[align=left] Overview Power distribution system automation is an important part of urban power grid planning and construction. The implementation of power distribution system automation should be based on the planning and construction of the urban power distribution network, focusing on three major goals: improving power supply reliability and power quality, improving services to users, and improving the economic benefits of power supply enterprises. After the large-scale urban power grid transformation during the Ninth Five-Year Plan period, the power grids of many large and medium-sized cities have basically met the conditions for implementing power distribution system automation. However, the practice time of power distribution system automation in China is not long, and many technical issues need to be tested in operation, and the functions need to be gradually improved. Therefore, we must formulate a development plan and implementation plan for power distribution system automation in our region, hoping that power distribution system automation will have a significant development in China. [b]1 Main Functions of Power Distribution Automation[/b] The main functions of power distribution system automation should include: (1) Dispatch Automation (SCADA). (2) Substation Automation System. (3) Feeder Automation (FA) and Distribution Network Automation (DA). (4) Automatic Mapping/Equipment Management/Geographic Information System (AM/FM/GIS). (5) User Fault Telephone Complaint (Repair) System (TCM). (6) Distribution Management System (DJM). (7) Distribution Network Application Software. (8) Electricity Business Automation System. (9) Load Management System. (10) Remote Automatic Meter Reading System. (11) Distribution Transformer Online Monitoring Device. (12) Automatic Control of Reactive Power Compensation on Medium and Low Voltage Sides. Among the above functions, (1) to (7) are the functions that need to be developed at present, and the others are related sub-functions that have been implemented or are being implemented. Among them, the regular functions of the SCADA dispatching system are the same as those of existing products, but in order to realize distribution network automation, the functions must be expanded and developed. [b]2 10 kV Feeder Automation[/b] 2.1 Classification of Feeder Automation According to the implementation principle, it is divided into: voltage type or voltage-time type (Japanese model) feeder automation, current type (American model) feeder automation, improved voltage type feeder automation, and remote control type feeder automation. According to whether there is a channel, it is divided into: feeder automation without a channel and feeder automation with a channel. According to the remote control type, there are two types: feeder automation controlled by the substation (secondary master station) and feeder automation controlled by the dispatch control center (primary master station). 2.2 Voltage-type feeder automation (no channel) Figure 1 shows a voltage-type feeder automation and the operation process when a fault occurs in section 2. The 10kV feeder on the A side of the substation is divided into 4 sections and is connected to the feeder of the opposite substation through the tie switch LD. The line circuit breaker CB1 is equipped with a relay protection device to cut off the fault current. The line sectionalizing switches FD1-FD3 are load switches, and their operation characteristics are: (1) When the voltage is lost on both sides of the sectionalizing switch, the sectionalizing switch will automatically open instantly. (2) When one side of the sectionalizing switch is energized, it will automatically close after x seconds. (3) The energization detection time after closing is set to y seconds. When y>x, it is judged to be in normal condition. When y<x, it is judged to be a permanent fault, and the reclosing will be permanently blocked after the second voltage loss. (4) The tie switch LD can be operated manually or automatically. In automatic mode, when one side is energized and the other side is de-energized, it automatically closes after a delay greater than the total cycle of two reclosing cycles after the circuit breaker on one side of the line clears the permanent fault. [/align][align=left] [img=610,446]http://zszl.cepee.com/cepee_kjlw_pic/files/wx/zjdl/2001-1/2-1.jpg[/img] The characteristics of voltage-type feeder automation are: (1) Using load switches as sectionalizing switches, the cost is lower than that of using circuit breakers (about 20% lower). (2) It mainly relies on pre-set logic coordination to complete the prescribed action procedures, avoiding complex relay protection setting coordination. (3) It has promotional value for distribution networks that do not have channel conditions. Its main disadvantages are: (1) The time for power restoration is relatively long. (2) For clearing permanent faults, the main power supply line side recloses twice and is impacted by short-circuit current twice (same as the case without feeder automation), and the backup power supply line side also recloses once and is impacted by short-circuit current once, and the users on the opposite side of the line are affected by unnecessary short-term power outages. (3) The existing protection and reclosing devices of the substation feeders need to be improved to adapt to the operating logic, or additional reclosers should be added. 