Can someone help me out with Generator Power factors and consequences when working on a network or island mode?
I got asked today what would happen when the power factor of a generator got more lagging. I said that would depend on what caused it to get 'more lagging'.... Surely this could mean that the KW has dropped and the KVar has stayed the same, or the Kvar has increased and the KW has stayed the same, this could be due to a number or things. Guy says that KW are always going to be the same on a generator in island mode and that only KVar would change to make the powerfactor go 'more lagging' ... The impact this would have is that the generator would get reverse Vars from the loads and trip on reverse power.
I just thought this is wrong? Reverse power trip on generators is only when the system receives amps from loads or networks isn't it? Say if I lost the engine to my generator, the loads or network would supply amps to the Generator because it is now motoring. This would cause a reverse power trip. Maybe I'm completely wrong..
I thought if the power factor went from 0.8 lag to 0.5 lag, the problem could be either the prime mover is unable to keep up with the current demand and the generator would trip on overload or under frequency (because it would be drastically trying to power the load), or say the current demand is fine, but the Vars are greater. The AVR has to supply a great deal of excitation to the generator to keep that load running? This could cause problems in the currents induced in the generator and could cause a trip on overheating of the exciter or rotor? If someone could explain what would happen when going from 0.8lag to 0.5lag that would be much appreciated.
I have the same question when connected with another generator in a network and the PF of one machine falls to 0.5, what would happen and what would you do. But I'd rather have a sound knowledge of what would happen in the first case before I move on.
In island mode, with a single generator supplying a load which has a large number of induction motors, for example, the generated kW and the generated kVAr must both match the kW and kVAr required by the load. In this case, the governor will adjust fuel flow to maintain the kW match, and the AVR will adjust excitation to maintain the kVAr match.
If a large motor is added to the load, but is itself unloaded, the kW requirement will not change significantly but there will be an added kVAr requirement. To maintain system voltage, the AVR will increase excitation. The power factor delivered by the generator will fall (become more lagging). There will be an increase in total current which can be worked out from the capability diagram. If the mechanical load on that motor is subsequently increased, the active power will increase but the kVAr will not change significantly. There will be a further increase in current. The power factor will increase and the stator current will also increase - again, the effects can be seen from the capability diagram.
The power factor of the generator in island mode will not just "get more lagging" - it can change only in response to events on the connected system. This of course assumes that the governor and AVR are function to maintain speed and terminal voltage respectively. There is no way a reduction in load kVAr can cause a reverse power trip when there is an active load being supplied (although strange things can happen with the protection if the CTs and VTs aren't connected properly).
Once again, Bruce Durdle steps in to save the day--thanks!
I find it helpful to think of reactive power (VArs; power factor) and system voltage as being similar to real power (watts) and system frequency? For example, when the amount of real power being generated matches the amount of real power being consumed the frequency of the system (small or large) is at rated. If the amount of power being generated is less than what's being consumed, then the amount of consumption (the load) doesn't change, but some of the energy that's required to maintain rated frequency goes into supplying the load causing the grid frequency to decrease.
Similarly, the amount of reactive load (VArs) on a system is a function of the nature of the loads (inductive; capacitive) and the requirements of the loads. And, unless something is done to counter the reactive component of the load the system voltage will vary from rated/nominal as the reactive load changes. On a small system (a single generator supplying a load consisting of real- and reactive components) when the reactive load is stable and the excitation being applied to the generator rotor is equal to what's required to keep the system voltage at rated and the reactive component of the load increases (because some additional reactive load is added to the system) if nothing is done to change the excitation being applied to the generator rotor then the system voltage will change.
Inductive loads tend to reduce system voltage, so while the inductive reactance doesn't just change unless inductive load is added or removed from the system, when inductive load is added to the system the net effect is for the system voltage to decrease. And, it's necessary to increase excitation (or use some other method to counter the voltage decrease) in order to maintain system voltage. This is why when air conditioning loads on an AC power system are very high the system can experience low voltage and what's called "brown-outs." The reactive component of the number of induction motors driving the refrigeration compressors and pumps and forced air fans can be very high and cause the system voltage to "sag" requiring synchronous generators to compensate by increasing their generator rotor excitation to counter the effect of the reactive load and help to support system voltage. Since the power required to increase generator excitation has to come from somewhere--that amount of power to supply the real load of the system is slightly decreased, and since most generators only get paid for watt-hours and not VAr-hours they don't want to produce VArs (support system voltage) unless they absolutely have to.
