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A. BHATT ET AL.
Although most industrial boilers utilize fossil-based fuels, some industries, like pulp and paper, utilize alterna- tive biomass-based fuels such as black liquor (a waste product from the chemical pulping process) along with bark, wood chips, and production wastes (Energy and Environmental Analysis, Inc. 2005). Biorefineries, which produce biofuels from biomass, also have opportunities to utilize their renewable waste streams as boiler fuels to meet their heat and power needs in an energy self-sufficient manner. For example, biorefineries using biochemical con- version processes yield several biomass-derived waste streams, including lignin, biogas, sludge, and off-gases, which can be used as fuels in boilers. Research has shown that biomass fuels from wood and plant residues are impor- tant sources of primary energy, accounting for about 13% of global fuel consumption (Slade, Bauen, and Gross 2014). The most common type of boiler commercially uti- lized for biomass combustion is a fluidized bed boiler (Anthony 1995; Singh et al. 2018), with stoker-fired boi- lers, originally utilized for coal and wood combustion, also being used for biomass combustion as well. Through thermodegradation and oxidation reactions, burning bio- mass results in emissions of several criteria and toxic air pollutants (Ushakova et al. 2017). These pollutants include carbon monoxide (CO), nitrogen oxides (NO x ), sulfur oxides (SO x ), hydrocarbons/volatile organic com- pounds (VOCs), and particulate matter (PM; PM includes filterable PM [PM f ] that can be captured on a filter, and condensable PM [PM c ], which is in the gas phase when exiting the stack, but rapidly condenses to form submicron particles once exposed to atmospheric conditions). CO emissions are mainly from incomplete combustion of biomass fuels. NO x emissions are predo- minantly from nitrogen in the fuel (Mitchell et al. 2016), referred to as fuel-bound NO x , but a smaller portion comes from thermal NO x , which produces NO x from nitrogen in the atmosphere reacting within the flame. SO 2 emissions from biomass combustion result from sulfur in the fuel, whereas PM is a result of incomplete combustion, the presence of inert material in the fuel, and an improper air/fuel ratio (Jenkins et al. 1998). Because boilers can be the largest emission sources for certain pollutants within biorefineries (e.g., boilers con- tribute the largest fraction of some gaseous pollutants, and PM emissions have been attributed to boilers in some studies), it is important to characterize their emissions and develop control strategies to protect air quality when building a new biorefinery with an on-site boiler. To maintain compliance with the National Ambient Air Quality Standards (NAAQS) (EPA 1970), the U.S. Environmental Protection Agency (EPA) sets emission standards for new and modified stationary pollution sources and/or unit operations, such as boilers, under
the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) in the form of emission limits (Federal Register 2017; Federal Register, NSPS 2023). The emission limits in the federal standards control the emissions of pollutants, generally defined as a parameter that relates the quantity of a pollutant with the activity associated with release of that pollutant, also known as the emission factor (EPA 2022). In the case of boilers, burn- ing fuel is considered an activity whose emission factor is expressed as the weight of the pollutant (pounds, kilo- grams, etc.) divided by the heat input capacity of the boiler (British thermal units or standard cubic feet). Although emission factors have been used in preparing the national and regional emissions inventory and design- ing emission control strategies, they are often also used for other purposes, such as air permitting. The current data and guidelines published in EPA’s emission factor database (AP-42) address emission factors for boilers burning coal, natural gas, fuel oil, wood, and wood residues (EPA 2009). These emission factors typically represent average emis- sions based on emission testing and monitoring of data collected during normal operating conditions. Many of the data sources used to calculate the emission factors reported in the AP-42 database were collected 20+ years ago and may not represent the more advanced boiler technologies developed for newly emerging, unconventional fuels (EPA 2009, 2015). Additionally, in some cases (e.g., for boilers using wood residue), the emission factors have low relia- bility ratings. For example, biorefineries can now utilize biomass waste produced on-site as boiler fuel(s); the exist- ing AP-42 emission factors for wood and wood residues are likely inaccurate for these boilers. Factors affecting the types and magnitudes of emissions from the boiler include fuel type (e.g., gas, biomass, coal, or a mixture), type of boiler (fluidized bed, stoker, etc.), fuel properties (such as sulfur, nitrogen, ash, and moisture con- tent), and firing practices employed by the facility. For example, a biorefinery that utilizes biomass as a feedstock may pretreat the feedstock using sulfuric acid and ammonia to break down the cellulose for further processing (Davis et al. 2022), resulting in much higher levels of nitrogen and sulfuric acid in the boiler fuel downstream than the typical woody biomass. The emission factors of combusting bio- mass could be considerably different than those of com- busting solid fossil fuels such as coal. This is due to biomass’ higher heterogeneous particle size, higher volatility, higher moisture content and oxygen level, and lower sulfur con- tent and energy density. Moreover, the transport-limited devolatilization characteristics of biomass particles could affect carbon conversion, heat release, pollutant generation, ash formation (from silicon, potassium, etc.), and deposi- tion, among others (Panagiotis 2010).
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