Frame 6 GT was running parallel with grid at 22 MW preselect load. All of sudden MW hunting was observed (what causes hunting is not clear). The observation was that GT MW was rapidly varying from 40 MW to -20 MW. Another interesting thing was that grid frequency was fairly steady but GT speed was showing variation from 99 to 102 %. This speed variation was physically seen on field also.
During this period, our metering system was showing import and export with the grid in line with load variation seen in GT.
But this is in contradiction with popular belief that when synchronised, all units should run at same speed.

What can be the reason?

Second question is that during all this, we were unable to stop hunting even after putting machine in part load. Eventually hunting was stopped only once we were islanded with the grid.

 

The fact that everything stabilized when you islanded makes me very suspicious that something was happening on the grid. What was the period of the swing, like 1 second or less or more? If it was very rapid, maybe your frequency meter wasn't catching it. How long did this disturbance last? Have you re-synched to grid and now have stability?

 

Put the synchroscope ON and see what is the result.

Once machine is synchronized, speed can not be higher or lower. if the speed really is higher or lower, synchorscope will reflect it. it means generator is being de-synchronized momentarily.

there might be a probable reason of field failure, but it is blind guess only.

 

The load variation was for significant time. All theories suggest that turbine cannot run at different speed wrt grid and all replied will also say the same.

There were similar post few years back also, where there were numerous discussions but mostly inconclusive.

Finding the cause for hunting is irrelevant but by this post, I expect discussions by experts and to explore how it can be happened, rather than debating that it is not possible.

 

Oh well, in that case I won't waste any more time replying.

 

vinayak_paranjape,

There was a feeling about this thread which caused me not to post immediately.... There was just a "tone" which was foreboding.

Look--there are some physical locations and conditions on grids that are very "soft" and therefore the frequency and voltage can vary much more at these locations than others. These off-frequency operations usually don't last very long--because there are supposed to be protections (protective relays) to prevent prolonged operation at off-frequency conditions because when multiple generators and their prime movers are synchronized together on a grid off-frequency operations can affect all of them, some in more serious ways than others.

If one or more large generating stations "near" your location (and when speaking of grids, proximity can take many forms) tripped off-line or were separated from the section of the grid you are synchronized to then very strange things can happen. A well-regulated grid with properly tuned and properly operated (manually and automatically) prime movers and their governors will sense these kind of dramatic frequency excursions and either drop customers off (called "shedding load") or separate generators rather than suffer prolonged frequency excursions. (Pre-Selected Load Control does not qualify as proper operations--particularly during a frequency disturbance.) By your own admission, this was a one-off event--and as such, the details of it probably aren't fully known, and certainly not fully understood, by you and/or the operators/management at your site.

But, for all intents and purposes, when synchronized to a stable grid (frequency and voltage) the speed of any synchronous generator and its prime mover is magnetically locked into synchronism by the relationship:<pre>F=(P*N)/120

or

N=(120*F)/P

where F = Frequency (in Hz)
N = Speed of generator rotor (in RPM)
P = Number of magnetic poles of generator rotor (always an even number)</pre>This is scientific fact. Since the beginning of AC power systems. And hasn't--and doesn't change--except under extremely unusual circumstances which are <b>well beyond</b> the ability of your Frame 6 and it's turbine control system to correct.

Again, there are "soft" spots in many grids--and you haven't told us anything about your site and where on the grid you are located (how many kilometers from the nearest substation and/or the nearest generation facility of any substantial size; etc.).

Do you have hard, printable, electronic data to support what was observed? (This is called actionable data, as oppose to anecdotal data--that data just observed and verbally communicated, but without visible data (printed/printable; electronic) to support.)

People just don't seem to understand the basic physical principles at work in AC power systems and synchronous generators: magnetism. There are two magnetic fields in a synchronous generator when it's synchronized to a grid (or when it's supplying a load): the rotating magnetic field of the generator rotor (created by applying DC to coils mounted on the rotor), and the magnetic field created by the flow of AC current in the synchronous generator stator (armature) windings. And, the magnetic field of the stator "appears" to rotate because of the AC current flowing in the windings.

The generator rotor's magnetic field is locked into synchronism with the "rotating" magnetic field of the generator stator--just like when you have two magnets in your hands. When the North pole of one of the magnets in your hand is close to the South pole of the magnet in your other hand--WHAM! they are attracted to each other, very strongly. And it takes effort (dependent upon the strengths of the two magnets) to separate them. AND, when you try to force the two North (or the two South) poles of the magnets together--there is a great force repelling the magnets apart.

The SAME thing happens inside every synchronous generator when there is AC current flowing in the generator stator windings and there is DC current flowing in the generator rotor windings: the opposite poles of the two magnetic fields are VERY strongly attracted to each other, and because of the "apparent" rotation of the magnetic field resulting from the AC current flowing in the generator stator windings the generator rotor <b>>>>CANNOT<<<<</b> rotate any faster or any slower than the apparently rotating magnetic field of the generator stator. Pure and simple. Full stop. Period.

If you don't believe this, look at YouTube--there are tens, hundreds, of videos and demonstrations of AC generators and motors (they are essentially the same devices--one produce torque from amperes, the other produces amperes from torque--and wires connect them together) to see how this "apparent" rotation occurs. The apply your "hands-on" knowledge of how magnets work to the videos (videos are proof positive to many people of how things work!) and you can see--speed of rotation can't be faster or slower than synchronous speed (the speed proportional to the frequency of the grid).

