Choosing Cogen

Cogeneration, also known as combined heat and power, is the simultaneous production and utilization of power and heat, typically in the form of electricity and either steam or hot water. Because the heat generated by the production of electricity is captured and utilized—and not expelled as waste heat—successful cogeneration results in a much higher fuel efficiency and lower energy costs.

There are many options for small on-site cogeneration, but the most dramatic developments in recent years center around small combustion turbines and emerging distributed-generation technologies such as fuel cells and microturbines. These "prime-mover" technologies feature low emissions and high efficiency, and each has its own appeal for specific applications. Another option, reciprocating-engine-based systems, has also remained popular for small-scale cogen—particularly in the sub-5-MW range where the technology offers low capital costs, efficiency and reliability, making it highly competitive with other options.

Regardless of which technology is used, all small-scale cogen projects must start with a thorough screening of many factors—namely a site's thermal and electrical load profiles, as well as its technical and permit constraints. Once these issues are fully understood, the challenges are twofold: to integrate the technology that best meets a site's needs and to operate and maintain the chosen option for highest possible efficiency.

For purposes of this discussion, the focus is on systems based around small gas-turbine units in the sub-15-MW range, and fuel-cell or microturbine-based options in the sub-500-kW range.

In breaking down a facility's thermal and electrical loads, it is especially important to note projected daily, weekly and seasonal variations. For a retrofit, it may be necessary to look at the facility's logbooks and utility records for the past two years or more in order to gain a true picture of the seasonal load profile.

Because prime movers—gas turbines, fuel cells and microturbines—generally run more efficiently when operated at or near full load, cogen system designers should aim to size units to operate as close to full load for as much of the time as possible. As a result, units may be sized too small to meet peak seasonal demand, and a facility may need to buy more power (See "Small Gas Turbines in Action," below).

As part of the economic screening, both installed costs and life-cycle costs must be analyzed. Thus, it is critical to understand all operation and maintenance costs. For example, how often do major overhauls for the main cogen systems and their auxiliaries have to be conducted? What will it cost to man a facility, including required training and certification? What will the costs be for insurance, permitting and environmental impact statements? How much will the replacement energy cost be during planned and unplanned system outages?

A thorough screening also examines federal and state grants, as well as any available tax incentives. For example, one fuel cell project currently under development at a pharmaceutical company in New Jersey is receiving more than $700,000 in clean-energy incentives from the state, plus $200,000 from the U.S. Dept. of Energy as part of a program promoting clean power technologies.

Other key economic and technical considerations include:

• A conservative review of likely costs for power purchase, standby power and fuel supply.
• Utility inter-tie requirements for fuel and electricity.
• Analysis of the facility's tolerance for temporary outages and how quickly backup power will kick in.
• Integration of auxiliary systems—existing or new—into the cogen system, such as feedwater treatment, steam distribution and condensate systems.
• Development of plans and documentation for plant commissioning; cogen system operation; operator training and safety; and scheduled maintenance of all auxiliaries, such as water treatment and gas-compression systems.
• Evaluation of spare parts requirements for auxiliaries.

Once evaluations are completed, assorted cogen options can be analyzed.

For example, gas turbines (GTs), when paired with heat-recovery steam generators (HRSGs), have been successfully used for the cogeneration of electricity and steam for more than four decades in difficult, remote applications such as oil fields, off-shore drilling platforms and gas pipelines. Over the past 15 years, thousands of megawatts of GT-based cogeneration have been installed in North America alone.

One of the big benefits of GT-based cogen in the sub-15-MW range is that it ideally meets the thermal and electric needs of many mid- to large-sized facilities, including hospitals and campus-style complexes such as corporate office parks, research centers, universities and other institutions. In addition, anywhere utility power costs are high and gas prices are low, GT-based systems may be economical. Similarly, any sites where inefficient or outdated boilers cannot meet new emissions requirements may be an opportunity for gas-based cogeneration.GT/HRSG cogen systems are reliable, efficient and feature very low emissions. They are often modular pre-packaged systems delivered to a site for integration with other packages such as gas compressor skids or water-treatment systems. Some newer units also feature on-skid controls which facilitate shorter commissioning time with fewer field connections (see figure above).

GT-based systems also offer great flexibility in the rate of steam production. For example, one manufacturer's 11.7-MW unit can be combined with different HRSG options to deliver 125-psig steam at rates from 49,000 lb./hr. up to 237,000 lb./hr. by using a supplemental duct burner to boost steam output. With supplemental firing, natural gas is injected for combustion within the flue-gas stream just before the steam generator, taking advantage of the abundant excess oxygen available in the GT exhaust flow.

