Supervisory Control

SUPERVISORY CONTROL & DATA ACQUISITION SYSTEM (SCADA) History In 1993 it was determined that a Supervisory Control & Data Acquisition System (SCADA) system was needed to monitor the campus electrical supply and distribution system. A study was conducted to determine which SCADA system would be most appropriate for Stanford University Power Systems. We reviewed other utilities' SCADA and wall Map systems such as PG&E, Palo Alto, Santa Clara and Berkeley. In addition, we contacted numerous vendors in order to better understand the different technologies available. Most of the packaged systems involved the purchase of a complete SCADA system as opposed to the method of using single meters as the basic component. We were aware that strategically placing these meters both in switch gear at the substations and building switchgear; an effective instant evaluation could be made regarding the status of the electrical power distribution system. In 1994 the Utilities Division started installation of the campus SCADA system using Intelligent Electronic Devices (IEDs) and a DOS based SCADA software package. The Energy Management Control Systems (EMCS) group, which is a department in the Utilities Division, also needs data from building meters. The IEDs provide communications to the SCADA software as well as an analog output signal (proportional to kW) which is read by the building EMCS. The building EMCS (a Rosemont system) records this signal to track electrical energy demand and Kilo Watt Hours (KWH). The SCADA software is a graphical package using a Window NT Operation System. The system, manufactured by Power Measurement Ltd (PML), provides the programming necessary to incorporate actual AutoCAD campus maps and diagrams, and to display real time information on top of the graphic background. Items such as: power system parameters, breakers and switches status, alarms, event logs & historical data logs; can be overlaid on the AutoCAD Single-Line Diagram. Additionally, this system allows the Facilities Operations - High Volt Technicians to view the big picture (a section of campus), and then tunnel down to a detailed view ( a single-line) as needed. SCADA automatically generates alarms and monthly energy reports and is easily expandable as the needs grow. The new system is extremely flexible and is completely expandable as IED meters are added. Benefits Present Benefits The University needs have grown and the demands for reliable and accurate performance and trend data have increased. High Volt Technicians need to be able to remotely and instantaneously, identify electrical power loop feeder sections that are affected, and respond accordingly. As discussed, when a particular section of the distribution system goes down, the operators are provided with instant information. This enables the system operators to provide individual building managers, researchers, department chairs and others, information on the problem. In addition, the engineers are able to examine historical data for load trending, planning and improving system performance. In addition, the following functions are being utilized more and more as the SCADA system is expanded across campus. •

Manual meter reading is being replaced with automatic reporting

•

The Utilities Division can be proactive in providing quality information to its customers.

Long Term Benefits and Future Needs Power System Operators need to be able to continue to remotely and instantaneously, identify electrical power system failures at any location in the distribution system. Accurate real time alarming and historical information is needed to continually meet the needs of a diverse community of energy users. A continuation of the demands for high reliability and accurate performance and trending data is paramount. Stanford has already been experimenting with the web based metering and plans to incorporate, and design custom features with off the shelf web based tools. This will allow users within the university community to access specific information by using a web browser instead of expensive third party software (e.g., energy consumption report, performance data, etc...). Summary It is considered imperative that Stanford University become fully aware of the disposition of the Electrical System at all times in order to serve the academic mission with the least amount of disruptions. Stanford requires accurate real-time alarming and historical information to continually meet the needs of a diverse community of energy users. We need to prevent outages and other power problems proactively. We have acquired a solid communications and highly reliable SCADA system. SCADA System in Action Fault Location Prior to 1993, the method used to determine the magnitude of a campus power failure such as which buildings were affected and what should be first priority to restore power to were determined by a combination of waiting, hoping, guessing, triangulation and luck. A triangulation scenario: A power failure on the campus would usually start with a call being received from Maintenance Customer Service (MCS) or a building manager stating that a building, ( in some cases a number of buildings) had lost its electrical power. Not knowing which branch of the circuit had failed; High-Volt Electricians would wait for a second call identifying another building power outage. Eventually, when a number of buildings without power were identified, by using a simple method of triangulation could be used to determine which area of the distributions system had failed. This would be an elaborate procedure, sometimes taking several hours. High-Volt crews would be dispatched along the route of the distribution (all of which is underground at Stanford) and would selectively remove vault and manhole covers, observing the fault indicators on the distribution cables. In time, the cause of these multiple building power failures were becoming more difficult to locate, consequently, fault location time, and subsequent restoration time could be several hours. With the installation of SCADA technology, the excessive time spent investigating faults and problems is reduce substantially. Outage Record Post incident analysis is required to prevent reoccurrence of similar outages and power failures. Position and Status of Breakers Multiple use of HV switch contacts that are connected to the system, gives the system operators the ability to obtain instant and remote status changes. Amperage on Feeder Cables In addition to the fault location requirement, the High Volt Technicians needed to able to record and evaluate the current use of specific distribution cables. Switching operations required daily reports to enable them to transfer load to other feeders. In the past obtaining this information required sending an electrician to the substation to record the feeder ammeters, a time consuming event. Substation Battery Status Five banks of batteries are installed for breaker control, relay protection and tripping circuits. Loss of the critical function of the battery system can be devastating for a switchgear breaker unit and inability

