1-We have a Gas Turbine GE Frame -5 MS-5341. SRV control loop working with P2 value and reference value from control system Mark-VI. What happened if P2 Fail? Is SRV will shift to position control loop? Or How it control the speed as it is speed ratio and stop valve?
2- If CPD fails GT selects the maximum value of 10kg/cm2. Then what happen on TTRX( exhaust temperature control limit)? Is TTRX increase or decrease?
Any calculation method to measure TTRX?
3- How Isochronous and Droop Governor control works? How they share load? As once our GT trip and breaker open the other generator is on droop mood will reach to the frequency 54.34HZ and turbine will trip on reverse power relay actuation.How these two share load?

 

@MRA,

1) The SRV does not control speed; the GCV controls speed.

2) I don’t recall the Mark VI shifting to a maximum value on loss of CPD feedback. And 10 kg/cm2 is a very high value for a Frame 5 in my experience. Can you post a picture of the block that makes the selection of a MAX value on loss of CPD feedback?

3) Your definition of the scenario is incomplete. You must define the mode of each GT when they are operating together (synchronized; paralleled) and the load the GTs are supplying BEFORE one GT trips and the load remaining GT is carrying after one GT trips. You must also tell us if there is some kind of external load/frequency control system that sends signals to the GTs to raise or lower load and what mode to operate in and possibly if the external system can disconnect (“shed”) load if necessary. Sometimes the external load/frequency control system is called a PMS (Power Management System).

The topics of Droop- and Isoch Speed Control have been discussed MANY times on Control.com. Use the Search feature of Control.com to find LOTS of threads; you may have to read several threads to find precisely what you are looking for but you will learn something in each thread you read.

 

1- What will happen if P2 downstream of SRV fails?

 

@MRA,

1) To be completely accurate it would be necessary to see the application code running in the Mark VI. And, are you suggesting the gas fuel supply pressure decreases OR the P2 pressure transmitter fails in its predominant failure mode which is to have zero output to the Mark VI?

In general if the machine is running at Part Load (some load between 0 MW and Base Load) and the gas fuel supply pressure falls to some value less than the P2 pressure reference, signal FPRG (Fuel Pressure-Reference, Gas), the SRV will open to try to maintain the P2. If the P2 pressure can’t be maintained then the machine will start to lose load. If the machine is operating in Droop Speed Control and AUTO governor mode with Pre-Selected Load Control enabled the GCV will open to try to maintain the Pre-Selected Load Control reference. If gas fuel supply pressure continues to decrease there will be insufficient fuel to maintain flame and the machine will trip on LOSS OF FLAME. This explanation presumes the machine does NOT have liquid fuel capability and the ability to transfer to liquid fuel on low gas fuel supply pressure.

In general the same scenario might also apply to loss of P2 pressure feedback—the Mark* would send the SRV open because it would think there was no P2 pressure and this would probably happen very quickly if the P2 pressure feedback dropped suddenly. This could cause the GT exhaust temperature to spike and result in an EXHAUST OVERTEMPERATURE Alarm and possibly Trip. If the machine didn’t trip the SRV would be mechanically fully open which is NOT a good condition. The Mark* VI application code may have some limitations on SRV opening, but it would be necessary to review the application code in the Mark* VI to be sure.

I hope you can understand that the question as you have asked it is very vague and difficult to answer. Every GE-design Frame 5 heavy duty gas turbine IS NOT exactly like every other GE-design Frame 5 heavy duty gas turbine. They can burn one or more fuels; they can have different application code running in the Mark* turbine control system; they might or might not have a remote load control reference; and they may or may not use Pre-Selected Load Control. The description above is from decades of experience with GE-design heavy duty gas turbines burning natural gas fuel using what was standard control and protection schemes for those decades. The control and protection schemes were proven, tried and tested. As different divisions of GE have been given responsibility for the control and protection of different Frame sizes and types of machines the control and protection schemes are undergoing change. So, without being able to review the application code running in the machines at your plant it is nearly impossible to say with any degree of certainty how the machines at your plant are configured to operate. Especially when the questions being asked are incomplete and there are many things we don’t know—and cannot know if you don’t tell us. We can ask lots of questions but historically many people don’t like to answer the questions, and choose to answer only a couple of questions rather than all of them. All GE-design heavy duty gas turbines suck, squeeze, burn and blow (they draw (suck) air into an axial compressor; they compress (squeeze) the air; they mix fuel with the air and burn the fuel-air mixture; and they exhaust hot gases at a relatively low pressure (blow) to the atmosphere or a boiler). But there are many different types of control and protection schemes and control and protection philosophies and fuels and auxiliaries and applications. So we do what we can to try to answer questions based on the information provided. Sometimes we ask a lot of questions to demonstrate the complexity of the systems and control and protection schemes and applications but that doesn’t seem to be good enough and people don’t answer most of the questions, if any at all.

