First of all, I need a clarification about droop characteristic. To my knowledge, droop can be seen as a speed error or mismatch of turbine speed in case of load change. In other words, it is said that droop of governing system is let's say 5% if change of 100% of load is causing 5% of change of turbine speed. Droop can be understood by characteristic frequency-output power and is approximately linear.
Now, I have found one example. It says basically this: "When frequency changes in the grid, every turbo-generator unit reacts and adjust its generated power. For instance, when frequency falls by about 0.1%, generation of a unit should be increased by 20% with droop of 5%."
Now I cannot understand this example. How 20% of more generation with 5 % droop can correct 0.1% in frequency drop? I guess this example assumes that there is only one unit in the grid which is allowed to correct frequency error.
What if there are more units on the grid? Due to primary regulation every turbine controller system (governing system) will try to correct this.
There has been a LOT written on droop speed control on control.com. Use the fine 'Search' feature and you will find more than you probably ever wanted to know.
Synchronous generators. Their speed is a function of their frequency (or, it can also be said that their frequency is a function of their speed). But because they are synchronous generators no generator can go faster or slower than the speed that is dictated by the frequency. And, because they are all connected together and their rotors are locked into synchronism with each other (magnetically), the prime movers which are mechanically coupled to the generators can't change their speeds either.
When a prime mover driving a synchronous generator is connected to a grid with other generators and their prime movers, particularly a large or "infinte" grid, the frequency of the generator is controlled by the frequency of the grid. And, since the speed of the prime mover is a function of the frequency of the generator (I'm talking about prime movers that are mechanically coupled to synchronous generator rotors), then the speed of the prime mover is fixed.
No synchronous generator (nor its prime mover) can run faster or slower than the other synchronous generators (and their prime movers) on the grid. It's just not physically possible for one generator to be running at 50.134 Hz and another to be running at 52.27 Hz, and still another to be running at 49.65 Hz if they are all connected to the same grid which is operating at 50.001 Hz. It just can't happen.
So, while a lot of texts try to describe droop in the way you did, in the real world, it just doesn't work that way, except when there's just one machine driving a load independent of any other machine. And in that case, the prime mover control system is usually operating in Isochronous Speed Control, not in Droop Speed Control.
To make a prime mover (which is providing the torque input that the generator is converting to amps that is being converted to torque by motors which are also connected to the grid) stably control its power output while connected in parallel with other generators and prime movers on a grid, the control systems employ straight proportional control. And that proportional control is called droop control, droop speed control.
By the way, stably controlling power output when connected to a grid in parallel with other prime movers and their generators is my definition of "sharing load."
Droop speed control looks at a prime mover's speed reference and it's actual speed, which is a function of the grid frequency.
To increase the power output, the speed reference is increased. But, since the speed can't actually change the increased error between reference and actual speed is converted to increased fuel flow. That increased fuel flow, which would tend to increase the speed, which can't increase appreciably, is still extra torque. And the generator converts that extra torque into more amps. All of this is done very smoothly and all the prime movers and their generators behave nicely and work together to provide the load. If the "load" on the generator is to be increased, then the turbine speed reference is increase again, the error between the actual speed and the speed reference increases again, which increases the fuel flow which increases the torque which increases the amps.
When turbine operators are watching the watt meter and twisting the governor handle in the Raise direction to get the watt meter reading to increase, they aren't changing the watt reference they are changing the turbine speed reference.
Droop speed control is straight proportional control in the strictest, purest sense of the word. There is no reset or integral action to increase the fuel to make the actual speed be equal to the reference. It can't be equal to the reference (if the reference is more than the actual speed); it's not physically possible. And droop speed control makes use of that impossibility to stably control the fuel in proportion to the error.
The error can change for either of two reasons: a change in the speed reference, or a change in the actual speed. It's not common (in most parts of the world!) for the actual speed (grid frequency) to change. But when the grid frequency (and hence the actual speed) does change, the control system "automatically" reacts to the change because the error changes and adjusts the fuel to try to compensate for the change in actual speed relative to the speed reference.
