Trends in Intelligent Electrical Switchgear Technology

1. System Solutions

Product solutions include: 10–20 kV switchgear automation assemblies; ring-main unit automation upgrade; Internet applications and big-data platform development; improvement of safety control levels for remote electrical operation of switchgear cabinets.

Automated distribution switchgear is mainly classified by function into four types: A, B, C, and D.

A: switchgear with circuit breaker or recloser providing main cable line protection.
B: load-break switchgear for segmenting main cables; it only needs to interrupt normal load current.
C: ring-main interconnection switchgear, focusing on checking the surge impact on the grid when two power sources are closed together.
D: terminal automatic transfer switchgear, capable of rapid transfer of the supply network.

These four types are used at different nodes in an automated distribution network to perform their respective functions.

Technical consulting scope: cabinet structural layout design; primary and secondary integrated cabling; control models and control technologies for automated cable networks and overhead feeder automation; functional standardization of switchgear to reduce cabinet variants where appropriate; fault location techniques; standardized construction processes; online software monitoring; system safety assessment; operational modes and protection setting analysis; mesh distribution power flow calculations.

Development trends:

Intelligent grid switchgear is moving toward higher performance and miniaturization.
Associated equipment is evolving toward new materials and lower pollution.
Integration of multiple sensor technologies is driving multifunctional electrical equipment.
Product design is shifting from single-device control to series and assembled equipment.
Manufacturers are moving from supplying individual devices to offering integrated solutions to users.
Extensive R&D and application of "Internet+" integration technologies in power equipment.

2. Content of Switchgear Technology Upgrades

Integration of primary and secondary electrical switchgear.

Switchgear upgrade design mainly covers four aspects:

Improve the safety and reliability level of switchgear technical equipment.
Save equipment investment through upgrades and increase technical added value.
Apply computer network technology to optimize safe operation modes, modernizing distribution network management.
Use IoT information technology to address fault alarms and fault location challenges.

Maintenance plan after commissioning: ongoing maintenance, system testing, line fault simulation and practical training.

3. Product (Primary-Secondary Integrated Equipment) Solutions

Includes secondary instrument control enclosures.

Early-stage distribution automation planning: switchgear matching, retrofit consulting, selection of layouts compatible with DTU, and cost-performance analysis.
Feasible design: intelligent cabinet structure design, switch component functional design, DTU cabinet functional integration, upstream and downstream product matching, retrofit configuration design, and remote control method design.
Technical retrofit and performance upgrade: system commissioning, retrofit process definition, line structure design and connections, motor safety control, factory-style construction, and complete-assembly commissioning.

4. Main Wiring Methods for Switchgear Operating Mechanisms

Main wiring (integrated cabling) types: circuit breaker cabinet + isolation switch; load-break switch cabinet; load-break switch + fuse combination cabinet; sectionalizer combination cabinet; outgoing feeder circuit breaker cabinet.

II. Practical Technical Problems and Solutions

Primary-secondary integration converts manual switchgear into intelligent switchgear. The main benefit is better utilization of existing equipment and extension of switchgear service life. Major technical problems for retrofits include:

Long outdoor on-site construction times.
Difficulties obtaining 220 V power on site.
Most outdoor switchgear currently lack dedicated low-voltage control enclosures.
CT parameter inconsistency leads to large errors during signal conversion.
Most distribution switchgear uses SF6 gas-insulated cabinets; abnormal gas pressure plus remote control operations can cause hazardous incidents.
Large equipment size may require expanded external housings that are constrained by site, complicating retrofit of outdoor substations and RMUs.

III. Solving Switchgear Fault Detection Issues

Primary objective of integrated primary-secondary switchgear technology is to resolve fault detection and remote fault handling.

Three causes of outages in a 10 kV distribution network:

Operations due to sudden line faults causing outages.
Operations during planned outage for line maintenance.
Operations for supply transfer when changing the line operating mode.

Local fault detection can locate faults without sending fault data to the control center for analysis and without additional fault indicators.

By collecting voltage information from all cable branches, distribution automation terminals can determine current direction for each RMU bay, so the control center can clearly identify incoming and outgoing feeders. As network topology changes, in/out data refresh automatically, eliminating repeated on-site verification.

Safe operation modes for various switching scenarios

Control devices add SF6 gas pressure electronic detection and automatic undervoltage interlock functions. Operators must check the SF6 pressure gauge before local switching; operations are prohibited if pressure is outside the safe range. RMU retrofits include mechanical and electronic interlocks to make human-machine interaction safer and more reliable.

New electronic detection and interlock functions allow remote dispatch to operate as if on site. If an incorrect open/close command is issued remotely, the local controller can automatically protect the switchgear to prevent larger accidents caused by erroneous operations.

Key safety extension functions

Main safety functions for switchgear open/close operations include:

Door-open alarm.
External transformer (PT) power detection.
Cabinet gas pressure low alarm.
Backup power battery undervoltage detection and interlock.
Fault interlock protection to prohibit operations.
Local/remote control switching per circuit.
Directional detection of current flow during open/close operations.
Earthing knife detection.
Phase overcurrent and earth-fault detection.
Open-circuit/phase-loss, three-phase imbalance, and phase-sequence automatic detection.

