Energy Generation Alternatives

Definition

The term “cogeneration” does not have a single, accepted definition. In fact, there are many terms and acronyms that have essentially similar meanings. In this section we will define it to specifically include electric generation:

Cogeneration is the sequential generation of electric and useful thermal energy from a single energy source.

This is interchangeable with a generally accepted definition of combined heat and power (CHP). Trigeneration, sometimes referred to as combined cooling, heating, and power (CCHP), is considered a subset of cogeneration for this discussion.

There are three basic cogeneration cycle configurations: topping cycle, bottoming cycle, and combined cycle.

Topping Cycles

If electricity is generated in the first process and the rejected heat becomes an energy source for a subsequent process (such as heating and cooling a campus), then it is called a topping cycle. Topping cycles are the most common cogeneration cycles employed on college campuses. Schematic diagrams are shown in Figure 1 for three prime movers.

Figure 1(a). Cogeneration topping cycle with reciprocating engine prime mover.

Figure 1(b). Cogeneration topping cycle with combustion turbine prime mover.

Figure 1(c). Cogeneration topping cycle with steam boiler prime mover.

Bottoming Cycles

If the first process produces rejected heat that is used to generate electricity in the second cycle, then it is called a bottoming cycle. A bottoming cycle usually involves a waste heat recovery boiler that produces steam to drive a turbine generator. A schematic diagram is shown in Figure 2.

Figure 2. Cogeneration bottoming cycle.

Combined Cycles

A combined cycle is a combination of a topping and a bottoming cycle. In this case, electricity is produced on both ends of the cycle. A schematic diagram of a combined cycle using a gas turbine, heat recovery steam generator, and extraction steam turbine is shown in Figure 3.

Figure 3. Cogeneration combined cycle.

Operations Management

A cogeneration system is a complex, interactive, interdependent system, with numerous primary and secondary variables that can have a significant impact on cost-effective operations. Operating permit conditions or changes in statutory requirements may impose other restrictions. Routine and preventative maintenance activities need advance planning to mitigate and minimize the impacts of downtime. A competent engineering staff knowledgeable about these topics will provide essential support for performance testing, design and implementation of modifications, and long-range planning to ensure successful plant operation.

It is imperative that the knowledge developed by the engineering staff during the process that led to the decision to install a cogeneration system be memorialized, and this knowledge should be the basis of training for both engineering and operations staff. Operators should understand how and why the cogeneration system works, as well as how to operate the equipment. Whereas operators may not need an in-depth understanding of all engineering issues, they should have a situational awareness of how the balance of the plant as well as the outside campus reacts to their operating practices.

A cogeneration system provides both electric and thermal energy. In general, campus requirements for these two utilities are essentially independent, and the preferred mode of operation will depend on the root justifications for the cogeneration system. This discussion assumes that the generator is connected and synchronized to the electric grid.

Starting with the consideration of electric loads, thermal loads, and cogeneration system size, three basic operating scenarios are available. The first is constant full-load operation. If the electric load and thermal load are greater than the cogeneration system capacity, this mode is indicated. The balance of the electric load is served by the grid, while traditional boilers serve the balance of the thermal load. This is typically the most energy- and economically efficient operating condition for the cogeneration system because it maximizes both electric generation and heat recovery.

If the electric load is greater than the system capacity and the thermal load is less than the system capacity, then constant full-load operation is the typical mode. The balance of the electric load is served by the grid, while excess thermal capacity is rejected, clearly reducing system efficiency. Depending on the system design, this may be accomplished by bypassing the heat recovery system, venting steam, or dumping the excess recovered heat to an alternate heat sink such as a cooling tower. The other operating option is to follow the thermal load, which reduces the amount of electricity generated and increases grid electric purchases. This operating condition generally sacrifices energy efficiency, and it wastes generation capacity, which is usually the preferred energy output.

If the electric load is less than the system capacity and the thermal load is greater than the system capacity, then electric load following is the typical mode. The balance of the thermal load is served by traditional boilers. The other operating option is to follow the thermal load, which generates excess electricity that must be exported to the grid. The electric utility may require special metering and contract agreements for this operating mode.

Economic dispatch can be considered if the electric generating capacity is significantly greater than the campus electric load. In this mode, the cogeneration system is operated to generate excess electricity that is sold to the grid when the grid price paid for electricity is favorable. The economic assessment must take into account whether excess heat must be rejected. The electric utility will require special metering and contract agreements for this operating mode. There may also be grid ancillary services such as reactive power and voltage control, frequency control, or synchronized reserve dispatch that the facility may choose to participate in for additional economic value.

Overview of Technologies

The cogeneration system consists of a prime mover that consumes input fuel to drive the first process, with equipment to recover waste heat from the first process for use in the second process. For this discussion, electricity generation is the first process, and the prime movers are combustion turbines, reciprocating engines, steam turbines, and fuel cells.

