You may be surprised to learn that even with the increased demand for biomass fuels for power generation, construction and demolition fuel is classified as solid waste, not biomass. Reconsidering this designation is critical as U.S. environmental regulations tighten emission profiles for solid waste combustion units and renewable portfolio standards expand.

Courtesy: Public Service of New Hampshire

Many U.S. industrial coal users and utilities are investigating alternative generation options as the regulatory squeeze on coal-fired combustion increases. Some of these options include natural gas conversion of solid fuel steam generators, decommissioning of existing coal-fired steam generators and replacement with natural gas combined cycles, and the use of renewable fuel sources. Given the historic volatility of natural gas prices and suppressed energy demand growth in recent years, many utilities have been reluctant to make the switch to a completely natural gas fleet. Some are considering biomass, because the many new environmental rules and regulations that call for reductions of coal-fired power plant emissions—the Mercury and Air Toxics Standards (MATS), Carbon Pollution Standard, Cross-State Air Pollution Rule (CSAPR), and Greenhouse Gas Tailoring Rule—exempt biomass combustion.

Like natural gas, biomass fuels are uniquely situated as a potential replacement for coal, particularly where retrofits of existing solid fuel boilers already have air quality control equipment. Although biomass may not be the optimal fuel for combustion in a steam generator designed for coal combustion, the operational issues experienced with biomass combustion are well understood. Additionally, 30 of the 50 states plus the District of Columbia have renewable portfolio standards (RPS) that give the biomass plant certain benefits, in addition to federal production tax credits.

Each state has a unique RPS eligibility timeline that generally falls between 2015 and 2025. Each RPS will also have a different standard or requirement for generation from renewable sources, ranging from 10% to 33%. With such a large portion of energy potentially coming from renewable sources, energy producers must focus on developing baseload renewable power generation in the future.

Wind and solar power generation are intermittent and often unpredictable resources that depend on nature’s cooperation. Hydroelectric and geothermal resources offer baseload options but are not universally accepted RPS technologies. Hydroelectric power, for example, is restricted by technology (pumped storage does not qualify in all states or existing plants are not counted) and in some states is restricted by the amount of potential generation.

Biomass power generation on the other hand, is an acceptable technology under all RPSs and offers a historically reliable baseload generation option. So, why haven’t more industrial facilities and utilities made the conversion of existing coal steam generators to biomass?

A Challenging Fuel

The sourcing of biomass fuels is not a straightforward design or operational problem. Biomass fuel types and supplies vary significantly by region, and long-term fuel contracts are very difficult to secure. Furthermore, fuel density, morphology, and moisture content can dramatically affect transportation costs and often dictate the best combustion technology. It is because of these design and availability challenges that many potential users are hesitant to make the leap to biomass power.

The most commonly considered biomass fuel is virgin wood chips due to their wide regional availability, although several other sourcing options do exist. Agricultural byproducts such as corn stover act as an opportunity fuel during the harvest season but are not typically available on a year-round basis. Processing byproducts such as bagasse and rice husks are typically available year round and have very few uses but are usually only available in small quantities. Purpose-grown energy crops such as miscanthus and switch grass are also a viable solution, but as with agricultural byproducts, they will not provide a stable year-round fuel source (Figure 1).

1. Processing wood fuel. A typical biomass material-handling system is shown. The fuel-handling system must be designed with a particular fuel in mind. Courtesy: KBR Power & Industrial

Despite these challenges, the quantity of biomass fuel required to provide the amount of power required by large industrial users and utilities cannot be ignored. Because of the lower energy content of biomass fuels, the volumetric throughput is typically between three and six times that of coal. In addition to handling large volumes of fuel, reduced boiler efficiency from unprocessed fuels such as wood lead to reduced boiler efficiencies and increased mass flows of fuel. Typically, one million tons of virgin wood chips are required on a yearly basis to provide a net output of 80 MW.

Procuring such large amounts of fuel is challenging, but there are ways to work around that problem. For example, Portland General Electric is proposing a full biomass conversion on its 585-MW Boardman Plant. The utility is investigating the use of a purpose-grown energy crop called giant cane as a replacement for the coal now used. The project was prompted by a settlement of legal challenges brought by the U.S. Environmental Protection Agency (EPA) and the Sierra Club. As a result of this resolution, the Boardman Plant has installed new environmental control systems and must stop using coal at the plant by December 31, 2020.

