Steam Turbine Operated in Pressure/Power Control Mode


Thread Starter


Hopefully the following questions can be answered by those who have knowledge/experience in steam turbine operation (especially when considering combined cycle power plants), e.g., Mikas, CSA, or other knowledgeable people.

What would be the scenario(s) when a steam turbine is manipulated to operate in a pressure control mode, and in a power control mode?

Can the steam turbine switch mode from one to another frequently? Under what circumstances the change of mode would take place?

If the unit/plant is connected to the national grid that has power sale agreement with the grid system operator, how would the different modes affect both the grid and plant against compliances (e.g., dropping <= 4% ~ 5%, maintaining frequency 60Hz)? How would the term PFR (Primary Frequency Response) fit in the subject? How would the situation change when a gas turbine comes in to play?

Are there any books or materials you would suggest reading about this topic?

Your valuable explanations and feedbacks are very much appreciated!

You didn't say if the steam turbine has controlled or uncontrolled extractions. This can have a very large effect on how the steam turbine is to be operated.

>What would be the scenario(s) when a steam turbine is
>manipulated to operate in a pressure control mode, and in a
>power control mode?

Inlet pressure control (IPC) is more commonly used when, for example, there is some process that steam is being supplied to from the main (Inlet) steam line which can cause the steam pressure to fluctuate, or if the boiler isn't very good at controlling steam pressure. When operating in IPC, the load being produced by the steam turbine varies as necessary because of the change in main (Inlet) steam flow required to maintain the inlet pressure setpoint.

Power control mode does just what it says--it uses a power (load) setpoint and varies the inlet (and possibly extraction control) valves to maintain a load setpoint.

>Can the steam turbine switch mode from one to another
>frequently? Under what circumstances the change of mode
>would take place?

Usually, switching between modes is "bumpless"--or at least it should be--meaning the load will change but will not be a step-change, ramping up or down as necessary.

>If the unit/plant is connected to the national grid that has
>power sale agreement with the grid system operator, how
>would the different modes affect both the grid and plant
>against compliances (e.g., dropping <= 4% ~ 5%, maintaining
>frequency 60Hz)?

Frequency control. We don't know how large the steam turbine is with respect to other prime movers in the area, and with respect to the total generation (load) on the grid in question. Larger steam turbines (those usually not at Combined Cycle Power Plants) will have some form of droop speed control which will assist the utility with grid stability. (Most steam turbines at CCPPs are what's called "load-following" because they are 'slaves' to the heat being produced by the gas turbines; the inlet control valves are just opened to maximum opening and take all the steam they can get and produce as much power as they can get. And since they're usually smaller than the gas turbines (in output rating) they can't really affect the frequency very much.)

>How would the term PFR (Primary Frequency
>Response) fit in the subject? How would the situation change
>when a gas turbine comes in to play?

Are you referring to GE's PFR? This OEM's version of the option allows one to set a load setpoint for times when the grid frequency is stable, and when the grid frequency is unstable the load will vary in response to grid frequency--as it <b>should</b> to help support grid stability. Without PFR, when the grid frequency deviates and the governor tries to change the load to support grid frequency the load control scheme (without PFR) tries to maintaint the load setpoint--which is <b>exactly the opposite</b> of what the turbine-generator should be doing during a frequency excursion and actually contributes to the grid instability instead of assisting with maintaining stability.

AND just to be clear, for GE-design heavy duty gas turbines PFR only works below Base Load, so during Part Load operation. I don't know if PFR is offered on their steam turbine controls.

>Are there any books or materials you would suggest reading
>about this topic?

I'm still looking myself for good written materials on the subject of droop speed control and turbine operating modes. If I find something, I'll share it here on

Hope this helps!


Thank you for your time and explanation, CSA!

Yes, they help a lot!

So, is it right to say that PFR only works when the steam turbine operates in a power(load) mode? What if the unit has to operate in IPC most of the time, but at the same time it also has to maintain the grid stability when connected to the grid purchasing/selling energy? Based on your experience, what could be the options to resolve such issue?
I don't have any experience with PFR on steam turbines--it sure seems like it would be applicable to a steam turbine, and it wouldn't have to be used only in power (load) mode. It's important for all prime mover governors to respond appropriately to grid frequency disturbances no matter the mode of operation.