A combustion turbine converts the energy of fuel to mechanical energy by combustion to turn an electric generator. It can be used in a closed cycle or an open cycle configuration (Figures 4 and 5). In a closed cycle, the working medium (usually air or helium) is physically isolated from the combustion process, so combustion products and the corrosion and erosion they produce are not present in the turbine. External combustion allows for use of a wide variety of fuels, such as coal and refuse-derived fuel. In the open cycle, which is more prevalent, the working medium, air, is compressed and used in the combustion process, and is then used to drive the turbine before exhausting back to the atmosphere. Primary fuel sources for the open cycle are natural gas and fuel oil, although landfill gas and biogas can be viable fuels with proper combustion tuning.

Figure 4. Closed cycle gas turbine schematic.

Figure 5. Open cycle gas turbine schematic.

The electrical efficiency of combustion turbine cogeneration systems varies widely. Unit selection is important because smaller units tend to be less efficient, and even similar-sized units from different manufacturers can perform much differently. Operating conditions can have a larger impact than initial equipment selection because part load operations, dirty filters, and inlet air temperatures warmer than the rated temperature will further degrade efficiencies.

A reciprocating engine also converts the energy of fuel to mechanical energy by combustion to turn an electric generator. Primary fuel sources are natural gas and fuel oil. The electrical efficiency of reciprocating engine cogeneration systems can be quite high, and the efficiencies of these systems exhibit less sensitivity to part load operations and inlet air temperatures.

A steam turbine uses a closed cycle with water as the working medium. The external combustion occurs in a boiler to produce steam that drives a steam turbine generator. The electrical efficiency of steam turbine cogeneration systems varies widely. Generator sizing has an impact, and even more important are the steam turbine exhaust conditions. A back pressure turbine can provide acceptable efficiencies if all of the steam can be used in the second process. If the steam turbine exhaust goes to a condenser, then the rejected heat is part of the electric energy balance and dramatically reduces electrical efficiency.

A fuel cell converts energy of fuel into electricity by a chemical process without combustion. A fuel cell operates like a battery, with a negative electrode, a positive electrode, and an electrolyte. At present, commercially available units use hydrogen or a hydrogen-rich fuel such as natural gas or biogas. Hydrogen is provided to the negative electrode either directly or by using a reformer to purify the fuel. The hydrogen is ionized, and the resulting electrons go through an external circuit that creates the flow of electricity. The hydrogen recombines with oxygen and the returning electrons at the positive electrode, producing water and heat. Fuel cells generate direct current and require an inverter to convert to alternating current.

Performance Ratings

Marketing literature and nominal ratings for cogeneration systems are based on standard test conditions and assumptions that generally allow valid comparisons between products and manufacturers, but these can set unrealistic expectations of performance for installed systems. The following are examples of rating characteristics that need to be considered.

Combustion turbine performance is specified at ISO Standard conditions: 15°C, 60 percent relative humidity, sea level air pressure, zero inlet and exhaust losses, and 100 percent power output. Rated power of an installed unit at 15°C may be several percent less than the ISO rating, and the fuel input may be several percent higher. This may not be a penalty if the electric efficiency losses can be offset by increased thermal efficiency. Actual ambient weather conditions will have a noticeable effect on performance. If summer peak electric generation is important, inlet cooling may be an economically justifiable option to ensure generating capacity.

Fuel input for combustion turbines and reciprocating engines is based on lower heating value, so a correction must be made when evaluating fuel purchase volumes and costs that are based on higher heating value. The difference between lower heating value and higher heating value varies by fuel. For natural gas, multiply the higher heating value by 0.91 to calculate the lower heating value. For diesel, multiply the higher heating value by 0.937 to calculate the lower heating value.

Electric power output is typically quoted at the generator terminals. Parasitic or auxiliary electric loads such as lubricant-circulating pumps, enclosure fans, and controls will consume on the order of 1 percent of the power. Other ancillary equipment also needs to be accounted for in determining the net power that can be supplied to campus loads. This could include gas compressors for supplying fuel at the required pressure, cooling-circuit pumps and fans for heat recovery and heat rejection, and chiller operation if inlet cooling is used.

The amount of recoverable heat claimed will depend on the temperature assumptions used, so it is important to understand those assumptions. Reciprocating engines and fuel cells may have separate heat-recovery loops for high-grade and low-grade heat to increase theoretical thermal efficiencies. Lower temperatures allow more heat transfer, but if the thermal load does not support those temperatures, then the recoverable heat is not usable heat, so the installation will not achieve claimed thermal efficiencies.

Fuels

Fuel selection for a cogeneration system will affect the specifications and performance of the equipment. Fuel availability, quality, delivery by pipeline or truck, the need for onsite storage, and the need for backup fuel sources are factors to consider when choosing the primary fuel.

Natural gas is a clean-burning, high-quality fuel. It has an extensive distribution pipeline that provides high reliability and availability in most regions of North America. It is generally the preferred primary fuel for a cogeneration installation. If a backup gaseous fuel source is needed, propane is an option that can be metered through an air-propane mixing station as a direct replacement for natural gas.

