AMAZON multi-meters discounts AMAZON oscilloscope discounts
[cont. from part 1]
3.3.3 Relay Protection with Terminal Units Mode
For relay protection with terminal units mode, relay protection devices are installed on the branches or laterals with higher fault ratios and coordinated with relay protection devices in the substations to reduce the influence of outage due to faults, which is equivalent to decreasing the fault ratio of the feeder. FTUs or fault indicators are also installed to further improve the reliability.
Assuming that the ratio of amount of branch or lateral faults to the fault of the whole feeder is ?, the ratio of relay protection devices installed on branches and laterals is µ, the fault ratio of the whole feeder may decrease to F/
as shown in
Equation (eq. 19)
(eq. 19, not shown)
Replace the F in Equation (eq. 13) with F/ and we may obtain the number of FTUs needed to be installed as shown in Equation (eq. 20)
(eq. , not shown)
Also, all the loop switches should also be installed with FTUs.
Replace the F in Equation (eq. 18) with F/ and we may obtain the number of fault indicators needed to be installed as shown in Equation (eq. 21)
(eq. , not shown)
3.3.4 Hybrid Mode of FTUs and Fault Indicators
As for the hybrid mode of FTUs and fault indicators, some of the terminal units are FTUs, the other terminal units are fault indicators. The cost of the hybrid mode of FTUs and fault indicators is moderate, where the area of fault isolation may be larger than the located fault region.
Assuming that the summation of FTUs and fault indicators on a feeder is k and the fault indicators are evenly inserted in the area surrounded by FTUs, source nodes, and ending nodes with h fault indicators in each, we have
[...]
As for hybrid mode of FTUs and fault indicators, the amounts of terminal units are different with the varying value of h. The costs of these feasible schemes are different.
We should choose the scheme with the lowest cost.
3.3.5 Discussions
In previous paragraphs, the planning of amount of terminals in typical cases is investigated. In this paragraph, some problems are discussed.
3.3.5.1 Hybrid Feeder of Cables and Overhead Lines
In previous paragraphs, the fault ratio per kilometer is assumed to be the same, in these cases the feeder is constituted by merely cables or overhead lines.
For the hybrid feeder of cables and overhead lines, if it mainly constitutes cables with a few overhead lines, it can be approximately regarded as a cable based feeder.
Conversely, if the feeder mainly constitutes overhead lines with a few cables, it can be approximately regarded as overhead line based feeder. If both the cable part and the overhead line part cannot be ignored, they should be planned according to the methods described in previous paragraphs, respectively.
3.3.5.2 Radial Feeders
In previous paragraphs, the planning method in case of satisfaction of the N – 1 criterion is described, which is not applicable for radial feeders.
Since radial feeders are mainly in rural areas, fault indicators are the first choice instead of FTUs. Assuming that k fault indicators are installed on the trunk dividing the feeder into k + 1 sections and the desired ASAI to only include the outage due to fault is no less than A, we have
[...]
FIG. 3 Examples to explain the amount of FTUs for cable feeders. (a) An example for large trunk layout; (b) An example of a large branch layout
3.3.5.3 FTU in a Ring Main Unit Cabinet
A FTU installed in a ring main unit cabinet sometimes may control more than one node, because the FTU is often equipped to monitor and control many switches.
Examples are shown in FIG. 3(a) and (b), respectively, in which the squares indicate the switches that have remote control ability, while the circles indicate the switches without the function of remote control. The solid ones indicate the corresponding switches are closed while the hollow ones indicate the corresponding switches are open.
A large trunk layout is shown in FIG. 3(a), in which the feeder is divided into five sections by four switches with remote control function. Two switches needing remote control are in the second ring main unit cabinet. Thus the FTU in the second ring main unit cabinet may monitor and control two such switches. Since only one switch needing remote control is in the third ring main unit cabinet, the FTU in the third ring main unit cabinet may monitor and control only one switch. The fourth switch needing remote control and the loop switch that also needs remote control are in the fifth ring main unit cabinet. Thus the FTU in the fifth ring main unit cabinet may monitor and control two such switches. Therefore, we need to equip three FTUs to remote control five switches distributed in three ring main unit cabinets.
