Biogas and Cogeneration


Biogas has been quietly serving as a fuel for combined heat and power (a.k.a. cogeneration) plants and as a revenue generator for waste treatment facilities, landfills, and dairies for some time, mainly in Europe. But it is becoming more popular here in the US as municipalities and utilities seek out energy cost reductions and base-load electricity sources.

Biogas is a product of recycling organic waste, whether it be in anaerobic digesters at wastewater treatment centers and farms or piping off the gas from landfills to cogenerators or natural gas pipelines. Fats, oils, and grease (FOG), as well as food waste, are quickly becoming a new source to increase biogas production and are increasing revenues for waste treatment plants.

Methane generated in landfills, a major constituent of biogas, is cleaned up and piped to fuel cogeneration systems, or cleaned for insertion into natural gas pipelines as “renewable natural gas.”

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Biogas facilities, which now number 17,000 in all of Europe, are popular there due to factors opposite to those in the US, according to Patrick Serfass, executive director of the American Biogas Council (ABC). High electricity prices, lack of landfill space, high landfill tipping fees, and a sense of social responsibility drive European interest in renewable resources, he says.

However, in the US, biogas is produced at just over 2,200 sites in the 50 states. Serfass pointed out that this is due to low electricity prices and available land for landfills, and no aggressive policies for renewables except for a few states such as California, Massachusetts, and Vermont.

According to the ABC, there are 259 anaerobic digesters on farms and 1,269 water resource recovery facilities using anaerobic digesters. Of those, about 860 currently use the biogas they produce and 39 are standalone systems that digest food waste. There are 652 landfill gas projects.

On the other hand, the potential for the industry’s growth is huge, says the ABC. It has counted over 13,500 new sites ripe for development—more than 8,000 dairy and swine farms and almost 4,000 water resource recovery facilities in addition to over 900 food-scrap-only systems and 415 landfills currently flaring their gas.

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Anne Hampson, a consultant in the Fairfax, VA, office of ICF, a global consulting and technology services company, says, “We are definitely seeing more biogas produced in processing food waste. The use of digesters has been more prominent in wastewater. And we’ve seen some uptick, at breweries, in particular, those focusing on craft beers.” She confirms one of the new developments is introducing food waste and FOG into waste treatment plants which boost biogas volume and production.

A New Source of Baseload Power
Cogeneration opportunities fed by biomass exist where there is a need for reliable electricity such as at wastewater plants, farms, food processors, and breweries, according to several sources. And anaerobic digesters operate 24 hours a day, seven days a week.

What are the drivers here? Farms, Serfass says, have to manage manure, particularly the odors and nutrients. Farms are now located much closer to residential areas which have spread out and residents are complaining of the odors. Anaerobic digesters eliminate those odors.

Anaerobic digesters operating on farms also allow for getting the right amount of nutrients on the land at the right time to eliminate runoff into local streams and rivers. Serfass says the drive is to reduce the volume of material farmers need to put on land by 40% to 60% and to do it about three months ahead of harvests—a significant amount of time for raw products to lay on the land.

Furthermore, by feeding the biogas produced in digesters into a generator, the heat produced can be used for dairy feeding parlors, hot water, and other uses.

Wastewater treatment plants use energy for pumping, heating, and moving materials and they are often the largest energy user in a city, Serfass says. A city is driven to reduce those energy costs and increase recycling. Furthermore, there is an added sense of social responsibility to take action, he says.

Digesting solids in a digester and generating electricity means the city can make at least one-half of the electricity it needs to operate the plant, says Serfass. If it adds food waste, which contains more nutrients, the city can generate 100% of the electricity it needs for the plant. The cost of such a plant can vary widely says Serfass, depending on a city’s population and revenues derived from the products.

Landfills should capture methane rather than flaring it as they have traditionally done. Cogeneration here has been a common application to generate electricity, but there is not a large need for the exhaust heat. Instead, the methane is upgraded to pipeline quality and sold as renewable natural gas. Raw biogas is 50% to 80% methane and natural gas is 99% methane. Moisture must be removed along with silicon compounds and sulfur compounds. When you combust silicon, it turns into sand and is corrosive to engines, Serfass says. He notes that these compounds make up only 1% of the raw biogas, but it is important to remove them.

