I am a Ge-F9 operator. Our grid company asked us to remote the unit so they can set the preferred load for the unit through AGC. Also they said that during sending setpoints through AGC, the primary frequency control through governors should be ON.
But when I want to remote the unit, I should turn off the primary frequency control. actually the remote key is freeze as long as the primary frequency control is ON.
here is my question:
How can I remote the unit for AGC commands at the same time that primary frequency control is ON through governors?
My mail: Loghman.email@example.com
When AGC is ON, what is the signal coming from the grid--is it a load reference (usually a 4-20 mA signal), or RAISE- and LOWER SPEED/LOAD signals to increase or decrease the turbine speed reference (usually discrete signals (contact closures))?
When AGC is ON, what operating mode is enabled and active?
Does the Mark* turbine control system have the GE Primary Frequency Response option/feature? If so, has it been used, and if so, was it successful?
When the turbine is operating with AGC OFF do you Pre-Selected Load Control to operate the unit?
Technically speaking, Part Load Droop Speed Control IS primary frequency response--but NOT if Pre-Selected Load Control is enabled and active. UNLESS the Mark* has the PFR (Primary Frequency Response option AND it's working properly).
We need the answers to ALL the questions to be of any further assistance.
So, I've re-read the original post several times, and it's beginning to make more sense now (sorry; sometimes I can be a little more obtuse than usual).
Without being able to see the programming in the Mark* at your site, it would seem (based on the information provided) the Mark* has the GE Primary Frequency Response (PFR) option, and that when it's active you can't choose Remote mode??? Is that correct?
That would seem to be a programming issue with the Mark*. Either someone didn't program it correctly, OR, someone didn't want PFR to be active when REMOTE was selected.
Here's how GE's PFR option works; it's not easy to explain without graphs and drawings AND we have to start with Droop Speed Control (yes, Droop Speed Control). When the unit is operating at Part Load (less than Base Load), AND Pre-Selected Load Control is NOT enabled or active the reference for the governor function of the Mark* is turbine speed. And, turbine speed, when synchronized to a grid with other prime movers and synchronous AC (Alternating Current) generators is controlled by the grid frequency--NOT by the turbine speed reference.
BUT, Droop Speed Control works on the DIFFERENCE between the turbine speed reference and the actual speed (which is a function of grid frequency). So, if the unit is running, at say, 80 MW (Part Load of a machine rated at 120 MW (in our example)) on a day when the ambient temperature matches the turbine nameplate rating and the unit is faily clean and not needing a maintenance outage, AND Pre-Selected Load Control is OFF, it is running on Droop Speed Control. And, since 80 MW is 2/3 of 120 MW, and the unit probably has a 4% Droop characteristic, that means that the turbine speed reference will be approximately 102.67%. And, if the grid frequency is stable the actual turbine speed will be 100%, and the difference between the turbine speed reference and the actual turbine speed will be stable at 2.67%. That difference is used to calculate how much fuel is going into the combustors, which affects how much load is being produced by the turbine-generator.
Now, if the operator wants to increase the load, he will click on RAISE SPEED/LOAD which will increase the turbine speed reference, which will cause the error between the speed reference and actual speed to increase--which will cause the fuel flow-rate to increase and increase the load. And if the operator wants to decrease the load, he will click on LOWER SPEED/LOAD and the difference between the speed reference and the actual speed will decrease--which will decrease the fuel flow-rate and decrease the load. Both of these conditions presume the grid frequency is stable; it might be at 99.7% or 100.1%--but it is presumed to be relatively stable.
Now, if the grid frequency changes (let's say it decreases from 100.1% to 99.5%), then what will happen is that the difference between the speed reference and the actual speed will increase--just as when the operator clicks on RAISE SPEED/LOAD and the grid frequency is stable. This will in turn cause the fuel flow-rate to increase which will increase the load--this is done to try to help the grid frequency to return to normal. Sometimes it helps, sometimes it doesn't. BUT THAT'S WHAT'S SUPPOSED TO HAPPEN AT PART LOAD!!! The load is supposed to change to try to help support grid frequency/stability.
And, that's one of the things that Droop Speed Control does--AUTOMATICALLY.
