The second part of this three-part series explores the types of protection applied to specific equipment installed at water and wastewater facilities and some typical criteria used to develop protective settings.
Application of Protective Relaying to Specific Equipment
This section shows what types of protection are applied to specific equipment that might be installed at a water or wastewater facility and some typical criteria that would be used to develop protective settings. The information is intended to give general understanding and guidance but is not a complete discussion of all the equipment characteristics and relay capabilities that must be considered to develop a protective relaying system. The choice of actual protection and relay settings to be applied depends on the specific conditions for each installation and may differ from those discussed in this section.
Transformer Protection
In addition to the damage at the immediate location of an internal fault, a transformer is subject to damage from the fault current flowing in its windings. Damage is caused by heating and by magnetic forces associated with the current.[3] Magnetic forces can cause deformation or destruction of the windings, while thermal and mechanical damage also can occur when the transformer supplies current to an external fault. High speed protection is essential to avoid thermal and mechanical damage for external faults and to limit the damage for internal faults.
For a smaller transformer, perhaps less than 10-MVA capacity, protection may simply be power fuses applied at the high side terminals. Protective relays are typically applied to larger transformers or if there is a design preference to use circuit breakers instead of fuses. Phase and ground overcurrent protection may be the only relaying applied.
For more critical transformers, the main protection is often differential relaying. Overcurrent relays are then used as backup protection. A typical configuration for overcurrent relaying is time and instantaneous overcurrent relays for phase and ground faults on the transformer high side, and separate time overcurrent relaying for phase and ground faults on the low side. If the transformer provides resistance grounding for the system, ground fault current will be limited to values that might not be reliably detected by differential relays. In these cases, separate ground differential relaying can be applied.
Differential relays may require general settings such as the transformer rated voltage, kVA, winding connections, and CT ratios. Protective settings may include minimum pickup, slope of the differential characteristic, and settings to inhibit relay operation when the transformer is energized after being out of service and magnetizing inrush current flows. A typical minimum pickup setting might be 15 percent of the transformer rated current. Differential relays may also provide an instantaneous overcurrent element that measures differential current but is not restrained. The unrestrained instantaneous pickup setting must be high enough so that it can only operate for transformer internal faults.
For example, in a radial system, the unrestrained instantaneous pickup setting would be lower than the current for a fault at the transformer high side terminals but higher than the current for a fault at the low side terminals. If the instantaneous element is not restrained for magnetizing inrush, its setting must also be higher than the inrush current.
Some general guidelines for transformer overcurrent relay settings are as follows:
- High side phase instantaneous overcurrent: Set similar to the unrestrained differential relay instantaneous element. Set higher than the current for a fault at the low side terminals, higher than magnetizing inrush current, and ower than current for a fault at the high side terminals.
- High side phase time overcurrent: Set pickup to allow for normal and emergency loading and to comply with requirements in NEC Table 450.3(A).[11] Set time delay to coordinate with industry-standard transformer damage limits[3] and to coordinate with time overcurrent devices upstream and downstream from the transformer.
- High side ground overcurrent: Transformer winding connections determine the criteria for setting ground overcurrent relays. Usually, high side winding is connected in delta and low side winding is connected in wye. There is no ground current on the delta side for a ground fault on the wye side, and ground relays can be set very sensitively.
There is a possibility that magnetizing inrush current could cause current transformers to be inaccurate, resulting in a current measured by the ground overcurrent relay when no ground fault exists. For security, it may be desirable to set the high side ground instantaneous relay at perhaps 25 percent of the setting for the phase instantaneous overcurrent relay. With a delta-wye connection, high side ground time overcurrent relaying is not required, but may be applied for redundancy. A pickup setting of 25 percent of transformer full load current and time delay of 0.1 second at the maximum ground fault current is suggested.
- Low side phase overcurrent: Instantaneous overcurrent is not recommended because it cannot be coordinated with downstream overcurrent devices. Set the time overcurrent pickup to allow for normal and emergency loading. Set the time delay to coordinate with upstream and downstream overcurrent devices and to coordinate with the transformer damage limits.
- Low side ground overcurrent: As with the low side phase relays, instantaneous overcurrent is not recommended because it cannot be coordinated with downstream overcurrent devices. Set the time overcurrent pickup at 25 percent or more of the transformer full load current to allow for load unbalance and to facilitate coordination with downstream overcurrent devices. Usually, the transformer winding connection eliminates the need to coordinate the low side ground overcurrent relay with devices on the high side, and the time delay can be set to coordinate with downstream devices.
Other protection using devices other than protective relays might be applied for larger transformers. For example, liquid-filled transformers can be equipped with a specialized relay to detect sudden pressure changes caused by faults inside the transformer tank. Arcing vaporizes the insulating fluid in the immediate vicinity of the fault and the resulting pressure wave propagates through the tank volume. The sudden pressure relay does not respond to gradual pressure fluctuations caused by changes in loading or ambient temperature. Sudden pressure relays can provide more sensitive fault detection than differential relays but cannot respond to faults that are in the transformer zone but outside of the tank.
Liquid-filled transformers can be equipped with sensors to measure the temperature of the insulating fluid and the hottest part of the winding. Dry type transformers may include thermocouples to measure winding temperature. Gauges for oil temperature, hot spot temperature, and winding temperature can be equipped with settable contacts to start cooling fans, provide an alarm, and provide a trip signal.
