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Steam turbine generator speed control - clarification
Engineering and workplace issues. topic
Posted by Mikas on 19 June, 2007 - 11:48 am
Hello to all,

I need clarification about a couple of things regarding turbogenerator's speed control.
Can you confirm the following:

1. When generator is not connected to the grig, when openning steam regulating valves and allowing more steam to turbine, turbine will rotate faster, right?

2. Generator is mechanicaly coupled with the turbine and it always rotates same speed as turbine.

3. When generator is in parallel with the grid, it cannot rotate faster or slower then 50Hz (suppose for Europe) or 3000 rpm (2 pole machine), or in another way, it will rotate the same speed as grid's frequency (for example 49.98 Hz).

4. When generator is synchronized with the grid, adjusting steam control valves cannot change the speed of the turbine/generator and it will change only output power.

I'm looking forward to your comments.
Thank you very much.


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Posted by CSA on 20 June, 2007 - 12:02 am
Mikas,

You have it all correct.

1) When the unit is not connected to a grid (particularly a large, or infinite, grid) increasing the energy being admitted to the prime mover will cause the prime mover to increase speed.

When the unit is connected to a grid, increasing the energy being admitted to the prime mover will NOT result in a speed increase. It WILL result in an increase in the amperage of the generator. In other words, the power output of the generator will increase. The extra torque which would cause the unit to increase its speed when not connected to the grid gets converted by the generator into additional power output (amps).

2) If the prime mover and generator are directly coupled, in other words, there is no reduction gear or speed increaser between the prime mover and the generator, the prime mover and the generator will turn at the same speed as the generator.

Even if there is some gear box (reduction or speed increaser), the speed of the prime mover is still directly proportional to the speed of the generator rotor. And the speed of the generator rotor is directly proportional to the frequency of the grid to which the generator is connected.

As has been noted elsewhere on control.com, the frequency of a generator is directly proportional to the product of the number of poles of the generator times the speed of the rotor (in RPM), divided by 120: F = (P*N)/120. If a grid is operating at 50 Hz and the generator connected to the grid has two poles, the speed of the generator rotor will be 3000 RPM (N = (120*50)/2).

3) AC generators are usually synchronous generators. Synchronous means they are locked in synchronism with the frequency of the grid to which they are connected, especially if the grid is very large, or, infinite. Suppose a 60 MW steam turbine is connected in parallel with other generators on a grid with a total output of 6,000 MW. The little 60 MW steam turbine isn't going to make all the other turbines speed up or slow down detectably as the prime mover's energy is increased or decreased--there's just too much inertia to overcome.

Also, there should be operators and control systems somewhere on the grid which would decrease the load of one or more units to maintain the grid frequency at rated. As units are loaded by their operators they actually accept some of the load from the grid. If enough units are loaded without some units being unloaded equally, the grid frequency will begin to increase.

4) See 1, 2, and 3 above.

But, you've got it!


Posted by CTTech on 22 June, 2007 - 2:20 am
Control systems have a controlled variable and a manipulated variable. If a control system detects no change in the controlled variable, the system has no reason to change the manipulated variable.

If a synchronized generator is asked to adjust load, torque is removed or applied to the prime mover. If these changes in speed are "undetectable", the control system has no reason to increase or decrease power input. The changes are infinitely small, yet must exist for the control system to respond. I will concede that multiple things are happening in one instant of time, but a detectable change is occuring.

Although the hugh power sink in a large grid seem to minimize or absorb changes, measureable changes are occuring. If not the manipulated variables would not change.

The large "infinite bus", whether controlled by human or non-human controls systems must be able to "detect" these incredibly small changes or no reason would exist for the control systems to change their manipulated variables (i.e. other generator sets on the grid.) and maintain this dynamic and delicate balance of frequency and voltage.

I may be totally wrong. I have found that on the generator sets that I have encountered; Speed is the controlled variable and steam or fuel input to the turbine is the manipulated variable. Therefore speed must change to induce a change in steam/fuel imput.

I welcome all feedback on why I am wrong.

CTTech


Posted by Bruce Durdle on 23 June, 2007 - 2:02 pm
Lets go back to basics ... A turbine-generator set obeys an energy balance law. Energy in = energy out + change in stored energy. Or power in = power out + rate of change of stored energy.

Power in is found by multiplying the steam flow by the steam enthalpy (- the cooling water flow * increase in CW energy) (- a few other terms that are more or less constant). Power out is the electrical load on the generator. Stored energy in the machine is kinetic energy of rotation and proportional to the square of RPM. If the load is increased above the power in, the machine will slow down.

A power system is an energy balance on a very large scale. The energy in is the mechanical energy applied to all the turbines. The energy out is the sum of the demand of all the light bulbs, wall warts, TV sets, and electric motors connected to the system. When you turn on a light bulb, all the connected rotating machines will slow down. Somewhere on the system is a generator that will sense the drop in speed and increase generation.

On a large interconnected system such as that in North America, this speed drop is infinitesimal - but it still happens. On a smaller system such as we have here in NZ, frequency excursions due to sudden load changes are a fact of life - a hiccup on the DC link connecting the 2 islands can cause a 1 or 2 % frequency drop in 1 or 2 seconds.

On a steam turbine connected to a grid, a shortfall between power in and power out could occur if there is a small drop in steam pressure or temperature, as well as a load change. This will cause the rotating parts to slow down. As a result, the internal angle between the rotor poles and the magnetic field set up by the stator currents will fall, and the exported electrical power will drop. This restores the balance. The speed excursion will be very short-lived and will probably not affect a governor.

In older systems, the set-point for a governor was referred to as the "speeder gear". Prior to synchronising, a change in the setting for the speeder gear resulted in a speed change. After synchronising, the same change would give an increase in power with no obvious change in speed. With electronic governors, the control strategy can be a lot more complicated and perhaps needs to be.

On one plant I have worked on we had a small 2.5 MW gas turbine. The governor system was capable of reacting very quickly to the above-mentioned frequency dips, and would increase generation in response - sometimes to well above the nameplate rating (I have seen the analogue power indication at more than 3.5 MW on occasion). An electronic power limit would have been quite useful in that case.

So CTTech is right - speed is the major controlled variable, and changes in speed act to change the governor valves. The system is also self-regulating in that the electrical power out changes with machine angle.

Bruce.


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Posted by Phil Corso on 24 June, 2007 - 10:47 am
I disagree with both CCTech's 23-Jun (02:29) and Bruce Durdle's 23-Jun (14:02) comments stating that the major controlled variable is speed.

I believe we can all agree that power-demand (kW) is provided by the prime mover. Furthermore, we can agree that any power demand change will cause the turbine's Speed Regulator, the Turbine Governor Control (TGC), to intervene, thus correcting deviations. But, the response is relatively slow. So slow in fact, that its impact on system stability is ignored! (Just think of the original TGC, the Watt rotating-ball governor)

But, now consider the case when load power-factor changes, i.e., power-demand remains constant but the load's power-factor, or as is said, reactive-power (kVAr) changes. Does the speed change? No! Why not? Because reactive-power is not real-power! So what happens? Of course, the generator's current output changes! That change, then results in a change of the generator's terminal voltage. What detects that change: the AVR!

Thus, the voltage regulator, or in today's jargon, the AVR, changes the generator's field-excitation to correct the terminal voltage. (The 'A' in AVR, of course eliminated the need for an operator to keep an eye on the volt-meter!) The AVR, while it can't supersede the TGC, certainly complements it. It allows quicker response to output requirements. There shouldn't be any doubt about the improvement in dynamic response that today's computer-generated transfer-function models have made to system stability and transient recovery! But, the real key is the AVR's ability to instantly detect electrical parameter change, not the TGC's ability to control turbine speed!

Phil Corso, PE (Cepsicon@aol.com)


Posted by CTTech on 24 June, 2007 - 5:13 pm
I concur with Mr. Corso to a degree. A GE EX2000 Excitation drive is so fast in response time that an additional feedback signal had to be added to stabilize the drive. The feedback is speed.

I merely wanted to point out that to fully understand this delicate and dynamic balance; one must first learn the basics. Generator speed and generator frequency are directly related and this cannot be ignored. To infere that generator speed is NOT changing while synchronized is ignoring this relationship.

Once the basics are learned, one can investigate the many other things that are happening in the same instant of time to stabilize yet increase response time of the delicate energy balance.

Best regards,
CTTech


Posted by Mikas on 9 August, 2007 - 11:33 pm
Thank you all for your replies. I've learned a lot by reading your posts.

However, I'd like to ask you to help me understand what is primary and what is secondary control of turbine speed.

If I understood correctly, primary control is spontaneous reaction of turbine's controller, but don't know what secondary control would be.
Please, can you give a detailed explanation?
Thanks.


Posted by CSA on 24 June, 2007 - 5:10 pm
Thanks to Mr. Durdle for sparking a return to basics. There's nothing more enlightening than beginning at the beginning. Unfortunately, we can't discuss the theory of magnetism and amperes and voltage and current, and specifically, of alternating current and voltage; it's presumed we all understand those basics or can look them up. But, we'll venture again into the breach.

