Bus Protection Principles
The behavior of bus protection systems during different fault conditions is critical to the stability and security of the electric power system, due to the tripping of the multiple lines and transformers connected to the bus. Fast fault clearing for faults on the bus is very important, while at the same time operation of the bus protection for external faults must be avoided in order to reduce the probability of a system disturbance.
For many years, transmission bus protection systems were based on a centralized principle using physical summation of all incoming currents into the bus differential relay. The differential current is defined as:
Idiff(t) = i1 + i2 + … + iN (1)
High or low impedance relays with fast operating times protect busses at different voltage levels. This principle is quite simple, but requires all current transformers to be more or less identical and is susceptible to the impact of CT saturation for high current external faults (Figure 1).
Low impedance bus differential protection relays with multiple restrained inputs significantly reduced the impact of CT saturation and allowed using current transformers with different CT ratios. They typically work based on single or multi-slope characteristic defined by an operating Iop and restrained Ibias current, where:
Idiff(t) = |idiff(t)| = |∑i| (2) Ibias(t) = |i1| + |i2| + … + |iN| (3) (See Figure 2).
However, the high cost limited their application to a relatively small number of critical substations.
The advancements in communication technology have resulted in significant changes in the design and implementation of bus protection for transmission substations. The conventional centralized bus protection relays are being replaced by communications based distributed bus protection systems that are the subject of this article. Two main types of bus protection are discussed:
Based on remote (peripheral) units that provide the interface with the process and a central unit that performs the bus bar differential protection function
Based on remote (peripheral) units that provide the interface with the process and determine the direction of the fault and a central unit that performs the bus bar directional comparison protection function
The remote units in both cases can be multifunctional IEDs by themselves. In the case of IEC 61850 based systems a new type of device – the merging unit – is introduced.
IEC 61850 has a significant impact on the way distributed bus protection systems can be designed and implemented. This article analyzes such systems. Comparisons between the conventional and IEC 61850 based cases are presented.
Distributed Bus Differential Protection
While bus differential protection in the past was centralized, based on a summation of currents from all current transformers defining the zone of protection, the introduction of advanced high-speed substation communications has resulted in the development and implementation of a new generation of bus differential relays with distributed architecture.
The numerical technology and its implementations to bus protection offer some significant advantages. The classical bus differential schemes have more or less a fixed zone of protection because they have a single current input that is the sum of all current circuits wired into the relay. Modern distributed schemes can easily change the zone of protection based on the knowledge of the substation topology and the state of breakers and isolators.
While the classical schemes need all current transformers to have the same CT ration, the modern schemes can accommodate different CT ratios throughout the protected zone. This mismatch must be accounted for by the scheme.
Communications based distributed bus differential protection (Figure 3) started with proprietary solutions using two types of devices:
Bus protection relays perform more functions than basic bus differential protection. These functions are also distributed between the peripheral units and the central unit. The following are examples of such additional functions and their distribution:
Substation topology determination
Summation of currents
Busbar differential protection
Breaker failure protection tripping decisions
Current signals processing
Breaker status monitoring
Isolators status monitoring
Breaker failure detection
Local protection, totally independent of the central unit
The central unit is connected to the peripheral units using fiber cables that ensure broadband communications, while at the same time are not affected by any electromagnetic transients that may occur in the substation.
One of the most important requirements for such distributed applications is the synchronization of the data acquisition by the peripheral units.
The knowledge of the general topology of the substation is essential to the definition of the zones of protection and the execution of tripping in case of breaker failure protection.
This is an important responsibility of the central unit that runs topology algorithms which determine dynamically the electric scheme of the substation. They are based on information from the auxiliary contact of circuit breakers and isolators monitored by the individual peripheral units.
An important benefit of such distributed schemes is that the peripheral units can be installed at the breaker cabinets in the substation yard thus significantly reducing the burden on the CTs and reducing the probability for CT saturation.
IEC 61850 Process Bus Based Bus Differential Protection
While the above described bus differential protection system is based on proprietary communications of current phasor measurements between the peripheral units and the central unit performing the differential protection function, IEC 61850 allows the implementation of distributed bus differential protection systems using sampled analog values over the substation process bus. The architecture of such a system is shown in Figure 4.
The peripheral unit in the previous differential protection system is replaced by the Merging Unit in the IEC 61850 solution. The merging unit has the task of converting an analog signal from a non-conventional or conventional sensor to sampled values that can be transmitted over the fiber cables to the central unit that performs the differential current calculation and makes a decision if there is a fault within the zone of protection.
Interoperability between merging units and protection, control, monitoring or recording devices is ensured through documents providing implementation guidelines. For protection applications, the merging units send 80 samples/cycle in 80 messages/cycle.