To control the amount of material that will be handled by the facility, the giant cane will be processed by the torrefaction method prior to combustion in the steam generator. Torrefaction will heat the biomass fuel in a sub-stoichiometric atmosphere at temperatures between 400F and 600F to drive off moisture and superfluous volatiles but will not combust the char left behind. The volatiles lost in the process will be collected and combusted to provide the heat needed for torrefaction. The resulting material is typically pelletized to provide an energy-dense material with a heating value similar to that of subbituminous coals. Approximately 8,000 tons a day of biomass will be needed to maintain Boardman’s design power output.

The substantial amounts of biomass required will force agricultural expansion in the region to support the plant’s fuel needs. Even with the required agricultural expansion, Boardman is fortunate to reside in a location that can support the considerable amount of fuel required to maintain a baseload biomass plant. Nevertheless, the plant will have its operations affected if droughts or other upsets to growing conditions occur. Secondary biomass fuel supplies need to be considered in the event that growing conditions are not optimal. In the case of Boardman, a utility spokesperson has said that after it switches to biomass, the plant will likely run only during summer and winter peak seasons.

Most biomass conversion projects also will require substantial investment in new capital equipment. The transportation, receiving, dust suppression, storage, and sizing equipment for wood-related fuels differ significantly from equipment found at coal plants. Coal tends to be dry and has a high energy density for a solid fuel, whereas wood tends to be low in energy density and high in moisture. Existing air quality equipment may also require upgrades to match the new fuel.

Biomass conversions are not always an attractive option for large industrial facilities and utilities, particularly because of the large supply of biomass fuel required and the challenges associated with securing long-term fuel contracts.

Classifying C&D Fuel

Construction and demolition (C&D) fuel is typically categorized as a biomass fuel as it largely consists of wood. Because of its woody composition, C&D fuel is analogous to that of a typical pelletized biomass fuel and, as such, biomass material-handling systems can be properly designed to handle the fuel. The classification of C&D fuels is necessarily broad and generally includes building-related debris, disaster debris, and land-clearing debris. Unfortunately, these potential renewable fuel sources are not classified as a biomass fuel by the EPA, and therefore they are not exempt from more stringent environmental regulations.

The current Non-Hazardous Secondary Materials That Are Solid Wastes Rule classifies C&D as a “solid waste” and as such makes it subject to the Commercial and Industrial Solid Waste Incineration Units (CISWI) standard under Section 129 of the Clean Air Act (CAA). Section 129 was specifically added in 1990 to address emissions from solid waste combustion. Because solid waste incineration units were added to the CAA, the EPA is required to set new source performance standards (NSPS) for new units, establish emission guidelines (EG) for existing units, and use a maximum available control technology (MACT) type of approach for both new and existing units.

The Regulatory History

The recent promulgation of the CISWI (Dec. 20, 2012) is an update of a decade-old rule. On Dec. 1, 2000, the EPA promulgated NSPS and EG for CISWI units. On Jan. 30, 2001, the Sierra Club filed a petition challenging the CISWI rule. As a result of a federal court decision that addressed the method by which the EPA set MACT floors (see Cement Kiln Recycling Coalition v. EPA [255 F.3d 855, DC Cir. 2001]), the EPA voluntarily vacated the CISWI. On Sept. 22, 2005, the EPA issued the CISWI Definition Rule to better define the term “solid waste.”

Almost two years after promulgation of the CISWI Definition Rule, on June 8, 2007, the courts vacated and remanded it due to its inclusion of all facilities combusting any solid waste material. The December 2012 final decision incorporates updates to the Definitions Rule and the voluntary vacatur of the 2000 CISWI (Table 1).

Table 1. The long history of the CISWI Rule. Source: EPA


Table 2. CISWI emission limits for existing units. Source: EPA


Table 3. Boiler MACT emission limits for existing biomass units. Source: EPA


Table 4. CISWI limits for new units. Source: EPA


Table 5. Boiler MACT emission limits for new units. Source: EPA

Solid Waste Classification

If C&D were to be granted a classification change from a solid waste to a biomass fuel, facilities wishing to use the fuel for power generation would have less-stringent emission limitations. These facilities would be regulated by the recently promulgated (Dec. 21, 2012) National Emission Standards for Hazardous Air Pollutants for Major/Area Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (Boiler MACT) under Section 112 of the CAA. This is a significant change, as the Boiler MACT regulations for biomass combustion are far less onerous than the limits imposed by the CISWI for burning the same materials (see Tables 2 to 5 for a comparision of the difference in emission limits).

As part of the Non-Hazardous Secondary Material Rule (NHSMR), C&D can be reclassified from a solid waste to “clean” C&D if it can pass the EPA’s “Legitimacy Criteria” evaluation. The requirements to reclassify C&D fuel as a nonwaste fuel are fourfold: the material must be “managed as a valuable commodity; have a meaningful heating value; be used as a fuel in a combustion unit that recovers energy; and contain contaminants at levels comparable to or lower than those in traditional fuels which the combustion unit is designed to burn.”

