For catalyst regeneration, the emitter must measure the parameters in accordance with QC.9.4.1.
QC.12.4.2. Flares and other antipollution devices
For flares and antipollution devices, the emitter must measure the parameters in accordance with QC.9.4.5 and determine quarterly the carbon content and high heat value.
QC.12.4.3. Process vents
For process vents, the emitter must, for each process vent event, measure the parameters in accordance with QC.9.4.2.
QC.12.4.4. (Revoked).
QC.12.4.5. Storage tanks
For storage tanks, the emitter must measure the annual throughput of crude oil, naphtha, distillate oils and gasoil using flowmeters.
QC.12.4.6. Wastewater treatment
For wastewater treatment, the emitter must measure the parameters in accordance with QC.9.4.7.
QC.12.4.7. Oil-water separators...
For oil-water separators, the emitter must measure the daily volume of wastewater treated in the oil-water separators.
QC.12.4.8. Feedstock consumption and products
An emitter who calculates greenhouse gas emissions in accordance with QC.12.3.1 must determine, monthly, the quantity of feedstock consumed and the quantity of products produced using the following methods:
(1) if the feedstock and product are gases, using a flowmeter;
(2) if the feedstock and product are liquids, using a flowmeter or by measuring the liquid level in a storage tank;
(3) if the feedstock and product are solids, using the same plant instruments as those used for inventory purposes, such as weigh hoppers or belt weight feeders.
The emitter must determine carbon content monthly and, in the case of a gas, its molecular weight, using the sampling and analysis results indicated by the supplier or samples taken by the emitter. When more than one monthly value is available, the arithmetic average must be used.
When the monthly average concentration of a specific compound in a feedstock or product is greater than 99.5% by weight or, in the case of a gas, by volume then, as an alternative, the emitter may determine the carbon content by assuming that 100% of that feedstock or product is the specific compound in normal operating conditions. A determination made using this alternative must be reevaluated after any process change that affects the feedstock or product composition. However, this alternative may not be used for products during periods of operation when off-specification product is produced, or when the average monthly concentration falls below 99.5%.
QC.12.5. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern carbon content, molecular mass, molar fraction, molecular fraction, high heat value, CO2 concentration, CO concentration, O2 concentration, temperature, pressure, nitrogen content or biochemical oxygen demand,
(i) determine the sampling or measurement rate using the following equation:
Equation 12-3
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.12.4;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern coke burn, volumetric gas flow, gas volume, number of hours of operation, quantity of raw materials, quantity of product, quantity of steam or quantity of wastewater treated, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.13. ADIPIC ACID PRODUCTION.
QC.13.1. Covered sources
The covered sources are all the oxidization processes used for the production of adipic acid.
QC.13.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) the annual N2O emissions attributable to the production of adipic acid in metric tons;
(1.1) the annual CO2, CH4 and N2O emissions attributable to combustion, calculated and reported in accordance with QC.1, in metric tons;
(2) the total annual production of adipic acid, in metric tons;
(2.1) the annual production of adipic acid when the antipollution system is used, in metric tons;
(3) the N2O emission factor in metric tons of N2O per metric ton of adipic acid;
(4) the destruction factor for the facility's antipollution equipment;
(5) the utilization factor for the facility's antipollution equipment;
(6) the number of times that the methods for estimating missing data in QC.13.5 were used;
(7) (subparagraph revoked).
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraph 1.1 of the first paragraph are emissions attributable to combustion;
(2) the emissions referred to in subparagraph 1 of the first paragraph are other emissions.
QC.13.3. Calculation methods for N2O emissions attributable to the oxidation process
The annual N2O emissions attributable to the oxidation process must be calculated in accordance with the calculation method in QC.13.3.1 for each of the facility’s antipollution equipments.
QC.13.3.1. Calculation method using the N2O emission factor and destruction factors and the use of antipollution equipment
The annual N2O emissions must be calculated using equation 13-1:
Equation 13-1
Where:
N2O = N2O emissions attributable to the oxidation process, in metric tons;
n = Total number of periods. When a performance test is conducted annually, “n” is 1. If data is obtained from a continuous emission monitoring and recording system, “n” is at least 12;
i = Period;
EFN2O = N2O emission factor for period i, calculated in accordance with equation 13-2 or 13-3, in kilograms of N2O per metric ton of adipic acid produced;
PAA = Production of adipic acid in period i, in metric tons;
FD = Destruction factor for the antipollution equipment for period i, determined in accordance with QC.13.4;
FU = Use factor for the antipollution equipment, calculated in accordance with equation 13-4;
0.001 = Conversion factor, kilograms in metric tons;
Equation 13-2
Where:
EFN2O = N2O emission factor, in kilograms of N2O per metric ton of adipic acid produced;
n = Number of performance tests;
i = Performance test conducted in accordance with QC.13.4;
CN2O = N2O concentration in the gas stream during performance test i carried out in accordance with QC.13.4, in ppm;
Qfg = Volumetric flow of gas stream during performance test i, in cubic metres at standard conditions per hour;
1.826 × 10-6 = Conversion factor of ppm, kilograms per cubic metre at standard conditions;
P = Production rate of adipic acid during performance test i, in metric tons per hour;
Equation 13-3
CN2O × Qfg × 1.826 × 10-6 EFN2O = _________________________ P
Where:
EFN2O = N2O emission factor, in kilograms of N2O per metric ton of adipic acid produced;
CN2O = N2O concentration in the continuously-measured gas stream, in ppm;
Qfg = Volumetric flow of continuously-measured gas stream, in cubic metres at standard conditions per hour;
1.826 × 10-6 = Conversion factor of ppm, in kilograms per cubic metre at standard conditions;
P = Production rate of adipic acid measured continuously, in metric tons per hour;
Equation 13-4
PAA,1 FU = _____ PAA,2
Where:
FU = Use factor of antipollution equipment;
PAA,1 = Production of adipic acid when the antipollution equipment is used, in metric tons;
PAA,2 = Annual production of adipic acid, in metric tons.
