Today is...
Sunday, August 25, 2019
Welcome to Control.com, the global online
community of automation professionals.
Featured Video...
Featured Video
Wiring and programming your servos and I/O just got a lot easier...
Our Advertisers
Help keep our servers running...
Patronize our advertisers!
Visit our Post Archive
Free Governor Mode of Operation
Safe Load setting value of Gas Turbine with 10% droop for FGMO operation in a 49.5Hz to 51.4Hz swinging Grid
1 out of 2 members thought this post was helpful...

Our plant consists of two GE-9E machines,two HRSGs and one ST. The GE-9E machines each with rated load 117900 KW at 32C, 80% RH and 1013 mbar (atm). The nominal frequency is 50Hz. For grid stability the transmission company now emphasize to run the plant on FGMO (Free Governor Mode of Operation). To optimize CCPP (combined cycle power plant) operations we generally set GT load 98 MW each and enable FGMO operation mode by clicking Raise/Lower button of SPEED/LOAD control @50.0HZ Grid Frequency.

However we observed abnormal load variations when grid frequency too much fluctuated (49.5 Hz to 51.4Hz). Sometimes at 50.12HZ load is around 85MW, and sometimes it is 93MW and at 51.0HZ grid frequency sometimes the load is 65MW and sometimes 75MW. The reference droop of our Gas Turbines are 10% each.

Is there any option to set a safe load set point for FGMO operation at 50.0Hz frequency which is nominal frequency in our case?

Need a fruitful explanation regarding the issue from the MVPs of this forum.

Regards,
Rokan Uddin

5 out of 5 members thought this post was helpful...

rokan_123,

I may not be the nicest person to explain this, and I may not have done it in the nicest manner. And, when I say "you" and "your" below I am referring to ALL the people who want THEIR power plant to remain stable during times of grid frequency disturbances--not just you, personally, rokan_123. These are the people operating the electric power plants that supply our nations, our homes, our hospitals, our water treatment plants, our businesses and factories. And, very few actually understand basic AC power generation fundamentals and principles.

The principles of AC power generation have been explained many times on control.com. F=(P*N)/120. It's the most basic formula for AC power generation there is.

Synchronism is a very powerful, and non-ambiguous word. It means that all synchronous generators synchronized to an AC grid with other synchronous generators all operate at a speed that is proportional to the frequency of the grid they are synchronized to. That means, that ALL two-pole generators (such as are used with GE-design Frame 9E heavy duty gas turbine generators) synchronized to a grid will operate at 3000 RPM when the grid frequency is 50.0 Hz. And when the grid frequency is 49.5 Hz, ALL two-pole generators synchronized to the grid will operate at 2970 RPM. And, when the grid frequency is 51.4 Hz, ALL two-pole generators synchronized to the grid will operate at 3084 RPM. Full stop. Period. End of discussion.

HUGE magnetic forces at work inside the generator keep the generator rotor locked into synchronism with magnetic forces developed when alternating power is flowing in the generator stator windings. Locked into synchronism. That's literally what it means--no rotor can spin faster or slower than the speed which is a function of the frequency of the grid it is synchronized to.

Now why is that important? Because virtually every synchronous generator and it's prime mover synchronized to any AC grid anywhere in the world operates on Droop Speed Control (the original term for "Free Governor Mode of Operation"). Droop Speed Control says: The amount of energy flowing into the prime mover of a synchronous generator is a function of the difference between the speed reference of the unit and the actual speed of the unit. When a unit is synchronized to a grid operating stably at 50.0 Hz (100% frequency), it's actual speed will be 100% (3000 RPM for a prime mover directly coupled to a two-pole generator). And, during synchronization of the generator to the grid the speed of the unit is also at 100% (or a little bit higher, for reasons we don't need to go into here and now)--because it's speed reference is approximately 100%. When the generator breaker closes during synchronization the speed of the generator and it's prime mover is now controlled by (is a function of; is proportional to) the frequency of the grid.

As long as the grid frequency is stable at 50 Hz (100%), the actual speed of the generator and it's prime mover will also be 100%. If the operator wants to increase the load of the generator, he or she will click on RAISE SPEED/LOAD--which will increase the speed reference. As long as the grid frequency (which means the actual speed of the turbine-generator) remains at 100%, when the speed reference increases Droop Speed Control will see the difference between the speed reference and the actual speed has increased and will therefore increase the energy (fuel) flow-rate into the turbine, which will in turn increase the power being produced by the generator. The actual speed of the generator DOESN'T change when synchronized to a stable grid operating at rated frequency. So, changing the speed reference changes the error (the difference) between the two, which changes the energy flow-rate into the prime mover, which changes the power output of the generator. Again--the speeds of all the synchronous generators synchronized to a grid are all controlled by the frequency of the grid. If the grid frequency is stable and not changing, then the actual speeds of all the generators and their prime movers are stable and not changing. So, changing the speed reference (even though the actual speed CANNOT and DOES NOT CHANGE) will cause the energy flow-rate into the prime mover to change, which will change the power output of the generator to change.

Let's say the turbine speed reference of your units with 10% droop (which is not typical, by the way) is at approximately 109% when the grid frequency is at 50 Hz (100%). The difference between the speed reference and the actual speed (frequency) is 9%. The speed reference is not changing, and the actual speed (frequency) of the unit is not changing (because the grid frequency is stable at 50 Hz), so the difference (the "error" between the reference and the actual) is stable at 9%--which means the fuel flow-rate is stable, which means the load is also stable.

