Recently, I posted a message trying to co-relate DSP of MARK II and MARK V... One thing I understood from the reply is that TNR is the equivalent of DSP... It was also alluded in the reply about a recent posting on relation between TNR,TNH etc... I understood from that reference that TNR is the setpoint in percentage and TNH is the speed feedback in percentage... For a closed loop control system, if TNH is less that TNR, it will try to catch up with TNR... Right?? Now in our turbine I observed the following case :

Mode of Operation : Speed - Droop
TNR : 103.91%
TNH : 99.78%
NHP : 5060
Grid Freq : 49.56Hz

The question : Why is the Turbine not catching up with TNR though it is still approx. 4% below the setpoint?

Is it because the Grid frequency is giving a lesser output to the Min Value Gate..?? If that's the case then what is that signal..?? Min Value Gate has only five inputs : Viz. Temp loop output, speed loop o/p, start up o/p, shutdown o/p and acc. loop o/p... Where does the grid freq. figure in here..??

Regards
Rahul

 

Would you want your turbine/generator to be running at 104% of rated speed when connected in parallel to other generators on an AC electrical grid? (Remember: the frequency of an AC electrical generator (rightly called an alternator) is equal to the product of the number of magnetic poles of the generator times the speed (in RPM) of the rotor, divided by 120, or: f =(P*N)/120).)

Has your Mk II SpeedTronic-equipped, GE-design, heavy-duty gas turbine-generator been operating incorrectly for the two decades or so since it was installed?

Grid frequency is NOT an input to the Min. Value gate; it IS an input to the "speed loop o/p" which is an input to the Min. Value gate. The 4% error you are witnessing is typical of most generator prime movers (regardless of type or manufacturer) operating at rated load, and is often referred to as "4% speed regulation."

It is one of the many mixed blessings of the English language (particularly as practiced by the Americans) that technical "terms" are actually bad synonyms. Droop speed control is but another example of this (like "make-up valve" and "let-down station," both of which can be used interchangeably to refer to a pressure regulator!). When something "droops," it can be considered to be limp or sagging. Merriam-Webster's Online Thesaurus describes the noun "droop" as "...the extent to which something hangs or dips below a straight line..." (One has to wonder what Droop speed control is called in the French language.?.?.?)

Droop speed control is used on almost EVERY prime mover and generator set produced since electricity was discovered and multiple AC generators (rightly called 'alternators') were connected in parallel. There are probably as many different explanations of Droop (and Isochronous) speed control as there are machines running under control of one or the other. One of this author's favorites is: "...The design of the speed droop governor is such that the governor operates at a slower speed as engine load increases. It is through this characteristic that stability of the system is achieved and division of load between paralleled units is made possible...." (Huh?)

With the UTMOST sincerity, please stop and consider this question:

Why is it called DROOP speed control?

Droop speed control is straight proportional control; there is nothing in proportional control which will drive the actual value equal to be equal to the setpoint if they differ. In fact, many times in proportional control if the gain of the control loop is increased to drive the actual value to be nearly equal to the setpoint, the system will be come unstable. The original "designers" of Droop speed control made use of the fact that on an AC electrical grid some single machine was set to adjust the prime mover to control frequency very tightly, and in the process would control the frequency (speed) of all generators connected to the same grid (no AC electrical generator connected in parallel with other AC electrical generators can have a higher, or lower, frequency than any other generator: f = (P*N)/120).

Back in the days before power (watts) could be converted into an electrical signal and fed back to a control system as part of a control loop, there was only speed feedback and speed reference. Ever seen a picture of a fly-ball governor, which is one of the earliest "control systems" ever invented? Ever seen one in operation? Where did load (power output) make it back into that contraption? It didn't! Prime mover speed, in the form of centrifugal force, acted against a spring--the speed reference--to control the amount of fuel, water, steam, wind, etc., admitted to the prime mover.

So, by understanding that the speed (frequency) of the prime mover/generator would be controlled by some "external" means when connected to an AC electrical grid, the designers could develop an error signal between a speed reference ("variable") and the actual speed ("constant"), and use that error to control the amount of fuel, steam, water, wind, etc. being admitted to the prime mover. The amount of energy admitted to the prime mover is proportional to the difference (error) between the speed reference and the actual speed--and that difference (error) is ELEMENTAL and CRITICAL to the operation of the whole scheme.