When multiple (two or more) generators and their prime movers are synchronized together they are ALL <i>locked into synchronism</i> with each other. What this means is that ALL of the generators are running at the same frequency--no single generator or group of generators (when synchronized to a grid with other generators) can run at any other frequency than the frequency of the rest of the grid all the generators are synchronized to.

How does this happen? There are very great magnetic forces inside the generator--one from the rotor (the "field"), and one from the stator windings (where the AC is flowing). When the generator breaker closes those two magnetic fields work to keep the frequency--and therefore the speed, since speed and frequency are directly related--equal to the frequency of every other generator on the grid. You know what it's like when you have two magnets and you get the North and South poles of them in proximity with each other--they "snap" together. And it takes a fair bit of force to disconnect them. And, when you try to push the two North poles (or the two South poles) of the magnets together--they do NOT want to be held close together. It's the same thing inside the generator--opposite poles attract, and the do so VERY strongly. So strongly that the force (torque) being applied to the generator rotor by the prime mover cannot separate the opposite poles from each other--so the rotor is locked into the speed which is proportional to the frequency of the AC flowing in the generator stator windings. (There are some very good YouTube videos about synchronous generators and how the magnetic forces are developed and how they work.)

I don't know what problems you are referring to. If a grid is experiencing problems with frequency control it's because there is some event which starts (stimulates) the frequency deviation. Either a large generator, or a group of generators, is tripped off the line causing there to be a deficiency of generation with respect to load, which causes the grid frequency to decrease. Or, some large block or blocks of load are tripped off line resulting in an excess of generation with respect to load, which causes the grid frequency to increase. Generator prime mover governors are supposed to be free to respond to these grid frequency excursions--when the grid frequency drops the governors should be free to increase their power output, and when grid frequency increases the governors should be free to decrease their power output. When they are in "load" control during a grid frequency excursion the load control function will generally operate to oppose a change in load--so that when the grid frequency decreases and the load starts to increase the load control will work to try to maintain the load. This means that the unit is actually contributing to the grid frequency instability instead of working to support it. If I understand your reference to PFR--PFR is a means of allowing a unit to be operated in load control mode but still respond to grid frequency disturbances in the appropriate manner.

If the frequency of your plant is going up and down when the grid is experiencing a grid frequency disturbance, that's normal and to be expected. What your plant--and the turbines in your plant--is supposed to do is to increase their output when the frequency decreases and increase their output when the frequency decreases. But, you can't control the frequency of your machines--or the grid--from your plant (unless it's a VERY large plant on a relatively small grid. Yes, there is some effect from individual plants and generators, but if the grid is large the effect is proportional to the rated output of the prime mover relative to the load on the grid.

And, all of the above ONLY HAPPENS when a prime mover and its generator are operating at PART LOAD. When a prime mover is producing rated power output, it can't increase its power output even if the grid frequency is decreasing. It's already at rated power output, so if any of the units at your plant are operating at rated power during a grid frequency disturbance then the power output of those machines <i>can't be changed by the prime mover governor</i> (unless the governor has special provisions to do so--and some do, but most don't). Only units which have "unused capacity" (meaning they are operating at less than rated load) have the ability to respond to grid frequency excursions, particulary frequency decreases.

So, I don't know who's expecting what from your plant. But, there's only so much a plant can do. When there was only Droop speed control this wasn't a real problem--because Droop speed control does all this automatically. With the advent of digital control systems and more complex governor modes Droop speed control has kind of been pushed to the wayside--at the expense of grid frequency stability. So, PFR is an attempt to allow units to be operated in modes other than Droop speed control mode and yet still respond to grid frequency disturbances as if they were in Droop speed control mode.

There has been a LOT written about Droop speed control mode on It's a very simple concept, and it's very powerful at the same time. Power (Load) control, or Pre-Selected Load Control, modify the turbine speed reference when they are active in order to control load to some desired setpoint. The turbine speed reference is compared to the actual speed (which is a function of frequency!) and the error between the two is used control the fuel- or steam flow-rate into the turbine. As long as the grid frequency--the actual speed of the machine--is stable, and the reference is stable the flow-rate of energy into the prime mover will be stable which means the power output of the unit will be stable.

