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Home       > Electronic Reading       Room       > Document       Collections       > General       Communications       > Information       Notices       > 2001       > IN 2001-09

UNITED STATESNUCLEAR REGULATORY COMMISSIONOFFICE OF NUCLEAR REACTOR REGULATIONWASHINGTON, D.C. 20555-0001

June 12, 2001
NRC INFORMATION NOTICE 2001-09: MAIN FEEDWATER SYSTEM DEGRADATION IN SAFETY-RELATED ASME CODE CLASS 2 PIPING INSIDE THE CONTAINMENT OF A PRESSURIZED WATER REACTOR - Addressees 
- Purpose 
- Description   of Circumstances 
- Background 
- Discussion 
Addressees
All holders of operating licenses for pressurized water nuclear power reactors except those who have ceased operations and have certified that fuel has been permanently removed from the reactor vessel.
Purpose
The U.S. Nuclear Regulatory Commission (NRC) is issuing this information notice (IN) to alert addressees to the discovery of main feedwater (MFW) system wall thinning to below allowable limits in turbine building components and in risk-important, safety-related portions of American Society of Mechanical Engineers (ASME) Code Class 2 piping inside the reactor containment building (containment) at the Callaway Plant.

It is expected that recipients will review the information for applicability to their facilities and consider actions, as appropriate. However, suggestions contained in this IN are not NRC requirements; therefore, no specific actions or written response is required.
Description of Circumstances
During a refueling outage that began on April 7, 2001, the Callaway Plant licensee conducted scheduled inspections to assess the effects of erosion/corrosion on steel piping exposed to flowing water (single-phase fluids) and water-steam mixtures (two-phase fluids). These effects are commonly referred to as flow-accelerated corrosion (FAC). Inspections identified several instances of localized MFW system piping wall thinning to below the minimum thickness required by ASME Boiler and Pressure Vessel Code, Section III, for safety-related piping, and to below the minimum thickness specified by American National Standards Institute (ANSI) B31.1, "Power Piping," for non-safety-related portions of the MFW system. The wall thicknesses in the degraded areas had not been previously measured.

The licensee had expanded and upgraded its FAC program following an August 11, 1999, event in which an 8-inch moisture separator reheater drain line experienced a double-ended guillotine break causing operators to manually trip the reactor. The upgraded and expanded FAC program, utilizing CHECWORKS� Rev. F software, predicted wall thinning in the MFW system. However, without wall thickness trending data, the software was not able to accurately predict the extent of degradation. After performing an inspection during the current outage, the licensee found the MFW degradation to be more extensive than anticipated.

Based on the licensee's initial findings and on additional industry information, FAC inspections were expanded to include portions of the condensate system, auxiliary feedwater (AFW) system, feedwater heaters, and other areas. Additional degradation was found in piping for the feedwater heaters.

Several instances of MFW system wall thinning were identified in risk-important sections of 14-inch ASME Code Class 2 safety-related piping components inside the containment. The licensee identified six 90-degree elbows, two 45-degree elbows, one 14-to-16-inch expander, and a 6-foot section of piping that had degraded to less than the ASME minimum design allowable wall thickness (below allowance) or that the licensee projected would degrade below allowance during the following cycle. The as-found wall thicknesses for components degraded below allowance ranged from 75 to 96 percent of the minimum allowable thickness required by the code. These components were identified in common MFW/auxiliary feedwater (AFW) flow paths to three of the unit's four steam generators (SGs). All safety-related components in the containment that were below allowance (or that the licensee predicted would degrade below allowance during the following cycle) were replaced. Some degraded non-safety-related components outside the containment were repaired rather than replaced.
Background
Since 1982, the NRC has issued numerous generic communications addressing various issues and events related to pipe wall thinning. Several of those communications are particularly relevant to the recently identified MFW wall-thinning at Callaway Plant. They are summarized below and annotated in Table 1, "Summary of Related Previous Generic Communications." Table 2 is a brief chronology of previously identified pipe wall thinning issues and events.

IN 87-36, "Significant Unexpected Erosion of Feedwater Lines," August 4, 1987, addressed the 1987 discovery of MFW degradation at the Trojan Nuclear Plant similar to that observed at Callaway Plant. The thinning was discovered when Trojan's steam piping inspection program was expanded to include single-phase piping. It was attributed to high fluid flow velocities and other operating factors.

