Generating Power at the Plant: CHP Boosts Efficiency
May 4, 2009
BY Susanne Retka Schill
Electrical power generation has long been recognized as highly inefficient. Two-thirds of the energy fueling the process is wasted as unused heat after high pressure, high temperature steam does its work. When the typical efficiency of electrical generation is added to the typical efficiency of a boiler system providing process heat to an ethanol plant, the combined efficiency is roughly 49 percent. Bringing the power generation to the ethanol plant and making use of the electrical generation's waste heat in a combined heat and power (CHP) system, boosts that efficiency to 75 percent. Increasing the efficiency of power and steam generation, in turn, reduces carbon emissions.
The round-the-clock plant operations and steady steam and power load in ethanol plants make the industry a prime candidate for CHP systems. Bringing the power plant to the user means that the waste heat from electrical generation can be recovered for process heat. The system efficiencies and reductions in carbon emissions are impressive, and depending on a plant's fuel cost and electrical rates, can also provide cost savings to the ethanol plant.
The U.S. DOE published a CHP analysis last winter that says if 20 percent of the nation's electrical generation came from CHP systems, the resulting reduction in carbon emissions would be the equivalent of removing 154 million cars from the road—more than half the U.S. vehicle fleet. The paper, "Combined Heat and Power: Effective Energy Solutions for a Sustainable Future," published December 2008 by the Oakridge National Laboratory, recommends the U.S. boost its CHP use from the current 9 percent of generating capacity to 20 percent over the next 20 years. The paper argues increasing CHP capacity is a cost effective means of reducing electricity's carbon footprint using a well-established technology that would be relatively quick to deploy.
A Good Fit
CHP systems have been around for a century and are used in large industrial settings such as paper mills, refineries, and chemical and metal manufacturing. In the mid-1990s, the DOE and U.S. EPA realized there could be real benefits if those large CHP systems were downsized for commercial applications such as hospitals, campuses, hotels and medium-sized industrial users. In 1993, the EPA began its outreach to the ethanol industry as a prime candidate for CHP. In addition to promoting the CHP concept, the EPA provides technical assistance such as preliminary system evaluation and permitting assistance.
CHP is a good fit for ethanol plants because energy is the second highest cost after corn. A typical 50 MMgy dry mill will have steam loads of 100,000 to 150,000 pounds per hour and power demands of 4 to 6 megawatts (MW), depending on its vintage and mix of operations.
The most common CHP technology used in the dozen or so ethanol plants with installed CHP systems consists of a gas turbine electric generator placed in tandem with a waste heat boiler (heat recovery steam generator or HRSG). Natural gas produces steam to drive the turbine that provides electricity for the facility and the turbine exhaust is used in the waste heat boiler to produce steam for the ethanol process. Interest in biomass- and coal-fired CHP is growing for ethanol plants located near feedstock sources. Central Minnesota Ethanol Co-op at Little Falls, Minn., has a wood-based biomass CHP system, and Riverland Biofuels LLC at Canton, Ill., has a coal-based system. Coal or biomass systems generally include fluidized-bed gasifiers or boilers that can be configured so the exhaust from the driers is routed to become the combustion air in the boilers, effectively controlling volatile organic compound (VOC) emissions and eliminating the need for thermal oxidizers.
According to the EPA, CHP can be combined with VOC destruction in other configurations. The thermal oxidizer can be integrated with a waste-heat boiler to produce steam from the thermal oxidizer exhaust. High-pressure steam from the waste-heat boiler is then used in a steam turbine-generator unit to produce electricity, and low-pressure steam from the back end of the turbine is used to meet process heat requirements. Another approach for VOC destruction is to integrate the dryer exhaust into the gas turbine waste heat generator, then use a secondary supplemental burner to oxidize the VOCs and efficiently generate additional steam for the plant.
There are two strategies for sizing CHP units in ethanol plants. One is to use all of the electrical power generated on site because the economics for selling excess generation to the grid are generally not as favorable as utilizing it on site. When sizing the CHP system based on steam requirements, an ethanol plant will generally produce three or four times more electrical power than the plant uses, making a utility partnership attractive.