Through the years (decades) since the first AC electrical generators and prime mover control systems, the concept of Isochronous and Droop speed control (governor modes) was maintained by most every prime mover control system manufacturer in existence, including GE, Woodward, Siemens, and many, many others. "If it ain't broke, don't fix it!"

If anyone is in doubt about the relationship between TNR (DSP), TNH (NHP), and FSR (VCE), just read the CSP (or the SpeedTronic elementary). Work backwards from FSR (VCE), or work forwards from TNH (NHP), or work forwards from the GOVERNOR RAISE/LOWER switch on the generator control panel or from the SPEED/LOAD RAISE and -LOWER targets on the <I> or GE Mk V HMI--it all leads to the same place with the same result. If the unit is running in Droop speed control (governor) mode, the error between the speed setpoint (reference) and the actual speed feedback is used to increase or decrease the amount of fuel admitted to the turbine.

With the exception of those GE heavy-duty combustion turbines with 'Constant Settable Droop', the amount of load plays no part in the control of the unit. Even those units with Constant Settable Droop (yet another poor choice for describing a governor mode) STILL use speed reference, in percent, compared to a load signal, converted to percent of speed, to control load between no load and Base Load. (And, Constant Settable Droop primarily came into wide-spread use solely as a means of limiting load swings during combustion mode transfers on DLN combustor-equipped units; it wasn't because of any real enlightenment or desire to "modernize" GE heavy-duty gas turbine controls!)

If your unit is operating in Droop speed control and the grid frequency (i.e., the frequency of the grid to which your generator is connected in parallel with) is less than it should be, then whoever is in control of the grid frequency isn't paying attention to the amount of load on the system and the amount of generation on the system, or whatever is in control of the energy being admitted to the Isochronous unit isn't operating properly or the Isochronous unit isn't being operated properly.

Use your preferred Internet search engine and look up "droop+governor+mode" or "droop+speed+control". Also, look up "proportional+control" or "PID+control" since this is the underlying concept behind Droop speed control.

So, what word/term in French is used for "droop" speed control.?.?.? And what is it's English-language translation and meaning???

 

Wowwww..!! Amazing clarity... More amazing is the fact that the inherent limitation of Proportional control is used as an advantage... I am sure, most people, who fail to understand Droop control, would gain a lot from your reply...

I would want to clarify my understanding a little further...

You explained it's the error between TNR and TNH that is crucial to the power of the turbine, and hence the load deliverance.... So if the Grid Freq is 49 AND my Generator is delivering the RATED Load (20MW in my case) THEN automatically TNR would "become" 102% and TNH would be 98% (cos TNH has to match the Grid Freq...)... Right??
Now say, I start clicking the "Lower" Target... So TNR will begin to reduce but TNH will be held "constant"... If TNR becomes now 101% (making the error = 3%) then the load on the turbine would have reduced by 5MW... Is this right..??
Continuing the process will cut the load by 25% for each percent drop in error... Is this right...??
What will be the condition when the error is reduced to 0% (I keep clicking Lower continuously till the load drops to 0MW)... Is it tantamount to arriving at FSNL by clicking "Lower" icon continuously..??
Next, let me ask you please, about the case when Grid Freq increases to, say 51Hz. So NHP will be 5207... (102%)... Does it mean that if my Turbine is running at Rated Load, TNR in this case will automatically rise to 102 + 4 = 106%...??? and the load will vary from 0 to 20MW for a TNR variation from 102 to 106%...???
Last query, what will happen if instead of "Lower" icon, the "Raise" icon was continuosly clicked at Rated Load and 4% error..?? Will the TNR increase still further causing the error margin to widen beyond 4%...???

And ah!! Except for a kiss and Goodbye, there is no other French I am aware of...

Thanks and Regards
Rahul

 

Yes, when a turbine-generator is connected to the grid, TNH (NHP) will be the turbine's equivalent of the grid frequency. That's one of the acts of synchronizing--making the "incoming" generator's frequency (prime mover speed) nearly equal to and in phase with that of the electrical grid. Once synchronized, the frequency of the generator (and the speed of a directly-connected prime mover) will be the same as the electrical grid's (with the exception of an Isochronous unit which is operating somewhere between zero- and rated load; see below.)

