An Overview of Cogeneration Operations

What Is the Process of a Cogeneration Plant?

When a power plant creates electricity, it also generates heat. If the plant emits that heat into the atmosphere as exhaust, it constitutes a massive waste of energy. The majority of the heat may be collected and reused. When heat is repurposed, the power plant operates as a cogeneration system.

The cogeneration process may improve total energy efficiency, with typical systems achieving efficiency levels ranging from 65 to 90 percent. Businesses that employ cogeneration may reduce greenhouse gas emissions and pollutants while lowering operating costs and increasing self-sufficiency.

The History of CHP

Thomas Edison, widely regarded as America’s greatest inventor, planned and completed Pearl Street Station in New York City in 1892.

The idea of combining heat and electricity is not new. CHP was utilized in Europe and the United States as early as 1880 to 1890. Many companies employed their own coal-fired power plants to create the energy that powered their mills, factories, or mines during those years.

As a byproduct, the steam was utilized to provide thermal energy for different industrial operations or to heat the area.

In 1882, Thomas Edison planned and constructed the first commercial power plant in the United States, which also occurred to be a cogeneration facility. The thermal waste of Edison’s Pearl Street Station in New York was sent as steam to local factories, as well as heating neighboring buildings.

The Rise and Fall of CHP Utilization

CHP systems provided around 58 percent of the total on-site electrical power generated in industrial enterprises in the United States in the early 1900s. According to “Cogeneration: Technologies, Optimization, and Implementation,” edited by Christos A. Frangopoulos, that number had dropped to barely 5% by 1974.

There were several explanations for the precipitous drop.

Electricity from central power grids grew more dependable and less expensive to purchase, while fuel, such as natural gas, became more affordable, making privately owned coal-fired on-site power plants less appealing. In addition, the government raised the quantity and scope of rules and limitations pertaining to power generating. However, as fuel prices surged in 1973 and public awareness of the detrimental impacts of pollution expanded, cogeneration regained prominence.

Why Should You Use Cogeneration?

Cogeneration has a number of advantages. The primary motivations for using CHP are to save energy and money by lowering fuel use. Existing CHP customers in the United Kingdom, for example, save 20% on their energy bills.

When fuel energy is turned into mechanical or electrical energy via CHP, the majority of the heat emitted is not squandered. Less fuel is required to perform the same quantity of productive work as a typical power plant.

This lower fuel consumption has various advantages, including:

  • Reduced gasoline expenses
  • Fuel storage and transportation requirements are reduced.
  • Emissions reduction — CHP is one of the most cost-effective methods of reducing carbon emissions.
  • Machine wear is minimized as a result of reduced pollution exposure.
  • Another advantage is security.

Cogeneration is regarded as a secure power source since it produces stand-alone electricity that is not reliant on a municipal power system. A cogeneration-powered firm may operate off-grid or simply supplement to meet a rise in power demand.

The Basic Elements of a Cogeneration Plant

A typical cogeneration facility, at its most basic, consists of an electricity generator and a heat-recovery system. Here are some fundamental components of a CHP system:

  • Prime movers: These machines convert fuel into heat and electrical energy, which may then be utilized to create mechanical energy. Gas turbines and reciprocating engines are examples of primary movers.
  • Mechanical energy is converted into electrical energy by an electrical generator.
  • System of heat recovery: Heat is captured from the primary mover.
  • Heat exchanger: Ensures that the collected heat is used.

What Are the Fuels Used in Cogeneration Plants?

Cogeneration facilities may run on a range of fuels, including natural gas, diesel, gasoline, coal, and biofuels.

Biofuels used in cogeneration are generally produced from renewable resources such as landfill gas and agricultural solid waste.

CHP systems are classified into two kinds.

  • Cycle plants at the top: The production of power is the first step in a topping cycle system.
  • Plants in the bottoming cycle: The first step is to create heat – waste heat generates steam, which is subsequently utilized to generate electricity.

Bottoming cycle plants may be found in businesses that employ very hot furnaces. They are less prevalent than topping cycle plants, because to the ease with which surplus power may be sold.