Help us to help you by telling us as much as you can about the machine and how it’s being operated, and external control systems it might interface or communicate with, or receive commands from; what kinds of secondary fuels the machine might burn; what modes (speed control and operating modes (AUTO; REMOTE), if the machines exhaust to atmosphere or a boiler (HRSG); what kind of combustion system (conventional; DLN (Dry Ow NOx); if the machines have Water- or Steam Injection for emissions reduction; etc.). If you have an issue you have been troubleshooting and are asking for help with tell what has been done to try to resolve the issue. AND, VERY IMPORTANTLY, tell us what alarms—BOTH Process AND Diagnostic Alarms are active when the condition is occurring—even if you don’t think the alarms are relevant. We can help—but we can provide the most concise and effective solutions if we know as much as we can about the situation and the alarms and what has been done to try to resolve the problem.

 

@MRA,

2) TTRX (Turbine Temperature-Reference, Exhaust) is the calculated value of the hot gases leaving the first-stage turbine nozzles (on a Frame 5 it might be the temperature of the hot gases entering the first-stage turbine nozzle--your machine may or may not have air-cooled first-stage turbine nozzles). This is often called 'firing temperature' which is something of a misnomer because the temperature of hot combustion gases where the fuel is burning is often MUCH higher that the temperature of gases entering or leaving the first-stage turbine nozzle. Machines with conventional combustors use air entering the combustion liners through slots and holes in the liners to cool the hot gases (which can be around 3000 deg F) to something cooler which will not damage the turbine section (nozzles and buckets). Machines with DLN combustors use a very lean fuel/air mixture (bordering on unstable flame) to burn the fuel at a very low temperature that is then passed to the turbine section. This low temperature burning reduces the formation of NOx--an air pollutant--in the gas turbine exhaust.

This temperature (of the gases entering/leaving the first stage turbine nozzles) cannot be accurately measured (though technology is changing quickly!), but GE through decades of experimentation in a combustion laboratory and also by gathering data from running machines in the field has learned how to use actual gas turbine exhaust temperature and axial compressor discharge pressure to approximate (by calculation) the 'firing temperature' in order to protect the turbine section AND to optimize power output (torque--which the generator converts to amperes when supplying a load or loads). The calculated approximate value of the hot gases entering/leaving the first-stage turbine nozzles is then used as a limit to prevent damaging the turbine section with excessively hot combustion gases.

TTRX is continuously calculated--even when the machine is not running. It can limit fuel flow during starting and acceleration (if the actual gas turbine exhaust temperature, signal TTXM, exceeds TTRX) and it is used when the machine is operating at Base Load (and/or Peak Load if the machine has that capability). The topic of TTRX has also been covered many times on Control.com and can be found using the Search feature of Control.com.

I'm guessing (because I don't recall ever seeing the Mark* switch to a Control Constant value of CPD if the CPD transmitter input drops below some level. I may be wrong, and I have been wrong before, but as I write this I don't have access to any application code and I do not recall the scheme. I know that when the CPD feedback drops below a certain level there is a Process Alarm and I think some other action(s) might also be initiated to prevent damage to the machine while still allowing it to operate without damage, but probably limiting the output somewhat.

But that's my recollection of TTRX's function and how it might operate in the absence of CPD feedback.

