This is my first post on this forum. I hope there is someone who can provide some insight to my query!
Ok, here is the scenario. I have a turbine-generator synchronised with a large national grid. I am wanting to understand what happens to the power factor when grid power demand increases? Does it move towards unity, i.e improve? If so, what is happening to reduce the reactive component?
I understand that the generator must operate at the same frequency as the grid. So when grid demand increases, frequency decreases and the prime mover will utilise more steam or water or gas to increase shaft power to bring the frequency of the generator back in balance with the grid. Is this correct? But what about the power factor?
Can anyone shed any light?
Thanks in advance. Ian
The power factor of your generator is dictated by the nature of your load (you can refer to your "electrical machines" by siskind). Since majority of connected loads in the infinite grid is inductive by nature, it follows that your power factor will lag. And this is where your power factor regulator take place to compensate for additional VARS and bringing back your machine to its optimize power factor, usually 0.9 to 0.95 lagging to make the system stable.
did I answer your question?
When a synchronous generator (regardless of prime mover) is synchronized to a large grid it's speed is fixed by the frequency of the grid. The formula is:
F = ( P * N ) / 120
where, F = Frequency, in Hertz
P = number of poles of the generator (an even number)
and N = the speed of the rotor, in RPM.
Solving for speed:
N = ( 120 * F ) / P
The term synchronous means it is in step with the grid frequency, so changes in load don't affect speed or frequency. (That's not 100% true, but for a large grid the addition of a single motor to the load or the increase of energy provided by a single prime mover to a generator that it is driving will only change the frequency by hundreds of thousands of a hertz (0.00001 Hz), or less, so it's really insignificant, unless we are talking about the sudden loss of a very large generator or multiple generators, in which case the frequency (and hence the speed of the generators) will change by a larger amount.)
A generator is a device for converting torque into amps. A motor is a device for converting amps into torque. Generators drive motors. Prime movers drive generators. Motors drive pumps and fans. Lights and computers are also loads that are powered by generators. An electrical system is nothing more than a means of producing torque in one place and transmitting it to another to be converted back into torque somewhere else (or light or computing "horsepower).
The load (in Watts or KW, kilowatts, or MW, Megawatts) of a grid is the aggregate sum of all the motors and lights and computers connected to the grid, and the amount of generation (the amount of torque being produced by all of the generators' prime movers) must be exactly equal to the load or the frequency will vary from the desired setpoint. It's VERY important to note that the load of a grid is not determined by the amount or capacity of generation connected to the grid. The generators just work together to supply the motors and lights and computers (the load) of a grid, and if the amount of generation exceeds the amount of the load the grid frequency will increase, or if the amount of generation is less than the amount of the load the grid frequency will decrease. On an AC grid, excess power generation cannot be stored for later use. So the amount of generation must always equal the amount of the load (motors, lights, computers) connected to the grid.
As motors are started and lights turned on and computers turned on, the load of a grid increases. If the amount of torque being produced and supplied to the generators doesn't change, the frequency of the grid will decrease. So, the grid operators monitor the grid frequency and when the see it go down they increase the power produced by one or more prime movers to keep the grid frequency approximately equal to desired. Or, when motors are stopped and lights and computers are turned off the grid frequency will tend to increase but the system operators need to decrease the power produced by one or more prime movers to keep the grid frequency approximately equal to desired. This balancing act is going on all the time, all day, every day.
If you want to see an example of an operating "infinite" grid's frequency, real time, go to www.ucte.org, which has a little pop-up applet which shows EU grid frequency. Note: The scales change without notice. It's very interesting to watch the frequency in the evening and then again in the mornings, as load goes up and down, and then up. Very englightening. Note the grid frequency is not always a constant 50.0 Hz, but it doesn't vary very much from that, unless there is a grid disturbance or the grid operators aren't increasing or decreasing generation in response to load variations.
Power factor isn't really related to load (watts, KW, MW); it's related to the reactive load (the amount of capacitance and inductance) of the devices connected to the grid. The power factor of a synchronous generator connected to a large grid can usually be "controlled" by varying the amount of excitation applied to the generator field (usually the rotor). The amount of excitation is related to the generator terminal voltage. If the amount of excitation being applied is exactly equal to the amount required to make the generator terminal voltage exactly equal to the grid voltage (at the generator terminals), the power factor will be 1.0 (or, unity). If the excitation is less than required, the power factor will be less than 1.0, and usually is considered negative, and the power factor will be leading. If the excitation is more than required, the power factor will be less than 1.0, and usually considered positive, and the power factor will be lagging. (Note: This is from a generator perspective.)
When you have a unit connected to a large grid and it is not being operated in power factor control mode, and the excitation being applied to the generator rotor is stable, the real power output (watts, KW, MW) is stable, and the power factor changes, that's because the grid voltage is changing. (Grid voltage changes throughout the day, all day long, on most grids.) To maintain a certain power factor, one has to adjust the generator excitation to keep the generator terminal voltage in the desired relationship to system voltage (as determined by the power factor). Also, usually when generators are loaded or unloaded, if the excitation is held constant the terminal voltage will change and that will affect the power factor (something called "armature reaction").
The part about frequency changing and the prime mover governor acting to increase power output in response to a frequency decrease is what's called "droop" response, or droop speed control. The topic has been covered many times on control.com; use the 'Search' function to find the archived threads. The power output will only increase if the frequency is less than desired; as the frequency increases (either because the load decreases or the system operators increase the power output of other generators) the units which have increased their load due to the frequency decrease will decrease their output. The action is proportional, so if the error between actual speed and speed reference returns to normal, the output will return to normal. Only when the error increases or decreases in response to grid frequency changes will the output of the prime mover (and the generator, which is only a device for converting torque from the prime mover into amps) decrease or increase, respectively.
I also have a peculiar problem, there are 3 STG's, 2x 25 MW and 1X30 MW coal based supplying load in a steel plant. total plant load is around 48 MW and rest is exported to Grid. after grid is open, the plant is presently in non load sharing mode. The plant has 4 electric furnaces, where the load per furnace during throw off is 8 MW- which is for 10 minutes and again runs for 40 minutes and throw off. But there is no fixed load throw here. It can rise to 12 MW if the customer decides to open CB of other processes.
Although we suggested load sharing, bigger problem is of the load shedding needed, that is far too dynamic and bigger to be controlled- with a PLC, and signals to be sent to Governors for speed/load controls- that would be put in load sharing mode using dedicated controllers. Also there are cases like one TG not working and others sharing full load.
Load sharing or a power management system would be a good solution, but if you could get some advance notification from the plant that would be helpful for operators who, if they had some training, might be better able to respond.
Can any of the turbines operate in Isochronous speed control mode when separated from the grid? That may also be helpful though sometimes "smaller" coal-fired boilers can't be made to respond quickly enough to large, sudden load swings like "throw-offs" (rejections) or sudden increases like you seem to be describing.
The problem likely requires an analysis by a knowledgeable engineering organization who may be able to recommend a combination of things to help make the entire system better able to respond to load changes. I don't believe any single change is going to make enough of a difference to help significantly based on the information provided.