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What is a Combined Cycle Power Plant?

As opposed to a Simple Cycle Power Plant that is not very efficient as the heat from the turbine is "wasted" to the atmosphere, a Combined Cycle Power Plant ("CCPP") recovers this heat. CCPP's, also referred to as "Combined Cycle Cogeneration, is a natural gas (or diesel) turbine coupled with an electrical generator, together, referred to as a "genset." The exhaust heat from the gas turbine is directed to a waste heat recovery boiler ("WHRB") or heat-recovery steam generator ("HRSG"). The steam from the WHRB or HRSG where the steam is directed to a steam turbine generator where the steam is used to power the steam turbine genset. By capturing the waste heat of the gas turbine in a Combined Cycle Power Plant, and putting it to work, the overall thermal efficiency of the plant is increased. In a typical cogeneration plant, electric power is generated but some of the steam from the WHRB or HRSG is used for process heat. By diagram below, the combined-cycle power plant combines the Rankine (steam turbine) and Brayton (gas turbine) thermodynamic cycles by using heat recovery boilers to capture the energy in the gas turbine exhaust gases for steam production to supply a steam turbine as shown in the figure "Combined-Cycle Cogeneration". Process steam can be also provided for industrial purposes.

Fossil fuel-fired (central) power plants use either steam or combustion turbines to provide the mechanical power to electrical generators. Pressurized high temperature steam or gas expands through various stages of a turbine, transferring energy to the rotating turbine blades. The turbine is mechanically coupled to a generator, which produces electricity.

Steam Turbine Power Plants:

Steam turbine power plants operate on a Rankine cycle. The steam is created by a boiler, where pure water passes through a series of tubes to capture heat from the firebox and then boils under high pressure to become superheated steam. The heat in the firebox is normally provided by burning fossil fuel (e.g. coal, fuel oil or natural gas). However, the heat can also be provided by biomass, solar energy or nuclear fuel. The superheated steam leaving the boiler then enters the steam turbine throttle, where it powers the turbine and connected generator to make electricity. After the steam expands through the turbine, it exits the back end of the turbine, where it is cooled and condensed back to water in the surface condenser. This condensate is then returned to the boiler through high-pressure feedpumps for reuse. Heat from the condensing steam is normally rejected from the condenser to a body of water, such as a river or cooling tower.

Steam turbine plants generally have a history of achieving up to 95% availability and can operate for more than a year between shutdowns for maintenance and inspections. Their unplanned or forced outage rates are typically less than 2% or less than one week per year.

Modern large steam turbine plants (over 500 MW) have efficiencies approaching 40-45%. These plants have installed costs between $800 and$2000/kW, depending on environmental permitting requirements.

Combustion (Gas) Turbines:

Combustion turbine plants operate on the Brayton cycle. They use a compressor to compress the inlet air upstream of a combustion chamber. Then the fuel is introduced and ignited to produce a high temperature, high-pressure gas that enters and expands through the turbine section. The turbine section powers both the generator and compressor. Combustion turbines are also able to burn a wide range of liquid and gaseous fuels from crude oil to natural gas.

The combustion turbine’s energy conversion typically ranges between 25% to 35% efficiency as a simple cycle. The simple cycle efficiency can be increased by installing a recuperator or waste heat boiler onto the turbine’s exhaust. A recuperator captures waste heat in the turbine exhaust stream to preheat the compressor discharge air before it enters the combustion chamber. A waste heat boiler generates steam by capturing heat form the turbine exhaust. These boilers are known as heat recovery steam generators (HRSG). They can provide steam for heating or industrial processes, which is called cogeneration. High-pressure steam from these boilers can also generate power with steam turbines, which is called a combined cycle (steam and combustion turbine operation). Recuperators and HRSGs can increase the combustion turbine’s overall energy cycle efficiency up to 80%.

Calculating Heat Rate: Q&A

Even with today’s fuel prices dropping the way they are, calculating and monitoring your heat rate is important. Changes in heat rate can indicate problems with your unit – problems may include instrument calibration drift, gas path fouling or foreign object damage (FOD). Although, in most cases, performance losses due to FOD are noticeable without getting out the calculator.

There are only three numbers that go into the heat rate calculation, so it should be simple, right? But, when you look at those three numbers a little closer, several questions can come up.

First, the calculation:

Heat Rate = Fuel Flow * Fuel Heating Value / Power Output

The first question is: What are the engineering units on these values?

In the US, Heat Rate is most often shown in Btu/kWh. Fuel Flow can be in a number of different units, the most common being KPPH (thousands of pounds per hour), PPS (pounds per second) or SCFM (standard cubic feet per minute). Fuel Heating Value might be provided in Btu/SCF or Btu/lb. Power Output is nearly always in either kW or MW.

For places outside the US, Heat Rate is most often shown in kJ/kWh. Fuel Flow might be reported in m3/hr (standard cubic meters per hour) or kg/hr. Fuel Heating Value may be in GJ/kg, or GJ/m3. Power Output is still in either kW or MW.

As long as your fuel flow rate and fuel heating value are in compatible units (both mass basis or both volume basis), your units should cancel out. If not, you will need to know the density of your fuel (kg/m3) in order to convert them to a common basis. To calculated the density of the fuel, you’ll need to know the constituent analysis: for natural gas, this would mean the volume percent of Methane, Ethane, Propane, Hexane, etc. Note: Industry standards, such as ASME PTC-22, provide guidance on converting the constituent analysis to a density (as well as calculating the heating value).

The next question is: Where does the fuel heating value come from? The best answer for this question is to have your own gas chromatograph or heating value lab on site. A more common source of fuel heating value and constituent analysis is your fuel supplier. If the supplier cannot provide you the detail you need for the time frame you need, or if there are mixing stations between their reporting station and your unit, you may need to take your own fuel samples and send them to a laboratory for analysis. You’ll need to determine the source of your fuel heating value prior to calculating heat rate, just in case you do need to take your own samples. Samples need to be taken at an approved location (free from moisture or other ‘heavy’ particles that are filtered out prior to combustion in the unit), and must be transported in an approved container (an approved pressurized cylinder for natural gas) to an appropriate lab.

Once you have your fuel heating value source, the sources for the other two values must be found as well, but luckily, these two are normally easier to identify. There are normally two choices for fuel and power output: At the unit, or at the plant boundary (i.e. the billing meters). The heat rate you need to determine will define which meters to use.

For a gas turbine unit heat rate, you’ll want to record the fuel flow to the gas turbine at the meter closest to the unit and the power output from the power meter on the gas turbine generator – again, at the meter closest to the unit

For an overall plant or facility heat rate, you’ll probably want to use the billing meters for both gas and electricity – and this should therefore be a net heat rate for the facility (after all auxiliary and house loads have been accounted for).

There is still the question of uncertainty, or: How accurate do I know my calculated heat rate? For an ASME PTC level test, facility heat rate should be known with an error band of less than 1.5% (including corrections to reference conditions). When doing spot checks for heat rate using permanently installed instrumentation and a fuel suppler reported heating value, the uncertainty may be much higher – it all depends on the sources of your information.

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