Evolutionary Compliance

Even as the U.S. EPA is exploring reclassifying the emissions thresholds for ethanol facilities, technology providers and government agencies are offering options for reducing emissions. The landscape of environmental concerns continues to change.
By Dave Nilles | August 01, 2006
From Howard Gebhart's perspective, environmental compliance is largely a game of continuous adaptation. The Air Resource Specialists permitting expert has an intimate understanding of the regulatory changes that have impacted the U.S. ethanol industry over the past several years, and he's seen enough to know change is a constant in this business. State and federal regulatory agencies continue to assess and reinterpret the rules affecting environmental compliance, leading to changes in permitting for ethanol projects and existing plants.

As new environmental regulations come about, and the interpretation and enforcement of existing law keep evolving, new equipment, practices and strategies are being developed in response to—or anticipation of—resultant changes. Again this year, environmental compliance was a major topic at the 2006 FEW. From the look of U.S. EPA activity in the industry, it will continue to be a hot topic in the years ahead. Here's a look at some of the topics addressed at the conference.

EPA Considers Major Changes
Perhaps more of a historical casualty than anything else, ethanol plants have long been considered a "chemical processing plant" under EPA regulations. This classification has been disputed for years since an ethanol plant's existence is based on fermenting grain. Finally, the EPA is making moves that would recognize this difference.

A new rule drafted and currently under consideration by the EPA would exempt ethanol producers from the status of being a chemical processor. This change would increase the new source review major source threshold from 100 tons per year to 250 tons per year. Currently, major source criteria are 100 tons per year or more of emissions. The cap on hazardous air pollutant (HAP) emissions is 10 tons per year per individual chemical (of the possible 189) or 25 tons per year aggregate.

While the proposed rule would increase maximum emissions, the HAP emissions requirements would remain the same. Gebhart, who spoke during the FEW's June 22 session titled, "Environmental Compliance: Clearing the Air," said there is an important distinction with the possible rule change. Fugitive emissions would be excluded from the total emissions. Gebhart explains fugitive emissions as those that can't be reasonably captured (e.g., run through a vent or emissions device). An example is dust created by truck traffic, or a leaky valve. "It would significantly ease the burden of new source review if this rule change goes through," Gebhart said.

The public comment period for the proposal ended in May. The final ruling is scheduled for March 2007. Gebhart said the final outcome of the ruling is still uncertain, as is the exact timeline of implementation if it should pass. Once a federal EPA rule is implemented, each state would have to change its regulations for it to become effective, possibly stretching out the timeline to late 2007.

With current regulations, many proposed ethanol projects may want to seriously consider going above the minor synthetic limit of 100 tons, Gebhart said. Despite the longer permitting timeline, major source emitters tend to get less scrutiny than minor sources operating near the 100-ton threshold. "Staying as a minor source, in my opinion, isn't always the best choice," Gebhart said.

Gebhart also advised ethanol producers to stay abreast of water-related issues. Plants having more than 1 million gallons of on-site storage in close proximity to waterways are covered by the EPA's Spill Prevention, Control and Countermeasure program. Regulators have ruled that denatured ethanol is considered an oil and therefore requires a facility response plan. More information is available at www.epa.gov/oilspill/spcc.htm.

Technology Solutions
While changes may be on the horizon, most ethanol producers can't wait for a potential EPA emissions change to plan for financial success. Many producers continue to expand production levels while remaining in minor source status.

A Wisconsin producer considered moving from 40 MMgy to 52 MMgy. However, while easily meeting emissions compliance at 40 MMgy, the extra 12 MMgy put the plant uncomfortably near, or over, thresholds for oxides of nitrogen (NOx), carbon monoxide (CO) and volatile organic compounds (VOCs). It's not an uncommon problem for companies considering expansion.

In order to maintain its permitted status, the Wisconsin producer turned to Connecticut-based Combustion Components Associates (CCA), a 26-year-old company specializing in the engineering, design and manufacture of low-emission combustion systems and emissions control technologies for utility and industrial boilers.

CCA President Gifford Broderick, who also spoke during the June 22 "Environmental Compliance" session, used computational fluid dynamics (CFD) modeling to find a solution to the plant's issues. The plant was using a boiler to act as a thermal oxidizer, Broderick said. According to the CFD modeling, the boiler's mixing baffle wasn't working appropriately, leading to poor mixing of the dryer flue gas and flame. This resulted in insufficient destruction of carbon monoxide and VOCs. By installing a swirl mixer, CCA was able to sufficiently improve dryer gas mixing and increase the boiler's internal recirculation zone, promoting a more complete destruction of emissions.

Further burner modifications resulted in NOx reduction. CCA also increased the operating temperature of the unit by covering the boiler with refractory coating.

Preliminary test results at the 52 MMgy production level showed 31 tons per year of NOx and 65 tons per year of carbon monoxide, both well below the minor synthetic rates.
CCA also worked with a 40 MMgy Iowa facility with the objective of meeting environmental compliance while remaining a synthetic minor emitter. Facility officials wanted to utilize its existing thermal oxidizer with improvements based on CFD modeling.

The existing design limited their options. To accomplish the requirements, CCA designed a new thermal oxidizer burner without the use of an external flue gas recirculation burner. The CFD modeling showed the need to reduce the amount of dryer gas spin within the thermal oxidizer in order to mix the dryer effluent and burn carbon monoxide and VOCs.
Broderick said the results of a CCA-designed low NOx burner and thermal oxidizer had the final output of 38 tons per year of NOx and 42 tons per year of carbon monoxide. Again, both results kept the producer under the minor threshold maximum.

CCA has six similar systems in operation with similar performance results, Broderick said.

