Designing a CHP plant
Consulting engineers should understand the criteria for determining the feasibility of using combined heat and power in their design projects.
- Know whether combined heat and power is appropriate for a project.
- Learn about steam and electrical load and capacity of CHP systems.
- Understand how to select appropriate generation systems for a facility to achieve maximum performance.
Combined heat and power (CHP) systems generate both electricity and usable heat. These cogeneration systems are often used on college or industrial campuses and in hospitals. They offer high-efficiency operation, ease of system maintenance, and sustainable design. Conventional power generation using a turbine generator is generally only 40% to 45% efficient. The turbine mechanically powers the shaft of the generator, but heat from the combustion of natural gas is exhausted to the atmosphere. Cogeneration uses that otherwise wasted thermal energy to boost the thermal efficiency to more than 80%. This can be done by using a heat recovery steam generator (HRSG).
In addition to improving overall system efficiency, CHP reduces emissions of air pollutants and provides other environmental benefits. The U.S. Environmental Protection Agency offers additional information on the environmental benefits of CHP.
Designing an actual CHP plant
A project being designed by Stanley Consultants involves adding a natural-gas-powered turbine generator and an HRSG in a new facility adjacent to the existing boiler house of an industrial campus. Electricity will be generated on-site and will supplement campus utility power. Heat from the turbine exhaust will be used to create steam to supplement the boiler plant production.
The new facility will include a nominal 6.5-MW gas turbine generator with an HRSG. The system will include a bypass damper and bypass stack to allow the gas turbine to operate without the HRSG in operation. Electricity from the turbine generator will supply power to a substation and provide auxiliary power for the new CHP facility.
The turbine generator will burn natural gas to produce electricity (6,200 to 6,800 kW) to supplement the electrical supply for the campus. Exhaust gas from the turbine will be used for creating process and heating steam to supplement the steam capacity of the boiler plant.
The HRSG will replace an old gas-fired boiler and will have a steam capacity of 100,000 lb/hr, which is similar to, but slightly larger than the unit being retired. It will normally operate in conjunction with the turbine generator with the auxiliary firing of natural gas in a supplemental burner to control steam header pressure. The supplemental burner also has the capacity to allow the HRSG to operate at full capacity if the turbine is offline. Minimum steam requirements from the existing boiler house are normally around 40,000 lb/hr. The HRSG was sized to operate at this steam capacity level at minimum auxiliary firing.
Based on the technical specifications, Rentech proposed an O-type, water wall HRSG. This was used as the basis for the design.
Steam flow below 40,000 lb/hr will be achieved by modulating the bypass damper to divert some of the turbine exhaust out the bypass stack to reduce HRSG steam output. The HRSG is also supplied with a fresh air fan. The fan is ducted to pull outside air for HRSG combustion when the turbine is not operational. If the turbine trips offline, the fresh air fan will automatically start and maintain combustion air to the HRSG as the bypass damper opens to the full bypass position. This will allow the HRSG to operate at full rated capacity independent of turbine operation.
Supply and exhaust ductwork is extended through the roof of the CHP plant. This includes ventilation (supply and exhaust) air for the turbine and generator enclosures. Noise emissions are mitigated with silencers and, if required, special building construction. The combustion air inlet for the turbine requires a large filter to protect the turbine. There were several considerations in selecting the duct arrangement. Exhaust air is directed away from the intakes, and the intakes are raised above roof level to avoid drifting snow from entering the intakes. Access was provided for filter maintenance. Also, a future CHP plant adjacent to the new facility had to be considered (see Figure 1).
The turbine generator will be connected to a nominal 15-kV bus in the new facility. A transformer will reduce the power to 480 V for use by the turbine and HRSG auxiliary loads. This electrical gear will be located in an electrical room inside the new facility. The two main feeds to the substation will be supplied from this electrical room. This configuration will allow the new turbine to operate in an island mode, supplying power to its own auxiliary loads only. Island mode refers to when the turbine generator continues to power the CHP, even though grid power from the electric utility is no longer present. It is assumed that the existing heating plant will always be able to supply boiler feedwater to the new HRSG in the turbine facility.
