Synchronized or Islaned Mode Operation

If I understand you correctly, you have indicated that the local generation is inadequate for the total plant load, and that any outside switching causes the voltage to sag, so Islanding is not an option.

If you were asking whether the governor/load control could be set to Island Mode while you're synchronized to the grid, the answer is still no because you would force the local generators to run at a fixed load while using the utility to act as your swing bus, something they would not be pleased to do.

You have to provide more inertia for your system. You can provide this inertia in a number of ways, add flywheels to the critical rotating loads, add flywheels to your existing generation, or provide the same effect plant-wide by increasing your generating capacity beyond that needed to carry your plant without any grid support. You could also install a huge UPS to carry the motors through, install DC motors and a battery system to keep them running, or install a huge flywheel driving an unpowered generator (all forms of added energy inertia).

When operating in Island or Frequency mode:

If starting of one of these big motors causes a disturbance bad enough to trip the plant, then you must not be in Island mode when starting one of these motors.

When operating in parallel with the local utility:

You are synchronized to the local grid so that you can draw power from them when a big motor is starting. This means that your frequency and voltage will be determined by the local utility.

If the utility's power is so off specification as to cause you problems, the only thing I know to do is to separate from the utility when they are operating off spec. or when you suspect that they may have a disturbance bad enough to cause you trouble.

This means that your generators must be very reliable and you must be able to synchronize to the utility when you need more juice to start a big motor.

These are fairly common problems where plants have to either deal with unreliable local utilities or there are no utilities available because of remote location.

My question to you is what is the 300 to 500 ms switching time thing?

If you are paralleled to the utility and decide to go island, there should be no local loss of power. If everything is set up properly to switch the VRs and governors into local parallel isochronous load sharing or You zero your load across the tie to the utility and then open the tie. There should be little or no disturbance on either the plant or utility bus when the separation is made.

When your plant is island and you decide to connect to the utility, your generators must match phase and voltage to the utility and then close the tie. Again, if done correctly, there will be very little if any disturbance.

This assumes that your switchgear, voltage regulators on your generators and your governors are setup properly to do the switching hot.

The only time I see power drop outs like you describe are when the local utility power fails and it takes some finite time for the utility tie to open, leaving the plant in island mode or when the utility is lost and the generators must load or unload to make frequency/voltage.

Could you tell us a little more about how the switching and load shed logic works?

Well, 300 to 500 ms is the time taken by the grid swichgear in case of lightning strikes impact over de overhead line to first open, then re-close and finally open if the foult persist because the arc is yet stinguished, that is the stimate period to not close againt the fault, if the first reclose is succssesful then you have to wait up to 1.2 to 1.3 sec for the motors residual voltage decay and the phese sequence be on aceptable valeu to restart the motors to avoid an overcurrent and get an success restart.

If the time are beyond 1.3 sec. then the motors reduce the rpm therefore the flow meters trip the plant. it is really a litter bit complicated and require a deep study to explain in this forum. I jus give an idea as you request.

To clarify other member, the national grid is powerful so it is not weak but this accur through the world to strong systems.

That is why I posted this question to all wonderfull CR4 member

Bye

Since you cannot handle big motor islanded, maybe you should prohibit starting them until returning to the Grid.

Dear Mr.juanJ.Isdray,

In your posting, You have not indicated, the H.P/KW of the big Motor(s) and type of Starter used for starting the motor and whether you have provision to switch on capacitor bank, so as to reduce the Line current. You have to furnish the details here, for proper understanding of the issue.

Are you using, AUTO-SLIP REGULATOR type of Starter, for starting the Motor.? If not try this Starter. Use of Capacitor bank, combined with ASR starter, in my opinion, should solve your problem.

What is the driven equipment.? Whether the shaft on the non-drive side can be extended to fix a v-belt pulley drive and a small capacity motor and start, say 20% to 30% of rated speed and then you start the regular motor. This will reduce the Inertial Force and control the current drawn by the motor.

For a similar problem, I have done this and solved the problem. Of course, De-clutching arrangement to be provided to stop belt drive after starting the motor.

I am eager to know details and how the problem is solved.

DHAYANANDHAN.S

Dear Sir.

Please see post #3 reply for you to clarify more about it

Motors are 440V and 6 KV from 75 to 1500 HP driven pump, compressors ID fans etc.

Soft start is not possible to use due to process requirements threfore all motors are DOL start.

Thank

Bye

If it is several motors coming onto the generators at once, can the motors be sequenced to restart at different times? If the plant could survive with various motors dropping off completely during this transient, maybe you could stay online.

The total motor are not included in the restart schedule only the essential for process equipment about 40% of running load operation to keep the process ready to go back to 100% of production

, they are start by hand or By DCS system

It seems to me, from your information,that

1. following Grid disconnection, due to "auto reclose sequence"; the local generators are unable to hold the load without a frequency dip which causes their shutdown.
2. You give a 500 ms off-Grid time and 2 x 10 MW local generators. But it is not clear if site load L (excluding motor start) is less than generator rating G or more.
3. If L > G, then maybe a selective load shed of non-essentials could help.
4. If G > L, we are guessing about the proportion of rating the generators are at when Grid is disconnected. In this case, the rate at which the engine can respond to increase power is critical. We do not know how much power engine has to increase in 0.5s. I can only say that if the engine is lightly loaded, its response is much slower and that using isochronous will not help if the engine response is slow anyhow.
5. A bit more information please!!

Hi 67 model

In my OP I intentionally omited several technical details because my main purpose was only to know the wise forum members think how is the best way to operate an industrial installation provide with on-site generators when thr Grid present unstable PQ due to lightning strikes and othes disturbances. latter on in post # 6 I tried to give more information.

After all, I agree the jack of all trade recommendation as the best comment of how to management this contingency.

Any way, to put and end of this issue I try to answer you back your questions.

No 2 The site load is less than generator rating

No 3 The essential load was pre-selected by process engineers

As you can imagine it is not an easy matter to be define in a forum due to involved several equipments as motors, switches,protective devices etc.

For your information, the electrical system architecture is as following:

• Two 115 Kv overhead supply lines
• two 115/6.3 Kv main transformer to feed a secundary selective circuit by 6.3 and 480V
• one main 6 KV switchboard with a tie CB
• two on-site generator connected into both side of the 6 Kv busbar (2x10MW)
• 20 6 kv motors from 250 to 1500 HP
• 10 stepdonw distribution transformer (6/0.480 Kv)
• About 1200 480 motors

Thank for your attention

Bye