So now you can imagine what happens when the turbine speed references of all the prime movers connected to a large, "infinite" grid are all fairly constant, which means the errors between their speed references and their actual speeds are all fairly constant, and the grid frequency changes. Since frequency and speed are directly proportional, the error between actual speed and speed reference changes. If the grid frequency decreases, then the error increases which increases the fuel--of all the machines because they are connected together to the grid.
Each prime mover's governor (control system) will respond to a change of frequency as a function of the amount of droop that the control system is programmed to have. A 1% change in frequency on a machine with 5% droop will result a 20% change in load, nominally, supposing the machine was running at 80% of load or less to begin with. A unit with 4% droop will respond with a 25% change in load, nominally, again presuming the machine was running at 75% or less than rated load to begin with.
Some manufacturers use the above scenario, what happens to the power output of a machine whose primer mover is operating in droop speed control when the grid frequency changes as their definition of "load sharing".
It's important to note that if a machine is operating at rated power output on droop speed control and the grid frequency decreases, the prime mover cannot increase its power output any further. And a LOT of prime movers connected to a large "infinite" grid at any one time are operating at rated power output. So even though they are in droop speed control they can't pick up any additional load by increasing their power output when the grid frequency decreases. They're just along for the ride at that point. And if the turbine is a combustion turbine, a single shaft combustion turbine, well that's not good for the grid. But, that's for another thread.
Now, a machine which is said to have 5% droop will nominally reach rated output when the speed reference reaches approximately 105% of rated speed. Nominally is the operative word here. A machine with 4% droop will reach its rated power when the speed reference is 104%.
So, mull this over. Search the archives of control.com with the 'Search' feature and ask more questions. This is not a complicated subject, but a lot of what has been written in many texts is very theoretical and very confusing.
I like to describe droop one way like this: We are telling the turbine to run faster than it can when we increase the turbine speed reference. In other words, we are "allowing" the turbine speed to droop below the set point, AND we are making use of the the fact that under normal conditions the actual speed is relatively constant and use the error between the two signals to control the amount of fuel or steam or water or whatever energy source is being used in the prime mover.
As a side benefit of this, if the actual speed does change for some reason the control will automatically respond in the appropriate way to try to help maintain the grid frequency.
It's a wonderful thing, droop speed control. It's so simple, and so powerful. All at the same time.
thank you for your effort to expain this matter.
Actually, my questions came after reading this overview:
As I assumed in the article there is a mistake about 0.1% of frequency drop instead of 1% that will cause 20% of power output increase with 5 % droop.
However, your explanation rise another set of questions. Normally, as I understand the article and what I know from practice, prime mover control system usually has three modes of operation:
1. Speed control
2. Load control
3. Pressure control
In the start up phase, when generator circuit breaker is open, prime mover is controlled in speed control mode. Adjusting control valves changes total amount of steam flow entering steam turbine (assuming steam turbine as prime mover) which is directly proportional to speed of rotation.
Once generator is synchronized to the grid, control system is in either load or pressure mode (depends what is preferred by operators). For now let's assume it's load control mode. In this mode, control error that represents input to the controller is formed as a difference between set point and actual load.
What you have written in you response about changing speed reference is really strange to me.
I didn't find anywhere this information "To increase the power output, the speed reference is increased". I used to work in a steam power plant not that long ago and never seen that speed reference is changing in order to control output power Maybe it was going on "under the hood" but I don't think so. Control error was formed by comparing load set point with actual output power.
Although I can agree that both control modes uses the same controller, just in principle, there is a switch between speed difference (control deviation) and load difference (load control deviation). Either of these signals (which depends on control mode) is lead to a P-only controller. Speed set point and Load set point are entered separately (speed set point is meaningful only prior to synchronization).
If there is a mismatch then for example turbine's CVs (control valves) would open more to allow more steam flow. Since more steam flow cannot cause turbine to rotate faster, it will increase load (torque) angle and raise power.
There are many discussion about whether this action increase turbine speed a little bit or not at all. I wasn't able to observe this, since speed measurement is masked with process and measurement noise (+ or -2 rpm to 3000 rpm) so couldn't tell for sure.
Again thanks for the explanation, I must admit I don't have a clear understanding of droop control concept yet. Need to dig more....
