From my understanding that, if turbine speed reaches 3120 rpm, the governor will close all governing valves and if turbine speed decreases to 2880rpm then governing valves will open fully.

But we have some odd logic in our plant, which is they have given a upper limit of 30rpm. This means whenever reaches speed reaches 3030rpm, the governor will keep the valves opening command will remain same for all values above 3030rpm. Whenever speed decreases, it does not have any limit. It operates up to the full droop limit of -120rpm. In short the droop range is (-120rpm to 30 rpm).

Why this limit given?

 

SRPO9002,

Is the steam turbine part of a Combined Cycle Power Plant--or some process plant that receives steam from steam turbine extractions and/or the steam turbine exhaust?

Does the steam turbine speed change when load changes while the generator is synchronized?

Is the steam turbine operated in IPC (Inlet Pressure Control) mode or Extraction Control or Exhaust Pressure Control?

Have you read any of the Droop speed control-related threads on control.com? (There is a 'Search' field at the far right of every Menu bar of every control.com webpage. The Search 'Help' is highly recommended.)

 

You have discovered what many refer to as Digital Setpoint settings
in a speedtronic. 104% of 3000 rpm =

 

Hi CSA,

1. Its only Pulverizered coal boiler and steam generated is feed into the turbine. No steam from other process.
2. When generator is synchronised, turbine speed changes according to grid frequency, irrespective of any load changes.
3. Steam turbine is operates with inlet pressure control only.
4. This droop settings will come only when generator is disconnected from grid and supplies power to captive load. That time its mode will change and it will come to droop mode. The governor valve has output of 0 to 120%. In this droop command will add the output or decrease the output to valve output command thereby maintaining the frequency(3000rpm). My doubt is, in this addition/subtraction of valve command is, in the positive side it will add only upto maximum limit of 30%, in negative side its full(120%)?

Could you able to understand?

 

SRPO9002,

Sorry; after re-reading this thread several times, I'm still not able to understand.

When frequency INCREASES Droop speed control acts to lower the load of the unit it is active on by closing the control valve. I believe you said when the frequency INCREASES the action of the turbine control system (the turbine governor) was to OPEN the control valve (if I understood your original post).

What Droop speed control does is to REDUCE load when frequency INCREASES by closing the control valves in proportion to the frequency deviation. Frequency increases on a system (large or small) when the load on the system exceeds the amount of generation on the system. Frequency decreases on a system (large or small) when the load on the system is greater than the amount of generation on the system.

Droop speed control does NOT restore frequency to normal--in fact, it only changes when, 1) the turbine speed reference changes in relation to the actual turbine speed (frequency, OR, 2) the actual turbine speed (frequency) changes with relation to the turbine speed reference.

Droop speed control only acts to change the energy flow-rate into the prime mover (which directly controls the generator output) when the ERROR between the turbine speed reference and the actual turbine speed (frequency) changes--and it doesn't return the frequency to normal--it only acts to support the load change.

It is straight proportional control--it only works when there is an error and it does nothing to return the error to zero (to make the actual turbine speed (frequency) equal to the turbine speed reference). Returning the speed error to zero is the responsibility of either the human operators, some external "automatic" control system, or the Isochronous machine (presuming it's not overloaded or underloaded).

What happens sometimes during commissioning (or even sometimes long after commissioning) is that programming modifications are made which may or may not be prudent and well thought-through. And, some time later (years even) the changes become evident and the reason(s) for them are not known to anyone in the plant at that time, or the reason(s) for them may not be fully recalled. "Modifying" Droop speed control is one of the more commonly-made and ill-advised things to be modified to try solve problems which are not properly attributable to Droop speed control.

The operating modes of your plant, and its configuration, are not clear, either. When a turbine-generator--or multiple turbine-generators--are isolated from a utility (called captive or "island" mode), it's very common for the island load to be less than the operating power output of the generator(s) at the time of isolation. So, usually, there is some "external" load-sharing and/or frequency control scheme (sometimes called PMS--for Power Management System) that is activated when the utility tie breaker opens to control frequency (by controlling the load of one or more generator(s)).

This will quickly reduce the energy flow-rate(s) into one or more generator prime movers to try to limit the frequency increase to a minimum which would happen if the outputs of the generators were greater than the load when the utility tie breaker opens. (In the case where the island load is greater than the amount of generation when the utility tie breaker opens, a function called load-shedding is employed to quickly shut down or eliminate non-essential loads to prevent the frequency from decreasing significantly when the tie breaker opens.)

Let's consider a boiler which isn't really capable of quickly responding to load changes (which will result in frequency deviations when islanded) and is not tuned so as to be able maintain steam turbine inlet pressure very well during load changes, either. It's not uncommon for some modifications to be made to the turbine governor to try to make up for the boiler's inability to change load and/or maintain pressure.

However, if you wrote correctly, opening the turbine control valves during a load drop/frequency increases would seem to be the wrong thing to do (which happens when site modifications are made without factory review during commissioning, or sometimes even after commissioning).

For example, let's say the opposite of your original post is what really happens--when the frequency drops by more than 1% (30 RPM) the control valves are commanded to fully open--because the steam pressure is already dropping in response to a 1% speed/frequency change and the boiler isn't increasing the firing rate fast enough and steam pressure will continue to drop even further if the control valves aren't opened more and quickly.

Is that the correct action to take? Only someone with intimate knowledge of your plant and the control systems would know, unfortunately. But, it doesn't make much (obvious) sense to make the control valves open when the frequency is increasing because the frequency increases when the load is too great--and opening the control valves will only make the power output of the turbine-generator increase, which will only make the frequency increase further, which is not the (obvious) desired action.

So, no; I'm still not clear about many things.

