01-23-2012 11:27 AM
what are the permissible phase angle difference,frequency difference and voltage difference allowable for synchronization of 608 kva, C18 caterpillar generator sets.
01-23-2012 06:55 PM
In general, a plus/minus 10 degree phase angle is a good starting point for a diesel driven unit. The frequency difference drives the phase angle difference. If you want to do slip frequency synchronizing, typically used if you have an unstable or large unit, and sometimes to help sync a unit to an active bus, then 0.10 Hz is a good starting point.
Voltage match is normally somewhere between 1 and 3%, some systems can tolerate a 5% voltage difference at close, depends on your systems dynamics. I usually start with 2% and watch the system. If you have a good quality electrical protective relay, you can program it to save an oscilliograph on breaker close, then you can review how the generator comes into the system.
01-31-2012 10:41 AM
He gave a good answer above, but I would ask "why?" The smaller the better when to comes to sync'ing. Lower slip Hz, lower phase angle, lower voltage difference. Even small difference in phase angle can have large differences in peak currents that the gen will see. I have seen generators destroyed by coming in 15 degrees out of phase when paralleling a genset to a very stiff grid. But paralleling 2 similar gensets, you can probably parallel up to 20 degrees and still be OK...tough on equipment, but it might survive.
Are you paralleling unloaded gensets and trying to open the phase angle to get them on line faster? If so, there are better ways to do that...see the discussions on Close Before Excitation or Dead Bus Paralleling.
Are you setting protective relays? If so, consult the power system study. There could be other factors at play.
Is one supplying power to a load, and you want to add a second? Then I would use even tighter settings since 10 degrees out might cause enough of a current spike to trip the loaded gen off-line.
Good luck, write back if you want to discuss more.
02-02-2012 11:38 AM
i am planning to use the three generator sets as a standby to the main grid supply. i will check the synchroniation time starting with the lowest voltage ,frequency and phase angle difference setting and i will take the smallest difference setting whith the acceptable synchronization time.
the master will close on dead bus and the slave will synchronize to the master out put and close the contactor when it is synchronized.(the slave will start and sync
hronize based on the load requrement.
i am using the DKG 707 datakom automatic synchronizer module and it has a built in reverse power protection setting. i am planning to set the reverse current to 10 ampere for 3seconds .that means if the reverse current exccedes 10 amper for more than three seconds the controller will dump the load and it stops the genset.i may increase the setting a littile after carefully observing the operation?
how much reverse current do you think a generator of this size can stand. for how much time?
02-02-2012 01:00 PM
There is no way for me to know if 10 amps is OK unless i know the CT ratio, the gen capability curves, etc. Don't guess...you miss and you could destroy your gens.
ANSI 32 = reverse power is not as important in diesel gensets as it is in turbines. You know diesel trucks go down hill and reverse power their engines for several minutes. As long as the current is within the normal operating range and the KVAR is within limits of the gen capability curve and the engine does not over heat or carbon stack, you should be fine. BUT this ONLY way to know for sure is a Power System Study. Without the PSS it is all guess work and 'rules of thumb'. In addition to 32, I would suggest true-ANSI40 protection -- follow-the-capability-curve relays that operate on VARs. Many of the 40 protections out there are really reverse vars (32RV) protections. This is fine for 95% of applications when used in combination with 50/51, 27, 59, and 81 O/U. (current, voltage and Hz)
Expect unstability with unloaded gensets, of course. Nature of the beast. This can add several seconds to paralleling unloaded gens.
What is your time limit to get them on line? Are you in US and/or trying to meet NFPA110? 10 sec? Can you get all 3 sync'd in time? I doubt it. Opening the sync window is the old way and is dangerous with today's minimally designed gensets. You might want to opt for larger framed gens or use Close Before Sync or Dead Bus paralleling. Search these terms and you will see other threads about that concept. I can also send you or you can search for an article published in EGSA's Powerline.
02-04-2012 03:49 PM
I have to agree with Steve, you asked a pretty general question to start your post, now you want specific infomation for a particular system. Your 10 amps could be insignificant at low voltage, could be a lot at higher voltages, without better details hard to make accurate recommendations.
Yes, your prime mover can tolerate some reverse power, you tail end, especially a standby rated one, is likely a bit more sensitive to problems from reverse power or loss of field. New synchronus generators seem to be pretty poor motors, I change a lot of diodes and surge suppressors on newer more units than I ever did on old ones, so I think my field experience would support that opinion.
Get the proper TMI data for your equipment to help generate the proper protective settings for paralleled units. If you're not sure, engage an experienced engineer who knows small generation systems to help until you have the experience you need to do it the right way. Older equipment in less critical systems allowed for a lot of leeway and use of general settings and "rules of thumb". In general for experienced field technicians the original info I gave will provide a reasonable starting point for most CAT and similar sized engine driven generator sets. Oh, and don't assume the settings in the CAT supplied control panel (if installed) will properly protect your unit when installed with other sources of power, or even standalone. The settings are installed to provide a basic set of protections for initial testing of a single unit with a pretty straight forward load, like a resistive or resistive/reactive load bank. Without knowing the other sources of power in a network or the system loads, you can't properly define and implement protective settings that will provide the needed protections required in today's power systems.
Hope that helps, Mike L.