If there is more than one generator supplying a load--a real load--and one of the generators reduces its output (in other words the load remains constant but the amount of generation doesn't change) what will tend to happen is that the system frequency will tend to decrease. One or more of the remaining generators will have to increase their generation (watts) by an amount equal to that lost when the one generator decreased its load in order to return the system frequency to normal. Or, if more resistive load is added to the system and no generator increases its output by an equal amount then the system frequency will decrease until one or more generators increases its output by an amount equal to the load increase which will restore the grid frequency to normal.
If there is more than one generator supplying a load--with real and reactive components--and the loads (real and reactive) are stable but the power factor of one of the generators decreases suddenly (or increases suddenly) the power factor of the other generator(s) will change by an equal amount but in the opposite direction. Again, if the reactive load is stable the only thing that can change is the amount of that reactive load being seen by each of the generators. And, for the power factor of one of the generators to change that (usually) means that the excitation of one of the generators has changed, and that will likely mean some change in the system voltage.
Changes in real load (resistive loads) on an AC power system result in a change in system frequency--unless the total amount of generation (watts) changes to keep the frequency constant. Changes in reactive load on an AC power system tend to change the system voltage--unless the excitation of one or more of the generators changes to keep the system voltage constant.
While there are a lot of other factors at work here (counter-emf; armature reaction; etc.) these are the effects seen by operators when monitoring generator- and system operation as loads (real and reactive) change.
The term reverse power refers only to real power--watts; amperes. There are generator protective relays that monitor under-excited conditions (lagging power factor at the generator terminals) to protect the generator against slipping a pole or from becoming an induction generator (for a very brief time as the heat generated when this happens can increase very quickly!).
Hope this helps! It's a great question, and, once again, I thank Bruce Durdle for being the voice of reason.
There are two generators with capacity 320 KVA and 500 KVA, if these two are run in parallel, the power factor of 500 KVA will remain 0.8 whereas the power factor of 320 KVA goes down to 0.5 from 0.8 If these two are run independently the power factor of both will remain 0.8. There is another 320 KVA generator if this generator is run in parallel to 500 KVA generator the power factor of these two will remain 0.8.
What are the possible reasons for decreasing of power factor in first case of 320 KVA generator to 0.5 from 0.8 and steps to be taken to improve power factor to 0.8
Voltage droop of the two generators to be set for this issue.
for this two step procedure
first step, nominal voltage of both genset to be set to equal at no load. (ex 450V set to both genset using nominal voltage adjustment in AVR).
second step, a constant load (for example 100 kVA) to be connected on genset 1. note down the voltage drop (for example nominal voltage 450 to goes down 445.8V).
connect that same load (100KVA) to genset 2 and set the voltage to 445.8V by using the droop adjustment in AVR.
after power factor will be same.
Read CSA's Post in:
When did this problem start?
It's likely if the units were running without problems for some time, and then after some repair or modification or maintenance work the problem started, then something was disturbed in the wiring between the generator excitation (AVR) control systems. The area most likely to be at fault is the droop- or compensation circuitry.
However, there are so many possibilities for wiring and interconnecting the generator control systems (particularly the excitation (AVR) control system), and for interconnecting the generators themselves (types of transformers; proximity of transformers to the generators; interconnection possibilities; etc.) that without being able to see detailed drawings and understand how the units are operated it's impossible to speculate any further.
These types of problems, especially ones that start after the plant has been running properly for some time, can usually be traced to either maintenance or repair works, where wiring problems were unknowingly introduced. OR, often, when control systems are upgraded or modified, inadvertent problems can be introduced (wiring; configuration; programming). So, as is often the case with a lot of troubleshooting--it's a logical process of elimination, eliminating the possibilities one at a time until the root cause is identified.
BUT, the process can usually be reduced to a limited number of possibilities if during the review and analysis and planning for troubleshooting the time when the problem started is identified and then any works done at that time are reviewed.
Hope this helps!