The world of electrical power systems is changing rapidly. As demand grows, renewable energy expands, and reliability expectations increase, the traditional substation—filled with copper wiring, electromechanical devices, and point-to-point analog signals—can no longer meet modern requirements.
Digital substations are changing the game. Instead of relying on tons of physical wiring, they use fast communication networks to move information more efficiently. A big part of this digital shift in substations comes from IEC 61850-9-2. It defines how current and voltage data is sent as Sampled Values over Ethernet, making the whole system faster, safer, and more flexible.
In this article, I break down IEC 61850-9-2 in a clear and practical way—what it is, why it matters, how it works, and how merging units, time sync, protection, and engineering all fit together. I also cover the real benefits and challenges of moving to a fully digital measurement system.
Table of Contents
Why Digital Substations Need IEC 61850-9-2
For decades, substations relied on individual copper wires running from instrument transformers in the yard to each protection relay in the control room. This wiring could stretch hundreds of meters, adding cost, weight, and installation time.
This approach has several limitations:
- Each relay requires its own dedicated wiring.
- Modifying or adding equipment means installing more cables.
- Long copper runs introduce electrical risks.
- Testing and maintenance are more labor-intensive.
Digital substations solve these limitations by by using fiber-optic Ethernet instead of analog wiring. Instead of sending raw electrical signals through long copper cables, the measurements are digitized right at the source and sent as Sampled Values to the protection devices.
This brings several major advantages:
- One set of measurements can be shared by multiple protection devices.
- Reduces large volumes of copper wiring.
- Enhances flexibility for expansion or reconfiguration.
- Improves safety by limiting exposure to high-energy circuits.
- Provides more accurate and consistent data for protection logic.
This approach removes hundreds of meters of copper cable, reduces installation cost, and improves safety. It also allows for centralized protection, where a single intelligent device—such as ABB’s SSC600—can protect an entire substation by receiving all the SMV streams from multiple bays. The SSC600 training material confirms that “measurements are delivered via Process Bus” using IEC 61850-9-2 LE.
Understanding What IEC 61850-9-2 Actually Defines
IEC 61850 is a broad, multi-part standard. Part 9-2 specifically defines the method used to transmit Sampled Measured Values (SMV) over an Ethernet-based process bus. These Sampled Values represent instantaneous measurements of electrical quantities such as:
- Three-phase currents
- Three-phase voltages
- Zero-sequence components
- Optional additional measurements
The basic workflow is:
- Instrument transformers measure analog values at the primary equipment.
- A merging unit samples these signals and digitizes them.
- The merging unit publishes Sampled Values at a fixed rate.
- Protection relays, centralized protection devices, or monitoring systems subscribe to these SV streams.
Sampling Rate
A common sampling rate is 4,000 samples per second for a 50-Hz power system. This corresponds to 80 samples per electrical cycle, providing enough detail for precise protection and measurement algorithms.
Multicast Ethernet Frames
Sampled Values are transmitted using Layer-2 multicast frames, allowing multiple devices to receive the same measurement stream simultaneously without extra wiring.
Two Variants
There are two widely used variants:
- IEC 61850-9-2 LE (Light Edition) — an earlier implementation profile widely adopted in practice.
- IEC 61850-9-2 Edition 2 — the more standardized and future-oriented version.
Both serve the same overall purpose but have technical and structural differences in dataset definitions and flexibility.
The Role of the Merging Unit
At the heart of IEC 61850-9-2 communication is the merging unit (MU). This device replaces the traditional wiring between CTs/VTs and protection relays.
A merging unit performs three essential tasks:
1. Digitization
The MU samples the analog input from CTs and VTs at a fixed interval. Sampling must be extremely accurate to ensure consistent timing across all devices in the substation.
2. Data Structuring
The sampled currents and voltages are packaged into standardized frames defined by IEC 61850-9-2. Each frame contains:
- Instantaneous current values
- Instantaneous voltage values
- Quality information
- Timestamp alignment
- Identification attributes
3. Communication
These frames are transmitted as multicast messages over the process bus. Any subscribing device can use these samples to:
- Perform protection calculations
- Measure power quality
- Visualize phasors
- Trigger fault detection algorithms
Modern merging units often support:
- Conventional CT/VT inputs
- Sensor-based inputs
- Redundant Ethernet ports
- IEEE-1588 time synchronization
- GOOSE messaging for additional status or control signals
The merging unit is essentially the digital bridge between the physical grid and the virtual protection environment.