Utility partnerships are involved in CHP systems installed at two Poet LLC ethanol plants in Missouri. The city of Macon, Mo., partnered with Poet Biorefining-Macon to install a 10 MW CHP system. The utility owns the natural gas turbine, while the ethanol plant is responsible for the HRSG. "HRSG's are a little unique in the setup, but from an operational standpoint they're like a boiler," says Rod Pierson, director of plant operations for Poet Plant Management. "The HRSG is not a lot of extra work, and the goal is to recover as much heat as possible." The HRSG at Macon recycles waste heat from the turbine into approximately 51,000 pounds per hour of steam to satisfy up to 70 percent of the plant's process heat. The 45 MMgy ethanol plant also has two natural gas boilers to supplement whatever level of thermal energy is not provided from the CHP. In normal operation, the power from the CHP is fed into the grid. With an electric substation installed on the site, the ethanol plant can disconnect from the local grid should the grid experience an outage and continue operating.
Eighty miles southeast of Macon at Laddonia, Mo., Poet Biorefining-Laddonia has partnered with the Missouri Joint Municipal Electric Utility Commission in a 14.4 MW CHP system.
The ethanol plant uses approximately 7 MW of power and 75,000 pounds per hour of steam for process heat for the 45 MMgy plant. The utility owns and is responsible for the gas turbine, while the ethanol plant owns and is responsible for the heat recovery boiler and steam system. The ethanol plant and the city formed a unique agreement with each entity paying half the cost of the turbine natural gas consumption. In turn, the ethanol plant recovers the entire waste heat load, resulting in an overall 20 percent annual savings in natural gas costs by the ethanol plant. The city of Macon is decreasing its fuel cost for the generated capacity by 50 percent and, along with the credits it receives for providing the added electric capacity to the local power pool, it has estimated a payback on its investment in the CHP system to be 13 years. In April, the EPA gave the utility commission an Energy Star CHP award for its efforts.
Separate power and heat systems typically use 154 units of fuels to produce 30 units of electricity and 45 units of steam at an overall efficiency of 49 percent. With combined heat and power (CHP), one system could provide the same amount of electricity and steam using only 100 units of fuel, offering an overall efficiency of 75 percent. Because the CHP system uses nearly 35 percent less fuel, it produces lower emissions than the conventional system. EPA estimates a CHP system produces about half the carbon emissions of conventional separate heat and power systems. The emissions reductions can be even greater when replacing aging conventional systems with CHP.
SOURCE: EPA CHP PARTNERSHIP
In Iowa, the Poet Biorefining-Ashton 55 MMgy ethanol plant has a natural-gas-fueled CHP system that supplies 75 percent of the plant's steam requirements and 7 MW of electrical power. In southern Minnesota, the CHP system at Poet Biorefining-Lake Crystal generates 1 MW of electrical power for the 56 MMgy ethanol plant. Essentially, the ethanol plants use standard boilers to generate steam at a higher pressure than a conventional ethanol plant's boiler to produce electricity. Once that work is accomplished, the lower pressure steam is used for process heat.
Like Poet's Lake Crystal plant, East Kansas Agri-Energy LLC in Garrett, Kan., generates 1 MW of electricity from a natural gas turbine. The natural gas boiler produces high pressure steam to generate about one-third of the 35 MMgy plant's electrical needs, then the lower pressure steam goes on to supply the plant's process heat. "We save $15,000 a month in electrical bills," says Doug Sommer, EKAE plant manager. The EPA figures the heat and electricity supplied to the plant requires approximately 23 percent less fuel than typical separate onsite thermal generation and purchased electricity. That in turn reduces carbon dioxide emissions by an estimated 14,500 tons per year, which is equal to removing the annual emissions from 2,400 cars and planting 3,000 acres of forest.
Calculating Payback Period
The capital cost for installing a CHP system is quite substantial, and the payback period depends upon the energy cost for fuel powering the system and electrical rates. The DOE's Midwest CHP Application Center published a study in 2007, "Research Investigation for the Potential Use of Combined Heat and Power at Natural Gas and Coal Fired Dry Ethanol Plants," that delved into the details of installation and energy costs for a CHP system in a 100 MMgy plant. The study concentrated on energy costs in the eight Midwestern states that comprise 80 percent of the nation's ethanol capacity. It found relatively attractive paybacks for natural-gas-fired ethanol plants ranging from three years in Wisconsin to six years in South Dakota. Coal-fired ethanol plants were even more attractive in the analysis ranging from a one-year payback in Wisconsin to 1.5 years in Nebraska (to access the DOE and EPA's papers and other information about CHP visit: www.epa.gov/chp/markets/ethanol.html).
