monitoring and measuring i&c performance in nuclear power plants (free chapter download)

vii

List of Figures........................................................................................................................................ix

List of Tables........................................................................................................................................xv

Acknowledgments...........................................................................................................................xvii

Preface.................................................................................................................................................xix

Acronyms.............................................................................................................................................xxi

introduction: nuclear Power Plant instrumentation and Control...................................1

Part One Instrumentation & Control: Pressure & Temperature Measurement1. Development and Application of Instrumentation and Control (I&C) Components in Nuclear Power Plants.................................................................................21

2. Pressure Transmitter Accuracy...............................................................................................49

3. A Practical Review of Methods for Measuring the Dynamic Characteristics of Industrial Pressure Transmitters.......................................................................................61

4. Using the Noise Analysis Technique to Detect Response Time Problems in the Sensing Lines of Nuclear Plant Pressure Transmitters......................................77

5. Nuclear Plant Temperature Instrumentation....................................................................91

6. Accuracy in Temperature Sensor Response Time Estimation for New Nuclear Reactor Designs.......................................................................................111

7. Response Time Testing of Temperature Sensors Using Loop Current Step Response Method.........................................................................................125

8. Regulations and Standards for the Measurement of Performance and Management of Aging of I&C Systems of Nuclear Power Plants...................147

ContentS

00-Frontmatter_final to ISA.indd 7 12/18/2013 2:32:55 PM

viii

Monitoring and Measuring I&C Performance in Nuclear Power Plants

Part Two State-of-the-Art I&C Technologies & Applications 9. The State of the Art in Nuclear Power Plant Instrumentation and Control........159

10. Wireless Sensor Applications in Nuclear Power Plants...............................................181

11. Wireless Sensors for Predictive Maintenance of Rotating Equipment in Research Reactors................................................................................................................193

12. Advanced Cable-Testing Techniques for Nuclear Power Plants..............................219

13. Aging of Electric Cables in Light Water Reactors..........................................................241

Part Three Online Condition Monitoring & Aging Management14. State-of-the-Art Predictive Maintenance Techniques................................................265

15. On-Line Monitoring Applications in Nuclear Power Plants......................................283

16. Applying Online Monitoring for Nuclear Power Plant Instrumentation and Control.................................................................................................................................311

17. Aging Management of Instrumentation and Control Sensors in Nuclear Power Plants..........................................................................................................325

18. Implementation of On-Line Condition Monitoring Technologies in Research Reactors................................................................................................................343

Index.....................................................................................................................................................355

00-Frontmatter_final to ISA.indd 8 12/18/2013 2:32:55 PM

21

1. IntroductionInstrumentation and control (I&C) components monitor and maintain nuclear power plants’ (NPP) process parameters to ensure that they stay within optimum operating ranges conducive to promoting reliable, efficient power production and ensuring the safe control of the plant under normal, transient, and design-base accident conditions. Used in virtually all systems of an NPP, I&C may encompass more than 10,000 devices per plant. Though the cost of I&C equipment comprises only a small fraction of an NPP’s total capital equipment costs, I&C is perhaps the most visible category of equipment in a plant.

I&C technology has evolved more quickly and more dramatically than any other aspect of NPP technology. This pace of change, pressures to improve plant efficiency and maximize safety, and the increasing age of existing NPPs are all forcing the worldwide nuclear power industry to confront the challenges of aging and possible obsolescence in I&C components. New aging management technologies, collectively known as on-line monitoring, enable plants to monitor the condition and aging of their installed I&C while the plant is operating.

2. Instrumentation and control components in nuclear power plantsThe evolution of NPP I&C has been driven by the emergence of new information, measurement, and control technologies; by NPP accidents that have accelerated interest in I&C that maximizes safety and operators’ awareness of plant conditions; and by an industry emphasis on optimizing operating efficiencies in both new and retrofitted plants, including those that have undergone power uprates (PUs). Under these influences, I&C systems have evolved from analog technology for instrumentation and relay-based equipment for control, to discrete or integrated

Chapter 1

Development and application of Instrumentation and Control (I&C) Components in Nuclear power plants

Originally published in Understanding and Mitigating Aging in Nuclear Power Plants: Materials and Operational Aspects of Plant Life Management, Philip G. Tipping, Editor. Cambridge, UK: Woodhead Publishing, 2010.

01-Part 1_final to ISA.indd 21 12/17/2013 9:59:50 AM

22


solid state equipment, for both these functions, to digital equipment for both instrumentation and control today.

The 1980s witnessed the earliest application of digital I&C, which was limited to programmable logic controllers (PLCs) and plant process monitoring computers. In mid-decade, the nuclear industry began to voice concern about the aging and obsolescence of analog I&C equipment, and digital equipment began to emerge as the inevitable future. In the 1990s, equipment and components such as digital relays, smart transmitters, digital recorders, and distributed control systems (DCSs) were being used in NPPs. In 1996, the United Kingdom completed its Sizewell B NPP with a digital plant protection system, and by the first decade of the 2000s, digital I&C equipment was being implemented in NPPs worldwide. The advantages of digital I&C were clear: greater measurement precision, reduced equipment volume and improved reliability, fault tolerance and simplified fault analysis, low signal drift, high data-handling and storage capacities, on-line diagnostics and self-checking capability, and improved human-machine interface.

Due to regulatory and industry concerns about software reliability and common-cause failure (CCF), however, in the United States digital I&C equipment was used mostly in non-safety-related systems such as feedwater, main turbine, and recirculation control. Critics noted that digital equipment in NPPs experienced power supply failures, feedwater control malfunctions caused by excessive traffic on Ethernet networks, software memory leaks that caused digital postaccident monitoring systems to lock up, errors in software verification and validation (V&V), software logic errors, unanticipated system interactions, plant trips caused by configuration changes made while at power, and excessive valve “hunting” (i.e., rapid opening and closing of the valve) caused by digital positioners.

Digital I&C systems’ increasing reliance on Internet or wireless transmissions also potentially pose critical security issues. Nondirected, damaging attacks by software viruses and worms; data network performance degradation from denial-of-service attacks and network spoofing (i.e., using forged IP addresses to conceal sender’s identity); loss of data privacy and confidentiality from eavesdropping and network packet sniffing (i.e., “wire tapping” or listening in on computer networks’ data packets); directed threats involving network packet modification, mimicking, and data tampering; and imprudent use of digital communication in the plant (e.g., to communicate between control, safety, and offsite) all pose security threats not faced by analog plants. A combination of improved encryption; cybersecurity-related standards (including those issued by IEC, IEEE, and ISA); vulnerability analyses; detailed procedures and installations; and intensive training will likely solve many of these potential security concerns. Due to the rapid pace of evolvement and change in digital I&C, obsolescence, rather than aging, is the primary concern.

While next-generation plants’ infrastructures will be digital rather than analog, these new plants will still use sensor technology whose principle of operation has remained largely unchanged for decades. Conventional resistance temperature detectors (RTDs) and thermocouples will still measure primary coolant and core-exit temperatures. Pressure (including differential pressure for measuring level and flow) will still use capacitance cells, bellows, and conventional force-balance sensing technologies to measure pressure, level, and flow in primary and secondary loops.


23

CHAPTER 1 Development and Application of Instrumentation and Control (I&C) Components in Nuclear Power Plants

3. Key instrumentation and control componentsI&C components are categorized in terms of their importance to plant safety: those that play a primary role in maintaining NPP safety (such as instruments involved in reactor shutdown, containment isolation, and emergency core cooling) and those that are only indirectly or secondarily related to plant safety (such as safety-related sensors and transmitters). The former provide automatic protection and exercise automatic control; the latter typically measure temperature, pressure, flow and level in the steam and auxiliary systems and in the containment. Fig. 1.1 shows the typical sensors used in an NPP.

