Four Colorado clean-water plants are implementing projects to recover and reuse biogas from anaerobic digestion.

Most wastewater treatment facilities use some biogas (a mixture of mainly methane and carbon dioxide) to fuel boilers that heat the anaerobic digester, and most of the biogas is flared. Instead of flaring the excess gas, the Colorado facilities are recovering, treating and using the biogas as alternative transportation fuel — as fuel for the cities’ fleet vehicles or through pipeline sales to other organizations.

The facilities are owned by Grand Junction, Longmont, Littleton/Englewood (now called the South Platte Water Renewal Partners), and Boulder. All four projects include a system to remove gas impurities (mainly hydrogen sulfide, siloxanes, VOCs, carbon dioxide and water). Each also produces compressed natural gas, or CNG.

Grand Junction and Longmont will use the biogas for the cities’ own CNG vehicles. In Grand Junction’s case, the project includes building a new gas pipeline from the wastewater treatment facility to the city’s fueling station. Boulder and South Platte will inject the biogas into a pipeline to sell to other customers as a transportation fuel.

Getting credits

A key to the winning economics for these projects is the sale of the credits for the fuel, called renewable identification numbers. For the RINs to be sold, the biogas must be used as a transportation fuel. The RINs are purchased by oil producers, which are required to produce a certain percentage of renewable fuel (or purchase RINs), under the federal Renewable Fuel Standard.

One RIN is a gallon of ethanol equivalent, or equivalent to 84,000 Btu (the heating value of that gallon). As of May, each RIN was worth about $2, which works out to about $26/MMBtu of biogas. However, the price of RINs may decline somewhat over the next five years as more treatment facilities and landfills take advantage of them. 

Table 1 below summarizes the initial investment and the annual costs and revenues for the biogas recovery/reuse projects. The simple payback periods are four to nine years, a reasonable investment for a city or treatment facility. Grand Junction’s initial costs included $1.3 million for a 5-mile gas pipeline extension, lengthening the project payback. 

Being sustainable

Aside from the favorable economics, the inspiration for the projects was sustainability: reduced CO2 and methane emissions from flaring, and the recovery and reuse of a valuable fuel resource. In addition, Grand Junction and Longmont reduced CO2 emissions by burning biogas rather than diesel in their trucks.

A gallon equivalent of CNG (or biogas) generates 30% lower CO2 emissions than a gallon of diesel. Table 2 (on following page) shows the emission reduction benefits and completion dates for the four projects.

On site or sale?

A key choice for a biogas recovery project is whether the city should use gas in its own vehicles or sell it. In the latter case, to obtain the RIN revenue, the city may need to hire a broker to sell the gas for use as a vehicle fuel, and to sell the RINs to one or more obligated oil companies.

Use of the biogas on site offers two advantages. First, the gas is worth more in annual revenues if replacing diesel at $2.50 to $3 per gallon than if sold as natural gas at $5.50/MMBtu (or about 75 cents/diesel gallon equivalent). Second, if the biogas is used on site, the city also reduces its fleet CO2 emissions.

On the other hand, using the fuel on site requires some coordination with the city’s fueling operations. Longmont navigated that challenge by locating its CNG vehicle fueling station at the wastewater treatment plant site.

John Gage, project manager for Longmont’s biogas project, observes, “We solved the logistical problem of where to locate the fueling station and avoided having to build a gas pipeline extension.” Grand Junction pipes the biogas to its vehicle fueling station, about 5 miles from the treatment plant.

Comparing to CHP

Using the biogas in a combined heat and power, or CHP, system is an option some of the four cities considered. Boulder evaluated replacing the CHP system at its Water Resource Recovery Facility, which was at the end of its useful life, and compared that option with biogas recovery and sale. The sale option had lower initial costs and a shorter payback.

It is also much simpler to maintain and operate the biogas treatment and compressor system than a CHP system. “Compared to the CHP system, the operation and maintenance of the biogas treatment and compressor system will be very simple,” notes Chris Douville, wastewater treatment manager in Boulder. “That will allow our team to focus on our core mission of returning high-quality final effluent to Boulder Creek.”

Biogas recovery may seem like an unnecessary added expense to a wastewater treatment facility. As such, gaining approval from the facility’s managers and the city council may present a challenge. The approval process for some of the four Colorado biogas projects took more than a year, but now all are on schedule to begin operating by the end of 2019.

For cities with sustainability and climate goals, projects of this kind make sense. Once the initial investment is paid off, the facility continues to earn substantial revenues from the sales of RINs and fuel, with low maintenance costs.

Wastewater treatment facilities that implement biogas recovery and reuse projects sooner rather than later will take advantage of a favorable RIN market, reducing financial risks and making the projects even more compelling.

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About the author

Neil Kolwey (nkolwey@swenergy.org) is industrial program director at the Southwest Energy Efficiency Project (SWEEP).