FRAME TYPE HEAVY DUTY GAS TURBINES BASIC INFORMATION AND TUTORIALS

Frame Type Heavy-Duty Gas Turbines - What is it?

Frame Type Heavy-Duty Gas Turbines. The frame units are the large power generation units ranging from 3 MW to 480 MW in a simple cycle configuration, with efficiencies ranging from 30–46%.

These gas turbines were designed shortly after World War II and introduced to the market in the early 1950s. The early heavy-duty gas turbine design was largely an extension of steam turbine design.

Restrictions of weight and space were not important factors for these ground-based units, and so the design characteristics included heavy-wall casings split on horizontal centerlines, sleeve bearings, large-diameter combustors, thick airfoil sections for blades and stators, and large frontal areas.

The overall pressure ratio of these units varied from 5:1 for the earlier units to 35:1 for the units in present-day service. Turbine inlet temperatures have been increased and run as high as 2500 ◦F (1371 ◦C) on some of these units. This makes the gas turbine one of the most efficient prime movers on the market today reaching efficiencies of 50%.

Projected temperatures approach 3000 ◦F (1649 ◦C) and, if achieved, would make the gas turbine even a more efficient unit. The Advanced Gas Turbine Programs sponsored by the U.S. Department of Energy has these high temperatures as one of its goals.

To achieve these high temperatures, steam cooling is being used in the latest designs to achieve the goals of maintaining blade metal temperatures below 1300 ◦F (704 ◦C) and prevent hot corrosion problems.

The industrial heavy-duty gas turbines employ axial-flow compressors and turbines. The industrial turbine consists of a 15–17 stage axial-flow compressor, with multiple can-annular combustors each connected to the other by cross-over tubes.

The cross-over tubes help propagate the flames from one combustor can to all the other chambers and also assure an equalization of the pressure between each combustor chamber.

The earlier industrial European designs have single stage side combustors. The new European designs do not use the side combustor in most of their newer designs. The newer European designs have can-annular or annular combustors since side (silo type) combustors had a tendency to distort the casing.

Figure 1-8 is a cross-sectional representation of the GE Industrial Type Gas Turbine, with can-annular combustors, and Figure 1-9 is a crosssectional representation of the Siemens Silo Type Combustor Gas Turbine. The turbine expander consists of a 2–4-stage axial-flow turbine, which drives both the axial-flow compressor and the generator.

The large frontal areas of these units reduce the inlet velocities, thus reducing air noise. The pressure rise in each compressor stage is reduced, creating a large, stable operating zone.

The auxiliary modules used on most of these units have gone through considerable hours of testing and are heavy-duty pumps and motors. The advantages of the heavy-duty gas turbines are their long life, high availability, and slightly higher overall efficiencies.

The noise level from this type of turbine is considerably less than an aircraft-type turbine. The heavy duty gas turbine’s largest customers are the electrical utilities, and independent power producers. Since the 1990s the industrial turbines have been the bulwarks of most combined cycle power plants.

The latest frame type units introduced are 480-MW units using steam cooling in the combined cycle mode, enabling the firing temperatures to reach 2600 ◦F (1427 ◦C). This enables efficiency in the combined cycle mode to reach 60% plus.

ELECTRICAL FAULT CONTROL FOR WIND TURBINES BASIC INFORMATION AND TUTORIALS

WIND TURBINE ELECTRICAL FAULT CONTROLS

How To Control Electrical Faults in Wind Turbines

One of the roles of a monitoring and control system in a turbine is that if some fault is detected, the proper action is taken. A fault can be any malfunctioning of a component, including damage and breakage; high or low operating temperature or pressure; or a value outside of the allowed tolerances for a mechanical or electrical parameter such as speed, voltage, current, and the like.

Depending on how serious the fault is, a turbine must be shut down if the fault cannot be corrected. If a turbine has to be shut down, a process of shutting down the turbine must be followed. Some faults may lead to a temporary action that must be checked a number of times to see if it persists.

Th e number of faults that can occur is large and it is not practical to list them, since faults can be diff erent from one machine to another. Some of the more important mechanical faults that can happen are mentioned here:

a. Excessive vibration in various parts of the turbine; this can be in any of the main bearings, in the nacelle, in the tower, and in the gearbox.

b. High temperatures of various fluids in the gearbox, bearings, oil cooling system, or any other hydraulic system.

c. Low level or low pressure of various liquids in various parts of the system.

Also, some faults are not detectable by a turbine controller, unless redundant systems are used. Redundant means that one parameter or variable is measured by two devices, so that if one fails the other shows a (diff erent) value. For instance, suppose that the anemometer malfunctions or freezes in a freezing rain. 

The reading from the anemometer then shows a zero speed for wind, whereas there is wind. In such a case, the controller interprets this as lack of wind and, thus, the turbine is put into halt and with the brakes on. Th is is a typical scenario that calls for a technician to act.

One of the major faults that can happen in a wind turbine and can lead to disastrous results is when a turbine speed increases beyond the allowed limit. Th is is called overspeed. When a turbine rotates, there are dynamic forces that act on blades and all the other related mechanical components.

