We can limit the minimum load for gas turbine at combined cycle when we active the primary fre

 

Hamada ramadan,

It's my understanding of the GE PFR (Primary Frequency Control) that there is no way to limit the minimum load. There may be some unusual or new logic/sequencing/application code, but when the grid frequency is unstable there is no way to limit the frequency excursions of the generator (and speed excursions of the turbine) nor is there any way to limit the changes in load. And, to be honest, doing so would be the opposite of what needs to happen when the grid frequency is not stable. One of the main concepts of Droop Speed Control is that it varies the fuel flow-rate (to gas turbines) as necessary to help support grid stability when the frequency is higher or lower than nominal. A failure to do so can result in black-outs, which are bad for everyone--the consumers of electricity as well as the producers.

EVERYONE wants the output of their turbine-generator to be stable and not change when the grid frequency is unstable--but that's just not the way AC power generation and Droop Speed Control work. That's not the way they are designed or implemented. And trying to hold output constant, or prevent dropping below a certain value--especially with turbines equipped with DLN combustors--is not good for the grid or for the turbines.

If you could explain a little more about your situation (because your original post is unfinished), we might be able to understand things a little better.

You should know that most people want to operate their GE-design heavy duty gas turbine in Pre-Selected Load Control mode--because they FALSELY believe if they don't the unit load will drift up and down "uncontrollably" and unit load will NOT remain stable (when the grid frequency is stable). Some grid operators and utility regulators have come to learn that operating in Pre-Selected Load Control at ALL times will prevent the unit from properly responding to grid fluctuations and actually contribute to grid instability, worsening the situation, by trying to maintain a stable load when frequency is more or less than rated or is fluctuating. The grid operators and utility regulators have, in many places in the world, decreed that Pre-Selected Load Control cannot be used at all times when synchronized to a grid. So, GE developed PFR (Primary Frequency Response) which detects frequency excursions while operating in Pre-Selected Load Control and allows the unit to properly respond to grid frequency disturbances. It's not an ideal situation, nor is it the best solution.

Pre-Selected Load Control was never designed to be used to operate GE-design heavy duty gas turbine at all times when producing power; it was designed as a way for the operator to input a desired load setpoint and let the turbine control system load (or unload) the unit in a smooth ramping fashion until the desired load was achieved, and then it should be disabled. Because, as long as the grid frequency remains stable the gas turbine-generator power output is going to remain stable--without Pre-Selected Load Control. However, when grid frequency deviates from nominal it is because of some imbalance in load and/or generation and if generators and their prime movers don't respond appropriately then, as was written, it can lead to black-outs. Pre-Selected Load Control, if left enabled and active--without PFR!!--over-rides Droop Speed Control. Worse, there is fighting between Pre-Selected Load Control and Droop Speed Control, which is one of several reasons that operating with Pre-Selected Load Control enabled and active--without PFR!!--actually worsens grid frequency problems.

To synchronize and operate multiple generators and their prime movers to a grid it is necessary for them to be operated in Droop Speed Control--this is the governor mode that allows multiple units of all sizes and capabilities to stably operate in parallel with each other when synchronized to a grid. It has been so since the beginning of AC power generation, transmission and distribution. People who believe (falsely) that their generator output should remain stable while the grid their generator and prime mover are synchronized to is unstable simply do not understand basic AC power generation fundamentals and live in an alternate world. It just doesn't work that way, and to even have a chance of stabilizing an unstable grid it is necessary for generators and their prime movers to respond and vary their output as necessary. It's physics and maths--and it can't be changed for one unit, or two or seven.

If the power plant where you work supplies a process plant independently of the grid, or exports a small amount of power to the gird while supplying an independent load (usually called an "island"), there are ways to mitigate the effects of grid frequency disturbances (they are not always desirable or easy--but there are some things which could be done depending on the situation). But, again, your original post was cut short, and we don't know the entire situation. But if you're attempting to ask if the minimum load of a gas turbine-generator operating with Pre-Selected Load Control AND PFR (Primary Frequency Response) enabled and active during grid frequency disturbances, the most probable answer is no, not with typical logic/sequencing/application code. And, probably not even with unique logic/sequencing/application code. If the GT load drops excessively and opens the generator breaker, or even results in flame-out of the gas turbine, then I would suggest some of the protective relay settings need to be checked and adjusted to prevent that, maybe even tripping the generator breaker open proactively.

