SCADA System Elements
At a high level, the elements of a distribution automation system can be divided into three main areas:
- SCADA application and server(s)
- DMS applications and server(s)
- Trouble management applications and server(s)
As was stated in the title, the Supervisory Control And Data Acquisition (SCADA) system is the heart of Distribution Management System (DMS) architecture.
A SCADA system should have all of the infrastructure elements to support the multifaceted nature of distribution automation and the higher level applications of a DMS. A Distribution SCADA system’s primary function is in support of distribution operations telemetry, alarming, event recording, and remote control of field equipment.
A modern SCADA system should support the engineering budgeting and planning functions by providing access to power system data without having to have possession of an operational workstation.
The main elements of a SCADA system are:
- Host equipment
- Communication infrastructure (network and serial communications)
- Field devices (in sufficient quantity to support operations and telemetry requirements of a DMS platform)
The essential elements of a distribution SCADA host are:
- Host servers (redundant servers with backup/failover capability).
- Communication front-end nodes (network based).
- Full graphics user interfaces.
- Relational database server (for archival of historical power system values) and data server/Web server (for access to near real time values and events).
The elements and components of the typical distribution automation system are illustrated in Figure 1 above.
Host Computer System
As SCADA has proven its value in operation during inclement weather conditions, service restoration, and daily operations, the dependency on SCADA has created a requirement for highly available and high performance systems. Redundant server hardware operating in a “live” backup/failover mode is required to meet the high availability criteria.
Communication Front-End (CFE) Processors
The current state of host to field device communications still depends heavily on serial communications.
This requirement is filled by the CFE. The CFE can come in several forms based on bus architecture (e.g., VME or PCI) and operating system. Location of the CFE in relation to the SCADA server can vary based on requirement. In some configurations the CFE is located on the LAN with the SCADA server. In other cases, existing communications hubs may dictate that the CFE reside at the communication hub.
The incorporation of the WAN into the architecture requires a more robust CFE application to compensate for less reliable communications (in comparison to LAN).
In general the CFE will include three functional devices:
- A network/CPU board,
- Serial cards, and
- Possibly a time code receiver.
Functionality should include the ability to download configuration and scan tables. The CFE should also support the ability to dead band values (i.e., report only those analog values that have changed by a user-defined amount).
CFE, network, and SCADA servers should be capable of supporting worst-case conditions (i.e., all points changing outside of the dead band limits), which typically occur during severe system disturbances.
Full Graphics User Interface
The current trend in the user interface (UI) is toward a full graphics (FG) user interface. While character graphics consoles are still in use by many utilities today, SCADA vendors are aggressively moving their platforms to a full graphics UI.
Quite often the SCADA vendors have implemented their new full graphics user interface on low-cost NT workstations using third-party applications to emulate the X11 window system.
Full graphic displays provide the ability to display power system data along with the electric distribution facilities in a geographical (or semigeographical) perspective.
The advantage of using a full graphics interface becomes evident (particularly for distribution utilities) as SCADA is deployed beyond the substation fence where feeder diagrams become critical to distribution operations.
Relational Databases, Data Servers, and Web Servers
The traditional SCADA systems were poor providers of data to anyone not connected to the SCADA system by an operational console.
This occurred due to the proprietary nature of the performance (in memory) database and its design optimization for putting scanned data in and pushing display values out. Power system quantities such as: bank and feeder loading (MW, MWH, MQH, and ampere loading), and bus volts provide valuable information to the distribution planning engineer.
Host to Field Communications
Serial communications to field devices can occur over several mediums: copper wire, fiber, radio, and even satellite. Telephone circuits, fiber, and satellites have a relatively high cost. New radio technologies offer good communications value.
The MAS operates in the 900 MHz range and is omnidirectional, providing radio coverage in an area with radius up to 20–25 miles depending on terrain. A single MAS master radio can communicate with many remote sites. Protocol and bandwidth limit the number of remote terminal units that can be communicated with by a master radio. The protocol limit is simply the address range supported by the protocol.
Bandwidth limitations can be offset by the use of efficient protocols, or slowing down the scan rate to include more remote units. Spread-spectrum and point-to-point radio (in combination with MAS) offers an opportunity to address specific communication problems.