In addition, the skids on this particular unit occupy less than 1,500 sq. ft. of floor space and can be configured for "black-start"—starting on diesel fuel, commencing electric power generation and then switching to gas fuel once the gas compression system is up and running. Because industrial gas turbines require gas-inlet pressure in excess of 175 psig, a gas-compression skid must be used unless the facility is close to a high-pressure gas main. At the same time, many gas turbines can run for extended periods on liquid fuel if the gas supply is interrupted for any reason, or if a gas-compression skid must be taken off-line for maintenance.

GT manufacturers have implemented extensive improvements in the last 10 years, and advances in component design, gas-path cooling and higher-temperature turbine materials have enabled ever higher simple-cycle thermal efficiencies. One advanced 4.2-MW unit can achieve simple-cycle efficiencies in excess of 40% and cogen cycle efficiencies topping 80% through the use of a recuperator, which boosts power output by pre-heating combustion air using energy recovered from the unit's exhaust gas stream.

One challenge faced by many GT-based designers is how to best meet required thermal and electric loads while running as close as possible to a unit's peak load. In some cases, this means that evaporative inlet-air cooling must be used to boost GT electrical output capacity during summer months when GT power output can drop off by 10% or more.

In other cases, the increased electrical output normally associated with summer air-conditioning load can instead be met or offset by the implementation of steam-turbine-driven chillers or steam-absorption cooling units. In fact, a number of companies are developing integrated energy systems (IES), which will directly package gas turbines—or other technologies—with absorption chillers in high-efficiency, power-heating-cooling configurations. In several demonstrations, exhaust gas from the prime movers is used as a direct heat source in absorption chillers. The development of these systems is currently being co-funded by $18.5 million worth of DOE grants.

The second emerging DG technology is fuel cells. These units produce electricity via an electrochemical reaction, rather than the combustion of fossil fuels, and have many appealing qualities such as near-zero pollutant emissions, the ability to operate at efficiencies topping 80%, high reliability, no moving parts, compact size and low noise. Because fuel cells are a new technology, manufacturers have not yet reached the economies of scale needed to make them cost competitive.

Although typical installed costs for fuel-cell-based cogen projects currently top $3,500 to $4,000 per kW, niche applications exist where fuel cells are ideal because they solve multiple problems (see "Investigating Fuel Cells," p. 40). For example, fuel cells can be attractive for serving critical data center loads in dense urban settings that require low-noise, low-emission technologies. Fuel cells can also eliminate the need for an uninterruptible power supply or backup batteries in some projects. One recent application at a large postal facility in Alaska demonstrates the ability of a multi-unit fuel-cell system to switch from grid-parallel to grid-independent operation in less then 4 milliseconds, which is fast enough to prevent any damage to the facility's computer systems.

Also, airborne emissions from currently available fuel cells are so low that the technology is exempt from environmental permitting requirements in many U.S. states. Noise emissions are similar to a typical HVAC installation—about 60-dBA at 30 ft. In addition, there are grants or tax incentives for using fuel cells in some states, including New York, Connecticut, California, Massachusetts and New Jersey.

In the realm of stationary power, phosphoric-acid fuel cells have become popular. One application, a 100,000 sq.-ft. pharmaceutical research center in New Jersey, features a single modular 200-kW fuel cell that serves a portion of the building's electrical load in parallel with an existing on-site generation system that provides hot water for the facility's laboratory reheat system. The unit, which is sited outside the facility at ground level, is rated to output 900,000 BTU/hr. of thermal energy.

The third option, small, high-speed microturbines, sized from 25 kW to 300 kW, can fill a wide range of niche applications, with manufacturers offering packages below $1,000 per kW and efficiencies 25% to 30% greater than what would be achieved without cogeneration (see chart on p. 42).

The first microturbine to be widely demonstrated for stationary power use is 30 kW. Approximately the size of a refrigerator, the unit was introduced in late 1998, and a 60-kW unit is also now available. Both sizes have NO_x emissions of less than 9 ppm for gas firing using a patented lean premix combustor. Emissions of carbon monoxide and hydrocarbons are reported to be less than 40 ppm. The largest multi-unit installation is a 2.4-MW plant in Japan, and one 750-kW facility has been in operation for over a year at Harbec Plastics Inc., a manufacturing company located in Ontario, N.Y., near Rochester (see story below).

According to Harbec's President Bob Bechtold, microturbines have many appealing features, but two key factors are:

• The need for extremely reliable, high-quality power because the manufacturing plant has numerous power-sensitive computer-numerical-controlled machines and CAD/CAM systems used for critical production tasks.
• The ability to operate and maintain the microturbine cogeneration plant using the existing staff of four electro-mechanical specialists.

Another manufacturer has developed a two-shaft, 70-kW recuperated microturbine system that is reportedly capable of lower heating value efficiencies up to 28%, and operating for 8,000 hours between maintenance outages, with an expected 80,000-hour service life based on typical, continuous-operation.

Whether it's small gas turbines, microturbines or fuel cells, the continued development and deployment of these technologies are expected to yield greater and greater efficiencies.