Now, if the grid frequency changes--then the speed of the turbine and generator will change. Let's say the grid frequency decreases to 49.5 Hz. That's a decrease of 1% of frequency (and also 1% of speed). So, the difference between the speed reference (109% in out example) and the actual speed (now at 99%) has increased to 10%. That means the governor (the Mark* turbine control system) will increase the fuel flow-rate into the turbine, which will increase the power output of the generator. It's as simple as that. The opposite happens when the grid frequency increases; the power output of the generator will decrease.

So, we've seen how Droop Speed Control works. If the grid frequency is stable and the operator wants to change load, he or she does so by changing the turbine speed reference, which changes the error between the reference speed and the actual speed, which changes the energy flow-rate, which changes the power produced by the generator. AND, if the speed reference is stable but the actual speed of the unit changes (because the grid frequency changed), that also changes the error between the reference speed and the actual speed, which changes the fuel flow-rate, which changes the power produced by the generator.

Now, when the grid frequency returns to normal, if the turbine speed reference has remained constant and hasn't changed the unit will return to the same load it was at before the grid frequency deviation occurred.

So, when grid frequency is unstable, the speed of ALL the synchronous generators connected to the grid changes, and for those machines not operating at full power output Droop Speed Control will cause the energy flow-rate into the prime movers to change which will cause the power being produced by the generators to change. That's how it works--and that's how IT'S SUPPOSED TO WORK.

This is what Droop Speed Control is all about. Controlling the energy flow-rate into the prime mover based on the difference between the speed reference and the actual speed. If either the speed reference OR the actual speed changes, that causes the energy flow-rate into the prime mover to change, which causes the power being produced by the generator to change. This is how all generators synchronized to a grid can help share in powering a load (the sum of all the motors and lights and computers and computer monitors and televisions and tea kettles) that is larger than any one single generator could every hope to power. Droop Speed Control is the way that many synchronous generators can all operate as "one" huge synchronous generator. That's why virtually every synchronous generator's prime mover uses Droop Speed Control when not operating at full power output--because that means all machines will behave in the same, predictable manner.

Grid operators (transmission companies) WANT the loads of the generators synchronized to their grids to change when the grid frequency changes. It helps to support grid stability, and helps them be able to more quickly return the grid frequency to normal. If multiple generators DON'T change their power output when operating on Droop Speed Control then it's much more difficult for grid operators (transmission companies) to correct and control grid frequency disturbances. And, when grid operators know the Droop characteristics of each generator--and can count on (rely on)--those generators to respond in a predictable way and by a predictable amount (based on the Droop characteristic) they can more reliably control and respond to any grid deviations when they do occur.

Many people want what you want--but that's because they don't understand basic AC power generation principles and concepts. Sure; it would be very nice if the power output of YOUR plant would stay constant and not change when the grid it is synchronized to was not stable and was not at rated frequency. Everybody wants that. But, it's not what should happen (no matter how much anyone wants it to!), and, in fact, it's irresponsible. Why should your plant's power output not swing when it should to support grid stability when every other power plant's power output is swiging? Why should your power plant be excepted from the instabilities other power plants are expected to endure in order to support grid stability?

Sure; it would be great if your (everyone's, actually) power plant would be stable and not oscillate during grid frequency disturbances. But, it shouldn't--and if it is, then it's actually contributing to the grid instability. Any plant whose power output doesn't change when the grid frequency changes is forcing other power plants to have to work harder to support grid stability, and making it more difficult for the grid operators (transmission companies) to restore grid stability sooner.

Basic AC power generation fundamentals and principles. It's not rocket science. It's basic AC power generation fundamentals and principles.

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

Dear CSA,

Thanks for your long valuable reply.My primary intension is to find out the clue of different loads at same frequency at different times when we are not changing anything. Say at 50.0HZ frequency we get 99MW load and at another 50.0Hz Frequency we get 93MW load. Why we will not get same load (99MW) at another 50.0HZ frequency? When we need to enable FGMO mode at 50.0HZ frequency (at which load of GT)?

Well, I have studied your several posts in control.com to understand the reason, but can not match my case with those fantastic reading materials.

Regards,
Rokan

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

rokan_123,

You say your unit has 10% Droop, and is rated at 117.9 MW. That means that for every 1% change in TNR (Turbine Speed Reference) the load will change by 11.79 MW when the frequency of the grid the unit is synchronized to is 50.0 Hz.

(90 MW/117.9 MW) = 76.33% of rated MW. Because your unit has 10% Droop, it's relatively easy to calculate what TNR should be when the load is 90 MW: 107.633% at 50.0 Hz. If the frequency dropped to 49.0 Hz, that would be a 2% increase in speed error (TNR remains constant in FGMO, but the actual speed would change by 2%, so the speed error would increase to 109.633%). And a 2% increase in speed error on a machine with 10% Droop rated at 117.9 MW the load would increase by (2*11.79=23.58 MW) to 113.58 MW.

We don't know if your unit has conventional combustors of DLN-I combustors. We don't know if your unit is burning gas fuel or liquid fuel. If your unit is burning gas fuel we don't know if the gas fuel supply pressure is at rated or below rated during the frequency excursions. We don't know how or when you're measuring 50.0 Hz, and what is happening when you;re measuring 50.0 Hz (is the load changing as the frequency is passing through 50.0 Hz; or are you measuring the load after the frequency has stabilized for a minute or so at 50.0 Hz). Specifying loads at 50.0 Hz is also pretty 'tight' ....