In general, your description of the 4% differential between turbine speed reference and actual turbine speed is true when a turbine-generator being operated at rated output/load if grid frequency is above or below "normal." But, depending on the stability of the grid frequency (i.e., how fast it is changing and the magnitude of the excursions) the turbine speed reference will generally be ramped up or down to try to maintain the 4% differential--but it won't just be automatically adjusted (by step-change); it will be ramped up or down--and this is assuming the unit is being operated in automatic Base Load control (CPD-biased exhaust temperature control).

Yes; 4% speed droop/regulation means that for each 1% differential between the turbine speed reference and the actual turbine speed, a change of 25% of rated load will occur.

If the unit is being operated in automatic Base Load control and is at Base Load (i.e., on CPD-biased exhaust temperature control) and the SPEED/LOAD LOWER target is clicked (or the Governor switch is held to the LOWER position), the turbine speed reference will be ramped down from it's value and the automatic Base Load control will be canceled. Clicking on the SPEED/LOAD RAISE target (or holding the Governor switch in the RAISE position) will cause the turbine speed reference to be increased from it's present value and automatic Base Load control will be canceled.

When an operator selects Base Load after synchronizing a GE heavy-duty gas turbine-generator with a SpeedTronic turbine control system, the SpeedTronic starts ramping the turbine speed reference up at a programmed rate. As the error between the turbine speed reference and the actual turbine speed increases, the fuel flow-rate to the turbine will be increased. In the case of the Mk V, FSRN will be increasing as the error between the turbine speed reference and the actual turbine speed increases. (And as the unit is loaded in this manner, FSRT will start decreasing as the unit begins to approach rated output.) Remember that FSRN and FSRT are inputs to the Min. Value "gate" block.

When FSRN equals FSRT, the unit is said to be at rated power output--at Base Load. However, if the ramping of TNR stopped at that point, the unit would be continually switching between (Droop) Speed Control and Temperature Control. Under normal operating conditions on a unit with 4% speed regulation, TNR will be approximately 104% at this point (assuming the grid is at rated frequency).

As long as Base Load is still selected and active, the SpeedTronic continues to ramp the turbine speed reference up--but load will NOT increase. This is done to ensure that (Droop) Speed Control is not "fighting" with CPD-biased exhaust temperature control (in other words, to ensure that FSRN and FSRT are not equal) and that fuel will be adjusted to maintain CPD-biased exhaust temperature control regardless of ambient conditions. This is why the RAISE indication is maintained for a short period of time AFTER the unit reaches/indicates it is on Temperature Control. TNR will be ramped up until a preset differential between FSRN and FSRT is reached.

As long as the unit is on automatic Base Load control (CPD-biased exhaust temperature control), the SpeedTronic will automatically adust the turbine speed reference (and, hence, FSRN) to maintain that preset differential between FSRN and FSRT--that's why the RAISE and LOWER indications "flash" while the unit is on CPD-biased exhaust temperature control.

If someone continues to click on SPEED/LOAD RAISE when the unit is operating on CPD-biased exhaust temperature control, TNR (and, hence, FSRN) will continue to increase--until it reaches the High Speed Stop setpoint, which is usually 107%. Now, the unit load will NOT increase--because fuel is being controlled by the CPD-biased exhaust temperature control reference, which is the upper limit of the unit's power output. If TNR is at 107% and someone initiates a unit STOP or starts clicking on SPEED/LOAD LOWER, load WILL NOT start to decrease until FSRN drops below FSRT--which could take several minutes depending on the programmed ramp rates!

