Substation Automation Data Acquisition and Control Functions

Table of Contents

• Sampling, Sensing, and Control: e.g. PT and CT Sampling, Fault indicator sensing, LTC Raise/Lower controls, and Protection Trip Signal
• Protection IED Interactions: e.g. interactions among protection IED to determine whether to trip, and which equipment to trip
• Substation Master System: e.g. Substation system that manages the IEDs within the substation, ranging from simple data concentrators, RTUs, to sophisticated master stations for managing substation automation functions
• DER Management Systems Monitoring and Control of DER Devices: e.g. managing Distributed Energy Resources in a substation or at an industrial customer site
• SCADA Systems within Control Centers for Monitoring and Control of Field Equipment: e.g. Control center SCADA system used to monitor substation data, and issue controls to substation equipment

Overview

Scope: The Data Acquisition and Control (DAC) functions of Substation Automation, used in transmission and distribution operations, comprise multiple types of mechanisms for data retrieval from field equipment and the issuing of control commands to power system equipment in the field, including among field devices, between field devices and systems located in substations, and between field devices and various systems (including, but not limited to, SCADA systems) located in DER and utility control centers and engineering/planning centers.

Objectives: The DAC function provides real-time data, statistical data, and other calculated and informational data from the power system to systems and applications that use the data. The DAC function also supports the issuing of control commands to power system equipment and the setting of parameters in IEDs and other field systems.

Rationale: Power system real-time data is source of most information required for power system operations. Control over the power system equipment can be achieved by issuing control commands and setting parameters.

The Data Acquisition and Control (DAC) function, used in transmission and distribution operations, comprises multiple types of mechanisms for data retrieval and issuing of control commands to power system equipment. These mechanisms are often used in conjunction with each other to provide the full range of DAC interactions. The DAC function, in turn, is used by other functions, such as Supervisory Control and Data Acquisition (SCADA) systems, Energy Management Systems (EMS), Protection Engineering systems, and Advanced Distribution Automation (ADA), as the means for their interactions with the power system equipment.

Substation Environments

The following drawing illustrates the two main IntelliGrid Environments in a Substation, the Environment between a substation and the control center, and the Environment within a control center. Click on each Environment to see a complete description of the Environment, the requirements that define the Environment, and the recommended standards, technologies, and best practices for that Environment.

The following figure shows some of the key information flows of data acquired in substations and other field locations (click on picture to enlarge it).

Sampling, Sensing, and Control of Power System Equipment

Narrative

Sampling and Sensing of Power System Equipment is performed by CTs, PTs, sensors, Intelligent Electronic Devices (IEDs), Remote Terminal Units (RTUs), or other microprocessor-based controllers. Control of Power System Equipment is performed by controllers, IEDs, or RTUs. These control commands are sometimes the result of applications within the IED or controller, and sometimes are passed through from external systems, such as a Substation Master System or a Control Center SCADA system.

The communications links are often very short (a few meters) but can also entail multi-mile links. The communications media typically are copper wires or optical fibers, but can include power line carrier, radio-based media, and possibly other media. Typically, the timing of the sampling, sensing, and control must meet very stringent requirements for rapid response (about 4 milliseconds), high availability, and high security.

They either use internal applications or are instructed by other entities to issue control signals to associated power system equipment. For example:

• Digital CTs sample the current on a substation bus
• Sensors monitor the status of a circuit breaker
• A Protection IED issues a trip signal to a circuit breaker
• Load Tap Changer IED raises and lowers the transformer tap position according to pre-set algorithms, based on voltage levels sensed by Potential Transformers (PTs).
• A circuit breaker IED issues an electro-mechanical or solid-state-based trip signal to a circuit breaker.
• A DER IED controller senses status and measurements of a DER generator and its prime mover, and then issues start and stop signals.

Diagram

Steps for Sampling, Sensing, and Control of Power System Equipment

An IED receives sensor data from a Potential Transformer (PT), or a circuit breaker IED issues a trip signal to a circuit breaker device.

Protection IED Interactions

Narrative

Protection IED Interactions are undertaken to respond to a relatively local situation within a substation or on a feeder that requires the exchange of information among two or more IEDs, specifically to determine whether to issue a trip signal, and which equipment should be tripped.

The communications media are normally point-to-point cables, LANs (in automated substations), and point-to-multi-point radio channels (on feeders). Transmission protection actions require very high speed communication channels, with response timeframes of 1 to 4 milliseconds, while distribution protection actions involving automated switches could tolerate longer response times. For example:

• A protection IED issues a trip command over a Process Bus LAN to a circuit breaker IED within a substation, based on its detection of different power system measurements, such as low frequency, current overload, etc.
• Multiple automated switch IEDs, using point-to-multi-point spread spectrum radio communications media, respond to a fault condition on a feeder segment by opening and closing switches to isolate the fault and restore power to unaffected feeder segments.

Diagram

Steps for Protection IED Interactions

A protection IED issues a trip command over a Deterministic Rapid Response LAN to a circuit breaker IED within a substation, based on its detection of different power system measurements, such as low frequency, current overload, etc.

Substation Master Systems

Narrative

A Substation Master System is a system within a substation that can:

• Acquire data from the substation IEDs
• Pass selected data to a control center
• Receive control commands from the control center
• Issue control commands to IEDs and controllers for them to take action

Substation Master Systems can be relatively simple or can include sophisticated capabilities. They include data concentrators, Remote Terminal Units (RTUs), as well as more sophisticated Substation Control and Data Acquisition Systems. These are generalized systems, as opposed to IEDs or controllers, and usually monitor and/or control more than one power system device. Data concentrators and RTUs just pass data through them, acting primarily as communication nodes, although they may include a local database. Basic Substation Master Systems may include applications to perform some local interactions, or may help coordinate IED actions. Highly capable Substation Master Systems may include applications that can perform closed loop control (e.g. does not interact with the human operator before issuing a control command).