A large branch layout is shown in FIG. 3(b), in which the feeder is divided into three sections by two switches with the function of remote control. These two switches needing remote control are in the third ring main unit cabinet. Thus the FTU in the third ring main unit cabinet may monitor and control two such switches. Therefore, we need to equip only one FTU to remote control two switches in the third ring main unit cabinet.
3.3.5.4 General Cases
The analysis in previous paragraphs is for some specified conditions. For other cases, although it is difficult to obtain unified formulations, the approaches to calculate the amount of FTUs and fault indicators are the same as describe in the previous subsections.
Considering that the parameters such as fault ratio, the time to isolate the fault region and restore the service of the healthy regions manually, and the repair time of failed devices corresponding to the fault, are quite difficult to accurately obtain, the results of the planning approach described in previous sections are sometimes used as reference, based on which the planner may adjust the results according to actual situations.
3.3.5.5 Modeled Connection Grids
For modeled connection grids, such as, multi-sectioned and multi-linked grids, multi supplying and one back-up grids, and 4 × 6 grids, the amount of FTUs relies on the need for corresponding modeled service restoration.
3.3.6 An Example of Planning
A city can be divided into three types of area according to the desired reliability of service. Supposing that the desired Average Service Availability Indexes (ASAI) of A-type, B-type, and C-type areas are 99.99%, 99.965%, and 99.897%, respectively.
The city distribution grids consist of 590 feeders. The A-type area consists of 50 cables. The B-type area consists of 60 cables, 80 insulated overhead lines, and 120 hybrid feeders. The C-type area consists of 180 un-insulated overhead lines.
The load reach of the feeders in the A-type area and B-type area is about 5 km while that in the C-type area is about 10 km.
The fault ratios per kilometer of un-insulated overhead lines, cables, insulated over head lines, and hybrid feeders are 0.1 (times/km.year), 0.04 (times/km.year), 0.07 (times/km.year), and 0.07 (times/km.year), respectively.
For the utility to supply the city distribution grid, the time to isolate the fault region and restore the service of the healthy regions by manual work is 1 h/time for the down town area and 2 h/time for the suburb. The time of the repair of the failed devices corresponding to the fault is 4 h/time for the downtown area and 6 h/time for the suburb.
The ratios of outage due to fault of the utility are 80% for an A-type area, 60% for a B-type area, and 22% for C-type area. Therefore, the Average Service Availability Indexes to only include the outage due to fault are 99.992% for an A-type area, 99.979% for a B-type area, and 99.977% for a C-type area.
These parameters may be obtained by statistical approaches.
It can be evaluated that if neither FTUs nor fault indicators are installed, the ASAI in the A-type area would be 99.9585%, the ASAI in the B-type area with cable feeders would be 99.9585%, while that with insulated overhead lines and hybrid feeders would be 99.9274%, the ASAI in the C-type area would be 99.7924%, which cannot reach the desired ASAI. Thus, FTUs or fault indicators should be installed in the A-type, B-type, or C-type area.
For the A-type area, the 50 cable based feeders are planned to form 25 couples of loop grids to meet the N - 1 criterion requirement. The feeders are only FTUs installed.
The 25 loop switches should equip FTUs in ring main unit cabinets. According to Equation (eq. 13), each feeder should equip one FTU in ring main unit cabinets. Thus, altogether, we need 75 FTUs in ring main unit cabinets for the A-type area. Also, no relay protection device should be implanted on the sectionalizing switches and loop switches of the feeder. All the sectionalizing switches and loop switches may be load switches instead of circuit breakers.
As for the 60 cable based feeders in the B-type area, they are planned to form 30 couples of loop grids to meet the N - 1 criterion requirement. The feeders are only installed FTUs. The 30 loop switches should equip FTUs in ring main unit cabinets. According to Equation (eq. 13), each feeder should equip one FTU in ring main unit cabinet. Also, no relay protection device should be implanted on the sectionalizing switches and loop switches of the feeder. All of the sectionalizing switches and loop switches may be load switches instead of circuit breakers.
Thus, altogether, we need 90 FTUs in ring main unit cabinets for B-type area cable based feeders.