The currents and voltages from TCTR and TVTR accordingly are delivered as sampled values over the substation LAN (Figure 5). In this case the network becomes the data bus that provides the interface between the instrument transformer logical nodes and the different logical nodes that are used to model the functional elements of the IED.
The status of the breakers in the substation is modeled using the XCBR logical node. It will provide information on the status of the switching device, as well as the normally open or closed auxiliary contacts to be used to determine the topology of the substation and zones of bus protection. Figure 5 shows a simplified block diagram of the logical nodes used to model the different components of the bus differential protection function. As can be seen from the figure, the TCTR, TVTR logical nodes are implemented in the merging unit. Interface units may be used instead of merging units due to the fact that such devices have binary inputs in addition to the analog inputs typically available in merging units.
PDIF is the logical node representing the bus differential element in the central unit. The differential current is calculated based on the samples with the same time stamp received from the merging units used in the system.
The transmission of sampled values requires special attention with regard to the time constraints. In this case the time synchronization of the individual merging units has to be better than 1 microsecond. Since SNTP does not allow such accuracy, the merging units at this stage of implementation of IEC 61850 are synchronized using any suitable method selected by the manufacturer.
Another benefit of the use of IEC 61850 is that it provides a standard format for the description of the substation topology. It is based on the substation configuration description (SCD) file.
The distributed bus differential protection system architecture includes four types of devices:
Central unit performing the differential, and all other related functions
Merging Units, providing the analog signal processing functions
The requirements for standardization of the time synchronization and elimination of a dedicated to this function network in the substation resulted in the development of a profile of the IEEE 1588 standard for accurate time synchronization over Ethernet published as IEEE C37.238.
Each merging unit is connected to an Ethernet switch that in this case is dedicated to the Process Bus.
The central unit receives from the switch all Ethernet messages from the merging units included in the system. Considering the size of the Ethernet frames and the number of lines and transformers connected to the bus, the number of Ethernet ports may need to be increased.
Another alternative solution for a large number of merging units in a big substation is to use a central unit with 1Gb/sec Ethernet port connected to a 1 Gb/sec Ethernet switch with 100 Mb/sec ports connected to the merging units.
IEC 61850 Process Bus Benefits
Process bus based applications offer some important advantages over conventional hard wired analog circuits that are especially important in the case of bus protection. The first very important one is the significant reduction in the cost of the system due to the fact that multiple copper cables are replaced with a small number of fiber optic cables.
Using a process bus also results in a significant reduction in the possibility for CT saturation because of the elimination of the current leads resistance. The impedance of the merging unit current inputs is very small, thus resulting in a significant reduction in the possibility for CT saturation and all associated with it protection issues. Process bus based solutions also improve the safety of the substation by eliminating one of the main safety related problems - an open current circuit condition. Since the only current circuit is between the secondary of a current transformer and the input of the merging unit located right next to it, the probability for an open current circuit condition is very small. It becomes non-existent if optical current sensors are used.
Last, but not least, the process bus improves the flexibility of the bus differential protection. Since current circuits cannot be easily switched due to open circuit concerns, the application of bus differential protection becomes more complicated. The above is not an issue with process bus, because any changes will only require modifications in the subscription of the protection IEDs receiving the sampled analog values over IEC 61850 9-2.
Distribution Bus Protection
The protection and control in substations is distributed in nature by the fact that each protective relay is designed in general to provide primary protection of individual substation equipment such as transmission and distribution lines, transformers, capacitor banks, etc.
The only substation equipment that requires a centralized form of protection in conventional systems is the busbar. Transmission buses are typically protected by bus differential protection relays discussed earlier in the article. Because of the high cost and the increased requirements for maintenance, in many cases bus differential protection is not installed on distribution or sub-transmission buses. As a result, bus faults are cleared by backup relays with longer fault clearing times caused by the need for time coordination between the distribution feeder relays and the transformer relays. This becomes a significant power quality problem because of the increased duration of voltage sags. Multiple protective IEDs with IEC 61850 GOOSE can be connected to the substation LAN and used in distributed bus protection applications for distribution systems.
In case of a fault on any of the protected feeders (F1 in Figure 7), the feeder protection IED will detect a fault. The same fault current will be recognized by the transformer protection IED. As soon as the overcurrent protection element of the feeder relay starts, the IED will send a GOOSE message indicating the detection of a fault on the feeder. The transformer protection IED subscribes to GOOSE messages from all feeder relays. When it receives the message indicating that there is a fault on one of the feeders, the overcurrent protection element that is used for bus protection is blocked.