Hope this helps!

 

Hamada ramadan,

It's my understanding of the GE PFR (Primary Frequency Control) that there is no way to limit the minimum load. There may be some unusual or new logic/sequencing/application code, but when the grid frequency is unstable there is no way to limit the frequency excursions of the generator (and speed excursions of the turbine) nor is there any way to limit the changes in load. And, to be honest, doing so would be the opposite of what needs to happen when the grid frequency is not stable. One of the main concepts of Droop Speed Control is that it varies the fuel flow-rate (to gas turbines) as necessary to help support grid stability when the frequency is higher or lower than nominal. A failure to do so can result in black-outs, which are bad for everyone--the consumers of electricity as well as the producers.

EVERYONE wants the output of their turbine-generator to be stable and not change when the grid frequency is unstable--but that's just not the way AC power generation and Droop Speed Control work. That's not the way they are designed or implemented. And trying to hold output constant, or prevent dropping below a certain value--especially with turbines equipped with DLN combustors--is not good for the grid or for the turbines.

If you could explain a little more about your situation (because your original post is unfinished), we might be able to understand things a little better.

You should know that most people want to operate their GE-design heavy duty gas turbine in Pre-Selected Load Control mode--because they FALSELY believe if they don't the unit load will drift up and down "uncontrollably" and unit load will NOT remain stable (when the grid frequency is stable). Some grid operators and utility regulators have come to learn that operating in Pre-Selected Load Control at ALL times will prevent the unit from properly responding to grid fluctuations and actually contribute to grid instability, worsening the situation, by trying to maintain a stable load when frequency is more or less than rated or is fluctuating. The grid operators and utility regulators have, in many places in the world, decreed that Pre-Selected Load Control cannot be used at all times when synchronized to a grid. So, GE developed PFR (Primary Frequency Response) which detects frequency excursions while operating in Pre-Selected Load Control and allows the unit to properly respond to grid frequency disturbances. It's not an ideal situation, nor is it the best solution.

Pre-Selected Load Control was never designed to be used to operate GE-design heavy duty gas turbine at all times when producing power; it was designed as a way for the operator to input a desired load setpoint and let the turbine control system load (or unload) the unit in a smooth ramping fashion until the desired load was achieved, and then it should be disabled. Because, as long as the grid frequency remains stable the gas turbine-generator power output is going to remain stable--without Pre-Selected Load Control. However, when grid frequency deviates from nominal it is because of some imbalance in load and/or generation and if generators and their prime movers don't respond appropriately then, as was written, it can lead to black-outs. Pre-Selected Load Control, if left enabled and active--without PFR!!--over-rides Droop Speed Control. Worse, there is fighting between Pre-Selected Load Control and Droop Speed Control, which is one of several reasons that operating with Pre-Selected Load Control enabled and active--without PFR!!--actually worsens grid frequency problems.

To synchronize and operate multiple generators and their prime movers to a grid it is necessary for them to be operated in Droop Speed Control--this is the governor mode that allows multiple units of all sizes and capabilities to stably operate in parallel with each other when synchronized to a grid. It has been so since the beginning of AC power generation, transmission and distribution. People who believe (falsely) that their generator output should remain stable while the grid their generator and prime mover are synchronized to is unstable simply do not understand basic AC power generation fundamentals and live in an alternate world. It just doesn't work that way, and to even have a chance of stabilizing an unstable grid it is necessary for generators and their prime movers to respond and vary their output as necessary. It's physics and maths--and it can't be changed for one unit, or two or seven.

If the power plant where you work supplies a process plant independently of the grid, or exports a small amount of power to the gird while supplying an independent load (usually called an "island"), there are ways to mitigate the effects of grid frequency disturbances (they are not always desirable or easy--but there are some things which could be done depending on the situation). But, again, your original post was cut short, and we don't know the entire situation. But if you're attempting to ask if the minimum load of a gas turbine-generator operating with Pre-Selected Load Control AND PFR (Primary Frequency Response) enabled and active during grid frequency disturbances, the most probable answer is no, not with typical logic/sequencing/application code. And, probably not even with unique logic/sequencing/application code. If the GT load drops excessively and opens the generator breaker, or even results in flame-out of the gas turbine, then I would suggest some of the protective relay settings need to be checked and adjusted to prevent that, maybe even tripping the generator breaker open proactively.

