machine droop setting is 4%. let's say machine is at 20 MW & rated load is 40 MW. Hence it is at 102% TNR. (TNR-TNH=2%) If TNH reduces by 1% machine's load will increase by 25% of rated load (25% of 40MW) 10MW. machine will increase to 30 MW from 20MW.
1) Will machine stay there or it will again come down to 20MW to maintain original TNR-TNH=2% at reduced TNH of 1%?
2) If three machines of 40MW are operating at different droop settings say 4, 5 & 6%, how thaey will share increased load of 10 MW? Is there any equation or graph for this situation?
From the "Serious Department", eh? As in, can "Anonymous" be seriously asking this question after all the droop discussions on this forum?
1) Since Droop Speed Control is straight proportional control, there is nothing to cause the GRID frequency to increase back to 100%; the grid frequency will probably increase by some amount, but that amount is dependant upon many factors: the Droop settings of the other generator prime movers, the number of other generators connected to the grid, etc., etc. There are too many parameters to say for sure, but unless this unit is capable of raising the entire grid frequency back to rated (100%), the answer would be no; the speed/frequency would not increase back to 100%.
Now, consider what would happen if the speed/frequency did return to 100%? Then the unit would "cycle" between 99% and 100% like a yo-yo, and the grid would be unstable.
Droop Speed Control is straight proportional control. No reset.
2) If you're asking what would happen to the power output of three machines, each with the Droop settings you specified, when the grid frequency dropped by 1%? The unit with 4% Droop would pick up 25% of rated output; the unit with 5% would pick up 20% of rated output; and the unit with 6% would pick up 16.67% of rated output.
If you're asking if three machines with the Droop settings you specified were all operating at 50% of rated output, and the load on the grid increased by 10 MW what would happen? If there's no Isochronous unit on the grid, and no other units on the grid, and no PMS System (Power Management System) outputting signals to raise/lower the Droop Speed Setpoints of the units based on changes in frequency--well, the grid frequency would decrease, and the three units would each pick up a proportionate share of the load based on the amount of the drop in speed/frequency (see above).
The amount of load on a grid is NOT a function of the rating of the prime movers & generators connected to the grid, it's a function of the motors, lights, transformers, door bells, blenders, and garage door openers connected to the grid and in operation at that specific instant in time. Some "entity" has to be in control of/monitoring grid frequency and adjusting the output of the units and adding additional generation or removing excess generation as required to maintain frequency (which seems to be a problem in some parts of the world served by contributors to this forum...).
Otherwise, your question 2 is not understood.
What is constant settable droop?
Is there any specific guideline about, when to use constant settable drrop v/s fixed droop?
Can you send me the response curve of FSR in case of sudden vriation in grid frequency with constant settable droop?
Which is a preferred option of droop control (fixed or constant settable) for stnadrad combustion Frame-9 gas turbine connected to grid?
"Constant Settable Droop" is a means of "connecting" Droop speed control and power output (recall the flyball governor example where it was not possible to use load feedback?). Constant Settable Droop (another extremely poor choice of a name/term for a control scheme) came into wide usage on GE-design heavy-duty gas turbine applications with the advent of DLN (Dry Low NOx) combustion systems. During initial development, it was common for load swings (dips and spikes) to occur during combustion mode transfers. By "connecting" turbine speed reference to load (which is what happens with Constant Settable Droop), any variance in speed OR load will result in a response by the SpeedTronic to try to maintain speed AND load.
Rather than just supply Constant Settable Droop on DLN-combustor equipped units and regular Droop Controll on non-DLN units, the decision was made to just use Constant Settable Droop Control on almost every new units regardless of combustor type beginning in the mid-1990s.
There really would be difference in response to grid frequency variations between a unit with Constant Settable Droop and one without it.
The decision to use or not use Constant Settable Droop is really a discretionary one (the discretion of the requisition engineer during the design phase of the unit). Using Constant Settable Droop or not using it should have no appreciable affect on the response of a unit connected to a stable or an "unstable" grid. There really aren't any compelling arguments for using it or not using it--except for DLN-combustor equipped units which are more susceptible to load swings during combustion mode transfers (though a lot of control system design and modification has been done to lessen and even eliminate load swings during combustion mode transfers).