QC.13.3.2. (Revoked)
QC.13.4. Sampling, analysis and measurement requirements
An emitter who operates a facility or establishment that produces adipic acid must use a continuous monitoring and recording system or conduct performance tests.
In the latter case, the performance test must be conducted annually on the waste gas stream from the nitric acid oxidation step when the adipic acid production process is changed either by altering the ratio of cyclohexanone to cyclohexanol or be conducted when installing an antipollution system, in normal operating conditions and when the antipollution system is not used. A report on the determination of the N2O emission factor, containing all the information needed to calculate the emission factor, must be prepared.
An emitter who does not use a continuous monitoring and recording system must also
(1) measure the N2O concentration using one of the following methods:
(a) Method 320 in appendix A of Part 63 of Title 40 of the Code of Federal Regulations “Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy”, published by the U.S. Environmental Protection Agency (USEPA);
(b) the most recent version of ASTM D6348 “Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy”;
(b.1) any other analysis method published by an organization listed in QC.1.5;
(c) determine the adipic acid production rate using annual sales data or using a measuring instrument such as a flowmeter or weight scales.
In all cases, an emitter must
(1) determine the total monthly quantity of adipic acid produced and, when the antipollution system is used, the quantity of adipic acid produced, using one of the methods in subparagraph c of subparagraph 1 of the third paragraph;
(2) determine the destruction factor using one of the following methods:
(a) using the manufacturer’s specified destruction factor;
(b) estimating the destruction factor based on all data relating to the processes used;
(c) conducting a performance test on the gas flow from the antipollution system;
(d) using a continuous emission monitoring and recording system.
QC.13.5. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when data determined on the basis of the performance test provided for in QC.13.4 is missing, conduct a new performance test;
(b) when the missing data concern carbon content, temperature, pressure or gas concentration, other than data prescribed in the performance test,
(i) determine the sampling or measurement rate using the following equation:
Equation 13-5
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.13.4;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(c) when the missing data concern adipic acid production or gas flow rate, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.14. LEAD PRODUCTION
QC.14.1. Covered sources
The covered sources are all processes used in primary and secondary lead production.
QC.14.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) (subparagraph revoked);
(2) the annual CO2 emissions attributable to the use in the furnace of each material that contributes 0.5% or more of the total carbon in the process, in metric tons;
(2.1) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion equipment, calculated and reported in accordance with QC.1, in metric tons;
(3) the annual quantity of each material or product that contributes 0.5% or more of the total carbon in the process, in metric tons;
(4) the average annual carbon content of each material or product that contributes 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material or product;
(5) the number of times that the methods for estimating missing data in QC.14.5 were used;
(6) (subparagraph revoked);
(7) the annual quantity of lead produced, in metric tons;
Subparagraph 4 of the first paragraph does not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraph 2.1 of the first paragraph are emissions attributable to combustion.
QC.14.3. Calculation methods for CO2 emissions attributable to primary and secondary lead production processes
The annual CO2 emissions attributable to use in the furnace of each material containing carbon must be calculated in accordance with one of the two calculation methods in QC.14.3.1 and QC.14.3.2.
QC.14.3.1. Use of a continuous emission monitoring and recording system
The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.
QC.14.3.2. Calculation by mass balance
The annual CO2 emissions may be calculated using equation 14-1:
Equation 14-1
Where:
CO2 = Emissions of CO2 attributable to the use in the furnace of materials containing carbon, in metric tons;
n = Number of types of material;
i = Type of material;
Mi = Annual quantity of each material i used that contributes 0.5% or more of the total carbon in the process, in metric tons;
Ci = Average annual carbon content of each material i used, in metric tons of carbon per metric ton of material;
m = Number of types of product;
j = Type of product;
Pj = Annual quantity of each product j that contributes 0.5% or more of the total carbon in the process, in metric tons;
Cj = Average annual carbon content of each product j used, in metric tons of carbon per metric ton of product;
3.664 = Ratio of molecular weights, CO2 to carbon.
QC.14.4. Sampling, analysis and measurement requirements
When the calculation method in QC.14.3.2 is used, an emitter who operates a facility or establishment that produces lead must:
(1) determine annually the carbon content of each material or product that contributes 0.5% or more of the total carbon in the process used in the furnace, either by using the data provided by the material or product supplier or by using the following methods, based on a minimum of 3 representative samples per year:
(a) for solid carbonaceous reducing agents and carbon electrodes, using the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”, or using any other analysis method published by an organization listed in QC.1.5;
(b) for liquid reducing agents, using the most recent version of ASTM D2502 “Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils From Viscosity Measurements”, ASTM D2503 “Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure”, ASTM D3238 “Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method” or ASTM D5291 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”, or using any other analysis method published by an organization listed in QC.1.5;
(c) for gaseous reducing agents, using the most recent version of ASTM D1945 “Standard Test Method for Analysis of Natural Gas by Gas Chromatograph” or ASTM D1946 “Standard Practice for Analysis of Reformed Gas by Gas Chromatography”, or using any other analysis method published by an organization listed in QC.1.5;
(d) for waste-based materials, ores or other materials or products, by sampling and chemical analysis using an analysis method published by an organization listed in QC.1.5;
(2) calculate the annual quantity of each material or product containing carbon used in the furnace by adding together the monthly quantities of the material or product, which must be weighed using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders.
QC.14.5. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern carbon content or other sampled data,
(i) determine the sampling or measurement rate using the following equation:
Equation 14-2
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.14.4;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern raw material consumption or the production of lead or other products, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.15. ZINC PRODUCTION
QC.15.1. Covered sources
The covered sources are all the processes used for primary and secondary zinc production.
QC.15.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) (subparagraph revoked);
(2) the annual CO2 emissions attributable to the use in the furnace of materials that contribute 0.5% or more of the total carbon in the process, in metric tons;
(2.1) the annual CO2, CH4 and N2O emissions attributable to combustion, calculated and reported in accordance with QC.1, in metric tons;
(3) the annual quantity of each material or product that contributes 0.5% or more of the total carbon in the process, in metric tons;
(4) the average annual carbon content of each material or product that contributes 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material;
(5) the number of times that the methods for estimating missing data in QC.15.5 were used;
(6) (subparagraph revoked);
(7) the annual quantity of cathodic zinc produced, in metric tons;
(8) the iron content of the ore, in metric tons.
