Cargill High River Fluidized Bed Boiler Offset Project

Transcription

1 Cargill High River Fluidized Bed Boiler Offset Project Greenhouse Gas Emissions Reduction Offset Project Report For the Period January 1, 2016 December 31, 2016 FINAL REPORT, version 3.0 May 3, 2017 (Authorized Project Contact) Suite 700, th Avenue SW Calgary, Alberta T2P 3R5 T: (403) F: (403) Web: Prepared for: Cargill Meat Solutions, A Division of Cargill Limited 472 Avenue and Hwy 2A North, P.O. Bag 3850 High River, Alberta T1V 1P4 T: (403) F: (316) Web:

2 Page i Contents Contents... i List of Tables... ii List of Abbreviations... ii 1 PROJECT SCOPE AND PROJECT DESCRIPTION PROJECT CONTACT INFORMATION PROJECT DESCRIPTION AND LOCATION PROJECT IMPLEMENTATION AND VARIANCE Prior variance to OPP valid in 2016 operations Additional 2016 Operational Variance to OPP REPORTING PERIOD SAMPLE GREENHOUSE GAS CALCULATIONS... 8 SS B1 Emissions Collection, Transfer, and Transport... 9 SS B15 Methane Emissions due to Landfill Avoidance... 9 SS B6 Emissions Electricity SS B18 Displaced On-Site Heat Generation SS B4 Emissions Fuel Extraction/Processing SS P4 Emissions Fuel Extraction/Processing SS P12 Emissions Facility Operation SS P15 Emissions Combustion of Biomass, Biogas and Fossil Fuels GREENHOUSE GAS ASSERTION PROJECT DEVELOPER SIGNATURES STATEMENT OF SENIOR REVIEW REFERENCES... 17

3 Page ii List of Tables TABLE EMISSION FACTORS USED FOR THE 2016 REPORTING PERIOD, (ALBERTA ENVIRONMENT AND SUSTAINABLE RESOURCE DEVELOPMENT, MARCH 2015)... 8 TABLE 6-2: LANDFILL DESIGN FACTORS... 9 TABLE OFFSET TONNES CREATED BY VINTAGE YEAR AND GHG, DISPLAYED IN T CO2E List of Abbreviations AEOR Alberta Emissions Offset Registry AENV Alberta Environment (now Alberta Environment and Parks) AEP AESRD Blue Source CH 4 CO 2 CO 2e DAF FBB GHG GWP HFC LSD N 2O PFC PLC SF 6 SGER SRM SS Alberta Environment and Parks Alberta Environment & Sustainable Resource Development (now Alberta Environment and Parks) Blue Source Canada ULC Methane Carbon Dioxide Carbon Dioxide-equivalent Dissolved Air Flotation Fluidized Bed Boiler Greenhouse gas Global Warming Potential Hydrofluorocarbon(s) Legal Site Description Nitrous Oxide Perfluorocarbon(s) Programmable Logic Controller Sulphur Hexafluoride Specified Gas Emitters Regulation Specified Risk Materials Sources and Sinks

4 Page 3 1 PROJECT SCOPE AND PROJECT DESCRIPTION The project title is: The project s purpose(s) and objective(s) are: Date when the project began: Expected lifetime of the project: Cargill High River Fluidized Bed Boiler Offset Project, the Project The Project is the implementation of a fluidized bed boiler (FBB) 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 displaces a portion of the natural gas as fuel for process steam requirements and fossil fuel generated electricity through on-site generation at the Cargill High River Beef Processing Plant. The project began 01 November 2012 and is a result of actions taken on, or after, 01 January The project is expected to continue for the lifetime of the equipment, provided that the High River facility continues to be economic. This lifetime is expected to be far in excess of the credit duration period. Credit start date: 09 May 2013 Credit duration period: The initial eight-year crediting period for the project starts on 09 May 2013 and ends on 08 May Reporting period: January 1, 2016 December 31, 2016 Actual reductions: Applicable Quantification Protocol(s): Protocol(s) Justification: emissions The previous emission reduction claimed for this project are: ,289 tonnes CO 2e ,159 tonnes CO 2e ,170 tonnes CO 2e In this report, which covers the period 01 January December 2016, the total project emission reductions from this project are calculated to be 26,039 tonnes CO 2e. Total project emission reductions to date are: 76,657 tco 2e The quantification protocol used is the Quantification Protocol for Energy Generation from the Combustion of Biomass Waste, version 2.0, April 2014, the Protocol, published by Alberta Environment. 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 CO 2, CH 4, and N 2O 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 CH 4. Other Environmental Attributes: As the activities of the Project are applicable under the Protocol and the displacement of fossil fuels with biomass is not an industry standard, the results of this Project is considered additional and would not have occurred under business as usual circumstances. The Project is eligible for producing renewable energy credits (RECs) in Alberta; however, the Proponent will not be creating RECs associated with