Early I&C systems were designed to fulfill both control during normal operation and protection during upset and accident conditions. Safety concerns and regulatory initiatives stemming from incidents such as Three Mile Island have led to a separate-system approach to I&C design: one independent system for normal operation and one for protection during accidents.

In general terms, I&C consists of the sensors that measure the process; signal conversion and signal conditioning equipment to produce an electrical signal that is proportional to the measured process; the communications media that transmit the measurement; the microprocessors and other integrated circuits that process the signals; and the computers, programmable logic controllers, application-specific integrated circuits, and software that interpret the signals and respond with appropriate control and actuation commands. I&C components thus encompass everything from sensors and transmitters, signal conditioning equipment, and data acquisition modules to small motors and motor control centers and cables, wires,

Fig. 1.1. Example of conventional sensors used in a PWR NPP.


24


transformers, relays and junction boxes. These components may be grouped into four broad categories: nuclear, process, radiation monitoring, and special instrumentation. Nuclear instrumentation includes components for measuring variables such as neutron flux density in the reactor fuel core for the purpose of monitoring power output. Process instrumentation includes sensors, controllers, recorders, indicators, and transmitters for measuring reactor pressure vessel, coolant or pressurizer level, steam flow, coolant temperature and flow, recirculation pump speed, and containment pressure, and for indicating component status. Radiation monitoring instrumentation includes components for monitoring steam lines, gas effluents, and plant sites for any possible radiation emission. Special dedicated instrumentation includes components for meteorology, seismic and vibration monitoring, measuring water conductivity and hydrogen or boric acid concentration, and for monitoring the settling of fundaments and the loss of tension in reinforced concrete armoring.

Notwithstanding this variety, I&C components such as temperature, pressure, level, flow, and neutron flux sensors represent the preponderance of the most important measurement devices used in NPPs today. Furthermore, the principal variables measured by nuclear plant I&C systems are still what they were when NPP I&C technology was first developed from process industry technology in the 1950s and 1960s: temperature, pressure, flow, position, level, and, specifically for the nuclear power industry, neutron flux. Similarly, despite many advances in electronics and computer technologies, NPP measurements are still made largely by conventional sensors, such as thermocouples, RTDs, and pressure and differential pressure sensors. The sensing element, transducer, and signal-conditioning electronics of these sensors have not changed significantly. Since the bulk of these sensors operate in the harshest environments of a NPP, they are particularly susceptible to conditions that promote aging and subsequent performance unreliability or degradation.

3.1 Pressure transmittersPressure, level, and flow transmitters provide most of the important signals for controlling and ensuring the safety of NPPs. For example, accurate flow measurement (such as by ultrasonic and venturi flow meters) can have a significant impact on a plant’s operating margins. On a per-unit basis, the single greatest impact on the accuracy of thermal power calculations, which confirm whether a plant is operating at 100 percent power, are errors in feedwater flow measurement.

Fig. 1.2. Important pressure transmitters in a loop of a PWR plant.


25


A typical four-loop PWR plant uses about 200 to 800 pressure and differential pressure transmitters to measure the process pressure, level, and flow in its primary and secondary systems. Typically, two types of pressure transmitters—motion-balance and force-balance—are used in most NPPs’ safety-related pressure measurements. Depending on their location and service, some of these transmitters must be able to withstand and operate properly in before, during, and after any accident. For this reason, manufacturers type-test representative transmitters and generically qualify them under simulated process conditions in a laboratory. Fig. 1.2 shows important pressure transmitters in a loop of a PWR plant.

So-called smart pressure transmitters are increasingly popular in NPPs because of their ease of calibration and configuration, memory, cost advantage compared to their conventional counterparts, and advanced features such as self-health assessment. Nevertheless, smart pressure sensors use conventional capacitance sensing cells, bellows, and other traditional sensors to measure pressure. The smart components are mostly in the sensor electronics and memory and in the ability to adjust the sensor’s output remotely using digital technology.

3.2 Temperature sensorsMost critical process temperatures in NPPs are measured using RTDs and thermocouples, whose basic principles of operation are more than a century old. In a PWR plant, the primary coolant temperature and feedwater temperature are measured using RTDs, and the temperature of the water that exits the reactor core is measured using core-exit thermocouples (CETs). A typical four-loop PWR plant uses twenty to forty RTDs and fifty core-exit thermocouples. RTDs with nuclear safety-related specifications (mostly used in the primary coolant system) must be very accurate, have good dynamic performance, and pass environmental and seismic testing to demonstrate that they can provide reliable service through a loss-of-coolant accident (LOCA) or seismic event. In each loop of a PWR plant and for each core quadrant, redundant RTDs and CETs are used to minimize the effect of failure of any one RTD or CET, because such failure could seriously affect the operator’s ability to safely and efficiently operate the plant.

3.3 Neutron detectorsNeutron detectors use either ionization or fission chambers to make neutrons detectable and measureable. In addition to measuring the neutron flux so as to monitor reactor power, neutron detectors can also be used to measure the vibrational characteristics of the reactor vessel and its internal components. NPPs typically employ 10–20 gas-filled neutron detectors whose operating principle is decades old. Neutron flux detector types include boron-10, boron trifluoride (BF3), and helium-3 (3H) proportional counters; boron and fission ionization chambers; intrinsic semiconductors; scintillation detectors; and self-powered neutron detectors.

3.4 CablesTypically consisting of conductors (usually copper), insulation (such as poly-vinylchloride), foil or braided shielding and the jacket, cables are a critical component of the NPP I&C system. Instrumentation and power cables that become exposed to or submerged in water, chemicals, or other environments during an accident must continue to function properly so that operators can activate pumps and valves to ensure plant recovery. Cabling is one of the largest cost factors in adding new


26


instrumentation to existing NPP equipment and one of the most difficult to replace. A project sponsored by the Electric Power Research Institute (EPRI) concluded in 2005 that adding cabling to existing nuclear plants can cost up to $6,000 per meter.

4. Aging and instrumentation and control (I&C)The U.S. Nuclear Regulatory Commission (NRC) defines aging as “the cumulative degradation that occurs with the passage of time, which can, if unchecked, lead to loss of function and impairment of safety.” Put another way, aging is the natural degradation of a component’s performance as it is subjected to normal environments and typical operating envelopes.

All I&C equipment are susceptible to aging, but I&C wire systems, including cables, connectors, junction boxes, and penetrations, are among the most susceptible. The effects of aging on I&C sensors, such as pressure, temperature, and neutron flux sensors, are of critical importance because of their impact on plant productivity and safety. The two principal effects are degradation (i.e., changes in the sensor’s response time) and calibration drift (i.e. changes in a sensor’s accuracy). The useful life of I&C components is typically specified by manufacturers based on the expected conditions to which the equipment may be exposed during normal operations. If the equipment is used in a more severe environment, its lifetime may be shortened. The mean operating lifetime of the bulk of plant I&C components (as distinct from peripheral equipment) is probably about twenty years.

4.1 ObsolescenceAging must be distinguished from obsolescence, which refers to the availability or replaceability of a component rather than to its degradation or loss of functionality. Obsolescence begins when a manufacturer ceases to market the component and culminates when the manufacturer no longer provides replacement parts or repair service. Obsolescence has been a significant concern for NPP I&C because the pace of change in I&C technology is rapid, and most nuclear plants have forty- to sixty-year lifetimes. The demand for I&C components and the range of safety-related components are relatively small and qualification costs therefore high, and there are relatively few nuclear-qualified I&C manufacturers. In the United States, because manufacturers are no longer interested in producing analog I&C, the slow migration toward digital I&C has resulted in a diminished inventory of analog equipment. Obsolescence is not as serious an issue for NPP sensors and transmitters because they are still based on conventional sensing technologies that are not becoming outmoded. Nevertheless, most of the electronic pressure, flow, and level sensors used in NPPs today are based on designs from the 1970s and will soon be obsolete. To avoid obsolescence, the nuclear power industry has selected modern designs of these sensors featuring digital electronics, and have had them qualified for use in NPPs.