If this weren't true, why is it so important to "synchronize" a generator to a grid with other generators? Why not just close the generator output breaker at any speed? Why is synchronizing a generator so involved and so critical? Because--if the two opposite magnetic poles aren't very closely aligned when the generator breaker is closed then the magnetic forces of repulsion will force the generator rotor to spin very fast in the direction of rotation--or WORSE, opposite to the direction of rotation--until the magnetic forces of attraction suddenly STOP the rotor when the opposite poles are attracted to each other. These mechanical forces caused by repulsion and attraction at work inside the generator can cause very serious damage to the generator, the coupling between the generator and the prime mover, and any gear box between the generator and rotor.

And, if maintaining synchronous speed wasn't so important when connected to a grid, why even worry about? Why not just let every prime mover and generator run at whatever speed is convenient for that site, the conditions, the operator's whims and fancies? Why do synchronous generators have to all run at synchronous speeds (speeds proportional to the frequency they are trying to produce or to the frequency of the grid with with they are SYNCHRONIZED)?

Again, there are unusual and unique circumstances, aided and abetted by physical locations (distance; wire size/type; transformers; coupling strengths; etc.) that can result in off-frequency variations, but they are usually not very long because there are protective relays which trip to protect generators and grid infrastructure--as well as other generators--from extended off-frequency operation.

Very sudden reverse power at high magnitudes (which -20 MW for a Frame 6B would qualify in my estimation) should cause the electromechanical or digital reverse power relay to operate and open the generator breaker. Why didn't it at your site???

Also, there are usually under- and over-frequency relays that operate to protect the generator and prime mover from off-frequency speed--and to protect other generators and grid infrastructure, also. Whey didn't these operate at your site?

Pre-selected Load Control is also a VERY poor way to operate GE-design heavy duty gas turbines--especially in locations where the grid frequency has a tendency to be unstable. When the grid frequency is unstable--the LAST thing anyone (grid operators; customers) want is for synchronous generators to be operating at a constant load. That's the EXACT OPPOSITE of what should be happening during a grid frequency excursion--all synchronous generators should be changing load to try to maintain frequency, not changing frequency to try to maintain load. The energy flow-rate into the prime mover needs to vary during frequency excursions which means the power output will vary, instead of the energy flow-rate into the prime mover remaining constant which means the power output will remain constant. If governors are "free" to change load to try to help stabilize grid frequency when it's off-normal, then the generator is NOT helping to support grid frequency.

One can use Pre-Selected Load Control to change load to some setpoint, but at that point the operator needs to click on RAISE- or LOWER SPEED/LOAD to cancel Pre-Selected Load Control. <b>Contrary to popular MYTH</b>, unit load will NOT change without Pre-Selected Load Control active and working at all times. As long as grid frequency is stable, load will be stable without Pre-Selected Load Control active. Try it and see? (I know it will NEVER happen, but I keep trying anyway....)

Finally, when someone offers help for your query/problem, don't be rude and keep insisting that "popular belief" means what you say you saw happened shouldn't happen--you are expressing that "popular belief" is doubtful and not true. Unless you can provide hard, actionable data to the contrary in this case "popular belief" (with but <b>VERY FEW</b> exceptions) is scientific fact. When synchronized to a grid with other generators and their prime movers, the speed of every synchronous generators is directly related (proportional to) to the frequency of the grid in relation to the formula above. Full stop. Period. End of discussion.

If the Droop speed setpoint of the GT turbine control system is not what it should be, or the coupling between the turbine and load gear or the coupling between the load gear and the generator rotor is very "spongy" (and they are not) then what you say happened might have happened. If the physical location of your turbine-generator on the grid is unique--or some large generation station or stations near your site tripped off line (???) then it's not very likely the speed fluctuations you or your operators allegedly observed actually occurred. It could be that the HMI display update rates weren't actually catching the real variations or were in fact catching and displaying only the extremes. And it could be that protections have been changed, because, again--reverse power relays and possibly over- and/or under-frequency relays should have opened the generator breaker to prevent what was allegedly occurring.

Glenmorangie is one of our best contributors here at control.com; he probably has more hands-on, operating experience with GE-design heavy duty gas turbines than many here (myself included). If you have doubts about things, that's fine--but to express them the way you did was disrespectful and showed a lack of basic understanding of the fundamentals of AC electric power systems. We do this (respond to requests for help with problems and information) for free--we are NOT compensated in any way (well, in little chocolate ways), and posting here doesn't cost anyone a cent.

 

vinayak_paranjape,

> The load variation was for significant time.

Define the significant time: 3 minutes; 9 minutes; 27 minutes?

Also, you say the speed fluctuation was observed in the field. Did someone actually use a tachometer (contact or non-contact type?) to physically measure the speed of the rotating shaft? Because, when there are wild load swings it <b>SOUNDS</b> like the speed is changing when it's really not. The <b>ACCELERATION RATE</b> can change (split-second)--but, again, unless there's something very unusual about your location and the conditions of the event it would be very difficult for the synchronous generator at your site to be running any faster or slower than the grid frequency would allow. Or, rather, that it forces the unit to run at.

> All theories suggest that turbine cannot run at different speed wrt grid
> and all replied will also say the same.

Um, if all will say it's not possible for a turbine to run at such wildly different speeds when the grid frequency is not changing (actually, I think you said it was "...fairly steady..." and you won't provide any details about the freequency variations), but you believe it is possible--and that it happened at your site--then it seems your problem is solved. What's a discussion going to do if it's based on science? Magnetism is magnetism--or is the synchronous generator at your site located in some kind of black hole?