5 Page 4 Legal land description of the project or the unique latitude and longitude: Ownership: Reporting details: Verification details: Project activity: the production of electricity through its combined heat and power facility at the Cargill High River Beef Processing Plant. 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. LSD: W4 Latitude/Longitude: 50 37'27.9"N '41.1"W The Project Proponent is Cargill Meat Solutions, 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. For the purposes of this Offset Project Report, the offsets to be claimed are from 01 January 2016 to 31 December The Proponent is expected to continue to submit annual reports based upon the calendar year for the Project. The Verifier, ClearSky Engineering Inc., is an independent third-party that meets the requirements outlined in the Specified Gas Emitters Regulation (SGER). An acceptable verification standard (e.g. ISO ) has been used and the Verifier has been vetted to ensure technical competence with this project type. This is the second verification carried out by the verifier for this project. This project meets the requirements for offset eligibility as outlined in section 3.1 of the Technical Guidance for Offset Project Developers (version 4.0, February 2013). In particular: 1. The project occurs in AB: as outlined above; 2. The project results from actions not otherwise required by law and beyond business as usual and sector common practices: Offsets being claimed under this project originate from a voluntary action. The project activity occurs at a non-regulated facility and is not required by law. The protocol uses a government approved quantification protocol, which indicates that the activity is undertaken by less than 40% of the industry and is therefore not considered to be sector common practice; 3. The project results from actions taken on or after January 1, 2002: as outlined above; 4. The project reductions/removals are real, demonstrable, quantifiable and verifiable: the project is creating real reductions that are not a result of shutdown, cessation of activity or drop in production levels. The emission reductions are demonstrable, quantifiable and verifiable as outlined in the remainder of this plan.

6 Page 5 5. The project has clearly established ownership: Insert statement on ownership. Credits created from the specified reduction activity have not been created, recorded or registered in more than one trading registry for the same time period. 6. The project will be counted once for compliance purposes: The project credits will be registered with the Alberta Emissions Offset Registry (AEOR) which tracks the creation, sale and retirement of credits. Credits created from the specified reduction activity have not been, and will not be, created, recorded or registered in more than one trading registry for the same time period. 2 PROJECT CONTACT INFORMATION Project Developer Contact Information Authorized Contact Project Cargill Meat Solutions, a division of Cargill Ltd Sean Murray t: f: e: Sean_Murray@cargill.com Blue Source Canada ULC Kelly Parker Carbon Services Project Analyst t: x260 f: e: kellyp@bluesourcecan.com 472 Ave & Hwy 2A North P.O. Bag 3850 High River, AB Canada T1V 1P4 Web: Suite th Avenue SW Calgary, AB Canada T2P 0Z3 Web: Verifier ClearSky Engineering Inc. Klym Bolechowsky, P.Eng Lead Verifier t: (403) e: klym@clearskyeng.com 221 Drake Landing Lane, Suite 1 Okotoks, Alberta Canada T2S 2M4 Web: This is the second verification carried out by the verifier for this project.