As for the 120 hybrid feeders and 60 insulated overhead line based feeders in the B-type area, they are planned to form 90 couples of loop grids to meet the N - 1 criterion requirement. The feeders are only installed FTUs. The 90 loop switches should equip FTUs. According to Equation (eq. 13), each feeder should equip one FTU. Also, no relay protection device should be implanted on the sectionalizing switches and loop switches of the feeder. All of the sectionalizing switches and loop switches may be load switches instead of circuit breakers. Thus, altogether, we need 270 FTUs for hybrid feeders and insulated over-head line based feeders of B-type area. Assuming that one-third of the FTUs are the type in the ring main unit cabinets, the others are pole mounted FTUs.
For the 180 un-insulated over-head line based feeders in C-type area, they are also planned to form 90 couples of loop grids to meet the N - 1 criterion requirement. The feeders are only installed fault indicators. All of the branches and laterals with higher fault ratios are equipped with relay protection devices, automatic reclosing control, and circuit breakers. Assuming that three suits of such devices and fault indicators are equipped on each feeder, these reduce the fault ratio of each feeder by one-third.
Table 4 The results of planning
According to Equation (eq. 21), each feeder should equip one fault indicator on the trunk. Also, all of the sectionalizing switches and loop switches on the trunk may be load switches instead of circuit breakers. Thus, we need 180 fault indicators on the trunk for a C-type area, 540 suites of relay protection devices, automatic reclosing control, fault indicators, and circuit breakers on the branches and laterals. All of the terminal units are pole-mounted.
For FTUs, we chose fiberoptic communication media while for fault indicators, we chose GPRS.
The results of planning are shown in Table 4.
After engineering according to the planning results, the ASAI in the A-type area would be 99.9917%, in the B-type area with cable feeders 99.9689%, while that with insulated overhead lines and hybrid feeders would be 99.9728%, the ASAI in the C-type area would be 99.9222%, which can reach the desired ASAI. Thus, the planning is effective.
4. Verification of the Property of Fault Processing
The fault processing procedure needs the coordination of the corresponding devices.
Thus, the performance of fault processing is rather difficult to verify. In the 1990s, centralized intelligence based distribution automation systems were constructed in almost every province of China, few of which worked well. One of the major reasons is the lack of testing methodology, causing fault processing properties that needed to be verified to have to wait a long time for a fault to occur on the feeder. Thus, the defects of the system cannot be found in time. Even if a certain fault is correctly processed, the fault processing procedure may also fail in the case where another fault occurs due to the diversity of various faults.
A series of testing methodologies and corresponding devices have been developed by the research team at the Shaanxi Electric Power Research Institute, which will be described in this section.
FIG. 4 The master injection testing methodology. Terminal unit; Master station
of DAS to be tested; Master injection testing tool; Standard communication
protocol
4.1 Master Injection Testing Methodology and the Testing Tool
4.1.1 Basic Principle
The master injection testing methodology is shown in FIG. 4.
This methodology aims to inject the information reflecting the fault phenomenon into the master station of a centralized intelligence based DAS to be tested by the master injection testing tool, which can set up various fault phenomena; such as different fault positions, load scenes, relay protection action, operation by mistake, and so on, and simulate large amount of FTUs and fault indicators to execute the information exchanging with the master station using standard protocols instead of actual terminal units to verify the performance of the fault processing procedure. In other words, the master injection testing tool provides a simulated fault environment for testing and responding to remote control orders from the master station of a DAS, thus, the fault processing procedure may be continuously carried out and the steps are recorded so as to evaluate the performance of the fault processing procedure.
4.1.2 Master Injection Testing Tool
The master injection testing tool consists of seven modules; a load simulator to calculate the load flow of a distribution grid, a fault simulator to produce the fault phenomenon, a modeling and configuration tool, a real time database, a protocol translator, a communication manager, and a human-computer interface, which is shown in FIG. 5.
====
FIG. 5 Structure of the master injection testing tool.
Real-time database Protocol translator Modeling and configuration tool Fault simulator Communication manager Human-computer interface The DAS to be tested Load simulator
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4.1.2.1 Load Simulator
The load simulator has the functions of network topology analysis and load flow calculation, both of which are based on the simplified model of distribution grids described in Section 4.
• The network topology analysis sub-module establishes the network topology of the distribution grid according to the states of switches in the real-time database.