I was explaining classic droop speed control which as been around since the beginning of governors; flyball governors were droop speed control proportional controllers. And for decades afterwards, governors and control systems were configured and programmed (when they became digital, programmed systems) to mimic the actions of flyball governors.
I'm not familiar with the kind of droop control you describe, and it raises some questions for me. If the control is strictly based on load, how does the control system respond to changes in frequency? Without somehow sensing a change in speed and responding to that change to try help support the grid when the frequency changes, the "droop" doesn't seem to be "droop" at all.
I have seen load-biased droop speed control, but that doesn't sound like what you're describing.
If you put in a load set-point, and the control makes the load equal to the set-point, then where's the "droop"? That's not strict proportional control. How does the system respond to changes in frequency, which will change the speed of the prime mover? That's one of the critical aspects to droop (speed) control for most grid operators and regulators.
You haven't said what kind of control system, and it wasn't clear from your original post that you were referring to steam turbines. My experience is primarily with gas turbines manufactured by GE.
A change of 0.1 Hz on a 50 Hz system represents a change of 6 RPM; a change of 0.2 Hz represents a change of 12 RPM.
I would be very surprised to learn there is no speed component at all in the droop control scheme on your unit.
On GE heavy duty gas turbines, when they are running in load control, the Speedtronic system changes the turbine speed reference to make the actual load equal to the load reference.
How does the control system at your site have 4% 0r 5% droop? What is the reference and what is the feedback for the droop control? Because if it's just load, and the load is always equal to the load reference, how do you know if the unit has 4% droop or 5% droop?
How will your unit respond to a 1% change in grid frequency when it's being operated in droop control?
Because that's part and parcel of droop control in my understanding: How a control system can be predicted to respond to a change in frequency. And most grid operators and regulators are keen to know this as well.
like I said, I worked for the power plant a long time ago. And even then, my main occupation wasn't turbine governing system. It was a steam power plant (coal fired). However, there was a misunderstanding. I wasn't talked about "my" power plant and droop about 4%. I was referring to that article in the link above. I didn't understand the example. Now I see there is a mistake. It was written 0.1% instead 1% of frequency change.
Now back to the load/speed controller. If I recall correctly, before synchronization control error is formed only from speed (set point - actual speed). After synchronization, turbine controller system is in load mode which means that control error is formed mainly from load deviation. Here I wasn't clear enough. I admit it. I was trying to say that concept of load control was not to artificially change speed set point. I'm pretty sure about that. Control system was digital but I don't recall which one (Alstom or Siemens I think, but never mind). There were separate speed set point and load set point on the operator screen - HMI. In load control mode primary controlled variable was power output, but there was a so called correction factor from speed. If I'm not mistaken, speed error (set point - actual speed) was added with some gain factor to control error which was formed from load.
I have already written that both control modes (speed and load) use same controller (as opposed to pressure control mode).
Anyway in steady state when there is no frequency (speed) error, and actual load is equal to set point, control deviation is zero and everything is OK. Now if load starts to change, there would be load error and controller would move control valves in order to correct it.
In the same way, if load is equal to set point, but there is change in a speed, so called speed correct factor would become different than zero. Now, even so load deviation is zero, there will be an overall control deviation (caused by speed correction factor), so again controller would change the position of control valves (HP and IP) to eliminate the error.
This way no set point is ever changed (they are adjusted by the operator) but speed/load control is done in a different way. Overall control deviation is formed this way:
CTRL_ERROR = (LOAD_SP - LOAD) + Kf*(SPEED_SP - SPEED). Some folks call this a cascade control, but it is not since for cascade control more than one controller is needed. Maybe feed-forward!?!, but in any case no set point is changed.
CSA, you didn't comment previous post. I wonder if you have seen that control concept before. There is one more thing if anyoone can clarify it.
Droop control is a pure proportional-only control. Recently I have found out that steam pressure control by turbine controller is PI (proportional plus integral) control. Can anyone explain, why PI control is necessary in this case?
I can understand that integral component of a controller is needed every time when steady state response experiences offset. If that is not desired, then integral component must be added to integrate error and thus eliminate steady state error.
However, I don't fully uderstand why this is important when controlling steam pressure.