The magnitude of these forces depends on the speed of rotation. If the speed goes up, the magnitudes of these forces increase as well, and can go beyond the values for which the components are designed. If this happens, these components can break. And if one component in a mechanical system breaks and the cause is still present, this can lead to other component failure and serious damage.

In particular, if the speed of a wind turbine increases beyond its designed value, the blades can fl y away and the whole turbine can fall apart in a short time. If during the normal operation of a wind turbine, the load is suddenly taken off the turbine, this can lead to overspeed. 

This can happen if the generator is disconnected from the grid, for instance, in the case of lightning tripping the overhead breakers and disconnecting the circuit. Even if the turbine controller starts shutting down the turbine in such a condition, the momentum in the rotor, as a result of its existing speed, can speed up the turbine to overspeed. 

In order to prevent this from happening to the turbine, modern turbines are equipped with a set of resistors that can connect to the generator and become a temporary load, until the situation is corrected, or the turbine has slowed down. 

These resistors, called crowbars, are not normally connected, but in the case when such a fault occurs they kick in and connect to generator stator. As a result of taking a large load from the generator, these resistors become hot and their heat must be taken from them as fast as possible. For this reason, they are placed outside of the nacelle where they can be cooled by fresh air.

Control Systems

As we have learned so far, many variables must be controlled in a wind turbine, such as blade pitch angle and nacelle yaw angle. Also, on the electrical side, there are voltage, current, frequency, and other variables that must be controlled to a desired value. Here, we elaborate on how an entity, in general, is controlled. The discussion here applies to any variable that needs to be controlled. But for sake of clarity, we may use the terms for blade pitch control, when necessary.

Suppose that the value of pitch angle for blades at a certain time during the operation of a turbine must be 35°. This value is from a reference point for measurement of blade angle that one may physically count 35°. Moreover, this value is not fixed, since a minute later, it could be altered to, say, 38°. But, for any given instant the figure defines the desired value.

A control action is normally taken in a control loop. In order for better control, feedback control is used and the value to be controlled is continuously checked and compared to the desired value, and corrections are made. In the control loop the desired value is the set point.

An action is taken on the difference between the actual value (that is, the measured value) and the set point. This difference is called error.

The action to be taken based upon the error is performed by the actuator. For a pitch control system, the actuator is an electric motor or a hydraulic piston that turns the blade. The command to the actuator for how much must it rotate the blade can be found by a control law. 

There are various control laws; but the most common and traditional ones are proportional control and PID control (PID stands for proportional, integral, and derivative). Each element in a PID control has a different role.

Proportional control introduces an action proportional to the value of the error. Its role is for stabilization of a system. The integral action is intended to take care of a drift in the controlled value. 

This drift is called offset or steady-state error. If not taken care of, by integral control, the value reached can be slightly different from the desired value. Derivative control has the effect of looking forward and predicting what can be expected to happen, and adding the necessary action.

TURBINE VIBRATION MEASUREMENTS ROTOR DYNAMICS BASIC INFORMATION AND TUTORIALS

What is rotor dynamics in vibration analysis?



The characteristics of the high speed rotor system are very important to define in evaluating the performance of the gas turbine. The vendor should provide a damped unbalanced response analysis for the prototype of each gas turbine model.

The damped unbalance response analysis should be based on but not limited to the following considerations of the turbine characteristics:

Support (base, flame, and beating housing) stiffness, mass, and damping characteristics, including effects of rotational speed variation. The vendor should state the support system values and the basis of these values.

2. Bearing stiffness and damping values used in the analysis. The basis of these values and the assumptions made in calculating these values.

3. Rotational speeds, including various starting speeds, operating speeds, critical speeds, and the trip speed. Start-up and coast down conditions indicating bleed valve closures and openings, respectively, must be fully documented.

4. Rotor masses including the mass moment of coupling halves, stiffness, and damping effects (such as accumulated fit tolerances, damping, frame effects).

5. Rotor system response to trim balancing in the field.

The analysis should consist of the following charts and tables:

1. A Nyquist and Bode chart showing the frequency phase and amplitude through the entire range of operation.

2. Identification of each critical speed from zero to trip.

3. Identification of mode shapes at each critical speed from zero to trip.

4. Tables showing the acceptable vibration level at various frequencies.

5. A detailed description of the rotor system including the number of stages, number of vanes and blades at each stage, number of gear teeth, and other geometric components that would affect the rotor characteristics of the turbine.

GAS TURBINE FLOW MEASUREMENT BASIC INFORMATION AND TUTORIALS

How to measure the flow in a gas turbine?

Gas flow through the compressor is measured by flow nozzles or other devices installed in the piping. Among the various devices are:

1. Orifice plates. Either the concentric orifice, eccentric orifice, or segmented orifice-type. Choice depends on the quality of the fluid handled.

2. Venturi tubes. These consist of a well-rounded convergent section at the entrance, a throat of constant diameter, and a divergent section. Their accuracy is high; however, installation, unless planned for in advance, is very difficult in the field.

3. ASME flow nozzles. These nozzles provide for accurate measurements. Their use is limited because they are not easily placed in a process plant; however, they are excellent for shop tests. Venturi meters and nozzles can handle about 60% more flow than orifice plates with varied pressure losses.

