Information Notice 2001-09, Main Feedwater System Degradation in Safety-Related ASME Code Class 2 Piping Inside the Containment of a Pressurized Water Reactor
| ML011490408 | |
| Person / Time | |
|---|---|
| Issue date: | 06/12/2001 |
| From: | Marsh L Operational Experience and Non-Power Reactors Branch |
| To: | |
| Telson, R - NRR/DRIP/REXB - 415-1175 | |
| References | |
| IN-01-009 | |
| Download: ML011490408 (18) | |
UNITED STATES
NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
WASHINGTON, 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
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 licensees 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 units 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 Trojans 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 industrys 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 industrys 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, Chief
Events Assessment, Generic Communications
and Non-Power Reactors Branch
Division of Regulatory Improvement Programs
Office of Nuclear Reactor Regulation
Technical contacts: Ross Telson, NRR Krzysztof Parczewski, NRR
301-415-1175 301-415-2705 E-mail: rdt@nrc.gov E-mail: kip@nrc.gov
William D. Johnson, R-IV David Terao, NRR
817-860-8148 301-415-3317 E-mail: wdj@nrc.gov E-mail: dxt@nrc.gov
Attachments:
1. Table 1: Summary of Related Previous Generic Communications
2. Table 2: Summary of Previously Identified Pipe Wall Thinning Issues and Events
3. List of Recently Issued NRC Information Notices 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, Chief
Events Assessment, Generic Communications
and Non-Power Reactors Branch
Division of Regulatory Improvement Programs
Office of Nuclear Reactor Regulation
Technical contacts: Ross Telson, NRR Krzysztof Parczewski, NRR
301-415-1175 301-415-2705 E-mail: rdt@nrc.gov E-mail: kip@nrc.gov
William D. Johnson, R-IV David Terao, NRR
817-860-8148 301-415-3317 E-mail: wdj@nrc.gov E-mail: dxt@nrc.gov
Attachments:
1. Table 1: Summary of Related Previous Generic Communications
2. Table 2: Summary of Previously Identified Pipe Wall Thinning Issues and Events
3. List of Recently Issued NRC Information Notices
DISTRIBUTION
Public
REXB R/F
IN File
- See Previous Concurrence
Accession No.: ML011490408 Template No.:NRR-056
- Publicly Available 9 Non-Publicly Available9 Sensitive :Non-Sensitive
OFFICE REXB Tech Editor C:EMCB C:EMEB
NAME RTelson* PKleene* WBateman* EImbro*
DATE 5/ 21 /01 5 /18 /01 5/15 /01 5 /29 /01 OFFICE SC:REXB C:REXB
NAME JTappert* LMarsh
DATE 6/5 /01 6 /11/01 OFFICIAL RECORD COPY
Attachment 1 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.
1. 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).
2. 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.
3. IN 86-106, Supplement 1, Feedwater Line Break, February 13, 1987, discussed the
licensees 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.
4. 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.
5. 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.
6. 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.
7. 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
Trojans steam piping inspection program was expanded to include single-phase piping
and was attributed to high fluid flow velocities and other operating factors.
8. 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.
Attachment 1 9. 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.
10. 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.
11. 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.
12. 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.
13. 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.
14. 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 industrys design and implementation of erosion/corrosion programs
in response to Generic Letter 89-08.
15. 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.
16. 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.
17. 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 Events
Date Site Details Ref.
1976 Oconee 3 Pinhole leak in an extraction steam line. A surveillance program IN 82-22 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.
1981 Millstone 2 Use of engineering personnel unfamiliar with plant operating IN 93-21 conditions, plant as-built designs, or erosion/corrosion history.
January Vermont Licensee shut down the plant after identifying steam blowing IN 82-22
1982 Yankee from a leak in the 12-inch-diameter drain line between a
moisture separator and heater drain tank.
January Trojan Steam line failure resulting in plant shutdown. IN 82-22
1982 February Zion 1 Steam leak in 150 psig high-pressure exhaust steam line IN 82-22
1982 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.
June 1982 Oconee 2 While operating at 95-percent power, a 4-square-foot rupture IN 82-22 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 licensees criteria for rejection.
June 1982 Browns Ferry 1 Steam line failure resulting in plant shutdown. IN 82-22 March Dresden 3 Steam leak from the shell side of the 3C3 low-pressure IN 99-19
1983 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.
March Haddam Neck Pipe rupture, approximately 1/2-by-2-1/4-inch, downstream of a GL 89-08
1985 normal level control valve for a feedwater heater.
December Surry 2 Catastrophic failure of 18-inch MFW pump suction line elbow IN 86-106
1986 when a main steam isolation valve failed closed on one of the Bulletin 87-01 steam generators. A 2-by-4-foot section of the elbow was blown IN 88-17 out and came to rest on an overhead cable tray. The reactive GL 89-08 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.
Attachment 2 Date Site Details Ref.
June 1987 Trojan MFW degradation was discovered by the licensee in at least two IN 87-36 areas of the straight sections of ASME Class 2 safety-related IN 88-17 MFW piping inside containment. The thinning was discovered GL 89-08 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.
