An upgrade to a Wisconsin treatment plant means energy savings and more opportunities for beneficial use of digester methane


Eighty-year-old aeration basins, 30-year-old equipment, no methane production from the digesters. The City of Two Rivers, Wis., had many reasons to upgrade its wastewater treatment plant.

Planning by Donohue & Associates Inc. started in 2006 to upgrade the aeration basins, install two new digesters, add a SCADA system, and use methane as fuel. It all turned into an award-winning design, receiving the State Finalist Engineering Excellence Award from the American Council of Engineering Companies of Wisconsin. The project’s general contractor was J.F. Ahern Company.

The upgraded plant, with 2.3 mgd average flow, is saving $20,000 a year in electricity and natural gas, $30,000 in chemicals, and 50 percent in biosolids hauling.

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Great timing

As it turned out, the timing for the upgrade couldn’t have been better for this city of 13,000 on Lake Michigan. As the city was considering the upgrade, the Village of Mishicot, six miles north, inquired about getting sewer service.

“They were facing a major upgrade to their system because they couldn’t meet the phosphorous and nitrogen requirements,” says Larry Lambries, the Two Rivers plant superintendent. The village was faced with replacing its treatment lagoons with a mechanical treatment plant.

The Two Rivers upgrade project started in late 2007 and continued through 2008, about a year later than originally planned. “It would have cost us $6 million either way, but because we waited, Mishicot paid 9 percent of the cost,” says Lambries.

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Serving Mishicot (population 1,500) costs only about $30,000 a year. The village contributes about 70 million gallons per year. In return, Two Rivers realizes $108,000 a year in revenue. The village also will pay its share of future capital costs based on its share of the flow.

Better all around

The Two Rivers plant’s two old anaerobic digesters had no heating and no mixing and created no methane. “We had gas compressors, but we weren’t generating any methane, so they were useless,” Lambries says.

Two active digesters with Ovivo mixers/heat exchangers were the key to the project. A Dystor membrane gas holder (Siemens) was added to collect the methane. The plant now uses about 15,000 cubic feet of methane per day to feed a Hurst boiler that heats the digesters to 96 degrees.

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Because more water is evaporated in the heating process, biosolids production is down about 50 percent. “It was costing us $25,000 a year to haul biosolids,” says Lambries. “Now we’re down to $12,000 a year. By having less material, we have less cost for polymers to treat it and need less electricity to run the dewatering press.”

The old plant could only achieve 15 to 20 percent volatiles reduction in the biosolids, while 38 percent was required for land application without incorporation into the soil. “We’re now getting 70 percent reduction,” Lambries says.

The digester heating system is cross-tied to the building’s HVAC. “If we have enough methane, we can use it to heat the building,” says Lambries. “If we don’t have enough, we can use our natural gas boilers to heat the digesters.”

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Improved aeration

The upgrade also enhanced aeration efficiency. Three new blowers were added along with automatic dissolved oxygen control (Hach) and variable-frequency drives (Eaton). “Our aeration system is running at 50 percent of the cost it used to,” says Lambries. Blower motors that ran at a constant 60 Hz now operate at 30 to 35 Hz. “You can’t control the price of electricity or natural gas, but you can do your best to keep your use as low as possible,” Lambries says.

Two new biosolids pumps (Vogelsang) were installed with VFDs for even more electrical savings. This also eliminated throttle valves that controlled biosolids flow. “The pumps are in the basement and the press is on the third floor,” Lambries says. “Every time we wanted to make an adjustment, the operator had to run up and down three flights of stairs. Now, the operator just presses a button.”

A SCADA system (Energenecs) monitors all 19 lift stations, upgraded with battery backup. Previously, lift station problems created an alarm with no indication of what was wrong. An operator then had to drive out and check each alarm.

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The SCADA system also improves daily operation. “We just don’t have enough people to go out and check 19 lift stations every day,” Lambries says. “We were trying to do it every two weeks. Now we check them from the control room.”

Nuisance odors have also been eliminated. The plant is near the city’s downtown, on the shore of Lake Michigan near the entrance to the harbor, and is surrounded by a marina/campground, lakeside hotel, the library and a park.

For the future, Lambries looks forward to adding cogeneration, perhaps with a microturbine, to take advantage of more of the methane, some of which is still flared in the summer. “We don’t have enough methane yet,” he says. “Once it gets to a point where it makes sense, we’ll pursue cogeneration.”

He estimates the plant needs a load increase of 30 to 40 percent before that would be cost-effective. While it could be several years, it is an option that didn’t exist before.


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