Subparagraph 4 of the first paragraph does not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraph 2.1 of the first paragraph are emissions attributable to combustion.
QC.15.3. Calculation methods for CO2 emissions attributable to primary and secondary zinc production processes
The annual CO2 emissions attributable to use in the furnace of each material containing carbon must be calculated in accordance with one of the two calculation methods in QC.15.3.1 and QC.15.3.2.
QC.15.3.1. Use of a continuous emission monitoring and recording system
The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.
QC.15.3.2. Calculation by mass balance
The annual CO2 emissions may be calculated using equation 15-1:
Equation 15-1
Where:
CO2 = Annual CO2 emissions attributable to the use in the furnace of materials containing carbon, in metric tons;
n = Number of types of material;
i = Type of material;
Mi = Annual quantity of each material i used that contributes 0.5% or more of the total carbon in the process, in metric tons;
Ci = Average monthly carbon content of material i used, in metric tons of carbon per metric ton of material;
m = Number of types of product;
j = Type of product;
Pj = Annual quantity of each product j that contributes 0.5% more of the total carbon in the process, in metric tons;
Cj = Average annual carbon content of each product j used, in metric tons of carbon per metric ton of product;
3.664 = Ratio of molecular weights, CO2 to carbon.
QC.15.4. Sampling, analysis and measurement requirements
When the calculation method in QC.15.3.2 is used, an emitter who operates a facility or establishment that produces zinc must:
(1) determine annually the carbon content of each material or product that contributes 0.5% or more of the total carbon in the process, either by using the data provided by the supplier, or by using the following methods:
(a) for ores containing zinc, using the most recent version of ASTM E1941 “Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys”, or using any other analysis method published by an organization listed in QC.1.5;
(b) for carbonaceous reducing agents and carbon electrodes, using the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal”, or using any other analysis method published by an organization listed in QC.1.5;
(c) for flux materials, using the most recent version of ASTM C25 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”, or using any other analysis method published by an organization listed in QC.1.5;
(d) for waste-based materials, ores or other materials or products, by sampling and chemical analysis using an analysis method published by an organization listed in QC.1.5;
(2) calculate the annual quantity of each material or product containing carbon entering the furnace by direct weight measurement using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders.
QC.15.5. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern carbon content or other sampled data,
(i) determine the sampling or measurement rate using the following equation:
Equation 15-2
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.15.4;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern raw material consumption, zinc production or by-product production, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.16. ELECTRICITY GENERATION
QC.16.1. Covered sources
The covered sources are stationary combustion units that combust solid, liquid or gaseous fuel for the purpose of producing electricity either for sale or for use at the facility or establishment, as well as cogeneration facilities where steam and electricity are produced.
However, emergency generators and other equipment used in an emergency with a rated capacity under 10 mW are not covered.
QC.16.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information, for each stationary combustion unit:
(1) the annual greenhouse gas emissions attributable to the combustion of fossil fuels, biomass fuels, biomass and municipal solid waste, in metric tons, indicating for each type of fuel:
(a) the CO2 emissions;
(b) the CH4 emissions;
(c) the N2O emissions;
(2) the annual consumption of fuel, expressed
(a) in bone dry metric tons, when the quantity is expressed as a mass;
(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;
(c) in kilolitres, when the quantity is expressed as a volume of liquid;
(d) in bone dry metric tons, in the case of biomass fuels, when the quantity is expressed as a mass;
(e) in metric tons collected, in the case of municipal solid waste;
(3) where carbon content is used to calculate CO2 emissions, the average annual carbon content of each type of fuel, in kilograms of carbon per kilogram of fuel;
(4) where high heat value is used to calculate CO2 emissions, the average annual high heat value of each type of fuel, expressed:
(a) in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;
(b) in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;
(c) in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;
(d) in gigajoules per metric ton collected, in the case of municipal solid waste;
(5) the nameplate generating capacity of each electricity generating unit, in megawatts;
(6) the annual electricity production, in megawatt-hours;
(7) for each cogeneration unit, the type of cycle, whether a topping or bottoming cycle, and the useful thermal output, as applicable, in megajoules;
(8) the annual CO2 emissions attributable to acid gas scrubbers for fluidized bed boilers, in metric tons;
(9) the annual fugitive emissions of each HFC from cooling units, in metric tons;
(10) the annual fugitive emissions of CO2 from geothermal facilities, in metric tons;
(11) the annual fugitive emissions of CH4 from coal storage calculated and reported in accordance with QC.5, in metric tons;
(12) the annual quantity of sorbent used in acid gas scrubbing equipment for fluidized bed boilers, in metric tons;
(13) the annual energy transferred from the steam or geothermal fluid in geothermal facilities, in gigajoules;
(14) where steam or heat is acquired from another facility or establishment for electricity generation, the name of the steam or heat supplier and the quantity supplied, in megajoules;
(15) where additional fuels are used to support electricity generation or industrial production, the annual consumption of fuel by fuel type;
(16) the number of times that the methods for estimating missing data provided for in QC.16.7 were used;
(17) the annual production of steam, in metric tons;
(18) (subparagraph revoked).
Subparagraphs 3 and 4 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraph 8 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraph 1 of the first paragraph are emissions attributable to combustion, excluding CO2 emissions attributable to the combustion of biomass;
(3) the emissions referred to in subparagraphs 9, 10 and 11 of the first paragraph are other emissions.
QC.16.3. Calculation methods for CO2 emissions
The annual CO2 emissions attributable to stationary combustion units that produce electricity, acid gas scrubbers and geothermal facilities must be calculated in accordance with one of the calculation methods in QC.16.3.1 to QC.16.3.4.