Fuel oil, specifically fuel oil no. 2, is a distillate oil refined from crude that meets quality standards. Although it has limited application as a primary fuel for continuous-duty cogeneration systems, it is widely used as a backup fuel to natural gas in dual-fuel installations. Air permit requirements may restrict the hours of operation on fuel oil to limit emissions of oxides of nitrogen (NOx), carbon monoxide (CO), and various trace elements in the oil that contribute to hazardous air pollutants.

Coal is a complex fuel that has a long history of use in closed cycle systems. It has significant emissions issues that discourage its use in new installations. Coal can be gasified to produce a cleaner burning syngas, but this technology is not yet commercially viable.

Biogas, digester gas, and landfill gas are alternative/renewable fuels composed primarily of methane and carbon dioxide. They can often be burned directly in atmospheric boilers, but they must be cleaned and have moisture removed so they can be used in pressurized combustion. Even with cleaning, trace elements that contribute to hazardous air pollutants may remain. Gas quantity and quality is site specific and can vary, and using this gas may affect equipment warranties. Equipment tuned for natural gas will work if small quantities of alternative gas are blended in, but combustors tuned to burn these alternative gases will probably not be suitable for natural gas.

Biomass is renewable fuel that can be used for direct combustion in closed cycle systems. Biomass quantity and quality are site specific and can vary. Moisture content is a significant consideration, because if the biomass is too wet it may not sustain combustion. Gasification to produce a syngas is an option when close-coupled to fire in atmospheric boilers. The technology is still maturing as different gasification processes and their adaptability to type and quality of the feedstock are investigated.

Waste Heat Recovery

The waste heat recovery system must be designed for the application. Heat recovery to generate steam and hot water are the typical applications. Special applications may use exhaust in direct-contact drying processes, air-to-air heat exchangers, or hot oil heat recovery.

Water-to-water heat exchangers are used on engine or fuel cell cooling circuits to recover low-grade heat in the form of hot water. Heat recovery from engine or turbine exhaust uses heat-recovery boilers producing high-temperature hot water or steam. In gas turbine applications, the exhaust contains enough excess air to support additional combustion. This allows for the opportunity to use supplemental firing to obtain additional heat at close to 100 percent recovery of the energy in the supplemental fuel. Supplemental fired heat recovery boilers can be equipped with supply air fans to allow operation when the prime mover is down for maintenance.

Regulatory Issues

Although the key legislation ensuring fair treatment of an owner who installs a cogeneration system is national, the regulatory requirements that must be satisfied vary by political and geographic region. Requirements may include the following:

• An exemption to bypass the more rigorous process for utility scale generators
• An environmental impact statement
• An air emissions permit
• An air emissions permit to construct
• An electric interconnection agreement

The specifics of the planned installation may dictate other studies, permits, and agreements that must be completed. Adjacent properties and neighborhoods may raise concerns about noise, viewshed, and traffic flow. This is not intended to be a comprehensive list, but it does illustrate that regulatory matters and public perception are a significant consideration, and they will affect implementation schedules and costs.

Screening Checklist for Cogeneration

The following questions need to be addressed early, and revisited as needed in the process of considering a cogeneration system. The responses to these questions may suggest other major points of consideration. As the assessment proceeds, the answers to these questions may change, and thus change the direction or scope of the study.

What Are My Reasons for Considering Cogeneration?

If specific quantifiable needs are not defined, such as increased reliability, energy cost savings, upgrading aging infrastructure, suitable year round thermal load, or addressing future energy requirements, then the exercise will be a waste of time and money, and the study will collect dust on the shelf. With definition it will be possible to determine if the proposed installation meets stated requirements.

Do I Have the Data?

This is historical operations data and should include purchased utility energy and costs, generated energy (chilled water, hot water, and steam), O&M labor and materials, subcontracted O&M, capital budgets, operating budgets, and unusual expense items. Higher future costs for some budget items may be acceptable if overall expenditures are reduced, but data is needed to evaluate that potential. If data is not available, additional metering may be needed to collect the information going forward. Utility rates and contracts will also be needed to determine the impact of a cogeneration project.

Who Will Perform the Evaluation?

Will the evaluation be performed by in-house engineering staff, will it be subcontracted to a consultant, or will it be provided as an at-risk evaluation by an energy services firm? A preliminary screening effort should be performed in-house to gain some understanding of the potential for cogeneration. Depending on time constraints and level of expertise, at some point it will probably be advisable to enlist outside help. This will be more productive if the screening questions are answered and data is available. The conclusions should be similar regardless of the source, but the particular expertise and biases of the evaluator will influence details of the proposed system.

Who Will Be Able to Say Yes?

There may be a number of stakeholders who must concur, and their concerns should be addressed, but who is the person who will have to say yes and sign on the dotted line? Knowing what will convince that person to say yes, and what issues will cause dismissal, is essential to implementing a project.