Before the implementation of distribution automation, Alabama Power Co.'s distribution system was operated manually under the direction of the distribution operator, who was located in the Distribution Operating office. While the distribution substations remained the responsibility of distribution operating personnel, the distribution operator, who did not have access to the transmission supervisory control and data acquisition (SCADA) terminal, had to call the Transmission Control Center to request remote control operations. During the mid-1980s, two distribution SCADA (DSCADA) pilots were installed and evaluated. These installations demonstrated the benefits of distribution substation automation, multiple address sys tem (MAS), radio communications and the use of DSCADA in the distribution operating offices.

During the summer of 1989, the distribution automation (DA) team was formed and charged with developing the plan to automate the distribution system, which was intended to provide automation for substations and line devices. The Automation 2000 goal was defined to include all substations with a low-side voltage of 12 kV to 34.5 kV throughout Alabama Power's service system using a system-level solution to support the 44,500 sq mile (115,255 sq km) area.

The DA Team The structure of the DA team represents the multi-faceted nature of the project. Each element of the organization chart represents a team that is focused on activities that are consistent with its experience and expertise. The hub-and-spoke nature of the organization chart illustrates the close coordination among the various parts of the DA team, which was organized using existing resources within Alabama Power Co. and the Southern Co.

The hardware, software and firmware development for the DSCADA host computers and field remote terminal units (RTU) is managed by the Real Time Systems-West department. This team is responsible for the DSCADA system engineering and administration, the development and implementation of the SES 92 protocol and the development of the DA system advanced applications. The SCADA operations center (SOC) within Real Time Systems-West provides a single point of contact for the DA system user to report any problems or maintenance requirements. The DSCADA Client Workstation Team is initially comprised of personnel who are familiar with the use of the workstation in the operation of the transmission SCADA system. The client workstation group has evolved into a DA/DSCADA client and display team with responsibility for guiding the development of the full graphics displays. Southern Company Services is providing the total communication support for the DA system. Information Resources-Telecommunications Field Services is responsible for the deployment of the MAS radio communications. The Network Operations Center is responsible for the network communications facilities that support the statewide deployment of the DA technology. Currently, the DA system communications run on the corporate network with all other corporate applications. Information Resources also supports the software and interface development for connections to other corporate applications that include AM/FM and trouble analysis. All system procurement requirements are managed by Material Services to ensure on-time delivery. The Power Delivery department manages the development of the installation specifications for the substation and distribution line applications. This team is responsible for maintaining consistent specifications within Southern Co. as well as developing new automation applications for integration into the DA system. Technical Services is responsible for maintenance of all substation and distribution line RTUs and coordinates the installation of new facilities, working with the SOC in performing the SCADA Operations Test (SOT). The SOT is the final check out of a DA installation to ensure that the DA site is ready for service. The Division/District Operations User Team represents all of the users of the DA technology, reviewing DA technology and applications development to ensure that the operational needs are met. The Project Management Team is responsible for the general oversight of the DA project, maintaining the budget, developing the deployment schedule and planning for future project requirements.

DA Technology Installation The installation of DA technology began in May 1991 with the deployment of 59 MAS master radios, 28 RTUs in distribution substations, 208 RTUs on distribution lines, six single DSCADA host systems and 14 DA clients. The initial host DSCADA systems were installed on VAX/VMS architecture. Cegelec ESCA Corp.'s DSCADA 2000, the SCADA subset of its EMP software, is implemented in the DSCADA host computers. The DSCADA client workstations are curr ently running the character graphics display software. This initial installation was completed in six months before Christmas of 1991. The system has grown to include more than 820 RTUs, nearly 100 MAS master radios and 75 DA clients. In 1995-96, the DSCADA hosts were upgraded to a dual host configuration on Alpha architecture with Open VMS operating system and backup/failover capability. The upgrade effort included the consolidation of the three northern hosts and three southern hosts into two host sites with the communications front ends (CFE) remotely deployed throughout the service territory. The corporate WAN communications network supports the remote deployment of the CFE and the communications between the host computers and the DA clients in the distribution operations centers (DOC), resulting in improved efficiencies for the system support staff. In 1998, the transition of the DSCADA client work-station to the full graphics display software will be started; completion is planned in 1999. The DA technology and MAS communications have also been used to automate 250 transmission line switches. The integration of the DA technology and the EMS 2000 system using the Power System Information eXchange (PSIX) software makes the views of the automated facilities seamless to the distribution and transmission operators. Through 1997, the percentage of automated distribution substations had increased to 63.3%.