Now, if someone initiates a STOP while the unit is on automatic Base Load control (CPD-biased exhaust temperature control) the SpeedTronic will begin lowering the turbine speed reference (and, hence, FSRN). Load will NOT begin to drop UNTIL FSRN is LESS THAN FSRT--this is why when someone initiates a STOP from Base Load that load doesn't immediately begin dropping--the turbine speed reference has to be decreased until FSRN is less than FSRT. And, FSRN was being maintained at a value that was slightly higher than FSRT while the unit was on automatic temperature control to prevent (Droop) Speed Control from "fighting" with CPD-biased exhaust temperature control so it takes a short period of time for FSRN to be less than FSRT. (The same thing happens if someone starts clicking on LOWER while the unit on automatic Base Load control; TNR will be decreased and load WILL NOT begin to drop until FSRN is less than FSRT.)

To answer your last question, if someone keeps clicking on SPEED/LOAD LOWER until TNR drops to the point that it's equal to TNH, then load should be approximately 0 MW. If one continues to click on LOWER, TNR will drop below TNH (because TNH must be equal to grid frequency when the generator breaker is closed) and power will begin to flow into the generator ("motorizing")--reverse power flow. There is usually a relay on the generator control panel (device number 32) and/or some sequencing in the SpeedTronic turbine control panel which will open the generator breaker when the reverse power flow exceeds a setpoint. At that point, the turbine speed will be something less than FSNL, depending on what the setting of the reverse power relay/sequencing is.

In fact, this is how a GE heavy-duty gas turbine-generator is automatically unloaded during a STOP sequence: TNR is lowered until reverse power flows into the generator which actuates some relay/logic which opens the generator breaker, and then the unit goes into a "fired shutdown" sequence. Some site have the reverse power setting "increased" to a value which is either equal to 0 MW or just slightly higher than 0 MW in order to prevent adversely affecting the electrical grid.

It needs to be noted that when any generator is synchronized with other generators on an electrical grid and that generator is "loaded" what is actually happening is that generator is "accepting" load from the other generatos on the electrical grid. The amount of load on an electrical grid is NOT equal to the rating and/or output of the generators connected to the grid, it is the amount of lights and motors and transformers connected to the grid. In other words, the amount of electrical power generation on an AC electrical grid cannot exceed the amount of electrical comsumption on the grid or the grid frequency will fluctuate. (There are no AC batteries or "storage pools" or "warehouses" in existence today....)

If NOTHING else happens on an AC electrical grid as a generator is synchronized to the grid and loaded the grid frequency will increase--the amount will depend on the total load on the grid and the relationship of the amount of load the newly synchronized generator is accepting. On an "infinite" grid (such as in North America or UK) the amount of frequency increase from fully loading a 20MW-rated unit could probably only be measured by a digital frequency meter with six or seven decimal places of accuracy. On a smaller grid with a total load of, say 200MW, the effect on frequency could be much more significant.

To keep the grid frequency constant, electrical system operators must be aware of units which are being synchronized and loaded, and must unload some other unit(s) to maintain grid frequency--again depending on the size of the electrical grid and the sizes of the generators being synch'ed and loaded. In the same way, units being unloaded and disconnected from a grid would tend to cause the grid frequency to decrease--if NOTHING else were done on the electrical grid. So, other units must be loaded as units are unloaded to maintain grid frequency.

If a grid is "small" enough and the electrical system operator has a unit "large" enough to absorb most grid load swings, the "large" unit could be operated in Isochronous mode--which will adjust the amount of energy being admitted to the prime mover in order to maintain grid frequency, to make TNH (NHP) equal to TNR (DSP). If the Isoch's unit load is allowd to increase to its rated output and no additional generation is brought on line and the system load increases, then the grid frequency will begin to decrease. Conversely, if the Isoch unit is allowed to unload to near zero output and system load continues to decrease and no other generators are unloaded, then the grid frequency will be begin to increase. The Isoch unit's prime mover must be capable of quickly reacting to large load swings in order to prevent large frequency fluctuations (such as the tripping of one or more generators or the opening of one or more large switchyard breakers causing large amounts of load to be disconnected from the grid).

There is a scheme referred to as 'Isochronous Load Sharing' which will allow multiple units with governors being operated in Isochronous governor mode to share in maintaining AC electrical grid frequency.

One wonders why your AC electrical grid frequency varies so much? Is(Are) there no Isoch unit(s)? Are generators connected to the grid unreliable (subject to excessive tripping)? Is the "load" unstable because of switching/switchyard issues?

 

New year greetings to you and all who are reading these postings...