The best time to install a CHP system is when the plant is being built, although retrofits can be attractive as well, according to Bruce Hedman, vice president of energy systems for the consulting firm Energy and Environmental Analysis Inc. The firm has worked with the EPA and DOE in promoting CHP. Hedman says that even though installing CHP when building a plant makes the most sense, in the heyday of the ethanol plant construction boom, the added time for permitting and additional engineering and construction demands made incorporating a CHP system a tough sell. "When times are tight and plants are trying to be low-cost producers, it may be time to look at CHP again," he adds.
A More Efficient Future
"Everyone in the CHP industry is pretty optimistic that even though times are tough, carbon reduction is not going away, and efficiency is key," Hedman says. "You get enormous efficiency and carbon dioxide reductions from CHP." In the future, CHP-generated power is likely to increase in value as utilities become required to build clean power portfolios and reduce their carbon emissions. Currently, utilities in 34 states are faced with state-level renewable power standards (RPS) and a national RPS is being considered by the U.S. Congress. Fourteen of the existing state RPS's qualify CHP using renewable fuels, but only two include CHP using gas turbines, Hedman says.
Other new policies have been passed that may tip the balance in favor of CHP. A 10 percent investment tax credit and accelerated depreciation for CHP systems are included in the Energy Independence & Security Act of 2007. The economic stimulus package also contained money for unfunded CHP incentives outlined in the 2007 EISA.
Pierson and Sommer say both of their companies are watching the development of carbon markets and legislation. "I don't see the point in spending money on infrastructure or even measuring carbon until there is concrete legislation," Sommer says. As soon as there is, EKAE will be looking for opportunities to participate. Pierson adds that Poet has a team evaluating the potential for participating in carbon markets. Pleased with the performance of CHP, Poet continues to evaluate its potential use at other facilities. "It all depends on local utilities and their need for electrical generation," Pierson says. "But as we go east in the Corn Belt, the cost of electricity goes up."
Susanne Retka Schill is an assistant editor at BBI International Reach her at sretkaschill@bbiinternational.com or (701) 738-4922.
The round-the-clock plant operations and steady steam and power load in ethanol plants make the industry a prime candidate for CHP systems. Bringing the power plant to the user means that the waste heat from electrical generation can be recovered for process heat. The system efficiencies and reductions in carbon emissions are impressive, and depending on a plant's fuel cost and electrical rates, can also provide cost savings to the ethanol plant.
The U.S. DOE published a CHP analysis last winter that says if 20 percent of the nation's electrical generation came from CHP systems, the resulting reduction in carbon emissions would be the equivalent of removing 154 million cars from the road—more than half the U.S. vehicle fleet. The paper, "Combined Heat and Power: Effective Energy Solutions for a Sustainable Future," published December 2008 by the Oakridge National Laboratory, recommends the U.S. boost its CHP use from the current 9 percent of generating capacity to 20 percent over the next 20 years. The paper argues increasing CHP capacity is a cost effective means of reducing electricity's carbon footprint using a well-established technology that would be relatively quick to deploy.
A Good Fit
CHP systems have been around for a century and are used in large industrial settings such as paper mills, refineries, and chemical and metal manufacturing. In the mid-1990s, the DOE and U.S. EPA realized there could be real benefits if those large CHP systems were downsized for commercial applications such as hospitals, campuses, hotels and medium-sized industrial users. In 1993, the EPA began its outreach to the ethanol industry as a prime candidate for CHP. In addition to promoting the CHP concept, the EPA provides technical assistance such as preliminary system evaluation and permitting assistance.
CHP is a good fit for ethanol plants because energy is the second highest cost after corn. A typical 50 MMgy dry mill will have steam loads of 100,000 to 150,000 pounds per hour and power demands of 4 to 6 megawatts (MW), depending on its vintage and mix of operations.