7 Page 6 3 PROJECT DESCRIPTION AND LOCATION The Cargill High River Beef Processing Plant (herein referred to as the Plant ) began operations in The Plant consists of holding pens, and houses facilities for animal slaughter, cutting, packaging and freezing, rendering of non-consumable materials, hide curing, and wastewater treatment. Approximately 4,500 cattle heads are processed per day at the facility. The construction of a fluidized bed boiler (FBB) has reduced the Plant s waste by utilizing both compostable wastes and SRMs as fuel to displace a portion of the electricity load and process steam requirements through on-site generation. The FBB project was approved by both Alberta Environment (Approval , dated March 31, 2011) and the Alberta Utilities Commission (Approval No U , dated November 9, 2011). In 2013, the Proponent began to utilize the bovine by-products, DAF fines, tricanter solids, and dewatered activated sludge as a solid fuel in the FBB. The Proponent collects, dewaters and combusts the biomass in an FBB system to produce high pressure steam in a water-tube boiler. This steam then passes through a back pressure 1.4 MW turbine and produces a portion of the base electrical load for first the FBB facility, and then any excess electricity generation is sent to the plant. The reduced pressure steam leaving the turbine is then captured and used in the plant production processes. As a result, the use of biomass as a solid fuel feedstock directly offsets the demand for natural gas and electricity sourced from the commercial distribution grid at the Plant. 4 PROJECT IMPLEMENTATION AND VARIANCE 4.1 Prior variance to OPP valid in 2016 operations The project continues to experience minor communication errors with the low pressure steam meter (tag FT-5000) less than 5% of total time, between the meter and SCADA system. Correct measurement data was used to create a statistically conservative average steam flowrate value that can be substituted when meter error exists, by selecting a confidence interval that introduced minimal variability in the estimated steam flow volume and impact to the GHG assertion (<5% uncertainty). The revised methodology is outlined stepwise below: 1. The daily average and standard deviation of steam generation per month both for weekday and weekend operations was calculated from available metered data. 2. For days where a meter ERROR is listed, the conservative value applied is the minimum steam flowrate value at which a selected percentage of data is equal to or greater than. This is determined through statistical analysis of a normal data distribution of metered data (removed of errors) by calculating the mean mass steam flowrate per day subtract the standard deviation of the steam meter values for the selected confidence interval (i.e. at a 95% confidence interval, the mean steam flowrate is subtracted by times the standard deviation to achieve a minimum value of which 95% of the data is above). As the weekend flowrates are much smaller

8 Page 7 and have less data variability this analysis often resulted in a negative value. When this occurred steam generation was assumed Consecutive days with repeat were compared to the operating days assigned to the thermal FBB operation via the SRM receiving records (t FBB,T). a. If there was no record of material received for that day the FBB was assumed nonoperational, and the flowrate value set to 0; b. If there was a record of material received for the day the meter error occurred, the 95% steam flowrate value was used. 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 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. 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 reconciling the trailer capacity, the measured mass of biomass, trip distance and fuel efficiency. 4.2 Additional 2016 Operational Variance to OPP 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. Biogas began being received at the FBB on May 14, 2017 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 are quantified in the methane generation waste water offset project. The FBB experienced an unplanned shutdown spanning the dates: February 20, 2016 February 29, 2016 due to emergency repairs that were conducted on the boiler. Six tubes were replaced in the secondary superheater, structural repairs and two tubes plugged as per work order # This shutdown resulted in a cessation of electricity generation and steam production for the dates indicated. Dewatered activated sludge is no longer used in the FBB as the energy content is too low.

9 Page 8 5 REPORTING PERIOD For the purposes of this project report, the carbon dioxide equivalent emission reduction credits are claimed for activities from 01 January 2016 to 31 December, The project is intended to proceed with annual quantification and verification as indicated in the project plan. 6 SAMPLE GREENHOUSE GAS CALCULATIONS GHG emission reductions were calculated following the Quantification Protocol for Energy Generation from the Combustion of Biomass wastes, version 2.0 April 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. The following equations serve as the basis for calculating the emission reductions from the comparison of the baseline and project conditions: Emission Reduction = Emissions Baseline Emissions Project Emissions Baseline = 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 6-1 provides the emission factors used for the project. A site specific natural gas combustion CO 2 emission factor is used for sources P15 and B18. Table Emission factors used for the 2016 Reporting period, (Alberta Environment and Sustainable Resource Development, March 2015) Parameter Relevant SS CO 2 Emission Factor CH 4 Emission Factor N 2O Emission Factor Electricity Generation B6, P tonnes - - CO 2e/MWh Electricity B6, P tonnes - - Consumption CO 2e/MWh Natural gas combustion P15, B kg/m g/m g/m 3