• The load flow calculation sub-module calculates the load flow according to the distributed load information from the regions in the real-time database to obtain the loads flowing through each node to simulate real-time information from the action and monitoring nodes collected by terminal units and then saves them in the real time database.
4.1.2.2 Real-Time Database
The real-time database has the following functions:
• Renewing the states of switches and the loads distributed from the regions according to the order from the protocol translator, the modeling and configuration tool, and the fault simulator.
• Renewing the loads flowing through each node.
• Renewing the fault information according to the orders from the fault simulator.
4.1.2.3 Modeling and Configuration Tool
The modeling and configuration tool has the following functions:
• Chart module integration based modeling of distribution grids adopting the simplified model of distribution grids described in Section 4.
• Configuration of switches, including their types, such as, circuit breaker, load switch, recloser, and so on, and states, such as closed or open.
• Configuration of load distributed from each region, which is described by load curves and with random fluctuation.
• Configuration of the terminal units and the corresponding configuration information of tele-control, tele-metering, and tele-indication.
4.1.2.4 Fault Simulator
The fault simulator has the following functions:
• Configuration of fault scenarios, such as fault positions (one or more), fault types (permanent or temporary), the switches refuse to act or not, reclosing is permitted or not, fault information missing or not, override trip or not, and so on.
• Produce the fault information and send it to the real-time database according to the configuration of the fault scenes and network topology.
The flowchart of fault simulation is shown in FIG. 6.
FIG. 6 Flowchart of fault simulation
4.1.2.5 Protocol Translator
The protocol translator has functions as follows:
• Configuration of the protocols, such as DNP, IEC-61850, IEC60870-5-101, IEC60870-5-104, and so on.
• Generation of the upgoing message according to the information in the real-time database produced by the load simulator and the fault simulator.
• Translation of the downgoing message and putting the load and switch state information into the real-time database. When receiving a tele-control order, set or reset the state of the corresponding switch considering whether the switch set refuses to act.
• Keep the real-time data interaction between the real-time database and the master station of the DAS to be tested.
4.1.2.6 Communication Manager
The communication manager has functions as follows:
• Message communication management with multi-IP address to simulate a large amount of terminal units communicating with the master station of the DAS to be tested.
• Link monitoring and reconnection when necessary.
4.1.2.7 Human-Computer Interface
The human-computer interface has functions as follows:
• Input and output management.
• Operation and control management.
• Generation of a table of test results.
4.1.3 Testing Steps
The testing steps of the master injection testing methodology are as follows:
• Data input, modeling, and configuration.
• Set the fault position, type, and scenarios.
• Set the loads distributed from the regions and the states of the switches before the fault.
• Inject the fault phenomenon to the master station of the DAS to be tested.
• Interaction with the master station of the DAS to be tested and response to the downgoing orders, during which the performance of fault processing is tested.
The master injection testing tool also has the function of importing and exporting the model of the distribution grid from the master station of the DAS to be tested via the data bus following standard IEC-61968. Thus, the modeling of a DAS is strongly recommended to be standard.
In the case where the model is exported from the master station of the DAS to be tested, the testing is aimed at the actual distribution grid to mainly find out the configuration errors. The fault can be set one region at a time automatically so as to test the fault processing performance of every region.
The test may also be based on some specially designed fault scenes, which are imported into the master station of the DAS to be tested. This testing is to verify the adaptability of fault processing performance. It is also used to evaluate DAS products.
To tackle lack of fault diversity by setting faults on the actual distribution grids means the test cases should be well designed.
FIG. 7 Schematic diagram of secondary synchronous injection test method
4.2 Secondary Synchronous Injection Testing Methodology and Testing Facilities
The secondary synchronous injection testing methodology uses the dedicated testing facilities consisting of a commander based on a portable computer and some fault information generating devices.
The secondary synchronous injection testing methodology is illustrated in FIG. 7.
A temporary relay protection device should be implanted on the source node in the substation to produce the information of a certain circuit breaker tripped while its corresponding relay protection device acts.
The fault information generating devices are connected to the terminal units upstream of the fault position to inject the fault current and voltage to the corresponding terminal units simultaneously, causing them to produce fault information to the master station of the DAS to be tested. The fault information generating devices are synchronized by GPS. The testing may cause short-time service interruption of the feeder to be tested.