2.3 Current-type feeder automation (no channel) This type is mainly used in the urban distribution network in the United States. In Figure 1, the sectionalizing switches and tie switches all use circuit breakers with reclosing function and are equipped with relay protection devices. When a fault occurs in the section between FD1 and FD2, the relay protection devices of the sectionalizing switches FD1 and FD2 near the fault point will operate to clear the fault. The advantage of current-type feeder automation is that the logic relationship is simple and the fault can be quickly isolated. A fault in one section does not affect the power supply of other sections. Its disadvantage is that the power outage protection configuration and setting are complex. The following is an analysis of two configuration methods using definite time and inverse time current protection: (1) Using definite time current protection instantaneous or time-limited current fast protection - Since the power supply radius of the 10 kV line in the urban network is short, only 3 to 5 km, and after being segmented, the short-circuit current level at the beginning and end of each segment does not change much, the current fast protection has almost no protection range. Overcurrent protection - Since the 10 kV feeder overcurrent protection is the last level of backup protection in the power grid, its operating time is generally 1 to 1.5 s. To ensure the step-by-step coordination with the protection devices of several sectional switches on the feeder in terms of time, considering the inherent opening time of the sectional switches (about 200 ms), the time difference must be at least 0.3 to 0.5 s, and definite time overcurrent protection cannot be used for coordination. (2) Using inverse time overcurrent protection to achieve coordination by utilizing the inverse time operating characteristics of the protection device. Successful operating experience has been achieved in the United States, but the setting coordination of inverse time overcurrent protection is very complicated. The current type feeder automation scheme is not suitable for urban power grids in China. Whether current-type feeder automation can be adopted in rural power grids also needs to be determined after analysis of the specific power grid. 2.4 Improved voltage-type feeder automation In response to the above-mentioned shortcomings of voltage-type feeder automation, domestic companies are developing improved products for voltage-type feeder automation. Two schemes are introduced below: (1) The sectionalizing switch has the function of detecting short pulses (pulse voltage ≥ 30% of rated voltage, duration ≥ 150 ms) and blocking reverse power-on closing. Figure 2 shows the operation process when a permanent fault occurs in section 2 (description omitted). When FD1 closes at the fault, FD2 has detected a very short live pulse. Its closing circuit is permanently blocked for reverse power-on, and the fault section is isolated. [/align][img=566,282]http://zszl.cepee.com/cepee_kjlw_pic/files/wx/zjdl/2001-1/3-1.jpg[/img] This scheme has a new idea and can realize reverse power-on blocking for asymmetrical faults. The disadvantage is that when a three-phase short circuit occurs, the sectionalizing switch on the far side of the fault point may not be able to detect the short pulse signal, so it is impossible to achieve reverse power-on blocking. (2) Sectional switches and tie switches with post-acceleration protection Based on Figure 1, the following improvements have been made: all sectionalizing switches and tie switches are circuit breakers, and protection devices with reclosing post-acceleration are configured on the sectionalizing switches and tie switches. This device is only put into operation after the reclosing is started. The post-acceleration protection operation delay t2 is less than the operation delay t1 of the time-limited fast-acting protection of the substation feeder circuit breaker. Since the post-acceleration protection only cooperates with the substation feeder protection after the reclosing operation, it is generally easy to set. Figure 3 shows the operation process when a fault occurs in section 2 (description omitted). When sectionalizing switches FD1 and FD2 reclose to a permanent fault, the acceleration trip and reclosing are blocked, and the fault is isolated. The main difference between the above two improvement schemes is that the sectionalizing switch in scheme (1) can be a load switch, while the sectionalizing switch in scheme (2) must be a circuit breaker. [img=561,288]http://zszl.cepee.com/cepee_kjlw_pic/files/wx/zjdl/2001-1/3-2.jpg[/img] 2.5 There are three remote control schemes for feeder automation with remote control function: (1) Based on the determination of the fault section, remote control operation is performed on the tie switch LD and the sectionalizing switch FD3 in Figure 1, which are far from the fault section. This is to speed up the restoration of power supply to the non-fault section. (2) At the secondary master station, the fault is located, isolated and power supply is restored. (3) At the primary master station, the fault is located, isolated and power supply is restored. The first type is suitable for the early stage of feeder automation development. On the basis of building the channel, the downlink remote control function is added and the operation command is manually issued by the dispatch center. The second type is suitable for distribution networks with simple network structure and small scale. It is just a simple reorganization of the network structure to realize load transfer. The third type of feeder automation is suitable for complex distribution networks with multiple segments and connections. It has stronger and more reasonable network optimization and