As explained in the other thread about captive power plants you have inquired in, the age-old, tried-and-true method of frequency control for an island (captive) load is to have one unit (usually a larger unit) operating in Isochronous speed control mode and any other units operating in Droop speed control mode. HOWEVER--contrary to popular belief--human operators still have to monitor and anticipate load changes in order to keep the Isochronous unit from becoming overloaded (in which case the frequency will decrease) or from opening the generator breaker on reverse power (if the load decreases below the Isochronous machine's minimum output, usually zero watts/KW/MW).

Many plants try to use external load-sharing/frequency control systems for multiple generator-sets operating in island (captive) mode. This rarely works as envisioned, and can result in black-outs and worse. It takes a great deal of knowledge and experience to properly program a load sharing/frequency control system for multiple generators--and even if it's successful during commissioning, usually, something changes which renders it problematic sometime in the future.

May sites have had such bad luck with operating one unit in Isochronous speed control and other units in Droop speed control when islanded that they just try to operate all units in Droop speed control when in island mode. Sometimes, if the load changes are not very large and/or can be anticipated, this works just fine if the human operators are diligent and understand what they're doing and why. But, generally, it results in undesirable, though "tolerable," frequency swings.

Some sites have so de-tuned Isochronous speed control on one or more units to try to achieve stability that frequency swings are expected and "tolerated" just because tuning generally takes time, and usually bad things happen when tuning (black-outs and worse).

Perhaps if you clarify your original post in light of the above and provide some more information about how your plant is configured and operated we can be of more help.

(I'm not good at proof-reading my own writing (as I'm sure most are aware), but I've made every effort to ensure I haven't made any errors in this post in an effort to try to respond correctly as best as possible. I apologize in advance for any errors which I hope I haven't made.)

 

>SRPO9002,
After all the proofreading there was still a mistake in the second sentence of the third paragraph; it should have read:

Frequency increases on a system (large or small) when the load on the system *IS LESS THAN* the amount of generation currently on the system.

 

>From my understanding that, if turbine speed reaches 3120
>rpm, the governor will close all governing valves and if
>turbine speed decreases to 2880rpm then governing valves
>will open fully.

This is your control limit for the turbine. It really has nothing to do with rpm when synchronized to the grid.

>But we have some odd logic in our plant, which is they have
>given a upper limit of 30rpm. This means whenever reaches
>speed reaches 3030rpm, the governor will keep the valves
>opening command will remain same for all values above
>3030rpm. Whenever speed decreases, it does not have any
>limit. It operates up to the full droop limit of -120rpm. In
>short the droop range is (-120rpm to 30 rpm).
>
>Why this limit given?

These limit are there because the grid has limits on hertz while synchronized. under frequency relays and over frequency relay are usually set just outside these limits.

Do the math on the rpm limits described and convert to frequency

 

CuriousOne,

Typically the over- and under-frequency relays are set to actuate before the Droop limits are reached. And, using 4%, the Droop limit as a function of frequency (at 50 Hz) would be +/- 2.0 Hz. But that's not always the case.

But, Droop speed control is about how much the energy flow-rate into the prime mover (the steam flow-rate into the steam turbine, in this thread) will change as the error between the turbine speed reference and the actual turbine speed changes.

So, when the turbine speed reference is 104% (3120 RPM) and the actual speed is 100% (3000 RPM when the grid frequency is 100%) the energy flow-rate into the prime mover will be at rated-/and because the electrical output of the generator driven by the prime mover is relative to the energy flow-rate into the prime mover the electrical output (in watts/KW/MW) will be at generator-set rating.

This means that for every 1% error the electrical output of the generator will change by 25% of rated--whether the turbine speed reference changes in relation to the actual turbine speed <b>OR</b> the actual turbine speed changes in relation to the turbine speed reference--up to a maximum error of 4% (in this thread).

So if the unit is running at 100% actual speed (3000 RPM) and the turbine speed reference is 102% (3060 RPM) the electrical output will be 50% of rated. If the grid frequency then changes by more than 2% of rated the error will change to more than 4%--BUT the electrical output can't increase above rated, because in this case the steam control valves will be wide open.

Most descriptions of Droop speed control say that as the load increases the generator-set speed will decrease--but that's only true when the gen-set is operating in Droop speed control independent of a well-regulated grid, or in "island mode." When connected to a well-regulated grid when the load increases--the load on the grid (the number of lights and motors and computers and computer monitors, etc., increases)--the grid frequency will remain relatively constant, which means the gen-set speed will remain constant and the electrical output of the gen-set will remain constant.

When an operator "loads" a generator while connected to a well-regulated grid while operating in Droop speed control the operator is increasing the turbine speed reference--but the actual turbine speed does not change. The increase in the error between the turbine speed reference and the actual turbine speed increases which increases the energy flow-rate into the prime mover and the electrical output of the generator.

SRPO9002 seems to be saying that when operating in IPC there is a "limit" of 30 RPM on the positive side which when reached will cause the output of the control valves to open fully. At least I think that's what is being said; it's not clear (to me, anyway). (And, is that a limit on the speed reference or the speed error?) If that's what is being said, it seems unusual--but when IPC is active it's pretty certain Droop speed control is not the primary governor reference--the two signals are "cascaded" to produce the signals to the control valves but IPC is the primary signal.

Droop speed control changes the output based on the difference between the turbine speed reference and the actual turbine speed--regardless of whether the turbine speed reference changes or the actual turbine speed changes. And if there's another mode of operation that's active it will change Droop speed control as required to make the process value equal to the setpoint. For IPC that means the turbine speed reference will be adjusted as necessary to make actual inlet pressure equal to the inlet pressure setpoint.

It also seems like there are issues with frequency control at SRPO9002's plant when operating independently of the grid (in captive, or island, mode). There's a lot we don't know at this point.