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Good Digestion

It’s been a bumpy road to full-scale adoption of anaerobic digestion technologies at ethanol plants
By Holly Jessen | December 12, 2011

Despite the promise of methane from anaerobic digestion technology, low natural gas rates and other factors have kept ethanol producers from jumping in with both feet. The race to be the first operational full-scale anaerobic digester co-located with an ethanol plant is being run between an existing ethanol plant in Kansas and an existing anaerobic digestor in Vegreville, Alberta. Western Plains Energy LLC, a 45 MMgy Oakely, Kan., ethanol plant, hopes to have a digester in operation by early next year. In Canada, ground was broken this fall for Growing Power Hairy Hill LP, a 40 MMly (approximately 10 MMgy) ethanol plant co-located with on-site digesters that have been in operation for about six years. Both facilities are utilizing Integrated bioRefinery technology, developed and trademarked by Himark, formerly Highmark Renewables.


In September, Western Plains Energy received a $15.6 million grant from the Kansas Department of Commerce, which it will use to help complete the estimated $35 to $40 million project. The methane produced will be used to completely refire the plant’s thermal oxidizer and boiler. “If we can improve the recipe, we may eventually make our own electricity, but our plans aren’t to sell back on the grid,” says CEO Steve McNinch.


On top of the digester, Western Plains Energy utilizes sorghum, or milo, as a feedstock in addition to corn. In October, the plant received $899,861 for production of ethanol from a renewable biomass, other than corn, through the USDA's Bioenergy Program for Advanced Biofuels program. By putting ethanol production from sorghum and power generation from an anaerobic digester together, the ethanol plant is hoping it will merit an advanced biofuel designation. “The digester gives us a chance to dramatically reduce our carbon footprint and hopefully qualify as an advanced biofuel for our ethanol at the end of the pathway analysis by the EPA,” McNinch says.


When considering anaerobic digestion, Western Plains Energy looked at several different factors. Although natural gas prices are currently low, the company doesn’t believe that will last forever, McNinch says. The company also considered overall cost of the project. “Currently the cost of capital is also extremely low,” he says, “so if you are going to enter into a construction phase, when basically the cost of construction is almost zero, now would be the time to do it.”


Plus, if Western Plains Energy is going to take advantage of the grant money it got from the state, the money has to be spent before the end of March. The money will come from unspent American Recovery and Reinvestment Act funds appropriated to the Kansas Corporation Commission’s Energy Division.


The factor that really tipped the scale in favor of the project, however, was technology advancements, McNinch tells EPM. Himark’s Integrated bioMass Utilization System, also trademarked, is unique in that it can be operated continually without sand and grit building up in the digester over time. The system also introduces heat to the digester. “So we will get gas quicker and the quality of the gas will be higher,” he says. “It’s just a much nicer technology.”


The main feedstock for the digester is manure from Pioneer Feeders, a 40,000-head feedlot about six miles from the ethanol plant. All the manure produced at the feedlot will be delivered to the ethanol plant by 25 trucks daily, McNinch says. The ethanol plant has an agreement with the feedlot to return all the organic fertilizer produced at the end of the digester process to the feedlot for the first year, followed by decreasing amounts after that. Eventually, the ethanol plant will market and sell the fertilizer itself.


The fertilizer produced during the digestion process is weed, seed and pathogen free. Unlike fresh manure, which has to be composted to knock down ammonia levels, the high-value fertilizer coming from a digester won’t cause water quality problems in runoff. It’s also highly concentrated. “For every five loads of manure that will go in the digesters, only one truckload of solids will come out,” he says.

Although McNinch declined to name all the feedstocks for the digester, he did say it would also utilize the plant’s thin stillage. Western Plains Energy currently uses a portion of its thin stillage for backset at the front end of the plant. Once the digester is online that water stream will be replaced by the recycled water coming out of the back end of the digester. 

Himark was established as a research and development company 11 years ago by brothers Bern and Mike Kotelko, owners of an Alberta feedlot. The digesters were originally built to address problems with smell, overloading of soil in the vicinity of the feedlot and the threat of possible water table contamination, says Evan Chrapko, co-CEO of Himark with his brother Shane Chrapko. After an expansion was completed in February, the digesters began processing half the daily output of manure at the co-located 36,000-head feedlot. Other feedstocks are used as well. This fall, with financing in place, the company moved forward with the final phase of the project—expanding the capacity of the digesters to 200 MMgy and building the 40 MMly ethanol plant. The goal is to feed the wet distillers grains to the cattle and use the manure from the feedlot in the digester to power the ethanol plant.