Before testing, the waveforms of fault currents and voltages are calculated by the analysis software of the commander computer and are sent to the corresponding fault information generating devices.
In the testing procedure, the waveforms of fault currents and voltages are amplified to the secondary ranges of the CT and PT, and injected to the corresponding terminal units simultaneously by the fault information generating devices in the sequence designed beforehand. In other words, the secondary synchronous injection testing facilities produce the simulated fault phenomenon and inject them to the input of the automatic devices.
Thus, the fault processing performance of the coordination of the master station, terminal units, relay protection devices, back-up power supplies, switches, and communication systems can be tested, which is the advantage of the secondary synchro nous injection testing methodology. But the workload is quite large during the testing procedure. The numbers of both workers and facilities are great, since each terminal unit needs work and a fault information generating device. Also, the testing may cause short-time service interruption of the feeder to be tested.
4.3 Master and Secondary Synchronous Injection Testing Methodology
The master and secondary synchronous injection testing methodology is a great help to avoid of service interruption during the test and reduce the numbers of workers and facilities.
4.3.1 Avoiding Service Interruption during the Test
Since the fault processing program is started when the master station receives information from a certain circuit breaker that is tripped while its corresponding relay protection device acts, the corresponding information is provided by the master injection testing tool instead of the actual signals from the secondary devices of the corresponding source node in the substation, so as to avoid tripping the source node.
The other fault information corresponding to the fault position is produced by the secondary synchronous injection testing facilities but relays are connected to the corresponding FTUs instead of the actual switches so as to avoid tripping of the switches.
Also, the master injection testing tool should be also synchronized by GPS.
With this approach, the service interruption is avoided but the coordination of back-up supplies and switches cannot be covered in the test and should be examined by the remote transmission test, which needs a planned outage.
The master and secondary synchronous injection testing methodology to avoid service interruption during the test is shown in FIG. 8.
FIG. 8 The master and secondary synchronous injection testing methodology
to avoid service interruption during the test
4.3.2 Reduce the Numbers of Workers and Facilities
To reduce these numbers, we may connect a few fault information generating devices alternative to the terminal units corresponding to the fault position to inject the fault current and voltage to the corresponding terminal units simultaneously, causing them to produce fault information to the master station of the DAS to be tested. The fault information of the other terminal units corresponding to the fault position is simulated by the master injection testing tool. Thus, only a few fault information generating devices and workers are needed during the test. Of course, the master injection testing tool should be also synchronized by GPS.
The master and secondary synchronous injection testing methodology to reduce the numbers during the test is shown in FIG. 9.
In the most compact case, the master and secondary synchronous injection testing methodology only needs one master injection testing tool and one fault information generating device.
With this approach, the numbers of both workers and facilities are reduced but the coordination of backup supplies and switches cannot be covered in the test and should be examined by the remote transmission test, which needs a planned outage.
FIG. 9 The master and secondary synchronous injection testing method to reduce
the numbers of workers and facilities
4.4 Direct Short-Circuit Test
The three injection testing methodologies described in Sections 4.1-4.3 are suitable for testing the performance of inter-phase short circuit fault processing for centralized intelligence based DAS and local intelligence devices, but rather difficult to use to test the performance of inter-phase short circuit fault processing for distribution intelligence systems and single phase to ground fault processing. The direct short-circuit test is an effective approach to solve these problems The direct short-circuit test is to insert a resistor between two phases or one phase to ground of the feeder by a switch to form a real slight fault to test the performance of the fault processing procedure.
The safety protection measures are the key of the direct short-circuit test.
A direct short-circuit test system consists of a specially designed resistor with a high power capacity, a quick switch, a remote controller, a suite of special fittings, and a set of over-current relay protection devices, which is shown in FIG. 10.
The resistance of the resistor needs to be carefully designed to meet the requirements of inter-phase short circuit fault and the single phase to ground fault tests. In Asia, the typical values are 800~1000 Ohm for an inter-phase short circuit fault and 100~300 Ohm for a single phase to ground fault. As for inter-phase short circuit fault tests, the resistance should be a little larger to reduce electric shock to the system.
