emission estimation technique manual for fossil fuel electric power generation
emission estimation technique manual for fossil fuel electric power generation
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emission estimation technique manual for fossil fuel electric power generation
This manual describes the procedures and recommended approaches for estimating emissions from facilities engaged in fossil fuel electric power generation. It considers combustion and non-combustion sources of emissions to air, water and land. The reporting list and detailed information on thresholds are contained in the NPI guide. In general, there are four types of emission estimation technique (EET) that may be used to estimate emissions from a facility. There are 94 EET manuals. Some industry sectors may require one or more EET manual. The NPI Guide should be used in conjunction with all manuals. Diffuse emissions manuals can also be used to estimate emissions at your facility. See EPA’s About PDF page to learn more. Go to the equivalencies calculator page for more information. These are calculated using GWPs from the Intergovernmental Panel on Climate Change’s Fourth Assessment Report. EE and RE programs are not generally assumed to affect baseload power plants that run all the time, but rather marginal power plants that are brought online as necessary to meet demand. Therefore, AVERT provides a national marginal emission factor for the Equivalencies Calculator. For reference, to obtain the number of grams of CO 2 emitted per gallon of gasoline combusted, the heat content of the fuel per gallon can be multiplied by the kg CO 2 per heat content of the fuel. Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule, page 25,330 (PDF) (407 pp, 5.7MB, About PDF ). Volume 2 (Energy). Intergovernmental Panel on Climate Change, Geneva, Switzerland. For reference, to obtain the number of grams of CO 2 emitted per gallon of diesel combusted, the heat content of the fuel per gallon can be multiplied by the kg CO 2 per heat content of the fuel. Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule, page 25,330 (PDF) (407 pp, 5.7MB, About PDF ). Volume 2 (Energy).
emission estimation technique manual for fossil fuel electric power generation.
Intergovernmental Panel on Climate Change, Geneva, Switzerland. The average vehicle miles traveled (VMT) in 2017 was 11,484 miles per year (FHWA 2019). Gallons of gasoline consumed was multiplied by carbon dioxide per gallon of gasoline to determine carbon dioxide emitted per vehicle per year. Carbon dioxide emissions were then divided by the ratio of carbon dioxide emissions to total vehicle greenhouse gas emissions to account for vehicle methane and nitrous oxide emissions. Chapter 3 (Energy), Tables 3-13, 3-14, and 3-15.Office of Highway Policy Information, Federal Highway Administration. Table VM-1. (1 pp, 12 KB About PDF ) In 2017, the ratio of carbon dioxide emissions to total greenhouse gas emissions (including carbon dioxide, methane, and nitrous oxide, all expressed as carbon dioxide equivalents) for passenger vehicles was 0.989 (EPA 2019). Carbon dioxide emissions were then divided by the ratio of carbon dioxide emissions to total vehicle greenhouse gas emissions to account for vehicle methane and nitrous oxide emissions. Chapter 3 (Energy), Tables 3-13, 3-14, and 3-15.Office of Highway Policy Information, Federal Highway Administration. Table VM-1. (1 pp, 12 KB About PDF ) The average carbon coefficient of pipeline natural gas burned in 2017is 14.43 kg carbon per mmbtu (EPA 2019). The fraction oxidized to CO 2 is assumed to be 100 percent (IPCC 2006). Direct methane emissions released to the atmosphere (without burning) are about 25 times more powerful than CO 2 in terms of their warming effect on the atmosphere. Volume 2 (Energy). Intergovernmental Panel on Climate Change, Geneva, Switzerland. The average carbon coefficient of crude oil is 20.31 kg carbon per mmbtu (EPA 2019). The fraction oxidized is assumed to be 100 percent (IPCC 2006). Volume 2 (Energy). Intergovernmental Panel on Climate Change, Geneva, Switzerland. A barrel equals 42 gallons. A typical gasoline tanker truck contains 8,500 gallons.
Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule, page 25,330 (PDF) (407 pp, 5.7MB, About PDF ). Volume 2 (Energy). Intergovernmental Panel on Climate Change, Geneva, Switzerland. Assuming an average daily use of 3 hours per day, an incandescent bulb consumes 47.1 kWh per year, and an LED bulb consumes 9.9 kWh per year (EPA 2016). Annual energy savings from replacing an incandescent light bulb with an equivalent LED bulb are calculated by multiplying the 34-watt difference in power between the two bulbs (43 watts minus 9 watts) by 3 hours per day and by 365 days per year. The national weighted average carbon dioxide marginal emission rate for delivered electricity in 2018 was 1,558.8 lbs CO 2 per megawatt-hour, which accounts for losses during transmission and distribution (EPA 2019). On average, each home consumed 12,146 kWh of delivered electricity (EIA 2019a). The national average carbon dioxide output rate for electricity generated in 2016 was 998.4 lbs CO 2 per megawatt-hour (EPA 2018), which translates to about 1,072.1 lbs CO 2 per megawatt-hour for delivered electricity, assuming transmission and distribution losses of 6.9 (EIA 2019b; EPA 2018). 1 On average, each home consumed 12,146 kWh of delivered electricity. Nationwide household consumption of natural gas, liquefied petroleum gas, and fuel oil totaled 5.02, 0.50, and 0.49 quadrillion Btu, respectively, in 2018 (EIA 2019a). Averaged across households in the United States, this amounts to 40,190 cubic feet of natural gas, 45 gallons of liquefied petroleum gas, and 29 gallons of fuel oil per home. The fraction oxidized to CO 2 is 100 percent (IPCC 2006). The fraction oxidized to CO 2 is 100 percent (IPCC 2006). The fraction oxidized is 100 percent (IPCC 2006). Volume 2 (Energy). Intergovernmental Panel on Climate Change, Geneva, Switzerland.
These estimates are based on the following assumptions: To estimate losses of growing trees, in lieu of a census conducted to accurately account for the total amount of seedlings planted versus surviving to a certain age, the sequestration rate (in lbs per tree) is multiplied by the survival factor to yield a probability-weighted sequestration rate. These values are summed for the 10-year period, beginning from the time of planting, to derive the estimate of 23.2 lbs of carbon per coniferous tree or 38.0 lbs of carbon per deciduous tree. Of a sample of approximately 11,000 coniferous and deciduous trees in seventeen major U.S. cities, approximately 11 percent and 89 percent of sampled trees were coniferous and deciduous, respectively (McPherson et al. 2016). Therefore, the weighted average carbon sequestered by a medium growth coniferous or deciduous tree, planted in an urban setting and allowed to grow for 10 years, is 36.4 lbs of carbon per tree. Voluntary Reporting of Greenhouse Gases, U.S. Department of Energy, Energy Information Administration (16 pp, 111K, About PDF ) Through the process of photosynthesis, trees remove CO 2 from the atmosphere and store it as cellulose, lignin, and other compounds. The rate of accumulation is equal to growth minus removals (i.e., harvest for the production of paper and wood) minus decomposition. In most U.S. forests, growth exceeds removals and decomposition, so the amount of carbon stored nationally is increasing overall, though at a decreasing rate. Net changes in carbon attributed to harvested wood products are not included in the calculation. Forest carbon stocks and carbon stock change are based on the stock difference methodology and algorithms described by Smith, Heath, and Nichols (2010). Significant geographical variations underlie the national estimates, and the values calculated here might not be representative of individual regions, states, or changes in the species composition of additional acres of forest.
Intergovernmental Panel on Climate Change, Geneva, Switzerland. General Technical Report NRS-13 revised, U.S. Department of Agriculture Forest Service, Northern Research Station. When calculating carbon stock changes in biomass due to conversion from forestland to cropland, the IPCC guidelines indicate that the average carbon stock change is equal to the carbon stock change due to removal of biomass from the outgoing land use (i.e., forestland) plus the carbon stocks from one year of growth in the incoming land use (i.e., cropland), or the carbon in biomass immediately after the conversion minus the carbon in biomass prior to the conversion plus the carbon stocks from one year of growth in the incoming land use (i.e., cropland) (IPCC 2006). The carbon stock in annual cropland biomass after one year is 5 metric tons C per hectare, and the carbon content of dry aboveground biomass is 45 percent (IPCC 2006). Therefore, the carbon stock in cropland after one year of growth is estimated to be 2.25 metric tons C per hectare (or 0.91 metric tons C per acre). Carbon stock change in soils is time-dependent, with a default time period for transition between equilibrium soil carbon values of 20 years for soils in cropland systems (IPCC 2006). Consequently, it is assumed that the change in equilibrium soil carbon will be annualized over 20 years to represent the annual flux in mineral and organic soils. Emissions from drained organic soils in forestland and drained organic soils in cropland vary based on the drainage depth and climate (IPCC 2006).Immediately after conversion from forestland to cropland, biomass is assumed to be zero, as the land is cleared of all vegetation before planting crops) The change in emissions from drained organic soils per hectare is estimated as the difference between emission factors for drained organic forest soils and drained organic cropland soils. Note that this represents CO 2 avoided in the year of conversion.