4. Elbow flow meters. The principle of centrifugal force at the bend is used to obtain the difference in pressure at the inside and outside of the elbow, which is then related to the discharge pressure.

5. Turbine flow meters. The principle of this flow meter is the computation of the revolutions of the turbine wheel in a given time frame.

Other techniques for measuring flow through the compressor include:

1. Calibrated pressure drops from the inlet flange to the eye of the first stage impeller in centrifugal compressors, when such data are available from the manufacturer.

2. A flow trace technique in which Freon is injected into the constream, and flight time between two detection points is measured. . Velocity traverse techniques must be used when, due to the configuration in piping, nozzles, or orifice plates, etc., cannot be used.

These techniques have been described previously in the pressure measurement section. Usually, one of the flow-measuring devices and the required instrumentation is incorporated as a part of the plant piping. The choice of technique depends on the allowable pressure drop, flow type, accuracy required, and cost. 

Nozzle arrangements for various applications vary considerably. For subcritical flow measurement at the outlet end, where nozzle differential pressure p is less than the barometric pressure, flow should be measured with impact tubes and manometers.

GAS TURBINE PERFORMANCE CODES BASIC INFORMATION AND TUTORIALS

Performance Codes used to Measure Turbine

Performance analysis is not only extremely important in determining overall performance of the cycle but also in determining life cycle considerations of various critical hot section components.

The following three ASME Test Codes govern the test of a Gas Turbine Power Plant:

ASME, Performance Test Code on Overall Plant Performance, ASME PTC 46 1996, American Society of Mechanical Engineers 1996 2.

ASME, Performance Test Code on Test Uncertainty: Instruments and Apparatus PTC 19.1, 1988
3. ASME, Performance Test Code on Gas Turbines, ASME PTC 22 1997, American Society of Mechanical Engineers 1997.

The ASME, Performance Test Code on Overall Plant Performance, ASME PTC 46, was designed to determine the performance of the entire heat cycle as an integrated system. This code provides explicit procedures for determination of power plant thermal performance and electrical output.

The ASME, Performance Test Code on Test Uncertainty: Instruments and Apparatus PTC 19.1 specifies procedures for evaluation of uncertainties in individual test measurements, arising from both random errors and systematic errors, and for the propagation of random and systematic uncertainties into the uncertainty of test results.

The various statistical terms involved are defined. The end result of a measurement uncertainty analysis is to provide numerical estimates of systematic uncertainties, random uncertainties, and the combination of these into a total uncertainty with an approximate confidence level.

This is especially very important when computing guarantees in plant output and plant efficiency.
The PTC 22 establishes a limit of uncertainty of each measurement required;

the overall uncertainty must then be calculated in accordance with the procedures defined in ASME PTC 19.1 Measurement Uncertainty. The code requires that the typical uncertainties be within a 1.1% for the Power Output, and 0.9% in the heat rate calculations.

It is very important that the post-test uncertainty analysis should also be performed to assure the parties that the actual test has met the requirement of the code.

The instrumentation will be calibrated as per the requirements of the test codes. All the instrumentation must be calibrated before a test and certified that they meet the code requirements. The ASME PTC 19 series outlines the governing requirements of all instrumentation for an ASME Performance Test to be within the governing band of uncertainty.

WIND TURBINE FAULT CONTROL BASIC INFORMATION AND TUTORIALS

Monitoring and Preventing Faults of the Wind Turbine



One of the roles of a monitoring and control system in a turbine is that if some fault is detected, the proper action is taken. A fault can be any malfunctioning of a component, including damage and breakage; high or low operating temperature or pressure; or a value outside of the allowed tolerances for a mechanical or electrical parameter such as speed, voltage, current, and the like.

Depending on how serious the fault is, a turbine must be shut down if the fault cannot be corrected. If a turbine has to be shut down, a process of shutting down the turbine must be followed. Some faults may lead to a temporary action that must be checked a number of times to see if it persists.

The number of faults that can occur is large and it is not practical to list them, since faults can be diff erent from one machine to another. Some of the more important mechanical faults that can happen are mentioned here:

a. Excessive vibration in various parts of the turbine; this can be in any of the main bearings, in the nacelle, in the tower, and in the gearbox.

b. High temperatures of various fl uids in the gearbox, bearings, oil cooling system, or any other hydraulic system.

c. Low level or low pressure of various liquids in various parts of the system.

Also, some faults are not detectable by a turbine controller, unless redundant systems are used. Redundant means that one parameter or variable is measured by two devices, so that if one fails the other shows a (different) value. For instance, suppose that the anemometer malfunctions or freezes in a freezing rain.

The reading from the anemometer then shows a zero speed for wind, whereas there is wind. In such a case, the controller interprets this as lack of wind and, thus, the turbine is put into halt and with the brakes on. This is a typical scenario that calls for a technician to act.

One of the major faults that can happen in a wind turbine and can lead to disastrous results is when a turbine speed increases beyond the allowed limit. This is called overspeed. When a turbine rotates, there are dynamic forces that act on blades and all the other related mechanical components.

