We have installed at our facility a 13.8 kV, 16.8 MW synchronous turbine-driven generator. We are currently experiencing an issue when placing the generator in service which I will attempt to summarize as best as possible.
Initially, the total power consumption by the facility is approximately 10 MW, which is supplied by the utility, at 13.8 kV with a power factor of 0.83 (or thereabout). When placing the generator in service, the excitation is turned on, after which the generator's supply is automatically synchronized to the utility's supply. Once the three breakers (generator, utility and tie) are closed, the generator is then loaded in Droop.
A power factor switch is turned on in order to toggle the excitation's control system (DECS 200) mode from AVR to PF control. Once this is completed, despite the power factor setpoint of the DECS being set at 0.8, the actual power factor drops immediately to approximately 0.2 - 0.3. The amperage drawn by the generator increases instantaneously from 250A to 800A. As the generator is loaded to match the demand from the users on its own loads, the power factor indicated for the utility drops from 0.83 to 0.4 or thereabout, with an additional current draw as well.
Once the generator is loaded to the required 5.5 MW, the tie breaker is opened and the power factor switch immediately turned off to return the mode of the DECS to AVR (with a pre-position setpoint of 13.8 kV). At this instant, there is a voltage spike from the generator, sometimes reaching between 14.8 - 15 kV (max range of the measurement device), which oftentimes causes upsets to lower-voltage equipment. The system then normalizes to the required 13.8 kV and 0.8 power factor while being operated in isochronous control. Based on this response, it seems that there is significant additional excitation which is immediately dissipated when the control is switched from power factor to AVR control.
Thus far, we have listed the DECS as the most likely cause of the issue, specifically when it is operated in power factor/droop control mode. The generator appears to be performing as required based on the output from the DECS as it functions without any issues in AVR/isochronous mode. Checks on the DECS were made to verify that the contacts were switching correctly based on the input signals received.
Although I do not believe that the generator's performance is to be questioned, it must be noted that this action was only observed after conducting some repairs to the unit approximately 1 year ago.
We do understand that operating the generator under these conditions means that we will be generating power inefficiently, as well as placing strain on the generator's windings based on the increased current draw/heating of the windings.
Based on the scenario provided, I would like to request the assistance of anyone who can provide some further insight/guidance into this issue, as it pertains to the reason for the behaviour of the generator in this condition, as well as any possible corrective measures that can be implemented (beside replacing the DECS) in order to resolve the issue or other checks that can be done on the system to gain more insight into the issue.
I do look forward to any feedback and questions.
Thanks and Best Regards.
You have most likely answered your own question:
>...., it must be noted that this action was
>only observed after conducting some repairs to the unit
>approximately 1 year ago.
What, exactly was the work done approximately 1 year ago? Why were the repairs necessary?
It would appear that everything was working correctly PRIOR to the repair work, so if you identify what was done then you can redo the repair works to correct the issue(s).
Based on the information provided, It would seem something is amiss with either the PT inputs and/or the CT inputs, and it's even possible the DECS 200 configuration has been improperly changed.
Again, if it worked properly before the repair works, something done during the repair works would seem to have been the problem.
Please write back to let us know what you discover!
As a Generator TFA and based on my experience, I would look at the current transformers, in particular the polarity.
When you are in automatic mode the regulator is only reading the PTs and hence do not care about the CTs. In that configuration, it seems that you are not experiencing any problem. But switching in PF mode will cause the AVR to read the CTs and the VTs to determine what is the actual reactive power and try to match the current value with the set point. If the AVR is reading a false reactive power, the regulator may act in te opposite way as it should. Send negative excitation order to increase the MVArs etc.
What you can do is to cross the MVAr and the MW values between the AVR and the protection relays for example. Obvioulsy you need to be sure of the relay you are reading.
Second, when you operate the generator in automatic mode, try to send +Exc order from the local display and check that MVAr are increasing.
The last thing I can think of, is how the AVR is expecting to see the phase sequence. Some companies make mistakes like setting up the AVR settings in ABC while the real sequence is ACB.
You may also look at the PTs, because if two phases are inverted, the same problem as described will happen.