If the fault is on the bus (F2 in Figure 7), no feeder IED will see a fault, and the transformer protection IED is not going to receive a GOOSE message indicating a feeder fault. This indicates a bus fault and the relay is going to trip the transformer breaker to clear the fault. The peer-to-peer communications based bus protection requires an operating time for the fault detection of about one cycle for the relays involved. The addition of 0.25 cycle (4-5 ms) for the communication message and the safety time delay of 0.75 cycle in the transformer protection relay ensures a total operating time of about 2 cycles.
The benefit of this scheme is that instead of clearing the bus fault with the long time delay of a coordinated backup transformer protection, the only time delay required will be the longest possible overcurrent element starting time plus a safety margin.
IEC 61850 Based Directional Comparison Bus Protection
An alternative method for protecting the busbar in IEC 61850 based substations using station bus is a directional comparison bus protection scheme. Applying the concept of Distributed Applications defined in IEC 61850, combined with the use of advanced high speed directional detection algorithms based on superimposed components of the currents and voltages calculated by multiple protective relays connected to the substation LAN provides an excellent solution as a distributed bus protection. This application is based on the high-speed peer-to-peer GOOSE.
In case of a fault on any of the protected elements, one or more IEDs will detect a fault in the forward direction. Each of the relays protecting transmission lines or transformers, or installed on tie breakers connected to the protected bus will send a GOOSE message indicating the detection of a fault, combined with the fault direction determined by the relay. In this case one or more relays will detect a forward fault and the rest will recognize a reverse fault, indicating to the central unit performing the directional comparison scheme that this is an external to the bus fault.
If the fault is on the bus, all IEDs will detect a reverse fault or no fault (if connected to a weak source), i.e., no IED will see a forward fault.
The central unit has to be programmed to subscribe to GOOSE messages from all protection devices with high speed directional detection elements connected to the protected bus. In case of a fault, the distributed bus protection function in the bay controller IED monitors the GOOSE messages coming from the individual relays included in the distributed bus protection function of the system. A small time delay is required to ensure that all relays have had sufficient time to detect the fault and determine its direction.
Superimposed Components Based Directional Detection
The high speed detection of the direction of the fault is a very important factor to be considered during the evaluation of the distributed bus protection system.
Typically the directional element in a multifunctional protective relay is based on the phase relationship between phase or sequence currents and selected polarizing quantities - zero sequence currents or zero and negative sequence voltages. Changing system configuration may affect the polarizing quantities used for directional determination and result in relay misoperation.
Superimposed currents and voltages that are directly related to the fault may also be used with great success to determine the direction of the fault. This method allows accurate directional detection under varying system conditions and is not affected by series compensated transmission lines or mutual coupling. Therefore, it reduces the probability of relay misoperation and provides a very fast (¼ or ½ of a cycle) and reliable directional decision that can be used by a distributed bus protection system.
The directional detection function is represented in IEC 61850 by the RDIR logical node.
Directional Comparison Bus Protection System
All relays protecting primary equipment connected to the bus act in this application as the directional detection devices (sending IEDs), while the central unit is the receiving IED. The bus protection system includes two types of devices:
Central unit performing the directional comparison and all other related functions
Directional detection devices
A small time delay (0.25 cycle) is used in the distributed bus protection relay (timer started by the first received message indicating fault condition) in order to provide a safety margin for the pick-up of the different IED's directional fault detectors.
The bus protection requires an operating time for the directional detection of less than 0.5 cycles for the relays involved. The addition of 0.25 cycle (4-5 ms) for the communication message and the time delay of 0.25 cycle in the bus protection relay ensures a total operating time of about 1 cycle.
The benefit of the peer-to-peer communications based distributed bus protection is that it provides fast fault clearance for sub-transmission and transmission bus faults without the need for any additional protection equipment (if the function is implemented in a bay controller IED). It replaces a high or low impedance transmission bus protection device and in some cases may eliminate the need for additions or replacement of current transformers.
The distributed bus protection is easily adapted to changes in the substation bus configuration, since it will receive GOOSE messages containing information on any switching in the substation. Based on this information the bay controller IED will dynamically change its subscription list in order to receive messages only from the IEDs connected to the protected bus (See Figure 6). Another important benefit of this scheme compared to the process bus based bus differential protection is that it does not require the accurate time synchronization, i.e. no need for a separate synchronization network.
IEC 61850 based bus protection reduces wiring, installation, maintenance and costs.
IEC 61850 based bus protection systems offer significant advantages compared to conventional bus differential protection.
Figure 3: While the classical schemes need all current transformers to have the same CT ration, the modern schemes can accommodate different CT ratios throughout the protected zone.
Figure 5: The difference in this case is that the data of the data set are of the common data class SAV as defined in part IEC 61850-7-3.