network structure reorganization functions. This actually goes beyond the scope of single feeder automation (FA) and constitutes distribution network automation (DA). Remote control feeder automation implemented by a primary or secondary master station is based on the principle of "area protection". That is, each sectional switch is not equipped with a separate relay protection device, but the fault current information of each sectional switch is reported to the master station through a channel. The master station uses this information to make a comprehensive judgment on the faulty section. Figure 4 shows an example of a multi-phase fault in section 3: when both sectional switches on both sides of a section have fault current flowing through them (such as sections 1 and 2), or neither has fault current flowing through them (such as section 4), it is judged as a non-faulty section. When one sectional switch (closer to the power supply side) of a section has fault current flowing through it, while the other sectional switch (far from the power supply side) has no fault current flowing through it, it is judged as a faulty section, as shown in section 3 in Figure 4. Obviously, since the determination of the fault section takes several seconds or more, the disconnection of the fault current must still be completed by the substation feeder circuit breaker. After the fault section is determined, the master station issues an instruction to trip the FD2 and FD3 sectionalizing switches, and close the substation feeder circuit breaker and tie switch LD according to a certain procedure to restore power supply to the non-faulty section. [align=left] [img=569,254]http://zszl.cepee.com/cepee_kjlw_pic/files/wx/zjdl/2001-1/4-1.jpg[/img] The advantages of remote control type distribution network automation (DA) are: (1) It speeds up the isolation of the fault area and shortens the fault handling process. (2) It speeds up the restoration of power supply to the non-faulty area. (3) It reduces the number of impacts on the system. (4) The reconstruction and optimization of the network can improve voltage quality and reduce network loss under multiple constraints. [b]3 User Fault Complaint System[/b] The power distribution network contains numerous branch lines, distribution transformers, and corresponding protective devices and operating switches, which are closely connected to a large number of users. When a fault in a branch line, distribution transformer, or its low-voltage side causes a power outage for some users, there is no real-time control mechanism. The user fault complaint system was developed in this context. After its establishment, the system determines the location of the user in the power grid based on their complaint call and identifies the fault range according to the network topology. For example, as shown in Figure 5, if all users experiencing a power outage are within the power supply range of distribution transformer 2, the fault is determined to occur within the power supply range of distribution transformer 2; if the users experiencing a power outage are scattered across the power supply ranges of two or more distribution transformers supplied by branch line 1, the fault is determined to occur on branch line 1; if the users experiencing a power outage are scattered across several branch lines, the fault may occur on the main line, and so on. Conversely, if only one user complains about their power outage, the fault is likely within the user's internal wiring. [img=275,238]http://zszl.cepee.com/cepee_kjlw_pic/files/wx/zjdl/2001-1/4-2.jpg[/img] Clearly, a geographically contextualized distribution network wiring diagram, along with historical user information obtained from the electricity business management system, forms the basis for handling fault complaint calls. The adoption of this system not only compensates for the insufficient real-time information of the distribution network but also establishes a good relationship between the power department and users, promptly answering users' most pressing questions such as the cause of power outages and the time of power restoration, further improving the quality of service to users. [b]4 Dispatch SCADA System[/b] In addition to collecting real-time information belonging to the distribution network within the substation, the dispatch SCADA system should also collect real-time information from equipment such as 10kV pole-mounted switches and ring network switchgear through feeder remote terminals (FTUs), develop necessary application software, and build communication channels. The SCA-DA dispatcher should not only have general functions, but also implement the following new functions according to the requirements of power distribution system automation and the characteristics of power distribution network: (1) User-friendly human-machine interface, easy operation, and full graphic display and multi-window technology. (2) Dynamic coloring and local tracking function of lines. (3) Equipment fault diagnosis, isolation and recovery. (4) Equipment location. 