Synchronism: to occur at the same interval or frequency. Synchronous generator: a device, usually with a rotating electrical field that, when operated properly (as per Mr. Corso) in parallel with other electrical generators, will spin at a speed that is directly proportional to the frequency of the alternating current on the grid.

From other posts, that speed is N = (120 * F)/P. N is the speed of the rotor, in RPM; F is the frequency of the AC system to which the synchronous generator is connected, in Hz; P is the number of poles of the electrical field; 120 is a number which allows for conversion between Hz (cycles per second) and RPM (revolutions per minute).

When a synchronous generator is connected in parallel with other synchronous generators, an electrical magnetic field is created on the stator, actually three electrical magnetic fields since most synchronous generators are three-phase machines. Because of the alternating nature of an AC electrical system, the magnetic fields created on the stator appear to rotate around the stator.

The rotating electrical field of the synchronous generator is locked in to synchronism with the rotating electrical fields of the stator and can not spin any faster or slower than the rotating electrical fields of the stator. And that speed is defined by the formula above.

When a synchronous generator is started and accelerated to synchronous speed in preparation for connecting the generator to a grid in parallel with other generators, any change in energy to the prime mover results in a change in speed of the rotor of the generator. That change in speed will result in a change of the frequency of the synchronous generator by solving the formula above for frequency: F = (P*N)/120, which is the same formula above, just solved for frequency.

Once the synchronous generator is synchronized (there's that word again!) to the grid with other generators, it's speed is fixed by the frequency of the grid. Any change in energy to the prime mover will result in a change in the amount of amperes flowing in the stator of the synchronous generator because. And the power produced by a synchronous generator is a function of the number of amps flowing in the stator of the generator.

This relationship between frequency and speed is one of the reasons why a synchronous generator must be synchronized with an electrical grid when it is being connected to an electrical grid. The frequency of the synchronous generator being connected to the grid must be made nearly equal to the grid's frequency before the generator breaker is closed for a smooth and stable breaker closure. The speed of the rotating magnetic field is directly proportional to the frequency of the synchronous generator, so the prime mover's speed is adjusted to make the frequency of the synchronous generator nearly equal to the grid's frequency.

Once the generator breaker is closed, any change in energy being admitted to the prime mover will result in a change in the torque being applied to the synchronous generator. Because the synchronous generator is now controlling the speed of the unit (the prime mover and the synchronous generator), the change in torque does not result in a change in speed of the unit, it results in a change in the amperes flowing in the stator of the generator.

So, there's a certain amount of energy that's required to make the synchronous generator rotor spin at a speed that makes the frequency of the generator equal to the frequency of the grid to which is is connected. This is the energy required to make the synchronous generator spin at synchronous speed.

Once the synchronous generator is connected to a grid with other electrical generators, an increase in energy being admitted to the prime mover which would tend to increase the speed of the unit results in an increase of the electrical power of the generator causing more amperes to flow in the stator of the generator, but not an increase in speed of the unit.

If the energy being admitted to the prime mover driving a synchronous generator connected to a grid with other electrical generators is less than the energy required to keep the generator rotor spinning at a speed sufficient to keep the generator frequency equal to the grid frequency the generator will become a motor and spin the prime mover at a speed which is directly proportional to the grid frequency. If the energy being admitted to the prime mover were shut off and the breaker remained closed, the unit would continue to spin at synchronous speed, as long as the excitation being applied to the synchronous generator rotor remained operational (in deference to Mr. Corso, which is why we must keep making reference to synchronous generators being operated as synchronous generators, even though he has provided no details about how long the synchronous generator which was operated asynchronously lasted when being operated without excitation or for how long it operated asynchron
ously).

To understand AC, alternating current, electrical power generation one must understand the machines used to generate electrical power and those are usually synchronous machines. When operated as designed when connected to an electrical grid with other generators, synchronous generators and the prime movers which are usually directly coupled to the generator rotors can spin no faster nor any slower than the speed defined by the formula above.

Any change in the torque being applied to the generator by the prime mover will result in a change in the amperes flowing in the generator stator. Increasing the torque above that required to maintain synchronous speed and frequency will result in amperes which can be used to power loads connected to the grid. These amperes are generally considered to "flow" out of the generator.

Decreasing the torque below that required to maintain synchronous speed and frequency will result in amperes flowing in the generator stator which will cause the generator to become a motor and keep the rotor and the prime mover turning at synchronous speed and frequency. In this case, the amperes are considered to "flow" into the generator, "motorizing" the generator.

The only difference between a synchronous motor and a synchronous generator is the direction of current flow, or, from a different point of reference, the direction of torque flow. Torque exceeding that required to maintain synchronous speed will cause the electrical machine to become a generator. Torque less than that required to maintain synchronous speed will cause the machine to become a motor. Amps will flow out of a synchronous electrical machine which has an excess of torque being applied to it, excess meaning more than required to maintain synchronous speed. Amps will flow into a synchronous electrical machine which has a deficiency of torque being applied to it, meaning less torque than required to maintain synchronous speed.

But in no case will the speed of a synchronous electrical machine be more or less than the synchronous speed, which is directly proportional to the frequency of the AC grid to which it is connected regardless of whether it is a motor or a generator.

The power, watts, produced by a synchronous machine are a function of the torque applied to the machine by the prime mover.

Amazingly enough, reactive power, or VArs, is very similar to watts. Increasing excitation above that required to maintain the generator terminal voltage equal to the voltage of the grid to which the synchronous generator is connected will cause VArs to "flow" out of the generator. Decreasing the excitation below that required to maintain the generator terminal voltage equal to the voltage of the grid to which the synchronous generator is connected will result in VArs "flowing" into the generator.

(This ought to get a response from Mr. Corso!)


Posted by CSA on 24 June, 2007 - 5:13 pm
From previous posts about droop speed control, which is how most prime movers are operated when the synchronous generators they are driving are connected in parallel with other generators on a grid, the frequency of a synchronous generator is defined by the formula F = (P * N) / 120. F is frequency, in Hz; p is the number of poles of the synchronous generator; N is the speed of the synchronous generator rotor to which the prime mover is typically coupled; and 120 is a constant which is used to convert all sorts of things (radians, and RPM to seconds (Hz), etc.).

The formula can be solved for speed: N = (120 * F) / P. For a two-pole synchronous generator connected to a 60 Hz grid, the rotor will spin at 3600 RPM. For a two-pole synchronous generator connected to a 50 Hz grid, the rotor will spin at 3000 RPM.

Most prime movers are connected directly to the synchronous generator rotor either though a single load coupling or through a reduction gear; very few couplings are variable speed couplings.

Consider a 40 MW turbine-generator connecting to a 6,000 MW grid. It's impossible for that 40 MW generator's prime mover to increase the speed of all the other generators on the grid by any appreciable amount. The 40 MW unit's synchronous generator is locked into the same frequency as all the other generators on the grid, and because the prime mover is directly coupled to the synchronous generator its speed is directly proportional to the generator rotor's speed which is a function of the frequency.

It's a pretty straightforward formula, and when a synchronous generator is connected in parallel with other synchronous generators, no single synchronous generator can run faster or slower than any other synchronous generator. (That's kind of the definition of synchronism: everything is occuring at the same interval or "frequency", no pun intended.)

If the prime mover could be disconnected from the synchronous generator rotor while the generator was still connected to the grid, the synchronous generator rotor would continue to spin at synchronous speed, no faster and no slower. In fact, if the energy being admitted to the prime mover is cut off and the synchronous generator remained connected to the grid, the generator and the prime mover will remain at synchronous speed.

The next time the units at your site are connected to the grid, check the speed of the prime movers--if the prime movers are directly coupled to the synchronous generators, the speed of the prime mover is fixed by the generator frequency when connected to the grid.

No matter how much torque is applied to the generator, as long as the torque doesn't exceed the rating of the generator, the speed of the synchronous generator rotor will be fixed by the frequency of the grid to which it is connected. The torque--which would increase the speed of the rotor if the generator were not connected to the grid--gets converted to amps by the generator. Amps that power devices connected to the grid.

Droop speed control changes the turbine speed reference--it doesn't actually change the turbine speed when the synchronous generator being driven by the prime mover is connected to a grid. Droop speed control is straight proportional speed control. If there is an error between the prime mover speed reference and the actual speed there is NOTHING in the control system which drives the error to zero.

So, when a prime mover is being commanded to operate at 102.4% of rated speed, it can only operate at the speed which is directly proportional to the frequency of the synchronous generator to which it is directly coupled. And if the generator is connected to a grid in parallel with other generators, its frequency is fixed by the frequency of the grid. The frequency of the grid is the one thing in a power system that's supposed to be fixed and constant. That is, unless you're in India where the grid frequency is ANYTHING but constant. Voltage can vary a little, but frequency is supposed to be constant.

If the frequency can't change, the speed of the rotor can't change. If the speed of the rotor can't change, the speed of the prime mover can't change since the prime mover is usually directly coupled to the rotor, sometimes through a reduction gear, but that's not variable.

Droop speed control uses the error between the speed reference and the actual speed to increase or decrease the amount of energy being admitted to the prime mover. As the prime mover speed reference is increased, but the actual speed is constant, fixed by the frequency of the generator which is connected to the grid, the error between the reference and the actual increases--and the energy admitted to the prime mover increases. The opposite happens with the speed reference is decreased.