Many thanks for your inputs CSA and Saul!
In October 2015, we experienced a mechanical failure of the PMG, which is coupled on the rotor shaft of the generator. One of the magnets was released onto the neighbouring exciter windings. As such, the PMG was completely removed from the shaft (as there is an alternative UPS to the DECS) and the exciter re-wound. With no physical damage to the stator windings, they were only varnished and baked.
It is indeed correct to say that everything worked with no issues prior to the repairs. Prior to the re-installation of the generator, the settings on the DECS were compared to the "As Left" settings from the commissioning of the unit, with no differences noted. All electrical connections were reconnected using photos taken, together with the wiring drawings in order to double check ourselves that no wiring mix ups were implemented.
The two avenues which are being considered are the functionality of the DECS when in PF mode and the phase differences between the two power sources (generator and utility). We will definitely check also the CTs as they play a vital role in the calculation of the PF when in PF mode.
Apart from verifying the CTs as an additional check, we did not have to remove the measuring CTs or disconnect wiring for the CTs which are used as an input to the DECS for PF. The setpoint of the DECS remains at 0.8 while the actual PF drops to the 0.2 - 0.3 range. One of the checks I will complete is to compare the DECS kVARs value to that of the generator's breaker independent metering system which also provides kVARs reading. This can confirm if the value being fed to the DECS during PF mode is accurate as this will not be a intermittent faulty reading. Can you please elaborate on "cross the MVAr and the MW values between the AVR and the protection relays for example?"
When the generator is operated in automatic voltage regulation (AVR), adjustments to the setpoint can be made manually using a Raise/Lower switch. We have adjusted this previously and the voltage and field current is increased. When in PF control, adjustments to the Raise/Lower switch have no effect on the actual PF, as the setpoint remains at 0.8 even as the PF decreases. However, with these adjustments, I did not observe if the MVARs was being adjusted as well. I will confirm the phase sequence as well. I will add the PTs to the list of things to check at the next opportunity.
Many thanks again for your inputs!
Whether you are in automatic or PF mode the DECS do exactly the same thing. It regulates the excitation field current flowing through the rotor.
The difference is the nature of the setpoint. In one case it regulates the excitation field current to match the voltage setpoint and in the other case it regulates the excitation field current to match the MVAr setpoint.
Let's say that the DECS is reading the right stator voltage and the right stator current magnitude, but not the right angle between them. Then you might have a flawed active and/or reactive power.
If the DECS is reading a false reactive power, for example if it reads a negative reactive power instead of positive one then it will never be able to reach the setpoint. By trying to reduce the gap it will actually increase it to the maximum untill it reach the limitations.
That is why you need to be 100% sure of the MW and MVAr read by the DECS.
Did you replace the PMG? Did you do a new magnetization of the magnets?
Thanks for the elaboration Saul!
Agreed on what the DECS does for the regulation of field current based on the mode and subsequent setpoint. I now understand what you meant by cross between the MW and MVArs. Since we made no changes to the DECS (wiring or software configuration), I believe this should be accurate. But it would definitely not hurt to double check.
We did not replace the PMG but removed it completely from the loop. Instead, we utilise a UPS to the DECS. This was actually done a few months prior to the mechanical failure of the PMG.
One new part of information we obtained is that the supply by the utility was switched from one distribution center to another at the end of 2015. With our generator out of service, it may also be worth checking the phases of this supply, just to ensure everything is as before. I will definitely schedule to check on the MW/MVAR readings obtained.
Thanks for the input Saul!!
You are welcome.
You should also check that the power of the UPS supply is strongh enough to support the excitation needs. Specially is the source has been swapped.
It sure seems, from the information provided, that when the DECS is transferred to PF control that it is not seeing the reactive current change--the signal from the CTs, usually. AND, we know the PF is going very low--but we DON'T KNOW if it's going in the LEADING or LAGGING direction. (I presume it's going in the LAGGING direction, because when the unit goes back to AVR mode the voltage is very high.)