The RTO Option
Many options exist to keep ethanol producers in compliance. One of the more common choices has been, and continues to be, the regenerative thermal oxidizer (RTO).
There are several reasons RTOs are a popular—albeit expensive—solution for emissions abatement. They typically provide high heat recovery, oftentimes greater than 95 percent. Due to heat sink, systems are forgiving to process load variations. However, due to high heat recovery, systems can be sensitive to particulate if not applied correctly.

Robert Cloud, vice president of CECO Abatement, said that perhaps half of all ethanol plants use a thermal oxidizer coupled with a heat recovery steam generator. There are three major types of RTOs available.

"Even-chambered" systems (usually in two or four chambers) are reliable and utilize a butterfly or poppet valve, according to Cloud, also a speaker in the June 22 "Environmental Compliance" session. All internal components are insulated, so there are no thermal stress areas and no areas prone to corrosion due to wear or exposure to hot corrosive gases. The units typically have a small footprint and are designed for simple preventative maintenance. Plants using even-chamber systems are Ethanol2000, Pro-Corn, Utica Energy, Tall Corn Ethanol, Pine Lake Corn Processors and Dakota Ethanol, according to Cloud.

Traditional three- or five-chambered systems comprised the majority of large-scale RTOs installed in the United States over the past two decades, Cloud said. Also reliable systems, they have the advantage of slower moving butterfly valves. Greater thermal efficiencies can reportedly be attained with these systems due to design flexibility. According to Cloud, plants using odd-chambered RTOs include Frontier Ethanol, Horizon Ethanol, Otter Creek Ethanol, Pinnacle Ethanol, Prairie Ethanol, Northstar Ethanol, Voyager Ethanol, Michigan Ethanol, Iowa Ethanol, Great Plains Ethanol, Sioux River Ethanol, Missouri Ethanol and Ag Processing Inc.

A final RTO style is the "compact system," which some suppliers market as "rotary valve" or "valveless" RTOs. These RTOs use a single-actuating element and have a reduced manufacturing cost by reducing thermal insulation, Cloud said.

CHP Assistance
Combined heat and power (CHP) projects not only provide ethanol plants with heat and electricity, but can also help to reduce the environmental impact of power generation. That is the emphasis laid forth by the EPA's CHP Partnership.

Project Head Kim Crossman, a speaker in the FEW's June 22 session titled, "Energy Alternatives & Emissions Controls," said there is approximately 80 gigawatts of CHP in the United States. A virtually unlimited number of opportunities exist for ethanol plants to get in the game. Some projects already are utilizing CHP (see chart on page 117).
Crossman said CHP offers ethanol producers increased energy efficiency of ethanol production, energy cost savings, reliable on-site electricity and steam generation, improved competitiveness and reduced greenhouse gas emissions. It may also provide hedging against unstable energy costs. As of mid-June, 20 states had companies facing proposals to raise electricity rates between 10 percent and 16 percent, according to Crossman.

Crossman said there are several options for implementing CHP, most of which should be considered prior to construction in order to save money on building costs. Plants could implement a boiler/steam turbine, which has a relatively short payback but limited electricity capacity. If sized to meet electricity needs, a gas turbine produces additional steam. A gas turbine/supplemental turbine can be sized to meet both steam and electric loads. A biomass-fueled system offers less costly fuel, but is often capital intensive.

CHP can improve the "green" factor of ethanol production through integrated VOC destruction. A plant can produce power with steam from a thermal oxidizer and incorporate VOC destruction in a turbine or boiler system. Crossman said CHP may even go toward improving the lifecycle analysis of ethanol production.

Crossman said the EPA offers assistance for those interested in CHP projects. She said that 100 units of fuel in a CHP unit provide approximately the equivalent of 154 units of power purchased off the grid. "In the long term, what makes you a viable and profitable plant if there is an overabundance of plants?" Crossman said. "Controlling operation cost dramatically improves one of those value streams."

Quantifying Emissions
The number of solutions to emissions control requirements are as varied as the number of companies offering them. However, an important factor is actually determining the amount of emissions a plant will release. There are various methodologies used to quantify emissions, including stack testing, parametric monitoring data, EPA or industry emission factors, and emissions models.

The level of emissions controls at an ethanol facility depends on several variables, including the production size of the plant, location of attainment status, fuel choice and similar sources in that EPA region, according to Donald Pinto, a senior associate with Malcolm Pirnie Inc., and a presenter in the "Energy Alternatives & Emission Controls" session. For plants covered by prevention of significant deterioration, best available control technology (BACT) must be applied. There are several BACT options.

A fabric filter baghouse that can attain greater than 99 percent control efficiency can be used to control particulate matter. In addition, a mechanical collector or cyclone may be used upstream of a recuperative or regenerative thermal oxidizer to prevent fouling.

In order to treat sulfur dioxide, a plant can conduct flue gas desulfurization with wet or dry scrubbers. These typically apply to coal-fired boilers. Low NOx burners and flue gas recirculators can attain up to 50 percent NOx reduction. VOCs are also reduced through thermal oxidizers or catalytic oxidizers

Finally, Pinto said prospective ethanol producers should conduct air dispersion modeling. Air dispersion modeling is used to predict the dispersion of air pollutants to maintain National Ambient Air Quality Standards. "What you have to prove is emissions will not affect human health at the fence line or risk attainment status," Pinto said.

Ideally, air dispersion modeling should be conducted in cooperation with the plant designer, Pinto said. This allows for plant layout changes, should the regulatory agency require them.

Ethanol plants will continue to be under regulatory scrutiny following the installation of emissions controls. This is driven in part by regulators keeping close watch on sources with emissions close to major source thresholds, according to Gebhart. "Environmental compliance will continue to evolve," he said.

Dave Nilles is an Ethanol Producer Magazine staff writer. Reach him at dnilles@bbibiofuels.com or (701) 373-0636.