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Cargill High River Fluidized Bed Boiler Offset Project

March 2018

Offset Project Report Form


Project Developer:

Cargill Ltd.

Prepared by:

Blue Source Canada

Reporting Period:

January 1, 2017 – December 31, 2017

Date:

March 7, 2018


March 2018

Greenhouse Gas Assertion

Project Developer:

Cargill Meat Solutions, a division of Cargill Ltd

Sean Murray

472 Ave & Hwy 2A North

High River, AB

(403) 652-8489

www.cargillmeatcsolutions.com

[email protected]

Project Documents:

Offset Project Report Form: Cargill High River Fluidized Bed Boiler Offset Project

Offset Project Plan: Cargill High River Fluidized Bed Boiler

Project Plan Date: December 2014, updated April 19, 2016

Quantification Protocol: Quantification Protocol for Energy generation from the Combustion of

Biomass, Version 2.0, April 2014

Project Identification:

Project Title: Cargill High River Fluidized Bed Boiler Offset Project (9327-1871)

Reporting Period: January 1, 2017 – December 31, 2017

Project Description:

The project reduces GHG emissions by displacing off-site fossil fuel generated electricity

emissions and natural gas combustion emissions. The Project consists of the fluidized bed boiler

(FBB) which produces energy fuelled by biomass sourced from bovine by-products and other

compostable plant wastes including meat, pen manure, paunch, dissolved air flotation (DAF) grit,

sludge, tri-canter solids, and specified risk materials (SRM). The FBB generates steam, which

produces electricity on site and displaces natural gas as fuel for process steam requirements.

Project Location: The Project is located at: 12-19-19-28 W4M

Emission Reduction Removal, Sequestration or Capture Assertion:

Vintage Gas Type Quantity (tCO2e)

January 1, 2017 – December

31, 2017

CO2

15,825.00

CH4 17,425.00

http://www.cargillmeatcsolutions.com/


March 2018

Vintage Gas Type Quantity (tCO2e)

N2O

-423.00

CO2e -1,170.00

Total Quantity CO2e 31,657.00


March 2018

Page | 5

Table of Contents

Greenhouse Gas Assertion ..................................................................................................... 2 1.0 Contact Information .............................................................................................. 6 2.0 Project Scope and Site Description .......................................................................... 6

2.1 Project Implementation .......................................................................................... 7 2.2 Protocol ............................................................................................................. 11 2.3 Risks ................................................................................................................. 12

3.0 Project Quantification .......................................................................................... 12 3.1 Summary Table Non-Levied Emissions ................................................................... 12 3.1 Summary Table Levied Emissions and Biogenic CO2 ................................................. 13 3.2 Calculations ........................................................................................................ 13

SS B1 Emissions Collection, Transfer, and Transport ................................................................................ 14 SS B15 Methane Emissions due to Landfill Avoidance .............................................................. 15 SS B6 Emissions Electricity....................................................................................................... 15 SS B18 Displaced On-Site Heat Generation ............................................................................ 16 SS B4 Emissions Fuel Extraction/Processing ....................................................................................... 17 SS P4 Emissions Fuel Extraction/Processing ........................................................................................ 17 SS P12 Emissions Facility Operation .............................................................................................. 17 SS P15 Emissions Combustion of Biomass, Biogas and Fossil Fuels .................................................................. 17 4.0 References ......................................................................................................... 18 Appendix A: Supporting Information ..................................................................................... 19

List of Tables

Table 1: Project Contact Information ...................................................................................... 6 Table 2: Project Information .................................................................................................. 6 Figure 1: Simplified Project Process Flow Diagram .................................................................... 9 Figure 2: Simplified Single Line Diagram ............................................................................... 10 Table 3: Emission factors used for the 2017 Reporting period, (AESRD, March 2015). ................ 14 Table 4: Landfill Design Factors ........................................................................................... 15


March 2018

Page | 6

1.0 Contact Information

Table 1: Project Contact Information

Project Developer Contact Information

Cargill Ltd.