I'm not extremely familiar with the Basler products, but one would think there would be some kind of "bumpless transfer" or smoothing of the jump in reference when transferring between PF (or VAr) control and voltage control ("AVR mode").
To my way of thinking--the DECS should not be transferred out of AVR mode to PF mode during grid-tie operation. It should be left in AVR mode, and the operators should be manually controlling the PF by adjusting the AVR setpoint both during grid-tie and isochronous operation. At least until the cause for the issue is understood and resolved. If transferring to PF mode is causing upsets and potential generator winding harm--and problems with other components when transferring back to AVR mode when switching from grid-tie to isochronous operation--then simply DON'T use PF mode until the cause is understood and resolved. That avoids the inefficiency issue, the potential generator winding damage, AND the component damage. Just don't use PF mode until the cause of the problem is resolved and understood.
Hope this helps!
Agree with CSA.
You should totally avoid operating the generator in PF mode until this problem is fixed.
Actually, I never seen any generator operating on the grid with a power factor of 0,2 or 0,3.
Did you notice any alarms/limitations while in PF mode?
Some good news is that we got the opportunity to load the generator, and it was not switched to power factor mode. This worked really good as there was no significant change as when it was switched. Now we will proceed to center our checks around the phase measurements for the generator as this may be the most likely cause of the problem. Just btw there were no alarms noted in previous synchronization attempts. Many thanks for your contributions.
Thank you very much for the feedback!
We look forward to hearing what you discover as you search for the root cause for this problem, too.
I have been extremely impressed by what you have returned here. There are similar situations happened in my plant. currently we are using steam turbine driven generator (11kV, 15MW) to sync with grid (very very stable). Our AVR and synchroniser are both from Basler Electric.
During the recent few times attempt to sync with grid, we found that immediately after generator breaker closed, the turbine speed drops a lot (sometimes from 5377rpm to 5240 rpm, generator is rated at 1500rpm. there is a gearbox between generator and turbine) which is very unusual.Also, sometimes, generator real power (MW) shoot up to 15MW which I cannot explain the reason why. This situation happened within 5s which it is not possible for the governor react to inject enough steam to generate 15MW. The total plant load before sync is around 4MW.I do understand that after generator tied with grid, the turbine speed should remain because grid frequency remains which has been mentioned by Mr CSA many times. Previously, after sync, turbine speed will drop around 10 rpm and immediately return back with the help to governor and no real power swings. Sometimes, after this generator power and turbine speed swings, generator will trip on reverse power(protection relay setting is 450kW for 3s).
I am struggling to find the root cause but my idea is that there should be something wrong with the synchroniser. It means the generator does not sync with the grid at the correct moment.My understanding on this, generator should only sync with the grid when the turbine speed is stable at the speed of grid frequency level rather then during accelerating or decelerating because there will be inertia for the turbine to keep accelerating or decelerating even after generator breaker closed.
I cannot explain why the turbine speed drops too much and generator real power spikes too much.
I really need your guys expertise on this.
Thanks and regards
What happens when a synchronous generator is synchronized to a (very very) stable grid is that it's speed immediately changes to the generator's synchronous speed--that is 1500 RPM for a 50 Hz grid. It can't slow down or speed up to anything more or less than 1500 RPM because the magnetic forces in the generator between the rotating magnetic field and the apparently rotating magnetic field of the stator lock the rotor into synchronous speed--again, 1500 RPM for a 50 Hz grid.
I would suggest that whatever method is being used to gather data is not very high speed, once per second or less, maybe.
It could be possible that the prime mover governor has an issue with what it does when it detects the generator breaker closes. Many governors, when operating in Droop mode (when the generator breaker closes when synchronizing to a grid with other prime movers and governors) add a little "bump" to the energy flow-rate into the prime mover to ensure there is positive power out of the generator to prevent a reverse power condition. Could there be something amiss with the setting of that "on-line setpoint" as it's sometimes called?
Again, if the grid is very very stable it's difficult to imagine how the speed could drop--because once the breaker closes the rotor magnetic field is locked into the speed that is a direct result of the frequency of the grid. It can't slow down--or speed up--as you have described if the breaker is, indeed, closed. Magnetic forces at work in the generator between the two magnetic fields lock the rotor speed in to the apparently rotating magnetic field of the stator that is a function of the grid frequency.