It is the fact that the actual speed of the prime mover is constant and the only variable which is changing is the speed reference that allows prime movers to share load with other prime movers and their generators on an electrical grid when prime movers are operated in droop speed control.

This is a pretty common misconception. Most operators and many technicians all see the speed of the prime mover increase and decrease during startup and shutdown and just assume that the speed changes when the synchronous generator is connected to the grid. But it can't.

So, you, too, CTTech, are correct when you say "speed is the controlled variable and fuel is the manipulated variable". But, it's the error between actual speed which should be constant and speed reference. It's the magnitude of the error which manipulates the fuel. The thing is: the actual speed is controlled by the grid via the frequency of the generator and the variable is the speed reference.

And now for the disclaimer: The above applies to synchronous generators which are not being operated asynchronously. (Even though asynchronous operation of a synchronous generator will usually result in an overheated rotor, and probably a pretty severe generator failure.)


Posted by Bruce Durdle on 25 June, 2007 - 12:30 pm
Since we are getting into the maths... Power transfer through a reactive transmission line depends on the products of the two terminal voltages, is inversely proportional to the reactance, and is proportional to the sine of the power angle or phase angle difference (delta) between the voltages. This is how power systems fall apart if a line is overloaded - when delta approaches 90 deg, sine delta reaches a maximum. If a generator is on the end of a line with significant reactance, and power is increased too far, delta exceeds 90 degrees and the transmitted power falls - the machine loses synchronism and trips - power available to the rest of the system falls - more lines are overloaded - and the lights go out.

While the machines on a system are all rotating at the same electrical speed they are not all aligned - the rotors of lightly-loaded machines will be more or less in step with each other, but the rotors of heavily-loaded machines will lag by somewhere about 60 deg. Sudden load changes will change this angle which will cause a very short-lived apparent speed change. In CSA's example of a 40 MW generator on a 6000 MW system, the frequency change needed to accommodate the loss of the 40 MW set is .013 Hz on a 50 Hz system, .016 Hz on a 60 Hz one, if all machines have a droop setting of 4%. This may or may not be appreciable. A good time to watch for frequency changes on a power system is between 6 am and 9 am - when loads are increasing and generation is increasing to match.

Bruce


Posted by Prince on 7 August, 2007 - 1:14 am
THANKS A LOT for the useful, easy to understand data! I wish you were my Power Systems professor. This is one VERY informative posting!


Posted by Namatimangan08 on 2 February, 2012 - 11:42 am
> I welcome all feedback on why I am wrong.
>
>CTTech

To my knowledge, you get it all right CTTech.


Posted by Mikas on 23 June, 2007 - 1:56 pm
Thank you very much for your answer.
There are more I'd like to learn.

1. What will happen with grid's frequency if one large transmission tower fail? In that case generators stays without load and I'm very interesting how frequency is changed!?!

2. Since increasing in steam flow in turbine will cause output power to increase and increasing in power is because increasing of generator current, I'd like to know what is happening with the voltage.

3. I know that reactive power is somehow related to generator's voltage and excitation, but that is very blur to me. If possible can you explain this?

Thank you very much!


Posted by CTTech on 24 June, 2007 - 10:46 am
1. Hopefully enough reliability is built into the system to prevent power loss to customers. If so, power system operators will only record a short lived frequency excursion and power will be rerouted. Crews to repair the damage to the tower will be dispatched.

If this is not the case, someone/something/somewhere will be without power until repairs can be made.

2/3. Most large loads on the power system are inductive (induction motors). An area that produces power must be able to react to the inductive load. They do this by producing VARs(Volt Amp Reactive power). Additional information on VARs is available on the internet.

Capacitance can also be added near a large inductive load reducing the need for VARs. VARs and MW output are connected.

VARs reduce the amount of megawatts a generator can produce, therefore a cost is incurred for the production of VARs. The power producer for an area must monitor loads through the different seasons and find a balance. The addition of capacitance in certain areas versus the cost of producings VARs and the resultant loss of system production capacity.


Posted by CSA on 26 June, 2007 - 12:42 am
1. The amount of generation must always equal the load in order for the frequency to be stable. If a transmission tower falls and some generation is removed from the grid unless there is sufficient capacity of the remaining generators, the grid frequency is going to decrease if the load exceeds the generation. Sufficient generation capacity means enough of the remaining generators and their prime movers which are still connected to the grid are running at part load and not at full rated power output and can be loaded to make up the difference of what was lost when the tower fell.

If a large block of load is suddenly removed from the grid because of the failure of a circuit breaker in a switchyard the grid frequency will increase unless one or more units have the energy admitted to the prime movers reduced. If the generation exceeds the load, the grid frequency will increase.

2. When torque input to the synchronous generator increases, the amperage flowing in the stator windings of the generator increases. This causes the strength of the magnetic fields of the stator to increase, which causes the field of the generator rotor to shrink or collapse. If nothing is done and the torque input to the generator continues to increase, the generator terminal voltage would tend to decrease. This is commonly referred to armature reaction.

In order to maintain VAr "flow" or power factor at a desired setpoint when manually controlling excitation while loading a unit (increasing the energy into the prime mover), it is necessary to increase excitation to counter the armature reaction.

Conversely, when unloading a unit (reducing the energy admitted to the prime mover) and controlling excitation manually it is necessary to reduce excitation as the unit is unloaded to maintain the desired VAr or power factor setpoint.

Some machines have VAr and/or power factor control features to automatically adjust excitation to control a VAr or power factor setpoint.

3. When a synchronous generator is not connected to the grid but is running at rated speed any increase in excitation will result in an increase in generator terminal voltage. Conversely, any decrease in excitation will cause the generator terminal voltage to decrease. Synchronous generator terminal voltage is directly proportional to the speed of the generator rotor (which is held fixed when connected to the grid) and excitation.

If a synchronous generator is connected to a grid with its terminal voltage equal to the grid voltage, the power factor will be unity, 1.0, and there will be zero VArs leading or lagging. Once connected to the grid, if the excitation is increased the power factor will shift to less than 1.0 lagging, and VArs will "flow out" of the synchronous generator on to the grid. So, that in the same way an increase in torque would tend to increase speed, an increase in excitation would tend to increase generator terminal voltage but the power factor and the VAr flow changes.

Usually, an increase in excitation will cause the synchronous generator terminal voltage to increase slightly when connected to the grid depending on grid conditions and other system factors, but it would not increase by the same amount as if the generator were not synchronized to the grid. Increasing excitation above that required to maintain generator terminal voltage equal to system grid voltage is sometimes referred to as over-excitation and results in the generator trying to boost the system voltage.

Decreasing excitation below that required to maintain synchronous generator terminal voltage equal to grid voltage is sometimes referred to as under-excitation and results in the generator trying to buck the system. When excitation is reduced below that required to maintain synchronous generator terminal voltage equal to grid voltage, the power factor shifts to leading and less than 1.0 and VArs "flow into" the generator.

Whether they actually flow into or out of the generator seems to have been contended before on this site. Convention talks about VArs flowing into and out of the generator. Some people dispute whether or not amperes flow in a generator stator on an AC system, since it is an alternating current. Others say current flows from positive to negative in a DC circuit, while still others say it flows from negative to positive.

It all depends on one's point of reference. And if VArs are considered as being consumed and produced as Watts are (and they are--it's just that most people never see a VAr-hour meter, but they do exist!) then synchronous machines produce VArs when they are over-excited and consume VArs when they are under-excited. It's not possible to control VAr consumption of machines like induction motors and transformers like Watt consumption is controlled; the VAr consumption is a function of how equipment and machines are built. But if someone doesn't produce VArs to at least partially offset the consumption of VArs, the lights are going to dim and maybe even go out.

And the maths are going to start coming now. Hopefully not, because we're just talking principles in general terms for operators and technicians, not scientists and engineers. The maths can be found in any text or reference book, but they rarely discuss principles and unless one takes a long time to understand the maths then it just confuses things for beginners--and we were all beginners once.

The maths are just proofs of principles, and we need to understand the principles to be good operators and technicians. To predict or model we need to understand the maths. But I've run into more than one person who can cite the maths, but can't explain what's really happening. Vectors and trigonometry and calculus are all wonderful things to engineers and scientists but just add to the confusion of operators and technicians. If they want to look up the maths and the formulae, they can. This seems to be a site where people can ask basic questions and learn and get more information if they desire.


Posted by CTTech on 27 June, 2007 - 1:01 am
Mr. Tesla and Mr. Westinghouse started out small. They had no idea how far this would go. I am sure that frequency was "something to watch" on their first outing.

I had no desire to overwelm anyone. For the "newbies": Study Tesla and the induction motor and AC. Learn the basics.

CTTech


Posted by Anonymous on 27 June, 2007 - 11:19 pm
1) Why do we want the VArs to flow out of the generator always?

2) If every generator is forcing VArs out, trying to maintain a lagging pf, then is there someone (a generator) out there who's allowing those forced out VArs, into them?

3) When you specifically say Synchronous Generator, does it also mean that there are Asynchronous Generators too? Or it only means that a generator automatically becomes synchronous (or can we say, synchronized?) when it's connected to an infinite bus because it's too small to effect a change on a large system and hence has to behave like the grid?

