The one-day-in-10-years criterion might have lost its usefulness in today’s energy markets. The criterion is highly conservative when used in calculating reserve margins for reliability. Can the...

## Synchronizing on West Point

Could local generators be used either to regulate voltage or control the power factor on distribution systems in New York?

emergency conditions. Removable couplings are needed to allow the generators to “motor.”

If we assume the power factor of these generators is 0.8, we have 4. ^{1} MVAR of dynamic reactive available. In theory, we may expect compensation equivalent to that paid by the ISO for generators located on the transmission system. This compensation is $4,000/MVAR per year, or $16,500 per year for the 4.1 MVAR.

The benefit from providing reactive power from the synchronous generators in the West Point distribution system may be approximated as follows. The generators are connected to 4,160-V buses. The peak West Point load is 17 MW in the summer and 12 MW in the fall, winter and spring. The West Point power factor is close to 0.9 for all months. If we assume an average load of 7 MW at 0.9 power factor, this results in reactive power absorption of 3.39 MVAR. This is smaller than the 4.1 MVAR of reactive power available from the onsite generators, so the reactive output of the generators could be used to correct the campus net power factor to 1.

For a rough estimate, let’s assume that the 4,160-V bus feeder cables are two 750 kCM in parallel, a common size seen in bus-feeder cables. These two cables in parallel would have a resistance of 0.073 ohms per 1,000 feet. The extra current associated with the 0.9 power factor is 107 amps at 4,160 V. The additional I squared R loss associated with this extra current is only about 16 kW. In addition, if we assume that the friction, windage and I squared R losses of the generators is 3 percent—a reasonable estimate—then the total losses of the 5.5 MW of generation is 165 kW. Thus the losses in the machines easily negate the possible savings in distribution system losses if the machines were to be operated solely for the purpose of providing reactive power to reduce West Point losses. Some transmission operators will compensate a synchronous condenser for the losses in the machine when the machine is supplying a reactive-power service. This would be essential for synchronous generators to economically supply reactive power.

The West Point generators were not purchased with removable couplings between the engine and generator; these would be required at perhaps $5,000 each as a minimum. A local generation excitation controller would be required at perhaps $5,000 each. The total cost to enable the generators to supply reactive power and control the net West Point power factor may be at least $40,000 to $50,000. The ISO pays $4,000 per year for reactive power to generators that are officially connected to their transmission system, where the ISO can control the reactive power being supplied.

If we were able to get some similar payment, it would probably only be for the amount that West Point could actually go leading. This would be the 4.1 MVAR available minus 3.39 MVAR absorbed, or 0.71 MVAR. If it could be paid, this would only yield roughly $2,800 per year. If friction, windage, and I squared R losses are not compensated for,