At the present time MAS radio is preferred to packet radio (another new radio technology); MAS radio communications tend to be more deterministic providing for smaller timeout values on communication noresponses and controls.
Distribution Automation (DA) field devices are multi-featured installations meeting a broad range of control, operations, planning, and system performance issues for the utility personnel.
Each device provides specific functionality, supports system operations, includes fault detection, captures planning data and records power quality information. These devices are found in the distribution substation and at selected locations along the distribution line. The multi-featured capability of the DA device increases its ability to be integrated into the electric distribution system.
The fault detection feature is the “eyes and ears” for the operating personnel. The fault detection capability becomes increasingly more useful with the penetration of DA devices on the distribution line.
The real-time data collected by the SCADA system is provided to the planning engineers for inclusion in the radial distribution line studies. As the distribution system continues to grow, the utility makes annual investments to improve the electric distribution system to maintain adequate facilities to meet the increasing load requirements.
The use of the real-time data permits the planning engineers to optimize the annual capital expenditures required to meet the growing needs of the electric distribution system.
The power quality information includes capturing harmonic content to the 15th harmonic and recording Percent Total Harmonic Distortion (%THD). This information is used to monitor the performance of the distribution electric system.
Today’s modern RTU is modular in construction with advanced capabilities to support functions that heretofore were not included in the RTU design.
The modular design supports installation configurations ranging from the small point count required for the distribution line pole-mounted units to the very large point count required for large bulk-power substations and power plant switchyard installations.
The modern RTU modules include analog units with 9 points, control units with 4 control pair points, status units with 16 points, and communication units with power supply.
The RTU installation requirements are met by accumulating the necessary number of modern RTU modules to support the analog, control, status, and communication requirements for the site to be automated. Packaging of the minimum point count RTUs is available for the distribution line requirement.
The distributed RTU modules are connected to a data concentrating unit which in turn communicates with the host SCADA computer system.
The modern RTU accepts direct AC inputs from a variety of measurement devices including line-post sensors, current transformers, potential transformers, station service transformers, and transducers. Direct AC inputs with the processing capability in the modern RTU supports fault current detection and harmonic content measurements. The modern RTU has the capability to report the magnitude, direction, and duration of fault current with time tagging of the fault event to 1-millisecond resolution. Monitoring and reporting of harmonic content in the distribution electric circuit are capabilities that are included in the modern RTU.
The digital signal processing capability of the modern RTU supports the necessary calculations to report %THD for each voltage and current measurement at the automated distribution line or substation site.
The modern RTU includes logic capability to support the creation of algorithms to meet specific operating needs.
The logic capability in the modern RTU has been used to create the algorithm to control distribution line switched capacitors for operation on a per phase basis. The capacitors are switched on at zero voltage crossing and switched off at zero current crossing.
The algorithm can be designed to switch the capacitors for various system parameters, such as voltage, reactive load, time, etc. The remote control capability of the modern RTU then allows the system operator to take control of the capacitors to meet system reactive load needs.
The modern RTU has become a dynamic device with increased capabilities. The new logic and input capabilities are being exploited to expand the uses and applications of the modern RTU.
PLCs and IEDs
Programmable Logic Controller (PLC) and Intelligent Electronic Device (IED) are components of the distribution automation system, which meet specific operating and data gathering requirements.
While there is some overlap in capability with the modern RTU, the authors are familiar with the use of PLCs for automatic isolation of the faulted power transformer in a two-bank substation and automatic transfer of load to the unfaulted power transformer to maintain an increased degree of reliability.
The PLC communicates with the modern RTU in the substation to facilitate the remote operation of the substation facility.
IEDs include electronic meters, electronic relays, and controls on specific substation equipment, such as breakers, regulators, LTC on power transformers, etc.
The IEDs also have the capability to support serial communications to a SCADA server. However, the authors’ experience indicates that the IEDs are typically reporting to the modern RTU via an RS-232 interface or via status output contact points.
As its communicating capability improves and achieves equal status with the functionality capability, the IED has the potential to become an equal player in the automation communication environment.
However, in the opinion of the authors, the limited processing capability for supporting the communication requirement, in addition to its functional requirements (i.e., relays, meters, etc.), hampers the widespread use of the IEDs in the distribution automation system.
Resource: Power System Operation and Control – George L. Clark and Simon W. Bowen