September 12, 2007 | General

Digester Developer Taps Natural Gas Markets

BioCycle September 2007, Vol. 48, No. 9, p. 40
Huckabay Ridge project in Stephensville, Texas will process manure from up to 10,000 cows to produce 2 million cfm/day of natural gas with an energy content of 650,000 million BTU/year.
Nora Goldstein

IN the late 1990s, Dan Eastman and two colleagues were researching business opportunities in the renewable energy industry. They were looking for a commercially viable technology that could take renewable energy from an experimental phase to a solid business investment. In 1999, Eastman and his partners founded Microgy, Inc., with its base in Wisconsin. The company licensed the Xergi anaerobic digester technology from Denmark. Xergi was among the pioneers in codigestion – anchoring a project with livestock manure but processing other waste streams to maximize energy output.
“Xergi’s approach is to incorporate the total community resource of biowaste and aggregate it in the best way it can,” says Eastman, who recently left Microgy. “When we licensed the technology, we took that model to the U.S. The American market hadn’t looked at local community biowaste streams as a resource. Our approach was to site the digester on a dairy farm and then look at the waste streams in that community to maximize digester output.”
In 2001, Microgy, Inc. was acquired by Environmental Power Corporation (EPC) of Portsmouth, New Hampshire, a publicly-traded energy development company (AMEX:EPG). Over the past 25 years, EPC has developed and/or owned and operated hydroelectric plants, municipal waste projects, coal-fired generating facilities and other energy recovery facilities. Microgy is currently the only operating subsidiary, and focuses on production of clean, renewable gas from agriculture and food industry wastes while simultaneously creating significant quantities of marketable carbon offset credits – which create another revenue stream from its project investments.
Initial digester installations were at dairies in Wisconsin, where Microgy designed, financed and built the projects for the farms. As part of the arrangement, Microgy operates the projects under a long-term arrangement and manages the sale of the biogas produced to the Dairyland Power Cooperative, a generation and transmission cooperative supplying power to four states in the Midwest. The origin of the projects was really a collaboration of Microgy, the farm owners and Dairyland, who was looking to add to its baseload capacity and renewable energy portfolio. Microgy and Dairyland identified a number of possible project locations, including the Five Star Dairy in Elk Mound, Wisconsin, with 900 milking cows. Five Star was interested in a better manure management system and intrigued by the additional benefits that an anaerobic digester project would provide.
Microgy installed a 750,000-gallon anaerobic digester tank, a smaller substrate tank, solids separation equipment, a 775kw Waukesha generator and the control systems to manage and monitor the operations. The system, which started up in 2005, generates about 64,000 million BTU (mmbtu)/year of biogas that is converted to power for Dairyland, along with 8,000 cubic yards of solids used as animal bedding and fertilizer. Five Star owns the project and uses revenue from biogas sales to pay the note owed to Microgy.
The Xergi anaerobic digester system is comprised of one or more above ground tanks that operate in the thermophilic temperature range (typically from 120° to 135°F) plus an additional tank for substrate storage. Digester tank sizes range based on the size of the operation. Computer controls monitor temperature and the chemistry in the tank (e.g., levels of volatile organics, amino acids) on a real-time basis to ensure addition of various feedstocks does not negatively impact the microbial balance. “This level of monitoring makes it feasible to process other waste streams from the community with manure,” says Mike Newman, Vice President of Operations for Microgy. “These operating efficiencies make it possible to digest a higher percent of the material in the tank at any given time.”
Average retention time in the complete mix digester is 21 days; materials are injected about 24 times/day. Solids content going into the digester is eight to 10 percent. Waste streams not in that range are slurried (with water) prior to being fed into the digesters. Fats, oils and grease (FOG) brought to the facilities are unloaded into a tank and heated with waste heat from the digester to keep it at the right viscosity to be added to the tanks. “This stream is sampled as it goes into the main digester to be sure it has the right chemical composition,” explains Newman. “Mixers in the digester homogenize these materials in the tank.”