One has to remember that when discussing Droop Speed Control (Constant Settable or "regular"), that the unit can only respond to grid frequency variations IF IT IS OPERATING AT PART LOAD _AND_ THE EXCURSION DOES NOT CAUSE THE UNIT TO REACH EXHAUST TEMPERATURE CONTROL. If a gas turbine is running on exhaust temperature control and the grid frequency drops, well ... the power output of the gas turbine goes DOWN (because the compressor slows and air flow through the unit decreases and CPD drops--and fuel flow must be reduced to keep from exceeding the exhaust temp limit). If the unit is operating at part load and the grid frequency excursion would cause the unit to exceed the exhaust temp limit, the power output is limited.
CORRECTION: The sentence in the third paragraph should have read:
"There really would be _little_ difference in response to grid frequency variations between a unit with Constant Settable Droop and one without it."
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If there are four machines connected in droop mode only and not connected to the grid will the speed of all the machines drop in the following case??
Case: Machines running at 50Hz, 10MW load on each of them and 5100 RPM. If the load increases suddenly to 20MW, it will be shared equally amongst them, i.e., 2.5MW each. considering 4% droop. After the sudden application of load, will the speed of each machine reduce by some amount?
Will the speed of each machine increase back to the same value if the additional load was suddenly taken away?
If there are four machines operating in Droop speed control mode--WITHOUT any external load reference (such as AGC (Automatic Governor Control) or PMS (Power Management System) supplying a signal to bias the Droop Speed Control Reference, AND the units are NOT operating in Preselected Load Control Mode, in other words straight proportional Droop Speed Control mode (known as "Part Load")--and all machines have 4% droop, and no machine is operating close to or on Exhaust Temperature Control (Base Load), then IDEALLY the load increase will be shared equally between the four machines.
Since all the machines are connected together electrically on the same "grid/bus", yes, the speed of all the machines will drop equally since no machine can spin faster than any other.
If the load is removed, all machines IDEALLY will return to the same speed/load as before.
The speed of regulators and response of the fuel valves and the speed sensing circuitry, etc., all contribute to small discrepancies in the ability of the control systems to sense changes in operating conditions and respond to them. So, there will most likely be some slight differences in response rate, but the units should all ultimately respond similarly since they all have the same Droop setting (per your case).
In this situation, if three machines trip, will the only running machine take the combined load of the other three machines?
Will the speed of the only-runnning-machine continuously drop in this case?
What will happen if the combined load of the three tripped machines is more than the rated capacity of the only-running-machine? Will it trip too, because of underfreq(or underspeed)?
Another question not related to the above questions:
If an Exhaust temp high alarm comes, will the machine begin to throw load?
Generally there are relays to trip generators if the frequency gets "too low." (How low is "too low?" Only your utility or electrical system designer knows for sure--actually, it would be the underfrequency relay setpoint since that would be the value determined by someone.) That's one of the things which are being neglected in these discussions: other generator- and turbine protective devices/relays/schemes which may come into play in a real power plant setting. This is all basically theoretical discussions, assuming no external protective relays/schemes.
So, attempting to describe how machines would respond in a "real-world" setting with typical protective relays/schemes is very difficult.
In this scenario where all four units operating in Droop speed control had 10 MW of load each (40 MW total grid load), and the grid (total) load suddenly increased by 10 MW to 50 MW, as long as the rated output of each unit at least approximately 12.5 MW they would all share the load equally as the frequency dropped (assuming the underfrequency relay(s) didn't actuate). (On GE-packaged heavy-duty gas turbine-generator units underfrequency relays usually actuate 86G lock-out relays....)
Further, if three of the units then tripped and if the rated power output of the remaining unit was at least 50 MW then it would pick up the load as the grid frequency continued to drop--again, assuming the underfrequency relay(s) did not actuate.
Remember: Droop speed control is based on the difference between the actual speed (frequency) and the speed reference. If a unit is programmed with 4% droop, when the difference between the actual speed and the speed reference reaches 4% then the unit will be approximately at its rated power output.