If the unit has DLN-I combustors, does it have IBH (Inlet Bleed Heat), and if it has IBH is it enabled and active during the frequency excursions? If the unit has DLN-I combustors when the frequency is bouncing around the IGVs are also going to be moving--a lot. And that's going to also have an effect on load and loading/unloading. And, if the unit has DLN-I combustors and the load you have set with the RAISE- and LOWER SPEED/LOAD buttons happens to be close to the combustion mode transfer point (between Premix Steady State and Lean-Lean combustion modes) and the frequency is swinging and the IGVs are moving and the load is changing, it's entirely possible the unit is transitioning combustion modes during these frequency excursions. And that can have an effect on load and loading/unloading.

So, there's a lot we don't know about your units and how they are operating. DLN-I units are not very good when the frequency is not very stable--no matter what the salespeople say. I suspect that may be one reason the units have 10% Droop (which is very atypical; most GTs around the world usually have 4% Droop).

There's just so much going on when grid frequency is unstable, especially if it's oscillating above and below rated and doing so relatively quickly (in just a couple of seconds or so). And, if the unit has DLN-I combustors and IBH there's even MORE going on.

Even when the units have conventional combustors when the frequency is changing the air flow through the machine is also changing (because the axial compressor speed is changing). And that's also true if the unit has DLN-I combustors.

>When we need to enable
>FGMO mode at 50.0HZ frequency (at which load of GT)?

Do you have a special button for enabling FGMO?

I also sense that you somehow believe that if you click on RAISE- or LOWER SPEED/LOAD at any time when the frequency is at or passing through 50.0 Hz that the Mark* will "capture" the load at that point. It doesn't. You need to use the RAISE- and LOWER SPEED/LOAD buttons to get to a desired load when the frequency is stable and has been for a minute or so, at least. If you can explain how you are selecting FGMO at 50.0 Hz (what is going on when you are selecting FGMO at 50.0 Hz) we might be able to understand and help you understand what is happening.

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

Dear CSA,

Our machines are standard combustion machines.
Regarding FGMO enable,

We normally use preselect mode to hold GT load say at 98MW and when we find 50.0HZ frequency for a moment (I told you our transmission line frequency is very unstable, and it is not possible to get 50.0HZ frequency for one minute). We just click on RAISE/LOWER button of SPEED/LOAD control and that's it. This method of enabling FGMO was supplied by GE Engineering team. If you have different views, please share.

Thank you very much for your supports.

Regards,
Rokan

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

rokan_123,

I don't understand how you can keep saying that you want to get the unit to hold a steady load at 50.0 Hz, when you now say the grid frequency won't be at 50.0 Hz for even one minute.

99 MW is pretty close to 117.9 MW, and if the units are exhausting into HRSGs (boilers) then they are probably operating on IGV exhaust temperature control, and that means the exhaust temperature is already at the maximum limit even though the IGVs are not fully open and the unit is not at Base Load (the definition of Base Load is when the IGVs are at maximum operating angle and the actual exhaust temperature is equal to the exhaust temperature reference/limit). When the grid frequency (and, therefore, unit speed--and axial compressor speed) is oscillating it's going to mean the load is going to be limited to less than normal (normal being at 50.0 Hz continuous operation) when the grid frequency is below 50 Hz because the exhaust temperature is already at maximum and if the air flow through the unit is dropping because the axial compressor speed is dropping the Mark* is going to reduce fuel pretty quickly while the IGVs are going to be trying to open to also help reduce the exhaust temperature. The opposite will happen when the grid frequency is higher than 50 Hz--the Mark* will be trying to put more fuel in the machine and the IGVs will be trying to close to get the exhaust temperature up and the power output will increase above normal.

Now, think about what's going to be happening if the frequency is oscillating above and below 50.0 Hz fairly quickly!

Tell us: when the unit was operating with Pre-Selected Load Control and the grid frequency was unstable was the unit power output more stable? Did you observe the RAISE- & LOWER SPEED/LOAD buttons continually flashing orange and cycling? Operating with Pre-Selected Load Control disabled on Droop Speed Control (FGMO} do you observe the RAISE-& LOWER SPEED/LOAD buttons flashing orange and cycling continuously?

I have been in some locations where the grid frequency was unstable for short periods of time<s few minutes, maybe a half-hour), but never continuously and or for longer periods. Sometimes synchronization was "fun" if they were trying to synch during a period of grid frequency instability.

Do you have any Trend Recorder files of unit operation you can share with us? It's possible to record only at 25 Hz (40 msec) as the fastest recording speed, but we could still get an idea of what's happening with the IGVs, exhaust temperature, FSR, TNR, TNH, grid frequency (SFL1), the exhaust temperature (TTXM), the exhaust temperature reference/limit (TTRX), P2 pressure, etc.

And that brings up another point (though you still haven't told us what fuel the units are burning): The SRV will be swinging when the grid frequency is oscillating which means the P2 pressure will also be oscillating which will just add to the chaos of the moment.

If you are asking if there's a way to get the unit to always put out 98 or 99 MW when the grid frequency returns to 50.0 Hz, that sounds like a pretty impossible task if the grid frequency won't be stable at 50.0 Hz for even one minute. Ag6, with IGV exhaust temperature control active at 98 or 99 MW the unit is already at maximum exhaust temperature and with all the other things happening as a result of the grid frequency instability it's really a testament to the Mark* turbine control the unit doesn't trip on exhaust over-temperature with some kind of"regularity."