Hey guys. In the plant that I'm working on now (CHP plant) there are two modes of operation. So called "frequency response" mode and "load control" mode. In the first case droop speed control takes place and the plant responds to the frequency variations automatically. In the second case load setpoint is coming from the central dispatch center which is monitoring the grid frequency and distributing setpoints proportionally. I hope that solves the problem.
Droop is a function in the turbine controller to help controlling frequency on the grid. If too high output is generated to the grid the result is a high frequency. At high frequency all producing turbine has to decrease their output in correspondence to the frequency on the grid and the opposite for too low frequency.
Droop is expressed as a percentage of speed change which will cause a 100% change in output. The frequency control error added together with the output control error will be the input to the Frequency/Output controller. The droop will be a pre-adjusted figure normally set between 3 and 10%. Normal default setting ,5%.
See also Dead band below.
Droop control is used when connected to utility or when frequency is controlled in island operation together with a limited number of other units.
I am working on Hitachi Gas Turbines and Shin Nippon Steam turbines. There are three modes of control provided for control of power.
1. Isochronous or Auto Frequency Regulator
2. Droop Mode
3. Load Limiter Mode or Auto Power Control Mode
Droop mode has been rightly explained by CSA. And of course the Isochronous mode is well known.
In Load Limiter Mode or Auto Power Control mode, the operator shall specify a certain value of load to be generated by the generator. When we keep the system in this mode, the generator load is fixed to the specified value. And this mode is enabled only if the Grid tie breakers are closed or when running in an islanded mode, the second generators tie breaker is in closed position and running in Isochronous.
This will have no control, and I seriously don't know how the machine may behave if a sudden load throw off is conducted.
This is just for your kind information.
CSA, really nice explanation.
I'm not an expert in this subject, but I'll try to share with you guys some of my experience in control modes for steam turbines operating "islanded" or connected with the grid. Please feel free to correct me or add some information, my intention here is to keep the discussion going and to learn more.
As you said, normally a steam turbine has many control modes: speed mode (which can be ISO or droop), pressure mode, "load" mode... The selected mode by the operators will depend to the overall site control strategy. What is the control objective for each machine, and its importance for the overall control strategy? How many backpressure turbines? Any other generators (gas turbines, condensing, etc)? How many steam headers? What is the steam level your boilers produce? How many other important equipment driven by steam (big compressors for an ethylene plant for example)? What about letdown valves and vents, how many?
This will determine if it is better to have a "load" mode as you described, or an "load-biased" droop as CSA said (which is called "pre-select mode" for a typical GE gas turbine I think). For most turbine governors (at least that I know), the "load control” you mention is nothing but an "outer" loop that acts moving the droop curve up and down, that is, "under the hood" the turbine is actually in droop mode and the load controller is changing the speed reference setpoint. For sure it would work if, as you said, it just controlled directly the steam inlet, but I don't think it would be a good way to operate for most site designs because it would not help the overall island control/grid control. However, you also said that there was some kind of feedforward strategy to adjust speed (never saw this, but it may work fine for your site. I'd like to know some details if it is possible).
In addition, when disconnected from the grid, at least one generator has to be in ISO mode (unless you have an external Generation Control System that acts controlling all generators in droop mode). Again, that is the standard as I know, but maybe your site has some specific situation to be handled.
Well, I'll go into details now about an specific example, so if you guys are interest you can keep reading. If you are already sleepy about my answer, stop right now because it will get worse (lol).
When starting up the turbine, before the generator's CB is closed, it is always in speed ISO mode. In this phase, we need that speed has zero offset from setpoint, for two main reasons:
1) The turbine has to follow the warm-up speed procedures (depends if it is a cold start, warm start or hot start), meaning the turbine may increase its speed in a straight ramp to the nominal speed, if in hot start, or in warm/cold start it has to maintain the speed in lower values for some minutes to warm-up (respecting the manufacturer's curves). It also makes sure that the turbine accelerates faster when passing through the critical speed zones (where it resonances and vibrates more).
2) We must achieve the same speed (or frequency) of the grid we will be connecting the generator (and also voltage and phase, but that's another topic), so we can synchronize both (close the CB).
After synchronized, we can also keep it in ISO mode if it is operating in island mode (that is, we do not have an "infinity" grid that dictates the frequency) but the chosen mode really depends of your site design. And that are a big number of possible designs and control strategies.