The first NHSMR test requires a fuel management plan that shows C&D waste is a “valuable commodity.” This plan must meet three standards as outlined by the EPA:

  • The storage of the nonhazardous secondary material (C&D) prior to use must not exceed reasonable time frames.
  • Where there is an analogous fuel, the nonhazardous secondary material must be managed in a manner consistent with the analogous fuel or otherwise be adequately contained to prevent releases to the environment.
  • If there is no analogous fuel, the nonhazardous secondary material must be adequately contained to prevent releases to the environment.

The fuel management plan standard was set as a means to differentiate typical wastes from those that have some economic value. Therefore, if C&D waste is used as a nonhazardous secondary material, it must be handled in the same manner as a facility using wood chips as its fuel source.

Most C&D wood is typically not transported directly to the plant from the location where it originated; usually, it has an intermediate stop where sorting and processing occurs to clean up the final product. The sorting process identifies wood containing contaminants such as treated wood (for example, railroad ties) or non-wood materials, removes these items from the material stream either with a mechanical separator or by human sorting. Technologies such as x-ray fluorescence analyzers are used to identify any painted or treated wood that the initial separation missed. After removal of contaminated C&D, the remaining material is typically reduced in size and compacted to a specific density to meet the purchaser’s specifications. After preprocessing the fuel, there is no difference between traditional biomass fuels and processed C&D waste fuel, thereby demonstrating that the fuel has economic value.

The second NHSMR test is to verify that the C&D fuel has a meaningful heating value. As defined by the EPA, a fuel that has a meaningful heating value is one with an as-fired heat content of 5,000 Btu/lb. For comparison, the heating values for unprocessed virgin chipped wood range from 4,100 Btu/lb to 4,900 Btu/lb—below the definition of meaningful heating value as outlined by the EPA. Typically, the heating value of C&D will vary greatly, depending on the source, but a reasonable estimate ranges from 6,700 Btu/lb to 9,000 Btu/lb, with an average heat content of 8,200 Btu/lb. This places C&D well above the minimum requirements and confirms that it has a heating content of meaningful value, and in the range of that for lignite or subbituminous coal.

The third qualifying test requires the unit to recover energy, which is a given for a developer of a new power generation plant or the conversion of an existing plant. Any existing unit that is currently being operated in a manner for power generation will qualify as a combustion unit that recovers energy. A new unit that is being designed would need to have the same characteristics as a boiler or process heater to meet this qualification.

The final qualifying test is if the fuel produces contaminants at levels comparable to or lower than those in traditional fuels. This is where the opportunity for using C&D as a biomass fuel becomes challenging.

The definition of “contaminants” is such that the C&D fuel, which has a multitude of pollutants by its very nature, is the same as virgin wood or “clean cellulosic biomass.” As defined by the EPA, a contaminant is defined as “all pollutants listed in Clean Air Act sections 112(b) or 129(a)(4).” Section 112(b) of the CAA defines the 187 pollutants that have been classified as hazardous air pollutants (HAPs) while Section 129(a)(4) defines nine pollutants consisting of criteria pollutants and HAPs. Likewise, virgin wood emissions will vary depending on what species of wood is used. The EPA has not provided guidance as to what baseline emissions for virgin wood will be used to set the emission standard. Using clean cellulosic biomass to set the air emissions contaminant loadings that are indistinguishable from virgin wood is an unreasonable burden for C&D waste.

Lost Opportunities

The EPA contends that no analysis that meets its expectations has yet been provided to show that C&D is of a quality on par with virgin wood—even after C&D waste has been processed and sorted to remove contaminated waste. Without being able to clear this last hurdle, C&D materials do not meet the nonhazardous secondary material requirements and retain their solid waste classification.

Additionally, partial use of C&D wastes as a biomass fuel is problematic, as using any percentage of solid waste in the combustion process will automatically reclassify a unit as a commercial and industrial solid waste incineration unit. As defined by the EPA, such unit redesignation occurs if “any commercial or industrial facility that combusts, or has combusted in the preceding six months, any solid waste.”

Classifying C&D as biomass would open up many new fuel sources that can provide valuable baseload renewable power generation; more utilities and industrial users would find the conversion of coal-fired steam generators to biomass plants attractive. Unfortunately, the EPA’s unreasonable emission rule interpretation effectively eliminates C&D fuels from any consideration as a future renewable fuel source.

Brandon Bell, PE ([email protected]) is a principal mechanical engineer with KBR Power and Industrial, Chicago.