The Importance of Time Synchronization
Accurate time synchronization is absolutely essential for IEC 61850-9-2 systems. All merging units must sample currents and voltages at the exact same moment. Even tiny timing differences can lead to incorrect calculations—for example, in differential protection, where two or more current values must be compared precisely.
To accomplish this, digital substations rely on IEEE 1588 Precision Time Protocol version 2 (PTP) using the Power Utility Profile.
Why PTP Is Necessary
Power system protection demands microsecond-level accuracy. If sampling is misaligned:
- Differential protection might interpret mismatched inputs as a fault.
- Phasor calculations may become inaccurate.
- Distance protection zone boundaries can shift unexpectedly.
- Harmonics and power quality measurements become unreliable.
PTP ensures that all devices—merging units, protection relays, centralized controllers, and recorders—operate using one unified, high-precision time source.
Typical Time Sync Architecture
A typical substation includes:
- A grandmaster clock
- Redundant PTP-aware network switches
- Slave devices such as merging units and protection bays
This synchronized environment ensures consistent and dependable protection performance.
How Sampled Values Improve Protection and Control
The introduction of Sampled Values dramatically changes how protection schemes are designed and implemented. Instead of each protection relay measuring its own currents and voltages physically, everything is delivered digitally.
Centralized Protection
A major innovation enabled by IEC 61850-9-2 is the possibility of centralized protection. Instead of having one relay per bay, a single powerful device can protect multiple bays by subscribing to all SMV streams in the substation.
This provides:
- Simplified maintenance
- Easier updates to protection logic
- Quicker project deployment
- Higher availability through redundancy
- Very high measurement accuracy because all inputs share the same time reference
Flexible Logic
Digital substations are software-defined. Protection logic, interlocking, and automation sequences can be modified without touching any physical wiring. Adding new functions becomes a configuration task instead of a construction project.
Multi-Use Measurements
With SMV, the same dataset can be used simultaneously by multiple devices:
- Protection units
- SCADA systems
- Fault recorders
- Power quality analyzers
- Synchrophasor units
This dramatically improves the visibility and transparency of the substation.
The Process Bus: Backbone of SV Communication
The process bus is the Ethernet network that carries Sampled Values from merging units to protection devices. It must be extremely reliable, fast, and deterministic. While office networks care about throughput, substation process buses care about timing and continuity. A single lost frame may affect protection calculations.
Key Requirements
A well-designed process bus must have:
- Deterministic latency
- Sufficient bandwidth
- Multicast support
- Priority tagging (QoS)
- VLAN segmentation
- Redundant paths
- PTP awareness
Redundancy Protocols
To ensure continuous operation even during failures, two redundancy methods are widely used:
PRP (Parallel Redundancy Protocol)
Devices transmit frames simultaneously on two independent networks. If one path fails, the other carries traffic without delay.
HSR (High-availability Seamless Redundancy)
Frames circulate across a ring structure. If one link breaks, traffic flows in the opposite direction.
Both systems prevent packet loss and guarantee seamless protection communication.
How GOOSE Messaging Complements SMV
Sampled Values provide measurements, but protection and control systems also require fast exchange of discrete signals—such as:
- Breaker open/close
- Disconnector and earthing switch status
- Interlocking signals
- Trip and closing commands
- Protection start/operate outputs
- Arc-flash detection
GOOSE (Generic Object Oriented Substation Event) messaging handles this. GOOSE and SMV work together as two halves of a complete digital protection ecosystem.
SMV
- Provides continuous measurement data
- Sent at fixed intervals
- Enables protection functions and calculations
GOOSE
- Sends event-driven status and commands
- Delivers interlocking and control messages
- Transfers binary protection states
This combination replaces most of the copper wiring traditionally used in substations.
Engineering an IEC 61850-9-2 System
Engineering a digital substation does not involve pulling wires. Instead, it focuses on configuring software and network parameters.