For a facility or establishment with natural gas, diesel or heavy oil-powered units that are not individually equipped with a flowmeter or a dedicated tank and for which data cannot be obtained using a continuous emission monitoring and recording system, an emitter may quantify CO2 emissions using data from a measurement device common to all the units.
To determine the emissions attributable to each stationary combustion unit, the estimate must be based on total emissions, the hours of operation and the combustion efficiency of each unit. For diesel-powered units, the estimate may be based on the total quantity of energy produced, the energy produced by each unit, and the total quantity of diesel fuel consumed.
QC.16.3.1. Use of a continuous emission monitoring and recording system
The annual CO2 emissions attributable to stationary combustion units producing electricity may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.
QC.16.3.2. Calculation of CO2 emissions attributable to stationary combustion units producing electricity
The annual CO2 emissions attributable to stationary combustion units producing electricity may be calculated using the following calculation methods:
(1) for units that use natural gas as a fuel or a fuel specified in Table 1-2:
(a) when the high heat value of the gas is greater than or equal to 36.3 MJ/m3 and less than or equal to 40.98 MJ/m3 at standard conditions, in accordance with QC.1.3.3 or, for an emitter to whom section 6.6 of this Regulation does not apply, in accordance with QC.1.3.2;
(b) when the high heat value of the gas is less than 36.3 MJ/m3 or greater than 40.98 MJ/ m3 at standard conditions, in accordance with QC.1.3.3;
(2) for units that use coal or petroleum coke as a fuel, in accordance with QC.1.3.3(1);
(3) for units that use middle distillates as a fuel other than those specified in Table 1-2, such as diesel, fuel oil or kerosene, gasoline, residual oil or liquefied petroleum such as ethane, propane, isobutene or n-butane, in accordance with QC.1.3.3 or, for an emitter to whom section 6.6 of this Regulation does not apply, in accordance with QC.1.3.2;
(4) for units that use refinery fuel gas, flexigas or associated gas as a fuel, in accordance with QC.2;
(5) for units that use biogas or biomass as a fuel, the calculations must be completed in accordance with QC.1.3.3 or, for an emitter to whom section 6.6 of this Regulation does not apply, in accordance with QC.1.3.1 or QC.1.3.2;
(6) for units that use municipal solid waste as a fuel, in accordance with QC.1.3.3 or, for an emitter to whom section 6.6 of this Regulation does not apply, in accordance with QC.1.3.1 or QC.1.3.2;
(7) for units that use biogas or biomass as a fuel but that, during start-up, shut-down, or malfunction operating periods only use fossil fuels or fuel gas, the CO2 emissions attributable to those fuels must be calculated:
(a) for fossil fuels, in accordance with QC.1.3.1, QC.1.3.2 or QC.1.3.3;
(b) for fuel gas, in accordance with QC.2.
(8) for units that use only a mixture of fossil fuels, in accordance with QC.16.3.2(1) to (4), for each type of fuel;
(9) for units that use a mixture of fossil fuels and biogas or biomass:
(a) when the emissions are calculated using data from a continuous emission monitoring and recording system, the portion of CO2 emissions attributable to the biomass or biogas must be calculated in accordance with subparagraph 2 of the fifth paragraph of QC.1.3.4;
(b) when the emissions are not calculated using data from a continuous emission monitoring and recording system, in accordance with QC.16.3.2(1) to (7), for each type of fuel;
(10) for an emitter who determines the high heat value of fuels using measurements made in accordance with QC.1.5.4 or data indicated by the fuel supplier at the intervals specified in QC.1.5.1, in accordance with QC.1.3.2, QC.1.3.3 or QC.1.3.4.
QC.16.3.3. Calculation of CO2 emissions from acid gas scrubbing for fluidized bed boilers
The annual CO2 emissions from acid gas scrubbing for fluidized bed boilers must be calculated in accordance with QC.1.3.6.
QC.16.3.4. Calculation of fugitive CO2 emissions from geothermal facilities
The annual fugitive CO2 emissions from geothermal facilities must be calculated using equation 16-1:
Equation 16-1
CO2 = 7.14 × QE × 0.001
Where:
CO2 = Annual fugitive emissions of CO2 from geothermal facilities, in metric tons per year;
7.14 = Default fugitive CO2 emission factor for geothermal facilities, in kilograms per gigajoule;
QE = Quantity of energy transferred from geothermal steam or fluid, in gigajoulesper year;
0.001 = Conversion factor, kilograms to metric tons.
QC.16.4. Calculation methods for CH4 and N2O emissions
The annual CH4 and N2O emissions attributable to stationary combustion units producing electricity must be calculated in accordance with QC.1.4.
For a facility or establishment with natural gas, diesel or heavy oil-powered units that are not individually equipped with a flowmeter or a dedicated tank and for which data cannot be obtained using a continuous emission monitoring and recording system, an emitter may calculate CO2, CH4 and N2O emissions using data from a measurement device common to all the units.
To calculate the emissions attributable to each stationary combustion unit, the estimate must be based on total emissions, the hours of operation and the combustion efficiency of each unit. For diesel-powered units, the estimate may be based on the total quantity of energy produced, the energy produced by each unit, and the total quantity of diesel fuel consumed.
QC.16.5. Calculation methods for fugitive HFC emissions
The annual fugitive HFC emissions attributable to cooling units used in electricity production must be calculated in accordance with one of the calculation methods in QC.16.5.1 and QC.16.5.2.