 

Thanks CSA. I didn't have the time (or the inclination) to argue finite vs. infinite networks. I have seen these kind of load/frequency excursions on weak networks before,also thanks for pointing out Pre-selected Load problems (again).

Let's hope we can get more real data and we can try and help!

 

Dear Glenmorangie and CSA.

You people are our best guides in understanding GTs more. My apologies to you for my rude words.

The post was written that way because I am convinced that our turbine was rotating with high and low speed (TNH 99 to 101) compared to grid frequency (~50 Hz) and both max and min was for 1 or 2 seconds. This event was going on for nearly 1 hr, which was terminated only after we started one more machine in parallel.

All trip (protections) were in line, the load was reversing before actuating any of the trip.

 

As usual CSA you supported lot and others too.

We too felt different after reading initial comment from the author, anyhow he understood now.

take care
g.rajesh

 

This primary purpose of this post is to describe what happens when Pre-Selected Load Control is used to maintain load (electrical power output) during Part Load operation of a GE-design heavy duty gas turbine. Many of the principles involved are applicable to most, if not all, prime movers and generators synchronized to a grid. There are some definitions of terms and presumptions, a basic description of how "straight" Droop speed control is accomplished in digitial GE Mark* Speedtronic turbine control systems, then a description of how most Pre-Selected Load Control is accomplished--along with how it makes the heavy duty gas turbine "behave" during grid frequency disturbances. (And "behave" it does not.)

And then there are some sobering truths at the end.

The length of this post is directly related to trying to address most typical operating conditions and the questions I've been asked (and answered) many times when trying to verbally explain Droop speed control and Pre-Selected Load Control.

Any reference to gas turbine-generator operation below presumes a heavy duty gas turbine and that the turbine and axial compressor are in a new and clean condition, the turbine air inlet filter pressure drop is minimal (that is, the filters are clean), the exhaust duct back-pressure is at or below rated, the fuel being burned meets specifications provided when the fuel system was manufactured, the combustion system is NOT a low-emissions combustion system, the axial compressor inlet temperature is at machine rating, and all LVDTs and pressure transmitters are properly calibrated. Gas turbine-generator operation references also refer to Part Load (less than Base Load) operation unless otherwise specified.

References to AC power grids (generation, transmission and distribution, and loads--AC electric motors, lights, televisions, computers and computer monitors, etc.) are for very large, sometimes called "infinite"--grids with tens, hundreds or even thousands of generators, NOT small, so-called "islanded" systems with one, two or some small number of generators and prime movers, such as are common at some large refineries, some chemical plants, some natural gas compression/liquefaction plants, aluminum smelters, and even some paper mills.

In reality, all AC grids fluctuate during the course of every day, usually only by hundredths-, or less than one-tenth, of a Hertz--and this can be called "fairly steady" grid frequency. This is to distinguish the usage in this response from the original poster's usage of the term "fairly steady" grid frequency--which, as of this writing, has never been properly characterized by the original poster.

It's also important to note that multiple generators all synchronized together on a grid (of any size) are really acting as one very large generator to supply what appears to them ("it") as a single very large load that is comprised of many individual loads (electric motors, lights, televisions, computers and computer monitors, etc.). This is yet another "reason" or "explanation" for why all synchronous generators synchronized together on an AC grid must--and do--operate at fixed speeds (each machine has its own rated speed for the frequency of the synchronous generator's output): they are all acting together as one "generator."

All references to generator operation presume a synchronous generator and that it is synchronized to a grid with it's generator breaker closed--meaning there is alternating current flowing in the synchronous generator's stator (armature) windings and the generator rotating field is normally and properly excited.

Multiple generators and their prime movers synchronized together on a grid operate with the prime mover governors in Droop speed control mode. Droop speed control mode controls the amount of energy flowing into the prime movers driving the generators. Increasing the energy flow-rate into a prime mover increases the amount of electrical energy being produced by the generator being driven by the prime mover. Decreasing the energy flow-rate into a prime mover decreases the amount of electrical energy being produced by the generator being driven by the prime mover.

The basic formula, or equation, (in digital GE-design Mark* Speedtronic turbine control systems) for Droop speed control is:<pre>(Gain*(Speed Reference-Actual Speed))+Offset=Energy (Fuel) Flow-rate</pre>The Gain and Offset terms are fixed values (called Control <i>Constants</i>) meaning that during normal operation neither of them vary or change. They are adjustable but they are rarely, if ever, changed and should be done so ONLY by knowledgeable and experienced people who understand all the knock-on effects--and there are <i><b>many</i></b> (knock-on effects) in GE-design digital Mark* Speedtronic turbine control systems.

The term (Speed Reference-Actual Speed) has two variables each of which can, and do, change during synchronized operation: Speed Reference and Actual Speed. The term (Speed Reference-Actual Speed) is called the speed difference (because Actual Speed is subtracted from Speed Reference), or, the Speed Error. The energy flow-rate into a prime mover varies with changes in the Speed Error. Change the Speed Error, by changing either the Speed Reference or the Actual Speed, and the energy flow-rate into the prime mover will change which will change the electrical output of the generator being driven by the prime mover. Again, the Gain and Offset terms are fixed values and don't change during unit operation. (Sometimes the Speed Reference value is also called the Droop Speed Reference--because it's the Speed reference for the Droop speed control equation.)