3) I'm going to discuss the roles and some of the functions of Isochronous and Droop Speed Control--but I'm going to preface my writing by saying that in the examples below there is NO PMS or similarly functioning system controlling the frequency of the system/grid in the examples. Just "plain" Isochronous Speed Control and Droop Speed Control. That's it. It will all seem a little counter-intuitive at first (you will think I don't know of what I write) but if you read it, and re-read it and keeping reading it and re-reading it it should begin to make sense. One thing to remember about AC (Alternating Current) systems: maintaining system/grid frequency is VERY important. AND, when the amount of power being supplied to the grid exactly matches the amount of power being consumed the loads of the grid--then the system/grid frequency will be at or very near rated. If the load on the system/grid increases with no changes by the machines on the grid, or if one of the machines on the grid trips off the grid (or is shut down), the system/grid frequency will decrease--the AMOUNT of load being produced will not change but the system/grid frequency will change (decrease). Conversely, if the load on the system/grid decreases, or another generator is synchronized to the system/grid and increases its power (load), then the system/grid frequency will increase (presuming no changes are made to the machines synchronized to the grid). It's all a balancing act--a very delicate balancing act, like a ballet, almost. Finally, contrary to popular belief Isochronous Speed Control of a machine synchronized with one or more other machines IS NOT entirely automatic. It requires constant monitoring and attention--and that should come from trained, and hopefully experienced, operators (or system/grid regulators). This is one of the reasons PMSs (Power Management Systems) exist because of the myth of fully automatic Isochronous Speed Control of system/grid frequency. And because the concepts of Isochronous and Droop Speed Control are so misunderstood even in the power generation industry many PMSs are not fit for function and do not work very well. Or, the problems with the PMS are known and can be anticipated by humans (if they're paying attention). So, here we go. It's a long read, but it's also a difficult subject to describe properly. Much of what is written in textbooks and reference books and even university graduate study papers is poorly described it's no wonder that it's such a misunderstood subject. Droop Speed Control is ingeniously simple, yet very complicated (especially to describe because it does so many things). Some aspects of AC power generation control just seem so "wrong" at first read, primarily because the conditions for the written description are not properly explained, if at all. But, in all honesty it is very simple. But, it has so many aspects that it covers extremely well it is ubiquitious (present everywhere) in AC power generation and yet very, very misunderstood.

Isochronous Speed Control is intended to be a means of--more or less--maintaining the frequency of a system/grid automatically. If there is just one machine powering a small system/grid that machine would, typically, be operating in Isochronous Speed Control mode--because the prime mover governor (control system) will adjust the fuel flow-rate VERY quickly to any changes in load which have a direct impact of frequency. If load increases on a system/grid, even one with a single machine, the immediate effect on the system will be for the frequency to decrease--but the Isochronous Speed Control function will very quickly sense the change in frequency (because AC generator frequency is is directly related to the prime mover speed) and increase the fuel flow to return and keep the system/grid frequency at normal. If a load stops or is disconnected from the grid/system, the immediate effect on the system/grid will be for the frequency to increase and the Isochronous Speed Control function senses the increase if machine speed (because the frequency increased) and reduce the fuel very quickly to return the frequency to normal and maintain the normal frequency. That's what Isochronous Speed Control does: change the load of the machine so that the machine speed remains near constant as the load(s) the machine is powering increase or decrease. And, Isochronous Speed Control functions DO NOT like to share load with Isochronous Speed Control functions on other machines synchronized to the same system/grid. Two machines (only), both operating in Isochronous Speed Control, will violently fight each other for control of the system/grid frequency--it's ugly and usually leads to blackouts (one or both machines tripping on either excessively high or low frequency, or reverse power). It's a NO-NO--don't do it. Not even once. Unless you have a torch (flashlight in some parts of the world) in your hand or pocket.

If one wants to power an AC (Alternating Current) system/grid with a second generator in parallel with (synchronized to) a single machine operating in Isochronous Speed Control, the machine being "added" to the system/grid must be in Droop Speed Control mode. This machine will operate stably and smoothly, and "knows" its job IS NOT to control frequency--ever--that's the job of the Isochronous Speed Control machine. When the second machine is synchronized to the grid and loaded, to say 5 MW, the load on the Isochronous Speed Control machine will be reduced by 5 MW. If it's desired to increase the load on the Isochronous Speed Control machine the operator REDUCES the load on the Droop Speed Control machine (YES, reduces the load on the Droop Speed Control machine.) So, if the Droop Speed Control machine was operating at 8 MW and the Isochronous Speed Control machine was operating at 3.72 MW and it was decided the Isochronous Speed Control Machine should be operating at 6 MW the operator would decrease the load on the Droop Speed Control Machine by 2.28 MW, to 5.72 MW. The load on the system grid, presuming it's stable and not changing by very much, was 11.72 MW prior to making the change to increase the load on the Isochronous Speed Control machine, and, when the load change was complete, the load on the system/grid was still 11.72 MW. THAT'S how the two machines "share" load--and the system/grid frequency remains at or very near normal. The amount of power being produced equals (matches) the amount of power being produced at the rated frequency. THAT'S load-sharing.

