A smart grid has five layers: the physical grid, field devices and metering, communications, management systems and distributed resources. Each layer depends on the one below, and the most frequent failures appear at the joints between layers, not inside a single device.
Short answer
A smart grid has five layers: the physical grid, field and metering devices, communications, management systems and distributed resources (generation, storage and flexible demand). Each depends on the one below. In practice, problems rarely start inside a single device: they appear at the joints, where a field data point must reach the control center with the same meaning.
The overall concept comes down to the grid measuring, communicating and acting.
Layer 1: the physical grid
These are the lines, transformers and substations. The smart grid does not replace them: it uses them. What changes is that certain points receive additional devices to measure and switch. A distribution transformer, for example, may have a meter or load monitor; a line may have an indicator that shows whether fault current passed that point.
Layer 2: field devices and metering
These are the devices that measure and act on the grid:
- Reclosers. They open on a fault and reclose on their own; with communications they become remote-controlled. They are explained in recloser: what it is, parts, functions and tests.
- Sectionalizers and remote-controlled switches. They isolate sections of a feeder on command from the operator or an automation scheme.
- Fault passage indicators. They show whether fault current passed a point, which shortens the time to locate the affected section.
- Voltage regulators and capacitor banks with automatic control, which hold voltage along the feeder.
- Advanced meters. They record consumption in more detail and report it over a communication channel.
- Bay controllers, relays and RTUs in substations, which gather signals and commands from the primary equipment.
Layer 3: communications
This is the fabric that ties everything else together. It changes depending on where the device is:
| Segment | Typical media | Purpose |
|---|---|---|
| Inside the substation | Local Ethernet network, with IEC 61850 | Relays, controllers and gateway |
| Substation to control center | Optical fiber or transport network | Remote control, telemetering, teleprotection |
| Devices along the feeder | Radio, cellular networks, fiber where it exists | Reclosers, indicators, switching devices |
The protocols most used toward SCADA are IEC 60870-5-104 and DNP3 (IEEE 1815); between devices in the same substation, IEC 61850 is used. How to choose is explained in IEC 61850 vs IEC 104 vs DNP3 vs Modbus. The limits of radio and cellular links are in radio and cellular links for SCADA, and the network that ties substations together in WAN networks for substations.
With the number of connected devices, this layer is also the one that exposes the grid most to attack. Segmentation and monitoring are covered in OT network segmentation: zones and conduits.
Layer 4: management systems
They receive field data, present it to the operator and, in the most advanced systems, calculate and order actions:
- SCADA. Supervises and controls. It is the foundation; see SCADA vs SAS vs DCS vs HMI.
- Distribution management system. Uses a network model to locate faults, calculate reconfigurations and optimize voltage. NREL describes an ADMS as a platform that supports the full set of distribution management and optimization functions.
- Distributed energy resource management system (DERMS). A software platform that helps the utility operate the grid with the support of distributed energy resources.
- Advanced metering systems. They receive and manage the meter data.
These systems need a common model of the network. The IEC 61970-301 standard defines the Common Information Model (CIM), an abstract model of the objects of an electric utility that makes it easier to integrate applications from different vendors.
Layer 5: distributed resources and customers
These are rooftop solar systems and small plants, battery energy storage systems and loads that can reduce or shift their consumption. For the grid they are both an opportunity and an operating challenge: they provide flexibility, but they also change the direction of power flows and the way feeders are protected. See distributed generation and utility-scale self-generation and protection requirements for distributed generation.
Where the chain breaks
The most common failures in a smart grid are between layers:
- Different point lists between the device controller and SCADA, so a status arrives with a different meaning.
- Links that fail precisely during the fault, when voltage drops or the radio loses power.
- Uncontrolled firmware or settings changes on devices spread across the whole grid.
- Unsynchronized clocks, which make it impossible to order events from different devices.
The defense is point-to-point testing of every signal and every command, from the device to the control center, before going into operation; see point-to-point signal testing.
Where to start reviewing an existing grid
Before buying new equipment, it pays to take an inventory by layer. Ask which field devices already measure and can be operated, and which links exist, with what availability. Review which signals reach SCADA today and with what meaning, and what network model the control center has. Often the biggest gain is in completing what is already there, for example by connecting installed reclosers that were operating standalone.
To go further, see the general picture of the smart grid, AMI architecture: meter, concentrator and head-end system, AMI communications: PLC, RF mesh and cellular and how microgrids operate.
How we help
At Tiza Group we configure field and control devices, define their communications and test the complete chain up to SCADA. If you are integrating equipment from several brands, we start with the signal map and the communications architecture. See SCADA integration and gateways or communications engineering and tell us about your project so we can quote it.
Related guides
- What is a smart grid and how does it work?
- SCADA, ADMS and DERMS: what each one does
- AMI architecture: meter, concentrator and head-end system
- Recloser: what it is, parts, functions and tests
- Distribution automation: reclosers and FLISR
References
- NREL, reports on ADMS and DERMS (docs.nrel.gov/docs/fy19osti/72108.pdf; docs.nrel.gov/docs/fy25osti/92831.pdf).
- IEC 61970-301, Common Information Model (CIM) base (webstore.iec.ch/en/publication/62698).
Frequently asked questions
What are the minimum components of a smart grid?
Field devices that measure and can be operated remotely, a reliable communications link to the control center and a system that receives the data and lets the operator decide. With those three elements you already have visibility and remote control; the rest is added in stages.
What role does the substation play in a smart grid?
It is the node where metering, protection and control for a group of feeders are concentrated. Its control equipment and local network deliver the data to SCADA and receive the commands. That is why the substation is usually the first layer to be modernized.
Why do integrations between layers fail?
Because each layer is usually purchased and configured separately. A status that the field device reports with one meaning reaches SCADA with another, or a control command is executed at a different point than intended. It is avoided with end-to-end, point-to-point testing of every signal and every command.