our gas turbine control system is mark-iv. so when the grid frequency goes downward for same load, the turbine goes to temperature control mode and then TTXC/TTXM is equal to TTRXB. so now I want to know that if turbine goes to temperature control mode then it is bad for turbine or not? if yes, then what should we do for that condition? what happens in temperature control mode? how can increase the value of TTRXB so that turbine reaches that value of TTRXB for more time. please give me the details about temperature control system and above question.

 

Temperature control system is using in GE turbine to protect turbine hot gas path equipment. Gas turbine load is regulating according to TTFR1 ( turbine first stage inlet temperature). However, control system cannot measure this temperature directly. Instead of this, Mark V system calculates this temperature by using compressor discharge pressure, exhaust temperature and air inlet temperature.

TTXM value is average of exhaust thermocouples. CDP is compressor discharge pressure measuring by three pressure transmitters.

MarkV calculates TTRF1 value and adjust the generator output by using this value. If TTRF1 reaches to unsafe value, control system decreases gas flow to reduce TTXM value and in the same time TTRF1 value. TTXB is also a calculated value by control system. It means the base load exhaust temperature in actual atmosphere condition. When TTXM reaches to TTXB temperature, it means turbine at base load. Above this point is dangerous for turbine parts. TTXB value should not be changed.

 

A Speedtronic turbine control system calculates an exhaust temperature reference, TTRX, based on axial compressor discharge pressure. This exhaust temperature reference represents constant firing temperature, which for many machines with air-cooled first stage turbine nozzles is the temperature of the combustion gases leaving the stationary first stage turbine nozzles and impinging on the rotating first stage turbine buckets. This is the optimum temperature for power output and hot gas path parts life. (For units without air-cooled first stage turbine nozzles, firing temperature is deemed to be the temperature of the hot gases entering the stationary first stage turbine nozzles.)

As axial compressor discharge pressure increases more fuel can be burned for the same firing temperature. As axial compressor discharge pressure decreases less fuel can be burned for the same firing temperature.

TTRF1 is only used as a "switch" for changing combustion modes on DLN combustor-equipped machines. TTRF1 is another extremely poorly named signal in GE's control scheme. It's not really <b>"the"</b> firing temperature. It's properly the 'combustion reference temperature' which is really nothing more than an approximation of average combustion gas temperature, but the signal is not used for anything other than as a switch for changing combustion modes. As the combustion reference temperature changes, and increases above or decreases below various setpoints, the combustion mode will change (be switched). While combustion reference temperature is nearly equal to firing temperature, they are not exactly the same value. And again, TTRF1, besides being a poor choice of a mnemonic for a signal name, is just an approximation of combustion gas temperature.

Even if you had a Mark VIe, the newest version of GE's venerable Speedtronic turbine control systems, when the grid frequency decreases your turbine speed, and therefore the speed of the axial compressor, will decrease. If the fuel flow-rate is held constant when the axial compressor speed decreases two things will happen. The first is that axial compressor discharge pressure will go down because the speed of the axial compressor has decreased, which means less air if flowing through the machine.

The second thing that happens when the frequency decreases and the turbine (and axial compressor) speed decreases is that with a constant fuel flow the exhaust temperature will increase because there is less air being pumped by the compressor to cool the exhaust gases.

When the grid frequency goes down and the turbine and axial compressor slow down the unit cannot produce the same power as when it's spinning at rated speed and rated frequency. It's as simple as that. There's not enough air flowing through the machine at less than rated speed to support the same amount of fuel as at rated speed. Which means the power output will be less at less than rated speed.

If you were to do anything to increase the amount of fuel being burned at lower than rated turbine speeds (because of grid frequency excursions) to increase the power output during grid frequency excursions you would find during your next maintenance outage, if not before, that the hot gas path parts had seriously degraded if not outright failed.

This is a "dirty little secret" of gas turbines, of any manufacturer. When the grid frequency goes down, the maximum power output of the gas turbine decreases, which is not what one really wants to happen. Even if a gas turbine is being operated at Part Load (some load less than Base Load) which, for a GE-design heavy duty gas turbine is Droop Speed Control, the unit will try to increase its power output when the grid frequency decreases, but it can do so only up the CPD-biased exhaust temperature control limit calculated by the Speedtronic. Any more fuel than that and the temperature of the combustion gases increases and that decreases the hot gas path parts life.