Sean Murray

472 Ave & Hwy 2A North

High River, AB

(403) 652-8489

www.cargillmeatcsolutions.com

[email protected]

Authorized Project Contact

Blue Source Canada ULC

Kelly Parker

1605, 840-7th Avenue SW

Calgary, AB, T2P 3G2

(403) 262-3026 (ext 260)

www.bluesource.com

[email protected]

2.0 Project Scope and Site Description

Table 2: Project Information

Project title Cargill High River Fluidized Bed Boiler Offset Project (9327-1871)

Project purpose and

objectives

The Project is the implementation of a fluidized bed boiler (FBB) fueled

by biomass sourced from bovine by-products and other compostable

plant wastes including meat, pen manure, paunch, dissolved air flotation

(DAF) grit, sludge, tri-canter solids, and specified risk materials (SRM).

The use of bovine by-products as a solid fuel source to the FBB

displaces natural gas demands and electricity sourced from the

commercial grid and, therefore, directly avoids the release of non-

biogenic CO2, CH4, and N2O into the atmosphere as a result of

combustion processes. Furthermore, in the absence of the Project, the

SRMs would have continued to be sent to a landfill for disposal where

varying degrees of anaerobic decomposition may take place and result

in the release of non-biogenic CH4.

Activity start date November 1, 2012

Offset start date May 9, 2013

http://www.cargillmeatcsolutions.com/


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Offset crediting

period

May 9, 2013 – May 8, 2021

Reporting period

covered by the

project

January 1, 2017 to December 31, 2017

Actual emission

reductions

31,657.00 Tonnes CO2e

Unique site identifier Latitude: 50°37'27.9"N

Longitude: 113°52'41.1"W

LSD: 12-19-19-28 W4M

The Project is located at the Cargill High River Beef Processing Plant in

the northwest quarter of Section 19 (Township Road 19, and Range

Road 28) and 5 km north of the town of High River, Alberta. This is not

an aggregated project.

Project boundary The project boundary includes the entire Cargill Meat Plant, as biomass

is sourced from various areas within the operation.

Specifically, the FBB System includes: the biomass metering bin, natural

gas lines, fluidized bed combustor, storage containers, boiler, steam

turbines, ash storage, fans, stack, and the power lines for electricity

production.

Ownership The Project Proponent is Cargill Ltd., “the Proponent”. The Proponent is

the sole owner of the Cargill High River Beef Processing Plant. All

greenhouse gas reduction benefits resulting from displacing natural gas

and fossil fuel derived electricity from the commercial grid through on-

site heat and power generation are owned by the Proponent.

2.1 Project Implementation

The following changes to the offset project were made in relation to the revised offset

project plan (OPP) dated April 19, 2016 and remain valid to the current reporting period.

i) The project experienced minor communication errors with the low-pressure

steam meter (tag FT-5000) for 12% of total time, between the meter and SCADA

system. These errors were removed from the summation, and metered volume

was assumed to be zero for that day. This is a more conservative approach than

the method listed in the OPP.

ii) Two additional source emissions were added to the quantification methodology

captured under the source P12 – Facility Operations. These source emissions are

the combustion emissions associated with the weekly testing of the emergency

diesel generator and the electricity consumption emissions of two screw pumps

located in the basement of the main facility used to pump the paunch to the FBB

loading area. The diesel generator model is DS500, and while no specifications

could be found on the engine, a genset package for SDS500 by engine


March 2018

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manufacturer MTU Onsite Energy was used to approximate the fuel consumption

at 100% power rating of 91 l/hr. The two screw pumps have a power rating of 50

hp and are assumed to run 100% of the year, data provided by Thomas D’Amato,

Process Engineer. This approach is conservative.

iii) The fuel consumption to transport the biomass from site to landfill in the baseline

is not directly measured or reconciled based upon storage volume. As source

emission B1 was an upstream emission that was not directly controlled by the

Proponent, measured data is unavailable. As such, the baseline source emission

B1 is calculated by reconciling the trailer capacity, the measured mass of

biomass, trip distance and fuel efficiency.

iv) A biogas pipeline was tied into the FBB overbed burner to increase the capacity of

the plant to combust the biogas generation from the on-site wastewater

treatment plant. The FBB began to receive biogas on May 14, 2016 mainly on

weekends, experiencing a slow ramp up. Combustion emissions and natural gas

offset from the biogas usage are quantified in source P15 of the FBB offset

project. The avoided venting emissions from the biogas were quantified in the

methane generation waste water offset project, prior to crediting period

completion.

v) Dewatered activated sludge is no longer used in the FBB as the energy content is

too low. This change has no impact on the project.