When synchronized to a grid with a stable and constant frequency at nominal, the speed of all generators and their prime movers is also stable and constant at nominal. We will refer to stable and constant rated frequency of generators and prime movers as 100% frequency, which is equal 100% Actual Speed.

So, during normal operation on a grid with stable and fairly steady frequency at nominal the Actual Speed of the prime movers and generators synchronized to the grid is 100%--which means one of the two variables in the Speed Error is stable and constant at 100%: the variable Actual Speed. (Using percentages for both frequency and speed--which <b>are directly</b> related--instead of trying to relate speed (in RPM) and frequency (in Hertz) is much easier.)

During normal operation with Actual Speed stable and fairly steady at 100%, to change the energy flow-rate into a prime mover--and hence the electrical output of the generator driven by the prime mover--the Speed Reference has to change to change the Speed Error.

A prime mover governor with 4% Droop setpoint and operating on a grid with stable and constant frequency at nominal with a speed reference of 101% will result in a Speed Error of 1% (101%-100%) which is 25% of the Droop setpoint of 4%, which will result in an electrical power output of 25% of the rating of the prime mover. A heavy duty gas turbine prime mover operating as described above with a rating of 32 MW and a Droop setpoint of 4% will produce 8 MW when the Speed Reference is 101% when the grid frequency is 100%--meaning the Actual Speed of the gas turbine-generator is 100%.

Increasing the Speed Reference (when an operator clicks on RAISE SPEED/LOAD) from 101% to 101.5% while the grid frequency is fairly steady at nominal (Actual Speed 100%) will increases the load of the gas turbine-generator in this example to 12 MW. Increasing the Speed Reference to 104.0% will result in a Speed Error of 4% which will result in an electrical output of 32 MW.

Even though the operator is watching the MW meter when clicking on RAISE- or LOWER SPEED/LOAD, what is really happening is the Speed Reference (signal name TNR for a GE-design digital Mark* Speedtronic turbine control system) is increasing or decreasing, respectively. (The signal name for Actual Speed, in percent, is TNH.)

Let's presume the unit <b>IS NOT</b> being operated in Pre-Selected Load Control but "straight" Droop speed control mode (the operator is manually changing load as necessary using the RAISE- and LOWER SPEED/LOAD "switches") and the grid frequency is fairly steady at nominal and the Speed Reference is constant at 101.5% and the machine in this example is producing 12 MW. Suddenly the grid frequency drops by 0.5% to 99.5% (for a 50 Hz machine that would be a decrease to 49.75 Hz); this means the Actual Speed will decrease to 99.5%. The Speed Error will increase to 102% (101.5%-99.5%). This will increase the energy flow-rate into the prime mover which will increase the electrical output of the generator from 12 MW to 16 MW, because the Speed Error is 2% which is half of the Droop setpoint of 4%, which means the output will increase to 16 MW--half of rated gas turbine power output in this example.

This is exactly what's supposed to happen: Machines operating at Part Load when the grid frequency decreases <i><b>should increase their power output to help maintain grid stability.</i></b> And, when the grid frequency increases, machines operating at Part Load<i><b>should decrease their power output to help maintain grid stability.</i></b> Machines operating at Part Load <b>should be free</b> to change load to help maintain grid stability.</b> They <b>SHOULD NOT</b> maintain a constant power output during a grid frequency disturbance. If they do maintain a (relatively) constant power output, <b>they are <i>NOT</i> helping to maintain grid stability</b>, they are actually making the grid frequency disturbance worse.

[NOTE: This only happens for machines which are NOT already operating at rated power output (Base Load)--if they're already operating at rated power output (Base Load) when the grid frequency decreases their output can't increase any further. And, anything less than Base Load is referred to as Part Load.]

<b>Now for the important part of this response</b> (not that any of the above is not important to the following--it's all important) we'll talk about what happens when operators use Pre-Selected Load Control to change and "maintain" the load of a GE-design heavy duty gas turbine with a digital Mark* Speedtronic turbine control system. Pre-Selected Load Control modifies the Speed Reference based on another error--an error between the actual load and the Pre-Selected Load Control setpoint. It's not a "special case" of Droop speed control--it attempts to over-ride Droop speed control to make the actual load equal to the Pre-Selected Load Control setpoint.

When the operator inputs a Pre-Selected Load Control setpoint while Pre-Selected Load Control is active (or enters a setpoint and then activates Pre-Selected Load Control), the Mark* compares the actual load (signal name DW or DWATT) to the Pre-Selected Load Control setpoint and increases or decreases the Droop speed control Speed Reference to change the Speed Error to make the actual load equal to the Pre-Selected Load Control setpoint. <i><b>This works REALLY GREAT when the grid frequency (Actual Speed) is stable and constant at nominal (100%).</i></b>

However, when the grid frequency changes while the unit is being operated at Part Load in Droop speed control mode with Pre-Selected Load Control active and the grid frequency decreases, the Speedtronic will at first try to increase the electrical power output because the Speed Error increases because the Actual Speed decreased. BUT, the Speedtronic will sense the increase in load and will reduce the Speed Reference to try to make the actual load equal to the Pre-Selected Load Control setpoint. But the increased Speed Error due to the decreased frequency (Actual Speed) will try again to raise the load, but the Speedtronic will continue to try lower the Speed Reference to keep the actual load equal to the Pre-Selected Load Control setpoint. And on, and on, and on, and on, and on, .... as long as the grid frequency is less than 100%.

This results in hunting (oscillation; fluctuation; instability) of the energy (fuel) flow-rate into the gas turbine which means the electrical output of the generator will also hunt (oscillate; fluctuate; be unstable). This just further contributes to the grid frequency disturbance and causes further oscillations of the grid frequency in addition to the off-frequency operation.

