Ethanol Producers Embrace Biomass Power and Thermal

With an eye toward both energy costs and environmental concerns, ethanol producers are embarking on innovative energy projects.
By Holly Jessen | April 29, 2011

Although natural gas is king of power generation at ethanol plants, there’s increasing interest in renewable energy technologies that could help ethanol plants someday produce a domestically grown fuel without using fossil fuels. A handful ethanol plants, for example, are working to reduce fossil fuel use through innovation. Whether producing power from a biomass boiler, gasifier or anaerobic digester, or installing heat exchangers to utilize waste heat, it’s all about reducing the amount of natural gas used per gallon of ethanol produced.

Second only to feedstock costs, energy costs can have a major impact on an ethanol plant’s bottom line. In 2010, energy expenses made up 9 percent of  the total costs at an ethanol plant, including electricity, according to Christianson & Associates in its Biofuels Benchmarking Annual Report. Energy can also be a volatile expense for ethanol producers. In 2009-’10, the industry average cost for energy ranged from 15 to 21 cents per gallon of ethanol produced, according to Christianson & Associates. Energy prices were an even bigger piece of the pie in 2008, when natural gas prices dramatically shot up. According to U.S. Energy Information Administration records, commercial natural gas prices hit $11.99 per million Btu (MMBtu) in 2008, before dropping to $9.66 per MMBtu in 2009 and $9.04 per MMBtu last year. Natural gas prices aren’t likely to get anywhere near the highs of 2008 for decades, according to the EIA. The agency predicts a slight increase in prices this year followed by a slow but fairly steady decline until 2014. After that, natural gas prices are expected to slowly climb, hitting the $10 mark in 2027 and reaching $11.10 per MMBtu by 2035.

Several ethanol producers are skeptical, however. The CEO of North West Bio-Energy Ltd. in Unity, Saskatchewan, is preparing for higher-than-expected prices. “Our impression of the world is that, over time, natural gas prices will go up, the way all energy prices are going up,” says Jason Skinner. Vincent Copa, a process engineer at Minnesota’s Chippewa Valley Ethanol Co. LLLP, also thinks it’s possible that natural gas prices could climb higher than predicted. Since natural gas is a relatively inexpensive fuel today, it’s likely to be tapped by more and more users in the future. That demand would push the price up.

Then there are the environmental motivations for pursuing alternative forms of energy for process heat at an ethanol plant. In the future, plants that install advanced technologies may have an edge, depending on the direction the U.S. goes with its energy policies. United Ethanol LLC in Milton, Wis., has its eye on the possibility that the U.S. EPA could someday qualify its fuel as an advanced biofuel because the corn-to-ethanol plant installed new, more efficient technologies and reduced its greenhouse gas emissions, says Alan Jentz, vice president of grain operations and risk management.
More near term, some ethanol producers are looking to California, where low-carbon ethanol could command a premium price. That state is moving toward sustainability requirements that would push for advanced technologies, such as biomass power generation, and where California goes, other states are likely to follow, Copa says.

On the other hand, if there aren’t economic reasons for transitioning an ethanol plant to more environmentally friendly technologies, ethanol producers won’t be able to do it simply because it’s green. An ethanol plant is a business and, more than the color green, its owners are concerned more with the black and red on financial reports. “Our shareholders care about the bottom line and if being green is not going to pay, we can’t afford to make that kind of a [public relations] move,” Copa says.
Power in Chaff

North West Bio-Energy, a 25 MMly (6.6 MMgy) ethanol plant, is well-situated for feedstock delivery. It is co-located with the company’s grain terminal, which handles about 425,000 metric tons of commodities annually—including the feed wheat it uses to make ethanol.

Another co-location perk is a ready feedstock for the ethanol plant’s newly installed biomass boiler. Chaff, previously a problem for the grain terminal, will be burned to replace some or all of its natural gas use, depending on prices. The company spent $1.5 million, without the aid of grants or other assistance, to install a firebox unit with a reciprocating grate to burn biomass for power generation, Skinner says.

With natural gas prices relatively low right now, the company isn’t in a big rush to get the project wrapped up, he says. The boiler installation took place over about two years and likely won’t be ready for full use until sometime this summer. “We’re setting this system up so, if we see times when natural gas prices go up quite a bit, then we would be able to use biomass as an alternative fuel,” he says.

In late March, North West Bio-Energy was paying about $3.50 per gigajoule (GJ) for natural gas—but the company has seen prices as high as $12 per GJ in the past. The cost of chaff is estimated at $2.50 per GJ, which could mean some real savings for the plant if natural gas prices increase, something the company fully expects to happen. “The neat part about the biomass that’s available in our part of the world is that the price tends not to go up to the same extent—so it’s a more stable cost,” he says.