The remedies for obsolescence include prudent planning, market research, and vendor management; component stockpiling; and extending the life of existing field cabling, sensors, and actuators by, for example, replacing the analog electronics of an important control system with digital electronics.

4.2 Causes of aging The degradation that aging causes to I&C components is a function of the duration, range, and intensity of stressors and associated stresses that the components


27


undergo in the plant. I&C components are subject to both external stressors from the environment surrounding them in the plant—such as temperature, humidity, radiation, electricity, and vibration—and internal stressors, which arise from the operation of the equipment or system itself, such as internal heating, physical stresses, vibration, or wearing of electrical or mechanical parts during operation. External stressors may occur gradually over time or result from instantaneous step changes. Internal stressors can include those resulting from poor initial design or manufacture.

In the nuclear industry’s early years, NPP engineers believed that I&C components were more likely to fail the older they became. Research performed over the past three decades has demonstrated that other failure possibilities exist (see Fig. 1.3): “infant mortality” failure or initial break-in period failure and random failure. Infant mortality—a component’s failure at the beginning of its operational life—is actually the most common form of failure by far. Components that survive and continue operating for long periods (e.g., twenty years) will have a low and only random probability of failure until the end of their useful lives, when wear and fatigue render the component unreliable and its failure rate, in general, statistically unpredictable. This behavior of observed failure rates and data has had profound implications for the effective aging management of NPP I&C.

4.3 Aging of pressure sensorsThe useful life of most NPP pressure transmitters is about twenty years. Typical aging mechanisms for pressure transmitters include thermal, mechanical, or electrical fatigue; wear; corrosion; erosion; embrittlement; diffusion; chemical reaction; cracking or fracture; and surface contamination (see Table 1.1). These degradations may result from exposure to any combination of the following stressors: heat, humidity, vibration, radiation, mechanical shock, thermal shock, temperature cycling, pressure cycling, testing, and electromagnetic interferences.

Degradation of the transmitter’s accuracy and response time (two uncorrelated phenomena) are the two most important consequences of aging. Aging caused by heat and humidity can cause the transmitter sealing materials to fail, allowing moisture to enter the transmitter housing. This can cause calibration shifts and

Fig. 1.3. Bathtub curve showing different failure possibilities.


28


high-frequency noise at the transmitter’s output, which can render the transmitter inoperable or unreliable. Though NPP I&C failure data indicates that calibration drift accounts for anywhere from 59 percent to 77 percent of all age-related failure in pressure transmitters (flow blockage, fatigue, and other factors accounting for the remaining age-related failures), a survey of the nuclear industry in the early 1990s showed that fewer than 10 percent of NPP pressure transmitters actually drift out of tolerance and that in a typical two-year fuel cycle only about 1–3 percent of transmitters suffer calibration failure.

The sensing lines that bring the pressure signals from the process to the transmitter can become partially or totally blocked due to sludge, boron solidification (in PWRs), and other debris in the reactor coolant, causing sluggish dynamic performance in the transmitter. According to NRC data, blockages, voids, and leaks account for nearly 70 percent of the age-related problems in sensing lines. Nevertheless, the effects of aging on response time are even less significant than the effects on calibration. The response times of 84 percent of transmitters tested in a 1994 study written by the author for Nuclear Safety were unaffected by aging. Of the remainder, only 4 percent delivered response times that could be considered failing.

4.4 Aging of temperature sensorsThe normal aging of temperature sensors is caused by long-term exposure to any combination of heat, humidity, vibration, temperature cycling, mechanical shock, or other taxing conditions found in NPP environments. The effect of temperature is the most important because the RTD sensor material has different thermal-expansion coefficients, a fact that causes the element to experience stress whenever the temperature changes. The sensing element’s resistance normally increases under tensile stress and decreases with compression stress. The average life of RTDs used

Table 1.1. Potential effects of aging on performance of NPP pressure transmitters.

Degradation Potential CauseAffected Performance

Calibration Response time

Partial or total loss of fill fluid � Manufacturing flaws � High pressure

√ √

Viscosity change of fill fluid � Radiation and heat √

Wear, friction, and sticking of mechanical linkages (especially in force balance transmitters)

� Pressure fluctuations and surges � Corrosion and oxidation

√

Failure of seals allowing moisture into transmitter electronics

� Embrittlement and cracking of seals due to radiation and heat

√

Leakage of process fluid into cell fluid resulting in temperature changes in sensor, viscosity changes in fill fluid, etc.

� Failure of seals � Manufacturing flaws � Rupture of sensing elements

√ √

Changes in characteristic values of electronic components

� Heat, radiation, humidity � Changes in power supply voltages � Maintenance

√

Changes in spring constants of bellows and diaphragms

� Mechanical fatigue � Pressure cycling

√ √


29


in NPPs is about twenty years. Nuclear-grade RTDs can suffer from calibration drift, response-time degradation, reduced insulation resistance, erratic output, wiring problems, and the like. But just as with pressure transmitters, the sensor calibration and response time are the most important functionalities affected by aging.

Thermocouples are affected by the same stressors as RTDs and in the same ways. Though core-exit thermocouples (CETs) are used mainly for monitoring temperature and are therefore not subject to stringent requirements for accuracy and response time, primary coolant RTDs typically feed the plant’s control and safety systems and must be very accurate and responsive. A one-degree error in an RTD’s measurement of the temperature difference across the reactor core corresponds to either a plus or minus 3.33 percent in power output. Primary coolant RTDs are therefore typically calibrated to an accuracy of 0.3°C or better.

The response time of a temperature sensor depends on installation and process conditions, especially temperature and flow. Aged RTD and thermocouple seals can dry out, shrink, or crack and allow moisture into the sensor, causing a reduction in insulation resistance. The low insulation resistance can result in temperature measurement errors. Moisture in temperature sensors can also cause noise at the sensor’s output, the magnitude of which depends on the temperature and the amount of moisture in the sensor. Table 1.2 shows examples of RTD response- time degradation in NPPs.

In the first twenty years of plant operation, between 10 percent and 20 percent of core-exit thermocouples in PWR plants fail, usually by showing large calibration shifts (e.g., 10–30°C errors at 300°C), erratic and noisy output, or saturated output. NPRDS data for RTD failures from the mid-1970s through1987 showed that about 40 percent of the failures were caused by age-related problems. To place this failure rate in context, plants submitting Nuclear Plant Reliability Data System (NPRDS) reports reported only one RTD failure every two years (1984 to mid-1989).

4.5 Aging of neutron detectorsNeutron detection technology is diverse, and each sensor type is affected by a different aging mechanism. For example, because proportional counter detectors use a gas multiplication factor, they are excessively sensitive to gas quality, so the presence

Table 1.2. Examples of RTD response-time degradation in NPPs.

Response Time (in Seconds)

End of Cycle One End of Cycle Two Change

Thermowell-Mounted RTDs

2.7 3.7 37%

4.0 5.9 48%

2.4 3.3 38%

Direct-Immersion RTDs

1.9 2.5 32%

2.8 3.9 39%

2.0 2.5 25%

Results in table are from LCSR testing performed on RTDs as installed in nuclear power plants under normal operating conditions.


30


of impurities, oxygen traces, or humidity may cause aging-related degradation. Similarly, the central wire in the ionization chambers of boron trifluoride (BF3) flux detectors may be vulnerable to ionic attack, resulting in failure. In fission couples, fission chambers, or self-powered neutron detectors, the degradation of insulation resistance can modify the sensor’s sensitivity. The sensor of each type of flux detector has a normal response curve function, and the aging mechanism typically changes the response curve.