Hope this helps!

Thank you for reply

 

Hamada ramadan,

It's my understanding of the GE PFR (Primary Frequency Control) that there is no way to limit the minimum load. There may be some unusual or new logic/sequencing/application code, but when the grid frequency is unstable there is no way to limit the frequency excursions of the generator (and speed excursions of the turbine) nor is there any way to limit the changes in load. And, to be honest, doing so would be the opposite of what needs to happen when the grid frequency is not stable. One of the main concepts of Droop Speed Control is that it varies the fuel flow-rate (to gas turbines) as necessary to help support grid stability when the frequency is higher or lower than nominal. A failure to do so can result in black-outs, which are bad for everyone--the consumers of electricity as well as the producers.

EVERYONE wants the output of their turbine-generator to be stable and not change when the grid frequency is unstable--but that's just not the way AC power generation and Droop Speed Control work. That's not the way they are designed or implemented. And trying to hold output constant, or prevent dropping below a certain value--especially with turbines equipped with DLN combustors--is not good for the grid or for the turbines.

If you could explain a little more about your situation (because your original post is unfinished), we might be able to understand things a little better.

You should know that most people want to operate their GE-design heavy duty gas turbine in Pre-Selected Load Control mode--because they FALSELY believe if they don't the unit load will drift up and down "uncontrollably" and unit load will NOT remain stable (when the grid frequency is stable). Some grid operators and utility regulators have come to learn that operating in Pre-Selected Load Control at ALL times will prevent the unit from properly responding to grid fluctuations and actually contribute to grid instability, worsening the situation, by trying to maintain a stable load when frequency is more or less than rated or is fluctuating. The grid operators and utility regulators have, in many places in the world, decreed that Pre-Selected Load Control cannot be used at all times when synchronized to a grid. So, GE developed PFR (Primary Frequency Response) which detects frequency excursions while operating in Pre-Selected Load Control and allows the unit to properly respond to grid frequency disturbances. It's not an ideal situation, nor is it the best solution.

Pre-Selected Load Control was never designed to be used to operate GE-design heavy duty gas turbine at all times when producing power; it was designed as a way for the operator to input a desired load setpoint and let the turbine control system load (or unload) the unit in a smooth ramping fashion until the desired load was achieved, and then it should be disabled. Because, as long as the grid frequency remains stable the gas turbine-generator power output is going to remain stable--without Pre-Selected Load Control. However, when grid frequency deviates from nominal it is because of some imbalance in load and/or generation and if generators and their prime movers don't respond appropriately then, as was written, it can lead to black-outs. Pre-Selected Load Control, if left enabled and active--without PFR!!--over-rides Droop Speed Control. Worse, there is fighting between Pre-Selected Load Control and Droop Speed Control, which is one of several reasons that operating with Pre-Selected Load Control enabled and active--without PFR!!--actually worsens grid frequency problems.

To synchronize and operate multiple generators and their prime movers to a grid it is necessary for them to be operated in Droop Speed Control--this is the governor mode that allows multiple units of all sizes and capabilities to stably operate in parallel with each other when synchronized to a grid. It has been so since the beginning of AC power generation, transmission and distribution. People who believe (falsely) that their generator output should remain stable while the grid their generator and prime mover are synchronized to is unstable simply do not understand basic AC power generation fundamentals and live in an alternate world. It just doesn't work that way, and to even have a chance of stabilizing an unstable grid it is necessary for generators and their prime movers to respond and vary their output as necessary. It's physics and maths--and it can't be changed for one unit, or two or seven.

If the power plant where you work supplies a process plant independently of the grid, or exports a small amount of power to the gird while supplying an independent load (usually called an "island"), there are ways to mitigate the effects of grid frequency disturbances (they are not always desirable or easy--but there are some things which could be done depending on the situation). But, again, your original post was cut short, and we don't know the entire situation. But if you're attempting to ask if the minimum load of a gas turbine-generator operating with Pre-Selected Load Control AND PFR (Primary Frequency Response) enabled and active during grid frequency disturbances, the most probable answer is no, not with typical logic/sequencing/application code. And, probably not even with unique logic/sequencing/application code. If the GT load drops excessively and opens the generator breaker, or even results in flame-out of the gas turbine, then I would suggest some of the protective relay settings need to be checked and adjusted to prevent that, maybe even tripping the generator breaker open proactively.

