Combined Heat and Power Plants:
Authored by:
Tom McNay, Director, Development Engineering, Cinergy Solutions, (513) 419-5971, tmcnay@cinergy.com
and
Tillman Burnett, Development Engineer, Cinergy Solutions, (513) 419-5955, tillman.burnett@cinergy.com
Edited by: Julie Jones
An Introduction to Cogeneration
Cogeneration is defined as the simultaneous production of electrical and thermal energy. It is considered to be an energy conservation measure because it utilizes heat that is lost in more conventional electric generation processes. For this reason, as well as others, many industries use cogeneration extensively. Cogeneration is used widely in the pulp and paper industry, petrochemical, metals, mining, and food industries. The primary consideration in most industrial complexes is the supply of thermal energy usually in the form of steam or hot water. For this reason electric production is often thought of as a by-product of the steam- producing process. Commercial buildings such as hotels, hospitals, universities, and shopping centers also use cogeneration on a smaller scale.
Tremendous gains in efficiency are possible with cogeneration plants, also known as combined heat and power (CHP) plants, over power plants generating only electricity. CHP plants are attractive because of plant efficiency and the reduced emissions to the environment. A good example of this is to compare a coal-fired Rankine cycle plant with a cogeneration plant. A Rankine cycle electric generating plant, which comprises most of the country’s generating base, is typically about 33% efficient. In simple terms, this means 33% of the fuel combusted is turned into power, while the rest is usually wasted as vented heat to the atmosphere. The net production of steam for process use in older industrial systems will range between 55% and 75% depending on fuel burned and the feedwater systems employed. Since a cogeneration plant provides thermal energy to a process that can be considered useful, thermal output efficiencies of over 80% are possible with CHP. This is considerably better than even state-of-the-art, gas-fired, combined cycle plants available today with an efficiency of around 58%.
By combining the production of thermal and electric energy production into
the same process, there is a reduction in the amount of fuel burned resulting
in reductions in emissions to the environment -- including those tied to acid
rain and the formation of greenhouse gases. In addition, the amount of ash
from solid fuel plants disposed of in landfills is lowered. These benefits
have led to increased interest in CHP technology and a push by the government
and environmentalists to expand the use of CHP where opportunities exist and
are feasible. President Bush’s national energy policy revealed in May 2001
at Cinergy Solutions’ cogeneration site in
Cogeneration plants are nothing new. It is not uncommon to find electric generators buried inside of old industrial process complexes. The original installation of these systems can probably be more directly linked to control and reliability rather than environmental gains or efficiency. These systems were also built to serve or offset the loads within the industrial site. However, changes in technology have expanded the possibilities for the use of cogeneration. The Public Utility Regulatory Policy Act (PURPA) also opened the door for the expanded use of cogeneration. Plants which meet PURPA’s definition for both thermal operating standards and efficiency standards (Qualifying Facilities) allow for excess electricity generated through CHP to be purchased by the local utility grid. The price must equal the utilities’ marginal cost of power. While the money made by the sale of this power would rarely justify over-sizing a plant to produce excess power, it nevertheless did open the door to break down the monopolistic use of the power grids and allow for flexibility in the design and operations of CHP plants. Furthermore, the movements towards deregulation by many states and the Federal Energy Regulatory Commission (FERC) are opening even more opportunity for CHP plants that can provide for excess power. A deregulated environment allows for sales of this excess power at market-based prices, which are much different from the utilities’ marginal cost of power.
CHP plants are often referred to as “topping cycles” or “bottoming cycles.” A topping cycle plant is a plant where electric generation is at the top or beginning of the cycle and steam or other resulting thermal energy streams are sent to other process uses after the production of electric. An example of a topping cycle is a steam boiler that sends steam to a steam turbine electric generator with exhaust steam or extraction steam from the turbine being sent to a process use. Another example is the use of a gas turbine generator used to produce electricity with the use of a heat recovery steam generator (HRSG) to recover heat from the gas turbine exhaust for the production of process steam. A topping cycle is illustrated in Figure 1.
Figure 1. CHP topping cycle example
A bottoming cycle plant is a plant that recovers steam or heat from a process
stream to produce electricity. An example of a bottoming cycle (shown in Figure
2) would be a case where steam is produced for process use and exhausted from
the process at a quality high enough to supply a steam turbine generator for
the production of electricity. Another example is heat recovered from the discharge
of a cement kiln or other process to make steam for electricity.
In both cases the efficiency gains are reached by recovering heat that would have normally been discarded or vented if it was not used for a second purpose of either process use (topping cycle) or electricity generation (bottoming cycle).