In Canada, grain is cleaned before it is exported. The company pays the farmer for the grain, with the weight of the dockage—weed seeds, broken kernels and chaff—deducted, although not always. “Currently, we pay the farmer $10 per metric ton for the dockage because we are able to sell things like broken seeds to offset this cost,” he says. “We use the payment for dockage as a competitive tool to buy grain.” Unlike broken seeds, chaff has little to no value today. A nearby feed mill sometimes buys the chaff, but in the summer months there’s no market at all. In addition, it’s so light it’s difficult to transport. “It’s a problem getting rid of the material,” Skinner says. The solution is the biomass boiler. The company will actually start encouraging farmers to leave more dockage in their grain by increasing payments, he says. The dust and chaff collected from wheat, barley, canola and peas can then be used as a fuel to offset natural gas use.

This is going to require a mindset change for farmers, who don’t want to pay freight to have it hauled to the grain terminal, for one. “As a rule, farmers have grown up wanting the least amount of chaff in the grain, so they try to keep it very clean,” he says. “But we’re trying to do the opposite thing.” If natural gas prices go up, however, burning chaff in the biomass boiler won’t just save the ethanol plant money. “We’re a shareholder-owned company so a lot of the farmers in our region own our company,” he says. “Being able to buy their chaff or their dockage from them when they bring it to the elevator would give them another revenue stream coming off their land.” The company estimates that if farmers leave between 5 and 7 percent dockage in their grain, it would provide enough chaff to power the ethanol plant all year. In that scenario the company would increase its dockage payments to $50 a metric ton. “That’s a real win-win for us and our shareholder farmer customers,” he says.
The plant will have the flexibility to switch between biomass and natural gas, depending on availability and price. Over time, Skinner believes the biomass boiler will pay for itself. And, although Canada is further behind than the U.S. on the push to make ethanol plants more environmentally friendly, he believes the project will also benefit the plant in that arena.

It’s a Gas

Although the gasifier at CVEC hasn’t operated for about a year, that doesn’t mean the Benson, Minn., ethanol plant has abandoned the project. In fact, the company is hard at work obtaining Minnesota Pollution Control Agency permits for additional types of biomass to use in the gasifier, should natural gas prices go up and it becomes economical again, Copa says.

CVEC’s gasifier was completed in the spring of 2008, in the midst of the high natural gas prices that prompted the project. It can provide 90 percent of the ethanol plant’s power needs by burning primarily waste wood chips and corncobs. A gasifier thermally breaks down dry biomass at the molecular level in temperatures greater than 1,500 degrees, producing carbon monoxide and hydrogen, Copa explains. An air-blown system, like the one at CVEC, produces gas containing 150 Btu per cubic foot (cu ft) because the gas is diluted with nitrogen from the air. In comparison, an oxygen-blown system produces gas with about 600 Btu per cu ft. Pipeline-quality natural gas has an energy content of 1,000 Btu per cu ft. In an aerobic digester, bacteria breaks down wet biomass emitting methane (natural gas), CO2 and water, and has an energy content of 600 Btu per cu ft.CVEC’s gasifier can use a variety of feedstocks, such as sunflower hulls, as experimental feedstocks, as long as they are used in limited quantities for short periods of time, he said. The company received permit approval for wood chips for normal production use in its gasifier when it was constructed, and is now working through the permitting process to use corncobs and glycerin from biodiesel production.

As part of the permitting process, the company has conducted emissions testing for wood chips and corncobs. Both feedstocks have acceptable emissions characteristics, much lower than the emissions from coal and similar to or lower than natural gas emissions. Carbon monoxide or other volatile organic compound emissions are slightly lower, and dioxins, furans and mercury—the sort of emissions that really scare pollution control agencies—are virtually nondetectable. On the other hand, as expected, levels of nitrogen oxides (NOx) were slightly higher than NOx emissions from natural gas. In the future, Copa hopes the MPCA won’t require emissions testing for each new type of biomass. “We were able to show that the expected emissions characteristics are about the same for each biomass that we tested,” he says. “Hopefully, after we test a couple more types of biomass they’ll get the hint.”

Carbon is a big buzz word right now. CVEC’s gasifier participates in the carbon cycle by combusting carbon that living plants pulled from the air, unlike natural gas. “That carbon has been sequestered in the ground for millions of years, so burning it is adding a net addition to what’s already in the atmosphere,” Copa says.

As much as CVEC is convinced that the gasifier is environmentally the right decision, the company won’t run it again unless natural gas prices go up enough to make it economical. At current prices, CVEC could find reliable supplies of biomass at about $6.50 per MMBtu, or $60 to $65 a ton. With natural gas prices today, biomass would be competitive at about $5 MMBtu, but just barely, he says. At that rate, the company would have to watch its biomass prices carefully to make even a tiny dent in the payoff of the investment.