Most landfill operators don’t want to pay for the equipment to clean their biogas to that level, so they will seek a generator designed for biogas, allowing the biogas to be cleaned up less. It’s an economic decision, says Serfass.

Food waste is not as homogenous as manure or wastewater sludge, but it contains 30 times more energy and creates more revenues. Thus, a legacy digester would have to be modified to handle diverse food wastes, but modifications are minor, says Serfass.

The Cogeneration Manufacturers
“Biogas, together with CHP or cogeneration, is a great baseload green energy source, and it’s a great market for us,” says Tom Drake, the regional sales manager for gas power systems at MTU Onsite Energy. The company is part of the Rolls-Royce Power Systems Group.

MTU manufactures reciprocating engines for both the natural gas and biogas markets. Drake explains that not any gas generator set can burn biogas since it contains less energy and requires higher compression ratios than natural gas.

Drake says, “When we speak with a customer, we determine the fuel and choose the engine customized for each application. The methane value and BTU (British Thermal Unit) count has to be evaluated, along with the location’s elevation and ambient temperatures. Miami is warmer and more humid than Denver, which has a much higher elevation. We also ask the customer what balance of plant do they want? How much power generation do they want to supply?

“Some customers want us to take the fuel from the digester, and in this case we clean it, dry it, and compress it to be burned in the CHP unit,” says Drake. Other customers just want to buy the engine. “We customize for the level of service customers want and offer long-term service agreements,” he says.

MTU’s line of biogas engines includes one of the more popular models—the 16-volt 4000L32FB engine, rated at 1,500 kilowatts. MTU can also provide 8V, 12V, and 20V versions. Drake explains that distribution partners need to be trained and knowledgeable on tooling to service customers’ CHP units. All parts come from the factory.

Drake says that 20% of their engine sales are for biogas engines. He sees that number getting bigger thanks in part to states like California, Massachusetts, New York, Maryland, and North and South Carolina seeing anaerobic digesters as solutions to a multitude of problems.

The biggest hurdle (and there are many), Drake says, is connecting power to the grid. Competitive power contracts are necessary to achieve this. For example, in Ohio and Wisconsin, power purchase agreements are less than 5 cents per kilowatt-hour. A good PPA price that could help a developer sell a digester/cogeneration project is 12 cents/kWh to 14 cents/kWh. In Europe, developers sign contracts with prices in excess of 20 cents/kWh, Drake says.

Given these hurdles, “We have to do plenty of planning,” Drake says. A well-designed anaerobic digester/cogeneration project needs a lot of revenue streams to bring it to reality. On the front end, food waste should get tipping fees when it is delivered to the site. On the back end, what’s left over can be sold as mulch, or bedding for hogs, or fertilizer.

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Credit: Capstone
Capstone turbines installed at the Sheboygan, WI, Regional Wastewater Plant. The 30-kW units (10 in all) generate more than 1,600 MW while operating on biogas generated in the digesters in the background.

Capstone Microturbines Have Few Emissions
Capstone Turbine, headquartered in Chatsworth, CA, a suburb of Los Angeles, is the largest manufacturer of microturbines, with about 9,000 installations around the world. Jim Crouse, executive vice president for sales and marketing at Capstone, estimates that of those 9,000, approximately 450 installations burn biogas generated at waste treatment centers, landfills, and farms. He says most installations are at waste treatment plants. Recently he has seen installations increase at dairies and breweries.

Capstone microturbines are air-cooled and air-lubricated which leads to very low maintenance costs. They have very low pollution emissions which may allow the owners to have no emission reporting obligations to local or state agencies.

The sizes of Capstone microturbines are scalable from 30 kW to 30 MW by combining different sizes, available in 200 kW, 600 kW, 800 kW, and 1,000 kW units.

