We have a not very usual CCPP with 6 CT, each one has an HRSG associated, and all the steam production is sent to a single steam header to feed only one Steam Turbine.
We had a problem in the FeedWater CV of one HRSG and its drum flooded. A lot of water flowed from the drum to the superheaters, then to the steam header where, mixed with the steam coming from the others HRSG, made the steam temperature suddenly decrease. This cold and wet steam fed the ST some minutes until it was manually tripped. We had to overhaul both, the ST and the HRSG to inspect. Fortunately, after a very costly inspection, some minor damage was found.
I've to say that we were lucky this time, but need to improve our DCS. We realized that a high water level in the drum of any of our HRSGs, will only produce an alarm signal to the Operator but, will not trip the HRSG neither the ST, neither the associated CT. The DCS will just advice the operator that there is high water level in a drum, and nothing else. No automatic protection actions.
Also, in the ST there is only an alarm signal if the steam temperature decreases 40°F from nominal temp. But if the steam temperature continues to decrease, or if it suddenly falls say 200°F, nothing else happens...no automatic protection actions.
We are trying to develop an automatic protection in our DCS for the HRSGs and the ST to prevent future similar faults. We believe that a high-high level in a drum should:
1st) trip the HRSG: close supplementary fire gas valve, close FW inlet valve and steam outlet valve. Not sure if it should also trip the CT.
2nd) trip the ST: if in addition to the high-high level in the drum, low steam temperature is detected upstream the main steam valves of the ST. Not sure which should be this low temperature trip value.
Any feedback is welcome. thank you for shearing your experience.
High drum level can be a problem. I was just in a control room 3 hours ago during a refire and the drum level got high...most drums being cylinders doesn't help either.
I understand the desire for safety mechanisms, but do you really want the HRSG to trip right away at a High-High alarm? I think I would like to have some sort of timer involved. Then again, I can understand that the high alarm is supposed to be the "warning" and the high-high is the trip. I wouldn't want this implantation to cause nuisance trips.
I don't see a need to trip the CT, unless there is worry of overheating HRSG tubes.
Tripping the ST due to low steam temp/bad quality sounds like a good idea, but I don't know exactly how you would implement it. I would think that absolute steam temp isn't the concern, but the amount of superheat. As long as the required superheat is there, you shouldn't damage your turbine. I am by no means a steam turbine "expert" in this regards.
Thank you for your time...
Regarding HRSG trip: the plan is to have 3 steps: first a "high level" warning signal, then a "high-high level" signal to emergency open the drum drains, and finally an "extra high-high level" which after a time delay, trips the HRSG. My plan is also check simultaneously the steam outlet temperature of this HRSG and, if it drops while the drum is at "extra high-high level", then trip the HRSG.
You know, I've heard horror stories about water induction on steam turbines. I don't want this to my unit. Also, our combined cycle is a bit complex (6 CT to 1 ST), energy price is ridiculous here so, I believe that been conservative may be a good idea in this situation. but also it is really a very rare event so I believe that the probability of annoying trips is low.
Regarding ST, yes, the plan is to implement a warning or trip checking the "distance" between the real steam temperature and a calculated saturation temperature, and after a delay, then trip the unit. So far, I'm studying how to make a reliable algorithm to calculate the saturation temperature. any idea is welcome.
Thank you for your feedback.
Water induction is a horror story, and is the primary reason for tripping on high drum level. I believe that ASME code requires this protection.
For calculating saturation temperature as a function of pressure, most DCS controls used in power plants these days have that as a built in steam table function. If yours does not have this, I suggest you plot the steam table saturation curve over the pressure range for your application and use a table interpolation function. Even the oldest DCS controls had this feature.
Another comment - be careful about opening steam drum drains under pressure, especially the startup blowdown, as it is usually sized to prevent swell at lower pressures during startup. Opening that valve at full pressure might empty the drum and quickly get you to the low level trip condition. It can also overwhelm the blowdown system.
In multishaft CCPP projects I have been associated with, the usual practice was to have 3 distinct high drum level settings:
H = alarm only
HH = trip HRSG and close its isolation valve to stop steam flow to the header. After time delay, if isolation valve is not closed and the drum level is still above HH setpoint, trip the steam turbine.
HHH = immediate trip of the steam turbine
If you have exhaust path damper(s) to isolate the HRSG from the CT, it is not necessary to trip the CT. If not, you must trip it to trip the HRSG (need to remove the energy source for the HRSG).
We have sometimes also used low steam temperature protection for the steam turbine. This would typically be based on superheat (calculate saturation temperature as a function of pressure and if the measured steam temperature falls below Tsat + 42 degC, trip). You can also look at rate of decay in temperature, since even if superheat is maintained, a rapid drop in steam temperature will stress the steam turbine.