The magnitude of these forces depends on the speed of rotation. If the speed goes up, the magnitudes of these forces increase as well, and can go beyond the values for which the components are designed. If this happens, these components can break. And if one component in a mechanical system breaks and the cause is still present, this can lead to other component failure and serious damage.

In particular, if the speed of a wind turbine increases beyond its designed value, the blades can fl y away and the whole turbine can fall apart in a short time. If during the normal operation of a wind turbine, the load is suddenly taken off the turbine, this can lead to overspeed.

This can happen if the generator is disconnected from the grid, for instance, in the case of lightning tripping the overhead breakers and disconnecting the circuit. Even if the turbine controller starts shutting down the turbine in such a condition, the momentum in the rotor, as a result of its existing speed, can speed up the turbine to overspeed.

In order to prevent this from happening to the turbine, modern turbines are equipped with a set of resistors that can connect to the generator and become a temporary load, until the situation is corrected, or the turbine has slowed down.

These resistors, called crowbars, are not normally connected, but in the case when such a fault occurs they kick in and connect to generator stator. As a result of taking a large load from the generator, these resistors become hot and their heat must be taken from them as fast as possible. For this reason, they are placed outside of the nacelle where they can be cooled by fresh air.

WIND TURBINE OPERATING POWER CURVE BASIC INFORMATION AND TUTORIALS

What is the operating power curve of wind turbine?

The power curve of a turbine is built by connecting the maximum points of individual characteristic curves at various blade pitch angles, taking into account the maximum capacity of the turbine generator.

A curve specific to a wind turbine that determines the output power versus the wind speed. This curve is used by the wind turbine controller during operation to adjust the blade pitch.

Illustrates a typical characteristic curve of wind turbines based on which a turbine is to adjust its parameters and set points for the operation at various wind speed conditions. It is interesting to understand how this curve has been generated.

The performance (power coefficient and power capture) of a turbine changes with the tip speed ratio and that for a specific rpm of a turbine the tip speed ratio depends on the wind speed. On the other hand, we would like a turbine to always work, as much as possible, with maximum power coefficient, that is, around the peak of its characteristic curve at each wind speed.

If the maximum points of the characteristic curves for each wind speed are connected together, the resulting curve shows the desired points of operation of a turbine at various speeds. This curve, when blended with a cap for the maximum capacity of the turbine generator, defines a curve based on which a turbine is scheduled and controlled. That is the curve introduced in figure 10.3; it is referred to as a wind turbine power curve.

GAS TURBINE THRUST BEARING DESIGN FAILURE BASIC INFORMATION AND TUTORIALS

Factors Affecting Thrust-Bearing Design

The principal function of a thrust beating is to resist the thrust unbalance developed within the working elements of a turbomachine and to maintain the rotor position within tolerable limits.

After an accurate analysis has been made of the thrust load, the thrust bearing should be sized to support this load in the most efficient method possible. Many tests have proven that thrust bearings are limited in load capacity by the strength of the babbitt surface in the high load and temperature zone of the beating.

In normal steel-backed babbitted tilting-pad thrust bearings, this capacity is limited to between 250 and 500 psi (17 and 35 Bar) average pressure. It is the temperature accumulation at the surface and pad crowning that cause this limit.

The thrust-carrying capacity can be greatly improved by maintaining pad flatness and by removing heat from the loaded zone. By the use of high thermal conductivity backing materials with proper thickness and proper support, the maximum continuous thrust limit can be increased to 1000 psi or more.

This new limit can be used to increase either the factor of safety and improve the surge capacity of a given size bearing or reduce the thrust beating size and consequently the losses generated for a given load.

Since the higher thermal conductivity material (copper or bronze) is a much better beating material than the conventional steel backing, it is possible to reduce the babbitt thickness to .010-.030 of an inch (.254-.762 mm). Embedded thermocouples and RTDs will signal distress in the beating if properly positioned.

Temperature monitoring systems have been found to be more accurate than axial position indicators, which tend to have linearity problems at high temperatures. In a change from steel-backing to copper-backing a different set of temperature limiting criteria should be used..

GAS TURBINE TEMPERATURE MEASUREMENTS BASIC INFORMATION AND TUTORIALS

Temperature Measurement Techniques of Gas Turbines

Temperature may be measured by any of the following instruments:

1. Mercury-in-glass thermometers

2. Thermocouples

3. Resistance thermometers

4. Thermometer wells

Thermocouples are the preferred type of instruments because of the simplicity in basic design and operation. They can attain a high level of accuracy, are suitable for remote reading, and are robust and relatively inexpensive.

Regardless of the temperature-measuring device to be used, on-site calibration of the entire measurement system is desirable. Usually, a two-point check can be made by employing frozen and boiling water. 

At the very least, all devices can be checked at a common temperature, preferably in the midrange of expected temperatures so that any deviant devices can be discarded. This check is particularly desirable for low-head machines where the temperature rise will be slight.

Test plans frequently are prepared on the assumption that a laboratory thermometer can replace an operating instrument in an existing thermometer well.

While this change may be satisfactory, the prudent tester needs to be aware that because of the propensity of thermowells to break off and perhaps enter the machine or cause a hazardous leak, their design is compromised such that true gas temperature determination is impossible. The compromise may be to make the well short and/or to make it thick-walled. 

