I have one query regarding generator exciter control. I have two nos. 30MW GTG's connected directly to 11kV bus without any generator transformer. Also I have one grid transformer 132/11kV connected to same 11kV bus.Of course, there is bus-section in 11kV bus. All three are running in parallel and only 1-2 MW power is drawn fromgrid during normal condition. In this condition, both GTG AVR are kept in Voltage mode to control the plant 11kV bus voltage. Here can I put one AVR GTG in Q mode and other in V mode. What will be the effect. Alternatively, if I want to control the grid incomer p.f by giving grid incomer CT/VT input to AVR so that my grid p.f remains between 0.9 lag-0-0.9 lead what will be the effect. Whether this is done in any places as per your experience. I want to control grid incomer power factor by controlling the excitation of GTG by AVR. One AVR I will put in p.f mode and other AVR will be in voltage mode so that all MVArs requirement of plant is met by one GTG and other GTG will maintain the plant voltage 11kV constant.Any drawback for controlling in this way.I have check the GTG MVAr capability curve limit. It is within the capability limit.

Your control options will depend on what type of speed (and voltage) control devices you have implemented. Some controls will allow you to operate your unit speed controls in isoch mode but use a master device that will bias the unit controllers to act as if they are in base load.

To answer Rajendra Pal's question, generally, the AVR is in the voltage control mode. If you want to know the effect of changing modes, you can try some Matlab/Simulink models. There are complete dynamic models available, but most of them are probably only V control in the AVR. You have to code PF control and Q control.

Generally, it can be said that iso mode of all generating units in island condition would led to control fighting of them. in other hands all if units try to set the predefined frequency, and even a bit difference between their characteristics led to this problem. so the best way of power control of units in island is using of droop control participating of generating units in as a primary frequency control and final adjusting of frequency by a other unit as a iso unit or PMS system.

We have a system that operate all generating units, during island condition, in isochronous load sharing. While each unit continues to run at isochronous speed, load changes of each generator are proportional to its rated output. Several isochronous load sharing engine-generator sets connected in parallel respond as a single swing machine. During parallel condition with the grid, all generating units run at base load (set by operator or by automatic tie control). An automatic system changes the operating mode according to system condition (island or parallel with the grid).

I recommend to see Chapter 2 Review of common control modes on Woodward Manual 01740 - Power management.

Thanks to all you guys. By the way, in case I have three identical GTGs (same MVA and PF rating) with implementing the Load Sharing PLC. Are all three GTGs be able to operate in isochronous mode?

•If the three generators are connected to the grid, they cannot operate on isochronous mode. They have to operate in speed droop and the load sharing PLC will then distribute the load among these three units by adjustments in their respective speed setpoints.Parallel interconnection of generation units in isochronous control mode results in unstable operation and, typically, "hunting" among these units.

I agree with Leonardo and Charles. For the three generators connected to the grid they have to operate in speed droop and base load. For the three generators in parallel during island condition (not connected to the grid) isochronous load sharing is a good way.

The BIG question are these Generators will be Connected to Utility or it will be islanded ?1- if connected to utility * Usually the generators Have to be Operated into Droop Mode , the Governor's setting and droop setting have to be adjusted if the generator supplying a fixed amount of power . while the utility will control the frequency and work as a big isochronous swing machine absorbing any change on the load (of course just the normal change )* while nowadays a new controller and load sharing systems permit the operation of generator on isochronous mode with an adjustable import/export quantity ,the utility as we said will recover any change on the load . it mean if load increase it will supply more power and the opposite is true

2- if islanded from my opinion Droop mode is preferred but it still depends on the application* i - two Droop Mode Generator if have the same droop & speed setting they each will share load Proportional to their full power capacity * ii - two isochronous Generator . one of the unit will try to carry the entire load and the other will shed all of it's load , that's the normal unless we control both of them with load sharing line which adjust each one governor* iii - one droop unite & one isochronous unite a- normally the droop unite will run at the frequency of the isochronous unite (maximum output power of this system = max power of the isochronous + power output of the Droop mode unite)

b - if load increase the isochronous unite will change to follow the change on load c - if load decrease than the Droop o/p power . the frequency decrease and the isochronous unite will be motorized

from all of the options listed above it's clear that alllll options available but what's the application and what's the controller capability you have ?? it's worthy to know that

Ahmed has a good point.It depends on what control system you have available in the first place, as to what the preferred operational configuration will be.