Who Can Benefit from Cogeneration?

Heat and electricity are in high demand in the industrial sector. Metal makers, for example, largely employ heat, while others mostly use electricity. Other businesses need varied amounts of heat and power.

A recycled energy system may help in any circumstance. A factory that uses more heat than electricity may sell the heat to a utility, and surplus power can be sold in the same way.

There are three sizes of cogeneration plants:

  • Small: The military, colleges, and non-utility corporations run several small CHP plants in the United States and Canada. What they have in common is a strong demand for energy, as well as a pressing need for dependable and self-sufficient energy sources. According to a Scientific American article, a computer networking firm that uses CHP saves roughly $300,000 in energy expenditures each year.
  • Medium: The market for medium-scale cogeneration systems is expanding. According to David Flin’s “Cogeneration: A User’s Guide,” medium-scale units produce 50 to 500 kW of electricity. This category includes industries that demand significant heat and energy loads, such as hospitals and hotels.
  • Large: Large CHP plants may be found in energy-intensive industries like as oil refineries and food processing plants. These may generate 500 kW or more of electricity.

Cogeneration makes sense when the necessary circumstances are met. It’s a dependable and efficient solution to offer on-site electricity that’s both inexpensive and ecologically friendly.

A thorough knowledge of steam-turbine operating and power generating costs may aid in increasing total cogeneration profitability. This article explains the fundamental economics of cogeneration.

Cogeneration enables a facility to lessen its dependency on external electrical energy purchases by utilizing steam to spin turbines and create electricity. This article outlines best practices for steam cogeneration system selection, operation, integration, and control.

Cogeneration’s thermodynamics

To calculate the energy conversion efficiency of a turbine, you must first comprehend the fundamental thermodynamic words and ideas.

The quantity of energy per unit mass of steam is expressed as specific enthalpy (h). It is often measured in BTU/lb, MWh/kg, or GJ/kg.

The specific heat of vaporization (hlg) is the amount of energy needed per unit mass to convert the condition of water to steam at constant pressure. It is often represented in BTU/lb, MWh/kg, or GJ/kg units.

Specific entropy (s) may be regarded of as steam’s potential energy, with a lower entropy value indicating a greater potential energy and a higher entropy value indicating a lower potential energy. The total system entropy of a closed system with no losses may either rise or remain constant (sfinal sinitial).

The ratio of the actual work generated by the turbine to the greatest amount of work that the turbine might extract if the process were optimal is referred to as steam turbine efficiency (eff) (i.e., a no-loss isentropic expansion).

A steam turbine with a 100 percent isentropic efficiency may harvest all of the potential power in the steam. The input entropy will equal the output entropy in this hypothetical instance. A turbine with a 0 percent efficiency cannot transform thermal energy into power. This is referred to as an adiabatic process since the entrance and output enthalpy are equal.

Follow these three procedures to compute the amount of power produced and the output conditions of the steam turbine:

  • Determine the output enthalpy for a turbine that is 100 percent efficient (sin = sout).
  • To estimate the true amount of power extracted, calculate the amount of energy extracted by the turbine at 100 percent efficiency (hisen = hg,in – hg,out,isen) and multiply that figure by the turbine efficiency.
  • Recalculate the outlet enthalpy (hg,out= hg,in – effhisen) and use a steam table to compute additional steam conditions.

Steam turbine types

Steam turbines are classified into two types: backpressure and condensing. The output of a backpressure turbine is linked to a header, which distributes steam to the different process users. In a condensing turbine, exit steam is routed to a vacuum-operated condenser.

Basic backpressure or condensing turbines are often found exclusively in simple steam systems. Numerous backpressure turbines may be connected in series to produce a single turbine with multiple steam exits in more sophisticated applications. Extraction turbines are turbines with several outlet ports that are often used for cogeneration because they enable steam to be withdrawn at one or more intermediate places in the turbine casing.