I am still reading and comprehending the details of the last message you posted... In our recent shutdown of MARK-II system, I really had an opportunity to observe the behaviour of DSP w.r.t the MW and Freq and Speed of the turbine... Broadly, I could understand and conclude that DSP = 2*freq + (MW/5)... For all the values of Speed - Droop mode of operation, I was able to guess the DSP value using this... And it was an exciting experience doing that... Thanks for your valuable explaination....

I remain,
Ever so thankfully
Rahul

 

You should be able to find the formula and values used for configuring the speed control input to the Min. Value gate in your SpeedTronic elementary and/or your 'Control Specification, Control System Setting' document for the Mk II unit(s).

You should be able to find the same information in the Control Sequence Program of the Mk V unit(s) and in the Control Specification of the Mk V unit. Follow the TNR signal through the CSP as it gets compared to TNH and the error ultimately becomes FSRN.

Section 2 of the Control Specification document contains the 'Speed Control and Protection' information.

 

In your case (50 cycle AC electrical grid), 2*freq = 100, and MW/5 = 20(rated power output)/5 = 4, which is 4% regulation, or 4% droop. The 100 is really 100% of rated speed (NHP).

20 MW divided by 5 (rated power output/percent speed) works out to a 4% droop setpoint.

The values you seek (and have basically determined) should all be defined in the 'Control Specification, Control System Settings' document for your Mk II, in Section II, 'Speed Control and Protection.'

 

Good article and discussions. I am a control systems engineer, but new in this electric power control area.

I have the following two comments and questions:

1. It would help a lot if the acronyms like TNR, TNH and NHP were fully spelled out and defined. Are they related to Generator shaft Rated speed?

2. Is it possible for you to provide simple algorithms to define Droop Speed Control as proportional control equations which could address specifications of the following two paragraphs from Markvguy on Dec 27.

"Grid frequency is NOT an input to the Min. Value gate; it IS an input to the "speed loop o/p" which is an input to the Min. Value gate."

"Droop speed control is straight proportional control; there is nothing in proportional control which will drive the actual value equal to be equal to the setpoint if they differ. In fact, many times in proportional control if the gain of the control loop is increased to drive the actual value to be nearly equal to the setpoint, the system will be come unstable."

Any other technical literatures you could recommend on this topic Droop Speed Control? Your response will be appreciated. Thanks.

 

With regard to your comments about grid frequency, although in the UK / Europe / USA, grid frequency is reasonably well controlled, in many developing countries there is almost no control of grid frequency. In part this can be due to a shortfall in generation - if you are running everything flat out and then you start shedding or lose load - you will have frequency excursions. About ten years ago and during some load control tests, I witnessed the Indian grid frequency change from 48.5 to 51.0 Hz in a matter of minutes !

In some situations these problems are compounded by the natural response of single shaft (industrial) GTs to frequency changes. I believe a few year years ago, a Far East country was completely 'blacked-out' as a result of frequency excursions causing the GTs to trip. The UK Grid Code was actually amended as a result of this incident !

Also regarding your comments on the term 'droop' - this is actually a very well defined term - ref: BS 132

 

TNR: Turbine Speed Reference (expressed in % of rated speed)
DSP: Digital Set-Point (turbine speed reference, expressed in % of rated speed)
TNH: Turbine Speed, High-pressure Shaft (expressed in % of rated speed) --actual turbine speed converted to percent of rated speed
NHP: Turbine Speed, High-pressure Shaft (expressend in % of rated speed) -- actual turbine speed converted to percent of rated speed.

It's unfortunate that this discussion is centered on GE SpeedTronic heavy-duty gas turbine control systems, because the concept of Droop speed control has existed for more than a century and is essential to the proper operation of AC electrical generation and grids. There have been a couple of related threads in which the terms have been defined, and the discussions have been re-started (search control.com for 'droop' or any of the terms and you can find the previous threads).

