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Interconnection with Utility

Interconnection with Utility

Interconnection with Utility

(OP)
We are studying the generator impact on the local grid. One of the requirements is, the generators shall operate in automatic voltage control mode. Other operating modes such as Constant VAr regulation mode and power factor control mode are not acceptable for connection and operation. However, voltage control mode would limit the output of the generators in order to maintain the high power factor ( above 0.90 lag). But the load customer desires to utilize the their on-site generator as much as possible and purchase as less power as possible from the utility. Power factor control and Varc control would allow the user to produce more power and purchase less power, however the shutdown of the generators would cause high inrush in the grid, which is not desired by the the utility. Any suggestions?  Any discussions are appreciated.   

RE: Interconnection with Utility

For a generator that is relatively small compared to the connected system, voltage control is pretty pointless. Watt/VAr or Watt/PF makes far more sense. A generator can actually comply with either over a broad wage of real power output while attempting to maintain compliance with the wrong voltage schedule can severly (and meaninglessly) real power output. If you insist on voltage control then you have to give them free reign on power factor.  

RE: Interconnection with Utility

Has your customer considered running their own generators on an N+1 basis and not using the grid. Or possibly a small service from the grid for critical lighting and black starting?
Without knowing the capacity of the and the number of the generators and the load profile of the plant our suggestions are sort of guessing in the dark.
The tariffs and penalties will have a big influence on the final operating plan.
Some points that you may encounter.
The power that you buy will be at a much greater price than power that you sell.
To get the best price for power sold you may have to assure steady delivery of power. If there are any interruptions in your generation the penalties may be very severe.
Similarly, demand charges often account for about 50% of a power bill for an industrial plant. You will want to look at the net profit for a months energy sales. You will then want to look at the penalties back charges and demand charges that you will incur should your generation go off-line. Check your tariff, some demand charges persist for a year or more once incurred.
Consider also a partial generator failure where your client must decide whether to curtail the plant in order to honor your commitments for power sales or to keep the plant online and default on power sales.

As far as voltage control,you may be able to use a transformer with an On line Tap Changer to control both voltage and power factor. If it is not feasible to use a tap changer you may be able to use a bank of distribution type voltage regulators.

Get back to us with as much information as possible.  

Bill
--------------------
"Why not the best?"
Jimmy Carter

RE: Interconnection with Utility

Hamid are you north or south of highway 11?

Bill
--------------------
"Why not the best?"
Jimmy Carter

RE: Interconnection with Utility

Is the utility requiring AVR mode or is it because NERC requires Generator Operators to use AVR mode per VAR-002-1? I am not sure what the generator size is before you have to worry about that.

My understanding is that our plants run in AVR mode to provide voltage support during transient events, but that there is also an outer control loop that adjusts the AVR set point very slowly based on the power factor at the high side bus.

 

RE: Interconnection with Utility

Constant VAr or power factor control is not allowed in most systems due to some wide area cascading blackouts where that control mode was a contributing factor.

Constant VAr control is great from the generator's perspective.  As the system voltage and generator MW changes the AVR automatically keeps the generator at the MVAR operating point.

When some generation or tie lines are lost during a system upset, the system voltage may drop. Additional reactive power output is needed from all remaining generators to raise system voltage back to normal. But the generators operating in constant VAr mode see their reactive power increase suddenly due to the drop in system voltage. So the AVR reduces excitation to bring MVAr's back in line.

If enough generators are in constant VAr or pf mode, the system voltage drops more instead of increasing.  That drop pulls more MVAr from the generators so the AVR reacts and drops voltage further.  Finally the system voltage collapses and the avoidable blackout spreads.

RE: Interconnection with Utility

(OP)
The generator is 150MW, which is huge. The utility requires the plant to run the generator at Voltage control mode while maintaining at least 0.9 power factor. Another option I am  thinking of is to have 2X85 MW Generators. If only one fails, the grid won't see a bi inrush. Hopefully we can negotiate with them to allow us to run the generator at Var or power factor control mode.     

RE: Interconnection with Utility

for Hamidele:

Your response is a bit ridiculous, pls understand what rcwilson has very clearly explained. Such large units have to run under AVR control, with suitable limiters for underexcitation, overexcitation, and/or VAR limit, all of which have to be set according to a system study. These limiters are standard equipment for large generator excitation systems.

The idea of running under PF control (a slow-acting function) is only possible on relatively small (usually industrial) generators parallelled with a large system. Then the limits of AVR voltage setting range have to be programmed into the equipment. In case that the small generator trips off the large system, then the PF control would be immediately disabled, and the unit would run under AVR control, set for nominal voltage, only to avoid the local loads being subjected to abnormal voltage conditions.

I suppose that this is some office exercise, where ideas are being pushed around on paper at the present time.

rasevskii

RE: Interconnection with Utility

(OP)
Thanks, Racevskii,
 
It looks like you have a lot of experience on Co-generation. We are still at the very early stage of the project and investigating every possible scenario. Of course, there are learning curves for us.


 

RE: Interconnection with Utility

Most grid operators would require a Power System Stabilizer for this size unit as well.  I agree with others that it will have to be operated in voltage control mode, not power factor.  Grid operator will require that this unit do its part in voltage/var support.   

David Castor
www.cvoes.com

RE: Interconnection with Utility

Hamid- I am guessing that you are thinking of running in power factor or VAR control mode to maximize revenue & minimize kW losses by operating as close to 1.0 pf as possible.   Or maybe you are thinking the plant will have to back off kW to stay within the reactive capability curve if the utility voltage drops and MVAR output increases.

Our experience is that operating in voltage control usually does not limit the plant output. Also, the kW difference in losses between .95 and 1.0 power factor are not much.  You're chasing a small efficiency improvement that probably would not return enough avoided costs to cover your fees.  (On my first cogen plants I spent a lot of time getting the PF and VAR control to work, thinking I was saving the clients money.  Power factor control led to stability issues and nuisance trips which cost more than they ever saved.)

If this is a true cogen plant that supplies power to a plant process, you  want to stay in voltage control to maintain the process load bus voltages.

The interconnecting utility or system operator cannot require the plant to operate outside the generator limits.  It would be a very unusual situation if the MW output had to be reduced to maintain MVAR ouput.   

RE: Interconnection with Utility

Quote:

It would be a very unusual situation if the MW output had to be reduced to maintain MVAR output.

I'm not sure it would that unusual for a merchant plant that is only interested in selling kWh.  Their goal is to operate at max kW output and zero kVAR.  Assuming the prime mover can provide the necessary kW, any required kVAR would likely reduce the kW the generator could theoretically produce, thereby reducing their revenue.  At least that is the bean-counters would look at it.  

 

David Castor
www.cvoes.com

RE: Interconnection with Utility

(OP)
DPC, you are correct. The grid requires to operate all the tie-in generators in voltage control mode. I guess we have no choice. We specified the genrator with a Power System Stabilizer to help keep the voltage stable. I was trying to undertand the theory behind it and will try to convince our collegues and client.If the power factor turns out to be below 0.9, we will either add power factor correction a proper locations or accept the panelties.
Thank you all for the valuable discussions.  

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