Extractive condensing turbines High-pressure (HP) steam generated by the boilers is delivered to the steam turbine in this extraction turbine, and the turbine governor valve regulates the flowrate of the incoming steam flow to the turbine. The MP extraction steam flow is regulated by throttling the extraction valve, where opening the extraction valve reduces the extraction flow and closing the extraction valve increases the extraction flow. Modulating the flow of steam at the extraction point also affects the pressure in the MP header. In a steam turbine, there is almost no steam generation or loss. As a result, the input steam flow equals the total of the extraction steam flow and the condenser flow.

Creating a real-world CHP plant

Stanley Consultants is designing a project that will include a natural-gas-powered turbine generator and an HRSG in a new building close to an industrial campus’s existing boiler house. On-site generation of electricity will augment campus utility power. The heat produced by the turbines will be utilized to generate steam to enhance the boiler plant’s output.

A notional 6.5-MW gas turbine generator with an HRSG will be installed at the new site. The system will contain a bypass damper and bypass stack, allowing the gas turbine to run without the HRSG. The turbine generator’s electricity will power a substation and provide auxiliary power for the future CHP complex.

The turbine generator will use natural gas to generate energy (6,200 to 6,800 kW) to complement the campus’s power supply. The turbine’s exhaust gas will be utilized to generate process and heating steam, supplementing the boiler plant’s steam capacity.

The HRSG will replace an existing gas-fired boiler and have a steam capacity of 100,000 lb/hr, which is comparable to, but somewhat greater than, the unit being retired. It will generally work in tandem with the turbine generator, igniting natural gas in a supplementary burner to manage steam header pressure. The auxiliary burner can also keep the HRSG running at full capacity if the turbine goes down. The present boiler house’s minimum steam needs are typically approximately 40,000 lb/hr. The HRSG was designed to run at this steam capacity level with the least amount of auxiliary firing.

Rentech presented an O-type, water wall HRSG based on the technical parameters. This served as the foundation for the design.

To minimize HRSG steam production, the bypass damper will be modulated to deflect part of the turbine exhaust through the bypass stack, resulting in a steam flow of less than 40,000 lb/hr. A fresh air fan is also included with the HRSG. When the turbine is not in use, the fan is ducted to draw outside air for HRSG combustion. If the turbine fails, the fresh air fan will automatically start and sustain combustion air to the HRSG when the bypass damper is opened to full bypass. This will enable the HRSG to run at full capacity regardless of turbine operation.

The CHP plant’s supply and exhaust ducting runs through the roof. This covers supply and exhaust air ventilation for the turbine and generator enclosures. Silencers and, if necessary, unique building construction are used to reduce noise pollution. To safeguard the turbine, the combustion air entrance needs a big filter. Several factors were taken into account while deciding on the duct configuration. To prevent drifting snow from entering the intakes, exhaust air is diverted away from them, and the intakes are elevated above roof level. Filter maintenance was made possible. A future CHP plant next to the new complex has to be addressed as well.

Connections to electricity

In the new facility, the turbine generator will be linked to a nominal 15-kV bus. The electricity will be reduced to 480 V via a transformer for usage by the turbine and HRSG auxiliary loads. This electrical equipment will be kept in an electrical room inside the new facility. This electrical room will provide the two major feeds to the substation. The new turbine will be able to operate in an island mode, delivering electricity exclusively to its own auxiliary loads. The term “island mode” refers to the situation in which the turbine generator continues to power the CHP even when grid power from the electric utility is no longer available. The old heating plant is expected to always be able to deliver boiler feedwater to the new HRSG in the turbine facility.

One of two redundant streams will provide electricity to the substation. At any one moment, only one feed will be active. The substation will regulate the system’s electrical load. The turbine generator may be programmed to run base loaded at a preset power output level, or it can be adjusted to follow the needed loading up to the unit’s capacity.

The gas turbine will normally operate in parallel with the utility, delivering a set quantity of electrical power to the substation. If the system ever goes into island mode, it will be able to synchronize with any of the two electrical feeds. Load shedding at the substation will be done manually. The power cannot be returned to the current heating plant.