To get the unit to put out any load setpoint at 50.0 Hz you really have to set the load while the grid frequency is stable at 50.0 Hz for some period of time, or when the grid frequency is not oscillating too much above or below 50.0 Hz. If you can do that a couple of times and record the value that is probably the only way you're going to determine what that turbine speed reference value (TNR) is that will almost always return the output to the same output when the grid frequency does return to 50.0 Hz. But I believe it's going to be a trial-and-error process to determine the TNR value--but determining the TNR value and then using the RAISE- & LOWER SPEED/LOAD buttons to adjust TNR to that same value is going to be the best way to arrive at that desired load if and when the grid frequency ever does get to 50.0 hz

I have one idea: 99 MW out of 117.9 MW would correspond to a TNR of 108.39% for a unit with 10% Droop. You could start your process of deriving the proper TNR by using the RAISE- & LOWER SPEED/LOAD buttons to adjust TNR to 108.39% and observe what happens. BUT, I still maintain the grid frequency would need to settle for at least 30 seconds to a minute to determine if the 108.39% value was close to correct. The IGVs and the fuel control valve(s) and the exhaust temperature have to have some time to come to some equilibrium (settle). But, I think adjusting TNR to approximately 108% would be a good starting point for determining the best value for your site.

Please write back to let us know how setting TNR to approximately 198% works. But if the grid frequency is as unstable as you seem to be telling us, and you are running at 98 or 99 MW with IGV exhaust temperature control active I think it's going to be a difficult task to evaluate if any TNR setpoint is "successful." Best of luck, and keep us informed. I think starting with a TNR of approximately 108% is as good a starting point as any.

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

CSA
Very good explanation. You are good at explaining things.

Rokan_123

When we choose the pre-select mode the GT load remains constant. If the frequency changes the TNR changes automatically. The preselect mode will keep the TNR-TNH constant. This is how it will keep the load constant because whtn TNR-TNH is constant the fuel admitted to turbine will remain same and so does the power output.

As far as I can understand, one of the reasons the load is different for same frequencies is that when you select the FGMO the frequency is not exactly 50.0 Hz. So everytime the TNR-TNH is different. Can you please check the TNR and TNH for the different scenarios you have mentioned? I guess, in your case TNR will be different and TNH will be same for different scenarios.

I hope it will help.

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

Esoteric_Stone,

Pre-Selected Load Control is just a very bad way to continuously operate a GE-design heavy duty gas turbine (unless the unit has the GE Primary Frequency Response Option and it is also enabled)--a very bad way. AND, if the grid frequency is unstable it's even a WORSE way to continuously operate the gas turbine.

The GE Primary Frequency Response option effectively disables Pre-Selected Load Control when the grid frequency deviates from rated by some set amount. So, it allows the unit to respond as if it were in Droop Speed Control (Free Governor Mode of Operation)--while the frequency is out of the allowable window.

If the frequency is constantly unstable, it would be pretty much useless; better to just completely cancel Pre-Selected Load Control by clicking on RAISE- or LOWER SPEED/LOAD and let Droop Speed Control (FGMO) operate as it should.

Droop Speed Control has been used for over a hundred years, all around the world, and pretty much without anyone understanding how it works! (It's like closing the light switch and the light coming on. Most people don't have any idea what's involved in making that happen, and keeping it happening!) But, it's a time-tested and proven method for operating power generation prime movers--until GE foisted Pre-Selected Load Control on their Customers.

What I would dearly love to know from rokan_123 is: Why is the grid frequency so unstable? And, has the transmission company's insistence on using FGMO made it any better? What is it about the grid operating conditions that make it so difficult for the transmission company (grid operators) to maintain a stable frequency? Do they know have the ability to directly control generators (using AGC (Automatic Governor Control)? Are the generators constantly and unexpectedly tripping and causing problems? Are there large loads on the grid that unexpectedly start and stop?

"Back in the day" when utility companies owned and operated most if not all of the power generation assets of their region they were much more able to control loads and frequency--because they could say when to start and stop units, and when to load and unload units. With the advent of cogeneration, de-regulation and independent power producers, the use of more and more solar- and wind power generation, and the tendency of utilities to get out of the power generation business and the increasing use of gas turbine-generators for power generation it seems that grid frequency control has become more and more of an issue, and even a problem. It's a problem which needs to be solved. And, it's an interesting problem to observe being solved.

In the meantime, though, we are going to have to contend with the problems. Hopefully, FGMO will help. But, good training and experience of power plant operators (of all sizes and types!) and their supervisors and owners, as well as of grid operators (transmission company employees) would also go a long way to helping resolve the problem. There are a LOT of GE-design heavy duty gas turbines in operation, and if operators would stop using Pre-Selected Load Control (except for changing load) that would go a long way towards helping to resolve the problem. But, power plant operators have the most inertia of any substance in the universe--they just refuse to change. "We've always used Pre-Selected Load Control!" is their refrain, and if allowed they will continue to use it. It's the way they were "trained" (and most of them were trained by other operators, not in any kind of formal training or internship programs--which used to be the norm).

Alas, I digress. (But Pre-Selected Load Control is not a good way to continuously operate a GE-design heavy duty gas turbine.)

Hopefully we will hear back from rokan_123, and maybe he can tell us a little about the conditions of the grid operation in his area of the world and why the frequency is so unstable. And, if FGMO has helped stabilize the grid at all since it's use has been "requested" by the transmission company (grid operators).

@CSA

Sir, I have a small doubt which is articulated by an example as follows:

The scenario is single GTG capacity-50MW is running in preselect mode in parallel with grid. GTG is loaded with 40MW in Preselect mode, Grid import is 5MW, both supplying to in-house load demand of plant. Now if Grid tripped, this extra 5MW is to be taken up by GTG. In free governor mode (float/part mode) GTG would take up this extra load but in Preselect mode what will happen. Will GTG trip on under frequency or it will come out of preselect mode automatically.