In either event the mass of metal exposed to ambient temperature may exceed that exposed to the gas, resulting in significant error if the gas temperature is much different from the ambient temperature. High-pressure systems requiring thick-wall pipe are particularly susceptible to this fault. However, the use of a good heat-transfer fluid can minimize the error. 

The best gas temperature reading is attained by a calibrated fine-wire thermocouple with the junction directly exposed to the gas near the center of the flow. As deviations from this ideal are made, the potential for error is increased.

Inlet and discharge temperatures are the stagnation temperatures at the respective points and should be measured within an accuracy of 1 ~ (0.55 ~ When the velocity of the gas stream is more than 125 fps (36.6 mps), the velocity effect should be included in the temperature measurement with a total temperature probe. 

This probe is a thermocouple with its hot junction provided with a shielded cup. The cup opening points upstream. A trade-off has to be made in a field test situation where the gas is not clean.

GAS TURBINE PERFORMANCE TESTS BASIC INFORMATION AND TUTORIALS

How to conduct gas turbine performance tests.

The performance analysis of the new generation of gas turbines is complex and presents new problems, which have to be addressed. Performance acceptance tests, which are required to be conducted for contractual guarantees, require that the turbine be cleaned before the test.

The average commissioning time for the advanced gas turbine (G Type) units is longer than the F and FA Type units. This is usually due to the increased number of starts and trips during commissioning, due to a lot of fine tuning required for the DLN combustors, cooling systems, and complicated control systems, which increase the number of equivalent engine hours.

It is recommended that contractually the maximum number of equivalent engine hours be limited to about 600-800 hours regardless of the actual equivalent operating hours.

If this is not done then the power output will be corrected to a larger corrected output, reducing the actual power the plant will produce. There have been many cases of 2000 to 6500 equivalent operating hours recorded during commissioning, which in many cases amount to the power and heat rate being corrected by 2 to 5%. This affects the profitability of the plant.

The new units operate at very high turbine firing temperatures. Thus, variation in this firing temperature significantly affects the performance and life of the components in the hot section of the turbine.

The compressor pressure ratio is high which leads to a very narrow operation margin, thus making the turbine very susceptible to compressor fouling. The turbines are also very sensitive to back pressure exerted on them when used in combined cycle or cogeneration duty. The pressure drop through the air filter also results in major deterioration of the performance of the turbine.

If a life cycle analysis were conducted the new costs of a plant are about 7-10% of the life cycle costs. Maintenance costs are approximately 15-20% of the life cycle costs. Operating costs, which essentially consist of energy costs, make up the remainder, between 70-80% of the life cycle costs, of any major power plant.

Thus, performance evaluation of the turbine is one of the most important parameters in the operation of a plant. Total performance monitoring on- or off-line is important for the plant engineers to achieve their goals of:

1. Maintaining high availability of their machinery.
2. Minimizing degradation and maintaining operation near design efficiencies.
3. Diagnosing problems, and avoiding operating in regions, which could lead to serious malfunctions.
4. Extending time between inspections and overhauls.
5. Reducing life cycle costs.

To determine the deterioration in component performance and efficiency, the values must be corrected to a reference plane. These corrected measurements will be referenced to different reference planes depending upon the point, which is being investigated.

Corrected values can further be adjusted to a transposed design value to properly evaluate the deterioration of any given component. Transposed data points are very dependent on the characteristics of the component's performance curves.

To determine the characteristics of these curves, raw data points must be corrected and then plotted against representative nondimensional parameters. It is for this reason that we must evaluate the turbine train while its characteristics have not been altered due to component deterioration. If component data were available from the manufacturer, the task would be greatly reduced.

WIND TURBINE AERODYNAMIC BLADES BASIC INFORMATION AND TUTORIALS

Aerodynamic Blade Wind Turbines

Each blade of a turbine is subject to aerodynamic forces from the wind. The airstream has a relatively fixed direction for the area swept by the blades, at an instant, but since blades are twisted the relative direction of wind with respect to a blade is not the same for various segments of the blade. 

Moreover, whereas the windstream has a constant speed (for a short period under consideration), the speed of air as a result of the blade rotation is smaller for the segments of the blade closer to the hub than the segments closer to the tip of the blade.

Consequently, the relative motion of air with respect to the blade as a result of wind and blade motion varies along the length of a blade. The resulting aerodynamic force, thus, varies in both magnitude and direction along the blade span. The typical force for a segment is shown in figure below (a blade can be assumed to be made of any arbitrary number of segments).

The force on each blade segment consists of two components: one component along the direction of wind (the drag force, almost in the horizontal direction) and one perpendicular to wind (the lift component, in a near vertical plane). These forces are depicted for a two-blade turbine in figure below.

A two blade-turbine is more appropriate to demonstrate the fact that all the components along the wind direction have the same force direction in the two blades, whereas the forces normal to the wind have opposite directions in the two blades, since the blades are symmetric to each other. 