Another advantage Capstone microturbines have is their ability to be free of hydrogen sulfide problems when burning biomass. Other reciprocating engines require that hydrogen sulfide is scrubbed from the biogas before burning it. Crouse says that if not scrubbed, hydrogen sulfide will mix with the lubricants required in engines and convert to sulfuric acid, thereby corroding engine parts. However, Capstone microturbine components are stainless steel or titanium, they lack oil-based lubricants, and are not susceptible to degradation. They can handle up to 70,000 ppm of hydrogen sulfide, Crouse says.

Capstone also manufactures dual-mode microturbines, allowing them to automatically disconnect the plant from the utility when power fails. The York Waste Treatment Plant in York, PA, operates a 600-kWh CHP system on biogas and it also has a 1,000-kWh dual-mode unit fueled by utility-supplied natural gas which the plant uses for peak shaving. The combined 1.6 MW thus relieves the plant from power interruptions.

The first Capstone installation of a dual-mode biomass-fueled microturbine was at the Swineline Farm in Cullinan, South Africa. The 65-kilowatt microturbine uses a dual mode controller to act as an automatic transfer switch. It monitors incoming power and directs the microturbine to switch to standalone operation within 10 seconds of grid failure.

Crouse says the farm is in a remote area where utility power is unreliable. He cautions, however, that biogas as a fuel doesn’t support combustion as well as natural gas and the system has to be engineered properly. He said operators have to carefully control the loads as they vary.

Financing biogas-fueled generator or microturbine projects may be tricky for municipalities. Crouse says they cannot take advantage of tax incentives such as investment tax credits and equipment depreciation as private companies do, so they look for private financing or third-party ownership. Many waste treatment authorities count on renewable energy credits for income to produce a reasonable rate of return, he says. However, the 2009 crash caused carbon pricing to collapse and the ability to use renewable energy credits disappeared, and these haven’t recovered, he says.

The superintendent of the Sheboygan, WI, Regional Wastewater Plant began in 2003 to search for a cogeneration system to utilize its biogas and sought an agreement with Alliant Energy-Wisconsin Power and Light directly south of the treatment plant. However, that project failed.

Eventually, Unison Solutions, the distributor for Capstone in the Midwest, produced a proposal in which Alliant would purchase ten 30-kW Capstone microturbines, pay for electrical connections from the wastewater plant to the electrical grid, purchase a gas-cleaning system that removes moisture and siloxanes from the raw methane gas, and purchase a gas compression system that compresses the clean methane gas fed to the microturbines.

The city agreed to purchase all electricity the microturbines produce from Alliant, install a heat-recovery module to capture the waste heat, and provide the biogas to fuel the microturbines. Eventually, the city will purchase the system at a reduced price. The waste treatment plant got the go-ahead for the project in December 2005 and began operating it in February 2006.

Finally, the wastewater treatment plant receives one renewable energy credit for every megawatt of renewable energy the microturbines create, which the plant can sell. The superintendent, Dale Doerr, told Capstone in 2007 the wastewater treatment plant produced 1,681 MW, valued at $121,000. And it sold 2,076 renewable energy credits for $6,540. The plant’s total revenues in 2007 were more than $33,600.

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Credit: Victor Valley Wastewater Treatment Plan
Organic fiber byproducts produced by anaerobic disgestion at the Middleton Dairy in Middleton, WI, are composted onsite into soil amendment
products by Purple Cow Organics and sold. Gundersen Health System cofunded the
project with Dane County, WI

2G Engines Designed for Biogas
2G Energy was founded in Germany in 1997 and has sold over 5,000 biogas and natural gas cogeneration units worldwide. “Within the last 10 years, the natural gas market materialized for us [in the US],” says Emily Robertson, the company’s marketing and sales support specialist. Its US headquarters opened seven years ago in St. Augustine, FL, where it has been manufacturing natural gas units.

The company’s first product was the G-box, a 50-kW biogas plant, and it is still being manufactured in Germany. The cogeneration unit includes a control cabinet with PLC controller. 2G’s product portfolio now includes engines ranging in size from 20 kW to 4,000 kW in electric capacity. They operate with natural gas, biogas, biomethane (which meets natural gas standards), and other lean gases.