Now, if the unit synchronizes out of phase (which should be very difficult, if not impossible, if the synchronizer and the synch-check relay are working properly) it IS possible that for a split second the rotor speed will suddenly slow down OR speed up but it will even MORE SUDDENLY come to a STOP when the North pole of the rotor catches up with the South pole of the stator and the South pole of the rotor catches up with the North pole of the stator and it will then be spinning at synchronous speed. That is usually accompanied by a very large BUMP, and if the phasing is seriously out then even worse things can happen, like breaking the coupling shaft between the reduction gear box and the generator rotor flange, and/or damaging the reduction gear teeth/bearings, and/or the coupling between the turbine shaft and the reduction gear box.
Also, some MW transducers are NOT very fast responding, and they can produce what appear to be excessive load swings at times of unusual operation, much larger than are really being experienced--which can also be exaggerated by a slow data-capture and -storage system which interpolates between actual data points.
Without a LOT more in-depth knowledge of the system at your plant and how it is being operated, and what may have changed--because it would seem this is a relatively new situation, and things were working correctly before, so something seems to have been changed or disturbed (most likely in the PT and/or CT wiring circuits--which should ALWAYS be verified if wires are lifted/landed/disturbed during some outage, forced or planned!) which is causing this problem to begin.
You might have some data about the steam inlet control valves to see if there is actual movement which might cause steam flow to suddenly increase--or even station someone within visual distance of the valves to observe their operation during synchronization.
It's very difficult to say too much more.
A generator can be synchronized either running a little slower than grid frequency, at grid frequency, or a little faster than grid frequency. What happens if the generator is running a little faster than grid frequency is that the generator rotor will slow down when it is locked into grid frequency--and the extra energy that was making the rotor spin a little faster than grid frequency becomes positive amperes flowing out of the generator stator, producing positive power output. (Remember--that's what generators do: they convert torque to amperes.)
When the generator rotor is spinning at the exact same speed as the grid frequency and the generator breaker closes, the power output will be zero watts (kW; MW) because there is no "extra" energy flowing into the generator.
When the generator rotor is spinning at a speed that is slightly slower than grid frequency and the generator breaker closes the power output will be negative watts (kW; MW) because there was insufficient energy flowing into the prime mover to make its speed at least equal to or slightly greater than grid frequency. And, so amperes flow into the generator stator to make the rotor speed up and rotate at the grid frequency speed (synchronous speed), and that is reverse power. The generator at this point has become a motor--and a load on the grid instead of a producer on the grid. And, for a steam turbine this is not a good condition--because the generator is now spinning the steam turbine faster than the steam flowing the steam turbine can spin it and that creates forces in the opposite direction from normal as well as creating heat by spinning the turbine blades/buckets in the steam flow path. That's why reverse power relays are so important--to protect the prime mover from damage when the generator becomes a motor because the prime mover isn't supplying enough torque to the generator to produce positive power output.
The generator rotor MUST spin at synchronous speed--and it will, because of the magnetic forces at work inside the generator when the generator breaker is closed. If the torque being supplied is in excess of that required to make the generator rotor spin at synchronous speed, then the generator converts that torque to amperes which is positive power flowing out of the generator stator.
If the torque being produced by the prime mover is less than that required to make the generator rotor spin at synchronous speed then the generator will draw amperes from the grid to keep the generator rotor spinning at synchronous speed. And in this condition the generator becomes a motor, and reverse power is flowing from the grid into the stator to keep the rotor spinning at synchronous speed. And, depending on the prime mover, that is NOT a good thing. And, it's also not good for the unit to be a load on the grid and taking power from other prime movers and generators.
The only difference between a motor and a generator is the directions of torque and amperes. A generator converts torque from the prime mover to amperes that flow out of the stator. A motor converts amperes flowing into the stator into torque to drive a load (even if that load is temporarily a prime mover!).
Hope this helps! We would need a LOT more data to be of any further help for this particular situation. Please write back to let us know what you find!!!