IN 88-17, "Summary of Responses to NRC Bulletin 87-01, 'Thinning of Pipe Walls in Nuclear Power Plants'," April 22, 1988, summarized licensee responses to and NRC observations on the thinning of nuclear power plant pipe walls. The IN noted that all licensees reported having established programs for inspecting pipe wall thinning for two-phase, high-energy carbon steel piping systems. Inspection locations were generally reported to have been selected in accordance the 1985 guidelines in Electric Power Research Institute (EPRI) Document NP-3944, "Erosion/Corrosion in Nuclear Plant Steam Piping: Causes and Inspection Program Guidelines." However, because implementation of these guidelines was not required, the scope of the programs varied significantly from plant to plant.

Generic Letter 89-08, "Erosion/Corrosion-Induced Pipe Wall Thinning," May 2, 1989, requested licensees to implement long-term erosion/corrosion monitoring programs to provide assurance that procedures or administrative controls were in place to maintain the structural integrity of all carbon steel systems carrying high-energy fluids. EPRI released the pipe wall thinning predictive computer code CHEC� in June 1987, CHECMATE� in April 1989, and CHECWORKS� in August 1994, to assist licensees in selecting for testing those areas of the piping systems with the highest probabilities of wall thinning. The Massachusetts Institute of Technology method described in NUREG/CR-5007, "Prediction and Mitigation of Erosion-Corrosive Wear in Secondary Piping Systems of Nuclear Power Plants," September 1987, also ranked systems and components according to their erosion/corrosion susceptibility.

IN 93-21, "Summary of NRC Staff Observations Compiled During Engineering Audits or Inspections of Licensee Erosion/Corrosion Programs," March 25, 1993, addressed NRC observations on the industry's design and implementation of erosion/corrosion programs in response to Generic Letter 89-08. Among other observations, the IN identified instances of erosion/corrosion in safety-related portions of MFW and main steam systems and described the problems licensees were having in implementing effective FAC programs. In November 1993, EPRI released document NSALC-202L, "Recommendations for an Effective Flow-Accelerated Corrosion Program." Rev. 2 of the document was released in April 1999.
Discussion
Although the MFW degradation was identified and addressed by the licensee before catastrophic failure, the extent of the degradation at the time of discovery is of concern to the NRC, given the maturity of the industry's FAC programs. Of particular concern is the degradation in risk-important non-isolable sections of single-phase ASME Code Class 2 piping inside the containment. These factors can impact the safety significance of pipe wall thinning.

MFW systems, like other power conversion systems, are important to the safe operation of nuclear power plants. Past failures of feedwater and other high-energy system components have resulted in complex challenges to operating staff when the released high-energy steam and water interacted with other systems, such as electrical distribution, fire protection, and security systems. Personnel injuries and fatalities have also occurred. The failure to maintain high energy piping and components within allowable thickness values can (1) increase the initiating event frequency for transients with loss of the power conversion system, main steam line breaks, and other initiating events due to system interactions with high-energy steam and water; (2) adversely affect the operability, availability, reliability, or function of systems required for safe shutdown and accident mitigation; and/or (3) impact the integrity of fission product barriers.

This IN requires no specific action or written response. If you have any questions about the information in this notice, please contact one of the technical contacts listed below or the appropriate Office of Nuclear Reactor Regulation (NRR) project manager.
/RA/       
Ledyard B. Marsh, ChiefEvents Assessment, Generic Communications       and Non-Power Reactors BranchDivision of Regulatory Improvement       ProgramsOffice of Nuclear Reactor Regulation
Technical contacts:Ross Telson, NRR301-415-1175E-mail: rdt@nrc.govKrzysztof Parczewski, NRR301-415-2705E-mail:       kip@nrc.govWilliam D. Johnson, R-IV 817-860-8148 E-mail: wdj@nrc.govDavid Terao, NRR 301-415-3317 E-mail: dxt@nrc.gov
Attachments:

1. Table 1: Summary of Related Previous Generic Communications2. Table 2: Summary of Previously Identified Pipe Wall Thinning Issues and Events3. List of Recently Issued NRC Information Notices

(ADAMS Accession Number ML011490408)