maintenance personnel who can respond quickly and avert a major problem. Switching and Paralleling Operations Confirmation of the physical change in operator switch position was not available prior to the use of remote SCADA applications. Power Quality As needed, generally after an event, or upon query from building users power users power quality records are requested. Substation Security Fires and Door Alarms Early on in the design of the SCADA application, it was determined that fire/smoke detectors were needed in all substation switch gear rooms. This function, along with door alarm contacts, provides the system operators with the ability to respond instantly to these types of events. Substation Primary Transformer Status Most substation transformer status alarms and events are monitored by the system. The annunciation and display of alarm conditions ensures timely investigation of the problem. Remedial action can prevent future equipment damage and power outages. Emergency Generator & Power Available Status Stanford has an ongoing program to replace the Cogeneration Plant emergency feeders stand-alone generators. Emergency generator breaker running and transfer switch transferred status is imperative to understanding the specific availability of the emergency source. These monitored events provide the added assurance that all systems are working correctly. Breaker Position Status at Building Voltage Level Auxiliary breaker contacts on the main building, 208/480-Volt service boards are connected into the SCADA system. These enable High Volt Technicians to be informed of a single or multiple building area power failure. Hospital and Medical School Emergency Services Status

Gas transmission and distribution (T&D) companies depend on the reliable operation of facilities over a widespread geographic area. The U.S. transmission pipeline alone consists of more than 1.2 million miles of pipeline. To maintain reliability of the T&D system, operators not only require a regular and continuous flow of information as to how these facilities are functioning, but they also must be able to contact certain key facilities to make any operational changes needed to maintain a properly balanced system. These systems are used for controlling facilities, including regulating valves to control the supply from a long-haul transmission pipeline to a local distribution system; starting and stopping compressors along the system; and controlling valves at major customer installations and city gates. To avoid the cost of staffing all of these locations, as well as building and maintaining associated facilities, most organizations rely on automated data gathering and recording systems.

Supervisory Control and Data Acquisition (SCADA) systems are computerbased automated control systems that monitor and control the transport of gas through pipelines. SCADA systems provide two basic functions: real-time monitoring (sensing) and control at remote sites

Reliable operations of SCADA systems depends on proper configuration, cyber security measures, and other factors. Argonne National Laboratory has been investigating and evaluating SCADA systems and has developed various tools, technologies and methodologies for assessing and improving these

Information Assurance and Security: Intrusion Detection | Reverse Engineering | PKI - Public Key Infrastructure VPN - Virtual Private Network | SCADA Systems | Information Assurance Information Sciences Home: About Information Sciences | Internet Technologies | Information Architectures Information Assurance and Security | Systems and Network Engineering | Data Acquisition Systems Independent Verification and Validation | Publications | Related Links | Contacts DIS Home | DIS Site Map | Search DIS | Argonne Home

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is presently in place? How will it change with new equipment? 13. What are your present costs for inspection, maintenance and repair? How can it be changed to be cost-effective? How will it change with a new SCADA or data acquisition system? 14. If changes are made to the present system, will outside vendors (telephone company, satellite links, etc.) service change and what are those changes? (new transmission modes, service charges, etc.)

Future System Needs (Telemetry/Communication Path) 1. 2. 3. 4. 5. 6. 7. 8.

Where will the control center be located? What is the distance you need to span between sites? Will additional sites be added in the future? What obstacles are between the control center and each present and future site, if known? What topology and transmission mode is best suited for your application? What transmission media is available? (May be different for each site.) What are your maintenance/service needs? Will you assign your own maintenance personnel or contract out? How much is in the budget to spend?

(Protocol-Encoding/Decoding) 1. Will the future system use existing protocol? (If new purchase, do not use proprietary protocol! You will reduce your options for integrating future equipment. If possible, use the Modbus protocol.) 2. Is there complete documentation? 3. What existing equipment do you need to connect to? 4. Do you need a multi-vendor software application to communicate with a variety of manufacturer's equipment? 5. Consider the security issues: What type of protection/safeguards will be needed and used to keep out hacking, tampering, sabotage and other unauthorized use. (Master Control Station) 1. Do you need the master station to control local input/output and back up operations? 2. How many sites and stations does your application require? 3. Will the remote station collect data independent from the master station? Purchasing Principles