Dear,

The company I work for, we have 03 frame 7EA gas turbines and a steam turbine. Gas turbines operate with Mark V. Our system is connected to the National Interconnected System and operate in Droop mode, usually at part load.

Recently had an oscillation frequency due to a concussion occurred in the National Interconnected System. Our turbines were operating at partial load and the selected pre activated. Despite the pre selected to be activated, the power of the turbine varied. With this variation turbine exhaust pressure reached high exhaustion and off automatically.

Until then, I thought that when the turbine was in " Pre Selected" the power would not vary when an oscillation occurred in the national power system. I searched a few posts on the subject, but was still not very clear "Pre Selected"

Could anyone help me understand how the operation works when the turbine is activated with the preselected in droop mode?

In a material that found " Constant Settable Droop Design Standard of GE " explains about Droop, however would like to know where I can find the information on these parameters in the logic of the turbine, for example, the CSP file? But what points?

 

Dear Abbernardo,

Pre-selected Load Control is a very poor mode to operate a GE-design heavy duty gas turbine in. The Speedtronic is still in Droop Speed Control and so when a frequency concussion occurs the first action the Speedtronic will take is to adjust the load in response to the frequency disturbance. Then Pre-Selected Load Control will sense the change in load and start counter-acting Droop Speed Control--which is exactly what should <b>NOT</b> happen as far as the grid is concerned. And the two (Pre-Selected Load Control and Droop Speed Control) fight each other as long as the frequency is not at nominal, which is also not good for the grid.

Has anyone at your plant ever manually loaded or unloaded a gas turbine to a desired load and then just watched to see if the turbine maintained load, or drifted away from the desired setpoint?

I'd even be willing to bet that while the turbine is running in Pre-Selected Load Control that the Speedtronic is constantly issuing raises and lowers and that the load is changing by at least 1MW more or less than the desired setpoint (because Pre-Selected Load Control was not properly tuned).

Some day soon grid regulators are going to wake up and make it "illegal" for gas turbines to operate in Pre-Selected Load Control because it causes turbines to respond <b>OPPOSITE</b> to how they <b>need</b> to respond during a frequency disturbance to help support and maintain grid frequency. I just hope it happens before a serious grid event occurs and a loss of life occurs because people aren't properly operating their power generation equipment--and the grid regulators are allowing them to do so.

Pre-Selected Load Control should only be used to change load, and only if trained operators can't do so manually. Once the desired load setpoint is reached the operator should then click on RAISE or LOWER to cancel Pre-Selected Load Control and then monitor load and--if necessary--correct load back to desired using manual RAISE or LOWER.

As long as grid frequency is stable when an operator "parks" a turbine at some load it will stay at that load all by itself--without activating Pre-Selected Control! AND, if grid frequency changes the turbine <b>MUST</b> be allowed to change load to help support grid stability. That's one of the most important aspects of Droop Speed Control--that prime movers (gas turbines in this case) do--and must--respond appropriately to grid frequency disturbances to help support grid stability. I dare you to ask your National Interconnected System operators if they want your units to maintain stable load during a grid frequency disturbance. I'll bet cold, hard cash they will emphatically say, "No!"

If you want to tackle Constant-Settable Droop, you're on your own. The "best" description is in the Control Specification provided with the turbines (Sect. 03, Speed Control). It has all the relevant CDB signal names and some verbage that will likely cause more questions than it will answer. Constant-Settable Droop is a fancy way of integrating load into Droop Speed Control, but it was developed primarily for fuels that didn't have similar hearing values and was later used to reduce load swings during DLN combustion mode transfers. Good luck with your research on this topic.

Lastly, don't believe everything you're told about how GE-design heavy duty gas turbines operate, and don't make assumptions based on function names, either. There are a lot of myths and falsehoods and lies out there about GE-design heavy duty gas turbines and how they operate.

Hope this helps!

 

Dear CSA,

What you said about Pre-select load is true also for external load set-point also. the only difference being that the command is coming from another control system other than Mark 5. But, what I want to ask is if one receives schedule from grid for only part load operation, what other choice do we have, even though it is not supporting the grid?

 

K.R.Manish,

If you receive a dispatch to operate at, say 25 MW on a 40 MW machine, you can use Pre-Selected Load to load (or unload) the unit to 25 MW and then simply click on RAISE- or LOWER SPEED/LOAD one time to cancel Pre-Selected Load. That's all need be done. The turbine speed reference will not be changing when Pre-Selected Load is deactivated.

For a properly configured Speedtronic turbine control panel 25 MW out of 40 MW is equal to (25/40) 0.625 of rated load. For a properly configured Speedtronic turbine control system with 4% droop that translates into a TNR (Turbine Speed Reference) of (0.625 * 4) 2.5 (plus 100), or 102.5%.

Droop Speed Control looks at the difference between the turbine speed reference (TNR) and the actual turbine speed (TNH) and adjust the fuel accordingly.

When load is stable at 25 MW the TNR will be stable at 102.5% and as long as the grid frequency is stable the actual turbine speed will be stable--so the fuel won't change.

And if the fuel doesn't change, the load doesn't change.

It's as simple as that.

Or, one can just use the RAISE- & LOWER SPEED/LOAD targets to get the load to 25 MW. TNR won't change, so load will be stable. As long as grid frequency is stable.

And if grid frequency is not stable, then generators and their prime movers are <b>SUPPOSED</b> to change load. Again, ask any knowledgeable grid supervisor if they want units to remain at constant load when the grid frequency is unstable. For all but extremely unusual circumstances the answer will be, <b>"NO!!!"</b>

But most operators and their supervisors will <b>NEVER</b> operate in Part Load without Pre-Selected Load. Why? "Because that's they way we've always operated!" Which translates to, "I don't understand how the turbine control system operates, and I'm afraid to try anything which might trip the turbine and result in losing my job. So, take your foolish idea and go away and let me read my newspaper in peace without fear of losing my job!"

Pre-Selected Load Control, and to your point, External Load Control, changes TNR in proportion to the difference between the load setpoint and the actual load. This is great where the grid frequency is stable, and not great where it's not stable. And will be potentially disastrous on a stable grid if there is a frequency disturbance.

GE is actually getting sites to pay for a fix for this problem, called Primary Frequency Response. A problem their load control schemes cause.

Anyway, if you are successful in operating at Part Load without Pre-Selected Load Control enabled, it would be great to hear the results of your operation. Specifically, does the load drift or is it stable? (Presuming stable grid frequency, of course.)

 

I appreciate the quick turnaround and help others! I was hoping it was you that answered the question. I had already read your response on the same day that he replied, however I get more information as you recommended. I have read various documents and posts written by you, but still doubt occurred to me, maybe my way of interpreting.

If we let loose loads, they usually keep the setpoint, but the fact that currently there is construction of transmission lines / substations and testing by the National System Operator, our load frequently varies from what was selected.

If I were to bet against you, I would lose. For even in Pre Selected Load Control loads oscillate approximately 1MW up / down. Due to the non-precision calculations.

As for challenge of asking the operators of the National System, did not think it would be a good idea, but I think you would win money.

About Constant Settable Droop, reading of documents (found in section 2), makes us doubt what was to be expected. While I understand the philosophy of this control, some particularities still make me scratch my head.
For example:
What does the DWDROOP?

Your explanation is great about Speed Droop!
So to say that when an oscillation frequency and the turbine occurs is with the Pre Selected enabled the turbine receives the speed variation and for a time helps the National System, but quickly the turbine already trying to get back to speed reference (TNR) as it is with the Pre Selected enabled.

Is there a specific time (minimum or maximum) for the turbine back to TNR, after it has oscillated by an external event (National System)? Remembering that she is with the Pre Selected enabled.

Where do I find the value of droop set to 4% or may be different in my turbine?

 

Abbernardo.

The work om the transmission system should not affect the load on the unit--unless the grid frequency is being affected. And I have a difficult time understanding how the grid operator would allow this to happen.

EVERY time I have revealed the name of the Control Constant GE uses to set droop it has come back to haunt me. There are too many people who don't understand Droop Speed Control and think that this or that <b>perceived</b> problem can be solved by changing the droop setpoint. And all they do is make a mess of the turbine operation--and blame it all on the evil Speedtronic turbine control system. While you may not change the droop setpoint at your site there will be at least ten people who will as a result of reading my reply, making it irresponsible of me to directly answer your question about how to check the droop setpoint. Sorry, but I must decline. (I even know GE field service personnel that have changed the droop setpoint only to find they have created a completely new problem or set of problems when there was no problem to begin with--except for the problem of perception.)

And as for Constant Settable Droop, all I will say is that the turbine speed reference is biased by load and that there is integral control action along with proportional control. Again, have a read of the Control Specification; it's all the documentation that exists--in public. (Or that I know of, anyway.)

The turbine loading and unloading rates are interlocked with the droop setpoint, so if one changes the droop setpoint for any reason (and there is almost NEVER a valid reason for doing so on a GE-design heavy duty gas turbine) without re-calculating the loading/unloading rates it is going to result in problems. And, contrary to popular belief, changing the droop setpoint is <b<not</b> the proper way to change loading or unloading rates. Unfortunately, GE has tied the two together.

If you want to know what the droop setpoint is for your turbine change TNR by 1% and note the change in load. If the load changes by 25% percent of rated, then the droop setpoint is 4%. If the load changes by 20% of rated then the droop setpoint is 5%. [<b>NOTE:</b> If the unit is capable of Peak Load, that is, if the nameplate has a Peak Load rating on it, then rated load is the Peak Load value.]


Droop Speed Control is about how much the fuel flow-rate will change for a change in the difference between THR and TNH. If TNH is stable (meaning grid frequency is stable) and TNR is stable, then fuel flow-rate will be stable and load will be stable. If TNR changes and TNH is stable, then fuel flow-rate and load will change--in proportion the change in TNR versus TNH. If TNR is stable and TNH changes, such as when grid frequency changes, then fuel flow-rate and load will change.

When Pre-Selected Load Control is enabled and active then Pre-Selected Load Control will change TNR when load changes. As long as grid frequency is stable (and if Pre-Selected Load Control is properly tuned) then load will be stable because Pre-Selected Load Control will not be trying to change TNR.

When grid frequency changes the difference between TNR and TNH changes immediately--and it's one of the important functions of droop speed control to immediately change load in response to the grid frequency change. If grid frequency decreases, the error between TNR and TNH will increase and load SHOULD--and will--increase. However, Pre-Selected Load Control will sense the change in load and will immediately change TNR to try to reduce the error between TNR and TNH to reduce load. Which will increase the error between TNR and TNH and so on, in an endless (vicious) circle--which is NOT good for the grid stability.

Pre-Selected Load Control (and External Load Control) both act to change TNR when load changes due to grid frequency disturbances--but in the OPPOSITE direction of what should be happening when grid frequency is abnormal.

With proportional control, there is no lag; when the error increases or decreases the action is immediate--in the case of GE-design heavy duty gas turbines that means when the error between TNR and TNH changes <b>for ANY reason</b> the fuel flow-rate will change immediately. That's one of the very important aspects of Droop Speed Control. [NOTE: This does <b>NOT</b> happen when the unit is on exhaust temperature control--Base Load or Peak Load--only when it's operating at Part Load.]

The aspect of Droop Speed Control that helps to support grid stability needs to be immediate, and the proportional action of droop speed control is what does that. It's strictly related to the error between TNR and TNH. The basic formula is:

FSRN = [FSKRN2 * (TNR - TNH)] + FSKRN1 (This is the formula for NON-Constant Settable Droop, but is extremely similar to the formula for Constant Settable Droop.)

If you look very closely at the formula it is:

y = mx + b OR f(x)= mx + b

where (TNR - TNH) is the variable, "x". Only in this case, the variable is <b>two</b> variables: TNR and TNH. For most grids with stable frequency TNH doesn't change, so the only variable is TNR. But, when the unit is operating at a steady load and the grid frequency (TNH) changes then the Speedtronic immediately changes fuel in proportion to the change in the error between TNR and TNH.

Look, if the grid operator calls and says, "Maintain 25 MW" that means "As long as the grid frequency is stable, maintain 25 MW--but when the grid frequency is unstable, by all means, HELP US OUT!" And, if you're operating at 25 MW on Pre-Selected Load Control and the grid frequency is not normal then the turbine is NOT helping to support grid stability--it's doing quite the opposite, in fact.

Pre-Selected Load Control is useful for changing load (by lazy operators, because operators can click on RAISE- or LOWER SPEED/LOAD to change load to get within 1 MW of the setpoint). But, once the turbine is at the desired load, then Pre-Selected Load should be disabled so that if the grid frequency changes the turbine will contribute to supporting grid stability.

I hope this helps. An "order" to maintain a particular load is really only a valid order <b>when the grid frequency is stable.</b> When the grid frequency is not at rated, then any unit (gas turbine-generator; steam turbine-generator; hydro turbine-generator; reciprocating engine-driven generator) is <b>supposed</b> to contribute to grid stability by responding in a known manner--and droop speed control is that manner. All over the world. Everywhere. Period. Full stop. If something over-rides droop speed control (like Pre-Selected Load Control or even External Load Control), then the turbine is not doing its part--as expected--to help stabilize the grid.

Period. Full stop.

Again, if you want to know how much droop your turbine is programmed for, record TNR at some load and also record the load. Change TNR by 1% (up or down--using the RAISE- or LOWER SPEED/LOAD targets) and then record the load. Compare the change in load to the rated load (Base or Peak, as noted above). If the load changes by 25% of rated, the droop is 4%. If the load changes by 20% of rated, the droop is 5%. (This is not meant to be exactly 20.00% or 25.000%; but it should be within a couple of tenths one way or the other.) Droop Speed Control is primarily about how much the load will change for a change in the error between the reference and the actual. When the actual speed is stable (as it should be on any AC power system) changing the speed reference by a known amount should result in a proportional change in load. And it's this proportional change in load that will help to support grid stability when the grid frequency is not normal.

I sincerely hope this helps, because I don't know how to explain it any better.

 

As usual CSA well explained the basics.

Thank you

take care
G.Rajesh

 

Abbernardo and CSA, I would like to make a comment just to make sure I am understanding the situation and just maybe help others.

Abbernardo you say your machine was operating in preselected load mode at some part load amount. Meaning you had a preselected load setpoint active and that load was something less than full load or temperature control. You say that something happened on the grid that caused frequency to change from normal. This change in frequency caused the output of the turbine to change, and the machine tripped on what I understand was high exhaust back pressure.

My interpretation of what happened is your units were operating at part load, can you tell us what your megawatt setpoint was? My assumption is that grid frequency fell below normal. This reduction in grid frequency caused an error between the speed reference(TNR) of the turbine and the actual speed(TNH). The reaction of the control system operating in droop mode is to increase fuel, very fast, to reduce the error.

As CSA explains though, with the machine operating in preselected load, the control system will then attempt to reduce megawatt output by reducing the TNR setpoint. But my understanding is that this change rate is much much slower than the rate of change of the droop calculation. While not optimal this is what will happen.

I am curious in your case though of what exactly happened. Assuming grid frequency fell, the droop calculation will increase fuel to reduce the speed error. The increase in fuel will increase megawatt load output. The unit should raise load until either grid frequency recovers or the unit hits temperature control. In your case it sounds like you may have some issue with exhaust duct pressure?

I tend to over simplify my thinking. But it sounds like the turbine did what it needed to do. The question is why did you trip on exhaust duct pressure?

If you are trying to run your machine at some load setpoint and you don't want it to change load if grid frequency deviates from normal, then I don't think that's possible. That is the whole idea of droop control.

CSA, please tell me if I am wrong!

 

MIKEVI,

Yes, there is some time delay between when Pre-Selected Load Control (or External Load Control) would change TNR as load changed in response to a frequency disturbance. That's because TNR is ramped up and down at the selected ramp rate for the chosen operating mode (in this case, it's usually the Auto load/unload rate, but it could be different depending on the sequencing/logic/application code running in the Speedtronic).

It's difficult to understand why the turbine would trip on high exhaust pressure--it's more likely it initially tripped on high exhaust temperature. (GE has the extremely annoying practice of not blocking subsequent trips after the initial trip has occurred, and most sites don't properly read Alarm Logs to determine which trip occurred first, they just assume the trip at the "top" of the list is the condition that tripped the turbine--which is NOT usually true if there is more than one trip annunciated. GE really needs to change this practice.)

You are correct, MIKEVI--the Droop Speed Control did what it's supposed to do. The perception that when Pre-Selected Load Control is active that load will not/should not change is incorrect. Again, as long as grid frequency is stable load will not change very much (and if it does oscillate periodically (at the same period/frequency) above and below the Pre-Selected Load Control setpoint that's almost always the result of incorrect tuning of Pre-Selected Load Control. In my humble opinion, Pre-Selected Load Control is useless, because when TNR is stable and not changing and grid frequency (TNH) is stable and not changing then load will be stable will not change. Why does one even need Pre-Selected Load Control? Especially when, if it's not tuned correctly, it will cause the load to oscillate about the setpoint! It's really more trouble than it's worth, especially when one considers that because of the lack of documentation that causes misperceptions that all manner of problems can result.

The key to remember here is that there is a caveat to the order/dispatch/request to operate the unit at some part load condition: That the grid frequency will remain stable during the time the order/dispatch/request is active. AC power systems depend on the Droop Speed Control action of prime movers operating at Part Load to help stabilize grids during frequency excursions--which are caused by overloading of the grid (usually caused by loss of generation or separation of generation), or excessive generation (usually caused by loss of load).

Again, ask any grid operator/regulator/supervisor if they want a turbine operating at Part Load to remain at constant load during a frequency excursion and I'm fairly confident they will answer, "No." And perhaps, very emphatically, with some expletives thrown in for clarity.

 

Dear CSA,

With reference to the FGMO mode which you have described, I agree with you that it is indeed the best mode of operation where grid frequency is stable. But this is not true everywhere in the world. For example, we sometimes have a frequency variation as large as 1 Hz [ie 2% rated speed] within a block [ie 15 minutes]. During a sudden load crash, as is the norm during thunderstorms, due to large scale tripping of overhead HT feeder lines, the frequency may shoot up to as large as 50.65 or may be even 51 Hz. If we try to operate in FGMO as you described, in such an event the gas turbines would get unloaded to around 50%. In such as case, we would not be able to get sufficient main steam temperature for our steam turbine from our heat recovery steam generators [We have a combined cycle power plant with 2 gas turbines having 2 heat recovery steam generators which generate steam for driving a steam turbine]. Consequently, the steam turbine would trip on wet steam / low main steam temperature protection.

 

K.R. Manish,

What is FGMO, please?

This is a good discussion, and as such, I hope you continue it by contributing your responses to the questions below.

Every power plant synchronized to a grid with other power plants, regardless of who owns the power plant or for what purpose the power plant was intended for, has a responsibility to operate in a manner that is conducive to maintaining grid stability. That goes for co-generation power plants (where steam is the primary product and electricity is the by-product), combined-cycle power plants, and IPPs (Independent Power Producers)--as well as power plants owned and operated by a utility and/or the grid. This is the way AC power grids are to be operated, the way they must be operated in order to achieve the most stability and reliability.

If a power plant not associated with the utility/grid but that is selling power to the utility/grid then it is likely doing so under a contract it has with the utility/grid. And it's highly likely that the contract states the power plant is to be operated in Droop Speed Control mode when at Part Load which at the very minimum implies the plant is supposed to contribute to grid stability when being operated at Part Load. The language of the contract when it comes to supporting grid stability may be even more specific, but the concept of Droop Speed Control is that it is the method by which multiple generators and their prime movers can stably supply power to a load that is larger than any single generator could supply by itself, and Droop Speed Control is also the method by which all generators and their prime movers work together to help support grid stability during frequency excursions caused by any number of conditions.

Ultimately grid operators have the responsibility for ensuring and maintaining grid stability and reliability--but they certainly can't do so if some or many of the plants connected to the grid aren't being operated in accordance with the way the grid operators believe the power plants are being operated or the way power plants are expected to be operated when synchronized to a grid with other power plants.

This is the way AC power systems have to be operated to ensure stability and reliability. It's one of the fundamentals of AC power systems. And every power plant synchronized to an AC power system (grid) with other power plants has to act in concert with other power plants--in a responsible manner--to help achieve and maintain stable and reliable grid frequency. The more power plants that don't do so the more unstable the grid is going to be and the worse the instability is going to be.

Again, this is fundamental to AC power systems and the way they work and the way that multiple generators and their prime movers have to be operated to ensure stable and reliable AC power production and transmission and distribution. Certainly, there are probably things which the grid operator (transmission and distribution) can do to help with not introducing and even reducing problems, but when power plants operate in a selfish manner that is opposite to the principles and fundamentals of parallel (synchronized) operation with other power plants.

I understand your dilemma, and sympathize. But, on the other hand, when a power plant is doing the exact opposite of what it should be doing during a grid frequency disturbance do you believe that power plant is operating as per contract with the grid with which is it connected? Is the plant operating in a manner which is conducive to maintaining grid stability? Would you want to be trying to synchronize your plant to the grid during such a frequency disturbance?

As a generator of electricity synchronized to a grid with other generators and their prime movers what do you believe is the responsibility of your plant to help maintain grid stability during disturbances? What about the responsibility of other plants to help maintain grid stability during frequency disturbances?

Do you, as a consumer of electricity at home, have to have power filters to protect your electronic devices (TV; computer and computer monitor; etc.) from grid frequency excursions? Does your plant have to have power filters for the electronic equipment at the plant to protect against grid frequency disturbances?

It's just not responsible, nor acceptable, to say, "We are exempt from the principles and rules," and expect the grid to be reliable and stable. As a consumer of electric power, is that acceptable to you?

Oh, if it were only possible for every power plant to operate independently of every other power plant on an AC grid--but it's not. And that has to be taken into consideration when operating a power plant connected to an AC grid in parallel (synchronized) with other generators and their prime movers.

I look forward to your responses, sir.

 

Dear CSA,

> What is FGMO, please?

FGMO is free governing mode of operation, which you had just before described in which the gas turbine would load or unload depending on the grid frequency.

I think you have misunderstood me. We do not operate in Preselect mode because we need a financial gain. Yes, it is true that when frequency drops our machines get unloaded. But if the grid operator feels that they need more MW, he tells us so & we raise the load. Once it reaches base load, we change the control mode to base.

Again, we always maintain close to a 100% actual generation to scheduled generation on a daily basis but it is true that we do not do it every single block [15 minutes]. This cannot be achieved even if operate in pure droop mode as you have beautifully described, due to the varying grid frequency. But definitely it would help stabilize the grid, but to what extent? How much frequency rise/drop will 2 or 3 MW cause in a grid of 100 GW capacity? And if in trying do this if your machine unloads & trips, what about the frequency drop due to 150 MW? Which would you give preference to?

Yes, we have synchronised our plant to the grid time & again during intervals of low frequency in the past, though not so much now [grid frequency has improved over the years]. Yes, I do have voltage stabilizers for electric home appliances. Yes, there are frequency disturbance recorders in plant. Yes, as a consumer it is acceptable to me to have power at say 49.5 Hz than to have a power outage. Yes, it can reduce the life of equipments, but at least one can use them. What is the use of having electrical equipments with long life, if one is not able to use them half the time due to lack of power.

While we do what we can to support the grid, we certainly would not risk a tripping, unless the grid explicitly asks us to step up the generation.

That being said, we do not always have this kind of problem. As you said, we will try operation in pure droop but for that we do need a schedule which is above the technical minimum for reliable operation. Otherwise, it would be like digging one's own grave.

 

K.R. Manish,

Thank you for the explanation. Abbreviations or acronyms are useful--once they are understood.

When the grid frequency drops, Droop Speed Control loads the turbine--because the error between the speed reference and the actual speed increases. The 2 or 3 MW from your plant alone (see below for an analysis of this claim) won't do much to help the "infinite" grid, but if lots of other prime movers are operating in Pre-Selected Load Control Mode (or something similar) or their Droop Speed Control is not tuned properly then the support the grid regulators are expecting from units operating in Droop Speed Control is not there--and that does make the problem worse.

And when the problem is worsened then the likelihood of tripping is also increased, which in turns makes the problem even more dire. Again, it's the way that AC grids are to be operated, with turbines in "FGMO" and able to change load when the grid frequency changes. And if those units don't respond in the desired manner, combined with the opposite action of Base Loaded units, then, well, a bad situation just gets worse.

I understand that makes it difficult for some plants to operate--and those plants, once they recognize the limitations--need to work with the grid regulators to devise a means of operating that is agreeable to both parties and which helps to support grid operation. With the increasing usage of gas turbines as prime movers in power plants--especially combined cycle power plants--the limitations of operation must be taken into account by all parties, owners/operators and grid regulators.

It puts many people--and many plants--in a difficult position. But, we're really talking about the common, greater good here, as well as basic physical principles. Again, if several, or, as seems to be the case the majority, of plants are only concerned about their plant and not about the grid with which they supplying power to then the whole thing will eventually just crumble. As I'm sure you're painfully aware.

49.5 Hz out of 50 Hz represents a 1% decrease in frequency. If my maths are correct, that corresponds to a 1% speed difference, which on a turbine with 4% droop corresponds to a 25% change in load, and on a turbine rated at 200+ MW, that corresponds to more than 50 MW. (You didn't say what size the turbines were at your plant; I'm presuming they are Frame 9FAs with an appropriately-sized steam turbine.) So, it's not just 2 or 3 MW for a drop to 49.5 Hz for a GE-design Frame 9FA heavy duty gas turbine. And 50 MW, while not a lot to a 100 GW grid, is still a lot of homes and businesses. If there are a lot of power plants which could provide 50, or 100, or 125 MW of increased generation but don't, that adds up fast, doesn't it? Especially when one considers that there are a lot of gas turbine-driven plants that were operating at Base Load which also decrease their power output when the frequency goes down.... It all adds, doesn't it?

Here's where the "C" word becomes very important: Communication. Grid operators need to understand how the plants connected to their grid operate. Owners/operators need to be able to operate their plants in an economic and reliable manner--while maintaining generation under most grid disturbances.

I am pretty certain that if the grid regulators could choose between maintaining a generation schedule at ALL times and during all grid frequency conditions, and having increased generation when the frequency goes down and decreased generation when frequency goes up--to support grid load during those times--they would choose deviating from schedule to support grid stability. Maybe that's just because I'm looking at the pure physics of the AC system, but I am genuinely, absolutely keen to know what their preference would be.

I want to go back to my bicycle analogy again, only this time I want to state the conditions as tens or hundreds of cyclists all pedaling bicycles with fixed gear ratios (they can be different, but they aren't variable) all "hitched" together to a very large wagon filled with goods which are to be moved at a constant rate (km/h, or mph) by the cyclists over a flat terrain. This means that all the cyclists are pedaling at rates that are fixed by the speed of the entire group. And, there are so many cyclists and the load is so large that if one cyclist isn't able to pedal any longer, or pedals harder than previously for, some reason the speed of the entire group (cyclists and load) doesn't change appreciably (sure; if the speedometer had enough precision (decimal places) we could see a change in speed, but for all intents an purposes the speed remains constant).

Now, let's say that most of the cyclists are pedaling as hard as they physically can while maintaining the desired speed. And a small majority of the cyclists are only pedaling at a portion of their ability but are still providing motive force to the load. But the cyclists and the load are all moving along at, basically, the desired speed.

All of a sudden, the chains of many bicycles all break for some odd reason. Some of these are on bicycles that were being pedaled at part ability; most of them, however were on bicycles that were being pedaled at full ability. The speed of the entire group (cyclists and load) would start to slow down. But, if the remaining cyclists that were only pedaling at part ability increased their torque output then the load would continue to move, but probably at a reduced speed--until someone directed multiple cyclists to further increase their output which would tend to help accelerate the group back to desired speed.

That's how droop speed control works--or at least how it's intended to work.

But, suppose, some or most of the cyclists pedaling at only part of their ability didn't increase their output when the speed decreased when the chain-breaking event occurred. What would happen to the speed of the group? It would start to decrease, and continue to decrease. What if some of those cyclists started to increase their output but then reduced it, and what if their output varied and wasn't constant during the chain-breaking event? The speed would drop, and continue to drop, and would even be erratic while dropping--until some cyclists (hopefully enough cyclists)--could be directed to increase their output to help stabilize and increase the speed.

Or, let's say some of the goods in the wagon were jettisoned to decrease the load until the available force from the cyclists was able to stabilize and increase the speed back to desired, at which time goods could be added back to the wagon and cyclists had repaired their chains (yes; while the group was moving...).

Now, if some of the cyclists pedaling at only part of their ability have developed asthma, or were dehydrated, or had muscle strains or just weren't capable of providing the motive force they were capable of or supposed to be able to provide, then, well, the speed of the group isn't going to be very stable or near rated during a frequency drop.

This is how droop speed control works--or is supposed to work. Without some prime movers and generators picking up load when the frequency goes down (or dropping load when frequency goes up) the frequency of the grid isn't going to stabilize, it's just going to continue to spiral down (or up).

I'm not criticizing or pointing fingers. I'm just asking if it's acceptable for some cyclists to not contribute as they could or should, or to even act in an opposite manner to the way they are expected to contribute to keep the speed of the group at desired. If you're a consumer and are expecting your goods to arrive at a certain time, is that acceptable? If you are the coordinator of the group of cyclists who have agreed to pedal bicycles in an orderly fashion and in an agreed-upon mode and you are paying for their services to deliver goods on time (at the desired speed between one point and another), is it acceptable for some of the cyclists to decide to change their mode which adversely affects the group and the speed and the delivery of goods? Sure, the goods will arrive, late, but is that acceptable in the long run?

How can the situation be improved? Does it take legal action--laws and governmental regulation and penalties, civil and/or criminal? Or, by working with the grid regulators to understand their requirements and having them understand your "requirements" (limitations)?

I do empathize with the plights of many power plants, but I feel that by educating and communicating (plant owners/operators, plant designers, and grid regulators) the problem can eventually be resolved. (Of course, when we get mass storage schemes which can instantly make up for lost generation this will all be moot.) But, in the interim, what should be done? How should power plants react?

I suggest that if more combined cycle power plants operating at Part Load under Droop Speed Control alone (FGMO) that the grid frequency problems would not be as severe as they currently are--and you say they are getting better. Is that because more generation is coming on line, or because the grid regulators can deal with system problems better? What do you think would happen if units operating at Part Load under Droop Speed Control (FGMO) were responding to grid frequency disturbances as they should--would the severity be better or worse? If it was better, would you need to necessarily try to maintain a constant load (read: exhaust temperature/exhaust flow) during a grid frequency excursion?

What about using auxiliary HRSG firing ("duct burners") during frequency disturbances to keep exhaust temperatures higher?

What would happen if the steam turbine automatically transferred to Inlet Pressure Control and tried to keep steam pressure, and to a certain extent steam temperature, higher?

I realize frequency excursions go both ways--high as well as low. So, if the steam turbine load dropped as the gas turbine load dropped during a high grid frequency event wouldn't that help to protect against carryover/low steam temperature?

So, aren't there things which can be done--using available technology--to better respond to grid frequency disturbances without the possibility of tripping the turbine(s)?

Isn't the real question: How do the grid regulators--or the people who buy your power and distribute it to others--want your unit to operate during a grid frequency disturbance? Are you <b>certain</b> the grid wants you to maintain a set load regardless of grid frequency unless they call to ask for a load change?

Or, is it just Fear of the Bean Counters that forces the operations supervisors/operators to keep load as per the schedule regardless of grid conditions.?.?.?