ATTACHMENT 1

IN 2001-09
Table 1: Summary of Related Previous Generic Communications
The titles of generic communications referenced in the text of this IN or considered particularly relevant are underlined.
- IN   82-22 , "Failures in Turbine Exhaust Lines," July 9, 1982, addressed the   rupture of a 24-inch-diameter long-radius elbow in a feedwater heat extraction   line at Oconee Unit 2 and four similar failures identified by the Institute of   Nuclear Power Operations (INPO).     
- IN   86-106 , "Feedwater Line Break," December 16, 1986, addressed a potentially   generic problem with feedwater pipe thinning and other problems related to the   catastrophic failure of an 18-inch-diameter MFW pump suction line at Surry   Unit 2.     
- IN   86-106, Supplement 1 , "Feedwater Line Break," February 13, 1987, discussed   the licensee's failure analysis, the parameters that could have potentially   contributed to pipe break, the predictive measures used to detect   erosion/corrosion, and the inservice inspection requirements of ASME Code for   Code Class 1 and 2 piping systems and of ANSI B31.1 for other piping systems.     
- IN   86-106, Supplement 2 , "Feedwater Line Break," October 21, 1988, addressed   the discovery that an elbow installed on the suction side of a MFW pump during   a 1987 Surry Unit 2 refueling outage had thinned more rapidly than expected,   giving up 20 percent of its 0.500-inch wall thickness in 1.2 years. Wall   thinning was also observed in safety-related MFW piping and in other   non-safety-related condensate piping.     
- IN   86-106, Supplement 3 , "Feedwater Line Break," November 10, 1988, further   addressed the faster-than-expected wall thinning at Surry Unit 2, noting the   disparity between the previously estimated 20-30 mils/year thinning rate and   maximum observed rate of 90 mils/year. The IN also noted that accelerated wall   thinning may have coincided with a reduction in feedwater dissolved-oxygen   concentration.     
- NRC Bulletin 87-01, "Thinning of Pipe Walls in Nuclear Power   Plants," July 9, 1987, requested licensees to inform the NRC about their   programs for monitoring the thickness of pipe walls of carbon steel piping in   both safety-related and non-safety-related high-energy fluid (single-phase and   two-phase) systems.     
- IN   87-36, "Significant Unexpected Erosion of Feedwater Lines,"  August 4,   1987, addressed potentially generic unexpected erosion which resulted in pipe   wall thinning in both safety-related and non-safety-related portions of   feedwater lines (both inside and outside the containment) at Trojan Nuclear   Plant. The thinning was discovered when Trojan's steam piping inspection   program was expanded to include single-phase piping and was attributed to high   fluid flow velocities and other operating factors.     
- IN   88-17, "Summary of Responses to NRC Bulletin 87-01, 'Thinning of Pipe Walls in   Nuclear Power Plants,'"  April 22, 1988, reported the results of responses   to NRC Bulletin 87-01 and described a recent event at LaSalle County Station   Unit 1.     
- IN   89-01 , "Valve Body Erosion," January 4, 1989, addressed a potential   generic problem with erosion in carbon steel valve bodies in safety-related   systems.     
- Generic Letter 89-08, "Erosion/Corrosion-Induced Pipe Wall   Thinning," May 2, 1989, requested licensees to implement long-term   erosion/corrosion monitoring programs to obtain assurance that procedures or   administrative controls were in place to maintain the structural integrity of   all carbon steel systems carrying high-energy fluids.     
- IN   89-53 , "Rupture of Extraction Steam Line on High Pressure Turbine," June   13, 1989, addressed a potential generic problem with erosion in carbon steel   piping in secondary plant systems.     
- IN   91-18 , "High Energy Pipe Failures Caused by Wall Thinning," March 12,   1991, addressed continuing erosion/corrosion of high-energy piping systems and   apparently inadequate monitoring programs.     
- IN   92-35, "Higher Than Predicted Erosion/Corrosion in Unisolable Reactor Coolant   Pressure Boundary Piping Inside Containment at a Boiling Water Reactor,"    May 6, 1992, addressed an unexpectedly high rate of erosion/corrosion in   certain main feedwater piping inside the containment at the Susquehanna Unit 1   boiling water reactor (BWR). The condition was noted to be of particular   concern since it was in a section of piping that could not be isolated from   the reactor vessel.     
- IN   93-21, "Summary of NRC Staff Observations Compiled During Engineering Audits   or Inspections of Licensee Erosion/Corrosion Programs,"  March 25, 1993,   addressed NRC observations on the industry's design and implementation of   erosion/corrosion programs in response to Generic Letter 89-08.     
- IN   95-11 , "Failure of Condensate Piping Because of Erosion/Corrosion at a   Flow-Straightening Device," February 24, 1995, addressed possible piping   failures caused by flow disturbances that were not accounted for in   erosion/corrosion programs.     
- IN   97-84 , "Rupture in Extraction Steam Piping as a Result of Flow-Accelerated   Corrosion," December 11, 1997, addressed potential generic problems related to   the occurrence and prediction of flow-accelerated corrosion (FAC) in   extraction steam lines.     
- IN   99-19 , "Rupture of the Shell Side of a Feedwater Heater at the Point Beach   Nuclear Plant," June 23, 1999, addressed the rupture of the shell side of a   feedwater heater at the Point Beach Nuclear Plant Unit 1. 