It's difficult to provide examples of SpeedTronic algorithms because they involve more nmemonics and signal names, which don't really mean anything to anyone without a SpeedTronic elementary or Control Sequence Program to reference, but here goes:

FSRN = (TNR - TNH) * FSKNG

FSRN = Fuel Stroke Reference-Speed Control (%)
TNR = Turbine Speed Reference (%)
TNH = Turbine Speed High-pressure Shaft (%) (actual speed)
FSKNG = Droop Speed Control Proportional Gai (%/%)

The above equation is how the droop speed control fuel flow reference is derived: the actual turbine speed (fixed by the grid when the unit is synch'ed to the grid) is subtracted from the turbine speed reference, and that difference is multiplied by a gain to derive the amount of fuel to be admitted to the gas turbine. As the turbine speed reference is increased, the actual turbine speed remains unchanged (when synch'ed to the grid) so the error between the two increases and therefore the amount of fuel to be admitted increases. Straight proportional control--no "reset", no "integral", nothing to drive the actual speed to be equal to the reference (which, of course, the grid frequency would never allow, anyway).

The turbine speed reference is raised or lowered by the turbine operator (or the control system if the unit is being operated in one of several automatic control modes) when the push the RAISE or LOWER button is pushed or the governor RAISE/LOWER switch is held to one position or the other. Even though they might be watching the MW meter as they are initiating a RAISE or a LOWER, what they are really changing is the turbine speed reference, which is changing the amount of fuel being admitted to the turbine, which is changing the amount of torque being admitted to the generator, which is changing the amount of amps flowing out of the generator, which is changing the "load" of the generator.

In a SpeedTronic heavy-duty gas turbine control panel, there are several different "FSRs" (Fuel Stroke References) being calculated at ALL times--droop speed control (FSRN) is just one of them. They are all inputs to a "minimum value gate" or "minimum value selector", and the lowest of all the inputs actually "sets" the amount of fuel being admitted to the turbine. In a gas turbine, it's important for the exhaust temperature not to exceed a calculated value, so one of the "min. value gate" inputs is FSRT--Fuel Stroke Reference, Temperature Control.

It should be noted that grid frequency itself is not an input to anything; since turbine shaft speed is directly "proportional" to grid frequency when the generator is synch'ed to the grid.

Unfortunately, there is not much written on droop speed control--at least in recent literature. In research for these discussions, most of the recent literature seems to describe droop speed control as the relationship of the drop in frequency to the change in load--which might be true for an uncontrolled AC electrical machine/grid, but that's not true for electrical grids today.

In the largest sense, droop speed control is the means by which multiple electrical generators connected in parallel to an AC electrical grid "share" load with each other. (That word "share" also causes a lot of confusion--especially when OEMs use it loosely....)

It should be clear from the forumla above that with some "external" means controlling frequency (speed), and if that frequency remains relatively constant, that by using the error between a variable speed reference to control the amount of energy being admitted to a prime mover. When the reference is not changing and the grid frequency/speed is not changing, the amount of energy being admitted to the prime mover is not changing--i.e., it's "stable". If the reference is ramped up or down smoothly, the error will increase or decrease smoothly, and the amount of energy will be increased or decreased smoothly--as long as the grid frequency remains relatively stable.

The other means of speed control--Isochronous--is very tight speed/frequency control. If more than one prime mover is configured to operate in Isochronous governor mode when connected to an AC electrical grid with other prime movers configured in Isochronous mode, the Isochronous governors will literally "fight" with each other to control frequency, and will be increasing/decreasing energy very quickly, causing their outputs to be very unstable.

Hence, the need for some means of "load sharing" developed. As the total load on AC electrical grids increased above the capacity of one generator/prime mover and it was necessary to parallel the outputs of multiple generators, it was important to have the governors operate stably and "behave" when connected with other generators/prime movers.

In the early days of AC electrical power generation, there was only speed control: speed/frequency feedback and speed reference in mechanical governors (fly-ball governors). It wasn't possible to convert load (KW) into mechanicall force to use in the mechanical governors of yester-year.

Today, most governor control systems probably use a 4-20 mA power (load) feedback signal, and use some form of load control as "droop" control to allow generators to "behave" when synch'ed with other generators on AC electrical grids. But, the important point is: There must be some means of stably controlling the power ouput of AC electrical generators when connected with other AC electrical generators on an AC electrical grid. It's still called "droop" control today, it's probably just not accomplished in the same way as it was in the beginning of power generation.