When one wants to increase the power output of the unit one increases the turbine speed reference, which increases the error between the reference and the actual speed (which is constant as long as frequency is constant) and that increases the energy flow-rate into the prime mover which increases the power output of the generator.

If the speed reference is constant (as it is when the power output of the generator is stable) and the grid frequency changes, the speed of the unit changes and Droop speed control senses the change and changes the energy flow-rate into the prime mover to respond appropriately. It increases the energy flow-rate into the prime mover when the frequency drops, and it decreases the energy flow-rate into the prime mover when the frequency increases.

BUT, if some kind of load control is active that's trying to keep the load constant it will over-ride the Droop speed control function to keep the load constant--which is NOT what the grid wants or needs. Hence, an over-ride to the over-ride--which is what PFR is. PFR really refers to Droop speed control--which is what Droop speed control does all by itself (not control frequency but controls load in attempt to stabilize frequency excursions until the grid regulators can get control of the situation and return the frequency to normal). When the governor designers/programmers invented all these other types of load control modes that over-rode Droop speed control that's when a lot of the problem started, or got worse. So, now governor manufacturer/programmers have had to come up with an over-ride to the over-ride--just to make Droop speed control work properly during grid frequency excursions. AND ONLY WHEN THE UNIT IS AT PART LOAD.

I'm not extremely familiar with steam turbine operating modes; and most of my experience with steam turbines is in combined-cycle applications, where, again, they are in a "following" position, they can only make as much power as the steam which is generated by the gas turbine exhaust(s). So, mostly, in my experience, the steam turbine inlet control valves, are, pretty much just opened wide once the turbine is warmed-up and whatever steam comes into the turbine is converted to torque which the generator converts to amperes. As the gas turbine load goes up and down, so does the steam production which means the steam turbine load goes up and down with gas turbine load.

Steam turbines with controlled extractions are another beast altogether, and can have multiple "cascaded" control modes.

Again, you haven't provided much in the way of details about the situation, and since we are therefore just talking in generalities and practices, this is about all I can offer.

GE offers a mode called PFR (Primary Frequency Response) for their GTs; I have never seen it implemented on steam turbines, though I don't know why it couldn't be if the application permitted. I do know that many grids are using the term PFR to refer to Droop speed control, or some mode(s) that offer normal Droop speed control action during grid frequency excursions regardless of the mode (load control; Pre-Selected Load control; etc.). This is the important thing for grids and grid regulators and supervisors: That generator-sets respond in predictable ways when grid frequency excursions occur. And, most operators and their supervisors and plant managers all mistakenly believe that when grid frequency excursions occur that their plant should remain at a constant power output--and frequency output--which is just pure, deluded fantasy.

A machine which maintains its output (when at Part Load) during a grid frequency excursion is part of the problem--not part of the solution. And contributes to grid instability and frequency excursions. But, when a machine is synchronized to a grid--there's a physical reason for that term "synhronized"!--it's speed is controlled by the grid frequency. Plain and simple. Full stop. Period. (Unless it's a small grid or the machine is very large with respect to other machines on the grid.)

PFR is mostly rightly a term which is used to ensure that generator-sets will respond appropriately to grid frequency excursions. And, it's a sad fact that many operators and their supervisors and plant managers don't understand what that means--and how machines should operate during a grid frequency excursion.

Hope this helps! It's not a simple topic--especially if one has an incorrect perception of how AC power systems work and how they're supposed to work. Many people don't really get trained in the basic physics of AC power systems (F=(P*N)/120), and what Droop speed control is and how it works. Droop speed control is an extremely powerful, and very simple, method for controlling the energy flow-rate into a prime mover, which controls the torque produced by the prime mover, which controls the amperes produced by the generator driven by the prime mover. There is a clevely-hidden 'Search' field at the far right of the Menu bar of every webpage. (For those using the mobile version of the 'Search' function is hidden under the Control.Co Menu drop-down. Use the Search Help before using the 'Search' feature--it's not like most other search engines--but it is very powerful). Use the 'Search' feature to look for +"droop speed control" (exactly as shown, with the plus sign and the double quotes).


Dear CSA,

I sincerely appreciate your clear explanations on Power(load) mode, PFR/Droop Speed Control, and indeed your suggestion on Search features is fascinating! I'll make sure to utilize the useful tactic when I search (should have used the Help tool to read more >_!).