In 2017, energy associated with the boiler feed water input was included in the

quantification of sources B18 and P15. There is also a new data collection file used for

the Project data sources, titled FBB P&L Tracking Spreadsheet. This file is updated

weekly by personnel at the FBB, from the raw data files. No other changes were made to

the data collection process, record keeping, or emission factors during this reporting

period.

While the current reporting period is unimpacted by recent regulatory changes, the

Project will be required to be updated to the new Protocol in 2019 following the

completion of the carbon levy alignment process with the offset system in Alberta. At

that time, the Project will have to account for levied and non-levied emission reductions

from fuel types impacted by the carbon levy, and levied emissions will be excluded from

the greenhouse gas reduction assertion.

Please see the following pages for the simplified process flow diagram and single line

diagram.


March 2018

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Figure 1: Simplified Project Process Flow Diagram

>>

FBB Offset Project Boundary

MD5B Grid electricity consumed: 1,799,179.00 KwH

Natural Gas: >> 119,656.63 GJ

Biogas: >> 51,088.77 GJ >> Reduced Grid Electricity Import: 623,745.00 KwH

Biomass: >> 527,408.27 GJ >> HP Steam 532,312.70 GJ >> LP Steam: 462,253.76 GJ

BFW: >> 88,638.33 GJ

Efficiency(HHV): 68%

>>

FBB Blowdown: 2%

FBB Turbine Main Plant

Alberta Grid


March 2018

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Figure 2: Simplified Single Line Diagram

FBB Generator

>>

<<

Dir

ecti

on

al O

verc

urr

ent

REL

AY

<>

<>

>

<

<<

GRID

MDP-5B1: FBB Building load & emergency generator

FBB Equipment

Meter: MDP-5B2

Meter: MDP-5B

MDP-5A: Main Plant

Meter: MDP-5


March 2018

Page | 11

2.2 Protocol

The Project was implemented under the Quantification Protocol for Energy Generation

from the Combustion of Biomass Waste, version 2.0, April 2014. Only one protocol was

used to develop this Project.

The Protocol was applicable to the Project because the use of bovine by-products as a

biomass fuel source to the FBB displacing natural gas demands and electricity sourced

from the commercial grid. Therefore, the Project directly avoided the release of non-

biogenic CO2, CH4, and N2O into the atmosphere as a result of combustion processes. In

the absence of the Project, the SRMs would have continued to be sent to a landfill for

disposal where varying degrees of anaerobic decomposition may take place and result in

the release of non-biogenic CH4.

Therefore, the Project met the Protocol requirements as follows:

• Eligible agricultural processing and residues (such as food processing wastes,

paunch, etc.) biomass feedstocks were used in the Project

• The project diverted feedstocks, such as SRM, from landfill

• The biomass was combusted to produce heat or electricity in a thermal energy

system

• Energy generated from the combustion of biomass waste offset fossil fuel-based

energy

• Emissions from the Project were less than those that would have occurred in the

absence of the Project, and

• The reductions achieved by the Project were based on actual measurement and

monitoring

As the activities of the Project were applicable under the Protocol and the displacement

of fossil fuels with biomass was not an industry standard, the results of this Project were

considered additional and would not have occurred under business as usual

circumstances.

Flexibility Mechanisms:

The quantification of GHG emission reductions for the Project uses the following

flexibility mechanisms as outlined in section 1.3 of the Protocol:

Flexibility (1): Diversion of biomass waste from baseline disposal in a landfill. The

project developer must be able to demonstrate that the waste stream was being

disposed of in a landfill for a period of three years prior to project initiation (see

section 5.1.2 for minimum disposal requirements).

Because the SRM was combusted in the FBB system rather than sent to landfill and

decomposed, this flexibility mechanism was used to capture the emission reduction from

avoided landfill methane generation. The Project met the minimum record requirements

for documentation of the baseline electricity use via invoicing, as well as the records


March 2018

Page | 12

requirements from the waste management facilities to claim landfill diversion methane

avoidance credits from landfill records and waste tracking records.

Flexibility (5): Projects can use an energy-based approach to estimate biomass fuel

consumed. If this approach is being used, the project developer must be able to

measure, monitor, and record the energy flow of all streams into and out of the

biomass combustion unit to generate an accurate energy balance for the project.

Energy-based combustion emission factors for biomass and fossil fuel combustion

are applied to quantify emissions for each stream and to quantify GHG emission

reductions.

