Environmental Protection

Reliable Power Distribution

A loss of power can result in raw sewage being dumped in streams, rivers, and lakes

Two independent power sources are better than one for wastewater treatment facilities, according to U.S. Environmental Protection Agency guidelines. These sources can either be independent utility feeds or a utility feed with on-site generation.

To minimize power disruptions caused by blackouts or excavations, utility feeds should come from separate substations or at least separate transformers within the same substation. Utilities charge between $500,000 and $1 million for a second distribution circuit with a two-year lead time. Another option for the second power source is a standby generator, which is about twice as reliable as the utility and costs about $250,000 to install. However, it has greater operating and maintenance costs. So for capacities greater than 5 MW where multiple generators are required, a utility source might actually be the least expensive option.

An analysis of several types of common power system configurations -- radial, looped, main-tie-main -- can help determine the most failure-prone system components and whether they can be bypassed to help ensure reliability. This analysis provides insights on how to address potential issues as well as guidance on the most cost-effective designs for given criteria.

The reliability of individual system components provides context for the overall configuration. Power sources tend to have the poorest reliability, and distribution equipment, while more reliable, can have very long repair times (see Table 1). Both are disruptive.

Example Reliability Calculation for MV Radial Configuration

The reliability will be determined at the load side of the left transformer switch. The elements that can cause loss of power to the left transformer when failed are:

• Utility
• Main Switch
• Each cable segment (3 at 300 feet each)
• Three transformer switches

This table shows how the reliability indices are derived.

The components are in series, which means failure of any one of them will result in loss of power at the point of evaluation. For a series arrangement, the expected failure rate, ?, of the system is the sum of the individual failure rates.
?s = S ?i

The unavailability, U, of each component is the product of the failure rate and the mean time to repair, r, of the component.
Ui = S ?i * ri

The unavailability of the system is the sum of the component unavailabilities.
Us = S Ui

The mean time to repair the system is the system unavailability divided by the system failure rate.
rs = Us / ?s

In this analysis, it is assumed that an alternative source or path is always available. That is not the case in actual systems, but including failure of an alternate source or path changes the indices very little. This is a comparative analysis and the small change does not alter the relative effectiveness of the configurations.

If the load can be switched to restore power, the mean repair time can be replaced with the mean switching time for all the components upstream of the switching point. For a simple analysis, this method suffices to represent the interruption time.

Fuses or circuit breakers?
The type of switching device used in a design significantly impacts system cost and down time. A load interrupting fused switch is the most inexpensive. At medium voltage (MV), this switch can average about $15,000, whereas a main circuit breaker section will be about $50,000. At low voltage (LV), a fuseable switch board might be 25 percent less expensive than switchgear using circuit breakers. The fused switch requires trained personnel and time to perform switching. It should be used when installation cost is a major concern and reliability is not.

The circuit breaker operates automatically, switching to different power sources or reconfiguring within a few seconds. When a circuit breaker trips, all three phases are opened, preventing single-phase operation. Tripping is controlled by a separate protective relay that, in addition to simple over-current, can trip for low or high voltage, ground fault, phase sequence, differential, or other functions.

The large variety of protective functions and setting adjustability give the advantage to circuit breakers for selective coordination, which selects the protective device setting that helps ensure the nearest upstream device clears the fault. This prevents faults from causing several protective devices to operate.

Circuit breakers are more durable than switches and have a greater number of rated operations. If and when they need to be replaced, medium voltage circuit breakers are draw-out and can be quickly replaced with a spare. Low-voltage circuit breakers are available as draw-out or fixed while lower-rated breakers are only available as fixed.

The reliability analysis, described by Billington and Allen in Reliability Evaluation of Power Systems2, is applied in two parts: the electric utility and the facility MV distribution, and then the LV distribution system to the load. This approach helps clarify their contributions and allows evaluation of a greater number of configurations.

