Figure 1. Diagram of a small congeneration system with a recriprocating prime mover.

Hospitals, hospitality, municipalities, and industrial applications may face their best chance in years to save money (and natural resources) with a combined heat and power (CHP) system. From steam turbines that rely on boilers to gas turbines, on to reciprocating engines and fuel cells, the variety of options is as wide as the range of settings where it might make sense. Reacquaint yourself with CHP, including the sidebar’s “small” example that can save over $100,000 per year.

Cogeneration can be employed anywhere there is a simultaneous need for electrical and thermal energy, and it is often referred to as combined heat and power (CHP). CHP is any number of applied technologies that simultaneously produces two or more forms of energy from a single fuel source.

Prior to the development of the electrical distribution grid, industrial concerns generated their power on-site and developed cogeneration techniques and applications to utilize the resulting waste heat. As the utility industry grew and took hold, their economies of scale and reliability eventually made on-site generation of electricity uneconomical in many cases and thereby significantly reduced the prevalence of cogenerated power. But in 1978, the Public Utilities Regulatory Policy Act (PURPA) required public utilities to purchase a portion of their electric generating capacity from non-utility generators that use alternative energy sources and cogeneration in order to reduce dependence on foreign oil.

In the ’80s, lower natural gas rates allowed the economical production of on-site power and helped to spur cogeneration projects. Growth in this sector was then stalled due to higher gas prices. The recession has kept gas prices depressed and discoveries in Texas’ Barnett shale and Pennsylvania’s Marcellus shale may keep these prices low. Present concerns about global warming and the long-term availability of fossil fuels have created an environment where re-exploring the application of cogeneration makes good sense, since this process can result in less fossil fuel consumption and fewer emissions than generating electrical power and heat through separate processes.


Most CHP systems use a topping cycle, in which the fuel source is first used for generating electricity and then to recover the resultant heat for thermal needs, such as space and domestic water heating and cooling and the regeneration of desiccants used for dehumidification. A bottoming cycle uses fuel to drive industrial thermal processes, with the exhaust gases then being used to produce power, typically with a heat recovery steam generator in series with a steam turbine. The topping cycle can use a variety of prime movers, such as reciprocating engines, steam turbines, gas turbines, microturbines, and fuel cells to generate electrical power.

A common prime mover for CHP applications is the reciprocating engine, which has high mechanical efficiency over a wide range of loading. By adding a turbocharger, the capacity of an engine can be increased by 30 to 40%. Four-stroke engines operating at 1,800 rpm are a typical configuration. Engines can be run on natural gas, diesel, or heavy (residual) fuel oils. In addition to the electrical power produced, thermal energy can be recovered from radiation off the engine block, exhaust gases, lubricating oil, jacket water, and the engine after-cooler. Jacket heat can be recovered either as hot water or as low-pressure steam, either under pressure in a forced circulation system or an ebullient (boiling water) system.

The gas or combustion turbine consists of a compressor that takes air at atmospheric pressure and increases its pressure for entry into the combustor where it is combined with fuel and burned. The exhaust gases in the neighborhood of 2,300°F are then delivered to the turbine, where they are converted to mechanical work. Up to 50% of the turbine power can be used to drive the compressor, so strategies to cool the inlet air and increase overall efficiencies are often implemented. The turbine exhaust temperatures are typically less than half that of the temperature entering the turbine and can be used in a heat recovery steam generator (HRSG) to produce steam for heating, or they can be used directly for a process that includes a direct-fired absorption chiller. Microturbines operate on the same principal as gas turbines but have the advantage of being small and lightweight, therefore offering installation flexibility.

The steam turbine is the workhorse of the utility power industry and can be used on a smaller scale for CHP applications. Fuel is burned in a boiler to generate high-pressure steam, where it is sent to a steam turbine to generate electrical power. Before returning to the boiler, the turbine exhaust must be condensed, and this can be done by using the heat to drive thermal processes instead of being rejected to a heat sink such as a river or cooling tower. A steam turbine can also be used in combination with a combustion turbine in what is known as a combined cycle, where the output from the HRSG is used to drive the steam turbine for additional electric power production. Unlike the combustion turbine, which can be dispatched quickly, the steam turbine system may take several hours for warm-up.

Fuel cells produce electric power without combustion by a direct conversion of the fuel into electricity typically by stripping the hydrogen from natural gas, propane, or butane and combining it with oxygen in air. The byproducts include water, direct-current electricity, heat, and low levels of CO, CO2, and NOx. Electrolyte filled “cells” are placed in series to produce the voltage potential and are arranged in parallel to develop amperage capacity. An inverter is used to convert the direct current power to alternating current power. Although the quantity of waste heat is limited since much of it is used in the conversion process, the usable temperature can be high and can develop hot water as well as low- and high-pressure steam. Although it is viewed as an emerging technology, a fuel cell’s low noise level is an advantage compared to other types of CHP systems.