Please neglect transient effects.

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

RJ_VR,

I'm very disappointed to hear about your doubts. But, your question isn't really related to this thread.

Whether the unit is in FGMO or Pre-Selected Load Control it is in Droop Speed Control. Pre-Selected Load Control is an outer control loop to Droop Speed Control.

If the unit is in Pre-Selected Load Control and the grid tie-breaker trips when power was being imported from the grid, Droop Speed Control is going to see the change in frequency because the lost power from the grid is going to cause the in-house load to make the frequency decrease--and pretty fast. So, the first thing that's going to happen is the load on the unit is going to go to 45 MW and Droop Speed Control is going to make that happen by increasing fuel pretty quickly. BUT, Pre-Selected Load is going to then start trying to return the load to 40 MW (the setpoint before the grid tie-breaker opened) by reducing fuel. And that's going to make the frequency decrease further. Pre-Selected Load Control and Droop Speed Control will fight each other--with Droop trying to hold the load at 45 MW and Pre-Selected Load Control trying to decrease the load by reducing the fuel flow-rate to the turbine. It's not pretty--and that's one of the reasons it's NOT proper to use Pre-Selected Load Control to continuously operate the gas turbine for just this reason--when
Droop Speed Control is trying to maintain load during a frequency excursion, Pre-Selected Load Control is trying to do exactly the opposite. That's why transmission companies and grid operators are telling generators to use FGMO and not Pre-Selected Load Control.

In my opinion, in your scenario where the unit is operating with Pre-Selected Load Control active while synchronized to the grid if the in-house load requires power from the grid and the grid tie-breaker opens (trips) eventually the GTG is going to trip on under-frequency. And it probably won't take very long to happen, either.

What should happen is that the unit should immediately transfer to Isochronous Speed Control at the instant the grid tie-breaker opens (trips) if there was power being imported from the grid before the grid tie-breaker opened. OR, at a minimum Pre-Selected Load Control should be immediately canceled to allow Droop Speed Control (FGMO) to try to maintain the in-house load--but I believe the frequency decrease caused by the loss of 5 MW from the grid would probably be enough to cause an under-frequency trip, if not quickly then after some time if the operators couldn't quickly increase the load on the unit.

Transferring to Isochronous Speed Control when the grid tie-breaker opens will cause the turbine control system to immediately pick up the lost power from the grid and pretty quickly return to rated frequency while producing the lost power from the grid. That's what Isochronous Speed Control is for. (I'm presuming there are no other generators in the plant, by the way, because you didn't mention any other generators running at the time of the event.)

It would be necessary to transfer back to Droop Speed Control just before re-synchronizing to the grid, but that should be simple enough as long as the in-house load is pretty stable when you are going to re-synchronize to the grid (and it should how you are presently re-synchronizing to the grid (when the load is stable)).

Free Governor Mode of Operation is just a new-fangled term for Droop Speed Control without any outer control loop. Just "straight," "plain" Droop Speed Control.

Hope this helps answer your questions. Doubts are not our responsibility because no information related to your scenario/questions were previously provided in this thread.

@CSA Thanks for the reply and sorry that it disappointed you by asking question on thread not related to topic. But specifically I wanted to hear it from you. I analysed all block diagrams in MARK-Vie starting from dwatt transducer output to generating FSRN but found that MARK-Vie has no inbuilt mechanism to come out of preselect mode automatically based on upper/lower limits of frequency or based on input from Grid trip/close status or any other way. To get cross informed on the matter I asked that question, as I don't have any special knowledge in this type of systems.

Now I want to add one extra block diagram in which it compares TNH with upper/lower limits(constant) of frequency (limits to be decided by the grid frequency trend and trip settings of GTG). Based on this comparison it should change the status of L83PS(PRESELECT LOAD COMMAND) tag, with a alarm also.

OR

another block which can change the state of L83PS based on the close/trip status of grid breaker, also alarm to be generated.

How can I introduce this extra block in MARK-Vie?

Please tell me what could be the implication on other programs by these changes in MARK-Vie and is it safe to introduce such modification?

L83PS is a bool type variable, state of which can be changed only by clicking preselect or raise/lower symbol on HMI, I didn't find any other block which is changing the state of L83PS.

RJ_VR,

Making changes to the application code of a Mark VIe is not for the faint of heart--or even for those with a high tolerance for risk. I understand the desire (or need) to automate canceling Pre-Selected Load Control when the desired set-point is reached (to prevent operators from getting RSI (Repetitive Stress Injury by clicking on buttons, and to eliminate possible operator error should they forget to click on RAISE- or LOWER SPEED/LOAD to cancel Pre-Selected Load Control once the unit reaches the Pre-Selected Load reference).

I would highly recommend writing up a description of your desired change (a high-level description would be fine) and then hiring a person knowledgeable in editing Mark VIe application code to make the changes you desire. (I caution you--alarms should be alarms. Not notices to the operator--but real alarm conditions.) It is VERY easy to mess things up, and if you don't have a proper back-up which was created BEFORE you started making changes you can quickly find yourself in a world of trouble. And, that's just for starters.

For the Mark VI, there was a GE publication titled 'Control System Toolbox for Mark VI.' There is probably something similar for the Mark VIe and ToolboxST. If you are serious about doing this yourself, you should start by MAKING A PROPER BACK-UP OF THE ENTIRE HARD DRIVE!!! Then you should obtain a copy of the aforementioned GE publication for Control System ToolboxST and Mark VIe, and start reading. If you have questions, you can ask here.