If the grid frequency increased while the speed reference was stable, then the difference (the error) between the speed reference and the actual speed would decrease, which would cause the fuel flow-rate to the turbine to decrease which would decrease the load--in an effort to help the grid frequency return (decrease) to normal. Again, that's automatically done by Droop Speed Control. Droop Speed Control technically provides Primary Frequency Response. (In some parts of the world, Droop Speed Control is being called 'Free Governor Response' because it allows the governor to freely respond to grid frequency disturbances.)
Now, in the GE Mark* system when Pre-Selected Load Control--or AGC--is active, the Mark* looks at the actual load being produced and compares it to a load setpoint (either the Pre-Selected Load Control setpoint, or the AGC load setpoint) and it adjusts the turbine speed reference to make the actual load equal to the load setpoint. AS LONG AS GRID FREQUENCY IS STABLE this works just perfectly.
BUT, let's say the unit is operating at 80 MW with Pre-Selected Load Control--or AGC--active, and the load setpoint is 80 MW. As long as the grid frequency is stable, the speed reference will be stable (at 102.67% in our example) to make the load stable at 80 MW--which will make the fuel flow-rate stable. NOW, if the grid frequency decreases what will happen is that the difference between the turbine speed reference (102.67%) and the actual turbine speed (which is now LESS than 100%, let's say 99.4%), and that will immediately cause the error to increase to 3.07% which will cause the fuel flow-rate to increase which will cause the load to increase above 80 MW to try support the grid.
BUT, because either Pre-Selected Load Control or AGC is active with a load setpoint of 80 MW, the Mark* will REDUCE the turbine speed reference below 102.67% to try to reduce the load back to 80 MW--which is EXACTLY the opposite of what should be happening when there is a frequency disturbance! And, this causes the grid to be even MORE unstable--which is NOT desirable for anyone (power producers OR Customers).
So, what GE did to correct this little goof in the governor control programming was to implement something they call "Primary Frequency Response" (PFR) and it sees that if the actual turbine speed changed because the grid frequency changed then it will NOT adjust the turbine speed reference to try to maintain the load control setpoint. Which is what SHOULD be happening anyway. PFR was designed to correct a goof in the Mark* system that would ONLY happen if Pre-Selected Load Control (or AGC) were active.
[And, that's the REAL PROBLEM--most sites ONLY use Pre-Selected Load Control to operate the unit. They REFUSE to EVER even TRY to operate the unit at Part Load without Pre-Selected Load Control Active. And, so when the grid frequency deviates from normal the Mark* WILL NOT respond as it should--as it WOULD if Pre-Selected Load Control (or AGC) were not enabled.]
So, this "work-around" (PFR) was developed to allow people to use load control (Pre-Selected or AGC) to respond properly to grid frequency disturbances as if load control was NOT enabled.
What seems to be happening, based on the information provided, is that when the unit is in REMOTE (when AGC is to be active at your site?!?!!?) the programming in the Mark* will not allow PFR to be enabled. That may or may not be by design--you really need to consult with the supplier of the Mark* to understand why it was programmed that way, or even if it can be programmed to allow PFR to be active when REMOTE is selected (AGC is enabled).
If the grid company is sending a load control setpoint (either by 4-20 mA signal or something similar, like MODBUS or GSM)--AND they want the unit to properly respond to grid frequency disturbances when AGC is active then you are going to need to work with the supplier of the Mark* to understand if this can be--or should be--accomplished. (In my estimation, it should be possible--but I don't know all of the facts of this situation.)
If the grid company could monitor the load of the turbine-generator (using a 4-20 mA signal or MODBUS or something similar) and send RAISE SPEED/LOAD or LOWER SPEED/LOAD commands (discrete contact closures) and the unit was NOT operating with Pre-Selected Load Control or AGC Load Control using an actual load setpoint, then the unit could be operated in Droop Speed Control and it wouldn't need PFR.
But, that's asking management to make a HUGE leap of faith that most management isn't willing to make.
Best to work with the Mark* supplier to understand what is happening, and why, and what's possible--if anything.
Hope this helps. It's not easy to explain, but it is pretty simple if you understand Droop Speed Control and how it's supposed to respond to grid frequency disturbances, and how the GE Mark* turbine control system little "goof" actually responds when Pre-Selected (or AGC) Load Control is active. And why it was necessary to "invent" Primary Frequency Response to fix that little goof.
Thanks a lot for your complete answer.
here is an example:
1) the unit is operating under AGC (Remote).
