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Issue 2 and Volume 3.

 

 

 

 

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Devices serving as data collectors can give operators valuable information about the operating state of process and control valves.

 

 

By Justin Keim, Supervising Engineer, Wolf Creek Nuclear Power Plant and Bill Fitzgerald, Vice President, Emerson Process Management, Nuclear Business Unit for Fisher Control Valves

Wolf Creek Nuclear Power Station is a 1,200 MW unit in Coffey County, Kansas. It is a Westinghouse PWR and has been in operation since 1985. It is the only nuclear power plant in operation in Kansas and supplies enough power for about 800,000 homes in the state. It is affiliated with the Utilities Service Alliance, a consortium of nuclear utilities that share best practices in procurement and operational processes.

The plant has applied for and received a life extension that will keep it in operation through 2045. As part of that plan, the plant is going through a modernization process that will insure it can continue to deliver power in an effective manner throughout its current projected life.

One area being looked at is the use of modern digital instrumentation on its population of control valves. Digital instrumentation came on the scene in the process control industries in the mid 1990s and has been widely adopted outside the nuclear industry. Current estimates have over 5 million of these devices installed around the world. One major advantage associated with this technology is the ability to transmit data to and from field devices such as control valves and transmitters. Because of this, these new devices can serve as data collectors in the field giving the operators valuable information about the operating state of the process and the control valves that are being used to control that process.

This enables the people who operate the plant to transform the way they maintain it. Traditionally, most plants have relied on a preventative maintenance approach. In this approach, personnel analyze each piece of equipment in terms of how likely it is to have a problem based on design and the application it is being used in, and what the consequences might be if it does fail. This analysis is part of a risk-based maintenance program. The results are then used to determine how often the equipment will be maintained. The goal is to insure that the equipment is repaired and brought back to “like new” performance before any significant problems crop up. Although this tends to be a generally effective way to maintain the plants, there still are some pieces of equipment that fail before their scheduled maintenance. And many power plant operators suspect they may be spending money maintaining equipment that is still in good condition.

A better approach is to monitor equipment condition while in service and trend that data so any problems can be dealt with before they become severe. This approach is called predictive maintenance. Before the advent of digital field devices there was no cost-effective means of tracking the condition of components like control valves; hence no need to use a preventative approach. With digital devices, the plants can perform on-line monitoring, track performance and fix components only when they really need it. This can save money and insure that performance is adequate.

As part of this modernization process, the plant decided in 2005 to replace the positioners on its four feedwater regulation valves, some of the most critical valves in the plant. The old analog-style positioners tended to be unreliable and were hard to get parts and support for. They were also fairly slow and unresponsive, making them hard to control and causing problems with controlling steam generator level at the plant. Plant operators selected Fisher FIELDVUE DVC 6000’s, a digital controller capable of two-way transmittal of data as described above.

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Figure 1 Fisher Fieldvue DVC6000 series

The units selected included performance diagnostics and ValveLink software that would enable the operators and technicians to review valve and process performance while the process was on line and the valve in service. Data could be trended over time to look for advance indications of any problems. The units were installed in 2005 and set up for on-line monitoring. Overall process performance improved, as one would expect, because the other advantages these digital devices provided were high-speed response that could be custom tuned, using digital adjustments, to match the process they were controlling. The plant’s operators were happy with the upgrade and the ability to monitor performance on line.

In 2007, plant operators noticed signs of packing failure on several of the valves. As the packing wore out, steam leakage began to occur at the valve stem. The valves were tending to go unstable, because the high packing friction that had been present tended to help dampen the valves’ inherent instability. With the deterioration, packing friction dropped off and the dampening effect on valve stem motion disappeared. Valve instability threatened to bring the plant down as this made it nearly impossible to control steam generator level.

If the plant were to trip, the costs would exceed $1 million a day for a plant this size, so emphasis was placed on finding a repair that would keep the plant online until the next scheduled outage. After study, it was determined that a Furmanite process could be used where a hot, highly fibrous slurry could be pumped into the packing box serving as a temporary replacement for the packing that should last until the next outage.

While this would temporarily solve the packing leakage problem, the plant was still concerned about how to control the valves during the repair process because the friction would be dropping to low levels. Operators also needed to determine when they had pumped enough slurry into the packing box to provide a good seal and to add enough friction to quiet the motion of the valve stem and make the valves stable again.

The plant decided to use the digital positioner’s two-way communication capability to monitor friction levels throughout the process and to make sure a successful repair had been implemented. Because the new digital positioners are fast and stable, they were able to provide solid process control during the repair process while the friction essentially went to zero and was then built back up to several hundred pounds.

The plant used this technique and the repair went well, with no risk of instability. The valve packing area was effectively repaired, eliminating leaks, while packing friction was restored to a level that would still enable the actuator to operate the valve, while reducing the instability associated with normal valve operation.

During the balance of the operating cycle, two more of the four valves had to be repaired using the same techniques. All of the repairs went well and the plant was able to stay online until the next scheduled outage. The diagnostic signature developed during the repair was used as a reference point, so that the valves could be monitored and compared to the base line to insure they were still operating properly up to the point where they were taken offline during the outage.

Overall, this was a successful use of the power of digital instrumentation that saved the utility millions of dollars. Next steps in the process are to work on the valves themselves to solve the inherent instability problem rather than just treating the symptoms. The plant is also looking for other ways to use this technology to save maintenance dollars or increase revenues by keeping the plant online longer between outages. Many nuclear plants are targeting feedwater heater systems for these upgrades as they tend to be unstable as well. Problems with these systems have a direct impact on the overall efficiency of the plant.

 

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