I am actually new in this area/industry (at least it's not my profession at this point yet, but I am very interested in learning more and learning them right) and here the forum as well, so, I apologize for a lack of information I have provided until now but promise that I will share more and be more specific in my future posts in order for us to discuss particular cases when the time comes. In fact, this forum has allowed me to learn the relevant subjects more than I expected, especially with the supportive aid of your crystal-clear explanations. I wonder if you've published your own textbooks or articles on these subjects in the past; if you have, I'd love to know! (Do you mind sharing your biography here ^^? Not sure if they are allowed here... maybe at least your background and experience)

When you say 'Part Load', could you kindly explain to me what it means? (I know it may sound a dumb question but I'd like to make sure of it) In your aforementioned statements you said that PFR for GE heavy duty gas turbine only works bellow Base Load, then what will work when it's above Base Load? In what situations a gas/steam turbine will operate bellow/above Base Load?

The next question (which you did not really focus on in the last post) is that suppose we have a steam turbine that is supplied by its boiler to generate electricity which is provided to run their chemical plants and/or other facilities, meanwhile whatever is left is sold to the grid. As I have been told that the unit has to operate in the pressure control mode rather than power control mode so the pressure can be maintained (balanced), and if we combine a gas turbine in the operation, the gas turbine would seem to contribute more to the pressure stability. Now, my question is, why is the pressure stability more concerned than the gird stability here? If operating in pressure control mode is inevitable, will the droop speed control (or other methods) work to maintain the grid stability? Can this situation happen in the combined-cycle applications?

Finally, I understand that you haven't found good written materials on these subjects, but can you at least provide those that had helped you understand the materials since you were a student and/or working in the industry?

Thank you so much again for your time and efforts, CSA!!!

You're very welcome, and I'm glad to have been of help.

Base Load refers to rated load of the prime mover (the steam turbine or gas turbine) which drives/provides torque to a generator. A machine (generator set--prime mover and generator) is rated based on the power output of the prime mover. Most generators can produce way more than nameplate rating--but only for short periods of time (because of the heat that's generated when high currents are flowing in the windings--both the stator and the rotor). So, Base Load is really the "maximum" power a prime mover can produce and supply to a generator. And, it's really the maximum amount of power a prime mover can produce while keeping parts life to an optimum value. (Prime movers can often produce more than rated power, for brief periods of time, but at a cost to parts/machine life. This is often called "Peak Load", but, again, operating at Peak Load for long periods of time will seriously degrade machine life and parts life--of the prime mover.)

Part Load refers to any load between zero load and Base Load. So, if a generator-set (turbine-generator) is rated at 25 MW, if it's operating at 20- or 17.4- or 12- or 9.7 MW it's operating at Part Load--less than Base Load, which is considered to be full load (hence the name Part Load).

Most prime mover governors (control systems) use Droop speed control, or some form of Droop speed control to load and unload the unit between zero load and Base Load (Part Load). This is because Droop speed control defines how the energy flow-rate into the prime mover is controlled, based on the difference between the prime mover speed reference and the prime mover's actual speed. As the difference (or, error) increases, the energy flow-rate increases, and as the difference, or error, decreases the energy flow-rate decreases. If the difference, or error, between the speed reference and the actual speed stays constant then the amount of energy flowing into the prime mover will stay constant.

The way the machines are loaded is by increasing the turbine speed reference--because on a stable grid the frequency is stable which means the prime mover speed is stable. So, when the error between the speed reference and the actual speed changes then the energy flow-rate changes.

Another way the error between the speed reference changes is when the speed reference is stable (as it is when the unit is producing a steady, constant power output) and the actual speed changes--when the grid frequency changes. And, usually when the grid frequency goes down the error increases which increases the energy flow-rate into the prime mover which increases the power output of the generator.

This is how grids and generators and their prime movers that are synchronized to grids are supposed to operate to support grid stability (even when the frequency is oscillating!). Anything that inhibits that operation during grid frequency disturbances is not helping grid stability, and can even be making the frequency disturbances worse.

