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By Charles Rhodes, P. Eng., Ph.D.

Distributed generation is generation that is directly connected to a Local Distribution Company (LDC) without going through the Hydro One transmission system.

The system reliability with Distributed Generation (DG) partially depends on the ability of the LDC to regulate voltage and efficiently route energy from branch feeders that have surplus power to branch feeders that at that need additional power. The complexity of the required control and monitoring system increases with the number of connected generators.

As the control and monitoring system complexity increases, so also does the signal system bandwidth required to support that control and monitoring system. Within a metropolitan area control and monitoring signals are easily transmitted via short range UHF/microwave mesh networks. However, in rural areas of Ontario reliable transmission of wideband control and monitoring signals can be a major challenge.

At the time of writing (August 10, 2018) Hydro One is many years behind in implementation of its smart metering system. About 90% of the Hydro One smart meters are operational. However, most of the remaining 10% are in locations where the only practical method of meter data acquisition is via the consumer's wireless internet service. The equipment and software for this method of meter data acquisition has not been deployed. The Ministry of Energy and Hydro One both failed to adequately consider this issue in the Ontario smart meter implementation plan.

A significant constraint on distributed generation network architecture is the ability of existing branch isolation switchgear to clear short circuit faults under worst case conditions. If behind the meter generators are permitted to export power to an existing local distribution circuit measures must be taken to ensure that the short circuit disconnect capacity rating of every branch isolation safety switch and/or fuse connected to that circuit will not be exceeded. Switchgear failures can cause very large costs due to protracted power outages, damaged equipment and personnel injury/deaths. Under existing legislation there is no mechanism for paying for these switchgear upgrades. Hence behind the meter generation should be controlled so that it cannot export power to the grid. The whole concept of consumers acting as distributed generators is a pipe dream that makes no practical implementation sense.

A variation on this same problem is the concept of connecting distributed wind generation to distribution. The extra protection system costs required to safely implement such distribution connected generation are seldom adequately recognized. When power can only flow in one direction the power flow is typiclly constrained by the rating of the transformer(s) used. When net power can flow in either direction the electrical system protection criteria become much more complex.

Another rapidly emerging high voltage switchgear related problem is inappropriate use of SF6. Sulfur hexafluoride (SF6) is a synthetic gas with excellent properties for use in electrrical switchgear. It assists in extinguishing plasma arcs that occur when major electrical circuits are openned and it provides much better resistance to high voltage breakdown than does air. However, SF6 is also a very stable gas with a very strong greenhouse effect. Unintentional leakage of SF6 to the atmosphere is seriously aggravating global warming problems. There is no simple solution to this problem other than application of a very high tax to SF6 to encourage its conservation and to prevent it being used for non-essential applications.

Another constraint on application of intermittent distributed generation is voltage drop along a long distribution feeder. Let the nominal feeder voltage be Vn. In order to meet the input requirements of consumer electrical appliances, at all points and at all times along the feeder the voltage V must be in the range:
0.94 Vn < V < 1.06 Vn.
The voltage at a generator located at any point on a lightly loaded feeder must always be less than 1.06 Vn. The voltage at a load that is located far from a substation on a heavily loaded feeder with no operating distributed generation must always be greater than 0.94 Vn. These constraints limit the amounts of intermittent generation and intermittent load that can be connected near the far end of of distribution feeder.

Assume that each distributed generator has an output power versus voltage characteristic such that the power generation is maximum when the feeder voltage at the generator is .94 Vn and the power generation is zero when the feeder voltage at the generator is 1.06 Vn. Hence the generator's output power versus voltage curve has a negative slope. Implementation of this control algorithm is easily done but may involve generator control hardware that is not presently contemplated by the parties.

The voltage at a substation transformer secondary is usually controlled by an automatic transformer tap changer. For use with distributed generation the controller for this tap changer should be programmed to maintain a negative slope power to feeder versus voltage curve. This curve can be remotely offset by the LDC or the IESO. The offset is chosen so that under average distributed generation conditions the feeder voltage measured at the substation takes its nominal value Vn. If maximum power is to be fed from the transmission system to the feeder the control curve is offset so that this voltage rises to 1.06 Vn. If maximum power is to be fed from the feeder to the transmission system this offset is reversed so that the feeder voltage measured at the substation falls to 0.94 Vn. Note that the substation transformer secondary tap changer control algorithm should have a dead band sufficient to prevent the tap changer short cycling. Generally the substation tap changer is controlled via a proportional-integral (PI) control algorithm. The distributed generators operating under constraint should use proportional (P) control algorithms. Use of proportional-integral (PI) or proportional-integral-differential (PID) control algorithms at distributed generators will generally cause power system instability and generator inefficiency.

Power control involves giving the Independent Electricity System Operator (IESO) control of the tap changer contol algorithm offset. By changing this offset the IESO can indirectly change the voltage on the feeder and hence the amount of operating distributed generation connected to the feeder. Note that if the distributed generation is out of service the optimum value of this control offset changes. Hence, there should be feedback to the IESO to warn the system operator of prolonged out-of-normal voltage as measured at the substation transformer secondary. One of the challenges of both wind and solar based distributed generation is that at certain times the rate of change of the renewable power generation can be very high, which increases the complexity of overall Ontario grid operation.

As intermittent generation is added to an electricity system, corresponding sheddable load, energy storage or balancing generation must also be added to the electricity system. If all of the generation is distributed and there is no energy storage or sheddable load, then in order to achieve voltage control and system reliability almost all of the distributed generation must be constrained.

This generation constraint requirement can be met by requiring all distributed generators to operate on a specified negative slope power versus voltage curve. However, implementation of this generation constraint methodology requires acceptance by the parties. This generator constraint is not presently contemplated by the IESO Feed-In Tariff.

Operation of unconstrained generators leads to loss of revenue by load following generators. This is a financial issue that has yet to be adequately addressed by the IESO.

The instantaneously immediate availability of sufficient spinning reserve generation or IESO controllable load is key to network stability when a major energy source drops out either due to a generator trip or due to a transmission line fault. The IESO should be including an element of line voltage dependent generator constraint in all distributed generation contracts.

Another issue that has not been adequately addressed by the IESO is requiring distributed generators to be self excited to reduce their dependence on other generation for voltage regulation, reactive power and black start.

With Distributed Generation (DG) the process of locating and isolating faults is more complex than with Central Generation (CG).

When a feeder with distributed generation is disconnected from a substation transformer secondary, power islanding can potentially occur. The substation control system must be enhanced to so that it reconnects to the power island only when all the generation within the power island is locked off or when the power island is synchronized to the grid. Generally the frequency in the power island is intentionally made slightly different from the grid frequency in order to allow the gradual relative phase change required for reconnection.

Whenever power islanding can occur there is potential for electrocution of electrical workers. Before anyone touches a power line measures must be taken to ensure that the line is fully isolated from all sources of generation. If the distributed generation capacity exceeds the distributed load on the same feeder power islands can easily form and there are many practical complications to ensuring electrical worker safety.

This web page last updated October 17,2019.

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