This invention relates generally to power generation facilities, and more specifically to a method of measuring an expansion efficiency of a turbine utilized in a power plant.
At least some known power plants include a low pressure steam turbine (LP) coupled with an intermediate pressure (IP) and/or high pressure (HP) steam turbine to drive a common generator. Measuring the steam turbine efficiency, i.e. a ratio of a measured enthalpy drop to an ideal (isentropic) enthalpy drop, of the LP steam turbine may be problematic when steam entering a condenser includes a mixture of saturated steam and water. Furthermore, accurately quantifying the quality and the enthalpy of steam in a wet region of the steam flow may also problematic.
Steam turbine section expansion efficiency is commonly measured when the expansion takes place entirely in a dry or superheated region because, in the case of superheated steam, the measured temperature and pressure expressly defines steam enthalpy. The expansion efficiency of an LP steam turbine section is normally not measured in the wet region since enthalpy is no longer only a function of pressure and temperature, but is also a function of a steam moisture content. Exhaust moisture is extremely difficult to measure, and as such exhaust moisture and LP steam turbine expansion efficiency, are typically calculated by measuring other quantities and performing an energy balance calculation. Although the HP turbine and IP turbine efficiency may be directly measured, by virtue of their superheated exhausts, the uncertainty in these measurements and in the HP, IP, and LP steam turbine flow results in undesirably high uncertainty in LP power output and derived efficiency.
In one aspect, a method for measuring expansion efficiency of a turbine within a combined cycle power plant is provided. The method includes operating the power plant at a first load, wherein a gas turbine is operated with a first fuel flow and a first gas turbine inlet air flow, and wherein a steam turbine within the combined cycle power plant includes at least a first turbine exhausting superheated steam and a second turbine exhausting two phase steam, determining a first shaft output at the first load with steam supplied from a heat recovery steam generator (HRSG) to both the first steam turbine inlet and the second steam turbine inlet, maintaining the first gas turbine fuel flow, the first gas turbine inlet air flow, and the first steam turbine inlet steam flow while isolating the second steam turbine from the steam admission flow from the HRSG, determining a second shaft output while the second steam turbine is isolated from the steam admission flow, and determining an expansion efficiency of the second steam turbine based on the first shaft output and the second shaft output and a measured change in the second steam turbine admission steam flow.
In another aspect, a method for measuring expansion efficiency of a turbine within a direct fired Rankine or combined cycle power plant is provided. The method includes operating the power plant at a first load, wherein a boiler or gas turbine is operated with a first fuel flow and a first inlet air flow, and wherein a steam turbine within the power plant includes at least a first turbine exhausting superheated steam and a second turbine exhausting two phase steam and determining a first shaft output at the first load with steam extracted from the second steam turbine to a process user. The method also includes determining a second shaft output at the first fuel flow without steam extraction from the second steam turbine to a process user, and determining a second shaft output at the first fuel flow without steam extraction from the second steam turbine to a process user.
In a still another aspect, a method for measuring expansion efficiency of a turbine within a direct fired Rankine cycle power plant is provided. The method includes operating a Rankine cycle steam power plant including at least one steam turbine at a first load (fuel and air flow to the boiler) and a first HP throttle steam flow, the steam turbine including a first turbine with superheated exhaust and a second turbine with two phase exhaust and uncontrolled steam extraction to a feedwater heater, and determining a first shaft output at the first load with steam extraction flow to the extraction feedwater heater from the second steam turbine inlet or after partial expansion in the second steam turbine. The method also includes determining a second shaft output at the first load (fuel and air flow to the boiler), the first HP throttle steam flow and the extraction from the second steam turbine to feedwater heating closed, and determining an expansion efficiency of the second steam turbine using the first shaft output, the second shaft output, and a change in extraction steam flow from the second steam turbine.
a is a first portion of a table illustrating exemplary results obtained using the method shown in
b is a second portion of a table illustrating exemplary results obtained using the method shown in
c is a third portion of a table illustrating exemplary results obtained using the method shown in
In another embodiment, and referring to
In use, ambient air 40 is channeled into a turbine compressor section 42 and compressed. Compressed air is then directed into a combustion section 44 and mixed with fuel 46 and the mixture is ignited, and the combustion gases are channeled to rotate a turbine section 48. In
Exhaust heat from gas turbine 14 is introduced into HRSG 20 via an exhaust duct 52, wherein the exhaust heat is used to convert water supplied from steam turbine condenser 22 into steam for re-admission into steam turbine 16. Specifically, water from condenser 22 is supplied to each multiple pressure level (three in
After the steam has passed through LP section 32, the steam exhausts to condenser 22 to be condensed to water. The water is pumped back to HRSG 20 to restart the steam generation cycle again.