The response time of neutron detectors usually increases with aging. Neutron flux detectors are also prone to cable and connector problems due to the harsh environment (thermal, radiation and other effects) and the low levels of their signals. Finally, the aging sensitivity of neutron detectors will depend on the detector manufacturer. Some recommend their detectors be replaced every five years; some state they can be used for forty years if they are performing properly.

4.6 Aging of cablesCable aging presents fewer problems for NPPs compared to other I&C components. Under normal operating conditions cables will usually outlive the plant. Because of the cost, ubiquity, and complexity of cabling in NPPs, however, until recently research into I&C aging has focused mostly on cables.

High environmental temperature or humidity, cyclic mechanical stress, and exposure to radiation cause aging degradation in cables. When these stressors affect the conductor, the signal transmitted by the cable may become inconsistent. Aging can cause the cable insulation to become brittle and flammable, and age-degraded cable insulation can also affect the sensor signals. If the cables become bare, shunting and short circuits may result. Dirt, lubricants, chemicals, or contaminants are among the other environmental stressors. Internal stressors can include ohmic heating created by electric currents passing through the cable. Since aging-related performance issues in a component’s cables can easily be misattributed to the component’s sensors, aging tests should be run on both cable and sensors when a component’s performance is degraded.

5. Mitigating aging in instrumentation and control (I&C) componentsThe traditional philosophy governing the aging management of I&C components has been that it is conservative, safe, and prudent to overhaul critical equipment from time to time to reduce the likelihood of component failure. In the U.S. nuclear industry, conventional aging management has involved qualitatively checking key I&C components two or three times a day, surveillance testing them every one to three months, and fully calibrating components at every refueling outage and whenever a component is replaced. Conventional aging management methods have several disadvantages. Because they are performed manually, they can only be performed when the plant is shut down or off line. As a result, the plant loses valuable production time, and the effects of environment and process conditions cannot be monitored. Moreover, such invasive maintenance can only be performed occasionally, ruling out the possibility of ongoing process monitoring. Most importantly, traditional invasive aging techniques can actually accelerate component aging. A component that is running properly has a statistically higher likelihood of failing after it has been rebuilt or overhauled than if it is left alone.


31


Before 1975, most nuclear-power-related R&D focused on plant design, improving plant operations, and the aging trends of large plant components such as the reactor pressure vessel. But increasing pressures to reduce maintenance costs and improve plant safety by defining an objective basis for the aging-related testing of I&C components led to analysis of equipment performance histories, industry and plant databases, and aging research programs to determine how I&C components actually age in operation. For example, a review by the author in the 1970s of databases as well as data from representative plants showed that NPP pressure transmitters do not degrade sufficiently to justify full calibrations at every refueling outage. Reliability-centered maintenance (RCM) studies developed by engineers at United Airlines in the 1970s also demonstrated that the correlation between equipment age and failure rate is weak. Indeed, a majority of equipment failures are most likely random. These studies raised serious doubts about the prudence of using a traditional time-based maintenance philosophy—replace or repair a component when it reaches a certain age—to manage I&C aging.

The 1979 accident at Three Mile Island (TMI) raised questions about conventional methods for maintaining and interpreting the signals from I&C. A substantial role in the accident sequence was played by a failed sensor, and control room personnel’s lack of awareness of this failure. The author was called upon to interpret the readings of temperature sensors in the plant’s primary coolant system and to help determine water levels in the reactor vessel and the primary coolant system. TMI’s core-exit thermocouples were indicating erroneous and implausible temperatures, and there was no instrumentation in the plant that could be relied upon to verify the water level in the reactor vessel or determine if the reactor coolant pipes were solid. Only

Table 1.3. Test methods for verifying the performance and monitoring the aging of I&C components.

Component Performance Indicators Test Method

RTD � Calibration accuracy/stability � Response time and self-heating

index � Electrical parameters

� Cross-calibration � LCSR test � Insulation resistance, loop resistance, capacitance � Self-heating measurements

I&C cables / connectors � Cable conductor characteristics � Cable insulation / jacket material

properties

� TDR and LCSR tests � TDR, DC resistance, AC impedance, ductility,

chemical analysis � Inductance (L), capacitance (C), and resistance (R)

measurements or LCR tests

Pressure, level, and flow � Calibration accuracy and stability � Response time

� On-line calibration verification � Noise analysis and PI tests

Pressure impulse line / sensing line

� Blockages, voids, leaks � Calibration accuracy / stability

� Noise analysis � On-line calibration verification, trending, empirical

and physical modelling, neural networks

Neutron detectors � Calibration accuracy / stability � Response time � Cables and connectors � Dynamic descriptors of detector

noise output (mean, variance, skewness, kurtosis)

� Calorimetric calculations and conventional calibrations with a source

� Noise analysis � TDR, DC and AC impedance measurements


32


experts’ interpretation of the existing functioning instrumentation enabled the plant to determine the validity of the signals, diagnose the status of the reactor, and ultimately help bring the plant to a safe shutdown.

The TMI accident helped stimulate new R&D efforts in I&C system design, signal validation, and the role played by human error in understanding and making decisions based on I&C data. Before TMI, NPPs had followed an “event-oriented” philosophy for responding to accidents in which operators first determined the cause of an event before ensuring that safety-critical parameters were not exceeded. After TMI a “symptom-oriented” philosophy emerged, in which procedures were introduced that compelled operators to first ensure that safety-critical parameters were not violated before they determined causes. TMI—and the regulatory guidelines and industry standards it spawned—also hastened the development of methods and policies for more precisely and objectively determining the true aging trends of critical NPP I&C. In the United States for example, the NRC issued in 1996 its “maintenance rule,” requiring all NPPs to track the performance of equipment, including process instrumentation, to identify the onset of failures.

The evolution, application, and integration of noninvasive, continuous I&C monitoring techniques eventually formed the body of aging measurement techniques that comprise on-line monitoring systems for managing I&C aging.

Table 1.4. OLM techniques for mechanical, electrical, and stationary equipment.

Mechanical Equipment Electrical Equipment Stationary Systems

Vibration MCSA on-line Visual inspection

Mechanical ultrasonics MCSA off-line Dye penetration

Infrared thermography Infrared thermography Ultrasonic thickness

Oil Analysis Electrical ultrasonics Eddy current

Mechanical IR Electrical IR Airborne ultrasonics

IR: Insulation resistance MCSA: Motor current signature analysis

Table 1.5. Examples of OLM applications for mechanical, electrical, and stationary equipment in industrial processes.

Mechanical Electrical Stationary

Example of Equipment Type Versus Technology Applications

Vibra

tion

Ultra

soun

d

Infra

red

Oil A

nalys

is

MCA

On-

line

MCA

Off-

line

Infra

red

Ultra

soun

d

Visua

l Insp

ectio

n

Ultra

sonic

Thick

ness

Dye P

enet

rant

Testi

ng

Eddy

Curre

nt

Chillers √ √ √ √ √ √ √ √

Pumps/Motors √ √ √ √ √ √ √ √ √

Compressors √ √ √ √ √ √ √ √

Valves √ √

Evaporators √ √ √


33


6. On-line monitoring (OLM)The term on-line monitoring (OLM) describes methods for evaluating the health and reliability of nuclear plant sensors, processes, and equipment from data acquired while the plant is operating (see Table 1.3). It is based on the principle that I&C components will provide indications of problems before failing. OLM technologies provide plants with the information to evaluate I&C sensors using applications that identify drifting instruments, alert plant personnel of unusual process conditions, predict impending failures of plant equipment, and improve the efficiency of operating nuclear power plants.