On an AC transmission and distribution system ALL of the loads (electric motors; lights; tea kettles; fans, refrigerators; air conditioners; televisions; radios; computers and computer monitors; etc.) appear as a single load. If that load is larger than any single generator could supply then multiple machines are added to the system/grid--called synchronizing, or paralleling--all acting as one single generator to supply one single load (which is really a lot of individual loads). ALL of the generators MUST run at what's called their synchronous speed (the speed that corresponds to the rated grid frequency) to supply the same frequency to EVERY load of every size. And, they do.

Technically, there would be one large generator and its prime mover always operating in Isochronous Speed Control on a system or grid of any size--even huge, called infinite, systems/grid. But, that's not always the case. The system/grid regulators work to manage all of the generators (now including solar power and wind power) to keep the grid running at or very near rated frequency. It's a big job--especially considering that the "load" changes throughout the day, and the week, and the month, and the years. Their job is to try to anticipate normal expected changes in load (like when everyone wakes up in the morning and turns on their TV/radio and tea kettle and maybe their computer), and factories start production, and then end production and everyone turns out the lights and turns off the TV and the computer and goes to sleep--just to repeat it all again, day after day, week after week, month after month, year after year.

BUT the thing is that EVERY generator and it prime mover synchronized together with other machines and their prime movers on a system/grid runs in Droop Speed Control--unless there is one Isochronous Speed Control machine running somewhere on that system/grid. And only one Isochronous Speed Control machine. Droop Speed Control is a LOT of things--but most importantly, it allows multiple generators and their prime movers to be synchronized together and provide smooth stable power from each of the machines regardless of what is happening to the system/grid frequency (well, almost regardless--but that's not going to be discussed in this thread). Without Droop Speed Control, there would have to be some other method of controlling the energy flow-rate into prime movers to control the electrical power out of the generators the prime movers drive and do so smoothly and stably without any fighting or load swings (caused by the governors fighting each other).

Droop Speed Control does a LOT of other things--but its most important function is to allow multiple machines to "play nicely" together--to SHARE LOAD--to power a load that is MUCH larger than any single generator and its prime mover could power. The other functions are very important, too, but the "load sharing" feature of Droop Speed Control is THE MOST important one.

Now, if we continue with the example above of one machine in Isoch and a second in Droop, synchronized together on a system/grid without any other machines, if the Droop machine trips and the load that was being supplied by the Droop machine can be "absorbed" by the Isoch machine, then there will probably be a little bounce in the system/grid frequency, but it should stabilize quickly and remain stable.

However, if the Isoch machine tripped leaving only the Droop machine to power the system/grid, then the grid frequency is going to change. The Droop machine will try to power the load(s) on the system/grid by changing the energy flow-rate into the Droop machine's prime mover BUT if the load on the Droop machine increased because of the loss of the Isoch machine the system/grid frequency will decrease below rated--and stay there until a trained operator responds appropriately to return the system/grid frequency to normal. And as long as the machine remains in Droop Speed Control it will be the operator who has to manually adjust the load of the Droop machine to maintain system/grid frequency. Again, because it's NOT the job of Droop Machines to control frequency--it's the job of an Isoch machine OR the system/grid regulators (in this example, a human operator).

 

The Stop Ratio Valve (SRV) is modulating in response to TNH (turbine speed), whereas the Gas Control Valve (GCV) is controlled by the Fuel Stroke Reference (FSR) and P2 pressure feedback.
If the control system is TMR (Triple Modular Redundant), P2 is the median value selected from the three pressure transmitters.
In the event of a CPD (Compressor Discharge Pressure) signal failure, the control system defaults to a predefined FSR (Fuel Stroke Reference) curve to maintain safe turbine operation and avoid instability