Method 100 also includes loading a combined cycle power plant, such as plant 10, to a target load for the test, typically base load, and then stabilizing power plant 10 with LP steam admitted to LP steam turbine 32. The following exemplary measurements are then taken using installed instrumentation either manually, or automatically using a data acquisition system:
After the above parameters have been recorded, the LP steam admission valve is closed, and the LP steam is bypassed to a condenser, at the same time, fuel flow and air flow to the gas turbine remain substantially constant, i.e. fuel is not increased or decreased to the gas turbine, such that the change in output from the power plant is purely a function of the change in the LP admission steam flow to the LP section. The following exemplary measurements are then recorded:
In use, a first LP section efficiency (η1) is estimated. The IP turbine and the LP turbine outputs are then calculated with and without steam admitted to the LP steam turbine. The IP efficiency for both calculations is aligned to the measured IP section efficiency with the LP admission closed. The expected change in a measured generator output ΔkW1 is then determined in accordance with:
ΔkW1=calculated (IP+LP Output) with admission−calculated (IP+LP Output) without admission. Where LP Output is calculated using first LP section efficiency (η1)
A second LP section efficiency (η2) is estimated. The IP section and the LP section outputs are then calculated with and without steam admitted to the LP section. The IP section efficiency for both calculations is again aligned to the measured IP section efficiency with the LP admission closed. The expected change in a measured generator output ΔkW2 is then determined in accordance with:
ΔkW2=calculated (IP+LP Output) with admission−calculated (IP+LP Output) without admission. Where LP Output is calculated using second LP section efficiency (η2)
The LP section efficiency is then calculated in accordance with:
The methods described herein can also be applied to other power plant configurations as long as the section efficiency immediately upstream of the LP admission can be directly measured. Additionally, the methods described herein can be accomplished manually or using a computer model which readily accounts for small changes in IP and LP section efficiencies due to a change in IP and LP exhaust pressures, when LP extraction steam is bypassed. Additionally, the model will account for the change in LP exhaust loss as a function of exhaust velocity and moisture, and generator electrical losses as a function of generator load.
In another embodiment, LP section efficiency can be calculated by iterating the computer model to match the measured (kW(1)−kW(2)) by manipulation of the estimated LP section efficiency. For example, the model initially predicts an LP section efficiency and then calculates the IP and LP outputs for both sets of measured statepoints, i.e. with and without steam admitted to the LP turbine. If the calculated ΔkW corresponds to the measured (kW(1)−kW(2)) then the correct LP efficiency has been determined. If the calculated ΔkW does not correspond to the measured (kW(1)−kW(2)) then the computer model selects another efficiency and recalculates the equation repeatedly (as required) until the correct efficiency has been determined.
a is a first portion of a table illustrating exemplary results obtained using the method shown in
In use a performance test and a data analysis procedure are used to determine the expansion efficiency of LP steam turbine. The following exemplary measurements are then taken manually using installed instrumentation, or automatically using a data acquisition system:
After the above parameters have been recorded, the LP steam extraction valve is closed, at the same time fuel flow and air flow to the gas turbine or boiler remain substantially constant, i.e. fuel is not increased or decreased to the boiler, such that the change in output from the LP section is purely a function of the change in LP steam extracted from the LP section. The following exemplary measurements are then recorded:
In use, a first LP section expansion efficiency (η1) is estimated. The IP and LP output are then calculated with and without steam extraction from the LP steam turbine. The IP efficiency for both calculations is calibrated to the measured IP section efficiency with the LP extraction valve closed. The expected change in a measured generator output ΔkW1 is then determined in accordance with:
ΔkW1=calculated (IP+LP Output) without extraction−calculated (IP+LP Output) with extraction. Where LP Output is calculated using first LP section efficiency (η1)
A second LP section efficiency (η2) is estimated. The IP and LP Output are then calculated with and without steam extraction from the LP steam turbine. The IP efficiency for both calculations is calibrated to the measured IP section efficiency with the LP extraction valve closed. The expected change in a measured generator output ΔkW2 is then determined in accordance with:
ΔkW2=calculated (IP+LP Output) without extraction−calculated (IP+LP Output) with extraction. Where LP Output is calculated using second LP section efficiency (η2)
LP steam turbine 32 efficiency can be calculated in accordance with:
Alternatively, a computer performance model of the plant can be iterated to match the measured (kW(1)−kW(2)) by manipulation of assumed LP section efficiency.
In use a performance test and a data analysis procedure are used to determine the expansion efficiency of LP steam turbine. At least the following measurements are then taken using installed instrumentation either manually, or automatically using a data acquisition system:
After the above parameters have been recorded, the LP steam extraction valve is closed while maintaining constant HP steam turbine throttle flow. The change in output from LP section 32 is primarily a function of the change in LP steam extracted from LP section 32 but in this embodiment will also be influenced by changes in other upstream uncontrolled extraction flows. For this reason the plant should be operated during this test with as few extraction feedwater heaters in operation as possible to keep the LP expansion efficiency and output calculations as simple as possible and reduce sources of measurement uncertainty. At least the following measurements are then recorded:
Note that in the case of a unit with multiple extraction feedwater heaters it may (based on instrumentation uncertainties) be more accurate to calculate the LP extraction flows based on the energy balance around each feedwater heater from measured feedwater flow, heater inlet and outlet temperatures, drain temperatures, and heater operating pressures. In use, a first LP section efficiency (η1) is estimated. The IP and LP Output are then calculated with and without steam extraction from LP steam turbine 32. The expected change in a measured generator output ΔkW1 is then determined in accordance with computer model prediction.
A second LP section efficiency (η2) is estimated. The IP and LP Output are then calculated with and without steam extraction from LP steam turbine 32. The IP efficiency for both calculations is calibrated to the measured IP section efficiency with the LP extraction valve closed. The expected change in a measured generator output ΔkW2 is then determined in accordance with computer model prediction.
LP steam turbine 32 efficiency can be calculated in accordance with:
An exemplary embodiment of a plurality of methods for measuring expansion efficiency of a low pressure steam turbine are described above in detail. The above-described methods for measuring expansion efficiency of a turbine provide an efficient and effective method of measuring the expansion efficiency of a low pressure turbine used in a combined cycle or Rankine cycle plant. The methods illustrated are not limited to the specific embodiments described herein, but rather, may be utilized in a wide variety of steam turbine applications.
While the invention has been described in terms of various specific embodiments, those skilled in the art will recognize that the invention can be practiced with modification within the spirit and scope of the claims.
This application is a Continuation-In-Part of U.S. patent application Ser. No. 10/444,153 filed May 22, 2003.
Number | Date | Country | |
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Parent | 10444153 | May 2003 | US |
Child | 11108299 | Apr 2005 | US |