I would HIGHLY recommend that AFTER you make a proper back-up of the entire HMI hard drive, you also make a back-up of the device (G1 or whatever it's called in ControlSystem ToolboxST for the gas turbine Mark VIe) in a separate directory, and start making your changes on THAT copy, and doing your saves and Validations and Builds. And once you get to the point you want to download them to test them, do so during a maintenance outage, when the turbine is down and off cooldown. Make sure the original Mark VIe application code is Equal to the code in the panel, and then try downloading application code from the copy you have edited to the Mark VIe and testing your changes. If they work, well, you will have to decide how to proceed from there. (Meaning, will you now continue to use the new application code, or will you make all of the changes you have tested to the original Mark VIe application code and re-download and re-test.)

Hope this helps! I really wouldn't recommend making application code changes without taking a course first, or hiring a knowledgeable person to come and make the changes for you. Then they are responsible for resolving any problems--and there can be lots of problems--LOTS of problems.

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

Dear CSA & Esoteric,

Please find my replies into the brackets.
Apologize for include the whole things (your replies)!!!

I don't understand how you can keep saying that you want to get the unit to hold a steady load at 50.0 Hz, when you now say the grid frequency won't be at 50.0 Hz for even one minute.

(Actually I am not expecting steady load but what I am expecting is an amount of Load that is consistent in the same frequency level i.e. if load is 98MW at 50.0HZ frequency for one time so whenever 50.0HZ frequency appear the unit would be 98MW(that's my expectation)!!)

99 MW is pretty close to 117.9 MW, and if the units are exhausting into HRSGs (boilers) then they are probably operating on IGV exhaust temperature control, and that means the exhaust temperature is already at the maximum limit even though the IGVs are not fully open and the unit is not at Base Load (the definition of Base Load is when the IGVs are at maximum operating angle and the actual exhaust temperature is equal to the exhaust temperature reference/limit). When the grid frequency (and, therefore, unit speed--and axial compressor speed) is oscillating it's going to mean the load is going to be limited to less than normal (normal being at 50.0 Hz continuous operation) when the grid frequency is below 50 Hz because the exhaust temperature is already at maximum and if the air flow through the unit is dropping because the axial compressor speed is dropping the Mark* is going to reduce fuel pretty quickly while the IGVs are going to be trying to open to also help reduce the exhaust temperature. The opposite will happen when the grid frequency is higher than 50 Hz--the Mark* will be trying to put more fuel in the machine and the IGVs will be trying to close to get the exhaust temperature up and the power output will increase above normal.

Now, think about what's going to be happening if the frequency is oscillating above and below 50.0 Hz fairly quickly!
Tell us: when the unit was operating with Pre-Selected Load Control and the grid frequency was unstable was the unit power output more stable? Did you observe the RAISE- & LOWER SPEED/LOAD buttons continually flashing orange and cycling? Operating with Pre-Selected Load Control disabled on Droop Speed Control (FGMO} do you observe the RAISE-& LOWER SPEED/LOAD buttons flashing orange and cycling continuously?

(When we operated/operating on Pre-Select Load control mode the unit load is steadier irrespective of frequency with PFR in off condition. Yes the RAISE- & LOWER SPEED/LOAD buttons were continuously flashing when on Preselect mode.)

I have been in some locations where the grid frequency was unstable for short periods of time<s few minutes, maybe a half-hour), but never continuously and or for longer periods. Sometimes synchronization was "fun" if they were trying to synch during a period of grid frequency instability.

Do you have any Trend Recorder files of unit operation you can share with us? It's possible to record only at 25 Hz (40 msec) as the fastest recording speed, but we could still get an idea of what's happening with the IGVs, exhaust temperature, FSR, TNR, TNH, grid frequency (SFL1), the exhaust temperature (TTXM), the exhaust temperature reference/limit (TTRX), P2 pressure, etc.


(This is another unfortunate case for us. The owner of CCPP did not buy the MarkVI-e with features like historian server rather it can save data when we make trends with parameters and keep running and save manually.)

And that brings up another point (though you still haven't told us what fuel the units are burning): The SRV will be swinging when the grid frequency is oscillating which means the P2 pressure will also be oscillating which will just add to the chaos of the moment.

(The Fuel is Natural gas. Yes SRV is oscillating to maintain P2 pressure.)

If you are asking if there's a way to get the unit to always put out 98 or 99 MW when the grid frequency returns to 50.0 Hz, that sounds like a pretty impossible task if the grid frequency won't be stable at 50.0 Hz for even one minute. Ag6, with IGV exhaust temperature control active at 98 or 99 MW the unit is already at maximum exhaust temperature and with all the other things happening as a result of the grid frequency instability it's really a testament to the Mark* turbine control the unit doesn't trip on exhaust over-temperature with some kind of"regularity."