At my site, for example, we have two gas turbines (32MW each), two backpressure turbines (42 MW each) and one condensing turbine (it can operate with two steam levels. When with 3.5 bar, it can generate 8.5 MW, and when with 15 bar it can generate 42 MW max). As the gas turbines have its exhaust aligned one to a HRSG and the other to provide hot air for industrial crackers (big furnaces), the most economical way to operate them is in base load (which is in fact droop mode, but as they are at maximum load, they won't be able to increase load any further). So for us it makes no sense to use them in ISO mode, as we can't be varying theirs exhaust too much because, in a simple way to explain, "it is bad for the process".
Our boilers generates steam at 120 bar (called S-120). The backpressure turbines have inlet in 120 bar pressure, one extraction in 42 bar (called S-42) and one exhaust in 15 bar (called S-15). So, when we are connected to the grid, we always use pressure mode for these guys. The main purpose for them is to control the steam headers' pressure constant (S-42 and S-15), and the power generation in just a consequence. In pressure mode, they receive S-42 and S-15 steam flow setpoints from two header pressure master controllers, and have one PI controllers for each steam level. We do not have any droop in this case, the machine is not even worried about MW, frequency, speed, etc, because it is connected to an "infinity" grid. Of course we have many protection to avoid excess MW generation (above integrity limits), over pressure, over temperature, over speed, etc (safety first).
However, when the grid tie line opens (I'll not get in details about the reasons why), our system automatically put the steam turbines to ISO mode, as now the main purpose is to maintain the island frequency (site frequency) stable and avoid electrical equipment "malfunctioning" or even a completely blackout. For this we also have a load-shedding system, but again this is another long chapter. When the backpressure turbine is in ISO mode, the headers' pressure are maintained by letdown valves (less economical, but it is an emergency situation). If both of them are operating, we have a "de-tuned" ISO mode (a load sharing strategy) that the manufacturer called "parallel-isochronous" (I never heard about this nomenclature in literature, but this manufacturer called this way).
We do not have load mode for these two guys (and we don't need it), but it would be very easy to make it: just need to put them in droop control and configure an PI controller that would "look at" the MW transducer and then increase/decrease speed reference (change droop curve) to adjust MW generation (with some other strategies like anti-windup). These machines droop is very similar to a constant settable droop that we sometimes have in GE gas turbines (other option is standard droop). You just have to make sure you know what you are doing (not just know, but you are really good in this subject or have a specialized company to do this for you) and that your control strategy is well developed and implemented (and also, it is important to make a really good risk analysis, maybe even a HAZOP if necessary. Again, safety first).
One curious information: our backpresure turbines only goes to droop mode if the system has some inconsistent information about the grid ties, that is, when the system can't be sure if it is islanded or connected to the grid. The reason for that is a trade-off between pressure control and frequency control, since the S-42 loop continues to modulate independently from speed control. Again, this is a very specific situation that for our site, each site may have a best way to operate.
Well, hope to hear more from you guys. Best regards.
Very nice explanation about droop. could not be clearer. we planning to introduce AGC in my country in order to regulate automatically the frequency. I live in a small island in the indian ocean without any interconnection ties but we planning to increase the share of RES (wind and solar) to atleast 30% of generation in the next 5 years. It is believed that AGC may then help for the regulation. My questions are:
1. Can a generator operate both in droop and AGC modes?
2. After primary control has acted, what additional control AGC will bring?
Can you also clarify the following. when several units are on droop control and the grid frequency drops, this in turn increases the speed error and thus injects more fuel to increase the power of the units. the load will be shared as per their resp droop. However, due to an increase in load, the turbines actual speed decrease and thus grid freq decrease. The frequency is not restored to the nominal value unless the speed error is manually adjusted. with AGC the manual intervention will be automatic.
is that correct?
thank you for the reply
>1. Can a generator operate both in droop and AGC modes?
The two are not exclusive; that is it's not an either-or decision. In fact, AGC is effectively "remote" manual control of the speed reference. AGC just allows a remote operator or control system to change the speed reference using either discrete signals (RAISE and LOWER) or an analog signal to change the speed reference.