On one level, OLM techniques may be categorized according to the type of equipment they are applied to. For example, mechanical equipment such as pumps, valves, motors, and compressors are monitored primarily by vibration monitoring, ultrasonic testing, infrared thermography, and oil analysis. Electrical equipment may be monitored by motor current signature analysis (MCSA), which may be applied while the equipment is installed in an operating process (on-line MCSA) or when the process is shut down (offline MCSA). Infrared thermography and ultrasonics can also be used to monitor the condition of electrical equipment. As for stationary components such as vessels and tanks, visual inspection is an effective way to monitor condition, followed by nondestructive testing (NDT) techniques such as dye penetration, ultrasonic thickness measurements, and eddy current testing. Table 1.4 shows OLM techniques for mechanical, electrical, and stationary I&C equipment, and Table 1.5 shows examples of OLM applications for these equipment types.

A more revealing way of categorizing OLM techniques is by the type of data source that the particular monitoring technique uses (see Fig. 1.4): data from existing sensors, data from test sensors, or data from signals injected into the I&C component. The first category consists of methods that use data from existing process sensors—such as pressure sensors, thermocouples, and RTDs—that measure variables like temperature, pressure, level, and flow. In other words, the output of a pressure sensor in an operating plant can be used not only to indicate the pressure, but also to verify the calibration and response time of the sensor itself and to identify anomalies in the process such as blockages, voids, and leaks that can interfere with

Fig. 1.4. OLM techniques categorized by source of data.


34


accurate measurement of process parameters or disturb the plant’s operation, safety, or reliability. The second category of OLM methods uses data from test sensors (including wireless sensors) such as accelerometers for measuring vibration and acoustic sensors for detecting leaks.

These first two classes of OLM techniques are passive. In contrast, the third category of OLM technology depends on signals that are injected into the equipment to test them. This category includes active measurements such as self-heating index (SHI); the power interrupt (PI) test; insulation resistance tests; and inductance (L), capacitance (C), and resistance (R) measurements, also known as LCR testing. These methods are used to detect defects such as cracks, corrosion, and wear for the aging management of cables, motors, sensors, and other equipment. This third category of OLM techniques also includes the time domain reflectometry (TDR) test and loop current step response (LCSR) method; the latter is routinely used in NPPs for in-situ response-time testing of RTDs and thermocouples.

6.1 OLM methods based on existing sensorsNormally, while the plant is operating, a sensor’s output will have a steady-state value, often referred to as the static component or DC value, that corresponds to the process parameter that the sensor indicates. A small fluctuating signal, known as the signal’s dynamic component or AC signal, is also naturally present on the sensor output, reflecting turbulence, random flux, random heat transfer, vibration, and/or other effects in the process parameter.

Using data acquisition and analysis modules, OLM systems can use both the static (DC) and dynamic (AC) components of output from existing process sensors to gain aging-related information about the I&C sensors (see Table 1.6). The types of applications appropriate for OLM using existing sensors are in large part determined by the sampling rates available for the system’s data acquisition stage. Static or DC OLM applications typically require sampling rates up to 1 Hz, while dynamic or AC OLM applications use data sampled in the 1 kHz range. For example, applications that monitor for gradual changes in the process over the fuel cycle, such as sensor calibration monitoring, make use of the static, DC, or low-frequency component. Applications that monitor fast-changing events, such as core barrel motion or testing

Fig. 1.5. OLM applications versus sampling frequency.


35


Fig. 1.6. OLM applications of static and dynamic data analysis.

Table 1.6. Examples of NPP applications of OLM using signals for existing sensors.

ApplicationSignal Plant Types

DC AC PWR BWR

In Situ Response Time Testing of Process Instrumentation √ √ √

Instrument Calibration Monitoring √ √ √

Cross Correlation Flow Monitoring √ √ √

Online Detection of Venturi Fouling √ √ √

Online Detection of Sensing Line Blockages, Voids, and Leaks √ √ √

Fluid and Gas Leak Detection √ √ √ √

Equipment and Process Condition Monitoring √ √ √ √

Core Barrel Vibration Measurement √ √

On-line Measurement of Temperature Coefficient of Reactivity √ √

Aging Management of Neutron Detectors, CETs, and Other Sensors √ √ √ √

Measurement of Vibration of In-Core Flux Monitors √ √

Core Flow Monitoring √ √ √

N-16 Flow Measurement √ √

Note: Checkmark (√) means that the application shown is based on AC and/or DC signal analysis (as indicated) and that the application is useful in PWRs and/or BWRs (as indicated).


36


sensor response time, use the information in the dynamic, AC, or high-frequency component. OLM applications that use I&C sensors for measuring temperature, pressure, level, flow, and neutron flux up to data sampling frequencies around 1 kHz represent the preponderance of measurement devices in NPPs. Fig. 1.5 illustrates the OLM applications that can be used to monitor NPP I&C versus the range of data-sampling frequency. Fig. 1.6 illustrates how OLM systems use existing data from NPP sensors to satisfy these applications.

Note from Fig. 1.6 that the static, low-frequency data is analyzed using empirical and physical modeling and averaging techniques involving multiple signals, while dynamic, high-frequency data analysis involves time domain and frequency domain analysis using single signals or pairs of signals. For example, the dynamic response time of a nuclear plant pressure transmitter is identified by fast Fourier transform (FFT) of the noise signal. The FFT yields the auto power spectral density (APSD) of the noise data, from which the transmitter response time is calculated. In applications where pairs of signals are used (e.g., core barrel vibration measurements), the cross power spectral density (CPSD) phase and coherence data are calculated to distinguish the vibration characteristics of various constituents of the specific reactor internal involved.

Low-frequency OLM methods using existing sensorsAs noted, DC or low-frequency (1 mHz to 1 Hz) signal analysis is used to identify slowly developing processes in NPP sensors. Two of the most important low-frequency OLM applications using existing NPP sensors are RTD cross-calibration and pressure transmitter calibration monitoring.

The cross-calibration technique exploits the redundancy that is built into each loop of an NPP and into each core quadrant so as to minimize the consequences of failure of any one RTD or CET. Essentially, the cross-calibration technique involves systematically intercomparing redundant temperature sensors to identify any outliers while the sensors are installed in an NPP. Redundant temperature measurements are averaged to produce a best estimate of the true process temperature. The measurements of each individual RTD and CET are then subtracted from the process estimate to produce the cross-calibration results in terms of the deviation of each RTD from the average of all redundant RTDs (less any outliers). If the deviations from the process estimate of an RTD or CET are within acceptable limits, the sensor is considered in calibration. When the plant shuts down, technicians calibrate only those transmitters that have drifted. This approach reduces by 80–90 percent of the effort formerly expended on calibrating I&C sensors. With the new and more advanced plant computers used in current OLM systems, RTD and CET measurements can be collected in the plant computer, which provides a centralized location for monitoring and storing the measurements.

OLM systems can also use this technique of averaging the output of redundant sensors to monitor the calibration of NPP pressure transmitters. The averaged value, or process estimate, is then used as a reference to determine the deviation or drift of each sensor from the average of the redundant sensors and identify the outliers. If the transmitter drift is insignificant, no calibration is performed for as long as eight years typically (based on a two-year operating cycle and a redundancy level of four transmitters). In this application, OLM is not a substitute for traditional calibration of pressure transmitters; rather, it is a means for determining when to schedule a traditional calibration. At most plants, the plant computer contains all the data required to verify the calibration of pressure transmitters, including data from plant


37


startup and shutdown periods. In the 2000s, the author and his colleagues developed a calibration reduction system for NPP pressure, level, and flow transmitters that uses data from the plant computer to identify drift in a sensor output and thereby segregate sensors that are drifting from those that are not. This information is then used to identify which transmitters must be calibrated.

Analytical modeling for nonredundant sensorsFor plants with nonredundant pressure sensors, a reference value obviously cannot be determined by averaging. Therefore, the process estimate for calibration monitoring is determined by analytical modeling of the process. Both empirical and physical modeling techniques are used in this application, although empirical models are preferable because they can be adapted to various processes and different operational envelopes.

