droop setting

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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.

markvguy
 
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.

markvguy
 
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."

markvguy
 
Let me explain how the machine responds to grid fluctuations with calculation part.

FSRN=(TNRL-TNH)*FSKNG+FSRN(existing)
where
TNRL=TNR-DWDROOP
DWDROOP=DWATT*DWKDG
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
TNRL=(102-62.5*.032)=100
TNH=98%
FSKNG=15 (constant)
FSRN=(100-98)*15+35(existing FSR)

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.

ankarao
 
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markvguy

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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).

markvguy
 
Hi Ankarao,

The equation you have given I have some question about that:

I think it is like
FSRN=(TNR-TNH)*FSKNG+FSR(AT FSNL)

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.

Thanks
Regards
RAM
 
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.

markvguy
 
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.).

markvguy
 
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?

thank you
 
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.

markvguy
 
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.

markvguy
 
Still is not clear to me which formula is correct:

FSRN=(TNRL-TNH)*FSKNG+FSRN(existing) or FSRN=(TNR-TNH)*FSKNG+FSR(AT FSNL)?

Thanks
Bob
 
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