>2. After primary control has acted, what additional control
>AGC will bring?
I want to try to answer two questions with a single answer.
>Can you also clarify the following. when several units are
>on droop control and the grid frequency drops, this in turn
>increases the speed error and thus injects more fuel to
>increase the power of the units. the load will be shared as
>per their resp droop. However, due to an increase in load,
>the turbines actual speed decrease and thus grid freq
>decrease. The frequency is not restored to the nominal value
>unless the speed error is manually adjusted. with AGC the
>manual intervention will be automatic.
Primary frequency control is the "other" part of Droop speed control. At it's most basic, Droop speed control is about the error between the speed reference and the actual speed. So, under normal conditions the speed is constant (when grid frequency is constant), so to change load one changes the prime mover speed reference. And, when the desired load is reached then one stops changing the prime mover speed reference and the error stops changing and the load remains constant.
The basic formula for Droop speed control is:
Energy flow-rate into prime mover =The (Speed Reference - Actual Speed) term is the "error"--the difference between the speed reference and the actual speed. The 'Gain' value is effectively the "droop setpoint" and the 'Offset' value is the amount of energy flow-rate required to make the generator spin at synchronous speed (the speed equal to nominal grid frequency) with no (zero) load. 'Offset' and 'Gain' are fixed values (usually they are programmable values, meaning they can be changed manually, but for all intents and purposes they remain unchanged unless the Droop setpoint needs to change (which is almost never), or there is some large change in the prime mover operating or governing characteristic which requires more or less fuel to maintain synchronous speed with no load. (The energy flow-rate into a prime mover driving a synchronous generator is directly proportional to the amount of electrical power produced by the synchronous generator. Increase the energy flow-rate into the prime mover, and the electrical output of the generator will increase. Decrease the energy flow-rate into the prime mover, and the electrical output of the generator will decrease. An electric generator is just a device for converting torque into amperes, just an an electric motor is a device for converting amperes into torque.)
((Speed Reference - Actual Speed) * Gain) + Offset
Now, if the frequency changes--meaning the speed changes--then the error still changes, but this time the prime mover speed reference is staying constant and the actual speed is changing. As you correctly described, when the grid frequency drops this causes the energy flow-rate into the prime mover to increase--but only as long as the grid frequency is less than normal. To get the grid frequency to go back to normal it's necessary to increase the Speed Reference--and that's what AGC does. As was said above, AGC is a remote means of changing the prime mover speed reference. To get the speed (grid frequency) back to rated it is necessary to increase the Speed Reference to get more energy to flow into the prime mover to increase the speed.
When the load exceeds the ability of the energy flow-rate into the prime movers to maintain rated speed (frequency) then some of the 'Offset' energy flow-rate goes into supplying the load. So, let's say the load was 10 MW on the grid at rated frequency, and then a 1 MW load was suddenly started. If all the prime movers are operating in Droop speed control, then the grid frequency will drop slightly which will decrease the speed of all the prime movers and generators by the same amount. The prime movers need to supply 11 MW, and Droop speed control senses the change in grid frequency. The Speed Reference hasn't changed, but the Actual Speed did change, so some of the energy from the 'Offset' term that was helping to keep the units at rated frequency now gets consumed to supply the extra 1 MW in this case. To return the prime movers and generators and the grid frequency to normal, one needs to increase the prime mover speed reference slightly--and that can be done either by an operator using the RAISE SPEED/LOAD "button" on one or more units, or by a remote operator (or control system) issuing a RAISE SPEED/LOAD signal to one or more units via the AGC method (either a discrete RAISE signal, or increasing the analog Speed/Load signal--however AGC has been implemented).
Droop speed control is proportional-only control--meaning that there is nothing (no control action) that zeroes the error between the setpoint and the process variable. As you can see, in fact, Droop speed control requires an error to change energy flow-rate; with no error, the Gain term is zero, and the energy flow-rate will only be equal to the Offset value, which is just the amount of energy flow required to maintain synchronous speed.
Isochronous speed control is proportional-plus-integral (or reset) control, meaning that control action will always be trying to zero the error between setpoint and process variable. But, it's not normal to have one or more prime movers operating in Isochronous speed control on a grid (in theory it is, and on some small "island" loads, as they're called, there may be one or more units operating in Isochronous speed control or Isochronous load-sharing control (for multiple governors operating in Isochronous speed control, which is really a kind of de-tuned Isochronous speed control).