Thus, sometimes the setting values of corresponding relay protection devices and terminal units may decrease during the test.
The direct short-circuit test is suitable to verify both the inter-phase short circuit fault and the single phase to ground fault processing procedure of any mechanism.
4.5 Comparison of the Four Testing Methodologies
The four testing methodologies described in previous sections have their pros and cons. The comparisons are shown in Table 5.
The facilities required by the four testing methodologies are shown in Table 6.
FIG. 10 A direct short-circuit test system
5. Conclusion and Summary
Some approaches including relay protection, automatic reclosing, backup switching, recloser and voltage-delay sectionalizers, reclosing with fast protection, the fast healing approach based on neighbor communication, and centralized intelligence DAS are compared for their inter-phase short circuit fault processing performance. A fault location and restoration approach based on coordination of centralized, distributed, and local intelligence is proposed. When a fault occurs on a distribution grid, the local and distributed intelligent based devices clear the fault and roughly isolate the faulted
section immediately. After collecting the total fault information, the DAS accurately locates the fault position and carries out correcting control to finely isolate the fault section and restore the service to as many loads as possible in an optimized way. The performance of fault isolation and restoration for distributed grids can be improved by coordination of centralized, distributed, and local intelligence.
From the point of view of service reliability, the required amounts of various kinds of
terminal units in different situations, such as only FTUs with tele-control function, only fault indicators without tele-control function, and hybrids of FTUs and fault indicators, are investigated. The following conclusions are drawn that only one terminal unit for each feeder is the best choice on the view point of cost-benefit ratio, and that the amounts of various kinds of terminal units depend on the desired service reliability performance, the time to isolate the fault section, the repair time, and the frequency of failure per-year. A DAS planning example is given to illustrate the methodology described in this section.
In order to verify the fault processing performance of the centralized intelligence based DAS, the local intelligence based relay protections and distributed intelligence based DAS, four testing methodologies are described including the master injection testing methodology, secondary synchronous injection testing methodology, master and secondary synchronous injection testing methodology, and the direct short circuit test. The four testing methodologies have their pros and cons and are suitable for use in different applications.
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Table 5 The comparison of the four testing methodologies
Testing methodologies | Advantages | Disadvantages | Scope of application | Master injection testing methodology
The complicated fault phenomenon and scenes can be set up. Without electric shock. Multiple faults can be simulated for stress test. Without service interruption.
Only covers the master station of the centralized intelligence based DAS.
The single phase to ground fault processing performance cannot be tested Verifying the inter-phase short circuit fault processing performance of the master station of the centralized intelligence based DAS.
Secondary synchronous injection testing methodology
Without electric shock. The coordination of the master station, terminal units, relay protection devices, back-up power supplies, switches, and the communication systems can be tested The fault phenomena and scenario set up is simple. Multi-fault is difficult to simulate for stress test.
The numbers of both workers and facilities are larger.
Needs service interruption. The single phase to ground fault processing performance cannot be tested Verifying the inter-phase Short-circuit fault processing performance of the centralized intelligence based DAS and the local intelligence based relay protections.
Master and secondary synchronous injection testing methodology
The complicated fault phenomenon and scenes can be set up. The master station, terminal units, relay protection devices and the communication systems can be covered. Without electric shock.
Multiple faults can be simulated for stress test.
Without service interruption.
The numbers of both workers and facilities are greatly reduced.
The coordination of back-up supplies and switches cannot be covered in the test.
The single phase to ground fault processing performance cannot be tested Verifying the inter-phase short circuit fault processing performance of the centralized intelligence based DAS.
Direct short circuit test
More realistic fault phenomena. The coordination of the master station, terminal units, relay protection devices, backup power supplies, switches and the communication systems can be tested. Distributed intelligence based DAS can be tested. The single phase to ground fault processing performance can be tested; The fault phenomenon and scenes set up is simple. Multi-fault is difficult to simulate for stress test. The workload is larger. Needs service interruption and with electric shock.
Verifying the inter-phase short circuit fault and single phase to ground fault processing performance of the centralized intelligence based DAS, the local intelligence based relay protections and the distributed intelligence based DAS
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Table 6 The facilities required by the four testing methodologies
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