Typical engineering steps involve:
1. Network Planning
- Selecting topology (star, ring, PRP, HSR)
- Defining VLANs
- Assigning priorities
- Ensuring sufficient bandwidth
2. Configuring Merging Units
- Setting sampling rates
- Defining SMV IDs
- Configuring dataset structures
- Linking physical inputs to digital outputs
3. Setting Up Subscribers
Protection devices must be told which SMV streams they will subscribe to. This requires:
- Assigning SMV receive blocks
- Mapping current and voltage inputs
- Establishing correct scaling settings
- Handling quality flags
4. Time Synchronization Setup
Every device needs the appropriate PTP role configured:
- Grandmaster
- Boundary clock
- Slave clock
5. Logic Engineering
Protection logic is built in application configuration tools and includes:
- Current & voltage protection
- Sequence logic
- Interlocking
- Breaker control
- Arc-flash detection
- Busbar differential
6. System Testing and Commissioning
Modern test equipment can publish simulated SMV streams, allowing testing without energizing the substation. This makes commissioning significantly easier than with conventional wiring.
SMV in Differential and Busbar Protection
Differential protection schemes benefit tremendously from SMV. Because each merging unit samples based on the same time reference, the currents at different ends of the equipment can be compared accurately in real time.
Advantages Include:
- No CT mismatch due to different burden or saturation
- No need for physical differential wiring
- Multiple protection zones can be created with software
- Easy adaptation of complex busbar configurations
Busbar protection is especially suitable for SMV-based digital substations. The protection unit receives current samples from all bays, applies the differential algorithm, and issues trips through GOOSE messaging.
Fault Recording and Monitoring with SMV
Fault analysis becomes easier and more powerful in a digital substation. Since all analog and digital signals are available on the network, they can be recorded centrally.
Key monitoring features include:
- Real-time phasor diagrams
- Event and disturbance records
- Instantaneous waveform recording
- Boolean (binary) signal capture
- Quality flag evaluation
- Validity indicators for GOOSE and SMV
This improves troubleshooting, enhances learning from incidents, and reduces downtime.
Benefits of Transitioning to IEC 61850-9-2
Digital substations bring a long list of operational, economic, and safety advantages.
Reduced Wiring
A single fiber cable replaces large bundles of copper. This reduces installation time, cost, and physical complexity.
Improved Safety
Fiber carries no dangerous voltage and reduces electromagnetic interference.
Scalability and Flexibility
Adding new bays becomes a configuration problem rather than a construction project.
Vendor Interoperability
Because IEC 61850 defines standardized communication, equipment from different vendors can work together.
Higher Precision
Time-aligned sampling and digital measurement improve protection performance.
Faster Commissioning
Testing is easier because measurements can be injected digitally through SMV simulators.
Challenges and Considerations
Despite the advantages, adopting IEC 61850-9-2 introduces new challenges that must be addressed.
Network Design Complexity
Protection engineers must become familiar with:
- Ethernet switching
- VLANs
- QoS
- Multicast filtering
- Redundancy protocols
Cybersecurity Demands
As substations become networked, protecting them from cyber threats becomes critical.
Dependency on Time Sync
Loss of PTP synchronization can compromise protection. Systems must include redundancy and monitoring.
Interoperability Testing
Although IEC 61850 is standardized, devices still require thorough system testing.
Skill Requirements
Teams must develop expertise in IT/OT convergence, networking, configuration tools, and digital troubleshooting.
The Future of IEC 61850-9-2 and Digital Protection
Digital substations will play a central role in future power systems. As utilities modernize, IEC 61850-9-2 will continue to expand in several directions:
- Full adoption of Edition 2
- Wider use of sensor-based instrument transformers
- More centralized and distributed protection hybrids
- Integration with synchrophasor-based monitoring
- Smarter event analysis using AI and machine learning
- Enhanced cybersecurity frameworks
The movement from copper-based, relay-by-relay thinking to integrated, Ethernet-based architectures is irreversible. Digital substations bring the precision, flexibility, and scalability required for a modern electric grid.
Conclusion
IEC 61850-9-2 Sampled Values communication represents one of the most significant technological advancements in modern substation design. By digitizing current and voltage measurements at the merging unit and sending them over a high-speed, synchronized, redundant process bus, substations gain unprecedented flexibility, accuracy, and visibility.
Protection functions become more powerful, more reliable, and easier to manage. Centralized protection, software-defined logic, and shared measurement streams enable designs that are impossible in conventional substations. Although adopting IEC 61850-9-2 requires new skills, careful engineering, and strong cybersecurity practices, the long-term benefits far outweigh these challenges.
As power systems evolve toward more renewable energy, more dynamic load behavior, and more demanding reliability requirements, IEC 61850-9-2 provides the communication backbone that future digital substations will rely on. Its influence will continue to grow, shaping the way utilities design grid protection, monitoring, and control for decades to come.