These barriers won’t completely stop CVEC from working on projects such as the gasifier, however. The company, which is also known for producing alcohol that goes into Shakers Vodka and industrial uses, is always working on innovative things, Copa says. In the past there have been complaints that some side projects were more effort than they were worth for the small amount of income they brought the company. However, it was those projects that brought CVEC through difficult financial times in 2008, when other ethanol plants didn’t make it, he adds.

Good Digestion

At United Ethanol, installing an anaerobic digester is about reducing the plant’s carbon footprint while, at the same time, increasing ethanol production through increased efficiency. “It’s a way to extract more value out of our inputs, the corn, and make the plant greener and more energy efficient,” says Dave Cramer, president and CEO of United Ethanol.

The 50 MMgy year ethanol plant planned to break ground on the $6.75 million project in April and hopes to have it completed by the end of this year, Jentz says. To assist in installing the digester, the company received a $2.25 million low-interest loan from Wisconsin’s Energy Program, which is funded through the American Recovery and Reinvestment Act of 2009. The air permit for the project was approved in early March.

United Ethanol is working with Eisenmann Corp., which will install its Biogas-TS system at the plant. It will utilize a portion of the plant’s thin stillage to create methane in the digester and ultimately reduce the plant’s natural gas use by up to 25 percent, Jentz says. Current estimates show the project should have about a four-year payback. The major elements of the system include three 1 million-gallon digesters and a biogas-fired boiler to augment the two existing natural gas-fired boilers, says Howard Hohl, sales manager for Eisenmann.

Using the thin stillage for power generation will have several efficiency perks for United Ethanol. Primarily, it will reduce the amount of nonfermentables produced at the plant, help cut back on evaporator bottlenecks and alleviate water balance issues. Thin stillage contains fine solids, proteins and other organic materials that are digestible, Hohl says, but not fermentable. By using it for power generation, the overall organic load of the plant’s backset will be reduced by 95 percent. Reducing nonfermentables will, in turn, reduce the load on the driers, which means reduced energy requirements for producing dried distillers grains, Jentz adds. United Ethanol also recently added corn-oil extraction at the plant, another technology that helps reduce energy use.

Some anaerobic digesters utilize thick stillage or syrup, which contains from 32 to 35 percent solids, Hohl adds. Thin stillage, which United Ethanol will use, contains only about 10 percent solids. “Either one of those methods could work,” he says. “We will potentially augment the digester with syrup to maintain our solids at a certain level, to ensure that we get the right amount of biogas generation.” Using thick stillage or syrup for biogas production results in additional coproducts and waste streams. The solids, or sludge, produced must be disposed of, recycled or sold into the fertilizer market. Biogas production from thin stillage, however, results in a closed-loop system with no blowdown or loss of solids. “It all goes back to the plant,” Hohl says.

Eisenmann can guarantee two things about the anaerobic digester: First, it will reduce natural gas use and the plant’s carbon footprint. Second, the company expects the ethanol plant will see a 2 to 2.5 percent increase in ethanol production, because the system will reduce recycling of nonfermentable solids.
There are likely to be other benefits to the system as well, but since this will be the first full-scale installation of an anaerobic digester for Eisenmann, the company isn’t revealing details yet. “There are a number of other soft benefits that we expect United will gain with this installation and we’ll share those with you as the project progresses,” Hohl says.

Waste Not

Biomass utilization isn’t the only strategy to reduce natural gas consumption at an ethanol plant. Ace Ethanol LLC and CVEC are two examples of ethanol plants installing heat exchange equipment for waste heat recovery. By utilizing waste heat from the regenerative thermal oxidizer (RTO) for process heat and steam, heat exchange equipment can help lower the amount of natural gas used per gallon of ethanol produced, says Neal Kemmet, general manager of Ace.

Ace received a $270,000 grant from Focus on Energy, Wisconsin’s energy efficiency and renewable energy initiative, plus a $595,000 low-interest loan from Wisconsin’s Department of Commerce Energy Program. CVEC received a $500,000 low-interest loan from a similar program in Minnesota. Both ethanol plants were awarded the money in 2010 and plan to complete the installation projects this spring.

An RTO is a pollution control device that cleans the emissions from grain drying by heating it up from about 300 to 1,650 degrees, Kemmet explains. Although most of that heat is reused in the system, the RTO still exhausts vapor at 350 degrees. Installing heat exchangers will capture that heat.

“There’s a lot of hot, moist air, so we’re going to cool that hot, moist air from 350 degrees down to about 220 degrees,” he says. The reclaimed heat will be used for process heat, reducing the amount of natural gas needed to power the plant. Ace estimates the $1 million heat exchange project will reduce its natural gas use by 3.5 percent. “Even with the reduced natural gas cost, the project is still expected to have a payback that is right about three years,” he says.

CVEC is still adding up the total cost of its project, Copa says, but he calls it a multi-million dollar project with an acceptable payback of two to three years.

Author:Holly Jessen
Associate Editor, Ethanol Producer Magazine
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