ATTACHMENT 2
Table 2: Summary of Previously Identified Pipe Wall Thinning Issues and EventsDateSiteDetailsRef.1976Oconee 3Pinhole leak in an extraction steam line. A surveillance program       utilizing ultrasonic examination of extraction steam lines was initiated       and, in 1980, identified two degraded elbows identical to the Unit 2 elbow       that subsequently failed in 1982. The elbows were replaced.IN 82-221981Millstone 2Use of engineering personnel unfamiliar with plant operating       conditions, plant as-built designs, or erosion/corrosion history.IN 93-21January 1982Vermont YankeeLicensee shut down the plant after identifying steam blowing from a       leak in the 12-inch-diameter drain line between a moisture separator and       heater drain tank. IN 82-22January 1982TrojanSteam line failure resulting in plant shutdown.IN 82-22February 1982Zion 1Steam leak in 150 psig high-pressure exhaust steam line originating       from an 8-inch crack on a weld joining 24-inch piping with the 37.5-inch       high-pressure steam exhaust piping leading to the moisture separator       reheater. The event resulted in plant shutdown.IN 82-22June 1982Oconee 2While operating at 95-percent power, a 4-square-foot rupture occurred       in a 24-inch-diameter long-radius elbow in a feedwater heat extraction       line. The reactor was manually tripped, a steam jet destroyed a       non-safety-related load center and certain non-safety-related       instrumentation. Personnel were hospitalized overnight with steam burns.       An ultrasonic inspection had identified substantial erosion of the elbow       In March 1982, but the erosion failed to meet the licensee's criteria for       rejection. IN 82-22June 1982Browns Ferry 1Steam line failure resulting in plant shutdown.IN 82-22March 1983Dresden 3Steam leak from the shell side of the 3C3 low-pressure feedwater       heater near the extraction steam inlet nozzle. The leak was attributed to       erosion by deflected extraction steam. The feedwater heaters had not been       included in a periodic inspection program. IN 99-19March 1985Haddam NeckPipe rupture, approximately 1⁄2-by-2-1/4-inch, downstream of a normal       level control valve for a feedwater heater.GL 89-08December 1986Surry 2Catastrophic failure of 18-inch MFW pump suction line elbow when a       main steam isolation valve failed closed on one of the steam generators. A       2-by-4-foot section of the elbow was blown out and came to rest on an       overhead cable tray. The reactive force completely severed the suction       line. The free end whipped and came to rest against the discharge line for       another pump. The failure of the piping, which was carrying single-phase       fluid, was caused by erosion/corrosion of the carbon steel pipe wall. The       unit had been operating at full power. An automatic plant trip occurred       and four workers suffered fatal injuries. Released steam caused the fire       suppression system to actuate, releasing halon and carbon dioxide into       emergency switchgear. The NRC dispatched an augmented inspection team to       the site.IN 86-106Bulletin 87-01IN 88-17GL 89-08June 1987TrojanMFW degradation was discovered by the licensee in at least two areas       of the straight sections of ASME Class 2 safety-related MFW piping inside       containment. The thinning was discovered when the Trojan steam piping       inspection program was expanded to include single-phase piping. The       thinning was attributed to high fluid flow velocities and other operating       factors. IN 87-36IN 88-17GL 89-08December 1987LaSalle 1Through-wall pinhole leaks due to erosion were discovered in a       45-degree elbow down stream of a turbine-driven reactor feedwater pump       minimum-flow control valve. Subsequent inspections identified additional       areas of wall thinning.IN 88-17September 1988Surry 2The pipe wall of an elbow installed on the suction side of a MFW pump       during a 1987 refueling outage was discovered to have thinned more rapidly       than expected, losing 20 percent of its 0.500-inch wall thickness in 1.2       years. Wall thinning was also observed in safety-related MFW piping and in       other non-safety-related condensate piping.GL 89-08December 1988Brunswick 1Inspection indicated areas of significant but localized erosion on the       internal surfaces of several carbon steel valve bodies. The affected       safety-related valves were the 24-inch residual heat removal/low pressure       core injection (RHR/LPCI) system injection and 16-inch suppression pool       isolation valves.IN 89-01April 1989Arkansas Nuclear One Unit 2Steam escaping from a ruptured 14-inch high-pressure