So, using Pre-Selected Load Control to maintain a load setpoint during Part Load operation on GE-design heavy duty gas turbine-generators synchronized to grids subject to frequent grid frequency disturbances is not recommended and actually causes any grid frequency disturbances to be worsened because the units are not free to change load to try to help support grid stability. Actually, using Pre-Selected Load Control--except to make load changes but not to maintain load for longer than a couple of minutes at a time--is not recommended (by me, that is). It's a very poor way to operate GE-design heavy duty gas turbines with digital Mark* Speedtronic turbine control systems. VERY POOR.

[GE does have an option that can be purchased to fix this Pre-Selected Load control problem they created: it's called Primary Frequency Response. But, it's a purchased option. GE-design Mark* Speedtronic heavy duty gas turbine control systems with Primary Frequency Response can be more reliably operated on grids subject to frequent grid frequency disturbances. ANY GE-design heavy duty gas turbine which is operated with Pre-Selected Load Control should be upgraded to include Primary Frequency Response--because when a grid frequency disturbance occurs it will allow units operating at Part Load with Pre-Selected Load Control to respond as they should to help support grid stability. Even for extremely stable grids. And units with DLN-I combustors have even more issues which can cause instability during grid frequency disturbances--even with Primary Frequency Response, and regardless of whether they are being operated at Part Load with Pre-Selected Load control active.]

So, people are asking, how is a GE-design heavy duty gas turbine with a digital Mark* Speedtronic turbine control system supposed to be operated at Part Load if Pre-Selected Load Control isn't a good operating mode, or the control hasn't been modified to include Primary Frequency Response? Well, the Droop speed control equation provides the answer--when the grid frequency is stable, one just changes the Speed Reference until the load is at the desired value. As long as the Actual Speed is relatively constant and the Speed Reference remains constant, the Speed Error will remain constant--meaning the load will remain constant. It's as simple as that. Changing the Speed Reference by using RAISE-/LOWER SPEED LOAD "switches" while looking at the MW meter is the best way to operate the machine manually.

And when the unit load is stable--meaning the Speed Reference and the Actual Speeds are both stable--and the grid frequency does change, then the Actual Speed will change which will means the Speed Error will change and the unit will respond <b>as it should</b> to grid frequency changes. Which, by definition, means that if the grid frequency is unstable the Speed Error will be unstable and the unit load will also be unstable. Unit load can't--and shouldn't--be expected to be stable if grid frequency (Actual Speed) is not at rated. Load is not supposed to be stable and constant when the grid frequency isn't at rated and stable; that's not how machines operating at Part Load are supposed to operate--they are supposed to change load when grid frequency changes. And not just GE-design heavy duty gas turbines, all machines operating at less than rated load with Droop speed control. And if grid frequency is unstable, then load should be unstable. Because the Speed Error is unstable. Plain and simple.

If you've read this far, vinayak_paranjape, you should have a very good idea what probably happened in your case. Operating with Pre-Selected Load Control while synchronized to a grid that is experiencing a grid frequency disturbance <b>IS NOT</b> recommended. And, the load <b>SHOULD</b> be free to change with grid frequency to help support grid stability. If the load is constant when the grid frequency changes then the grid frequency problem is only being worsened. If the unit is being operated at Part Load with Pre-Selected Load Control active while the grid frequency is unstable, the gas turbine output will also be unstable but will by trying to maintain the actual load equal to the Pre-Selected Load Control setpoint instead of changing in relation to the grid frequency change(s). This is not what should be happening. If the grid frequency is unstable--the gas turbine power output should be unstable. Even if it's not "pretty."

Even when you "switched to part load" (which means an operator canceled Pre-Selected Load Control by clicking on RAISE- or LOWER SPEED/LOAD, or clicked on STOP then START) the hunting/oscillation of speed and load will continue <b>as long a grid frequency is unstable.</b> It's how Droop speed control works when the grid frequency is not stable--and how it's supposed to work. It's not a fault of failure of the control system; it's a fault or failure of perception about how the control system works or should work.

Even if the grid frequency is oscillating, the gas turbine power output should be oscillating (increasing when frequency is less than rated, and decreasing when frequency is more than rated)--not trying to maintain the Pre-Selected Load Control setpoint. Droop speed control will vary load as Actual Speed varies during a grid frequency disturbance--that's what it's SUPPOSED to do. Whether one believes load should remain constant or not--that's how Droop speed control works during a grid frequency disturbance. And the above is how Pre-Selected Load Control works during a grid frequency disturbance (when it's not also equipped with Primary Frequency Response).

If the grid frequency is less than rated but stable, the gas turbine power output should increase and be stable at the higher power output. If the grid frequency is more than rated but stable the gas turbine power output should decrease and be stable at the lower power output. But, without the Primary Frequency Response option, Pre-Selected Load control will make the power output unstable even when the grid frequency is off-rated and unstable. Imagine what happens when the grid frequency is oscillating above and below rated, or is less than rated and unstable. Or more than rated and unstable. Pre-Selected Load Control (without the Primary Frequency Response option) will make the gas turbine output even more unstable while trying to maintain actual load equal to the Pre-Selected Load Control setpoint. It can get really ugly, really fast.