So, you have everything exactly correct! Just remember that when multiple synchronous generators are operating in parallel (synchronized with each other) to supply a large load, they (the generator and their prime movers) are really acting as one large generator. And all of the motors and lights and televisions and computers and computer monitors are all acting as one load. The thing about AC power transmission and distribution is that it occurs most efficiently when the frequency is at or very near rated--and that's whether it's one or one hundred or one thousand generators and their prime movers supplying "a" load (which can be tens, hundreds, thousands of individual loads). And, just to keep the prime movers and generators spinning at synchronous speed (the speed equal to nominal grid frequency) requires a certain amount of energy (steam; hydrocarbon-based fuel; water (for a hydro turbine); wind (for a wind turbine; etc.).
I have a question, if I could, ADOS. Has the power factor of the load of the island been considered for RES operation? Because, it's my understanding that solar (photo-voltaic) power sources don't supply, or aren't normally capable of supplying, (producing) reactive power, and wind turbines are generally "consumers" of reactive power (many of the generators are hybrid induction generators). How will the power factor of the island grid be maintained as more RES is added to the grid?
Thank you both ADOS and CSA for your clarifications.
However, I'd like to give my two cents here. By reading this and many other topics on this issue I also spotted that many people don't understand how droop control works on many modern prime mover's governor with electronic control system.
As CSA already explained, droop is now programmable and can be adjusted in the control system of prime mover. Therefore it is not a characteristic of a generator but characteristic of a prime mover's controller. I found on many places that droop is considered as generator's feature.
Like CSA explained, droop control is in fact Proportional only control (P controller) i.e. it doesn't have integral part according to the control system theory there will be always a mismatch between desired and actual speed. This is what enables load sharing with other generators on the grid.
However many people still asks the following:
1. How come that during the unit's start up turbine's speed is so accurately controlled when speed controller is P-only control?
2. How come that when generator is on the grid that load control is so accurately controlled?
I myself works in one coal fired power plant and in load control mode, stem turbine governor controls keeps actual load equal to load setpoint +-0.5 MW.
These are confusing things and I myself when starting work in the power plant asked myself the same questions. When turbine control system work in pressure control mode, it perfectly controls the initial steam pressure. When turbine controller works in load control mode, it perfectly keeps actual load equal to setpoint (or + or -0.5 MW which is negligible).
During the turbine startup, prior to generator's synchronization to the grid, turbine's rpm are very accurately controlled. Therefore all these controllers are definitely PI controllers. In our power plant we have 4 units and the system is very stable (part of European network, so there are no frequency deviations except for some major disturbance that are not seen lately).
And still our electronic turbine control systems have droop adjusted to the 5%. When examining how this is done during the commissioning, I have discover the following:
During the startup, speed controller works as classical PI control and controls speed very accurately. After synchronization, speed controller becomes P-only controller (Integral component is bypassed). In this case, if frequency deadband deviation is turned off, then actual speed (converted to Hz since generator is on the grid) - setpoint speed (50 Hz) forms deviation that is then divided with this adjustable droop factor and the total output of this P-only controller is added to the Load controller setpoint. This load controller setpoint is then compared with actual generator load and control deviation is then used as an input to PI controller.
So, when frequency deadband zone is Turned ON, small frequency deviation is blocked, therefore output from P-only speed controller is zero, so to the PI load controller goes only (Load SP - actual Load). That is why during normal operation on the grid, turbine controller keeps actual load very close to desired load.
If the frequency deadzone is turned OFF, then frequency deviation goes to P-only controller and gets divided with droop factor and overall signal is added to the load setpoint.
So for example, if there is an increase of grid's frequency (it means that more MWs are generated than actually needed i.e. generation is higher than consumption) speed setpoint - actual setpoint will be some negative value that is inputted to the P-only speed controller. Output of P-only speed (droop) controller is negative value that is added to the load setpoint for the accurate Load PI controller thus decreasing generator power. This is how it actually works.
I hope I made this a little bit more clear.