steam extraction       line caused a spurious turbine/reactor trip from 100-percent power. This       straight run of piping terminates at an elbow that was replaced during the       previous outage because of erosion-induced wall thinning. The pipe and       those of similar geometries had not been included in the licensee's       surveillance samples, and the degraded condition was not detected during       the elbow replacement.IN 89-53March 1990Surry 1Rupture of a straight section of piping downstream of a level control       valve in the low-pressure heater drain (LPHD) system. The LPHD system was       included in the licensee's FAC program at the time, but the program did       not provide an inspection for the affected section of piping. IN 91-18May 1990Loviisa 1 (foreign)A flow-measuring orifice flange in the main feedwater system ruptured       after one of five main feedwater pumps tripped, causing a check valve in       the line to slam shut, creating a pressure spike. Subsequent inspections       determined that 9 of 10 flanges had thinned to below minimum wall       requirements.IN 91-18July 1990San Onofre 2The licensee was forced to shut down the unit after discovering a       steam leak in one of the feedwater regulating valve bypass lines.IN 91-18December 1990Millstone 3Two 6-inch pipes in the moisture separator drain (MSD) system ruptured       when a MSD pump was stopped to facilitate component isolation for repairs.       Stopping the pump caused a pressure transient. The high-energy water       flashed to steam and actuated portions of the turbine building fire       protection deluge system. Two 480-volt motor control centers and one       non-vital 120-volt inverter were rendered inoperable by the flooding,       resulting in the loss of the plant process computer and the isolation of       the instrument air to the containment building. IN 91-18November 1991Millstone 2Rupture at an 8-inch elbow of a moisture separator reheater.       High-energy water flashed to steam, actuating portions of the turbine fire       protection deluge system. The license had not selected the ruptured elbow       for ultrasonic testing in its erosion/corrosion monitoring program. See       LER 50-336/91-12.IN 91-181992Millstone 3See LER 50-309/92-07.IN 93-211992Maine YankeeSee LER 92-007.IN 93-211992Salem 1Improper determination of code minimum wall thickness acceptance       criteria resulted in improper disposition of degraded components. See       Inspection Report 50-272/92-08.IN 93-211992Hope CreekLack of baseline thickness measurements (history) of originally       designed piping was identified. See Inspection Report 50-354/92-11. IN 93-211992Millstone 1Lack of baseline thickness measurements of replacement piping before       the replacement piping was put into service. See Inspection Report       50-245/92-80.IN 93-211992Hope CreekUse of engineering personnel who are unfamiliar with plant operating       conditions, plant as-built designs, or erosion/corrosion history.----- -----1993DiabloCanyon 1Erosion/corrosion wear was discovered behind a thermal sleeve in the       interior of the feedwater nozzle and on the feedwater nozzle itself.IN 93-21November 1994Sequoyah 1Licensee identified a 180-degree circumferential crack in a reduced       section of 14-inch condensate piping used for flow-metering. The section       of piping had been modeled incorrectly in CHECMATE� without any diameter       or thickness changes and had not been visually inspected.IN 95-11April 1997Fort CalhounManual scram and emergency boration following a 6-square-foot rupture       of a 12-inch diameter sweep elbow in the fourth-stage extraction steam       piping. A non-safety-related electrical load center, several cable trays       and pipe hangers were damaged. In addition, asbestos-containing insulation       was blown throughout the turbine building and portions of the fire       protection system were actuated.IN 97-84May 1999Point Beach 1Manual trip from 100-percent power and manual safety injection       actuation when the shell side of the feedwater heater ruptured. The       fish-mouth rupture was approximately 27-inches long and 0.75-inch at its       widest point. Feedwater heater leaks were also identified at Pilgrim       Station and the Susquehanna units. None of the feedwater heaters had been       included in a periodic inspection program. IN 99-19August 1999CallawayOperators manually tripped the reactor on indication of a steam leak       in the turbine building. An 8-inch line from the first stage reheater       drain tank to the high-pressure heater experienced a double-ended       guillotine break.Event Notification 36015