2) the unit is operating in 80 MW (part load) and rated power is 120 MW
3) Unit is in Droop control Mode
4) Reference speed = RS (controls with AGC command = new setpoint)
5) Actual speed = AS (controls with grid frequency)
6) fuel rate = RS - AS
7) the AGC commands to unit to go to 90 MW = RS increase
8) at the same time of "7", grid frequency decreases = AS decreases
9) according to "6", fuel rate increases and final output became for example 92 MW (90 MW from AGC + 2 MW because of frequency drop and maybe the output became 88 MW in case of increasing frequency)!! So logically its no problem and fuel rate can be control by changing RS and AS at the same time regardless to increase or decrease each of them. what is important is "RS - AS" which controls the fuel rate. I saw this logic in V94.2 Siemens gas turbines named load/speed control that load control (RS) and speed control (AS) can be active in parallel. but in my GE unit, steps "1" and "3" cant be activate together.
regardless to AGC, I want a mode that feedback from Frequency and at the same time I can send setpoint commands to unit (4-20ma).
I don't know if I could change the logic myself for my purpose. So as you suggested I should talk to the supplier.
1) When AGC is ON,the command is a 4-20ma current command.
2) When AGC is ON, I should enable Pre-select so that the grid operator can send 4-20ma commands as new setpoint to the unit. for enabling Pre-select, first I should turn off primary frequency control (droop control). but I don't prefer to do that. I want the droop control be On in parallel with AGC.
3) the droop control is being used until now and its OK.
4) When the turbine is operating with AGC OFF, it's OK because I use Pre-Selected Load Control to give new setpoints to the units and after stabilizing the unit output. I will turn on droop control again.
5) actually I want that Preselect and Droop control be active at the same time so that the unit can correct the grid frequency and also get setpoint commands from AGC.
It's probably a language issue, but you don't seem to understand how GE heavy duty gas turbines are controlled--which is similar to how just about every other prime mover (be it steam turbine or gas turbine) that is synchronized to a grid with other prime movers.
When the unit MASTER SELECT control mode is set to AUTO, the default modes of operation are:
Droop Speed Control (Part Load operation)
CPR- (or CPD-) biased Exhaust Temperature Control (Base Load operation)
The TOTAL amount of fuel being admitted to the turbine combustors (the fuel flow-rate, or, the FSR (Fuel Stroke Reference)) is a function of EITHER Droop Speed Control (the difference, or error, between the turbine speed reference and the actual turbine speed, OR the TOTAL amount of fuel being admitted to the turbine combustors is a function of the allowable exhaust temperature limit.
Droop Speed Control is active between FSNL (Full Speed-No Load) and Base Load operation.
CPR- (or CPD-) biased Exhaust Temperature Control is active when the IGVs are at maximum operating angle AND the turbine exhaust temperature (TTXM, Temperature, Turbine eXhaust Median) as a function of the Compressor Pressure Ratio (or the Compressor Discharge Pressure) is at the maximum allowable limit (TTRX, Temperature, Turbine Reference eXhaust). This is known as "Base Load"--the maximum allowable power that can be produced for the present machine and ambient conditions.
Now, with most F-class machines since they usually have DLN (Dry Low NOx) combustors the total fuel flow to the combustors is divided (or "split") between various fuel nozzles in order to control exhaust emissions (usually NOx, but sometimes also CO). That has nothing to do with either Droop Speed Control or Exhaust Temperature Control.
When the unit is NOT at Base Load, it is considered to be at Part Load. And when it is at Part Load, it is being operated on Droop Speed Control. Droop Speed Control was described previously, and it's really very simple: it's based on the difference between the turbine speed reference (which is how the operator or the control system changes load when the grid frequency is stable) and the actual speed of the turbine-generator (which is a function of the grid frequency when the unit is synchronized to a grid). Normally, the grid frequency is very near nominal (rated), and relatively stable. So, to change the load of the unit one changes the turbine speed reference, which changes the difference (the error) between the turbine speed reference (a value called TNR in the Mark* turbine control system, for Turbine Speed Reference) and the actual turbine-generator speed (a value called TNH in the Mark*). Both are expressed in percent, and when TNH is subtracted from TNR, the difference (the error between the two) controls the total amount of fuel that flows to the combustors.