 

Gas (Combustion) turbines, in general, when being operated at rated power ouput are being operated at the upper limits of turbine- and firing temperatures. The air flow through axial compressors is greatly affected by speed fluctuations, and as the air flow increases or decreases the critical temperatures decrease or increase, respectively.

Consider what happens when a combustion turbine-generator operating at rated power output is subjected to varying AC electrical grid frequencies. If the grid frequency decreases, the speed of the turbine-generator--and the axial compressor--decreases, and the decreased air flow causes the critical temperatures to increase. The control system then starts to decrease the fuel flow to decrease the temperatures, which is exactly the opposite of what one really wants to happen! Power output decreases as air/fuel flow decreases during a low-frequency excursion--when one really wants power output to increase to help support the grid.

The opposite is true during a high-frequency excursion.

Remember--this is what happens when the units are operating at rated (i.e. "Base") load. At part load, that droop thing actually does what it's supposed to do.

Yes; the UK Grid Code requires gas turbine control algorithms which monitor frequency closely and actually "over-fire" gas turbines during low-frequency excursions (and the opposite during high-frequency excursion) to prevent what happened on the Malay peninsula in the late 1990s.

Can you be more specific about the reference you cited: BS 132? (Or, should I just be creative with decoding the two-letter acronym.?.?.?)

 

You said that with the reducing frequency, the speed reduces to keep up with the Grid freq... This causes the air flow to reduce (so lower PCD) and the control system acts to reduce the fuel to reduce the temp... But the PCD to Temp curves say that the Control system would increase the fuel as the PCD would reduce... wouldnt it be so?

Rahul

 

For those unfamiliar with the terminology, PCD stands for 'Pressure, Compressor Discharge.' PCD is a GE Mk II SpeedTronic turbine control system signal name for axial compressor discharge pressure. CPD, or, 'Compressor Pressure, Discharge,' is the GE SpeedTronic Mk IV, Mk V, & Mk VI signal name for compressor discharge pressure. (Isn't this fun? Believe it or not, CDP was actually used for a time on some SpeedTronic control systems.... The changes were part of a long-abandoned intent to standardize on a methodology for developing signal names: component, parameter, location, qualifier. CPD for Compressor Pressure, Discharge.)

The following applies to GE-design heavy-duty gas turbines operating on automatic Base Load control, also known as compressor discharge pressure-biased exhaust temperature control. (Newer units use compressor pressure ratio-biased exhaust temperature, which is just a fancier way of calculating the pressure increase across a compressor.)

Rahul, you look at the compressor discharge pressure-biased exhaust temperature control curve and ASSUME that because exhaust temperature increases when compressor discharge pressure decreases that fuel flow is increasing when a unit is operating on automatic Base Load control. You have the ability to prove to yourself what actually happens to exhaust temperature when compressor discharge pressure decreases or increases while the unit is operating on automatic Base Load control.

You have a unit with a Mk V control system. Use Real Time Plotting to collect the following data: plot compressor discharge pressure (CPD), TTXM (Turbine Temperature eXhaust, Median), FQT (Fuel Flow, Total), CTIM (Compressor Temperature Inlet, Median), and DW (Driven device, Watts--the turbine drives, or provides power to the generator, the driven device). All of these values will be plotted against time on the x-axis. (Once you configure the Real Time Plot, it should continue to gather data for those points even if you exit the display to return to the Main Display and then return to the Real Time Plot display. If it doesn't, write back obtain the "switch" to configure Real Time Plotting to "remember" the previous signals and continue gathering data while the user is viewing other displays.)

After gathering the data for at least a 12-hour period with the unit running on automatic Base Load control (preferrably from, say, 1200 hours to 2400 hours, or from 0000 hours to 1200 hours), analyze the data. During the course of any day, as ambient temperature (compressor inlet temperature) increases, air density decreases. As air density decreases, compressor discharge pressure decreases. As compressor discharge pressure decreases, power output decreases. As power output decreases, fuel flow decreases. As fuel flow and compressor discharge pressure and power output decrease, what is happening to exhaust temperature?

It is INCREASING.

