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Introduction
Smart substations have made clear progress in both digitalization and automation. Compared with traditional substations, secondary circuits have been digitized and fiber-optic based, saving large amounts of cabling and metal, reducing secondary circuit failure rates, and enabling status monitoring and intelligent alarms. Some advanced functions of substation automation have also improved and become standardized; features such as sequence control can significantly increase the operational efficiency of switches and breakers.
However, smart substation projects still face several problems: some secondary devices show poor stability and high failure rates; testing and commissioning capabilities are insufficient; operation and maintenance are inconvenient; retrofits and expansions are difficult; frontline management is weak in some regions; and on-site staff may not adapt quickly to new technologies. There is still no effective systematic solution. The main causes can be grouped into three areas:
1) Complexity of the IEC 61850 standard
The IEC 61850 standard family is extensive and complex, making it difficult for many technical personnel to master. A substation designed strictly to IEC 61850 typically uses a single SCD file to configure information exchange across all secondary devices, so a single change can affect the entire station. System operation depends on the station SCD and device CID files, and configuration methods are not easy to master. Tools for debugging, operation, and maintenance are still immature and not user friendly.
2) Reliability of electronic instrument transformers
Electronic instrument transformers face issues in device quality, manufacturing and installation processes, and data-processing reliability. The reliability of merge units is also a significant factor, and this interacts with local installation approaches and substation architecture.
3) Complexity of the substation architecture
The smart substation architecture is typically three-layer (station control layer, bay layer, process layer) and two-network (station control network, process network). Monitoring systems and other devices use network-sampled values and network-based tripping. Protective relaying, to ensure speed and reliability, uses direct acquisition and direct tripping, while interlock signals are still transmitted over the network. This leads to a very complex process layer, a large number of device interfaces, increased design and manufacturing difficulty, and more operational issues.
These three problems are interdependent and difficult to solve separately, so a systematic solution is required.
1 Design approach
1.1 Technical principles
The next-generation smart substation secondary system should inherit practical experience from previous generations and adopt proven key technical principles. Main principles include:
- Continue to adopt the IEC 61850 standard.
- Support both electronic instrument transformers and conventional instrument transformers.
- Protective relaying devices should be independent and distributed, not dependent on external time synchronization, while ensuring fast and reliable system response.
- Secondary system operation and maintenance units should match the primary system bay structure. Although current practice configures secondary devices by bay, there is no explicit principle for configuring secondary circuits by bay. The transition of secondary circuits to fiber networks and associated software, configuration files, and information flows has obscured the per-bay configuration principle. Therefore, secondary devices and secondary circuits (including networks, software, configuration files, and information flows) should be configured per bay and not expanded beyond the bay, so that secondary O&M units match primary system bays. This principle is key to the success of the next-generation smart substation.
1.2 Technical route
The overall technical route is a simplification and adjustment of existing smart substation solutions to form a clear and concise architecture, improving O&M convenience and operational reliability, enabling large-scale efficient deployment and easing retrofit of existing substations. Key actions include:
- Simplify application of IEC 61850 in smart substations; or develop tailored sub-standards or clauses suited to local conditions.
- Raise the importance of commissioning and O&M software and hardware tools, with emphasis on user experience. Develop function-oriented configuration and commissioning tools to make IEC 61850 transparent to users.
- Develop a clear, simple architecture that satisfies protection, measurement and control requirements; consider removing the process-layer network and switches.
- Configure secondary circuits (including network, software, configuration files, and information flows) by bay. Decouple the station-level SCD into per-bay components and decouple device CID files by process-layer, bay-layer, and station-layer, forming independent small configuration files (or in some cases eliminating configuration files). Small configuration files can be modified without mutual interference and can be locally validated after changes.
- Eliminate or simplify merge units of electronic instrument transformers to improve transformer reliability.
- Retain the advantages of local installation of protective relays while avoiding the maintenance inconveniences it may introduce.
- Improve secondary system integration and joint debugging efficiency.
2 Process layer improvements using a digital secondary-circuit device
Although secondary circuits have evolved into fiber networks and corresponding software, configuration files, and information flows, they should still be configured by bay so that secondary O&M units match the primary system bays. To this end, a new digital secondary-circuit device is proposed. It is configured per bay and requires no station-level configuration file; it needs only simple settings or may require no settings at all.
The following subsections describe schemes for line bays in single/dual bus topologies, bus bays, and the overall station secondary-system architecture. Examples include TV bays, bus-coupler (sectionalizing) bays, and main transformer bays.
2.1 Line bay scheme for single/dual bus
Each bay is configured with one digital secondary-circuit device that performs all secondary-circuit connection functions within that bay. Downstream it connects to the bay's CT sampling modules, VT sampling modules, breaker intelligent terminal, and TV bay voltage input. Upstream it connects to protection, measurement and control devices, and the bus protection device, as shown in the figure.
The digital secondary-circuit device supports multiple communication interfaces and can flexibly connect to various device interfaces. When transmitting sampled values, each phase current and voltage sample carries a sampling delay. Sampling delays are measurable and can potentially be kept fixed. The device can perform functions analogous to CT series connections, VT parallel connections, and relay contact wiring in a conventional substation (including trip/close commands, interlock signals, and position status). Bus protection requires current, voltage, position signals and trip commands that are all transmitted by this device. Start and lock signals between bus protection and line protection are also transmitted by this device.
The process layer eliminates electronic instrument transformer merge units; transformer sampling modules (remote modules) connect directly to the digital secondary-circuit device. For conventional transformers, CT and VT sampling modules are configured separately. Breaker intelligent terminals retain existing designs and configurations and connect to the digital secondary-circuit device via their communication interfaces.
2.2 Bus bay scheme
Bus-bay secondary equipment configuration and connections differ from line bays. Electrical quantities, discrete signals, and trip commands required by bus protection are transmitted through the digital secondary-circuit devices of each connected element bay, as shown in the figure.
To further improve bus protection reliability, a dedicated digital secondary-circuit device can be provided for bus protection. Its configuration and wiring are similar and are not repeated here.
2.3 TV bay scheme
The TV bay digital secondary-circuit device collects voltage samples sent by the local VT sampling modules and the TV disconnect position signal, and performs VT voltage paralleling. The TV bay device has multiple output interfaces to send voltage signals to the digital secondary-circuit devices in line bays. Its function is similar to an existing bus VT merge unit, as shown in the figure.
Note: Voltage switching for line bays is handled by protection devices. The digital secondary-circuit device performs message forwarding only and does not implement logical functions.
2.4 Bus-coupler (sectionalizing) bay scheme
Secondary equipment configuration and connections for bus-coupler or sectionalizing bays are similar to line bays and are not detailed here.
2.5 Main transformer bay scheme
The configuration and connection principles for main transformer bays are the same as for line bays. Each side of the main transformer is configured with one digital secondary-circuit device, as illustrated in the figure.
2.6 Overall secondary-system architecture for the smart substation
Under the above design approach, the substation architecture no longer requires a process-layer network or switches, and bay secondary equipment and secondary circuits are autonomous. Station control layer equipment and the station control layer network remain essentially unchanged. The substation time synchronization system follows existing solutions: sampling modules access the time signal and sampled values carry timestamps for synchronization in measurement, control, and metering devices. Protective relay functionality does not depend on this time synchronization system.
By removing the process-layer network and switches, the digital secondary-circuit devices no longer require IEC 61850 configuration files. The station SCD is greatly simplified and essentially contains only station-control-layer device information and bay-layer information related to the station control layer, significantly reducing secondary-system integration and joint-debugging workload.