Note: The derived reliabilities should only be used to compare design configurations. They are not absolute values that predict actual downtime. Real reliabilities depend on equipment age, operating history, maintenance level, environmental conditions, etc.

Reliability is evaluated at a single point for each configuration. In MV, it is the load side of the feeder breaker or switch that supplies the load. For LV, it is the feed point of a load. LV includes the MV feeder conductor and the step-down transformer. Although this does not cleanly divide the equipment by voltage level, it does reveal the reliability of MV and LV more distinctly.

Installed costs include equipment and labor for the circuit breakers or switches shown in the figures. Engineered-to-order equipment costs are taken at current market prices. In addition, conductors are included and assumed to be installed in buried polyvinyl chloride (PVC) for MV and overhead galvanized rigid conduit for LV. Wiring materials and labor costs are taken from RSMeans Electrical Cost Data. 3 Conductor lengths are assumed to be 300 feet unless otherwise noted.

The reliability and cost determinations are sensitive to the number of feeders in the design. Adding more feeders decreases reliability because more equipment is added that can fail. To try to normalize the installed costs, they are determined on a per feeder basis. Obviously, more feeders spread the fixed cost of the scheme and reduce the per feeder cost. With MV, the analysis assumes three feeders feed off the bus and four feeders in LV configurations.

Utility and medium voltage
The simplest power distribution system is a radial system Figure 1. A radial design provides power distribution with the minimum initial equipment cost and is typically configured with a load break switch. Loss of the utility, switch, or conductors will make the system unavailable until repairs can be completed, as there are no alternate paths or sources.

The utility is by far the most unreliable element in the radial configuration and dominates the reliability of the system Table 2. There is an estimated average of 3.30 hours of forced downtime per year due largely to the utility restoration time as the configuration does not allow any scheduled maintenance to be performed on the system without shutting the load down as well. The approximate cost for this installation is $37,000 per feeder. This configuration could be appropriate where the loss of capability can be tolerated or offset by other methods, such as a small remote pumping station.

In the primary selective configuration, a second utility feed is provided to a radial system at the transformer primary Figure 2). It requires a second primary conductor and disconnect switch. A duplex switch can be provided at the transformer that uses a common fuse for a slightly lower switch cost. In this configuration, one source feeds the transformer; these installations normally do not parallel the sources. In this case and all subsequent configurations, it is assumed the manual switching takes 20 minutes to reconfigure the system.

The reliability of primary selective feed is identical to the radial design because the normal source is exactly the same (Table 2). There is substantial improvement in the unavailability because the load can be switched to the alternate source in 20 minutes. (The alternate source is assumed to always be available in this analysis).

The configuration allows work to be performed on the primary conductors to the transformer switch while the transformer is fed from the other conductor. Work can also be performed on one of the transformers while the others are energized.

Note: the cost has doubled due largely to the additional switches needed. For the per feeder cost, it is assumed there are three feeders and the cost of the common components are shared.

The looped network is a variation on the primary selective configuration (Figure 3). The loads are in series rather than parallel, and one of the switches will be open so that the utility sources are not paralleled. The number of switches required is equal to the equivalent primary selective scheme although duplex switches are shown here with one fuse per transformer. The advantage of the looped system is that less conductor length is required.

A commercial version of the looped system can be applied as part of underground distribution at a campus-type setting where several separated buildings are fed from individual pad-mounted outdoor transformers. Equipment cost can be reduced by replacing the two disconnect switches with dead front elbow terminators in the transformer to switch source conductors.

The overall failure rate of the looped system is slightly greater than the previous two schemes, but its unavailability falls somewhere between them. After a fault occurs, all the transformers on the de-energized section will be down and all the equipment must be inspected to try to locate a visible fault. When a conductor fails, it can take eight hours to locate the faulted segment and the de-energized transformers cannot be restored until the faulted segment is isolated.

The example looped system is 25 percent less expensive than the primary selective case and offers a second source. Conductors were $7,000 less expensive than the primary selective case, and the duplex switches were $7,000 less expensive than the full switches.