As ambient temperature is decreasing, air density is increasing. As air density is increasing, compressor discharge pressure is increasing. As compressor discharge pressure increases, power output increases. As power output increases, fuel flow increases. As fuel flow and compressor discharge pressure and power output increase, what is happening to exhaust temperature?

It is DECREASING.

From the plots, it can be seen that fuel actually increases as compressor discharge pressure increases. Fuel equals torque; torque equals amps; amps equals watts. More fuel equals more more torque; more torque equals more amps; more amps equals more power. Less fuel equals less torque; less torque equals less amps; less amps equals less power.

It _IS_ somewhat counter-intuitive, but that's the way combustion turbines work when operating on compressor discharge pressure-biased exhaust temperature control. From a previous discussion, the negatively-sloped portion of the compressor discharge pressure-biased exhaust temperature control curve represents CONSTANT FIRING TEMPERATURE.

But, firing temperature--the temperature of the combustion gases entering the first-stage turbine nozzles--is not being monitored, only exhaust temperature and compressor discharge pressure are being monitored. When a unit is operating at Base Load, the SpeedTronic is programmed to adjust the fuel as necessary in order to maintain a CONSTANT FIRING TEMPERATURE as compressor discharge pressure (the x-axis "variable" in the equation) changes. Exhaust temperature is the function of the variable (the y-axis).

The alternative is to load the unit until fuel flow reaches some setpoint, and then maintain fuel flow constant regardless of changes in ambient conditions. At some times during the day, the unit would not be producing as much power output as it could; at other parts of the day it might actually be overfiring (exceeding the optimal firing temperature for the turbine section materials) and unnecessarily decreasing the life expectancy of the parts.

But, gas turbines have been operating for decades at Base Load with compressor discharge pressure-biased exhaust temperature control--and doing so reliably and as designed, with optimal parts life and optimal effienciency as ambient conditions vary.

By the way, you should already have plots of fuel flow and exhaust temperature and power ouput as the unit is being loaded from FSNL to Base Load, and unloaded from Base Load to FSNL. In all cases, as compressor discharge pressure increases, fuel flow increases; as compressor discharge pressure decreases, fuel flow decreases. The difference is that at Part Load (when the unit is operating on ... Droop speed control .!.!.! isn't this where we started this thread????), the exhaust temperature increases or decreases as fuel increases or decreases.

Au revoir!

 

This year we replace an old turbine-controller (ProControl ABB) by a new Triconex-controller. Not being familiar with turbines in general, I found your discussions about 'speed droop' an interesting starting-point to build up my understanding on this subject. Thanks for sharing the knowledge...

 

We have a gas turbine generator rated 20 MW with Mark V control system. It is running in parallel with two steam turbine generators rated 10.5 MW each.We are not connected to the grid and run our system in isolation. Our system peak load is 36 MW. We are now running all the machines in droop mode. We would like to operate the gas turbine in Isochronous mode to have a tight control on our system frequency. But we forsee a problem that in case of tripping of big loads, the isochronous machine may unload to below 11 MW and pose a problem to the HRSG associated with it. Is there any way by which we can operate the machine in isochronous mode and ensure that the load on it does not go below a predefined load limit? Is there a logic through which the Isochronous mode be made to revert to Droop control mode on reaching a pre defined load? I guess not. Pls provide your valuable expert comments. It was an amazing experience going through your discussion, starting with the flyball governor and ending with the latest technology.

Best regards.
K.Jayapal

 

It sounds as if maintaining steam flow/temperature/pressure to a process is a requirement, and that you have to manually unload the steam turbines in order to maintain sufficient load on the gas turbine to have sufficient exhaust temperature for the HRSG. Custom sequencing and logic in the Mk V could be written to do something similar to what you describe by monitoring gas turbine output and/or exhaust temperature, but one would think some kind of plant load control scheme executed in a DCS or overall plant control system to monitor load swings and breaker/starter status might be a better option. This way, the steam turbines could be automatically unloaded to keep load/exhaust temperature up on the gas turbine.

Does the gas turbine have IGV Exhaust Temperature Control, sometimes called "Combined Cycle Exhaust Temperature Control"? If so, is it enabled and working? For units with modulated IGVs, this can be used to maximize exhaust temperature at part load operation.

markvguy