Equipment condition assessment In addition to evaluating the aging characteristics of individual existing sensors in an NPP, as in RTD cross-calibration and transmitter calibration monitoring, static or low-frequency OLM methods may be used for so-called equipment condition assessment (ECA) applications. These methods take the OLM idea a step further by monitoring for abnormal behavior in a group of sensors so as to identify nuclear plant equipment or system malfunctions, as in a PWR’s chemical and volume control system (CVCS) (see Fig. 1.7). The CVCS controls the volume of primary coolant in the reactor control system (RCS), controls the chemistry and boron concentration in the RCS; and supplies seal water to the reactor coolant pumps (RCPs). During normal operation, the measurements of these parameters will fluctuate slightly, but they should remain at a consistent relative level. However, in abnormal conditions, such as an RCP seal leak, some parameters may exhibit upward or downward trends, indicating a problem in the plant. ECAs provide early warning of abnormalities in related parameters occurring close in time, abnormalities that are likely to indicate the onset of a system or equipment problem.

Fig. 1.7. Simplified diagram of chemical and volume control system components.


38


High-frequency OLM methods using existing sensorsThe applications for dynamic, AC, or high-frequency (1 Hz to 1 kHz) OLM methods for existing NPP sensors include monitoring the dynamic response of pressure, level, and flow transmitters using the noise analysis technique; monitoring reactor internals; detecting core flow anomalies; and extending the life of neutron detectors.

Noise analysisThe noise analysis technique is based on monitoring the noise or AC signal in frequency domain (using FFT) or in time domain (using autoregressive modeling) to obtain the response time of the pressure transmitters. The abnormal state of the system is discovered either by a shift of these parameters into nonpermitted regions, or by the appearance of a changed structure of the noise signatures, usually frequency spectra, indicating an anomaly. The technique’s advantage is that it measures process variables under operation without disturbing the sensor or shutting down the process—in contrast to conventional invasive I&C aging management techniques. Fig. 1.8 shows actual noise data from a pressure transmitter in an NPP. This is just a 50-second portion of a data record that is one hour long. The spectrum of the one-hour data is also shown in Fig. 1.8.

In the late 1970s the author and his colleagues determined through validation testing that the noise analysis technique had the potential to provide an in situ means for measuring the response time of RTDs and thermocouples as installed in operating processes. In subsequent years the author has led efforts that validated the noise analysis technique for other NPP I&C variables, such as reactivity coefficients, vibration amplitudes, and others for temperature, pressure, and neutron flux sensors.

Detecting sensing-line blockages Chief among applications of the noise analysis method in NPP aging management is detecting sensing-line blockages. Using existing sensor-based OLM techniques, one

Fig. 1.8. Actual noise data from a pressure transmitter in an NPP and spectrum of one-hour record of this data.


39


can identify the sensing lines that must be purged and cleared rather than having to purge all of them. This technique makes it possible to detect blockages while the plant is on line using the normal output of pressure transmitters at the end of the sensing line. Fig. 1.9 shows an application of this method. Two PSDs are shown in

Fig. 1.9. Effect of sensing-line blockage on dynamic performance of a pressure transmitter.

Fig. 1.10. Auto power spectral density containing vibration signatures of reactor internals.


40


the lower right-hand plot, one for a partially blocked sensing line and the other for the same sensing line after it was purged of the blockage. These PSDs are taken from an analysis of actual noise data from a nuclear plant pressure transmitter. Observing the break frequency, it is clear that the blockage reduced the dynamic response of the sensor by an order of magnitude.

Monitoring reactor internals Fig. 1.10 shows the APSD of the neutron signal from an external-core (“ex-core”) neutron detector (NI-42) in a PWR plant. This APSD contains the vibration signatures (i.e., amplitude and frequency) of the reactor components, including the reactor pressure vessel, core barrel, fuel assemblies, thermal shield, etc. These signatures can be trended to identify the onset of aging degradation, which can damage reactor internals. For example, in the mid-2000s, the cause of a rod stepping problem in a PWR plant in the United States was identified using signals from existing ex-core neutron detectors. In this plant, neutron signals are used in the rod control system. Due to neutron flux spikes, the reactor regulation system would move the control rods in and out of the plant. The first step in resolving the problem was to measure the neutron noise and verify that the neutron flux spikes were not caused by any abnormal vibration of reactor internals. Once the vibration of the reactor internals was confirmed to be normal and no significant flow anomalies were discovered, the plant was notified that this problem did not threaten the safety of the plant and could be resolved by raising the setpoint that triggers the rods to move or by placing a low-pass electronic filter at the output of neutron detectors to dampen the spikes.

Detecting core flow anomaliesIn a typical PWR plant, fifty thermocouples are located on the top of the core to monitor the reactor coolant’s temperature at the exit of the core. They can also be used in conjunction with the ex-core neutron detectors to monitor flow through the reactor system. By cross-correlating signals from the ex-core neutron detectors and CETs, it is possible to identify the time required for the reactor coolant to travel between the physical location of the neutron detectors and the thermocouple. The result, referred to as transit time, can be used with core geometric data to evaluate the reactor coolant’s flow through the system, identify flow anomalies, detect flow blockages, and perform a variety of other aging-related diagnostics.

Measurement Benefits Pitfalls

PressureFlowAcoustic emissionBlast wavesStrainsTemperatureDisplacementAccelerationRadiation dose

Small sizeLight weightEMI/RFI immunityFatigue resistantHigh sensitivityFast responseCorrosion resistanceIntrinsic safetyEmbeddableMultiplexing

Tight alignment tolerancesVulnerable to thermal and pressure cycling, shock, and vibrationDifficult/expensive to easily configure to existing electronic hardware systemsCabling often has strict minimum bend radius criteria (~15 cm)Radiation darkening and embrittlement

Table 1.7. Examples of process measurements that can be made with fiber-optic sensors and the typical benefits and pitfalls of these sensors.


41


Extending the life of neutron detectorsCable testing and static and/or dynamic performance monitoring are useful for verifying that neutron detectors are in good working condition. For static performance monitoring, data available in the plant computer may be used to look for drift and anomalies, that is, low-frequency output from the detectors. The dynamic response of neutron detectors can be monitored using the noise analysis technique. In addition to trending response times, the noise output of neutron detectors can be examined for signs of other problems in the nuclear instrumentation circuit, such as cable and connector anomalies, which may indicate aging.

Sensor Status Key Attributes Shortcomings

Conventional sensors (RTDs, thermocouples, and pressure, level and flow transmitters)

Old technology, but still the best available for process measurements. No new sensors that can easily replace them are currently on the market.

Mature technology, long history of use in nuclear power plants.

Some of these conventional sensors suffer from long-standing and often inherent problems such as drift.

Smart sensors Fully developed, qualified, and used in nuclear power plants even for safety-related applications.

Easier to calibrate and maintain. Contain self-diagnostic capabilities, memory, and digital equipment attributes.

Little operating experience in nuclear power plants.

Fiber-optic sensors Fully developed for industrial applications; not yet qualified for use in nuclear power plants.

High bandwidth, no drift.Easy to install.

Radiation darkening of fiber-optic material, expensive.

Wireless sensors Commercially available and some are used in nuclear power plants for equipment condition monitoring. Not expected to serve in process measurements in the foreseeable future.

No wires needed, low cost, and easy to install.

Cyber security, battery life, EMI/RFI issues.

Next-generation sensors R&D continuing; some are almost ready for implementation in nuclear power plants.

Incorporate latest technologies to potentially increase accuracy, redundancy, and add capabilities compatible with “Gen IV” reactors.

Most are in their infancy and none are commercially available.

Ultrasonic flow sensors (not new, but newly popular)

Fully developed and used in nuclear power plants in a number of applications, especially to measure feedwater flow.

Accuracy is better than conventional flow sensors (e.g., venturi), and they have been approved for up to about 2% power up-rating.