The forces shown correspond to when the blade is feathered and does not catch much energy (the lift components are smaller than the drag components). This is just for the sake of clarity of the figure. This implies, also, the fact that the horizontal force on the blades is greater when a turbine is parked than when it is working.

It is easy to verify that the resultant of the two sets of forces is a push on both blades in the wind direction and a torque about the turbine shaft axis. In other words, all those force components along the wind direction contribute to a backward push on the blades, and do not generate any rotational motion.

However, those force components that are in the opposite direction in a (near) vertical plane are the only ones that generate a torque that makes the turbine rotate.

Note that the just mentioned aerodynamic forces are functions of wind speed, rotational speed, and pitch angle. Therefore, they are not the same for different operating conditions and for when the turbine is parked. 

A blade must be able to withstand these forces in the harshest condition; that is, when these forces are at their highest.

All the forces on a turbine must ultimately be transferred to the ground through the tower.

DIFFERENCE BETWEEN IMPULSE AND REACTION HYDRAULIC TURBINES BASIC INFORMATION

What is the difference between an impulse and reaction turbine?

Impulse Turbine wherein the available hydraulic energy is first converted into kinetic energy by means of an efficient nozzle. The high velocity jet issuing from the nozzle then strikes a series of suitably shaped buckets fixed around the rim of a wheel. The buckets change the direction of jet without changing its pressure.

Reaction Turbine wherein a part of the total available hydraulic energy is transformed into kinetic energy before the water is taken to the turbine runner. A substantial part remains in the form of pressure energy. Subsequently both the velocity and pressure change simultaneously as water glides along the turbine runner. The flow from inlet to outlet of the turbine is under pressure and, therefore, blades of a reaction turbine are closed passages sealed from atmospheric conditions.



Impulse Turbine

1. All the available energy of the fluid is converted into kinetic energy by an efficient nozzle that forms a free jet.

2. The jet is unconfined and at atmospheric pressure throughout the action of water on the runner, and during its subsequent flow to the tail race.

3. Blades are only in action when they are in front of the nozzle.

4. Water may be allowed to enter a part or whole of the wheel circumference.

5. The wheel does not run full and air has free access to the buckets.

6. Casing has no hydraulic function to perform; it only serves to prevent splashing and to guide the water to the tail race.

7. Unit is installed above the tail race.

8. Flow regulation is possible without loss.

9. When water glides over the moving blades, its relative velocity either remains constant or reduces slightly due to friction.

Reaction Turbine
1. Only a portion of the fluid energy is transformed into kinetic energy before the fluid enters the turbine runner.

2. Water enters the runner with an excess pressure, and then both the velocity and pressure change as water passes through the runner.

3. Blades are in action all the time.

4. Water is admitted over the circumference of the wheel.

5. Water completely fills the vane passages throughout the operation of the turbine.

6. Pressure at inlet to the turbine is much higher than the pressure at outlet ; unit has to be sealed from atmospheric conditions and, therefore, casing is absolutely essential.

7. Unit is kept entirely submerged in water below the tail race.

8. Flow regulation is always accompanied by loss.

9. Since there is continuous drop in pressure during flow through the blade passages, the relative velocity does increase.

GAS TURBINE COMBUSTOR REQUIREMENTS BASIC INFORMATION AND TUTORIALS

What is a gas turbine combustor?

A gas turbine combustor must satisfy a wide range of requirements whose relative importance varies among engine types. However, the basic requirements of all combustors may be listed as follows:

1. High-combustion efficiency (i.e., the fuel should be completely burned so that all its chemical energy is liberated as heat)

2. Reliable and smooth ignition, both on the ground (especially at very low ambient temperatures) and, in the case of aircraft engines, after a flameout at high altitude

3. Wide stability limits (i.e., the flame should stay alight over wide ranges of pressure and air/fuel ratio)

4. Low pressure loss

5. An outlet temperature distribution (pattern factor) that is tailored to maximize the lives of the turbine blades and nozzle guide vanes

6. Low emissions of smoke and gaseous pollutant species

7. Freedom from pressure pulsations and other manifestations of combustion- induced instability

8. Size and shape compatible with engine envelope

9. Design for minimum cost and ease of manufacturing

10. Maintainability

11. Durability

12. Petroleum, synthetic, and biomass-based multifuel capability.

For aircraft engines, size and weight are important considerations, whereas for industrial engines more emphasis is placed on other items, such as long operating life and multifuel capability. For all types of engines, the requirements of low fuel consumption and low pollutant emissions are paramount.

PELTON TURBINE REGULATION BASIC INFORMATION AND TUTORIALS

Hydraulic turbines are usually coupled to an electric generator and the generator must run at constant speed to maintain frequency of supply constant. The speed of generator N in rev/min, the frequency of supply (f) in Hertz and number of poles of the generator P are related by the equation:

f = NP/120

The peripheral velocity u of turbine wheel must remain constant as speed is constant. The velocity u and speed N are connected by the formula:

u = pi DN/60

where D is mean diameter of the wheel.