Really appreciate your reply. I was doing troubleshooting with synchroniser and turbine OEM for the past few days. Would like to give an update on this issue.
Tell the result first. We tried to sync 2 times and it was successful at the 2nd time. The 1st time was tripped by reverse power trip. The 2nd time was good but the power spike was still there and the person near the turbine they can hear a 'bump' sound on the turbine. I believe the problem is still not solved.
Before we did the actual sync, we have done few simulation test for the synchroniser. We found the frequency raising command issued by synchroniser to turbine control is not properly tuned and we change the frequency adjustment pulse from continuous pulse to 4s width pulse (proportional pulse, the actual pulse width is proportional to the frequency difference between Generator and Grid) with 10s pulse interval. The turbine reaction for this pulse is set to 1rpm/s. It looks like a very conservative speed control. But the outcome is still ok. we can see that Generator frequency and grid frequency falls into the range (+0.05Hz, it means synchroniser will only issue a closing breaker command when generator freq is higher than grid freq within 0.05Hz).We can also confirm that voltage for generator and grid is also matched (voltage difference setting is 1%).
What we cannot explained is why there is still a power spike immediately after sync. It is also abnormal that we found the grid frequency dropped from 49.99Hz to 49.2Hz which is totally unexplainable. It may be a false reading. But it will be very hard to prove the reading is wrong. We also saw that turbine speed dropped 30rpm right after the time of Generator breaker closing. I would link this 2 phenomena (turbine speed drop and power spike to -17MW) together. Turbine control will switch from speed control to load control after breaker closing. My suspect is that the time of switching to load control is too long so that load controller cannot cut in and react to the grid immediately by increasing the turbine speed or increasing the torque.
Another possibility is that error in the measurement meters. I suspect the meter maybe give some funny readings with a sudden change in PT and CT secondary reading since when the breaker closes, the current flow happens.
Another reason I am thinking is the phase angle diff is too large so that a very huge current flowing out of Generator, this will directly cause the power spike to -17MW. Is there anyway to confirm the phase angle immediately after breaker closing. The current breaker closing time is tested and set at 49ms in the synchroniser. We do see the phase matches from the synchscope at the time of sending breaker closing signal while doing the simulation test.
I would like to know what is the normal control logic after Generator breaker closing. What the turbine control does after this.
The discussion is still ongoing. Will update soon.
When did this problem start? (In other words, had the unit been running without problems for some time and then this problem started? Or are you trying to commission the unit (turbine control system, including synchronizer) and trying to tune the unit during synchronization?)
>Another possibility is that error in the measurement meters.
>I suspect the meter maybe give some funny readings with a
>sudden change in PT and CT secondary reading since when the
>breaker closes, the current flow happens.
If you're just using meters to detect changes in speed and load and frequency, and you're not using some kind of trending/data recording method, then it's likely the issues you are seeing aren't real. The "bump" reported by the observer is most likely the change in turbine speed when the generator breaker is closing. Again, the typical method of synchronization is to have the generator (and turbine) spinning slightly faster than synchronous speed. This is one way to ensure that when the generator breaker closes the unit will pick up load, and produce positive power (watts; kW; MW). The turbine control system usually maintains the speed reference at a slightly higher value than synchronous speed after synchronization, and the extra energy (steam in this case) that was making the unit spin a little faster than synchronous speed gets converted to armature amperes when the generator breaker closes and the unit gets locked into synchronous speed. That's probably the "bump" sound being heard.
The exciter regulator, sometimes called the AVR, can also cause some issues if it's not adjusted correctly and doesn't maintain voltage during and after synchronization. For the same reason that speed is to be a little higher during synchronization than synchronous speed, generator terminal voltage is to be a little higher during synchronization than grid voltage. This is to ensure that when the generator breaker closes that positive reactive current (positive VArs; a lagging power factor) will occur at the time of synchronization. And, just like turbine controls, some AVRs have an adjustment that actually increases generator terminal voltage at the time of synchronization to also help ensure positive reactive power after synchronization.