Electricity will be provided to the substation by one of two redundant feeds. Only one feed will be operational at a time. System electrical load will be controlled from the substation. The turbine generator will operate either base loaded at a fixed power production level, or it can be set to follow the required loading up to the capacity of the unit.
Normal operation will be with the gas turbine supplying a fixed amount of electrical power to the substation and operating in parallel with the utility. If the system is ever in island mode, it will be capable of synchronizing with either electrical feed. Load shedding in the substation will be a manual operation. Power cannot be supplied back to the existing heating plant.
However, emergency power will be supplied from the heating plant. The existing emergency generator will be connected to the new facility to provide "black-start" power. Black start is the process of restoring a power station to operation without relying on the external electric power transmission network. This emergency generator has sufficient capacity to start the new turbine and its auxiliary loads only if the heating plant is not also using the emergency generator to supply loads. The new turbine facility should be started first and put in island mode. Then the emergency generator can be used to start the heating plant.
The existing central heating plant will provide most of the support systems for the new CHP facility. Boiler feedwater will be provided from existing boiler feed pumps. A new boiler feedwater line will connect the existing boiler feedwater header to the new CHP facility. This will eliminate the need for any new makeup water, condensate, or boiler feed pumps. These existing pumps are connected to an essential power system.
Steam: A single steam line will run from the new HRSG to the existing steam supply headers in the heating plant. The HRSG will produce 30,000 lb/hr to 100,000 lb/hr, 190 psig saturated steam to supplement the existing boiler house production. The piping system is sized to accommodate a future steam generator and includes a steam stop valve, nonreturn valve, safety relief valves, a steam-flow meter, and flanged connections designated for future use.
Blowdown and service water: HRSG blowdown will be returned to the existing blowdown tank. Building service water will also be provided from the existing central heating plant. A supply line will be routed to the new CHP facility. An instantaneous water heater in the janitor's closet will provide hot water in that location, and service water will be provided throughout the new CHP installation.
Natural gas supply: A new natural gas line will bring high-pressure (270 psig minimum) gas to the new facility and will be the only fuel for the gas turbine or HRSG. This gas will be piped directly to the fuel train of the gas turbine, eliminating the need for gas compressors. A pressure reducing station will reduce the pressure to around 30 psig for use by the HRSG. This low-pressure line will also be connected to the existing natural gas line in the heating plant to act as a backup supply. A second pressure reducing station will provide natural gas for the backup building heaters. The heaters are not designed to keep the building at a comfortable 68 F with the gas turbine and HRSG shut down, but will maintain a minimum temperature to protect equipment and fire protection piping from freezing.
Lube oil: Hot lube oil from the turbine will be collected in a tank, pumped to an air-cooled lube oil cooler on the roof of the CHP building, and returned to the turbine. The system is primarily integral to the equipment.
Compressed air: A new instrument air compressor, air receiver, and air dryer will be provided. This system will be connected into the existing air supply system. The new air compressor is sized for the new turbine facility only, and is not sized to supply air to the existing plant.
Wastewater: Wastewater from the CHP building includes oily water collected from floor drains throughout the building and the utility sink drain. Drain lines will be below the floor and will slope to a common header, which will drain into an oil/water separator. The separator will be located flush with the floor of the CHP building with an access panel for maintenance. Water will drain from the separator to a new manhole. The new manhole will be connected to the existing waste water system.
Building heating and ventilation: The new CHP building will have ventilation in each of the spaces and heating for freeze protection when the unit is down. The turbine/HRSG space and the electrical room will be ventilated using roof-mounted exhaust fans to draw outside air into the space through operating louvers located on the exterior walls. Due to the heat generated by the equipment, these spaces will need ventilation year-round whenever the equipment is in operation. When the equipment is down, gas-fired unit heaters will maintain a minimum of 50 F in the spaces to provide freeze protection. The maintenance room will be ventilated using a roof-mounted exhaust fan to draw air into the space.