The company announced in August 2017 a new range of low-emission cogeneration systems ranging from 20 kW to 240 kW. According to a press release, the systems emit 90% less nitrogen oxide compared with standard units.

Robertson says the 2G engines are very popular with farmers and municipalities that have realized they can utilize CHP to power parts of their towns. “We do have projects that are pushing out power to communities,” she says.

The Customers
Victorville is located 90 miles northeast of Los Angeles, CA, in the high desert. Its population is just over 116,000. The larger area is known as Victor Valley, with a population of over 300,000 and includes seven additional cities with Victorville as the business hub of the area.

The Victor Valley Wastewater Reclamation Authority, located in Victorville, began operating in 1981. It was established by the Mojave Water Agency to help meet the requirements of the federal Clean Water Act and provide wastewater treatment for the growing area of Victor Valley.

The original treatment plant provided tertiary level treatment for up to 4.5 million gallons per day. Today, it processes 1.5 million gallons per day, divided between tertiary level and secondary level treatment for percolation. It is now a joint powers authority and public agency of the state of California.

Logan Olds, general manager, describes the wastewater treatment plant as a conventional activated sludge facility doing biological nutrient reduction. It flared the biogas before the 1.6-MW cogeneration system, built by 2G Energy, was installed in 2015. The plant produces biogas in two digesters installed in 2008 which fuel the cogeneration unit.

Biogas is run through turbo-blowers to provide oxygen to generate mixed liquor suspended solids in the aeration tank. This is to ensure that there is a sufficient quantity of active microorganisms to consume organic pollutants. Biogas was used for this process before the cogeneration system was installed and continues today. Olds labels this the second type of cogeneration.

The Wastewater Reclamation Authority signed a 20-year power purchase agreement with Anaergia, a manufacturer of anaerobic digestion technologies with offices in California, Hawaii, Germany, Italy, the UK, Singapore, South Africa, and Ontario, Canada. The electricity produced by the cogeneration system provides over 70% of the facility’s electrical needs. Net costs were reduced by $249,435 after the first year. “Our average electrical demand is just over 900 kW. We have a non-export interconnection agreement with Southern California Edison,” he explains. So all power generated is used onsite.

Olds says the treatment facility was the first in the nation to perform full-scale digestion of food waste. He says they studied how food waste would work by allowing food and FOG haulers to drop off the food waste for free for a year to study how it would affect the system and the economics, and the haulers learned how the wastewater facility does business. Once they decided to make it a permanent operation, the Wastewater Reclamation Authority set tipping fees at four cents per gallon. “It worked out very well for us,” he says.

Olds says the treatment plant discharges to two north-flowing rivers requiring very stringent permit requirements. “It affects everything we do,” he says. “It is a very intensive energy process. We do not do mechanical dewatering. Instead, we do solar thermal powering beds.” Olds explains the discharges are laid out on the ground and when dried, the products are given to farmers for fertilizing their land.

Olds says construction will start on a microgrid with flow cell batteries in January. It should be online in May or June 2018 and will provide power and controls to the entire facility. Olds says, “This should enable us to supply 90% or greater of our energy needs onsite from the biogas.” If the microgrid and storage batteries work as intended, “There is an opportunity for us to go off the grid,” he says. “We may go with net energy metering, [allowing the facility to sell power to the utility] but only after evaluating microgrid operation. It’s more related to interconnection equipment than our agreement with Southern California Edison,” he explains.

The waste treatment facility is now in negotiations to privatize a portion of its facility to increase biogas production, Olds says. “This project is unique, but I believe it is where our industry will head in about five years.” The plan is to privatize three of the digesters currently not being used, so they can produce more biogas for renewable natural gas for injection into pipelines.

“We’re trying to conclude negotiations by February,” says Olds. The private partner they are negotiating with must determine the business climate which is most stable and reliable over the term. Olds says he has had the idea of privatizing the older digesters for some time and explains that this is the reason they were not removed.

