A growing list of nuclear power plants throughout the world face obsolescence problems with their instrumentation and control (I&C) systems. Plants designed a generation ago Struggle to maintain their original analog or electromechanical I&C systems, if they have experienced technicians. Upgrading with advanced, digital-based controls is the obvious solution, but that’s not always a straightforward exercise for many stations because of the complexity and regulatory oversight.

Today’s critical power generation assets are often stressed to the max with equipment not designed for today’s operating requirements. When the Edison Electric Institute regularly publishes its list of forced outage causes for utility plants, control systems and components invariably top of the list. It’s not surprising when you consider that, for many plants, the controls were installed 20 to 30 years ago. At the same time plants are being asked to add modern performance upgrades and squeeze in new environmental equipment and interface all the plant controls real challenge when each control system speaks a different language.

System mortality
Older mechanical/hydraulic and analog electronic controls do not lend them¬selves to system changes without the addition of expensive hardware. On the other hand, digital controls are inherent¬ly well suited to provide these benefits and future enhancements. The vintage mechanical/hydraulic and electronic con-trols require larger safety margins because of set point drift, ambient effects, as well as slower load and transient response times. Modern digitalcontrols are able to play an ever-increas¬ing role in improving turbine efficiency, because they reliably and accurately operate the turbine closer to optimum running conditions.

The typical experience is that control system failures increase as the systems age and useful life is reached. At that point costs of maintenance and repair will increase. At some point the break¬even point will be reached: The cost of ever-increasing repairs will surpass the cost of retrofitting to modern digital controls. Typically, that crossover point conies approximately 15 to 20 years after initial startup. Many power plants currently have control systems beyond or approaching this expected life span and would be candidates for cost-reduc¬ing upgrades.

The advent of digital controls has brought our focus back to the promise of improving the performance of the complete plant through increased availability, reliability, and safety. Is your plant a can¬didate for a digital controls upgrade? Here’s a short test:

• Have you ever thought the age of your plant wiring, sensor age, or the lack of timely and reasonably priced spares cost more this year than in the past?

• Would the addition of diagnostic, data logging, sequence of events-recorder information before, during, and after startups or a trip help to quickly solve problems and get your plant back on-line?

• Are you concerned about the retire¬ments of experienced instrumentation techs who keep your electromechani¬cal turbine controls functioning?

• Are you concerned that your-older controls are no longer able to maintain calibration, increasing the potential for failures due to recalibration errors?

• Do you need a baseball team-sized crew to start up your plant while your headcount is slowly being reduced?

• Do you have nuisance trips due to single-point failures of control ele¬ments, and does it take weeks to make controls updates and changes?

Navajo upgrade
In the mid 1990s, the Navajo Generating Station (NC!S)initialed a major, six-year plant upgrade project designed to address plant operational, maintenance, and environmental issues (Figure 1). This project included the installation of a state-of-the-art, $430-million dollar sulfur dioxide scrubber system and upgrad¬ing the entire plant to a modern digital control system. Foxboro (now part of Invensys) was selected as the turnkey control system vendor for both retro-fitting existing controls and implement-ing the controls for the new scrubbers, which added more than 6,000 additional I/O points to the system (Figure 2).

Navajo Generating Station

Navajo Generating Station, located on the Navajo Reservation, four and one-half miles southeast of Page, Arizona, is the state’s largest coal-fired electric generating station. The station produces electricity for customers in Arizona, California, and Nevada. This location, adjacent to the Grand Canyon, one of North America’s natural treasures, makes it particularly critical that the station minimize emissions from its three 800-MW coal-fired units. The plant came on-line in 1976. Courtesy: Salt River Project

power plant

2. One is better than many
The original Navajo generating station controls were separate systems—each from a dif¬ferent vendor—for boiler controls, burner management, turbine control, and data acqui¬sition. All these functions, plus controls for the new scrubbers (one for each unit), are performed by the new plantwide digital control system. Courtesy: Salt River Project

According to NGS Plant Manager Robert Talbot, “Our existing controls were obsolete, which was diminishing reliability. Due to the difficulty in obtaining spare parts, the legacy con-trols were also becoming increasingly difficult to maintain. At the same time, the loss of key personnel through retirement—combined with competitive pressures to reduce overall headcounts created some serious staffing problems. We saw the implementation of modern automation technology as a large part of the solution we needed to meet these multiple challenges.”
The original plant control arrangements utilized separate systems each from a different vendor for boiler controls, burner management, turbine control, and data acquisition. All these functions, plus con¬trol for the new scrubbers (one for each unit), are performed by the new plantwide digital control system.

The new system was implemented in phases. The data acquisition system functions were implemented first to enable the process control operators to become familiar with the new digital technology and graphical user interface. The balance of the control system was implemented one year later during an eight week planned outage. This includ¬ed coordinated control, turbine control, automatic turbine startup, burner management, plant logic, and scrubber con¬trol (21,000 points in all). According to Robert Talbot, “The project came together very smoothly with essentially no startup problems.”