QC.16.5.1. Calculation of fugitive HFC emissions based on change in inventory
The annual fugitive HFC emissions attributable to cooling units used in electricity production may be calculated based on the change in inventory using equation 16-2:
Equation 16-2
QC.16.5.2. Calculation of fugitives HFC emissions based on service logs
The annual fugitive HFC emissions attributable to cooling units used in electricity production may be calculated on the basis of entries in equipment service logs using equation 16-3:
Equation 16-3
Where:
HFC = Annual fugitive HFC emissions attributable to cooling units used in electricity production, in metric tons;
n = Number of new cooling units brought into operation during the year;
i = New cooling unit brought into operation;
Q NEWi = Quantity of HFC used to fill the new cooling unit brought into operation i, in kilograms;
NC NEWi = Nameplate capacity of the new cooling unit brought into
operation i, in kilograms;
m = Number of maintenance operations, either to recharge or recover, completed during the year;
j = Cooling unit maintained;
Q RECHj = Quantity of HFC used to recharge the unit during maintenance of cooling unit i, in kilograms;
Q RECOj = Quantity of HFC recovered during maintenance of cooling unit i, in kilograms;
p = Number of cooling units retired during the year;
k = Cooling unit retired;
NC RETk = Nameplate capacity of cooling unit k, in kilograms;
Q RETk = Quantity of HFC recovered from unit k, in kilograms;
0.001 = Conversion factor, kilograms to metric tons.
QC.16.6. Sampling, analysis and measurement requirements
QC.16.6.1. Solid, liquid and gaseous fuels
For all fuels except refinery fuel gas, flexigas and associated gas, sampling, consumption measurements, carbon content measurements, and measurements to calculate high heat value and emission factors must be completed in accordance with QC.1.5 when the calculation method in QC.16.3.2 is used.
QC.16.6.2. Refinery fuel gas, flexigas and associated gas
For refinery fuel gas, flexigas and associated gas, sampling, consumption measurements, carbon content measurements, and measurements to calculate high heat value and emission factors must be completed in accordance with QC.2.4 when the calculation method in QC.16.3.2 is used.
QC.16.6.3. Acid gas scrubbing
The emitter who operates a fluid bed boiler equipped with a gas scrubber must measure the quantity of sorbent used annually.
QC.16.6.4. Geothermal facility
The emitter must measure the quantity of energy transferred annually from geothermal steam or fluid.
QC.16.7. Methods for estimating missing data
When, as part of an emitter's sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.
When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:
(1) an emitter who uses one of the calculation methods provided for in this Protocol must,
(a) when the missing data concern sampled data,
(i) determine the sampling or measurement rate using the following equation:
Equation 16-4
R = QS Act/QS Required
Where:
R = Actual sampling or measurement rate, expressed as a percentage;
QS Act = Quantity of actual samples or measurements obtained by the emitter;
QS Required = Quantity of samples or measurements required under QC.16.6;
(ii) for data that require sampling or analysis,
- if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;
- if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;
- if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;
(b) when the missing data concern the quantity of energy transferred or a quantity of HFC, the replacement data must be estimated on the basis of all the data relating to the processes used;
(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.
QC.17. CONSUMPTION AND SALE OF ELECTRICITY PRODUCED OUTSIDE QUÉBEC, AND EXPORTATION OF ELECTRICITY
QC.17.1. Covered sources
The covered sources are the activities of persons and municipalities that operate an enterprise, a facility or en establishment that purchases electricity produced outside Québec for their own consumption or for sale in Québec, or that exports electricity.
For the purposes of this Part, a facility is considered identifiable when it meets the following conditions:
(1) the importation of the reported electricity is subject to a written contract between the facility and the first importer;
(2) the imported and reported electricity, as the case may be,
(a) comes from an electricity production facility built after 1 January 2008;
(b) is the result of an increase in production of the facility that occurred after 1 January 2008;
(c) was imported from a facility within the framework of a contract entered into before 1 January 2008 that is still in force or has been renewed, or was imported from that facility after the end of the contract.
QC.17.2. Specific information to be reported concerning greenhouse gas emissions
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) for the acquisition of electricity produced outside Québec for the consumption of the enterprise, facility or establishment or for sale within Québec:
(a) the total quantity of electricity produced outside Québec that was acquired during the year for consumption or sale in Québec, in megawatt-hours;
(b) the annual total greenhouse gas emissions attributable to the production of electricity referred to in subparagraph a, calculated in accordance with QC.17.3.1, in metric tons CO2 equivalent;
(c) for each identifiable facility covered by a greenhouse gas emissions report made to Environment Canada under section 71 of the Canadian Environmental Protection Act (1999) (1999, c.33), to the U.S. Environmental Protection Agency (USEPA) under Part 75 of Title 40 of the Code of Federal Regulations, or to the organization The Climate Registry:
(i) the name and address of the facility, the identification number assigned to it by the National Pollutant Release Inventory of Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the organization The Climate Registry;
(ii) the total quantity of electricity acquired, in megawatt-hours;
(iii) the transmission losses, in megawatt-hours;
(iv) the facility's net annual electricity production, in megawatt-hours;
(v) the annual greenhouse gas emissions attributable to the production of the electricity acquired from the facility, in metric tons CO2 equivalent;
(vi) the annual greenhouse gas emissions of the facility, in metric tons CO2 equivalent;
(d) for each identifiable facility not covered by a greenhouse gas emissions report made to one of the organizations referred to in subparagraph c:
(i) the information specified in subparagraphs i to v of subparagraph c, the identification number being required only if assigned;
(ii) each fuel type used for electricity production and its heat value, that is:
- in gigajoules per metric ton, when the quantity of fuel is expressed as a mass;
- in gigajoules per kilolitre, when the quantity of fuel is expressed as a volume of liquid;
- in gigajoules per cubic metre, when the quantity of fuel is expressed as a volume of gas;
(e) for each identifiable facility for which the information needed to calculate greenhouse gas emissions using equation 17-1 or 17-2 is not available, and for each unspecified facility:
(i) the province or state from which the electricity is acquired;
(ii) the total quantity of electricity acquired, in megawatt-hours, for each province or state,;
(iii) the annual greenhouse gas emissions attributable to the electricity acquired, in metric tons CO2 equivalent, by province or state;
(2) for the exportation of electricity:
(a) the total quantity of electricity exported annually by the enterprise, facility or establishment, in megawatt-hours;
(b) the annual total greenhouse gas emissions caused or avoided by the exportation of the electricity, calculated in accordance with QC.17.3.2, in metric tons CO2 equivalent;
(c) for each identifiable facility covered by a greenhouse gas emissions report in accordance with this Regulation, for each destination province or state:
(i) the annual greenhouse gas emissions caused or avoided by the exportation of the electricity produced by the facility, in metric tons CO2 equivalent;
(ii) the total quantity of electricity produced by the facility and exported annually, in megawatt-hours;
(d) for each identifiable facility not covered by a greenhouse gas emissions report in accordance with this Regulation, and for each unidentifiable facility, by destination province or state:
(i) the annual CO2 emissions caused or avoided by the exportation of the electricity produced by the specified or unspecified facility, in metric tons;
(ii) the annual greenhouse gas emissions caused or avoided by the exportation of the electricity produced by the facility, in metric tons CO2 equivalent;
QC.17.3. Calculation methods for greenhouse gas emissions
The annual greenhouse gas emissions attributable to the production of electricity acquired outside Québec and acquired by an enterprise, a facility or an establishment for its own consumption or for sale within Québec must be calculated in accordance with one of the calculation methods in QC.17.3.1. The annual greenhouse gas emissions caused or avoided by the exportation of the electricity must be calculated in accordance with one of the calculation methods in QC.17.3.2.