10 Natural Gas P kg/m g/m g/m 3 Extraction Natural Gas P kg/m g/m g/m 3 Processing Diesel Combustion B g/l g/l 0.4 g/l Diesel Production B kg/l kg/l SS B1 Emissions Collection, Transfer, and Transport SSB1 = Fossil Fuel for Transport EF transport 10 6 (1) Where, Fossil Fuel for Transport = M Biomass Transport Distance Truck Capacity Truck Fuel Efficiency (2) And: Page 9 EF transport = Product Transport Emission Factors, g CO 2e/l 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 Q CH4,t = t=40 t=1 [k (M SRM M ASH ) Lo e k(t 1) (1 Ox)] (1 R) (1) Equation 1 is used in conjunction with Table 6-2 to determine the emissions from avoided biomass disposal. Table 6-2: 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 CH 4 in Off gas from Disposal Site F 0.5 Recovered CH 4 at Disposal Site R 0 Oxidation factor Ox yr Annual Average Precipitation (mm/yr) Brownfield, AB PCPN 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.

11 Page 10 SS B6 Emissions Electricity Emissions of CO 2 e = max(e generated,project E consumed,project Where, E generated,historic,adjusted, 0) EF P E generated,project = electricity generated by the Project, kwh; E consumed, project = electricity consumed by the Project, kwh; E generated, 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 onsite. EF P (tonnes CO 2e/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: Where, If (H g,proj H c,proj ) < 0, then: H g,proj = V NG,eq EF NG,i (7) H g,proj (H LP) = heat generated by the project, GJ H c,proj (H HP H LP) = Thermal heat energy used by the project, internal heat loss in the system, GJ V NG,eq = Equivalent volume of natural gas displaced by thermal energy production, e 3 m 3 ; EF NG,i = Natural Gas Combustion emission factor for GHG species, i, tonnes/e 3 m 3 i = CO 2, CH 4, N 2O And: Where, V NG,eq = Q LP HHV NG 1000 Efficiency NG Boiler (8) Q LP = Energy of Low Pressure steam produced, GJ HHV NG = higher heating value of natural gas, MJ/m 2 Efficiency NG-Boiler = Boiler efficiency curve of pre-existing natural gas boiler, % Where, Q LP = H LP M S (9) 2 HHV was used as the boiler efficiency of Saskatoon boiler was calculated using HHV values

12 Page 11 And: H LP = Enthalpy of low pressure steam, BTU/lbm, M S = 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 (H gproj H c,proj ) > 0, 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 there is no average historic heat generation to compare against, and a natural gas baseline is assumed. SS B4 Emissions Fuel Extraction/Processing E NGXP = VNGeq EFNXP i (10) Where, EFNXP i= Emission factor for natural gas extraction and processing, i= CO 2, CH 4, and N 2O, tonnes/e 3 m 3 SS P4 Emissions Fuel Extraction/Processing Extraction and Processing Emissions = i ( V j XP i ) (13) XP = extraction and processing emission factors i = Greenhouse gas species: carbon dioxide, methane, nitrous oxide j = fossil fuel: diesel, natural gas j SS P12 Emissions Facility Operation Emissions, i = ((V DT +V GENSET ) EF Diesel,i ) i + (FBB Grid EF C ) (11) FBB Grid = Electricity required to operate the primary and auxiliary electrical equipment located in the boiler building, MWh; EF C = Emission factor for grid electricity consumption SS P15 Emissions Combustion of Biomass, Biogas and Fossil Fuels Combustion Emissions, P15 = Natural Gas Combustion + Biogas Combustion + Biomass Combustion Natural Gas Combustion Emissions = ((V NG ) EF NG,i ) i (12) Where: V NG = 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 = Carbon dioxide, methane, nitrous oxide