The upgrade project; including installation of the scrubbers and the digital control retrofit has provided the desired improvements in emissions reduction, unit performance, system and unit availability, and productivity.

Thanks to the new scrubbers and associated operational improvements, NGS is currently among the cleanest coal-fired plants in the United States. SO2 emissions have been reduced to just 0.003 pounds per million Btus of heat output, and NOx emissions have been reduced to just 0.38 pounds per million Btus.

Competitive edge
According to Bob Swapp, system administrator at NGS, the new digital control system provides the station’s three once-through supercritical units with more precise overall performance. “The units can now make a smoother transition from maximum load to half load, with no step changes, “commented Swapp. “We now have the ability to ramp the units at 75 MW per minute, compared to just 10 15 MW per minute with the old controls. This enables us to respond more
to system load and, as a result, respond better to customer needs, which makes us more competitive.”

Tlbot added, “The old controls had trouble maintaining heat changes, particularly during soot blowing and similar load change operations. The new system does an excellent job of controlling re-heat temperature and actually improved heat rate to about 9,980 Btu/kWh.”

The highly reliable, redundant/fault-tol¬erant hardware design of the new digital control system; the robust, well-proven software; and the ease of obtaining any and all spare parts required, have eliminated the system reliability issues that had plagued the station prior to the control upgrade project. Improved control has also reduced unit trips. During runbacks, the system responds quickly enough to avoid trips and keep the boiler and turbine para¬meters in line.

As previously mentioned, staff attrition due to the retirement of key personnel and other cuts resulted in the need for productivity improvements. The new digital control system has helped enable NGS to operate safely and efficiently with smaller operations and maintenance staffs.

Before the combined scrubber and control upgrade project, 26 operators were required per shift. Today, just 17 operators per shift operate the entire sta¬tion, including the new scrubbers. The scrubbers and generating units are con-trolled from the same control rooms. This represents a 35% overall reduction in operators. Maintenance staffing has been reduced by 36% overall.

To help to further improve operator productivity, in 2002, NGS installed an Esscor high-fidelity simulator for the Foxboro control system. Operator training helps bring new operators up to speed quickly and enables more experienced operators to fine-tune their skills. Moving forward, the control system simulator will also be utilized as a performance-enhancement tool that will allow plant engineers to try out new control strategies in an off-line environment.

OPG upgrades in phases
To be able to meet growing electricity demands while remaining competitive, Ontario Power Generation (OPG) focus¬es on continuously improving energy efficiency, lowering product costs, and ensuring cleaner electricity production throughout its fleet of plants. This focus includes a major revitalization project at its Nanticoke Generating Station in Ontario, Canada (Figure 3).

Nanticoke Generating Station

3. Nanticoke Generating Station
Ontario Power Generation’s Nanticoke Generating Station (NGS), located on the north shore of Lake Erie, has a combined capacity of 3,920 MW from the station’s eight generating units. NGS is one of the largest coal-burning plants in North America. Courtesy: Ontario Power Generation

In 2001, Nanticoke plant management initiated a phased, five year digital control integration and performance improvement project that would help the plant meet the current energy demands of its customers and position it to meet future demands.

“The legacy control systems at Nanticoke were designed and installed in the early 1970s and were no longer supported by the vendor, which was a great concern to us,” said Mike Considine, Nanticoke project leader (now retired). “In addition, the control systems had limited or no expansion capability, we began experiencing deterioration in reliability, and we had limited diagnostics capabilities, which delayed our ability to make necessary repairs. So we knew we had to make significant improvements in our control systems.”

Nanticoke requested proposals from several different control system vendors, with the intent of choosing the vendor that offered hardware maturity, reliability, backward compatibility, and a mature and proven software design. “We selected the Foxboro control system as it had proven technology and hardware and used a UNIX operating system, which we considered very robust for process controls,” said Considine.

Invensys, under a partnership agreement with OPG, is replacing the legacy control systems at the Nanticoke plant with new Foxboro digital control systems on four of the eight units. Invensys is also supplying new operator control interfaces, advanced control packages, engineering, integration, installation, and commissioning services. Nanticoke has four control rooms, each controlling two boilers. The controls on Units 5 and 6 have already been upgraded and, accord¬ing to plant management, the new digital control system is performing up to expectations (Figure 4).

Nanticoke now in digital age

4. Nanticoke now in digital age
Nanticoke’s legacy control systems were designed and installed in the early 1970s and were no longer supported by the vendor, had limited or no expansion capability, and were decreasing in reliability. The new digital control system is expected to increase boiler efficiency and reduce emissions. Courtesy: Ontario Power Generation

When the overall project is complet-ed, the improvements are expected to help increase boiler efficiency and responsiveness, enhance productivity, reduce maintenance and fuel costs, and reduce emissions through the use of advanced controls.

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