The most common CHP technology used in the dozen or so ethanol plants with installed CHP systems consists of a gas turbine electric generator placed in tandem with a waste heat boiler (heat recovery steam generator or HRSG). Natural gas produces steam to drive the turbine that provides electricity for the facility and the turbine exhaust is used in the waste heat boiler to produce steam for the ethanol process. Interest in biomass- and coal-fired CHP is growing for ethanol plants located near feedstock sources. Central Minnesota Ethanol Co-op at Little Falls, Minn., has a wood-based biomass CHP system, and Riverland Biofuels LLC at Canton, Ill., has a coal-based system. Coal or biomass systems generally include fluidized-bed gasifiers or boilers that can be configured so the exhaust from the driers is routed to become the combustion air in the boilers, effectively controlling volatile organic compound (VOC) emissions and eliminating the need for thermal oxidizers.
According to the EPA, CHP can be combined with VOC destruction in other configurations. The thermal oxidizer can be integrated with a waste-heat boiler to produce steam from the thermal oxidizer exhaust. High-pressure steam from the waste-heat boiler is then used in a steam turbine-generator unit to produce electricity, and low-pressure steam from the back end of the turbine is used to meet process heat requirements. Another approach for VOC destruction is to integrate the dryer exhaust into the gas turbine waste heat generator, then use a secondary supplemental burner to oxidize the VOCs and efficiently generate additional steam for the plant.
There are two strategies for sizing CHP units in ethanol plants. One is to use all of the electrical power generated on site because the economics for selling excess generation to the grid are generally not as favorable as utilizing it on site. When sizing the CHP system based on steam requirements, an ethanol plant will generally produce three or four times more electrical power than the plant uses, making a utility partnership attractive.
Utility partnerships are involved in CHP systems installed at two Poet LLC ethanol plants in Missouri. The city of Macon, Mo., partnered with Poet Biorefining-Macon to install a 10 MW CHP system. The utility owns the natural gas turbine, while the ethanol plant is responsible for the HRSG. "HRSG's are a little unique in the setup, but from an operational standpoint they're like a boiler," says Rod Pierson, director of plant operations for Poet Plant Management. "The HRSG is not a lot of extra work, and the goal is to recover as much heat as possible." The HRSG at Macon recycles waste heat from the turbine into approximately 51,000 pounds per hour of steam to satisfy up to 70 percent of the plant's process heat. The 45 MMgy ethanol plant also has two natural gas boilers to supplement whatever level of thermal energy is not provided from the CHP. In normal operation, the power from the CHP is fed into the grid. With an electric substation installed on the site, the ethanol plant can disconnect from the local grid should the grid experience an outage and continue operating.
Eighty miles southeast of Macon at Laddonia, Mo., Poet Biorefining-Laddonia has partnered with the Missouri Joint Municipal Electric Utility Commission in a 14.4 MW CHP system.
The ethanol plant uses approximately 7 MW of power and 75,000 pounds per hour of steam for process heat for the 45 MMgy plant. The utility owns and is responsible for the gas turbine, while the ethanol plant owns and is responsible for the heat recovery boiler and steam system. The ethanol plant and the city formed a unique agreement with each entity paying half the cost of the turbine natural gas consumption. In turn, the ethanol plant recovers the entire waste heat load, resulting in an overall 20 percent annual savings in natural gas costs by the ethanol plant. The city of Macon is decreasing its fuel cost for the generated capacity by 50 percent and, along with the credits it receives for providing the added electric capacity to the local power pool, it has estimated a payback on its investment in the CHP system to be 13 years. In April, the EPA gave the utility commission an Energy Star CHP award for its efforts.
Separate power and heat systems typically use 154 units of fuels to produce 30 units of electricity and 45 units of steam at an overall efficiency of 49 percent. With combined heat and power (CHP), one system could provide the same amount of electricity and steam using only 100 units of fuel, offering an overall efficiency of 75 percent. Because the CHP system uses nearly 35 percent less fuel, it produces lower emissions than the conventional system. EPA estimates a CHP system produces about half the carbon emissions of conventional separate heat and power systems. The emissions reductions can be even greater when replacing aging conventional systems with CHP.