While overcurrent relays provide some degree of overload protection, they are primarily intended for fault protection. Direct temperature measurement can provide overload protection as well as protection against transformer cooling system failures. Since it is a direct indication of the highest temperature in any winding, the hot spot temperature gauge is used for tripping. For liquid-filled transformers, trip settings may be based on maximum hot spot temperatures of 356-deg F (180-deg C) for power transformers and 392-deg F (200-deg C) for distribution transformers.[1]
Figure 1 shows AC current connections for a typical electromechanical transformer differential relay. With electromechanical relays, current transformer connections are made to compensate for the phase shift introduced by the main transformer winding connections. The figure shows CT connections for a delta-wye transformer. Microprocessor-based relays compensate for the phase shift with settings and can utilize wye-connected CTs regardless of the main transformer winding connection.
Figure 1. Typical application of current-differential relays for delta-wye transformer protection.
Figure 2 shows a one-line representation of a transformer differential scheme, including the circuit breakers and trip logic. In this figure, the secondary protective device is shown as a low voltage power circuit breaker. It is important that the protective devices on both sides of the transformer be capable of fault-interrupting duty and suitable for relay tripping. A lockout relay is used to trip both the primary and secondary devices. The lockout relay is designated 86T with 86 the designation for a lockout relay and T designating transformer protection. The differential relay is denoted 87T with 87 the designation for a differential relay and T again designating transformer protection. The wye and delta CT connections also are noted.
Figure 2, left. Transformer differential relay application from Figure 1 in one-line diagram format.
Bus Protection
Differential protection should be applied to any open air or switchgear bus. The high speed and selectivity of bus differential protection are important in limiting hazards to personnel and in avoiding loss of service to large parts of a system. For example, large switchgear buses typically are split into sections with tie breakers between the sections and a separate source for each section. The tie breakers allow operating flexibility but also allow a faulted bus section to be isolated while maintaining service to circuits on the other sections.
Bus differential relay settings are of concern mainly for high impedance and partial differential schemes. For high impedance differential relaying, the voltage setting must be higher than the maximum error voltage for a fault outside the bus differential zone. The settings require calculations based on CT secondary circuit impedances and CT characteristics.[2]
Partial differential protection, sometimes called bus overcurrent, is sometimes used for buses where current transformers are not available for all connected circuits. A typical scheme would use CTs from the main and tie breakers connected to measure total bus current. The protection is based on overcurrent relays and setting guidelines are similar to those for overcurrent relays. The pickup setting must allow for maximum total load current supplied by the bus and the time delay must be set to coordinate with upstream and downstream time overcurrent devices.
Distribution Feeder Protection
Distribution feeders at water and wastewater facilities may be overhead or underground. While overhead lines can suffer a fault without permanent damage, cable faults are generally permanent. Cables can be susceptible to heating damage from fault current because the conductors are covered with insulation and the cables are installed underground or in conduit. Industry standards define damage limits for power cables.[4]
A further concern with underground cables is that the shields typically have a much lower cross-sectional area than the main conductor and are particularly vulnerable to damage from fault current. Protection for distribution lines and cables usually is provided by phase and ground overcurrent relays.
Some general guidelines for feeder overcurrent relay settings are as follows:
- Phase instantaneous overcurrent: Set lower than the available fault current at the beginning of the line, but higher than the available fault current at the end of the line or at the closest downstream overcurrent device. A suggested minimum setting is 125 percent of the current at the end of the line or closest downstream device. For distribution feeders that supply unit substation transformers, set high enough to avoid tripping for faults on the transformer secondary side.
The goal is to provide the largest zone possible for instantaneous protection while maintaining coordination with downstream overcurrent devices. Also, set high enough to avoid tripping for transformer magnetizing inrush current. Developing a suitable setting may require judgment and making tradeoffs between the need for high speed protection and the need to coordinate with downstream overcurrent devices.
- Phase time overcurrent: Set pickup to allow for normal and emergency loading. Set no higher than 600 percent of the feeder conductor capacity to comply with NEC Article 240.101.[11] To ensure adequate sensitivity, the pickup should be no higher than perhaps one-third of the available current at the most remote downstream overcurrent device. Usually, available fault current is more than adequate to meet this guideline. Set the time delay to coordinate with upstream and downstream overcurrent devices.
- Ground instantaneous overcurrent: The criteria are similar to those for phase instantaneous overcurrent relays except settings are based on ground fault current.
- Ground time overcurrent: Usually, distribution feeders at water and wastewater facilities do not supply loads connected phase to neutral, and a sensitive pickup setting could be used. A pickup setting of 25 percent or more of the phase relay pickup may be required to coordinate with downstream overcurrent devices. As with phase relays, the pickup should be no higher than perhaps one third of the available ground fault current at the most remote downstream overcurrent device. The time delay should be set to coordinate with upstream and downstream overcurrent devices.
Next month we'll conclude our discussion with a look at generator and capacitor protection and protection at the utility interface.
References
[1] IEEE Std C57.91-1995, IEEE Guide for Loading Mineral-Oil-Immersed Transformers
[2] ABB Power T&D Company, Protective Relaying Theory and Applications, 1994
[3] IEEE C37.91-1985 (Reaff. 1990), IEEE Guide for Protective Relay Applications to Power Transformers
[4] ICEA P-32-382, Short Circuit Characteristics of Insulated Cable, 1987
[5] Schneider Electric, Sepam 1000+ Digital Relay Series 40 Reference Guide, document no. 63230-216-220/A1, 2002
Pumps & Systems, November 2007