13 Page 12 Biomass Combustion Emissions = ( Energy HP Steam Q TOTAL,IN i ) EF B,i (13) Where, (12) η FBB ENERGY HP STEAM = high pressure steam energy produced (energy output), GJ EF B, i = CH 4 and N 2O emission factors for the combustion of biomass,(co2 emissions are biogenic and excluded from the quantification) tonne/gj ƞ FBB = FBB efficiency, % Q TOTAL, IN = total energy input to FBB, GJ And QTOTAL, IN = Q NG + Q BIOGAS Where, Q NG Q Biogas = energy of natural gas used in the FBB, GJ = energy of the biogas used in the FBB, GJ Biogas Combustion Emissions = i ((V BG ) EF NG,i ) (14) Where, = volume of biogas sent to FBB, e3m3 V BG EF NG,I = CH 4 and N 2O emission factors for the combustion of natural gas, assumed to be representative of the biogas (CO 2 emissions are biogenic and excluded from the quantification), tonne/e 3 m 3

14 Page 13 7 GREENHOUSE GAS ASSERTION The greenhouse gas assertion is a statement of the number of offset tonnes achieved during the reporting period. The assertion identifies emissions reductions per vintage year and includes a breakout of individual greenhouse gas types (CO 2, CH 4, N 2O, SF 6, HFCs, and PFCs) applicable to the project and total emissions reported as CO 2e. The total in units of tonnes of carbon dioxide equivalent (CO 2e) is calculated using the global warming potentials (GWPs) referenced in the SGER. Table Offset tonnes created by vintage year and GHG, displayed in t CO2e SS Baseline Emissions t CO 2 t CH 4 t N 2 O PFCs HFCs SF6 t CO 2 e t CO 2 e B1 transportation B4 Fuel Extraction and Processing 1, , B6 Electricity Production B15 Decomposition of Biomass and Methane Collection/Destruction - 13, , B18 Thermal Energy Produced 24, , Total Baseline 26, , , Project Emissions t CO 2 t CH 4 t N 2 O PFCs HFCs SF6 t CO 2 e t CO 2 e P4 Fuel Extraction and Processing P12 Facility Operations , , P15 Combustion of Biomass and Fossil Fuels 8, , , Total Project 9, , , , Emission Offset Credits Created ALL t CO 2 t CH 4 t N 2 O PFCs HFCs SF6 t CO 2 e t CO 2 e , Table 7-1 identifies the greenhouse gas assertion, containing the calculated number of offset tonnes achieved, separated by each unique vintage year and GHG released. The total assertion is 26,039 t CO 2e. The main contribution to CO 2 emissions in the baseline results from the equivalent volume of natural gas that would have been combusted to generate the same amount of energy generated by the FBB contained in the low pressure steam.

15 Offset Volume, tco 2 e Page 14 The main source of baseline methane emissions results from the decomposition of the SRM in landfill. Project methane emissions result mostly from the combustion of the biomass in the FBB Figure 1: Vintage offset creation from May 9, 2013 December 31, 2016, disaggregated by year

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17 Page 16 9 STATEMENT OF SENIOR REVIEW This offset project report was prepared by Kelly Parker, Engineer, Blue Source Canada and senior reviewed by Tooraj Moulai, Senior Engineer, Blue Source Canada. Although care has been taken in preparing this document, it cannot be guaranteed to be free of errors or omissions. Prepared by: Senior reviewed by: Kelly Parker, P.Eng Tooraj Moulai, P.Eng.

18 Page REFERENCES Alberta Environment, 2013, Technical Guidance for Offset Project Developers - Version 4.0, February Alberta Environment, Quantification Protocol for Energy Generation from the Combustion of Biomass Waste, version 2.0, April Environment Canada, 2016, National Inventory Report : Greenhouse Gas Sources and Sinks in Canada. Environment Canada, Ottawa. Gas Processors Association, 2009, GPA Standard : 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: