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Grid Frequency Instability & base load operations
Unit unable to maintain baseload control (droop) because of large grid swings (upto 51.8HZ on a nominal 50HZ grid system). Need a solution to keep unit stable when the grid frequency swings

Hi everyone,

Relatively new here and have had some really useful insights from a lot of guys here treating many posts since joining, though this is my own very first post (cries of help).

We operate a series of GE 9E in SC configuration, single fuel DLN-1 in Africa, supplying power to the grid. Problem is not being able to optimise the units (500MW combined plant capacity) due grid swings. Mostly have to go to pre-select load once the grid goes beyond certain frequency. Hopeless to say units rated at 126MW ISO being operated at pre-select loads of 70MW because of grid. Even if we produce our own fuel! What can be done to keep our units in baseload control even at relatively higher/lower grid frequencies? I have heard of "increasing the deadband", if anyone knows what this means. I will suppose this means incresing the droop deadband nominally set at between 49.5hz to 50.5hz to something wider?

If this is done, what will be the implication on the turbine and the generators?

Thanks

The droop curve is usually set at 4% (speed/load). Yours may be set too low even below 4%

Increase the droop above 4, Increase to 6, 8 or 10 and see what happens.

The response will be a lot less.

Hello Mashll,

First of all, I don't think that your turbine being operated at preselect 70MW load has anything to do with the software, nor can be solved modifying the software. If you have to operate it at such loads it has to be due to the fact that there is not enough demand in the grid.

Then, frequencies higher than 50Hz are normally due to few factors:

1. Sudden shutdown of big consumers

2. Bad grid regulation with individual power plants not participating (or not being able to participate) to frequency regulation

3. Bad "grid clock" - each grid has one or more generators that set the grid frequency.

If you have a normal 9E, your turbine is set to stay synchronized as long as the grid frequency is anywhere between 47.5 and 52.5%. Outside these values, your generator is no longer safely operated.

Now, when you say you have to go to preselect from Base Load when above certain frequency, you mean the machine is going automatically out of Base Load? I have to admit, I don't have too much experience with unstable grids. But I don't really see how this would happen automatically. I checked a Frame9e software and found nothing, but I might have missed something. I would rather expect that you are asked for lower loads by the grid operators instead of a result of the control system software (well... I am sure CSA will have something to say about this, something new to learn for me as well)

2 out of 2 members thought this post was helpful...

Mashll,

Your situation is "hopeless", per your description. The situation is this: As the grid frequency goes up and down, so will the speed of your turbines--because speed is directly proportional to frequency. There is no change that can be made to alter the direct relationship between speed and frequency. None. Full stop. Period.

As the speed of a single-shaft gas turbine increases and decreases, the air flow through the machine will change. As the frequency goes up, the speed will increase and the air flow will increase. And, if the unit is operating at Base Load, the power output will increase--because exhaust temperature control (i.e., Base Load) doesn't care about frequency, it just wants to make as much power as possible by keeping the exhaust temperature as high as possible for the ambient- and machine conditions. If the frequency goes down when the unit is operating at Base Load, then the air flow will decrease and the power output will go down. Again, Base Load says keep the exhaust temperature as high as possible for the current operating conditions, and when the air flow goes down then amount of fuel that can be burned goes down and that means the power decreases.

If you are operating at Part Load, say 70 MW to use your example, and you are NOT operating with Pre-Selected Load Control enabled and active then as grid frequency changes the load will change--per Droop Speed Control governing action. That's what's supposed to happen--because it's intended that units with reserve capacity (those NOT operating at full output) are supposed to change their load to try to help maintain grid frequency. If the frequency goes down, then load is supposed to increase. If the frequency goes up, then load is supposed to decrease. Droop speed control is designed and intended to support maintaining grid frequency by having machines vary their load as grid frequency changes.

Now, if a large plant (such as yours) unilaterally decides, "NO! We don't want our load to change when frequency changes--we insist that our load remain stable regardless of that darned grid frequency!!!" and decides to operate their plant at Part Load with Pre-Selected Load Control enabled and active, then that large plant is actually making the grid frequency fluctuations worse. Yes, WORSE!

By not allowing their turbines to respond to grid frequency disturbances as nature, and Droop Speed Control intended, they are exacerbating the problem and making the situation worse.

Let's say you are riding on a bicycle with several other riders and each rider has a set of pedals on a crankset, and all the cranksets are connected together with chains and fixed gears, and to the rear drive wheel by a chain. Now, the orders for this group of riders are that they are to transport some packages in baskets on the bicycle from one location to another at a constant rate of speed--meaning that the riders all have to work together to maintain the speed (no one rider can provide enough torque to keep the bicycle and riders and packages moving at the desired speed; several riders will have to work together to maintain the speed).

Now, one rider suffers an injury to his legs and can no longer pedal the bicycle. To keep the same speed, the remaining riders are going to have to pedal harder (apply more torque to the pedals). If one rider applies more torque than is necessary to keep the bicycle moving at the desired speed then the bicycle will speed up unless another rider or riders decrease torque. It takes some coordination to keep all the riders working together to maintain the desired speed.

Another rider now suffers an injury and is no longer able to pedal the bicycle. Now, the remaining riders will have to pedal as hard as they can just to maintain desired speed.

Let's say the bicycle passes a station and another package is added to one of the baskets, increasing the load, which causes the speed to decrease. If all of the riders are pedaling as hard as they can, then the speed will not be maintained. If one of the riders that was injured can begin pedaling again then the speed can be increased to desired.

Now, let's say that one or two of the riders just decide without any consultation with any of the other riders that they are only going to provide 50% of the torque they are capable of providing and no more. And, let's say that that's enough to keep the bicycle moving at desired speed as long as the other riders are pedaling as hard as they can. Some more packages are added to the bicycle and now the speed starts to decrease. But, the majority of riders are already pedaling as hard as they can, and those two riders are only producing 50% of what they could produce, even though the speed of the bicycle is decreasing. They could increase their output, but they don't. They don't want to pedal any harder even though the bicycle speed is less than desired.

Those two bicycle riders are making the speed problem worse. They could increase their output and help maintain speed, but they won't. They just want to keep producing the same amount of torque, regardless of bicycle speed. So, the bicycle slows down instead of maintaining speed.

That's how Droop Speed Control works. As load on a grid increases the frequency will start to decrease. As the frequency starts to decrease those units with reserve capacity--and which are not operating in Pre-Selected Load Control--will increase their output to try help maintain frequency. If there are enough units increasing their output then the grid frequency won't decrease by very much.

Everywhere I've ever worked in the world, when a plant signs an agreement to connect to a grid they also tacitly, at least, if not contractually, agree to help support grid frequency through Droop Speed Control governing action. In fact, most contracts require the power generator to specify the amount of Droop Speed Control, 4% o 5% depending on the machine and the application and the location. Which means that for a 1% change in frequency the load of a machine with 4% droop will change by 25%--up to rated output. If the unit was at essentially zero load and in a new and clean condition and ambient conditions were at rated, then if the frequency decreased by 4% the power output of the turbine would increase by 100%. (Now that's no 100% true, because, again, as speed goes down so does air flow, and power output decreases as air flow goes down, but the 25% output change for each 1% frequency change is the key to Droop Speed Control.)

When your generator is synchronized to a grid with other generators the frequency of your machine is controlled by the grid. Just as on the bicycle where all the cranksets are connected by chains and the speed of all the cranksets is the same at any bicycle speed (in essence, they are "synchronized"). In the generator, it's magnetic forces that keep the generators locked in synchronism. On the bicycle, it's the chain that has a fixed number of links (usually the same number of links on gears with the same number of teeth) connected by a final drive chain to the rear wheel, thereby keeping the cranksets rotating at the same speed relative to bicycle speed.

But, if everyone isn't "sharing" in maintaining the bicycle speed, then the bicycle speed isn't going to be maintained very well. And, in the case of combustion turbines when air flow through the machine changes as speed changes, then power output will also change (at any load). A properly regulated and controlled grid requires responsible power generators who understand how their machines operate, how a grid operates, and how their machines contribute to a properly operating grid.

It's as simple as that. Full stop. Period.

And there's no setting that will allow your machines to run at different frequencies (speed) than all the other machines on an AC grid. Full stop. Period.

So it is when you are connected to a poorly regulated grid. Magnetics and physics dictate that your speed, and the amount of power being produced, is fated by the grid frequency and how well the regulators are controlling generation to match load. If generators are prone to tripping excessively and there isn't sufficient reserve capacity to make up for the lost generation--or there are some plants which just arbitrarily decide not to participate in Droop Speed Control schemes--then the grid frequency isn't going to be maintained very well.

And, don't be fooled because your Speedtronic panels are in Droop Speed Control when Pre-Selected Load Control is enabled and active. Because Pre-Selected Load Control over-rides Droop Speed Control when it's enabled and active. So, if you are operating your machines at a constant output as grid frequency is changing, you are part of the problem--not part of the solution.

Sorry, but them's the facts.

No matter what you want them to be, them's the facts.

I hope this helps!

Can anyone let me know how generators on a grid remain synchronized? I mean why they don't simply lose synchronization.

I can understand what happens when they are first synchronized with all the phase angle and speed and voltage matching but what keeps these parameters synchronized thereafter?!

Thanks

Magnetism.

2 out of 2 members thought this post was helpful...

GenSet_Expert,

The whole purpose of matching speed and phase angle is to make sure that when the generator breaker is closed that the rotor magnetic poles are properly aligned with stator magnetic poles so that when the breaker is closed rotor North is near stator South and rotor South is near stator North.

Because if the rotor South pole is near the stator South pole and the rotor North pole is near the stator North pole, REALLY BAD things can happen. You know what happens when you try to force two magnets together when the South Poles (or the North Poles) are near the point of contact--it doesn't happen. You can push and push and push, and while you might eventually get the two magnets to touch each other, when you release them they fly apart.

And you know what happens when you put two magnets together with opposite poles near each other--the two magnets fly together without much assistance. And require force to separate them.

This is exactly what is happening in a synchronous generator. The magnetic forces of attraction are VERY strong, and keep the rotor from spinning faster than the "rotating" magnetic fields of the stator. The rotor North pole follows the "rotating" stator South pole, and the rotor South pole follows the "rotating" stator North pole--with very great forces of magnetic attraction. The magnetic forces of attraction are so great that the prime mover cannot break them to spin the rotor faster than the speed proportional the frequency of the AC flowing in the stator.

This is why the speed of a synchronous generator is directly proportional to the frequency of the grid with which it is connected. The forces of magnetic attraction keep the generator rotor running at synchronous speed--the speed that is proportional to frequency--which is what is called synchronized.

If the phase angle and speed weren't matched during the process of closing the generator breaker, the magnetic forces of repulsion--which are just as strong as those of magnetic attraction--which try to spin the generator rotor extremely fast in one direction or the other (possibly against rotation!) to attract the proper rotor poles. And, that can cause great mechanical damage to the generator, the load coupling, and the prime mover.

And, once the process of synchronization is done, the generator remains "synchronized", running at a speed that is proportional to frequency REGARDLESS OF THE LOAD OR THE FUEL OR THE STEAM BEING ADMITTED TO THE PRIME MOVER DRIVING THE GENERATOR.

It's simple magnetism. Period. Full stop. Nothing more. Nothing less.

EVERY synchronous generator synchronized to an electric grid with other synchronous generators is running at synchronous speed--the speed that is proportional to the AC grid frequency. And, they are all locked into synchronous speed by the forces of magnetic attraction at work inside the synchronous generator. No generator synchronized to an electric grid can spin faster or slower than its synchronous speed (which is a function of the number of poles of the generator rotors.

This is the part that most people miss about AC electric power systems and the part that helps people understand Droop speed control: Once the generator breaker is closed on a well-regulated electric grid, the speed of the generator (and of the prime mover driving the generator) DOES NOT CHANGE. Sure, when the prime mover is being started and accelerated, the speed changes as fuel or steam is admitted to the prime mover. But, once that generator breaker closes the speed of the generator and of the prime mover driving the generator is fixed by the frequency of the grid. Adding more fuel or steam to the prime mover DOES NOT increase the speed of the prime mover or the generator.

Most people think the speed changes as fuel or steam flow is changed because that's what happens during starting and acceleration. But, it doesn't. The grid frequency controls the speed when the generator breaker is closed. And it's all because of the forces of magnetic attraction.

Pretty amazing, huh?

Hope this helps!

2 out of 3 members thought this post was helpful...

I probably need to add to the explanation that in an AC machine (motor or generator) the magnetic poles created when current is flowing in the stator appear to "rotate", and they rotate at a speed that is proportional to frequency and the design of the machine (which includes the number of poles of the rotor). On a well-regulated grid of any size the frequency is, or at least it should be, stable and relatively constant, which means the speeds of the electric machines connected to the grid will be constant and relatively stable.

Also, if the generator breaker remains closed when fuel or steam is removed from the prime mover driving the generator the generator will automatically become a motor and will continue to spin at the same speed (proportional to the frequency of the AC grid with which it is synchronized). This is called "reverse power" and is not good for most prime movers (especially steam turbines and reciprocating engines) because the "generator" (which is now a motor) is spinning the prime mover, and there are generally protective relays to ensure the generator breaker opens in a sufficient time to prevent damage to the prime mover.

It's all about magnetism. Simple, and easy. There are lots of youTube videos about motors and generators and "rotating" magnetic stator fields, as well as reference materials all over the World Wide Web.

Remember: There is no difference between a motor and a generator--except the direction of current flowing in the stator, and whether or not torque is being supplied to the electric machine (when it is a generator), or the electric machine is supplying torque to some device like a pump or a fan (when the electric machine is a motor). Electric current is the medium by which torque is transmitted from the electric machine being driven by a prime mover to an electric machine driving a pump or a fan or some other device that requires torque (including those "virtual torque" devices called computers!).

And on a properly regulated AC grid of any size (an "island" with a single or two or three generators, to the European continent) all of the generators that are synchronized together to supply all of the lights and fans and pumps and computers and monitors are spinning at a speed that is directly proportional to the frequency of the grid with which they are connected: synchronous speed. And no single generator can spin faster or slower than synchronous speed when synchronized to a grid with other generators. So, in effect, they are all spinning at exactly the same speed: synchronous speed.

And magnetism is the reason. Pure and simple.

If the excitation being applied to the rotor of a generator drops below a certain amount (which varies with a lot of different parameters) then the rotor can "slip a pole" which means the North pole of the rotor jumps out of "lock" (the forces of magnetic attraction are broken) with the "rotating" South pole of the stator (and the same with the South pole of the rotor and the "rotating" North pole of the stator) and when that the rotor accelerates VERY fast and when the North pole of the rotor approaches the "rotating" North pole of the stator (and at the SAME time the South pole of the rotor is also approaching the South pole of the stator!) the forces of magnetic repulsion can try to stop the rotor or even try to to force it to turn backwards--which can be VERY destructive to the generator, the load coupling, and the prime mover. VERY destructive. VERY destructive.

So, there are protective relay functions (minimum excitation limits and loss of excitation) to open the generator breaker to stop current from flowing in the stator and to eliminate the "rotating" magnetic fields of the stator to prevent the damage which can be caused by slipping a pole.

But, in any case: the answer to your question is one single word.

Magnetism.

It's what makes electric machines (motors and generators) go 'round! And why the speeds of AC electric machines are proportional to the number of poles of the machine AND to the frequency of the applied AC.

Variable frequency AC is used to vary the speed of AC motors--but the magnetic principles are exactly the same, just the frequency is variable. (The number of poles of an electric machines' rotor is not usually variable.) Some very large gas turbine generators actually use the generator, driven by a variable frequency source, as the starting means to accelerate the unit to near rated speed, at which time, the generator becomes a generator again.

But it's still about magnetism and North- and South magnetic poles. And the attraction between. Current flowing in a conductor, and in coils of conductors, creates magnetic poles. Got two magnetic fields, one which "appears to rotate" and the other free to rotate, and you've got yourself the makings of an electric machine. Apply torque to the electric machine and it can become a generator. Apply current to the stator and it can become an electric motor.

But they all require magnetic fields.

Isn't the world a very simple place, after all? At least the things that have been around for a long time, anyway. And they haven't changed, which is kind of nice, also.

By Namatimangan08 on 8 October, 2012 - 8:44 pm
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What are off peak and peak demand capacity of your grid?

2 out of 2 members thought this post was helpful...

Dear Mashll, I would suggest using the search feature of control.com to look for previous post having to do with grid frequency etc. There have been a few posts that got very complex, and long!!

It is difficult to fully understand your situation but the situation of unstable grid frequency regulation is not new. As stated by other authors a lot has to do with how your area is regulated, the size and configuration of generators in the area, and how generator governors are set. But an unstable grid is typically an issue of inadequate system generation and incorrect relay settings for load shedding.

In a fairly stable grid with adequate generation, if load increases, generators in the area ramp up. Not all can be operating at full (base) load, so that they can provide output for the increase in load. When load drops, generators reduce output to keep frequency stable. If load increases above generation limits, lets say a generator is out of service, then all generators will ramp to full output, but frequency will fall due to lack of generation. In this case transmission relays typically will shed load to protect system frequency.

In your case I am not sure why you are going to preselect load during frequency excursions? If your units were operating at baseload and frequency goes high, they should reduce output to "help" reduce system frequency. It will depend on the magnitude of the swings, the size of your generators VS the total system load of your area, and how long the swings last, but if frequency stays high, theoretically the units should unload as needed.

Now if frequency goes low and your units are operating at baseload, then they will not be able to increase load to support frequency, since they are already operating at the maximum limit. In this case the output of the machine will actually decrease due to lower axial compressor speed and lower mass flow. This is unless you have some of the newer software from GE that allows the unit to overfire slightly to help these situations.

So without more information its hard to provide a real answer for you. One question I have is how are the units controlled? Do the machines get a setpoint from some sort of central power control center? I have encountered some areas where the unit setpoints were recieved from a SCADA system that was not real time. During times of frequency excursions the SCADA setpoint was actually contributing to the problem.

Lastly I would be hesitant to be changing the deadband or settings for droop output without knowing what you are trying to accomplish. Unfortunately in many cases companies are trying to change machine operational programming, instead of trying to fix the real problem.

Know this your not alone, and many here will offer what advice they can to help.

1 out of 1 members thought this post was helpful...

MIKEVI,

When a GE-design heavy duty gas turbine is operating at Base Load without any special "grid code" sequencing (which is optional and not typically provided on most machines) if the grid frequency increases the gas turbine power output will also increase. That's because the air flow increases so the amount of fuel that can be burned also increases, and together, the increased mass flow of air and the additional fuel increase the power output. There is no Droop Speed Control action when a GE-design heavy duty gas turbine is operating at Base Load. In fact, FSRN (Droop Speed Control FSR) is set to a slightly higher value than FSRT (Exhaust Temperature Control FSR) and that differential is maintained as long as Base Load is active. (The "flickering" of the RAISE- and LOWER SPD/LD targets/indicating lamps while the unit is on Base Load is the Speedtronic raising or lowering FSRN to maintain a constant differential above FSRT.)

The opposite happens when a GE-design heavy duty gas turbine is operating at Base Load and grid frequency decreases. The air flow through the machine decreases, the amount of fuel that can be burned decreases, and together they combine to reduce power output.

Now, both of the above results are exactly opposite of what the grid regulators want to happen when there is a grid frequency disturbance! Because when grid frequency increases it means there is an excess of generation relative to load (lights, motors, computers and monitors, etc.) and that translates into a higher than desired frequency. So, even if there are machines operating at Part Load with Droop Speed Control active, the gas turbines operating at Base Load will still be doing exactly the opposite of what the grid regulators, and the grid customers, want to have happen.

It's a dirty little secret of gas turbines--of any manufacture--that this happens at Base Load. It can be particularly disruptive.

I could understand when the grid frequency at Mashll's site goes high the national grid regulators calling to say reduce load to some value below Base Load, perhaps even to 70 MW, though that seems extreme without knowing more about the conditions. But, if the site is unilaterally reducing load when there is any grid frequency disturbance AND putting the units into Pre-Selected Load Control, then they are not contributing to grid stability. While the power output of the turbines might be more stable, the fuel valves are probably going wild trying to keep up with the frequency (axial compressor speed) changes. And that's not helping grid stability either.

As axial compressor speed goes up and down when a GE-design heavy duty gas turbine is operating at Part Load the air flow through the machine is increasing and decreasing. And since gas turbines are primarily mass flow machines, that makes the power output fluctuate in and of itself. The fuel valves, being controlled by a Pre-Selected Load Control Setpoint, are going to be jumping around trying to maintain a constant load depending on the nature of the frequency variations.

Lastly, Mashll said his turbines had DLN-I combustors. YIKES! That's really not good for DLN combustors, having a fluctuating axial compressor speed and mass flow. I can envision the IGVs and the gas valves swinging pretty wildly. The reason they probably go down to 70 MW is to remain in Primary- or Lean-Lean Combustion Mode, because it would probably be VERY hard to stay in Premix Steady-State Combustion Mode, or just Premix Combustion Mode, with grid frequency disturbances above approximately 90-100 MW. The gas fuel valves and IGVs could really be having a go with large and frequent frequency disturbances.

And, though Mashll indicated the units were Simple Cycle, there's still the possibility that they have Inlet Bleed Heating. And that adds dimension when trying to control load and combustion stability during frequency disturbances.

All in all, not a very good situation. Grid regulators need to get a handle on the situation, and power producers need to fully understand how their machines operate, and how they can improve, or de-improve, grid frequency disturbances.

Really, though, it's not a situation that can be solved via a forum like this.

By B.Pavalavannan/NLC Engineer,India. on 6 April, 2013 - 5:34 am

Dear Marshall

your reply is excellent but i would like to ask u one thing. How much frequency will vary or how to calculate if some load got shed ie. say a generator is down?

Hello CSA,

I will really appreciate your response if you could answer the following question. I was advised to find a similar post and add to existing threads conversation. Whatever little I know about GTs mode of operation is because of you guys invaluable contribution. Hats off to your dedication.

I work in an industrial plant which normally exports power in excess of 300-400MW to grid. The system is equipped with IMS (Island Management Scheme) which upon detecting Island condition, rejects certain amount of generation within few cycles based on export level just a moment after the disturbance. It also switch gas turbines mode of combustion from premix to extended lean-lean as soon as it senses isolation of electrical system from grid.

Pre-islanding:
All the GE gas turbines in normal condition operate in either baseload or pre-select mode depending on operations requirement but it can be said with certainty that majority of time they operate gas turbines in baseload.

Post-Islanding:
As explained above, all the GE gas turbines will be made to switch to extended Lean-Lean mode
.
Question: I completely understand these machines response if they are operating in preselect mode and in fact I simulated the event to see their dynamic response which is exactly what is explained in various threads of this website (provided initial frequency response for 10-25 seconds according to droop settings and then withdrew the response to achieve the preselected MW set point). I also simulated pure droop response (neither preselect nor baseload) and found it much faster than preselect due to obvious reasons. I was quite satisfied I have done my job but through this website, I learnt about exhaust temperature control and how it limits governor's response and adjusts fuel flow according to temperature and completely ignoring governor's speed regulation (due to high value of FSRN).

a) Could you please explain how GE gas turbines (single shaft with HRSG [supplying boilers to support process]) will behave to over frequency in the island due to excess generation? Will they drop their load to decrease overall system's frequency or they will increase their load due to increased air flow because of increased turbine's speed as a result of higher system frequency after Islanding: 63Hz initially but settles to 62Hz if all machines operating in preselect and settles to 61Hz if all operating in pure droop? I contacted GE and was informed it will drop its output in response to over frequency condition in the island. However informed me it will not respond to under frequency event, because its already producing the maximum output at base load. Which is also partially true because what was not told that it will make situation worst during under frequency because due to decreasing turbine speed, air flow will be limited thus reducing its output to make things worse.

b) Is their any automatic control which makes a gas turbine to decrease its load once it is automatically switched to extended Lean-Lean mode from pre-mix without operator's manual intervention? I would appreciate if someone can explain, if this switch of combustion mode will have any effect on a machines MW output/load which is operating in baseload right at the moment they Island from Grid. You can perhaps understand why am I asking, will it have any effect on MW output?

zakoota,

Quite an interesting question, and quite a bunch of considerations.

The big unknown for me here is the IMS. And, how exactly does the IMS respond to an opening of the grid tie breaker? What action, specifically, does the IMS take action with respect to load under all conditions? You have briefly described what happens when the unit(s) are operating with Pre-Selected Control, and saying the IMS operates differently when Base Load control is active and enabled? But, we don't know how Base Load control is active and enabled (is it by selecting BASE LOAD on the operator interface, or by setting a Pre-Selected Load Control setpoint (reference) above the suspected Base Load value, or ???).

Also, we don't know precisely how the Mark* is programmed and configured.

You also haven't stated the number of GE-design Frame 9E heavy duty gas turbines running when supplying power to the grid, what the plant load is while connected to the grid, if the 300-400 MW is total GT output or GT output minus plant load, or what the plant load is when separated from the grid. Also, does the IMS do any load shedding in the plant when separated from the grid? So, lots of unknowns here. (Sorry; I'm a very literal person, and I don't like to make a lot of assumptions or read between the lines--because it usually wastes everyone's time and my effort.)

I think there's a bit of a misunderstanding about AC power generation, transmission and distribution systems work. So, let's skip past the very basic part (where speed and frequency are directly related) and do some explanation or review to see if that helps everyone's understanding.

Let's take a very simple independent power system with a single prime mover and generator supplying a load that never exceeds the maximum rating of the prime mover. (The load is really a lot of small loads (motors; televisions; computers and computer monitors; tea kettles; etc.) that all appear as one load to the generator and prime mover.) It requires a certain amount of energy to get the prime mover and generator up to rated speed--to produce rated frequency. (Remember: Speed and frequency are directly related; one can't change without a corresponding change in the other.) And, once the load is (loads are) connected to the generator the amount of torque produced by the prime mover has to match the amount of torque required by the load (loads) PLUS the amount of torque required to maintain rated speed (and frequency).

If the amount of power being produced by the generator prime mover EXCEEDS the amount of power required to maintain rated speed PLUS the amount of power required to exactly supply the requirement(s) of the load(s), the speed and frequency of the unit and the system will INCREASE ABOVE rated. The amount of load (loads) doesn't change--ONLY the frequency of the system changes. If the load was 43.7 MW and steady and not changing, and the energy flow-rate into the generator prime mover increased, the load would still be 43.7 MW, but the speed of the prime mover and generator would increase--and so would the frequency of the system. OR, if a circuit breaker powering a portion of the load being powered by the prime mover and generator opened, removing 6.2 MW of load from the system, and the prime mover control system kept the energy flow-rate into the prime mover unchanged--the load would decrease to 37.5 MW and the speed of the prime mover and generator would increase--and so would the frequency of the system.

If the amount of power being produced by the generator prime mover DOES NOT MEET the amount of power required to maintain rated speed PLUS the amount of power required to exactly supply the requirement(s) of the load(s), the speed of the prime mover and generator--and the frequency of the system--will DECREASE BELOW rated. The amount of load (amount of loads) doesn't change--ONLY the frequency of the system changes. If the load was 43.7 MW, and an electric arc furnace was started, increasing the load by 1.9 MW to 45.6 MW, BUT the prime mover control system didn't increase the energy flow-rate into the prime mover at all--the load would be 45.6 MW, but the speed of the prime mover and generator would decrease--and so would the frequency of the system. OR, if something happened to cause the energy flow-rate to decrease while the load was still at 43.7 MW, the speed of the prime mover and generator would decrease--and so would the frequency of the system; BUT the load would remain at 43.7 MW.

The load on a system is equal to the sum of all the motors and lights and computers and computer monitors and televisions and tea kettles on the system. If the power being applied to the generator by the prime mover (torque) is equal to the amount required to maintain rated speed (and frequency) PLUS the amount required to power the load(s) connected to the generator, then the speed and frequency of the prime mover and generator, and of the system, will be at rated. If the load is stable and not changing by very much, if at all, changing the energy flow-rate into the generator prime mover WILL NOT change the load on the system (the number of motors and lights and computers and computer monitors and televisions and tea kettles)--it only changes the energy which is flowing into the prime mover and being transmitted to and converted by the generator to amperes and supplied to the load(s) connected to the generator. The electrical load doesn't change; only the amount of power being applied by the prime mover to the generator. Anything that causes an imbalance of power (the power required to maintain rated speed and frequency PLUS the power required to supply the load(s) connected to the generator) will result in an over- or under-frequency of the generator and system (and the speed of the prime mover and generator).

Think of it like this: If the amount of energy flowing into the generator prime mover is NOT equal to the amount of power required to maintain rated speed AND supply the electrical load(s) connected to the generator, the electrical load connected to the generator isn't going to change. But, some of the energy that was being used to maintain rated speed and frequency is going to have to be used to supply the requirement(s) of the electrical load(s) connected to the generator--so the speed and frequency of the prime mover and generator, and system, is going to change. Unless and until something acts to change the energy flow-rate into the generator prime mover to restore the prime mover speed and frequency back to rated. The imbalance can be caused by the result of any change in either the energy flow-rate into the prime mover OR the electrical load(s) connected to the generator. If there is more or less power being produced by the generator prime mover than is required to maintain prime mover and generator rated speed and frequency AND supply the electrical load(s) connected to the generator (the motors and lights and computers and computer monitors and televisions and tea kettles)--something has to suffer. And it's going to be the system frequency (and the speed of the prime mover and generator--because speed and frequency are directly related).

My example is very simple--but it's totally and 100% applicable. Just because I'm presuming relatively stable loads or unchanging energy flow-rate into the prime mover doesn't affect the analogy. Just because under normal circumstances load can be very unstable (as in the case of sudden separation from the grid--that's just the same as suddenly shutting of a bunch of motors and lights and computers and computer monitors and televisions and tea kettles. If the energy flow-rate into the prime doesn't respond to that change in electrical load, something is going to change--and it's the prime mover, generator and system frequency, until something is done to change the energy flow-rate into the generator prime mover (or the tie breaker re-closes).

That's the way AC power generation and transmission and distribution systems work. When the total energy being produced by the prime mover is equal to the amount required to maintain prime mover and generator rated speed and frequency AND (or, PLUS) the amount of electrical power required by the load(s) connected to the generator then the frequency of the system will be at rated. Upset that balance somehow (more or less power being produced than is required to maintain rated speed and frequency PLUS power the electrical load(s) connected to the generator) and something has to suffer. At the generator end of the power generation, transmission and distribution system the electrical load(s) can't be changed (well, sometimes it's possible to shed load(s))--but the amount of load(s) connected to and powered by the generator (even if changing by a little, or by a lot) are what they are and require what they require and the generator prime mover can't change that. It can only change the amount of energy flowing into the prime mover and being transmitted to the generator. When everything is in balance, the system frequency (and prime mover and generator speed) are at rated. When there's an imbalance, the prime mover can't change the electrical load(s)--it can only change the energy flow-rate into the prime mover and being transmitted to the generator. So, it's the speed--and frequency--that suffer (vary).

Multiple generators (and their prime movers--GTs in this case) act as ONE generator when synchronized together supplying a load (lots of loads, actually, that all appear as one load). And that's whether the generators (and their prime movers) are connected to a large, "infinite" grid or whether there are two or three or four (or more) units synchronized together supplying a small, "island" load (independent of a grid). A third-party controller, such as your IMS (sometimes called a PMS, Power Management System) will be used to send signals to multiple prime movers to control load and frequency when operating in independent of a large, infinite grid. This can be done in many ways, but it's often done with the prime movers operating in Droop Speed Control mode--and the third-party controller operates as a trained, experienced operator would--managing the load(s) of the unit(s) to maintain the frequency of the system. Sometimes, one unit is chosen as the "master" unit and it's turbine control system adjusts its torque production to respond to changes in system load to maintain frequency. (This is usually called Isochronous Speed Control mode; and there is usually only a single prime mover operating in Isochronous Speed Control mode. But, as with all things, there is also something called Isochronous Load Sharing where multiple prime mover control systems operate in what's called Isochronous Speed Control Mode, but it's really a de-tuned Isochronous mode or a fast Droop Speed Control mode.)

I would expect the IMS to sense the opening of the grid tie breaker and immediately switch the unit(s) to Pre-Selected Load Control with the proper load setpoint (reflecting just the load of the plant being supplied) to reduce the fuel flow-rate(s) and control the frequency. This presumes the units operate in Droop Speed Control (when not operating at Base Load). Isn't that what the IMS does--regulate frequency by controlling load (fuel flow-rate) when separated from the grid? Since we don't know what the system load goes to at the instant the plant is separated from the grid, it's hard to say exactly what's happening.

What is the difference--to the IMS--when the grid tie breaker is opened causing separation from the grid whether the unit is operating at Base Load or Pre-Selected Load Control (Droop Speed Control)? If, as you say (or at least I think you said), the unit is operating in Pre-Selected Load Control when a grid separation event occurs the IMS switches the Pre-Selected Load Control setpoint (reference) to a value that reduces fuel flow-rate to reduce power output to limit and control frequency, why can't the IMS do the same thing when Base Load is active when a grid separation event occurs? Just have the IMS select Pre-Selected Load Control (which would cancel the Base Load control action) and issue the proper load setpoint to limit fuel to limit/control frequency of the host plant? Is that not happening now--the IMS can only issue Pre-Selected Load Control Setpoint changes if the unit is already operating on Pre-Selected Load Control? That's a simple change to the turbine control system programming/configuration, to switch to Pre-Selected Load Control from Base Load on a grid separation event. Actually, all I believe would need to be done is to just select Pre-Selected Load Control whether Base Load control is active or enable or Pre-Selected Load Control is active or enabled--and the unit would switch to or remain in Pre-Selected Load Control.

If Base Load was selected and active at the time the tie breaker opened and the system load decreased (meaning the load on the system dropped because the amount of power being exported suddenly "went away") and NOTHING was done to cancel the Base Load command I would expect the unit(s) would increase speed and frequency trying to maintain the exhaust temperature setpoint (presuming typical Mark* programming and configuration!), and the load on the unit(s) would decrease to match the plant load minus the amount that was being exported. If there is NO automatic action canceling Base Load (exhaust temperature control) and the Mark* is typically configured and programmed I would expect the unit(s) would likely go into an over-frequency condition--because the fuel flow-rate into the gas turbine would exceed the amount required to maintain rated prime mover and generator speed and frequency AND power the electrical load(s) connected to the generator(s). Not knowing what the IMS would do when the over-frequency condition occurs (but having a reasonable suspicion) I would expect the IMS would effectively cancel the Base Load command, switching the unit to Pre-Selected Load Control (Droop Speed Control) and sending a load setpoint (reference) to try to reduce the system frequency back to rated. Depending on how the IMS is programmed and configured, it might do that quickly and reasonably well--or, as many such third-part control systems do it would be slow and not properly judge how much the Pre-Selected Load Control setpoint needs to be to quickly return the system frequency to normal. But, this is really all just speculation--because we don't know enough about the situation and conditions or the IMS and how its programmed and configured, or even exactly how the Mark* is programmed and configured.

I don't know what GE was thinking, considering, was told or knows about the IMS and the full conditions of your plant's configuration and operation. Because if Base Load is selected and active (NOT because the Pre-Selected Load Control Setpoint (reference) is above the exhaust temperature control value!!!), when a grid separation event occurs the unit is going to try to maintain exhaust temperature control--and if the load is insufficient then the frequency is going to increase, never mind what happens to the air flow. Electrical power output is going to match the electrical power required--it will just occur at a higher-than-desired frequency.

>b) Is their any automatic control which makes a gas turbine
>to decrease its load once it is automatically switched to
>extended Lean-Lean mode from pre-mix without operator's
>manual intervention?

As for combustion mode with respect to load, no. If the turbine control system is simply programmed to change combustion mode during a grid separation event, that has NO effect on load (which is a function of fuel flow--not combustion mode). Combustion mode changes just affect the way the fuel is being combusted (burned), not the amount being combusted.

The most likely reason the combustion mode is switched from Premix to Extended Lean-Lean is that when an upset occurs if the combustion is not switched then it will most likely be switched anyway because of the sudden changes in fuel flow and/or air flow on a grid separation event (because of a primary zone re-ignition). Combustion mode changes don't affect OVERALL fuel flow-rates--which determines load (and frequency when running independently of a large, "infinite" grid!). Combustion mode changes only where the fuel is directed in the combustor(s)--how much fuel is going to which combustion zone/nozzles.

A unit running in Extended Lean-Lean can still produce Base Load--though it shouldn't. GE says every hour of running in Extended Lean-Lean mode is equivalent to 10 hours of running in Premix Steady-State mode. It's VERY hard on the combustors (and transition pieces) to run both combustion zones in diffusion flame at the fuel flow-rates associated with Base Load--or even 70-80 % of rated load--it's just not recommended to run for very long in Extended Lean-Lean combustion mode. Extended Lean-Lean combustion mode is intended as a way to prevent tripping the unit on a primary zone re-ignition--to allow the unit to keep running while the operator lowers load to Lean-Lean so that the operator can then re-load the unit back into Premix combustion mode. BUT, the fact remains: Extended Lean-Lean is NOT a recommended combustion mode for long-term operation. Sometimes, though, it has to happen--the equivalent operating hours just need to be factored into the maintenance planning, and it shouldn't be a "regular" occurrence if it can be avoided. (Yes; some companies, including the OEM I'm hearing, are now offering software modifications to automatically transition from Extended Lean-Lean back into Premix, some without having to unload the unit.)

Hope this helps! Balance. Just as in life, it's all about balance. An AC power system can't supply more electrical power than the load connected to the system requires. If it tries to, the system frequency is going to increase. It also has to supply the electrical power required by the electrical loads connected to the system even if there's an insufficient amount of power being produced by the prime mover and transmitted to the generator. In this case, the system frequency is going to decrease below rated. Or, if the electrical load on the system decreases by the energy flow-rate into the generator prime mover doesn't change then the system frequency is going to increase. Or, if the energy flow-rate into the generator prime mover suddenly decreases by the electrical power required by the load(s) connected to the system doesn't also decrease, then the system frequency is going to decrease. Whether the unit is operating in Base Load control or Pre-Selected Load Control (Droop Speed Control)--it doesn't matter. We're just talking about the balance between what's require to maintain rated speed and frequency PLUS what's required to power the electrical loads on the system. Whether or not the energy flow-rate is being controlled with respect to speed error or load control setpoint or exhaust temperature control setpoint.

Now, when the units are connected to a large, infinite grid--actually the SAME things happen. It's just that on a large, infinite grid it's more difficult to see frequency excursions--but they do occur and for exactly the same reasons as on a smaller, independent electrical system. If a 120 MW unit suddenly goes on line (synchronizes to a 6,000 MW grid), or suddenly trips off a 6,000 MW grid--the frequency is going to change--but the magnitude of the frequency change is much smaller and maybe almost imperceptible. But, if a 120 MW unit synchronizes to a 600 MW grid or suddenly trips off a 600 MW grid, the magnitude of the frequency change is going to be much larger, and more "noticeable."

Balance. And scale. The physical properties all still apply in the same way, regardless of the scale or the "notice-ability" of the change.

By Namatimangan08 on 9 October, 2012 - 5:47 am
0 out of 1 members thought this post was helpful...

The dead band +/- 0.5 Hz has already very high. Further increasing it won't help you to solve fundamental problem with the frequency oscillation. At best, it may reduce the number of event related to load oscillation for your plant. At worse, once it happens the load oscillation will become even bigger.

Before you responding to my question, by looking at your plant configuration I'm looking at your grid system peak load demand is 5000MW and above. I might be wrong. Hopefully I'm not wrong since if I'm wrong you might not able to solve your system's frequency oscillation problem for the next 5 years or more.

If your grid peak demand is above 6000MW, such problem can be solved, assuming the biggest per unit capacity of your grid is 300MW. Most likely it has something to do with improper load share scheme via droop setting and/or secondary response overwhelmingly bigger than the primary response (droop response). At least I would that say very remote possibility that it cannot be solved.

Minimum good frequency control and regulation can be achieved if the ratio between the biggest per unit on bars and the peak demand capacity is 0.05 or smaller. If such ratio is greater than 0.15, I would say it is very remote such problem can be solved. The ratio has to go down first before frequency oscillation can be made to reduce.

Hello Sir, kindly permit me to put the following queries which comes up day to day during the operation of our gas turbine plant. GE frame-v, 19.6 MW, three nos with mark-VIe control and synchronised with grid.

1. During normal condition all GTs are in LCM mode (fixed load) with say 15 MW each. Now what will happen to generation in both cases of Grid frequency increases or decreases. In case of fixed load, can the generation increase if the grid frequency increases?

2. If somehow one of the GT gone to float mode (part load) & the operator could not recognize, what will happen to the GT with load in case of grid frequency increases and decreases and Why?

3. Out GTs are always in Droop Mode. How droop control governor works both in base load as well as LCM mode (Fixed load)?

Hope to get some reply please
regards
jagriti

jagriti,

Please read my latest post in reply to zakoota. It should start your mind's wheels turning--in synchronism.

>1. During normal condition all GTs are in LCM mode (fixed
>load) with say 15 MW each. Now what will happen to
>generation in both cases of Grid frequency increases or
>decreases. In case of fixed load, can the generation
>increase if the grid frequency increases?

If I understand "fixed load" mode and LCM correctly, AND if the Mark* doesn't have Primary Frequency Response enabled and active when operating in "fixed load"/LCM, the Mark* is going to first try to change the load of the turbine-generator BUT "fixed load"/LCM is going to respond by saying, "No; no; NO! The load of the generator is going to remain at the "fixed load"/LCM setpoint!" and it's going to try to return the turbine-generator load to the "fixed load"/LCM setpoint. But, the Mark* (again--without Primary Frequency Response mode enabled and active (if it's even present in the control system)) is going to try to change the load per the Droop Speed Control scheme, but "fixed load"/LCM is going to say--again, "No; no; NO!" and try to return the turbine-generator load to the "fixed load"/LCM setpoint value. And this will go on as long as the operator allows it to happen as long as the grid frequency is not at rated.

(Pre-Selected Load Control, or "fixed load" mode, or LCM, is a mode which under normal configuration and programming (that is without Primary Frequency Response) over-rides Droop Speed Control mode and control. It's NOT a proper way to continuously operate a GE-design heavy duty gas turbine (unless the control system has Primary Frequency Response enabled and active).)

>2. If somehow one of the GT gone to float mode (part load) &
>the operator could not recognize, what will happen to the GT
>with load in case of grid frequency increases and decreases
>and Why?

If I understand "float mode", you mean Droop Speed Control mode. When a unit is operating in Droop Speed Control mode with no over-riding control (like "fixed load" or LCM or Pre-Selected Load Control) and frequency changes, then the electrical power output of the turbine-generator will changes in proportion to the change in frequency. For a machine with 4% Droop (which many GE-design heavy duty gas turbines are configured with/for), that means if the frequency changes by 1% the electrical load of the unit will change by approximately 25% of the rating of the turbine (1% is one quarter of, or 25% of, 4%). That presumes the unit isn't operating very close to either Base Load (maximum output), or zero load (0 MW). That is what is SUPPOSED to happen when grid frequency deviates from rated on a normal grid. REGARDLESS of what any operator thinks or believes (or knows!), or any Operations Supervisor thinks or believes (or knows!), or any Plant Manager thinks or believes (or knows!), or any instrumentation & control technician thinks or believes (or knows!). That's how AC power generation, transmission and distribution systems are designed to operate--generators and their prime movers, when operating in Droop Speed Control mode with no over-riding control scheme active, are SUPPOSED to change load to help support grid stability. If they don't change load when they should be changing load, they are actually making the grid more unstable. And contributing to grid instability.

>3. Out GTs are always in Droop Mode. How droop control
>governor works both in base load as well as LCM mode (Fixed
>load)?

Well, ACTUALLY, when your unit operator interface display says Droop Speed Control mode is active, it isn't always active. There is an operator interface display (or there should be) called the FSR Display. And on that display there are several bars the height of which is proportional to the calculated value of each of several different FSRs (Start-up; Shutdown; Speed Control (Droop Speed Control); Exhaust Temperature Control; Acceleration Control; Manual Control). The bar which is green is the FSR which is in control of the fuel being admitted to the fuel nozzles in the combustors. And, when the unit is operating in Exhaust Temperature Control active (Base Load), the bar associated with FSRT will be green, and FSRN (Droop Speed Control FSR) is NOT active (not green).

When the unit is NOT at Base Load (meaning it is at Part Load, in GE-speak), it should be normally operating in Droop Speed Control mode (the FSRN bar should be green). And, if "fixed load"/LCM (or Pre-Selected Load Control) is active, then Droop Speed Control is being over-ridden by load control--which is okay UNTIL the grid frequency deviates from rated!

The above explanations are pretty simplified; it can be a lot more technical. I'm not familiar with "fixed load" or LCM; I'm presuming it's what is typically called Pre-Selected Load control; maybe a version of that called External Load Control. But I'm pretty certain that unless the Mark* has Primary Frequency Response control mode, and it's active and enabled when load control is active at Part Load, that it's just over-riding Droop Speed Control, which, again, is okay as long as the grid frequency is normal.

Exhaust Temperature Control (Base Load), actually limits Droop Speed Control when it is active (exhaust temperature control is active)--if necessary. When BASE LOAD on the Main Display of the operator interface (GE Mark VIe HMI) is enabled and active, the Mark* is putting absolutely as much fuel as possible into the unit to try to make the actual turbine exhaust temperature equal to the turbine exhaust temperature control reference--thereby making as much power as possible.

When Droop Speed Control is active, the amount of fuel flowing into the fuel nozzles in the combustors is only equal to the difference between the turbine speed reference and the actual turbine speed (called the "speed error"). So, the amount of power being produced is less than what would be produced if operating on turbine exhaust temperature control. That's how the unit is loaded and unloaded (from 0 MW to Base Load, and between 0 MW and Base Load)--by changing the turbine speed reference which changes the speed error which changes the fuel flow-rate which changes the electrical load.

Droop Speed Control has been covered MANY times before on control.com--so many times I think the name should be change to droopspeedcontrol.com.

Hope this helps! I'm sure you're a little confused, but be patient. You'll get there--eventually.

Dear Mashil,

Your reply is excellent, but i would like to ask you one thing. How much frequency will vary or how to calculate if some load got shed, i.e., say a generator is down?

Dear faaramin,

There is no simple answer to your question. The magnitude of the frequency variation due to a disturbance, e.g. a generator tripping, depends on a number of factors, of which the main ones are:

- The magnitude of the loss of generation relative to the total load (or generation, which should match load in normal steady conditions). In CSA's tandem bicycle example: how much power was the tripped generator/cyclist supplying relative (i.e. as a fraction of) the total load/generation?;

- The Frequency Sensitivity of Load (FSL), i.e. how much does the load naturally change if the grid frequency changes, normally in the same direction as the frequency change (i.e. if frequency drops, load also drops). For the bicycle: if the speed drops, then how much does the load power drop due to reduced wind and rolling resistance force?; in real grids, typically large rotating machinery tends to reduce its load at lower frequencies. This is a 'damping' factor, which reduces the effect of load and generation disturbances on grid frequency. However, the increase of modern electronic devices which regulate their power intake to a constant value means that the FSL is reduced, which means that frequency variations due to disturbances increase, making controlled response (governors, etc.) more important;

- The response (droop/governor/control/...) strategies and settings of the remaining power generators on the grid, and their power range. For the bicycle: as CSA noted, how do the (other) cyclists respond if one trips/stops cycling?

Thus, to calculate a numerical value for frequency change due to a generator trip, you need a lot of information.

As an aside, load shedding is different from a generator tripping/stopping and has the opposite effect; it means reducing the load on the grid. In the bicycle example, load shedding is throwing one or more of the baskets off the bicycle to reduce the load, as opposed to reducing (or adding) generation/cyclists. Here in the UK we had an example of this a couple of weeks ago, when two large generators tripped nearly simultaneously and a section of the national grid was disconnected temporarily to maintain the stability of the rest of the grid (and allow the frequency to recover to a normal value), because other generation to compensate for the loss could not be increased fast enough.

Hope this helps.

very very thank you