As electricity demands rise in this country and as steam and utility systems in industrial plants age and require repair and replacement, opportunities arise for the use of CHP plants that can serve the industrial complex and that can provide electricity use for others economically and in an environmentally friendly manner. In evaluating the use of a CHP plant, there are several factors to keep in consideration:
1. Steam
load vs. electric load
2. Capital
utilization / productivity
3. Reliability
requirements (steam and electric)
4. Local
electricity rates
5. Efficiency
gains vs. fuel prices
6. Fuel
availability and selection
7. Staffing
and training
In defining a CHP plant, it is important to understand the steam and electric demands of the plant. The attempt is to balance the demands and variability of the steam supply with the demands and variability of the electric generation from an economic perspective. The optimum match from an efficiency consideration is to match electric generation with the process steam demand. If considering a steam generator or boiler to supply steam to a steam turbine electric generator, best efficiency is realized if all of the steam supplied to the turbine is used for process or feedwater treatment through the exhaust of the turbine or as an extraction from the turbine. This means that a condenser is not used as a thermal sink at the turbine exhaust to allow for additional electric generation above that which is generated by the process steam demand. In the case of a gas turbine / HRSG plant, the exhaust gas stream from the gas turbine when operating at its rated capacity for electric generation is supplied to a HRSG to convert the heat from the gas into steam for process use. Additional steam can be produced by the addition of heat to the gas turbine exhaust through the use of duct burners. Duct burners are an efficient means of increasing the output of steam from the HRSG to optimize efficiency. In both of these cases, electric and steam loads must match the chosen equipment configuration. If the equipment produces less than the full needs of the facility, a second source of electric or steam is necessary to meet the required demand. A surplus of power or steam requires a sink such as the electric utility grid or a second steam customer. It is relatively easy to optimize a CHP system design for a given steam and electric demand. The difficulty, however, comes with the variability of steam and electric demand and is even more difficult when those variations are not closely correlated. Because of this it may be more cost effective to design the CHP plant for an optimum (typically lower) match of steam and electric, and utilize secondary sources of steam and electric to meet surplus demand.
A concept to consider in evaluating CHP is “fuel chargeable to power.” Fuel chargeable to power (FCP) is actually an inverse of efficiency in terms of heat rate expressed in the units Btu/kWh. The heat in the steam to process is credited to the fuel to determine the remaining fuel that is allocated to power. The formula is as follows:
FCP = (Total Fuel – Fuel Chargeable to Thermal Energy) / kW produced.
Another cost consideration is the capital productivity of the plant. This factor considers the cost of the plant construction compared to the average thermal and electric output of the plant. This factor is decreased by reducing capital costs, increasing the capacity factor, or fully utilizing the plant. Capacity factor is defined as the average load over a defined time period divided by the design capacity of the plant. A CHP plant with a capacity factor of 40% has a capital productivity factor double that of a plant with an average capacity factor of 80%. A plant designed for a load with significant variability of steam and electric not only suffers from thermal inefficiencies, but also results in a higher cost of capital on a dollar ($) per energy unit basis. This again drives economic considerations towards designing the plant to meet average loads for lowest capital cost and utilizing secondary sources to meet remaining demands.
Reliability requirements for the steam and electric loads must be factored into any CHP plant design basis. Because a CHP combines both steam and electric production from one plant, the loss of production of one commodity can also mean the loss of the other. In other words, a mechanical failure resulting in the loss of steam production can also mean a loss in electric supply capability. The length of any allowable interruption must also be considered. For some process plants a short 15-minute interruption in steam or electric may result in weeks or months of lost production to the host process plant. Depending on the critical use of the steam, either a redundant source is kept on-line in parallel with the CHP or a redundant, stand-by CHP system is installed in parallel. However, a redundant CHP plant usually results in plant inefficiencies as discussed above and an expensive plant to build. The requirement for electricity usually requires an instantaneous back-up source. The most reliable and stable source of backup is typically the local utility grid. Alternatives including redundant CHP units in parallel are again possible. However, economics and reliability will still usually lead to the direction of the utility grid.