4) Is terminal voltage only due to AVR excitation? Will the torque (and not the speed) of the prime mover have no role to play in determining the terminal voltage?

5) When the generator and prime-mover are spinning in synch with the grid, does an extra fuel into the prime mover also increase the mass flow of air through the prime-mover (a single shaft turbine), if the axial compressor air inlet vanes are not modulating with load?

thanks.


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Posted by CSA on 28 June, 2007 - 11:15 pm
1) Because the majority of synchronous generators are not made to run in an underexcited (leading power factor) mode. Refer to the reactive capability curve of the generator for specifics of how a generator may be operated.

Excessively reducing excitation to put the generator in a leading power factor reduces the synchronous generator field strength, increasing the possiblity of allowing the torque being input to the rotor to overcome the magnetic attraction between the rotor and the stator, "slipping a pole" which is very catastrophic. There are also problems with generator heating when operating in an underexcited condition.

2) Lagging VArs feed a lagging load. The majority of reactive loads on most grids are inductive: induction (asynchronous) motors and transformers (yes, transformers are a inductive load on the system). The effect of a lagging load is to shift the voltage and current sine waves out of phase with each other. By providing lagging VArs, the voltage and current sine waves are shifted back towards each other.

3) Yes, there are induction (asynchronous) generators, though they are usually small machines (small hydro turbine-generator or small wind turbine-generators).

4) Synchronous generator terminal voltage is a function of two variables: speed and excitation. Since the speed of a synchronous generator is usually constant, the way to change terminal voltage is to change excitation.

As was said previously, armature reaction affects terminal voltage. Increasing armature current reduces generator terminal voltage due to armature reaction.

5) When fuel is burned in the combustor of a gas turbine, the pressure in the combustor increases. Axial compressors don't behave as people expect them to; when the "back pressure" in the combustor increases due to the addition of more fuel, the axial compressor discharge pressure increases. So, even though the air flow is not changing because the speed is not changing (for a single-shaft gas turbine) and the variable inlet guide vanes are stationary, the axial compressor discharge pressure will increase as fuel is increased.

Extra fuel does increase the total mass flow--but not the mass flow of air, just the axial compressor discharge pressure.


Posted by pv on 13 July, 2007 - 12:16 am
Extra fuel does increase the total mass flow--but not the mass flow of air, just the axial compressor discharge pressure.

1) What happens to the exhaust temperature?

2) If the exhaust temperature increases then the guide vanes will open to maintain the exhaust temperature and otherwards TTXM will go higher. Is it right? Can you please explain?


Posted by CTTech on 13 July, 2007 - 12:46 pm
Please start a new topic. We beat this one to death.

CTTech


Posted by CSA on 15 July, 2007 - 6:46 pm
From many other posts on this site, as a GE-design heavy duty gas turbine is loaded the exhaust temperature will increase. As the unit is loaded to Base Load, the IGVs of more recent units will modulate open at various points during the loading depending on the mode of IGV control.

The early versions of IGV control for most simple cycle applications kept the IGVs at the minimum modulating position, usually 57 degrees, until the exhaust temperature reached approximately 900 F. Then as load (fuel flow) was increased the IGVs were opened to maintain 900 F until they were fully open, usually 84 degrees. At that point, any increase in load (fuel flow) would cause the exhaust temperature to increase until the unit reached Base Load exhaust temperature control.

Combined-cycle applications can improve the over-all plant efficiency by maximizing gas turbine exhaust temperature during low load operation. So, the IGVs were usually held at the minimum modulating position until the exhaust temperature was equal to or slightly less than the exhaust temperature control reference as the unit was loaded.

When the exhaust temperature at part load reached the exhaust temperature control reference, the IGVs were opened to keep the exhaust temperature at or near the exhaust temperature control reference until they were fully opened. At that point the unit was usually at or near Base Load anyway.

However, when the unit is operating on Base Load, an increase in load results when air flow increases (usually due to a decrease in compressor inlet temperature) which cause CPD to increase. The increased CPD would tend to cause both the firing temperature and the exhaust temperature to decrease if the fuel were held constant, but the Exhaust Temp Control curve allows a little extra fuel to be burned because it is really trying to maintain a constant firing temperature.

The confusing part of this for most people is that even though fuel flow and load increase slightly, exhaust temperature decreases. The exhaust temperature decreases because the net effect of the increased air flow and CPD causes the exhaust temperature to decrease because the majority of the increased air flow is not used in the combustion of the increased gas fuel flow.

The exhaust temperature control curve has a negative slope, so for an increase in CPD, the resultant exhaust temperature reference will decrease. CPD increases as load increases while operating on exhaust temperature control. This just drives some people crazy because it seems to be opposite of what would be expected.

The exhaust temp control curve represents a constant firing temperature--which is not being monitored. It's being predicted by the exhaust temperature control curve based on two parameters, CPD and exhaust temperature. If we could measure the firing temperature while operating on Base Load, it would be constant at any point on the sloped portion of the curve--regardless of CPD or exhaust temperature and fuel flow.

That's what the sloped line represents: constant firing temperature. Exhaust temperature and CPD will vary while operating on Base Load, but the firing temperature will not. And that's what Base Load is all about: maintaining constant firing temperature and maximizing power output under changing ambient conditions while optimizing the parts life of the gas turbine.

So, the answers to your questions depend on what type of IGV control is being used, and whether or not the unit is operating at Base Load. It's not a simple answer, but in general as units are loaded the exhaust temperature will increase as CPD increases until the unit reaches Base Load. At that point the unit cannot be loaded any further by the operator. Changes in ambient temperature will cause load to increase or decrease slightly while on Base Load, but the exhaust temperature will respond opposite to what is expected while on exhaust temp control. It drives most people crazy, but that's the way it works.

And, to CTTech's point, we are a little off-topic here. But, a question is a question, and it deserves an answer. One will find all kinds of drift on topics on control.com.


Posted by CSA on 17 July, 2007 - 9:19 pm
By the way, there is a pretty cool little real-time "ticker" application on http://www.ucte.org of the European grid frequency.

These are the little disturbances that the system operators have to respond to during the day. Check it out in the middle of the evening, and in the middle of the morning, and in the middle of the day, and on weekends at various times during the day--but check it out!

Note the resolution of the graph. It's pretty "fine", like thousandths of a Hz. That's why it can sometimes look pretty ragged.


Posted by Anonymous on 1 August, 2007 - 11:17 am
I understand that synchronous generators and the prime movers which are usually directly coupled to the generator rotors can spin no faster nor any slower than the frequency (speed) of the main power grid they are connected to. However, how does the amperage in the stator increase/decrease based on torque?

"Any change in the torque being applied to the generator by the prime mover will result in a change in the amperes flowing in the generator stator. Increasing the torque above that required to maintain synchronous speed and frequency will result in amperes which can be used to power loads connected to the grid. These amperes are generally considered to "flow" out of the generator.

Decreasing the torque below that required to maintain synchronous speed and frequency will result in amperes flowing in the generator stator which will cause the generator to become a motor and keep the rotor and the prime mover turning at synchronous speed and frequency. In this case, the amperes are considered to "flow" into the generator, "motorizing" the generator."


Posted by DB on 3 August, 2007 - 12:05 am
We appear to be making a complex topic out of a simple situation. First generators are not smart machines and only obey the laws of physics. When we have a generator running under load and we appy more load the resistance of the system goes down as resitance goes down current goes up. If the generator current goes up and we maintain the same torque the voltage has a tendancy to fall. Exciters (AVRs) correct this but frequency still goes down unless we apply more speed (fuel/torque). If we have have no magnetic field we have no voltage, if we over excite (more voltage) we produce extra VARs if we under excite (less voltage)we accept VARs. The changing of the strength of the magnetic field (excitation) creates a stronger magnetic field which keeps trying to force the two different magnetic poles to stop in one position creating a speed drop (load on the prime mover). We must thefore increase the fuel into the system to maintain the same frequency. If we add more fuel it creates heat and is restricted in its flow out of the system, so we in turn create higher temperatures (the gases need to escape faster). Our modern controllers do all of the adjustments automatically not so complex.


Posted by CSA on 3 August, 2007 - 12:09 am
That's EXACTLY what a generator does: convert torque into amperes.

This is exactly what electricity is used for: Transmitting torque long distances via thin conductors.

Of course, these days, a lot of electricity is used for lighting, and computers (virtual torque??), but in the early days it was for factories and machines (the Industrial Revolution!).

So, one burns a hydrocarbon-based fuel to produce heat which is converted to torque which is converted to amps which is transmitted via wires to areas where it is reconverted to torque (pumps, air conditioners, elevators, virtual torque (computers), and light and heat).

Actually, when you think about it, the turbine-generator is really doing the work that the pumps and air conditioners and elevators and computers are doing, by providing the torque which is being produced by the motors (and virtual torque motors--microprocessors) driving the pumps and air conditioners and elevators and computers and lights and heaters.

Pretty ingenious, huh?