Also, it has been assumed that when connected to the grid, that the 'grid' will provide frequency control.In the end frequency control has to be provided by a genarator ( the grid merely allows all the generators to be interconnected with each other and to the load demanded).

Usually in any sophisticated network control system you have two levels of control.The software programme ( EMS) that signals to the generators what their ootput should be ( inclusive or running the system outside of nominal frequency to correct system time, for example) and the hard wired system which the generator defaults to in the event of the failure of the EMS, eg, droop/ischronous control of the governor.

Great question btw, and good discussion... thanks to all for their input.

•If the two generators are connected to the electrical grid the frequency is imposed by the network and the generators have to run in droop mode. On island mode with two generators (or more) connected one of the generators should to be in droop mode and another in isochronous mode.Moments before performing the parallel with the network is usual that the generator in isochronous mode have to go to the droop to allow the synchronism.In terms of voltage control, if a step-up transformer exists with on-load automatic voltage control (automatic tap changer) is necessary to take in account that instability may occur due to voltage control of the generators (AVR) in order to avoid an unstable situation on the voltage and reactive power transit which can lead to a in the generator by under or over excitation.I'm referring to a mode of operation using two GE Frame6B Turbines + two generators 42MW in a refinery.If the plants in question provide power to sensitive loads is advisable to carry out a electrical stability study in order to predict the behavior of the electrical grid in transient situations.

There is a lot of conjecture about why 50 Hz or 60 Hz or why not some other frequency. I'm sure there wasn't just one reason, but several. But, it is what it is where it is, and we must accept it, because we can't change it.

Quite simply, if you don't match frequency (and likely voltage) and get the phasing within a certain range, the synchronizing relays won't allow synchronization (presuming they work correctly).

There are many good references to synchronization of synchronous generators on the Internet. I believe that one that's been recommended many times before on control.com is candu.canteach.org. It's some information from the Canadian Nuclear Industry that is very, very good. Some of the links and material are for the nuclear industry, specifically, but there is a lot of very good material about generators and synchronization and basic fundamentals about that kind of "stuff" there. Use your favorite Internet search engine and you can find more, it's certain.

A synchronous generator has a very large rotating magnetic field, and for a Frame 9E that rotating magnetic field (the generator rotor) has two poles (a North and a South pole) and it spins at 3000 RPM to produce 50 Hz "electricity."

There's this little formula that relates speed and frequency:

F = (P * N) / 120

where F = Frequency (in Hz)P = the number of poles of the generator rotorN = Speed of generator rotor (in RPM)

When a generator is synchronized to a grid with other generators there is current flowing in the stator windings, and what happens when current flows through a coil (in this case, lots of coils with many turns)? A magnetic field is generated, and in this case the magnetic field (three of them actually) are very, Very, VERY strong. So, this is a "second" magnetic field that is present in the generator, along with the rotating magnetic field of the generator rotor.

They call it a synchronous generator because when it's being operated properly, the magnetic forces of the generator rotor are coupled with the magnetic forces of the stator windings, and this magnetic coupling is very, Very, VERY strong.

The turbine actually tries to make the generator rotor go faster than 3000 RPM when the unit is producing power, but the frequency of the grid through that little formula above and the strength of the magnetic forces inside the generator *will NOT* allow the generator rotor to spin any faster than the frequency of the grid. (If the generator breaker were opened when the unit was producing power and the fuel were not quickly reduced, the turbine and generator rotor speed will increase very quickly, in fact, it's likely the unit might trip on overspeed depending on how much power was being produced

when the breaker was opened.)

So, when you are synchronizing the generator to the grid with other generators it's very, Very, VERY important to get the frequency and phasing correct so that the magnetic fields are not opposing each other and are attracting each other. Because if the generator breaker is closed and the fields are not closely aligned, there will be a very, Very, VERY big, loud noise and the generator and turbine will likely not be able to produce power for a very long time.

Now, when we talk about speed, or frequency, matching we don't usually match the generator frequency exactly. Usually the turbine and generator frequency is just slightly higher than grid frequency, and the synchroscope is rotating slowly in the clockwise direction. When the needle of the synchroscope approaches the 12 o'clock position then the voltage sine waves of the generator's frequency and the grid frequency are approaching the same point ("in phase") and that's when we like to close the generator breaker.