IV. Improving O&M Quality and Efficiency of Intelligent Switchgear

Improve standardization and integration of primary-secondary equipment, enhance customized production and operational levels of assembled distribution equipment, and improve O&M quality and efficiency.

1. Integrated manufacturing

Cabinet optimization: new structures and processes such as front-and-rear doors and raised top plates to ease installation and maintenance.
Resolve on-site PT power extraction and continuous high-power supply issues.
Address voltage acquisition challenges.

New capacitive composite sensor technology enables cable voltage acquisition. Intelligent devices can infer current direction based on voltage operational power, solving incomplete detection information for power lines.

Improve high-precision current acquisition quality to address power and fault-direction determination. By collecting current data and estimating power angle, the system provides foundational data for stable operation of ring-main lines.

Address installation difficulties of intelligent terminal devices: moving 90% of retrofit work to back-end factory preassembly with preinstalled components simplifies site work and improves retrofit quality.

Solve drive circuit installation issues: the motor-driven mechanical transmission for opening/closing is a core part of intelligent switchgear. Reliable motor drive and error-free safety control are essential. Innovations achieved reliable circuits and fail-safe control to improve operational safety.

2. Unified technical standards among component suppliers

Primary-secondary integration for RMUs resolves module replacement and factory maintenance issues, with the final assembly plant coordinating unified technical standards.

Resolve mismatched primary-secondary interface dimensions, poor compatibility, limited expandability, and interchangeability.
Mediate product quality responsibility disputes between primary and secondary equipment manufacturers.

3. Fault detection and protection functions

Overcurrent protection: configurable protection time limits and phase current settings. Fault judgement should be at least two-stage, with adjustable trip currents and delays.
Zero-sequence current protection: detect zero-sequence current with configurable trip current and delay.
Zero-sequence voltage protection: detect zero-sequence voltage with configurable trip voltage and alarm time.
Reclosing protection: configurable up to two automatic reclosing attempts with adjustable counts and delays.
Second-stage locking of reclosing: if a fault current is detected within a configured period after the first reclosing, lock the second reclosing.

V. Distribution Automation Functional Modes

1. Voltage-based automation (voltage loss-trip type)

Loop closing detection: detect voltage difference across a switch to support loop closing.
Voltage-loss delayed trip logic: if the switch is closed and both sides lose voltage and there is no load, after the delay the terminal should trip.
Voltage-restored delayed close logic: if the switch is open and one side regains voltage while the other remains unenergized, after the delay the terminal should close.
Single-side voltage-loss delayed close: if the switch is open and both sides were stable for 30 s, then one side loses voltage and the delay expires, the terminal should close; this function can be configured for either side.
Prohibit close when both sides have voltage: if open and both sides have normal voltage, FTU should lock the close function.
Locking close detection: if after closing the set fault-detection period a voltage loss and fault current are detected, auto-trip and lock the close; if no fault current is detected, trip without locking the close.
Short-term lock on trip: for voltage-type switches, after successful closing a brief lock on tripping is required; if no fault is detected within the set time, the short-term lock resets.

2. Current-based automation (overcurrent protection logic)

Phase fault judgment: after setting relay protection thresholds, detect phase faults with instantaneous trip and terminal should trip immediately.
Earth fault judgment: detect zero-sequence voltage within a set delay and trip immediately to clear earth faults; if outside the delay, overhead-line terminals do not act.
Non-interrupting current protection: FTU should lock the trip circuit when current through a load-break switch exceeds a set threshold (e.g., 600 A).

3. Intelligent automation functions

If a cable fault indicator lights red, the circuit should automatically lock to prohibit closing.
After tripping, if the line remains live, automatically lock earthing knives and cable compartment covers.
After system operation is locked due to a fault, determine whether local unlock is permitted.
If both feeders are incoming and one has already performed a close, determine whether the other is prohibited from closing.
Detect incorrect phase sequence for loop closing and lock operations automatically.
Determine whether loop closing operations are prohibited by the automation system.

VI. Intelligent Medium-Voltage Switchgear

Intelligent switchgear integrates information technology into traditional electrical switchgear. It relies on digital acquisition, processing, use, and transmission of information in an open interconnected model to improve equipment performance, reliability, and safety, and to provide richer digital information for grid operation control to enhance overall supply performance.

Technical features of intelligent switchgear:

Basic functions are control and protection: sense grid current, monitor voltage and current in real time, rapidly trip to isolate fault current, and protect transformers and customer equipment. Intelligent switchgear senses, diagnoses faults, and executes line protection functions.
Medium-voltage switchgear intelligence: sensors gather equipment operating state and convert analog signals to digital for local processing or transmission via high-speed network interfaces to remote control centers.
Distribution network self-healing: the system should detect faults, warn of unsafe states, and operate to minimize impact on users. Achieving self-healing requires efficient intelligent devices.