From a scheduled maintenance standpoint, this configuration is identical to primary selective.

A very common two-source selective configuration is the primary main-tie-main (MTM, Figure 5). The primary source feeds an entire bus and a normally open tie between the two buses provides source selection. Where there are many nearby MV loads, a bus arrangement is a more effective means to distribute power than the previous configurations. With MTM, the buses must be rated for the load of both buses with the tie closed. MTM typically employs circuit breakers.

This analysis assumes a three-second automatic throwover by the circuit breakers to the other bus if the normal source is lost (Table 3). This switching time reduces the unavailability almost 100 times for this configuration. However, there is no alternative source for the bus, feeder breakers, or the feeder conductors.

This analysis shows the reliability at the load feeder breaker. If the point of evaluation is moved to the transformer primary, the feeder conductor increases the unavailability to over 30 minutes per year. This is because there is no alternative feed to the transformer and its takes an assumed 97 hours to replace the conductor. In this case and subsequent cases with MV buses, the analysis is to the feeder breaker. Feeder conductor failures can obscure the characteristics of the particular scheme. MV feeder conductor reliability will be included in the LV analysis.

Scheduled maintenance can be performed on the main beaker or upstream of it without disruption to the feeder loads. However, work on the bus, feeder breakers or tie would require shut down of the feeder loads.

Additional buses and ties can be added to the MTM arrangement if there are more than two sources. However, a more flexible scheme is to use a synchronizing, or star, bus configuration (Figure 6). Here, a separate conductor, bus duct, or switchgear bus links all the buses through circuit breakers. It uses one more breaker than the MTM configuration but also provides the ability to tie any combination of buses together.

Sometimes one of the buses will have a source but no load -- for example, a bus with several paralleled standby generators (hence the synchronizing bus designation) or a bus that is fed by a transformer, called a sparing bus.

The availability and the reliability of the synchronizing bus decrease a small amount compared to the MTM arrangement due to the addition of the extra breaker. For the purposes of this analysis, the reliability of the two configurations should be considered identical.

The cost of the synchronizing bus is about 15 percent greater than the MTM due to the extra breaker and cabling but that cost buys additional switching flexibility.

As with the MTM scheme, scheduled maintenance can be performed on the main beaker or upstream of it without disruption to the feeder loads. However, work on the bus or feeder breakers would require shut down of the feeder loads.

The ring bus is configuration sometimes found in utilities but not often in industrials (Figure 7). A utility would normally operate with the sources paralleled but the industrial version typically would not. This arrangement has the advantage of using a minimum number of breakers while having the ability to switch the loads between sources.

The availability of the ring bus is several times better than the best considered so far because the design uses minimal hardware and can accommodate automatic throwover.

The cost per feeder, however, is very high. Each feeder has two breakers sized as mains, and the total number of breakers per feeder is high. Another disadvantage is the ring bus still does not address the loss of the bus or feeder conductor.

The good availability of the ring bus is offset by the high per feeder cost. Nevertheless, it is not practical for industrial power distribution. An industrial version of the ring bus would need utility breakers and more feeders with individual breakers on the load or source buses, increasing cost even further.

The double bus arrangement is a modification of the ring bus (Figure 8). There is no tie breaker between buses but each feeder can be fed from either bus. The switchgear lineups usually face each other across an isle. Unlike MTM, it allows throwover to the other source if the bus is lost.

This configuration can be very flexible with multiple sources, such as two utilities and a standby generator. In that case, one of the buses would be split into a MTM for the other source. The double bus arrangement would be found in very large water or wastewater treatment facilities.

Again, the reliability and cost of the double bus are based on three feeders.

The time unavailable is reduced by about half compared to MTM. The feeder cannot be restored after a bus or breaker fault with MTM until the equipment is repaired, but with the double bus scheme, the feeder is switched to the other bus in three seconds for a source bus fault. However, a fault on the load bus or one of the load bus breakers does not provide an immediate alternate source.