QC.17.3.1. Calculation of greenhouse gas emissions attributable to the production of electricity acquired outside Québec and sold or consumed within Québec
The annual greenhouse gas emissions attributable to electricity produced outside Québec and sold or consumed within Québec must be calculated by adding the greenhouse gas emissions attributable to electricity acquired outside Québec and produced by identifiable and unidentifiable facilities which emissions are calculated in accordance with the following methods:
(1) for an identifiable facility covered by a greenhouse gas emissions report made to Environment Canada under section 71 of the Canadian Environmental Protection Act (1999) (S.C. 1999, c. 33), the U.S. Environmental Protection Agency (USEPA) under Part 75 of Title 40 of the Code of Federal Regulations, or the organization The Climate Registry, using equation 17-1:
Equation 17-1
MWhimp GHG = GHGi × _____ MWhn
Where:
GHG = Annual greenhouse gas emissions attributable to the production of electricity acquired outside Québec and produced by the identifiable facility, in metric tons CO2 equivalent;
GHGi = Annual greenhouse gas emissions attributable to the identifiable facility, in metric tons CO2 equivalent;
MWhimp = Total quantity of electricity acquired from the identifiable facility and consumed or sold annually in Québec, including an estimate of transmission losses, from the facility's busbar, in megawatt-hours;
MWhn = Net annual production of electricity at the identifiable facility, in megawatt-hours;
(2) for an identifiable facility not covered by a greenhouse gas emissions report made to one of the organizations referred to in paragraph 1, using equation 17-2:
Equation 17-2
Where:
GHG = Annual greenhouse gas emissions attributable to the production of electricity acquired outside Québec and produced by the identifiable facility, in metric tons CO2 equivalent;
n = Number of fuels used annually by the facility;
j = Type of fuel;
Qj = Quantity of fuel j, expressed
- in bone dry metric tons, when the quantity is expressed as a mass;
- in kilolitres, when the quantity is expressed as a volume of liquid;
- in thousands of cubic metres, when the quantity is expressed as a volume of gas;
HHVj = High heat value of fuel j consumed for electricity production, as specified in Table 1-1 or 1-2 in QC.1.7, expressed
- in gigajoules per bone dry metric ton, when the quantity is expressed as a mass;
- in gigajoules per kilolitre, when the quantity is expressed as a volume of liquid;
- in gigajoules per thousand cubic metres, when the quantity is expressed as a volume of gas;
EFj = Greenhouse gas emission factor for fuel j, calculated using equation 17-2.1, in metric tons CO2 equivalent per gigajoule;
MWhimp = Quantity of electricity acquired from the identifiable facility and consumed or sold annually in Québec, including an estimate of transmission losses, from the facility's busbar, in megawatt-hours;
MWhn = Net annual production of electricity at the identifiable facility, in megawatt-hours;
Equation 17-2.1
EFj = [(EFCO2 × 1000) + (EFCH4 × 21) + (EFN2O × 310)] × 0.000001
Where:
EFj = Greenhouse gas emission factor for fuel j, in metric tons CO2 equivalent per gigajoule;
EFCO2 = CO2 emission factor for fuel j as specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6 in QC.1.7, in kilograms of CO2 per gigajoule;
1000 = Conversion factor, kilograms to grams;
EFCH4 = CH4 emission factor for fuel j as specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6 in QC.1.7, in grams of CH4 per gigajoule;
21 = Global warming potential of CH4;
EFN2O = N2O emission factor for fuel j as specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6 in QC.1.7, in grams of N2O per gigajoule;
310 = Global warming potential of N2O;
0.000001 = Conversion factor, grams to metric tons;
(3) for an identifiable facility for which the information needed to calculate greenhouse gas emissions using equation 17-1 or 17-2 is not available, and for an unidentifiable facility, using equation 17-3:
Equation 17-3
GHG = MWhimp × EFD
Where:
GHG = Annual greenhouse gas emissions attributable to the production of electricity acquired outside Québec and produced by the identifiable or unidentifiable facility, in metric tons CO2 equivalent;
MWhimp = Quantity of electricity acquired from the identifiable or unidentifiable facility and consumed or sold annually in Québec, in megawatt-hours;
EFD = Greenhouse gas emission factor for the province or North American market from which the electricity comes, in metric tons of CO2 per megawatt-hour, which is either
- indicated in Table 17-1 in QC.17.4;
- when the electricity comes from an identifiable nuclear, hydroelectric, sea current, wind, solar or tidal power facility, a factor of 0;
- when the electricity comes from a non-identifiable facility, a factor of 0.999.