The Project employed an energy-based approach to estimate the biomass fuel consumed

in the project condition as described above and illustrated in Figure 1. It utilized the

energy-based combustion emission factor as published in the IPCC 2006 Guidelines for

National Greenhouse Gas Inventories, Volume 2 Energy (International Panel on Climate

Change, 2006) to quantify emissions from biomass combustion. However, mass-based

values will be used for the quantification of Flexibility mechanism 1.

Flexibility (6): Site-specific emission factors calculated on the basis of fuel analysis

are preferred and must be used when available. If site-specific factors cannot be

obtained, emission factors from Environment Canada or equivalent must be used.

The Project employed a combination of default emission factors from Alberta

Environment and Sustainable Resource Development (AESRD, 2015), as well as site

specific emissions factors where available.

While this Protocol is flagged as part of the Carbon Levy Alignment process, this is an

ongoing Project and does not require authorization from the Director to quantify. Finally,

deviation requests were not initiated or required for this Project.

2.3 Risks

Risks associated with the offset Project have been included and discussed in Table 2 of

the offset project plan, and no additional risks have been identified during this reporting

period. No other offset project exists at the LSD 12-19-19-28 W4M at this time.

3.0 Project Quantification

3.1 Summary Table Non-Levied Emissions

Vintage Gas Type Baseline

Emissions

Project

Emissions

Total

Reduction,

Sequestration,

or Capture

2017 CO2 22,287.67 6,461.98 15,825.00

2017 CH4 21,330.73 3,905.08 17,425.00


March 2018

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2017 N2O 151.87 575.41 -423.00

2017 CO2e 399.20 1,569.54 -1,170.00

Total for

Reporting

Period

CO2e 44,169.46

tCO2e

12,512.01

tCO2e

31,657.00

tCO2e

Table “3.1 Summary Table Levied Emissions and Biogenic CO2” below is excluded for this

report, as levied emissions and biogenic CO2 are not applicable to this project for vintage

2017. Following the release of the new offset protocols to align with the carbon levy, this

project will be updated in 2019 to exclude levied emission reductions from the offset claim

and abide with the new protocol. However, only non-levied emissions have been reported,

as indicated above, for this reporting period.

3.1 Summary Table Levied Emissions and Biogenic CO2

Vintage1 Gas Type2 Baseline

Emissions

Project

Emissions

Total

Reduction,

Sequestration,

or Capture

2017 CO2 n/a n/a n/a

2017 CH4 n/a n/a n/a

2017 N2O n/a n/a n/a

2017 Other

(specify)

n/a n/a n/a

2017 Biogenic n/a n/a 0 tCO2

Total 2017 CO2e 0 tCO2e 0 tCO2e 0 tCO2e

Total for

Reporting

Period

CO2e XX tCO2e XX tCO2e XXtCO2e

3.2 Calculations

GHG emission reductions were calculated following the Quantification Protocol for Energy

Generation from the Combustion of Biomass wastes, version 2.0 April 2014. The

activities and procedures outlined in the Offset Project Plan provide a detailed

description of the project’s adherence to the requirements of the quantification protocol.

The formulas used to quantify greenhouse gas offset by the project are listed below.


March 2018

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EmissionReduction = EmissionsBaseline – EmissionsProject

EmissionsBaseline = sum of the emissions under the baseline condition

= Emissions from Collection, Transfer and Transport of Biomass (B1)

+ Emissions from Biomass Disposal (B15)

+ Emission from Displaced Off-site Electricity Generation (B6)

+ Emission from Displaced On-site Heat Generation (B18)

+ Emission from Fuel Extraction and Processing (B4)

Emissions Project = sum of the emissions under the project condition.

+ Emissions from combustion of biomass, biogas and fossil fuels (P15)

+ Emissions from facility operation (P12)

+ Emissions from fuel extraction and processing (P4)

Table 3 provides the emission factors used for the project. A site specific natural gas

combustion CO2 emission factor is used for sources P15 and B18.

Table 3: Emission factors used for the 2017 Reporting period, (AESRD, March

2015).