Please also note that this calculation method assumes that all of the forest biomass is oxidized during clearing (i.e., none of the burned biomass remains as charcoal or ash). Also note that this estimate includes both mineral soil and organic soil carbon stocks. Chapter 2: Drained Inland Organic Soils. Intergovernmental Panel on Climate Change, Geneva, Switzerland. Volume 4 (Agriculture, Forestry and Other Land Use). Intergovernmental Panel on Climate Change, Geneva, Switzerland. The fraction oxidized is assumed to be 100 percent (IPCC 2006). Propane cylinders vary with respect to size; for the purpose of this equivalency calculation, a typical cylinder for home use was assumed to contain 18 pounds of propane. Volume 2 (Energy). Intergovernmental Panel on Climate Change, Geneva, Switzerland. The average carbon coefficient of coal combusted for electricity generation in 2017 was 26.08 kilograms carbon per mmbtu (EPA 2019). The fraction oxidized is assumed to be 100 percent (IPCC 2006). The amount of coal in an average railcar was assumed to be 100.19 short tons, or 90.89 metric tons (Hancock 2001). Conversion of Weight of Freight to Number of Railcars. Transportation Research Board, Paper 01-2056, 2001. Volume 2 (Energy). Intergovernmental Panel on Climate Change, Geneva, Switzerland. The average carbon coefficient of coal combusted for electricity generation in 2017 was 26.08 kilograms carbon per mmbtu (EPA 2019). The fraction oxidized is 100 percent (IPCC 2006). Volume 2 (Energy). Intergovernmental Panel on Climate Change, Geneva, Switzerland. These emission factors were developed following a life-cycle assessment methodology using estimation techniques developed for national inventories of greenhouse gas emissions. According to WARM, the net emission reduction from recycling mixed recyclables (e.g., paper, metals, plastics), compared with a baseline in which the materials are landfilled (i.e., accounting for the avoided emissions from landfilling), is 2.
The activities covered by this Manual apply to facilities primarily engaged in the conversion of fossil fuels (particularly coal, natural gas, and liquid hydrocarbons) into electricity. EET MNUL: Fossil Fuel Electric Power Generation NZSIC Please note that the NZSIC code is part of NPI reporting requirements. The NPI Guide contains an explanation of the NZSIC code. The Electricity Supply ssociation of ustralia Ltd (ES) (now esaa, the Energy Supply ssociation of ustralia) wrote this Manual on behalf of and in conjunction with the ustralian Government. It has been developed through a process of national consultation involving state and territory environment departments and key industry stakeholders. The Manual was revised by ES in March The review document proposed a number of changes to the Manual based on recently available information and improved emission estimation techniques. The scientific review report (Reference: Pacific Power International 2002) and detailed references are held in the library of the ustralian Department of Sustainability, Environment, Water, Population and Communities.This guidance material documents the processes for the generation of electricity via the combustion of fossil fuels. The process by which this occurs is as follows, chemical energy stored in solid fuel is used to generate steam. This steam then drives turbine that drives a generator to produce electricity. This process takes stored chemical energy to kinetic to electrical energy. This is similar to the way that power can be harnessed using hydro-electric and wind turbines.