There's a formula which is hard to reproduce on this forum:

T = K(t) * phi(f) * I(A)

where K(T) is a Torque Constant ("K sub T"), phi(F) is Field Flux ("phi sub F"), and I(A) is Armature Current ("I sub A"). In the formula, K(T) is the physical construction of the synchronous generator--which is fixed and doesn't change as the synchronous generator is operation (diameter, length, windings, etc.). Field Flux is the strength of the magnetic field of the synchronous generator, which is held reasonably constant as the synchronous generator is operated. Which leaves only two variables: torque and armature current.

Solving the above equation for I(A):

I(A) = T / (K(T) * phi(F))

So, it can be seen that if the denominator on the right side of the equation remains relatively constant as the synchronous generator is operated, varying the torque (the numerator) applied to the generator directly varies the armature current flowing in the synchronous generator stator. More torque equals more current.

Power in a three-phase electrical system is: P = V(T) * I(A) * 3^2 * pf,

where P is Power, in watts; V(T) is generator terminal voltage ("V sub T"); I(A) is Armature Current ("I sub A"); 3^2 is the square root of 3; and pf is the power factor of the load. Generator terminal voltage stays fairly constant during synchronous generator operation; the square root of 3 doesn't change as the synchronous generator is loaded/unloaded; and we presume the power factor of a load is stable. So, if the only real variable in the power equation is I(A), which is the same I(A) as in the torque equation, then increasing torque increases armature current which increases power (out of the generator).

It don't get no simpler than this.


Posted by S.Hines on 4 August, 2007 - 10:57 am
Thanks. The above information has been extremely helpful and I am greatly appreciative. I am currently participating in a hydropower program and I undergo oral examinations that sometimes exceed four hours in length. My background as a machinist doesn't help much in the area of electrical power generation. Your comments, however, have helped shed light on what would (for me) otherwise be an odious task.

Once again, Thanks!

S.Hines


Posted by CSA on 5 August, 2007 - 2:51 pm
We aim to please!

Glad to be of help! This seems to be a great site for asking basic questions and getting some decent answers.

But the thing that really makes this site useful is when people write back to say they've learned something or been helped by the information provided. That way, we can all benefit when we know something has been helpful or informative!

Although this topic is titled "Steam turbine generator speed control", a steam turbine is no different from a hydro turbine or a gas turbine or a reciprocating engine or a wind turbine or any kind of torque-producing prime mover driving a synchronous generator: they provide torque that the synchronous generator converts into amperes.

So the principles being discussed here apply to hydro turbine-generators also. Any kind of prime mover, actually, since a prime mover produces torque which is transmitted to the synchronous generator rotor through the load coupling and which the synchronous generator converts into amperes (when connected to a load).


Posted by GMS on 15 August, 2007 - 10:57 pm
Ok, you've all discussed the connection of a generator to an infinite bus. What about a generator which is feeding its own small island of load (e.g. a wind turbine supplying a remote farm) or feeding into a weak bus? What is the result here when the wind blows stronger and the prime-mover speeds up? Surely now the frequency will change? What happens to the voltage and current magnitudes? I assume the current becomes purely load dependent?

Thanks,
GMS


Posted by CSA on 17 August, 2007 - 10:31 am
Wind turbines operating a small load are a whole 'nuther topic, really, just for the reason you cited: varying wind speed. There are lots of different systems on the market for such an application, many involve using a DC generator to charge a battery. Some require the conversion of the loads to run on DC; some use inverters to convert the DC to a relatively constant frequency AC at a typical voltage (usually 120- or 220 VAC depending on the geographical location). In this way, some energy can be stored for use (in the battery) when the wind speed isn't very high, and frequency can be controlled by the inverter.

There's a lot of different systems, and a lot of different opinions as to which is better--but, as you suggest, it wouldn't be very practical to hook up an alternator (AC generator) directly driven by a wind turbine to your house/farm which was wired for 60 Hz, 220/120 VAC, and just release the blade. If the wind speed was high and the load low, the frequency would be excessive. If the wind speed was low and the load "high", the frequency would be less than nominal.


Posted by GMS on 19 August, 2007 - 7:50 pm
Thanks for your reply.

I'm very interested in the technical aspects of generation on a small (250kW and less) scale; wind, solar, small hydro, diesel etc etc. Does anyone know of a good source of information on this stuff?


Posted by CSA on 5 August, 2007 - 3:24 pm
Actually, I think 3^2 is three squared, and 3^1/2 is the square root of three. I hope this didn't cause too much confusion.


Posted by Rahul P Sharma on 19 August, 2007 - 7:25 pm
If there are two GTGs connected in parallel (but not to the grid) to supply the load with one of them in Preselect Mode and other in floating mode, which generator will control the frequency, with none being in Isoc mode?

au revoir
Rahul


Posted by CTTech on 7 August, 2007 - 12:25 am
Outstanding explanation of the the difference between a diffusion flame liquid fuel oil fired 7B and a gas fired IGV controlled DLN 7EA gas turbine.

Regards,

CTTech


Posted by Mikas on 20 August, 2007 - 11:59 am
Hello,

I'd like to ask for further explanation about primary and secondary control (regulation). If I understood correctly, primary control is spontaneous reaction of turbine's controller, but don't know what secondary control would be. Please, can you give a detailed explanation?

Thanks.


Posted by CSA on 20 August, 2007 - 11:48 pm
It seems you're asking a question that's probably related to a particular turbine manufacturer's control scheme or turbine control manufacturer's control scheme. That may be why no one's responded; they're not familiar with it because it's not a "generic" term applied to prime mover control systems.

Was primary and secondary control ever mentioned in the post prior to the first time you asked about it?

Where did you read or hear this term; can you provide information/details which we could review for comment?


Posted by Mikas on 21 August, 2007 - 4:59 pm
I think that problem is in fact due to terminology. I'm not speaking about any particular turbine. I've tried google terms "primary and secondary regulation" and I failed to find something that matches what I need. If I literally translate, then primary and secondary control would be the terms. I'll try to describe what I'm referring to and hopefully someone will recognize what I want.

The article I'm reading and which actually has triggered previous questions mentions primary and secondary control. It's about controlling frequency and active power of one power system. The article says that there is a tight connection between grid's frequency and produced active power on one side and between voltage and reactive power on the other side. Primary regulation means a spontaneous action of primary machine's controllers (turbine controllers) whenever there is grid's frequency to change. But because it is related to turbine's controllers primary regulation is slow and transients disappearing with time constants of cca 10s. Primary regulation has static steady state error and therefore it is needed that secondary regulation be included. Secondary regulation is added to primary regulation in order to eliminate this error. Production units that participate in secondary regulation are often called regulation units....

This is roughly what is stated in the article. If this sounds familiar to someone please offer more appropriate terminology...

Thanks.


1 out of 1 members thought this post was helpful...
Posted by Phil Corso, PE on 22 August, 2007 - 11:56 pm
Responding to Mikas' 21-Aug (16:59)query... perhaps Charles Concordia's IEEE paper can help:

"Effect of Prime-Mover Speed Control Characteristics on Electric Power System Performance"
IEEE Transactions on Power Apparatus and Systems
Vol PAS-88; Issue 5 Part-I; May '69; pgs; 752-756.

Regards, Phil Corso (cepsicon@aol.com)


Posted by CSA on 23 August, 2007 - 12:36 am
I think you might be reading the wonderful UCTE document regarding requirements for connecting to the grid. It seems to refer to primary- and secondary frequency control, and my interpretation is that primary frequency control is most likely regular droop speed control and secondary frequency control is remote adjustment (by some regulatory agency) of turbine speed reference to try to assist with grid frequency disturbances. It's not too clear without reading the entire 92-page document (at least that's the size of the English translation one that was given to me was) and a lot of things seemed to have been "lost in translation."

Without being able to speak directly to people who know exactly what was written and/or who understand exactly what is meant in that document it's difficult to say. There have been a lot of "interpretations" by many different people from many parts of the world that have read some portion of that document (I don't think most of them have read it all; some of them have been simple but most have been obtuse. Some extremely obtuse.


Posted by Mikas on 25 August, 2007 - 12:06 am
Probably you're right, but I cannot tall that, because I'm reading article in my langauge which is not translation of the document you mention (beacause it is not stated that way). If you have that document in electronic form can you send it to me by email to "brobigi at yahoo.com"?
Thanks.


Posted by CSA on 28 August, 2007 - 4:24 pm
The document can be downloaded from http://www.ucte.org.


Posted by Namatimangan08 on 15 February, 2011 - 2:27 pm
>I'd like to ask for further explanation
>about primary and secondary control
>(regulation). If I understood correctly,
>primary control is spontaneous reaction
>of turbine's controller, but don't know
>what secondary control would be.

The function of primary control is to bring frequency rate of change to zero in less than 10 seconds. It can be achieved by means of one way, namely governor speed drop. How does it can do it?

Assuming you are operating 21 turbine generators in parallel to load 6000MW demands including losses. To comply with (N-1) redundancy you need to load each turbine generator at 6000/21 =285.7MW. The biggest per unit capacity of your turbine generator is 300MW. In our case here let us assume you have uniform per unit capacity turbine generator of 300MW but overrated capacity of 305MW.

By doing so you have a sufficient active power spinning reserve in case one of your turbine generators trips off.

