load rate (stag ms9001fa)

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koukos

I wonder....could a Power Plant unit "behave" properly, if the control of its load reference is modified by the operators of the plant the same as it was controlled "In Remote" by a dispatch center.

For example: when given by the dispatch center a signal (4-20mA) which it is received by the DCS via RTU and then sent to MARK VI. let's say from 300 MWatts to drop down to 250 MWatts (technical minimum load of the plant is 220 MWatts). how will the load rate will behave then? Will be, for example, 20 MWatts per minute? Which are the parameters/variables that will affect to that load rate? Is it acceptable for the operator to intervene to such constant variables of the system?
Thanx a lot in advance !
 
Koukos,

There is a saying in the Western world: "Curiosity killed the cat." In other words, a curious cat that is not cautious can experience loss of life.

The loading (and unloading) rates of a Speedtronic are adjustable--within limits. By design, the "manual" loading (and unloading) rates are faster than most automatic loading rates, just because it is believed that if the operator is making a change it might be "important" for the load change to be done quicker than say, an automatic load change.

The limits are a function of many things. If we're talking about a single-shaft, steam and gas turbine and generator on a single shaft, the loading (unloading) rate of the steam turbine is as important as that of the gas turbine.

I'm going to point you in a direction, and remind you of the Western saying above.... The Control Constants for loading/unloading rates usually have a signal name something like this: TNKR1_n, where "n" is a number from 0 through 7 (it's actually an eight point array). Sometimes, the Mark VI version of the signal name is TNKR1_[n] or something similar. Control Constants can be adjusted by someone with knowledge of the appropriate password.

There are "longname" descriptions of the Control Constants. <b>The caveat here is: The longname descriptions for these specific Control Constants are quite frequently >>WRONG.<<</b> DO NOT think or believe the longname description of these particular Control Constants is correct for the turbine at your site. <b>Look at the application code that selects each one of the rates </b>(the values of TNKR_[n] are rates)<b> to determine exactly which rate is in effect any any particular point in time.</b>

The rates are usually expressed in %/MIN, percent-per-minute. The percent is the percent of turbine speed reference (TNR). For a machine with 5% droop and a rate value of 0.5%/MIN, the unit would go from zero load to rated load in approximately 10 minutes, or from rated load to zero load in approximately 10 minutes (once load started decreasing). So, the Droop percentage of the machine is important to understand, as well as the rated load of the machine. And, using those values, one can then calculate an approximation of MW/MIN, which is what everyone wants the rates to be expressed in, but which GE almost NEVER uses.

It's not easy to do, but it is absolutely necessary for you to ensure if you change a rate's value that you change the right one!!!

And, remember, as most people forget--when you change that value it is changed ANY TIME that rate is selected. Most people want a faster rate when a remote signal comes in SOMETIMES, but not always. They get very upset when it's faster when they don't want it to be faster, which is usually most of the time. But, they want it to be faster when they want it to be faster.

It's possible to have a "selectable" rate, but one has to define <b>EXACTLY</b> when that rate is to be faster and <b>EXACTLY</b> when it's not to be faster. And, that is sometimes very difficult to do with the available logic and inputs in the Speedtronic panel.

An operator should ALWAYS be able to interrupt any automatic loading or unloading sequence by clicking on the 'RAISE SPD/LOAD' or 'LOWER SPD/LOAD' target on the HMI (presuming the logic has been properly written to allow an operator to interrupt an automatic loading/unloading sequence--which can only be determined by reviewing the application code in the Mark VI, or by "experimentation".) That is usually part of GE's heavy duty gas turbine control philosophy: to allow operator (manual) intervention of any automatic loading/unloading sequence, unless it's an automatic shutdown because of some alarm condition. But, lately, the longtime controls philosophies and practices (which aren't really documented anywhere--even in GE) are being ignored.

Remember the curious cat. Caution is the order of the day when dealing with loading/unloading rates.

It's not an easy topic to explain, especially without being able to use drawings. If you're not sure, have a Mark VI-knowledgeable person come to site to help understand what's possible and what's not.

Hope this helps!

And for anyone else reading this thread the same thing applies: NEVER rely solely on the longname description of any Control Constant, <b>particularly</b> these loading/unloading rates. <b>VERIFY</b> the actual usage before making any changes. You may (most likely will) be very sorry if you don't!

Lastly, do try to research and understand the maximum loading and unloading rates for the unit at your site. There are maximum loading/unloading rates, put in place to protect turbines (both gas and steam) from excessive thermal shock, and in some cases to prevent slugging the steam turbine with water carryover from the boiler. In the case of the gas turbine, it's to prevent thermally stressing the hot gas path parts. In the case of F-class machines, it's also about changing combustion modes and protecting the delicate nature of F-class machines (they really DON'T like sudden thermal stresses--as evidenced by the OEM's trip reduction efforts over many years).

Another saying in the Western world is: "Kids, don't try this at home!" In other words, if you're going to try this, make sure your "parents" know what you're doing and are prepared for the results--bad as well as good. And, long-term effects are as important as short-term effects.

One more thing, HRSG (boiler) loading/unloading rates are sometimes used to calculate the loading/unloading rates used at some sites to protect the HRSG.

There; that's it. All warnings and admonitions have been given. Hopefully, otised (another respected contributor to control.com) will add to thread this with his experience and knowledge.
 
GE sets the loading rates so as to maximize the operating life of the equipment. Or, perhaps, so as to not unduly shorten the equipment life. They also recognize that the end user would generally like to be able to change loads as rapidly as possible to respond to demand changes.

For a combined cycle system, the loading rate limiting item is generally the steam turbine. The HRSG imposes limitations during startup, but once warmed up (pressurized) is able to handle the gas turbine's allowable loading rate.

The loading rate is ultimately controlled by the gas turbine fuel control, and GE does this by setting the no load to full load slew rate. I am not sure what the current limit is for the "F" series gas turbines in simple cycle mode. Back in the days of Mark I and Mark II SPEEDTRONIC controls, the maximum automatic simple cycle normal loading rate was 12 minutes from no load to full load. There was a fast loading rate of 6 minutes available for some applications, and it did reduce the operating life of the hot gas path parts. There was also a "manual" loading rate (via the Raise/Lower switch) of 90 seconds; this was never intended to be used for large changes in load.
In combined cycle, the steam turbine generally had a maximum loading rate of 5% per minute (equivalent to 20 minutes from no load to full load) when "hot." The "cold" rate was 1% per minute and there was a "warm" rate of 3% per minute. The definition of cold, warm and hot was based on the steam turbine inlet metal temperature, and I don't remember the numbers. So, in combined cycle, the gas turbine automatic loading rate was set to 18 minutes from no load to full load, and various schemes were put in the DCS (or plant level controls in the analog days) to further reduce the gas turbine loading rate to maintain the life of the steam turbine.
With the Mark VI controls, there is sufficient processing power to calculate stress limits for the steam turbine and this has permitted generally faster loading rates. For single shaft combined cycle applications, the steam turbine control directly modifies the gas turbine loading rate; for multi shaft, the DCS generally reads the load rate from the steam turbine and sends the appropriate rates to the gas turbine controls.

Now, based on the above, I recommend that you don't go changing automatic loading rates without involving the equipment supplier (presumably GE). Typically, the main reason for needing some change is to meet secondary frequency response needs requested by the grid operator. I know GE has dealt with this issue in the past.
 
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