Types of fossil fuel electricity generation facilities commonly found in ustralia include: steam cycle facilities (commonly used for large base load facilities); open cycle gas turbines (commonly used for moderate sized peaking facilities); cogeneration and combined cycle facility (the combination of gas turbines or internal combustion engines with heat recovery systems); and internal combustion engines (commonly used for small remote sites or stand-by (emergency) generation). Each of these facility types is considered in more detail in sections 2.1 to 2.4. The combustion processes in fossil fuel power generation lead to the coincidental production of a number of NPI category 1 substances. Refer to the NPI Guide for more information about coincidental production and determining NPI reporting requirements ( For most Category 1 organic compounds, the coincidental production during combustion of fossil fuel will be below NPI threshold levels. In such cases, reporting may only be required if these organics are used in some other process at the facility. For example, reporting of some Category 1 substances may be triggered by liquid fuel use, in which case all emissions, including emissions from combustion, must be reported. NPI reportable emissions from fossil fuel power stations are largely emissions from stacks, with water emissions from wet ash dams from some facilities also being a source of reportable emissions. Chemical use within power stations tends to be relatively modest. Bulk chemicals are used to treat boiler water and cooling water for steam cycle facilities. Facilities need to assess whether the use of substances such as ammonia, chlorine and sulfuric acid will lead to the NPI reporting threshold being exceeded for those substances. Coal storage and handling as well as ash storage may result in fugitive particulate emissions.
While maintenance activities such as degreasing of metal components may lead to emissions to air and water, the use of degreasers alone is unlikely to lead to the NPI reporting thresholds being exceeded for substances contained in these products. This manual will assist you to estimate the emissions you may need to report to the NPI. It is your responsibility to report to the NPI if your facility exceeds reporting thresholds for NPI substances. 2 Figure 1 is a basic flow diagram for a steam cycle facility. In the ustralian context, a steam cycle facility is based on the combustion of fossil fuel in a boiler to produce high pressure and high temperature steam that is expanded through a steam turbine coupled to an electricity generator. The steam is condensed for reuse in the cycle. Steam cycle facilities are typically used for large base load electricity generation. Fuels commonly used in ustralia are black coal in New South Wales, Queensland and Western ustralia, brown coal (or lignite) in South ustralia and Victoria and natural gas in South ustralia, Victoria, and Western ustralia. Fuel oil, lighter oils, natural gas, brown coal briquettes, or liquefied petroleum gas (LPG) are commonly used as auxiliary fuels (e.g. during start-up procedures). The boiler water is commonly treated to reduce corrosion and scaling in the boiler tubes. Cooling water used to condense the steam is often treated to reduce algal growth.Indicative properties and composition of ustralian coals used for electricity generation in ustralia are included in ppendix B. Because of the variation in coal properties it is sometimes necessary to characterise different emission factors based on the different regions of coals in ustralia. Coals are usually pulverised prior to combustion. Particulate material (e.g. fly ash) in gas streams from the combustion process are captured by electrostatic precipitators or fabric filters (FF also called baghouses).
Fly ash from some power stations can be used as a resource, such as blending with cement.Usually only very small amounts of ash are released to air. Carbon dioxide and water vapour are not NPI substances and are not reported to the NPI. Coal and ash storage and handling facilities, and bulk hydrocarbon storage associated with power station operations, can lead to fugitive dust (i.e. coal or ash) and hydrocarbon emissions to air respectively. 4 Generally, they do not have control equipment to collect particulate matter, as emissions of particulate matter are low for gas and generally low for oil. Emissions to air include carbon dioxide (CO 2 ), water vapour, oxides of nitrogen (NO x ), carbon monoxide (CO), minor emissions of metals and metal compounds and organics, and sulfur dioxide (SO 2 ) for oil firing. Carbon dioxide and water vapour are not NPI substances and are not reported to the NPI. Bulk hydrocarbon storage can be a source of emissions of Total Volatile Organic Compounds (Total VOCs) and of individual hydrocarbon substances due to evaporative losses from storage tanks. 2.2 Gas Turbine The gas turbine cycle relies on the expansion of very high temperature compressed gas through a gas turbine connected to an electricity generator. To achieve this, air is compressed and mixed with the fuel (usually natural gas or distillate), and burnt in a combustion chamber(s) prior to expansion through the turbine. Figure 2 illustrates a simple open cycle gas turbine facility. Gas turbine facilities are generally physically smaller and generally produce less electricity than steam cycle facilities and can be operated with short start-up periods. They are commonly used to generate electricity at intermediate and peak load periods. Gas turbines are also used as standby (i.e. emergency) facilities. Occasionally, gas turbine facilities are used for base load operations.