The above describes what happens when Pre-Selected Load Control, or some other form of Load Control (and AGC control usually qualifies as a similar form of Load Control in the Mark* turbine control system) is that there is a load control setpoint (or reference) and the actual generator load is compared to the reference and the turbine speed reference is adjusted to make the actual load equal to the load control setpoint (or reference). Again--this is VERY important: When load control is active, the Mark* compares the actual generator load to the load control setpoint (reference) and modifies the turbine speed reference to make the actual generator load equal to the load control reference.
When load control is NOT active, load is not, per se, being controlled--only the amount of fuel being admitted to the combustors. And that control is a function of the difference between the turbine speed reference (which is variable) and the actual turbine-generator speed (which is variable--but should be relatively constant and stable). Yes--the operator, when clicking on RAISE- or LOWER SPEED/LOAD is watching the MW meter (and NOT the actual speed--because it doesn't change when clicking on RAISE- or LOWER SPEED/LOAD) and stops clicking on RAISE- or LOWER SPEED/LOAD when the value of the MW meter equals what is desired. BUT, what is really happening in the background is that when the operator is clicking on RAISE- or LOWER SPEED/LOAD the turbine speed reference is changing--NOT a load setpoint or reference! And, as the turbine speed reference changes the difference (or the error) between the turbine speed reference and the actual turbine-generator speed changes and THAT change in the difference (the error) causes the total amount of fuel flowing to the turbine combustors to change. Which changes the load being produced by the generator (because the torque being produced by the turbine is changing). When the value on the MW meter is equal to the value the operator is trying to achieve, he stops clicking on RAISE- or LOWER SPEED/LOAD and the turbine speed reference stops changing, and as long as the grid frequency is constant and stable the difference between the turbine speed reference and the actual turbine generator speed stops changing and the fuel flow-rate will stop changing--which means the torque being produced by the turbine will stabilize and the load being produced by the generator will stabilize.
HOWEVER, when load control (Pre-Selected, and MOST types of AGC) is active (and it can really only be "active" when the unit is below Base Load) then the turbine speed reference is modified by the Pre-Selected Load Control function to make the turbine load equal to the Pre-Selected Load Control reference (setpoint). Just like the operator monitoring the MW meter to achieve, or maintain, a particular desired load setpoint (or "reference") and clicking on RAISE- or LOWER SPEED/LOAD to achieve or maintain that desired load setpoint, load control is comparing the actual turbine-generator load to the load control setpoint and adjusting the turbine speed reference (essentially by "clicking" on RAISE- or LOWER SPEED/LOAD!) to make the actual turbine-generator load equal to the load control setpoint. That's why when Pre-Selected Load Control is enabled and active you see the RAISE- or LOWER SPEED/LOAD "buttons" on the HMI flashing orange from time to time--because load control is doing the EXACT SAME THING and operator would when manually controlling turbine load, it's just doing it automatically (so the operator doesn't have to click on RAISE- or LOWER SPEED/LOAD, and can keep reading the newspaper or eating biryani, or texting with his family, or surfing the World Wide Web instead of watching turbine load).
Now, as was described above there is a little "goof" when load control is active--because it will cause the Mark* to do exactly the opposite of what it should do when the grid frequency--and the actual turbine-generator speed--changes. SO, GE came up with a function (option) called Primary Frequency Response (PFR). It's usually turned ON or OFF with a button on an HMI display. And, what this function (option) does is allow load control to be used continuously AND the Mark* to respond appropriately to grid frequency changes while load control is active.
As was also previously mentioned, in some parts of the world Droop Speed Control is being called 'Free Governor Control.' It really is frequency response because that's one of the main attributes of Droop Speed Control is that it causes units (not operating at rated power output!!!) to change load when grid frequency changes to help support grid stability and to try to help the grid to return to nominal rated frequency. Some grid companies refer to Droop Speed Control as 'primary frequency control,' or even as 'primary frequency response.' That DOES NOT mean the Mark* has PFR (Primary Frequency Response)--it just means the grid company/operator wants the prime mover governor (the Mark* turbine control system) to properly respond to grid frequency disturbances NO MATTER WHAT MODE OF CONTROL OR OPERATION THE UNIT IS OPERATING IN OR UNDER. Call it what you (or anyone) will: Droop Speed Control is what the grid company/operator wants. They want units to properly and appropriately respond to grid frequency disturbances whenever they are synchronized to the grid. Full stop. Period. The GE goof that causes the unit to respond in exactly the opposite manner than it should makes grid frequency disturbances WORSE--and nobody wants that.