To get the unit to put out any load setpoint at 50.0 Hz you really have to set the load while the grid frequency is stable at 50.0 Hz for some period of time, or when the grid frequency is not oscillating too much above or below 50.0 Hz. If you can do that a couple of times and record the value that is probably the only way you're going to determine what that turbine speed reference value (TNR) is that will almost always return the output to the same output when the grid frequency does return to 50.0 Hz. But I believe it's going to be a trial-and-error process to determine the TNR value--but determining the TNR value and then using the RAISE- & LOWER SPEED/LOAD buttons to adjust TNR to that same value is going to be the best way to arrive at that desired load if and when the grid frequency ever does get to 50.0 hz
I have one idea: 99 MW out of 117.9 MW would correspond to a TNR of 108.39% for a unit with 10% Droop. You could start your process of deriving the proper TNR by using the RAISE- & LOWER SPEED/LOAD buttons to adjust TNR to 108.39% and observe what happens. BUT, I still maintain the grid frequency would need to settle for at least 30 seconds to a minute to determine if the 108.39% value was close to correct. The IGVs and the fuel control valve(s) and the exhaust temperature have to have some time to come to some equilibrium (settle). But, I think adjusting TNR to approximately 108% would be a good starting point for determining the best value for your site.
Please write back to let us know how setting TNR to approximately 108% works. But if the grid frequency is as unstable as you seem to be telling us, and you are running at 98 or 99 MW with IGV exhaust temperature control active I think it's going to be a difficult task to evaluate if any TNR setpoint is "successful." Best of luck, and keep us informed. I think starting with a TNR of approximately 108% is as good a starting point as any

(I will inform you whenever we implement your idea i.e. 108% TNR.)


CSA
Very good explanation. You are good at explaining things.

Rokan_123
When we choose the pre-select mode the GT load remains constant. If the frequency changes the TNR changes automatically. The preselect mode will keep the TNR-TNH constant. This is how it will keep the load constant because whtn TNR-TNH is constant the fuel admitted to turbine will remain same and so does the power output.
As far as I can understand, one of the reasons the load is different for same frequencies is that when you select the FGMO the frequency is not exactly 50.0 Hz. So everytime the TNR-TNH is different. Can you please check the TNR and TNH for the different scenarios you have mentioned? I guess, in your case TNR will be different and TNH will be same for different scenarios.
I hope it will help.

Esoteric_Stone,
Pre-Selected Load Control is just a very bad way to continuously operate a GE-design heavy duty gas turbine (unless the unit has the GE Primary Frequency Response Option and it is also enabled)--a very bad way. AND, if the grid frequency is unstable it's even a WORSE way to continuously operate the gas turbine.
The GE Primary Frequency Response option effectively disables Pre-Selected Load Control when the grid frequency deviates from rated by some set amount. So, it allows the unit to respond as if it were in Droop Speed Control (Free Governor Mode of Operation)--while the frequency is out of the allowable window.
If the frequency is constantly unstable, it would be pretty much useless; better to just completely cancel Pre-Selected Load Control by clicking on RAISE- or LOWER SPEED/LOAD and let Droop Speed Control (FGMO) operate as it should.
Droop Speed Control has been used for over a hundred years, all around the world, and pretty much without anyone understanding how it works! (It's like closing the light switch and the light coming on. Most people don't have any idea what's involved in making that happen, and keeping it happening!) But, it's a time-tested and proven method for operating power generation prime movers--until GE foisted Pre-Selected Load Control on their Customers.
What I would dearly love to know from rokan_123 is: Why is the grid frequency so unstable? And, has the transmission company's insistence on using FGMO made it any better? What is it about the grid operating conditions that make it so difficult for the transmission company (grid operators) to maintain a stable frequency? Do they know have the ability to directly control generators (using AGC (Automatic Governor Control)? Are the generators constantly and unexpectedly tripping and causing problems? Are there large loads on the grid that unexpectedly start and stop?


(Our current grid company does not operate the grid with all the generators in FGMO.There are several big CCPPs (450MW~300MW) with preselect mode, several engine plants with their base load and some units with FGMO including ours one. And the distribution companies also not follow the grid company. The grid company trying to maintain the grid with FGMO operations of 2500MW out of 10500MW.That may be reason of unstable grid. Moreover, FGMO system incorporates here just one year ago with 2000MW units. One year ago our units were on HSD (and now in gas fuel) and due to that off taker did not include us in FGMO scheme at that time. Now they include our units and according to PPA agreement we have to follow their decision.)

"Back in the day" when utility companies owned and operated most if not all of the power generation assets of their region they were much more able to control loads and frequency--because they could say when to start and stop units, and when to load and unload units. With the advent of cogeneration, de-regulation and independent power producers, the use of more and more solar- and wind power generation, and the tendency of utilities to get out of the power generation business and the increasing use of gas turbine-generators for power generation it seems that grid frequency control has become more and more of an issue, and even a problem. It's a problem which needs to be solved. And, it's an interesting problem to observe being solved.

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

rokan_123,

>(Actually I am not expecting steady load but what I am
>expecting is an amount of Load that is consistent in the
>same frequency level i.e. if load is 98MW at 50.0HZ
>frequency for one time so whenever 50.0HZ frequency appear
>the unit would be 98MW(that's my expectation)!!)

We don't know how you're "measuring" frequency and load. Are you using Trend Recorder? I have noticed there is a slight lag in the output of the load (MW) transducers at times, and I would imagine that is slightly magnified when frequency and load are changing. I also believe that, as has been said, because of the load you are trying to operate at (98 or 99 MW) with IGV exhaust temperature control active and with the SRV oscillating also because of the frequency (speed) oscillations it's going to take 10-30 seconds for things to "settle out" or "settle down" to get a good, stable reading of load and frequency. If you're relying on visual monitoring of load and frequency, realize that there is as much as 1 second of lag time on the CIMPLICITY display, sometimes even more (not too much more, but more, and usually depending on the number of devices on the UDH (Unit Data Highway) and the UDH network traffic (alarms; events; Mark VI data; exciter data; etc.)). With frequency oscillating (and we don't really have any exact data about the periods of oscillation and the magnitude of oscillations) and operating near Base Load with exhaust temperature at the maximum allowable level, the IGVs moving--and with the SRV also oscillating because the frequency (speed) is varying--there's just a LOT going on that needs to settle out for a few seconds anyway to get good readings. BUT, that being said, using Trend Recorder with a high resolution (I would recommend a 40 msec rate for this trend data) would be the best way to judge if the unit returns to a fairly consistent output when frequency "returns" to approximately 50.0 Hz.