Having the spinning reserve is one thing. To activate your spinning reserve to support generation shortfall when it comes to time you need it most is another thing.

Now your system frequency is at 50Hz. All of sudden one of your turbine generators trips off. Just after the tripping you have generation shortfall by 285.7MW. The total demand and losses remain at 6000MW. Obviously you have the scenario where there is net deceleration torque to slow down the system frequency equals to 285.7MW in power equivalent. The system free fall frequency rate (FFR) becomes

FFR = [H(MJ)/285.7MJ/s] seconds (for 50hz)

Where H is inertial energy of rotating masses of you turbine generators and loads.

Let us take a figure for H= 60,000MJ at 50Hz.

FFR= 50 Hz in 210second

FFR above means that such shortfall in generation will consume all inertial energy of rotating masses in 210 seconds. In the other words all your turbine generators' shafts become stand still after 210 seconds! 210seconds? It seems you have ample of times right? Wrong. Lower frequency limit of your system could be around 49.8Hz. Thus you have approximately 1 second to increase generation by 285.7MW in order to match supply and demand before the frequency falls below 49.8Hz. To date only one way it could be done, i.e. via proper setting of the governor speed droops for all your turbine generators.

I don't want to talk about how to set your droops since it has been much talked about.

What actually you want your droops to do? At system frequency => 49.80Hz you want all droops to command the remaining 20 turbine generators to increase output 285.7MW/20 each. If you set it well, each turbine generator will increase its output by 14.25MW at system frequency reaches 49.8Hz. Since you have 20 of them, you will get back 285.7MW generation you have lost. At this moment you should be able to arrest system frequency decay at 49.80Hz. The frequency rate of change (dF/dt) shall become zero. But you have already consumed dH by approximately

dH =(50-49.8)* 6000 =240MJ

Note that supply-demand are already matched. But you still have to accelerate the shaft by providing net accelerating torque. Otherwise the system frequency will stay there at 49.80Hz. This is called secondary control or supplementary controls. There are many methods to achieve this objective. One of the methods is operator's intervention. E.g. all plant operators may change turbine generators set points to 300MW at system frequency 49.80Hz. Note that we have additional unit capacity of 5X20MW to be used to accelerate the frequency. We need roughly 10MW accelerating load that we apply for 24 second to reset system inertial energy of rotating masses to 60000MJ (at 50 Hz). In reality the process it is slightly complex than this since, except the two units that you use to accelerate the frequency, all your turbine generators will withdraw the loads as system frequency is rising from 49.80 to 50Hz due to the nature of speed droops operation. To mitigate this problem plant operators shall change the load set points as system frequency is rising.


1 out of 1 members thought this post was helpful...
Posted by Phil Corso, PE on 23 August, 2007 - 12:32 am
Responding to CSA's 28-Jun-07 (23:15) mis-statement, "yes, transformers are an inductive load on the system." I would be remiss if I let this error pass without comment.

A transformer is not an inductive load! The only "load" a power source would be "charged" with (excuse the pun) are the transformer's losses and magnetizing current. Combined, they're an insignificant "load!"

Regards, Phil Corso (cepsicon@aol.com)


0 out of 1 members thought this post was helpful...
Posted by CSA on 29 August, 2007 - 12:01 am
Oh, come on, Phil. You could be remiss once in your life.

I often wonder what the "1" key looks like on your computer keyboard(s).


Posted by sud on 13 July, 2010 - 2:00 am
hello,
i have a doubt and was hoping if any of you might clear it. what happens when the load of an isolated alternator is increased or decreased. is there :

1) only change in terminal voltage.
2) change in speed and frequency.
3)change in excitation voltage.

according to one source only the terminal voltage changes. but the important point is that there is a so called drooping effect. so definitely there should be a change in frequency. if so, why does the speed get altered ?


Posted by CSA on 16 July, 2010 - 1:08 pm
sud,

The clarity you seek can be found in the term 'isochronous control.' There should be no droop control on an isolated system.

If you are reading texts and manuals, skepticism is a good thing, unfortunately. A lot of these things seem to be produced by people who don't have any real-world experience with small, "islanded" power systems and who don't properly state all the conditions under which they are making their statements.

An alternating current system is "defined" by it's frequency, usually either 50 Hz or 60 Hz. Maintaining the frequency relatively constant is very important to an AC system (in most parts of the world, anyway; a certain Asian sub-continent seems to have a different view about this concept).

It's also important to know that the frequency of an AC generator is directly proportional to the speed of the generator rotor, which is driven by the prime mover (turbine, reciprocating engine, etc.) of the generator.

Voltage stability is also critical on an electrical system, so maintaining the voltage is very important in most parts of the world, as well as for an isolated system.

The governor of the prime mover which is producing the torque that the AC generator (more correctly called an alternator) is converting to amperes should be configured to maintain rated speed and frequency regardless of the load. That is the function of isochronous speed control: to maintain rated frequency during load changes.

The voltage of an AC generator (alternator) is a function of the excitation applied to the rotating magnetic field, which is controlled by the exciter regulator, commonly referred to as the AVR (Automatic Voltage Regulator). The purpose of the AVR is to vary the excitation as required to maintain the generator terminal voltage setpoint.

So, working together the prime mover governor and the AVR (exciter regulator) should be able to maintain rated frequency and voltage for an isolated system, provided the load does not exceed the rating of the prime mover and the rating of the exciter.

The authors of many of these texts and references don't properly state the conditions of operation when trying to describe the effects of loading. They should be saying that if the prime mover governor does nothing to maintain the rated speed (and hence, frequency) of the AC generator and the exciter regulator (AVR) does nothing to maintain the rated generator terminal voltage, that when load is increased the speed will decrease and the generator terminal voltage will decrease.

But, in the real world, we don't want those things to happen so the prime mover governors and the exciter regulators are designed to maintain speed (frequency) and terminal voltage as load changes.

Skepticism is good, and I applaud you for doubting the references you have found.

Remember: An electrical system is just a means for transmitting torque from one place to another, or to many other places. The prime mover driving the generator is really driving all the loads connected to the generator by the wires of the transmission and distribution system. The generator converts the torque from the prime mover into amps, and the loads convert the amps back into torque (in various forms, including "virtual torque" of computers).


Posted by Philipe on 13 February, 2009 - 6:35 pm
This is a very interesting discussion. I am wondering if anyone has had experience operating an induction generator at varying speeds above synchronous speeds, say 1810 to 1850 rpm.


1 out of 1 members thought this post was helpful...
Posted by Phil Corso on 15 February, 2009 - 7:21 am
Philipe, I suggest you submit your post as a new topic... "induction generator."

BTW, component substitution is one of the better ways to resolve problems.

Regards, Phil Corso (cepsicon@aol.com)



Posted by surya on 8 August, 2010 - 6:58 pm
Dear CSA,

you said that increasing torque will increase the current in the generator. my question is torque means mechanical torque or electromagnetic torque. if it is a prime mover torque could you please explain me briefly about this subject


Posted by CSA on 9 August, 2010 - 8:17 pm
A generator is a device for converting mechanical torque into amps.

A motor is a device for converting amps into mechanical torque.

Motors and generators are joined together using wires.

So, in effect, one is just transmitting torque over wires using electricity as the medium.

Same as with a hydraulic system. One uses a pump (driven by an electric motor, usually!) to convert mechanical torque into pressure and flow. And then at the other end of the hose or pipe that pressure and flow is converted back into mechanical torque or work (power).

In a hydraulic system, one is sending mechanical torque from one place to another using hydraulic media and means (fluid and pipes).

In an electrical system, one is sending mechanical torque from one place to another using wires.

Hope this helps!


Posted by surya on 12 August, 2010 - 10:42 am
dear csa,

thank u for giving me information but my doubt is if the frequency of grid remains constant and if we want to increase the load. what we are doing is we are increasing the mass flow of turbine, increasing the massflow will increase the torque on the turbine. how this prime mover torque is related with increase in the current. could you please explain me this briefly


1 out of 2 members thought this post was helpful...
Posted by CSA on 12 August, 2010 - 7:38 pm
surya,

If you're riding your bicycle on a relatively flat and smooth road and you want to maintain a constant speed then you will apply a relatively constant torque to the pedals. If you increase the torque, then the speed of the bicycle will increase. If you decrease the torque, then the speed of the bicycle will increase. But, if you want to maintain a constant speed you will maintain a constant application of torque to the pedals.

Now, let's say you are riding a tandem bicycle with another person who is also pedaling. And you are on the same relatively flat and smooth road and you are to maintain a constant speed. The two of you will work together to apply sufficient torque to maintain the constant speed. Now, if you suddenly increase the torque you are applying to the pedals and the other rider does nothing, he maintains his torque constant, then the speed of the bicycle will increase. In this case the load (the weight of the two riders and the bicycle and any wind resistance) hasn't changed, but the amount of torque being applied to the pedals has changed, and that will result in a change in speed. But, that change in speed is undesirable (you're supposed to be traveling at a constant speed, remember?), so the other rider will have to decrease the torque he's applying to the pedals to maintain the constant speed because you have increased your torque.