Hope this helps!

In combined cycle mode
What the reasons of low exhaust temperature for some of gas turbine ?
GT#1. 1029°F at 90MW
GT#2. 1070°F at 90MW
.............................…......................
GT#1. 1080°F at 100MW
GT#2. 1080°F at 100MW
So I ask to limit the load

 

Hamada ramadan,

We are not there beside you, and I don't want to be guessing at what you want or are trying to ask.

A LOT of people (engineers and plant managers, in particular) have this (false) idea that two (or more) turbines sitting next to each other on the same site will most always have similar operating characteristics, including output and exhaust temperature. Not so. Unless all of the machines undergo maintenance outages at precisely the same time, and all machines have the same air filter cleanliness, and all machines have the same IGV LVDT calibration, and all machines have the same degree of compressor cleanliness/fouling, and all machines have the same amount of air leakage into the combustors and nozzle side seals, and all machines have the same wear on the turbine nozzles and buckets and shrouds, and all machines have the same amount of exhaust duct back-pressure, and--in today's world--all machines have precisely the same exhaust temperature control parameters, along with tens of other intangibles (including cooling and sealing air flows, etc.) the machines ARE NOT going to behave identically. Add to this DLN tuning (if the units have DLN combustors--something we don't know about the machines at your site unless you tell us, eh?), and that's even another intangible. In today's world, when machines are commissioned many of them undergo performance tests and also have their performance characteristics adjusted to optimize machine performance and parts life--each machine on a multi-unit site.

And there's also the condition of the HRSG--which can have a lot to do with exhaust duct back-pressure and machine performance and operation (think of how easy it is to breathe through a face mask .... IN and OUT). Some HRSGs have auxiliary duct burners (auxiliary firing); some have ammonia injection; etc.). Sometimes insulation gets loose from behind insulated walls/ducts and plugs the super heater section.

So, unless you can quantify all of these factors for any two (or more) machines, even ones sitting side by side (one might be next to a busy road, with lots of lorries, with exhaust soot and/or road dust--so the inlet air filters may be dirtier, and get dirtier faster).

The differences you listed aren't much--unless, of course, you are trying to maximize steam production, in which case, you are playing a losing game, my friend. You will be "tweaking" things forever, and "un-tweaking" them after maintenance outages, and "tweaking" them again--but to different degrees (no pun intended).

Your original post was about limiting load with PFR. Without being able to see the application code/programming in the turbine control systems it's impossible to say if GE Belfort (or BHEL--whomever the packager/supplier was) was aware of this requirement and tried to add it to the turbine control system and added it to the control system. As was written, it's not possible with the normal, typical PFR.

You could probably have someone write some code/program to control to an exhaust temperature setpoint (when not operating at Base Load)--but then you wouldn't always get the same outputs, and that will engender this same question: Why the difference(s)? You get to control one parameter (if you have the ability to control exhaust temperature at part load--and with DLN machines that's probably NOT going to happen at all...), and you'll have to learn to live with the other. Controlling load to control exhaust temperature--probably possible, but it probably wouldn't be pretty or very stable (for load or exhaust temperature). Your site seems to want to operate near Base Load, but not at Base Load (probably because they are trying to maximize power output without exporting too much power), and now someone wants to ALSO control exhaust temperature at Part Load. That would best be done with the IGVs--but as was said (and you haven't told us!)--if the unit have DLN combustors that's probably not really likely, though if anyone would attempt it it would be GE Belfort (and I wouldn't want to see that code/programming.... the word ugly comes immediately to mind).

So, I guess I have actually tried to guess at what you want--and if I didn't, it's not my fault. Tell us what you want to do (and forget about PFR) and we can try to help.

Just remember, we can't read your mind, nor can we know or see what you see about your site and the conditions and equipment. Contrary to VERY popular (and VERY false) belief--every GE-design Frame 9E heavy duty gas turbine is NOT like every other GE-design Frame 9E heavy duty gas turbine. Sure, they're Frame 9Es, and they suck and squeeze and burn and blow--just like every other gas turbine made by any manufacturer--but the similarities and operating characteristics pretty much end there (at the name). Auxiliaries, and fuels and programming and combustion systems are NOT the same, and neither are sites (locations; ambient conditions; elevation; etc.).

Best of luck!