Alternative Energy Sources and Air Permitting Considerations for New Ethanol Plants

By T. Donald Pinto | June 01, 2006
  • WARNING: Resizehelper couldn't find requeted file: /datadrive/websites/ethanolproducer.com/app/webroot/uploads/posts/magazine/412-1292253880.jpg
  • WARNING: Resizehelper couldn't find requeted file: /datadrive/websites/ethanolproducer.com/app/webroot/uploads/posts/magazine/413-1292253880.jpg
After corn, energy is the second highest operating cost faced by most ethanol plants. The cost breakdown for a typical 40 MMgy ethanol plant is illustrated in Figure 1. This dynamic emphasizes why it is critical that any proposed new ethanol plant give careful consideration to its energy choices if it is to be successful. This is particularly true in light of the forecasts that the higher energy prices we have experienced over the last several years will continue.

The largest sources of energy consumption in a typical corn dry-mill ethanol plant are the boilers and grain dryers. The boilers are used to generate process steam for heat; the dryers are used for drying distillers grains. Natural gas is the most common fuel source for these process units with coal used to a lesser extent. It is estimated that over 85 percent of operating U.S. ethanol plants use natural gas. With the escalating costs of natural gas, many new plants are looking to coal and alternate energy sources.

Biomass is an emerging fuel source being explored for heat generation in ethanol production. Fuels in this category include agricultural and forest wastes, DDGS, and municipal solid waste. To increase energy efficiency, combined heat and power (CHP) systems are also being proposed at new ethanol plants. A common CHP system entails burning the fuel feedstock to produce steam. The steam drives a turbine connected to a generator that converts the power into electricity for use in the plant.

In tandem with fuel choices, a proposed new ethanol plant must also consider the air permitting requirements that will be applicable to the plant. In nearly all states, a new ethanol plant cannot begin construction without first obtaining an air permit from the U.S. EPA and/or delegated state regulatory agencies. The agency will specify in the air permit what the allowable criteria pollutant and hazardous air pollutant (HAP) emission from the plant are, as well as the pollution control equipment that the plant will be required to operate to meet these emission limits.

Most proposed ethanol plants have fast-track project schedules whereby initiating plant construction and getting sellable ethanol to the market as early as possible is key. Accordingly, it is important to understand at the onset of the planning process the inter-relationships between plant location, size (in MMgy), fuel choice and regulatory requirements. Issues to consider include:

Location: The attainment status with respect to the National Ambient Air Quality Standards of the area where the plant is proposed to be located should be considered. The criteria pollutant(s), for which the area is designated "non-attainment" (if applicable) and the degree of non-attainment, will influence the proposed plant size, fuel source and control equipment necessary. For example, if an area is designated non-attainment for sulfur dioxide, natural gas may be the fuel of choice rather than coal (because of the negligible sulfur content of natural gas as compared to coal). Likewise, if an area is designated "severe non-attainment" for ozone, it may be impractical or infeasible to incorporate grain dryers in the plant design regardless of fuel choice because of emission of volatile organic compounds and nitrogen oxides from the process (both being precursors to ozone formation).

Fuel Availability: As process heat is vital to the ethanol production process, it is critical that the plant have a reliable, uninterruptible fuel source. Because of rising costs and unpredictable supplies, many existing natural gas-fired plants are considering moving to coal. Biomass as a fuel source is generally only practical if the proposed plant is in proximity to the lumber mill, paper mill or landfill providing the biomass feedstock. Today, most large ethanol plants—especially those that are 80 MMgy and larger—are being designed to operate on more than one fuel type (for example coal or biomass with natural gas as a backup energy feedstock).

Capital and Construction Costs: Fuels like coal and biomass, while cheaper in unit cost than natural gas, are more expensive in terms of the infrastructure required to handle the fuel. Natural gas can typically be fed into the plant from the main utility supply line without additional handling or treatment. This is not the case with coal or biomass fuels, which can entail large outdoor or indoor storage piles of the fuel feedstock; equipment to crush, grind and screen the feedstock to a finer, more-combustible grade; and conveyors to feed the finer material into the boiler.

Control Equipment Costs: Typically, as the plant capacity increases, so does its emissions of criteria pollutants and HAPs, which will necessitate the use of more complex and expensive controls to maintain emissions below regulatory requirements. Presented in Table 1 is a summary of control equipment (by pollutant) commonly used at ethanol plants. With natural gas, the focus is typically on controlling nitrogen oxide emissions. With coal, control of particulate matter emissions from coal-crushing and conveying operations, and sulfur dioxide emissions from coal combustion are also concerns. Consideration should be given to the operational costs to run the control equipment, including as appropriate, costs associated with treatment chemicals, waste residue handling and routine maintenance. For example, with coal combustion, sulfur dioxide emissions are often treated with a wet or dry lime scrubber. In addition, a non-combustible residue, such as fly ash, remains when coal is burned. Both the fly ash and the scrubber effluent (gypsum) have to be managed on- or off-site at an additional cost.

Air Permit Application Preparation: With regard to the duration required to prepare the air permit application, selecting a fuel source with a proven track record and widespread use in the industry is preferred. As natural gas is the most common fuel choice at currently operating ethanol plants, industry designs for natural gas-fired boilers and dryers are arguably somewhat standardized, as is the control equipment required. This means that information on many of the elements required in the air permit application will be available early in the design process, thus enabling the application to be submitted promptly to the state regulatory agency. In addition, much of the data submitted in the application will have been derived (and thereby field-verified) from actual installations at existing plants. This will reduce the danger that the proposed plant, once operational, fails to meet the performance limits related to emissions and controls specified in its operating permit. The consequences of such failure can include penalties and restarting the permitting process with the regulatory agency, effectively delaying the plant's targeted schedule for full production start-up. Accordingly, one should allow for a longer lead time to prepare the air permit application if natural gas is not the primary fuel chosen for the plant.

Air Permit Issuance: Most state regulatory agencies where existing ethanol plants are located likely have a template established as a starting point for writing the air permit based on the type of fuel used. The template would include the permit terms addressing production scenarios, pollutant emissions, control equipment operation, as well as routine monitoring, record keeping and reporting. Having such a template should expedite the regulatory agency's writing of the permit as opposed to its personnel having to conduct research and write the permit from scratch for a fuel type with which they have little experience. It is therefore advisable to discuss plant fuel choices with the agency early in the planning process to obtain their feedback and give them a head start at doing the research necessary for compiling the terms in the permit.

Properly understanding and managing the interplay between these elements can greatly influence how successful a project is in all phases of planning, design, construction and operation.

T. Donald Pinto is a senior associate at Malcolm Pirnie Inc.'s Columbus, Ohio office. He can be reached at dpinto@pirnie.com or (614) 430.2665.