Now, let's say the two of you are riding on the same relatively flat and smooth road and are working together very well to maintain the constant speed. Suddenly, your young cousin who's running alongside jumps on the handlebars of the bicycle, increasing the load and decreasing the speed. Either you, or the other rider, or the two of you together, will have to increase the amount of torque being applied to the pedals to get back to and maintain that constant speed. Until the two of you can reach a proper equilibrium the speed may vary above and below the desired speed, but eventually everything smooths out and you all three are traveling at the desired rate of speed.

An electrical grid is no different. The load on an electrical grid is the sum of all the motors and lights and devices that are converting amps into power and the amount of generation must exactly match the load in order for the grid frequency to remain constant. On an AC grid, it's very important (in most parts of the world, except, it seems, for a certain Asian sub-continent) to maintain a relatively stable grid frequency.

In reality, as motors and lights and other loads are switched on and off and loaded and unloaded, the grid frequency varies somewhat from 50.00 Hz or 60.00 Hz (which is the typical frequency in most parts of the world). The variance is usually on the order of hundredths of a Hz (0.0n Hz). It's never exactly 50.000000 Hz or 60.000000 Hz all the time, because loads are continually being switched on and off. And at certain times of the day and evening and night, the grid operators have to be very careful to add more generation (increase the amount of torque being produced and/or increase the number of generators and prime movers) or decrease generation in order to be able to maintain a relatively stable frequency, not exactly 50.000000 or 60.000000 Hz, but as close as possible. The variance from nominal is a reflection of how well the generation is matched to the load. The closer to nominal, the better; the further from nominal, the less better.

Just like the two riders have to do on the bicycle when the load suddenly increases, or decreases. Control systems can be programmed to do lots of this responding to changes in load, but people still have to assist these control systems.

It's important to understand that when you increase the "load" on a generator, by increasing the amount of torque being produced by the prime mover driving the generator, that if the load on the grid is not changing appreciably, then some other generator and it's prime mover must reduce the load it is providing, or else the grid frequency will increase. That's what governors and grid operators do: They control the amount of generation to provide only enough power to supply the load that is currently connected to the grid. If the governor and/or the grid operators don't increase generation when it's required, then the grid frequency will decrease. If the they don't decrease power when the load decreases, then the grid frequency will increase.

Exactly like what happens on the tandem bicycle. Only, a grid is like a bicycle with many cranks and people applying torque to the cranks. And the load is the weight being carried by the bicycle (presuming it's on a relatively flat and smooth road). If the weight (load) is variable, then the amount of torque will have to vary also--to maintain a constant speed!

If there are tens or hundreds of people pedaling this bicycle to carry the load at a constant speed, then if one person increases the amount of torque he's applying to the pedals and the load is constant at that point then the speed of the bicycle will increase very slightly, almost imperceptibly. But, it's likely that someone is watching the speed of the bicycle and they will either reduce the amount of torque they are providing or they will tell someone to reduce their torque--in order to maintain a constant speed while carrying the load.

Multiple generators on a grid are like multiple people pedaling a bicycle to carry a load at a constant speed. They are supplying torque to move a load that is likely bigger than any single person could move independently. And, their pedals are all linked together by a chain that prevents any one person's pedal speed to be more or less than any other person's. And, the speed of the bicycle dictates how fast the pedals are turning.

Let's say that the load being transported by the bicycle is on multiple trailers hitched to the bicycle. Further, let's say that several of the last trailers become disconnected from the bicycle; this would represent a decrease in load. If everyone pedaling the bicycle continued providing the same amount of torque the speed would increase. So, someone or something will tell some of the people to reduce the amount of torque they are providing, or even to stop pedaling altogether, in order to get the speed to remain as close as possible to the desired speed.

On an AC grid, when the load increases but the generation (the amount of torque being provided to the generator(s)) does not increase, then grid frequency goes down. Or, when the load decreases but the generation (the amount of torque being provided to the generator(s)) does not decrease, then the grid frequency goes up. So, that's how prime mover governors and grid operators know when to increase or decrease generation (the amount of torque being provided to the generators): when the grid frequency is changing. And, good grid operators can anticipate load changes, such as when people wake up in the morning and turn on their lights and stoves and tea kettles and their damned television sets (now there's a waste of torque if there ever was one!). And when people generally turn everything off at night and go to sleep.

If you want physics and maths, use your preferred Internet search engine and search for various electrical generation articles. There is www.wikipedia.org, www.howstuffworks.com, candu.canteach.org, and any number of other similar sites for the basics. Wikipedia usually has links to references, which can be very detailed. Use different search terms, as you learn new words and terms and concepts, and you will find no shortage of detailed search results, some better than others.

A generator is a device for converting torque into amps. A motor is a device for converting amps into torque. Torque is the form of power that is mostly needed by various factories and loads (elevators; water pumps--the largest consumer of electric power (fresh-, grey- and black water); refrigerators; air conditioners; etc.). Lights are converting amps into heat, and that heat is producing light. And most consumers of power are not located near large sources of energy (rivers; natural gas pipelines; fuel oil pipelines/storage tanks; coal piles; etc.). So, energy is converted into torque by prime movers which are coupled to generators which convert the torque into amps which is transmitted by wires to various loads which are some distance away from the prime mover and its energy source. That's what electricity is: Converting power into amps to convert it back into power.

When the amount of torque being applied to a synchronous generator being operated in parallel with other synchronous generators is increased, the speed of the generator rotor cannot be increased. It's locked into synchronous speed, which is governed by the frequency of the grid with which it is connected.

So, because the speed cannot be increased, some 'magic stuff' happens inside the generator and the "extra" torque is converted into amps, which can be transmitted over wires to motors and other devices which can convert the amps into power (usually mechanical power) at the other end (of the wire that's connected to the generator that's being driven by the torque coming from the prime mover that's coupled to the generator).

Now, if you want to understand emf and counter emf and radians and armature reaction to satisfy your "doubt" (and that is a mis-use of the word; please see your Oxford's English Dictionary, or any online dictionary, for the proper definition and usage of the word 'doubt') then hopefully someone else can contribute to this thread, or you can use your preferred Internet search engine on any of the site listed above, and others which have been listed in many related threads on control.com, to answer your question(s) and satisfy your curiosity.

But, that's what generators do: They are devices for converting torque into amps so that the amps can be transmitted to remote locations and then reconverted into power to be used at the remote locations. Electricity is all about transmitting power from one location to another. There has to be a load for a generator to produce power. Energy is converted into power in the form of torque by the prime mover, and that energy is applied to the generator rotor, and the generator converts the torque into amps, and wires carry those amps to remote locations, where devices at the other end convert the amps into power (motors, lights, etc.).

Now, it's best to add this disclaimer: This applies to either relatively large grids or to smaller grids with good frequency control.

Now, surya, if you have observed other physical phenomena with respect to synchronous generators (alternators) being operated in parallel with other alternators and these observations are causing you to have questions about something you've read or been told please tell us what you have experienced and why it causes you to question something you have been told.

Or, if this is just curiosity about electricity and how it's generated, it's okay to say that, too.

But, we digress.

Generators are for converting torque into amps. If there was no electricity to allow torque (power) to be transmitted by wires to many remote locations, then everyone of those remote locations would have to have their own sources of torque (power) for their needs. And those sources of power would all require energy to be widely distributed. But, electricity makes that mostly unnecessary.

Exactly how those generators work and all the physics and maths is more than I need to know to be able to operate them properly and maintain them. Maybe you have a different need; we don't know, you haven't told us!

But every time someone has used physics and maths to try to explain electrical generation to me, I have gotten very confused, and when I have tried to use physics and maths to explain it to people they have gotten very confused.

Electricity is not rocket science. There are no rocket scientists working at power plants. (There are some who liken themselves to rocket scientists, but, ... well, ... I digress. Again.)

If you consider a bicycle as a means for carrying a variable load or loads (packages, goods, people, vegetables), and if you think of how to carry a variable load at a constant speed on a relatively flat and smooth road, then it should all become a little clearer. Because it's all about providing torque to a load at a constant speed, the same as on an AC grid.

Best of luck!


Posted by CSA on 12 August, 2010 - 7:57 pm
surya,

Here's a link I had been looking for for some time. The frequency graph used to be "real-time" but it seems to be static now.

https://www.entsoe.eu/index.php?id=108

There is yet another explanation of grid frequency, that may be of some help.

You might try looking at this page at different times during the day to see if the graph changes.

Enjoy!


1 out of 1 members thought this post was helpful...
Posted by Shahvir on 13 August, 2010 - 12:34 pm
Dear Surya,

I think the CANDU/CANTEACH link is really great as it even covers generators on finite grid.Also, different operating conditions (like AVR on manual, etc.) are also covers in the articles by Cowling. I feel you should really go thru it!

Regards,
Shahvir


Posted by CSA on 13 August, 2010 - 5:35 pm
To Shahvir's point, grids are generally classified into two different types: finite and infinite. The description provided previously is most applicable to what's termed an infinite grid, a very large electrical transmission and distribution system with many generators and prime movers connected in parallel supplying many loads, and the total load is infinitely larger than even the most powerful prime mover and generator connected to the system could ever supply on its own.