5 Power Distribution Network Analysis Application Software The power distribution network analysis application software mainly includes: (1) network modeling, (2) network topology, (3) state estimation, (4) load modeling and calibration, (5) power flow of power distribution network, (6) fault location, isolation and recovery, and (7) network structure reconstruction and optimization. For power distribution networks with a three-phase imbalance greater than 5%, it is hoped that power flow software adapted to three-phase unbalanced power distribution systems can be developed. The constraints for network structure reconstruction and optimization are: (1) minimizing the power outage range for users; (2) avoiding overload on equipment and lines; (3) ensuring qualified voltage quality; (4) minimizing the number of switching operations; (5) minimizing network losses; and (6) distributing loads as evenly as possible among feeders. Much research has been conducted on distribution network application software in China. However, software suitable for network structure reconstruction and optimization in distribution networks still needs further accumulation of operational experience and continuous improvement. [b]6 Distribution Network Geographic Information System[/b] The urban distribution network geographic information system describes the structure of the urban distribution network using geographic graphics against the background of the urban geographic map. Ultimately, it forms a geographic information system with distribution network characteristics, user characteristics, and geographic characteristics. This system is a key technology for building distribution system automation. On this system platform, online and offline distribution network data, distribution network data and user data, and power grid graphics and geographic graphics are effectively integrated, mainly applied to the following aspects (see Figure 6). [img=360,272]http://zszl.cepee.com/cepee_kjlw_pic/files/wx/zjdl/2001-1/5-1.jpg[/img] (1) Provides a geographical background image for the dispatch SCADA system, providing dispatchers with an effective, realistic, and intuitive network model with geographical information. (2) Serves as the basis for handling fault complaint calls. (3) Provides various forms of information to the electricity business management system for users to apply for electricity connection, load management, and other business operations. Querying relevant user geographical locations automatically generates several power supply schemes, effectively reducing the workload of on-site surveys, accelerating the speed of new user electricity connection applications, and even enabling telephone connection applications. (4) Provides a geographical background to the power distribution work management system, serving as the basis for the operation, maintenance, design, and construction management of power distribution network equipment. (5) Provides a geographical background for urban power grid planning, determining reasonable and feasible line (cable) routes and the locations of substations and switching stations. **7 Distribution Operation Management** Distribution operation management involves comprehensive management of the daily operations of the distribution network on a geographic background graphical interface provided by GIS. This includes: distribution network operation management, equipment maintenance management, file and statistical management, statistical reports, and management of distribution engineering design, as-built drawings, and completion reports. Based on successful international practices, efficient maintenance of distribution system automation data is a crucial management task. That is, construction drawings for distribution network renovation projects must be completed on the same geographic information system to ensure that the construction drawings conform to the current reality. After construction is completed, the as-built drawings that conform to the reality must be promptly returned to the geographic information system to ensure that the system always remains consistent with the site conditions. **8 Main Principles of Development and Application** Distribution system automation is a comprehensive automation system for distribution networks, substations, and users. It has basic functions such as monitoring, control and protection, design, construction and maintenance, management, and service. It involves a wide range of management aspects, many professional departments, a large amount of data, high capital investment, and a long cycle. In its development and application, the following main principles should be followed. 8.1 Strengthen leadership, unify planning, and implement in stages. The development and application of power distribution system automation is a transformation from traditional manual management to modern management. Whether this transformation can be completed depends on many factors: (1) Power distribution system automation is a high-investment industry. Therefore, the application of power distribution system automation technology in a region depends first on the region's economic development level and the degree of power supply reliability requirements. Attention must be paid to the input-output efficiency. (2) Power distribution system automation involves the coordinated actions of multiple professional departments. The level of understanding of the application of this technology by leaders at all levels is key. Only the coordinated actions of the leadership can solve many problems that must be solved, such as funding, management, system, and talent. (3) On the basis of planning and constructing the urban power distribution network, carry out the planning and construction of power distribution system automation. Make good unified plans and implement in stages, including the gradual improvement of functions and the gradual expansion of application scope. (4) Talent reserve is fundamental. (5) Strengthen the collection and organization of basic data to adapt to the needs of modern management. For example, the establishment of electronic maps must be planned and prepared as early as possible. 