In addition to these two projects, Poet LLC, the largest U.S. ethanol producer, has a small-scale anaerobic digester in operation at its cellulosic ethanol pilot plant in Scotland, S.D., that converts corn cobs and light corn stover to ethanol. The company intends to locate a digester with its first commercial-scale cellulosic plant, Project Liberty, planned for Emmetsberg, Iowa. The feedstock for both digesters is lignin.

Digestion Disorder?
Unfortunately, there is more than one example of ethanol plants aiming for biogas production but missing the mark. United Ethanol LLC in Milton, Wis., had planned to install a digester to displace 25 percent of the plant’s natural gas use after it received a $2.25 million low-interest loan from Wisconsin’s Energy Program last October. But, construction never actually began. “Construction of the anaerobic digester project for United Ethanol LLC has been put on hold pending further improvements in the economic model and satisfaction of proposed project impacts to overall United Ethanol operations,” said Dori Lichty, communications, media, and public relations manager.

California ethanol plant, Calgren Renewable Fuels LLC, struggled to get local approval for an anaerobic digester after objections by the ethanol plant’s neighbors about odor, impact to air and water quality and possible contamination by pathogens—things digesters actually improve or prevent. The project was put on hold in June, though by November it was tentatively moving forward again pending approval by the county planning commission. In response to those concerns, changes were made to the proposed project, including no trucking of manure, says Daryl Maas, project manager. Instead, it will all be delivered via a pipeline from a nearby dairy. In addition, a pasteurization step has been added at the back end of the digester. The 58 MMgy plant was awarded a $4.68 million matching grant from the California Energy Commission to build the $10 million project.

There are two examples of project failures in 2007, though not because the digesters weren’t working. The Renova Energy Idaho LLC ethanol plant in Heyburn, Idaho, was never completed—also sidelining its digester, although that part of the project was 95 percent complete. The E3 Biofuels plant, now working toward restarting in 2012 as AltEn LLC, never reached its full potential before a boiler explosion put the 23 MMgy ethanol plant down a path to bankruptcy. In this case, the digester technology was already in place and functioned above expected levels in testing.  

Convincing ethanol plants to move forward with anaerobic digestion is a slow and heartbreaking process, according to David Rein, a process engineer with Rein & Associates of Moorhead, Minn. Rein spoke on the topic at a conference put on by the Energy & Environmental Research Center in July at the University of North Dakota. The company has been conducting bench and pilot studies of biogas production from thin stillage since 2006 and completed feasibility studies that resulted in three separate grant awards to ethanol plants, which ranged from $1.6 million to $3.2 million. All three grants were through the USDA Repowering Assistance Program, which offers biorefineries funding to use renewable biomass as a replacement fuel source for process heat or power. The funding, which would have provided for only a fraction of the full project cost, was ultimately turned down by all three ethanol plants, Rein said at the EERC conference.

Feedstock Source
Co-locating digesters with ethanol plants for power generation isn’t the only model out there. Houston, Texas-based Natural Chem Group LLC wants to operate digesters utilizing syrup from ethanol production as well as other feedstocks, says CEO Robert Salazar. Looking to the future, the company is working to build 10 digesters, including three adjacent to ethanol production facilities in the Texas Panhandle, California and Wisconsin. The goal is to provide biomethane power to California, or, more likely, selling further purified compressed natural gas or liquid natural gas into the transportation fuels market.

Natural Chem already owns the digester in Heyburn, located next to the failed Renova Energy Idaho LLC ethanol plant. The digester’s main feedstock will be syrup from nearby ethanol plants as well as milk, cheese and potato waste from area industries. The original plan was to produce raw biogas, which is 60 percent methane, but Natural Chem is working on the financing to expand the output and purify it to 99 percent methane, he says. Once completed, the digester will produce about 2 million MM Btu yearly of pipeline quality biomethane, which will likely be converted onsite to compressed natural gas and sold into the Idaho transportation fuels market. “We would expect that by the end of the first quarter of 2012 we will go ahead and complete the financing for the expansion and other improvements,” Salazar says. “We should be online within about 10 months.” Natural Chem also plans to develop about 20 compressed natural gas fueling stations in Idaho, Oregon and Washington and will supply the product to fleets and school districts.

The company has been in existence since 1992 and spent a lot of time in research and development, working on creating new revenue streams from low value byproducts such as syrup and crude glycerin. Its mission is to work to create new applications for state-of-the art, existing technologies. “There’s no rocket science in what Natural Chem does,” Salazar tells EPM, adding that the company does feel it fits the definition for being innovative. Natural Chem expects to have all the necessary agreements in place to buy its raw materials and sell compressed natural gas by the first quarter of the year. The company is using a project finance model having multiyear contracts in place before closing on any financing. “We’re just patiently, step by step, getting all the pieces in place,” he says.

Author: Holly Jessen
Associate Editor, Ethanol Producer Magazine
(701) 738-4946
hjessen@bbiinternational.com

 

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