Expensive (nearly $2 million per installation). Reliability of ultrasonic flow sensors has recently come into question in a few plants.

Note: Micro-electro-mechanical sensors (MEMS) are not included as they are not yet evaluated for process measurements in nuclear power plants.

Table 1.8. The state of the art in sensors for NPPs.


42


6.2 OLM methods based on test sensorsThe second category of OLM techniques is, like the first, passive. However, rather than relying on existing sensors for its data, they use data from test or diagnostic sensors to determine I&C aging. Typical examples of test sensors are accelerometers for measuring vibration and acoustic sensors for detecting leaks. For example, acoustic sensors installed downstream of valves can establish whether the valves are operating as expected: if a valve is completely open or completely closed, there is normally no detectable acoustic signal above the background noise.

When existing process sensors are not available to provide the necessary data, wireless sensors can be deployed. For example, wireless sensors can be implemented in such a way as to combine vibration, acoustic, and other data with environmental information such as humidity and ambient temperature to yield a comprehensive assessment of the condition of the process’s equipment and health. Wireless sensors can facilitate difficult measurements in industrial plant processes where wiring is a weak link, such as flame and high furnace temperature measurements. Wireless sensors also facilitate measurement in hazardous environments and in applications where space for wiring installation is limited. Wireless sensors can also be the answer to the threat posed by rust, corrosion, steam, dirt, dust, and water to wires in industrial facilities. With wireless sensors, data can be collected from anywhere and routed on to the Internet where they can be easily accessed and analyzed. Whereas wiring costs in an industrial process can be as high as $6,000 per meter, if wireless equipment were used, wiring costs would fall to $60 per meter. Wireless sensors

Fig. 1.11. Principle of LCSR test.


43


promise to enhance NPP productivity, lower plants’ own energy requirements and material costs, and increase I&C equipment availability.

6.3 OLM methods based on active measurementsThe first two OLM categories are mostly passive, do not involve disturbing the equipment being tested, and can be performed in most cases while the plant is operating. The third category of OLM methods depends on active measurements from test signals: injecting a signal into the equipment to measure their performance and aging characteristics. For example, the loop current step response (LCSR) test can remotely measure the response time of temperature sensors while the plant is on line by sending an electrical signal to the sensor in the form of a step charge (see Fig. 1.11).

In the LCSR test, a step change signal in current is sent to the RTD sensing element, which causes the sensor to heat internally. The test is performed by connecting the RTD to a Wheatstone resistance bridge. The bridge includes a switch that allows the electrical current through the RTD to be switched from 1 or 2 mA to 30 to 50 mA for the test. This internal heating causes a transient increase in the RTD resistance that manifests itself as an exponential transit at the Wheatstone bridge’s output. This transient is recorded and analyzed to identify the RTD’s response time. Because it takes into account the effects both of installation and process conditions on response time, the LCSR method represents a significant step beyond traditional age-testing techniques for thermocouples.

During the late 1970s, the author developed prototype equipment including hardware, software, and procedures for testing RTDs in NPPs using the LCSR method and validated the technique under operating conditions in a PWR. Since then, the method has been used successfully in other applications, such as for determining the quality of bonding between sensors and solids, verifying that sensors are properly installed in thermowells, testing for thermocouple inhomogeneity, and identifying cable and connector problems or moisture in temperature sensors.

Active measurement or test signal-based predictive maintenance methods also include the time domain reflectometry (TDR) test. It is used to locate problems along a cable, in a connector, or at an end device by sending a test signal through the conductors in the cable and measuring its reflection. The TDR technique has also served the nuclear power industry in testing instrumentation circuits, motors, heater coils, and a variety of other components. In a TDR test, a step signal is sent through the cable, and its reflection is plotted versus time. The plot will show any changes in impedance along the cable, including at the end of the cable. If the TDR is trended, problems that may develop along the cable or at the end device can be identified and located. The simplest application of TDR is locating an open circuit along a cable. It is possible to tell whether the circuit is open by measuring its loop resistance, but only a TDR would indicate where the circuit is open. A complementary set of cable tests, LCR testing, is often used in addition to TDR to identify whether a circuit problem is caused by an open circuit, short circuit, shunt, moisture intrusion, or other age-related problems (see Fig. 1.12).

The combination of TDR, LCR, and LCSR tests has proved very effective in separating age-related cable problems from sensor problems in RTDs, thermocouples, and strain gauges. As for other nuclear plant sensors such as neutron detectors, the combination of TDR, LCR and the noise analysis technique are used to verify the integrity of the cables and performance of the end device, in this case, the neutron detector.


44


7. On-line monitoring methods and aging managementSince on-line monitoring (OLM) methods are passive, nonintrusive, and in situ (the instrument is not removed from the process), they can be used to monitor aging-related degradation and anomalies as they occur, they take into account installation and process condition effects on the monitored I&C, and they avoid unnecessary maintenance to I&C that are showing no aging issues. Moreover, both the AC and DC data acquisition and signal processing monitoring techniques can be integrated into the same OLM system, and such systems can be used in multiple reactor types, including PWRs, BWRs, and WWERs. With the expanding use of fast data acquisition technologies, advanced data processing algorithms and software packages, and

Fig. 1.12. Potential outcomes of TDR tests.


45


wireless transmission capabilities, OLM is making continuous and periodic aging management of NPP I&C routine and efficient.

French-designed reactors in France, China, and elsewhere have been using OLM-related techniques for nearly twenty years with successful results. The use of OLM methods for applications such as calibration monitoring of pressure, level, and flow transmitters has been formally approved by the U.S. and British regulatory authorities. The Sizewell B plant in England anticipates savings of $58 million per operating cycle when OLM technologies are fully implemented versus a total implementation cost of about $5 million. The International Atomic Energy Agency (IAEA) has been active over the past five years in promoting the use of OLM technologies in NPPs. As its Nuclear Power Plant Control and Instrumentation technical working group declared in 2004: “in dealing with I&C aging and obsolescence, one has to consider how to proceed in addressing this question, not only from a plant operational and safety standpoint, but also in the context of plant economy in terms of the cost of electricity production, and including initial and recurring capital costs. For this important reason, consideration of new technologies, such as on-line monitoring and in situ testing methods is recommended. These can be used not only to predict the consequences of aging, and guard against it, but also to verify equipment performance throughout the lifetime of the plant, and help establish replacement schedules for I&C equipment, and predict residual life.”

8. Future trendsThough NPP sensor technologies will probably not change significantly in the short term, the pace of change in nonsensor I&C will continue to be driven by increasing bandwidth and computer speed. The availability of process sensor data in the plant computer will increase, sampling frequency and resolution data acquisition capabilities will continue to grow, critical process sensors will be installed with greater redundancy, and I&C infrastructure will become increasingly flexible to accommodate future data acquisition needs.

8.1 Sensor trendsShort-term advances in terms of I&C sensors and transmitters will center on fiber-optic and wireless sensors. Fiber-optic pressure sensors offer excellent stability, high accuracy, and very low maintenance requirements as well as immunity from the effects of high temperature, high electromagnetic interference, and high corrosion. However, work remains to be done on their ability to withstand nuclear radiation (neutron and gamma). Table 1.7 shows the measurements that can typically be made with fiber-optic sensors as well as these sensors’ benefits and pitfalls. Table 1.8 summarizes the key characteristics of conventional and smart sensors as well as fiber-optic, wireless, and next-generation sensors.

Future NPPs will have further and enhanced I&C capability. Extensive instrumentation requires transmission capacity; wireless sensors will provide that capacity. Though wireless sensors are currently limited mostly to vibration monitoring, longer term they will be implemented to combine vibration, acoustic, and other data with environmental information such as humidity and ambient temperature to yield a comprehensive assessment of the condition of the process’s equipment and fitness-for-service. Cyber security concerns, limited battery life, and malicious interference issues are among the main obstacles to the use of wireless


46


sensors in NPPs for any critical applications. Using a software “bridge” program it will be possible for integrated OLM systems to read data from wireless I&C sensors from different manufacturers, bringing all of a plant’s wireless data together in one place in one format so it can be analyzed and compared.