8.2 Planning and Construction of Urban Distribution Networks Urban distribution networks should be constructed according to the following principles, which are also the basic conditions for implementing distribution automation: (1) Ensure that in the event of an accident in the 110 kV power grid, the 110 kV substation capacity and the 10 kV main line have sufficient load transfer capacity. 1) There are two or more reliable independent power sources (220 kV substation - 110 kV substation) supplying power to the medium-voltage distribution network. The medium-voltage distribution network forms a ring network connection and open-loop operation power supply mode. 2) The interconnected feeder lines should have sufficient reserve capacity to bear the load current transferred by the faulty line. Therefore, the main line should use large cross-section conductors, and the load current under normal operating conditions should be 2/3 to 1/2 of the allowable current for heating. The medium-voltage distribution networks of developed countries abroad have developed to the point that all feeders have the ability to transfer loads, and the distribution networks of many large cities in China are also working towards this goal. (2) Divide the 10 kV feeders into appropriate and reasonable sections. More feeder segments are not necessarily better. Too many segments will drastically increase power supply costs, while power supply reliability will not increase proportionally. Generally, the number of segments should be determined based on the load density and through technical and economic comparison. The urban power grid of Zhejiang Province stipulates that the normal load current of each 10 kV line should be controlled at 200 A, and the maximum load current should be 300 A. Generally, 3 to 4 segments are appropriate. The total capacity of transformers installed on each 10 kV line should be ≤10,000 kVA, and the total capacity of transformers installed on each segment should be controlled within 2,500 to 3,000 kVA. (3) Benefits of implementing feeder automation. If all feeders of the substation are connected in a ring network manner to achieve "ring network connection and open-loop operation" power supply, the power supply reliability rate can reach 99.96% to 99.98%. Implementing feeder automation can further improve the power supply reliability rate by about 0.02 percentage points. For distribution networks with a low power supply reliability rate, although implementing feeder automation can also improve the reliability rate, it is undoubtedly a counterproductive approach. 8.3 The principle of economic benefits Many factors affect the economic benefits of power distribution system automation, such as the number of line segments, the selection of segment switches (load switches or circuit breakers), the selection of dispatch master station, the selection of communication channel mode, the collection of real-time information, and the protection of the owner's investment. All of these should be decided on the basis of a good technical and economic comparison and according to local conditions. The scale of real-time information collection is an important indicator that directly affects the scale of the master station and the design of software functions. It is the most sensitive to the impact on investment. The practices of each country are different, which is related to the national conditions and national strength of each country: (1) In the New York power distribution network in the United States, by 1997, about 1/3 of the distribution transformers and 1/2 to 2/3 of the switches were remotely controlled. Tokyo Electric Power Company in Japan started to develop towards remote control and centralized control on the basis of voltage-type feeder automation. The Spanish power company IBER-DROLA consulted a consulting firm on the collection and control of real-time data in the distribution network. The conclusion was that the amount of real-time data collected and controlled should account for about 8% of the total amount of all objects. In actual engineering implementation, it may be less than 8%, and some countries believe that it can reach 10%. The appropriate proportion should be specially demonstrated to determine the appropriate proportion for our national conditions. (2) Collection of real-time information of distribution transformers. First, it is necessary to plan and build a good power supply scheme for the low-voltage distribution network, determine a reasonable power supply radius and distribution transformer capacity, ensure that the transformers in the community operate under economic conditions and the voltage quality of users, and form a relatively standardized power supply mode. For this purpose, it is necessary to monitor the real-time status of typical distribution transformers for different types of users to provide sufficient basic data for the planning of the low-voltage network. However, in the long run, once the planning and construction of the low-voltage network is in place, it is neither necessary nor possible to monitor all distribution transformers in real time. (3) Other alternative schemes. By establishing load models of various types of distribution transformers, the measured load current of the substation feeder can be distributed to the connected distribution transformers or the load current of each segment can be distributed proportionally. Make the load or segmented load of the network load point match the measured load recorded at the feeder port of the substation. Regarding the protection of the owner's investment, it has the following implications: (1) Make good interfaces with the computer application subsystems already developed by the owner to avoid waste of resources. (2) Provide technical means for data format conversion between different subsystems and products from different manufacturers to avoid repeated input of a large amount of original data. (3) Pay attention to the connection between products from different manufacturers. 