QC.17.3.2. Calculation of greenhouse gas emissions caused or avoided by the exportation of the electricity
The annual greenhouse gas emissions caused or avoided by the exportation of the electricity must be calculated by adding the greenhouse gas emissions attributable to the exportation of electricity produced by identifiable facilities to the greenhouse gas emissions attributable to the exportation of electricity produced by unidentifiable facilities, using one of the following methods:
(1) for an identifiable facility covered by a greenhouse gas emissions report in accordance with QC.16, using equation 17-4:
Equation 17-4
MWhexp GHG = GHGi × _____ − (MWhexp × EFD) MWhn
Where:
GHG = Annual greenhouse gas emissions caused or avoided by the exportation of the electricity produced by the identifiable facility, in metric tons CO2 equivalent;
GHGt = Total annual greenhouse gas emissions attributable to the identifiable facility, in metric tons CO2 equivalent;
MWhexp = Total quantity of electricity produced by the identifiable facility and exported annually, including an estimate of transmission losses, from the facility's busbar, in megawatt-hours;
MWhn = Net annual production of electricity at the identifiable facility, in megawatt-hours;
EFD = Greenhouse gas emission factor for the province or North American market where the electricity is delivered, as specified in Table 17-1 in QC.17.4, in metric tons CO2 equivalent per megawatt-hour;
(2) for an identifiable facility not covered by a greenhouse gas emissions report in accordance with QC.16 and for an unidentifiable facility, using equation 17-5:
Equation 17-5
GHG = MWhexp × (EFQC - EFD)
Where:
GHG = Annual greenhouse gas emissions caused or avoided by the exportation of the electricity produced by the identifiable or unidentifiable facility, in metric tons CO2 equivalent;
MWhexp = Quantity of electricity produced by the identifiable or unidentifiable facility and exported annually, in megawatt-hours;
EFQC = Greenhouse gas emission factor for Québec, as specified in Table 17-1 in QC.17.4, in metric tons CO2 equivalent per megawatt-hour;
EFD = Greenhouse gas emission factor for the province or North American market where the electricity is delivered, in metric tons CO2 equivalent per megawatt-hour, which is either
- indicated in Table 17-1 in QC.17.4;
- when the electricity comes from an identifiable nuclear, hydroelectric, sea current, wind, solar or tidal power facility, a factor of 0;
- when the electricity comes from a non-identifiable facility, a factor of 0.
QC.17.4. Table
Table 17-1. Default greenhouse gas emission factors for Canadian provinces and certain North American markets, in metric tons CO2 equivalent per megawatt-hour
(QC.17.3.1(3), QC.17.3.2(1) and (2))
__________________________________________________________________________________
| | |
| Canadian provinces and North American | Default emission factor |
| markets | (metric tons CO2 equivalent per |
| | megawatt-hour) |
|_____________________________________________|____________________________________|
| | |
| Newfoundland and Labrador | 0.020 |
|_____________________________________________|____________________________________|
| | |
| Nova Scotia | 0.717 |
|_____________________________________________|____________________________________|
| | |
| New Brunswick | 0.444 |
|_____________________________________________|____________________________________|
| | |
| Québec | 0.002 |
|_____________________________________________|____________________________________|
| | |
| Ontario | 0.098 |
|_____________________________________________|____________________________________|
| | |
| Manitoba | 0.003 |
|_____________________________________________|____________________________________|
| | |
| Vermont | 0.001 |
|_____________________________________________|____________________________________|
| | |
| New England Independent System Operator | 0.333 |
| (NE-ISO), including all or part of the | |
| following states: | |
| | |
| - Connecticut | |
| - Massachusetts | |
| - Maine | |
| - Rhode Island | |
| - Vermont | |
| - New Hampshire | |
|_____________________________________________|____________________________________|
| | |
| New York Independent System Operator | 0.304 |
| (NY-ISO) | |
|_____________________________________________|____________________________________|
| | |
| Pennsylvania Jersey Maryland | 0.660 |
| Interconnection Regional Transmission | |
| Organization (PJM-RTO), including all or | |
| part of the following states: | |
| - North Carolina | |
| - Delaware | |
| - Indiana | |
| - Illinois | |
| - Kentucky | |
| - Maryland | |
| - Michigan | |
| - New Jersey | |
| - Ohio | |
| - Pennsylvania | |
| - Tenessee | |
| - Virginia | |
| - West Virginia | |
| - District of Columbia | |
|_____________________________________________|____________________________________|
| | |
| Midwest Independent Transmission System | 0.727 |
| Operator (MISO-RTO), including all or part | |
| of the following states: | |
| - North Dakota | |
| - South Dakota | |
| - Minnesota | |
| - Iowa | |
| - Missouri | |
| - Wisconsin | |
| - Illinois | |
| - Manitoba | |
| - Michigan | |
| - Nebraska | |
| - Indiana | |
| - Ohio | |
| - Montana | |
| - Kentucky | |
|_____________________________________________|____________________________________| 1 The ASTM standards mentioned in this Schedule are published by the American Society of Testing and Materials (ASTM International).
QC.18. NICKEL AND COPPER PRODUCTION
QC.18.1. Covered sources
The covered sources are all the processes used for nickel and copper production in metal smelting and refining facilities.
More specifically, the processes covered are those used to remove impurities from nickel or copper ore concentrate by adding carbonate flux reagents and to extract metals from their oxides using reducing agents, and processes involving the use of materials for slag cleaning, the consumption of electrodes in electric arc furnaces, and the use of carbon-containing raw materials, such as recycled secondary materials.