Off-farm wastes boost biogas output while stabilizing production for use as an energy resource. A wide variety of materials can be used in a codigestion system including food waste, spoiled agricultural products and even crops. “We source materials for our codigestion projects based on their content of proteins, carbohydrates and fats,” he adds. “We have used brewery waste, spoiled soybean oil and turkey fat among other things.”
While most of its projects to date are at large-scale dairy operations – thus liquid manure is the primary feedstock – Microgy plans to install a digester facility at a Swift & Co. meat packing plant in Nebraska. Manure from the animals on-site will be mixed with paunch and other animal slaughtering by-products and fed into a multiple tank digester system. “We are looking at a daily production rate of about 235 to 250 million BTUs of biogas that will make up about one-quarter of the daily natural gas requirements at the meat packing plant,” explains Brian Bzdawka, Vice-President of Business Development at Microgy. “The biogas will be scrubbed of hydrogen sulfide, then fired in the plant’s boiler system.” The facility is expected to be on line in 2008.
The initial projects in Wisconsin utilize reciprocating gas engines (gen sets) to convert biogas to electricity to feed into the grid. The gen sets convert about 30 percent of the biogas into electricity. Over time, Microgy has evaluated options to maximize utilization of the biogas produced. “In terms of conversion efficiency, an engine or simple cycle gas turbine converts biogas to electricity with an efficiency of 30 to 40 percent,” explains Mark Hall, Senior Vice President of Environmental Power. “A combined cycle project that captures the waste heat to produce additional power can achieve 55 percent efficiency and combined heat and power projects that produce electricity and thermal energy like steam or hot water can achieve 80 percent efficiency. If the biogas can be delivered to projects where the conversion efficiencies are higher, everyone gets more value. That is why we introduced Renewable Natural Gas (RNG).”
According to Hall, RNG is biogas cleaned up to pipeline quality standards which can then be transported through the existing natural gas pipeline system. “By putting it into the pipeline, we can sell it in the highest price market, taking advantage of moving it to a place where the gas is more valuable,” he explains.
Hall adds that with on-site electricity generation, there can be challenges related to interconnections with local utilities and volatility with the price paid per kilowatt hour. “Markets for electricity are much more locational and it is much less liquid of a market to participate in,” he says. “If you can do anaerobic digestion in a high cost power market with the utility interested in having you there, it can be great. But a lower cost market with a reluctant utility can make it difficult to make projects work.”
Microgy has made its debut into the natural gas marketplace with a large-scale anaerobic digestion plant in Stephensville, Texas, which is in the heart of the Bosque River Watershed that has been severely impaired by excess nutrients. The company installed eight 916,000-gallon digester tanks, with capacity to process manure from up to 10,000 cows. The facility is located at a dairy manure composting plant – Producers Compost, Inc. – that processes manure from over 20,000 cows in the area. Producers Compost, along with other manure management operations in that region, have been able to tap into financial incentives established a number of years ago by the Texas Commission on Environmental Quality to move manure out of the watershed to be managed.
Known as the Huckabay Ridge project, the facility is expected to produce about 2 million cfm/day of natural gas with an energy content of 650,000 mmbtu/year (equivalent to approximately 12,700 gallons/day of heating oil). Manure delivered to the site is drier than what Microgy typically loads into its digesters. Therefore water needs to be added to reach the desired slurry form of about eight to 10 percent solids. According to Environmental Power, the project has cost $18.4 million to date although future projects of similar size should cost less.
The Huckabay Ridge project started operating this past spring, and has been gradually ramping up its natural gas production. Microgy installed commercially available gas clean up and compression equipment acquired from a third party supplier. The company experienced mechanical problems with the equipment provided. “This is an established technology, and we just had difficulties with the particular set of equipment delivered,” says Hall. “We will be more sensitive going forward in terms of the specifications that fit our setting best. Biogas from digesters is not complicated to clean up and it is much more consistent in its quality than landfill gas.”