MOST GE-design heavy-duty gas turbines do not shed load when an exhaust overtemperature ALARM is annunciated--but that's a function of how the unit's control system is "programmed" based on how the owner/operator or utility wanted it programmed, or how the packager thought it should be programmed.
Thanks for the answer. One last question, if you dont mind. Since you mentioned the speed reference I would like to know a bit more about it through my question.
As I understand, the difference between the speed reference and instantaneous speed is equal (or proportional) to the load demand. In my question above, the speed reduces for a 2.5MW equal load on each generator. In this case will the speed reference come in picture (i.e., increase with 2.5MW additional load demand) since the speed is already reduced proportionately, thereby widening the difference between the TNR and the TNH. So whatever is the desired difference between TNR and TNH, it's achieved by a reducing TNH? So will the TNR at all need to increase to meet the load demand?
One last answer, if you don't mind.
When an operator wishes to increase the power output of a prime mover driving a generator being operated in Droop speed control he/she does so by increasing the prime mover's speed reference. If the prime mover is a GE-design heavy-duyt gas turbine with a SpeedTronic turbine control panel the name of the turbine's speed reference signal is TNR.
The assumption when operating a unit in Droop speed control in parallel with other generators on an electrical grid is that the grid frequency is relatively stable (actually, that it is stable) and is being controlled by some other machine (which is operating in Isochronous speed control mode, or, in the case of an infinite grid that some entity or organization is controlling the frequency by controlling the loads of multiple machines operating in Droop speed control mode in response to changes in grid frequency). The actual speed of the prime mover will not vary when the grid frequency is stable, so increasing the prime mover's speed reference will increase the error between the reference and the actual speed and this increased error will result in more energy being admitted to the prime mover.
When the unit is being operated in Droop speed control (i.e., it is not being operated at rated power output), and the load is steady that is because the speed reference is steady (the assumption being that the grid frequency is stable). If the grid frequency suddenly changes because of an increase in load--per your scenario where all the unit were operating in Droop speed control with the same droop setting--then the grid frequency would drop, which would increase the error between the speed reference and the actual speed thereby increasing the energy admitted to the prime mover.
"Steady-state" operation in Droop speed control mode (not including any External Load Control methods such as AGC (Automatic Governor Control) or a "local" load control such as Pre-selected Load Control which is an option usually provided with GE-design heavy-duty gas turbines which automatically raises/lowers the speed reference to maintain a LOAD setpoint) means that the droop speed reference is stable.
"Desired difference" between TNR and TNH? 99.99% of GE-design heavy-duty gas turbine operators, maintenance technicians, plant engineers, and plant managers don't have any idea that when they click on the RAISE- or LOWER SPD/LOAD targets or twist the SPEED/LOAD handle in the RAISE or LOWER direcion that they are changing the turbine speed reference which is increasing the prime mover's power output--they are only watching the megawatt meter's needle rotate in the clockwise or anti-clockwise direction. This author has never seen or heard anyone refer to increasing or decreasing load by increasing or decreasing the turbine speed reference. It's just one of those things which a person "does": click on RAISE SPD/LOAD to increase power output. They don't know "how" or "why"--that's just what they were taught to do to increase load. The "mechanics" of what's happening are just a mystery.
Go ahead--ask any operator, "What will be the difference between TNR and TNH when the unit is at 40% of rated power output?" Or, tell the operator, "Increase the TNR to 102.5%." The operator is going to look at you as if you were speaking Klingon (a reference to a language spoken by inhabitants of a distant planet on the Star Trek television show/movie series).
Droop training is now officially over.
I am a late-comer so did not know that this topic has been discussed ad nauseam earlier. can you suggest a good book for parallel operations of machines.
One really good resource this author has found on power plant operation and fundamentals is http://www.canteach.candu.org. Search for parallel, droop, synchronizing on the site--as well as many other topics. There is a wealth of free information there, some very basic, some at an intermediate level--all of it very useful and informative. This is a great resource for all kinds of topics!
There are many texts; Charles I. Hubert's books (see http://www.Amazon.com or http://www.alibris.com) are very good. This author has also found "reprints" of the U.S. Navy Bureau of Personnel 'Basic Electricity' texts available for less than USD$20.00--which is a BARGAIN!--which are also very good for fundamental descriptions of principles. ('Basic Electricity,' Publisher: Dover Publications, ISBN: 0486209733).
http://www.alibris.com is a very good source for out-of-print books and used copies of expensive texts (usually at very reasonable prices!), as well as new books and texts--highly recommended!