A finite grid is usually much smaller, and composed of a few (one, two, three, seven) prime movers and generators operating in parallel to supply a much smaller total load. Sometimes, the load is small enough that the most powerful prime mover and generator could supply the load by itself, but for reliability purposes it's decided to have multiple generators for redundancy. The prime movers running these generators would not be operating at maximum output, but would be operating at "part load", assisting with supplying the load at the desired frequency.

Some of these finite grids have the governor of one large prime mover and generator that is operated in Isochronous speed control mode, which means that if the load changes (motors and lights switched on or off; motors loaded and unloaded; etc.) which would tend to cause a change in the grid frequency that the Isochronous governor will adjust the energy being admitted to the prime mover to keep the frequency constant. The other generators and their prime movers are typically operated in Droop speed control mode, and they continue producing power at a relatively unchanged level (presuming the Isochronous governor is well-tuned and fast-acting).

If the Isochronous governor is not well-tuned and/or is not fast-acting then it's possible that the grid frequency will vary until the Isochronous governor can stabilize the grid frequency. In this case, the speed of all the generators and prime movers will vary as the frequency varies.

One more important thing to note is that we are discussing prime movers that are mechanically coupled to the generators, either directly or through reduction gears. There are some generators which are driven by "free turbines" which are uncoupled from the prime movers producing the energy admitted to the "free turbine." In such a case, it's very common for the "power turbines" to vary their speed with load, but the "free turbine" which is mechanically coupled to the generator (to transmit torque) is still held to a speed that is directly proportional to generator frequency.

A finite grid can be considered as a simple tandem bicycle trying to maintain a constant speed on a relatively flat and smooth road. If one rider changes the amount of torque being provided and the other rider does not (presuming the load is constant) then the speed will change.

If the load being carried by the bicycle is variable and the load increases and neither rider increases the amount of torque being provided then speed of the bicycle will decrease. It would make sense for the two riders to agree that one of them would attempt to vary his torque output to try to maintain a constant speed as load changed, because if they both do so and there is no communication or coordination between them then the speed will be unstable until they can both adjust their output to respond to the change in load. The rider who agreed to adjust his output to control speed as load changed would be analogous to the Isochronous governor of a generator's prime mover, automatically responding to changes in load which would tend to cause changes in frequency.

So, it would also be helpful, surya, if you would tell us a little more about your "situation", and if you're working on a smaller, finite grid (sometimes called an "island grid"), or if you're working on a larger, infinite grid, and if either of the grids are unstable.

And, as Shahvir has suggested, please review the information on candu.canteach.org, because it really is some very good and useful material; some of the best I've found and I've looked for a lot of information on the World Wide Web on governor control (which is what this topic is primarily about).


Posted by Shahvir on 15 August, 2010 - 2:55 am
Surya, in passing I suggest you also go thru the 'Woodward Governor' website where there's some great info on alternator Governor control & behavior of alternators on finite & infinite grid conditions, in Isochronous & Droop control.

Dear CSA, I applaud your patience in writing a detailed explanation for benefit of the posters... in spite of it being extremely exhausting! I thank you on behalf of all the electrical engineers for your service to the Engineering community. Do keep up the good work & God Bless!

Regards,
Shahvir


Posted by CSA on 15 August, 2010 - 3:17 pm
Shahvir,

Thanks for the help--and the kind words. I just try to remember how difficult it was for me to grasp some of these concepts back when I was reading the available literature (texts and reference material).

However, I don't think we've helped surya. I keep re-reading his posts and I think he's not clear on how generators convert torque into amps.

I'd wager he has no problem with how motors convert amps into torque. So, I'm just trying to find a way to help him understand that generators (really the prime movers driving the generators) are just converting the torque from the prime movers into something that can be easily transmitted to electrical machines on the other end that convert it back into power. Power being a time-rate of doing work, it isn't stored like energy can be. The amount of power being supplied by all the generators and their prime movers must be exactly equal to the amount of power being consumed by the total load (motors, lights, etc.) on the grid. If the load exceeds the power being provided, then the frequency decreases. If the power being provided exceeds the load then the frequency goes up. It's a balancing act that some grid operators and regulators are very good at, while others aren't for a variety of reasons.

Power out equals power in minus losses and inefficiencies. And it all has to be done at a relatively constant frequency, which directly translates into speed.

Most people don't seem to have a problem with the fact that AC motors operate at a relatively constant speed (those that are directly connected to the mains). But, when it comes to generators they seem to think that because the speed varies during start-up and shutdown that the speed must vary during loading and unloading, because the fuel is changing during loading and unloading just like it does during starting and shutdown.

And, I believe most people don't really understand the whole synchronous part of synchronous motors and generators. That the speed is "fixed" by the frequency of the grid with which the machine is connected, that there are great magnetic forces at work inside the synchronous machine that keep the speed directly proportional to the frequency, regardless of the torque being applied. (The caveat here is that this explanation applies to very large, infinite grids, or to smaller finite grids with good load and frequency control.)

Anyway, thanks for the help with references, and please feel free to offer your own analogies or explanations or clarifications to anything that is written here!


Posted by Shahvir on 16 August, 2010 - 12:48 pm
Dear CSA,

You are most welcome!... coming to our thread, I think the problem with many posters in grasping these theories is because it looks convincing in print but is hard to visualize! If you do remember, I was stuck with the same problem in the past in which Mr. Phil Corso's help was involved.

The reason being, most of the time, alternator operation is always attempted to be understood when operating on finite grid , wherein the capacity of the alternator in question is more than 5% of total grid capacity. On a finite grid, the terminal voltage too changes with changes in driving torque (considering AVR on manual). I must admit the CANTEACH/CANDU article was of great help to me in understanding the same.

In due course of time, I came to understand how important a role was that of an 'automatic Governal control mechanism' (it is but obvious in practice, but in theory, the automatic Governor speed control is not emphasized upon)...and then there was this 'Woodward Governor' website & everything fell into place.

I think an Engineering concept is best understood if it could be visualized....your beautiful analogy with 2 riders on a bicycle falls into this!

Many a times, posters try to compare theoretical concepts with the practical... the problem arises when they try to visualize these concepts. The conversion of torque into Amperes cannot be easily visualized in AC machines as a lot of electromagnetic physics is involved and there are too many physical events (mechanical to electromagnetic) happening at the same time. We always tend to relate voltage with Amperes (Ohm's Laws) but it's a bit difficult to relate (visualize) Torque with Amperes. This is due to our inherently strict belief in Ohm's Laws taught throughout grad school.

In passing, I feel a concept is best understood if it could be easily visualized. Maybe, the poster is finding difficulty in same.

Regards,
Shahvir


Posted by CSA on 16 August, 2010 - 3:29 pm
Shavir,

Can you share the link to the Woodward Governor Control document which was so helpful? I must have missed that one!

Thanks!


Posted by Shahvir on 17 August, 2010 - 1:10 pm
Dear CSA,

Following is the link you asked for;

www.canadiancontrols.com (then go to the 'resources' tab for pdf articles)

One could also Google 'Woodward Governors' and get an array of articles on the topic.

Regards,
Shahvir

P.S. - How does one upload attachments on Control.com?


Posted by surya on 20 August, 2010 - 11:35 am
Dear CSA,
thank u for giving me the valuable information on the frequency vs torque. My doubt is somewhat cleared after reading the load angle theory.


Posted by NITIN singh on 6 February, 2011 - 7:03 pm
My name is NITIN

1.How does steam turbine comes in speed controller from load controller?

2.what is pressure controller and what are its types and how does steam turbine comes in pressure controller from load controller?


Posted by jahanzeb on 2 June, 2011 - 4:00 am
Dear,

in steam turbine speed controller mode is only active up to FSNL.just when we sinc with Grid it shifted from Speed Controller Mode to load controller mode(to control the load)now if change in frequency of the system speed will only change with load rejection and load increment on ST by Load control Mode.

when ST will Desinc with grid it will come on Speed controller mode again...

About your Second Question pressure controller mode is the mode in which ST is controlling our Boiler.if a set point of pressure is given on Pressure mode now ST Governor Valve will set that pressure on the Boiler by opening And closing not seeing the load....


Posted by Fawad on 19 July, 2011 - 2:22 am
The turbine components shall comprise of spiral case, runner, turbine shaft, guide vanes, stay vanes, draft tube bend, links and levers for guide vane operation, servomotor etc. The turbine components dimensions and weights worked out by the computation programs, however, these dimensions may vary slightly depending upon the selected manufacturer. Nevertheless, due to these small variations, the powerhouse structures shall not be affected.

Source
http://enggpedia.com/mechanical-engineering-encyclopedia/dictionary /hydraulics/1729-components-of-turbine


Posted by tim on 1 February, 2012 - 4:41 pm
Helpful discussion here on turbine control systems. I'd refer to some of the PDF resources here that may be helpful as well:

http://www.mdaturbines.com/parts/steam-turbine-control-components


Posted by terry on 19 February, 2012 - 12:08 am
Dear CSA,

if the load sudden decrease in power system, the frequency of grid will increase, it will cause the governor to react to the change (decrease the speed).

However, what i heard from my lecturer, the detection of frequency from the grid is too slow compared to detection of pressure in the generator in order for the governor to react. Can you help me to explain this point?

Best Regards,
Wei Sheng

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