Solids from the digester are composted on-site. Separated liquids were going to be land applied on neighboring farm fields. There were delays in acquiring the permit to apply the effluent, so Microgy had to use available storage capacity for the effluent. Heavy rains in the spring filled the storage capacity, so operators decided to utilize some of the stored effluent to slurry the manure ahead of digestion. “That turned out to be problematic for the chemical balance in the digesters,” says Newman “The bacteria didn’t respond well and as a result, biogas production dropped. Once we realized what was happening, we stopped the process of recycling effluent. But we had to reseed some of the digesters to achieve the gas production quantities we need for the pipeline.”
As of mid-August, three of the digesters are fully operational; the remaining five are expected to be “healthy” over the next six to eight weeks, enabling Microgy to start commercial-scale operations by mid-October. Until the land application permit is received, Microgy has made arrangements to truck effluent out of the watershed for reuse elsewhere if necessary.
Composting time for the digested manure solids is expected to be reduced by almost half – from roughly six months to three months. Microgy works with haulers bringing manure to the Producers Compost site to ensure the material it is taking for digestion has a minimal amount of sand and rocks. “If a load is not in the best condition for the digesters, we will direct it to the windrows,” says Newman.
Similar to its other projects, biowaste feedstocks are being tipped at Huckabay Ridge for digestion. These include glycerin from a biodiesel plant and fats, oils and grease. “We look for the ‘waste of the waste,'” says Hall. “We’ll take the organic wastes that no one else can use.”
Microgy has a contract with the Lower Colorado River Authority (LCRA) to purchase the natural gas that is put into the pipeline. The initial agreement is for 18 months to accommodate start-up of Huckabay Ridge and its initial commercial operations. It expects to sign a long-term purchase agreement to replace the existing contract when the initial one expires. The natural gas industry was deregulated over 10 years ago, so getting into this business is fairly straightforward. Companies that own the pipelines make their profit on transporting the gas, but cannot buy or sell gas themselves. In the case of Huckabay Ridge, the LCRA pays for transport of the gas through the pipeline. Microgy says that RNG projects are typically breakeven at natural gas prices between $4.50 and $5.50/mmbtu, depending on various site-specific factors. Long-term natural gas prices range between $7 to $8.50/mmbtu.
The quality of the gas produced at Huckabay Ridge was analyzed by an independent laboratory, then shared with the pipeline transmission company. “The gas quality met or exceeded natural gas pulled out of the land,” says Newman.
The capital required to clean gas to pipeline standards is significant, which can make the economics challenging for smaller biogas producers. Essentially, explains Hall, there are two considerations when it comes to project economics. “The gas needs to be compressed to a pressure that is higher than the pressure in the pipeline in order for it to get into the line. There is a set distance that the gas can be pushed with one compressor before another one would have to be installed to push it along. That alone can quickly get very expensive. The second consideration is the economics of access to the pipes. There may be fewer gas transport lines out in the areas where the projects are. A related challenge is acquiring the rights of way to get to the pipeline. That can be a complicated and lengthy process.”
A significant benefit to project economics, however, are the Renewable Energy Certificates (REC) that companies combusting gas from projects like Huckabay Ridge are qualified to receive. “Biogas from anaerobic digestion qualifies in every state’s Renewable Portfolio Standard,” he adds. “Anyone that combusts that gas to produce power qualifies for the RECs, which have cash value. So we can get paid more for the gas.”
Environmental Power also has announced projects in California, Colorado and Idaho. For example, a news release in August stated that the California Public Utilities Commission approved a gas purchase agreement between Pacific Gas and Electric Co. and Microgy for up to 8,000 mcf of RNG. Microgy plans to construct four production facilities at large dairy farms in California’s Central Valley. PG&E has an extensive natural gas pipeline network for interconnections with the digester projects.
These planned projects will be located at dairies, versus the non-dairy location for Huckabay Ridge. “It is more typical for us to be on site at the dairy, and to intercept what is going into a lagoon,” says Newman. “The project at Huckabay Ridge is more complicated in that regard, with the materials handling and slurrying required. It adds a lot more front-end management to the plant. It works, but is more complicated versus a location where we can get a lower percent solids pumped directly to the digesters.”

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