However, the heating plant will provide emergency electricity. To supply “black-start” electricity, the current emergency generator will be linked to the new facility. The process of returning a power station to operation without depending on the external electric power transmission network is known as black start. If the heating plant is not also utilizing the emergency generator to provide loads, this emergency generator has the power to start the new turbine and its auxiliary loads. The new turbine facility should be powered up first and placed in island mode. The emergency generator may then be utilized to power the heating plant.

Systems of assistance

The majority of the support systems for the new CHP facility will be provided by the existing central heating plant. Existing boiler feed pumps will provide boiler feedwater. The current boiler feedwater header will be connected to the new CHP unit through a new boiler feedwater pipe. There will be no need for any new makeup water, condensate, or boiler feed pumps as a result of this. These current pumps are linked to a critical power system.

  • Steam: A single steam line will connect the new HRSG to the heating plant’s current steam supply headers. To enhance the current boiler house output, the HRSG will provide 30,000 lb/hr to 100,000 lb/hr, 190 psig saturated steam. The pipe system is designed to handle a future steam generator and includes a steam stop valve, nonreturn valve, safety relief valves, a steam-flow meter, and future-use flanged connections.
  • HRSG blowdown and service water will be returned to the existing blowdown tank. The current central heating unit will also provide building service water. The new CHP facility will be served by a supply line. Hot water will be given in the janitor’s closet by an instantaneous water heater, and service water will be delivered throughout the entire CHP system.
  • Natural gas supply: A new natural gas line will transport high-pressure (at least 270 psig) gas to the new plant, which will be the only fuel for the gas turbine or HRSG. This gas will be fed straight to the gas turbine’s fuel train, obviating the requirement for gas compressors. The pressure will be reduced to roughly 30 psig via a pressure lowering station for use by the HRSG. This low-pressure connection will also be linked to the heating plant’s existing natural gas line as a backup source. Natural gas will be supplied via a second pressure reduction station for the backup building heaters. The heaters are not intended to keep the building at a pleasant 68 degrees Fahrenheit with the gas turbine and HRSG turned off, but rather to prevent equipment and fire protection pipes from freezing.
  • Lube oil: Hot turbine lube oil will be collected in a tank, pumped to an air-cooled lube oil cooler on the CHP building’s roof, and returned to the turbine. The system is largely a component of the equipment.
  • Compressed air will be given in the form of a new instrument air compressor, air receiver, and air dryer. This system will be linked to the current air supply system. The new air compressor is just large enough to give air to the new turbine facility and is not large enough to supply air to the current plant.
  • Wastewater: The CHP building’s wastewater comprises greasy water collected from floor drains throughout the facility as well as the utility sink drain. Drain lines will be installed under the floor and slope to a shared header, which will drain into an oil/water separator. The divider will be flush with the CHP building’s floor, with an access panel for maintenance. Water will be drained from the separator and sent to a new manhole. The new manhole will be linked to the current waste water system.
  • Heating and ventilation in the building: The new CHP building will include ventilation in each area as well as heating for frost protection when the unit is not in use. The turbine/HRSG area and the electrical room will be ventilated by roof-mounted exhaust fans that suck outside air into the space through operable louvers on the external walls. Because of the heat created by the equipment, these rooms will need ventilation at all times the equipment is in use. When the machinery is turned off, gas-fired unit heaters will keep the areas at a minimum temperature of 50 degrees Fahrenheit to prevent freezing. The maintenance room will be ventilated with the help of a roof-mounted exhaust fan that will pull air into the area.
  • Fire and safety: A sprinkler system will be installed throughout the CHP building, including the electrical room, maintenance area, and hallway. The boiler plant’s existing fire pump will provide fire water. A new dedicated fire waterline will be installed from the pump output to the CHP building, passing via the boiler plant. Fire water will run via a single, wet-pipe sprinkler riser and into the sprinkler system in the CHP maintenance room. For fire truck access, a test connection and Siamese hose connection will be readily positioned outside the structure. Furthermore, fire extinguishers will be placed throughout the structure.