DA Substation and Line RTUs The present DA system RTU incorporates modular design, which supports interchangeability between RTU applications. To illustrate its flexibility, The RTU is being used in distribution substations, distribution line devices, standby generator installations, network underground systems, transmission line switches and transmission substations. The DAQ Electronics' Callisto line of RTUs is being used for the current DA system RTU deployment requirements. The DA system uses the SES92 protocol for communications with field devices. This SES92 protocol, developed in-house for use at Alabama Power and throughout Southern Co., has been placed in the public domain as a non-proprietary protocol. In addition to the typical monitoring and control capabilities, the RTUs support direct ac inputs from distribution line sensors and substation current and potential transformers. The RTUs calculate and report the full range of power system values, such as energy, demand and power factor. The RTUs are capable of reporting harmonics up to the 15th harmonic with total harmonic distortion (THD) being captured and reported on a real-time basis. The RTU contains logic software to support site specific operational applications; an example being the development of an automatic transfer scheme that uses the RTU logic software and two automated distribution line switches. Intelligent electronic device (IED) interfaces for the RTU have been developed. The RTU communicates with the Schlumberger Quantum meter and the Schweitzer relay. The modular design of the RTU supports the traditional RTU installation and a distributed RTU installation in the substation.

DA Toolbox Distribution line monitoring was the initial application developed to support the deployment of the DA technology throughout the service area. The DA Toolbox concept, an outgrowth of this deployment, contains the automated systems that are made available to the distribution engineer to meet the requirements of the distribution system. In addition to line monitoring capability, the toolbox has been expanded to include automated pole-mounted reclosers, automated motor-operated switches, automated pad-mounted transfer switches and automated network protectors. An in-house solution has been developed to integrate the RTU and pole-mounted recloser. The Cleaveland Price motor-operator and the S&C SCADAMate incorporate the DAQ RTU to provide automated sectionalizing for these circuits. The RTU has been integrated into pad-mounted switchgear and network installations to expand the DA technology to underground systems. Development is under way for the switched capacitor bank controller using the pole-mounted RTU and its logic capability.

DA Operational Features The DA system supports the deployment of traditional SCADA functionality with analog and status information being recovered on a real-time basis to support operational needs in the DOC. Status values are scanned every 6 seconds and analog values are scanned every 12 seconds. The DOC operator has the capability to control the state of the distribution feeder breaker in the substation, the pole-mounted recloser, the motor-operated switches and the pad-mounted transfer switches. Also provided is the ability to remotely remove the reclosing capability and the ground relay on the substation breaker as well as the pole-mounted recloser.

The hot-line tagging feature is probably the most frequently used functionality in the system. The substation breakers and the pole-mounted reclosers have been equipped with the capability to apply a remote hot-line tag. Alabama Power Co. uses energized line construction techniques for distribution voltages through 34.5 kV, which removes the reclosing capability while the work is under way. The remote application of the hot-line tag permits the DOC operator to proceed with the issuance of the hot-line work permit without having to dispatch field personnel to the automated source breaker or recloser. The remote hot-line tag also ensures that the reclosing capability is promptly returned to the breaker or recloser at the conclusion of the energized line work, allowing these pieces of equipment to be returned to normal operation as quickly as possible to ensure system reliability.

DA Database Server Data retrieval capability of the DA system is making substantial improvement in the planning process with the DA Database Server sampling the system every 15 minutes and recording the data in a relational database for use by the planning engineers. The data are made available to the engineers using standard desktop PC tools and are used to validate load flow calculations. Some planning studies are being performed on a per phase basis, illustrating the dynamic nature of the distribution system and the ability of the DA monitoring to document these system dynamics. System event logs are being distributed as ASCII text files for trouble analysis and to monitor breaker operations for increased activity. The data are being used to improve system analysis during emergencies and response to system disturbances with each line application, as well as each substation, being a potential source of distribution planning data. Using the information collected from the database server, planning engineers can optimize capital expenditures for system improvements.

Multi-dimensional DA Device The typical DA device is multi-dimensional with multiple uses. Its main function is the automation of a substation or distribution line. With the installation of the DA functionality, the device becomes an operational tool by providing monitoring and control capability. The DA device is also a planning tool when the monitoring capability is integrated into the planning process. Finally, the device is a power quality tool. The multi-dimensional characteristics of the device make it a critical component in the distribution system with its ability to support multiple areas of system responsibility.

DA Addresses System Needs Distribution automation addresses several system requirements, contributing directly to improved reliability with its remote control features facilitating the normal operation of the system. The ability to reconfigure the system is enhanced with the addition of each DA device, facilitating the prompt identification of system disturbances, providing remote switching options to the operator and improving service restoration. Its ability to accomplish service restoration was exemplified during the Christmas shopping season in 1996 at the Quintard Mall in Anniston, Alabama when a truck took down a pole in the circuit serving the mall interrupting services. Within 2 minutes, the Eastern Division DOC rerouted the service, isolating the faulted portion of the distribution system. Service to the mall was rerouted using automated distribution line switches and DA technology.

Larry Clark is principal engineer-power delivery for Alabama Power Co. in Birmingham and also manages the Distribution Automation Project. He earned the BSEE degree from the University of South Alabama and has been with the company for 30 years. He previously was responsible for operations and maintenance of the distribution system. He is a senior member of IEEE and is a registered professional engineer in Alabama.