In a partnership with and funded by Anaergia, the Wastewater Reclamation Authority launched the Omnivore Project with additional funding from the California Energy Commission. Anaergia created a recuperative thickener to remove more moisture from the sludge compared to traditional methods. It thickens sludge and increases the capacity of digestion inside a newly retrofitted anaerobic digester and increases the production of biogas. Food waste (including FOG from local businesses) and sludge are mixed to increase digestion capacity up to three times in the same tank.

Biogas Revenues Support Healthcare System
Gundersen Health System, headquartered in La Crosse, WI, has been working to reduce its energy use since 2008, a major challenge since it has 50 facilities in Wisconsin, Minnesota, and Iowa.

Gundersen Health System built up its energy production with two wind farms, a biogas trigeneration system, a biomass woodchip project, two dairy manure digester projects, a geothermal heat pump system, and solar photovoltaic and solar thermal projects. It has reduced energy use by 60% and offset 76% of its fossil fuel use. Its conservation efforts alone have resulted in cumulative financial savings of more than $14.1 million.

According to Jeff Rich, executive director of its energy division, GL Envision, Gundersen was the first health system in the country to achieve its first fossil-free day on October 14, 2014. In 2016, Rich says Gundersen was energy independent for 97 days when it produced more energy than it consumed.

Gundersen won an Environmental Protection Agency award for its unique trigeneration system. An engine located at its Onalaska, WI, campus burns landfill gas generated at the La Crosse County landfill 1.5 miles away. The engine turns a 1,137-kW connected generator to produce electricity sold under a special tariff to Excel Energy. The heat captured off the engine block heats the 350,000-square-foot campus. Excess heat is further used to generate air conditioning, thus qualifying the system as trigeneration. The project represents about 13% of Gundersen’s total renewable energy production.

Gundersen built the Lewiston Wind Farm’s two turbines that generate 4.95 MW sold to the local utility. It built the Cashton Greens Wind Farm, also with two turbines, in collaboration with Organic Valley, an organic farmers’ cooperative. It generates about 5 MW.

Gundersen replaced its aging boilers with a biomass boiler and steam turbine to reduce its use of fossil fuels, and it is considered to be the largest single cogeneration project that helped Gundersen become energy independent. It burns wood fuel, such as milling or forest residues sourced locally, in the boiler to heat water and create steam used throughout Gundersen’s main La Crosse Campus.

Steam is also run through a steam turbine to generate electricity used onsite. The system is installed with state-of-the-art emissions controls. The biomass boiler saves Gundersen approximately $500,000 annually. However, the project still spends about $650,000 annually for the biomass fuel from local mills. Gundersen justifies this cost by pointing out that the dollars are spent in the local communities rather than out-of-state. The project was supported in part by a Wisconsin Bioenergy Grant.

Gundersen partnered with Dane County, WI, to serve three dairies. At the Middleton project, manure produced by more than 2,000 cows is processed in three anaerobic digesters to produce biogas that is burned in generators to produce about 16 million kWh which is then sold to Madison Gas and Electric and sent to the local grid. The organic fiber byproducts produced in the digester process are composted onsite by Purple Cow Organics. Production began in December 2013.

The other benefit of the project is that it prevents phosphorus runoff to the waterways in Dane County. The phosphorus is the leading cause of green algae and other weed growth in the county’s lakes.

At the second Sunnyside biogas dairy project, Gundersen constructed a dairy digester on the Maunesha River Dairy near Sun Prairie, WI, which began production in April 2014. Approximately 1,300 cows supply more than enough manure to make the project viable. The manure is processed in the anaerobic digester to produce enough biogas to generate about 5 million kWh annually. Alliant Energy purchases the electricity. The organic fiber byproduct also produced in the process is used for cow bedding.

Together, the two wind farms, the two dairy manure digesters, and the landfill gas project have generated revenues totaling $3.5 million in electricity sales. These revenues, in turn, help to make Gundersen’s healthcare delivery more affordable to its patients and improve health through decreased greenhouse gas emissions. De Bug Web

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