A base-loaded system will operate so that the prime mover is generating at full capacity nearly year-round only being stopped for annual maintenance. At times when the rejected heat cannot be fully utilized, it will be dumped to the environment. CHP prime movers can also be operated to track either the electrical load or thermal load requirements of the site, or they can be used in a limited capacity in a peak-shaving operation. For facilities that have negotiated interruptible rates or are located in areas where the utility has instituted real-time pricing for electricity, the CHP system can be operated in an economic dispatch mode to produce power when it is less to do so that purchasing the power from the utility.

Since CHP systems use a single fuel input to provide electrical power and thermal energy, having a simultaneous need for both is a prerequisite for implementation. Leading examples of industrial applications include chemical, pulp and paper, textile, and ethanol production. The hospitality industry, where large hotels, resorts, and casinos have on-site laundry, shower, and other thermally intense needs, can find a CHP system to be an attractive proposition. Corporate research campuses offer opportunities when there is a steam distribution system that requires thermal input year-round.

Hospitals and other types of critical facilities can obtain the added benefit of a redundant power supply. Health care and higher education campuses have led the way with smaller CHP plants, but municipalities have gotten into the act with installations at airports and with municipal district heating and cooling systems. The thermal energy developed through cogeneration can be used during the cooling season to operate steam turbine-driven chillers and absorption chillers as well as for the regeneration process involved with desiccant dehumidifiers.

Municipalities have tied CHP operations with their waste programs by utilizing digester and landfill gas, trash, and other urban wastes. District Energy St. Paul operates the largest wood chip power plant in the United States. This combined heat and power plant heats 185 buildings and 300 single family homes (31.1 million sq ft), cools more than 95 buildings (18.8 million sq ft) as well as generates 25 MW of electricity. The plant uses 280,000 tons of wood waste/yr per year from the city’s recycling center, which is supplemented by natural gas, oil, and coal. Military installations account for CHP applications, including remote facilities such as radar sites in Alaska. In this application cogeneration is the obvious choice as there is no grid to tie into and there is a need for simultaneous thermal and electrical production.


The average coal-fired power plant in the U.S. operates at an efficiency of about 32%, which is primarily due to the 40% efficiency of the typical steam turbine in converting mechanical power to electrical power. Consequently, two-thirds of the prime energy input is wasted as heat to the atmosphere. Because of this, CHP systems can be viable in applications where there is a large and continuous demand for thermal energy in close proximity to the cogeneration plant.

To be economical, this thermal load should be year-round and not just seasonal in nature. CHP systems obtain most of their economic benefit from the production of electrical power where large installations may sell excess power to the electric utility, while smaller systems will typically use the power on-site to offset purchased power from the grid. CHP economics fare better where they have a high generating efficiency, so a microturbine-based system with a 24% efficiency may not be as attractive as one with a reciprocating engine with a 36% efficiency.

An example of a small CHP application is shown in the sidebar, using a gas reciprocating engine that has an electric efficiency of 32% that coincidently matches the U.S. average of coal-fired plants.


The ultimate appeal of the concept of cogeneration depends on one’s vantage point, with technicians marveling at its sheer efficiency, the environmentally minded at its promise for the economical use of the Earth’s remaining fossil fuels, and with the plant manager looking to reduce operational costs.

Most of us should by now have the sense that the cost of fossil fuels will rise over time in one of three possible scenarios: 1) slowly, as technological advances in exploration and discovery help offset increases in consumption; 2) rapidly, as we emerge from economic recession or are faced with carbon caps or taxes; or 3) catastrophically, as we head off a production cliff. Whatever your profession, political tendencies, or social disposition, you should applaud advances in the development of cogeneration technologies, since they will help slow the use of finite resources, reduce pollution, and help us compete in a competitive global economy.ES

Sidebar: Cogeneration Economics: An Example

A research campus has minimum low-pressure steam consumption of 2,700 lb/hr in the summer at night just to offset losses in the distribution system and has decided to install a CHP plant using a 500-kW natural gas reciprocating generator in a base loaded configuration, which will operate 8,600 hrs/yr. The facility has an average purchased-power cost of $0.07/kWh and a gas cost of $5/MMBtuh. The plant assumptions are an electrical conversion efficiency of 32% and a heat recovery effectiveness of 70%, for an overall efficiency of roughly 80%.
  • The plant will consume 46,000 MMBtuh of natural gas annually x $5 = $230,000/yr

  • The plant will produce 8,600 hr/yr x 500 kWh = 4,300,000 kWh for an avoided cost of 4,300,000 kWh x $0.07/kWh = $301,000

  • Annual maintenance is assumed at $0.01/kWh production or $43,000

  • The annual heat recovery is estimated at 22,500 MMBtuh, which would require a boiler input of 27,500 MMBtuh assuming an 80% efficient boiler, for an avoided cost of 27,500 MMBtuh x $5 = $137,500/yr

  • Total electric and gas avoided cost is $301,000 + $137,500 = $438,500.
The avoided cost of $438,500 minus the gas consumption of $230,000 yields a $208,500 annual utility cost savings. Subtracting out the $43,000 maintenance cost results in a $165,500 net annual savings.

At an installed cost of $1,100 per kWh or $550,000, the CHP plant has a simple payback of $550,000/$165,500 = 3.3 years.