If the turbine control system can't trend data, and the plant doesn't have any data recording/archival/retrieval equipment you will probably need to rent some kind of data recorder(s) to help with understanding what's going on. You will need to connect them to the existing PTs cna CTs, or some can be rented with their own PT/CT set-ups (some may even have clamp-on CTs which will help greatly with connection and removal). You should also be monitoring turbine speed to see what's happening with that at the time of and immediately after synchronization.
You have said the grid is very, very stable. Unless this plant is located a very great distance from the main grid and the grid in your location is considered to be "soft" it's entirely inconceivable how the grid frequency can be dropping when your turbo-generator is synchronized to the grid. Entirely inconceivable. And, if it was working for a while, and then this problem started--WHAT CHANGED?
What happens when you try to synchronize the unit manually?
Many steam turbine control systems operate in Isochronous speed control during synchronization and then switch to Droop speed control at the instant the generator breaker closes. Some do switch to load control at the time of synchronization, but many do not. Can your turbine control system be programmed to NOT switch immediately to load control at the time of generator breaker closure--and if so, what happens when that is tried? In my personal opinion the operator should select load control after synchronizaton--not the control system. Or the control system should not select load control until some time after synchronization had been successful and the unit has time to stabilize. But, at the time of synchronization the unit should be in or switched to Droop speed control--immediately upon breaker closure, if not before.
Droop speed control is the governor mode that allows generators and their prime movers to be synchronized with other generators and their prime movers and share in the production of power as if all the generators were really one large generator. That's one reason why it's called synchronization--because all of the generators are locked into synchronous speed (their synchronous speed) and are running at the same frequency. One, or seven, or 87 generators can't be running at 49.36 Hz, while 6 or 8 or 92 are running at 50.34 Hz, and others are all running at 50.0 Hz. They all have to run at the same frequency, which is at their synchronous speed (based on the number of poles of the generator). If not, what then makes 50.0 Hz come out of the outlet on the wall???
Many steam turbine controls operate in Isochronous speed control mode during off-line operation (start-up and acceleration), and during synchronization. But they MUST switch to Droop speed control immediately upon generator breaker closure or there will be odd things happening. Droop speed control is, again, how multiple generators and their prime movers all share in the stable production of power. If a machine is synchronized to the unit when it's in Isochronous speed control mode, it will behave very badly, until such time as it is either tripped of line or switched to Droop speed control mode. (We're speaking of large, or "infinite," grids. Small isolated loads and grids can be slightly different with one or more units operating in Isochronous speed control mode or Isochronous load-sharing mode.)
You need reliable data--called "actionable data"--to understand what's happening, and meters don't do that, especially in today's modern world where meters are not nearly as accurate as they were before and are rarely, if ever, calibrated. Even "digital" meters are not good at instantaneous measurements/displays because they have to sample the input to convert it to a digital display. To troubleshoot issues like this, you need good data--fast and reliable. Some turbine control systems, and some plant control systems ("DCS" control systems) can get good, high-speed data. Some digital electrical meters (manufactured by companies like Schweitzer (sp?), and Basler, and others) capture data which can be downloaded and analyzed.
Thanks CSA for your help. You are really nice.
We are currently using GE PQM and GE Multilin Relay to capture Generator and Grid power parameters. Our current turbine control is using Siemens PCS7 and this was updated in 2017 from Turbolog. Synchroniser and AVR was updated in 2015. We saw this kind of power spike after 2015. We do have trending for monitoring, is there any way to share with you since I cannot find attachment upload function here. I have to rush back to do troubleshooting and will be back soon to update you any findings.
If you are seeing these kinds of spikes and frequency changes using a PQM (Power Quality Meter) and Multilin relay, then I would have to say the grid is NOT as very very stable as you would like to believe. Either that or there's something not right with the metering PTs and CTs and/or their circuits.
I was going to suggest that some turbine control systems use a contact from the generator breaker to switch from Isochronous speed control to Droop speed control when the generator breaker closes during synchronization. That contact MUST be a direct-acting contact from the generator breaker itself--not from an interposing relay or another control system. If there is any delay in switching from Isoch to Droop--and this is all just conjecture at this point--that can cause the turbine control system to misbehave during the time delay.
