Advances in distributed intelligence also have helped to encourage greater use of SCADA over large geographical areas. “Critical tasks such as high-speed counting and PID (proportional integral derivative) control can be distributed at the I/O (input/output) level,” says Arun Sinha, director of business development at Opto 22, a Temecula, Calif., automation supplier. “These are time-critical tasks that would otherwise have to happen back at the control room.”
These benefits attracted the attention of McMinnville Water & Light, the small utility serving the 25,000 people living in and around McMinnville, Ore. The company’s old SCADA system was not monitoring its grid and evaluating the effects of corrective actions on power quality in real time. The dial-up data modems and leased phone lines that it was using to communicate with its six substations were too slow in transmitting crucial information between the PLCs and the operations staff. The system, moreover, was capturing only a portion of the pulses from meters used for calculating bills.
To improve the system’s response and reliability, the company installed a Snap Ethernet I/O control system from Opto 22 and strung a fiber-optic line to link the substations with the main office. “With our extended wide-area network, we can look at just about every field device connected to it without our having to leave our desks,” says Jon Spence, the technician at McMinnville who does all of the SCADA programming.
Technicians can now use real-time data to perform substation switching and see the effects immediately. With the old SCADA system, they had to wait as long as 24 hours until the system took its daily poll of the controllers to get the load and phase data. “And if a superintendent were to close a breaker, it could take as long as two minutes before he saw any change,” says Spence. “Now it takes a few seconds.”
Another reason for the success of SCADA over large areas has been the adoption of high-speed wireless communications. Greater bandwidth and better communications protocols have made it more practical. In fact, several water companies are running radio networks off their towers and setting up peer-to-peer radio networks to collect data, reports Steve Garbrecht, director of product marketing at Wonderware, a Lake Forest, Calif.-based automation software supplier and a unit of Invensys Systems Inc.
Satellites are also part of today’s mix of wireless communications. “Bandwidth is now available at a reasonable cost for locations that were not economically viable before,” notes George Quesada, product manager for oil and gas SCADA at automation vendor ABB Inc., in Calgary, Alberta.
SCADA by satellite
In fact, communicating by satellite is an important part of SCADA at Oil and Natural Gas Corp. (ONGC), based in Delhi, India. There, ABB’s SCADAvantage runs on almost 300 servers and covers all of India, possibly making the SCADA installation the largest in the oil and gas industry.
ONGS made the investment because gathering consolidated field data on production had been taking weeks or months. To make matters worse, the data contained inconsistencies, and the costs to obtain it were rising. It was necessary to find a way to streamline the data flow and to deliver information in real time. Real-time data is an important management tool today for reaching business objectives, says A.K. Balyan, Ph.D., director of infocom services.
To cover the territory, it was necessary to distribute the system in three tiers. The first is the more than 270 field installations handling the daily operations of onshore sites and offshore platforms. The second tier is the 13 regional centers that optimize activities, and the third is the central office in Delhi. The software replicates both the data and configuration information in real time and automatically recovers from any interruption in communications. Consequently, Balyan reports that there is no loss of data.
The Puerto Rico Aqueduct and Sewage Authority (PRASA) also transmits data by satellite, adding this mode of communication to its mix of media. The island’s rugged, mountainous terrain renders radio communications impractical to impossible in many regions. “So we use satellite cell phone technology instead,” explains Tony Matias, director of both PRASA’s western region and the company’s Integrated Preventive Maintenance Program.
Another complication is the complexity of Puerto Rico’s water system. Not only does the 5,300-employee company serve 1.2 million customers, but it also must manage 1,500 sites spread over the 100-by-25-mile island. For various reasons in the past, the water filtration plants were not located at altitudes that would permit distributing the water by gravity alone. Consequently, a network of 249 pumping stations pump most of the clean water coming from the 124 filtration plants to 227 reservoirs. About 600 pumping stations return sewage to 60 treatment plants.
Because of the terrain, corrective maintenance was a slow, manual process before SCADA. Whenever a pumping station would develop a problem, it would often take three to four days to discover it and to reestablish normal service. The automatic monitoring permitted by the SCADA has changed all of that. “A problem that used to take 72 hours to resolve now takes only five to six hours,” says Matias.
The system’s control hierarchy has three autonomous levels, each of which can work independently of the others if it loses its communications link temporarily. The various pumping stations and reservoir tanks associated with a plant report operating data to the plant’s control center, which passes it to one of the five regional centers. Each regional center relays information to headquarters in Hato Rey.
SCADA is the backbone of a five-year, $2.5 billion capital improvement program that was negotiated with the U.S. Environmental Protection Agency and the Department of Justice. Part of the deal was the development of a preventive maintenance program. “If we hadn’t selected SCADA software, we would have been forced to hire approximately 600 to 700 more employees just to monitor and collect the necessary information,” says Matias.
So far, PRASA has connected 212 sites to the SCADA monitoring system and expects to have all 1,500 sites connected by 2010. Matias is also developing the system further at the water plant in Maricao to do remote control. His goal is to tighten control with fewer people.
Strength through software
A strength of Wonderware’s platform is that it is component-object based. In other words, users can generate one template for monitoring and controlling a kind of asset, such as a pumping station, and use it wherever similar monitoring functions are needed. “If you want to change or add a parameter to a pump, you modify the template and deploy it to all of the running applications across the entire SCADA network simultaneously,” says Garbrecht.
Other flexible SCADA software exists, as PEMEX Exploration and Production (PEP) discovered when this agency of the Mexican government went looking for a way to tighten the coordination of its southern operations. It found LabView, a graphical programming language from National Instruments Corp. (NI), of Austin, Texas. This language not only comes with configuration-based SCADA tools, but also offers users the flexibility to develop links to PLCs and other industrial devices.
“A conventional SCADA package is configuration based, and a programming language is bolted onto it by way of scripts,” says Arun Veeramani, NI’s product manager for LabView. “If you have any customization, you invoke a script.” He claims that programmability of LabView removes the traditional boundaries between hardware such as programmable automation controllers and the SCADA application.
Removing these boundaries was important to PEP because the company had grown by acquisition and its various units contained a large number of disparate transmitters, PLCs, and other devices. Although the devices measured key data electronically in the field, the automation for collecting and distributing them was local. Coordination between the different management teams and their computer systems occurred manually by phone and e-mail.
This manual intervention allowed slight, but expensive errors to creep into the data. The southern region produces 1.52 million barrels of crude oil a day, which is 43 percent of Mexico’s total production. Because this volume is worth about $3 billion, measurement errors as low as 1 percent can translate easily into millions of dollars. “We needed an integrated and low-cost monitoring system that would enhance coordination between these teams and take advantage of existing measurement systems,” says Martin Fernandez Corzo, automation specialist at PEP.
As a first step, PEP engineers linked the 12 key remote workstations collecting information from the measurement devices, programming each to run an OPC (an open connectivity standard) server appropriate for the connected devices. “We developed a LabView DSC (for Datalogging and Supervisory Control) application for each of the stations that display the variables’ real-time values and historical trends,” explains Corzo. “These data are then connected to PEP’s intranet, so the variables can be published on the network through the LabView DSC Tag Engine.” The central station sorts through 3,000 tags to monitor all operating variables reported by the local stations.
Not only does the integration of these 12 stations allow management to make decisions more quickly, but it also improves the accuracy of the communications between the different supply and distribution centers. For this reason, management is considering how it might add more stations to the monitoring network, and make its world a much smaller and more profitable place.