Fire and safety: The entire CHP building, including the electrical room, maintenance area, and corridor, will have a sprinkler system for fire suppression. Fire water will be supplied from the existing fire pump in the boiler plant. A new dedicated fire waterline will be provided from the pump discharge, through the boiler plant, to the CHP building. In the CHP maintenance room, fire water will flow through a single, wet-pipe sprinkler riser and to the sprinkler system. A test connection and Siamese hose connection will be conveniently located outside the building for fire truck access. Additionally, fire extinguishers will be provided throughout the building.
Stanley Consultants has completed the preliminary design of this new CHP facility. The project will be funded through an energy service agreement. The final design is scheduled to be completed by early 2015, and construction is to begin shortly after. The facility is scheduled to be operational in 2016, and will provide the capability of generating 6.5 MW of electricity for campus use and will produce 100,000 lb/hr of steam to supplement the existing steam plant at a fraction of conventional purchased energy cost.
CHP design best practices
To determine if CHP is an economical option for a new or existing facility, several factors must be considered. Costs of electricity, fuel, maintenance, and construction are only some of those factors. Others include hours of operation, heat rate, base load requirements, electric and thermal capacity, utilization factors, and the proposed size of the turbine-generator.
Utility rates can be estimated through examination of historic utility bills. However, historic trends of the cost of utilities do not necessarily indicate what the future rates will be. Also, consider peak demand rates for electricity, which may have a significant impact on the operating time of the CHP, and standby rates that may apply during CHP outages. Discuss these rates with the facility owner and agree on a basis for economic analysis.
Operation and maintenance costs must be considered. Can the existing plant operators be used for operation of the new CHP? If not, include costs for additional personnel. If the new equipment is replacing old equipment (i.e., HRSG replacing an old boiler), then avoided costs to replace the old equipment can be considered. Replacing a boiler with a new HRSG will also be a factor when obtaining a new air permit.
There are several ways to fund the project, such as through a design-build contract, an energy performance contract, an up-front capital investment, or other methods. Each project will be based on unique circumstances and operational needs of the facility owner and therefore must be modeled accordingly in the financial analysis. Utility rebates are often available. Review EPA resources for possible rebates.
CHP is prevalent in industrial and medical applications because of the continuous need for steam throughout the year for sterilization or industrial processes. College campuses, hospitals, industrial sites, and military bases may also use steam for absorption chillers in the summer months to increase the CHP operating time. Savings will vary with each project based on specific energy rates and usage. Maximizing the hours of operation (producing electricity and steam) will maximize savings and thus minimize the payback period.
Ideally, energy consumption data must be available to develop annual load profiles. For systems that use data logging, hourly data should be available. Otherwise, monthly averages can be used. If electric and steam meters are not in place or historic data has not been recorded, then a study of all the campus energy users must be done to estimate load profiles. Loads must be adjusted for known future projects that may add new users or retire existing ones. Remember to include additional loads for the new CHP plant in the adjusted profile (see Figure 2).
In this example, observe that steam energy in kWt (kilowatt-thermal) is used all year. Steam demand increases in the heating season while electrical demand decreases. Monthly averages are often used for demand curves. However, for facilities with large load variations, daily or hourly loads should be considered.
Hours of operation can be determined by analysis of thermal and electric load duration curves. An electric load duration curve graphically depicts the number of hours per year the facility consumes electricity from peak load to no load. Similarly, a steam load duration curve depicts the number of hours per year the facility consumes steam from peak load to no load.
For example, in the steam load duration curve shown in Figure 3, a 70,000 lb/hr steam generator would operate at full load for more than 6,000 hr/yr. In the electric load duration curve, a 7-MW generator would operate at full load for more than 6,500 hr/yr (see Figure 4). To provide the maximum efficiency, the capacities of the HRSG and the turbine generator must be selected carefully to minimize heat and fuel waste. If the turbine exhaust gas does not provide the heat energy required to run the HRSG at full load, supplemental firing will be required to generate the designed steam condition. If the turbine exhaust energy is too great for the need of the HRSG, it will need to be exhausted to the atmosphere.
Mark Wagner is a senior mechanical engineer at Stanley Consultants. He has nearly 25 years of experience in study and design of central plants, energy conservation, and process systems for federal, educational, commercial, industrial, and power facilities.