Many people have posted trends and drawings and such to free Web-hosting sites, such as tinypic.com, and then posted the link to the material on control.com. That's about the only way to share information, unfortunately.
But, based on this new information, and on my experience, I don't feel there's anything more I can offer. I'm not a fan of using PLCs for turbine control--not that they're not capable, it's just that they usually require some special cards (contrary to popular belief) and some special software to be able to handle high-speed rotating equipment control and protection applications. And, they usually have to use one or more signal converters which can introduce errors and points-of-failures to the system that aren't generally present with a purpose-built turbine control system. There are some control system integrators that are very capable and have a lot of experience with PLCs as turbine control systems and do a fine job of applying PLCs as turbine control systems. And, there are also lots of control system integrators that are very good at applying PLCs for lots of other applications but which don't have the experience or the capability to apply a PLC as a turbine control. It's really a mixed bag and one doesn't know what they're going to get UNLESS they asked for references from the potential supplier(s) and talked to the references to see what their experience was. That's difficult and most people don't do it, and some live to regret that decision.
If you can post your information to a site and then post the link to this thread, someone might be able to provide some additional information.
A bit more findings after yesterdays troubleshooting.
I suspect the phase angle is the issue. This may result from 2 reasons which can not be confirmed yet since plant is running. I will check and confirm during blackout day.
1. I will check PT secondary connection for both Generator and grid. Since I found generator PT is star-open delta connection and grid PT is 2 windings PT.
2. I will check again generator and grid PT secondary side to synchroniser voltage sensing input wiring connection.
Normally, the turbine controller is configured to automatically increase the speed setpoint reference to a certain amount (e.g., 30 or 50 rpm higher than synchronous speed) upon synchronization purposely to drive the control valve to open by some amount so as to inject sufficient torque to the prime and thus convert this torque into corresponding MW of power. The main purpose of such arrangement is to prevent reverse-power as fully explained by CSA.
We called this as initial loading or bias setting of the turbine controller upon generator synchronization.
Pls check. Your controller must have this setting configured.
Appreciate your help.
I have checked with my control engineer. My current logic is that when breaker closes, turbine speed setpoint does not increase immediately but track the turbine speed PV and adjust the governor opening percentage. For the last attempt, turbine speed dropped from 5377rpm to 5310rpm. Then the system increase turbine speed setpoint for the purpose of bringing back the turbine speed to 5377rpm, at this time, governor opens another 5%. Is this logic correct?
I believe this is already late in terms of turbine reaction after sync.
My control engineer's worry about this is if directly increase the setpoint, then the governor will open too much. When we track other plant within our organisation, there is no speed drop after sync, i am not sure whether there got any same logic as what you suggest for now. but if at this situation, what will happen when increase the speed setpoint by another 30 or 50rpm?
Really appreciate your help again.
Sorry for jumping in to this part of the thread, govyman, but I, personally, have never seen this kind of logic. I don't think you have ever posted what the reduction gear box nameplate lists for input- and output speeds. Specifically, what is the input speed for a 1500 RPM output speed? What is the 50.000 Hz RPM for the steam turbine (what is the turbine's synchronous speed)?
And, specifically, tell us what the speed is during synchronization just prior to breaker closure, as well as what happens to turbine speed just after breaker closure (as close to breaker closure as possible), and then what happens to turbine speed 0.5 seconds after breaker closure, 1 second after breaker close, 1.5 seconds after breaker closure, 2.0 seconds after breaker closure, 2.5 seconds after breaker closure, and 3.0 seconds after breaker closure.
As has been said several times, when synchronizing the turbine speed will be slightly higher than the turbine's synchronous speed, so, for example, if the turbine's synchronous speed was 5360 RPM, the turbine speed during synchronization might be 5377 RPM (for a speed differential of 100.3%). At the time of synchronization to a very, very stable grid operating at 50.00 Hz the speed would drop by exactly 17 RPM to 5360 RPM. MOST turbine control systems would hold the current speed setpoint (100.3%) which would keep the steam control valve at it's same opening, which would be admitting a little more steam than is required to keep the unit spinning at 5360 RPM (because it was spinning at 5377 RPM during synchronization prior to breaker closure)--and this "extra" steam would ensure a positive power output of the generator. The extra torque that WAS keeping the generator spinning at 1504.5 RPM (100.3% of rated speed) will be converted into armature amperes by the generator when the rotor is locked into synchronous speed (1500 RPM) when the generator breaker closes.