SOURCE: EPA CHP PARTNERSHIP
In Iowa, the Poet Biorefining-Ashton 55 MMgy ethanol plant has a natural-gas-fueled CHP system that supplies 75 percent of the plant's steam requirements and 7 MW of electrical power. In southern Minnesota, the CHP system at Poet Biorefining-Lake Crystal generates 1 MW of electrical power for the 56 MMgy ethanol plant. Essentially, the ethanol plants use standard boilers to generate steam at a higher pressure than a conventional ethanol plant's boiler to produce electricity. Once that work is accomplished, the lower pressure steam is used for process heat.
Like Poet's Lake Crystal plant, East Kansas Agri-Energy LLC in Garrett, Kan., generates 1 MW of electricity from a natural gas turbine. The natural gas boiler produces high pressure steam to generate about one-third of the 35 MMgy plant's electrical needs, then the lower pressure steam goes on to supply the plant's process heat. "We save $15,000 a month in electrical bills," says Doug Sommer, EKAE plant manager. The EPA figures the heat and electricity supplied to the plant requires approximately 23 percent less fuel than typical separate onsite thermal generation and purchased electricity. That in turn reduces carbon dioxide emissions by an estimated 14,500 tons per year, which is equal to removing the annual emissions from 2,400 cars and planting 3,000 acres of forest.
Calculating Payback Period
The capital cost for installing a CHP system is quite substantial, and the payback period depends upon the energy cost for fuel powering the system and electrical rates. The DOE's Midwest CHP Application Center published a study in 2007, "Research Investigation for the Potential Use of Combined Heat and Power at Natural Gas and Coal Fired Dry Ethanol Plants," that delved into the details of installation and energy costs for a CHP system in a 100 MMgy plant. The study concentrated on energy costs in the eight Midwestern states that comprise 80 percent of the nation's ethanol capacity. It found relatively attractive paybacks for natural-gas-fired ethanol plants ranging from three years in Wisconsin to six years in South Dakota. Coal-fired ethanol plants were even more attractive in the analysis ranging from a one-year payback in Wisconsin to 1.5 years in Nebraska (to access the DOE and EPA's papers and other information about CHP visit: www.epa.gov/chp/markets/ethanol.html).
The best time to install a CHP system is when the plant is being built, although retrofits can be attractive as well, according to Bruce Hedman, vice president of energy systems for the consulting firm Energy and Environmental Analysis Inc. The firm has worked with the EPA and DOE in promoting CHP. Hedman says that even though installing CHP when building a plant makes the most sense, in the heyday of the ethanol plant construction boom, the added time for permitting and additional engineering and construction demands made incorporating a CHP system a tough sell. "When times are tight and plants are trying to be low-cost producers, it may be time to look at CHP again," he adds.
A More Efficient Future
"Everyone in the CHP industry is pretty optimistic that even though times are tough, carbon reduction is not going away, and efficiency is key," Hedman says. "You get enormous efficiency and carbon dioxide reductions from CHP." In the future, CHP-generated power is likely to increase in value as utilities become required to build clean power portfolios and reduce their carbon emissions. Currently, utilities in 34 states are faced with state-level renewable power standards (RPS) and a national RPS is being considered by the U.S. Congress. Fourteen of the existing state RPS's qualify CHP using renewable fuels, but only two include CHP using gas turbines, Hedman says.
Other new policies have been passed that may tip the balance in favor of CHP. A 10 percent investment tax credit and accelerated depreciation for CHP systems are included in the Energy Independence & Security Act of 2007. The economic stimulus package also contained money for unfunded CHP incentives outlined in the 2007 EISA.
Pierson and Sommer say both of their companies are watching the development of carbon markets and legislation. "I don't see the point in spending money on infrastructure or even measuring carbon until there is concrete legislation," Sommer says. As soon as there is, EKAE will be looking for opportunities to participate. Pierson adds that Poet has a team evaluating the potential for participating in carbon markets. Pleased with the performance of CHP, Poet continues to evaluate its potential use at other facilities. "It all depends on local utilities and their need for electrical generation," Pierson says. "But as we go east in the Corn Belt, the cost of electricity goes up."
Susanne Retka Schill is an assistant editor at BBI International Reach her at sretkaschill@bbiinternational.com or (701) 738-4922.
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