Another book, 'Power Generation Handbook,' by Kiameh (author's surname) is also very good--with lots of information on heavy-duty combustion turbine principles, also.
Let me explain how the machine responds to grid fluctuations with calculation part.
FSRN is speed control FSR
TNRL is load turbine speed reference
TNH is turbine shaft speed
FSKNG is FSR speed ref prop gain (constant)
DWKDG is speed control droop reference
DWDROOP is turbine load reference
DWKDG is calculated constant. For frame nine machine of 125 MW capacity and 4% droop setting DWKDG=4/125=0.032 %/ MW. It can be calculated for 5% droop and 6% droop.
Let us take an example:
Machine is operating at 62.5 MW load at 50 HZ and TNR is 102%
Suppose grid frequency dips to 49 HZ
So new FSR will be 65%, in this process the machine may reach base load. Once the machine reach base load FSRT takeover the control from FSRN. When the grid frequency sharply increases the machine gets unloaded as per above the calculation. sometimes manual intervention is required to stop unloading beyond the acceptable limits.
In either case machine come back to original set point provided that manual intervention is not taken place.
The equation you have given I have some question about that:
I think it is like
Is this the equation or am I missing something? If I miss something then tell me. Meantime I will search the CSP to find out that.
Still is not clear to me which formula is correct:
FSRN=(TNRL-TNH)*FSKNG+FSRN(existing) or FSRN=(TNR-TNH)*FSKNG+FSR(AT FSNL)?
TNRL (Turbine Speed Reference-Load-biased) is generally the name of the load-biased droop speed control reference when a GE-design heavy-duty gas turbine is controlled using a Speedtronic turbine control system which is configured for Constant Settable Droop speed control.
To be certain which formula is used on a particular unit, one needs to consult the SpeedTronic Elementary, or the CSP (Control Sequence Program), or the Toolbox sequencing.
Thank you, but i have a little question i think u can help me.
Suppose the correct formula is :
and suppose we are connect to the public utility, if the frequency goes up (means the public utlity is loosing some loads) our generator will start to be downloaded because of the excess power from the public utlity.
Now just taking the above example with the following data:
"Machine is operating at 62.5 MW load at 50 HZ and TNR is 102%"
i expect that TNLR will change at same time when the excess power from the public utlity will be available. Basically it will be more then 100% because i expect DWDROOP feedback less the 100% ( let's say 1.9% and therefore TNLR should be 100.1%).
However at the same time also TNH will increase ( let's say to 100.1%) so it looks to me that FSRN will never be operated ( to close the governor valve) because TLRN and TNH will be equal at same time.
As i said this is because i expect our generator to be downloaded as soon as the the excess power from the public utlity will be available.
Maybe i'm wrong but the alternative solution for the above formula is that TLNR is always 100% and TNH is going above 100%.
When utility frequency increases while a unit is operating on Droop Speed Control (including Constant Settable Droop) TNH will increase (since TNH is the ACTUAL turbine shaft speed which is directly proportional to frequency). TNRL isn't changing because frequency changes; TNH does. The change in TNH precipitates the change in load. Load won't change unless fuel changes.
When TNH increases, the error between TNRL and TNH decreases which reduces the amount of fuel, which reduces the power output and causes TNRL to decrease because DWDROOP decreases.
That's what Droop Speed Control is supposed to do--and that's why utilities all over the world require generators paralleled with their grids to have Droop Speed Control. When frequency increases, it's because there is more power being provided to the grid than there is load using the power--so Droop Speed Control lowers the outputs of the units operating at part load on Droop Speed Control and that helps to control grid frequency.
Conversely, when grid frequency decreases it's because there is not enough power being applied to the grid to supply the load using the power--so Droop Speed Control increases the fuel to try to bring frequency back to "normal." It's not clear where the FSRN(existing) came from; it appears to be a way of expressing that the value of FSRN from the previous scan of the CSP is being used.?.?.?