Now, since the AGC load setpoint is coming in to the Mark* as a 4-10 mA signal, it's almost certainly a load setpoint (or reference), and to make it work some kind of load control must be selected (sometimes it's labelled as AGC; sometimes it's labelled as REMOTE LOAD CONTROL; sometimes it's labelled as EXTERNAL LOAD CONTROL). BUT, ESSENTIALLY it is the same as described above--it is a load control setpoint (or reference), that is compared (by the Mark*) to the actual turbine-generator load, and the Mark* adjusts the turbine speed reference to make the actual turbine generator load equal to the load control setpoint (or reference). (You should see the RAISE- or LOWER SPEED/LOAD buttons flashing orange as the turbine speed reference is increased or decreased to keep the actual turbine-generator load equal to the load control setpoint--when AGC is active, JUST AS WHEN Pre-Selected Load Control is active!!!)
IF the Mark* has the (PFR) Primary Frequency Response function (or option), it should be possible to enable PFR while load control (Pre-Selected Load Control or AGC load control) is active to allow the load to be automatically controlled AND to properly respond to grid frequency disturbances. We don't know if the Mark*(s) at your site have the PFR (Primary Frequency Response) function (option). AGAIN, it would have to be programmed in the Mark* and it would, typically, have to be enabled by an operator by clicking on a button on an HMI display. Just because the grid company/operator is asking for 'primary frequency response' DOES NOT mean that the Mark* has the Primary Frequency Response (PFR) function (option)!!! Similar words and/or terms are often confusing.
IN MY EXPERIENCE (more than 30 years), when any kind of load control is active (Pre-Selected Load Control; AGC; REMOTE LOAD CONTROL; EXTERNAL LOAD CONTROL; etc.) the unit, even if it is Droop Speed Control at Part Load (less than Base Load) the unit WILL NOT properly respond to grid frequency disturbances. That is why GE "invented" what they call Primary Frequency Response. And, in my experience, it has to be enabled by an operator by clicking on a button on an HMI display. It will allow any kind of load control to be active AND permit the Mark* to properly respond to grid frequency disturbances at the same time.
Finally, it is NOT possible to have Pre-Selected Load Control AND any other type of load control (AGC; REMOTE LOAD CONTROL; EXTERNAL LOAD CONTROL; etc.) active at the same time. Only ONE method of load control can be active at any time. Full stop. Period.
One more thing--when a unit is operating on CPR- (or CPD-)biased Exhaust Temperature Control it WILL NOT respond properly to grid frequency disturbances. It IS NOT on Droop Speed Control; it is CPR- (or CPD-)biased Exhaust Temperature Control. The reference for fuel control is no longer speed--it is exhaust temperature as a function of CPR (or CPD). (In fact, the unit will respond exactly OPPOSITE to grid frequency disturbances when it is on Base Load; but that's ANOTHER topic for another thread and another year.)
So, to be clear: In order for a unit to receive a load control setpoint (reference) and to control the actual turbine-generator load to make it equal to the load control setpoint reference, it has to be at Part Load (less than Base Load). AND, UNLESS THE GE PRIMARY FREQUENCY RESPONSE (PFR) FUNCTION (OPTION) IN THE MARK* IS ENABLED AND ACTIVE if the grid frequency deviates from nominal the turbine-generator WILL NOT respond appropriately to the grid frequency deviation (disturbance). Only one method of load control can be active at any one time. The GE Primary Frequency Response function (option) is required to allow any kind of load control to be active AND for the Mark* to appropriately respond to a grid frequency disturbance. And, it must be active (usually by an operator clicking on a button on an HMI).
The GE Primary Frequency Response (PFR) function (option) could be programmed to be active whenever any kind of load control is enabled and active. But, that is not typically done, though it could be. AND, if the unit is operating at Base Load (CPR- (or CPD-)biased Exhaust Temperature Control) even if the GE Primary Frequency Response (PFR) function (option) was active, it WOULD NOT cause the unit to properly respond to a grid frequency disturbance.
This is the way GE heavy duty gas turbine control systems work--typically. GE Belfort (who has the responsibility for GE Frame 9 heavy duty gas turbines) has been steadily making changes but this is pretty basic and it probably hasn't changed too much. (Though with GE Belfort, one can NEVER tell what they are going to change, though one can always tell WHY they changed something: because they can (not because the should, but just because they can and their way is ALWAYS better. Even if it's not.)
Hope this helps!