The communications media can be LANs, copper wire, optical cables, microwave radio, leased telephone lines, cellphones, and many other types. Data exchanges range from a few 10’s of milliseconds up to 1 second. Examples include:

• Data concentrator in a substation monitors data from IEDs that are located on feeders connected to the substation. It passes some of this data to a SCADA system and passes control commands from the SCADA to the IEDs. It may collect sequence of events data and some statistical information in a database.
• Substation master coordinates the protection settings of substation IEDs based on requests from the SCADA system for different response patterns. For instance, different protection trigger levels are set for recloser responses if a storm is pending, or if reconfiguration of a feeder impacts the expected fault current level, or if DER generation levels could cause fuses to blow unnecessarily.
• Substation master provides information to automated switch IEDs on a feeder as to the actual configuration of a neighboring feeder. This information will permit the automated switch IEDs to take more appropriate action if a fault occurs.
• Substation master performs advanced substation automation functions, by responding to field conditions reported by IEDs and issuing control commands for volt/var optimization, fault location, isolation, and restoration, multi-feeder reconfiguration, etc.

Diagram

Steps for Substation Master Systems

Substation master systems coordinate the protection settings of substation IEDs based on requests from the SCADA system for different response patterns. For instance, different protection trigger levels are set for zone 3 protection or for recloser responses if a storm is pending, or if reconfiguration of a feeder impacts the expected fault current level, or if DER generation levels could cause fuses to blow unnecessarily.

DER Management Systems Monitoring and Control of DER Devices

Narrative

DER management systems perform monitoring and control of a DER device, either at a customer site or within a substation or from a utility’s distribution control center (see Figure 1‑1). The DER management system could be a DER owner’s SCADA system, a customer’s Building Automation System (BAS), an energy aggregator’s system, or a distribution operations SCADA system. Communications media can include virtually any type, so long as response times of a few seconds can be accommodated. Examples include:

• Loss of power is detected at a customer site. The backup diesel generator starts up, the automatic transfer switch connecting the customer to the utility EPS opens, and the generator is connected to the customer’s local EPS (or just the critical equipment).
• The owner of the DER device decides to reduce his load on the utility EPS by increasing generation. The DER operator implements this decision by setting new parameters in the DER management system. (These are manual actions by persons.) As an automated result, another generator is started by the DER management system, synchronized with the local EPS, and interconnected.
• An energy aggregator sets groups of DER devices to cycle on and off over the next day, taking into account pollution limits, the real-time price of energy, and contractual arrangements with the owners of the DER devices.
• While a DER device is interconnected with the utility EPS, a fault occurs on the feeder. The DER management system ensures that the DER device either trips off or the interconnection circuit breaker opens.
• The DER management system collects sequence-of-events, performance data, and statistical information from DER devices in a substation.

Diagram

Figure DER Management Systems Monitoring and Control of DER Devices

Steps for DER Management System Monitoring and Control of DER Devices

The owner of the DER device decides to reduce his load on the utility EPS by increasing generation. The DER operator implements this decision by setting new parameters in the DER management system. (These are manual actions by persons.) As an automated result, another generator is started by the DER management system, synchronized with the local EPS, and interconnected.

Control Center SCADA Systems Monitoring and Control of Field Equipment and IEDs

Narrative

SCADA systems perform remote monitoring and control of field equipment and IEDs. The term “SCADA” is used here to imply any centralized system which retrieves data from remote sites and may issue control commands when authorized. These SCADA systems are typically located in a utility control center, but may include an engineering “SCADA” system which retrieves protection data or disturbance data, or a maintenance “SCADA” system which monitors the health of both power system and communications equipment.

SCADA system monitoring can use communication channels directly to IEDs, via Remote Terminal Units (RTUs), through a data concentrator, through a substation master, or through a DER management system. The communications media can include virtually any type, so long as response times of 1 second can be accommodated. Although typically seen as used only for real-time distribution operations, the data acquired by the SCADA system can be used by many different systems, applications, and personnel in the control center. This Use Case is limited to the monitoring and control function by SCADA systems; other Use Cases (e.g. ADA Use Case) describe their interactions with the SCADA systems.

SCADA system monitoring and control examples include:

• Power system operations SCADA system receives real-time data from power system equipment via:

–    RTUs

–    IEDs inside substations

–    IEDs along feeders

–    Substation masters

–    DER (or other generation) management systems

–    Other control centers

–    Manual entry

• Power system operations SCADA system issues control commands to power system equipment in real-time via:

–    RTUs

–    IEDs inside substations

–    IEDs along feeders

–    Substation masters

–    DER (or other generation) management systems

–    Other control centers (if authorized)

• Power system operations SCADA system receives metering information
• Data management “SCADA” system receives power equipment configuration data from devices. It may have its own communication channels to the remote sites, or it may acquire this data through the distribution operations SCADA system
• Engineering “SCADA” system receives sequence of events data, oscillographic data (special handling required), historical data, and statistical data. It may have its own communication channels to the remote sites, or it may acquire this data through the distribution operations SCADA system
• Maintenance “SCADA” system receives data related to the health of power system equipment and communications equipment. It may have its own communication channels to the remote sites, or it may acquire this data through the distribution operations SCADA system.
• Planning “SCADA” system receives data that can be used for statistical analysis of power system measurements: maximums, minimums, averages, trends, profiles, power quality metrics, etc, needed for short and long term planning.

Diagram

Steps for Monitoring and Control by SCADA System

Distribution operations SCADA system monitors and controls power system equipment via a multitude of mechanisms.

 Source: EPRI