You need to use the values of DWKDG for your unit and build yourself a table of values. DWDROOP will never be negative, unless power flow is negative.
Unfortunately, this author has a new computer and no access to his old one, and MS doesn't provide the MS_lineDraw.ttf font with WinXP.... Can we say we love Microsoft? (Actually, this author has made a lot of money because of the way MS does business; it's not easy money--in fact, it can be pretty frustrating at times. But that's the way the world works, eh?) So, a CSP looks like gooble-de-gook without the proper font.
Thank you again for your reply.
Last question just for my understanding (hope you don't mind).
If i'm connected to the grid and frequency change is because my network is producing more power then what is required (loss of loads somehere).
Practically the excess power will be absorbed by all the machines connected to the network like kinetic energy increasing the rotor speed and therefore frequency.
(I suppose that all generators connected to the grid and the grid it's self are in droop with frequency at 50Hz, no ISOCH control)
If the droop acts to close the fuel valve
of each generator (including grid itself)reducing the MW ouput according to the speed the total produced power decrease and then again the speed.
It looks that the balance point cannot be reached
at more the 50Hz.
From my understanding i though that new balance point is at smth more then 50Hz but i'm not able to give an explanation. Could you help me?
Thanx for your prompt reply.
I have just an additional question for my understanding, hope you don't mind.
Suppose i have my plant with four generators and the plant is connected to the grid (let's say that TNH is 100%).
If frequency increase is because the grid (which is suppose to be very big) increase the power generation more then required (i.e.some big load has been disconnected from the grid).
Now the extra power coming from the grid should be absorbed by my gererators and all the other generators connected to the grid like kinetic energy increasing the rotating speed of the rotor and therefore frequency in the network (let's say 101% TNH; moreover all generators in the entire network are in DROOP speed control).
Thus all generators will receive a command to close the fuel valve as per droop characteristic.
Now it was my understanding that the new balance point for all the generators is at 101%.
But if all generators are closing the fuel gas valves the kinetic energy coming from the extra power should decrease and all the generators will produce the required power (P generated= P Load).
If so the frequency should drop again to the previous 100% TNH.
Can you clarify me better how the generators will respond in DROOP and how the kinetic energy is changing with different transient condition?
Yes, it would seem that a stable point will not be reached. But, in reality, the dynamics of an electric grid is a science all by itself.
The discussions here have all been under "ideal" conditions and do not necessarily reflect what would happen on a real grid, especially a large, "infinite" grid.
Grids can be "soft" or "hard." Stability depends on lots of factors, including the distances between generators and loads. The types of generator prime movers (combustion turbines, steam turbines, hydro turbines, reciprocating engines, wind turbines, etc.) all respond differently to changes in load/frequency caused by frequency excursion.
It is recommended you refer to some texts on electric utility grid control for the finer details you are searching for.
The real effect of droop speed control is to reduce the effect of frequency excursions, not to completely correct them. Grids require monitoring and control to maintain stability and frequency control.
The Search function of control.com is VERY fast and powerful; most of these control-system specific terms have been defined in previous posts.
TNR is GE SpeedTronic-speak for Turbine Speed Reference ("N" is typical mnemonic for speed in mathematical formulae).
TNH is GE SpeedTronic-speak for Turbine Speed-High-pressure Shaft (since turbines can have more than one shaft, they are usually identified as high-pressure, low-pressure, or intermediate-pressure, depending on the unit/configuration). This is generally the ACTUAL speed of the prime mover.
The method by which the droop is set or specified in a control system depends on the control system and its vintage. Generally, it's a VERY BAD idea to change droop settings from those originally supplied with the unit without a complete power system study and a review of how it would affect other operating parameters (loading/unloading rates, etc.).
I am new in this forum, I have been working in hydro plant, and I have some question about this topic. Could you give some explanation about how to tune PID controllers? I mean, are there the same gains (PID) for interconected and aislated operation? Do you give some matematical models to demostrate it?
I hope your help.
Unfortunately, markvguy has no experience with hydro turbine control systems and tuning of their PID controllers.
Woodward Governor Co. has some manuals on line on their website. Their manuals usually have some very good generic information on PID loop tuning.