VII. Core Controller for Intelligent Ring-Main Units

Distribution automation requires many intelligent devices. The controller is the core unit for intelligent RMUs. It changes the main or control circuit wiring and adjusts circuit resistance values in a predefined sequence to control motor start, speed regulation, braking, and reversal.

1. Main controller functions and roles

Receive and identify upper-level commands: the controller must accept various commands from the control center, poll local sensors, and report execution results upstream.
The controller acts as the control element while peripheral devices are the executing elements, linked via control wiring.
Control issues commands via control lines and receives feedback via status lines for "state testing" to issue new commands based on execution state.
Controllers are divided by motor-drive function into unidirectional and bidirectional controllers.

Controllers must include motor constant-current control: matching startup torque current and dynamic running current to balance starting torque and provide protection if mechanical gear torque increases due to faults. Controllers need suitable current-control components to be compatible with various motors, ensuring safe control without on-site matching, simplifying installation and use.

Controllers should automatically detect relevant interface states (e.g., external switch signals) and implement automatic protection on faults, restoring normal state when faults are cleared. Controllers should support integrated automatic/manual operation and flexible configuration. Electrical interlocks with mechanical interlocks ensure automatic parameter adjustment.

2. Controller practical functions

Provide local/remote switch at the controller.
Allow open/close operations via lever or button.
After manual trip, if the cable is de-energized, the controller remains unlocked.
The circuit can still be operated by lever/button and the earthing knife can be operated.
With the earthing knife closed and the front cover opened, cable maintenance is possible.
If the cable head remains live after a trip, the controller's lock switch locks automatically.
When locked, electric operations and earthing operations are disabled; manual lever operations remain possible.
If the earthing knife cannot be closed, the front cover remains locked.
After maintenance, return the controller lock to the unlocked position.
After unlocking, lever/button open/close operations are permitted.
Set the controller back to remote for entry into the remote-control system.

3. Main functions of switching breakers

Close: moving contacts are controlled by a quick-acting mechanism. Load-break switches do not have stored energy except for contact movement. For circuit breakers and fused load-break switches, the operating mechanism can store energy simultaneously with contact closure.
Open: opening is achieved by reversing the quick-acting mechanism. For circuit breakers and fused load-break switches, opening is via button operation or fault trip.
Earthing: a specially designed handle inserted into an operating hole closes or opens earthing contacts. Holes for handle insertion are blocked by shutters; when the switch is open the hole is accessible, and when closed the hole is locked. The earthing switch is interlocked with the bay front cover; the cover opens only when the earthing switch is closed.
Position indicator: mounted directly on the moving contact shaft to reliably indicate device status.
Operating handle: anti-repeat-operation design prevents immediate re-opening after a load-break or earthing switch is closed.
Padlock device: accommodates 1–3 padlocks to prevent accidental operation, used to lock switch or breaker axes, earthing switch axes, or trip buttons.
Earthing switch closed-position indicator: located on the device top; status is visible through a transparent cover when the earthing switch is closed.
Metal enclosure: sealed stainless-steel enclosure complying with IP67. Installed on functional units for internal cable live indication, meeting IEC-61958 technical standard.

4. RMU Secondary Basic Circuit

Upgrading motor-operated devices to automated remote devices requires replacing manual signal observation with automatic signal acquisition. Low-voltage acquisition is a technical challenge. Common practice adds 1–2 PTs (0.22/10 kV) to measure incoming feeder voltages. Since typical switchgear has four circuits, not all cable voltages can be measured. Line voltage indicators rely on capacitive coupling at cable terminations; the voltage signal is very weak and difficult to use directly.

1. Line live indicator

Capacitive voltage indicator: shows whether the bushing is energized and provides a socket for phase verification. The system integrates voltage indicators (LEDs). For normal operation environments, live display devices are recommended. Phase identification should use a recommended phase comparator.

2. Manual phase comparator

Phase comparators display phase balance between two modules. For use in capacitive coupling systems, follow the relevant IEC requirements. The phase comparator must be used with the recommended voltage indicator to verify correct line connections before energizing.

3. Line fault indicator

When short-circuit or zero-sequence current exceeds preset values, the device LEDs flash and a contact operates for remote signaling. When the fault clears and the preset delay elapses, the device resets or can be reset via a contact input.

DTU devices amplify weak voltage signals to usable levels. DTU terminals can determine fault currents (single-phase, phase-to-phase, earth) based on collected current magnitudes and set thresholds, and then send fault data to the distribution control center to support fault analysis, isolation, and load transfer. Fault signals can quickly lock devices via remote signaling and light fault indicators. Data is retained in the DTU and is retrievable on site through management software.

3. Conclusion

Converting manual switchgear to intelligent switchgear enables fuller utilization of equipment and extends switchgear service life.

Switchgear upgrade and retrofit focus on four areas: increasing safety and reliability of technical equipment; saving investment and increasing technical added value; applying computer network technology to optimize safe operation and modernize distribution management; and applying information technology to resolve fault alarm and fault location challenges.