It is also desirable to run turbine at maximum efficiency and therefore speed ratio u/VI must remain same which means the jet velocity must not change as head available H is constant. The only way to adjust the load is to change hydraulic power input given by p= yQH

As y, specific weight of water and H are constant, the only variable factor is Q volume flow rate of water entering the turbine. The flow rate Q is Q = Area of nozzle x velocity of jet

Thus flow rate will change by changing the area of the jet or more closely the diameter of the jet. This is accomplished by a spear valve and deflector plate shown in figure below.

The spear alters the cross-sectioned area ofthe jet. The position of spear is controlled by a servo mechanism that senses the load change. For a sudden loss of load when the turbine is shut down, a deflector plate rises to remove the jet totally from the buckets and to allow time for the spear to move to new position.

As seen in the figure for high load the spear valve has moved out, then increasing the area of the jet, at low loads the spear has moved in, decreasing the area of the jet. Deflector plate in normal position and fully deflected jet are also seen in the figures.

TYPES OF GEAR FAILURES GENERAL PROBLEMS OF WIND GEARS BASIC INFORMATION AND TUTORIALS

GEAR FAILURES TUTORIALS
What are the types of gear failures?

Gearboxes, in general, are subject to a number of problems during their operation. These problems can be enhanced or accelerated if faulty situations happen. Faulty situations are undesirable conditions that may arise for various reasons.

For example, the lubricating oil leaks and the oil level drops, or improper oil is used. As a result of any of these situations insufficient lubrication and cooling takes place and parts become heated or hot spots develop, or other damage can occur. Any damage can lead to tooth breakage and the permanent failure of a gearbox.

There are two particular issues with wind turbine gearboxes. The first one, as mentioned earlier, is that in wind turbines the gearbox is not used as a speed reducer, as is the case in the majority of applications. The second issue is that, because of the nature of wind, the gearbox is subjected to frequent and sudden changes of the power it handles. Such power fluctuations, which in turn translate to load variation on the teeth, is not a desirable situation for the gearbox.

In this sense, the chances of damage and failure in wind turbine gearboxes are more than in many other applications. Moreover, changing a gearbox in a wind turbine is extremely expensive, since the operation is not on the ground. In summary, the failure in a wind turbine gearbox can be due to (a)
design and manufacturing, (b) mounting and usage, or (c) operation and maintenance.

Poor or wrong design defi nitely can lead to problems during operation. Similarly, defects in manufacturing create unnecessary stresses, wear, heat, and fatigue. In mounting a gearbox, alignment with the rotating shaft , in both the input side and the output side, is absolutely necessary. Alignment implies that the axes of two mating gears are completely parallel to each other.

Misalignment causes the teeth to go under fluctuating stress, meaning that the stress in parts of a tooth continuously changes from compression to tension and vice versa. Th is is called fatigue and, compared to a part under the same magnitude but constant stress, can tremendously decrease the useful life of a machine part.

Proper mounting of a gearbox implies taking care that the alignment remains within the recommended tolerance. Bad usage implies if a wrong gearbox is selected for an application; for instance, when a gearbox cannot handle the power or cannot transfer the torque it is applied on.

This leads to overload on the gear teeth.

Examples of faults in operation were just mentioned. Th ese are essentially based on the lubrication oil, overheating, and malfunctioning of an associated device such as a pump that must circulate the oil.

Other examples are contamination of oil, say if humidity gets to the oil; and if the oil fi lter clogs and oil pressure drops. Faults in maintenance refers to any mistake concerning prolonged delays in oil change, the wrong oil type, and so on.

Typical gear damage or failures are:
1. Fracture
2. Bending
3. Wear
4. Fatigue
5. Cracking
6. Scuffi ng

Fracture implies that a piece of tooth breaks apart. In such an occurrence, not only does the tooth with the broken part become weaker, the broken part has a grinding action on all other parts, because it can move around with oil into all the other teeth, until it is stopped by the oil filter.


Gear tooth bending is a deformation of teeth in the direction of load. Note that when two objects (here the gear teeth of the two meshing gears) push each other, the force on one is the opposite of the force on the other (see the discussion on force and stress).

This can happen due to overloading and/or high temperatures. High temperatures can weaken a metal part in terms of lessening its strength to loads. Thus, the part can bend or deform more easily.

Wear is normally in the form of abrasion, where two matching parts can grind against each other. In the case of two gear teeth, this happens if there is not suffi cient room for smooth rolling motion between the teeth. Th is can also happen due to contamination and debris in the oil. A physical abrasion action is normally called erosion, and if it happens due to chemical reactions (acid in the oil, for instance) it is called cavitation.

Fatigue, as mentioned earlier, occurs when a machine element is subject to frequent change in the applied force. As a result, the part is forced to compress and then pulled to extend. Consider a gear tooth that is pushed up, then pushed down, on a permanent basis. Th is causes fatigue. Vibration in gears causes such a phenomenon.

Fatigue can occur in the tooth roots due to the bending of teeth (which can be called bending fatigue), or it can happen at the points of contact where two teeth press each other and then are relieved. Note that we also have thermal fatigue, which happens in parts of devices that are subject to temperature fl uctuations (becoming very hot and then very cold, repeatedly). Th is does not normally happen in gears.

Cracking is self-explanatory. It is the starting point for eventual fracture, and it is due to localized stress. Cracks can start under the surface, and eventually expand to the surface at different parts of a tooth body.