Longer-term advances in sensors will include the essentially drift-free “Johnson Noise Thermometer,” which consists of an RTD whose open-circuit voltage is measured and related to temperature to measure absolute temperature; solid-state neutron flux monitors; magnetic flowmeters; silicon carbide (SiC) neutron flux monitors; and hydrogen sensors, among others.

In general, the capacity to do more signal processing are increasingly shifting toward the I&C sensor itself. The benefits of this trend are the location of more capable instrumentation in the reactor core, greater opportunities for signal validation and data cross-comparison, more sophisticated data analysis arising from more and better processed signal data, and more responsive, timely, and appropriate maintenance. One consequence of this trend is greater use of bus technology rather than individual sensor cables.

Fig. 1.13. Integrated OLM system.


47


8.2 I&C system trendsThe nuclear industry will continue its transition from the traditional time-directed, hands-on, and reactive maintenance procedures to condition-based, risk-informed, and automated maintenance strategies. Integrating OLM techniques with the latest sensor technologies (e.g., wireless) will enable plants to avoid unnecessary equipment replacement, save costs, and improve process safety, availability, and efficiency. In twenty to thirty years most NPPs will have an integrated OLM system (Fig. 1.13) that takes age-related data from all three data sources—process sensors, test sensors, and active measurement test signals—performs the necessary analysis, and provides results in terms of equipment performance, process health, and equipment diagnostics and prognostics.

New analytical tools such as neural networks, artificial intelligence, and pattern recognition on PC-based test equipment will analyze the data and interpret the results to identify even small changes in the performance of equipment and alert operating personnel of significant age-related problems or incipient failure.

Sources of further information1. Sensor Performance and Reliability by H. M. Hashemian (Research Triangle Park, NC: ISA—International Automation Society,

2005). Describes several instrumentation testing, diagnostics, and analysis techniques (such as in-situ methods for sensor response time testing and calibration and on-line measurements to identify blockages and voids in pressure sensing lines) to verify the reliability, health, and performance of process instrumentation. Describes how to objectively assess the accuracy, response time, residual life and other characteristics of installed instrumentation and offers a practical means to identify the problems, assess their consequences, and help resolve some of the problems.

2. Maintenance of Process Instrumentation in Nuclear Power Plants by H. M. Hashemian (Berlin: Springer-Verlag, 2006). This book compiles thirty years of practical knowledge gained by the author and his staff in testing the I&C systems of nuclear power plants around the world. It focuses on process temperature and pressure sensors such as RTDs, thermocouples, and conventional pressure and differential pressure sensors and the verification of these sensors’ calibration and response time.

3. Management of Life Cycle and Aging at Nuclear Power Plants: Improved I&C Maintenance TECDOC-1402 (Vienna: International Atomic Energy Agency, 2004). Provides information on aging, obsolescence, and performance monitoring of safety and safety-related I&C equipment including I&C wire systems, sensors and transmitters, process to sensor interfaces, and analog and digital electronics.

4. Nuclear Power Plants—Instrumentation and Control Systems Important to Safety: Management of Ageing, IEC 62342 (Geneva: International Electrotechnical Commission, 2007). The principal international standard governing the management of aging in NPP I&C systems.

5. Modern Instrumentation and Control for Nuclear Power Plants (Vienna: International Atomic Energy Agency, 1999). Summarizes the field of NPP I&C. Divided into five parts: requirements, constraint and recent issues; design concepts; recent developments in instrumentation and control; Instrumentation and control in a new nuclear power plant; and examples of current instrumentation and control systems.

ReferencesElectric Power Research institute (2006). Plant application of on-line monitoring for calibration interval

extension of safety-related instruments: Volume 1, Palo Alto, CA, EPRI; Suffolk, UK, British Energy Group PLC.

Hashemian, H.M. (March 1993). Long term performance and aging characteristics of nuclear plant pressure transmitters, NUREG/CR-5851, Washington, D.C., U.S. NRC.

Hashemian, H.M. (1994). “Effects of normal aging on calibration and response time of nuclear plant resistance temperature detectors and pressure sensors,” Nuclear Safety Technical Progress Journal, 35:2, 223–234.

Hashemian, H.M. (November 1995). On-line testing of calibration of process instrumentation channels in nuclear power plants, NUREG/CR-6343, Washington D.C., U.S. NRC.


Hashemian, H.M. (2005). Sensor performance and reliability, Research Triangle Park, NC: ISA.

Hashemian, H.M. (2006). Maintenance of process instrumentation in nuclear power plants,” Berlin, Springer-Verlag.

Hashemian, H.M. (April 2007). “Targeting calibration,” Nuclear Engineering International, 16–19.

Hashemian, H.M., Black, C.L., and Farmer J.L. (April 1995). Assessment of Fiber Optic Pressure Sensors, NUREG/CR-6312, Washington, D.C., U.S. NRC.

Hines, J.W., Seibert, R., and Arndt, S.A. (January 2006). Technical review of on-line monitoring techniques for performance assessment, Volume 1: State-of-the-Art. NUREG/CR-6895, Washington, D.C., U.S. NRC.

International Atomic Energy Agency (1999). Modern instrumentation and control for nuclear power plants, Vienna, IAEA.

International Atomic Energy Agency (June 2000). Management of ageing of I&C equipment in nuclear power plants, TECDOC-1147, Vienna, IAEA.

International Atomic Energy Agency (2004). Management of Life Cycle and Ageing at Nuclear Power Plants: Improved I&C Maintenance, TECDOC-1402, Vienna, IAEA.

International Atomic Energy Agency (September 2008). On-line monitoring for improving performance of nuclear power plants part 1: Instrumentation channel monitoring, IAEA Nuclear Energy Series No. NP-T-1.1, Vienna, IAEA.

International Atomic Energy Agency (September 2008). On-line monitoring for improving performance of nuclear power plants part 2: Process and component condition monitoring and diagnostics, IAEA Nuclear Energy Series No. NP-T-1.2, Vienna, IAEA.

International Electrotechnical Commission (2007). Nuclear power plants—instrumentation and control systems important to safety: management of ageing, IEC 62342, Geneva, IEC.

Korsah, K., Wood, R.T., Freer, E., and Antonescu C. (November 2006). “Emerging sensor and I&C technologies for nuclear power plants,” paper presented at the American Nuclear Society Topical Meeting on Nuclear Power Plant Instrumentation and Control and Human Machine Interface Technologies, Albuquerque, New Mexico.

Liu H., Miller D.W., and Talnagi F. (September 2004). “Fabry-Perot fiber optic sensors for ex-core in-containment applications,” paper presented at the 4th International Topical Meeting on Nuclear Plant Instrumentation, Control and Human Machine Interface Technology, Columbus, Ohio.

Oak Ridge National Laboratory (2003). Emerging technologies in instrumentation and control, NUREG/CR-6812, ORNL/UM-2003/22, Washington, D.C., U.S. NRC.

U.S. Nuclear Regulatory Commission (July 2000). Application of on-line performance monitoring to extend calibration intervals of instrument channel calibrations required by the technical specifications: Safety evaluation report, Washington, DC, U.S. NRC.

Zavaljevski, N. and Gross K.C. (2000). “Sensor fault detection in nuclear power plants using multivariate state estimation technique and support vector machines,” Paper presented at Third International Conference of the Yugoslav Nuclear Society (YUNSC), Belgrade, Yugoslavia.


monitoring and measuring i&c performance in nuclear power plants (free chapter download)

Technology

instrumentation control

control ic components

ic performance

ic technology

management of aging

introduction instrumentation

efficient power production

cost of ic equipment