December LaSalle 1 Through-wall pinhole leaks due to erosion were discovered in a IN 88-17
1987 45-degree elbow down stream of a turbine-driven reactor
feedwater pump minimum-flow control valve. Subsequent
inspections identified additional areas of wall thinning.
September Surry 2 The pipe wall of an elbow installed on the suction side of a MFW GL 89-08
1988 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.
December Brunswick 1 Inspection indicated areas of significant but localized erosion on IN 89-01
1988 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.
April 1989 Arkansas Steam escaping from a ruptured 14-inch high-pressure steam IN 89-53 Nuclear One extraction line caused a spurious turbine/reactor trip from
Unit 2 100-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 licensees surveillance
samples, and the degraded condition was not detected during
the elbow replacement.
March Surry 1 Rupture of a straight section of piping downstream of a level IN 91-18
1990 control valve in the low-pressure heater drain (LPHD) system.
The LPHD system was included in the licensees FAC program
at the time, but the program did not provide an inspection for the
affected section of piping.
May 1990 Loviisa 1 A flow-measuring orifice flange in the main feedwater system IN 91-18 (foreign) 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.
July 1990 San Onofre 2 The licensee was forced to shut down the unit after discovering IN 91-18 a steam leak in one of the feedwater regulating valve bypass
lines.
December Millstone 3 Two 6-inch pipes in the moisture separator drain (MSD) system IN 91-18
1990 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.
Attachment 2 Date Site Details Ref.
November Millstone 2 Rupture at an 8-inch elbow of a moisture separator reheater. IN 91-18
1991 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.
1992 Millstone 3 See LER 50-309/92-07. IN 93-21
1992 Maine Yankee See LER 92-007. IN 93-21
1992 Salem 1 Improper determination of code minimum wall thickness IN 93-21 acceptance criteria resulted in improper disposition of degraded
components. See Inspection Report 50-272/92-08.
1992 Hope Creek Lack of baseline thickness measurements (history) of originally IN 93-21 designed piping was identified. See Inspection Report 50-
354/92-11.
1992 Millstone 1 Lack of baseline thickness measurements of replacement piping IN 93-21 before the replacement piping was put into service. See
Inspection Report 50-245/92-80.
1992 Hope Creek Use of engineering personnel who are unfamiliar with plant
operating conditions, plant as-built designs, or erosion/corrosion ----- -----
history.
1993 Diablo Erosion/corrosion wear was discovered behind a thermal sleeve IN 93-21 Canyon 1 in the interior of the feedwater nozzle and on the feedwater
nozzle itself.
November Sequoyah 1 Licensee identified a 180-degree circumferential crack in a IN 95-11
1994 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.
April 1997 Fort Calhoun Manual scram and emergency boration following a 6-square- IN 97-84 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.
May 1999 Point Beach 1 Manual trip from 100-percent power and manual safety injection IN 99-19 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.
August Callaway Operators manually tripped the reactor on indication of a steam Event
1999 leak in the turbine building. An 8-inch line from the first stage Notification
reheater drain tank to the high-pressure heater experienced a 36015 double-ended guillotine break.
Attachment 3 LIST OF RECENTLY ISSUED
NRC INFORMATION NOTICES
_____________________________________________________________________________________
Information Date of
Notice No. Subject Issuance Issued to
______________________________________________________________________________________
2001-08 Update on the Investigation of 06/06/01 All Medical Licensees
Supplement 1 Patient Deaths in Panama, Following Radiation Therapy
2001-08 Treatment Planning System 06/01/01 All medical licensees
Errors Result in Deaths of
Overseas Radiation Therapy
Patients
2001-07 Unescorted Access Granted 05/11/01 All holders of nuclear reactor
Based on Incomplete and/or operating licenses who are
Inaccurate Information subject to Section 73.56 of Title
10, of the Code of Federal
Regulations (10 CFR 73.56),
Personnel Access Authorization
Requirements of Nuclear Power
Plants.
2001-06 Centrifugal Charging Pump 05/11/01 All holders of operating licenses
Thrust Bearing Damage not for nuclear power reactors, Detected Due to Inadequate except those who have
Assessment of Oil Analysis permanently ceased operations
Results and Selection of Pump and have certified that fuel has
Surveillance Points been permanently removed from
the reactor
2001-05 Through-Wall Circumferential 04/30/01 All holders of operating licenses
Cracking of Reactor Pressure for pressurized water nuclear
Vessel Head Control Rod Drive power reactors except those who
Mechanism Penetration have ceased operations and have
Nozzles at Oconee Nuclear certified that fuel has been
Station, Unit 3 permanently removed from the
reactor vessel
2001-04 Neglected Fire Extinguisher 04/11/01 All holders of licenses for nuclear
Maintenance Causes Fatality power, research, and test
reactors and fuel cycle facilities
2001-03 Incident Reporting 04/06/01 All industrial radiography
Requirements for Radiography licensees
Licensees
______________________________________________________________________________________
OL = Operating License
CP = Construction Permit