Scuffing is the term used when tiny pieces of metal tear from one gear tooth and due to localized heat adhere (weld) to the body of the matching teeth. Th is causes the surfaces to become rough, instead of being smooth, which in turn causes the development of more stress in the teeth and vibration in the gears.

SAFETY ON WIND TURBINE OPERATION BASIC INFORMATION AND TUTORIALS

WIND TURBINE SAFETY OPERATION
How to stay safe in operating wind turbines?

• When working on wind turbines, technicians and workers are subject to a number of hazards. These hazards are mainly due to the height, the confined environment, the electrical equipment, and the possibility of turbine motion.

• Falling from a height is the most serious hazard. The number of workrelated fatal occupational injuries in 2008 in the United States due to falls from height was 700.

• Human error or lack of knowledge and ignoring safety rules are among the other causes of accidents.

• It is necessary that technicians learn about safety rules and follow them carefully. Training for safety and rescue is provided to workers by employers.

• It is the responsibility of an employer to provide a safe environment for the workers. Because of the hazardous nature of work on wind turbines, moreover, it is a worker’s responsibility to care for his or her safety as well as the safety of other workers.

• Safety regulations are set and monitored by authorities in each country. In the United States, these regulations are set by the Occupational Safety and Health Administration (OSHA).

• A mindset for a good technician is that “safety is rule number 1, always.”

• For any job that involves hazards, personal protection equipment (PPE) is to be used in order to reduce the risk of having accidents. PPE is not the same for all jobs and depends on the nature of a hazard(s) involved in a job and the work environment.

• For working on wind turbines, PPE comprises climbing gear, a hard hat, and fall arrest equipment. In the simplest version, climbing gear includes a harness to wear, a cable grip, and a locking carabiner. The fall arrest gear is a lanyard with which a worker can hook himself or herself to a secure point during work.

• Long-sleeve shirts and pants, with no jewelry or unnecessary items on the body (or in the pockets) are part of the proper clothing that a wind turbine worker must bear in mind. A pair of gloves is often very useful when climbing a ladder.

• PPE must always be checked before each use to make sure it is in perfect order. A periodic professional inspection, for instance, a yearly inspection, may also become necessary, depending on the frequency of usage.

• A good safe action is to respect tagout and lockout practice at work. Tagout implies putting a note on a device or equipment, notifying others about a hazard or danger. Lockout implies that equipment or a device, or a place containing such a device, be physically locked to prevent it from being accessed.

• In addition to training for safety, a technician working on wind turbines receives training for self-rescue in case it becomes necessary to escape from a turbine without using the ladder inside the tower.

• It is also essential that a worker learns how to rescue a colleague who might get involved in an accident. A fi rst rule to follow is that one must never put his or her safety at risk in such a rescue mission.

GAS TURBINES CATEGORIES BASIC INFORMATION AND TUTORIALS

Categories of Gas Turbines defined.
What are the different types of gas turbines?

The simple-cycle gas turbine is classified into five broad groups:

1. Frame Type Heavy-Duty Gas Turbines. 

The frame units are the large power generation units ranging from 3 MW to 480 MW in a simple cycle configuration, with efficiencies ranging from 30-46%.

2. Aircraft-Derivative Gas Turbines Aero-derivative. 

As the name indicates, these are power generation units, which originated in the aerospace industry as the prime mover of aircraft. These units have been adapted to the electrical generation industry by removing the bypass fans, and adding a power turbine at their exhaust.

These units range in power from 2.5 MW to about 50 MW. The efficiencies of these units can range from 35-45%.

3. Industrial Type-Gas Turbines.

These vary in range from about 2.5 MW- 15 MW. This type of turbine is used extensively in many petrochemical plants for compressor drive trains. The efficiencies of these units are in the low 30s.

4. Small Gas Turbines. 

These gas turbines are in the range from about 0.5 MW-2.5 MW. They often have centrifugal compressors and radial inflow turbines. Efficiencies in the simple cycle applications vary from 15-25%.

5. Micro-Turbines. 

These turbines are in the range from 20 kW-350 kW. The growth of these turbines has been dramatic from the late 1990s, as there is an upsurge in the distributed generation market.

ADVANTAGES OF STEAM TURBINE OVER STEAM ENGINE BASIC INFORMATION AND TUTORIALS

Comparing steam turbine and steam engine, which is better?


The various advantages of steam turbine are as follows :

(i) It requires less space.

(ii) Absence of various links such as piston, piston rod, cross head etc. make the mechanism simple. It is quiet and smooth in operation,

(iii) Its over-load capacity is large.

(iv) It can be designed for much greater capacities as compared to steam engine. Steam turbines can be built in sizes ranging from a few horse power to over 200,000 horse power in single units.

(v) The internal lubrication is not required in steam turbine. This reduces to the cost of lubrication.

(vi) In steam turbine the steam consumption does not increase with increase in years of service.

(vii) In steam turbine power is generated at uniform rate, therefore, flywheel is not needed.

(viii) It can be designed for much higher speed and greater range of speed.

(ix) The thermodynamic efficiency of steam turbine is higher.