And, a measly GE-design Frame 6 heavy duty gas turbine can't change the grid frequency of a grid with tens or hundreds or even thousands of generators synchronized together. It just can't--and should not be expected to. Magnetism is going to make it's frequency change with grid frequency, and the governor should be free to change load as frequency changes. EXCEPT FOR EXTREMELY UNUSUAL CIRCUMSTANCES (which haven't been detailed by the original poster in this thread), no single generator can operate at any speed other than the speed proportional to (related to) the grid frequency while synchronized to a grid. It just can't happen (except under extremely unusual circumstances).

Full stop.

Period.

Those are the facts.

Like them or not.

<b>Now for the sobering truths.

<i>Perception is not reality.</i></b>

And operating prime movers and generators ain't a dramatic- or comedy television show where the perception of the writer(s) can be made to seem like reality.

This is the real world--not even a reality TV show (which can be "produced" (manipulated)). Control principles and philosophies are real and not fuzzy and not subject to perception, no matter how widespread the perception--or misunderstanding--is.

Full stop.

Period.

Now, vinayak_paranjape, you've confused things considerably more by talking about islanded operation, and then saying another generator was synchronized--both of which caused the instability to cease. This is the problem I have with queries like this--especially when the problem details change. <i><b>Changing "details" only serves to confuse people trying to follow and understand these threads</i>.</b> Usually, the questioner is trying to obtain justification for his/her preformed perception of what caused the unstable operation. And, they're also usually trying to blame the prime mover governor for all the problems--based on preformed perceptions. And, because the whole truth is complicated and difficult to explain and understand, the people asked to "help" (really, to provide justification for preformed perceptions) get labeled as geeks, and worse.

Droop speed control is not that difficult to understand or explain. It's what happens when Pre-Selected Load Control is being used during grid frequency disturbances that's hard to explain and difficult to understand. Read the above, re-read it. Go do something else for the rest of the day, then re-read it again tomorrow. Print a copy. Highlight sentences and paragraphs. Print several copies; highlight and make notes on them as you study and start to understand, until it's clear--but don't express doubts about physical principles and control concepts. Study and ponder and work it through until it's clear.

These are the facts, not subject to perceptions.

And, as for why the unit didn't trip on reverse power when the load went as low as -20 MW--well, that's part of the difficulty of trying to answer questions like this. Because the reverse power relay should have opened the generator breaker.... But, apparently it did not--for reasons we will probably never understand. <b>AND,</b> the frequency was "...fairly stable..." which is also very odd and unusual. Because turbine speed--when synchronized to a grid with lots of other prime movers and generators--can't be more or less than the speed related to grid frequency which means the turbine speed was also "...fairly stable..." <b>BUT</b> it wasn't.... Unless, the "grid" was actually pretty small (just a few prime movers and generators).

Again, questions like this are usually about obtaining justification for preformed perceptions. And it usually results in the person being asked to provide the justification for the preformed perceptions being labeled as 'not really the expert he was supposed to be,' or just another technical geek, or worse. Usually, reputations suffer--because of poor, ill, preformed perceptions. And the real cause for events such as this one are never understood, nor corrective actions taken. The turbine control system always gets the blame--always. Never the operations "procedures" or methods. Just because Pre-Selected Load Control is "easy" to use doesn't mean it should be used continuously during Part Load operation. But, trying to convince people not to use Pre-Selected Load Control is futile (for me), so I've given up. I just present the facts, and get labeled as a technical geek with no <b>real</b> answers to <b>perceived</b> problems. (But, I'm not bitter about it....)

If you want real help, provide real operating data--not changing versions and preformed perceptions of what did or might have happened. We don't deal in perceptions, or respond to doubts. And sometimes, it's just not possible to get help in a forum like this--someone needs to go to site and review actionable data and talk to several people, sometimes even grid regulators, to get a clear understanding of what happened--and why.

As an aside for those GE-design heavy duty gas turbines being "automatically controlled" by an analog load setpoint signal from a DCS or other control system/scheme, they will operate just as if Pre-Selected Load Control was active during a frequency disturbance--meaning they will try to maintain the load setpoint instead by changing Speed Reference to keep the actual load equal to the load setpoint. In case of a grid frequency deviation external/"automatic" load control should be disabled--<b>unless</b> the load signal is coming from a grid regulator (sometimes called "AGC" (Automatic Generation Control)) in which case the grid regulator is directly using the machine to help maintain grid stability. There are even crude external controls system that monitor load and send discrete RAISE/LOWER SPEED/LOAD signals to the turbine control system to make the actual load equal to the load reference in the external control system--and they will cause the digital GE Mark* Speedtronic turbine control system to act just like Pre-Selected Load Control was active during a grid frequency disturbance.

All attempts were made to correct any technical, grammatical, spelling or typographical errors prior to posting this response--but, proofreading isn't my strong point. (There were a couple of errors in my previous long response for which I apologize; hopefully people can spot them and understand.) Any errors are mine, and are difficult to correct once "Post" is clicked on. Patience is appreciated, and any noted errors will be clarified--but not if expressed as "doubts." There should be doubt about the physical principles and control philosophies presented above, but due to my errors there may be some clarification(s) required.

Hope this helps!

 

I missed a couple of good opportunities to provide some more clarification on a couple of issues.

The original poster mentioned the grid frequency was "fairly stable" during the MW hunting, but then also says the Actual turbine Speed (TNH varied between 99- & 101%). For a 50 Hz grid, 99% frequency is 49.5Hz, and 101% frequency is 100.5 Hz. To most people, that's not very stable. It's more than the few hundredths or one-tenth of a Hz most grids (infinite grids) experience even when large generators trip suddenly, or large amounts of load suddenly are separated from the grid. Again, though, everything is relative; right?

Next, the Primary Frequency Response purchased option being offered by the control system OEM is actually being required in some parts of the world--precisely because it allows synchronous generator output to change as frequency changes which actually supports grid stability, and DOES NOT maintain constant load during grid frequency changes which actually can make them worse (the grid frequency disturbances, that is). So, it allows Pre-Selected Load Control to be active at all times while the synchronous generator is synchronized to the grid, and it allows the unit to respond <b><i>appropriately</b></i> to grid frequency changes when they do occur. It's not perfect, but it's the best thing being offered to allow Pre-Selected Load Control to be used at all times--which is actually being forbidden in some parts of the world. (Isn't the world a wonderful place, and aren't "standards" great, especially when there are so many of them to choose from?)

Finally, grid frequency disturbances are most generally the result of one or two scenarios:

-- A large generator, or a number of generators, are suddenly separated (tripped, usually) from the grid while the amount of load (the number of motors, televisions, lights, computers and computer monitors) remains fixed; this is known as an excess of load for the currently available amount of generation, or a deficiency of generation for the current amount of load (the same thing said two different ways)

OR

--A large load or block of load (a significant manufacturing or production or pumping facility, etc.) trips off line, or a neighborhood or part of a town or city suddenly trips off line; this reduces the amount of load versus the current amount of generation, or the amount of generation is more than the amount of load currently on the system

When either of these things happens the grid frequency usually changes by some amount and remains stable at that off-frequency operatiing value until load is reduced or more generation is added (in the first case) or the amount of generation for the load is reduced or the disconnected load(s) can be reconnected to the grid (in the second case).

But, in the interim if the generator prime movers operating at Part Load that are synchronized to the grid respond stably by increasing or decreasing their output to match the change in frequency then the grid frequency will be stable even at the off-frequency value--which is what grid regulators and Customers want. Even if the grid frequency is lower- or higher than nominal, if it's stable it's easier to respond.

However, if the way the units are being operated causes the generator outputs to hunt/oscillate/fluctuate instead of changing to a stable point, well, that just makes the frequency excursion worse. So, that's how Pre-Selected Load Control (without Primary Frequency Response) makes grid frequency disturbances worse. It's very hard to synchronize additional generation to a fluctuating grid.... Not impossible, but hard. So, if load can't be reduced when grid frequency is less than rated and it's necessary to synchronize more generators to the grid if the grid frequency is unstable that can make adding generation to the grid very difficult.

And, it's not just GE-design heavy duty gas turbines that operate with Pre-Selected Load Control that cause the disturbances to be worsened--a LOT of other prime mover governors have similar modes of operation where load control modifies the Droop speed control function inappropriately. So, just one OEM isn't to blame--but since that is probably what we're discussing here (a GE Mark* Speedtronic turbine control system being operated with Pre-Selected Load Control active at all times during Part Load operation--but the original poster hasn't really told us...) that's the example for this thread.

I hope the concept of Droop speed control is becoming easier to understand. It's very simple--when the Speed Error changes the energy flow-rate into the prime mover will change, which will change the power output of the synchronous generator. And, instead of one variable which can affect the Speed Error, there are two: Speed Reference and Actual Speed. For most times in most parts of the world, the grid frequency is stable, which means the Actual Speed is stable, which means to change generator load one just needs to change the Speed Reference. And, because most machines operate at stable loads, that means that when Speed Reference is also stable and only changes to change load. So, when load is stable both Speed Reference and Actual Speed are stable.

And, when grid frequency does change Actual Speed changes and Speed Reference remains constant power output is SUPPOSED to change--if power output doesn't change when Actual Speed changes, or if power output is unstable when Actual Speed changes, then the grid frequency disturbances (excursions) can be worsened.

But, maintaining the same power output during a grid frequency disturbance as when it started is NOT what's supposed to happen. No matter if that "seems" like what should happen--it's NOT what's supposed to happen. And, if it does happen--or, worse, if power output is "artificially" unstable because of the oscillations/hunting/fluctuations caused by Pre-Selected Load Control, well, then the problem is just made worse.

Hope this is all clearer now. Study it in small pieces; then start putting them all together until it becomes clear. It isn't that hard to understand--or fix (by not using Pre-Selected Load Control ALL the time when operating in Part Load, or by purchasing Primary Frequency Response).

 

Vinayak...

returning to your original query related to "MW Hunting"... what has transpired since 7-Nov?

Phil Corso

 

Dear Phil

We are trying to find out what caused the turbine rpm (TNH 99 to 101) to vary when grid was quite stable (~50 Hz). We had seen load hunting in the past but this time with load hunting we had seen speed variation and that is our main concern. As of now we have some clues but there are number of loose ends. I will update once we closed the findings.

Currently we have kept unit standby.

Thanks Dear CSA for spending valuable time for explaining various aspects. These posts are really helpful in understanding the concepts further.

 

Dear vinayak_paranjape,

In your original post you had mentioned: "...Another interesting thing was that grid frequency was fairly steady but GT speed was showing variation from 99 to 102 %. This speed variation was physically seen on field also."

99% TNH is 99% frequency, and for a 50 Hz machine that's 49.5 Hz.

102% TNH is 102% frequency, and for a 50 Hz machine that's 51.0 Hz.

In a later post you wrote: ".... our turbine was rotating with high and low speed (TNH 99 to 101) compared to grid frequency (~50 Hz) and both max and min was for 1 or 2 seconds."