Emissions to air from a gas turbine facility include carbon dioxide (CO 2 ), water vapour, carbon monoxide (CO), oxides of nitrogen (NO x ), and minor emissions of metals and metal compounds and organics. Carbon dioxide and water vapour are not NPI substances and are not reported to the NPI. Emissions to water from gas turbine facilities tend to be minor and relate to maintenance activities. Bulk hydrocarbon storage can be a source of emissions. Figure 2 Flow diagram for a gas turbine facility Fuel Combustion Chamber Exhaust Gas Gas Turbine Electricity Generator Compressed ir Compressor Exhaust Gas Exhaust Gas ir 5 Cogeneration utilises the heat from the exhaust of the gas turbine, engine, or boiler, to heat water or raise stream for either domestic or industrial processes. In combined cycle gas turbine facility, hot exhaust gases from the gas turbine are used to raise steam in a heat recovery steam generator. The steam is used to drive a steam turbine and electrical generator. Cogeneration and combined cycle facilities can operate for considerable periods (to supply the heat and electricity requirements) and have overall thermal efficiencies (measure of energy utilisation) greater than simple gas turbines or stationary engine facilities. Emissions to air include carbon dioxide (CO 2 ), water vapour, carbon monoxide (CO), oxides of nitrogen (NO x ), hydrocarbons, and minor emissions of metals and metal compounds. Emissions to water sources relate to the specific configuration of the heat recovery system, which may include water treatment and facility maintenance. 2.4 Internal Combustion (Stationary) Engines Internal combustion engines using either petrol, natural gas, distillate, or LPG, coupled to electricity generators. Engines are commonly used to provide electricity in remote sites and stand-by (emergency) facilities. Usually, internal combustion engines are relatively small units compared to those considered above.
Emissions to air include carbon dioxide (CO 2 ), water vapour, carbon monoxide (CO), oxides of nitrogen (NO x ), hydrocarbons, and minor emissions of metals and metal compounds. Bulk organic liquid storage may be a source of emissions. Minor emissions to water can relate to engine cooling systems and facility maintenance. 6 When reporting to the destination of pollutant emissions needs to be determined. For additional information about the destination of pollutant emissions see the NPI Guide ( 3.1 Emissions to ir Emissions to air can be categorised as either point sources, such as stacks, or fugitive sources, such as stockpiles. Fugitive emissions Fugitive emissions are emitted to air from sources not associated with a specific process, but scattered throughout the plant. Examples of fugitive emissions include dust from stockpiles, volatilisation of vapour from open vessels, and material handling. Emissions emanating from ridgeline roof-vents, louvres, and open doors of a building, as well as equipment leaks, and leaks from valves and flanges are also examples of fugitive emissions. With appropriate management, these emission sources are expected to be minor for power stations. Emission factors are the usual method for estimating emissions from fugitive sources. Refer to the Fugitive Emissions NPI manual for more information about estimating emissions from fugitive sources. Point source emissions Point source emissions are emitted from a stack or vent to air, usually for a specific section of a facility. Emission control equipment (e.g. an electrostatic precipitator or fabric filter (baghouse)) can be used to decrease point source emissions.
Summary of sources of emissions to air Sources of emission to air for fossil fuel electric power generation include: fuel combustion products (from stacks); fugitive emissions from coal stockpiles and handling equipment; fugitive emission from ash storage; additives used for water treatment; organic compounds from bulk hydrocarbon storage tanks; and solvents used for degreasing metal components. 7 There is currently no emission factors included for emissions to water. Sources of emissions to water are primarily from steam cycle facilities and can include: sh transport wastewater and discharge from wet ash dams; Boiler and cooling tower blowdown; Coal stockpile runoff; Floor drains; 8 Emissions to land include solid wastes, slurries, sediments, liquid spills and leaks, and chemicals used to control various environmental issues where these chemicals contain NPI-listed substances. These emission sources can be broadly categorised as: Groundwater; Surface impoundments of liquids and slurries; and Unintentional leaks and spills. 9 The NPI has six different threshold categories and each NPI substance has at least one reporting threshold. If the use of any NPI substance exceeds the threshold, all of the emissions of that substance from the facility must be reported. In the case of fossil fuel electricity generation, the main uses are related to the combustion of fuel, mining of fuel and treatment of waste water. The transfer of wastes may also be applicable. The NPI Guide outlines detailed information on thresholds and identifying emission sources. The method involves identifying any NPI substances that may be used by your facility, or are components of materials used by your facility, and then calculating whether the quantity used exceeds the NPI threshold. 11 Stack tests for NPI reporting should be performed under representative (i.e. normal) operating conditions, and in accordance with the methods, or standards, approved by the relevant environmental authority.