So, unless you want to be performing maintenance outages on a more frequent basis and replacing the hot gas path parts on a more frequent basis, you shouldn't be doing anything to change the operating parameters of the unit, regardless of whether it has a Mark IV, a Mark V, a Mark VI, or a Mark VIe, or even a Mark II or a Mark I. It has nothing to do with the generation of Speedtonic, it's all about the way heavy duty gas turbines operate.

Now, GE can sell you an option that will allow your turbine to temporarily increase power output when the grid frequency decreases, <b>but</b> they will also install a new set of timers and counters to monitor the time spent operating "above" optimum output and they will hand you a new GEI which will tell you how much every hour at the increased output decreases the maintenance intervals, and then they will stand there with their hand out while you pay for the new combustion hardware which you have to purchase sooner than normal. (By the way, you'd need to buy a new turbine control system to get this increased output on frequency decrease!)

There is no such thing as a free lunch, or dinner, or supper, or breakfast, or even a snack. You can have your cake to admire, but if you eat it you won't be able to admire it later. Everything comes at a price. If you could get the utility you sell power to to pay for the increased maintenance costs, then maybe it would be to your advantage. Maybe you're the utility and you have to have the capability, but it still ain't gonna come for free.

 

Dear CSA,

You have given me a lot of information regarding exhaust temperature control on GE machines, and I think applied also to other machines like our Westinghouse engines. Just want to know your idea on biasing exhaust temperature setpoints whenever we inject water into the combustor for NOX control and for power augmentation. On GE machines, just want to know how do water injection affects the exhaust temperature setpoint (whether adding, subtracting or no change) to maintain same firing temp and consider combustor parts life. We have 2 Westinghouse gas turbine, gas fired with Water Injection for NOX control and Wet COmpression for power augmentation. On our logics, adding up water on both systems have a corresponding increase on the exhaust temp setpoint. Can you give your opinion on this wheter this is a good control practice or can affect the combustor parts life. We are always shutting down our machines halfway before the scheduled maintenance because of premature failure in the combustor components.

Regards,
JCP

 

Dear CSA,

I would like to learn more about the signal TTRF1. Can you explain to me how it is calculated or at least what are the main inputs to this calculation?

Can you support me with a brief description or a kind of control scheme?

Thanks in advance!

Marco

 

The calculation for TTRF1 is proprietary; that's why it's inside a block.

If you have an early Mark V, the calculation is implemented in primitive blocks (ADD, SUB, MULT, DIV, etc.).

You can see all the inputs for the block in use at your site in the CSP for the unit at your site.

Again, the internals are proprietary, to GE.

If you're experiencing some problems, explain what's happening and we can try to help.

 

Unfortunately, I don't have any experience on any other manufacturer's machines, but I'm working on trying to remedy that.

The issue with injecting any kind of diluent (water or steam) for emissions control directly into the combustor is that over-injecting can cause high dynamic pressure oscillations in the combustors, which can lead to premature wear, failure, cracking, etc. Over-injecting is defined as exceeding the threshold of acceptable dynamic pressure oscillations, thereby causing the premature failures.

Over-injection can occur for several reasons. The manufacturer may have misjudged the amount of water or steam required to meet the emissions guarantee without exceeding acceptable dynamic pressure oscillations. Also, for some systems without continuous emissions monitoring systems if the flow-rate monitoring equipment isn't properly calibrated then more diluent can be injected than is thought. Or, if the flow-rate reference isn't properly "calibrated" then the flow-rate reference can be calling for more injection than it should be. Without continuous emissions monitoring, which should indicate low NOx emissions levels during most over-injection conditions (other than a misjudgment about required flow-rates), it's difficult to know on a real-time basis if the proper injection rate is being maintained.

Or, it could occur for any combination of the above conditions.

As for the wet compression, I think the jury's still out on the long-term effects on the axial compressor and turbine.

I believe that GE biases the exhaust temperature control curves when diluent is being injected, because it likely reduces firing temperature by a couple of degrees so a little more fuel can be burned to raise the firing temperature back to the machine rating and a little more power output is derived.

I don't believe, at least on the GE machines I have worked on, that exhaust temperature control curve-biasing is done based on whether or not water or steam injection is flowing, because the machines I have worked on could not be operated without NOx reduction without facing fines from the local air management authorities and regulating agencies.