In addition, many turbine control systems add even a little more energy to the prime mover (steam flow in your case) to ensure a positive power output from the generator, particularly when the grid isn't so very, very stable.
Are you synchronizing to a grid with many other generators and their prime movers, or are you synchronizing to an small grid that is supplying a load that is isolated from a "large" grid? Because, that's about the only way I could understand how the turbine speed could change so much after synchronization. You have mentioned a 15 MW spike (I presume that was a positive 15 MW spike), AND you have also mentioned a -17 MW "spike" (or dip). I'm a little confused about this.
If the turbine speed was higher than grid frequency at the time of synchronization then the load (power output) "spike" at breaker closure should be positive (on a relatively stable grid). If the turbine speed was lower than grid frequency at the time of synchronization then the load (power output) "dip" would be negative--because what would happen is that the grid would have to supply power to the turbine-generator to increase the speed to match grid frequency.
If the unit is not being synchronized to a stable grid, or is being synchronized to a small, isolated grid (sometimes called an "island" grid) supplying a local load such as for a refinery or cement plant or something similar, and there is an external control system that is sending signal(s) to control frequency, that could be part of the problem. If the unit is being synchronized to a utility grid with tens or hundreds of turbines, many of which might be much larger than your steam turbine, and the grid frequency is, indeed, stable then it's very difficult to understand how, under normal circumstances, what you describe is occurring.
You mentioned in one post that the total plant load before synchronization was approximately 4 MW. Is the turbine supplying this load before it is being synchronized to a larger grid? I'm getting more confused as I re-read the previous posts. Please help to clarify your previous posts.
Apologies for misunderstanding. Let me clarify.
It is a -17MW dip rather than a spike for this time. Sometimes it has 15MW spike also. My generator PT is 3 windings star-open-delta connection. Grid PT is 2 windings connection. The previous ABB synchroniser is equipped with phase angle compensation function. I am not really sure how the function is achieved.
I found that the turbine speed characteristics was not always the same. The recent time, at 1s speed is 5316, 1.5s 5345rpm, 2s 5380rpm.
I am wondering any possibility of the freq drop may because of long distance from grid. Only freq of my plant premises is dropped, and when this travels to the grid, the effect is very minimum.
Before sync, 4MW is purely supplied by grid. After sync, we will adjust the generator MW setpoint to share the load.
Thanks for your continuous support. I really appreciate it.
I have heard of plants located a long distance from a grid on a certain type of connection (can't recall the type) experiencing problems with unstable frequency, but not like this. This seems odd. How far away is your plant from the main grid? Is it a single connection to the grid? How far is your plant from the nearest generator and prime mover (other plant)?
So, I take it that there was another synchronizer before. And did the unit have the same problem when synchronizing?
And, if there was another synchronizer before, was there another turbine control system before??
You still haven't told what the turbine synchronous speed is. What is the turbine speed when the frequency is 50.0 Hz? (The reduction gear nameplate should show this information.)
I could imagine a situation where if the turbine control system closed the control valve slightly during synchronization immediately after breaker closure that the MW would dip negatively. But I would also expect the reverse power relay would trip the breaker/turbine on -17 MW, even if it was only for a split second--most reverse power relays operate such that if the reverse power is very high in magnitude the relay will trip the unit very quickly. If the reverse power increases in magnitude slowly then the relay will trip more slowly.
If the speed is dropping as much as you say it is, that's NOT good for the reduction gear or the couplings between the turbine and the reduction gear or the reduction gear and the generator.
And if the phase angle is really wrong when the breaker is closing that's not good for the couplings, the reduction gear or the turbine--or the generator rotor. The "bump" must be a BIG bump.
Very strange problem.