Harris Nuclear Generating Station is a single unit, 900 MW Westinghouse pressurized water reactor that began commercial operation in 1987. Photo courtesy of Progress Energy.
Like many nuclear power stations in the United States, the process control and instrumentation systems at Progress Energy’s 900 MW Harris nuclear power plant in North Carolina dated from the 1960s and 1970s, when the plant was first constructed. Given their age, system components at Harris—as elsewhere—were beginning to present reliability and maintenance issues to the plant’s operators. Not the least of these issues was the growing difficulty operators had in finding spare parts to repair and maintain increasingly obsolete equipment.
The upgrades that were done over the years at Harris tended to be driven by specific problems rather than by an overarching strategic plan. With time, the control room had a hodgepodge of vendors and systems, few if any of which communicated well with one another.
“Most nuclear plant management has a philosophy of operating plants, not making design changes,” said David Hooten of Progress Energy. He spoke at a recent Honeywell Users Group meeting in Phoenix. One key factor changed that management mindset at Progress Energy: license renewal. As the company’s four nuclear power stations began to move through the license renewal and extension process, it became clear that upgrading control systems and instrumentation would prove important after all.
“When we thought we were going to shut them down there was no reason to upgrade,” Hooten said. “License renewal was the key.”
Progress Energy has more than 4,300 MW of nuclear capacity out of a total of 21,000 MW of generating capacity. The nuclear plants include:
- Harris 1 (New Hill, N.C.), Westinghouse PWR (900 MW)
- Brunswick 1 and 2 (Southport, N.C.), General Electric BWR (1,875 MW)
- Robinson 2 (Hartsville, S.C.), Westinghouse PWR (710 MW)
- Crystal River 3 (Crystal River, Fla.), Babcock & Wilcox PWR (838 MW)
As the plants moved toward upgrading their distributed control systems (DCS), several constraints needed to be addressed. First, the upgrades needed to be done without an increase in budget. Instead, available money had to be spent smarter, Hooten said. Second, each of the plants was to be considered as its own cost center with control over its own budget.
The expense of replacing key information and control infrastructure within each plant, however, left most control system projects noncompetitive from a cost point of view. As a result, a base set of DCS infrastructure projects were paid for at the corporate level. This ensured that all plants received a similar set of basic upgrades. These upgrades included a fault tolerant Ethernet network; redundant Experion server cabinets; two redundant (C200) controller chassis pairs; remote (Series A) I/O chassis; workstation, printer and network time server; and R201 base software.
Once these basic infrastructure improvements were in place, Progress Energy management began to look for a plant-specific control system project to take on. The selection process involved several promising starts as well as disappointing stops, but the Harris plant’s RAB normal ventilation control system finally was chosen.
The project would upgrade controls that previously had relied on a pneumatic system that was obsolete and beginning to require frequent repairs. The existing exhaust fan pneumatics displayed poor component design and posed a complex calibration problem attributable to their inherent tendency to drift. As a result, the system placed a significant burden on plant personnel who had to address frequently recurring problems. This, in turn, degraded system performance and affected daily plant work activities. At least as worrying was excessive radon gas buildup, which, on occasion delayed personnel from leaving the radiation controlled access (RCA) area.
The upgrade project was also seen as posing a relatively low risk, compared with other possible improvement projects from across the Progress Energy fleet of nuclear power plants.
As part of the Harris upgrade project, smart pressure transmitters were installed, profit loop function blocks were used and MCR operator interfaces were retained. This last item avoided emulation vs. virtual stimulation issues, Hooten said. One downside was that the control room interfaces with operations didn’t change, largely because of a conflict with simulator operators over installing an operating station in the control room. The simulator operators said they would have to build a system to translate data into a language native to the simulator. That project was estimated to cost between $500,000 and $1 million.
“We pulled the plug on that project,” Hooten said. As a result, the control room interface was left as is, although the decision resulted in requiring more I/O support.
On the positive side, the DCS development and test system was built in the corporate office. Because it was built to match exactly the system being installed in the plant, hands-on learning was greatly facilitated.
Hooten said a key lesson learned from the Harris project is that the poorly functioning pneumatic control system masked degraded actuators and dampeners. What was more, operating procedures needed to be rewritten once the system actually performed closed-loop control. And, the operators needed training on how to operate the system once the controls worked properly.
“Operators had no idea this could operate to a set point because it never had before,” Hooten said.
From a management perspective, the Harris project was a success and significant milestone. The project offered the industry tangible proof that DCS upgrades are a good thing. It encouraged Harris plant management to move on with the next project, which aims to upgrade the radiation monitoring system. Future projects may include plant vent stack effluent monitoring, ATWS mitigation system actuation circuitry upgrades and main turbine controls. In addition, the operations department wants MCR workstations as a way to solve the simulation issue.