The cost of electricity and fuel greatly influence the decisions about the design of a CHP plant, excess electric generating capability, and backup electric sources. The costs of electricity must be evaluated taking into account the demand and energy portion of the electric rates. Some electric utility companies have electric tariff rate structures that deter the development of CHP plants by their customers. These “cogen buster” rates add significant difficulties in making CHP plants economically feasible while remaining tied to the electric utility for supplemental or backup services. To effectively evaluate the “all in” costs of electric with the CHP plant it is necessary to thoroughly understand the electric load profile of the load it is serving, the expected generating capabilities of the plant and its relationship to steam loads, and the utility rates available from the local utility for supplemental power and backup power. Because cogeneration is the generation of both electric and steam, CHP plants are best fit to serve loads where the electric and steam loads are well related. The CHP plant will generate a fixed amount of electricity when fulfilling a given steam demand, or the plant will provide heat to generate a fixed steam supply when generating a given electric load. If included in the initial design, supplemental fuel can be added to generate additional steam without increasing electric output. If the CHP plant includes a condensing steam turbine generator, additional electricity can be generated by condensing steam at a loss in CHP efficiency. In cases where electric loads and steam loads are not well related, the CHP plant performance is often inefficient and the plant underutilized due to supplemental electric purchases and supplemental fuel use. The “all in” cost of electricity can be defined as:
Total CHP Electric Cost = Capital Recovery + Cost of Fuel Chargeable to Power + O&M Cost Chargeable to Power + Supplemental Electric Costs + Backup Power Costs – Excess Electric Sales
The cost to produce electricity from the CHP plant is determined based on the fuel charged to power as discussed above. The capacity of the CHP plant may vary seasonally or daily due to ambient conditions or based on the process steam demands. This is dependent on the plant design. By overlaying the CHP plant electric supply profile with the process plant electric demand, the expected supplemental electric and excess electric is determined. The electric demand seen by the utility must be evaluated considering peak requirements and variations in the electric supply capacity. Electric utility companies often will have demand “ratchets” in their rates, such that once a demand is seen at the meter the customer is billed for that demand for a defined period. This demand ratchet is then billed whether or not the meter sees that demand for the remainder of the ratchet time period. The electric utility supplier defines the cost of this supplemental electric and the revenue or credit for the excess electric sold to the utility grid. The local utility company will also have strict requirements for operating a generator in parallel with its electric service and for interconnecting to the utility grid. Reliability of the CHP plant will result in backup electric costs due to forced outages. Backup charges can be costly. A company considering the installation of a CHP plant must clearly understand the cost impact and potential of these external sales and purchases. See Figure 3.
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Figure 3. Seasonal variations in CHP capacity and load will result in excess capacity for sales to the utility grid and shortfalls in capacity which will require supplemental power purchases.
The high efficiencies, reduced emissions, and fuel use are attractive enticers to switch to cogeneration from traditional paths. However, fuel source is a significant cost driver even with the large efficiency gains. Replacement of a retiring coal-fired steam plant with a new state-of-the-art, gas-fired CHP plant may not be the most cost-effective approach. Even with a reduction in fuel usage of 30% for the same thermal output, the price for natural gas compared to coal is even more significant. The result can be a greater total fuel cost with CHP. The economic analysis of the plant must include a full comparison of costs for electric and steam. Volatility of fuel prices and electric prices can make the analysis difficult. Capital project needs, existing system reliability, and other drivers often influence the final decisions to implement a CHP plant.
The technology and equipment used in today’s state-of-the-art cogeneration plants usually requires experience and skills, which may not be found in the ranks of an industrial company’s existing utility staff. Staffing and training is an additional factor that is best considered upfront rather than just before start-up of the new facility. Reliability shortfalls while skills are being learned can be extremely costly to a company. An alternative approach is to implement a CHP plant through a third party energy service provider. This outsourcing approach assures that the learning curve is accelerated. Skills are acquired and training is provided by the energy service provider with experience in CHP systems and equipment. The energy partner can also provide services in the design and construction of the CHP plant, as well as O&M services, financing, and possible ownership or lease back of the plant. Regardless of the approach to O&M, it is important to consider the change in required skill sets, available talent, and costs to successfully meet the energy demands of the host site with a new CHP plant.
Cogeneration / Combined Heat and Power (CHP) plants are efficient means to generating electric and steam or other useful thermal outputs. The benefits to industrial companies in terms of reduced energy costs can be substantial in the right situations. As discussed, there are many conditions and considerations to evaluate before implementing a CHP project including fuel availability and prices, permit risks, reliability requirements, design and construction factors, economic feasibility, and electric utility company interfaces. Properly developed and implemented CHP plants can create a great win-win for both the industrial customer served by the CHP project and the surrounding environment. Industrial CHP opportunities serve as a platform from which to build future electric generation and to efficiently meet growing electric demands with an environmentally friendly approach.
Cinergy Solutions www.cinergysolutions.com is a wholely owned subsidiary of Cinergy Corp. created in October 1996 focusing on combined heat and power opportunities and central utility services with an interest in 1320 MW of electric capacity, 2939 MW of steam or thermal capacity and 343 MW thermal chilled water supply. The parent company, Cinergy Corp., owns and/or operates nearly 6000 MW of regulated generating capacity, 7000 MW of deregulated electric generation and 4500 MW (electric and thermal) of non-regulated combined heat & power capacity. .