Distributed generation (DG) units can relieve burdened utility systems and increase reliability to customers who experience frequent outages. But the interconnection of DG units and utility grids doesn't come without challenges. Most distribution systems are designed to optimize the delivery of power in one direction. DG installations of any size can create conflicts with a system's operation. In this article, we'll discuss several interconnection problems you can resolve. There's a limit, however, to how much DG can be added to an existing system without significant incremental cost.
Most distribution systems (especially rural ones) are set up in a radial configuration (see Fig. 1). This structure allows for simple operation and an economic overcurrent protection system, but it also creates some problems.
The basic element in this scheme is the fuse, which dictates the characteristics and behaviors of the other overcurrent protection devices (OCDs). Setting the utility breakers and reclosers so they work in concert with the fuses is referred to as the “coordination” of the OCDs. The purpose of coordination is to minimize disruption to customers when a fault occurs. On a radial system, fault clearing requires only one device to open because only one source contributes current to the fault. In contrast, meshed networked systems require breakers at both ends of a faulted line to open. With DG, multiple sources are present, and opening only the utility breaker doesn't guarantee the fault will clear promptly. It would be far too costly to revamp the distribution system's protection scheme so it operates in the same manner as a meshed transmission system. The only solution is to require the DG to disconnect from the system when a fault is suspected. Then the system will revert to a true radial configuration, allowing the normal fault-clearing process to proceed.
Fig. 2 illustrates one impact DG can have on utility protective relaying. The figure shows a utility substation with a circuit breaker and a recloser at the midpoint of the line. Utility breakers and reclosers are set to “see” a certain distance down the radial feeder. Some refer to this as the “reach,” which is determined by the minimum fault current the device will detect. The protection zones are designed so each device in series sees a significant distance past the next device.
At peak loading, when DG used for feeder support purposes is likely to be interconnected, the relaying is fairly sensitive, and the reach is large. It doesn't take much additional current to trip the breaker. DG infeed can cut sharply into that reach. There is a significantly high risk that faults with high resistance will go undetected until they burn into larger faults. The obvious result is more damage to the utility plant and more risk of sustained interruption to customers. Thus, the perception that DG will bring more reliability to the system is generally true for the generator owner only.
Most utility systems have a large number of overhead lines, and most faults on overhead lines are due to trees or lightning. When these faults occur, the fault arc is interrupted, and the insulation level of the line is re-established. Power can then be immediately restored by reclosing the interrupting device (a breaker or recloser). Fig. 3 illustrates this principle by showing the fault currents and the reclose interval between “shots.”
Some types of DG are fundamentally incompatible with reclosing. Successful reclosing requires a sufficient time between shots for a fault arc to dissipate and clear. If a DG unit doesn't detect the fault and disconnect early in the reclose interval, the fault continues, with significant consequences. A clearing failure means there will be prolonged arcing, and the utility substation transformers will experience another “through fault.” Both can result in shortened life spans and costly utility equipment repairs.
Failure to clear also means some utility customers will see a sustained interruption, instead of a momentary one. And if the DG is still connected upon reclosure, the DG equipment itself is subject to damage. For a rotating machine (the most common type of generator), owners can expect damage to the shaft, coupler, and prime mover because of out-of-phase switching.
Another concern related to fault clearing and reclosing is voltage regulation (see Fig. 4). This issue often sets the most restrictive limits on how much DG can be served from a particular feeder without making costly changes, particularly on more rural feeders. Before a fault occurs, DG helps support the voltage and may be large enough to actually raise the voltage (as suggested in Fig. 3). In one sense, DG improves the reliability of the distribution system by allowing it to serve more load at a good voltage. However, if the load increases to the point where the feeder depends on the DG system to support the load, the voltage will sag too low after a reclose because the DG has been required to disconnect. The utility will not be able to pick up the load successfully.
Many utilities use instantaneous reclosing to improve power quality. This reclose interval is nominally 0.5 sec, but it can be as short as 0.2 sec. Instantaneous reclosing is meant to alleviate such problems as the nuisance blinking clock and adjustable-speed drive dropouts, but the probability that the DG system will not disconnect in time increases sharply. It may not be possible for the DG relaying system to reliably detect the existence of a utility-side fault until interruption actually takes place. Then it becomes a race between the utility reclosing and the DG breaker clearing operation.
There are only a few problems with today's low-penetration levels on distribution systems. But as DG installations increase in number and size, there will almost certainly be a conflict between the needs of DG and the use of instantaneous reclosing. I recommend against using instantaneous reclosing on feeder sections that contain DG. A reclose interval of 1.0 sec or more would be preferable. However, this means reduced power quality for those customers who benefit from instantaneous reclosing. As you can see, there's a clear conflict over maintaining the best possible power quality the wires can deliver and providing an interconnection that will work with DG.
Conflicts of Rules and Reality
Although it is sound practice and a universal rule to disconnect the DG system promptly when a fault occurs, there are sometimes unintended consequences. For example, many modern loads are served with underground cable at the primary distribution level. The cable is commonly run from an overhead line with fuses at the riser pole to separate other utility customers from faults on the cable. The fuses are sized to blow quickly because it's assumed that all cable faults are permanent.
In addition, larger DG units commonly have their own service transformer. Therefore, requiring the DG unit to disconnect at the first sign of trouble could leave the service transformer isolated without load and served with one or two open phases.
Fig. 5, on page 32, illustrates this situation with a delta-wye grounded service transformer. A negative sequence relay can easily detect an open-fuse condition at the generator, tripping the breaker and yielding a classic ferroresonance condition. The capacitance of the cable appears in series with the magnetizing inductance of the transformer, which can result in very high voltages and currents (see Fig. 6, on page 32). If a small amount of load remains connected, it can sustain damage. The transformer and its arresters have been known to fail if the condition persists. Unfortunately, this condition tends to persist unless line crews are nearby to correct it. Frequently, conventional relaying behind the fuse will not detect ferroresonance until something else fails.
This situation is not unique to DG installations. It also occurs in many modern commercial loads where the loads are automatically disconnected from the mains and transferred to backup power the moment a problem with the utility system appears.
One solution is to arrange the load, if possible, so there is always some non-trivial load on the transformer when the isolation occurs.
Another solution is to employ a 3-phase switch (such as a recloser) on the primary side of the service. Unfortunately, this adds a relatively large expense for smaller DG sites and may eliminate much of the economic advantage of the DG. Utilities may choose to replace the riser-pole fuses with solid blades, which results in a slight degradation of power quality and reliability to the rest of the feeder. More customers now experience inconvenience from failures on the cable system.
DG systems can greatly improve power reliability for generator owners when they provide backup for an interruption in utility service. But power quality for other customers on a utility system may be slightly worse because of changes needed to accommodate a DG system. DG owners should expect charges for engineering services and additional equipment, and utilities should expect compromises in long-established operating practices.
End users that produce high-value products and suffer frequent outages have the most to gain. And while they may experience an improvement in reliability, they shouldn't necessarily expect better power quality when running off-grid. Because of a weaker source, voltage sags from motor starting and harmonic distortion are much likely to be worse. It may be impossible to operate some loads without interconnection.
Roger Dugan is a senior consultant for Electrotek Concepts in Knoxville, Tenn. You can reach him at email@example.com.