This configuration uses two breakers per feeder and increases per feeder cost 50 percent over that of MTM.

With the ability to feed loads from either bus, maintenance is possible at the MV bus while the other bus serves the loads. However, maintenance is not possible without a shutdown from the load bus to the load.

Low voltage
Overall, the failure rates for LV components are low, but some of the repair times are quite long (Table 4). Specifically, transformer and bus repair times can take days, which reduce availability.

The single ended radial configuration is the simplest LV design (Figure 9). It is the least expensive arrangement and provides no alternative feed to the loads if normal power is lost. The implementation would likely use fused switchboard due to cost considerations.

Each of these examples assumes a 2,000 kVA transformer with a secondary main, four feeders, and 300-feet conductor lengths. The load evaluated for reliability is at the end of a 300-foot LV feeder conductor.

The failure rate is low compared to the MV examples primarily because no utility is included (Table 5). However, the unavailability is similar, because of the long repair time for the transformer and, to a lesser extent, the MV conductors. This provides insight into what should be bypassed in subsequent configurations to improve reliability.

The radial design serves as a reference for comparison of the other designs.

Power must be shut down to the load for any maintenance that must be performed on the equipment.

One of the more common LV configurations is the secondary selective or MTM (Figure 10). For maximum reliability, drawout power circuit breakers with automatic transfer should be used. The automatic transfer switches to the alternate source in three seconds rather than the 20 minutes it may take to manually transfer.

The unavailability is reduced more than 10 times compared to the single-ended radial value. The transformer and MV conductor have long repair times and the MTM allows them to be automatically bypassed. Still, loss of the bus, one of the bus breakers, or the feeder conductor to the load, requires the load to be down until repairs are completed.

Cost per feeder is 15 percent more compared to the radial configuration due to the transition from fused switches to breakers and the addition of the tie breaker.

The secondary spot network configures the secondaries of two or more transformers parallel through a special circuit breaker called a network protector (Figure 11) If there is a transformer or MV feeder fault, the secondary bus will back feed it through the network protector, which can isolate the faulted equipment from the secondary bus. Removable links typically are added to isolate the buses.

A spot network refers to two or more parallel sources to serve a specific load, such as the main switchgear for a building. It is implemented in an industrial setting where loads are frequently moved by running a bus duct between the substations and adding loads where needed. The distribution is not likely used in water or wastewater treatment facilities because loads tend to be permanent.

An interruption will only occur when all the sources are lost or one of the secondary buses fault. However, the loads will see all the voltage sags on the sources or as a result of a fault within the facility. With the voltage sag threshold of some electronic equipment at 85 percent of nominal voltage, a voltage sag may be as disruptive as an interruption.

This evaluation assumes a power circuit breaker main and 300 feet of 3000 A aluminum bus duct with eight 600 A bus duct plugs. In this case, the bus duct drops are assumed to be 150 feet because the bus duct should be closer to the loads than a substation.

Interestingly, the reliability results don’t demonstrate a remarkable performance for this design. While the spot network is immune to interruptions originating upstream of the network protector (barring loss of all sources), it is vulnerable to loss of the bus duct, network protectors, and the load conductors. The bus duct failure rate and repair time are high and dominate the results, therefore this design has an availability that is comparable to the single ended radial configuration.

The cost of the spot network is higher than any of the other configurations. The largest cost item is the long length of high ampacity bus duct. The transformers and bus must be oversized and circuit breakers must have a high interrupting rating due to the increased fault current available with the paralleled sources.

References
1. IEEE Standard 493-1997, IEEE Recommended Practice for Design of Reliable Industrial and Commercial Power Systems (The Gold Book).

2. Billington, Roy & Allen, Ronald N, Reliability Evaluation of Power Systems, Plenum Press, 1984.

3. RSMeans Electrical Cost Data, 30th Edition, 2007.

Beeman, Donald, (editor), Industrial Power System Handbook, McGraw-Hill, 1955.

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