Parameter Relevant

SS

CO2 Emission

Factor

CH4 Emission

Factor

N2O Emission

Factor

Electricity

Generation

B6, P12 0.59 tonnes

CO2e/MWh

- -

Electricity

Consumption

B6, P12 0.64tonnes

CO2e/MWh

- -

Natural gas

combustion

P15, B18 2.03 kg/m3 0.037 g/m3 0.035 g/m3

Natural Gas

Extraction

P4 0.043 kg/m3 2.3 g/m3 0.004 g/m3

Natural Gas

Processing

P4 0.090 kg/m3 0.3 g/m3 0.003 g/m3

Diesel Combustion B1 2663 g/l 0.133 g/l 0.4 g/l

Diesel Production B4 0.138 kg/l 0.0109 0.000004 kg/l

SS B1 Emissions Collection, Transfer, and Transport

SSB1 = Fossil Fuel for Transport × EFtransport × 10−6

(1)

= 637.94 tCO2e

Where:

Fossil Fuel for Transport =MBiomass

Truck Capacity× Transport Distance × Truck Fuel Efficiency

(2) = 229,020.50 litres

And:

EFtransport = Product Transport Emission Factors, g CO2e/l


March 2018

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Truck fuel Efficiency = 39.5 l/100 km (NRCAN, 2013)1

Transport Distance = 750 km round trip

SS B15 Methane Emissions due to Landfill Avoidance

QCH4,t = ∑ [k × (MSRM − MASH) × Lo × e−k(t−1) × (1 − Ox)]t=40t=1 × (1 − R) (1)

=

Equation 1 is used in conjunction with Table 4 to determine the emissions from avoided

biomass disposal.

Table 4: Landfill Design Factors

Design factor Notation Value

Methane Correction Factor MCF 1

Degradable Organic Carbon DOC 0.17

Fraction of Degradable Organic Carbon Dissimilated DOCF 0.5

Fraction of CH4 in Off gas from Disposal Site F 0.5

Recovered CH4 at Disposal Site R 0

Oxidation factor Ox 0.1

30 yr Annual Average Precipitation (mm/yr) – Brownfield, AB PCPN 470

SS B6 Emissions Electricity

Emissions of CO2e = max(Egenerated,project − Econsumed,project − Egenerated,historic,adjusted, 0) ×

EFP

= 399.20 tCO2e

Where:

Egenerated,project = electricity generated by the Project, kWh;

Econsumed, project = electricity consumed by the Project, kWh;

Egenerated, Historic, adjusted = Historic electricity generated on site scaled to meet current

production, kWh. This term will always be zero for the Project as previously no

electricity was generated on-site.

1 The fuel efficiency for heavy duty trucks may be updated following the phase-in of

Environment Canada’s proposed Heavy Truck GHG Emission Standards as it applies to the

Project.


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EFP (tonnes CO2e/kWh) =Emission factor for on-site renewable electricity

production

SS B18 Displaced On-Site Heat Generation

The avoided emissions from displacing natural gas used in the baseline occur through the

distribution of low pressure steam to the Cargill High River Plant. The low-pressure steam

generation is calculated using the methods as outlined below:

E𝐵18 = VNG,eq × EFNG,i (7)

= 20,438.12 tCO2e

Where:

VNG,eq = Equivalent volume of natural gas displaced by thermal energy production, e3m3 EFNG,i = Natural Gas Combustion emission factor for GHG species, i, tonnes/e3m3 i = CO2, CH4, N2O gas species

And:

𝑉𝑁𝐺,𝑒𝑞 = (𝑄𝐿𝑃 − QBFW) ÷ EfficiencyNG−Boiler ÷ 𝐻𝐻𝑉𝑁𝐺 (8)

= 9,931.07 e3m3

Where:

QLP = Energy of Low Pressure steam produced, GJ QBFW = Energy of boiler feed water input, 76,797 GJ HHVNG = higher heating value of natural gas, MJ/m2 EfficiencyNG-Boiler

3= Boiler efficiency of pre-existing natural gas boiler, %

Where:

𝑄𝐿𝑃 = 𝐻𝐿𝑃 × 𝑀𝑆 = 400,438.67GJ (9)

And: HLP = Enthalpy of low pressure steam, BTU/lbm,

MS = Mass flow rate of steam, klbs

The enthalpy of the steam at the specific temperature and pressure can be found using

steam tables, or as in this case, calculated through the Excel add in: WINSTEAM 4.0.

If (𝐻𝑔𝑝𝑟𝑜𝑗 − 𝐻𝑐,𝑝𝑟𝑜𝑗) > 0,

where: Hg,project = thermal heat generated by the project, GJ Hc,proj =(HHP – HLP) =Thermal heat energy used by the project, internal heat loss in the

system, GJ

then the heat generated by the project must be compared to the average adjusted historic

heat generation over a 3 year period scaled to current operations. As this is a newly

constructed facility, a natural gas baseline is assumed, and the historic heat generated is

equivalent to the project heat generation.