We are using MaxDNA DCS system in our 360MW CCPP and it has the features of tripping HRSG at HIHI level of drum. After updating WINXP based MaxDNA we had also face problem regarding HRSG drum level. Alarm buzzer was not operated at HIHI drum level and the control room operator did not notice the alarm.After six minutes(time delay) HRSG tripped with that alarm and consequently ST tripped.
Three no.s of high level switches and three no.s of low level switches required.
VH- below Safe limit with timer time T
HH- Immediate trip and closer of steam admission with zero delay
The timer timing T can be 10 secs or 20 secs depending on the capacity of drum and time taken to reach from VH level to HH level.
Likewise for low level trip, L, VL and LL can be envisaged.
VL- It can be set with Tsat-40deg c
LL- Tsat-60 deg C
timer in VL should be set to 10-15 secs
To facilitate the safe level of drum in case of VH ,motorized blow down of drum can be envisaged with inching valve arrangement.
Online monitoring of drum level with steam/water demarcations can be used using resistivity sensors.
Some more information on the setup indicated by Norberto is required before on can propose solutions to Norberto's problem. So here are some questions:
1. six heat recovery boilers all feed to one steam turbine. These boilers have supplementary firing. What is the temperature of the steam leaving the boilers without and with the supplementary firing turned on? Is it the same or is it different?
2. If the reply to point (1) is that there are different steam temperatures, does the steam header allow different steam temperatures along it, or is there some sort of protection/warning that there is too high a temperature difference between steam from boiler and steam in header?
3. Are the gas turbines equipped with exhaust bypass ducts that permit operation of the gas turbines with their associated boilers shut down? Or can the boilers be run dry, i.e. gas turbine running but no feedwater entering boiler?
4. Is the main steam system equipped with a bypass steam line which dumps the steam straight to the steam turbine condensor, to permit heating up of the boilers without wasting water, during warm up of the boilers, or do the boilers vent to atmosphere until appropriate steam conditions are reached?
5. Is the supplementary firing used to boost steam turbine output when required or does it have to be continuously in operation to attain the required steam temperature for the steam turbine?
6. Are the boilers equipped with dump valves on the drums having adequate capacity to permit dumping of water when a high drum level condition occurs, or are there simply normal blowdown valves?
7. What happens in case the steam turbine trips when all boilers are in service with their supplementary firing turned on?
8. This question just for curiosity - has this power plant been design as indicated (i.e. 6 GTs, 6 boilers and 1 steam turbine) from scratch or are the GTs and boilers a retrofit to a steam turbine that originally was driven by one big boiler?
My answers to JOJO's questions:
> 1. six heat recovery boilers all feed to one steam turbine. These boilers have supplementary firing. What is the temperature of the steam leaving the boilers without and with the supplementary firing turned on? Is it the same or is it different? <
->->Actually in both situations the temperature is about the same, because there is a desuperheater control valve in each HRSG steam outlet controlling the steam temperature if it is high, for example as consequence of high supplementary firing condition<-<-
> 2. If the reply to point (1) is that there are different steam temperatures, does the steam header allow different steam temperatures along it, or is there some sort of protection/warning that there is too high a temperature difference between steam from boiler and steam in header? <
->->The steam header allows different temperatures but not so different. For example, nominal steam temperature is 900°F, and we have a warning if it falls to 860°F before the Steam Turbine. There is no protection/warning if there is a large difference between any HRSG and the header<-<-
> 3. Are the gas turbines equipped with exhaust bypass ducts that permit operation of the gas turbines with their associated boilers shut down? Or can the boilers be run dry, i.e. gas turbine running but no feedwater entering boiler? <
->-> all the 6 gas turbines have exhaust bypass duct. There is a guillotine in the HRSG inlet and a damper in the by-pass stack. Operating time is about 7 minutes for guillotine from open to closed position. We can not run with hrsg dry<-<-
> 4. Is the main steam system equipped with a bypas s steam line which dumps the steam straight to the steam turbine condensor, to permit heating up of the boilers without wasting water, during warm up of the boilers, or do the boilers vent to atmosphere until appropriate steam conditions are reached? <
->->there is one small by-pass which allows 30% of nominal steam flow for initial start up of steam turbine. But, each HRSG has vent valves to atmosphere upstream its main steam stop valve to header, to vent steam until reaching conditions before supplying its steam to the header. The plant was designed as a "base loaded" CCPP, but since some years ago we are cycling. If we need to reduce load, the first step is to reduce supplementary fire, and the second is to remove one GT-HRSG and then other and so on...<-<-
> 5. Is the supplementary firing used to boost steam turbine output when required or does it have to be continuously in operation to attain the required steam temperature for the steam turbine? <