02-21-2012 02:44 PM
i have synchronized only the two gen sets (with all the neutrals solidly connected to the same bus bar and the bus bar being connected to the ground)but after the synchronizer adjusts (to the voltage difference of 5v,frequency 0.1 hz and phase angle to 3) and closes the slave generator set contactor the synchronizer stops the generator set due to high earth current and it goes above 100 amper .then i tried to synchronize the gensets by isolating only the neutralof the slave generaor set from the common neutral bus bar but the voltageof the slave generator set becomes unbalanced and varies significantly when the synchronizer tries to synchronize the slave generator with the master generator set.due to these the synchronizer fails to synchronize. i dont expect these considering that the generators are identical and the voltage difference is small.do you think this has got a connection with the step up transformer installed after the synchronized out put. please give me the possible cause of the problem and solution
02-28-2012 02:28 AM
Today's gensets are not designed to have the same leeway as older gensets. Look at the difference in physical size as one indicator. As Mike said, you cannot reliably use "rules of thumb" any more. You can't guess anymore. You must be accurate and KNOW what is going on.
What you are seeing could be circulating currents. It could be due to different pitches of the machines. It could be due to the exciters being set with different time constants in the regulators. It could be due to different time constants in the genset speed/kw regulators. It could be due to no load--remember above where I said unloaded gens are very difficult to parallel. Add some load and maybe they will stabilize. But if you need 2 or 3 gens on line before you add load, this could be a problem. It could be a transformer--I would need a 1 line to know for sure. It could be phasing problem. Many people think phase rotation is the same as phasing. If you don't know the difference, you should not be starting up parallel gensets.
The old "guess and test" method needs to left to the history books. You could damage or destroy your gens or your power system or worse kill somebody. Today you gotta "study and know" before you test. You need to have a power system engineer help you. You might eventually "guess and test" and get it to work, but the first time the system changes for any reason, you will be back there working on it again. Do the PSS. Know what you are doing or don't do it!
02-28-2012 11:47 PM
Thought I could share some of my experiences on this so much discussed topic even in IEEE papers.. The first issue we need to have clear is that the reverse power and phase angle difference are two different issues and we can discuss this separately.. Firstly on the reverse power it is not so much an Engine issue.. What happens in reverse power is exactly similar to Dyno loading on the Engine.. If the load is too much engine will just go into lug.. The main issue is on the generator and the coupling.. Let us consider the example of truck going downhill and the load on the Engine.. What will wear out is your clutch.. Similarly in a generator the link is the rotor and the coupling to the rotating magnetic field.. When motoring occurs there is a force on the rotor bars.. If the design is strong enough they will not bend.. Also the reversing of the magnetic field rotation in motoring will cause heating of the rotor.. So the reverse power settings are directly connected to rotor withstand. Conventionally the current decrement curve of the generator and rotor time constant should be able to provide you a guideline of the settings.. Usually it is 15% for smaller and 10% for larger units depending on the rotor design and 10 secs is the delay. These data can be had from the manufacturer generator data sheet.
When it comes to phase angle difference it cannot be seen in isolation.. What happens is that the rotor will get pulled to synchronization by the grid .. During this time there will be some amount of motoring also as usually the incoming generator will be brought in at a lower frequency.. This is the frequency difference that we are talking about.. This again is dependent on the rotor design and machine size.. There is a very interesting case study in IEEE where they have tried out a 31.5 KVA DG with grid and paralleled with a 20Deg angle and 10 % voltage and frequency difference.. The results suggest that this is well within the generator short circuit capacities.. As you can see the angle difference depends on the generator size.. Medium generators(500 kVA and Above) are usually safe Upton 10 Degrees and lager ones (2000 kVA and above) suggest 6Deg ..
Voltage difference will cause reactive current circulations.. The capacity of the generator to withstand the KVA will depend on the power factor after closing.. Higher the voltage difference the greater the reactive current and the generator derates due to leading power factor and will not withstand.. The operating curve of the generator vs power factor will be a good indicator of the range. Reverse KVAR can protect in this case.
Typically for a 608 KVA I would start with a 10 deg angle and a 5% voltage and frequency window.. Based on how the system behaves and load swings I would try to get the optimum point for smooth operation..
Hope this helps..
02-29-2012 12:40 AM
The phase angle-mismatch-withstand also LARGELY depends on the impedance of the source you are paralleling to. If you are paralleling to a very stiff grid, that is low z and very fast time constant, the current (reactive and real) that flows at 10 degrees of mis-match will be significantly different than the current that flows between 2 30kva gensets at 20 degrees out.
It also depends on the real and reactive current flow to the load. I won't get into each case, but you can see this easily when you parallel 2 unloaded gensets vs adding a genset onto an already loaded genset. Think about the case where the loaded genset is already at 98% forward KW and you parallel 10 degrees out of sync and cause 20% current flow. Depending upon the reactive and real power flows, you could kill the entire system.
I have seen where 20 degrees out destroyed a generator. Did not break the coupling. Did not harm the engine. Destroyed the generator windings. It looked like the end turns were ripped out and then came in contact with the frame and rotor. (OK, maybe they had done 20 degrees out many times: that we will never know.)
I have seen where 180 degrees out just tripped the CB and did no damage to either one. It was an OLD generator, huge iron and copper. They don't make them that way anymore.
When someone gives out "rules of thumb" or "this is what worked in the past" they are just guessing. You can tell because they are cloaking their answers in CYA with that phrase. By definition they are history. Call them up and say, "I followed your advice and my genset is destroyed. I want you to pay for it." Then see what happens.
So again I say, "pay me now or pay me later" when it comes to power system studies. If you don't KNOW what will happen, you can only GUESS what will happen. Might as well go to Vegas and bet it all on red...
And I will say again, I am not a PSS engineer. I do not sell PSS's. But with today's minimally designed components and liability laws you cannot afford to guess.
PS: Srivatsa, please add paragraphs to your writings. Your content was good, but it is hard to read.