8.4 Regarding system selection, on the basis of analyzing functional requirements, make good overall system design and propose detailed technical indicators. This article focuses on clarifying integration and openness. At present, domestic and foreign manufacturers are still based on two main platforms: the dispatch SCADA platform and the geographic information system (GIS) platform. The integration of the platform requires a unified data environment, and the maintenance, modification and updating of data of the distribution network and users are unique to adapt to the high frequency of data changes in the distribution network and users, and can ensure: (1) the safety of dispatch operation, (2) the safety of on-site maintenance and construction operations, (3) the accuracy and timeliness of user business expansion application, and (4) the improvement of distribution management efficiency. Based on the current level of technological development and product situation, the system can be categorized into the following types: (1) Due to historical development reasons, SCADA was developed first, followed by GIS. These two system platforms are completely independent and unrelated. (2) SCADA functions are implemented on the GIS platform. Manufacturers must clearly define the applicable power grid scale and scope of the system. (3) Data integration is achieved on the two platforms, which involves three stages: 1) Real-time data from SCADA is transmitted to the GIS platform in a unidirectional manner, but the GIS data and graphics cannot be viewed on the SCADA platform. There must be two workstations, SCADA and GIS, on the dispatch console. 2) Graphic exchange: Both SCADA and GIS content can be viewed on the same workstation. 3) Same data environment: Not only can both SCADA and GIS content be viewed on the same workstation, but the data of the distribution network equipment is also maintained under a unified data environment, ensuring the consistency and uniqueness of the data. (4) SCADA data and GIS data are "integrated" into the same database. This is just a concept, and no operational practice has been seen yet. Regarding system openness, there are many specific requirements, but in summary, it is necessary to optimize system resource allocation, use standardized and general-purpose products for system hardware as much as possible, ensure that application software can run on major computer models, use commercial general-purpose databases as historical databases, adopt standard TCP/IP network protocols, support multiple RTU (FTU) protocols, adopt API application programming interfaces, and have a development environment for user application software, etc. 8.5 Make good planning and construction of corresponding communication channels. The implementation of power distribution system automation must have a sound communication plan, and the planning and construction of communication channels should be regarded as an important part of the construction of power distribution system automation. The design of information channels for power distribution system automation should consider its own characteristics: (1) There are many nodes in the power distribution communication network, which are scattered and intersecting. (2) The distance between each node is relatively close. (3) The amount of information at each monitoring point is small, and it should have the function of actively reporting information. (4) The communication route should adapt to the frequent changes in the power distribution network structure and have diversified route selection. The available communication methods are: wired audio communication, wireless communication, fiber optic communication, and medium-voltage carrier in the power distribution network. When selecting a communication method, factors such as the amount of information to be transmitted, reliability, transmission rate, anti-interference capability, and attenuation should be considered, and a comprehensive determination should be made based on local conditions and a technical and economic comparison. Generally, a hybrid method is preferable, and the comprehensive utilization of communication channels should be encouraged to avoid redundant investment. 8.6 Selection of Primary/Secondary Equipment for Distribution System Automation The implementation of distribution system automation will multiply the number of primary and secondary equipment in the distribution network. In addition, a large number of high-tech pole-mounted products (intelligent pole-mounted switches, FTUs, etc.) will be added. Due to the harsh outdoor operating conditions, the scope of high-altitude operations may expand, which will greatly increase the cost of operation and maintenance. Therefore, highly reliable, maintenance-free products must be used; otherwise, power supply companies will be overwhelmed. Auxiliary equipment such as CTs and PTs配套 with switches should preferably be built-in. Outdoor equipment must meet a series of technical requirements, including rust prevention, condensation prevention, leakage prevention, wide temperature tolerance range, low power consumption of the operating mechanism, and long-life batteries.