->->we can run with no supplementary fire if we need. Most of the times (except with very cold ambient temperature) steam temperature from HRSGs is enough with 0% of supplementary fire<-<-
> 6. Are the boilers equipped with dump valves on the drums having adequate capacity to permit dumping of water when a high drum level condition occurs, or are there simply normal blowdown valves? <
->->they have a 1 ½" blowdown valve directly connected to the drum. Just to have an idea, the feedwater line is a 6" pipe.<-<-
> 7. What happens in case the steam turbine trips when all boilers are in service with their supplementary firing turned on? <
->->a ST trip generates a signal to stop supplementary fire, and to switch to closed position the hrsg guillotine and to open position the by-pass damper. 30% of steam production will be by-passed to condenser, and the remaining steam vented. GT will continue running if no trip is generated in the HRSGs (like low water level or high pressure...) while the guillotine is not fully closed<-<-
> 8. This question just for curiosity - has this power plant been design as indicated (i.e. 6 GTs, 6 boilers and 1 steam turbine) from scratch or are the GTs and boilers a retrofit to a steam turbine th at originally was driven by one big boiler? <
->->in the beginning there were only 2 GT, then other 3 GTs were purchased and then the last GT. The first fives units are 48Mw, and the last is a 124Mw GT. The plant operated in open cycle some years, and then was converted to combined cycle with the acquisition of the 6HRSGs and the 300Mw steam turbine<-<-
Thank you again for sharing your valuable experience.
In view of your answers you have the following possibilities:
1. I would definitely insert an alarm, and possibly a trip on the boilers if their discharge steam temperature is lower than the header steam temperature. This alarm/trip becomes active once the boiler steam header valve is opened. Measure the temperature leaving the boiler and compare it with that leaving the other boilers. This way you will have a pre-warning that things are not right on a particular boiler. Detecting this at the steam turbine end may be too late as to cool the steam temperature at that end you need to pump in a lot of water/cold steam.
2. As already indicated in earlier threads, you should have protection alarms/trips on high level in the drums.
The major problem I see with your setup is not the acquisition of signals to determine the faulty condition, but how to command and handle a boiler trip. One of the main issues is that the operating time of the guillotine damper is too long. In view of this, your immediate action should be to close the boiler steam header valve and open the vent to atmosphere. This will prevent cold steam from entering the header and at the same time prevent an overpressure situation on the boiler. Thus a boiler trip should do the following:
a. Shut off boiler steam header isolating valve
b. Open vent to atmosphere valve
c. shut off the supplementary firing
d. open the gas turbine bypass damper
b. send a command to close the guillotine damper.
You need to check that:
a. the vent to atmosphere is capable of handling the full boiler output with the supplementary firing on.
b. the guillotine damper can be closed with the gas turbine running (i.e. it is not intended solely as a maintenance isolation and cannot be operated with the gas turbine running).
If the above fails to correct your situation, then you have no other option but to:
a. close boiler steam header isolating valve
b. open vent to atmosphere
c. trip the gas turbine
In all the situations described above, you need to be sure that the operation of the other boilers is not disrupted when you trip out a particular boiler. This is because the trip of a boiler will induce a fall in steam header pressure. This in turn will cause the water levels of the other boilers to rise. At this point the steam turbine governors need to be closed to maintain original steam header pressure. Please note that if you are using sliding pressure on the steam system, with steam turbine governor valves fully open to optimise efficiency then this is going to be a problem, especially if the larger boiler decides to trip.
Having said all the above, you should endeavor to install this protection. repairing a 300MW steam turbine is not a cheap job, apart from the loss of output.
Yes Sir... Jojo's has a clear visualization of the problem and the solution. Guillotine dampers can be operated with GT running, but the weak point is their long closing time. Anyway, while the guillotine damper is running to the closed position, an overpressure may occur in the boiler, and the automatic vent valve may not be capable of managing all the steam because they are not designed for fully fired boiler capacity. but if pressure continues to rise the safety valves will operate and if pressure is still rising the GT will be tripped. It's ok for me...should work.
We do not operate in sliding pressure, so the ST CV will react if the header pressure falls. this should not be an issue. The header pressure is controlled by the ST CV or by the Supplementary Fire depending the operation mode selected: turbine follow or boiler follow. develop the sliding pressure operation is my still pending matter. Thank you very much for your time.
I have done it and it works, it also is what PPN is basically a Pro-Plus.
Of course Emerson will not warrant nor talk to you in any way about it. But I have successfully installed it onto laptops. The issue is while you are traveling, there will be no changes allowed without the Pro Plus availability.........and of Emerson will tell you it cannot be done but again Simulate PPN is basically an unlicensed pro plus (and everything else)
Control Systems Engineer