When the generator breaker closes with the generator frequency a little higher than the grid frequency and current starts to flow in the stator windings the magnetic forces of the fields developed in the stator GRAB the magnetic forces of the field and actually slow the generator rotor (and turbine shaft) down slightly. Because the fuel is not changed the extra torque that was being used to make the generator frequency a little higher than the grid frequency (by spinning the generator rotor a little faster than the speed which would correspond to grid frequency) causes power to be produced by the generator.

Generators are devices for converting torque (which is what makes the generator rotor spin) into amps. And when the generator rotor is locked into synchronism with the grid if the fuel flow-rate to the turbine is increased then the turbine produces more torque. That increased torque would TEND to increase the speed of the turbine and generator rotor, BUT the magnetic forces at work in the generator keeping the generator rotor magnetic poles locked in synchronism with the stator field forces means the generator rotor cannot be spun any faster. But, the generator, being a device that converts torque to amps, turns the extra torque into amps. And when we multiply amps times volts (and throw in the square root of 3 plus the power factor) we end up with power (watts, or rather, millions of watts, megawatts).

In addition, when you are synchronizing the generator to the grid with other generators it's important to match the voltage of the generator closely to the grid voltage. There are a couple of reasons, and one of them is that if there is a large difference in voltage (potential) between the generator terminal voltage and the grid voltage the generator breaker closing mechanism has to work very hard to close the contacts. If the voltage difference is very small, then the contacts close much easier.

The second reason for matching voltage closely (it's not usually matched exactly, though it can be and at some sites they do match voltages exactly) is that when the generator breaker closes when the two voltages are very closely matched there will be very little reactive power "flow" (we have to be careful when we use "flow" to describe reactive power here on control.com, because we can incur the wrath of

the Exclamation Pointer). If the generator terminal voltage is much higher than the grid voltage when the generator breaker is closed, then the VAr meter will indicate lots of lagging VArs when the breaker closes. Conversely, if the generator terminal voltage is much less than the grid voltage when the generator breaker is closed then the VAr meter will indicate lots of leading VArs. (Of the two possible conditions, lagging VArs is more preferable, but usually it's not desirable to have a large lagging VAr indication as it can upset the grid operators and grid reactive power and voltage levels.)

It's very, Very, VERY important to "match" frequency and voltage when synchronizing a generator and to make sure the magnetic fields are nearly "in phase" with each other when closing the generator breaker and to try to limit the VAr meter from indicating too many lagging or leading VArs (again, we have to avoid using "flow" when talking about VArs, even though everyone else in the world uses that description).

Think of how much power the Frame 9E turbine produces when it's running at rated output, 100 MW in your case. 100 MW is more than 127,000 horsepower! And the magnetic forces at work inside the generator are keeping that 127,000 horsepower from turning the generator rotor any faster than 3000 RPM. The Speedtronic isn't stopping the speed from increasing, the generator is! (Remember we said that if the generator breaker were suddenly opened when the unit was producing power that the speed would increase very quickly because that torque which was being converted into amps by the generator will then be allowed to increase the shaft speed, and very quickly!)

Now, think about what would happen if you closed the generator breaker when the magnetic fields were 180 degrees out of phase. The magnetic forces of the stator windings are going to spin the rotor VERY fast in one direction or the other to try to make the fields attract each other and then they are going to cause the rotor to STOP when the fields are attracting each other! In fact, if the generator breaker is closed when the magnetic fields are 180 degrees out of alignment then they are trying to repel each other with maximum force at that instant in time! In any case, the resulting mechanical forces from repulsion/attraction would just destroy the load coupling for certain, and probably the turbine- and generator rotors and/or coupling faces as well. It would not be a very pretty sight.

That's why those synchronizing relays mentioned at the beginning are there: to prevent closing the generator breaker when the magnetic fields are not in phase with each other. Because the results could be not only catastrophic, but deadly.

Look around the Internet (the World Wide Web) actually, for more information. This is difficult to describe without pictures and diagrams, but the concepts are the same whether or not there are pictures and diagrams.

Hope this helps!

And I just noticed, you indicated your unit does not have a GE control system. No matter; the turbine control system doesn't control the unit speed when it's synchronized on a grid with other generators

and their prime movers. The grid frequency controls the speed by virtue of that little formula at the top of the response.