>(When we operated/operating on Pre-Select Load control mode
>the unit load is steadier irrespective of frequency with PFR
>in off condition. Yes the RAISE- & LOWER SPEED/LOAD buttons
>were continuously flashing when on Preselect mode.)

So, this is a new twist--the unit has PFR (Primary Frequency Response) which is supposed to over-ride Pre-Selected Load Control and let the unit operate as if it were in FGMO during frequency excursions.... My my. The plot thickeneth. I could imagine that if Pre-Selected Load control were tuned properly AND in conjunction with the frequency excursion periods (if they are at all repeatable) that you might actually see a slightly more stable load. BUT, I can tell you that the Mark* is going to be working VERY hard to achieve that, and the fuel valves and the IGVs are going to also be working hard (the servos and hydraulic actuators) to achieve that. Not that they weren't more or less designed to do that, but I don't think anyone anticipated that near-constant frequency deviations would exist anywhere and have to be dealt with.

>(This is another unfortunate case for us. The owner of CCPP
>did not buy the MarkVI-e with features like historian server
>rather it can save data when we make trends with parameters
>and keep running and save manually.)

You can record your own Trends using Trend Recorder in ToolboxST--AND the resolution of the trends (as fast as 40 msec!) will be MUCH higher than a GE Historian would provide.

>(The Fuel is Natural gas. Yes SRV is oscillating to maintain
>P2 pressure.)

This isn't helping the issue.

>(I will inform you whenever we implement your idea i.e. 108%
>TNR.)

Thank you, but--again: You need to be using sound measurement and recording methods (such as ToolboxST Trend Recorder) when assessing the success of the attempt.

Please record the following signals (at a minimum):

TNR
TNH
DWATT
CPD
CSRGV
CSGV
FSGR
FPRG
FPG2 (or whatever P2 pressure is called these days in the Mark VIe)
SFL1
TNH_RPM
FSG
FSR
FSRN
FSRT
FSRACC
TTRX
TTXM
Thanks for the information on the grid situation; it's interesting to follow how these things are being handled.

Trend Recorder does not require any special ToolboxST password privilege to access and use. It WILL NOT cause a turbine trip!!! It's easy to configure, and it's a very powerful tool for troubleshooting and understanding unit operation. You just want to make sure that when you are setting it up that you choose a sufficiently high resolution, and for this effort I would recommend 40 msec. You don't need to run it for long to get meaningful data, I would say 5 minutes for the first attempt. You can post the .trn file to a web hosting site (like www.tinypic.com, or some place like Google Drive) and then post a link to the location on a response to this thread so we can download it and analyze it. There's NOTHING like good hard, actionable data--and there's nothing like Trend Recorder for getting that data!

If you have questions about setting up Trend Recorder, just ask them here. It's really very simple, but like everything--it takes some time to become familiar with it. But, I guarantee, once you do you will use it for lots of things! It really is just about the best feature of the Mark VIe--and it's very under-utilized.

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

Dear CSA,

Thank you very much.
I will get back to you soon after collecting all the data.

Regards,
Rokan

Dear CSA,

Please find the picture of our Gas Turbine Control console at
http://feed3.tinypic.com/rss.php?u=56NdKG8Rc120nEpCSLzMkA%3D%3D.

The picture was taken when the unit in FGMO.
Will get back to you with the data.

Regards,
Rokan

rokan_123,

The plot thickens even more....

That unit has some very unique features I have NEVER seen before. You are going to have to work with the supplier of the unit (GE; BHEL) to understand what is going on. I suspect that more than one feature is enabled when only one should be, OR that the parameters need some kind of tuning.

Did GE provide any kind of documentation, description, operating instructions for those features? If so, can you share it/them?

It's normal for people who only have experience with one GE-design heavy duty gas turbine installation to believe that all similar GE-design heavy duty gas turbine installations are similar or the same. I should have considered (and did--but kind of just "let it go") that the unit control was unique when you mentioned the 10% Droop.... My bad; I'm sorry.

Although I'd like to be of more help, I can't without being able to look at the application code running in the Mark VIe. And, I'm guessing you probably have Version 5 or greater of ToolboxST--and I don't have a dongle that would allow me to look at that code. So, as much as I would REALLY like to help with this problem, I'm afraid I can't (without being able to obtain a copy of your application code, and without being able to spend time (probably more than I honestly have) reviewing the code to be able to provide any more help and suggestions.

I would still like to see the Trend Recorder data, but, I'm afraid there's so much unique stuff possibly going on that even if all those options were, indeed, disabled there is a very real possibility that there is some unintended "cross-talk" between these functions and pure Droop Speed Control (FGMO) that anything I might add would only make the situation worse.

I highly recommend you get someone out from the supplier (GE; BHEL) who either has experience with this system or has access to the PAC os some kind of Product- or Customer Service that can get the programmer who wrote the application code to help with troubleshooting or even just understanding the functions shown on the display picture you posted (thank you for that!!!).

I'm very sorry I can't be of more help! And, in the next month or so my work deliverables are going to keep me VERY busy, so I really can't devote too much more time to this right now.

I would love to know how this all works out!!!