101% TNH is 101% frequency, and for a 50 Hz machine that's 50.5 Hz.

If you consider 49.5 Hz-50.5 Hz as ~50 Hz, that's your prerogative.

You had mentioned: "...Eventually hunting was stopped only once we were islanded with the grid."

Do you mean the turbine and some load (some kind of plant or facility) were both separated from the grid and operating independently of the grid?

If so, did the turbine control system switch from Droop speed control to Isochronous speed control--either manually or automatically?

In another reply you had mentioned: "...This event was going on for nearly 1 hr, which was terminated only after we started one more machine in parallel."

Again, changing details and a suspected incorrect usage of terms ("islanded" and "parallel") without any more information on either makes replying very difficult.

You also wrote: "Finding the cause for hunting is irrelevant but by this post, I expect discussions by experts and to explore how it can be happened, rather than debating that it is not possible." About the only way it can happen is if the grid where your plant is located is a "soft" region of the grid, and then sometimes small speed variations on the order of split-seconds (less than one second) can occur, usually also combined with voltage variations (deviations)--which have NOT been mentioned in this discussion. If there were other problems on the grid (substations/transformers/transmission lines tripped or overloaded; breaker "pumping"; etc.) that you (and we) don't know about, then, again, small very short changes in speed are possible.

But, think again about the tremendous forces at work inside the synchronous generator keeping the generator rotor locked into synchronism with the apparently rotating magnetic field resulting from the AC current flowing in the stator (armature) windings (whether that power be positive or reverse (negative)). If the North-South pole attractions between the rotor- and stator magnetic fields "break" then the torque of the prime mover will suddenly turn the rotor <b>EXTREMELY</b> quickly bringing the South pole of the rotor in line with the South pole of the stator--and the North pole of the rotor in line with the North pole of the stator. As the two like poles approach each other there will be GREAT forces developing to repel them causing the generator rotor to slow very quickly--and if the turbine torque and angular rotation of the generator rotor is strong enough cause the like pole pairs to "pass" each other then there will still be a repulsive force "pushing" the generator rotor faster again to move the like pole pairs away from each other.

BUT THEN the opposite pole pairs come into alignment and the generator rotor then starts to slow again as the forces of attraction try to "grab" and "hold" the generator rotor.

All of this is happening VERY FAST, and the sudden acceleration/de-acceleration/acceleration occurs in less than one revolution (of a turbine rotating at approximately 5100 RPM and a generator rotating at approximately 300 RPM with fixed couplings and a gear box between them) is VERY DESTRUCTIVE to the coupling between the prime mover and the generator--and the Load (Reduction) Gear of a GE-design Frame 6B heavy duty gas turbine-generator. The phenomenon is called "slipping a pole" and the resulting damage can be catastrophic to the equipment. When "pole slippage" does occur it usually doesn't come and go and come and go--but, again, in some very unusual and extreme grid disturbances it has happened. But, there's no indication from the information provided that there were very unusual and extreme grid disturbances--except the -20 MW-40 MW load swings which apparently happened SO quickly that the reverse power relay did not detect and trip the unit.

<i><b>Based on the information provided,</i></b> it's not possible. for turbine-generator speed--when synchronized to "fairly stable" grid--to vary from synchronous speed (the speed proportional to the frequency of the grid with which the generator is synchronized). If there are more details and information about which we are unaware (such as islanded operation, or starting and paralleling/synchronization of another unit to the grid along with the unit experiencing problems, the details of the "tie" between the two units (are there any main step-up transformers between the two turbines or are they paralleled to a common bus which then is connected to a transformer then connected to the grid, generator terminal voltage information (was it stable, or was it fluctuating--and if it was fluctuating, by how much--specifically), etc., then we might be able to provide more help. But, with the sketchy and incomplete information provided there's not much more we can do to help.

Finally, do you have any archived (electronic) data you are using or can use to analyze the event? If so, what is the resolution of the data--that is, is it once-per-second (1 Hz) data, or faster, or slower? Are you simply relying on operator recollections and recall?

 

I have experienced a non-GE large steam turbine hunting on grid. It was a serious thing that scared shit out of all there. 500MW unit was swinging more than 150MW at aprox. 0.5HZ.

It was a set of circumstances that made it possible. However, at the bottom it was a MW drop design that GE is using as well. With such a design ones unit is synchronized there is a MW closed loop effectively in place. As any other closed loop that one can go unstable as well.

In case of GE gas turbines it shouldn't be happening if all is reasonable OK. So I would go through the unit software, valves, fuel etc. to find what went wrong there!

 

Vinayak,

Reading your posts, your generator should had experienced high currents up and down during this event. I would assumed you don't have pole slip protection or it was blocked. how big is the grid where this generator is connected? for this mode of control you were in closed loop with a MW transducer, how many transducers are you using?

 

Vinayak,

During this event, was PSS on?

 

Don't remember all the details. It happened some years back. We stopped the unit after a few swings only. The customer asked for the unit droop to go from 5% to 10%. Normally a higher droop would mean a lesser chance for any instability however, in our case it was the trigger.

Studied the whole system afterwards and find the cause in MW droop design plus a series of unfavorable circumstances ("bad luck") as too sharp speed loop tuning and others that you normally don't expect with GE units ran by some Speedtronic. My post was to give an example of unit hunting while synchronized on a strong and steady grid. However, if the grid is not such as in quite a few places in Asia and Africa, running preselected MW would not be be a default. It can still work but need to look into the tuning and other things.