3 HHV was used as the boiler efficiency of Saskatoon boiler was calculated using HHV values


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SS B4 Emissions Fuel Extraction/Processing

ENGXP = ∑ VNGeq × EFNXP𝑖 (10)

=2,175.66 tCO2e

Where:

EFNXPi= Emission factor for natural gas extraction and processing, i= CO2, CH4, and

N2O, tonnes/e3m3

SS P4 Emissions Fuel Extraction/Processing

Extraction and Processing Emissions = ∑ ( V𝑗 × XPi)𝑗𝑖 (13)

=588.25 tCO2e

Where:

XP = extraction and processing emission factors

i = CO2, CH4, N2O gas species

j = fossil fuel: diesel, natural gas

SS P12 Emissions Facility Operation

Emissions, i = ∑ ((𝑉𝐷𝑇+𝑉𝐺𝐸𝑁𝑆𝐸𝑇) × EFDiesel,i)𝑖 + (FBBGrid × EFC) (11)

=1625.86 tCO2e

Where:

FBBGrid = Electricity required to operate the primary and auxiliary electrical

equipment located in the boiler building, MWh;

EFC = Emission factor for grid electricity consumption, see table 3

SS P15 Emissions Combustion of Biomass, Biogas and Fossil Fuels

Combustion Emissions, P15 = Natural Gas Combustion + Biogas Combustion + Biomass

Combustion

Natural Gas Combustion Emissions = ∑ ((𝑉𝑁𝐺) × EF𝑁𝐺,𝑖)𝑖 (12)

=10,297.90 tCO2e

Where:

VNG = total volume of natural gas required for start-up of the under-bed

burner, and supplementary gas for the over-bed burner when required, e3m3;

EF NG, i = natural gas combustion emission factor for industrial processes of

specified greenhouse gas species , i

i = CO2, CH4, N2O gas species

Biomass Combustion Emissions = ∑ (Energy HP Steam−QTOTAL,IN

𝜂𝐹𝐵𝐵) × EF𝐵,𝑖𝑖 (13)


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Where:

ENERGY HP STEAM = high pressure steam energy produced (energy output), GJ

EFB, i = CH4 and N2O emission factors for the combustion of biomass,(CO2

emissions are biogenic and excluded from the quantification) tonne/GJ

ƞFBB = FBB efficiency, 68%

QTOTAL, IN = total energy input to FBB, GJ

And:

QTOTAL, IN = QNG + QBIOGAS +QBFW

Where:

QNG = energy of natural gas used in the FBB, GJ

QBiogas = energy of the biogas used in the FBB, GJ

QBFW = energy of the boiler feed water, GJ

Biogas Combustion Emissions = ∑ ((𝑉𝐵𝐺) × EF𝑁𝐺,𝑖)𝑖 (14)

Where:

VBG = volume of biogas sent to FBB, e3m3

EFNG,I = CH4 and N2O emission factors for the combustion of natural gas,

assumed to be representative of the biogas (CO2 emissions are biogenic and

excluded from the quantification), tonne/e3m3

4.0 References

Alberta Environment, 2014. Quantification Protocol for Energy Generation from the Combustion of

Biomass Waste, version 2.0, April 2014.

Environment Canada, 2016, National Inventory Report 1990-2014: Greenhouse Gas Sources and

Sinks in Canada. Environment Canada, Ottawa.

Gas Processors Association, 2009, GPA Standard 2145-09: Table of Physical Properties for

Hydrocarbons and Other Compounds of Interest to the Natural Gas Industry. GPA, Tulsa.

Alberta Environment and Sustainable Resource Development. (March 2015). Carbon Offset Emission Factors

Handbook, version 1.0. Edmonton: Government of Alberta.

IPCC. (2006). Stationary Combustion . Guidelines for National Greenhouse Gas Inventories. IPCC.

NRCAN. (2013, 11 18). Fuel Efficiency Benchmarking in Canada's Trucking Industry. Retrieved 12 17, 2014, from

Natural Resources Canada: http://www.nrcan.gc.ca/energy/efficiency/transportation/commercial-

vehicles/reports/7607


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Appendix A: Supporting Information