When a unit is operating at Base Load, usually (at least for most heavy duty gas turbines, anyway) the reference is NOT turbine speed--it's usually exhaust temperature. So, the governor (the control system) is dumping as much fuel as it can in to the turbine to make the exhaust temperature equal to the exhaust temperature reference at all times--to maintain the actual exhaust temperature equal to the exhaust temperature reference at all times. Regardless of speed. Speed is no longer the reference or the feedback--only exhaust temperature. So, when the unit exhaust temperature reaches the exhaust temperature reference and the inlet guide vanes are fully open, the governor (the control system) transitions from Droop speed control to exhaust temperature control, and the speed will be whatever it will be--as a function of grid frequency, just as the speed is a function of grid frequency during Part Load operation.

But, when a machine is operating at Base Load (a heavy duty gas turbine, in this case) the governor can't increase the fuel flow-rate if the grid frequency decreases--because the fuel flow-rate is already at maximum. And, neither can it decrease the fuel flow-rate when the grid frequency increases--because it's trying to put as much fuel as possible into the turbine in order to make the actual exhaust temperature equal to the exhaust temperature reference. So, it's just making as much power as it can--regardless of the grid frequency.

Only when the unit is at Part Load operating on Droop speed control (or some facsimile thereof), can it respond appropriately to grid frequency disturbances.

So, at many types of plant there is a need for steam for the process(es) at the plant. And, usually, that steam is not at a high temperature or pressure (though at some very large refineries and chemical plants the steam requirements do require higher temperatures and pressures). So, a small boiler can be used to produce the steam, but those aren't very efficient. It's usually more efficient to produce steam at higher temperatures and pressures especially if the are large flows required. But if the process requires steam at lower temperatures and pressures then one can either use a pressure-reducing valve and attemporators (which are inefficient, also)--or one can use a steam turbine as a pressure reducing valve, also (by using extractions off the steam turbine for steam at lower temperatures and pressures). And, in the process, electricity (current) is generated, which can be used in the plant and/or sold to a grid. And, it's all very efficient. So, in many plants where there is a steam turbine and generator, the electricity produced by the steam turbine-generator is NOT the prime product of that process--steam is. And in many cases, especially if steam at steam turbine inlet pressure is used in some process, or the steam turbine needs to have a stable inlet pressure, then the steam turbine is operated in IPC (Inlet Pressure Control) mode.

And, many steam turbines have one or two controlled extractions--where steam at a particular pressure is "sucked off" to send to some process. And, there are various extraction control modes, too. In these types of applications the turbines are not generally "counted" or relied upon for grid stability--though they can be. And--in some cases--if they don't respond correctly they can also exacerbate some grid frequency/instability problems. A lot of site, when the grid experiences stability problems that actually significantly impact the plant, will separate from the grid and produce their own power (at reduced levels) until the grid gets stable again--simply because they can't really have a material impact on grid frequency to help stabilize it.

But, some plants are required by purchase power agreement to stay on line to try to help with grid stability during excursions. It all depends on the contract--and in that case, PFR is very important for all generator sets. (Though MANY operators and operations managers and plant managers still believe that their generators while still connected to the grid should be stable (power and frequency!) and that just can't be--physics don't allow that, no matter what a person thinks or believes or perceives. The laws of physics just don't work that way--yet (if ever).

And while we're talking about "boilers," using the exhaust heat from a combustion (gas) turbine to produce steam is also a pretty efficient way to produce steam--as well as electricity. Again, the steam turbine can be used as a pressure-reducing valve--extracting work while reducing the power, work that is used to produce more electricity--to get the steam to the values required by the process/plant without much efficiency/energy loss. And, while making more electricity in the process.

Battery technology--that's going to be the next big thing in power generation and transmission and distribution. For homes and businesses and plants, large and small. That's going to help with a lot of grid frequency problems.

Anyway, gotta run. Hope this helps!

Honestly, I haven't really found any good references or texts--and I actively search for them. Most references and texts which describe Droop speed control talk about speed changing as load changes--and that just doesn't happen when a generator-set is connected to a stable grid. It does happen if one operates a generator set in Droop speed control mode independent of other generator-sets and load changes (load in this sense being the number of lights and motors and televisions and computers and computer monitors). Speed will change <i>if the operator or control system doesn't respond appropriately</i> and the load changes and the unit is in Droop speed control--but that's not what the texts and references say. They just say the speed will change as load changes--and that doesn't happen in normal life on most grids when the frequency is stable even as load is changing.

I'll keep looking. ;-)