QC.18.2. Greenhouse gas reporting requirements
In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:
(1) (subparagraph revoked);
(2) the annual CO2, CH4 and N2O emissions attributable to combustion, calculated and reported in accordance with QC.1, in metric tons;
(3) the annual CO2 emissions attributable to the use of carbonate flux reagents, in metric tons;
(4) the annual CO2 emissions attributable to the use of reducing agents and other materials for slag cleaning, in metric tons;
(5) the annual CO2 emissions attributable to the carbon contained in the nickel or copper ore processed, in metric tons;
(6) the annual CO2 emissions attributable to the consumption of carbon electrodes in electric arc furnaces, in metric tons;
(7) the annual CO2 emissions attributable to the carbon contained in carbon-containing raw materials such as recycled secondary materials, in metric tons;
(8) the annual consumption of each carbonate flux reagent, in metric tons;
(9) the average annual carbon content of each carbonate flux reagent, in metric tons of carbon per metric ton of carbonate flux reagent;
(10) the annual consumption of each reducing agent and each material used for slag cleaning, in metric tons;
(11) the average annual carbon content of each reducing agent and each material used for slag cleaning, in metric tons of carbon per metric ton of reducing agent;
(12) the annual consumption of carbon electrodes, in metric tons;
(13) the average annual carbon content of carbon electrodes, in metric tons of carbon per metric ton of carbon electrode;
(14) the annual quantity of nickel or copper ore processed, in metric tons;
(15) the average annual carbon content of the nickel or copper ore processed, in metric tons of carbon per metric ton of ore;
(16) the annual consumption of each other raw material that contributes 0.5% or more of the total carbon in the process, in metric tons;
(17) the average annual carbon content of the other raw materials that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of feedstock;
(18) the number of times that the methods for estimating missing data in QC.18.5 were used;
(19) (subparagraph revoked);
(20) the quantity of nickel produced, in metric tons;
(21) the quantity of copper produced, in metric tons.
Subparagraphs 9, 11, 13, 15 and 17 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system. When the emissions referred to in subparagraphs 3 to 7 of the first paragraph are measured by the same continuous emission monitoring and recording system, the emissions may be declared as a whole.
For the purposes of subparagraph 8 of the first paragraph of section 6.2:
(1) the emissions referred to in subparagraphs 3 to 7 of the first paragraph are emissions attributable to fixed processes;
(2) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to combustion.
QC.18.3. Calculation methods for CO2 emissions
The annual CO2 emissions attributable to nickel and copper production must be calculated using one of the calculation methods in QC.18.3.1 and QC.18.3.2.
QC.18.3.1. Use of a continuous emission monitoring and recording system
The annual CO2 emissions attributable to nickel and copper production may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.
QC.18.3.2. Calculation by mass balance
The annual CO2 emissions attributable to nickel and copper production must be calculated using the methods in paragraphs 1 to 6, depending on the process used, expressed:
(1) for the processes used in nickel and copper production, using equation 18-1:
Equation 18-1
CO2 = CO2,CR + CO2,RA + CO2,ORE + CO2,CE + CO2,RM
Where:
CO2 = Annual CO2 emissions attributable to nickel and copper production, in metric tons;
CO2,CR = Annual CO2 emissions attributable to the use of carbonate flux reagents, calculated in accordance with equation 18-2, in metric tons;
CO2,RA = Annual CO2 emissions attributable to the use of reducing agents and materials used for slag cleaning, calculated in accordance with equation 18-3, in metric tons;
CO2,ORE = Annual CO2 emissions attributable to carbon contained in the nickel or copper ore processed, calculated in accordance with equation 18-4, in metric tons;
CO2,CE = Annual CO2 emissions attributable to the consumption of carbon electrodes in electric arc furnaces, calculated in accordance with equation 18-5, in metric tons;
CO2,RM = Annual CO2 emissions attributable to carbon contained in other raw materials that contribute 0.5% or more of the total carbon in the process, calculated in accordance with equation 18-6, in metric tons;
(2) for the use of carbonate flux reagents, using equation 18-2:
Equation 18-2
Where:
CO2, CR = Annual CO2 emissions attributable to the use of carbonate flux reagents, in metric tons;
LS = Annual consumption of limestone, in metric tons;
CLS = Average annual calcium carbonate content of the limestone, in metric tons of calcium carbonate per metric ton of limestone;
44/100 = Ratio of molecular weights, CO2 to calcium carbonate;
D = Annual consumption of dolomite, in metric tons;
CD = Average annual calcium carbonate and magnesium carbonate content, in metric tons of carbonates per metric ton of dolomite;
88/184 = Ratio of molecular weights, CO2 to calcium carbonate and magnesium carbonate;
(3) for the use of reducing agents and materials used for slag cleaning, using equation 18-3:
Equation 18-3
Where:
CO2, RA = Annual CO2 emissions attributable to the use of reducing agents and materials used for slag cleaning, in metric tons;
n = Number of reducing agents and materials used for slag cleaning;
i = Reducing agent and materials used for slag cleaning;
RA = Annual consumption of each reducing agent i and material used for slag cleaning, in metric tons;
CRA = Average annual carbon content of each reducing agent i, in metric tons of carbon per metric ton of reducing agent i;
3.664 = Ratio of molecular weights, CO2 to carbon;
(4) for the nickel or copper ore processed, using equation 18-4:
Equation 18-4
CO2,ORE = ORE × CORE × 3.664
Where:
CO2,ORE = Annual CO2 emissions attributable to carbon contained in the nickel or copper ore processed, in metric tons;
ORE = Annual consumption of nickel or copper ore, in metric tons;
CORE = Average annual carbon content of nickel or copper ore, in metric tons of carbon per metric ton of ore;
3.664 = Ratio of molecular weights, CO2 to carbon;
(5) for the consumption of carbon electrodes in electric arc furnaces, using equation 18-5:
Equation 18-5
CO2,CE = CE × CCE × 3.664
Where:
CO2,CE = Annual CO2 emissions attributable to consumption of carbon electrodes in electric arc furnaces, in metric tons;
CE = Annual consumption of carbon electrodes in electric arc furnaces, in metric tons;
CCE = Average annual carbon content of the carbon electrodes, in metric tons of carbon per metric ton of carbon electrodes;
3.664 = Ratio of molecular weights, CO2 to carbon;
(6) for the consumption of other carbon-containing raw materials, using equation 18-6:
Equation 18-6
Where:
CO2,RM = Annual CO2 emissions attributable to raw materials that contribute 0.5% or more of the total carbon in the process, in metric tons;
n = Number of raw materials that contribute 0.5% or more of the total carbon in the process;
i = Raw material;
RMi = Annual consumption of raw material i that contributes 0.5% or more of the total carbon in the process, in metric tons;